ML15098A461
{{Adams | number = ML15098A461 | issue date = 02/28/2015 | title = Diablo Canyon Power Plant, Units 1 and 2, Final Safety Analysis Report Update | author name = Lingam S P | author affiliation = NRC/NRR/DORL/LPLIV-1 | addressee name = | addressee affiliation = | docket = 05000275, 05000323 | license number = DPR-080, DPR-082 | contact person = Lingam S P | document type = Final Safety Analysis Report (FSAR) | page count = 4961 }}
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{{#Wiki_filter:February 2015 This version of the Diablo Canyon Power Plant Units 1 and 2 Final Safety Analysis Report Update (FSARU) is the licensee's version submitted to the NRC on September 16, 2013, with information current through March 23, 2013, with certain redactions of sensitive information by staff of the Nuclear Regulatory Commission (NRC) to allow release to the public. The redactions are made under 10 CFR 2.390(d)(1). The material included within is classified as publicly available information. As of February 2015, this is the latest FSARU revision submitted to the NRC. The redactions were made due to meeting the NRC's criteria on sensitive information, as specified in SECY-04-0191, "Withholding Sensitive Unclassified Information Concerning Nuclear Power Reactors from Public Disclosure", dated October 19, 2004, ADAMS ML042310663, as modified by the NRC Commissioners Staff Requirements Memorandum on SECY-04-0191, dated November 9, 2004, ADAMS ML043140175. The following information was redacted by NRC staff: Figures 9.5-1 through 9.5-3, Figures 9.5F-20A, B, C, D Figures 9.5F-21 through 9.5F-33 Figures 12.1-1 through 12.1-12 Drawings: 57718 through 57734 102023-6 102023-8 102023-9 102023-11 102023-12 102023-16 102023-17 102023-18 108023-6 108023-8 108023-9 108023-11 108023-12 108023-18
438431 438432 438445 438449 439533 498992 498993 500002 500003 500852 500853 500964 through 500969 500971 through 500974 500976 500977 502699 507613 508845 515562 through 515580 515939 through515949 521120 through 521125 521130 through 521135 663082-2 Any other material that is listed as "deleted" was deleted by the licensee as part of their continuous update process for the FSARU. Diablo Canyon Power Plant Units 1 and 2 Final Safety Analysis Report Update Revision 21 September 2013 Docket No. 50-275 Docket No. 50-323 DIABLO CANYON POWER PLANT UNITS 1 AND 2 FSAR UPDATE CONTENTS i Revision 21 September 2013 Chapter 1 - INTRODUCTION AND GENERAL DESCRIPTION OF PLANT 1.1 Introduction 1.2 General Plant Description 1.3 Comparison Tables 1.4 Identification of Agents and Contractors 1.5 Requirements for Further Technical Information 1.6 Material Incorporated by Reference Tables for Chapter 1 Figures for Chapter 1 Chapter 2 - SITE CHARACTERISTICS 2.1 Geography and Demography 2.2 Nearby Industrial, Transportation, and Military Facilities 2.3 Meteorology 2.4 Hydrologic Engineering 2.5 Geology and Seismology Tables for Chapter 2 Figures for Chapter 2 Chapter 3 - DESIGN OF STRUCTURES, COMPONENTS, EQUIPMENT, AND SYSTEMS 3.1 Conformance with AEC General Design Criteria 3.2 Classification of Structures, Systems, and Components 3.3 Wind and Tornado Loadings 3.4 Water Level (Flood) Design 3.5 Missile Protection 3.6 Protection Against Dynamic Effects Associated with the Postulated Rupture of Piping 3.7 Seismic Design 3.8 Design of Design Class I Structures 3.9 Mechanical Systems and Components 3.10 Seismic Design of Design Class I Instrumentation, HVAC, and Electrical Equipment 3.11 Environmental Design of Mechanical and Electrical Equipment Tables for Chapter 3 Figures for Chapter 3 Appendices for Chapter 3 DIABLO CANYON POWER PLANT UNITS 1 AND 2 FSAR UPDATE CONTENTS ii Revision 21 September 2013 Chapter 4 - REACTOR 4.1 Summary Description 4.2 Mechanical Design 4.3 Nuclear Design 4.4 Thermal and Hydraulic Design Tables for Chapter 4 Figures for Chapter 4 Chapter 5 - REACTOR COOLANT SYSTEM 5.1 Summary Description 5.2 Integrity of the Reactor Coolant Pressure Boundary 5.3 Thermal Hydraulic System Design 5.4 Reactor Vessel and Appurtenances 5.5 Component and Subsystem Design 5.6 Instrumentation Requirements Tables for Chapter 5 Figures for Chapter 5 Appendices for Chapter 5 Chapter 6 - ENGINEERED SAFETY FEATURES 6.1 General 6.2 Containment Systems 6.3 Emergency Core Cooling System 6.4 Habitability Systems 6.5 Auxiliary Feedwater System Tables for Chapter 6 Figures for Chapter 6 Appendices for Chapter 6 Chapter 7 - INSTRUMENTATION AND CONTROLS 7.1 Introduction 7.2 Reactor Trip System 7.3 Engineered Safety Features Actuation System 7.4 Systems Required for Safe Shutdown 7.5 Safety-Related Display Instrumentation 7.6 All Other Instrumentation Systems Required for Safety 7.7 Control Systems Not Required for Safety DIABLO CANYON POWER PLANT UNITS 1 AND 2 FSAR UPDATE CONTENTS iii Revision 21 September 2013 Chapter 7 (continued) Tables for Chapter 7 Figures for Chapter 7 Chapter 8 - ELECTRIC POWER 8.1 Introduction 8.2 Offsite Power System 8.3 Onsite Power Systems Tables for Chapter 8 Figures for Chapter 8 Appendices for Chapter 8 Chapter 9 - AUXILIARY SYSTEMS 9.1 Fuel Storage and Handling 9.2 Water Systems 9.3 Process Auxiliaries 9.4 Heating, Ventilation, and Air-Conditioning (HVAC) Systems 9.5 Other Auxiliary Systems Tables for Chapter 9 Figures for Chapter 9 Appendices for Chapter 9 Chapter 10 - STEAM AND POWER CONVERSION SYSTEM 10.1 Summary Description 10.2 Turbine-Generator 10.3 Main Steam System 10.4 Other Features of Steam and Power Conversion System Tables for Chapter 10 Figures for Chapter 10 Chapter 11 - RADIOACTIVE WASTE MANAGEMENT 11.1 Source Terms 11.2 Liquid Waste System 11.3 Gaseous Waste System 11.4 Process and Effluent Radiological Monitoring System 11.5 Solid Waste System DIABLO CANYON POWER PLANT UNITS 1 AND 2 FSAR UPDATE CONTENTS iv Revision 21 September 2013 Chapter 11 (continued) 11.6 Offsite Radiological Monitoring Program Tables for Chapter 11 Figures for Chapter 11 Chapter 12 - RADIATION PROTECTION 12.1 Shielding 12.2 Ventilation 12.3 Health Physics Program Tables for Chapter 12 Figures for Chapter 12 Chapter 13 - CONDUCT OF OPERATIONS 13.1 Organizational Structure 13.2 Training Program 13.3 Emergency Planning 13.4 Review and Audit 13.5 Plant Procedures and Programs 13.6 Plant Records 13.7 Physical Security Tables for Chapter 13 Figures for Chapter 13 Chapter 14 - INITIAL TESTS AND OPERATION 14.1 Test Program 14.2 Augmentation of Applicant's Staff for Initial Tests and Operation 14.3 Postcommercial Operational Test Program Tables for Chapter 14 Figures for Chapter 14
DIABLO CANYON POWER PLANT UNITS 1 AND 2 FSAR UPDATE CONTENTS v Revision 21 September 2013 Chapter 15 - ACCIDENT ANALYSES 15.1 Condition I - Normal Operation and Operational Transients 15.2 Condition II - Faults of Moderate Frequency 15.3 Condition III - Infrequent Faults 15.4 Condition IV - Limiting Faults 15.5 Environmental Consequences of Plant Accidents Tables for Chapter 15 Figures for Chapter 15 Chapter 16 - TECHNICAL SPECIFICATIONS AND EQUIPMENT CONTROL GUIDELINES 16.1 Technical Specifications and Equipment Control Guidelines Table for Chapter 16 Chapter 17 - QUALITY ASSURANCE 17.1 Organization 17.2 Quality Assurance Program 17.3 Design Control 17.4 Procurement Document Control 17.5 Instructions, Procedures, and Drawings 17.6 Document Control 17.7 Control of Purchased Material, Equipment, and Services 17.8 Identification and Control of Materials, Parts, and Components 17.9 Special Processes 17.10 Inspection 17.11 Test Control 17.12 Control of Measuring and Test Equipment 17.13 Handling, Storage, and Shipping 17.14 Inspection, Test, and Operating Status 17.15 Control of Nonconforming Conditions 17.16 Corrective Action 17.17 Quality Assurance Records 17.18 Audits Tables for Chapter 17 Figures for Chapter 17 DCPP UNITS 1 & 2 FSAR UPDATE LIST OF CURRENT PAGES Page No. Rev. Page No. Rev. Page No. Rev. 1Revision 21 September 2013 CONTENTS i thru v 21
INDEX Removed in Rev 20
CHAPTER 1 i thru v 21 1.1-1 thru 1.1-2 18 1.2-1 thru 1.2-8 21 1.3-1 11 1.4-1 thru 1.4-3 15 1.5-1 11 1.6-1 thru 1.6-10 18 Table 1.3-1 -4 Sheets 18 Table 1.3-2 -4 Sheets 15 Table 1.4-1 -3 Sheets 11 Table 1.4-2 -3 Sheets 11 Table 1.4-3 -3 Sheets 11 Table 1.5-1 -3 Sheets 11 Table 1.6-1 -26 Sheets 21 Figure 1.2-1 18 Figure 1.2-2 11A
CHAPTER 2 i thru xix 21 2.1-1 thru 2.1-7 16 2.2-1 thru 2.2-4 16 2.3-1 thru 2.3-29 21 2.4-1 thru 2.4-22 19 2.5-1 thru 2.5-87 21 Table 2.1-1 14 Table 2.1-2 14 Table 2.1-3 14 Table 2.1-4 14 Table 2.1-5 11 Table 2.3-1 11 Table 2.3-2 11 Table 2.3-3 11 Table 2.3-4 11 Table 2.3-6 11 Table 2.3-7 11 Table 2.3-8 11 Table 2.3-9 11 Table 2.3-10 11 Table 2.3-11 11 Table 2.3-12 11 Table 2.3-13 11 Table 2.3-14 11 Table 2.3-15 11 Table 2.3-16 11 Table 2.3-17 11 Table 2.3-18 11 Table 2.3-19 11 Table 2.3-20 11 Table 2.3-21 11 Table 2.3-22 11 Table 2.3-23 11 Table 2.3-24 11 Table 2.3-25 11 Table 2.3-26 11 Table 2.3-27 11 Table 2.3-28 11 Table 2.3-29 11 Table 2.3-30 11 Table 2.3-31 11 Table 2.3-32 11 Table 2.3-33 11 Table 2.3-34 11 Table 2.3-35 11 Table 2.3-36 11 Table 2.3-37 11 Table 2.3-38 11 Table 2.3-39 11 Table 2.3-40 11 Table 2.3-41 -25 Sheets 15 Table 2.3-42 11 Table 2.3-43 11 Table 2.3-44 11 Table 2.3-45 11 Table 2.3-46 11 Table 2.3-47 11 Table 2.3-48 11 Table 2.3-49 11 Table 2.3-50 11 Table 2.3-51 11 Table 2.3-52 11 Table 2.3-53 11 Table 2.3-54 11 Table 2.3-55 11 Table 2.3-56 11 Table 2.3-57 11 Table 2.3-58 11 Table 2.3-59 11 Table 2.3-60 11 Table 2.3-61 11 Table 2.3-62 11 Table 2.3-63 11 Table 2.3-64 11 Table 2.3-65 11 Table 2.3-66 11 Table 2.3-67 11 Table 2.3-68 11 Table 2.3-69 11 Table 2.3-70 11 Table 2.3-71 11 Table 2.3-72 11 Table 2.3-73 11 Table 2.3-74 11 Table 2.3-75 11 Table 2.3-76 11 Table 2.3-77 11 Table 2.3-78 11 Table 2.3-79 11 Table 2.3-80 11 Table 2.3-81 11 Table 2.3-82 11 Table 2.3-83 11 Table 2.3-84 11 Table 2.3-85 11 Table 2.3-86 11 Table 2.3-87 11 Table 2.3-88 11 Table 2.3-89 11 Table 2.3-90 11 Table 2.3-91 11 Table 2.3-92 11 Table 2.3-93 11 Table 2.3-94 11 Table 2.3-95 11 Table 2.3-96 11 Table 2.3-97 11 Table 2.3-98 11 Table 2.3-99 11 Table 2.3-100 11 Table 2.3-101 11 Table 2.3-102 11 Table 2.3-103 11 Table 2.3-104 11 Table 2.3-105 11 Table 2.3-106 11 Table 2.3-107 11 Table 2.3-108 11 Table 2.3-109 11 Table 2.3-110 11 Table 2.3-111 11 Table 2.3-112 11 Table 2.3-113 11 Table 2.3-114 11 Table 2.3-115 11 Table 2.3-116 11 Table 2.3-117 11 Table 2.3-118 11 Table 2.3-119 11 Table 2.3-120 11 Table 2.3-121 11 Table 2.3-122 11 Table 2.3-123 11 Table 2.3-124 11 DCPP UNITS 1 & 2 FSAR UPDATE LIST OF CURRENT PAGES Page No. Rev. Page No. Rev. Page No. Rev. 2Revision 21 September 2013 Table 2.3-125 11 Table 2.3-126 11 Table 2.3-127 11 Table 2.3-128 11 Table 2.3-129 11 Table 2.3-130 11 Table 2.3-131 11 Table 2.3-132 11 Table 2.3-133 11 Table 2.3-134 11 Table 2.3-135 11 Table 2.3-136 11 Table 2.3-137 11 Table 2.3-138 11 Table 2.3-139 11 Table 2.3-141 11 Table 2.3-142 11 Table 2.3-144 11 Table 2.4-1 11 Table 2.5-1 -43 Sheets 17 Table 2.5-2 -2 Sheets 11 Table 2.5-3 -2 Sheets 11 Figure 2.1-1 11 Figure 2.1-2 11 Figure 2.1-3 11 Figure 2.1-4 14 Figure 2.1-5 14 Figure 2.1-6 14 Figure 2.1-7 14 Figure 2.1-8 14 Figure 2.1-9 14 Figure 2.1-14 11 Figure 2.1-15 13 Figure 2.3-1 11 Figure 2.3-2 11 Figure 2.3-3 11 Figure 2.3-4 20 Figure 2.4-1 -2 Sheets 11 Figure 2.4-2 11 Figure 2.4-3 11 Figure 2.4-4 -3 Sheets 11 Figure 2.4-5 -3 Sheets 11 Figure 2.4-6 -2 Sheets 11 Figure 2.4-9 11 Figure 2.5-1 11 Figure 2.5-2 11 Figure 2.5-3 11 Figure 2.5-4 11 Figure 2.5-5 -2 Sheets 11 Figure 2.5-6 11 Figure 2.5-7 11 Figure 2.5-8 11 Figure 2.5-9 11 Figure 2.5-10 11 Figure 2.5-11 11 Figure 2.5-12 11 Figure 2.5-13 11 Figure 2.5-14 11 Figure 2.5-15 11 Figure 2.5-16 11 Figure 2.5-17 11 Figure 2.5-18 11 Figure 2.5-19 11 Figure 2.5-20 11 Figure 2.5-21 11 Figure 2.5-22 11 Figure 2.5-23 11 Figure 2.5-24 11 Figure 2.5-25 11 Figure 2.5-26 11 Figure 2.5-27 11 Figure 2.5-28 11 Figure 2.5-29 11 Figure 2.5-30 11 Figure 2.5-31 11 Figure 2.5-32 11 Figure 2.5-33 21 Figure 2.5-34 21 Figure 2.5-35 21 Figure 2.5-36 21
CHAPTER 3 i thru xxxviii 21 3.1-1 thru 3.1-45 21 3.2-1 thru 3.2-10 15 3.3-1 thru 3.3-29 21 3.4-1 thru 3.4-2 15 3.5-1 thru 3.5-19 21 3.6-1 thru 3.6-26 19 3.7-1 thru 3.7-43 21 3.8-1 thru 3.8-82 21 3.9-1 thru 3.9-37 21 3.10-1 thru 3.10-41 21 3.11-1 thru 3.11-12 21 Table 3.1-1 20 Table 3.1-2 -6 Sheets 20 Table 3.2-1 -2 Sheets 13 Table 3.2-2 -4 Sheets 16 Table 3.3-1 11 Table 3.3-2 -4 Sheets 16 Table 3.3-3 -3 Sheets 15 Table 3.3-4 -2 Sheets 12 Table 3.3-5 -2 Sheets 16 Table 3.3-6 16 Table 3.5-2 11 Table 3.5-3 11 Table 3.5-4 11 Table 3.5-5 11 Table 3.5-6 11 Table 3.5-7 11 Table 3.5-8 12 Table 3.6-1 -9 Sheets 11 Table 3.6-2 -3 Sheets 19 Table 3.6-6 11 Table 3.7-1 11 Table 3.7-1A 11 Table 3.7-1B 11 Table 3.7-1C 11 Table 3.7-2 11 Table 3.7-3 11 Table 3.7-4 11 Table 3.7-5 11 Table 3.7-6 11 Table 3.7-7 11 Table 3.7-8 11 Table 3.7-8A 11 Table 3.7-8B 11 Table 3.7-8C 11 Table 3.7-8D 11 Table 3.7-8E 11 Table 3.7-8F 11 Table 3.7-8G 11 Table 3.7-8H 11 Table 3.7-8I 11 Table 3.7-8J 11 Table 3.7-8K 11 Table 3.7-8L -2 Sheets 21 Table 3.7-8M -2 Sheets 21 Table 3.7-8N -2 Sheets 21 Table 3.7-8O 11 Table 3.7-8P 11 Table 3.7-9 11 Table 3.7-10 11 Table 3.7-11 11 Table 3.7-11A 11 Table 3.7-11B 11 Table 3.7-12 11 Table 3.7-13 11 Table 3.7-14 11 Table 3.7-15 11 Table 3.7-16 11 Table 3.7-17 11 Table 3.7-18 11 Table 3.7-19 11 Table 3.7-20 11 Table 3.7-21 11 Table 3.7-22 11 Table 3.7-23 11 Table 3.7-23A -2 Sheets 11 Table 3.7-23B 11 Table 3.7-23C -2 Sheets 11 DCPP UNITS 1 & 2 FSAR UPDATE LIST OF CURRENT PAGES Page No. Rev. 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Page No. Rev. 3Revision 21 September 2013 Table 3.7-23D 11 Table 3.7-23E 11 Table 3.7-23F 12 Table 3.7-23G 11 Table 3.7-23H 11 Table 3.7-23I 11 Table 3.7-23J 11 Table 3.7-24 19 Table 3.8-1 -2 Sheets 11 Table 3.8-2 -5 Sheets 11 Table 3.8-3 -10 Sheets 11 Table 3.8-4 11 Table 3.8-5 -3 Sheets 11 Table 3.8-5A 11 Table 3.8-5B 12 Table 3.8-6 -3 Sheets 21 Table 3.8-6A 21 Table 3.8-6B 11 Table 3.8-7 19 Table 3.8-8 11 Table 3.8-9 11 Table 3.8-10 11 Table 3.8-11 11 Table 3.8-12 11 Table 3.8-13 11 Table 3.8-14 11 Table 3.8-15 11 Table 3.8-16 11 Table 3.8-17 11 Table 3.8-18 11 Table 3.8-19 11 Table 3.8-20 11 Table 3.8-21 11 Table 3.8-22 11 Table 3.8-23 11 Table 3.8-23A 11 Table 3.8-24 11 Table 3.8-25 11 Table 3.8-26 11 Table 3.8-27 11 Table 3.8-27A 11 Table 3.8-28 11 Table 3.9-1 -2 Sheets 12 Table 3.9-2 -3 Sheets 11 Table 3.9-3 -2 Sheets 11 Table 3.9-4 -3 Sheets 11 Table 3.9-5 -2 Sheets 11 Table 3.9-6 -3 Sheets 11 Table 3.9-7 -2 Sheets 11 Table 3.9-8 -3 Sheets 11 Table 3.9-9 -25 Sheets 19 Table 3.9-10 11 Table 3.9-11 -2 Sheets 15 Table 3.9-12 -5 Sheets 11 Table 3.10-1 -2 Sheets 12 Table 3.10-2 -4 Sheets 12 Table 3.10-3 -31 Sheets 21 Figure 3.3-1 13 Figure 3.3-2 13 Figure 3.3-3 11 Figure 3.3-4 -2 Sheets 11 Figure 3.5-1 20 Figure 3.5-2 11 Figure 3.6-1 11 Figure 3.6-3 11 Figure 3.6-3A 11 Figure 3.6-3B 11 Figure 3.6-3C 11 Figure 3.6-4 12 Figure 3.6-16 11 Figure 3.5-17 11 Figure 3.6-18 11 Figure 3.6-19 11 Figure 3.6-20 11 Figure 3.6-21 11 Figure 3.6-22 11 Figure 3.6-23 11 Figure 3.6-24 12 Figure 3.6-25 11 Figure 3.6-26 11 Figure 3.6-28 11 Figure 3.6-29 11 Figure 3.6-30 11 Figure 3.6-31 11 Figure 3.6-32 11 Figure 3.6-33 11 Figure 3.6-34 11 Figure 3.6-35 11 Figure 3.6-36 11 Figure 3.6-37 11 Figure 3.6-38 12 Figure 3.6-39 11 Figure 3.6-40 12 Figure 3.6-41 11 Figure 3.6-42 12 Figure 3.6-43 11 Figure 3.6-44 12 Figure 3.7-1 11 Figure 3.7-2 11 Figure 3.7-3 11 Figure 3.7-4 11 Figure 3.7-4A 11 Figure 3.7-4B 11 Figure 3.7-4C 11 Figure 3.7-4D 11 Figure 3.7-4E 11 Figure 3.7-4F 11 Figure 3.7-4G 11 Figure 3.7-4H 11 Figure 3.7-4I 11 Figure 3.7-4J 11 Figure 3.7-4K 11 Figure 3.7-4L 11A Figure 3.7-4M 11A Figure 3.7-4N 11 Figure 3.7-4O 11 Figure 3.7-4P 11 Figure 3.7-4Q 11 Figure 3.7-4R 11 Figure 3.7-4S 11A Figure 3.7-4T 11 Figure 3.7-5 11 Figure 3.7-5A 11 Figure 3.7-5B 11 Figure 3.7-5C 11 Figure 3.7-5D 11 Figure 3.7-5E 11 Figure 3.7-6 11 Figure 3.7-7 11 Figure 3.7-7A 21 Figure 3.7-8 11 Figure 3.7-9 11 Figure 3.7-10 11 Figure 3.7-11 11 Figure 3.7-12 11 Figure 3.7-12A 11 Figure 3.7-12B 11 Figure 3.7-12C 11 Figure 3.7-12D 11 Figure 3.7-12E 11 Figure 3.7-12F 11 Figure 3.7-12G 11 Figure 3.7-12H 11 Figure 3.7-12I 11 Figure 3.7-12J 11 Figure 3.7-12K 11 Figure 3.7-12L 11 Figure 3.7-12M 11 Figure 3.7-12N 11 Figure 3.7-12O 11 Figure 3.7-12P 11 Figure 3.7-12Q 11 Figure 3.7-12R 11 Figure 3.7-12S 11 Figure 3.7-13 11 Figure 3.7-13A 11 Figure 3.7-13B 11 Figure 3.7-14 11 Figure 3.7-15 11 Figure 3.7-15A 11 Figure 3.7-15B 11 Figure 3.7-15C 11 DCPP UNITS 1 & 2 FSAR UPDATE LIST OF CURRENT PAGES Page No. Rev. 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Page No. Rev. 4Revision 21 September 2013 Figure 3.7-15D 11 Figure 3.7-15E 11 Figure 3.7-15F 11 Figure 3.7-15G 17 Figure 3.7-15H 11 Figure 3.7-15I 11 Figure 3.7-16 11 Figure 3.7-17 11 Figure 3.7-18 11 Figure 3.7-19 11 Figure 3.7-20 11 Figure 3.7-21 11 Figure 3.7-21A 11 Figure 3.7-21B 11 Figure 3.7-21C 11 Figure 3.7-21D 11 Figure 3.7-21E 11 Figure 3.7-21F 11 Figure 3.7-21G 11 Figure 3.7-21H 11 Figure 3.7-21I 11 Figure 3.7-22 11 Figure 3.7-23 11 Figure 3.7-24 11 Figure 3.7-25 11 Figure 3.7-25A 11 Figure 3.7-25B 11 Figure 3.7-25C 11 Figure 3.7-25D 11 Figure 3.7-25E 11 Figure 3.7-25F 11 Figure 3.7-25G 11 Figure 3.7-25H 11 Figure 3.7-25I 11 Figure 3.7-25J 11 Figure 3.7-25K 11 Figure 3.7-25L 11 Figure 3.7-25M 11 Figure 3.7-25N 11 Figure 3.7-25O 11 Figure 3.7-25P 11 Figure 3.7-25Q 11 Figure 3.7-25R 11 Figure 3.7-25S 11 Figure 3.7-25T 11 Figure 3.7-26 11 Figure 3.7-27 11 Figure 3.7-27A 20 Figure 3.7-27B 20 Figure 3.7-27C 19 Figure 3.7-27D 20 Figure 3.7-27E 20 Figure 3.7-27F 14 Figure 3.7-28 11 Figure 3.7-29 11 Figure 3.8-1 11 Figure 3.8-2 11 Figure 3.8-3 11 Figure 3.8-4 11 Figure 3.8-5 11 Figure 3.8-6 11 Figure 3.8-7 11 Figure 3.8-10 11 Figure 3.8-11 11 Figure 3.8-12 11 Figure 3.8-13 11 Figure 3.8-14 11 Figure 3.8-15 11 Figure 3.8-21 -2 Sheets 11 Figure 3.8-22 -2 Sheets 11 Figure 3.8-27 11 Figure 3.8-28 11 Figure 3.8-29 11 Figure 3.8-30 11 Figure 3.8-31 11 Figure 3.8-32 11 Figure 3.8-33 11 Figure 3.8-34 11 Figure 3.8-35 11 Figure 3.8-37 11 Figure 3.8-38 11 Figure 3.8-39 11 Figure 3.8-40 11 Figure 3.8-41 11 Figure 3.8-42 11 Figure 3.8-43 11 Figure 3.8-44 11 Figure 3.8-60 11 Figure 3.8-61 11 Figure 3.8-62 11 Figure 3.8-63 11 Figure 3.8-64 11 Figure 3.8-66 11 Figure 3.8-67 11 Figure 3.8-68 11 Figure 3.8-69 11 Figure 3.8-70 11 Figure 3.8-71 11 Figure 3.8-75 11 Figure 3.8-76 11 Figure 3.8-77 11 Figure 3.8-78 11 Figure 3.8-79 11 Figure 3.8-80 11 Figure 3.8-81 11 Figure 3.8-82 11 Figure 3.9-1 11 Figure 3.9-2 11 Figure 3.9-3 11 Figure 3.9-4 11 Appendix 3.1A-1 thru 40 21
CHAPTER 4 i thru x 21 4.1-1 thru 4.1-4 21 4.2-1 thru 4.2-53 21 4.3-1 thru 4.3-40 21 4.4-1 thru 4.4-43 21 Table 4.1-1 -7 Sheets 21 Table 4.1-2 -3 Sheets 11 Table 4.1-3 12 Table 4.2-1 11 Table 4.3-1 -2 Sheets 16 Table 4.3-2 11 Table 4.3-3 11 Table 4.3-4 11 Table 4.3-5 11 Table 4.3-6 11 Table 4.3-7 11 Table 4.3-8 11 Table 4.3-9 11 Table 4.3-10 11 Table 4.3-11 11 Table 4.4-1 11 Table 4.4-2 11 Table 4.4-3 11 Figure 4.2-1 11 Figure 4.2-2 11 Figure 4.2-2A 15 Figure 4.2-3 11 Figure 4.2-3A 15 Figure 4.2-4 11 Figure 4.2-5 11 Figure 4.2-6 11 Figure 4.2-7 11 Figure 4.2-8 11 Figure 4.2-9 11 Figure 4.2-10 11 Figure 4.2-11 11 Figure 4.2-12 11 Figure 4.2-13 11 Figure 4.2-14 11 Figure 4.2-15 11 Figure 4.2-16 14 Figure 4.2-17 14 Figure 4.2-18 11 Figure 4.2-18a 11 Figure 4.2-19 11 Figure 4.2-20 11 Figure 4.2-21 11 Figure 4.2-21A 14 DCPP UNITS 1 & 2 FSAR UPDATE LIST OF CURRENT PAGES Page No. Rev. Page No. Rev. Page No. Rev. 5Revision 21 September 2013 Figure 4.2-22 11 Figure 4.2-23 20 Figure 4.2-24 20 Figure 4.2-25 11 Figure 4.2-26 11 Figure 4.3-1 11 Figure 4.3-2 11 Figure 4.3-3 11 Figure 4.3-4 11 Figure 4.3-5 11 Figure 4.3-6 11 Figure 4.3-7 11 Figure 4.3-8 11 Figure 4.3-9 11 Figure 4.3-10 11 Figure 4.3-11 11 Figure 4.3-12 11 Figure 4.3-13 11 Figure 4.3-14 11 Figure 4.3-15 11 Figure 4.3-16 11 Figure 4.3-17 11 Figure 4.3-21 11 Figure 4.3-22 11 Figure 4.3-23 11 Figure 4.3-24 11 Figure 4.3-25 11 Figure 4.3-26 11 Figure 4.3-27 11 Figure 4.3-28 11 Figure 4.3-29 11 Figure 4.3-30 11 Figure 4.3-31 11 Figure 4.3-32 11 Figure 4.3-33 11 Figure 4.3-34 11 Figure 4.3-35 11 Figure 4.3-36 11 Figure 4.3-37 11 Figure 4.3-38 11 Figure 4.3-39 11 Figure 4.3-40 11 Figure 4.3-41 11 Figure 4.3-42 11 Figure 4.3-43 11 Figure 4.3-44 11 Figure 4.3-45 11 Figure 4.3-46 11 Figure 4.3-47 11 Figure 4.4-1 11 Figure 4.4-2 11 Figure 4.4-3 11 Figure 4.4-4 11 Figure 4.4-5 11 Figure 4.4-6 11 Figure 4.4-7 11 Figure 4.4-8 11 Figure 4.4-9 11 Figure 4.4-10 11 Figure 4.4-11 11 Figure 4.4-12 11 Figure 4.4-13 11 Figure 4.4-14 11 Figure 4.4-15 11 Figure 4.4-16 11 Figure 4.4-17 11 Figure 4.4-18 11 Figure 4.4-19 11 Figure 4.4-20 11
CHAPTER 5 i thru xiii 21 5.1-1 thru 5.1-9 19 5.2-1 thru 5.2-72 21 5.3-1 thru 5.3-2 20 5.4-1 thru 5.4-6 20 5.5-1 thru 5.5-45 21 5.6-1 thru 5.6-2 21 Table 5.1-1 -2 Sheets 20 Table 5.2-1 -2 Sheets 19 Table 5.2-2 -2 Sheets 20 Table 5.2-3 20 Table 5.2-4 -2 Sheets 19 Table 5.2-5 11 Table 5.2-6 19 Table 5.2-7 19 Table 5.2-8 12 Table 5.2-9 -3 Sheets 20 Table 5.2-10 11A Table 5.2-11 21 Table 5.2-12 -2 Sheets 21 Table 5.2-13 19 Table 5.2-14 19 Table 5.2-15 12 Table 5.2-16 -4 Sheets 12 Table 5.2-17A 21 Table 5.2-17B 21 Table 5.2-18A 21 Table 5.2-18B 21 Table 5.2-19A 15 Table 5.2-19B 20 Table 5.2-20A 15 Table 5.2-20B 15 Table 5.2-21A 20 Table 5.2-21B 20 Table 5.2-22 21 Table 5.2-23 16 Table 5.4-1 11 Table 5.4-2 20 Table 5.5-1 11 Table 5.5-2 11 Table 5.5-3 -2 Sheets 19 Table 5.5-5 -2 Sheets 19 Table 5.5-6 16 Table 5.5-7 11 Table 5.5-8 14 Table 5.5-9 11 Table 5.5-10 -2 Sheets 12 Table 5.5-11 18 Table 5.5-12 12 Table 5.5-13 11 Table 5.5-14 11 Table 5.5-15 11 Table 5.5-16 11 Table 5.5-17 20 Figure 5.1-2 11 Figure 5.2-1 11 Figure 5.2-2 19 Figure 5.2-3 19 Figure 5.2-4 11 Figure 5.2-7 21 Figure 5.2-8 11 Figure 5.2-9 11 Figure 5.2-10 11 Figure 5.2-11 11 Figure 5.2-12 11 Figure 5.2-13 11 Figure 5.2-14 19 Figure 5.2-15 11 Figure 5.2-16 11 Figure 5.2-17 11 Figure 5.2-18 11 Figure 5.2-19 11 Figure 5.3-1 21 Figure 5.4-1 20 Figure 5.4-2 20 Figure 5.5-1 11 Figure 5.5-2 11 Figure 5.5-3 11 Figure 5.5-4 19 Figure 5.5-8 11 Figure 5.5-9 11 Figure 5.5-10 19 Figure 5.5-11 18 Figure 5.5-12 11 Figure 5.5-14 20 Figure 5.5-18 19 Appendix 5.5A-1 thru 4 15 Table 5.5A-1 15
DCPP UNITS 1 & 2 FSAR UPDATE LIST OF CURRENT PAGES Page No. Rev. Page No. Rev. Page No. Rev. 6Revision 21 September 2013 CHAPTER 6 i thru xiii 21 6.1-1 thru 6.1-5 21 6.2-1 thru 6.2-71 21 6.3-1 thru 6.3-37 21 6.4-1 thru 6.4-7 21 6.5-1 thru 6.5-14 21 Table 6.2-14 11 Table 6.2-15 11 Table 6.2-16 11 Table 6.2-17 11 Table 6.2-18 -2 Sheets 11 Table 6.2-19 -5 Sheets 11 Table 6.2-20 -6 Sheets 11 Table 6.2-21 19 Table 6.2-22 11 Table 6.2-23 11 Table 6.2-24 19 Table 6.2-25 12 Table 6.2-26 -3 Sheets 18 Table 6.2-27 12 Table 6.2-29 12 Table 6.2-30 11 Table 6.2-36 19 Table 6.2-37 11 Table 6.2-38 11 Table 6.2-39 -20 Sheets 20 Table 6.2-40 -2 Sheets 15 Table 6.2-41 14 Table 6.2-42 -2 Sheets 14 Table 6.2-43 14 Table 6.2-44 14 Table 6.2-45 14 Table 6.2-47 -2 Sheets 11 Table 6.2-48 -2 Sheets 19 Table 6.2-55 11 Table 6.3-1 -3 Sheets 18 Table 6.3-2 12 Table 6.3-3 -2 Sheets 12 Table 6.3-5 -6 Sheets 20 Table 6.3-6 12 Table 6.3-7 -4 Sheets 12 Table 6.3-8 12 Table 6.3-9 11 Table 6.3-10 11 Table 6.3-11 18 Table 6.3-12 -2 Sheets 16 Table 6.5-1 19 Table 6.5-2 -2 Sheets 19 Table 6.5-3 18 Figure 6.2-10 11 Figure 6.2-12 11 Figure 6.2-13 11 Figure 6.2-14 12 Figure 6.2-15 11 Figure 6.2-16 12 Figure 6.2-17 11 Figure 6.2-18 -2 Sheets 11 Figure 6.2-19, Sheet 1 11 Figure 6.2-19, Sheet 2 11 Figure 6.2-19, Sheet 3 11 Figure 6.2-19, Sheet 4 11 Figure 6.2-19, Sheet 5 21 Figure 6.2-19, Sheet 5A 21 Figure 6.2-19, Sheet 6 20 Figure 6.2-19, Sheet 7 21 Figure 6.2-19, Sheet 8 20 Figure 6.2-19, Sheet 8A 20 Figure 6.2-19, Sheet 9 21 Figure 6.2-19, Sheet 10 21 Figure 6.2-19, Sheet 11 11 Figure 6.2-19, Sheet 12 15 Figure 6.2-19, Sheet 13 20 Figure 6.2-19, Sheet 13A 20 Figure 6.2-19, Sheet 14 21 Figure 6.2-19, Sheet 15 11 Figure 6.2-19, Sheet 16 21 Figure 6.2-19, Sheet 17 15 Figure 6.2-19, Sheet 18 11 Figure 6.2-19, Sheet 19 11 Figure 6.2-19, Sheet 20 11 Figure 6.2-19, Sheet 21 19 Figure 6.2-19, Sheet 21A 19 Figure 6.2-19, Sheet 22 18 Figure 6.2-19, Sheet 23 21 Figure 6.2-19, Sheet 24 16 Figure 6.2-19, Sheet 25 21 Figure 6.2-20 11 Figure 6.2-21 11 Figure 6.2-22 16 Figure 6.2-23 11 Figure 6.2-24 11 Figure 6.2-25 14 Figure 6.2-26 14 Figure 6.2-27 14 Figure 6.2-28 14 Figure 6.2-29 14 Figure 6.2-33 11 Figure 6.2-34 11 Figure 6.2-35 11 Figure 6.2-36 11 Figure 6.2-37 11 Figure 6.2-38 11 Figure 6.2-39 11 Figure 6.2-40 11 Figure 6.2-41 11 Figure 6.2-42 11 Figure 6.2-43 11 Figure 6.2-44 11 Figure 6.2-45 11 Figure 6.2-46 11 Figure 6.2-51 11 Figure 6.2-52 11 Figure 6.3-1 11 Figure 6.3-2 18 Figure 6.3-3 11 Figure 6.3-4 20 Figure 6.3-5 20 Figure 6.5-3, Sheet 1 12 Figure 6.5-3, Sheet 2 20 Appendix 6.2D-1 thru 34 20 Table 6.2D-1 18 Table 6.2D-2 18 Table 6.2D-3 -6 Sheets 18 Table 6.2D-4 18 Table 6.2D-5 18 Table 6.2D-6 -6 Sheets 18 Table 6.2D-7-6 Sheets 18 Table 6.2D-8 -2 Sheets 18 Table 6.2D-9 -4 Sheets 18 Table 6.2D-10 18 Table 6.2D-11 18 Table 6.2D-12 18 Table 6.2D-13 20 Table 6.2D-14 18 Table 6.2D-15 18 Table 6.2D-16 19 Table 6.2D-17 -2 Sheets 18 Table 6.2D-18 18 Table 6.2D-19 18 Table 6.2D-20 18 Table 6.2D-21 18 Table 6.2D-22 18 Table 6.2D-23 18 Table 6.2D-24 18 Figure 6.2D-1 18 Figure 6.2D-2 18 Figure 6.2D-3 18 Figure 6.2D-4 18 Figure 6.2D-5 18 Figure 6.2D-6 18 Figure 6.2D-7 18 Figure 6.2D-8 18 Figure 6.2D-9 18 Figure 6.2D-10 18 Appendix 6.3A-1 thru 3 15 Table 6.3A-1 -3 Sheets 18 Table 6.3A-2 19
DCPP UNITS 1 & 2 FSAR UPDATE LIST OF CURRENT PAGES Page No. Rev. Page No. Rev. Page No. Rev. 7Revision 21 September 2013 CHAPTER 7 i thru xv 21 7.1-1 thru 7.1-15 21 7.2-1 thru 7.2-46 21 7.3-1 thru 7.3-32 21 7.4-1 thru 7.4-16 21 7.5-1 thru 7.5-25 21 7.6-1 thru 7.6-11 21 7.7-1 thru 7.7-33 21 Table 7.2-1 -3 Sheets 20 Table 7.2-2 -2 Sheets 12 Table 7.2-3 -4 Sheets 21 Table 7.3-1 11 Table 7.3-2 -2 Sheets 11 Table 7.3-3 -2 Sheets 20 Table 7.5-1 -4 Sheets 16 Table 7.5-2 -4 Sheets 17 Table 7.5-3 -8 Sheets 18 Table 7.5-4 -2 Sheets 21 Table 7.5-5 -2 Sheets 16 Table 7.5-6 -14 Sheets 21 Table 7.7-1 -2 Sheets 21 Figure 7.2-2 11 Figure 7.2-3 11 Figure 7.2-4 11 Figure 7.2-5 11 Figure 7.2-6 -2 Sheets 11 Figure 7.5-1 19 Figure 7.5-1B 19 Figure 7.5-2 12 Figure 7.7-1 11 Figure 7.7-2 16 Figure 7.7-3 11 Figure 7.7-4 16 Figure 7.7-5 21 Figure 7.7-8 21 Figure 7.7-9 11
CHAPTER 8 i thru vi 21 8.1-1 thru 8.1-6 21 8.2-1 thru 8.2-16 21 8.3-1 thru 8.3-87 21 Table 8.1-1 -4 Sheets 21 Table 8.3-1 -2 Sheets 12 Table 8.3-2 18 Table 8.3-3 21 Table 8.3-4 18 Table 8.3-5 18 Table 8.3-6 -3 Sheets 18 Table 8.3-7 18 Table 8.3-8 -5 Sheets 12 Table 8.3-9 11 Table 8.3-10 11 Table 8.3-11 12 Figure 8.3-21 11 Figure 8.3-22 11 Figure 8.3-23 11 Figure 8.3-24 11 Figure 8.3-25 11 Figure 8.3-26 11 Figure 8.3-27 11 Figure 8.3-28 11 Appendix 8.3B-1 thru 2 21 Appendix 8.3C-1 thru 3 15 CHAPTER 9 i thru xv 21 9.1-1 thru 9.1-53 21 9.2-1 thru 9.2-52 21 9.3-1 thru 9.3-54 20 9.4-1 thru 9.4-51 21 9.5-1 thru 9.5-37 21 Table 9.1-1 -2 Sheets 20 Table 9.1-2 -3 Sheets 16 Table 9.2-1 12 Table 9.2-2 21 Table 9.2-3 21 Table 9.2-4 20 Table 9.2-5 -2 Sheets 20 Table 9.2-6 15 Table 9.2-7 -3 Sheets 21 Table 9.2-9 -4 Sheets 19 Table 9.3-1 -2 Sheets 12 Table 9.3-2 11 Table 9.3-5 18 Table 9.3-6 -8 Sheets 20 Table 9.3-7 -2 Sheets 20 Table 9.3-8 14 Table 9.4-1 -2 Sheets 16 Table 9.4-2 -4 Sheets 21 Table 9.4-5 21 Table 9.4-6 -2 Sheets 12 Table 9.4-7 13 Table 9.4-8 -3 Sheets 15 Table 9.4-9 13 Table 9.4-10 -2 Sheets 21 Table 9.4-11 20 Table 9.4-12 11 Table 9.5-1 18 Table 9.5-2 11A Figure 9.1-1 11 Figure 9.1-2 11 Figure 9.1-2A 16 Figure 9.1-2B 15 Figure 9.1-4 19 Figure 9.1-5 18 Figure 9.1-6 19 Figure 9.1-7 19 Figure 9.1-8 11 Figure 9.1-9 11 Figure 9.1-10 11 Figure 9.1-11 11 Figure 9.1-12 11 Figure 9.1-12a 11 Figure 9.1-13 11 Figure 9.1-14 11 Figure 9.1-15 20 Figure 9.1-16 11 Figure 9.1-17 11 Figure 9.1-18 11 Figure 9.1-19 19 Figure 9.1-20 19 Figure 9.1-21 19 Figure 9.1-24 19 Figure 9.2-2 12 Figure 9.2-3 12 Figure 9.3-5 11 Figure 9.4-4 20 Figure 9.4-5 11 Figure 9.4-6 16 Figure 9.4-7 11 Figure 9.4-11 11 Figure 9.5-1 17 Figure 9.5-2 17 Figure 9.5-3 14 Figure 9.5-5 15 Figure 9.5-6 15 Appendix 9.5A-1 thru 609 21 Appendix 9.5B-1 thru 43 15 Appendix 9.5C-1 thru 6 15 Appendix 9.5D-1 thru 6 16 Appendix 9.5E-1 thru 2 15 Appendix 9.5F-1 thru 2 16 Figure 9.5F-20A 11 Figure 9.5F-20B 11 Figure 9.5F-20C 11 Figure 9.5F-20D 11 Figure 9.5F-21 11 Figure 9.5F-22 11 Figure 9.5F-23 11 Figure 9.5F-24 11 Figure 9.5F-25 11 Figure 9.5F-26 11 Figure 9.5F-27 11 Figure 9.5F-28 11 Figure 9.5F-29 11 Figure 9.5F-30 11 DCPP UNITS 1 & 2 FSAR UPDATE LIST OF CURRENT PAGES Page No. Rev. Page No. Rev. Page No. Rev. 8Revision 21 September 2013 Figure 9.5F-31 11 Figure 9.5F-32 11 Figure 9.5F-33 11 Appendix 9.5G-1 20 Table 9.5G-1 -10 Sheets 20 Table 9.5G-2 -10 Sheets 20 Appendix 9.5H-i 21 Appendix 9.5H-1 thru 20 21
CHAPTER 10 i thru v 21 10.1-1 thru 10.1-2 17 10.2-1 thru 10.2-11 21 10.3-1 thru 10.3-5 19 10.4-1 thru 10.4-20 21 Table 10.1-1 13 Table 10.1-2 19 Table 10.3-1 12 Table 10.4-1 17 Figure 10.2-1 18 Figure 10.3-6 11 Figure 10.4-2 11 Figure 10.4-3 11
CHAPTER 11 i thru xiii 21 11-1 thru 11-2 19 11.1-1 thru 11.1-7 19 11.2-1 thru 11.2-20 20 11.3-1 thru 11.3-10 20 11.4-1 thru 11.4-16 19 11.5-1 thru 11.5-6 21 11.6-1 thru 11.6-5 19 Table 11.1-1 11 Table 11.1-2 11 Table 11.1-3 11 Table 11.1-4 11 Table 11.1-5 11 Table 11.1-6 11 Table 11.1-7 11 Table 11.1-8 11 Table 11.1-9 11 Table 11.1-10 11 Table 11.1-11 13 Table 11.1-12 11 Table 11.1-13 11 Table 11.1-14 18 Table 11.1-15 20 Table 11.1-16 11 Table 11.1-17 11 Table 11.1-18 11 Table 11.1-19 11 Table 11.1-20 11 Table 11.1-21 11 Table 11.1-22 11 Table 11.1-23 11 Table 11.1-24 11 Table 11.1-25 11 Table 11.1-26 11 Table 11.1-27 11 Table 11.1-28 11 Table 11.1-29 11 Table 11.1-30 11 Table 11.1-31 11 Table 11.2-1 -2 Sheets 11 Table 11.2-2 20 Table 11.2-3 -2 Sheets 11 Table 11.2-4 -2 Sheets 11 Table 11.2-5 -4 Sheets 20 Table 11.2-6 -2 Sheets 20 Table 11.2-7 -2 Sheets 20 Table 11.2-8 -5 Sheets 11 Table 11.2-9 -5 Sheets 11 Table 11.2-10 -3 Sheets 19 Table 11.2-11 11 Table 11.2-13 11 Table 11.2-14 11 Table 11.2-15 11 Table 11.2-16 -2 Sheets 11 Table 11.2-17 11 Table 11.2-18 11 Table 11.2-19 11 Table 11.2-20 12 Table 11.2-21 -2 Sheets 11 Table 11.2-22 11 Table 11.2-23 11 Table 11.2-24 -2 Sheets 11 Table 11.2-25 -2 Sheets 11 Table 11.2-26 -2 Sheets 11 Table 11.3-1 -2 Sheets 12 Table 11.3-2 11 Table 11.3-3 -2 Sheets 11 Table 11.3-4 11 Table 11.3-5 11 Table 11.3-6 11 Table 11.3-7 11 Table 11.3-8 11 Table 11.3-9 11 Table 11.3-10 11 Table 11.3-11 11 Table 11.3-12 11 Table 11.3-13 -2 Sheets 11 Table 11.3-14 -2 Sheets 11 Table 11.3-15 11 Table 11.3-16 11 Table 11.3-17 11 Table 11.3-18 11 Table 11.3-19 11 Table 11.3-20 11 Table 11.3-21 11 Table 11.3-22 11 Table 11.3-23 11 Table 11.3-24 11 Table 11.3-25 11 Table 11.3-26 11 Table 11.3-27 11 Table 11.3-28 11 Table 11.3-29 11 Table 11.3-30 11 Table 11.3-31 11 Table 11.3-32 11 Table 11.3-33 11 Table 11.3-34 11 Table 11.3-35 11 Table 11.3-36 11 Table 11.3-37 11 Table 11.3-38 11 Table 11.3-39 11 Table 11.3-40 11 Table 11.3-41 11 Table 11.3-42 11 Table 11.3-43 11 Table 11.3-44 11 Table 11.4-1 -6 Sheets 18 Table 11.4-3 11 Table 11.5-1 11 Table 11.5-2 -2 Sheets 11 Table 11.5-4 11 Table 11.5-5 19 Table 11.6-1 -2 Sheets 12 Table 11.6-4 -5 Sheets 18 Table 11.6-11 -2 Sheets 12 Table 11.6-13 11 Table 11.6-14 11 Figure 11.1-1 11 Figure 11.2-2 20 Figure 11.2-3 20 Figure 11.2-4 11 Figure 11.2-5 11 Figure 11.2-6 11 Figure 11.2-7 11 Figure 11.2-8 11 Figure 11.2-9 11 Figure 11.3-4 11 Figure 11.4-1 -2 Sheets 18 Figure 11.5-1 11 Figure 11.5-3 20 Figure 11.5-4 16 Figure 11.5-6 20 Figure 11.5-7 11 DCPP UNITS 1 & 2 FSAR UPDATE LIST OF CURRENT PAGES Page No. Rev. Page No. Rev. Page No. Rev. 9Revision 21 September 2013 Figure 11.5-8 11 Figure 11.5-9 11 Figure 11.5-10 11 Figure 11.5-11 11 Figure 11.5-12 11
CHAPTER 12 i thru v 21 12.1-1 thru 12.1-12 21 12.2-1 thru 12.2-11 19 12.3-1 thru 12.3-5 20 Table 12.1-1 11 Table 12.1-2 20 Table 12.1-3 11 Table 12.1-4 11 Table 12.1-5 11 Table 12.1-6 20 Table 12.1-7 11 Table 12.1-8 11 Table 12.1-9 11 Table 12.1-10 11 Table 12.1-11 -2 Sheets 11 Table 12.1-12 11 Table 12.1-13 11 Table 12.1-14 11 Table 12.1-15 -2 Sheets 12 Table 12.2-1 12 Table 12.2-2 12 Table 12.2-3 13 Table 12.2-4 13 Table 12.2-5 11 Table 12.2-6 11 Table 12.2-7 11 Table 12.2-8 11 Table 12.2-9 11 Table 12.2-10 11 Table 12.2-11 11 Table 12.2-12 11 Table 12.2-13 11 Table 12.2-14 11 Table 12.2-15 11 Table 12.2-17 15 Table 12.2-18 -3 Sheets 11 Table 12.3-1 -3 Sheets 16 Table 12.3-2 19 Table 12.3-3 16 Figure 12.1-1 11 Figure 12.1-2 11 Figure 12.1-3 11 Figure 12.1-4 11 Figure 12.1-5 11 Figure 12.1-6 11 Figure 12.1-7 11 Figure 12.1-8 11 Figure 12.1-9 11 Figure 12.1-10 11 Figure 12.1-11 12 Figure 12.1-12 11
CHAPTER 13 i thru v 21 13.1-1 thru 13.1-16 21 13.2-1 thru 13.2-6 21 13.3-1 11 13.4-1 20 13.5-1 thru 13.5-3 21 13.6-1 11 13.7-1 20 Table 13.2-1 -5 Sheets 11 Table 13.2-2 -2 Sheets 11 Figure 13.1-1A 21 Figure 13.1-1B 18 Figure 13.1-1C 21 Figure 13.1-3 20 Figure 13.1-4 20 Figure 13.1-5 19 Figure 13.1-6 19 Figure 13.2-1 11
CHAPTER 14 i thru iv 21 14.1-1 thru 14.1-11 15 14.2-1 thru 14.2-6 15 14.3-1 17 Table 14.1-1 -8 Sheets 18 Table 14.1-2 -6 Sheets 15 Figure 14.1-1 -5 Sheets 11
CHAPTER 15 i thru xl 21 15-1 thru 15-2 20 15.1-1 thru 15.1-15 20 15.2-1 thru 15.2-51 21 15.3-1 thru 15.3-15 21 15.4-1 thru 15.4-73 21 15.5-1 thru 15.5-66 19 Table 15.1-1 14 Table 15.1-2 19 Table 15.1-4 -4 Sheets 21 Table 15.2-1 -7 Sheets 19 Table 15.3-1 21 Table 15.3-2 19 Table 15.3-3 15 Table 15.4.1-1A 21 Table 15.4.1-1B 18 Table 15.4.1-2A 21 Table 15.4.1-2B 18 Table 15.4.1-3A -4 Shts 21 Table 15.4.1-3B -3 Shts 21 Table 15.4.1-4A 21 Table 15.4.1-4B 18 Table 15.4.1-5A -2 Shts 18 Table 15.4.1-5B 18 Table 15.4.1-7A -3 Shts 19 Table 15.4.1-7B -2 Shts 18 Table 15.4.8 -3 Sheets 21 Table 15.4-10 11 Table 15.4-11 15 Table 15.4-12 19 Table 15.4-13A 20 Table 15.4-13B 20 Table 15.4-14 21 Table 15.5-1 11 Table 15.5-2 11 Table 15.5-3 11 Table 15.5-4 11 Table 15.5-5 11 Table 15.5-6 11 Table 15.5-7 11 Table 15.5-8 11 Table 15.5-9 19 Table 15.5-10 -2 Sheets 12 Table 15.5-11 11 Table 15.5-12 19 Table 15.5-13 11 Table 15.5-14 11 Table 15.5-15 11 Table 15.5-16 11 Table 15.5-17 11 Table 15.5-18 11 Table 15.5-19 11 Table 15.5-20 11 Table 15.5-21 11 Table 15.5-22 11 Table 15.5-23 11 Table 15.5-24 -5 Sheets 12 Table 15.5-25 11 Table 15.5-26 11 Table 15.5-27 -2 Sheets 11 Table 15.5-28 -2 Sheets 11 Table 15.5-29 11 Table 15.5-30 11 Table 15.5-31 -2 Sheets 11 Table 15.5-32 -3 Sheets 12 Table 15.5-33 11 Table 15.5-34 19 DCPP UNITS 1 & 2 FSAR UPDATE LIST OF CURRENT PAGES Page No. Rev. Page No. Rev. Page No. Rev. 10Revision 21 September 2013 Table 15.5-40 11 Table 15.5-41 -2 Sheets 11 Table 15.5-42 19 Table 15.5-44 16 Table 15.5-45 -2 Sheets 17 Table 15.5-47 18 Table 15.5-48 -2 Sheets 18 Table 15.5-49 15 Table 15.5-50 18 Table 15.5-51 -2 Sheets 11 Table 15.5-52 11 Table 15.5-53 11 Table 15.5-56 11 Table 15.5-57 11 Table 15.5-61 11 Table 15.5-62 11 Table 15.5-63 19 Table 15.5-64 -2 Sheets 19 Table 15.5-65 19 Table 15.5-66 19 Table 15.5-67 16 Table 15.5-68 16 Table 15.5-69 18 Table 15.5-70 16 Table 15.5-71 19 Table 15.5-72 16 Table 15.5-74 19 Table 15.5-75 19 Figure 15.1-1 14 Figure 15.1-2 11 Figure 15.1-3 11 Figure 15.1-4 11 Figure 15.1-5 11 Figure 15.1-6 11 Figure 15.1-7 11 Figure 15.1-8 11 Figure 15.2.1-1 11 Figure 15.2.1-2 11 Figure 15.2.1-3 11 Figure 15.2.2-1 11 Figure 15.2.2-2 11 Figure 15.2.2-3 11 Figure 15.2.2-4 11 Figure 15.2.2-5 11 Figure 15.2.2-6 11 Figure 15.2.2-7 11 Figure 15.2.3-1 11 Figure 15.2.3-2 11 Figure 15.2.4-1 11 Figure 15.2.5-1 11 Figure 15.2.5-2 11 Figure 15.2.5-3 11 Figure 15.2.5-4 11 Figure 15.2.5-5 11 Figure 15.2.6-1 11 Figure 15.2.6-2 11 Figure 15.2.6-3 11 Figure 15.2.6-4 11 Figure 15.2.6-5 11 Figure 15.2.7-1 11 Figure 15.2.7-2 11 Figure 15.2.7-3 11 Figure 15.2.7-4 11 Figure 15.2.7-9 11 Figure 15.2.7-10 11 Figure 15.2.7-11 11 Figure 15.2.7-12 11 Figure 15.2.8-1 19 Figure 15.2.8-2 19 Figure 15.2.8-3 19 Figure 15.2.10-1 19 Figure 15.2.10-2 19 Figure 15.2.10-3 19 Figure 15.2.11-1 11 Figure 15.2.11-2 11 Figure 15.2.11-3 11 Figure 15.2.11-4 11 Figure 15.2.11-5 11 Figure 15.2.11-6 11 Figure 15.2.11-7 11 Figure 15.2.11-8 11 Figure 15.2.12-1 14 Figure 15.2.12-2 14 Figure 15.2.15-1 16 Figure 15.2.15-2 16 Figure 15.2.15-3 18 Figure 15.2.15-4 18 Figure 15.2.15-5 18 Figure 15.3-1 13 Figure 15.3-2 -2 Sheets 21 Figure 15.3-3 -2 Sheets 21 Figure 15.3-4 -2 Sheets 21 Figure 15.3-8 13 Figure 15.3-9 -2 Sheets 21 Figure 15.3-11 -2 Sheets 21 Figure 15.3-13 -2 Sheets 21 Figure 15.3-15 21 Figure 15.3-16 21 Figure 15.3-17 21 Figure 15.3-18 21 Figure 15.3-19 21 Figure 15.3-33 -2 Sheets 21 Figure 15.3-34 -2 Sheets 21 Figure 15.3-35 -2 Sheets 21 Figure 15.3-36 -2 Sheets 21 Figure 15.3-37 -2 Sheets 21 Figure 15.3-38 -2 Sheets 21 Figure 15.3-39 -2 Sheets 21 Figure 15.3-40 21 Figure 15.3-41 21 Figure 15.3.4-1 11 Figure 15.3.4-2 11 Figure 15.3.4-3 11 Figure 15.3.4-4 11 Figure 15.4.1-1A 18 Figure 15.4.1-1B 18 Figure 15.4.1-2A 18 Figure 15.4.1-2B 18 Figure 15.4.1-3A 18 Figure 15.4.1-3B 18 Figure 15.4.1-4A 18 Figure 15.4.1-4B 18 Figure 15.4.1-5A 18 Figure 15.4.1-5B 18 Figure 15.4.1-6A 18 Figure 15.4.1-6B 18 Figure 15.4.1-7A 18 Figure 15.4.1-7B 18 Figure 15.4.1-8A 18 Figure 15.4.1-8B 18 Figure 15.4.1-9A 18 Figure 15.4.1-9B 18 Figure 15.4.1-10A 18 Figure 15.4.1-10B 18 Figure 15.4.1-11A 18 Figure 15.4.1-11B 18 Figure 15.4.1-12A 18 Figure 15.4.1-12B 18 Figure 15.4.1-13A 18 Figure 15.4.1-13B 18 Figure 15.4.1-14A 18 Figure 15.4.1-14B 18 Figure 15.4.1-15A 18 Figure 15.4.1-15B 18 Figure 15.4.2-1 19 Figure 15.4.2-2 19 Figure 15.4.2-3 21 Figure 15.4.2-4 19 Figure 15.4.2-5 19 Figure 15.4.2-6 19 Figure 15.4.2-7 19 Figure 15.4.2-8 19 Figure 15.4.2-9 19 Figure 15.4.2-10 19 Figure 15.4.2-11 19 Figure 15.4.2-12 19 Figure 15.4.2-13 19 Figure 15.4.2-14 19 Figure 15.4.2-15 19 Figure 15.4.2-16 19 Figure 15.4.2-17 19 Figure 15.4.2-18 19 DCPP UNITS 1 & 2 FSAR UPDATE LIST OF CURRENT PAGES Page No. Rev. Page No. Rev. 11Revision 21 September 2013 Figure 15.4.2-19 19 Figure 15.4.2-20 19 Figure 15.4.2-21 19 Figure 15.4.3-1A 20 Figure 15.4.3-1B 21 Figure 15.4.3-2A 20 Figure 15.4.3-2B 21 Figure 15.4.3-3A 20 Figure 15.4.3-3B 21 Figure 15.4.3-4A 20 Figure 15.4.3-4B 21 Figure 15.4.3-5B 21 Figure 15.4.3-6A 20 Figure 15.4.3-6B 21 Figure 15.4.3-7A 20 Figure 15.4.3-7B 21 Figure 15.4.3-8A 20 Figure 15.4.3-8B 21 Figure 15.4.3-9 21 Figure 15.4.3-10 21 Figure 15.4.3-11 21 Figure 15.4.4-1 11 Figure 15.4.4-2 11 Figure 15.4.4-3 11 Figure 15.4.4-4 11 Figure 15.4.4-5 11 Figure 15.4.6-1 11 Figure 15.4.6-2 11 Figure 15.4.6-3 11 Figure 15.4.6-4 11 Figure 15.5-1 11 Figure 15.5-2 11 Figure 15.5-3 11 Figure 15.5-4 11 Figure 15.5-5 11 Figure 15.5-6 11 Figure 15.5-7 11 Figure 15.5-8 11 Figure 15.5-9 11 Figure 15.5-10 11 Figure 15.5-11 11 Figure 15.5-12 11 Figure 15.5-14 11 Figure 15.5-15 11 Figure 15.5-16 11 CHAPTER 16 i thru ii 21 16.1-1 19 Table 16.1-1 -3 Sheets 16
CHAPTER 17 i thru iv 21 17.1-1 thru 17.1-8 21 17.2-1 thru 17.2-9 21 17.3-1 thru 17.3-3 19 17.4-1 11 17.5-1 thru 17.5-3 19 17.6-1 19 17.7-1 thru 17.7-2 18 17.8-1 11 17.9-1 13 17.10-1 thru 17.10-2 17 17.11-1 11 17.12-1 15 17.13-1 11 17.14-1 11 17.15-1 17 17.16-1 17 17.17-1 thru 17.17-5 21 17.18-1 thru 17.18-4 21 Table 17.1-1 -13 Sheets 21 Figure 17.1-1 21 Figure 17.1-2 21 DCPP UNITS 1 & 2 FSAR UPDATE i Revision 21 September 2013 Chapter 1 INTRODUCTION AND GENERAL DESCRIPTION OF PLANT CONTENTS Section Title Page
1.1 INTRODUCTION
1.1-1
1.2 GENERAL PLANT DESCRIPTION 1.2-1
1.2.1 Principal Site Characteristics 1.2-1 1.2.1.1 Location 1.2-1 1.2.1.2 Topography 1.2-1 1.2.1.3 Meteorology 1.2-1 1.2.1.4 Hydrology 1.2-2 1.2.1.5 Geology 1.2-2 1.2.1.6 Seismology 1.2-2 1.2.1.7 Oceanography 1.2-3
1.2.2 Facility Description 1.2-3 1.2.2.1 Design Criteria 1.2-3 1.2.2.2 Nuclear Steam Supply System 1.2-4 1.2.2.3 Engineered Safety Features 1.2-4 1.2.2.4 Instrumentation and Control 1.2-6 1.2.2.5 Electrical Systems 1.2-6 1.2.2.6 Power Conversion System 1.2-6 1.2.2.7 Fuel Handling and Storage 1.2-7 1.2.2.8 Auxiliary Systems 1.2-7 1.2.2.9 Radioactive Wastes 1.2-7 1.2.2.10 Shared Facilities and Equipment 1.2-7
1.2.3 References 1.2-8
1.2.4 Reference Drawings 1.2-8
1.3 COMPARISON TABLES 1.3-1
1.3.1 Comparison with Similar Facility Designs 1.3-1
1.3.2 Comparison of Final and Preliminary Designs 1.3-1
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 1 CONTENTS (Continued) Section Title Page ii Revision 21 September 2013 1.4 IDENTIFICATION OF AGENTS AND CONTRACTORS 1.4-1 1.4.1 Consultants 1.4-1
1.4.2 Nuclear Steam Supply System Supplier 1.4-1
1.4.3 Other Equipment Suppliers 1.4-2
1.4.4 Construction and Installation Contractors 1.4-3
1.5 REQUIREMENTS FOR FURTHER TECHNICAL INFORMATION 1.5-1
1.6 MATERIAL INCORPORATED BY REFERENCE 1.6-1
1.6.1 Westinghouse Technical Reports 1.6-1
1.6.2 Miscellaneous Technical Reports 1.6-6 1.6.3 Drawings Incorporated By Reference 1.6-10 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 1 TABLES Table Title iii Revision 21 September 2013 1.3-1 Design Comparison of Diablo Canyon Power Plant Units 1 & 2, Zion Station, and Trojan Nuclear Plant 1.3-2 Major Design Changes Since the PSAR
1.4-1 Principal Consultants and Contract Description
1.4-2 Suppliers of Important Equipment and Materials Other than Nuclear Steam Supply System 1.4-3 Construction and Installation Contractors
1.5-1 Research and Development Programs 1.6-1 Controlled Engineering Drawings/FSAR Update Figures Cross Reference DCPP UNITS 1 & 2 FSAR UPDATE Chapter 1 FIGURES Figure Title iv Revision 21 September 2013 1.2-1 Plot Plan 1.2-2 Plant Layout
1.2-3(a) Area Location Plan 1.2-4(a) Auxiliary, Containment, and Fuel Handling Buildings (Units 1 & 2), Plan at Elevation 140 ft 1.2-5(a) Auxiliary, Containment, and Fuel Handling Buildings (Units 1 & 2), Plan at Elevation 115 ft 1.2-6(a) Auxiliary, Containment, and Fuel Handling Buildings (Units 1 & 2), Plan at Elevations 91 and 100 ft 1.2-7(a) Auxiliary and Containment Buildings (Units 1 & 2), Plan at Elevation 85 ft
1.2-8(a) Auxiliary and Containment Buildings (Units 1 & 2), Plan at Elevation 73 ft
1.2-9(a) Auxiliary and Containment Buildings (Unit 1 & 2), Plan at Elevations 60 and 64 ft
1.2-10(a) Containment Building (Unit 2), Plan at Elevations 115 and 140 ft 1.2-11(a) Containment & Fuel Handling Buildings (Unit 2), Plan at Elevations 85, 91, and 100 ft 1.2-12(a) Containment Building (Unit 2), Plan at Elevations 60, 64, and 73 ft 1.2-13(a) Turbine Building (Unit 1), Plan at Elevation 140 ft 1.2-14(a) Turbine Building (Unit 1), Plan at Elevation 119 ft 1.2-15(a) Turbine Building (Unit 1), Plan at Elevation 104 ft 1.2-16(a) Turbine Building (Unit 1), Plan at Elevation 85 ft 1.2-17(a) Turbine Building (Unit 2), Plan at Elevation 140 ft DCPP UNITS 1 & 2 FSAR UPDATE Chapter 1 FIGURES Figure Title v Revision 21 September 2013 1.2-18(a) Turbine Building (Unit 2), Plan at Elevation 119 ft 1.2-19(a) Turbine Building (Unit 2), Plan at Elevation 104 ft 1.2-20(a) Turbine Building (Unit 2), Plan at Elevation 85 ft 1.2-21(a) Auxiliary Building (Units 1 & 2), Section A-A 1.2-22(a) Auxiliary and Containment Buildings (Unit 1 & 2), Section B-B 1.2-23(a) Auxiliary and Fuel Handling Buildings (Unit 1 & 2), Section C-C 1.2-24(a) Containment, Turbine, and Fuel Handling Buildings (Unit 1) Section D-D 1.2-25(a) Auxiliary, Turbine, and Fuel Handling Buildings (Unit 1), Section E-E 1.2-26(a) Auxiliary, Fuel Handling, and Turbine Buildings (Units 1 & 2), Section F-F 1.2-27(a) Turbine Building (Unit 1), Section G-G 1.2-28(a) Containment Building (Unit 2), Section A-A 1.2-29(a) Vent & Fuel Handling Buildings (Unit 2), Section B-B 1.2-30(a) Turbine, Containment, & Fuel Handling Buildings (Unit 2), Section C-C 1.2-31(a) Turbine Building (Unit 2), Sections D-D and E-E 1.2-32(a) Turbine Building (Unit 2), Section F-F NOTE:
(a) This figure corresponds to a controlled engineering drawing that is incorporated by reference into the FSAR Update. See Table 1.6-1 for the correlation between the FSAR Update figure number and the corresponding controlled engineering drawing number.
DCPP UNITS 1 & 2 FSAR UPDATE 1.1-1 Revision 18 October 2008 CHAPTER 1 INTRODUCTION AND GENERAL DESCRIPTION OF PLANT
1.1 INTRODUCTION
The Final Safety Analysis Report (FSAR) Update for the Diablo Canyon Power Plant (DCPP) is submitted in accordance with the requirements of 10 CFR 50.71(e) and contains all the changes necessary to reflect information and analyses submitted to the U.S. Nuclear Regulatory Commission (NRC) by Pacific Gas and Electric Company (PG&E) or prepared by PG&E pursuant to NRC requirements since the submittal of the original FSAR. The original FSAR was submitted in support of applications for permits to operate two substantially identical nuclear power units (Unit 1 and Unit 2) at the DCPP site. The DCPP site is located on the central California coast in San Luis Obispo County, approximately 12 miles west southwest of the city of San Luis Obispo.
The Construction Permit for Unit 1 (CPPR-39) was issued April 23, 1968, in response to PG&E's application dated January 16, 1967 (USAEC, Docket No. 50-275). The Construction Permit for Unit 2 (CPPR-69) was issued on December 9, 1970; the application was made on June 28, 1968 (USAEC, Docket No. 50-323).
Westinghouse Electric Corporation and PG&E jointly participated in the design and construction of each unit. The plant is operated by PG&E. Each unit employs a pressurized water reactor (PWR) nuclear steam supply system (NSSS) furnished by Westinghouse Electric Corporation and similar in design concept to several projects licensed by the NRC. Certain components of the auxiliary systems are shared by the two units, but in no case does such sharing compromise or impair the safe and continued operation of either unit. Those systems and components that are shared are identified and the effects of the sharing are discussed in the chapters in which they are described. The NSSS for each unit is contained within a steel-lined reinforced concrete structure that is capable of withstanding the pressure that might be developed as a result of the most severe postulated loss-of-coolant (LOCA) accident. The containment structure was designed by PG&E to meet the requirements specified by Westinghouse Electric Corporation.
While the reactors, structures, and all auxiliary equipment are substantially identical for the two units, there is a difference in the reactor internal flow path that results in a lower coolant flow rate for Unit 1. Consequently, the original license application reactor ratings were 3,338 MWt for Unit 1 and 3,411 MWt for Unit 2. The corresponding net electrical outputs were approximately 1,084 MWe and 1,106 MWe, respectively.
During the design phase, the expected ultimate output of the Unit 1 reactor was 3,488 MWt; the expected ultimate output of the Unit 2 reactor was 3,568 MWt. The corresponding NSSS outputs were 3,500 MWt and 3,580 MWt. (The difference of 12 MWt is due to the net contribution of heat to the reactor coolant system from DCPP UNITS 1 & 2 FSAR UPDATE 1.1-2 Revision 18 October 2008 nonreactor sources, primarily pump heat.) The corresponding estimated ultimate net electrical outputs were 1,131 MWe for Unit 1 and 1,156 MWe for Unit 2.
The NRC issued a low power-operating license for Unit 1 on September 22, 1981. PG&E voluntarily postponed fuel loading due to the discovery of design errors in the annulus region of the containment structure. Subsequently, the NRC suspended portions of the license on November 19, 1981, pending completion of an Independent Design Verification Program.
After completion of redesign and construction activities in November 1983, the NRC reinstated the fuel load portion of the Unit 1 low power-operating license. On April 19, 1984, the NRC fully reinstated the low power-operating license, which included low power testing. The Unit 1 full power-operating license was issued on November 2, 1984. Commercial operation for Unit 1 began on May 7, 1985, with a license expiration date of April 23, 2008.
The NRC issued a low power-operating license for Unit 2 on April 26, 1985. Unit 2 fuel loading was completed on May 15, 1985. A full power-operating license for Unit 2 was issued on August 26, 1985. Unit 2 commercial operation began on March 13, 1986, with a license expiration date of December 9, 2010.
In March 1996, the NRC approved license amendments extending the operating license for Unit 1 until September 22, 2021, and for Unit 2 until April 26, 2025.
In July 2006, the NRC approved license amendments extending the operating license for Unit 1 until November 2, 2024, and for Unit 2 until August 26, 2025. In October 2000, the NRC approved a license amendment (LA) 143 to increase the Unit 1 rated reactor thermal power from the original value of 3,338 MWt to 3,411 MWt to increase production and be consistent with Unit 2. LA 143 also documented the evaluation performed to revise the net contribution of heat to the reactor coolant system from nonreactor sources (primarily pump heat) to a nominal value of 14 MWt and established a NSSS power outlet of 3,425 MWt for both Unit 1 and Unit 2.
DCPP UNITS 1 & 2 FSAR UPDATE 1.2-1 Revision 21 September 2013 1.2 GENERAL PLANT DESCRIPTION 1.2.1 PRINCIPAL SITE CHARACTERISTICS 1.2.1.1 Location The DCPP site consists of approximately 750 acres located in San Luis Obispo County, California, adjacent to the Pacific Ocean and roughly equidistant from San Francisco and Los Angeles. The site location, the site boundary, and the location of principal structures are shown in Figure 1.2-1. The minimum distance from either reactor to the nearest site boundary on land is one-half mile, the minimum exclusion distance. The low population zone (LPZ), as defined in 10 CFR 100, is the area immediately surrounding the exclusion area. For DCPP, the LPZ is an area encompassed by a radius of 6.2 miles. This zone contains residents for whom there is reasonable probability that appropriate protective measures, as described in the DCPP Emergency Plan (Reference 1) can be taken in the event of a serious accident. The population center distance, as defined by 10 CFR 100, is approximately 10 miles, the distance to the nearest boundary of the city of San Luis Obispo. 1.2.1.2 Topography The plant site occupies a coastal terrace that ranges in elevation from 60 to 150 feet above sea level and is approximately 1000 feet wide. Plant grade is at elevation 85 feet. The seaward edge of the terrace is a near-vertical cliff. Back from the terrace and extending for several miles inland are the rugged Irish Hills, an area of steep, brush-covered hillsides and deep canyons that are part of the San Luis Mountains and attain an elevation of 1500 feet within about a mile of the site. Access to the site is by a private road from Avila Beach, a distance of nearly 8 miles. 1.2.1.3 Meteorology The climate of the site area is typical of that along the central California coast. In the dry season, mainly May through September, the Pacific Anticyclone stays off the California coast and prevents Pacific storms from moving eastward across the state. In the winter or wet season, November through March, the Pacific Anticyclone moves southward, weakening in intensity, and allows Pacific storms to enter the state. More than 80 percent of the average annual rainfall of 16 inches occurs during this 5-month period. April and October are considered transitional months. The average annual temperature of the site area is about 55°F, which reflects the strong maritime influence.
Most stations along the coast show a 5 to 10°F mean temperature difference between the coldest winter month and the warmest summer month. Extreme temperatures may range from 104°F in the summer to as low as 24°F in the winter. However, the recurrence interval of days having these extremes is in the order of 5 to 10 years. Maximum summer temperatures of 85°F and minimum winter temperatures of 35°F are exceeded only 1 percent of the time at both Morro Bay and Pismo Beach. Additional DCPP UNITS 1 & 2 FSAR UPDATE 1.2-2 Revision 21 September 2013 site temperature data are presented in Section 2.3. The onsite meteorological measurements program was initiated in July 1967. Data collected are presented in Section 2.3 and are used to establish atmospheric diffusion characteristics of the site. Severe weather conditions, such as tornadoes and hurricanes, have not been recorded in this area. Thunderstorms are also a rare phenomenon with the average occurrence of lightning being less than 3 days per year. 1.2.1.4 Hydrology Hydrological considerations at the plant site are limited to possible effects of plant operations on domestic water supplies and to the possibility of flooding. A survey of domestic water supplies in the environs shows that operation of the plant will not jeopardize any existing or planned facility. The topography of the site and the limited rainfall preclude any possibility of flooding. 1.2.1.5 Geology A comprehensive geological investigation has demonstrated that the site is geologically suitable for a nuclear power plant. Foundations are on firm bedrock fully capable of carrying the loads. Movement along the few small breaks in the vicinity of the plant has not occurred for at least 100,000 years and may well have taken place millions of years ago. The site was investigated in detail for faulting and other possibly detrimental geologic conditions. Results of faulting investigations are discussed in Section 2.5.3.7 and are based on site geology data presented in Section 2.5.1.2. Landslides do not threaten the plant.
1.2.1.6 Seismology Seismological investigations were undertaken to determine the potential for earthquakes in the site area, to form a basis of the establishment of seismic design criteria, and to evaluate the adequacy of seismic design margins for the plant (Section 2.5). Records indicate that seismic activity within 20 miles of Diablo Canyon has been very low compared to other parts of California. Until PG&E's seismological investigation of the Hosgri fault zone located approximately 3 miles offshore, the seismically significant fault system nearest the site was considered to be the Nacimiento Fault located about 20 miles away as discussed in Section 2.5.2.9. The largest earthquake known to have been associated with this fault system occurred at an epicentral distance to the site of about 44 miles. It is listed with a Richter magnitude 6. At its closest point, the San Andreas Fault passes some 48 miles from the site.
PG&E's reevaluation of the plant's capability to withstand a postulated Richter magnitude 7.5 "Hosgri" earthquake is discussed in Section 3.7.
DCPP UNITS 1 & 2 FSAR UPDATE 1.2-3 Revision 21 September 2013 1.2.1.7 Oceanography Condenser cooling water for the plant is pumped from the Pacific Ocean and returned to the ocean at Diablo Cove through an outfall at the water's edge. Controlled releases of low-level liquid radioactive wastes are discussed in Section 11.2. The Pacific Ocean in the area of the site is turbulent and has a great capacity for dilution of wastes and diffusion of heated cooling water. Investigations of the occurrence and maximum size of tsunamis (seismic sea waves) coincident with high tide and with short period storm waves are discussed in Design Criteria Memorandum T-9, Appendix A. These studies showed that extreme water elevation within the intake basin without a breakwater would be 44.32 feet above mean lower low water. The intake structure houses the safety-related auxiliary cooling water systems, which are protected against tsunami and wave splash with watertight compartments. This is discussed in Section 2.4.5.7. 1.2.2 FACILITY DESCRIPTION The plant incorporates two substantially identical PWR nuclear power units, each consisting of an NSSS, turbine-generator, auxiliary equipment, controls, and instrumentation. The general arrangement of the plant and the site is shown in Figure 1.2-1. Principal structures, shown in Figure 1.2-2, include the containment structures, turbine building, and auxiliary building (which includes the control room, the fuel handling areas, and the ventilation areas). Arrangement plans and sections are shown in Figures 1.2-3 through 1.2-32. The descriptions that follow apply to both units unless otherwise specified. 1.2.2.1 Design Criteria The principal design criteria for the DCPP nuclear units are those fundamental architectural and engineering design objectives established for the plant. The bases for development and selection of the design criteria used in this plant are: (a) those that provide protection to public health and safety, (b) those that provide for reliable and economic plant performance, and (c) those that provide an attractive external appearance to the plant.
The essential systems and components of the plant are designed to enable the facility to withstand, without loss of capability to protect the public, the forces resulting from normal operation plus those that might be imposed by natural phenomena. The designs are based on the most severe of the natural phenomena recorded for the vicinity of the site, with margin to account for uncertainties in the historical data.
The DCPP units are designed to comply with the "General Design Criteria for Nuclear Power Plant Construction Permits," published in July 1967. A discussion of conformance to these criteria is contained in Section 3.1. In addition, a summary discussion of the designs and procedures that are intended to meet the NRC General Design Criteria published as Appendix A to 10 CFR 50 in 1971 is provided in Chapter 3, Section 3.1, Appendix 3.1A. DCPP UNITS 1 & 2 FSAR UPDATE 1.2-4 Revision 21 September 2013 1.2.2.2 Nuclear Steam Supply System The NSSS consists of a PWR and associated auxiliary fluid systems. The reactor coolant system (RCS) consists of four parallel reactor coolant loops, each containing a steam generator and a reactor coolant pump. A pressurizer is connected to the hot leg of one reactor coolant loop.
The reactor core is composed of an array of 193 fuel assemblies, each containing 264 fuel rods. These rods are composed of uranium dioxide pellets enclosed in zirconium alloy tubes with welded end plugs. All fuel rods are pressurized with helium during fabrication to reduce stress and increase fatigue life. Reactor control and shutdown functions are performed by the rod cluster control assemblies (RCCAs). The RCCAs are stainless steel tubes containing a silver-indium-cadmium absorber and are positioned by drive mechanisms of the magnetic latch type. A soluble poison (boron) is introduced into the reactor coolant to compensate for long-term reactivity changes. The moderator temperature coefficient can be slightly positive at the beginning of cycle when boron concentration is high. However, for most operating conditions, the moderator coefficient is non-positive, but the power coefficient is negative at all times.
The reactor vessel and reactor internals contain and support the fuel and RCCAs. The vessel is cylindrical with hemispherical heads and is clad with stainless steel.
The pressurizer is a vertical cylindrical pressure vessel with hemispherical heads and is equipped with electrical heaters and spray nozzles for system pressure control.
The steam generators are vertical U-tube type heat exchangers with Inconel tubes. Reactor coolant flows inside the tubes; steam is generated in the shell and flows through the main steam lines to the turbine. When operating at 100 percent power, integral moisture separating equipment reduces moisture content of the steam at the exit of the steam generators to 0.05 percent. Under transient conditions at 100 percent power, the moisture content at the exit of the steam generators is <0.25 percent. The reactor coolant pumps are vertical, single-stage, centrifugal units equipped with controlled leakage shaft seals.
Auxiliary systems are provided to charge the RCS and add makeup water, to purify reactor coolant water, to provide chemicals for corrosion inhibition and reactor control, to cool system components, to remove residual heat when the reactor is shut down, to cool the spent fuel storage pool, to sample reactor coolant water, to provide for emergency safety injection, and to vent and drain the RCS. 1.2.2.3 Engineered Safety Features The engineered safety features (ESFs) provided for the DCPP have sufficient capacity and redundancy to protect the health and safety of the public by keeping exposure below the limits set forth in 10 CFR 100 for any postulated malfunction or accident, including the most severe LOCA. DCPP UNITS 1 & 2 FSAR UPDATE 1.2-5 Revision 21 September 2013 The ESFs provided in the DCPP are: (1) A containment system that consists primarily of a steel-lined, reinforced concrete containment structure designed to prevent significant release to the environs of radioactive materials that could result from accidents inside the containment (Sections 6.2.1 and 6.2.4). (2) An emergency core cooling system (ECCS) that provides water to cool the core in the event of an accidental loss of primary reactor coolant water. The ECCS also supplies dissolved boron into the cooling water to provide shutdown margin (Section 6.3). (3) A containment spray system (CSS) to help limit the peak pressure in the containment in the event of a major release of pressurized water from the primary coolant system (Section 6.2.2). (4) A containment fan cooler system that also functions to limit the pressure in the containment structure in the event of an accidental release of primary coolant water (Section 6.2.2). (5) A containment spray additive system that functions by adding sodium hydroxide, an effective iodine scrubbing solution, to the CSS water, thus reducing the content of iodine and other fission products in the containment atmosphere (Section 6.2.3). (6) Reduction in the long term buildup of gaseous hydrogen in the containment following a LOCA is assured primarily by internal hydrogen recombiners, supplemented by the containment hydrogen purge system and a provision to add external recombiners, if necessary (Section 6.2.5). (7) A fuel handling area heating and ventilating system consisting of fans, high-efficiency particulate air filters, and charcoal filters, provides a significant reduction in the amounts of volatile radioactive materials that could be released to the atmosphere in the event of a major fuel handling accident (Section 9.4.4). (8) An auxiliary building ventilating system that provides the capability for significant reduction in the amounts of volatile radioactive materials that could be released to the atmosphere in the event of leakage from the residual heat removal (RHR) circulation loop following a LOCA (Section 9.4.2). (9) A control room heating and ventilation system provides the capability to control the volatile radioactive material that could enter the control room atmosphere in the event of a LOCA (Section 6.4 and 9.4.1). DCPP UNITS 1 & 2 FSAR UPDATE 1.2-6 Revision 21 September 2013 (10) An auxiliary feedwater system supplies water to the secondary side of the steam generators for reactor decay heat removal, when the normal feedwater system is unavailable (Section 6.5). 1.2.2.4 Instrumentation and Control The primary purpose of the instrumentation and control system is to provide automatic protection against unsafe and improper reactor operation during steady state and transient power operation (ANS Conditions I, II, and III) and to provide initiating signals to mitigate the consequences of faulted conditions (ANS Condition IV). These plant conditions are discussed in Chapter 15, Accident Analysis.
The operation of the plant is monitored and controlled by operators in the control room, which is located in the auxiliary building. 1.2.2.5 Electrical Systems The electrical systems generate and transmit power to PG&E's high-voltage system, distribute power to the auxiliary loads, and provide control, protection, instrumentation, and annunciator power supplies for the units. Power is generated at 25 kV. Auxiliary loads are served at 12 kV, 4.16 kV, 480 V, 120 Vac, 125 Vdc, and 250 Vdc.
Offsite ac power for the units' auxiliaries is available from two 230-kV transmission circuits and three 500-kV transmission circuits.
Onsite ac auxiliary power is supplied by each unit's main generator and is also available for vital loads from six diesel engine-driven generators. Three diesel generators are dedicated to each unit.
Onsite dc power is provided by three vital and two nonvital 125-V batteries in each unit. The two nonvital batteries are connected in series to provide 250-Vdc power in each unit. 1.2.2.6 Power Conversion System The turbines are each tandem-compound, four-element, 1800 rpm units, having one high-pressure and three identical double flow low-pressure elements. Combination moisture separator-reheaters are employed between the high- and low-pressure elements to dry and superheat the steam. The auxiliaries include deaerating surface condensers, steam jet air ejectors, motor-driven condensate pumps, motor-driven condensate booster pumps, turbine-driven main feedwater pumps, six stages of feedwater heating, and a full flow condensate demineralizer system.
The steam and power conversion system is designed to receive the heat generated by the RCS during normal power operation, as well as following an emergency shutdown DCPP UNITS 1 & 2 FSAR UPDATE 1.2-7 Revision 21 September 2013 of the turbine-generator from full load. Heat rejection under the latter condition is accomplished by steam bypass to the condenser and pressure relief to the atmosphere. 1.2.2.7 Fuel Handling and Storage The reactor is refueled using equipment designed to handle spent fuel under water from the time it leaves the reactor vessel until it is placed in a cask either for transport to the Diablo Canyon Independent Spent Fuel Storage Installation or for shipment from the site. Underwater transfer of spent fuel provides an optically transparent radiation shield, as well as a reliable source of coolant for removal of decay heat. Spent fuel is stored onsite in the spent fuel pools, which are fitted with special spent fuel storage racks to ensure that criticality cannot be approached. The fuel handling system also provides capability for receiving, handling, and storing new fuel assemblies. 1.2.2.8 Auxiliary Systems Auxiliary systems are supporting systems included in the facility, some of which are required to perform certain functions during emergency or accident conditions. Included are the cooling water systems, the heating and ventilating systems, the fire protection system, the process auxiliaries, the compressed air system, the diesel generator fuel oil system, the communication systems, and the lighting systems. 1.2.2.9 Radioactive Wastes The radioactive waste treatment systems provide all equipment necessary to collect, process, monitor, and discharge radioactive liquid, gaseous, and solid wastes that are produced during reactor operation. A major portion of the waste treatment equipment is common for Units 1 and 2. This equipment is located in the shared auxiliary building. 1.2.2.10 Shared Facilities and Equipment Separate systems and equipment are provided for each unit, with few exceptions. A brief summary of shared facilities and equipment between both units follows. Interconnections between systems for Unit 1 and Unit 2 are shown in the system diagrams. The system diagrams are contained in the FSAR Update chapters referenced in the following paragraphs. 1.2.2.10.1 Site Facilities The two units share a common auxiliary building. The turbine building is common to both units. The machine shop, access control area, warehouse area, telecommunications systems, and administrative offices are common.
The two units also share a common raw water storage reservoir, fire pumps, fire water storage tank, diesel fuel oil storage tanks and transfer pumps, auxiliary boiler, makeup water system, plant air system, and lubricating oil storage system. DCPP UNITS 1 & 2 FSAR UPDATE 1.2-8 Revision 21 September 2013 1.2.2.10.2 Electrical Systems The 230-kV line from the 230-kV switchyard serves the standby/startup transformers for both Units 1 and 2. These are normally arranged on the low voltage sides to serve a single unit; however, the 12-kV buses for Units 1 and 2 are connected by an open circuit breaker.
The plant has six diesel generator sets for emergency power. 1.2.2.10.3 Control Room The plant is provided with a central control room located in the auxiliary building which is common to Units 1 and 2. Physical separation of control panels prevents interaction of the Unit 1 and Unit 2 control systems. 1.2.2.10.4 Chemical and Volume Control System Several components of the chemical and volume control system are shared, as detailed in Chapter 9. 1.2.2.10.5 Radioactive Waste Treatment Systems The major portion of the waste treatment equipment is shared by Units 1 and 2. This equipment is located in the shared auxiliary building and is described in Chapter 11. 1.2.2.10.6 Emergency Facilities and Equipment The emergency facilities and equipment, both onsite and offsite, are discussed in the Emergency Plan which applies to both Units 1 and 2. 1.
2.3 REFERENCES
- 1. Emergency Plan, Diablo Canyon Power Plant - Units 1 and 2, Pacific Gas and Electric Company. 1.2.4 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures.
DCPP UNITS 1 & 2 FSAR UPDATE 1.3-1 Revision 11 November 1996 1.3 COMPARISON TABLES 1.3.1 COMPARISON WITH SIMILAR FACILITY DESIGNS Table 1.3-1 presents a comparison of the principal similarities and differences of the design of the DCPP units with those of Unit 1 at Trojan Nuclear Power Plant and Units 1 and 2 at Zion Station. This comparison is historical in nature and is valid only through March 1984. 1.3.2 COMPARISON OF FINAL AND PRELIMINARY DESIGNS Table 1.3-2 identifies the major design changes made since the submittal of the DCPP Unit 2 Preliminary Safety Analysis Report. The comparison was considered to be valid through July 1974.
DCPP UNITS 1 & 2 FSAR UPDATE 1.4-1 Revision 15 September 2003 1.4 IDENTIFICATION OF AGENTS AND CONTRACTORS PG&E is the architect engineer, constructor, operator, and owner of DCPP and, as such, assumes full responsibility and authority for the design, construction, startup, and operation of Diablo Canyon Units 1 and 2. This section identifies the principal consultants, the nuclear steam system supplier, the suppliers of other equipment affecting nuclear safety, and the principal contractors engaged in the construction of the units. PG&E has performed all work for the planning, design, estimating, procurement, construction, installation, inspection, testing, and associated services necessary to provide complete plans and specifications and related services necessary to furnish a complete, operable, and acceptable plant, except for those items and functions that were furnished by those mentioned below. 1.4.1 CONSULTANTS The consultants whose contracts exceed one hundred thousand dollars are listed in Table 1.4-1. The list is historical in nature and is valid only through March 1986. They performed investigations and submitted reports and recommendations to PG&E on the subjects indicated in the table. Application of the material submitted is the responsibility of PG&E. 1.4.2 NUCLEAR STEAM SUPPLY SYSTEM SUPPLIER The NSSS was designed and furnished by the Westinghouse Electric Corporation. Westinghouse performed the detailed engineering design for all Westinghouse-supplied components and systems of the NSSS and procured, expedited, inspected, and delivered to PG&E all such equipment and components. Westinghouse provided design criteria, outline and/or assembly drawings, systems flow diagrams, and other data, as required, for PG&E to install, erect, operate, and maintain Westinghouse-supplied equipment and components. For all Westinghouse-supplied nuclear auxiliary systems, Westinghouse performed systems engineering, prepared reference designs and systems descriptions, and provided overall operating and engineering instructions.
Westinghouse further provided pertinent design criteria and data on the NSSS to enable PG&E to design the balance of plant. Westinghouse provided functional test procedures and technical assistance during construction, installation, inspections, and testing of its equipment and systems. A description of Westinghouse-provided technical assistance is given in Chapter 14, Initial Tests and Operations.
Westinghouse also performed the post-accident transient analysis of the plant containment system. This analysis consisted of determining the mass and energy releases (including metal-water reaction) as a function of time for the design basis LOCA and main steam line break. From the foregoing data, PG&E has determined the design pressure and temperature, containment volume cooling requirements, etc. In general, Westinghouse has performed such transient analyses on the plant as are required for the Westinghouse-furnished NSSS and turbine-generator unit. Transient DCPP UNITS 1 & 2 FSAR UPDATE 1.4-2 Revision 15 September 2003 analyses involving non-Westinghouse-supplied systems and components are PG&E's responsibility.
Westinghouse also supplied material that is informational in nature, some of which appears in response to questions asked of Westinghouse during review meetings. Other information and recommendations have been offered by Westinghouse from their background experience. This type of material is not contractually binding for either company, nor was it intended to be a commitment of final design or operation. This material includes:
(1) The conceptual design of the dry reactor containment system. The specific designs of the reactor containment structure and associated ESFs are developed by PG&E. (2) The details of a recommended waste disposal system that consists of equipment to collect, process, and dispose of radioactive liquid, gaseous, and solid wastes produced as a result of reactor operation (3) Five recommended ESFs that consist of: steel-lined concrete reactor containment vessel, the safety injection system, the containment fan coolers, the containment spray equipment, and the air recirculation filters.
Emergency power systems to operate the ESF systems are also as recommended by Westinghouse. (4) The details of the recommended fuel handling facilities including structures, equipment, transfer, and operation (5) The details of the recommended sampling system and analytical facilities (6) The details of the recommended radiation shielding (7) The outline of a recommended health physics program and recommended supplies (8) The general criteria and preliminary design data for certain balance of plant. Westinghouse, as a supplier to PG&E, is required to conform to the PG&E Quality Assurance Program as described in Chapter 17, Quality Assurance. 1.4.3 OTHER EQUIPMENT SUPPLIERS Suppliers of important equipment or materials furnished to PG&E are listed in Table 1.4-2. In each case, the equipment was fabricated, or the material supplied qualified, to written specifications and, if Design Class I, under the Quality Assurance DCPP UNITS 1 & 2 FSAR UPDATE 1.4-3 Revision 15 September 2003 Program in effect at the time of purchase. This list of suppliers is historical in nature and is valid only through March 1986. 1.4.4 CONSTRUCTION AND INSTALLATION CONTRACTORS The principal construction and installation contractors whose contracts exceed one hundred thousand dollars are listed in Table 1.4-3. The list of contractors is historical in nature and is valid only through March 1986. The contracts are agreements between PG&E as owner-constructor and the contractors as independent contractors, with specific provisions for inspection, testing, and quality assurance.
Each contract specification identifies any Design Class I equipment involved and requires the implementation of the supplier's Quality Assurance Program (see Chapter 17, Quality Assurance). In addition, PG&E maintains a staff of inspectors to assure the quality of non-Class I equipment installation.
DCPP UNITS 1 & 2 FSAR UPDATE 1.5-1 Revision 11 November 1996 1.5 REQUIREMENTS FOR FURTHER TECHNICAL INFORMATION The design of DCPP is based on proven concepts, systems, and equipment in order to minimize the potential for cost and schedule overruns and to enhance the reliability of operation. As a consequence, there have been few requirements for research and development programs to confirm the adequacy of the design. Those programs identified for DCPP have been satisfactorily completed, as well as any other programs that have been identified as valuable to define margins of conservatism or possible design improvements. Table 1.5-1 is a list of those programs that have been addressed in earlier revisions of the original FSAR. This table provides a listing of the technical reports that include a discussion the programs and their results. The listing is historical in nature and is valid only through November 1975.
DCPP UNITS 1 & 2 FSAR UPDATE 1.6-1 Revision 18 October 2008 1.6 MATERIAL INCORPORATED BY REFERENCE 1.6.1 WESTINGHOUSE TECHNICAL REPORTS Date Section Submitted Title Reference To AEC 1. C. J. Kubit, Safety-Related Research and Development for Westinghouse Pressurized Water Reactors, Program Summaries-Fall, 1971-Spring, 1972, WCAP-7856, April 1972. 1.5 5/9/72 2. F. T. Eggleston, Safety-Related Research and Development for Westinghouse PWRs, Program Summaries. Winter 77 - Summer 78, WCAP-8768, Rev. 2, October 1978. 1.5 10/78 3. R. M. Hunt, Safety-Related Research and Development for Westinghouse PWRs, Program Summaries. Fall 1970, WCAP-7614-L, November 1970. 1.5 11/70 4. R. M. Hunt, Safety-Related Research and Development for Westinghouse PWRs, Program Summaries. Spring 1970, WCAP-7498-L, May 1970. 1.5 5/70 5. M. D. Davis, Safety-Related Research and Development for Westinghouse PWRs, Program Summaries. Fall 1974, WCAP-8485, March 1975. 1.5 3/75 6. C. J. Kubit, Safety-Related Research and Development for Westinghouse PWRs, Program Summaries. Spring 1974, WCAP-8385, July 1974. 1.5 7/74 7. C. J. Kubit, Safety-Related Research and Development for Westinghouse PWRs, Program Summaries. Spring 1972, WCAP-7856, May 1972. 1.5 5/72 8. J. M. Hellman, Fuel Densification Experimental Results and Model for Reactor Operation, WCAP-8218-P-A, March 1975 (Proprietary) and WCAP-8219-A, March 1975 (Non-Proprietary). 1.5 3/75 9. L. Geninski, et al, Safety Analysis of the 17 x 17 Fuel Assembly for Combined Seismic and Loss-of-Coolant Accident, WCAP-8288, December 1973. 1.5 12/73 DCPP UNITS 1 & 2 FSAR UPDATE 1.6-2 Revision 18 October 2008 Date Section Submitted Title Reference To AEC 10. E. E. DeMario and S. Nakazato, Hydraulic Flow Test of the 17 x 17 Fuel Assembly, WCAP-8279, February 1974. 1.5 2/74 11. F. W. Cooper, Jr., 17 x 17 Drive Line Components Test - Phase IB, II, III - Drop and Deflection, WCAP-8446, December 1974. 1.5 12/74 12. K. W. Hill, et al, Effect of 17 x 17 Fuel Assembly Geometry on DNB, WCAP-8396-P-A, Feb. 1975 (Proprietary) and WCAP-8297-A, February 1975. 1.5 2/75 13. Motley, F. W., et al, The Effect of 17 x 17 Fuel Assembly Geometry on Interchannel Thermal Mixing, WCAP-8298-P-A (Proprietary) and WCAP-8299-A, January 1975. 1.5 1/75 14. A. J. Burnett and S. D. Kopelic, Westinghouse ECCS Evaluation Model October 1975 Version, WCAP-8622 (Proprietary) and WCAP-8623 (Non-Proprietary), November 1975. 1.5 11/75 15. Irradiation of 17 x 17 Demonstration Assemblies in Surry Units No.1 and 2, Cycle 2, WCAP-8262, July 1974. 1.5 7/74 16. G.J. Bohm, Indian Point Unit 2 Internals Mechanical Analysis for Blowdown Exitation, WCAP-7822, December 1971. 3.9 12/20/71 17. P. M. Wood, et al, Use of Burnable-Poison Rods in Westinghouse Pressurized Water Reactors, WCAP-7113, October 1967. 3.9 11/6/67 18. R. F. Barry, et al, Power Distribution Monitoring in the R. E. Ginna PWR, WCAP-7756, September 1971. 3.9 10/5/71 19. L. T. Gesinski, Fuel Assembly Safety Analysis for Combined Seismic and Loss-of-Coolant Accident, WCAP-7950, July 1972. 3.9 7/14/72 20. S. Fabic, Description of the BLODWN-2 Computer Code, WCAP-7918, Rev. 1, October 1970. 3.9 10/70 DCPP UNITS 1 & 2 FSAR UPDATE 1.6-3 Revision 18 October 2008 Date Section Submitted Title Reference To AEC 21. S. Fabic, Loss-of-Coolant Analysis: Comparison Between BLODWN-2 Code Results and Test Data, WCAP-7401, November 1969. 3.9 2/5/70 22. S. Kraus, Neutron Shielding Pads, WCAP-7870 including Appendix B, February 1972. 4.2 2/17/72 23. C. M. Friedrich and W. H. Guilinger, CYGLO-Z, A Fortran IV Computer Program for Stress Analysis of the Growth of Cylindrical Fuel Elements with Fission Gas Bubbles, WCAP-TM-574, November 1966. 4.2 11/66 24. A. F. McFarlane, Power Peaking Factors: WCAP-7912L, June 1972 (Westinghouse Proprietary) and WCAP-7912, March 1972. 4.3 3/8/72 25. J. A. Christensen, et al, Melting Point of Irradiated UO2, WCAP-6065, February 1965. 4.4 2/65 26. G. Hetsroni, Hydraulic Tests of the San Onofre Reactor Model, WCAP-3269-8, June 1964. 4.4 6/64 27. G. Hetsroni, Studies of the Connecticut-Yankee Hydraulic Model, WCAP-2761, June 1965, (NYO-3250-2). 4.4 6/65 28. J. S. Shefcheck, Application of the THINC Program to PWR Design, WCAP-7359-L, August 1969 (Westinghouse Proprietary) and WCAP-7838, January 1972. 4.4, 15.1 1/17/72 29. F. D. Carter, Inlet Orificing of Open PWR Cores, WCAP-9004, (Westinghouse Proprietary) and WCAP-836, January 1972. 4.4 3/19/69 1/17/72 30. J. A. Nay, Process Instrumentation for Westinghouse Nuclear Steam Supply System, WCAP-7671, April 1971. 5.2, 7.1, 7.2, 7.3 5/10/71 31. W. O. Shabbits, Dynamic Fracture Toughness Properties of Heavy Section-A-533 Grade B Class I Steel Plate, WCAP-7623, September 1972. 5.2 9/15/72 DCPP UNITS 1 & 2 FSAR UPDATE 1.6-4 Revision 18 October 2008 Date Section Submitted Title Reference To AEC 32. W. S. Hazelton, et al, Basis for Heatup and Cooldown Limit Curves, WCAP-7924, July 1972. 5.2 8/14/72 33. F. Bordelon and A. Nahavandi, A Space-Dependent Loss of Coolant Accident and Transient Analysis for PWR Systems (SATAN Digital Computer Code), WCAP-7845, January 1972. 5.2 8/9/72 34. J. Locante and E. G. Igne, Environmental Testing of Engineered Safety Features Related Equipment (NSSS-Standard Scope), WCAP-7744, Volume 1, August 1971. 5.5, 6.3 9/14/71 35. J. B. Lipchak and R. A. Stokes, Nuclear Instrumentation System, WCAP-7669, April 1971. 7.1, 7.2, 7.7 5/6/71 36. D. N. Katz, Solid State Logic Protection System Description, WCAP-7672, June 1971. 7.1, 7.2, 7.3 5/27/71 37. J. T. Haller, Engineered Safeguard Final Device or Activator Testing, WCAP-7705, February 1973. 7.1 2/27/73 38. J. Bruno, Isolation Tests Process Instrumentation Isolation Amplifier, Westinghouse Computer and Instrumentation Division, Model 131-110, WCAP-7824, December 1971. 7.2 12/16/71 39. R. Bartholomew and J. Lipchak, Test Report, Nuclear Instrumentation System Isolation Amplifier, WCAP-7819, Revision 1, January 1972. 7.2 1/17/72 40. W. C. Gangloff, An Evaluation of Anticipated Operational Transients in Westinghouse Pressurized Water Reactors, WCAP-7486, May 1971. 7.2, 15.2 5/21/71 41. T. W. T. Burnett, Reactor Protection System Diversity in Westinghouse Pressurized Water Reactors, WCAP-7306, April 1969. 7.2, 15.4 4/9/69 42. A. E. Blanchard, Rod Position Monitoring, WCAP-7571, March 1971. 7.7 4/5/71 43. J. J. Loving, In-Core Instrumentation (Flux Mapping System and Thermocouples), WCAP-7607, July 1971. 7.7 7/27/71 DCPP UNITS 1 & 2 FSAR UPDATE 1.6-5 Revision 18 October 2008 Date Section Submitted Title Reference To AEC 44. C. Hunin, FACTRAN, A Fortran IV Code for Thermal Transients in a UO2 Fuel Rod, WCAP-7908, June 1972. 15.1 9/20/72 45. J. M. Geets and R. Salvatori, Long Term Transient Analysis Program for PWRs (BLKOUT Code), WCAP-7898, April 1972. 15.1 9/20/72 46. J.M. Geets, MARVEL - A Digital Computer Code for Transient Analysis of a Multi-loop PWR System, WCAP-7909, June 1972. 15.1 10/11/72 47. T. W. T. Burnett, et al, LOFTRAN Code Description, WCAP-7907, June 1972. 15.1 10/11/72 48. R. F. Barry, LEOPARD - A Spectrum Dependent Non-Spatial Depletion Code for the IBM-7094, WCAP-3269-26, September 1963. 15.1 9/63 49. R. F. Barry, et al., The TURTLE Diffusion Depletion Code, WCAP-7213, June 1968 (Westinghouse Proprietary) and WCAP-7758, September 1971. 15.1 6/68, 9/71 50. D. H. Risher, Jr. and R. F. Barry, TWINKLE - A Multi-Dimensional Neutron Kinetics Computer Code, (Westinghouse Proprietary) and WCAP-7979, November 1972. 15.1 1/4/73 51. D. B. Fairbrother and H. G. Hargrove, WIT-6 Reactor Transient Analysis Computer Program Description, WCAP-7980, November 1972. 15.1 11/72 52. F. M. Bordelon, Calculation of Flow Coastdown after Loss of Reactor Coolant Pump (Phoenix Code), WCAP-7973, August 1973. 15.1 1/17/73 53. M. Ko, Setpoint Study for PG&E Diablo Canyon Units 1 and 2, WCAP-8320, June 1974. 15.1 6/74 54. F. W. Cooper, Jr., 17x17 Drive Line Components Tests Phase IB-II-III D-Loop Drop and Deflection, WCAP-8446 (Proprietary) and WCAP-8449 (Non-proprietary), (December 1974). 15.1 12/74 DCPP UNITS 1 & 2 FSAR UPDATE 1.6-6 Revision 18 October 2008 Date Section Submitted Title Reference To AEC 55. J. V. Miller (Ed.), Improved Analytical Methods Used in Westinghouse Fuel Rod Design Calculations, WCAP-8720, October 1976. 15.1 10/76 56. F. E. Motley and F. F. Cadek, DNB Test Results of New Mixing Vane Grids (R), WCAP-7695A, P-A (Proprietary) and WCAP-7958A (Non-Proprietary), January 1975. 15.2 1/75 57. M. A. Managan, Overpressure Protection for Westinghouse Pressurized Water Reactors, WCAP-7769, October 1971. 15.2 10/8/71 1.6.2 MISCELLANEOUS TECHNICAL REPORTS Section Title Reference
- 1. H. E. Cramer, et al, "Survey of the Elevated Line Source," Technical Report, Contract No. DA-42-007-AMC-120(R), GCA Technical Report No. 66-13-G, GCA Corporation, Bedford, Mass., 61 pp., 1967. 2.3 2. C. R. Dickson, et al, "Aerodynamic Effects of the EBR-II Containment Vessel Complex on Effluent Concentration,"
Proc. of the AEC Meteor. Inf. Meeting at Chalk River, Ontario, September 11-14, 1967, pp. 87-104. 2.3 3. J. G. Edinger, "The Influence of Terrain and Thermal Stratification of Flow Across the California Coastline," AFCRL-TR-60-438, Final Report, Contract No. AF(604)-5212, University of California, Los Angeles, 1960 2.3 4. P. A. Leighton, "Geographic Aspects of Air Pollution," Geographic Review, LVI, No. 2, 1966, pp. 153-174. 2.3 5. J. C. Ulberg, "Meteorological Data for Predicting Inhalation Hazards from Space Unit Launch Operations at Point Arguello," USNRDL-TR-1112, U.S. Naval Radiological Defense Laboratory, San Francisco, Ca., 1966, pp. 83. 2.3 DCPP UNITS 1 & 2 FSAR UPDATE 1.6-7 Revision 18 October 2008 Section Title Reference
- 6. H. E. Cramer, et al, "Meteorological Prediction Techniques and Data System," Final Report Contract No. DA-42-007-CML-552, U.S. Army, Dugway Proving Ground, Dugway, Utah, 1964. 2.3 7. F. Pasquill, Atmospheric Diffusion, D. Van Nostrand Company, Ltd., London, 1962, pp. 190. 2.3 8. R. A. Dean, "Thermal Contact Conductance Between U02 and Zircaloy-2," CVNA-127, May, 1962. 4.4 9. A. M. Ross and R. L. Stoute, "Heat Transfer Coefficient Between U02 and Zircaloy-2," NRCL-1552, June, 1962. 4.4 10. L. S. Tong, "Prediction of Departure from Nucleate Boiling for an Auxiliary Non-Uniform Heat Flux Distribution," Journal of Nuclear Energy, Vol. 21, 1967, pp. 241-248. 4.4 11. J. Weisman, et al, "Experimental Determination of the Departure from Nucleate Boiling in Large Rod Bundles at High Pressure," Chem, Eng., Prog. Sump. Ser., 64, No. 82, 1968, pp. 114-125. 4.4 12. L. S. Tong, et al, "Critical Heat Flux (DNB) in Square and Triangular Array Rod Bundles," JSME, Semi-International Symposium, Paper No. 256, Tokyo, Japan 1967 4.4 13. L. A. Stephan, The Effects of Cladding Material and Heat Treatment on the Response of Waterlogged U02 Fuel Rods to Power Bursts, IN-ITR-111, January, 1970. 4.4 14. Takasaki Tagami, Interim Report on Safety Assessments and Facilities Establishment Project in Japan for Period Ending June 1965, (No. 1). 6.2 15. N. Ranz and N. Marshall, Chem. Engr., Prog. 48, 3. pp. 141-146 and 48, 4, 1952, pp. 173, 180. 6.2 16. M. A. Styrikovich, et al, Atomnoya Energya, Vol. 17, No. 1, July 1964, pp. 45-49, (Translation in UD 621.039.562.5) 6.2 DCPP UNITS 1 & 2 FSAR UPDATE 1.6-8 Revision 18 October 2008 Section Title Reference
- 17. W. F. Pasedag and J. L. Gallagher, "Drop Size Distribution and Spray Effectiveness," Nuclear Technology, 10, 1971, p. 412. 6.2 18. L. F. Parsly, Design Considerations of Reactor Containment Spray Systems, ORNL-TM-2412, Part VII, 1970. 6.2 19. W. D. Fletcher, et al, "Post-LOCA Hydrogen Generation in PWR Containments," Journal of American Nuclear Society, June 1970. 6.2 20. W. D. Fletcher, et al, "Post-LOCA Hydrogen Generation in PWR Containments," Nuclear Technology 10, 1971, pp. 420-427. 6.2 21. H. E. Zittel, Radiation and Thermal Stability of Spray Solutions, ORNL-NSRD Program Bi-Monthly Report for May-June, 1969. ORNL-TM-2663, September 1969. 6.2 22. W. B. Cottrell, ORNL Nuclear Safety Research and Development Program Bi-Monthly Report for July-August 1968, ORNL-TM-2368, November 1968. 6.2 23. W. B. Cottrell, ORNL Nuclear Safety Research and Development Program Bi-Monthly Report for September- October 1968, ORNL-TM-2425, p. 53, January 1969. 6.2 24. H. E. Zittel and T. H. Row, "Radiation and Thermal Stability of Spray Solutions," Nuclear Technology, 10, 1971, pp. 436-443. 6.2 25. A. O. Allen, The Radiation Chemistry of Water and Aqueous Solutions, Princeton, N.J., Van Nostrand, 1961. 6.2 26. Bureau of Mines Bulletin 503, Limits of Flammability of Gases and Vapors, U.S. Government Printing Office, 1952. 6.2 27. M. G. Zabetakis, Research on the Combustion and Explosion Hazards of Hydrogen-Water Vapor-Air Mixtures, AECU-3327, September 1956. 6.2 28. E. A. J. Eggleton, A Theoretical Examination of Iodine-Water Partition Coefficients, AERE(R)-4887, 1967. 6.2 DCPP UNITS 1 & 2 FSAR UPDATE 1.6-9 Revision 18 October 2008 Section Title Reference
- 29. M. E. Meek and B. F. Rider, Summary of Fission Product Yields for U-235, U-238, Pu-239, and Pu-241 at Thermal, Fission Spectrum and 14 Mey Neutron Energies, APED-5398, March 1, 1968. 11.1 30. J. J. DiNunno, et al, Calculation of Distance Factors for Power and Test Reactor Sites, TID-14844, March 23, 1962. 11.1 31. J. O. Blomeke and M. F. Todd, Uranium-235 Fission - Product Production as a Function of Thermal Neutron Flux, Irradiation Time, and Decay Time, ORNL-2127, August 19, 1957. 11.1 32. F. J. Perkins and R. W. King, "Energy Release from the Decay of Fission Products," Nuclear Science and Engineering,1958. 11.1 33. D. F. Toner and J. S. Scott, Fission Product Release from UO2 Nuclear Safety, Volume 3, No. 2, December 1961. 11.1 34. J. Belle, "Uranium Dioxide: Properties and Nuclear Applications," Naval Reactor, DRD of NRC, 1961. 11.1 35. S. G. Gillespie and W. K. Brunot, "EMERALD NORMAL - A Program for the Calculation of Activity Releases and Doses from Normal Operation of a Pressurized Water Plant,"
Program Description and User's Manual, Pacific Gas and Electric Company, January 1973. (Provided to AEC in 1973.) 11.1, 11.2, 11.3, 15.1 36. Deleted in Revision 1.
- 37. A. B. Sisson, et al, "Evaluation for Removal of Radio-nuclides from PWR Steam Generator Blowdowns," International Water Conference, November 2, 1971. 11.2 38. E. K. Duursma and M. G. Gross, "Marine Sediments and Radioactivity," Radioactivity in the Marine Environment, National Academy of Sciences, 1971. 11.6 39. Statistical Summary of the United States, U.S. Bureau of Census. 11.6 DCPP UNITS 1 & 2 FSAR UPDATE 1.6-10 Revision 18 October 2008 Section Title Reference
- 40. Radioactivity in the Marine Environment, National Academy of Sciences, 1971. 11.6 41. W. K. Brunot, EMERALD - A Program for the Calculation of Activity Releases and Potential Doses From a Pressurized Water Reactor Plant, Pacific Gas and Electric Company, October 1971. (Provided to AEC in 1971.) 15.1 42. L. S. Tong, "Prediction of Departure from Nucleate Boiling for an Axially Non-Uniform Heat Flux Distribution,"
J. Nuclear Energy, 21, 1967, pp. 241-248. 15.2 43. F. W. Dittus and L. M. K. Boelter, University of California (Berkeley), Public Eng., 1930, 2,433. 15.4 44. W. H. Jens and P. A. Lottes, Analysis of Heat Transfer, Burnout, Pressure Drop, and Density Data for High Pressure Water, USAEC Report ANL-4627, 1951. 15.4 45. T. G. Taxelius, ed. Annual Report - Spert Project, October 1968 September 1969. Idaho Nuclear Corporation, IN-1370, June 1970. 15.4 46. R. C. Liimatainen and F. J. Testa, Studies in TREAT of Zircaloy-2-Clad, UO2 Core Simulated Fuel Elements, ANL-7225, January-June 1966, November, 1966, p. 177. 15.4 47. Regulatory Guide 1.109, Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10 CFR Part 50, Appendix I, Revision 1, October 1977. 15.5 1.6.3 DRAWINGS INCORPORATED BY REFERENCE Controlled engineering drawings were removed from the FSAR Update at Revision 15. The drawings are considered incorporated by reference. Table 1.6-1 identifies the controlled engineering drawings that are incorporated by reference and also provides a cross-reference of the controlled engineering drawings to the respective FSAR Update figure number. The contents of the drawings are controlled by DCPP procedures. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.3-1 Sheet 1 of 4 Revision 18 October 2008 DESIGN COMPARISON OF DIABLO CANYON POWER PLANT UNITS 1 & 2, ZION STATION, AND TROJAN NUCLEAR PLANT (Historical-valid through March 1984) Chapter Number System/Component Section Reference Discussion 1 Introduction 1.1 All are 4-loop plants Reactor power ratings (Core thermal output):
Diablo Canyon Unit 1: 3338 MWt Diablo Canyon Unit 2 & Trojan: 3411 MWt Zion: 3250 MWt 3 Containment 3.8.2 All containments are steel-lined concrete structures. Diablo Canyon uses conventional reinforcing; Trojan and Zion are posttensioned. Comparative dimensions and designed pressures are: Design I.D., ft Net Vol, cu ft Press, psig Diablo Canyon 140 2,630,000 47 Trojan 124 2,000,000 60 Zion 140 2,860,000 47 4 Reactor 4.2.1 Generally similar to Zion and Trojan, but differences exist in design based on nuclear and thermal-hydraulic design parameters. Reactor Vessel 4.2.2 Diablo Canyon Unit 1: Design of thermal shields and upper and lower Internals support structures, etc., is similar to Zion. Diablo Canyon Unit 2: Design of neutron pads and upper and lower support structures, etc., is similar to Trojan. Reactivity Control 4.2.3 Similar to Zion and Trojan. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.3-1 Sheet 2 of 4 Revision 18 October 2008 Chapter Number System/Component Section Reference Discussion 4 (Cont'd) Nuclear Design 4.3 Similar to Zion and Trojan except differences exist in fuel burnup rates, fuel enrichments, keff, and core kinetics characteristics. Thermal-hydraulic Design 4.4 Similar to Zion and Trojan except for rating differences. 5 Reactor Coolant System 5.1, 5.2, 5.3, 5.4, 5.5 All three plants are similar in design except Diablo Canyon will use codes that specifically apply. Zion has loop stop valves. Reactor Vessel 5.4 Diablo Canyon Units 1 and 2 each have 50-year design life while Trojan and Zion are designed for 40 years. Diablo Canyon Unit 2, Trojan, and Zion have four of the inner CRDM housings moved into the outer rows as compared to Diablo Canyon Unit 1. All have the same number of CRDM housings. Diablo Canyon Unit 1 uses ASME Code, Section III, 1965 Edition and addenda through winter 1966. Zion uses ASME Code, Section III, 1965 Edition and addenda through summer 1966. Diablo Canyon Unit 2 and Trojan use ASME Code, Section III, 1968 Edition. Diablo Canyon Unit 1 and Zion have blowout collars on bottom tubes only. Diablo Canyon Unit 2 does not have blowout collars. Trojan has blowout collars on control rod drive mechanisms and bottom tubes. Reactor Coolant Pumps 5.5.1 Diablo Canyon Units 1 and 2 and Trojan have spacer couplings. Zion does not. Steam Generators 5.5.2 Diablo Canyon and Zion have 1,100 psia secondary side design pressure. Trojan uses 1,200 psia. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.3-1 Sheet 3 of 4 Revision 18 October 2008 Chapter Number System/Component Section Reference Discussion 5 (Cont'd) Reactor Coolant Piping 5.5.3 Diablo Canyon Units 1 and 2 and Zion use seamless forged pipe sections and 90° elbows which are cast sections joined by electroslag welds. Trojan uses centrifugally cast pipe sections. Zion's design is modified to accommodate the loop stop valves. Diablo Canyon and Zion are designed to B31.1. Trojan is designed to B31.7. Residual Heat Removal System 5.5.6 All are similar in design.
Pressurizer 5.5.10 Head material is cast for Diablo Canyon Unit 1 and Zion while it is fabricated plate for Diablo Canyon Unit 2 and Trojan. The shell material is fabricated plate for all four units. 6 Containment Spray System 6.2.3 All are similar in design. Emergency Core Cooling System 6.3 All are similar in design. 7 Reactor Trip System 7.2 Diablo Canyon Units 1 and 2 and Trojan have solid-state logic protection systems while Zion has relay protection. The logic on trips associated with the reactor coolant pump power supplies is similar at Diablo Canyon Units 1 and 2 and Trojan. Zion is different because it has four separate buses, one for each pump, while Diablo Canyon and Trojan have two reactor coolant pumps per bus. Engineered Safety Features Actuation System 7.3 All four units have extended engineered safety features testability. Diablo Canyon Units 1 and 2 and Trojan have 2/3 high containment pressure logic for safety injection initiation, while Zion uses 2/4 high containment pressure. Systems Required for Safe Shutdown 7.4 System functions are similar on all four units. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.3-1 Sheet 4 of 4 Revision 18 October 2008 Chapter Number System/Component Section Reference Discussion 7 (Cont'd) Safety-related Display Instrumentation 7.5 Parametric display is similar for all four units. The physical configuration may differ. Other Safety Systems 7.6 All four units have residual heat removal isolation valve interlocking and automatic closure devices. Control Systems 7.7 Diablo Canyon Units 1 and 2 and Trojan have digital rod position indication systems, while Zion has analog rod position indication. 8 Electric Power Fig. 8.1-1 Diablo Canyon and Trojan auxiliary systems supply loads at 12 and 4.16 kV. Zion does not have 12-kV loads. Standby Power 8.3.2 Trojan has two 4.16-kV ESF buses with one standby diesel generator unit (two engines in line per unit) on each bus. Diablo Canyon and Zion have five standby diesel generators, two for each unit and one that can be transferred to either unit. 9 Chemical and Volume 9.3.4 Similar, except Diablo Units 1 and 2 and Zion have 12 percent boric acid concentration systems, while Trojan has a 4 percent system. 10 Steam and Power Conversion System 10.2 Turbines are similar with three double-flow low pressure elements and six stages of feedwater heating. 11 Radioactive Waste Management Entire chapter Systems and treatment provided are similar. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.3-2 Sheet 1 of 4 Revision 15 November 2003 MAJOR DESIGN CHANGES SINCE THE PSAR (Historical-valid through July 1974)
Item Changes in Design Original FSAR Section References 1. Reactor vessel internals changes (Unit 2) - Thermal shield replaced by neutron pads, and lower core support plate and upper internals support system redesigned. 4.2.2 2. Tetra boron carbide control rod poison material changed to silver-indium-cadmium. 4.2.3 3. Pellet density, fuel rod pressure, and burnable poison loading pattern have changed to reflect more detailed design calculations and latest operating experience. 4.3 4. Reactor vessel top and bottom head penetration and control rod drive mechanisms have been redesigned and removable insulation has been provided on the closure head to enable inservice inspection. 4.3, 5.4, 5.4.2, 5.4.4 5. Safety injection now provides cold leg injection with cold leg or hot leg recirculation. 6.3 6. Rod withdrawal step from rod drop signal and automatic turbine load cutback initiated by rod drop have been replaced by the power range neutron flux rate trips. 7.2 7. Relay logic for reactor protection and engineered safety features actuation system has been changed to solid-state logic. 7.2, 7.3 8. On-line testing has been provided for engineered safety features actuation system. 7.3 9. Analog rod position indication has been replaced by digital rod position indication. 7.7.1 10. Deleted in Revision 15 11. Design criteria changes in the event of inleakage of contaminated water into component cooling water (CCW) system. This tends to minimize possible release of reactor coolant outside containment via the CCW system. 9.2.2 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.3-2 Sheet 2 of 4 Revision 15 November 2003 Item Changes in Design Original FSAR Section References 12. The compressed air system is revised to eliminate the emergency air system. This satisfies safety criteria while reducing potential leakage paths from containment. 9.3.1 13. The stainless steel liner in the spent fuel pool and transfer canal is changed from Design Class I to Design Class II. The liners prevent minor leakage, and the pool and canal structures remain Design Class I and are relied upon to prevent major failure. 9.1.2 14. The primary water storage tank is reclassified from Design Class I to Design Class II. This is no longer the primary source of makeup water to the CCW System. A backup source to a makeup supply to a Design Class I system itself need not be classified Design Class I. 9.2.4 15. The detectors for the fire detection alarm system are relocated to give more specific identification of the location of the source. Instrument ac power is provided. 9.5.1 16. In the containment structure, vertical joints are provided with a shear key, as required by ACI 301-66. 3.8.2 17. The Chief Mechanical Engineer is no longer the designated Project Engineer. This change was made April 26, 1971. 17.0 18. Those parts of the fire protection system that protect Design Class II and III equipment and structures are not required to be Design Class I. 9.5.1 19. Inspection procedures for cable were modified to require tests on sample reels from each production run, rather than on each reel. 8.5.2 20. The fuel assembly array is revised from 15 x 15 to 17 x 17. The change was initiated to maintain sufficient flexibility to fulfill the requirements of, or any changes to, 10 CFR 50.46: "Acceptance Criteria for Emergency Core Cooling Systems for Light-Water Nuclear Power Reactors." 4 and 15 21. The steam generator blowdown treatment system is added to provide for treatment in the event that there is primary-to-secondary leakage. 11.2.2 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.3-2 Sheet 3 of 4 Revision 15 November 2003 Item Changes in Design Original FSAR Section References 22. An alarm system is added to indicate the rupture of a auxiliary seawater cooling header. The function of the alarm is to alert the operator in the event that the header breaks, so that the operator can route the cooling water to the redundant supply header and restore the cooling function to the CCW system. 9.2 23. The turbine building is protected from floods due to pipe breaks by the addition of an 18-inch overflow drain from the sump system to the circulating water discharge canal. 9.2 24 Protection against flooding of the turbine building is provided by design changes to decrease the probability of rupturing the expansion joints at the water box. Also, the consequences of a rupture are minimized by the addition of expansion joint sleeves. 10.4 25. A system is added and designed to detect and alarm in the event that there are loose parts in the reactor coolant system. 3.9 26. A Design Class I supply of demineralized water is provided for makeup to the spent fuel pool. 9.1 27. The ventilation system for the fuel handling area is modified and reclassified to Design Class I. 9.4 28. A Design Class I containment hydrogen purge system is provided for reducing the containment atmosphere hydrogen concentration in the event of a LOCA. The system has redundant sets of supply and exhaust fans and filters. Each fan is on a separate vital bus. 6.2 29. The heating, ventilating, and air conditioning system for the control room is modified and is reclassified as Design Class I. The system has four modes of operation designed to make the control room habitable: (a) during normal operation,(b) during long-term occupancy, (c) in the event that there is excessive airborne activity external to the control room, and (d) in the event that there is a fire in the control room. 9.4 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.3-2 Sheet 4 of 4 Revision 15 November 2003 Item Changes in Design Original FSAR Section References 30. Design changes add the capability of maintaining reactor coolant system temperature during hot shutdown operations; when the reactor is subcritical, the steam dumps to the main condenser. This is accomplished by a controller in the steam line, operating in the pressure control mode, which is set to maintain the steam generator steam pressure. 5.1 31. Meteorological monitoring equipment will provide data to be recorded in the control room during plant operation. 16.4 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.4-1 Sheet 1 of 3 Revision 11 November 1996 PRINCIPAL CONSULTANTS AND CONTRACT DESCRIPTION (Historical-valid through March 1986) Principal Consultant Contract (Over $100,000) Anco Engineers, Inc. Raceway system qualification; seismic testing of mechanical equipment Arremany & Associates Nondestructive examination services
Associated Technical Training Services Operator training Babcock & Wilcox, Inc. Engineering support Bechtel Power Corporation Project management, engineering, construction procurement, startup, project cost and scheduling, quality assurance J. R. Benjamin and Associates, Inc. Seismic verification of auxiliary and turbine buildings; frequency of vessel impact on intake structure William K. Brunot Reliability and risk analysis Burns & Roe, Inc. Engineering quality control services
California Department of Fish and Game Marine biology studies California Polytechnic State University Marine biology studies Chemrad Corporation Radiological and health physics support
Cygna Energy Services, Inc. Piping support and HVAC equipment qualification Earth Sciences Associates Geological investigations
Ecological Analysts, Inc. Marine biology studies
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.4-1 Sheet 2 of 3 Revision 11 November 1996 Principal Consultant Contract (Over $100,000) EDS Nuclear, Inc. Control room (HVAC) design, technical support center pressurization system design, piping anchors design review, radiation shielding design review, emergency core cooling system nozzle fatigue analysis Energy Training Corporation Operator training
Geri Engineering, Inc. Reactor vessel inservice inspection tool modification Harding - Lawson Associates Soil investigations, geophysical surveys
Hydro - Research Science Discharge structure model study Innova Corporation Pipe support design review and redesign engineering James Engineering Company Engineering support
Kaiser Engineers, Inc. Program management and engineering services, independent assessment of alternative cooling water systems Lambert & Company Nondestructive examination services Nuclear Services Corporation Pipe break analysis Nucon, Inc. Engineering support for fuel load and startup
NUS Corporation Engineering studies of spent fuel pool storage expansion Nutech Engineers, Inc. Seismic and environmental qualification engineering support Offshore Technology Corporation Intake structure hydraulic model studies Omar J. Lillevang Breakwater design, breakwater damage study DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.4-1 Sheet 3 of 3 Revision 11 November 1996 Principal Consultant Contract (Over $100,000) Pickard, Lowe, & Garrick, Inc. Probabilistic risk assessment
Project Assistance Corporation Quality assurance program support Radiation Research Associates, Inc. Shielding design review Regents of the University of California Thermal physical modeling studies
R. F. Reedy and Associates Quality assurance verification Robert L. Cloud Associates, Inc. Hosgri seismic reverification program Stone & Webster Engineering Corporation Independent design verification program - Phase II TERA Corporation Source modeling studies, general engineering, thermal discharge assessment, assessment of alternative cooling water systems Terra Technology Corporation Seismic recording system maintenance and records processing Teledyne Engineering Services Independent design verification program
URS/John A. Blume and Associates Seismic structural criteria, electrical seismic testing criteria, seismic research program, seismic review and reverification, independent internal review, Hosgri seismic evaluation Waltek Services Technical support services Westinghouse Electric Corporation Long-term seismic research program, environmental qualification, piping redesign and qualification, seismic reverification technical support Woodward - Clyde and Associates Seismic surveys Wyle Laboratories Seismic test and engineering support DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.4-2 Sheet 1 of 3 Revision 11 November 1996 SUPPLIERS OF IMPORTANT EQUIPMENT AND MATERIALS OTHER THAN NUCLEAR STEAM SUPPLY SYSTEM (Historical-valid through March 1986) Supplier Equipment/Materials Alco Engines Division, White Industrial Power, Inc. Diesel generator units American Bridge Co., Division of U.S. Steel Corp. Furnish structural steel AMF Cuno Division Radioactive waste filters Armco Steel Corp. Containment wall penetration flued heads
Babcock & Wilcox Safety parameter display system Berkeley Steel Construction Co. Radioactive waste tanks
Bingham-Willamette Pump Co. Component cooling water pumps, auxiliary saltwater pumps Byron Jackson Pump, Division of Borg-Warner Corp. Auxiliary feedwater pumps Capital Westward Inc. Radioactive waste tanks Chem-Nuclear Services Inc. Radioactive resin removal and transfer system Chemetron Corp. Carbon dioxide
Combustion Engineering Subcooled margin monitor Contromatics Corp. Radioactive waste valves
De Laval Turbine Inc. Diesel fuel transfer pumps
Dresser Industries Inc. Steam generator safety valves Fairbanks-Morse Co. Fire pumps
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.4-2 Sheet 2 of 3 Revision 11 November 1996 Supplier Equipment/Materials Fenwall Inc. Halon 1301 system
Fisher Controls Co. Class I pressure/level controllers, and control valves Fulton Shipyard Fuel handling area crane
General Electric Co. Electrical penetrations of containment structure, 12 and 4.16-kV switchgear Grinnell Co. Radioactive waste valves Harnischfeger P&H Turbine building bridge cranes
Ingersoll-Rand Co. Radioactive waste pumps, reactor coolant drain tank pump, makeup water system pumps J. E. Lonergan Co. Class I safety relief valves
Mine Safety Appliances Co. Radwaste gas analyzers Murphy Pacific Corp. Furnish structural steel M. W. Kellogg Co. (Pullman Power Products) Main systems piping National Controls, Inc. Condensed waste drumming system Paul Monroe Hydraulics Dome service crane snubbers
Pyrotronics, Inc. Fire detection and alarm system Quick Manufacturing Co. Dome service crane
Schutte and Koerting Co. Main steam isolation and check valves
Scott Company of California Ventilation and air filters, fire water and stand pipe system DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.4-2 Sheet 3 of 3 Revision 11 November 1996 Supplier Equipment/Materials Fenwall Inc. Halon 1301 system
Velan Valve Corp. Radioactive waste valves Viking Automatic Sprinkler Co., Chemtron Corp. (Subcontractor) Water spray and CO2 fire protection systems Westinghouse Electric Corp. Radioactive waste evaporators
Yuba Manufacturing Co. Component cooling water heat exchanger, polar crane DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.4-3 Sheet 1 of 3 Revision 11 November 1996 CONSTRUCTION AND INSTALLATION CONTRACTORS (Historical-valid through March 1986) Contractor Units 1 and 2 In-progress Contracts Over $100,000 Bechtel Construction Inc. Plant maintenance Plant Asbestos - Thorpe Insulation Furnish and install insulation
Promatec Furnish and install insulation
Pullman Power Products Erect plant and steam piping Westinghouse Electric Corporation Erect turbine-generator
Contractor Units 1 and 2 Completed Contracts Over $100,000 A. J. Diani Construction Paving of access roads American Bridge Complete structural steel
Ames Associates Repair breakwater Arrowhead Industrial Water Furnish demineralizer Bigge Crane & Rigging Co. Heavy equipment handling
Bigge Drayage Co. Material receiving/storage (Pismo Beach laydown and storage yard) Bostrom-Bergen Structural steel
Bovee & Crail Construction Erect intake equipment & pipe Chemtrol Corporation Furnish and install penetration seals
Continental Heller Corp. Construct security building
E.H. Haskell Company Parking lot DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.4-3 Sheet 2 of 3 Revision 11 November 1996 Contractor Units 1 and 2 In-progress Contracts Over $100,000 Endurance Metal Product Co. Erect miscellaneous steel
Granite Constr. Co. and Gordon H. Ball, Inc. Construct breakwaters Guy F. Atkinson Company Construction of seismic modifications, construct buildings Healy - Tibbits Repair breakwater H&H Construction, Inc. Grading and paving (Pismo Beach laydown and storage yard) H. H. Robertson Co. Install siding and roofing H.P. Foley Company Install wiring, electrical equipment, and instrumentation. Construct seismic modifications of buildings. Morgan Equipment Co. Batch plant Murphy Pacific Corp. Furnish and install structural steel erect turbine building cranes Pinkerton's Inc. Security guard service Pittsburg-Des Moines Steel Co. Fabricate auxiliary building tanks, construct storage tanks Pullman Power Products Construct pipe rupture restraints Relocate Structures, Inc. Construct administration building Robert McMullan & Son, Inc. Finish painting
Sanchez & Son, Inc. Grading and paving (Pismo Beach laydown and storage yard) San Luis Garbage Disposal of waste water DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.4-3 Sheet 3 of 3 Revision 11 November 1996 Contractor Units 1 and 2 In-progress Contracts Over $100,000 Scott Company of California Furnish and install air conditioning and ventilation
System Steel Builders Construction offices, warehouse buildings (Pismo Beach laydown and storage yard) Tech-Sil, Inc. Furnish and install penetration seals
Valley Trucking of Santa Maria, Inc. Disposal of waste water
Viking Automatic Sprinkler Co. Furnish and install fire protection Walter Bros. Construction Co. and Milburn & Sansome Co. Plant roads and site preparation, construct Harford Drive-County Road construct access road Wismer & Becker Contracting Engineers Install electrical equipment switchyard, install mechanical equipment/erect NSSS DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.5-1 Sheet 1 of 3 Revision 11 November 1996 RESEARCH AND DEVELOPMENT PROGRAMS (Historical-valid through November 1975) PROGRAM TECHNICAL REPORTS Fuel development for operations at high power densities Full-length emergency core cooling heat transfer tests (FLECHT) Reactor vessel thermal shock Verification test (17 x 17) Delayed departure from nucleate boiling (DDNB) F. T. Eggleston, Safety-Related Research and Development for Westinghouse PWRs, Program Summaries. Winter 77 - Summer 78, WCAP-8768, Rev. 2, October 1978. Core stability evaluation Blowdown forces program C. J. Kubit, Safety-Related Research and Blowdown Development for Westinghouse PWRs, Program Summaries. Fall 1972, WCAP-8004, January 1973. Containment spray Fuel rod burst Loss-of-coolant analysis ESADA DNB R. M. Hunt, Safety-Related Research and Development for Westinghouse PWRs, Program Summaries. Fall 1970, WCAP-7614-L, November 1970. Burnable poison Flashing heat transfer R. M. Hunt, Safety-Related Research and Development for Westinghouse PWRs, Program Summaries. Spring 1970, WCAP-7943-L, May 1970. Fuel development for operation at high power densities M. D. Davis, Safety-Related Research and Development for Westinghouse PWRs, Program Summaries. Fall 1974, WCAP-8483, March 1975. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.5-1 Sheet 2 of 3 Revision 11 November 1996 PROGRAM TECHNICAL REPORTS Incore detector Gross failed fuel detector C. J. Kubit, Safety-Related Research and Development for Westinghouse PWRs, Program Summaries. Spring 1974, WCAP-8385, July 1974. Environmental testing of engineered safety features related equipment C. J. Kubit, Safety-Related Research and Development for Westinghouse PWRs, Program Summaries. Spring 1972, WCAP-7856, May 1972. In-pile fuel densification J. M. Hellman, Fuel Densification Experimental Results and Model for Reactor Operation, WCAP-8218-P-A March 1975 (Proprietary) and WCAP-8219-A, March, 1975 (Non-proprietary). Verification test (17 x 17) L. Geninski, et al, Safety Analysis of the 17 x 17 Fuel Assembly for Combined Seismic and Loss-of-Coolant Accident, WCAP-8288, December 1973. Verification test (17 x 17) E. E. DeMario and S. Makazato, Hydraulic Flow Test of the 17 x 17 Fuel Assembly, WCAP-8279, February 1974. Verification test (17 x 17) F. W. Cooper, Jr., 17 x 17 Drive Line Components Test - Phase IB, II, II, - Drop and Deflections, WCAP-8446, December 1974. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.5-1 Sheet 3 of 3 Revision 11 November 1996 PROGRAM TECHNICAL REPORTS Departure from nucleate boiling (DNB) K. W. Hill, et al, Effect of 17 x 17 Fuel Assembler Geometry on DNB, WCAP-8396-P-A, February 1975 (Proprietary) and WCAP-8297-A, February 1975. Incore flow mixing F. W. Motley, et al, The Effect of 17 x 17 Fuel Assembly Geometry on Interchannel Thermal Mixing, (WCAP-8298-P-A) (Proprietary) and WCAP-8299-, January 1975. LOCA heat transfer tests A. J. Burnett and S. D. Kopelic, Westinghouse ECCS Evaluation Model October 1975 Version, WCAP-8622 (Proprietary) and WCAP-8623 (Non-Proprietary), November 1975. 17 x 17 fuel surveillance program Irradiation of 17 x 17 Demonstration Assemblies in Surry Units No. 1 and 2, Cycle 2, WCAP-8262, July 1974.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 1 of 26 Revision 21 September 2013 CONTROLLED ENGINEERING DRAWINGS/FSAR UPDATE FIGURES CROSS REFERENCE Figure Sheet Drawing Sheet Description 1.2-3 500001 Area Location Plan 1.2-4 57727 Auxiliary, Containment, and Fuel Handling Buildings (Units 1 & 2), Plan at Elevation 140 ft 1.2-5 57726 Auxiliary, Containment, and Fuel Handling Buildings (Units 1 & 2), Plan at Elevation 115 ft 1.2-6 57725 Auxiliary, Containment, and Fuel Handling Buildings (Units 1 & 2), Plan at Elevations 91 and 100 ft 1.2-7 57724 Auxiliary and Containment Buildings (Units 1 & 2), Plan at Elevation 85 ft 1.2-8 57723 Auxiliary and Containment Buildings (Units 1 & 2), Plan at Elevation 73 ft 1.2-9 57722 Auxiliary and Containment Buildings (Unit 1 & 2), Plan at Elevations 60 and 64 ft 1.2-10 500977 Containment Building (Unit 2), Plan at Elevations 115 and 140 ft 1.2-11 500971 Containment & Fuel Handling Buildings (Unit 2), Plan at Elevations 85, 91, and 100 ft 1.2-12 500968 Containment Building (Unit 2), Plan at Elevations 60, 64, and 73 ft 1.2-13 57721 Turbine Building (Unit 1), Plan at Elevation 140 ft 1.2-14 57720 Turbine Building (Unit 1), Plan at Elevation 119 ft 1.2-15 57719 Turbine Building (Unit 1), Plan at Elevation 104 ft 1.2-16 57718 Turbine Building (Unit 1), Plan at Elevation 85 ft1.2-17 500967 Turbine Building (Unit 2), Plan at Elevation 140 ft 1.2-18 500966 Turbine Building (Unit 2), Plan at Elevation 119 ft 1.2-19 500965 Turbine Building (Unit 2), Plan at Elevation 104 ft 1.2-20 500964 Turbine Building (Unit 2), Plan at Elevation 85 ft1.2-21 57728 Auxiliary Building (Units 1 & 2), Section A-A 1.2-22 57729 Auxiliary and Containment Buildings (Unit 1 & 2), Section B-B DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 2 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 1.2-23 57730 Auxiliary and Fuel Handling Buildings (Unit 1 & 2), Section C-C 1.2-24 57731 Containment, Turbine, and Fuel Handling Buildings (Unit 1) Section D-D 1.2-25 57732 Auxiliary, Turbine, and Fuel Handling Buildings (Unit 1), Section E-E 1.2-26 57733 Auxiliary, Fuel Handling, and Turbine Buildings (Units 1 & 2), Section F-F 1.2-27 57734 Turbine Building (Unit 1), Section G-G 1.2-28 500969 Containment Building (Unit 2), Section A-A 1.2-29 500972 Vent & Fuel Handling Buildings (Unit 2), Section B-B 1.2-30 500973 Turbine, Containment, & Fuel Handling Buildings (Unit 2), Section C-C 1.2-31 500974 Turbine Building (Unit 2), Sections D-D and E-E1.2-32 500976 Turbine Building (Unit 2), Section F-F 2.4-7 468999 Typical Sections for Tribar Armor Construction 2.4-8 469001 Restored Cross-sections and Embedment Plan 3.2-1 1 of 2 102001 3 Piping Schematic Legend 3.2-1 1A of 2 102023 2 Piping Schematic Legend 3.2-1 2 of 2 108001 3 Piping Schematic Legend 3.2-1 2A of 2 108023 2 Piping Schematic Legend 3.2-2 1 of 16 102002 4 Piping Schematic - Condensate System (16 Sheets) 3.2-2 2 of 16 108002 4 3.2-2 3 of 16 102002 5 3.2-2 4 of 16 108002 5 3.2-2 5 of 16 102002 6 3.2-2 6 of 16 108002 6 3.2-2 7 of 16 102002 7 3.2-2 8 of 16 108002 7 3.2-2 9 of 16 102002 8 3.2-2 10 of 16 108002 8 3.2-2 11 of 16 102002 9 3.2-2 12 of 16 108002 9 3.2-2 13 of 16 102002 10 3.2-2 14 of 16 108002 10 3.2-2 15 of 16 102002 11 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 3 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 3.2-2 16 of 16 108002 11 3.2-3 1 of 8 102003 3 Piping Schematic - Feedwater System (8 Sheets) 3.2-3 2 of 8 108003 3 3.2-3 3 of 8 102003 4 3.2-3 4 of 8 108003 4 3.2-3 5 of 8 102003 4A 3.2-3 6 of 8 108003 4A 3.2-3 7 of 8 102003 5 3.2-3 8 of 8 108003 5 3.2-4 1 of 14 102004 3 Piping Schematic - Turbine Steam Supply System (14 Sheets) 3.2-4 2 of 14 108004 3 3.2-4 3 of 14 102004 4 3.2-4 4 of 14 108004 4 3.2-4 5 of 14 102004 5 3.2-4 6 of 14 108004 5 3.2-4 7 of 14 102004 6 3.2-4 8 of 14 108004 6 3.2-4 9 of 14 102004 7 3.2-4 10 of 14 108004 7 3.2-4 11 of 14 102004 8 3.2-4 12 of 14 108004 8 3.2-4 13 of 14 102004 9 3.2-4 14 of 14 108004 9 3.2-5 1 of 12 102005 2 Piping Schematic - Extraction Steam and Heater Drip System (12 Sheets) 3.2-5 2 of 12 108005 2 3.2-5 3 of 12 102005 3 3.2-5 4 of 12 108005 3 3.2-5 5 of 12 102005 4 3.2-5 6 of 12 108005 4 3.2-5 7 of 12 102005 5 3.2-5 8 of 12 108005 5 3.2-5 9 of 12 102005 6 3.2-5 10 of 12 108005 6 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 4 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 3.2-5 11 of 12 102005 7 3.2-5 12 of 12 108005 7 3.2-6 1 of 8 102006 3 Piping Schematic - Auxiliary Steam System (8 Sheets) 3.2-6 2 of 8 108006 3 3.2-6 3 of 8 102006 4 3.2-6 4 of 8 108006 4 3.2-6 5 of 8 102006 4A 3.2-6 6 of 8 108006 4A 3.2-6 7 of 8 102006 5 3.2-6 8 of 8 108006 5 3.2-7 1 of 8 102007 3 Piping Schematic - Reactor Coolant System (8 Sheets) 3.2-7 2 of 8 108007 3 3.2-7 3 of 8 102007 4 3.2-7 4 of 8 108007 4 3.2-7 5 of 8 102007 5 3.2-7 6 of 8 108007 5 3.2-7 7 of 8 102007 5A 3.2-7 8 of 8 108007 5A 3.2-8 1 of 24 102008 3 Piping Schematic - Chemical and Volume Control System (24 Sheets) 3.2-8 2 of 24 108008 3 3.2-8 3 of 24 102008 4A 3.2-8 4 of 24 108008 4A 3.2-8 5 of 24 102008 4 3.2-8 6 of 24 108008 4 3.2-8 7 of 24 102008 4B 3.2-8 8 of 24 108008 4B 3.2-8 9 of 24 102008 5 3.2-8 10 of 24 108008 5 3.2-8 11 of 24 102008 5A 3.2-8 12 of 24 108008 5A 3.2-8 13 of 24 102008 5B 3.2-8 14 of 24 108008 5B 3.2-8 15 of 24 102008 5C DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 5 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 3.2-8 16 of 24 108008 5C 3.2-8 17 of 24 102008 6 3.2-8 18 of 24 108008 6 3.2-8 19 of 24 102008 7 3.2-8 20 of 24 108008 7 3.2-8 21 of 24 102008 8 3.2-8 22 of 24 108008 8 3.2-8 23 of 24 102008 9 3.2-8 24 of 24 108008 9 3.2-9 1 of 10 102009 3 Piping Schematic - Safety Injection System (10 Sheets) 3.2-9 2 of 10 108009 3 3.2-9 3 of 10 102009 4 3.2-9 4 of 10 108009 4 3.2-9 5 of 10 102009 5 3.2-9 6 of 10 108009 5 3.2-9 7 of 10 102009 6 3.2-9 8 of 10 108009 6 3.2-9 9 of 10 102009 7 3.2-9 10 of 10 108009 7 3.2-10 1 of 6 102010 3 Piping Schematic - Residual Heat Removal System (6 Sheets) 3.2-10 2 of 6 108010 3 3.2-10 3 of 6 102010 4 3.2-10 4 of 6 108010 4 3.2-10 5 of 6 102010 5 3.2-10 6 of 6 108010 5 3.2-11 1 of 10 102011 2 Piping Schematic - Nuclear Steam Supply Sampling System (10 Sheets) 3.2-11 2 of 10 108011 2 3.2-11 3 of 10 102011 3 3.2-11 4 of 10 108011 3 3.2-11 5 of 10 102011 4 3.2-11 6 of 10 108011 4 3.2-11 7 of 10 102011 5 3.2-11 8 of 10 108011 5 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 6 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 3.2-11 9 of 10 102011 6 3.2-11 10 of 10 108011 6 3.2-12 1 of 2 102012 3 Piping Schematic - Containment Spray System (2 Sheets) 3.2-12 2 of 2 108012 3 3.2-13 1 of 2 102013 2 Piping Schematic - Spent Fuel Pool Cooling System (2 Sheets) 3.2-13 2 of 2 108013 2 3.2-14 1 of 16 102014 5 Piping Schematic - Component Cooling Water System (16 Sheets) 3.2-14 2 of 16 108014 5 3.2-14 3 of 16 102014 5A 3.2-14 4 of 16 108014 5A 3.2-14 5 of 16 102014 6 3.2-14 6 of 16 108014 6 3.2-14 7 of 16 102014 6A 3.2-14 8 of 16 108014 6A 3.2-14 9 of 16 102014 7 3.2-14 10 of 16 108014 7 3.2-14 11 of 16 102014 8 3.2-14 12 of 16 108014 8 3.2-14 13 of 16 102014 9 3.2-14 14 of 16 108014 9 3.2-14 15 of 16 102014 10 3.2-14 16 of 16 108014 10 3.2-15 1 of 10 102015 3 Piping Schematic - Service Cooling Water System (10 Sheets) 3.2-15 2 of 10 108015 3 3.2-15 3 of 10 102015 4 3.2-15 4 of 10 108015 4 3.2-15 5 of 10 102015 5 3.2-15 6 of 10 108015 5 3.2-15 7 of 10 102015 6 3.2-15 8 of 10 108015 6 3.2-15 9 of 10 102015 7 3.2-15 10 of 10 108015 7 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 7 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 3.2-16 1 of 19 102016 1 Piping Schematic - Makeup Water System (19 Sheets) 3.2-16 2 of 19 108016 3 3.2-16 3 of 19 102016 4 3.2-16 4 of 19 108016 5 3.2-16 5 of 19 102016 6 3.2-16 6 of 19 102016 7 3.2-16 7 of 19 102016 8 3.2-16 8 of 19 102016 9 3.2-16 9 of 19 102016 9A 3.2-16 10 of 19 102016 10 3.2-16 11 of 19 102016 11 3.2-16 12 of 19 102016 13 3.2-16 13 of 19 102016 14 3.2-16 14 of 19 102016 16 3.2-16 15 of 19 108016 17 3.2-16 16 of 19 102016 18 3.2-16 17 of 19 108016 19 3.2-16 18 of 19 102016 20 3.2-16 19 of 19 102016 21 3.2-17 1 of 8 102017 3 Piping Schematic - Saltwater Systems (8 Sheets) 3.2-17 2 of 8 108017 3 3.2-17 3 of 8 102017 4 3.2-17 4 of 8 108017 4 3.2-17 5 of 8 102017 5 3.2-17 6 of 8 108017 5 3.2-17 7 of 8 102017 6 3.2-17 8 of 8 108017 6 3.2-18 1 of 18 102018 2 Piping Schematic - Fire Protection Systems (18 Sheets) 3.2-18 2 of 18 108018 2 3.2-18 3 of 18 102018 3 3.2-18 4 of 18 108018 3 3.2-18 5 of 18 102018 4 3.2-18 6 of 18 108018 4 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 8 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 3.2-18 7 of 18 102018 4A 3.2-18 8 of 18 108018 4A 3.2-18 9 of 18 102018 5 3.2-18 10 of 18 108018 5 3.2-18 11 of 18 102018 6 3.2-18 12 of 18 108018 6 3.2-18 13 of 18 102018 7 3.2-18 14 of 18 108018 7 3.2-18 15 of 18 102018 8 3.2-18 16 of 18 108018 8 3.2-18 17 of 18 102018 9 3.2-18 18 of 18 108018 9 3.2-19 1 of 16 102019 3 Piping Schematic - Liquid Radwaste System (17 Sheets) 3.2-19 2 of 16 108019 3 3.2-19 3 of 16 102019 3A 3.2-19 4 of 16 108019 3A 3.2-19 5 of 16 102019 4 3.2-19 6 of 16 108019 4 3.2-19 7 of 16 102019 5 3.2-19 8 of 16 108019 5 3.2-19 9 of 16 102019 6 3.2-19 10 of 16 108019 6 3.2-19 11 of 16 102019 6A 3.2-19 12 of 16 108019 6A 3.2-19 13 of 16 102019 7 3.2-19 14 of 16 108019 7 3.2-19 15 of 16 102019 8 3.2-19 15a of 16 102019 8A 3.2-19 16 of 16 108019 8 3.2-20 1 of 18 102020 3 Piping Schematic - Lube Oil Distribution and Purification System (18 Sheets) 3.2-20 2 of 18 108020 3 3.2-20 3 of 18 102020 4 3.2-20 4 of 18 108020 4 3.2-20 5 of 18 102020 5 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 9 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 3.2-20 6 of 18 108020 5 3.2-20 7 of 18 102020 6 3.2-20 8 of 18 108020 6 3.2-20 9 of 18 102020 7 3.2-20 10 of 18 108020 7 3.2-20 11 of 18 102020 8 3.2-20 12 of 18 108020 8 3.2-20 13 of 18 102020 9 3.2-20 14 of 18 108020 9 3.2-20 15 of 18 102020 10 3.2-20 16 of 18 108020 10 3.2-20 17 of 18 102020 11 3.2-20 18 of 18 108020 11 3.2-21 1 of 16 102021 2 Piping Schematic - Diesel Engine-Generator Systems (16 Sheets) 3.2-21 2 of 16 108021 2 3.2-21 3 of 16 102021 3 3.2-21 4 of 16 108021 3 3.2-21 5 of 16 102021 4 3.2-21 6 of 16 108021 4 3.2-21 7 of 16 102021 5 3.2-21 8 of 16 108021 5 3.2-21 9 of 16 102021 6 3.2-21 10 of 16 108021 6 3.2-21 11 of 16 102021 7 3.2-21 12 of 16 108021 7 3.2-21 13 of 16 102021 8 3.2-21 14 of 16 108021 8 3.2-21 15 of 16 102021 9 3.2-21 16 of 16 108021 9 3.2-22 1 of 12 102022 2 Piping Schematic - Turbine and Generator-Associated Systems (12 Sheets) 3.2-22 2 of 12 108022 2 3.2-22 3 of 12 102022 3 3.2-22 4 of 12 108022 3 3.2-22 5 of 12 102022 4 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 10 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 3.2-22 6 of 12 108022 4 3.2-22 7 of 12 102022 5 3.2-22 8 of 12 108022 5 3.2-22 9 of 12 102022 6 3.2-22 10 of 12 108022 6 3.2-22 11 of 12 102022 7 3.2-22 12 of 12 108022 7 3.2-23 1 of 32 102023 3 Piping Schematic - Ventilation and Air Conditioning Systems (32 Sheets) 3.2-23 2 of 32 108023 3 3.2-23 3 of 32 102023 4 3.2-23 4 of 32 108023 4 3.2-23 5 of 32 102023 5 3.2-23 6 of 32 108023 5 3.2-23 7 of 32 102023 6 3.2-23 8 of 32 108023 6 3.2-23 9 of 32 102023 7 3.2-23 10 of 32 108023 7 3.2-23 11 of 32 102023 8 3.2-23 12 of 32 108023 8 3.2-23 13 of 32 102023 9 3.2-23 14 of 32 108023 9 3.2-23 15 of 32 102023 10 3.2-23 16 of 32 108023 10 3.2-23 17 of 32 102023 11 3.2-23 18 of 32 108023 11 3.2-23 19 of 32 102023 12 3.2-23 20 of 32 108023 12 3.2-23 21 of 32 102023 13 3.2-23 22 of 32 108023 13 3.2-23 23 of 32 102023 14 3.2-23 24 of 32 108023 14 3.2-23 25 of 32 102023 16 3.2-23 25A of 32 102023 17A 3.2-23 26A of 32 102023 17B 3.2-23 26 of 32 102023 17 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 11 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 3.2-23 27 of 32 102023 15 3.2-23 28 of 32 102023 19 3.2-23 29 of 32 102023 18 3.2-23 30 of 32 108023 18 3.2-23 31 of 32 102023 20 3.2-23 32 of 32 108023 20 3.2-24 1 of 2 102024 3 Piping Schematic - Gaseous Radwaste System (2 Sheets) 3.2-24 2 of 2 108024 3 3.2-25 1 of 8 102025 3 Piping Schematic - Compressed Air System (8 Sheets) 3.2-25 2 of 8 108025 3 3.2-25 3 of 8 102025 4 3.2-25 4 of 8 108025 4 3.2-25 5 of 8 102025 5 3.2-25 6 of 8 108025 5 3.2-25 7 of 8 102025 6 3.2-25 8 of 8 108025 6 3.2-26 1 of 4 102026 3 Piping Schematic - Nitrogen and Hydrogen System (4 Sheets) 3.2-26 2 of 4 108026 3 3.2-26 3 of 4 102026 4 3.2-26 4 of 4 108026 4 3.2-27 1 of 2 102027 3 Piping Schematic - Oily Water Separator and Turbine Building Sump System (2 Sheets) 3.2-27 2 of 2 108027 3 3.5-6 505481 Auxiliary Feedwater Pump Turbine Missile Shield 3.6-2 1 of 2 438288 Containment Structure Pipe Rupture Restraints (2 sheets) 3.6-2 2 of 2 443359 3.6-5 515939 HELB Compartment Pressurization Study El. 85 ft Turbine Building 3.6-6 515940 HELB Compartment Pressurization Study El. 104 ft Turbine Building 3.6-7 515941 HELB Compartment Pressurization Study El. 119 ft Turbine Building DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 12 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 3.6-8 515942 HELB Compartment Pressurization Study El. 140 ft Turbine Building 3.6-9 515943 HELB Compartment Pressurization Study El. 60 ft Auxiliary and Containment Building 3.6-10 515944 HELB Compartment Pressurization Study El. 73 ft Auxiliary and Containment Building 3.6-11 515945 HELB Compartment Pressurization Study El. 85 ft Auxiliary and Containment Building 3.6-12 515946 HELB Compartment Pressurization Study El. 91 and 100 ft Auxiliary, Containment and Fuel Handling Bldg 3.6-13 515947 HELB Compartment Pressurization Study El. 115 ft Auxiliary, Containment and Fuel Handling Bldg 3.6-14 515948 HELB Compartment Pressurization Study El. 140 ft Auxiliary, Containment and Fuel Handling Bldg 3.6-15 515949 HELB Compartment Pressurization Study Section A-A Auxiliary Bldg 3.8-16 1 of 2 443252 Interior Concrete Outline - Plan at El. 119 ft and 140 ft, Containment Structure Areas G and F (2 sheets) 3.8-16 2 of 2 438233 3.8-17 1 of 2 443254 Interior Concrete Outline Main Sections Containment Structure (2 sheets) 3.8-17 2 of 2 438234 3.8-18 1 of 2 443276 Interior Concrete Reinforcing Typical Details and Drawing List Containment Structure (2 sheets) 3.8-18 2 of 2 438231 3.8-19 1 of 4 443277 Interior Concrete Reinforcing Sections and Details Containment Structure (4 sheets) 3.8-19 2 of 4 438239 3.8-19 3 of 4 438240 3.8-19 4 of 4 438242 3.8-20 1 of 2 443370 Concrete Outline and Reinforcing Annulus Platform at El. 140 ft, Containment Structure Areas F and G (2 sheets) 3.8-20 2 of 2 447254 3.8-23 438267 Containment Structure, Polar Crane DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 13 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 3.8-45 438431 Auxiliary Building, Concrete Outline - Plan at El. 100 ft Areas H and K 3.8-46 1 of 2 438432 Auxiliary Building, Concrete Outline - Plan at El. 115 ft Areas J, GE, and GW (2 sheets) 3.8-46 2 of 2 439533 3.8-47 1 of 3 438449 Auxiliary Building, Concrete Outline - Plans at El. 85, 100, 115, and 140 ft - Area L (3 sheets) 3.8-47 2 of 3 443204 3.8-47 3 of 3 443205 3.8-48 438445 Auxiliary Building, Concrete Outline - Section Areas J and K 3.8-49 438441 Auxiliary Building, Concrete Outline - Section Areas H and K 3.8-50 1 of 2 438457 Auxiliary Building, Concrete Reinforcing - Plan at El. 115 ft - Areas J, GE, and GW (2 sheets) 3.8-50 2 of 2 443227 3.8-51 438458 Auxiliary Building, Concrete Reinforcing - Plan at El. 115 ft - Areas H and K 3.8-52 443216 Auxiliary Building, Concrete Reinforcing - Plans at El. 115 and 140 ft - Area L 3.8-53 443460 Auxiliary Building, Concrete Reinforcing - Miscellaneous Sections - Area K 3.8-54 438471 Auxiliary Building, Concrete Reinforcing - Section Areas H, K, and GE 3.8-55 438465 Auxiliary Building, Control Room - Sections 3.8-56 438474 Auxiliary Building, Spent Fuel Pool - Concrete Reinforcing 3.8-57 439506 Auxiliary Building, Crane Support Structure - Elevations and Details 3.8-58 439507 Auxiliary Building, Crane Support Structure - Section and Details 3.8-59 439509 Auxiliary Building, Refueling Areas Overhead Crane 3.8-65 1 of 2 438034 Design Class I Tanks Concrete Foundations (2 Sheets) 3.8-65 2 of 2 463987 3.8-72 1 of 2 59459 Concrete Outline Plan - Top Deck Area 1 Intake Structure 3.8-72 2 of 2 59460 Concrete Outline Plan - Top Deck Area 2 Intake Structure DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 14 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 3.8-73 1 of 2 59461 Concrete Outline Plan - Pump Deck Area 1 Intake Structure 3.8-73 2 of 2 59462 Concrete Outline Plan - Pump Deck Area 2 Intake Structure 3.8-74 1 of 2 59463 Concrete Outline Plan - Invert Area 1 Intake Structure 3.8-74 2 of 2 59464 Concrete Outline Plan - Invert Area 2 Intake Structure 3.8-83 515213 Safety Related Masonry Walls, Turbine Bldg - Unit 1 3.8-84 515214 Safety Related Masonry Walls, Turbine Bldg - Unit 2 3.8-85 515215 Safety Related Masonry Walls, Auxiliary Bldg 5.5-13 500825 U1: Function Diagram, Reactor-Turbine Generator Protection 5.5-17 500800 U2: Function Diagram, Reactor-Turbine Generator Protection 6.2-11 6023231 1 DCPP1 Strainer Installation 6.2-11A 6023231 20 DCPP2 Strainer Installation 6.5-1 107031 4 of 36 Auxiliary Feedwater System 6.5-2 107031 1A of 36 Long Term Cooling Water System 7.2-1 1 of 18 495841 (U1) Instrumentation and Control System Logic Diagrams (18 Sheets) 7.2-1 1 of 18 495871 (U2) 7.2-1 2 of 18 495842 (U1) 7.2-1 2 of 18 495872 (U2) 7.2-1 3 of 18 495843 (U1) 7.2-1 3 of 18 495873 (U2) 7.2-1 4 of 18 495844 (U1) 7.2-1 4 of 18 495874 (U2) 7.2-1 5 of 18 495845 (U1) DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 15 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 7.2-1 5 of 18 495875 (U2) 7.2-1 6 of 18 495846 (U1) 7.2-1 6 of 18 495876 (U2) 7.2-1 7 of 18 495847 (U1) 7.2-1 7 of 18 495877 (U2) 7.2-1 8 of 18 495848 (U1) 7.2-1 8 of 18 495878 (U2) 7.2-1 9 of 18 495849 (U1) 7.2-1 9 of 18 495879 (U2) 7.2-1 10 of 18 495850 (U1) 7.2-1 10 of 18 495880 (U2) 7.2-1 11 of 18 495851 (U1) 7.2-1 11 of 18 495881 (U2) 7.2-1 12 of 18 495852 (U1) 7.2-1 12 of 18 495882 (U2) 7.2-1 13 of 18 495853 (U1) 7.2-1 13 of 18 495883 (U2) 7.2-1 14 of 18 495854 (U1) 7.2-1 14 of 18 495884 (U2) 7.2-1 15 of 18 495855 (U1) DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 16 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 7.2-1 15 of 18 495885 (U2) 7.2-1 16 of 18 495856 (U1) 7.2-1 16 of 18 495886 (U2) 7.2-1 17 of 18 495857 (U1) 7.2-1 17 of 18 495887 (U2) 7.2-1 18 of 18 495858 (U1) 7.2-1 18 of 18 495888 (U2) 7.3-1 19425 Logic Diagram Symbols 7.3-2 1 of 2 338070 Logic Diagram - Reactor Coolant Pump (2 sheets) 7.3-2 2 of 2 102787 7.3-3 1 of 2 19404 Logic Diagram - Centrifugal Charging Pump (CCP3) (2 sheets) 7.3-3 2 of 2 102788 7.3-4 1 of 2 19405 Logic Diagram - Centrifugal Charging Pumps (CCP1 and CCP2) (2 sheets) 7.3-4 2 of 2 102789 7.3-5 1 of 2 19406 Logic Diagram - Auxiliary Saltwater Pumps (2 sheets) 7.3-5 2 of 2 102790 7.3-6 1 of 2 19407 Logic Diagram - Containment Fan Coolers (2 sheets) 7.3-6 2 of 2 102791 7.3-7 1 of 2 19408 Logic Diagram - Component Cooling Water Pumps (2 sheets) 7.3-7 2 of 2 102792 7.3-8 1 of 2 19409 Logic Diagram - Auxiliary Feedwater Pumps (2 sheets) 7.3-8 2 of 2 102800 7.3-9 19410 Logic Diagram - Residual Heat Removal Pumps (2 sheets) DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 17 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 7.3-9 2 of 2 102793 7.3-10 1 of 2 19411 Logic Diagram - Safety Injection Pumps (2 sheets) 7.3-10 2 of 2 102794 7.3-11 1 of 2 19412 Logic Diagram - Containment Spray Pumps (2 sheets) 7.3-11 2 of 2 102795 7.3-12 1 of 2 19413 Logic Diagram - Primary Makeup Water Pumps (2 sheets) 7.3-12 2 of 2 102796 7.3-13 1 of 2 19414 Logic Diagram - Boric Acid Transfer Pumps (2 sheets) 7.3-13 2 of 2 102797 7.3-14 1 of 2 437507 Schematic Diagram - Auxiliary Feedwater Motor-Operated Valves (2 sheets) 7.3-14 2 of 2 441301 7.3-15 1 of 2 437551 Schematic Diagram - Turbine Control (2 sheets) 7.3-15 2 of 2 441253 7.3-16 1 of 2 437567 Schematic Diagram - Feedwater Pump Turbine Control (2 sheets) 7.3-16 2 of 2 441270 7.3-17 1 of 2 437583 Schematic Diagram - Motor-Driven Auxiliary Feedwater Pumps (2 sheets) 7.3-17 2 of 2 441302 7.3-18 1 of 4 437584 Schematic Diagram - Auxiliary Feedwater Pumps Turbine Control (4 Sheets) 7.3-18 2 of 4 455060 7.3-18 3 of 4 441303 7.3-18 4 of 4 455097 7.3-19 1 of 2 437585 Schematic Diagram - Feedwater Motor-Operated Isolation Valves (2 sheets) 7.3-19 2 of 2 441304 7.3-20 1 of 2 477846 Schematic Diagram - Reactor Coolant Pump (2 sheets) 7.3-20 2 of 2 441305 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 18 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 7.3-21 1 of 4 437587 Schematic Diagram - Reactor Coolant Motor-Operated Valves and Reactor Coolant System Solenoid Valves (4 Sheets) 7.3-21 2 of 4 437609 7.3-21 3 of 4 441306 7.3-21 4 of 4 441328 7.3-22 1 of 2 437588 Schematic Diagram - Safety Injection System Solenoid Valves (2 sheets) 7.3-22 2 of 2 441316 7.3-23 1 of 2 437589 Schematic Diagram - Safety Injection Pumps (2 sheets) 7.3-23 2 of 2 441315 7.3-24 1 of 2 437590 Schematic Diagram - Containment Spray Pumps (2 sheets) 7.3-24 2 of 2 441307 7.3-25 1 of 2 437591 Schematic Diagram - Residual Heat Removal Pumps (2 sheets) 7.3-25 2 of 2 441309 7.3-26 1 of 2 437592 Schematic Diagram - Residual Heat Removal Flow Control Valves (2 sheets) 7.3-26 2 of 2 441310 7.3-27 1 of 2 437593 Schematic Diagram - Component Cooling Water Pumps (2 sheets) 7.3-27 2 of 2 441311 7.3-28 1 of 2 437594 Schematic Diagram - Auxiliary Saltwater Pumps (2 sheets) 7.3-28 2 of 2 441287 7.3-29 1 of 2 437595 Schematic Diagram - Charging Pumps (2 sheets) 7.3-29 2 of 2 441312 7.3-30 1 of 8 437596 Schematic Diagram - Chemical and Volume Control System (8 Sheets) 7.3-30 2 of 8 437597 7.3-30 3 of 8 437598 7.3-30 4 of 8 437599 7.3-30 5 of 8 441320 7.3-30 6 of 8 441321 7.3-30 7 of 8 441322 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 19 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 7.3-30 8 of 8 477316 7.3-31 1 of 4 437600 1 Schematic Diagram - Containment Fan Coolers (4 sheets) 7.3-31 2 of 4 437600 2 7.3-31 3 of 4 441313 1 7.3-31 4 of 4 441313 2 7.3-32 1 of 2 437604 Schematic Diagram - Containment Spray System Motor-Operated Valves (2 sheets) 7.3-32 2 of 2 441308 7.3-33 1 of 4 437605 Schematic Diagram - Safety Injection System Motor-Operated Valves (4 Sheets) 7.3-33 2 of 4 437606 7.3-33 3 of 4 441317 7.3-33 4 of 4 441318 7.3-34 1 of 2 437607 Schematic Diagram - Chemical and Volume Control System Motor-Operated Valves . (2 sheets) 7.3-34 2 of 2 441324 7.3-35 1 of 2 437608 Schematic Diagram - Component Cooling Water System Motor-Operated Valves (2 sheets) 7.3-35 2 of 2 441325 7.3-36 1 of 2 437610 Schematic Diagram - Reactor Trip Breakers (2 sheets) 7.3-36 2 of 2 441489 7.3-37 437630 Schematic Diagram - Fire Pumps 7.3-38 1 of 2 437631 Schematic Diagram - Containment Purge System (2 sheets) 7.3-38 2 of 2 441490 7.3-39 437632 Schematic Diagram - Plant Air Compressors 7.3-40 1 of 4 437634 Schematic Diagram - Control Rod Drive Motor Generator Set (4 Sheets) 7.3-40 2 of 4 437603 7.3-40 3 of 4 441488 7.3-40 4 of 4 441487 7.3-41 437657 Schematic Diagram - Diesel Fuel Transfer Pumps DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 20 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 7.3-42 1 of 2 437679 Schematic Diagram - Main Steam Isolation Valves (2 sheets) 7.3-42 2 of 2 441296 7.3-43 1 of 2 437680 Schematic Diagram - Sampling System Solenoid Valves (2 sheets) 7.3-43 2 of 2 441329 7.3-44 1 of 2 437681 Schematic Diagram - Component Cooling Water Solenoid Valves (2 sheets) 7.3-44 2 of 2 441330 7.3-45 1 of 4 437682 Schematic Diagram - Chemical and Volume Control System Solenoid Valves (4 Sheets) 7.3-45 2 of 4 437683 7.3-45 3 of 4 441326 7.3-45 4 of 4 441327 7.3-46 1 of 2 437684 Schematic Diagram - Liquid Radwaste Solenoid Valves (2 sheets) 7.3-46 2 of 2 441319 7.3-47 1 of 2 437685 Schematic Diagram - Steam Generator Blowdown Solenoid Valves (2 sheets) 7.3-47 2 of 2 441461 7.3-48 1 of 4 437557 Schematic Diagram - Generator Control (4 Sheets) 7.3-48 2 of 4 437558 7.3-48 3 of 4 441245 7.3-48 4 of 4 441246 7.3-49 1 of 2 437701 Schematic Diagram - Permissive and Bypass Lights (2 sheets) 7.3-49 2 of 2 441369 7.3-50 1 of 2 445650 Separation and Color Code Instrumentation and Control - Engineered Safety Features (3 Sheets) 7.3-50 2A of 2 442561 (U2) 7.3-50 2 of 2 445651 (U1) 7.3-52 1 of 4 057673 Containment Electrical Penetrations, Cable Trays, and Supports (4 Sheets) 7.3-52 2 of 4 501445 7.3-52 3 of 4 500603 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 21 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 7.3-52 4 of 4 500793 7.6-1 1 of 6 437547 Instrumentation and Control Power Supply (6 Sheets) 7.6-1 2 of 6 445290 7.6-1 3 of 6 445291 7.6-1 4 of 6 441241 7.6-1 5 of 6 445390 7.6-1 6 of 6 445391 7.7-6 495860 Unit 1: Functional Logic Diagram, Digital Feedwater Control System, FW Flow Controller & Cv Demand 7.7-6 495890 Unit 2: Functional Logic Diagram, Digital Feedwater Control System, FW Flow Controller & Cv Demand 7.7-7 495853 Unit 1: Functional Logic Diagram, Digital Feedwater Control System, Feedwater Control & Isolation 7.7-7 495883 Unit 2: Functional Logic Diagram, Digital Feedwater Control System, Feedwater Control & Isolation 7.7-16 507613 Arrangement of Control Room 7.7-17 504479 Location of Control Console and Main Control Board 7.7-18 521120 Arrangement of Control Console Nuclear Instrumentation System (CC1), Primary Plant Control (CC2), and Secondary Plant Control (CC3) - Unit 1 7.7-19 521130 Arrangement of Control Console Nuclear Instrumentation System (CC1), Primary Plant Control (CC2), and Secondary Plant Control (CC3) - Unit 2 7.7-20 521121 Arrangement of Main Control Board - Engineered Safety Systems (VB1) - Unit 1 7.7-21 521131 Arrangement of Main Control Board - Engineered Safety Systems (VB1) - Unit 2 7.7-22 521122 Arrangement of Main Control Board - Primary Plant Systems (VB2) - Unit 1 7.7-23 521132 Arrangement of Main Control Board - Primary Plant Systems (VB2) - Unit 2 7.7-24 521123 Arrangement of Main Control Board - Steam and Turbine (VB3) - Unit 1 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 22 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 7.7-25 521133 Arrangement of Main Control Board - Steam and Turbine (VB3) - Unit 2 7.7-26 521124 Arrangement of Main Control Board - Auxiliary Equipment and Diesel VB4) - Unit 1 7.7-27 521134 Arrangement of Main Control Board - Auxiliary Equipment and Diesel VB4) - Unit 2 7.7-28 521125 Arrangement of Main Control Board - Station Electric (VB5) - Unit 1 7.7-29 521135 Arrangement of Main Control Board - Station Electric (VB5) - Unit 2 7.7-30 1 of 2 491716 Arrangement of Hot Shutdown Remote Control Panel (2 sheets) 7.7-30 2 of 2 494122 7.7-31 330557 Arrangement of Auxiliary Building Control Panel8.1-1 502110 Plant Single Line Diagram 8.2-3 57483 General Arrangement 230-kV and 500-kV Switchyard 8.2-6 500804 Arrangement of 12-kV Startup Transformers 8.3-1 1 of 2 437529 Single Line Meter and Relay Diagram - Generator, Main, and Auxiliary Transformers, and Excitation (2 sheets) 8.3-1 2 of 2 441226 8.3-2 1 of 2 437531 Single Line Meter and Relay Diagram kV System (2 sheets) 8.3-2 2 of 2 441227 8.3-3 1 of 2 437532 Single Line Meter and Relay Diagram kV System (2 sheets) 8.3-3 2 of 2 441228 8.3-4 1 of 3 437533 Single Line Meter and Relay Diagram kV System (Vital Bus) (3 sheets) 8.3-4 2 of 3 441229 8.3-4 3 of 3 441230 8.3-5 437530 Single Line Meter and Relay Diagram kV Startup System 8.3-6 1 of 2 437916 Single Line Meter and Relay Diagram - 480-V System Bus Section F (Vital Bus) (2 sheets) 8.3-6 2 of 2 441237 8.3-7 1 of 2 437542 Single Line Meter and Relay Diagram - 480-V System Bus Section G (Vital Bus) (2 sheets) DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 23 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 8.3-7 2 of 2 441238 8.3-8 1 of 2 437543 Single Line Meter and Relay Diagram - 480-V System Bus Section H (Vital Bus) (2 sheets) 8.3-8 2 of 2 441239 8.3-9 1 of 2 437625 Schematic Diagram kV Bus Section F Automatic Transfer (2 sheets) 8.3-9 2 of 2 441352 8.3-10 1 of 2 437626 Schematic Diagram kV Bus Section G Automatic Transfer (2 sheets) 8.3-10 2 of 2 441353 8.3-11 1 of 2 437627 Schematic Diagram kV Bus Section H Automatic Transfer (2 sheets) 8.3-11 2 of 2 441354 8.3-12 1 of 11 437579 Schematic Diagram kV Diesel Generators Controls (11 Sheets) 8.3-12 2 of 11 437580 8.3-12 3 of 11 437667 8.3-12 4 of 11 437668 8.3-12 5 of 11 441357 8.3-12 6 of 11 441358 8.3-12 7 of 11 496277 8.3-12 8 of 11 496278 8.3-12 9 of 11 496279 8.3-12 10 of11 496280 8.3-12 11 of 11 496281 8.3-13 1 of 7 437665 Schematic Diagram kV Diesel Generators and Associated Circuit Breakers (7 Sheets) 8.3-13 2 of 7 437676 8.3-13 3 of 7 437666 8.3-13 4 of 7 441355 8.3-13 5 of 7 441356 8.3-13 6 of 7 496275 8.3-13 7 of 7 496276 8.3-14 1 of 3 437674 Schematic Diagram kV Diesel Generators Auxiliary Motors (3 sheets) 8.3-14 2 of 3 441359 8.3-14 3 of 3 496282 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 24 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 8.3-16 1 of 6 458863 Logic Diagram - Automatic Transfer 4-kV buses F, G, and H (6 Sheets) 8.3-16 2 of 6 458864 8.3-16 3 of 6 458865 8.3-16 4 of 6 441286 8.3-16 5 of 6 441297 8.3-16 6 of 6 441337 8.3-17 1 of 4 437546 Class 1E 125-Vdc System (4 Sheets) 8.3-17 2 of 4 445076 8.3-17 3 of 4 445075 8.3-17 4 of 4 441240 8.3-18 1 of 2 455065 Normal (Non-Class 1E) 125-V and 250-Vdc System (2 sheets) 8.3-18 2 of 2 445295 8.3-19 1 of 2 437545 Pressurizer Heaters, Single Line Diagram (2 sheets) 8.3-19 2 of 2 441218 8.3-20 1 of 2 437614 Schematic Diagram Potential and Synchronizing 4160-Volt System (Vital Bus) (2 sheets) 8.3-20 2 of 2 441340 9.4-1 511157 Air Conditioning, Heating, Cooling, and Ventilation Systems - Control Room 9.4-2 1 of 2 59316 Air Conditioning, Cooling, and Ventilation Systems - Auxiliary Building (2 sheets) 9.4-2 2 of 2 501365 9.4-3 59317 Ventilation Flow Diagram Containment Fuel Handling Fan Rooms (Unit 1) 9.4-3A 501366 Ventilation Flow Diagram Containment Fuel Handling Fan Rooms (Unit 2) 9.4-8 516103 Ventilation System - Inverter Rooms and 480 V Switchgear Room in Auxiliary Building 9.4-10 512904 Ventilation Systems - Technical Support Center and Post-Accident Sampling Room 9.5-8 508845 Diesel Fuel Oil Transfer Pump Vaults 9.5-9 438165 Diesel Generator Fuel Oil Piping DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 25 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 9.5-10 1 of 4 500002 Diesel Generator Arrangement Plan (4 sheets) 9.5-10 2 of 4 500852 9.5-10 3 of 4 498992 9.5-10 4 of 4 498993 9.5-11 1 of 2 500003 Diesel Generator Arrangement Sections (2 sheets) 9.5-11 2 of 2 500853 9.5-12 663082 2 Diesel Engine Generator (Typical) 9.5F-1 515562 Fire Areas, Turbine Building Elevation 85 ft 9.5F-2 515563 Fire Areas, Turbine Building Elevation 104 ft 9.5F-3 515564 Fire Areas, Turbine Building Elevation 119 ft 9.5F-4 515565 Fire Areas, Turbine Building Elevation 140 ft 9.5F-5 515566 Fire Areas, Auxiliary Building Elevation 54 ft and 64 ft 9.5F-6 515567 Fire Areas, Auxiliary Building Elevation 75 ft 9.5F-7 515568 Fire Areas, Auxiliary Building + Containment, Elevation 85 ft 9.5F-8 515569 Fire Areas, Auxiliary Building + Containment + Fuel Handling Elevation 100 ft 9.5F-9 515570 Fire Areas, Auxiliary Building + Containment + Fuel Handling Elevation 115 ft 9.5F-10 515571 Fire Areas, Auxiliary Building + Containment + Fuel Handling Elevation 140 ft 9.5F-11 515572 Fire Areas, Auxiliary Building Elevation 125'-8", 127'-4" and 163'-4" 9.5F-12 515573 Fire Areas, Turbine Building Elevation 85 ft 9.5F-13 515574 Fire Areas, Turbine Building Elevation 104 ft 9.5F-14 515575 Fire Areas, Turbine Building Elevation 119 ft 9.5F-15 515576 Fire Areas, Turbine Building Elevation 140 ft 9.5F-16 515577 Fire Areas, Auxiliary Building + Containment + Fuel Handling Elevation 85 ft and 100 ft 9.5F-17 515578 Fire Areas, Auxiliary Building + Containment + Fuel Handling Elevation 115 ft and 140 ft 9.5F-18 515580 Fire Areas, Intake Structure 9.5F-19 515579 Fire Areas, Buttress Area 10.1-1 6021770 30 Unit 2: Heat Balance Diagram - Maximum Calculated - Post LP Retrofit DCPP UNITS 1 & 2 FSAR UPDATE TABLE 1.6-1Sheet 26 of 26 Revision 21 September 2013 Figure Sheet Drawing Sheet Description 10.1-2 6021770 22 Unit 2: Heat Balance Diagram - 100% RTO - Post LP Retrofit 10.1-5 6021770 19 Unit 1: Heat Balance Diagram - Maximum Calculated - Post LP Retrofit 10.1-6 6021770 5 Unit 1: Heat Balance Diagram - 100% RTO - Post LP Retrofit 11.5-5 502699 Solid Radwaste Storage Building FIGURE 1.2-1 PLOT PLAN UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
DCPP UNITS 1 & 2 FSAR UPDATE i Revision 21 September 2013 Chapter 2 SITE CHARACTERISTICS CONTENTS Section Title Page 2.1 GEOGRAPHY AND DEMOGRAPHY 2.1-1
2.1.1 Site Location 2.1-1
2.1.2 Site Description 2.1-1 2.1.2.1 Exclusion Area Control 2.1-2 2.1.2.2 Boundaries for Establishing Effluent Release Limits 2.1-3
2.1.3 Population and Population Distribution 2.1-3 2.1.3.1 Population Within 10 Miles 2.1-4 2.1.3.2 Population Between 10 and 50 Miles 2.1-4 2.1.3.3 Low Population Zone 2.1-4 2.1.3.4 Transient Population 2.1-5 2.1.3.5 Population Center Distance 2.1-5 2.1.3.6 Public Facilities and Institutions 2.1-5
2.1.4 Uses of Adjacent Lands and Waters 2.1-6 2.1.4.1 Agriculture 2.1-6 2.1.4.2 Dairying 2.1-6 2.1.4.3 Fisheries 2.1-6 2.1.4.4 Surface and Groundwater 2.1-7 2.1.4.5 Land Usage Within 5 Miles 2.1-7
2.1.5 References 2.1-7
2.2 NEARBY INDUSTRIAL, TRANSPORTATION, AND MILITARY FACILITIES 2.2-1
2.2.1 Locations and Routes 2.2-1
2.2.2 Descriptions 2.2-3
2.2.3 Evaluations 2.2-3
2.2.4 References 2.2-4
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 2 CONTENTS (Continued) Section Title Page ii Revision 21 September 2013 2.3 METEOROLOGY 2.3-1 2.3.1 Regional Climatology 2.3-1 2.3.1.1 Data Sources 2.3-1 2.3.1.2 General Climate 2.3-1 2.3.1.3 Severe Weather 2.3-2 2.3.2 Local Meteorology 2.3-3 2.3.2.1 Data from Offsite Sources 2.3-3 2.3.2.2 Onsite Normal and Extreme Values of Meteorological Parameters 2.3-3 2.3.2.3 Potential Influence of the Plant and Its Facilities on Local Meteorology 2.3-11 2.3.2.4 Topographical Description 2.3-11
2.3.3 Onsite Meteorological Measurement Program 2.3-12 2.3.3.1 Wind Measurement System 2.3-17 2.3.3.2 Temperature Measurement System 2.3-17 2.3.3.3 Dew Point Measurement System 2.3-17 2.3.3.4 Precipitation Measurement System 2.3-18 2.3.3.5 Supplemental Measurement System 2.3-18 2.3.3.6 Meteorological Datalogger 2.3-19 2.3.3.7 Meteorological Computers 2.3-20 2.3.3.8 Power Supply for Meteorological Equipment 2.3-23
2.3.4 Short-Term (Accident) Diffusion Estimates 2.3-23 2.3.4.1 Objective 2.3-23 2.3.4.2 Calculations 2.3-23
2.3.5 Long-Term (Routine) Diffusion Estimates 2.3-25 2.3.5.1 Objective 2.3-25 2.3.5.2 Calculations 2.3-25 2.3.5.3 Meteorological Parameters 2.3-25
2.3.6 Conclusions 2.3-27
2.3.7 References 2.3-27 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 2 CONTENTS (Continued) Section Title Page iii Revision 21 September 2013 2.4 HYDROLOGIC ENGINEERING 2.4-1 2.4.1 Hydrologic Description 2.4-1 2.4.1.1 Site and Facilities 2.4-1 2.4.1.2 Hydrosphere 2.4-1
2.4.2 Floods 2.4-2 2.4.2.1 Flood History 2.4-2 2.4.2.2 Flood Design Considerations 2.4-2
2.4.3 Probable Maximum Flood (PMF) on Streams and Rivers 2.4-4 2.4.3.1 Probable Maximum Precipitation 2.4-5 2.4.3.2 Precipitation Losses 2.4-5 2.4.3.3 Runoff Model 2.4-6 2.4.3.4 Probable Maximum Flood Flow 2.4-7 2.4.3.5 Water Level Determinations 2.4-7 2.4.3.6 Coincident Wind Wave Activity 2.4-7
2.4.4 Potential Dam Failures (Seismically Induced) 2.4-8
2.4.5 Probable Maximum Surge and Seiche Flooding 2.4-8 2.4.5.1 Probable Maximum Winds and Associated Meteorological Parameters 2.4-8 2.4.5.2 Surge and Seiche History 2.4-8 2.4.5.3 Surge and Seiche Sources 2.4-8 2.4.5.4 Wave Action 2.4-8 2.4.5.5 Resonance/Ponding 2.4-9 2.4.5.6 Runup and Drawdown 2.4-10 2.4.5.7 Protective Structures 2.4-10
2.4.6 Probable Maximum Tsunami Flooding 2.4-10 2.4.6.1 Probable Maximum Tsunami 2.4-10 2.4.6.2 Historical Tsunami Record 2.4-13 2.4.6.3 Source of Tsunami Wave Height 2.4-14 2.4.6.4 Tsunami Height Offshore 2.4-14 2.4.6.5 Hydrography and Harbor or Breakwater Influences on Tsunami 2.4-14 2.4.6.6 Effects on Safety-Related Facilities 2.4-15 2.4.6.7 Background and Evolution of the Tsunami Design Basis 2.4-16
2.4.7 Ice Flooding 2.4-16
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 2 CONTENTS (Continued) Section Title Page iv Revision 21 September 2013 2.4.8 Cooling Water Canals and Reservoirs 2.4-16 2.4.9 Channel Diversions 2.4-16
2.4.10 Flooding Protection Requirements 2.4-17
2.4.11 Low Water Considerations 2.4-17 2.4.11.1 Low Flow in Rivers and Streams 2.4-17 2.4.11.2 Low Water Resulting from Surges, Seiches, or Tsunamis 2.4-17 2.4.11.3 Historical Low Water 2.4-17 2.4.11.4 Future Control 2.4-17 2.4.11.5 Plant Requirements 2.4-17 2.4.11.6 Heat Sink Dependability Requirements 2.4-18
2.4.12 Environmental Acceptance of Effluents 2.4-18
2.4.13 Groundwater 2.4-18 2.4.13.1 Description and Onsite Use 2.4-18 2.4.13.2 Monitoring and Safeguard Requirements 2.4-19
2.4.14 Technical Specifications and Emergency Operation Requirements 2.4-19 2.4.15 References 2.4-19
2.4-16 Reference Drawings 2.4-22
2.5 GEOLOGY AND SEISMOLOGY 2.5-1
2.5.1 Design Basis 2.5-3 2.5.1.1 General Design Criterion 2, 1967 Performance Standards 2.5-3 2.5.1.2 License Condition 2.C(7) of DCPP Facility Operating License DPR-80 Rev. 44 (LTSP), Elements (1), (2) and (3) 2.5-4 2.5.1.3 CFR Part 100, March 1966- Reactor Site Criteria 2.5.4
2.5.2 Basic Geologic and Seismic Information 2.5-4 2.5.2.1 Regional Geography 2.5-5 2.5.2.2 Site Geology 2.5-25
2.5.3 Vibratory Ground Motion 2.5-56 2.5.3.1 Geologic Conditions of the Site and Vicinity 2.5-56 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 2 CONTENTS (Continued) Section Title Page v Revision 21 September 2013 2.5.3.2 Underlying Tectonic Structures 2.5-56 2.5.3.3 Behavior During Prior Earthquakes 2.5-57 2.5.3.4 Engineering Properties of Materials Underlying the Site 2.5-57 2.5.3.5 Earthquake History 2.5-57 2.5.3.6 Correlation of Epicenters with Geologic Structures 2.5-58 2.5.3.7 Results of Faulting Investigation 2.5-59 2.5.3.8 Description of Active Faults 2.5-59 2.5.3.9 Design and Licensing Basis Earthquakes 2.5-59 2.5.3.10 Ground Accelerations and Response Spectra 2.5-62
2.5.4 Surface Faulting 2.5-67 2.5.4.1 Geologic Conditions of the Site 2.5-67 2.5.4.2 Evidence for Fault Offset 2.5-67 2.5.4.3 Identification of Active Faults 2.5-67 2.5.4.4 Earthquakes Associated with Active Faults 2.5-67 2.5.4.5 Correlation of Epicenters with Active Faults 2.5-69 2.5.4.6 Description of Active Faults 2.5-71 2.5.4.7 Results of Faulting Investigation 2.5-71
2.5.5 Stability of Subsurface Materials 2.5-71 2.5.5.1 Geologic Features 2.5-71 2.5.5.2 Properties of Underlying Materials 2.5-76 2.5.5.3 Plot Plan 2.5-76 2.5.5.4 Soil and Rock Characteristics 2.5-76 2.5.5.5 Excavations and Backfill 2.5-76 2.5.5.6 Groundwater Conditions 2.5-76 2.5.5.7 Response of Soil and Rock to Dynamic Loading 2.5-77 2.5.5.8 Liquefaction Potential 2.5-77 2.5.5.9 Earthquake Design Basis 2.5-77 2.5.5.10 Static Analysis 2.5-77 2.5.5.11 Criteria and Design Methods 2.5.77 2.5.5.12 Techniques to Improve Subsurface Conditions 2.5-77
2.5.6 Slope Stability 2.5-78 2.5.6.1 Slope Characteristics 2.5-78 2.5.6.2 Design Criteria and Analyses 2.5-79 2.5.6.3 Slope Stability for Buried Auxiliary Saltwater System Piping 2.5-80
2.5.7 Long Term Seismic Program 2.5-80 2.5.7.1 Shoreline Fault Zone 2.5-81 2.5.7.2 Evaluation of Updated Estimates of Ground Motion 2.5-82 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 2 CONTENTS (Continued) Section Title Page vi Revision 21 September 2013 2.5.8 Safety Evaluation 2.5-82 2.5.8.1 General Design Criterion 2, 1967 Performance Standards 2.5-82 2.5.8.2 License Condition 2.C(7) of DCPP Facility Operating License DPR-80 Rev 44 (LTSP), Elements (1), (2) and (3) 2.5-82 2.5.8.3 10 CFR Part 100, March 1966 - Reactor Site Criteria 2.5-83
2.5.9 References 2.5-83 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 2 TABLES Table Title vii Revision 21 September 2013 2.1-1 Population Trends of the State of California and of San Luis Obispo and Santa Barbara Counties 2.1-2 Growth of Principal Communities Within 50 Miles of DCPP Site
2.1-3 Population Centers of 1000 or More Within 50 Miles of DCPP Site
2.1-4 Transient Population at Recreation Areas Within 50 Miles of DCPP Site
2.1-5 1985 Land Use Census -- Distances in Miles from the Unit 1 Centerline to the Nearest Milk Animal, Residence, Vegetable Garden 2.3-1 Persistence of Calm at Diablo Canyon Expressed As Percentage of Total Hourly Observations for Which the Mean Hourly Wind Speed Was Less Than 1 Mile Per Hour for More Than 1 to 10 Hours 2.3-2 Normalized Annual Ground Level Concentrations Downwind from DCPP Site Ground Release 2.3-3 Monthly Mixing Heights at DCPP Site
2.3-4 Estimates of Relative Concentrations at Specified Locations Downwind of DCPP Site 2.3-5 Deleted in Revision 2
2.3-6 DCPP Site Precipitation Data
2.3-7 DCPP Site Temperature Data
2.3-8 Percentage Frequency of Occurrence, Directions by Speed Groups - All Months - Santa Maria 2.3-9 Percentage Frequency of Occurrence, Directions by Speed Groups - January - Santa Maria 2.3-10 Percentage Frequency of Occurrence, Directions by Speed Groups - February - Santa Maria 2.3-11 Percentage Frequency of Occurrence, Directions by Speed Groups - March - Santa Maria DCPP UNITS 1 & 2 FSAR UPDATE Chapter 2 TABLES (Continued) Table Title viii Revision 21 September 2013 2.3-12 Percentage Frequency of Occurrence, Directions by Speed Groups - April - Santa Maria 2.3-13 Percentage Frequency of Occurrence, Directions by Speed Groups - May - Santa Maria 2.3-14 Percentage Frequency of Occurrence, Directions by Speed Groups - June - Santa Maria 2.3-15 Percentage Frequency of Occurrence, Directions by Speed Groups - July - Santa Maria 2.3-16 Percentage Frequency of Occurrence, Directions by Speed Groups - August - Santa Maria 2.3.17 Percentage Frequency of Occurrence, Directions by Speed Groups - September - Santa Maria 2.3-18 Percentage Frequency of Occurrence, Directions by Speed Groups - October - Santa Maria 2.3-19 Percentage Frequency of Occurrence, Directions by Speed Groups - November - Santa Maria 2.3-20 Percentage Frequency of Occurrence, Directions by Speed Groups - December - Santa Maria 2.3-21 Extremely Unstable, Frequency Table - Diablo Canyon
2.3-22 Moderately Unstable, Frequency Table - Diablo Canyon
2.3-23 Slightly Unstable, Frequency Table - Diablo Canyon
2.3-24 Neutral, Frequency Table - Diablo Canyon
2.3-25 Slightly Stable, Frequency Table - Diablo Canyon
2.3-26 Moderately Stable, Frequency Table - Diablo Canyon
2.3-27 Extremely Stable, Frequency Table - Diablo Canyon
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 2 TABLES (Continued) Table Title ix Revision 21 September 2013 2.3-28 DCPP Site - Distribution of Wind Speed Observations by Stability Class 2.3-29 DCPP Site - Station E 25 foot Level, Vertical Angle Stability Class A
2.3-30 DCPP Site - Station E 25 foot Level, Vertical Angle Stability Class B
2.3-31 DCPP Site - Station E 25 foot Level, Vertical Angle Stability Class C
2.3-32 DCPP Site - Station E 25 foot Level, Vertical Angle Stability Class D
2.3-33 DCPP Site - Station E 25 foot Level, Vertical Angle Stability Class E
2.3-34 DCPP Site - Station E 25 foot Level, Vertical Angle Stability Classes F and G 2.3-35 DCPP Site - Station E 25 foot Level, Azimuth Angle Stability Class A
2.3-36 DCPP Site - Station E 25 foot Level, Azimuth Angle Stability Class B 2.3-37 DCPP Site - Station E 25 foot Level, Azimuth Angle Stability Class C
2.3-38 DCPP Site - Station E 25 foot Level, Azimuth Angle Stability Class D
2.3-39 DCPP Site - Station E 25 foot Level, Azimuth Angle Stability Class E
2.3-40 DCPP Site - Station E 25 foot Level, Azimuth Angle Stability Class F and G 2.3-41 Cumulative Percentage Distributions of /Q Estimates at the Outer Boundary of the LPZ at DCPP Site 2.3-42 DCPP Site - Stability Based on Vertical Temperature Gradient, Extremely Unstable 2.3-43 DCPP Site - Stability Based on Vertical Temperature Gradient, Moderately Unstable 2.3-44 DCPP Site - Stability Based on Vertical Temperature Gradient, Slightly Unstable 2.3-45 DCPP Site - Stability Based on Vertical Temperature Gradient, Neutral
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 2 TABLES (Continued) Table Title x Revision 21 September 2013 2.3-46 DCPP Site - Stability Based on Vertical Temperature Gradient, Slightly Stable 2.3-47 DCPP Site - Stability Based on Vertical Temperature Gradient, Moderately Stable 2.3-48 DCPP Site - Stability Based on Vertical Temperature Gradient, Extremely Stable 2.3-49 DCPP Site Wind Data, Stability Class A, Annual
2.3-50 DCPP Site Wind Data, Stability Class B, Annual
2.3-51 DCPP Site Wind Data, Stability Class C, Annual
2.3-52 DCPP Site Wind Data, Stability Class D, Annual
2.3-53 DCPP Site Wind Data, Stability Class E, Annual 2.3-54 DCPP Site Wind Data, Stability Class F, Annual
2.3-55 DCPP Site Wind Data, Stability Class G, Annual
2.3-56 DCPP Site Wind Data, Stability Class A, January
2.3-57 DCPP Site Wind Data, Stability Class B, January
2.3-58 DCPP Site Wind Data, Stability Class C, January
2.3-59 DCPP Site Wind Data, Stability Class D, January
2.3-60 DCPP Site Wind Data, Stability Class E, January
2.3-61 DCPP Site Wind Data, Stability Class F, January
2.3-62 DCPP Site Wind Data, Stability Class G, January
2.3-63 DCPP Site Wind Data, Stability Class A, February
2.3-64 DCPP Site Wind Data, Stability Class B, February
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 2 TABLES (Continued) Table Title xi Revision 21 September 2013 2.3-65 DCPP Site Wind Data, Stability Class C, February 2.3-66 DCPP Site Wind Data, Stability Class D, February
2.3-67 DCPP Site Wind Data, Stability Class E, February
2.3-68 DCPP Site Wind Data, Stability Class F, February
2.3-69 DCPP Site Wind Data, Stability Class G, February
2.3-70 DCPP Site Wind Data, Stability Class A, March
2.3-71 DCPP Site Wind Data, Stability Class B, March
2.3-72 DCPP Site Wind Data, Stability Class C, March
2.3-73 DCPP Site Wind Data, Stability Class D, March 2.3-74 DCPP Site Wind Data, Stability Class E, March 2.3-75 DCPP Site Wind Data, Stability Class F, March
2.3-76 DCPP Site Wind Data, Stability Class G, March
2.3-77 DCPP Site Wind Data, Stability Class A, April
2.3-78 DCPP Site Wind Data, Stability Class B, April
2.3-79 DCPP Site Wind Data, Stability Class C, April
2.3-80 DCPP Site Wind Data, Stability Class D, April
2.3-81 DCPP Site Wind Data, Stability Class E, April
2.3-82 DCPP Site Wind Data, Stability Class F, April
2.3-83 DCPP Site Wind Data, Stability Class G, April
2.3-84 DCPP Site Wind Data, Stability Class A, May
2.3-85 DCPP Site Wind Data, Stability Class B, May DCPP UNITS 1 & 2 FSAR UPDATE Chapter 2 TABLES (Continued) Table Title xii Revision 21 September 2013 2.3-86 DCPP Site Wind Data, Stability Class C, May 2.3-87 DCPP Site Wind Data, Stability Class D, May
2.3-88 DCPP Site Wind Data, Stability Class E, May
2.3-89 DCPP Site Wind Data, Stability Class F, May
2.3-90 DCPP Site Wind Data, Stability Class G, May
2.3-91 DCPP Site Wind Data, Stability Class A, June
2.3-92 DCPP Site Wind Data, Stability Class B, June
2.3-93 DCPP Site Wind Data, Stability Class C, June
2.3-94 DCPP Site Wind Data, Stability Class D, June 2.3-95 DCPP Site Wind Data, Stability Class E, June 2.3-96 DCPP Site Wind Data, Stability Class F, June
2.3-97 DCPP Site Wind Data, Stability Class G, June
2.3-98 DCPP Site Wind Data, Stability Class A, July
2.3-99 DCPP Site Wind Data, Stability Class B, July
2.3-100 DCPP Site Wind Data, Stability Class C, July
2.3-101 DCPP Site Wind Data, Stability Class D, July
2.3-102 DCPP Site Wind Data, Stability Class E, July
2.3-103 DCPP Site Wind Data, Stability Class F, July
2.3-104 DCPP Site Wind Data, Stability Class G, July
2.3-105 DCPP Site Wind Data, Stability Class A, August
2.3-106 DCPP Site Wind Data, Stability Class B, August DCPP UNITS 1 & 2 FSAR UPDATE Chapter 2 TABLES (Continued) Table Title xiii Revision 21 September 2013 2.3-107 DCPP Site Wind Data, Stability Class C, August 2.3-108 DCPP Site Wind Data, Stability Class D, August
2.3-109 DCPP Site Wind Data, Stability Class E, August
2.3-110 DCPP Site Wind Data, Stability Class F, August
2.3-111 DCPP Site Wind Data, Stability Class G, August
2.3-112 DCPP Site Wind Data, Stability Class A, September
2.3-113 DCPP Site Wind Data, Stability Class B, September
2.3-114 DCPP Site Wind Data, Stability Class C, September
2.3-115 DCPP Site Wind Data, Stability Class D, September 2.3-116 DCPP Site Wind Data, Stability Class E, September 2.3-117 DCPP Site Wind Data, Stability Class F, September
2.3-118 DCPP Site Wind Data, Stability Class G, September
2.3-119 DCPP Site Wind Data, Stability Class A, October
2.3-120 DCPP Site Wind Data, Stability Class B, October
2.3-121 DCPP Site Wind Data, Stability Class C, October
2.3-122 DCPP Site Wind Data, Stability Class D, October
2.3-123 DCPP Site Wind Data, Stability Class E, October
2.3-124 DCPP Site Wind Data, Stability Class F, October
2.3-125 DCPP Site Wind Data, Stability Class G, October
2.3-126 DCPP Site Wind Data, Stability Class A, November
2.3-127 DCPP Site Wind Data, Stability Class B, November DCPP UNITS 1 & 2 FSAR UPDATE Chapter 2 TABLES (Continued) Table Title xiv Revision 21 September 2013 2.3-128 DCPP Site Wind Data, Stability Class C, November 2.3-129 DCPP Site Wind Data, Stability Class D, November
2.3-130 DCPP Site Wind Data, Stability Class E, November
2.3-131 DCPP Site Wind Data, Stability Class F, November
2.3-132 DCPP Site Wind Data, Stability Class G, November
2.3-133 DCPP Site Wind Data, Stability Class A, December
2.3-134 DCPP Site Wind Data, Stability Class B, December
2.3-135 DCPP Site Wind Data, Stability Class C, December
2.3-136 DCPP Site Wind Data, Stability Class D, December 2.3-137 DCPP Site Wind Data, Stability Class E, December 2.3-138 DCPP Site Wind Data, Stability Class F, December
2.3-139 DCPP Site Wind Data, Stability Class G, December
2.3-140 Deleted in Revision 9
2.3-141 Ranges of Stability Classification Parameters for Each Stability Category at DCPP Site 2.3-142 Summary of Meteorological Data for Diffusion Experiments at DCPP Site
2.3-143 Deleted in Revision 2
2.3-144 DCPP Site Nighttime P-G Stability Categories Based on 2.4-1 Probable Maximum Precipitation (PMP) As a Function of Duration at DCPP Site As Determined from USWB HMR No. 36 2.5-1 Listing of Earthquakes Within 75 Miles of the Diablo Canyon Power Plant Site DCPP UNITS 1 & 2 FSAR UPDATE Chapter 2 TABLES (Continued) Table Title xv Revision 21 September 2013 2.5-2 Summary, Revised Epicenters of Representative Samples of Earthquakes off the Coast of California Near San Luis Obispo 2.5-3 Displacement History of Faults in the Southern Coast Ranges of California
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 2 FIGURES Figure Title xvi Revision 21 September 2013 2.1-1 Site Location Map 2.1-2 Site Plan and Gaseous Liquid Effluent Release Points
2.1-3 Aerial Photograph of the Site
2.1-4 Population Distribution, 0 to 10 Miles, 1990 Census 2.1-5 Population Distribution, 0 to 10 Miles, 2010 Projected
2.1-6 Population Distribution, 0 to 10 Miles, 2025 Projected
2.1-7 Population Distribution, 10 to 50 Miles, 1990 Census
2.1-8 Population Distribution, 10 to 50 Miles, 2010 projected
2.1-9 Population Distribution, 10 to 50 Miles, 2025 Projected
2.1-10 Deleted in Revision 8
2.1-11 Deleted in Revision 8
2.1-12 Deleted in Revision 8
2.1-13 Deleted in Revision 8
2.1-14 1985 Land Use Census
2.1-15 Low Population Zone
2.3-1 Topographical Features at Cross Sections to a 10 mile Radius
2.3-2 Topographical Features at Cross Sections to a 10 mile Radius
2.3-3 Location of Meteorological Stations Within the Site Boundary
2.3-4 Location of Meteorological Measurement Sites at Diablo Canyon and Vicinity 2.4-1 Plant Site Location Drainage and Topography (2 sheets) DCPP UNITS 1 & 2 FSAR UPDATE Chapter 2 FIGURES (Continued) Figure Title xvii Revision 21 September 2013 2.4-2 Surface Drainage Plan 2.4-3 Diablo Creek from Foot of 230 kV Switchyard to Pacific Ocean
2.4-4 Optimization of Fit, Diablo - Los Berros (3 sheets)
2.4-5 Design Flood Hydrograph (3 sheets) 2.4-6 General Layout of Breakwaters (2 sheets)
2.4-7(a) Typical Sections for Tribar Armor Construction 2.4-8(a) Restored Cross-sections and Embedment Plan 2.4-9 Dimensions for Tribars
2.5-1 Plant Site Location and Topography
2.5-2 Earthquake Epicenters Within 200 Miles of Plant Site
2.5-3 Faults and Earthquake Epicenters Within 75 Miles of Plant Site (For Earthquakes with Assigned Magnitudes) 2.5-4 Faults and Earthquake Epicenters Within 75 Miles of Plant Site (For Earthquakes with Assigned Intensities Only) 2.5-5 Geologic and Tectonic Map of Southern Coast Ranges in the Region of Plant Site (2 sheets) 2.5-6 Geologic Map of the Morro Bay South and Port San Luis Quadrangles, San Luis Obispo County, California, and Adjacent Offshore Area 2.5-7 Geologic Section Through Exploratory Oil Wells in the San Luis Range
2.5-8 Geologic Map of Diablo Canyon Coastal Area
2.5-9 Geologic Map of Switchyard Area
2.5-10 Geologic Section Through the Plant Site
2.5-11 Site Exploration Features and Bedrock Contours DCPP UNITS 1 & 2 FSAR UPDATE Chapter 2 FIGURES (Continued) Figure Title xviii Revision 21 September 2013 2.5-12 Unit 1 - Geologic Sections and Sketches Along Exploratory Trenches 2.5-13 Unit 2 - Geologic Sections and Sketches Along Exploratory Trenches
2.5-14 Relationships of Faults and Shears at Plant Site
2.5-15 Geologic Map of Excavations for Plant Facilities 2.5-16 Geologic Sections Through Excavations for Plant Facilities 2.5-17 Plan of Excavation and Backfill 2.5-18 Section A-A, Excavation and Backfill 2.5-19 Soil Modulus of Elasticity and Poisson's Ratio 2.5-20 Smooth Response Acceleration Spectra - Earthquake "B" 2.5-21 Smooth Response Acceleration Spectra - Earthquake "D" Modified 2.5-22 Power Plant Slope - Plan 2.5-23 Power Plant Slope - Log of Boring 1 2.5-24 Power Plant Slope - Log of Boring 2 2.5-25 Power Plant Slope - Log of Boring 3 2.5-26 Power Plant Slope - Log of Test Pits 1 and 2 2.5-27 Power Plant Slope - Log of Test Pit 3 2.5-28 Power Plant Slope - Soil Classification Chart and Key to Test Data 2.5-29 Free Field Spectra (Horizontal), Hosgri: 7.5M/Blume 2.5-30 Free Field Spectra (Horizontal), Hosgri: 7.5M/Newmark 2.5-31 Free Field Spectra (Vertical), Hosgri: 7.5M/Blume 2.5-32 Free Field Spectra (Vertical), Hosgri: 7.5M/Newmark
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 2 FIGURES (Continued) Figure Title xix Revision 21 September 2013 2.5-33 Free Field Spectrum Horizontal 1991 LTSP (84th Percentile Non-Exceedance) as Modified per SSER-34 2.5-34 Free Field Spectrum Vertical 1991 LTSP (84th Percentile Non-Exceedance) as Modified per SSER-34 2.5-35 Free Field Spectra Horizontal LTSP (PG&E 1998) Ground Motion vs. Hosgri (Newmark 1977) 2.5-36 Map of Shoreline Fault Study Area
NOTE:
(a) This figure corresponds to a controlled engineering drawing that is incorporated by reference into the FSAR Update. See Table 1.6-1 for the correlation between the FSAR Update figure number and the corresponding controlled engineering drawing number.
DCPP UNITS 1 & 2 FSAR UPDATE 2.1-1 Revision 16 June 2005 Chapter 2 SITE CHARACTERISTICS This chapter provides information on the geological, seismological, hydrological, and meteorological characteristics of the Diablo Canyon Power Plant (DCPP) site and vicinity. Population distribution, land use, and site activities and controls are also discussed. This information, used in conjunction with the detailed technical discussions provided in other chapters, shows the adequacy of the site for the safe operation of nuclear power units. 2.1 GEOGRAPHY AND DEMOGRAPHY 2.1.1 SITE LOCATION The DCPP site is adjacent to the Pacific Ocean in San Luis Obispo County, California, and is approximately 12 miles west-southwest of the city of San Luis Obispo, the county seat. The reactor for Unit 1 is located at latitude 35°12'44" N and longitude 120°51'14" W. The Universal Transverse Mercator (UTM) coordinates for zone 10 are 695,350 meters E and 3,898,450 meters N. The reactor for Unit 2 is located at latitude 35°12'41" N and longitude 120°51'13" W. The UTM coordinates are 695,380 meters E and 3,898,400 meters N. Figure 2.1-1 locates the site on a map of western San Luis Obispo County. 2.1.2 SITE DESCRIPTION The site boundary and the location of principal structures are shown in Figure 2.1-2. A portion of the site is bounded by the Pacific Ocean. The DCPP site consists of approximately 750 acres of land located near the mouth of Diablo Creek. 165 acres of the DCPP site are located north of Diablo Creek; this acreage is owned by PG&E. The remaining 585 acres are located adjacent to and south of Diablo Creek. It was purchased in 1995 by Eureka Energy Company (Eureka), a wholly owned subsidiary of PG&E. All coastal properties located north of Diablo Creek, extending north to the southerly boundary of Montana de Oro State Park and reaching inland approximately 1.5 mile has been owned by PG&E since 1988. Coastal properties located south of Diablo Creek and also reaching inland approximately 1.5 mile has been owned by Eureka since 1995. Prior to 1995, PG&E leased the property from the owner, Luigi Marre Land and Cattle Company. In 1988, PG&E purchased approximately 4500 acres located north of the DCPP site. This section of land consists of approximately 5 miles of coastline and reaches inland approximately 1.5 mile. Except for the DCPP site, the approximately 4500 acres are encumbered by a grazing lease that expires in the year 2000. DCPP UNITS 1 & 2 FSAR UPDATE 2.1-2 Revision 16 June 2005 There are no plans for development of the property, most of which is within the area subject to the California Coastal Act of 1976. Any development plans would be subject to approval by a discretionary land use permitting process. In 1988 the San Luis Obispo County Planning Department was given authority by the California Coastal Commission to interpret the Act and incorporate it into the County of San Luis Obispo's General Plan, which included the right to issue coastal land use permits. Because it is a discretionary permitting process, the County of San Luis Obispo has the authority to require development projects to be approved by the California Coastal Commission rather than obtaining final approval by the County of San Luis Obispo, Board of Supervisors. In addition, portions of the coastal property have been listed in the National Register of Historic Places pursuant to the "National Historic Preservation Act of 1966" as a place of historic significance due to the presence of numerous Native American remains and scientific data potential. PG&E has complete authority to determine all activities within the site boundary and this authority extends to the mean high water line along the ocean. On land, the site boundary, the boundary of the exclusion area (as defined in 10 CFR 100), and the boundary of the unrestricted area (as defined in 10 CFR 20) are shown in Figure 2.1-2. Minimum distances from potential release points for radioactive materials to the unrestricted area boundary and to the mean high water line are also shown in Figure 2.1-2. The definition of unrestricted area has been expanded over that in 10 CFR 20.1003. The unrestricted area boundary may coincide with the exclusion (fenced) area boundary, as defined in 10 CFR 1003, but the unrestricted area does not include areas over water bodies. The concept of unrestricted areas, established at or beyond the site boundary, is utilized in the Technical Specifications limiting conditions for operation to keep levels of radioactive materials in liquid and gaseous effluents as low as is reasonably achievable, pursuant to 10 CFR 50.36a. 2.1.2.1 Exclusion Area Control On land, there are no activities unrelated to plant operation within the exclusion area; it is not traversed by public highway or railroad. Normal access to the site is from the south by private road (PG&E road easement) that is fenced and posted by PG&E. PG&E has the right, within the DCPP site, to use excavated materials during the construction of the plant (considering that PG&E obtains all permitting required by regulatory agencies prior to excavation). It is unclear legally if the owner retains all mineral rights. Whatever mineral rights an owner may retain, the owner cannot exercise any such rights in a manner that would interfere with PG&E's rights. Any proposed mining operation (including but not limited to excavation, drilling, and blasting) that would be conducted close enough to the plant to threaten the structural integrity of its foundations will be carefully reviewed and PG&E will take whatever steps it deems DCPP UNITS 1 & 2 FSAR UPDATE 2.1-3 Revision 16 June 2005 necessary to ensure that: (a) the health and safety of the public is not jeopardized, and (b) the operation of the plant is not disrupted. Any entry by the lessee onto the land is subject to PG&E's safety rules and regulations, as is the right to restrict the use of buildings and other structures, and to exclude persons therefrom to the extent necessary to comply with nuclear reactor site criteria. The mineral rights within the 165 acre PG&E portion of the DCPP site are owned by PG&E, but there is no information suggesting that the land contains any commercially valuable minerals other than for use as borrow materials. The offshore area (below the mean high water line) is not under PG&E's control. Due to the natural rough and precipitous conditions of the offshore area at Diablo Cove and near its southerly boundary, as shown in the aerial photograph, Figure 2.1-3, the area could only be occupied with great difficulty. (Some of these rocks have since been incorporated into the breakwater.) There is no history of public access to these rocks. The Captain of the Port of Los Angeles-Long Beach, under the authority of 33 U.S.C. Section 1226 and Section 1231, has established a Security Zone in the Pacific Ocean, from surface to bottom, within a 2,000-yard radius of DCPP centered at position 35 12' 23"N, 120 51' 23" W (Datum 83). No person or vessel may enter or remain in this Security Zone without the permission of the Captain of the Port Los Angeles-Long Beach. This Security Zone will be enforced by representatives of the Captain of the Port of Los Angeles-Long Beach, San Luis Obispo County Sheriff, and DCPP Security. 2.1.2.2 Boundaries for Establishing Effluent Release Limits On land, the boundary line of the unrestricted area (as defined in 10 CFR 20) coincides with the site boundary as shown in Figure 2.1-2. The relationship of the exclusion area to the unrestricted area and the site area is also shown in Figure 2.1-2. Control of access to the land area within this boundary is as described for the exclusion area control. As therein described, no special provisions have been made for control of access, during normal operation, to the offshore area below the mean high water line. Occupancy of this area by any member of the public is expected to result in exposures, during normal operation, within the limits established by 10 CFR 20 and will be maintained as low as reasonably achievable (ALARA). 2.1.3 POPULATION AND POPULATION DISTRIBUTION PG&E has reviewed the original population totals and projections within the 50-mile radius of the plant. The following population data are based on the 2000 census and on projections based on estimates prepared by the State of California Department of Finance. The portion of California that lies within 50 miles of the site is relatively sparsely populated, having approximately 424, 013 residents in 2000. A circle with a 50-mile radius includes most of San Luis Obispo County, about one-third of Santa Barbara County, and a minor, sparsely-populated portion of Monterey County. About DCPP UNITS 1 & 2 FSAR UPDATE 2.1-4 Revision 16 June 2005 55 percent of the area within the 50-mile circle is on land, the balance being on the Pacific Ocean. The 2000 census population of this region is very close to that projected in the original Final Safety Analysis Report (FSAR), and subsequent projections by the Department of Finance are similarly close to earlier projections. Table 2.1-1 shows population trends of the State of California and of San Luis Obispo and Santa Barbara Counties. Table 2.1-2 shows the growth since 1960 of the principal cities within 50 miles of the site. Table 2.1-3 lists all communities within 50 miles having a population of 1000 or more, gives distance and direction from the site, and gives the 2000 population. 2.1.3.1 Population Within 10 Miles In 1980, approximately 16,760 persons resided within 10 miles of the site. The 1990 census counted approximately 22,200 residents within the same 10 miles. The 2000 census counted approximately 23,661 residents within the same 10 miles. As in 1980, the nearest residence is about 1-1/2 miles north-northwest of the site and two persons occupy this dwelling. There are 9 permanently inhabited dwellings, for about 17 residents, within 5 miles of the plant. The population within the 6-mile radius, used in the emergency plan, is estimated to be 100. Figure 2.1-4 shows the 2000 population distribution within a 10-mile radius wherein the area is divided into 22-1/2° sectors, with part circles of radii of 1, 2, 3, 4, 5, and 10 miles. Figures 2.1-5 and 2.1-6 show projected population distributions for 2010 and 2025, respectively, and are based primarily on population projections published by the California Department of Finance. The distributions are based on the assumption that the land usage will not change in character during the next 25 years, and that population growth within 10 miles will be proportional to growth in San Luis Obispo County as a whole. 2.1.3.2 Population Between 10 and 50 Miles Figure 2.1-7 shows the 2000 population distribution between 10 and 50 miles, within the sectors of 22-1/2°, as before, but with part circles of radii of 10, 20, 30, 40, and 50 miles. Figures 2.1-8 and 2.1-9 show projected distributions for 2010 and 2025, respectively, and are based primarily on population projections published by the California Department of Finance and interviews with area government officials. In 2000, some 82 percent of those persons within 50 miles of the site resided in the population centers listed in Table 2.1-3. 2.1.3.3 Low Population Zone As previously mentioned, the population within the 6-mile radius used in the emergency plan is estimated to be 100. This number is derived from a survey of residences in this area, and approximates the low population zone (LPZ) as defined in 10 CFR 100. Coincidentally, 6 miles is the distance to the nearest residential community development DCPP UNITS 1 & 2 FSAR UPDATE 2.1-5 Revision 16 June 2005 at Los Osos, north of the site. It is assumed that the population within this mountainous and largely inaccessible zone will stay constant for the foreseeable future. Figure 2.1-15 shows the low population zone. 2.1.3.4 Transient Population In addition to the resident population presented in the tables and population distribution charts, there is a seasonal influx of vacation and weekend visitors, especially during the summer months. This influx is heaviest along the coast from Avila Beach to south of Oceano. During August, the month of heaviest influx, the maximum overnight transient population in motels and state parks in this area is approximately 100,000 persons. However, there are no significant seasonal or diurnal shifts in population or population distribution within the LPZ. Table 2.1-4 lists transient population for recreation areas within 50 miles of the site for the periods of record listed. Within the LPZ, the maximum recorded number of persons at any single time is estimated to be 5000. This figure is provided by the State Department of Parks and Recreation and corresponds to the maximum daytime use of Montana de Oro State Park. Overnight use is considerably less, an estimated maximum of 400. Evacuation of these numbers of persons from the park in the event of a radiation release could be accomplished as provided for in the emergency plan, with a reasonable probability that no injury would result. For all accident analyses considered in Chapter 15, there is a wide margin of safety between exposures at the outer boundary of the LPZ for a 30-day period following a postulated accident and the allowable doses considered acceptable in 10 CFR 100 for the same location. 2.1.3.5 Population Center Distance The population center distance as defined in 10 CFR 100 is approximately 10 miles, the distance to the nearest boundary of San Luis Obispo, situated beyond the San Luis Range, east-northeast of the site, with a 2000 population of 44,174. 2.1.3.6 Public Facilities and Institutions Several elementary schools are located within 10 miles of the site, near Los Osos and Avila Beach. These serve the local community and do not draw from outlying areas. California Polytechnic State University is 12 miles north-northeast of the DCPP site and has an enrollment of approximately 16,000. Cuesta College is located 10 miles northeast of the DCPP site and has an enrollment of approximately 7,000. Montana de Oro State Park is located north of the site. Its area of principal use is along the beach, between 4 and 5 miles north-northwest of the site. The total number of visitor days during a 12-month period over the last five years averages approximately 680,000. DCPP UNITS 1 & 2 FSAR UPDATE 2.1-6 Revision 16 June 2005 2.1.4 USES OF ADJACENT LANDS AND WATERS The San Luis Range, attaining a height of 1800 feet, dominates the region between the site and US Route 101. This upland country is used to a limited extent for grazing beef cattle and, to a very minor extent, dairy cattle. The terrain east of US Route 101, lying in the mostly inaccessible Santa Lucia Mountains, is sparsely populated with little development. A large portion of this area is included within the Los Padres National Forest. 2.1.4.1 Agriculture San Luis Obispo County has relatively little level land, except for a few small coastal valleys such as the Santa Maria and San Luis Valleys, and some land along the county's northern border in the Salinas Valley and Carrizo Plain areas. Farming is a significant land use in the county. Principal crops include wine grapes, vegetables, cattle, nurseries, fruits, nuts, and grain. There are several vineyards and wineries located in the county. The county's leading agricultural product is wine grapes, valued at $123,500,000 in 2003. The total farm acreage in the county is approximately 1,300,000. The county contains a total of 2,128,640 acres. 2.1.4.2 Dairying The nearest dairying activity is 12 miles northeast of the site at California State Polytechnic College and produces 1000 gallons of milk per day. Some replacement heifers and dry cows are sometimes pastured on property adjacent to site. 2.1.4.3 Fisheries The DCPP site is located between two fishing harbors that support commercial and sportfishing activities. Port San Luis Harbor is located in Avila Beach, approximately 7 miles downcoast of the DCPP site. Morro Bay Harbor is located in Morro Bay, approximately 14 miles upcoast of the site. In 2003 the combined landings for the sport catch (known as commercial passenger fishing vessel fleet) totaled approximately 110,510 rockfish and 10,683 fish of other species, for a total of 8 fishing vessels. Sport catch are calculated by the number of fish caught. Commercial landings are calculated by poundage of landings by port. In 2003 at Port San Luis and at Morro Bay Harbor, the landings were estimated to be as follows: 450,423 pounds of rockfish, 1,433,650 pounds of squid; 534,000 pounds of crab; 282,696 pounds of shrimp; and 1,592 pounds of urchins were landed., There has been a dramatic decrease since 1970 in the abalone fishery, with approximately 621,000 pounds taken in 1966 and 200,000 pounds taken in 1970. Some data suggest that the southern movement of the Southern California sea otter may have had an impact on the red abalone population. DCPP UNITS 1 & 2 FSAR UPDATE 2.1-7 Revision 16 June 2005 2.1.4.4 Surface and Groundwater As discussed in Section 2.4, there are two public water supply groundwater basins within 10 miles of the site. Avila Beach County Water and Sewer District and San Miguelito Mutual Water and Sewer Company provide water to the Avila Beach and Avila Valley area. 2.1.4.5 Land Usage Within 5 Miles An annual land use census is required by Regulatory Guide 4.8(1). A census is required to be conducted at least once per year during the growing season (between February 15 and December 1 for the Diablo Canyon environs). The census is to identify the nearest milk animal and nearest garden greater than 50 square meters (500 square feet) producing broadleaf vegetation in each of 16 22-1/2° sectors within a distance of 8 kilometers (5 miles) of the plant. In addition, Regulatory Guide 4.8 requires the identification of the location of the nearest residence in each of the 16 sectors within a distance of 5 miles. Land owners were identified from San Luis Obispo County records, and direct contact was made with them or their tenants. The only agricultural activities indicated by County personnel were cattle grazing in much of the area surrounding the site, and a farm in the east-southeast sector (along the site access road) producing legumes and cereal grass (grains). Personal and telephone contacts with the land owners or tenants also identified a household garden greater than 500 square feet in the east sector in addition to the above mentioned farming. No milk animals were identified on these properties or within the first 5 miles in any sector. The 1985 land use census results indicate the land use in the vicinity of the plant site has not changed significantly from that identified in Amendment 44 (July 1976) of the FSAR. A summary of the land use census is presented in Table 2.1-5 and Figure 2.1-14. Table 2.1-5 lists the distances measured in miles from the Unit 1 reactor centerline to the nearest animal, residence, and vegetable garden. The locations of gardens or farms greater than 500 square feet are shown in Figure 2.1-14. There is a farm in the southeast sector along the site access road on the coastal plateau; it starts approximately 2 miles from the plant and extends to 4.5 miles from the plant. Figure 2.1-14 also shows the nearest residence is 1.55 miles north-northwest of the plant. Nine permanent residences were identified within 5 miles of the plant. 2.
1.5 REFERENCES
- 1. Regulatory Guide 4.8, Environmental Technical Specifications for Nuclear Power Plants, USNRC, December 1975.
DCPP UNITS 1 & 2 FSAR UPDATE 2.2-1 Revision 16 June 2005 2.2 NEARBY INDUSTRIAL, TRANSPORTATION, AND MILITARY FACILITIES Industry in the vicinity of Diablo Canyon Power Plant (DCPP) site is mainly light and of a local nature serving the needs of agriculture in the area. Food processing and refining of crude oil are the area's major industries, although the numbers employed are not large. Less than 8 percent of the work force in San Luis Obispo County is engaged in manufacturing. (The largest industrial complex is Vandenberg Air Force Base, located about 35 miles south-southeast of the site in Santa Barbara County.) Port San Luis Harbor and the Point San Luis Lighthouse property are located approximately 6.5 miles south-southeast of the DCPP site. The Point San Luis Lighthouse is located on a 30-acre parcel of land. Until 1990, the US Coast Guard owned the lighthouse property. In 1990 the Port San Luis Harbor District, owners and operators of the Port San Luis Harbor, were granted ownership of the lighthouse and the 30 acres, except for approximately 3 acres of land (3 small parcels), which the Coast Guard retained as owners in order to operate and maintain the modern light station and navigating equipment located on those 3 acres. Located approximately 6.5 miles east-southeast of the DCPP site is the Port San Luis tanker-loading pier. This pier was built and is owned by Unocal. Unocal leases the property that the pier is located on from the Port San Luis Harbor District. 2.2.1 LOCATIONS AND ROUTES US Highway 101 is the main arterial road serving the coastal region in this portion of California. It passes about 9 miles east of the site, separated from it by the Irish Hills. US Highway 1 passes 10 miles to the north and carries moderate traffic between San Luis Obispo and the coast. The nearest public access is by county roads in Clark Valley (5 miles north) and See Canyon (5 miles east). Access to the site is by Avila Beach Drive (county road) to the entrance of Pacific Gas and Electric Company's (PG&E's) private access road (easement).
The Southern Pacific Transportation Company provides rail service to the county by a route that roughly parallels US Highway 101. There is no spur track into the site.
Coastal shipping lanes are approximately 20 miles offshore. Prior to 1998, there were local tankers coming into and out of Estero Bay, which is north of the DCPP site. There is no further tanker traffic in either Port San Luis or Estero Bay. The local tanker terminal at Estero Bay closed in 1994, and Avila Pier ceased operation in 1998. Petroleum products and crude oil are no longer stored at Avila Beach, since the storage tanks there were removed in 1999. However, some petroleum products and crude oil continue to be stored at Estero Bay approximately 10 miles from the DCPP site.
Jack R. Benjamin & Associates, Inc., (JBA) (Reference 1), consultant to PG&E, assessed the likelihood of marine vessel collisions with the intake structure thereby endangering operation of the safety-related auxiliary saltwater (ASW) system pumps.
DCPP UNITS 1 & 2 FSAR UPDATE 2.2-2 Revision 16 June 2005 JBA investigated maritime traffic in the vicinity of Diablo Canyon looking for events that could lead to a marine vessel collision with the intake structure. The study considered 13 categories of large vessels, those greater than 100 feet in length and of more than 250 long tons displacement, and a single category including all smaller vessels. Quantitative data were developed for the larger vessel collisions and probability analyses made for both storm dependent and storm independent cases. Development of quantitative data for the smaller vessel collision proved to be not feasible due to the lack of sufficient records of small vessel traffic and accidental groundings. As an alternative approach for smaller vessels, a deterministic structural analysis was made to assess the potential damage to the intake structure for an extreme case collision scenario involving the largest of the smaller vessel category.
The investigations were based on the following conservative assumptions that resulted in computed frequencies of collisions substantially greater than likely to occur:
(1) The entire length of the breakwater is degraded to the mean lower low water (MLLW) level (2) Any vessel crossing the breakwater boundary always impacts the intake structure (3) All barges (either large or small vessels) are empty and have only a 3 to 4-foot draft The storm-independent case probabilistic analysis for large vessels yielded a best-estimate frequency of 6.7 x 10-6 collisions per year. For the storm-dependent probabilistic analysis, the best-estimate annual frequency of collision increased only moderately to 1.9 x 10-5. However, the storm-independent case should be used as the basis for evaluating the frequency of collision since the available data did not indicate a correlation between storms and vessel grounding accidents.
The results of the deterministic analysis indicated that collisions with the intake structure by small vessels of 250 tons or less would be inconsequential to the safety-related function of the ASW pumps.
The study demonstrated that larger marine vessels are not likely to collide with the intake structure and that collisions by smaller vessels would not cause sufficient damage to the intake structure to impair the operation of the ASW system. It is, therefore, concluded that collisions of marine vessels with the intake structure are not a significant hazard to the safe operation of the power plant even if the entire breakwater were to be degraded to the MLLW level. The breakwater in the fully repaired normal condition provides a substantial physical barrier to vessels approaching the intake structure, further reducing the potential hazard from collisions.
DCPP UNITS 1 & 2 FSAR UPDATE 2.2-3 Revision 16 June 2005 The San Luis Obispo County Airport is 12 miles east of the site. It handles some 36 scheduled landings and departures per day of commercial commuter flights, provided primarily by turbo-prop aircraft that seat no more than 30 people with a gross weight of no more than 30,000 pounds. The airport handles approximately 7,500 total landings and departures of private aircraft per month. Private aircraft have 1 to 8 people with an average gross weight of 12,500 pounds. The approach route for a portion of the traffic passes within approximately 4 miles of the DCPP site at an elevation of 3,000 feet, but is used infrequently. The approach route for visual landings passes 8 miles from the site, on the far side of the San Luis Range. There is a smaller airport near Oceano, 15 miles east-southeast of the DCPP site, which accommodates private planes only. The Camp San Luis Obispo airfield, 8 miles northeast of the DCPP site, is not operational.
Vandenberg Air Force Base employs more than 4,400 people (3,200 military and 1,200 civilian) in the area of Lompoc-Santa Maria. Missiles fired to the Western Pacific Missile Range are not directed north or west. Missile launch sites are some 36 miles due south of DCPP. Polar orbit launches are in a southerly direction.
The closest US Army installation is the Hunter-Liggett Military Reservation located in Monterey County approximately 45 miles north of the site. The California National Guard maintains Camp Roberts, located on the border of Monterey County and San Luis Obispo County, southeast of the Hunter-Leggett Military Reservation and approximately 30 miles north of the DCPP site, and Camp San Luis Obispo, in San Luis Obispo County, located about 14 miles northeast of the DCPP site. In addition, as previously described, a US Coast Guard light station is located in Avila Beach on property commonly known as the Point San Luis Lighthouse property. 2.2.2 DESCRIPTIONS No products are manufactured within 5 miles of DCPP site. Within 6 to 10 miles of the DCPP site, 1 to 2 local tankers per month offload oil for storage at Avila Beach. Due to very limited industry within San Luis Obispo County, any products or materials manufactured, stored, or transported beyond 5 miles are not likely to be a significant hazard to the plant. 2.2.3 EVALUATIONS DCPP is located in a remote, sparsely populated, undeveloped site that is an essentially agricultural area. None of the activities described in Sections 2.2.1 and 2.2.2 could constitute a hazard to the plant.
Local shipping tankers come within 5 to 10 miles of the DCPP site. Coastal shipping lanes are approximately 20 miles offshore. Because shipping does not approach closer than 5 miles of the DCPP site and a limited number of tankers pass through, shipping does not pose a hazard to the DCPP site.
DCPP UNITS 1 & 2 FSAR UPDATE 2.2-4 Revision 16 June 2005 The intake structure is protected by massive breakwaters as described elsewhere in this chapter.
No explosive or combustible materials are stored within 5 miles of the site and no natural gas or other pipelines pass within 5 miles of the DCPP site.
Aircraft operating in the area are small in size and few in number. Landing patterns do not come near the DCPP site.
On the DCPP site, as well as surrounding properties, there are no natural-draft cooling towers or other tall structures with a potential for damage to equipment or structures important to safety in the event of collapse of such tall structures. 2.
2.4 REFERENCES
- 1. Charles A. Kircher, et al, Frequency of Vessel Impact With the Diablo Canyon Intake Structure, Jack R. Benjamin & Associates, Inc., Mountain View, CA, 1982.
DCPP UNITS 1 & 2 FSAR UPDATE 2.3-1 Revision 21 September 2013 2.3 METEOROLOGY 2.3.1 REGIONAL CLIMATOLOGY 2.3.1.1 Data Sources The information used in determining the regional meteorological characteristics of Diablo Canyon Power Plant (DCPP) site consists of climatological summaries, technical studies, and reports by Dye (Reference 2), Edinger (Reference 3), Elford (Reference 4), Holzworth (Reference 6), Martin (Reference 8), Thom References 13 and 14), and a Weather Bureau Technical Paper (Reference 16), all pertinent to the region. 2.3.1.2 General Climate The climate of the area is typical of the central California coastal region and is characterized by small diurnal and seasonal temperature variations and scanty summer precipitation. The prevailing wind direction is from the northwest, and the annual average wind speed is about 10 mph. In the dry season, which extends from May through September, the Pacific high-pressure area is located off the California coast, and the Pacific storm track is located far to the north. Moderate to strong sea breezes are common during the afternoon hours of this season while, at night, weak offshore drainage winds (land breezes) are prevalent. There is a high frequency of fog and low stratus clouds during the dry season, associated with a strong low-level temperature inversion.
The mean height of the inversion base is approximately 1100 feet. During the wet season, extending from November through March, the Pacific high-pressure area moves southward and weakens in intensity, allowing storms to move into and across the state. More than 80 percent of the annual rainfall occurs during this 5-month period. Middle and high clouds occur mainly with winter storm activity, and strong winds may be associated with the arrival and passage of storm systems. April and October are considered transitional months separating the two seasons.
The coastal mountains that extend in a general northwest-to-southeast direction along the coastline affect the general circulation patterns. The wind direction in many areas is more likely a result of the local terrain than it is of the prevailing circulation. This range of mountains is indented by numerous canyons and valleys, each of which has its own land-sea breeze regime. As the air flows along this barrier, it is dispersed inland by the valleys and canyons that indent the coastal range. Once the air enters these valleys and canyons, it is controlled by the local terrain features.
In areas where there are no breaks in the coastal range, the magnitude of the wind speed is increased and the variation in the wind direction decreases as the air is forced along the barrier. However, because of the irregular terrain profile and increased mechanical turbulence due to the rough terrain, vertical mixing and lateral meandering under the inversion are enhanced. Therefore, emissions injected into the coastal DCPP UNITS 1 & 2 FSAR UPDATE 2.3-2 Revision 21 September 2013 regime are transported and dispersed by a complex array of land-sea breeze regimes that lead to rapid dispersion in both the vertical and horizontal planes. 2.3.1.3 Severe Weather The annual mean number of days with severe weather conditions, such as tornadoes and ice storms at west coast sites, is zero. Thunderstorms and hail are also rare phenomena, the average occurrence being less than three days per year, as reported by Dye (Reference 2) and Thom (Reference 13). The maximum recorded precipitation in the San Luis Obispo region is 2.35 inches in 1 hour at the DCPP site, and 5.98 inches in 24 hours at San Luis Obispo. The 24 hour maximum and the 1 hour maximum occurred on March 4, 1978. The 24 hour maximum recorded precipitation resulted from a semistationary low-pressure system located southwest of the central California coast that produced a series of frontal waves. These surges of warm, moist air moved into and across the central portion of the state and produced heavy precipitation. The 1 hour maximum was associated with the passage of a strong cold front.
The maximum recorded annual precipitation at San Luis Obispo was 54.53 inches during 1969. The average annual precipitation at San Luis Obispo is 21.53 inches. There are no fastest mile wind speed records in the general area of Diablo Canyon; surface peak gusts at 46 mph have been reported at Santa Maria, California, and peak gusts of 56 mph have been recorded at the 250 foot level on the tower at DCPP site. The frequency of occurrence of peak gusts of this magnitude is approximately once every 10 years. The 100 year recurrence interval wind speed for the site area is 80 mph, Thom (Reference 14). The number of days having a high air pollution potential averages ten per year, Holzworth (Reference 6). One of the most severe tropical storms on record along the Southern California coast occurred September 24-25, 1939. It moved northward off the Southern California coast and came inland on the 25th in the Los Angeles area, but dissipated rapidly. This storm was attended by extremely heavy rains and winds of gale force in the Los Angeles area and southward. Precipitation amounts recorded during the storm are shown below; these data show that this storm had little or no effect on the DCPP site:
Precipitation in InchesLocation September 24 September 25 September 26 Total Los Angeles 1.62 3.96 0.04 5.62 Oxnard 0.00 1.67 0.02 1.69 Ventura 0.00 0.80 0.00 0.80 Santa Barbara 0.09 0.16 0.01 0.26 Santa Maria 1.13 0.29 0.00 1.42 San Luis Obispo 0.04 0.48 0.07 0.59
By definition, gale force winds range from 30 to 60 mph, so the intensity of this storm was about equal to the expected wind speed having a recurrence interval of 10 years at DCPP UNITS 1 & 2 FSAR UPDATE 2.3-3 Revision 21 September 2013 the site. The maximum daily precipitation of 4 inches recorded in this storm was well under the expected maximum probable precipitation estimated for DCPP site. 2.3.2 LOCAL METEOROLOGY 2.3.2.1 Data from Offsite Sources Meteorological data from National Weather Service Stations are indicated below and data from other sources near the DCPP site had been gathered and reported previously in prior FSAR Updates as Appendix 2.3J. Since this appendix, as well as other appendices to this chapter (including Appendices 2.3A-K, 2.4A-C, and 2.5A-F) is merely of historical value at this time, they have been removed from this revision of the FSAR Update and are included only by reference collectively as Reference 27. However, all of these appendices are maintained available for review at PG&E offices. In addition, these appendices have also been docketed at the NRC as a part of Revision 0 through Revision 10 of the FSAR Update. Further, since the nearest National Weather Service Station is located approximately 30 airline miles southeast of the DCPP site, and since other offsite sources are separated from the site by rugged terrain, data from other sources are not considered indicative of site conditions. The only representative local data source is the onsite meteorological measurement program, data from which are summarized in Section 2.3.2.2, below, and presented in detail in Appendix 2.3J of Reference 27.
Precipitation and ambient air temperature data at National Weather Service stations surrounding DCPP are shown in Tables 2.3-6 and 2.3-7. Annual and monthly wind data summaries for Santa Maria, California, are shown in Tables 2.3-8 through 2.3-20. The results of the analysis of the meteorological observations made at the DCPP site are summarized in the following sections and presented in further detail in References 1, 9, 10, and 11, and in Appendix 2.3J of Reference 27. 2.3.2.2 Onsite Normal and Extreme Values of Meteorological Parameters Summaries of normal and extreme values of meteorological parameters are presented in this section for six stations located on DCPP property. Detailed data are included in the locations described in this section. Additional data from continued long-term operation of one site station (Station E) are presented in Appendix 2.3J of Reference 27. 2.3.2.2.1 Wind Speed and Wind Direction The wind speed units in References 1, 9, and 10, and in Appendix 2.3J of Reference 27 are in miles per hour and were estimated to the nearest mile per hour. The wind speed values in the tables contained in Reference 9 and Appendix 2.3J of Reference 27 refer to the values included in each category. For example, the category of 4-7 includes all DCPP UNITS 1 & 2 FSAR UPDATE 2.3-4 Revision 21 September 2013 wind speed values for 4, 5, 6, and 7 mph. The wind speed values in the tables contained in References 1 and 10 are the midpoint values of the class intervals.
The seasonal and annual frequency distributions of wind speed and wind direction are shown graphically in Figures 1 through 4, Reference 9. The percentage occurrence (expressed as the percent of the total number of observations in the period) for each of the 16 wind direction sectors is represented by the length of the bars on the wind rose, and the average wind speed for each wind direction sector is plotted at the end of each bar.
The annual frequency distribution of wind speed and wind direction at the six DCPP stations is shown in Figure 1, Reference 9. The patterns at Stations E, A, and B are grossly similar with about 50 percent of the observations comprising northwesterly winds with average speeds of 10 to 15 mph. The percentage of indicated hourly mean wind speeds that are 2 mph or less varies from 21 percent at Station E to 14 percent at Station A. This variation may be attributed, in part, to the higher starting threshold of the sensors at Station E.
As shown in Tables S.2-1 and S.2-2 of Reference 11, there is a 4 percent difference in the percentage of indicated hourly mean wind speeds that are 2 mph or less for the two concurrent sets of measurements at the 25 foot level of Station E for the period April 1970 through March 1972. The measurements presented in Table S.2-1 were obtained from a lightweight cup and vane wind system, while the observations shown in Table S.2-2 are concurrent measurements obtained from a Bendix-Friez aerovane wind system. The wind flows at Stations C and D, both located in Diablo Canyon, reflect the channeling of the wind by the canyon walls; the predominant directions are up-canyon and down-canyon. The wind distribution at Station F tends to be somewhat circular, because of topographical factors, with the highest mean wind speeds identified with easterly flow.
The highest recorded peak gust at Station E is 84 mph, and the maximum recorded hourly mean wind speed is 54 mph, both recorded at the 76-m level of the primary tower.
Figure 2 of Reference 9 shows that during the dry season northwesterly flow is predominant; Figure 3 of Reference 9 shows there is an increase in southeasterly flow during the wet season compared to the annual distribution. Wind frequency distributions for the transitional months, April and October, show all six stations similar to the annual patterns. Because of the small variability from month to month within a particular season, monthly wind distributions have not been prepared.
The strong diurnal variability of the wind patterns at DCPP site is revealed in Figure 5 and in Figures I-1 through I-7 of Reference 9. The following time periods are shown in the figures for the six stations: Day, 1200-1700 PDT; Night, 2300-0500 PDT; Morning 0600-1100 PDT; and Evening, 1800-2200 PDT. During the day, the winds are northwesterly at Stations E, A, and B. The daytime flow at Stations C and D in DCPP UNITS 1 & 2 FSAR UPDATE 2.3-5 Revision 21 September 2013 Diablo Canyon is directed up-canyon. The most frequent daytime wind direction at Station F is from the northwest. During the night and morning periods, northerly and easterly drainage winds are typically present at all stations. The average nighttime wind speeds at Stations E, A, and B are approximately one-half as great as the average daytime speeds. At the other three stations, no large differences in mean wind speed between the daytime and nighttime regimes are apparent. 2.3.2.2.2 Ambient Air Temperature Average ambient air temperatures for each month of the year, calculated from the hourly temperature measurements at Stations E, B, and F up to the year 1980, are plotted in Figures I-15 through I-17 of Reference 9. The average annual temperature at the plant site is about 55°F. Generally, the warmest mean monthly temperature occurs in October, and the coldest mean monthly temperature occurs in December. The highest and lowest hourly temperatures recorded at the Diablo Canyon site through the year 2000 were 97F in October 1987 and 33F in December 1990, respectively. 2.3.2.2.3 Atmospheric Water Vapor and Fog Measurements of atmospheric water vapor and fog observations are not present throughout the entire meteorological data collection program. However, measurements of these parameters are not essential at DCPP site since regional data are adequate for design purposes and cooling towers are not being used. 2.3.2.2.4 Precipitation Rainfall measurements made at the DCPP shown herein for two report periods. The first period was from July 1, 1967 through October 31, 1969 and is discussed in Section 7.7 and summarized in Table 7 of Appendix 2.3A in Reference 27. The second period was from May 1973 through April 1981 and is discussed in Section 2.3J.4.2 and summarized in Table 2.3J-3 of Appendix 2.3J of Reference 27. Precipitation occurs typically during the period of late October through the first part of May and most frequently in the presence of southeasterly wind flow in advance of a frontal system. The average annual precipitation in the area is about 16 inches. The highest monthly total during the period of record (1967-1981) was 11.26 inches as shown in Section 7.7 of Appendix 2.3A of Reference 27. The greatest amount of precipitation received in a 24 hour period was 3.28 inches as shown in Section 2.3J.4.2 and Table 2.3J-3 of Appendix 2.3J of Reference 27. These maximums were recorded in January 1969 and March 1978, respectively. The maximum hourly amount recorded at DCPP site during the periods of record is 2.35 inches as shown in Section 2.3J.4.2 of Appendix 2.3J of Reference 27. The 1978-1979 winter season with 35.22 inches of rainfall was one of the heaviest precipitation seasons of record.
DCPP UNITS 1 & 2 FSAR UPDATE 2.3-6 Revision 21 September 2013 2.3.2.2.5 Wind Direction Persistence The steadiness of the wind flow at DCPP site has been studied by tabulating the number of consecutive hours the hourly mean wind direction remained within a given 22.5° angular sector. The results, expressed in terms of percentage of all hourly observations, are plotted in Figures I-8 through I-14 of Reference 9, and presented also in Table 2.3J-17 of Appendix 2.3J of Reference 27, for periods ranging from 1 through 24 hours. The mean wind direction at all stations in the analysis of Reference 9 remained within the same 22.5° sector for two consecutive hours or longer in 31 to 42 percent of the observations. The persistence of the wind direction decreases rapidly for a longer time period with only 3 to 4 percent of the observations showing a persistence of 8 hours or longer.
The longest run of persistent wind direction in the total set of measurements occurred at Station B where a northwest wind direction lasted for 51 consecutive hours. The longest period of calm (hourly mean wind speed less than 1 mph) observed at Station E, near the plant location, was 10 hours. As shown in Table 2.3-1, the percentage of the total hourly mean wind speed observations that are less than 1 mph at Station E is 5.9 and 4.9 percent at the 25 foot and 250 foot levels, respectively. The percentage of time that the mean hourly wind speed would be less than 1 mph for 8 consecutive hours or longer is less than 0.5.
As indicated by the persistence analysis, despite the prevalence of the marine inversion and the northwesterly wind flow gradient along the California coast, the long-term accumulation of plant emissions in any particular geographical area downwind is virtually impossible. Pollutants injected into the marine inversion layer of the coastal wind regime are transported and dispersed by a complex array of land-sea breeze regimes that exist all along the coast wherever canyons or valleys indent the coastal range. These conclusions are strongly supported by Edinger's (Reference 3) comprehensive analysis of the influence of terrain and thermal stratification on wind circulations along the California coast, as well as the onsite diffusion studies by Cramer and Record (Reference 1). 2.3.2.2.6 Atmospheric Stability Conditions Defined by Turbulence Measurements The Pasquill (Reference 17) stability categories (see Table 2.3-141) are frequently used as a convenient practical index for gauging the dispersal capacity of the atmosphere. For example, unstable and near-neutral stability conditions (Pasquill Categories A, B, C, D) are favorable for the dilution of pollutants; on the other hand, poor dilution occurs under stable conditions (Pasquill Categories E, F, G). Following a procedure outlined by Slade (Reference 12) the turbulence measurements obtained from the bidirectional vanes at Station E have been used to classify the wind observations at DCPP site according to the Pasquill stability categories. Table 4 of Reference 9, shows the relationship between the range in azimuth and vertical wind angle and the Pasquill stability categories. Scaling factors used to convert the angle ranges to standard deviations were determined from the data presented in Table 2 of Reference 9. DCPP UNITS 1 & 2 FSAR UPDATE 2.3-7 Revision 21 September 2013 The annual wind distributions for the 250 foot level at Station E, given by the measurements made during the period from July 1967 through October 1969, are classified according to the range values of azimuth and vertical wind angles associated with the various Pasquill categories, Tables I-2 through I-6 and Tables I-14 through I-18 of Reference 9. The corresponding annual wind distributions for the 25 foot level are similarly classified, using the 250 foot turbulence measurements, in Tables I-8 through I-12, and I-20 through I-24 of Reference 9. As mentioned above, turbulence measurements were available only at the 250-foot level for this period.
As shown in Table 5 of Reference 9, when the range in azimuth wind angle is used to determine the number of wind observations at Station E in the various Pasquill stability categories, 57 percent of the total observations are in the stable E, F, and G categories. The unstable categories A, B, and C contain 25 percent of the total observations. When the range in vertical wind angle is used to classify the Station E wind data, less than 20 percent of the total observations are in the E, F, and G stable categories. The unstable categories A, B, and C account for about 65 percent of the total observations. These apparent inconsistencies are explained in part by terrain restrictions on the azimuth wind variations at the site.
The results also indicate the routine presence of relatively large vertical turbulence intensities that are caused by the rough terrain at the site. Therefore, it is concluded that the range in vertical wind-angle is a better index of turbulent mixing at DCPP site than the range in azimuth angle. This conclusion is strongly supported by Luna and Church's (Reference 7) comprehensive analysis of the use of measured vertical turbulence values to define stability conditions at sites with rough terrain. Toward the end of the 2 year meteorological measurement program, July 1967 through October 1969, a question arose as to the applicability of the azimuth and vertical wind fluctuations measured at the 250-foot level in determining the site dispersion characteristics for low-level releases resulting from an accident. Therefore, 1 year (October 1969 through September 1970) of concurrent azimuth and vertical wind-angle measurements were obtained at the 25- and 250-foot levels. A detailed analysis of these data is contained in Reference 10 where Tables S.1-1 through S.1-6, pages 7 through 12, and Tables S.1-13 through S.1-18, pages 19 through 24, contains the annual wind distributions classified according to the azimuth wind-angle for the 25- and 250-foot levels, respectively. The annual distributions classified according to vertical wind angle for the two levels are shown in Tables S.1-7 through S.1-12, pages 13 through 18, and Tables S.1-19 through S.1-24, pages 25 through 30.
When the range in azimuth wind-angle is used to classify these concurrent measurements, the 250 foot azimuth range yields the same percentages as the data collected during the period July 1967 through October 1969 (57 percent for the E, F, and G stable categories, and 25 percent for the unstable categories A, B, and C). However, when the azimuth range measured at the 25 foot level is used to classify the total number of observations at the 25-foot level in the various Pasquill stability DCPP UNITS 1 & 2 FSAR UPDATE 2.3-8 Revision 21 September 2013 categories, 48 percent of the total observations are in the E, F, and G stable categories; the unstable categories A, B, and C contain 29 percent of the total observations.
When the range in vertical wind-angle is used to classify the 1 year of concurrent measurement, again at the 250 foot level, there is very little change from the data collected during the period of July 1967 through October 1969: 17 percent of the total observations are in the E, F, and G stable categories and 68 percent are in the unstable categories A, B, and C. At the 25-foot level, only 7 percent of the total observations are in the E, F, and G stable categories. The percentage of total observations in the unstable categories A, B, and C is 80 percent, compared to 66 percent calculated from the wind-angle measurements from the 250 foot level during the period of July 1967 through October 1969.
Because of the poor dilution normally associated with the Pasquill F and G stable categories, the annual percentage occurrences of the F and G categories, in combination with onshore winds of 2 mph or less were also determined and are shown in Tables S.1-1 and S.1-7 of Reference 10. Onshore wind directions include winds for southeast through west-northwest, measured clockwise. The results from the 25-foot level indicate that the Pasquill F and G and onshore wind combination defined above occurs slightly less than 4 percent of the time when the azimuth angle-range data are used as indices, and slightly more than 3 percent of the time when the vertical range-angle data are used as indices. These percentages, which were calculated from the wind-angle measurements from the 250-foot level, are approximately one percentage point less than those for the 25 foot level shown in Table 5 of Reference 9.
The seasonal distributions given in Figure 6 of Reference 9 show the highest percentage of stable conditions during the dry season for both the azimuth and vertical wind-angle classifications. Additional analyses and discussion are presented in Appendix 2.3K of Reference 27. 2.3.2.2.7 Atmospheric Stability Conditions Defined by Vertical Temperature Gradient Measurements The gross relationship between the hourly wind observations at Station E and the thermal stratification can be shown by classifying the wind data into three stability categories defined by the vertical temperature difference measured between the 250- and 25-foot levels on the tower.
The following ranges of the vertical temperature difference between these two levels can be used to define the categories: Stable (T250 T25) = +25.0 to +1.6°F Near Neutral (T250 T25) = +1.5 to 1.5°F Unstable (T250 T25) = 1.6 to 25.0°F DCPP UNITS 1 & 2 FSAR UPDATE 2.3-9 Revision 21 September 2013 A discussion of the effect of measurement interval on stability estimates of temperature gradients is provided in Appendix 2.3G of Reference 27.
Joint frequency distributions of hourly wind speed and wind direction measurements at the 250-foot level for the three stability categories are contained in Reference 9, Tables I-26 through I-28. Similar frequency distributions of the hourly wind observations at the 25-foot level are shown in Tables I-30 through I-32.
Over 70 percent of all the wind observations are grouped in the near-neutral category at both levels. This large percentage is probably explained by the small vertical temperature gradients in the surface layer of the maritime air that reaches the tower during onshore winds; the proximity of the tower to the shoreline, and the intense turbulent mixing induced by the rough terrain at DCPP site. Approximately 5 percent of the total hourly observations at each level are identified with stable thermal stratification and mean wind speeds of 2 mph or less. The percentage of total hourly observations and onshore winds (southeast through west-northwest measured clockwise), with mean wind speeds of 2 mph or less, is 3.2 for the 250-foot level and 1.4 for the 25-foot level. The corresponding percentages for the Pasquill F and G stability categories, as shown in Table 2 of Reference 10, page 4, are 6 at the 250-foot level and 3.2 at the 25-foot level when the range data for the vertical wind angle are used to define the Pasquill categories.
Wind data (speed and direction) classified into seven stability categories (Pasquill A through G) are shown in Tables 2.3-21 through 2.3-27. The wind data were measured at the 250-foot level and the vertical temperature difference measurements are 250-foot level minus 25-foot level. The wind speed values are in miles per hour and the values in the tables refer to the midpoint of each class interval. The rows are labeled with the wind direction at the midpoint of 22.5° intervals:
Midpoint, mph Class Interval, mph Calm Less than 1 2.0 1-3 5.1 4-7 9.6 8-12 15.1 13-18 21.1 19-24 39.6 > 24
Wind data (speed and direction) classified into seven stability categories (Pasquill A through G) for the period May 1973 through April 1974 are shown in Tables 2.3-42 through 2.3-48. The wind data were measured at the 25-foot level and the vertical temperature difference measurements are 250-foot level minus 25-foot level. The wind speed values are in miles per hour and the values in the tables refer to the midpoint of each class interval. The rows are labeled with the wind direction at the midpoint of 22.5° intervals:
DCPP UNITS 1 & 2 FSAR UPDATE 2.3-10 Revision 21 September 2013 Midpoint, mph Class Interval, mph Calm Less than 1 1.8 0.6 to 3.1 5.1 3.1 to 7.1 9.6 7.1 to 12.1 15.1 12.1 to 18.1 21.1 18.1 to 24.1 39.6 > 24
Wind data (speed and direction) classified into seven stability categories (Pasquill A through G) for the period May 1973 through April 1975 are shown in Tables 2.3-49 through 2.3-55 on an annual basis, and in Tables 2.3-56 through 2.3-139, on a monthly basis. The wind data were measured at the 10-meter level, and the vertical temperature gradient measurements were made at 76 meters minus 10 meters.
The wind speed values are in miles per hour and the values in the tables refer to the midpoint of each class interval. The rows are labeled with the wind direction at the midpoint of 22.5° intervals:
Midpoint, mph Class Interval, mph 1.5 1.0-3 5.1 3.1-7 9.6 7.1-12 15.1 12.1-18 21.1 18.1-24 29.6 24.1-35 40.1 35.1-45 50.1 >45
These 2 years of data, May 1973 through April 1975, are considered representative of long-term conditions at DCPP site, and are in agreement with other data taken at the site, such as that in Reference 9, Table I-7, page 2.3A-87, July 1967 through December 1969 and the data in Appendix 2.3J of Reference 27. The prevailing wind direction is from the northwest and the mean annual wind speed is about 10 mph. Between 70 to 90 percent of the observations are contained in the stability classes D and E, Tables 2.3-42 through 2.3-48, and Tables 2.3-49 through 2.3-55.
During the August 1969 review by the Environmental Science Services Administration (ESSA) for Diablo Canyon Nuclear Unit 2, it was requested that the wind data be processed so that the distribution of wind speeds of 3 mph and less could be examined. Since the wind sensor had a nominal starting speed of 2.2 mph, the following procedures were followed in processing the wind data:
(1) Calm refers to hourly wind speed traces indicating zero wind speed and hourly direction traces that were either squarewave or straight line DCPP UNITS 1 & 2 FSAR UPDATE 2.3-11 Revision 21 September 2013 (2) The values shown for the 1 and 2 mph categories were determined by equal area averaging (3) For wind speed entries in the 1 and 2 mph categories that show a calm wind direction, refer to hourly records for which a mean wind direction could not be defined Additional analyses and discussion are presented in Appendix 2.3J of Reference 27.
2.3.2.2.8 Atmospheric Stability Conditions Defined by Onsite Diffusion Studies Twenty-seven onsite field tests involving releases of smoke and fluorescent particles were made during various meteorological regimes. The data from these tests were used for verifying the diffusion model computations by comparing predicted ground level concentrations to observed concentrations. The data also served as a guide in the selection of parameters used in the long-term diffusion model. The analysis of the field measurements was performed by the GCA Corporation and is described in Reference 1. Additional analyses and discussion are contained in Appendix 2.3K of Reference 27.
Analysis of the meteorological and diffusion data obtained during the onsite field tests at Diablo Canyon leads to the following conclusions:
(1) For daytime elevated (250 foot) releases into northwesterly flow, only four measured concentrations exceeded the values predicted by the Pasquill-Gifford curve for Category D; these four values exceed the predicted values for Category D by a factor of 2 or less.
(2) For releases into southeasterly flow (generally prefrontal conditions), the Pasquill-Gifford curve for Category B serves as the upper bound for the concentrations measured during the 250-foot releases. (3) During light and variable winds, the fluorescent particle tracer was found along the coast both north and south of the release point; all measured concentrations for both 250 and 25-foot releases were below the Pasquill-Gifford curve for Category B. 2.3.2.3 Potential Influence of the Plant and Its Facilities on Local Meteorology Modification of local meteorological parameters is not expected by the presence and operation of DCPP. 2.3.2.4 Topographical Description The topographical features within a 10-mile radius of the plant site are shown in Figure 2.3-1. The vertical cross sections for the eight 22.5° onshore wind direction DCPP UNITS 1 & 2 FSAR UPDATE 2.3-12 Revision 21 September 2013 sectors (southeast through west-northwest) radiating from the plant are shown in Figure 2.3-2. Modification of the local topography by the plant is considered negligible.
Topographical influences on both short-term and long-term diffusion estimates are quite pronounced in that the ridge lines east of the plant location extend at least to the average height of the marine inversion base.
The implications of this barrier are:
(1) Any material released that is diverted along the coastline will be diluted and dispersed by the natural valleys and canyons, which indent the coastline.
(2) Any material released that is transported over the ridgeline will be distributed through a deep layer because of the enhanced vertical mixing due to topographic features. 2.3.3 ONSITE METEOROLOGICAL MEASUREMENT PROGRAM The preoperational meteorological data collection program is described in detail in the references. This meteorological program was designed and has been updated continually to meet the requirements of Regulatory Guide 1.23 (Reference 21). Onsite Meteorological Measurement Program (Historical) Data were collected from a comprehensive station network, shown as points A through F in Figure 2.3-3, over a 28-month period from July 1967 through October 1969. Because of a considerable amount of missing data during the first few months of the operation of the meteorological data network, the data collection period was extended four additional months beyond July 1, 1969, to eliminate any bias in the annual distributions caused by incomplete data. The above meteorological measurements were also supplemented by a 12-month program of concurrent turbulence measurements at heights of 250 and 25 feet from October 1969 through September 1970, and by a 24-month program of concurrent wind measurements at the 25 foot level of Station E using a Bendix-Friez aerovane wind system and a lightweight cup and vane system from April 1970 through March 1972. A complete description of the onsite meteorological measurement program is given in Reference 9.
Figure 2.3-1 shows the plant location and site boundary. Locations of Stations A through F of the meteorological measurement network are as shown in Figure 2.3-3. Stations A and B are approximately 3000 feet southeast of the plant location at elevations of 125 and 600 feet Mean Sea Level (MSL), respectively. Station C at elevation of 75 feet MSL and Station D at 350 feet MSL are in Diablo Canyon. Stations E and F are at elevations 85 and 920 feet MSL, respectively. The meteorological instruments at each of the six stations consisted of a Climet Model CI-26 cup and vane assembly mounted at a height of 35 feet above the surface. In addition, air temperature DCPP UNITS 1 & 2 FSAR UPDATE 2.3-13 Revision 21 September 2013 measurements were made at Station B at a height of 5 feet above the surface using a Foxboro Capillary System.
At Station E, currently the primary tower site, meteorological sensors were mounted at heights of 250 and 25 feet on a 260-foot tower. The sensors at the 250-foot level comprised a Bendix-Friez Model 120 Aerovane, a Meteorology Research Incorporated bidirectional vane, and a platinum resistance thermometer for measuring the vertical temperature gradient. The sensor installation at the 25-foot level comprised a Bendix-Friez Model 120 Aerovane and a platinum resistance thermometer for measuring ambient air temperature. A second Meteorology Research Incorporated bidirectional vane was installed at the 25-foot level at Station E in October 1969, and a Climet Model CI-26 cup and vane system was installed at the 25-foot level of Station E in April 1970 to obtain supplementary data. A tipping-bucket rain gauge was located near Station E at the surface.
At Station F, approximately 3000 feet directly east of the plant location at an elevation of 920 feet MSL, a Bendix-Friez Model 120 Aerovane and a Meteorology Research Incorporated bidirectional vane were mounted at the top of a 100-foot tower. Ambient air temperature measurements were made at the 5-foot level by means of a Foxboro Capillary Sensor. Accuracy specifications of the instrumentation used prior to the spring of 1973 are: (1) The Bendix-Friez Model 120 Aerovane has a stated accuracy of 2° over the complete direction range, an average wind speed error of 0.5 mph for speeds under 10 mph, and 1 mph for speeds between 10 and 200 mph (2) A Climet Model CI-26 wind speed sensor has a stated accuracy of 2 percent or 0.25 mph (whichever is greater) and a wind direction accuracy of 5° (3) Meteorology Research Inc. bivanes have stated accuracies of 3.6° for horizontal and 2° for vertical direction (4) The platinum resistance temperature gradient measurement system has an accuracy of 0.2°F Additional descriptions of the instruments are contained in Reference 9. The temperature gradient system and the Bendix-Friez wind systems were calibrated annually or more often when required. The lightweight cup and vane wind systems and the bidirectional wind systems were calibrated every 90 days, or sooner when required. Inspection was performed on a daily basis, and maintenance as necessary.
All of the meteorological sensor outputs from the network described above were recorded on continuous strip chart recorders at the site. Measurements of wind speed, azimuth wind direction, ambient air temperature, and vertical temperature gradient were reduced as hourly averages; rain gauge measurements were reduced to hourly totals; DCPP UNITS 1 & 2 FSAR UPDATE 2.3-14 Revision 21 September 2013 bidirectional vane measurements of the fluctuations in azimuth and vertical wind angles at Stations E and F were abstracted from the chart records in the form of 10 minute range values for the last 10 minutes of each hour. These range values were converted to 10 minute standard deviations of azimuth and vertical wind angle by the use of simple scaling factors and classified according to stability category following a procedure outlined by Slade (Reference 12).
Subsequent to November 1969, Station E became the primary meteorological measurement site at Diablo Canyon, and measurements were discontinued at Stations B, C, D, and F. Measurements at Station A were continued through August 1974.
During the spring of 1973 the instrumentation was changed. The Climet and Bendix-Friez systems were replaced with Teledyne Geotech Series 50 cup and vane sensors to improve reliability and response characteristics. The resistance thermometer system was changed to 4-wire Rosemont bridges and Teledyne Geotech aspirated shields and a sensor was added at the 150-foot level. The precipitation measurement system was changed to a weighing bucket gauge with a potentiometer. Signals from all of the above devices are processed by Teledyne Geotech Series 40 processors that provide output voltages and currents of 0-5 Vdc and 0-1 milliampere, respectively, to the digital and strip chart recorders. A Cambridge systems/EG&G chilled mirror dew point system was added at this time to provide dew point and backup ambient temperature at the 25 foot level. H. E. Cramer Corporation installed signal conditioning equipment of their own design that produced analog signals from the above equipment and the existing bivane equipment that were equivalent to 5 minute values of:
(1) Means of all parameters, except precipitation (2) Variance of horizontal and vertical wind directions (3) Peak wind speeds The signal conditioning provided by H. E. Cramer also converted the Teledyne Geotech 0-360° wind direction output to a 0-540° wind direction signal to accomplish Items 1 and 2 above. H. E. Cramer also provided a digitizing and recording system that utilized Nonlinear Systems' equipment for digitizing and a Bright Industries 7-track magnetic tape recorder for storage of the 5 minute data.
In 1973, a minicomputer and printer were added to the digital system in the control room. Digital data were taken at the tape recorder input and transmitted to the control room computer. The computer system was designed to calculate and display downwind concentrations based on real-time data.
The weighing bucket precipitation gauge was replaced with a tipping bucket gauge in December 1976.
DCPP UNITS 1 & 2 FSAR UPDATE 2.3-15 Revision 21 September 2013 In December 1978, Station E was again upgraded. The equipment was moved to a new equipment shelter at the site and completely rewired. Although the sensors were retained, considerable changes were made to the processors and recording system. A new microprocessor temperature processor was installed to replace the Rosemont Bridge system and improve the accuracy of the temperature difference measurements. The entire H.E. Cramer signal conditioning, digitizing, and recording system was replaced by a Teledyne Geotech Automet V microprocessor-based digital data system. The Automet V also replaced the minicomputer and only the printer remained in the control room. The multipoint Servo recorder was modified to record 25 foot temperature and temperature differences: 150 foot by 25 foot and 250 foot by 25 foot. The Bright Industries 7-track magnetic tape recorder was replaced with a Kennedy Model 9000, 9-track, 1600 bits per inch, phase encoded, buffered tape system.
In June 1980, the system was again upgraded by incorporation of improved wind direction processors using a linear output voltage with no step changes and phase-locked loops to increase immunity to sensor signal distortion. The new processors output a signal that changes linearly from 0 to 5 volts at 180° and back to 0 volts at 360°. A digital signal is used to identify which 180° is being processed. This eliminates errors in the 360° transition as 0° and 360° are both 0 volts rather than 5 volts for 360° in the old system. Digital processing was also changed at this time to use unit vectors for standard deviation and mean direction calculations to eliminate potential ambiguities inherent in the older system. An additional communications link was installed at this time to transmit meteorological data to the technical support center computer.
In May of 1981, the Automet system was revised to allow polling from the DCPP Emergency Assessment and Response System (EARS) computer, and a math processor was incorporated to speed up the processing of wind direction vectors.
In October of 1981, a new 60 meter tower was installed as a backup meteorological system. The backup tower has two levels of wind direction, wind speed, and temperature instrumentation. It is located approximately 1.2 km southeast of the primary tower. The instruments are at the 10 meter and 60 meter levels. Wind speed and wind direction processing is identical to the primary system. The temperature processing incorporates new analog processors from Teledyne Geotech with the same type of aspirated platinum resistance thermometers. The backup system is powered by batteries and is capable of 7 days of operation without external power.
The Automet microcomputer for the backup system is located in the technical support center and receives data digitally from a remote terminal at the tower location over a 4-wire communications link. The backup system printer and a 9-track magnetic tape recorder are also located in the technical support center. A switching system has been incorporated into the primary meteorological printer in the control room and allows the backup system printout to be substituted for the primary system printout. This switching system reconfigures the backup system automatically when the switch is actuated so that 5-minute updates of the current 15-minute logs derived from backup data are DCPP UNITS 1 & 2 FSAR UPDATE 2.3-16 Revision 21 September 2013 printed on the control room printer. The primary system data are output on the printer in the technical support center when the backup system is selected in the control room.
In the spring of 1982, a visibility measurement system was installed at the base of the primary tower. The system relates local visual range to forward light scattering by the air along a 4 foot horizontal path. This system was removed in February 1985 after a sufficient record of information had been collected. Onsite Meteorological Measurement Program (Current) The current onsite meteorological monitoring system consists of two independent subsystems that measure meteorological conditions and process the information into useable data. The measurement subsystems consist of a primary meteorological tower and a backup meteorological tower.
The primary meteorological tower location is shown in Figure 2.3-3 as station E. There are instruments located at the 10 m, 46 m, and 76 m elevations. The 10 m and 76 m elevations have wind speed, wind direction, and temperature sensors. The 46 m elevation has a temperature sensor. The 10 m level also has a dewpoint sensor. There is a precipitation measurement system at the base of the tower.
The backup meteorological tower is located approximately 1.2 km southeast of the primary tower and is listed as station A in Figure 2.3-3. There are wind speed, wind direction, and temperature sensors at the 10 m and 60 m elevations.
The processors for the above instruments reside in the meteorological facilities located near the towers. The temperature in these facilities is maintained to support processor operation. These processors provide input to strip chart recorders and the meteorological dataloggers. The dataloggers provide input to their respective meteorological computers.
The primary meteorological computer is located in the primary meteorological facility. The backup meteorological computer is located in the Technical Support Center. These two computers communicate with each other and the Emergency Assessment and Response System (EARS). The primary meteorological computer also communicates with the Unit 1 Transient Recording System (TRS) server. The backup meteorological computer also communicates with the Unit 2 TRS server. Primary and backup meteorological data is available on the Plant Process Computers via the TRS servers. Thus meteorological data is available in the Control Room and Emergency Response facilities in accordance with NUREG-0654 (Reference 23). A detailed discussion of each of the above instruments is provided in the following sections. DCPP UNITS 1 & 2 FSAR UPDATE 2.3-17 Revision 21 September 2013 2.3.3.1 Wind Measurement System The wind direction processor supplies voltage and current signals corresponding to -180 to 0 to 180 degrees. A digital signal is provided to identify which 180-degree sector the signal represents.
The wind speed signal is processed to develop a voltage signal for the data acquisition system and a current signal for the strip chart recorder. 2.3.3.2 Temperature Measurement System The primary tower temperature measurement system employs a microprocessor system in conjunction with platinum RTDs to measure temperature at three levels on the meteorological tower.
Analog outputs of the temperature processor are recorded on a 3-channel multipoint recorder and depict:
(1) 10 m temperature in degrees Fahrenheit from 0 to 120 (2) temperature difference 46 m to 10 m from -15 to 21°F (3) temperature difference 76 m to 10 m from -15 to 21°F Temperature probes are housed in aspirated radiation shields. Radiation errors are limited to less than 0.2°F at a radiation intensity of 1.56 gram-calories/cm/min. This radiation level represents approximately twice the highest summer radiation level for the DCPP site. Aspirators are individually monitored by motor current sensors and temperatures are invalidated if the motor current is out of a specified range.
The backup tower 10 m processor supplies an intermediate output that is used to sum with the intermediate output of the 60 m processor and provide a temperature difference output from the 60 m processor. Both processors supply a current signal to a multipoint strip chart recorder at the tower location and a voltage signal to the data acquisition system.
Measurement ranges are 0 to 120°F for the 10 m temperature and -15 to 21°F for the 60 to 10 m temperature difference. 2.3.3.3 Dew Point Measurement System A chilled mirror dew point measuring system is used to monitor the dew point at the primary tower 10 m level. The output voltage signal represents a range of 0 to 100°F. The sensor head is equipped with an aspirator to present a representative atmospheric sample to the mirror.
DCPP UNITS 1 & 2 FSAR UPDATE 2.3-18 Revision 21 September 2013 The voltage signal is further processed to generate a buffered voltage output to the data acquisition system and a current signal to the strip chart recorder. 2.3.3.4 Precipitation Measurement System Precipitation is measured by a tipping bucket rain gauge that delivers a pulse for each 0.01-inch increment of rainfall. This pulse is digitally accumulated by a processor module. The digital accumulator resets to zero after the 250th pulse and begins a new cycle. The digital accumulator output is processed by a digital-to-analog converter that provides a voltage signal to the data acquisition system and a current signal to the strip chart recorder. 2.3.3.5 Supplemental Measurement System A supplemental meteorological measurement system is present in the vicinity of the Diablo Canyon Power Plant site. This supplemental measurement system consists of three Doppler SODAR (Sonic Detection and Ranging) and seven tower sites located as indicated in Figure 2.3-4.
The Doppler sounders provide remote sensing of wind speed, wind direction, standard deviation of wind direction variability (sigma theta), vertical velocity, and standard deviation of vertical velocity (sigma w), as well as information on echo characteristics useful in deducing the presence of inversion layers. At each Doppler location, the above parameters are provided as 15 minute average values for each of twenty 30-m thick vertical layers above the instrument site. Layer midpoints extend from 40 m to 610 m above ground level, providing data to heights just exceeding the maximum height of the local terrain. A thorough evaluation of the Doppler technique has been made by the National Oceanic and Atmospheric Administration (Reference 25). The NOAA evaluation of the Doppler produced correlation coefficients on the order of 0.93 and higher for both wind speed and direction in comparison with measurements by sonic anemometers.
The offsite towers provide measurements of wind speed, wind direction, sigma theta, and temperatures as 15 minute averages. All of the supplemental tower measurements are taken at or near the 10-m level using instrumentation designed to meet or exceed ANSI/ANS 2.5 (Reference 24) for meteorological measurements at nuclear plant sites. Tower and Doppler data is telemetered to PG&E's Diablo Canyon Technical Support Center (TSC), Emergency Operations Facility (EOF) and General Office headquarters on a continuous basis. The data are archived as a permanent record.
Onsite meteorological data and supplemental wind speed and direction data is processed by the Emergency Assessment and Response System (EARS) software. The data is provided to the Meteorological Information and Dose Assessment System (MIDAS) software to make estimates and predictions of atmospheric effluent transport and diffusion during and immediately following an accidental airborne radioactivity release from the plant. The software can produce initial transport and diffusion DCPP UNITS 1 & 2 FSAR UPDATE 2.3-19 Revision 21 September 2013 estimates for the plume exposure Emergency Planning Zone (EPZ) within 15 minutes following the classification of an incident. The MIDAS model is designed to use actual 15 minute average meteorological data from on and off-site meteorological measurement systems. The output from the model includes the dimensions, position, locations, and arrival time of the plume.
If one or more of the supplemental tower data are unavailable, EARS and MIDAS will fail over to the supplemental tower most representative of the region which is missing data. If transmission of all supplemental data fails, EARS and MIDAS will continue to be functional with onsite meteorological data as the only source. 2.3.3.6 Meteorological Datalogger A datalogger is installed in both the primary and backup meteorological facilities. The dataloggers receive the outputs of the meteorological sensor signal processors and computer 15-minute averages and maximums. The dataloggers also assign quality values to each of the 15-minute values. On the quarter hour, the dataloggers output their 15-minute data sets to the meteorological computers.
The primary tower datalogger records the following:
(1) 10 m and 76 m wind speeds (2) 10 m and 76 m wind direction (3) 10 m temperature (4) 76 m-10 m temperature difference (5) 46 m-10 m temperature difference (6) precipitation (7) dewpoint (8) 10 m, 46 m, and 76 m aspirator currents The backup tower datalogger records the following: (1) 10 m and 60 m wind speeds (2) 10 m and 60 m wind direction (3) 10 m temperature (4) 60 m-10 m temperature difference DCPP UNITS 1 & 2 FSAR UPDATE 2.3-20 Revision 21 September 2013 (5) the sum of the aspirator currents (6) battery monitor voltage The dataloggers scan their inputs every 2 seconds (450 samples per 15 minutes). The following tests are performed to determine the validity of the meteorological sensor data: (1) If the wind direction standard deviation (calculated using the Yamartino method) is less than 1, the wind data is considered invalid.
(Appendix 2.3F of Reference 27 presents the historical Wind Direction Deviation Computation at Diablo Canyon and its reference has been retained to provide a continuity of understanding. (2) If the 15-minute average wind speed is greater then 0.75 mph and the difference between the peak wind speed and the average wind speed is less than 0.3, then the wind speed data is considered invalid. (3) If the wind speed is greater than 100 mph or less than 0 mph, that 2 second sample is invalid. If more than 150 samples are invalid (i.e., less than 10 minutes worth of good data), then the 15-minute wind speed data is invalid. (4) If more than 150 delta temperature samples are greater than 21 or less than -15, then the 15-minute temperature difference data is invalid. (5) If more than 150 dew point samples are greater than the 10 m temperature by 2 degrees, then the 15-minute dew point data is invalid. (6) If more than 150 aspirator samples are out of a specified range, then both the 15-minute aspirator value and the associated temperature value are invalid. 2.3.3.7 Meteorological Computers The primary meteorological computer resides in the primary meteorological facility and the backup meteorological computer is located in the Technical Support Center. The primary computer communicates with the primary datalogger, the Unit 1 TRS, the EARS server and the backup meteorological tower computer. The backup meteorological computer communicates with the backup datalogger, the Unit 2 TRS, the EARS server, and the primary tower computer. Meteorological data is also available on the Unit 1 and Unit 2 Plant Process Computers (PPC) via their respective TRS. Each computer receives data from its respective datalogger on a 15-minute basis and sends its data set to the other computer. Each computer then calculates chi/q, sigma Y, and sigma Z for 10 distances for both the primary and backup data sets. The primary DCPP UNITS 1 & 2 FSAR UPDATE 2.3-21 Revision 21 September 2013 computer sends both data sets to the Unit 1 TRS server and the EARS system. The backup computer sends both data sets to the Unit 2 TRS server, and the EARS system. Along with the 15-minute data set, each computer receives error flags, which are assigned to the appropriate data values, and these error flags are also sent to the Plant Process Computers and the EARS system. In this manner, the correct data quality is propagated through the entire system (datalogger, meteorological computer, Plant Process Computer, and EARS). The equation used to compute centerline /Q values is based on lateral fluctuations of wind direction (A) for horizontal spread, and vertical temperature gradient (T) for vertical spread of the plume for all daytime cases when the 10 meter speeds are not less than 1.5 m/sec. Nighttime cases in the same wind speed class are treated in accordance with the method of Mitchell and Timbre (Reference 19) as outlined in Table 2.3-144. For speeds less than 1.5 m/sec at the 10-meter level, both lateral and vertical spread of the plume are determined by the vertical temperature gradient. Estimates of both lateral and vertical plume dimensions are determined from the procedures described by Sagendorf (Reference 15). Equations used to determine /Q are: CA) (u1Qz y (2.3-1) ) (3 u1Qz y (2.3-2) zu1Qy (2.3-3) where: Q is the relative concentration (sec/m3) is 3.14159 u is the wind speed at the 10 meter level (m/sec) z y are the lateral and vertical cloud dimensions, respectively, as a function of downwind distance. The vertical cloud dimension has an upper limiting value of 1000 m or the product (Tm) (Hm), whichever is less. Tm DCPP UNITS 1 & 2 FSAR UPDATE 2.3-22 Revision 21 September 2013 is a multiplier which is used as a simple substitute for the multiple reflection term and is approximately 0.8 (References 5 and 12) Hm is the monthly average mixing layer depth for the four time periods of the day which were derived from Holzworth (Reference 6); data are given in Table 2.3-3. A is the minimum cross-sectional area of the reactor building (1600 m2) C is constant (0.5) y = My - at distances less than 800 m; at distances greater than or equal to 800 m - ym800yy)(1)(M M is a correction factor for meandering and assumes the following values for speeds less than 2 m/sec: u<2 m/sec 2 m/sec<u<6 m/sec Stability M M A,B,C 1 1 D 2 (u/6) -0.631 E 3 (u/6) -1.00 F 4 (u/6) -1.262 G 6 (u/6) -1.631 If both values at all levels are invalid, temperature differences (T) are used to determine both lateral and vertical stability categories regardless of wind speed. When this occurs, the dispersion equation used contains the plume meandering correction term. The applicable correction term M for the specific stability and wind speed is that derived from Figure 3 of Regulatory Guide 1.145 (Reference 22), page 1.145-9.
During neutral (D) or stable (E, F, G) stability conditions when 10-m wind speed is less than 6 m/sec, horizontal plume meander is considered. This process consists of comparing the values from Equations 1 and 2 and selecting the higher value selected. This value is then compared with the value from Equation 3 and the lower value of these selected for /Q value. During all other meteorological conditions, plume meander is not considered. The appropriate /Q value in these cases is the higher value calculated from Equations 1 and 2.
The dispersion model described above is a generic model and was not developed specifically for the DCPP site. Certain factors specific to the DCPP site bear upon the DCPP UNITS 1 & 2 FSAR UPDATE 2.3-23 Revision 21 September 2013 use and interpretation of the modeling output. Analysis and treatment of such site-specific factors are presented in Appendix 2.3H of Reference 27. 2.3.3.8 Power Supply For Meteorological Equipment Power for the main meteorological instrumentation building is supplied from Unit 1 480-volt nonvital bus. This source is supplied through a transfer switch and will automatically switch to Unit 2 nonvital 480-volt bus if a failure occurs on the Unit 1 bus. The microprocessor and the meteorological sensors are backed up by an 8-hour battery source to prevent any problems during switching and maintain a continuous database. The backup meteorological instrumentation is supplied with ac power from the underground Unit 2 12-kV startup bus. In case of an ac power failure, batteries supply emergency power for up to 1 week. During battery backup, the temperature system aspirators are not powered, thereby invalidating temperatures. If the measurement systems are being operated on battery power, T measurement is inactivated due to inability to aspirate the temperature shields. In this case, /Q values are based on lateral fluctuations of wind direction (A) for both horizontal and vertical spread of the plume. Nighttime stability categories are adjusted, however, in accordance with the method of Mitchell and Timbre (Reference 19) as outlined in Table 2.3-144.
Should both automated tower systems become inoperative, a portable battery-powered meteorological system is available for deployment and use in providing /Q values for input to dose-calculation algorithms as described in the Emergency Plan and outlined in Appendix 2.3I of Reference 27. Translation of /Q values to centerline and plume-spread estimates may be accomplished in accordance with procedures in the same Appendix 2.3I of Reference 27. (Appendix 2.3I of Reference 27 is historical in nature; however, reference to it has been retained to provide a continuity of understanding. Current procedures meet the requirements of Regulatory Guide 1.145 (Reference 22)). 2.3.4 SHORT-TERM (ACCIDENT) DIFFUSION ESTIMATES 2.3.4.1 Objective Estimates of dilution factors that apply at distances of 0.8 to 80 kilometers downwind from DCPP are shown in Table 2.3-41 for each wind direction sector. These dilution factors represent the distribution of /Q value within each wind direction sector at the various downwind distances. 2.3.4.2 Calculations The cumulative probability distribution of the dilution factor at the distances noted above were computed using one of the diffusion models shown below for centerline dispersion estimates from a ground level release. These are defined as: DCPP UNITS 1 & 2 FSAR UPDATE 2.3-24 Revision 21 September 2013 CA u1Qz y (2.3-4) zu31Qy (2.3-5) zyu1Q (2.3-6) where: = ground level centerline concentration, curies/cubic meter Q = source emission rate, curies/second y = standard deviation of the lateral concentration distribution, meters z = standard deviation of the vertical concentration distribution, meters u = mean wind speed, meters/second C = building wake shape factor, 0.5 A = minimum cross-sectional area of the reactor building, 1600 m2 y = f(y) = meander correction factor A complete description of the models and their selection for use is included in Reference 18.
The year-to-year variation in the frequency of occurrence of conditions producing high /Q values is small, so that data from one complete year are representative of the site. In fact, the addition of the second year's data from October 1970 through March 1971 and April 1972 through September 1972, resulted in a change in percentage frequency for the combined F and G categories of only 0.1 percent. Frequency distributions for joint probabilities using the 2-year length of record are given in Tables 2.3-29 through 2.3-40. The wind speed values are in miles per hour and the values in the tables refer to the midpoint of each of the following class intervals: 0-3, 4-7, 8-12, 13-18, 19-24, and greater than 24. The rows are labeled with the wind direction at the midpoint of each 22.5° interval. The 1-year gap (April 1971 through March 1972) in the period of record, October 1970 through September 1972, resulted from an unauthorized bivane modification.
Frequency distributions of wind speed and wind direction classified into seven stability classes as defined by the vertical temperature gradient are shown in Tables 2.3-21 through 2.3-28. The column headings are labeled in terms of mean hourly wind speed in miles per hour. The six wind speed categories are as follows: 1-3, 4-7, 8-12, 13-18, 19-24, and 25-55. The rows are labeled with the wind direction at the midpoints of 22.5° intervals. Table 2.3-28 shows the number of observations in each of the seven stability classes (Pasquill A through G) for the period of record July 1, 1967, through DCPP UNITS 1 & 2 FSAR UPDATE 2.3-25 Revision 21 September 2013 October 31, 1969, when the mean hourly wind speed is less than 1 mph. The wind data were measured at the 76 meter level, and the vertical temperature difference measurements are the 76 meter level minus the 10 meter level.
The radius of the low population zone (LPZ) at DCPP has been established to be approximately 10,000 meters. Cumulative frequency distributions of atmospheric dilution factors at each 22.5° intersection with this 10,000 meter radius for the period May 1973 through April 1975 are presented in Table 2.3-41, Sheets 10, 11, 12, 13, and 14. Each data set used to compile the frequency distribution is comprised of averages taken over 1 hour, 8 hours, 16 hours, 3 days, or 26 days, using overlapping means updated at 1-hour increments as specified by the NRC. Because of overlapping means, a 1 hour /Q is included in several observation periods: for example, an hourly /Q is included in 624 estimates of the 26-day averages. As a result, a single hourly measurement may influence the value of over 5 percent of the observations. Since overlapping means are used in the distributions, the data are not independent and no assumption of normality can be made. These data show /Q estimates from the 25th through the 100th percentile levels for each of the averaging periods. 2.3.5 LONG-TERM (ROUTINE) DIFFUSION ESTIMATES 2.3.5.1 Objective Annual relative concentrations (/Q) were estimated for distances out to 80 kilometers from onsite meteorological data for the period May 1973 through April 1975. These relative concentrations are presented in Table 2.3-2; they were estimated using the models described in Reference 18. The same program also produces cumulative frequency distributions for selected averaging periods using overlapping means having hourly updates. For critical offsite locations, measured lateral standard deviations of wind direction, A, and bulk Richardson number, Ri, were used as the stability parameters in the computations. The meteorological input data were measured at the 10 meter level of the meteorological tower at DCPP site. Annual averaged relative concentrations calculated by the above methods are presented in Table 2.3-4. 2.3.5.2 Calculations The meteorological instrumentation that was used to obtain the input data for the previously discussed relative concentration calculations at DCPP site is described in Section 2.3.3. Procedures for obtaining annual averaged relative concentrations are described in detail in Reference 15. 2.3.5.3 Meteorological Parameters The following assumptions were used in developing the meteorological input parameters required in the dispersion model: DCPP UNITS 1 & 2 FSAR UPDATE 2.3-26 Revision 21 September 2013 (1) There is no wind direction change with height (2) Wind speed changes with height can be estimated by a power law function where the exponent, P, varies with stability class and is assigned the following values: Pasquill Stability Class Exponent (P) A & B 0.10 C 0.15 D 0.20 E 0.25 F & G 0.30
If more than five hourly observations are missing in any 24-hour period, the estimated 24-hour concentration value is not included in the analyses.
Meteorological data collected at DCPP site are representative of atmospheric conditions along a Pacific coastal area having a complex terrain near the shoreline. Use of these data in estimating downwind relative concentrations results in realistic estimates as shown in the report by Cramer and Record (Reference 1). This field program included ground level concentration measurements out to a distance of about 20 kilometers. All concentration measurements were approximated by near-neutral through unstable stability classifications, even though both vertical and lateral turbulence measurements, E and A in Table 3.1 of Reference 1, indicated several stable regimes. Even during the nighttime periods when extreme stability may be expected, the relative concentrations in the area were characteristic of unstable lapse rates. Actual average temperature differences over the height of the tower for these trials, given in Table 2.3-142, show a high percentage of test periods with stable lapse rates. Five nighttime trials having light and variable winds were included; three were near ground level (8 meters) and two were elevated (76 meters) releases. Temperature gradient measurements indicated three of these trials having near-neutral and two with stable lapse rates, yet the measured ground level concentrations were at least two orders of magnitude less than the predicted peak concentrations for those stabilities. In fact, the diffusion rates, as shown in Figure 3-3 of Reference 1, based on measured ground level concentrations, were typical of those expected for extreme instability.
Results of this series of diffusion trials conducted at DCPP site have yielded considerable insight into the dispersal capabilities of a coastal site. They indicate that use of direct turbulence measurements and the split sigma approach to independently predict lateral and vertical cloud growth yield realistic estimates of site dilution factors without including any corrections or recirculation.
DCPP UNITS 1 & 2 FSAR UPDATE 2.3-27 Revision 21 September 2013 2.
3.6 CONCLUSION
S The principal conclusions reached as the result of the analysis of the data obtained during the onsite meteorological measurement program at DCPP site are listed below:
(1) Northwesterly wind directions with wind speeds averaging 10 to 15 mph can be expected to occur approximately 50 percent of the time. (2) Wind directions within a 22.5° sector that persist for periods of 8 hours or longer will occur 3 to 4 percent of the time. (3) Less than 4 percent of the total observations at the 25 foot level at Station E refer to the joint occurrence of mean wind speeds of 2 mph or less, onshore wind directions (southeast through west-northwest measured clockwise), and moderately stable and/or extremely stable thermal stratifications. (4) Despite the prevalence of the marine inversion and the northwesterly wind flow gradient along the California coast in the dry season, the long-term accumulation of plant emissions, released routinely or accidentally, in any particular geographical area downwind from the plant is virtually impossible. Pollutants injected into the marine inversion layer of the coastal wind regime are transported and dispersed by a complex array of land-sea breeze regimes that exist all along the coast wherever canyons or valleys indent the coastal range. Because of the complexities of the wind circulation in these regimes and their fundamental diurnal nature, the net result is a very effective and wide daily dispersal of any pollutants that are present in the marine coastal air. 2.
3.7 REFERENCES
- 1. H. E. Cramer and F. A. Record, Diffusion Studies at the Diablo Canyon Site, Environmental Sciences Laboratory, GCA Technology Division, GCA Corporation, Salt Lake City, Utah, 1970. (Appendix 2.3B to Diablo Canyon Power Plant Final Safety Analysis Report as amended through August 1980; see Reference 27).
- 2. L. W. Dye, Climatological Data National Summary, Department of Commerce, Asheville, North Carolina, 1972.
- 3. J. G. Edinger, The Influence of Terrain and Thermal Stratification of Flow Across the California Coastline, AFCRL-TR-60-438, Final Report, Contract No. AF (604) - 5512, University of California, Los Angeles, CA, 1960.
- 4. C. R. Elford, Climate of California, Climatography of the United States No. 60-52, Department of Commerce, Washington, D.C., 1970.
DCPP UNITS 1 & 2 FSAR UPDATE 2.3-28 Revision 21 September 2013 5. S. R. Hanna, et al, AMS Workshop on Stability Classification Schemes and Sigma Curves - Summary of Recommendations, Bulletin of American Meteorological Society, Vol. 58, No. 12, 1970.
- 6. G. C. Holzworth, Mixing Heights, Wind Speed, and Potential for Urban Air Pollution Throughout the Contiguous United States, Environmental Protection Agency, Research Triangle Park, NC, 1972.
- 7. R. E. Luna and H. W. Church, "A Comparison of Turbulence Intensity and Stability Ratio Measurements to Pasquill Stability Classes," J. Appl. Meteor., Vol. II, 1972.
- 8. R. G. Martin and J. B. Kincer, Climatography of the United States No. 10-4, Section 17 - Central California, U.S. Department of Commerce, Washington, D.C., 1960.
- 9. M. L. Mooney and H. E. Cramer, Meteorological Study of the Diablo Canyon Nuclear Power Plant Site, Meteorological Office, Gas Control Department, Pacific Gas and Electric Company, San Francisco, CA, 1970. (Appendix 2.3A to Diablo Canyon Power Plant Final Safety Analysis Report as amended through August 1980; see Reference 27).
- 10. M. L. Mooney, First Supplement, Meteorological Study of the Diablo Canyon Nuclear Power Plant Site, Meteorological Office, Gas Control Department, Pacific Gas and Electric Company, San Francisco, CA, 1971. (Appendix 2.3C to Diablo Canyon Power Plant Final Safety Analysis Report as amended through August 1980; see Reference 27).
- 11. M. L. Mooney, Second Supplement, Meteorological Study of the Diablo Canyon Nuclear Power Plant Site, Meteorological Office, Gas Control Department, Pacific Gas and Electric Company, San Francisco, CA, 1972. (Appendix 2.3D, to Diablo Canyon Power Plant Final Safety Analysis Report as amended through August 1980; see Reference 27).
- 12. David H. Slade (ed), Meteorology and Atomic Energy 1968, USAEC Division of Technical Information, Oak Ridge, TN, 1968.
- 13. H. C. S. Thom, "Tornado Probabilities," Monthly Weather Review, 1963.
- 14. H. C. S. Thom, "New Distribution of Extreme Winds in the United States," Journal of the Structural Division, Proc. of the ASCE, Vol. 94, No. ST 7, 1968.
DCPP UNITS 1 & 2 FSAR UPDATE 2.3-29 Revision 21 September 2013 15. J. F. Sagendorf, A Program for Evaluating Atmospheric Dispersion from a Nuclear Power Station, NOAA Technical Memorandum ERL ARL-42, Air Resources Laboratory, Idaho Falls, ID, 1974. (Appendix 2.3E to Diablo Canyon Power Plant Final Safety Analysis Report as amended through August 1980; see Reference 27).
- 16. Weather Bureau Technical Paper, Maximum Station Precipitation for 1, 2, 3, 6, 12, 24 Hours, Technical Paper No. 15, Part XXIII: California, U.S. Department of Commerce, Washington, D.C., 1969.
- 17. F. Pasquill, Atmospheric Diffusion, D. Van Nostrand Company, Ltd., London, 1962.
- 18. J. F. Sagendorf, Diffusion Model, Air Resources Laboratory, Idaho Falls, ID, 1981.
- 19. A. E. Mitchell, Jr., and K. O. Timbre, Atmospheric Stability Class from Horizontal Wind Fluctuation, Reprint, 72nd Annual Meeting of the Air Pollution Control Association, Cincinnati, Ohio, 1979.
- 20. Deleted in Revision 9.
- 21. Regulatory Guide 1.23, Safety Guide 23, Onsite Meteorological Programs, USNRC, February 1972.
- 22. Regulatory Guide 1.145, Atmospheric Dispersion Models for Potential Accident Consequence Assessments at Nuclear Power Plants, USNRC, February 1983.
- 23. NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, USNRC, January 1980, (as updated through November 1980).
- 24. ANSI/ANS 2.5, American National Standard for Determining Meteorological Information at Nuclear Power Sites, American Nuclear Society, 1984.
- 25. National Oceanic and Atmospheric Administration, An Evaluation of Wind Measurements by Four Doppler SODARS, NOAA Wave Propagation Laboratory, 1984.
- 26. Deleted in Revision 20.
- 27. PG&E reports previously submitted as Appendices 2.3A-K, 2.4A-C, and 2.5A-F of the FSAR Update, Revision 0 through Revision 10 (Currently maintained at PG&E Nuclear Power Generation Licensing office files).
DCPP UNITS 1 & 2 FSAR UPDATE 2.4-1 Revision 19 May 2010 2.4 HYDROLOGIC ENGINEERING 2.4.1 HYDROLOGIC DESCRIPTION 2.4.1.1 Site and Facilities The general topography with outline of the drainage basin at Diablo Canyon Power Plant (DCPP) site is shown in Sheet 1 of 2 of Figure 2.4-1, reproduced from the United States Geological Survey (USGS) Port San Luis and Pismo Beach 7.5 minute topographic quadrangles (contour interval 40 feet, original scale 1:24,000). Figure 2.4-2 shows the Diablo Creek drainage basin to a larger scale. The area encompasses some 5 square miles and is bounded by ridges reaching a maximum elevation of 1819 feet at Saddle Peak. The figure also shows changes to the natural drainage features. 2.4.1.2 Hydrosphere The hydrologic characteristics of the site are influenced by the Pacific Ocean on the west and by local storm runoff collected from the 5 square mile egg-shaped area drained by Diablo Creek. The maximum and minimum flows in Diablo Creek are highly variable. Average flows tend to be nearer the minimum flow value of 0.44 cfs. Maximum flows reflect short-term conditions associated with storm events. Usually within 1 or 2 days following a storm, flows return to normal. Flows during the wet season (October-April) vary daily and monthly. Dry season flows are sustained by groundwater seepage and are more consistent from day to day, tapering off over time. There is no other creek or river within the site area. Water for the city of San Luis Obispo is obtained principally from Salinas Reservoir, about 23 miles east-northeast of the site. Whale Rock Reservoir on Old Creek, 17 miles north of the site, and Chorro Reservoir, about 13 miles northeast of the site, are also used. A few small uncovered reservoirs are used in connection with the San Luis Obispo water system and are located about 18 miles northeast of the site. A reservoir in Lopez Canyon is 20 miles east of the site. Smaller towns in the region of San Luis Obispo depend on wells for domestic water.
There are two public water supply groundwater basins within 10 miles of the DCPP site. Avila Beach County Water District serves Avila Beach (including Unocal) with water and sewer needs, and the San Miguelito Mutual Water District and Sewer District serves most of the Avila Valley area. An ocean water desalinization plant has been built and in operation at the site since 1985 (Reference 1).
The property owners to the north and south of the DCPP site capture surface water from small intermittent streams and springs for minimal domestic use. Property owned by PG&E captures water from Crowbar Canyon, 1 mile north of the DCPP site. PG&E's lessee captures water 2 to 4 miles south of the DCPP site from streams and springs between Pecho Canyon and Rattlesnake Canyon. DCPP UNITS 1 & 2 FSAR UPDATE 2.4-2 Revision 19 May 2010 2.4.2 FLOODS 2.4.2.1 Flood History Since 1968, Pacific Gas and Electric Company (PG&E) has kept a record of flows through a V-notched weir located on Diablo Creek, as shown in Figure 2.4-2.
Two major storms occurred in the area between the time the weir was established and June 1973. One occurred on January 18-25, 1969, and the other on January 16-19, 1973. On each occasion, streamflow washed out the weir so no definitive readings were obtained. Flood hydrograph reconstitution indicated that the 1969 flood could have peaked with a flow of approximately 430 cfs and the 1973 flood could have peaked with a flow of approximately 400 cfs.
A USGS gauging station (Los Berros Creek, No. 11-1416), located 21 miles southeast of the site near Nipomo, has a 15 square mile drainage basin, approximately three times the size of the Diablo Creek basin. The gauge at this station recorded a peak flow of 599 cfs on January 25, 1969. The flow at the same station on January 18, 1973, was about 324 cfs. Regional floods of January and February 1969 are reported by U.S. government publications in References 2, 3, and 4.
Ocean wave history is discussed in Reference 5. 2.4.2.2 Flood Design Considerations 2.4.2.2.1 Site Flooding Topography and plant site arrangement limit flood design considerations to local floods from Diablo Creek and sea wave action from the Pacific Ocean. As discussed in Section 2.4.3, the canyon confining Diablo Creek remains intact and will pass any conceivable flood without hazard to safety-related equipment. Channel blockage from landslides downstream of the plant, sufficient to flood the plant yard, is not possible because of the topographic arrangement of the site. 2.4.2.2.2 Flood Waves Flooding conditions, for purposes of the following discussion, include the combined effects of a tsunami, wind-generated storm waves, storm surge ("piling up" of water near the shore due to a storm), and tides. The combination of these effects results in a rise and fall of the ocean surface level relative to a defined datum level. The reference datum is the mean lower low water level (MLLW). At DCPP, MLLW is 2.6 feet below the mean sea level (MSL), which is used as a reference datum for plant elevation. Values of water level rise and fall are expressed relative to MLLW. References to plant elevation are expressed relative to MSL.
DCPP UNITS 1 & 2 FSAR UPDATE 2.4-3 Revision 19 May 2010 When considering tsunami effects alone, the rise in water level is termed tsunami runup, and the fall of the water level is termed tsunami drawdown. Effects of both locally-generated (near-shore) tsunami and distantly-generated tsunami are considered. Tsunami runup and drawdown values given for locally-generated tsunami include the effects of subsidence at the plant site that is considered to occur as a result of near-shore earthquakes.
The wave terms are defined as follows: Still Water Level (SWL) The water level that includes the effects of tsunami, tide, and storm surge Combined Wave Runup The peak water level associated with storm wave action on top of SWL, but not including splash or spray effects associated with wave impacts Splash Runup The water level that includes wave runup effects plus splash effects, but not including spray effects Combined Wave Drawdown The lowest water level associated with tsunami coincident with low tide and short period storm waves The rise in water level may result in submersion, associated hydraulic loading and ground erosion effects, and may result in flooding effects, on structures and system components located in the zone of influence. The following effects are considered in determining the design water levels for DCPP: Storm Waves: waves induced by the wind and pressure effects of a storm Storm Surge: the "piling up" of water at the shore due to (a) a long duration storm wind acting on the water surface, (b) local reduction in atmospheric pressure, and (c) wave effects near the shoreline Tide: the rise and fall of the surface of the ocean caused by the gravitational attraction of the sun and moon on the earth. Tidal range is typically based on the maximum annual higher high tide and the minimum annual lower low tide. Tsunami: a long-period wave generated by a seismic event In addition to water level changes resulting from the effects described above, the following effects are also considered:
DCPP UNITS 1 & 2 FSAR UPDATE 2.4-4 Revision 19 May 2010 Breakwater Damage: only partial credit is taken for protection provided by the breakwaters, considering that they could potentially be damaged by near-shore seismic activity or by storm waves Resonance/Ponding Effects: local amplification of wave activity as a result of resonance effects in the intake basin, or increase in water level in the intake basin as a result of wave overtopping of the breakwaters, or wave ingress through the breakwater opening Combined runup and drawdown effects on DCPP safety-related structures and systems are as follows: Combined splash runup effects for applicable DCPP safety-related facilities and their supporting structures are discussed in Section 2.4.6.6 DCPP safety-related systems include consideration of the effects of the combined drawdown and are discussed in Section 2.4.6 Tsunami loads on the intake structure, including the effects of the combined wave runup are discussed in Section 2.4.6.6 2.4.2.2.3 Structural Evaluation As discussed in Section 2.4.6, testing and analyses demonstrate that equipment and structures important to safety will remain operable in the event of a probable maximum tsunami, storm, and tide occurrence (Reference 21). 2.4.3 PROBABLE MAXIMUM FLOOD (PMF) ON STREAMS AND RIVERS The only stream on the site subject to a PMF study is Diablo Creek. The creek collects runoff from a drainage area of 5.19 square miles up from the ocean side.
The PMF was obtained by deriving an estimated probable maximum precipitation (PMP) with a duration of 24 hours over the subject drainage area. The most severe antecedent condition of ground wetness favorable to high flood runoff was assumed. In view of the low elevation of the site, snowmelt was not considered in the study.
It was assumed that during a PMF all culverts are plugged, and water is impounded to the crest of the lowest depression of the switchyard's fill. The artificial reservoir formed in this assumption is so small that the PMF could not affect the plant.
For a drainage area of 5.19 square miles, the PMF was found to have a peak discharge of 6878 cfs (1325 cfs/sq mi) or a total volume of about 4306 acre-feet for the 24-hour storm.
DCPP UNITS 1 & 2 FSAR UPDATE 2.4-5 Revision 19 May 2010 2.4.3.1 Probable Maximum Precipitation Due to the small drainage area of the site, a PMP with 24 hours duration of rain was selected. Determination of the PMP is based entirely on the methods and procedures outlined in Reference 6. The unrestricted cumulative convergence PMP determined by the above method is found to be 16.6 inches during the month of October. PMP values for other durations as interpolated by the method suggested in Reference 6 are shown in Table 2.4-1. 2.4.3.2 Precipitation Losses Losses are a complex function of rain intensity and accumulated loss (as an index of ground wetness). Five loss rate variables in this study represent average loss, initial loss, rate of decrease of loss with wetness, relation of loss to rain intensity, and rate of recovery of loss rate between storm periods. The unit hydrograph and loss rate parameters are determined in a sequential successive approximation manner as described in Reference 7. Optimization of the basin parameters was performed with the aid of computer program No. 23-J-L211, "Unit Hydrograph and Loss Rate Optimization," developed by the U.S. Army Corps of Engineers, and modified by PG&E (Reference 8).
To obtain precipitation losses, the storm at DCPP site on January 24-25, 1969, was optimized with the runoff record at the USGS gauging station at Los Berros Creek for the same period. Actual rainfall-runoff optimization on Diablo Creek could have been done if the weir had not washed out during the major storms of 1969 and 1973. Nevertheless, geographic and geologic conditions of Los Berros Creek are similar to those of Diablo Creek; Los Berros is the nearest USGS gauging station in the vicinity of DCPP site. The records are good and unregulated. It is in the same hydrographic drainage area as the plant site and both drainage areas have relatively similar elevations. Geologic map comparison shows similarity of ground conditions. Isohyetal maps of major storms show similar magnitude of rainfall in both areas.
In the rainfall-runoff optimization fit using rainfall at DCPP site, the Los Berros recorded runoff responded well to the rainfall distribution at Diablo Canyon. Other rainfall stations around the gauging station were tried but no better fit could be derived than the above. On the foregoing consideration, the optimized loss rates are judged to be representative of the Diablo Canyon drainage basin.
The antecedent condition for the storm of January 24-25, 1969, was very favorable to heavy runoff. Heavy rains during the period of January 18-22, 1969, brought widespread but generally moderate flooding in the area. According to flood reports from USGS, this rain saturated the soil over much of the area. The time distribution of precipitation during the January 24-25 storm was conducive to rapid and intense runoff, because the heaviest rain occurred near the end of the storm when streams were already carrying large flood flows.
DCPP UNITS 1 & 2 FSAR UPDATE 2.4-6 Revision 19 May 2010 Choice of the January 24-25, 1969, storm gave, therefore, conservative results of loss rates. Precipitation data indicate that January 1969 was the wettest January in many years in the area.
As stated in Section 2.4.1.2, Hydrosphere, the average discharge at Diablo Creek is 0.5 cfs in its 16 years of record. However, base flow considerations were taken from the hydrograph of flood flow at Los Berros. The result of the optimization study is shown in Figure 2.4-4. 2.4.3.3 Runoff Model Based on the discussion in the preceding section, the hydrologic response characteristics of Diablo Creek were considered as those that were optimized. The time of concentration of the Diablo Creek basin was calculated using the formula of the Bureau of Reclamation, Design of Small Dams, where: 0.3853H11.9LTc (2.4-1) where: Tc = time of concentration in hours L = length of longest water course in miles H = elevation difference in feet Due to the small size of the basins, Variables 2 and 3 in the rainfall-runoff study were taken as the optimized values. The definitions of the variables or parameters in the optimized model are shown in Sheet 3 of Figure 2.4-5. The first three variables represent unit hydrograph parameters.
The mechanics of the mathematical model used in this study are described in the program documentation of the "Unit Hydrograph and Loss Rate Optimization" computer program of the U.S. Army Corps of Engineers.
Based on the mechanics of this program, PG&E developed the computer program listed as Reference 8. The parameters obtained and defined in the optimization, or other values considered, are held constant and considered representative of the basin. No optimization is performed. This model is capable of modeling any basin rainfall amount and time distribution up to and including the PMP. Loss rates are also calculated in a nonlinear function represented by the equation: EPKL (2.4-2) DCPP UNITS 1 & 2 FSAR UPDATE 2.4-7 Revision 19 May 2010 where: L = loss for each period K = a function of four variables (average value and initial loss increment, which differ from flood to flood, and recovery rate and exponential recession rate, which are uniform for all floods) P = rain for each period E = loss rate variable equal to Variable 7 in the program 2.4.3.4 Probable Maximum Flood Flow The PMP estimate obtained in Section 2.4.3.1 was distributed according to Reference 6. The loss rate parameters obtained in Section 2.4.3.2 were reduced by 50 percent to represent a much more severe antecedent condition and loss rate recession. The exponent of the loss rate equation (Variable 7) was not changed, but it was considered as an optimized regional value. Using the foregoing values as input, the synthetic PMF hydrograph for Diablo Creek up to the ocean side was derived with the aid of the PG&E computer program, Reference 8. The unit hydrograph constants were those that were derived in the runoff model. The hydrograph of inflow for the PMF is presented as a computer printout in Figure 2.4-5, Sheet 2. The peak flow for the PMF was found to be 6878 cfs (1325 cfs/sq mi) with a runoff factor of 0.92.
The switchyard embankment creates a dam upstream of the plant with a potential reservoir storage capacity of 1100 acre-feet. The possibility exists that this small reservoir is full prior to a PMF as a result of culvert plugging. Therefore, storage attenuation of inflow PMF was not considered. Section 2.4.10 discusses the capability of roof and yard drainage to handle runoff from local PMP without risk of flooding safety-related buildings. 2.4.3.5 Water Level Determinations Figure 2.4-3 shows that the hydraulic capacity of the canyon is in excess of 10,000 cfs. There is more than 11 feet of freeboard if the road crossing is washed out and more than 7 feet of freeboard if the road crossing remains intact; thus, there is no risk of flood to safety-related equipment. 2.4.3.6 Coincident Wind Wave Activity Wave runup, discussed in Section 2.4.5, coincident with PMF will have little effect on computed water surfaces. The roadway acting as a weir at an elevation of 65 feet above MLLW (see Figure 2.4-3) provides higher backwaters than the combined waves discussed in Sections 2.4.5 and 2.4.6.
DCPP UNITS 1 & 2 FSAR UPDATE 2.4-8 Revision 19 May 2010 2.4.4 POTENTIAL DAM FAILURES (SEISMICALLY INDUCED) There are no dams in the watershed and failure of dams outside the watershed could not generate sea waves higher than those discussed in Sections 2.4.5 and 2.4.6. The potential storage of water upstream of the switchyard fill described in Section 2.4.3.4 poses no flood threat since the switchyard fill is more than five times as wide as it is deep and the maximum storage of 1100 acre-feet has a face depth of 120 feet. 2.4.5 PROBABLE MAXIMUM SURGE AND SEICHE FLOODING 2.4.5.1 Probable Maximum Winds and Associated Meteorological Parameters Hurricanes or line squalls of sufficient magnitude to generate surge flooding (storm-generated long-period sea waves) have not been recorded on the Pacific coastline. This lack of observed events in 200 years of record lends reasonable assurance that such an event will not occur during the lifetime of the power plant. However, the effects of wind-generated storm waves, storm surge, and tides are conservatively considered in the evaluation of water level and its effects on safety-related equipment and structures. 2.4.5.2 Surge and Seiche History As discussed above, there is no record of surge flooding associated with hurricanes or line squalls. The history of short-period wave trains generated from remote storms in this region is limited. As described below, to compensate for the lack of historical knowledge, conservative flood levels have been developed on the basis of hindcasts and three-dimensional model testing. 2.4.5.3 Surge and Seiche Sources Since there is no record of hurricanes, cyclonic type wind storms, squall lines, etc., on the Pacific Coast, these phenomena are not a design consideration. However, design for any credible flooding, including tsunami in combination with wave and tide action as discussed in Section 2.4.6, is conservatively considered. 2.4.5.4 Wave Action Wave action behavior at DCPP was originally developed on the basis of hindcasts based on a statistical evaluation of historical data in combination with previous scale model testing. PG&E conducted an extensive review of the historical data that led to the estimation of the return periods of the critical storms, e.g., the 1905 storm and the 1981 storm. A major Pacific storm in January 1981 resulted in extensive damage to the west breakwater protecting the intake basin, and led to a review of all the design waves and water levels.
DCPP UNITS 1 & 2 FSAR UPDATE 2.4-9 Revision 19 May 2010 As a result of the damage, PG&E undertook a test program to determine critical wave behavior at the intake basin, including wave height, wave direction, wave runup, resulting forces, and the effects of wave splash on the intake structure and the auxiliary saltwater (ASW) system. A three-dimensional physical model of the basin and its surroundings was constructed, representing in a 1:45 scale the sea floor, the intake structure, and the breakwaters in storm-induced damage conditions.
The tests included the effects of: (a) wind-generated storm waves, including storm surge and tides, and (b) the effects of tsunami plus storm waves. The effects of the waves, including the wave heights, are discussed in detail in Section 2.4.6.
Because data related to wind-generated storm waves were very limited, PG&E developed and implemented a test program to generate the required data (Reference 16). The test program developed site-specific design basis flood events (References 16, 20).
Although the maximum still water level of 17 feet, for probable maximum tsunami, high tide, and storm surge, was conservatively used in the scale model tests (References 16 and 20), the still water level of 15.5 feet, as approved by the NRC, may be used (Reference 28).
Waves for the scale model tests were mechanically generated. Wave heights, outside the breakwater, of up to 45 feet, with periods of 12, 16, and 20 seconds were generated. The results for the model testing indicated that the response waves within the intake basin reached a maximum height that did not increase further in response to increases in the offshore wave height. This phenomenon is due to the effects of the natural terrain and the presence of the degraded breakwater. Therefore, the maximum credible wave event is based on the maximum response of the wave height within the basin, in combination with the still water level in the basin, and is used for assessing the maximum inundating effects and wave forces at the intake structure.
A wave data buoy was installed immediately off DCPP in May 1983 to directly obtain data on wave action. The data are recorded on site and telemetered to the Scripps Institute at La Jolla, California, where they are assimilated with data from other Pacific Coast buoys interconnected with the Scripps "Coastal Data Information Program." 2.4.5.5 Resonance/Ponding As discussed in Section 2.4.5.4, PG&E developed and implemented a test program to simulate the effects of storm waves and tsunamis on the intake basin. The scale model included the detailed relief of the surrounding submerged terrain, the breakwaters, and the intake structure. The action of the waves on the scale model automatically incorporates the resonance and ponding effects of the intake basin.
DCPP UNITS 1 & 2 FSAR UPDATE 2.4-10 Revision 19 May 2010 2.4.5.6 Runup and Drawdown Estimates of storm and tsunami wave runup and drawdown, and their effects on the plant, are presented in Section 2.4.6. 2.4.5.7 Protective Structures The only safety-related system that has components within the projected sea wave zone is the ASW system. The ASW pump motors are housed in watertight compartments within the intake structure. These compartments are designed for a combination tsunami-storm wave activity to elevation +48 feet MLLW (+45.4 feet MSL). The massive concrete intake structure ensures that the pumps remain in place and operate during extreme wave events. The intake structure is arranged to provide redundant paths for seawater to the pumps, ensuring a dependable supply of seawater.
In addition to the ASW pumps, the buried ASW piping outside of the intake structure, which is not attached to the circulating water tunnels, is vulnerable to the effects of tsunami and storm waves. An evaluation was conducted by Bechtel Corporation for PG&E to determine what protective measures were required to protect this buried ASW piping. This evaluation is described in Reference 40. Based on this evaluation, erosion protection, consisting of gabion mattresses, reinforced concrete pavement above this buried piping, and an armored embankment southeast of the intake structure, were designed and installed to resist the effects of tsunami and storm waves.
The model test program (References 16, 20) and resultant evaluations led to various structural modifications, including the extension of the ASW air vent structures with steel tubular snorkels having openings between elevations 48 and 52 feet MLLW. The snorkels were installed during 1982 and 1983 plant modifications. Analysis of the installed extensions by P. J. Ryan (Reference 18) further demonstrated that ingestion of sufficient water by the snorkels is extremely unlikely to jeopardize the operation of the ASW pumps. Section 2.4.6.6 provides additional details. 2.4.6 PROBABLE MAXIMUM TSUNAMI FLOODING The tsunami evaluation and design have evolved as a result of a number of studies and analyses during the original plant design period, the operating license review period, and following the breakwater damage in 1981. The licensing basis for tsunami evaluation is presented in Sections 2.4.6.1 to 2.4.6.6. The background and evolution of the tsunami design and evaluation are provided in Section 2.4.6.7. 2.4.6.1 Probable Maximum Tsunami Tsunamis are classified according to the distance from the shore to the location of the event (generator), which causes the wave. The design tsunami for DCPP represents the envelope of the following two classes of tsunamis:
DCPP UNITS 1 & 2 FSAR UPDATE 2.4-11 Revision 19 May 2010 Distantly-generated tsunami: a tsunami whose generator is located more than several times the principal source dimension (e.g., length of postulated fault rupture) from the plant, Marine Advisors, Inc., 1966 (Reference 24) Locally-generated (near-shore) tsunami: a tsunami whose generator is closer than the distance defined for distantly-generated tsunami The tsunami runup and drawdown at the intake structure are dependent on the source of the tsunami, the distance to the tsunami generator, and the near-shore undersea terrain, including the topography of the intake basin and the configuration of the breakwater.
Wave heights for the two classes of tsunamis considered in the design of DCPP are described in the following sections. 2.4.6.1.1 Distantly-Generated Tsunamis The predominant sources of distantly-generated tsunamis are limited to areas of earthquake and volcanic activity on the circum-Pacific belt. Distant sources relative to DCPP include the Aleutian area, the Kuril-Kamchatka region, and the South American coast.
The lack of historical data for the site during the construction permit review raised a question on the degree of confidence for a "virtually no risk of being exceeded" assurance. In 1967, the AEC staff and its consultants, the United States Coast and Geodetic Survey (USCGS), agreed that the probable maximum tsunami at the site, that had virtually no risk of being exceeded, would be less than the 17- to 20 foot waves experienced at Crescent City, California, as a result of the 1964 Anchorage, Alaska earthquake (Reference 35). To expedite the permit schedule, PG&E decided to use 20 feet as the maximum distantly-generated tsunami wave height. 2.4.6.1.2 Near-Shore Tsunami A number of investigations and analyses to determine the tsunami-generation potential of near-shore earthquake faults were performed during the period from 1966 to 1975. The design basis tsunami wave heights are based on the analysis performed in 1975 by Hwang, Yuen, and Brandsma (Reference 28). The following earthquake sources and characteristics were considered in the analysis: Santa Lucia Bank fault, located approximately 29 miles from the site, considering a resultant displacement of 9.8 feet and a vertical displacement (6.6 feet) equal to 2/3 of the resultant displacement Santa Maria Basin fault (later identified as the Hosgri fault), located approximately 3.5 miles from the site, considering a resultant DCPP UNITS 1 & 2 FSAR UPDATE 2.4-12 Revision 19 May 2010 displacement of 11 feet and a vertical displacement (7.3 feet) equal to 2/3 of the resultant displacement The analysis considered the cases of the breakwaters (a) present as originally constructed, (b) completely absent, and (c) in damaged conditions, in which the sides of the breakwaters slump to a 1-on-4, 1-on-5, or 1-on-6 vertical-to-horizontal slope.
The Santa Maria Basin fault source controls, producing a maximum runup of 9.2 feet and a maximum drawdown of 0.0 feet (Reference 28).
The design basis maximum combined wave runup is the greater of that determined for near-shore or distantly-generated tsunamis, and results from near-shore tsunamis. The bases of these runup values are given in the following two subsections. For distantly-generated tsunamis, the combined runup is 30 feet For near-shore tsunamis, the combined wave runup is 34.6 feet, as determined by hydraulic model testing (References 21, 37) 2.4.6.1.3 Combined Wave Runup for Distantly-Generated Tsunamis The combined wave runup for distantly-generated tsunamis is the same as the value adopted during the construction permit review. The value adopted at that time was 30 feet, as imposed by the NRC (Reference 35). 2.4.6.1.4 Combined Wave Runup for Near-Shore Tsunamis The combined wave runup for near-shore tsunamis, 34.6 feet, is based on observations during scale model testing (Reference 21), which was performed subsequent to the 1981 breakwater damage. This runup value represents the maximum runup observed at the location of the ventilation shafts in the test model, excluding wave spray. Wave splash and spray, which can extend to higher elevations, are discussed in Section 2.4.6.6.
A degraded breakwater model was used, representing the crest of both breakwaters reduced to MLLW, the seaward slopes below that level remaining as originally constructed, and the intake basin sides widened by as much as the material above MLLW could achieve while coming to rest at a slope of 1 vertical to 1.5 horizontal. The model represents the worst-case breakwater damage that could result from the cumulative effects of severe storms, a tsunami, and Hosgri effects (References 23 and 33).
Tsunami, storm surge, and tide effects have relatively long periods and were combined to represent a static change in the elevation of the still water surface. The dynamic effects of storm waves, which have shorter periods, were then superimposed.
DCPP UNITS 1 & 2 FSAR UPDATE 2.4-13 Revision 19 May 2010 2.4.6.1.5 Combined Wave Drawdown Minimum Water Level The maximum combined wave drawdown is the greater of that determined for near-shore or distantly-generated tsunamis, and results from distantly-generated tsunamis. This value constitutes the design combined drawdown value, which is 9.0 feet. Combined wave drawdown for distantly-generated tsunamis: The combined wave drawdown value of 9 feet, derived by a study performed during the construction permit review, is based on the combination of tsunami, storm wave, storm surge, and tide (Reference 24). Combined wave drawdown for near-shore tsunamis: The maximum combined wave drawdown determined by analysis for the case with the breakwaters intact, as originally constructed, is 4.07 feet (Reference 28). The maximum combined drawdown for the case with the breakwater degraded to MLLW has not been evaluated. However, analysis for the case of no breakwater present shows that the drawdown effect is 4.40 feet (Reference 28). Therefore, the drawdown for near-shore tsunamis will be less than for distantly-generated tsunamis. There is a significant margin between the 4.07 feet drawdown and the available pump submergence depth. 2.4.6.2 Historical Tsunami Record There is no historical record of tsunamis for DCPP site due to the remote location with respect to populated areas. The historical review of the region shows tsunamis that have been recorded in the region are of the same order of magnitude as the normal tide range and that local configurations play a large part in the ultimate effects of the tsunami.
At the California coast, reactions to tsunamis from distant sources have been generally moderate, with the exception of certain sensitive areas that have historically shown an abnormally high response as compared to the coast in general. Avila Beach is the closest sensitive area to DCPP.
A review of historical tsunami records and studies of the underwater topography has determined that wave heights recorded at Avila Beach are the result of local conditions that do not affect DCPP (Reference 24). The review demonstrated that DCPP need consider only a distantly-generated tsunami height of 5.0 to 6.0 feet, corresponding to the normal tidal range. Thus, a 6-foot change in the water level above or below MLLW could result (Reference 24). Hence, the 20 foot tsunami runup from a distantly-generated tsunami suggested by the USCGS (Reference 32) is extremely conservative.
DCPP UNITS 1 & 2 FSAR UPDATE 2.4-14 Revision 19 May 2010 2.4.6.3 Source of Tsunami Wave Height 2.4.6.3.1 Distantly-Generated Tsunamis As discussed in Section 2.4.6.1, the predominant sources of distantly-generated tsunamis are limited to areas of earthquake and volcanic activity on the circum-Pacific belt. Distant sources relative to DCPP include the Aleutian area, the Kuril-Kamchatka region, and the South American coast. 2.4.6.3.2 Near-Shore Tsunamis A number of investigations and analyses to determine the tsunami-generation potential of near-shore earthquake faults was performed during the period from 1966 to 1975. The following earthquake sources and characteristics were considered in the analyses: Santa Lucia Bank fault, located approximately 29 miles from the site, considering a resultant displacement of 9.8 feet and a vertical displacement (6.6 feet) equal to 2/3 of the resultant displacement Santa Maria Basin fault (later identified as the Hosgri fault), located approximately 3.5 miles from the site, considering a resultant displacement of 11 feet and a vertical displacement (7.3 feet) equal to 2/3 of the resultant displacement The design basis tsunami wave heights are based on the analysis performed in 1975 by Hwang, Yuen, and Brandsma of Tetra Tech, Inc (Reference 28). 2.4.6.4 Tsunami Height Offshore Estimates of tsunami heights from distant generators offshore are postulated to have dissipated to wave trains with heights on the order of astronomical tidal range of 6 feet. Locally-generated tsunami runup heights from seismic activity or from submarine land slides are estimated to be a maximum of 9.2 feet (Reference 28). 2.4.6.5 Hydrography and Harbor or Breakwater Influences on Tsunami Since the approach to the intake structure is across very irregular submerged terrain, PG&E decided after the January 1981 storm, which significantly damaged the breakwater, that the wave behavior under both extreme tide and tsunami condition would most reliably be evaluated through the use of a three-dimensional physical scale model. The effects of the intake basin, natural sea floor, and the breakwaters (in the damaged state) were considered in the testing and evaluation. Resonance and ponding effects are automatically incorporated by the model testing.
The 1:45, 80 feet by 120 feet, scale model was designed and constructed on the basis of detailed surveys and soundings. Wavemaking machines were positioned at various DCPP UNITS 1 & 2 FSAR UPDATE 2.4-15 Revision 19 May 2010 parts of the basin to drive waves of defined heights, periods, and directions toward the intake basin. Appropriate instrumentation was included to measure and record wave characteristics, and to measure and record critical forces and loads on the intake structure (References 16 and 20). 2.4.6.6 Effects on Safety-Related Facilities The only safety-related system that has components within the projected sea wave zone is the ASW system. The intake structure, within which this equipment is housed, has a main deck elevation of +20 feet above MLLW; it will withstand a tsunami coincident with high tide and depth-limited maximum storm waves that can occur within the intake basin. The safety-related equipment is installed in watertight compartments to protect it from adverse sea wave events to elevation +48 feet above MLLW.
In addition to the ASW pumps, the buried ASW piping outside of the intake structure, which is not attached to the circulating water tunnels, is vulnerable to the effects of tsunami and storm waves. An evaluation was conducted by Bechtel Corporation for PG&E to determine what protective measures were required to protect this buried ASW piping. This evaluation is described in Reference 40. Based on this evaluation, erosion protection, consisting of gabion mattresses, reinforced concrete pavement above this buried piping, and an armored embankment southeast of the intake structure, were designed and installed to resist the effects of tsunami and storm waves.
The structural integrity of the intake structure to resist extreme wave attack (design flood event) in the unlikely event of degradation of the breakwater was reviewed by model tests conducted by O. J. Lillevang (Reference 16) and Dr. Fredric Raichlen (Reference 20). Data from the model study were used by E. N. Matsuda (Reference 21) to structurally analyze the ability of the intake structure to resist the most extreme wave forces. Matsuda determined that, with minor modifications, the intake structure would not be structurally damaged by the most extreme wave forces that might occur even in the unlikely event the entire breakwater were to be degraded to zero feet MLLW. The modifications were completed in 1983.
In addition to the structural evaluations discussed above, the potential effects of splash and spray of the sea waves on safety-related equipment were evaluated. Splashing of water up to and above the top of the ventilation shaft (52 feet MLLW) for the ASW pump rooms was observed during the performance of the scale model testing (Reference 16). The testing demonstrated that the ventilation shaft extensions remained free of the upward splashed water as they are set back from the seaward edge of the concrete vent huts at a considerable distance from the seaward edge of the intake structure, and the openings face away from the sea.
Although the air intake would not be inundated by splashing of water, it could be subject to windborne spray. This spray could potentially wet the vent openings and enter the ASW pump rooms. As described in the following subsections, testing and analysis DCPP UNITS 1 & 2 FSAR UPDATE 2.4-16 Revision 19 May 2010 showed that it is inconceivable that the water level in a pump room would exceed the maximum design flood level for the room.
Additional tests, using the 1:45 scale model of the intake structure and take basin, were performed by Offshore Technology Corporation to determine the potential for ingestion of water by the ASW pump room ventilation shafts (Reference 30). Wave splash behavior in the vicinity of the ventilation shafts was recorded using high speed motion pictures, still photography, and visual observation. Subsequent to the testing, analyses were conducted to evaluate the effect of the splashing on the ASW pumps (Reference 18). The conclusion of this analysis was that the combination of degraded breakwater, tsunami, high tide, severe storm, and extreme winds in the offshore direction necessary to result in a critical volume of water being ingested is inconceivable (Reference 18).
The ASW pumps are protected against flooding for the maximum wave height under tsunami and storm wave conditions even if the entire length of the breakwater were degraded to MLLW. Since there is no assurance that the breakwater would not degrade below MLLW, even though Wiegel (Reference 33) indicates that this is very unlikely, the DCPP Equipment Control Guidelines (Reference 29) include requirements to monitor the condition of the breakwater, to implement corrective action when limited damage is sustained, and to identify the limiting condition for operation relative to the configuration of the breakwaters. 2.4.6.7 Background and Evolution of the Tsunami Design Basis The background and evolution of the tsunami design basis have been documented in detail in DCPP Design Criteria Memorandum (DCM) T-9, Appendix A. 2.4.7 ICE FLOODING As described in Section 2.3, the mild climate and general lack of freezing temperatures in this region make regional ice formation highly unlikely, and it was, therefore, not considered. 2.4.8 COOLING WATER CANALS AND RESERVOIRS The Pacific Ocean is the source of cooling water for the plant. This cooling water system contains no canals or reservoirs. 2.4.9 CHANNEL DIVERSIONS Upstream diversions associated with rivers, where low flow has an impact on dependable cooling water sources, is not a factor for this site.
DCPP UNITS 1 & 2 FSAR UPDATE 2.4-17 Revision 19 May 2010 2.4.10 FLOODING PROTECTION REQUIREMENTS The site arrangement, with the plant situated on a coastal terrace 85 feet above MSL, virtually eliminates all risks from flooding.
Roofs of safety-related buildings have a drainage system designed in accordance with the Uniform Plumbing Code for an adjusted regional PMP of 4 inches/hour. In addition, overflow scuppers are provided in parapet walls at roof level to prevent ponding of accumulated rainwater in excess of drain capacity. Yard areas around safety-related buildings are graded to provide positive slope away from buildings. Storm runoff is overland and unobstructed. It is, therefore, not possible for ponding from local PMP to flood safety-related buildings. 2.4.11 LOW WATER CONSIDERATIONS 2.4.11.1 Low Flow in Rivers and Streams There are no rivers or streams involved in plant operations; therefore, low flow conditions were not evaluated. 2.4.11.2 Low Water Resulting from Surges, Seiches, or Tsunamis Low water, as a result of tsunami drawdown occurring coincident with low tide and short-period storm waves, is projected by Marine Advisers (Reference 24) to result in a possible low water elevation of 9 feet below MLLW. 2.4.11.3 Historical Low Water As discussed in Section 2.4, there is no historical record for the site. Regional low water history is reported in Reference 24. 2.4.11.4 Future Control Flowrate factors generally associated with plants situated on rivers are not applicable to DCPP. 2.4.11.5 Plant Requirements The only safety related system impacted by tsunami drawdown is the ASW. To ensure adequate water supply to the ASW system in the event a tsunami downsurge occurs, the arrangement of the intake structure provides free access to the ocean. In the event of a low water elevation of 9 feet below MLLW, each ASW pump will provide approximately 85 percent of the design flow due to increased static head losses (while operating in the one-pump one-heat exchanger alignment) (See Section 9.2.7.2.3). This is a temporary condition and would not result in a significant increase in CCW temperature. DCPP UNITS 1 & 2 FSAR UPDATE 2.4-18 Revision 19 May 2010 2.4.11.6 Heat Sink Dependability Requirements The ASW pumps are designed to operate with the water level down to 17.4 feet below MLLW, substantially below the minimum water level of 9 feet below MLLW that might occur during a tsunami. Therefore, operation of the ASW system would not be interrupted by low water levels.
Cavitation (with the potential to significantly reduce system flow) is predicted to occur when operating with one ASW pump supplying two CCW heat exchangers during a tsunami drawdown. In the event a tsunami is indicated (by a tsunami warning or a severe earthquake) with two CCW heat exchangers in service, a loss of suction would be indicated by low ASW pump discharge pressure and/or low CCW heat exchanger D/P, low ASW bay level or fluctuating pump motor current. Operator action would be required to remove one of the CCW heat exchangers from service to reduce system flow and decrease pump suction head requirements. 2.4.12 ENVIRONMENTAL ACCEPTANCE OF EFFLUENTS Deep Well 0-2 is the source for groundwater for use at the DCPP site only, and there is no public use of this groundwater (as discussed in Section 2.4.13). No other significant groundwater source exists in this area. No detailed analysis of acceptance of effluents by surface or groundwater is relevant. The releases to the environment via the discharge canal are described in Chapter 11.
Estimated releases of activity from the liquid waste system are discussed in Section 11.2.6, and dilution factors for dilution of liquid wastes are discussed in Section 11.2.8. The release points for liquid waste are shown in Figure 11.2-9. A flow diagram for the design basis case for liquid waste processing is shown in Figure 11.2-2. The numbered waste input streams have their annual flow and isotopic spectra listed in Tables 11.2-3 and 11.2-5. The numbered process streams are listed in Tables 11.2-8 and 11.2-9, with flows and isotopic concentrations.
The possibility of accidental releases and the consequent dispersion of such releases are discussed in Chapter 15. Because of the location of the plant on the ocean and the separation of intake and discharge structures, insignificant recirculation occurs. 2.4.13 GROUNDWATER 2.4.13.1 Description and Onsite Use Groundwater at the site is limited to Deep Well 0-2. No other significant groundwater has been encountered. Three small springs were encountered during excavation for plant construction; two of these were wet spots and the third had a flow of less than thirty gallons per minute. The water was analyzed and found to be very hard (1050 mg/1 CaCO3 and high in dissolved residue (2148 mg/1). Groundwater and domestic water supplies are not affected by the operation of the plant. (Draft Environmental DCPP UNITS 1 & 2 FSAR UPDATE 2.4-19 Revision 19 May 2010 Statement of the Directorate of Licensing, United States Atomic Energy Commission, December 1972.) There is no public use of onsite groundwater. 2.4.13.2 Monitoring and Safeguard Requirements Process and effluent streams are monitored wherever a potential release of radioactivity exists during all modes of plant operation.
Differential temperature across the condenser is monitored as a condition of the national pollution discharge elimination system (NPDES) permit. 2.4.14 TECHNICAL SPECIFICATIONS AND EMERGENCY OPERATION REQUIREMENTS Technical Specifications that describe the safe operation or shutdown requirements for the plant are contained in Appendix A to the operating license. 2.4.15 REFERENCES
- 1. Joint Feasibility Report by the State of California Department of Water Resources and the United States Department of the Interior, Office of Saline Water, 1972.
- 2. A. O. Waananen, Open File Report, Water Resources Division, Geological Survey, U.S. Department of the Interior, 1977. 3. Report on January - February 1969 Floods, Central Coastal Streams (2 Vol.), San Francisco District, Corps of Engineers, Department of the Army, 1969.
- 4. Floods of January and February 1969 in Southern California, Los Angeles District, Corps of Engineers, Department of the Army, 1969.
- 5. PG&E, Ocean Wave History, Appendix E, of the Preliminary Safety Analysis Report (PSAR) for Nuclear Unit No. 2, San Francisco, California, 1967.
- 6. United States Weather Bureau (USWB), Hydrometeorological Report (HMR) No. 36, Interim Report - Probable Maximum Precipitation in California, and modification thereto suggested in Revisions of October 1969 to Hydrometeorological Report No. 36, Interim Report - Probable Maximum Precipitation in California, 1969.
- 7. L. R. Beard, Optimization Techniques for Hydrologic Engineering, U.S. Army Corps of Engineers Technical Paper No. 2, 1966.
DCPP UNITS 1 & 2 FSAR UPDATE 2.4-20 Revision 19 May 2010 8. C. B. Cecilio, Design Flood Hydrograph and Reservoir Flood Routing, Civil Engineering Department, Pacific Gas and Electric Company, San Francisco, California, 1970.
- 9. Deleted
- 10. Deleted
- 11. Deleted
- 12. Deleted
- 13. Deleted
- 14. Deleted
- 15. Deleted
- 16. O. J. Lillevang, et al, The Height Limiting Effect of Sea Floor Terrain Features and of Hypothetically Extensively Reduced Breakwaters on Wave Action at Diablo Canyon Sea Water Intake, California, 1982.
- 17. Deleted
- 18. P. J. Ryan, Investigations of Seawater Ingestion Into the Auxiliary Saltwater Pump Room Due to Splash Run-up During the Design Flood Events at Diablo Canyon, California, 1983.
- 19. Deleted
- 20. F. Raichlen, The Investigation of Wave-Structure Interactions for the Cooling Water Intake Structure of the Diablo Canyon Nuclear Power Plant, California, 1982.
- 21. E. N. Matsuda, Wave Effects on the Intake Structure, DCPP, California, 1983.
- 22. O. J. Lillevang, Letter/Report dated May 20, 1982, to R. V. Bettinger.
- 23. H. Bolton Seed Letter/Report dated September 22, 1981, to R. V. Bettinger.
- 24. An Evaluation of Tsunami Potential at the Diablo Canyon Site, Marine Advisers, Inc., Report A-253, 1966. (Appendix E of the PSAR).
DCPP UNITS 1 & 2 FSAR UPDATE 2.4-21 Revision 19 May 2010 25. O. J. Lillevang, A Basin Intake for Cooling Water at Diablo Canyon Power Plant, 1969. (Appendix 2.4A to Diablo Canyon Power Plant Final Safety Analysis Report as amended through August 1980). (See also Reference 27 of Section 2.3.)
- 26. Deleted
- 27. Li-San Hwang, et al, Earthquake Generated Water Waves at the Diablo Canyon Power Plant, 1974. (Appendix D of Appendix 2.4C to Diablo Canyon Power Plant Final Safety Analysis Report as amended through August 1980).
(See also Reference 27 of Section 2.3.)
- 28. Li-San Hwang, et al., Earthquake Generated Water Waves at the Diablo Canyon Power Plant, (Part Two), 1975. (Appendix E of Appendix 2.4C to Diablo Canyon Power Plant Final Safety Analysis Report as amended through August 1980). (See also Reference 27 of Section 2.3.)
- 29. DCPP Equipment Control Guideline 17.3, "Flood Protection," Pacific Gas and Electric Company.
- 30. J. I. Collins and W. G. Groskopf, Hydraulic Model Study of Diablo Canyon Intake Structure, Test Results - Ingestion Studies, OTC Corporation, 1983.
- 31. Diablo Canyon Power Plant, Auxiliary Seawater Cooling System - Erosion Protection for New Bypass Piping, Bechtel Corporation, October 1996. 32. U. S. Coast and Geodetic Survey, Report on the Seismicity of the Nuclear Plant at the Diablo Canyon Site, September 1967.
- 33. R. L. Wiegel, Breakwater Damage by Severe Storm Waves and Tsunami Waves, March 5, 1982.
- 34. Hydraulic Model Study of Diablo Canyon Intake Structure Test Results, December 1982, OTC-82-42.
- 35. Department of Engineering Memorandum, "Meeting with AEC Staff and Consultants, November 21, 1967," Pacific Gas and Electric Company, December 4, 1967.
- 36. F. Raichlen, "Wave Induced Effects in a Cooling Water Basin," Chapter 196, Proceedings of International Coastal Engineering Conference, 1986.
- 37. PG&E Calculation No. 52.18.13.1, "Combined Runup Depths for Tsunami and Storm Waves," 1997.
DCPP UNITS 1 & 2 FSAR UPDATE 2.4-22 Revision 19 May 2010 38. Regulatory Guide 1.102, Revision 1, Flood Protection for Nuclear Power Sites, USNRC, September 1976.
- 39. NUREG-0675, Supplement No. 5, Safety Evaluation of the Diablo Canyon Nuclear Power Station, Units 1 and 2, USNRC, September 1996.
- 40. Diablo Canyon Power Plant - Auxiliary Saltwater Cooling System Erosion Protection for New Bypass Piping, Bechtel Corporation, October 1996. 2.4.16 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-1 Revision 21 September 2013 2.5 GEOLOGY AND SEISMOLOGY This section presents the findings of the regional and site-specific geologic and seismologic investigations of the Diablo Canyon Power Plant (DCPP) site. Information presented is in compliance with the criteria in Appendix A of 10 CFR Part 100, as described below, and meets the format and content recommendations of Regulatory Guide 1.70, Revision 1 (Reference 39). Because the development of the seismic inputs for DCPP predates the issuance of 10 CFR Part 100, Appendix A, "Seismic and Geologic Siting Criteria for Nuclear Power Plants," the DCPP earthquakes are plant specific. To capture the historical progress of the geotechnical and seismological investigations associated with the DCPP site, information pertaining to the following three time periods is described herein: (1) Original Design Phase: investigations performed in support of the Preliminary Safety Analysis Report, prior to the issuance of the Unit 1 construction permit (1967), through the early stages of the construction of Unit 1 (1971). The Design Earthquake and Double Design Earthquake ground motions are associated with this phase. These earthquakes are similar to the regulatory ground motion level that the NRC subsequently developed in 10 CFR Part 100 Appendix A as the "Operating Basis Earthquake (OBE)" ground motion and the "Safe Shutdown Earthquake (SSE)" ground motion, respectively. (2) Hosgri Evaluation Phase: investigations performed in response to the identification of the offshore Hosgri fault zone (1971) through the issuance of the Unit 1 operating license (1984). The 1977 Hosgri Earthquake ground motions are associated with this phase. The Hosgri Evaluation Phase does not affect or change the investigations and conclusions of the Original Design Phase. (3) Long Term Seismic Program (LTSP) Evaluation Phase: investigations performed in response to the License Condition Item No. 2.C.(7) of the Unit 1 operating license (1984) through the removal of the License Condition (1991), including current on-going investigations. The 1991 L TSP ground motion is associated with this phase. The LTSP Evaluation Phase does not affect or change the investigations and conclusions of either the Original Design Phase or the Hosgri Evaluation Phase. Overview Locations of earthquake epicenters within 200 miles of the plant site, and faults and earthquake epicenters within 75 miles of the plant site for either magnitudes or intensities, respectively, are shown in Figures 2.5-2, 2.5-3, and 2.5-4 (through 1972). A geologic and tectonic map of the region surrounding the site is shown in Figure 2.5-5, DCPP UNITS 1 & 2 FSAR UPDATE 2.5-2 Revision 21 September 2013 and detailed information about site geology is presented in Figures 2.5-8 through 2.5-16. Geology and seismology are discussed in detail in Sections 2.5.2 through 2.5.5. Additional information on site geology is contained in References 1 and 2.
Detailed supporting data pertaining to this section are presented in Appendices 2.5A, 2.5B, 2.5C, and 2.5D of Reference 27 in Section 2.3. Geologic and seismic information from investigations that responded to Nuclear Regulatory Commission (NRC) licensing review questions are presented Appendices 2.5E and 2.5F of the same reference. A brief synopsis of the information presented in Reference 27 (Section 2.3) is given below. The DCPP site is located in San Luis Obispo County approximately 190 miles south of San Francisco and 150 miles northwest of Los Angeles, California. It is adjacent to the Pacific Ocean, 12 miles west-southwest of the city of San Luis Obispo, the county seat. The plant site location and topography are shown in Figure 2.5-1.
The site is located near the mouth of Diablo Creek which flows out of the San Luis Range, the dominant feature to the northeast. The Pacific Ocean is southwest of the site. Facilities for the power plant are located on a marine terrace that is situated between the mountain range and the ocean.
The terrace is bedrock overlain by surficial deposits of marine and nonmarine origin. PG&E Design Class I structures at the site are situated on bedrock that is predominantly stratified marine sedimentary rocks and volcanics, all of Miocene age. A more extensive discussion of the regional geology is presented in Section 2.5.2.1 and site geology in Section 2.5.2.2. Several investigations were performed at the site and in the vicinity of the site to determine: potential vibratory ground motion characteristics, existence of surface faulting, and stability of subsurface materials and cut slopes adjacent to Seismic Category I structures. Details of these investigations are presented in Sections 2.5.2 through 2.5.5. Consultants retained to perform these studies included: Earth Science Associates (geology and seismicity), John A. Blume and Associates (seismic design and foundation materials dynamic response), Harding-Lawson and Associates (stability of cut slope), Woodward-Clyde-Sherard and Associates (soil testing), and Geo-Recon, Incorporated (rock seismic velocity determinations). The findings of these consultants are summarized in this section and the detailed reports are included in Appendices 2.5A, 2.5B, 2.5C, 2.5D, 2.5E, and 2.5F of Reference 27 in Section 2.3.
Geologic investigation of the Diablo Canyon coastal area, including detailed mapping of all natural exposures and exploratory trenches, yielded the following basic conclusions:
(1) The area is underlain by sedimentary and volcanic bedrock units of Miocene age. Within this area, the power plant site is underlain almost wholly by sedimentary strata of the Monterey Formation, which dip northward at moderate to very steep angles. More specifically, the reactor site is underlain by thick-bedded to almost massive Monterey sandstone DCPP UNITS 1 & 2 FSAR UPDATE 2.5-3 Revision 21 September 2013 that is well indurated and firm. Where exposed on the nearby hillslope, this rock is markedly resistant to erosion. (2) The bedrock beneath the main terrace area, within which the power plant site has been located, is covered by 3 to 35 feet of surficial deposits.
These include marine sediments of Pleistocene age and nonmarine sediments of Pleistocene and Holocene age. In general, they are thickest in the vicinity of the reactor site. (3) The interface between the unconsolidated terrace deposits and the underlying bedrock comprises flat to moderately irregular surfaces of Pleistocene marine planation and intervening steeper slopes that also represent erosion in Pleistocene time. (4) The bedrock beneath the power plant site occupies the southerly flank of a major syncline that trends west to northwest. No evidence of a major fault has been recognized within or near the coastal area, and bedrock relationships in the exploratory trenches positively indicate that no such fault is present within the area of the power plant site. (5) Minor surfaces of disturbance, some of which plainly are faults, are present within the bedrock that underlies the power plant site. None of these breaks offsets the interface between bedrock and the cover of terrace deposits, and none of them extends upward into the surficial cover. Thus, the latest movements along these small faults must have antedated erosion of the bedrock section in Pleistocene time. (6) No landslide masses or other gross expressions of ground instability are present within the power plant site or on the main hillslope east of the site. Some landslides have been identified in adjacent ground, but these are minor features confined to the naturally oversteepened walls of Diablo Canyon. (7) No water of subsurface origin was encountered in the exploratory trenches, and the level of permanent groundwater beneath the main terrace area probably is little different from that of the adjacent lower reaches of the deeply incised Diablo Creek. 2.5.1. DESIGN BASIS 2.5.1.1 General Design Criterion 2, 1967 Performance Standards DCPP systems, structures, and components have been located, designed and analyzed to withstand those forces that might result from the most severe natural earthquake phenomena. DCPP UNITS 1 & 2 FSAR UPDATE 2.5-4 Revision 21 September 2013 2.5.1.2 License Condition 2.C(7) of DCPP Facility Operating License DPR-80 Rev. 44 (LTSP), Elements (1), (2) and (3) DCPP developed and implemented a program to re-evaluate the seismic design bases used for the Diablo Canyon Power Plant. The program included the following three Elements that were completed and accepted by the NRC (References 40, 41, and 43): (1) The identification, examination, and evaluation of all relevant geologic and seismic data, information, and interpretations that have become available since the 1979 ASLB hearing in order to update the geology, seismology and tectonics in the region of the Diablo Canyon Nuclear Power Plant. If needed to define the earthquake potential of the region as it affects the Diablo Canyon Plant, PG&E has also re-evaluated the earlier information and acquired additional data. (2) DCPP has re-evaluated the magnitude of the earthquakes used to determine the seismic basis of the Diablo Canyon Nuclear Plant using the information from Element 1. (3) DCPP has re-evaluated the ground motion at the site based on the results obtained from Element 2 with full consideration of site and other relevant effects. As a condition of the NRC's closeout of License Condition 2.C.(7), PG&E committed to several ongoing activities in support of the LTSP, as discussed in a public meeting between PG&E and the NRC on March 15, 1991 (Reference 53), described as the "Framework for the Future," in a letter to the NRC, dated April17, 1991 (Reference 50), and affirmed by the NRC in SSER 34 (Reference 43). These ongoing activities are discussed in Section 2.5.7. 2.5.1.3 10 CFR Part 100, March 1966- Reactor Site Criteria During the determination of the location of the Diablo Canyon Power Plant, consideration was given to the physical characteristics of the site, including seismology and geology. 2.5.2 BASIC GEOLOGIC AND SEISMIC INFORMATION This section presents the basic geologic and seismic information for DCPP site and surrounding region. Information contained herein has been obtained from literature studies, field investigations, and laboratory testing and is to be used as a basis for evaluations required to provide a safe design for the facility. The basic data contained in this section and in Reference 27 of Section 2.3 are referenced in several other DCPP UNITS 1 & 2 FSAR UPDATE 2.5-5 Revision 21 September 2013 sections of this FSAR Update. Additional information, developed during the Hosgri and LTSP evaluations, is described in Sections 2.5.3.9.3 and 2.5.3.9.4, respectively. 2.5.2.1 Regional Geology 2.5.2.1.1 Regional Physiography Diablo Canyon is in the southern Coast Range which is a part of the California Coast Ranges section of the Pacific Border physiographic province (refer to Figure 2.5-1). The region surrounding the power plant site consists of mountains, foothills, marine terraces, and valleys. The dominant features are the San Luis Range adjacent to the site to the northeast, the Santa Lucia Range farther inland, the lowlands of the Los Osos and San Luis Obispo Valleys separating the San Luis and Santa Lucia Ranges, and the marine terrace along the coastal margin of the San Luis Range.
Landforms of the San Luis Range and the adjacent marine terrace produce the physiography at the site and in the region surrounding the site. The westerly end of the San Luis Range is a mass of rugged high ground that extends from San Luis Obispo Creek and San Luis Obispo Bay on the east and is bounded by the Pacific Ocean on the south and west. Except for its narrow fringe of coastal terraces, the range is featured by west-northwesterly-trending ridge and canyon topography. Ridge crest altitudes range from about 800 to 1800 feet. Nearly all of the slopes are steep, and they are modified locally by extensive slump and earthflow landslides.
Most of the canyons have narrow-bottomed, V-shaped cross sections. Alluvial fans and talus aprons are prominent features along the bases of many slopes and at localities where ravines debouch onto relatively gentle terrace surfaces. The coastal terrace belt extends between a steep mountain-front backscarp and a near-vertical sea cliff 40 to 200 feet in height. Both the bedrock benches of the terraces and the present offshore wave-cut bench are irregular in detail, with numerous basins and rock projections.
The main terrace along the coastal margin of the San Luis Range is a gently to moderately sloping strip of land as much as 2000 feet in maximum width. The more landward parts of its surface are defined by broad aprons of alluvial deposits. This cover thins progressively in a seaward direction and is absent altogether in a few places along the present sea cliff. The main terrace represents a series of at least three wave-cut rock benches that have approximate shoreline-angle elevations of 70, 100, and 120 feet.
Owing to both the prevailing seaward slopes of the rock surfaces and the variable thickness of overlying marine and nonmarine cover, the present surface of the main terrace ranges from 70 to more than 200 feet in elevation. Remnants of higher terraces exist at scattered locations along upper slopes and ridge crests. The most extensive among these is a series of terrace surfaces at altitudes of 300+, 400+, and 700+ feet at the west end of the ridge between Coon and Islay Creeks, north of Point Buchon. A surface described by Headlee (Reference 19) as a marine terrace at an altitude of about DCPP UNITS 1 & 2 FSAR UPDATE 2.5-6 Revision 21 September 2013 700 feet forms the top of San Luis Hill. Remnants of a lower terrace at an altitude of 30 to 45 feet are preserved at the mouth of Diablo Canyon and at several places farther north.
Owing to contrasting resistance to erosion among the various bedrock units of the San Luis Range, the detailed topography of the wave-cut benches commonly is very irregular. As extreme examples, both modern and fossil sea stacks rise as much as 100 feet above the general levels of adjacent marine-eroded surfaces at several localities. 2.5.2.1.2 Regional Geologic and Tectonic Setting 2.5.2.1.2.1 Geologic Setting The San Luis Range is underlain by a synclinal section of Tertiary sedimentary and volcanic rocks, which have been downfolded into a basement of Mesozoic rocks now exposed along its southwest and northeast sides. Two zones of faulting have been recognized within the range. The Edna fault zone trends along its northeast side, and the Miguelito fault zone extends into the range from the vicinity of Avila Bay. Minor faults and bedding-plane shears can be seen in the parts of the section that are well exposed along the sea cliff fringing the coastal terrace benches. None of these faults shows evidence of geologically recent activity, and the most recent movements along those in the rocks underlying the youngest coastal terraces can be positively dated as older than 80,000 to 120,000 years. Geologic and tectonic maps of the region surrounding the site are shown in Figures 2.5-5 (2 sheets), 2.5-6, 2.5-8, and 2.5-9.
2.5.2.1.2.2 Tectonic Features of the Central Coastal Region DCPP site lies within the southern Coast Ranges structural province, and approximately upon the centerline axis of the northwest-trending block of crust that is bounded by the San Andreas fault on the northeast and the continental margin on the southwest. This crustal block is characterized by northwest-trending structural and geomorphic features, in contrast to the west-trending features of the Transverse Ranges to the south. A major geologic boundary within the block is associated with the Sur-Nacimiento and Rinconada faults, which separate terrains of contrasting basement rock types. The ground southwest of the Sur-Nacimiento zone and the southerly half of the Rinconada fault, referred to as the Coastal Block, is underlain by Franciscan basement rocks of dominantly oceanic types, whereas that to the northeast, referred to as the Salinia Block, is underlain by granitic and metamorphic basement rocks of continental types. Page (Reference 10) outlined the geology of the Coast Ranges, describing it generally in terms of "core complexes" of basement rocks and surrounding sections of younger sedimentary rocks. The principal Franciscan core complex of the southern Coast Range crops out on the coastal side of the Santa Lucia Range from the vicinity of San Luis Obispo to Point Sur, a distance of 120 miles. Its complex features reflect numerous episodes of deformation that evidently included folding, faulting, and the tectonic emplacement of extensive bodies of ultrabasic rocks. Other core complexes DCPP UNITS 1 & 2 FSAR UPDATE 2.5-7 Revision 21 September 2013 consisting of granitic and metamorphic basement rocks are exposed in the southern Coast Ranges in the ground between the Sur-Nacimiento and Rinconada and in the San Andreas fault zones. The locations of these areas of basement rock exposure are shown in Figure 2.5-6 and in Figure 1 of Appendix 2.5D of Reference 27 in Section 2.3.
Younger structural features include thick folded basins of Tertiary strata and the large faults that form structural boundaries between and within the core complexes and basins.
The structure of the southern Coast Ranges has evolved during a lengthy history of deformation extending from the time when the ancestral Sur-Nacimiento zone was a site for subduction (a Benioff zone) along the then-existing continental margin, through subsequent parts of Cenozoic time when the San Andreas fault system was the principal expression of the regional stress-strain system. The latest episodes of major deformation involved folding and faulting of Pliocene and older sediments during mid-Pliocene time, and renewed movements along preexisting faults during early or mid-Pliocene time. Present tectonic activity within the region is dominated by interaction between the Pacific and American crustal plates on opposite sides of the San Andreas fault and by continuing vertical uplift of the Coast Ranges. In the regional setting of DCPP site, the major structural features addressed during the original design phase are the San Andreas, Rinconada-San Marcos-Jolon, Sur-Nacimiento, and Santa Lucia Bank faults. Additional faults were identified during the Hosgri evaluation and LTSP evaluation phases, discussed in Sections 2.5.3.9.3 and 2.5.3.9.4, respectively. The San Simeon fault may also be included with this group. These original design phase faults are described as follows:
- 1. San Andreas Fault The San Andreas fault is recognized as a major transform fault of regional dimensions that forms an active boundary between the Pacific and North American crustal plates.
Cumulative slip along the San Andreas fault may have amounted to several hundred miles, and a substantial fraction of the total slip has occurred during late Cenozoic time. The fault has spectacular topographic expression, generally lying within a rift valley or along an escarpment mountain front, and having associated sag ponds, low scarps, right-laterally deflected streams, and related manifestations of recent activity.
The most recent episode of large-scale movement along the reach of the San Andreas fault that is closest to the San Luis Range occurred during the great Fort Tejon earthquake of 1857. Geologic evidence pertinent to the behavior of the fault during this and earlier seismic events was studied in great detail by Wallace (Reference 15 and 32) who reported in terms of infrequent great earthquakes accompanied by ground rupture of 10 to 30 feet, with intervening periods of near total quiescence. Allen (Reference 16 suggested that such behavior has been typical for this reach of the San Andreas fault and has been fundamentally different from the behavior of the fault along the reach farther northwest, where creep and numerous small earthquakes have occurred. He further suggested that release of accumulating strain energy might have been facilitated DCPP UNITS 1 & 2 FSAR UPDATE 2.5-8 Revision 21 September 2013 by the presence of large amounts of serpentine in the fault zone to the northwest, and retarded by the locking effect of the broad bend of the fault zone where it crosses the Transverse Ranges to the southeast.
Movement is currently taking place along large segments of the San Andreas fault. The active reach of the fault between Parkfield and San Francisco is currently undergoing relative movement of at least 3 to 4 cm/yr, as determined geodetically and analyzed by Savage and Burford (Reference 33). When the movement that occurs during the episodes of fault displacement in the western part of the Basin and Ranges Province is added to the minimum of 3 to 4 cm/yr of continuously and intermittently released strain, the total probably amounts to at least 5 to 6 cm/yr. This may account for essentially all of the relative motion between the Pacific and North American plates at present. In the Transverse Ranges to the south, this strain is distributed between lateral slip along the San Andreas system and east-west striking lateral slip faulting, thrust faulting, and folding. North of the latitude of Monterey Bay and south of the Transverse Ranges, transcurrent movement is again concentrated along the San Andreas system, but in those regions, it is distributed among several major strands of the system.
- 2. Sur-Nacimiento Fault Zone The Sur-Nacimiento fault zone has been regarded as the system of faults that extends from the vicinity of Point Sur, near the northwest end of the Santa Lucia Range, to the Big Pine fault in the western Transverse Ranges, and that separates the granitic-metamorphic basement of the Salinian Block from the Franciscan basement of the Coastal Block. The most prominent faults that are included within this zone are, from northwest to southeast, the Sur, Nacimiento, Rinconada, and (south) Nacimiento faults. The Sur fault, which extends as far northward as Point Sur on land, continues to the northwest in the offshore continental margin. At its southerly end, the zone terminates where the (south) Nacimiento fault is cut off by the Big Pine fault. The overall length of the Sur-Nacimiento fault zone between Point Sur and the Transverse Ranges is about 180 miles. The 60 mile long Nacimiento fault, between points of juncture with the Sur and Rinconada faults, forms the longest segment within this zone. Page (Reference 11) stated that:
"It is unlikely that the Nacimiento fault proper has displaced the ground surface in Late Quaternary time, as there are no indicative offsets of streams, ridges, terrace deposits, or other topographic features. The Great Valley-type rocks on the northeast side must have been down-dropped against the older Franciscan rocks on the southwest, yet they commonly stand higher in the topography. This implies relative quiescence of the Late Quaternary time, allowing differential erosion to take place. In a few localities, the northeast side is the low side, and this inconsistency favors the same conclusion. In addition to the foregoing circumstances, the fault is offset by minor cross-faults in a manner suggesting that little, if any, Late Quaternary near-surface movement had occurred along the main fracture."
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-9 Revision 21 September 2013 Hart (Reference 14), on the other hand, stated that: ". . . youthful topographic features (offset streams, sag ponds, possible fault scarplets, and apparently oversteepened slopes) suggest movement along both (Sur-Nacimiento and Rinconada) fault zones." The map compiled by Jennings (Reference 23), however, shows only the Rinconada with a symbol indicating "Quaternary fault displacement."
The results of photogeologic study of the region traversed by the Sur-Nacimiento fault zone tend to support Page's view. A pronounced zone of fault-controlled topographic lineaments can be traced from the northwest end of the Nacimiento fault southeastward to the Rinconada (south Nacimiento), East Huasna, and West Huasna faults. Only along the Rinconada, however, are there topographic features that seem to have originated through fault disturbances of the ground surface rather than through differential erosion along zones of shearing and juxtaposition of differing rocks. Richter (Reference 13) noted that some historic seismicity, particularly the 1952 Bryson earthquake, appears to have originated along the Nacimiento fault. This view is supported by recent work of S. W. Smith (Reference 30) that indicates that the Bryson shock and the epicenters of several smaller, more recent earthquakes were located along or near the trace of the Nacimiento.
- 3. Rinconada (Nacimiento)-San Marcos-Jolon-San Antonio Fault System A system of major faults extends northwestward, parallel to the San Andreas fault, from a point of junction with the Big Pine fault in the western Transverse Ranges. This system includes several faults that have been mapped as separate features and assigned individual names. Dibblee (Reference 27) however, has suggested that these faults are part of a single system, provisionally termed the Rinconada fault zone after one of its more prominent members. He also proposed abandoning the name Nacimiento for the large fault that constitutes the most southerly part of this system, as it is not continuous with the Nacimiento fault to the north, near the Nacimiento River.
The newly defined Rinconada fault system comprises the old (south) Nacimiento, Rinconada, and San Marcos faults. Dibblee proposed that the system also include the Espinosa and Reliz faults, to the north, but detailed work by Durham (Reference 28) does not seem to support this interpretation. Instead, the system may extend into Lockwood Valley and die out there along the Jolon and San Antonio faults. All the faults of the Rinconada system have undergone significant movement during middle and late Cenozoic time, though the entire system did not behave as a unit. Dibblee pointed out that: "Relative vertical displacements are controversial, inconsistent, reversed from one segment to another; the major movement may be strike slip, as on the San Andreas fault."
Regarding the structural relationship of the Rinconada fault to nearby faults, Dibblee wrote as follows:
"Thrust or reverse faults of Quaternary age are associated with the Rinconada fault along much of its course on one or both sides, within 9 miles, especially in areas of intense folding. In the northern part several, including the San Antonio fault, are DCPP UNITS 1 & 2 FSAR UPDATE 2.5-10 Revision 21 September 2013 present along both margins of the range of hills between the Salinas and Lockwood Valleys . . . . along which this range was elevated in part. Near the southern part are the major southwest-dipping South Cuyama and Ozena faults along which the Sierra Madre Range was elevated against Cuyama Valley, with vertical displacements possibly up to 8000 feet. All these thrust or reverse faults dip inward toward the Rinconada fault and presumably either splay from it at depth, or are branches of it. These faults, combined with the intense folding between them, indicated that severe compression accompanied possible transcurrent movement along the Rinconada fault." "The La Panza fault along which the La Panza Range was elevated .... in Quaternary time, is a reverse fault that dips northeast under the range, and is not directly related to the Rinconada fault.
"The Big Pine fault against which the Rinconada fault abuts . . . is a high angle left-lateral transcurrent fault active in Quaternary time (Reference 35). The Pine Mountain fault south of it . . . . is a northeast-dipping reverse fault along which the Pine Mountain Range was elevated in Quaternary time. This fault may have been reactivated along an earlier fault that may have been continuous with the Rinconada fault, but displaced about 8 miles from it by left slip on the Big Pine fault (Reference 12) in Quaternary time." "The Rinconada and Reliz faults were active after deposition of the Monterey Shale and Pancho Rico Formation, which are severely deformed adjacent and near the faults. The faults were again active after deposition of the Paso Robles Formation but to a lesser degree. These faults do not affect the alluvium or terrace deposits. There are no offset stream channels along these faults. However, in two areas several canyons and streams are deviated, possibly by right-lateral movement on the (Espinosa and San Marcos segments of the) Rinconada fault. There are no indications that these faults are presently active." 4. San Simeon Fault The fault here referred to as the San Simeon fault trends along the base of the peninsula that lies north of the settlement of San Simeon. This fault is on land for a distance of 12 miles between its only outcrop, north of Ragged Point, and Point San Simeon. It may extend as much as 16 miles farther to the southeast, to the vicinity of Point Estero. This possibility is suggested by the straight reach of coastline between Cambria and Point Estero, which is directly aligned with the onshore trend of the fault; its linear form may well have been controlled by a zone of structural weakness associated with the inferred southerly part of the fault. South of Port Estero, however, there is no evidence of faulting observable in the seismic reflection profiles across Estero Bay, and the trend defined by the Los Osos Valley-Estero Bay series of lower Miocene or Oligocene intrusives extends across the San Simeon trend without deviation.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-11 Revision 21 September 2013 North of Point Piedras Blancas, Silver (Reference 26) reports a fault with about 5 kilometers of vertical separation between the 4-kilometer-thick Tertiary section in the offshore basin and the nearby 1-kilometer-high exposure of Franciscan basement rocks in the coastline mountain front. The existence of a fault in this region is also indicated by the 30- milligal gravity anomaly between the offshore basin and the onshore ranges (Plate II of Appendix 2.5D of Reference 27 in Section 2.3). This postulated fault may well be a northward extension of the San Simeon fault. If this is the case, the San Simeon fault may have a total length of as much as 60 miles.
Between Point San Simeon and Ragged Point, the San Simeon fault lies along the base of a broad peninsula, the surface of which is characterized by elevated marine terraces and younger, steep-walled ravines and canyons. The low, terraced topography of the peninsula contrasts sharply with that of the steep mountain front that rises immediately behind it. Clearly, the ground west of the main fault represents a part of the sea floor that has been locally arched up.
This has resulted in exposure of the fault, which elsewhere is concealed underwater off the shoreline.
The ground between the San Simeon fault and the southwest coastline of the Piedras Blancas peninsula is underlain by faulted blocks and slivers of Franciscan rocks, serpentinites, Tertiary sedimentary breccia and volcanic rocks, and Miocene shale. The faulted contacts between these rock masses trend somewhat more westerly than the trend of the San Simeon fault. One north-dipping reverse fault, which separates serpentinite from graywacke, has broken marine terrace deposits in at least two places, one of them in the basal part of the lowest and youngest terrace. Movement along this branch fault has therefore occurred less than 130,000 years before the present, although the uppermost, youngest Pleistocene deposits are apparently not broken. Prominent topographic lineations defined by northwest-aligned ravines that incise the upper terrace surface, on the other hand, apparently have originated through headward gully erosion along faults and faulted contacts, rather than through the effects of surface faulting.
The characteristics of the San Simeon fault can be summarized as follows: The fault may be related to a fault along the coast to the north that displays some 5 kilometers of vertical displacement. Near San Simeon, it exhibits probable Pleistocene right-lateral strike-slip movement of as much as 1500 feet near San Simeon, although it apparently does not break dune sand deposits of late Pleistocene or early Holocene age. A branch reverse fault, however, breaks upper Pleistocene marine terrace deposits. The San Simeon fault may extend as far south as Point Estero, but it dies out before crossing the northern part of Estero Bay.
- 5. Santa Lucia Bank Fault South of the latitude of Point Piedras Blancas, the western boundary of the main offshore Santa Maria Basin is defined by the east-facing scarp along the east side of the DCPP UNITS 1 & 2 FSAR UPDATE 2.5-12 Revision 21 September 2013 Santa Lucia Bank. This scarp is associated with the Santa Lucia Bank fault, the structure that separates the subsided block under the basin from the structural high of the bank. The escarpment that rises above the west side of the fault trace has a maximum height of about 450 feet, as shown on U.S. Coast and Geodetic Survey (USC&GS) Bathymetric Map 1306N-20.
The Santa Lucia Bank fault can be traced on the sea floor for a distance of about 65 miles. Extensions that are overlapped by upper Tertiary strata continue to the south for at least another 10 miles, as well as to the north. The northern extension may be related to another, largely buried fault that crosses and may intersect the trend of the Santa Lucia Bank fault. This second fault extends to the surface only at points north of the latitude of Point Piedras Blancas.
West of the Santa Lucia Bank fault, between N latitudes 34°30' and 30°, several subparallel faults are characterized by apparent surface scarps. The longest of these faults trends along the upper continental slope for a distance of as much as 45 miles, and generally exhibits a west-facing scarp. Other faults are present in a zone about 30 miles long lying between the 45 mile fault and the Santa Lucia Bank fault. These faults range from 5 to 15 or more miles in length, and have both east-and west-facing scarps.
This zone of faulting corresponds closely in space with the cluster of earthquake epicenters around N latitude 34°45' and 121°30'W longitude, and it probably represents the source structure for those shocks (Figure 2.5-3). 2.5.2.1.2.3 Tectonic Features in the Vicinity of the DCPP Site Geologic relationships between the major fold and fault structures in the vicinity of Diablo Canyon are shown in Figures 2.5-5, 2.5-6, and 2.5-7, and are described and illustrated in Appendix 2.5D of Reference 27 of Section 2.3. The San Luis Ranges-Estero Bay area is characterized structurally by west-northwest-trending folds and faults. These include the San Luis-Pismo syncline and the bordering Los Osos Valley and Point San Luis antiformal highs, and the West Huasna, Edna, and San Miguelito faults. A few miles offshore, the structural features associated with this trend merge into a north-northwest-trending zone of folds and faults that is referred to herein as the offshore Santa Maria Basin East Boundary zone of folding and faulting. The general pattern of structural highs and lows of the onshore area is warped and stepped downward to the west across this boundary zone, to be replaced by more northerly-trending folds in the lower part of the offshore basin section. The overall relationship between the onshore Coast Ranges and the offshore continental margin is one of differential uplift and subsidence. The East Boundary zone represents the structural expression of the zone of inflection between these regions of contrasting vertical movement.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-13 Revision 21 September 2013 In terms of regional relationships, structural style, and history of movement, the faults in the San Luis Ranges-Estero Bay vicinity, identified during the original design phase, may be characterized as follows:
- 1. West Huasna Fault This fault zone separates the large downwarp of the Huasna syncline on the northeast from Franciscan assemblage rocks of the Los Osos Valley antiform and the Tertiary section of the southerly part of the San Luis-Pismo syncline on the southwest. The West Huasna fault is thought to join with the Suey fault to the south. Differences in thicknesses and facies relationships between units of apparently equivalent age on opposite sides of the fault are interpreted as indicating lateral movement along the fault; however, the available evidence regarding the amount and even the relative sense of displacement is not consistent. The West Huasna shows no evidence of late Quaternary activity.
- 2. Edna Fault Zone The Edna fault zone lies along a west-northwesterly trend that extends obliquely from the West Huasna fault at its southeast end to the hills of the San Luis Range south of Morro Bay. Several isolated breaks that lie on a line with the trend are present in the Tertiary strata beneath the south part of Estero Bay, east of the Santa Maria Basin East Boundary fault zone across the mouth of the bay.
The Edna fault is typically a zone of two or more anastomosing branches that range in width from 1/2 mile to as much as 1-1/2 miles. Although individual strands are variously oriented and exhibit various senses of amounts of movement, the zone as a whole clearly expresses high-angle dip-slip displacement (down to the southwest). The irregular traces of major strands suggest that little, if any, strike-slip movement has occurred. Preliminary geologic sections shown by Hall and Surdam (Reference 21) and Hall (Reference 20) imply that the total amount of vertical separation ranges from 1500 to a few thousand feet along the central part of the fault zone. The amount of displacement across the main fault trend evidently decreases to the northwest, where the zone is mostly overlapped by upper Tertiary strata.
It may be, however, that most of the movement in the Baywood Park vicinity has been transferred to the north-trending branch of the Edna, which juxtaposes Pliocene and Franciscan rocks where last exposed. In the northwesterly part of the San Luis Range, the Edna fault forms much of the boundary between the Tertiary and basement rock sections. Most of the measurable displacements along this zone of rupture occurred during or after folding of the Pliocene Pismo Formation but prior to deposition of the lower Pleistocene Paso Robles Formation. Some additional movement has occurred during or since early Pleistocene time, however, because Monterey strata have been faulted against Paso Robles deposits along at least one strand of the Edna near the head of Arroyo Grande valley. This involved steep reverse fault movement, with the DCPP UNITS 1 & 2 FSAR UPDATE 2.5-14 Revision 21 September 2013 southwest side raised, in contrast to the earlier normal displacement down to the southwest.
Search has failed to reveal dislocation of deposits younger than the Paso Robles Formation, disturbance of late Quaternary landforms, or other evidence of Holocene or late Pleistocene activity.
- 3. San Miguelito Fault Zone Northwesterly-trending faults have been mapped in the area between Pismo Beach and Arroyo Grande, and from Avila Beach to the vicinity of the west fork of Vineyard Canyon, north of San Luis Hill. Because these faults lie on the same trend, appear to reflect similar senses of movement, and are "separated" only by an area of no exposure along the shoreline between Pismo Beach and Avila Beach, they may well be part of a more or less continuous zone about 10 miles long. As on the Edna fault, movements along the San Miguelito fault appear to have been predominantly dip-slip, but with displacement down on the northeast. Hall's preliminary cross section indicates total vertical separation of about 1400 feet. The fault is mapped as being overlain by unbroken deposits of the Paso Robles Formation near Arroyo Grande.
Field checking of the ground along the projected trend of the San Miguelito fault zone northwest of Vineyard Canyon in the San Luis Range has substantiated Hall's note that the fault cannot be traced west of that area.
Detailed mapping of the nearly continuous sea cliff exposures extending across this trend northeast of Point Buchon has shown there is no faulting along the San Miguelito trend at the northwesterly end of the range. Like the Edna fault zone, the San Miguelito fault zone evidently represents a zone of high-angle dip-slip rupturing along the flank of the San Luis-Pismo syncline.
- 4. East Boundary Zone of the Offshore Santa Maria Basin The boundary between the offshore Santa Maria Basin and the onshore features of the southern Coast Ranges is a 4 to 5 wide zone of generally north-northwest-trending folds, faults, and onlap unconformities referred to as the "Hosgri fault zone" by Wagner (Reference 31). The geology of this boundary zone has been investigated in detail by means of extensive seismic reflection profiling, high resolution surface profiling, and side scan sonar surveying.
More general information about structural relationships along the boundary zone has been obtained from the pattern of Bouguer Gravity anomaly values that exist in its vicinity. These data show the East Boundary zone to consist of a series of generally parallel north-northwest-trending faults and folds, developed chiefly in upper Pliocene strata that flank upwarped lower Pliocene and older rocks. The zone extends from south of the latitude of Point Sal to north of Point Piedras Blancas. Within the zone, individual fault breaks range in length from less than 1000 feet up to a maximum of DCPP UNITS 1 & 2 FSAR UPDATE 2.5-15 Revision 21 September 2013 about 30 miles. The overall length of the zone is approximately 90 miles, with about 60 miles of relatively continuous faulting.
The apparent vertical component of movement is down to the west across some faults and down to the east across others. Along the central reach of the zone, opposite the San Luis Range, a block of ground has been dropped between the two main strands of the fault to form a graben structure. Within the graben, and at other points along the East Boundary zone, bedding in the rock has been folded down toward the upthrown side of the west side down fault. This feature evidently is an expression of "reverse drag" phenomena.
The axes of folds in the ground on either side of the principal fault breaks can be traced for distances of as much as 22 miles. The fold axes typically are nearly horizontal; maximum axial plunges seem to be 5° or less. The structure and onlap relationships of the upper Pliocene, as reflected in the configuration of the unconformity at its base, are such that it consistently rises from the offshore basin and across the boundary zone via a series of upwarps, asymmetric folds, and faults. This configuration seems to correspond generally to a zone of warping and partial disruption along the boundary between relatively uplifting and subsiding regions. 2.5.2.1.3 Geologic History The geologic history reflected by the rocks, structural features, and landforms of the San Luis Range is typical of that of the southern Coast Ranges of California in its length and complexity. Six general episodes for which there is direct evidence can be tabulated as follows: Age Episode Evidence Late Mesozoic Development of Franciscan and Franciscan and other Upper Cretaceous rock assemblages Mesozoic rocks Late Mesozoic - Early Coast Ranges Structural features pre-served Early Tertiary deformation in the Mesozoic rocks
Mid-Tertiary Uplift and erosion Erosion surface at the base of the Tertiary section
Mid- and late- Accumulation of Miocene Vaqueros, Rincon, Obispo, Tertiary and Pliocene sedimentary Point Sal, Monterey, and Pismo and volcanic rocks Formation and associated volcanic intrusive, and brecciated rocks
Pliocene Folding and faulting associated with Folding and faulting of the the Pliocene Coast Ranges deformation Tertiary and basement rocks
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-16 Revision 21 September 2013 Pleistocene Uplift and erosion, development of Pleistocene and Holocene successive tiers of wave-cut-benches deposits, present land-forms. alluvial fan, talus, and landslide deposition.
The earliest recognizable geologic history of the southern Coast Ranges began in Mesozoic time, during the Jurassic period when eugeosynclinal deposits (graywacke sandstone, shale, chert, and basalt) accumulated in an offshore trench developed in oceanic crust.
Some time after the initiation of Franciscan sedimentation, deposition of a sequence of miogeosynclinal or shelf sandstones and shales, known as the Great Valley Sequence, began on the continental crust, at some distance to the east of the Franciscan trench. Deposition of both sequences continued into Cretaceous time, even while the crustal basement section on which the Great Valley strata were being deposited was undergoing plutonism involving emplacement of granitic rocks. Subsequently, the Franciscan assemblage, the Great Valley Sequence, and the granite-intruded basement rocks were tectonically juxtaposed. The resulting terrane consisted generally of granitic basement thrust over intensely deformed Franciscan, with Great Valley Sequence strata overlying the basement, but thrust over and faulted into the Franciscan.
The processes that were involved in the tectonic juxtaposition evidently were active during the Mesozoic, and continued into the early Tertiary. Page (Reference 25) has shown that they were completed by no later than Oligocene time, so that the dual core complex basement of the southern Coast Ranges was formed by then.
The Miocene and later geologic history of the southern Coast Ranges region began with deposition of the Vaqueros and Rincon Formations on a surface eroded on the Franciscan and Great Valley core complex rocks.
Following deposition and some deformation and erosion of these formations, the stratigraphic unit that includes the Point Sal and Obispo Formations as approximately contemporaneous facies was laid down. The Obispo consists of a section of tuffaceous sandstone and mudstone, with lesser amounts of shale, and lensing layers of vitric and lithic-crystal tuff. Locally, the unit is featured by masses of clastic-textured tuffaceous rock that exhibit cross-cutting intrusive relations with the bedded parts of the formation. The Obispo and Point Sal were folded and locally eroded prior to initiation of the main episode of upper Miocene and Pliocene marine sedimentation.
During late middle Miocene to late Miocene time, deposition of the thick sections of silica-rich shale of the Monterey Formation began. Deposition of this formation and equivalent strata took place throughout much of the coastal region of California, but apparently was centered in a series of offshore basins that all developed at about the same time, some 10 to 12 million years ago. Local volcanism toward the latter part of this time is shown by the presence of diabase dikes and sills in the Monterey. Near the end of the Miocene, the Monterey strata were subjected to compressional deformation resulting in folding, in part with great complexity, and in faulting. Near the old DCPP UNITS 1 & 2 FSAR UPDATE 2.5-17 Revision 21 September 2013 continental margin, represented by the Sur-Nacimiento fault zone, the deformation was most intense, and was accompanied by uplift. This apparently resulted in the first development of many of the large folds of the southern Coast Ranges including the Huasna and San Luis-Pismo synclines, and in the partial erosion of the folded Monterey section in areas of uplift. The pattern of regional uplift of the Coast Ranges and subsidence of the offshore basins, with local upwarping and faulting in a zone of inflection along the boundary between the two regions, apparently became well established during the episode of late Miocene and Mio-Pliocene diastrophism.
Sedimentation resumed in Pliocene time throughout much of the region of the Miocene basins, and several thousand feet of siltstone and sandstone was deposited. This was the last significant episode of marine sedimentation in the region of the present Coast Ranges. Pliocene deposits in the region of uplift were then folded, and there was renewed movement along most of the preexisting larger faults.
Differential movements between the Coast Ranges uplift and the offshore basins were again concentrated along the boundary zone of inflection, resulting in upwarping and faulting of the basement, Miocene, and Pliocene sections. Relative displacement across parts of this zone evidently was dominantly vertical, because the faulting in the Pliocene has definitely extensional character, and Miocene structures can be traced across the zone without apparent lateral offset. The basement and Tertiary sections step down seaward, away from the uplift, along a system of normal faults having hundreds to nearly a thousand feet of dip-slip offset. A second, more seaward system of normal faults is antithetic to the master set and exhibits only tens to a few hundreds of feet of displacement. Strata between these faults locally exhibit reverse drag downfolding toward the edge of the Pliocene basin, whereas the section is essentially undeformed farther offshore. This style of deformation indicates a passive response, through gravity tectonics, to the onshore uplift.
The Plio-Pleistocene uplift was accompanied by rapid erosion, with consequent nearby deposition of clastic sediments such as the Paso Robles Formation in valleys throughout the southern Coast Ranges. The high-angle reverse and normal faulting observed by Compton (Reference 38) in the northern Santa Lucia Range also occurred farther south, probably more or less contemporaneously with accumulation of the continental deposits. Much of the Quaternary faulting other than that related to the San Andreas right lateral stress-strain system may well have occurred at this time.
Tectonic activity during the Quaternary has involved continued general uplift of the southern Coast Ranges, with superimposed local downwarping and continued movement along faults of the San Andreas system. The uplift is shown by the general high elevation and steep youthful topography that characterizes the Coast Ranges and by the widespread uplifted marine and stream terraces. Local downwarping can be seen in valleys, such as the Santa Maria Valley, where thick sections of Plio-Pleistocene and younger deposits have accumulated. Evidence of significant late Quaternary fault movement is seen in the topography along the Rinconada-San Marcos, Espinosa, San Simeon, and Santa Lucia Bank faults, as well DCPP UNITS 1 & 2 FSAR UPDATE 2.5-18 Revision 21 September 2013 as along the San Andreas itself. Only along the San Andreas, however, is there evidence of Holocene or contemporary movement.
The latest stage in the evolution of the San Luis Range has extended from mid-Pleistocene time to the present, and has involved more or less continuous interaction between apparent uplift of the range and alternating periods of erosion or deposition, especially along the coast, during times of relatively rising, falling, or unchanging sea level. The development of wave-cut benches and the accumulation of marine deposits on these benches have provided a reliable guide to the minimum age of latest displacements along breaks in the underlying bedrock. Detailed exploration of the interfaces between wave-cut benches and overlying marine deposits at the site of DCPP has shown that no breaks extend across these interfaces. This demonstrates that the youngest faulting or other bedrock breakage in that area antedated the time of terrace cutting, which is on the order of 80,000 to 120,000 years before the present.
The bedrock section and the surficial deposits that formerly capped this bedrock on which the power plant facilities are located have been studied in detail to determine whether they express any evidence of deformation or dislocation ascribable to earthquake effects.
The surficial geologic materials at the site consisted of a thin, discontinuous basal section of rubbly marine sand and silty sand, and an overlying section of nonmarine rocky sand and sandy clay alluvial and colluvial deposits. These deposits were extensively exposed by exploratory trenches, and were examined and mapped in detail. No evidence of earthquake-induced effects such as lurching, slumping, fissuring, and liquefaction was detected during this investigation. The initial movement of some of the landslide masses now present in Diablo Canyon upstream from the switchyard area may have been triggered by earthquake shaking. It is also possible that some local talus deposits may represent earthquake-triggered rock falls from the sea cliff or other steep slopes in the vicinity.
Deformation of the rock substrata in the site area may well have been accompanied by earthquake activity at the time of its occurrence in the geologic past. There is no evidence, however, of post-terrace earthquake effects in the bedrock where the power plant is being constructed. 2.5.2.1.4 Stratigraphy of the San Luis Range and Vicinity The geologic section exposed in the San Luis Range comprises sedimentary, igneous, and tectonically emplaced ultrabasic rocks of Mesozoic age, sedimentary, pyroclastic, and hypabyssal intrusive rocks of Tertiary age, and a variety of surficial deposits of Quaternary age. The lithology, age, and distribution of these rocks were studied by Headlee and more recently have been mapped in detail by Hall. The geology of the San Luis Range is shown in Figure 2.5-6 with a geologic cross section constructed using exploratory oil wells shown in Figure 2.5-7. The geologic events that resulted in DCPP UNITS 1 & 2 FSAR UPDATE 2.5-19 Revision 21 September 2013 the stratigraphic units described in this section are discussed in Section 2.5.2.1.3, Geologic History. 2.5.2.1.4.1 Basement Rocks An assemblage of rocks typical of the Coast Ranges basement terrane west of the Nacimiento fault zone is exposed along the south and northeast sides of the San Luis Range. As described by Headlee, this assemblage includes quartzose and greywacke sandstone, shale, radiolarian chert, intrusive serpentine and diabase, and pillow basalt. Some of these rocks have been dated as Upper Cretaceous from contained microfossils, including pollen and spores, and Headlee suggested that they may represent dislocated parts of the Great Valley Sequence. There is contrasting evidence, however, that at least the pillow basalt and associated cherty rocks may be more typically Franciscan. Certainly, such rocks are characteristic of the Franciscan terrane. Further, a potassium-argon age of 156 million years, equivalent to Upper Jurassic, has been determined for a core of similar rocks obtained from the bottom of the Montodoro Well No. 1 near Point Buchon. 2.5.2.1.4.2 Tertiary Rocks Five formational units are represented in the Tertiary section of the San Luis Range. The lower part of this section comprises rocks of the Vaqueros, Rincon, and Obispo Formations, which range in age from lower Miocene through middle Miocene. These strata crop out in the vicinity of Hazard Canyon, at the northwest end of the range, and in a broad band along the south coastal margin of the range. In both areas the Vaqueros rests directly on Mesozoic basement rocks. The core of the western San Luis Range is underlain by the Upper Miocene Monterey Formation, which constitutes the bulk of the Tertiary section. The Upper Miocene to Lower Pliocene Pismo Formation crops out in a discontinuous band along the southwest flank and across the west end of the range, resting with some discordance on the Monterey section and elsewhere directly on older Tertiary or basement rocks.
The coastal area in the vicinity of Diablo Canyon is underlain by strata that have been variously correlated with the Obispo, Point Sal, and Monterey Formations. Headlee, for example, has shown the Point Sal as overlying the Obispo, whereas Hall has considered these two units as different facies of a single time-stratigraphic unit. Whatever the exact stratigraphic relationships of these rocks might prove to be, it is clear that they lie above the main body of tuffaceous sedimentary rocks of the Obispo Formation and below the main part of the Monterey Formation. The existence of intrusive bodies of both tuff breccia and diabase in this part of the section indicates either that local volcanic activity continued beyond the time of deposition of the Obispo Formation, or that the section represents a predominantly sedimentary facies of the upper part of the Obispo Formation. In either case, the strata underlying the power plant site range downward through the Obispo Formation and presumably include a few hundred feet of the Rincon and Vaqueros Formations resting upon a basement of Mesozoic rocks. DCPP UNITS 1 & 2 FSAR UPDATE 2.5-20 Revision 21 September 2013 A generalized description of the major units in the Tertiary section follows, and a more detailed description of the rocks exposed at the power plant site is included in a later section.
The Vaqueros Formation has been described by Headlee as consisting of 100 to 400 feet of resistant, massive, coarse-grained, calcareously cemented bioclastic sandstone. The overlying Rincon Formation consists of 200 to 300 feet of dark gray to chocolate brown calcareous shale and mudstone.
The Obispo Formation (or Obispo Tuff) is 800 to 2000 feet thick and comprises alternating massive to thick-bedded, medium to fine grained vitric-lithic tuffs, finely laminated black and brown marine siltstone and shale, and medium grained light tan marine sandstone. Headlee assigned to the Point Sal Formation a section described as consisting chiefly of medium to fine grained silty sandstone, with several thin silty and fossiliferous limestone lenses; it is gradational upward into siliceous shale characteristic of the Monterey Formation. The Monterey Formation itself is composed predominantly of porcelaneous and finely laminated siliceous and cherty shales. The Pismo Formation consists of massive, medium to fine grained arkosic sandstone, with subordinate amounts of siltstone, sandy shale, mudstone, hard siliceous shale, and chert. 2.5.2.1.4.3 Quaternary Deposits Deposits of Pleistocene and Holocene age are widespread on the coastal terrace benches along the southwest margin of the San Luis Range, and they exist farther onshore as local alluvial and stream-terrace deposits, landslide debris, and various colluvial accumulations. The coastal terrace deposits include discontinuous thin basal sections of marine silt, sand, gravel, and rubble, some of which are highly fossiliferous, and generally much thicker overlying sections of talus, alluvial-fan debris, and other deposits of landward origin. All of the marine deposits and most of the overlying nonmarine accumulations are of Pleistocene age, but some of the uppermost talus and alluvial deposits are Holocene. Most of the alluvial and colluvial materials consist of silty clayey sand with irregularly distributed fragments and blocks of locally exposed rock types. The landslide deposits include chaotic mixtures of rock fragments and fine-grained matrix debris, as well as some large masses of nearly intact to thoroughly disrupted bedrock.
A more detailed description of surficial deposits that are present in the vicinity of the power plant site is included in a later section.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-21 Revision 21 September 2013 2.5.2.1.5 Structure of the San Luis Range and Vicinity 2.5.2.1.5.1 General Features The geologic structure of the San Luis Range-Estero Bay and adjacent offshore area is characterized by a complex set of folds and faults (Figures 2.5-5, 2.5-6, and 2.5-7). Tectonic events that produced these folds and faults are discussed in Section 2.5.2.1.3, Geologic History. The San Luis Range-Estero Bay and adjacent offshore area lies within the zone of transition from the west-trending Transverse Range structural province to the northwest-trending Coast Ranges province. Major structural features are the long narrow downfold of the San Luis-Pismo syncline and the bordering antiformal structural highs of Los Osos Valley on the northeast, and of Point San Luis and the adjacent offshore area on the southwest. This set of folds trends obliquely into a north-northwest aligned zone of basement upwarping, folding, and high-angle normal faulting that lies a few miles off the coast. The main onshore folds can be recognized, by seismic reflection and gravity techniques, in the structure of the buried, downfaulted Miocene section that lies across (west of) this zone.
Lesser, but yet important structural features in this area include smaller zones of faulting and trends of volcanic intrusives. The Edna and San Miguelito fault zones disrupt parts of the northeast and southwest flanks of the San Luis-Pismo syncline. A southward extension of the San Simeon fault, the existence of which is inferred on the basis of the linearity of the coastline between Cambria and Point Estero, and of the gravity gradient in that area, may extend into, and die out within, the northern part of Estero Bay. An aligned series of plugs and lensoid masses of Tertiary volcanic rocks that intrude the Franciscan Formation along the axis of the Los Osos Valley antiform extends from the outer part of Estero Bay southeastward for 22 miles (Figure 2.5-6). These features define the major elements of geologic structure in the San Luis Range-Estero Bay area. Other structural elements include the complex fold and fault structures within the Franciscan core complex rocks and the numerous smaller folds within the Tertiary section. 2.5.2.1.5.2 San Luis-Pismo Syncline The main synclinal fold of the San Luis Range, referred to here as the San Luis-Pismo syncline, trends about N60°W and forms a structural trend more than 15 miles in length. The fold system comprises several parallel anticlines and synclines across its maximum onshore width of about 5 miles. Individual folds of the system typically range in length from hundreds of feet to as much as 10,000 feet. The folds range from zero to more than 30° in plunge, and have flank dips as steep as 90°. Various kinds of smaller folds exist locally, especially flexures and drag folds associated with tuff intrusions and with zones of shear deformation.
Near Estero Bay, the major fold extends to a depth of more than 6000 feet. Farther south, in the central part of the San Luis Range, it is more than 11,000 feet deep. Parts DCPP UNITS 1 & 2 FSAR UPDATE 2.5-22 Revision 21 September 2013 of the northeast flank of the fold are disrupted by faults associated with the Edna fault zone. Local breaks along the central part of the southwest flank have been referred to as the San Miguelito fault zone. 2.5.2.1.5.3 Los Osos Valley Antiform The body of Franciscan and Great Valley Sequence rocks that crops out between the San Luis-Pismo and Huasna synclines is here referred to as the Los Osos Valley antiform. This composite structure extends southward from the Santa Lucia Range, across the central and northern part of Estero Bay, and thence southeastward to the point where it is faulted out at the juncture of the Edna and the West Huasna fault zones.
Notable structural features within this core complex include northwest- and west-northwest- trending-faults that separate Franciscan melange, graywacke, metavolcanic, and serpentinite units. The serpentinites have been intruded or dragged within faults, apparently over a wide range of scales. One of the more persistent zones of serpentinite bodies occurs along a trend which extends west-northwestward from the West Huasna fault. It has been suggested that movement from this fault may have taken place within this serpentine belt. The range of hills that lies between the coast and Highway 1 between Estero Bay and Cambria is underlain by sandstone and minor shale of the Great Valley Sequence, referred to as the Cambria slab, which has been underthrust by Franciscan rocks. The thrust contact extends southeastward under Estero Bay near Cayucos. This contact is probably related to the fault contact between Great Valley and Franciscan rocks located just north of San Luis Obispo, which Page has shown to be overlain by unbroken lower Miocene strata. A prominent feature of the Los Osos Valley antiform is the line of plugs and lensoid masses of intrusive Tertiary volcanic rocks. These distinctive bodies are present at isolated points along the approximate axis of the antiform over a distance of 22 miles, extending from the center of outer Estero Bay to the upper part of Los Osos Valley (Figure 2.5-6). The consistent trend of the intrusives provides a useful reference for assessing the possibility of northwest-trending lateral slip faulting within Estero Bay. It shows that such faulting has not extended across the trend from either the inferred San Simeon fault offshore south extension, or from faults in the ground east of the San Simeon trend. 2.5.2.1.5.4 Edna and San Miguelito Fault Zones These fault zones are described in Section 2.5.2.1.2.3. 2.5.2.1.5.5 Adjacent Offshore Area and East Boundary of the Offshore Santa Maria Basin The stratigraphy and west-northwest-trending structure that characterize the onshore region from Point Sal to north of Point Estero have been shown by extensive marine DCPP UNITS 1 & 2 FSAR UPDATE 2.5-23 Revision 21 September 2013 geophysical surveying to extend into the adjacent offshore area as far as the north-northwest trending structural zone that forms a boundary with the main offshore Santa Maria Basin. Owing to the irregular outline of the coast, the width of the offshore shelf east of this boundary zone ranges from 2-1/2 to as much as 12 miles. The shelf area is narrowest opposite the reach of coast between Point San Luis and Point Buchon, and widest in Estero Bay and south of San Luis Bay.
The major geologic features that underlie the near-shore shelf include, from south to north, the Casmalia Hills anticline, the broad Santa Maria Valley downwarp, the anticlinal structural high off Point San Luis, the San Luis-Pismo syncline, and the Los Osos Valley antiform.
The form of these features is defined by the outcrop pattern and structure of the older Pliocene, Miocene, and basement core complex rocks. The younger Pliocene strata that constitute the upper 1000 to 2000 feet of section in the adjacent offshore Santa Maria Basin are partly buttressed and partly faulted against the rocks that underlie the near-shore shelf, and they unconformably overlap the boundary zone and parts of the shelf in several areas.
The boundaries between the San Luis-Pismo syncline and the adjacent Los Osos Valley and Point San Luis antiforms can be seen in the offshore area to be expressed chiefly as zones of inflection between synclinal and anticlinal folds, rather than as zones of fault rupture such as occurs farther south along the Edna and San Miguelito faults. Isolated west-northwest- trending faults of no more than a few hundred feet displacement are located along the northeast flank of the syncline in Estero Bay. These faults evidently are the northwesternmost expressions of breakage along the Edna fault trend. The main San Luis-Pismo synclinal structure opens to the northwest, attaining a maximum width of 8 or 9 miles in the southerly part of Estero Bay. The Point San Luis high, on the other hand, is a domal structure, the exposed basement rock core of which is about 10 miles long and 5 miles wide.
The general characteristics of the Santa Maria Basin East Boundary zone have been described in Section 2.5.2.1.2.3. As was noted there, the zone is essentially an expression of the boundary between the synclinorial downwarp of the offshore basin and the regional uplift of the southern Coast Ranges. In the vicinity of the San Luis Range, the zone is characterized by pronounced upwarping and normal faulting of the basement and overlying Tertiary rock sections. Both modes of deformation have contributed to the structural relief of about 500 feet in the Pliocene section, and of 1500 feet or more in the basement rocks, across this boundary. Successively younger strata are banked unconformably against the slopes that have formed from time to time in response to the relative uplifting of the ground east of the boundary zone.
A series of near-surface structural troughs forms prominent features within the segment of the boundary zone structure that extends between the approximate latitudes of DCPP UNITS 1 & 2 FSAR UPDATE 2.5-24 Revision 21 September 2013 Arroyo Grande and Estero Bay. This trough structure apparently has formed through the extension and subsidence of a block of ground in the zone where the downwarp of the offshore basin has pulled away from the Santa Lucia uplift. Continued subsidence of this block has resulted in deformation and partial disruption of the buttress unconformity between the offshore Pliocene section and the near-shore Miocene and older rocks. This deformation is expressed by normal faulting and reverse drag type downfolding of the Pliocene strata adjacent to the contact, along the east side of the trough.
On the opposite, seaward side of the trough, a series of antithetic down-to-the-east normal faults of small displacement has formed in the Pliocene strata west of the contact zone. These faults exhibit only a few tens of feet displacement, and they seem to exhibit constant or even decreasing displacement downward.
The structural evolution of the offshore area near Estero Bay and the San Luis Range involved episodes of compressional deformation that affected the upper Tertiary section similarly on opposite sides of the boundary zone. The section on either side exhibits about the same intensity and style of folding. Major folds, such as the San Luis-Pismo syncline and the Piedras Blancas anticline, can be traced into the ground across the boundary zone.
The internal structure of the zone, including the presence of several on-lap unconformities in the adjacent Pliocene section, shows that, at least during Pliocene and early Pleistocene time, the boundary zone has been the inflection line between the Coast Ranges uplift and the offshore Santa Maria Basin downwarp. Evidence that uplift has continued through late Pleistocene time, at least in the vicinity of the San Luis Range, is given by the presence of successive tiers of marine terraces along the seaward flank of the range. The wave-cut benches and back scarps of these terraces now exist at elevations ranging from about -300 feet (below sea level) to more than 300 feet above sea level.
The ground within which the East Boundary zone lies has been beveled by the post-Wisconsin marine transgression, and so the zone generally is not expressed topographically. Small topographic features, such as a seaward topographic step-up of the sea floor surface across the east-down fault at the BBN (Reference 37) (offshore) survey line 27 crossing, in Estero Bay, and several possible fault-line notch back scarps, however, may represent minor topographic expressions of deformation within the zone. 2.5.2.1.6 Structural Stability The potential for surface or subsurface subsidence, uplift, or collapse at the site or in the region surrounding the site, is discussed in Section 2.5.5, Stability of Subsurface Materials. DCPP UNITS 1 & 2 FSAR UPDATE 2.5-25 Revision 21 September 2013 2.5.2.1.7 Regional Groundwater Groundwater in the region surrounding the site is used as a backup source due to its poor quality and the lack of a significant groundwater reservoir. Section 2.4.13 states that most of the groundwater at the site or in the area around the site is either in the alluvial deposits of Diablo Creek or seeps from springs encountered in excavations at the site. 2.5.2.2 Site Geology 2.5.2.2.1 Site Physiography The site consists of approximately 750 acres near the mouth of Diablo Creek and is located on a sloping coastal terrace, ranging from 60 to 150 feet above sea level. The terrace terminates at the Pacific Ocean on the southwest and extends toward the San Luis Mountains on the northeast. The terrace consists of bedrock overlain by surficial deposits of marine and nonmarine origin.
The remainder of this section presents a detailed description of site geology. 2.5.2.2.2 General Features The area of the DCPP site is a coastal tract in San Luis Obispo County approximately 6.5 miles northwest of Point San Luis. It lies immediately southeast of the mouth of Diablo Canyon, a major westward-draining feature of the San Luis Range, and about a mile southeast of Lion Rock, a prominent offshore element of the highly irregular coastline. The ground being developed as a power plant site occupies an extensive topographic terrace about 1000 feet in average width. In its pregrading, natural state, the gently undulating surface of this terrace sloped gradually southwestward to an abrupt termination along a cliff fronting the ocean; in a landward, or northeasterly, direction, it rose with progressively increasing slope to merge with the much steeper front of a foothill ridge of the San Luis Range. The surface ranged in altitude from 65 to 80 feet along the coastline to a maximum of nearly 300 feet along the base of the hillslope to the northeast, but nowhere was its local relief greater than 10 feet. Its only major interruption was the steep-walled canyon of lower Diablo Creek, a gash about 75 feet in average depth.
The entire subject area is underlain by a complex sequence of stratified marine sedimentary rocks and tuffaceous volcanic rocks, all of Tertiary (Miocene) age. Diabasic intrusive rocks are locally exposed high on the walls of Diablo Canyon at the edge of the area. Both the sedimentary and volcanic rocks have been folded and otherwise disturbed over a considerable range of scales.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-26 Revision 21 September 2013 Surficial deposits of Quaternary age are widespread. In a few places, they are as thick as 50 feet, but their average thickness probably is on the order of 20 feet over the terrace areas and 10 feet or less over the entire mapped ground. The most extensive deposits underlie the main topographic terrace.
Like many other parts of the California coast, the Diablo Canyon area is characterized by several wave-cut benches of Pleistocene age. These surfaces of irregular but generally low relief were developed across bedrock by marine erosion, and they are ancient analogues of the benches now being cut approximately at sea level along the present coast. They were formed during periods when the sea level was higher, relative to the adjacent land, than it is now. Each is thinly and discontinuously mantled with marine sand, gravel, and rubble similar to the beach and offshore deposits that are accumulating along the present coastline. Along its landward margin each bears thicker and more localized coarse deposits similar to the modern talus along the base of the present sea cliff.
Both the ancient wave-cut benches and their overlying marine and shoreline deposits have been buried beneath silty to gravelly detritus derived from landward sources after the benches were, in effect, abandoned by the ocean. This nonmarine cover is essentially an apron of coalescing fan deposits and other alluvial debris that is thickest adjacent to the mouths of major canyons.
Where they have been deeply trenched by subsequent erosion, as along Diablo Canyon in the map areas, these deposits can be seen to have buried some of the benches so deeply that their individual identities are not reflected by the present (pregrading) rather smooth terrace topography. Thus, the surface of the main terrace is defined mainly by nonmarine deposits that conceal both the older benches of marine erosion and some of the abruptly rising ground that separates them (refer to Figures 2.5-8 and 2.5-10). The observed and inferred relationships among the terrace surfaces and the wave-cut benches buried beneath them can be summarized as follows: Wave-cut Bench Terrace Surface Altitude, feet Location Altitude, feetLocation 170-175 Small remnants on sides of Diablo Canyon Mainly 170-190 Sides of Diablo Canyon and upper parts of main terrace; in places separated from 145-155 Very small remnants on sides of Diablo Canyon Mainly 150-170 lower parts of terrace by scarps 120-130 Subparallel benches elongate in a northwest- Mainly 70-160 Most of main terrace, a wide- spread surface on a composite90-100 southeast direction but with considerable section of nonmarine deposits; no well-defined scarps 65-80 aggregate width; wholly DCPP UNITS 1 & 2 FSAR UPDATE 2.5-27 Revision 21 September 2013 beneath main terrace surface 50-100 Small remnants above modern sea cliff 30-45 Small remnants above modern sea cliff No depositional terrace Approx. 0 Small to moderately large areas along present coastline. Within the subject area the wave-cut benches increase progressively in age with increasing elevation above present sea level; hence, their order in the above list is one of decreasing age. By far, the most extensive of these benches slopes gently seaward from a shoreline angle that lies at an elevation of 100 feet above present sea level.
The geology of the power plant site is shown in the site geologic maps, Figures 2.5-8 and 2.5-9, and geologic section, Figure 2.5-10. 2.5.2.2.3 Stratigraphy 2.5.2.2.3.1 Obispo Tuff The Obispo Tuff, which has been classified either as a separate formation or as a member of the Miocene Monterey Formation, is the oldest bedrock unit exposed in the site area. Its constituent rocks generally are well exposed, appear extensively in the coastward parts of the area, and form nearly all of the offshore prominences and shoals. They are dense to highly porous, and thinly layered to almost massive. Their color ranges from white to buff in fresh exposures, and from yellowish to reddish brown on weathered surfaces, many of which are variegated in shades of brown. Outcrop surfaces have a characteristic "punky" to crusty appearance, but the rocks in general are tough, cohesive, and relatively resistant to erosion.
Several pyroclastic rock types constitute the Obispo Tuff ("To" on map, Figure 2.5-8) in and near the subject area. By far, the most widespread is fine-grained vitric tuff with rare to moderately abundant tabular crystals of sodic plagioclase. The constituent glass commonly appears as fresh shards, but in many places it has been partly or completely devitrified. Crystal tuffs are locally prominent, and some of these are so crowded with 1/8 to 3/8 inch crystals of plagioclase that they superficially resemble granitoid plutonic rocks. Other observed rock types include pumiceous tuffs, pumice-pellet tuff breccias, perlitic vitreous tuffs, tuffaceous siltstones and mudstones, and fine-grained tuff breccias with fragments of glass and various Monterey rocks. No massive flow rocks were recognized anywhere in the exposed volcanic section.
In terms of bulk composition, the pyroclastic rocks appear to be chiefly soda rhyolites and soda quartz latites. Their plagioclase, which ranges from calcic albite to sodic oligoclase, commonly is accompanied by lesser amounts of quartz as small rounded DCPP UNITS 1 & 2 FSAR UPDATE 2.5-28 Revision 21 September 2013 crystals and irregular crystal fragments. Biotite, zircon, and apatite also are present in many of the specimens that were examined under the microscope. Most of the tuffaceous rocks, and especially the more vitreous ones, have been locally to pervasively altered. Products of silicification, zeolitization, and pyritization are readily recognizable in many exposures, where the rocks generally are traversed by numerous thin, irregular veinlets and layers of cherty to opaline material. Veinlets and thin, pod-like concentrations of gypsum also are widespread. Where pyrite is present, the rocks weather yellowish to brownish and are marked by gossan-like crusts.
The various contrasting rock types are simply interlayered in only a few places; much more typical are abutting, intertonguing, and irregularly interpenetrating relationships over a wide range of scales. Septa and inclusions of Monterey rocks are abundant, and a few of them are large enough to be shown separately on the accompanying geologic map (Figure 2.5-8). Highly irregular inclusions, a few inches to several feet in maximum dimension, are so densely packed together in some places that they form breccias with volcanic matrices.
The Obispo Tuff is underlain by mudstones of early Miocene (pre-Monterey) age, on which it rests with a highly irregular contact that appears to be in part intrusive. This contact lies offshore in the vicinity of the power plant site, but it is exposed along the seacoast to the southeast.
In a gross way, the Obispo underlies the basal part of the Monterey formation, but many of its contacts with these sedimentary strata are plainly intrusive. Moreover, individual sills and dikes of slightly to thoroughly altered tuffaceous rocks appear here and there in the Monterey section, not uncommonly at stratigraphic levels well above its base (refer to Figures 2.5-8 and 2.5-13). The observed physical relationships, together with the local occurrence of diatoms and foraminifera within the principal masses of volcanic rocks, indicate that much of the Obispo Tuff in this area probably was emplaced at shallow depths beneath the Miocene sea floor during accumulation of the Monterey strata. The tuff unit does not appear to represent a single, well-defined eruptive event, nor is it likely to have been derived from a single source conduit. 2.5.2.2.3.2 Monterey Formation Stratified marine rocks variously correlated with the Monterey Formation, Point Sal Formation, and Obispo Tuff underlie most of the subject area, including all of that portion intended for power plant location. They are almost continuously exposed along the crescentic sea cliff that borders Diablo Cove, and elsewhere they appear in much more localized outcrops. For convenience, they are here assigned to the Monterey Formation ("Tm" on map, Figure 2.5-8) in order to delineate them from the adjacent more tuffaceous rocks so typical of the Obispo Tuff.
The observed rock types, listed in general order of decreasing abundance, are silty and tuffaceous sandstone, siliceous shale, shaly siltstone and mudstone, diatomaceous shale, sandy to highly tuffaceous shale, calcareous shale and impure limestone, DCPP UNITS 1 & 2 FSAR UPDATE 2.5-29 Revision 21 September 2013 bituminous shale, fine- to coarse-grained sandstone, impure vitric tuff, silicified limestone and shale, and tuff-pellet sandstone. Dark colored and relatively fine-grained strata are most abundant in the lowest part of the section, as exposed along the east side of Diablo Cove, whereas lighter colored sandstones and siliceous shales are dominant at stratigraphically higher levels farther north. In detail, however, the different rock types are interbedded in various combinations, and intervals of uniform lithology rarely are thicker than 30 feet. Indeed, the closely-spaced alternations of contrasting strata yield a prominent rib-like pattern of outcrop along much of the sea cliff and shoreline bench forming the margin of Diablo Cove.
The sandstones are mainly fine- to medium-grained, and most are distinctly tuffaceous. Shards of volcanic glass generally are recognizable under the microscope, and the very fine-grained siliceous matrix may well have been derived largely through alteration of original glassy material. Some of the sandstone contains small but megascopically visible fragments of pumice, perlitic glass, and tuff, and a few beds grade along strike into submarine tuff breccia. The sandstones are thinly to very thickly layered; individual beds 6 inches to 4 feet thick are fairly common, and a few appear to be as thick as 15 feet. Some of them are hard and very resistant to erosion, and they typically form subdued but nearly continuous elongated projections on major hillslopes (Figure 2.5-8).
The siliceous shales are buff to light gray platy rocks that are moderately hard to extremely hard according to their silica content, but they tend to break readily along bedding and fracture surfaces. The bituminous rocks and the siltstones and mudstones are darker colored, softer, and grossly more compact. Some of them are very thinly bedded or laminated, others appear almost massive or form matrices for irregularly ellipsoidal masses of somewhat sandier material. The diatomaceous, tuffaceous, and sandy rocks are lighter colored. The more tuffaceous types are softer, and the diatomaceous ones are soft to the degree of punkiness; both kinds of rocks are easily eroded, but are markedly cohesive and tend to retain their gross positions on even the steepest of slopes.
The siliceous shale and most of the hardest, highly silicified rocks weather to very light gray, and the dark colored, fine-grained rocks tend to bleach when weathered. The other types, including the sandstones, weather to various shades of buff and light brown. Stains of iron oxides are widespread on exposures of nearly all the Monterey rocks, and are especially well developed on some of the finest-grained shales that contain disseminated pyrite. All but the hardest and most thick-bedded rocks are considerably broken to depths of as much as 6 feet in the zone of weathering on slopes other than the present sea cliff, and the broken fragments have been separated and displaced by surface creep to somewhat lesser depths. 2.5.2.2.3.3 Diabasic Intrusive Rocks Small, irregular bodies of diabasic rocks are poorly exposed high on the walls of Diablo Canyon at and beyond the northeasterly edge of the map area. Contact relationships are readily determined at only a few places where these rocks evidently are intrusive DCPP UNITS 1 & 2 FSAR UPDATE 2.5-30 Revision 21 September 2013 into the Monterey Formation. They are considerably weathered, but an ophitic texture is recognizable. They consist chiefly of calcic plagioclase and augite, with some olivine, opaque minerals, and zeolitic alteration products. 2.5.2.2.3.4 Masses of Brecciated Rocks Highly irregular masses of coarsely brecciated rocks, a few feet to many tens of feet in maximum dimension, are present in some of the relatively siliceous parts of the Monterey section that adjoin the principal bodies of Obispo Tuff. The fracturing and dislocation is not genetically related to any recognizable faults, but instead seems to have been associated with emplacement of the volcanic rocks; it evidently was accompanied by, or soon followed by, extensive silicification. Many adjacent fragments in the breccias are closely juxtaposed and have matching opposed surfaces, so that they plainly represent no more than coarse crackling of the brittle rocks. Other fragments, though angular or subangular, are not readily matched with adjacent fragments and hence may represent significant translation within the entire rock masses.
The ratio of matrix materials to coarse fragments is very low in most of the breccias and nowhere was it observed to exceed about 1:3. The matrices generally comprise smaller angular fragments of the same Monterey rocks that are elsewhere dominant in the breccias, and they characteristically are set in a siliceous cement. Tuffaceous matrices, with or without Monterey fragments, also are widespread and commonly show the effects of pervasive silicification. All the exposed breccias are firmly cemented, and they rank among the hardest and most resistant units in the entire bedrock section. A few 3 to 18 inch beds of sandstone have been pulled apart to form separate tabular masses along specific stratigraphic horizons in higher parts of the Monterey sequence. Such individual tablets, which are boudins rather than ordinary breccia fragments, are especially well exposed in the sea cliff at the northern corner of Diablo Cove. They are flanked by much finer-grained strata that converge around their ends and continue essentially unbroken beyond them. This boudinage or separation and stringing out of sandstone beds that lie within intervals of much softer and more shaly rocks has resulted from compression during folding of the Monterey section. Its distribution is stratigraphically controlled and is not systematically related to recognizable faults in the area. 2.5.2.2.3.5 Surficial Deposits
- 1. Coastal Terrace Deposits The coastal wave-cut benches of Pleistocene age, as described in a foregoing section, are almost continuously blanketed by terrace deposits (Qter in Figure 2.5-8) of several contrasting types and modes of origin. The oldest of these deposits are relatively thin and patchy in their occurrence, and were laid down along and adjacent to ancient beaches during Pleistocene time. They are covered by considerably thicker and more DCPP UNITS 1 & 2 FSAR UPDATE 2.5-31 Revision 21 September 2013 extensive nonmarine accumulations of detrital materials derived from various landward sources.
The marine deposits consist of silt, sand, gravel, and cobbly to bouldery rubble. They are approximately 2 feet in average thickness over the entire terrace area and reach a maximum observed thickness of about 8 feet. They rest directly upon bedrock, some of which is marked by numerous holes attributable to the action of boring marine mollusks, and they commonly contain large rounded cobbles and boulders of Monterey and Obispo rocks that have been similarly bored. Lenses and pockets of highly fossiliferous sand and gravel are present locally.
The marine sediments are poorly to very well sorted and loose to moderately well consolidated. All of them have been naturally compacted; the degree of compaction varies according to the material, but it is consistently greater than that observed in any of the associated surficial deposits of other types. Near the inner margins of individual wave-cut benches the marine deposits merge landward into coarser and less well-sorted debris that evidently accumulated along the bases of ancient sea cliffs or other shoreline slopes. This debris is locally as much as 12 feet thick; it forms broad but very short aprons, now buried beneath younger deposits, that are ancient analogues of the talus accumulations along the inner margin of the present beach in Diablo Cove. One of these occurrences, identified as "fossil Qtb" in the geologic map of Figure 2.5-8, is well exposed high on the northerly wall of Diablo Canyon.
A younger, thicker, and much more continuous nonmarine cover is present over most of the coastal terrace area. It consistently overlies the marine deposits noted above, and, where these are absent, it rests directly upon bedrock. It is composed in part of alluvial detritus contributed during Pleistocene time from Diablo Canyon and several smaller drainage courses, and it thickens markedly as traced sourceward toward these canyons. The detritus represents a series of alluvial fans, some of which appear to have partly coalesced with adjacent ones. It is chiefly fine- to moderately-coarse-grained gravel and rubble characterized by tabular fragments of Monterey rocks in a rather abundant silty to clayey matrix. Most of it is thinly and regularly stratified, but the distinctness of this layering varies greatly from place to place.
Slump, creep, and slope-wash deposits, derived from adjacent hillsides by relatively slow downhill movement over long periods of time, also form major parts of the nonmarine terrace cover. All are loose and uncompacted. They comprise fragments of Monterey rocks in dark colored clayey matrices, and their internal structure is essentially chaotic. In some places they are crudely interlayered with the alluvial fan deposits, and elsewhere they overlie these bedded sediments. On parts of the main terrace area not reached by any of the alluvial fans, a cover of slump, creep, and slope-wash deposits, a few inches to nearly 10 feet thick, rests directly upon either marine terrace deposits or bedrock.
Thus, the entire section of terrace deposits that caps the coastal benches of Pleistocene marine erosion is heterogeneous and internally complex; it includes contributions of DCPP UNITS 1 & 2 FSAR UPDATE 2.5-32 Revision 21 September 2013 detritus from contrasting sources, from different directions at different times, and via several basically different modes of transport and deposition.
- 2. Stream-terrace Deposits Several narrow, irregular benches along the walls of Diablo Canyon are veneered by a few inches to 6 feet of silty gravels that are somewhat coarser but otherwise similar to the alluvial fan deposits described above. These stream-terrace deposits (Qst) originally occupied the bottom of the canyon at a time when the lower course of Diablo Creek had been cut downward through the alluvial fan sediments of the main terrace and well into the underlying bedrock. Subsequent deepening of the canyon left remnants of the deposits as cappings on scattered small terraces.
- 3. Landslide Deposits The walls of Diablo Canyon also are marked by tongue- and bench-like accumulations of loose, rubbly landslide debris (Qls), consisting mainly of highly broken and jumbled masses of Monterey rocks with abundant silty and soily matrix materials. These landslide bodies represent localized failure on naturally oversteepened slopes, generally confined to fractured bedrock in and immediately beneath the zone of weathering.
Individual bodies within the mapped area are small, with probable maximum thicknesses no greater than 20 feet. All of them lie outside the area intended for power plant construction.
Landslide deposits along the sea cliff have been recognized at only one locality, on the north side of Diablo Cove about 400 feet northwest of the mouth of Diablo Canyon. Here slippage has occurred along bedding and fracture surfaces in siliceous Monterey rocks, and it has been confined essentially to the axial region of a well-defined syncline (refer to Figure 2.5-8). Several episodes of sliding are attested by thin, elongate masses of highly broken ground separated from one another by well-defined zones of dislocation. Some of these masses are still capped by terrace deposits. The entire composite accumulation of debris is not more than 35 feet in maximum thickness, and ground failure at this locality does not appear to have resulted in major recession of the cliff. Elsewhere within the mapped area, landsliding along the sea cliff evidently has not been a significant process.
Large landslides, some of them involving substantial thickness of bedrock, are present on both sides of Diablo Canyon not far northeast of the power plant area. These occurrences need not be considered in connection with the plant site, but they have been regarded as significant factors in establishing a satisfactory grading design for the switchyard and other up-canyon installations. They are not dealt with in this section.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-33 Revision 21 September 2013 4. Slump, Creep, and Slope-wash Deposits As noted earlier, slump, creep, and slope-wash deposits (Qsw) form parts of the nonmarine sedimentary blanket on the main terrace. These materials are shown separately on the geologic map only in those limited areas where they have been considerably concentrated along well-defined swales and are readily distinguished from other surficial deposits. Their actual distribution is much wider, and they undoubtedly are present over a large fraction of the areas designated as Qter; their average thickness in such areas, however, is probably less than 5 feet.
Angular fragments of Monterey rocks are sparsely to very abundantly scattered through the slump, creep, and slope-wash deposits, whose most characteristic feature is a fine-grained matrix that is dark colored, moderately rich in clay minerals, and extremely soft when wet. Internal layering is rarely observable and nowhere is sharply expressed. The debris seems to have been rather thoroughly intermixed during its slow migration down hillslopes in response to gravity. That it was derived mainly from broken materials in the zone of weathering is shown by several exposures in which it grades downward through soily debris into highly disturbed and partly weathered bedrock, and thence into progressively fresher and less broken bedrock.
- 5. Talus and Beach Deposits Much of the present coastline in the subject area is marked by bare rock, but Diablo Cove and a few other large indentations are fringed by narrow, discontinuous beaches and irregular concentrations of sea cliff talus. These deposits (Qtb) are very coarse grained. Their total volume is small, and they are of interest mainly as modern analogues of much older deposits at higher levels beneath the main terrace surface.
The beach deposits consist chiefly of well-rounded cobbles. They form thin veneers over bedrock, and in Diablo Cove they grade seaward into patches of coarse pebbly sand. The floors of both Diablo Cove and South Cove probably are irregular in detail and are featured by rather hard, fresh bedrock that is discontinuously overlain by irregular thin bodies of sand and gravel. The distribution and abundance of kelp suggest that bedrock crops out over large parts of these cove areas where the sea bottom cannot be observed from onshore points.
- 6. Stream-laid Alluvium Stream-laid alluvium (Qal) occurs as a strip along the present narrow floor of Diablo Canyon, where it is only a few feet in average thickness. It is composed of irregularly intertongued silt, sand, gravel, and rubble. It is crudely to sharply stratified, poorly to well sorted, and, in general, somewhat compacted. Most of it is at least moderately porous.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-34 Revision 21 September 2013 7. Other Deposits Earlier inhabitation of the area by Indians is indicated by several midden deposits that are rich in charcoal and fragments of shells and bones. The most extensive of these occurrences marks the site of a long-abandoned village along the edge of the main terrace immediately northwest of Diablo Canyon. Others have been noted on the main terrace just east of the mouth of Diablo Canyon, on the shoreward end of South Point, and at several places in and near the plant site. 2.5.2.2.4 Structure 2.5.2.2.4.1 Tectonic Structures Underlying the Region Surrounding the Site The dominant tectonic structure in the region of the power plant site is the San Luis-Pismo downwarp system of west-northwest-trending folds. This structure is bounded on the northeast by the antiformal basement rock structure of the Los Osos and San Luis Valley trend. The west-northwest-trending Edna fault zone lies along the northeast flank of the range, and the parallel Miguelito fault extends into the southeasterly end of the range. A north-northwest- trending structural discontinuity that may be a fault has been inferred or interpolated from widely spaced traverses in the offshore, extending within about 5 miles of the site at its point of closest approach. To the west of this discontinuity, the structure is dominated by north to north-northwest-trending folds in Tertiary rocks. These features are illustrated in Figure 2.5-3 and described in this section.
Tectonic structures underlying the site and region surrounding the site are identified in the above and following sections, and they are shown in Figures 2.5-3, 2.5-5, 2.5-8, 2.5-10, 2.5-15, and 2.5-16. They are listed as follows: 2.5.2.2.4.2 Tectonic Structures Underlying the Site The rocks underlying the DCPP site have been subjected to intrusive volcanic activity and to later compressional deformation that has given rise to folding, jointing and fracturing, minor faulting, and local brecciation. The site is situated in a section of moderately to steeply north-dipping strata, about 300 feet south of an east-west-trending synclinal fold axis (Figures 2.5-8 and 2.5-10). The rocks are jointed throughout, and they contain local zones of closely spaced high-angle fractures (Figure 2.5-16).
A minor fault zone extends into the site from the west, but dies out in the vicinity of the Unit 1 turbine building. Two other minor faults were mapped for distances of 35 to more than 200 feet in the bedrock section exposed in the excavation for the Unit 1 containment structure. In addition to these features, cross-cutting bodies of tuff and tuff brecia, and cemented "crackle breccia" could be considered as tectonic structures.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-35 Revision 21 September 2013 Exact ages of the various tectonic structures at the site are not known. It has been clearly demonstrated, however, that all of them are truncated by, and therefore antedate, the principal marine erosion surface that underlies the coastal terrace bench. This terrace can be correlated with coastal terraces to the north and south that have been dated as 80,000 to 120,000 years old. The tectonic structures probably are related to the Pliocene-lower Pleistocene episode of Coast Ranges deformation, which occurred more than 1 million years ago.
The bedrock units within the entire subject area form part of the southerly flank of a very large syncline that is a major feature of the San Luis Range. The northerly-dipping sequence of strata is marked by several smaller folds with subparallel trends and flank-to-flank dimensions measured in hundreds of feet. One of these, a syncline with gentle to moderate westerly plunge, is the largest flexure recognized in the vicinity of the power plant site. Its axis lies a short distance north of the site and about 450 feet northeast of the mouth of Diablo Canyon (Figures 2.5-8 and 2.5-10). East of the canyon this fold appears to be rather open and simple in form, but farther west it probably is complicated by several large wrinkles and may well lose its identity as a single feature. Some of this complexity is clearly revealed along the northerly margin of Diablo Cove, where the beds exposed in the sea cliff have been closely folded along east to northeast trends. Here a tight syncline (shown in Figure 2.5-8) and several smaller folds can be recognized, and steep to near-vertical dips are dominant in several parts of the section.
The southerly flank of the main syncline within the map area steepens markedly as traced southward away from the fold axis. Most of this steepening is concentrated within an across-strike distance of about 300 feet as revealed by the strata exposed in the sea cliff southeastward from the mouth of Diablo Canyon; farther southward the beds of sandstone and finer-grained rocks dip rather uniformly at angles of 70° or more. A slight overturning through the vertical characterizes the several hundred feet of section exposed immediately north of the Obispo Tuff that underlies South Point and the north shore of South Cove (refer to Figure 2.5-8). Thus the main syncline, though simple in gross form, is distinctly asymmetric. The steepness of its southerly flank may well have resulted from buttressing, during the folding, by the relatively massive and competent unit of tuffaceous rocks that adjoins the Monterey strata at this general level of exposure. Smaller folds, corrugations, and highly irregular convolutions are widespread among the Monterey rocks, especially the finest-grained and most shaley types. Some of these flexures trend east to southeast and appear to be drag features systematically related to the larger-scale folding in the area. Most, however, reflect no consistent form or trend, range in scale from inches to only a few feet, and evidently are confined to relatively soft rocks that are flanked by intervals of harder and more massive strata. They constitute crudely tabular zones of contortion within which individual rock layers can be traced for short distances but rarely are continuous throughout the deformed ground.
Some of this contortion appears to have derived from slumping and sliding of unconsolidated sediments on the Miocene sea floor during accumulation of the DCPP UNITS 1 & 2 FSAR UPDATE 2.5-36 Revision 21 September 2013 Monterey section. Most of it, in contrast, plainly occurred at much later times, presumably after conversion of the sediments to sedimentary rocks, and it can be most readily attributed to highly localized deformation during the ancient folding of a section that comprises rocks with contrasting degrees of structural competence. 2.5.2.2.4.3 Faults Numerous faults with total displacements ranging from a few inches to several feet cut the exposed Monterey rocks. Most of these occur within, or along the margins of, the zones of contortion noted above. They are sharp, tight breaks with highly diverse attitudes, and they typically are marked by 1/16-inch or less of gouge or microbreccia. Nearly all of them are curving or otherwise somewhat irregular surfaces, and many can be seen to terminate abruptly or to die out gradually within masses of tightly folded rocks. These small faults appear to have been developed as end products of localized intense deformation caused by folding of the bedrock section. Their unsystematic attitudes, small displacements, and limited effects upon the host rocks identify them as second-order features, i.e., as results rather than causes of the localized folding and convolution with which they are associated.
Three distinctly larger and more continuous faults also were recognized within the mapped area. They are well exposed on the sea cliff that fringes Diablo Cove (refer to Figure 2.5-8), and each lies within a zone of moderately to severely contorted fine-grained Monterey strata. Each is actually a zone, 6 inches to several feet wide, within which two or more subparallel tight breaks are marked by slickensides, 1/4-inch or less of gouge, and local stringers of gypsum. None of these breaks appears to be systematically related to individual folds within the adjoining rocks. None of them extends upward into the overlying blanket of Quaternary terrace deposits. One of these faults, exposed on the north side of the cove, trends north-northwest essentially parallel to the flanking Monterey beds, but it dips more steeply than these beds. Another, exposed on the east side of the cove, trends east-southeast and is essentially vertical; thus, it is essentially parallel to the structure of the host Monterey section. Neither of these faults projects toward the ground intended for power plant construction. The third fault, which appears on the sea cliff at the mouth of Diablo Canyon, trends northeast and projects toward the ground in the northernmost part of the power plant site. It dips northward somewhat more steeply than the adjacent strata.
Total displacement is not known for any of these three faults on the basis of natural exposures, but it could amount to as much as tens of feet. That these breaks are not major features, however, is strongly suggested by their sharpness, by the thinness of gouge along individual surfaces of slippage, and by the essential lack of correlation between the highly irregular geometry of deformation in the enclosing strata and any directions of movement along the slip surfaces.
The possibility that these surfaces are late-stage expressions of much larger-scale faulting at this general locality was tested by careful examination of the deformed rocks DCPP UNITS 1 & 2 FSAR UPDATE 2.5-37 Revision 21 September 2013 that they transect. On megascopic scales, the rocks appear to have been deformed much more by flexing than by rupture and slippage, as evidenced by local continuity of numerous thin beds that denies the existence of pervasive faulting within much of the ground in question. That the finer-grained rocks are not themselves fault gouged was confirmed by examination of 34 samples under the microscope.
Sedimentary layering, recognized in 27 of these samples, was observed to be grossly continuous even though dislocated here and there by tiny fractures. Moreover, nearly all the samples were found to contain shards of volcanic glass and/or the tests of foraminifera; some of these delicate components showed effects of microfracturing and a few had been offset a millimeter or less along tiny shear surfaces, but none appeared to have been smeared out or partially obliterated by intense shearing or grinding. Thus, the three larger faults in the area evidently were superimposed upon ground that already had been deformed primarily by small-scale and locally very intense folding rather than by pervasive grinding and milling.
It is not known whether these faults were late-stage results of major folding in the region or were products of independent tectonic activity. In either case, they are relatively ancient features, as they are capped without break by the Quaternary terrace deposits exposed along the upper part of the sea cliff. They probably are not large-scale elements of regional structure, as examination of the nearest areas of exposed bedrock along their respective landward projections revealed no evidence of substantial offsets among recognizable stratigraphic units.
Seaward projection of one or more of these faults might be taken to explain a possible large offset of the Obispo Tuff units exposed on North Point and South Point. The notion of such an offset, however, would rest upon the assumption that these two units are displaced parts of an originally continuous body, for which there is no real evidence. Indeed, the two tuff units are bounded on their northerly sides by lithologically different parts of the Monterey Formation; hence, they were clearly originally emplaced at different stratigraphic levels and are not directly correlative. 2.5.2.2.5 Geological Relationships at the Units 1 and 2 Power Plant Site 2.5.2.2.5.1 Geologic Investigations at the Site The geologic relationships at DCPP site have been studied in terms of both local and regional stratigraphy and structure, with an emphasis on relationships that could aid in dating the youngest tectonic activity in the area. Geologic conditions that could affect the design, construction, and performance of various components of the plant installation also were identified and evaluated. The investigations were carried out in three main phases, which spanned the time between initial site selection and completion of foundation construction.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-38 Revision 21 September 2013 2.5.2.2.5.2 Feasibility Investigation Phase Work directed toward determining the pertinent general geologic conditions at the plant site comprised detailed mapping of available exposures, limited hand trenching in areas with critical relationships, and petrographic study of the principal rock types. The results of this feasibility program were presented in a report that also included recommendations for determining suitability of the site in terms of geologic conditions. Information from this early phase of studies is included in the preceding four sections and illustrated in Figures 2.5-8, 2.5-9, and 2.5-10. 2.5.2.2.5.3 Suitability Investigation Phase The record phase of investigations was directed toward testing and confirming the favorable judgments concerning site feasibility. Inasmuch as the principal remaining uncertainties involved structural features in the local bedrock, additional effort was made to expose and map these features and their relationships. This was accomplished through excavation of large trenches on a grid pattern that extended throughout the plant area, followed by photographing the trench walls and logging the exposed geologic features. Large-scale photographs were used as a mapping base, and the recorded data were then transferred to controlled vertical sections at a scale of 1 inch = 20 feet. The results of this work were reported in three supplements to the original geologic report (Reference 1). Supplementary Reports I and III presented data and interpretation based on trench exposures in the areas of the Unit 1 and Unit 2 installations, respectively. Supplementary Report II described the relationships of small bedrock faults exposed in the exploratory trenches and in the nearby sea cliff. During these suitability investigations, special attention was given to the contact between bedrock and overlying terrace deposits in the plant site area. It was determined that none of the discontinuities present in the bedrock section displaces either the erosional surface developed across the bedrock or the terrace deposits that rest upon this surface. The pertinent data are presented farther on in this section and illustrated in Figures 2.5-11, 2.5-12, 2.5-13, and 2.5-14. 2.5.2.2.5.4 Construction Geology Investigation Phase Geologic work done during the course of construction at the plant site spanned an interval of 5 years, which encompassed the period of large-scale excavation. It included detailed mapping of all significant excavations, as well as special studies in some areas of rock bolting and other work involving rock reinforcement and temporary instrumentation. The mapping covered essentially all parts of the area to be occupied by structures for Units 1 and 2, including the excavations for the circulating water intake and outlet, the turbine-generator building, the auxiliary building, and the containment structures. The results of this mapping are described farther on and illustrated in Figures 2.5-15 and 2.5-16.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-39 Revision 21 September 2013 2.5.2.2.5.5 Exploratory Trenching Program, Unit 1 Site Four exploratory trenches were cut beneath the main terrace surface at the power plant site, as shown in Figures 2.5-8, 2.5-11, 2.5-12, and 2.5-13. Trench AF (Trench A), about 1080 feet long, extended in a north-northwesterly direction and thus was roughly parallel to the nearby margin of Diablo Cove. Trench BE (Trench B), 380 feet long, was parallel to Trench A and lay about 150 feet east of the northerly one-third of the longer trench. Trenches C and D, 450 and 490 feet long, respectively were nearly parallel to each other, 130 to 150 feet apart, and lay essentially normal to Trenches A and B. The two pairs of trenches crossed each other to form a "#" pattern that would have been symmetrical were it not for the long southerly extension of Trench A. They covered the area intended for Unit 1 power plant construction, and the intersection of Trenches B and C coincided in position with the center of the Unit 1 nuclear reactor structure.
All four trenches, throughout their aggregate length of approximately 2400 feet, revealed a section of surficial deposits and underlying bedrock that corresponds to the two-ply sequence of surficial deposits and Monterey strata exposed along the sea cliff in nearby Diablo Cove. The trenches ranged in depth from 10 feet to nearly 40 feet, and all had sloping sides that gave way downward to essentially vertical walls in the bedrock encountered 3 to 8 feet above their floors.
To facilitate detailed geologic mapping, the easterly walls of Trenches A and B and the southerly walls of Trenches C and D were trimmed to near-vertical slopes extending upward from the trench floors to levels well above the top of bedrock. These walls subsequently were scaled back by means of hand tools in order to provide fresh, clean exposures prior to mapping of the contact between bedrock and overlying unconsolidated materials. 1. Bedrock The bedrock that was continuously exposed in the lowest parts of all the exploratory trenches lies within a portion of the Montery Formation characterized by a preponderance of sandstone. It corresponds to the part of the section that crops out in lower Diablo Canyon and along the sea cliff souteastward from the canyon mouth. The sandstone ranges from light gray through buff to light reddish brown, from silty to markedly tuffaceous, and from thin-bedded and platy to massive. The distribution and thickness of beds can be readily appraised from sections along Trenches A and B (Figure 2.5-12) that show nearly all individual bedding surfaces that could be recognized on the ground.
The sandstone ranges from very hard to moderately soft, and some of it feels slightly punky when struck with a pick. All of it is, however, firm and very compact. In general, the most platy parts of the sequence are also the hardest, but the soundest rock in the area is almost massive sandstone of the kind that underlies the site of the intended reactor structure. This rock is well exposed on the nearby hillslope adjoining the main DCPP UNITS 1 & 2 FSAR UPDATE 2.5-40 Revision 21 September 2013 terrace area, where it has been markedly resistant to erosion and stands out as distinct low ridges.
Tuff, consisting chiefly of altered volcanic glass, forms irregular sills and dikes in several parts of the bedrock section. This material, generally light gray to buff, is compact but distinctly softer than the enclosing sandstone. Individual bodies are 1/2 inch to 4 feet thick. They are locally abundant in Trench C west of Trench A, and in Trench A southward beyond the end of the section in Figure 2.5-12. They are very rare or absent in Trenches B and D, and in the easterly parts of Trench C and the northerly parts of Trench A. These volcanic rocks probably are related to the Obispo Tuff as described earlier, but all known masses of typical Obispo rocks in this area lie at considerable distances west and south of the ground occupied by the trenches.
- 2. Bedrock Structure The stratification of the Monterey rocks dips northward wherever it was observable in the trenches, in general, at angles of 35 to 55°. Thus, the bedrock beneath the power plant site evidently lies on the southerly flank of the major syncline noted and described earlier. Zones of convolution and other expressions of locally intense folding were not recognized, and probably are much less common in this general part of the section than in other, previously described parts that include intervals of softer and more shaley rocks.
Much of the sandstone is traversed by fractures. Planar, curving, and irregular surfaces are well represented, and, in places, they are abundant and closely spaced. All prominent fractures and many of the minor and discontinuous ones are shown in the sections of Figure 2.5-12. Also shown in these sections are all recognized slip joints, shear surfaces, and faults, i.e., all surfaces along which the bedrock has been displaced. Such features are most abundant in Trenches A and C near their intersection, in Trench D west of the intersection with Trench A, and near the northerly end of Trench B.
Most of the surfaces of movement are hairline features with or without thin films of clay and/or gypsum. Displacements range from a small fraction of an inch to several inches. The other surfaces are more prominent, with well-defined zones of gouge and fine-grained breccia ordinarily 1/8 inch or less in thickness. Such zones were observed to reach a maximum thickness of nearly 1/2 inch along two small faults, but only as local lenses or pockets. Exposures were not sufficiently extensive in three dimensions for definitely determining the magnitude of slip along the more prominent faults, but all of these breaks appeared to be minor features. Indeed, no expressions of major faulting were recognized in any of the trenches despite careful search, and the continuous bedrock exposures precluded the possibility that such features could have been readily overlooked.
A northeast-trending fault that appears on the sea cliff at the mouth of Diablo Canyon projects toward the ground in the northernmost part of the power plant site, as noted in DCPP UNITS 1 & 2 FSAR UPDATE 2.5-41 Revision 21 September 2013 a foregoing section. No zone of breaks as prominent as this one was identified in the trench exposures, and any distinct northeastward continuation of the fault would necessarily lie north of the trenched ground. Alternatively, this fault might well separate northeastward into several smaller faults; some or all of these could correspond to some or all of the breaks mapped in the northerly parts of Trenches A and B.
- 3. Terrace Deposits Marine terrace deposits of Pleistocene age form a cover, generally 2 to 5 feet thick, over the bedrock that lies beneath the power plant site. This cover was observed to be continuous in Trench C and the northerly part of Trench A, and to be nearly continuous in the other two trenches. Its lithology is highly variable, and includes bouldery rubble, loose beach sand, pebbly silt, silty to clayey sand with abundant shell fragments, and soft clay derived from underlying tuffaceous rocks. Nearly all of these deposits are at least sparsely fossiliferous, and, in a few places, they consist mainly of shells and shell fragments. Vertebrate fossils, chiefly vertebral and rib materials representing large marine mammals, are present locally; recognized occurrences are designated by the symbol X in the sections of Figure 2.5-12.
At the easterly ends of Trenches C and D, the marine deposits intergrade and intertongue in a landward direction with thicker and coarser accumulations of poorly sorted debris. This material evidently is talus that was formed along the base of an ancient sea cliff or other shoreline slope. In some places, the marine deposits are overlain by nonmarine terrace sediments with a sharp break, but elsewhere the contact between these two kinds of deposits is a dark colored zone, a few inches to as much as 2 feet thick, that appears to represent a soil developed on the marine section. Fragments of these soily materials appear here and there in the basal parts of the nonmarine section.
The nonmarine sediments that were exposed in Trenches B, C, and D and in the northerly part of Trench A are mainly alluvial deposits derived in ancient times from Diablo Canyon. They consist of numerous tabular fragments of Monterey rocks in a relatively dark colored silty to clayey matrix, and, in general, they are distinctly bedded and moderately to highly compact. As indicated in the sections of Figure 2.5-12, they thicken progressively in a north-northeastward direction, i.e., toward their principal source, the ancient mouth of Diablo Canyon.
Slump, creep, and slope-wash deposits, which constitute the youngest major element of the terrace section, overlie the alluvial fan gravels and locally are interlayered with them. Where the gravels are absent, as in the southerly part of Trench A, this younger cover rests directly upon bedrock. It is loose and uncompacted, internally chaotic, and is composed of fragments of Monterey rocks in an abundant dark colored clayey matrix.
All the terrace deposits are soft and unconsolidated, and hence are much less resistant to erosion than is the underlying bedrock. Those appearing along the walls of exploratory trenches were exposed to heavy rainfall during two storms, and showed DCPP UNITS 1 & 2 FSAR UPDATE 2.5-42 Revision 21 September 2013 some tendency to wash and locally to rill. Little slumping and no gross failure were noted in the trenches, however, and it was not anticipated that these materials would cause special problems during construction of a power plant.
- 4. Interface Between Bedrock and Surficial Deposits As once exposed continuously in the exploratory trenches, the contact between bedrock and overlying terrace deposits represents a broad wave-cut platform of Pleistocene age.
This buried surface of ancient marine erosion ranges in altitude between extremes of 82 and 100 feet, and more than three-fourths of it lies within the more limited range of 90 to 100 feet. It terminates eastward against a moderately steep shoreline slope, the lowest parts of which were encountered at the extreme easterly ends of Trenches C and D, and beyond this slope is an older buried bench at an altitude of 120 to 130 feet.
Available exposures indicate that the configuration of the erosional platform is markedly similar, over a wide range of scales, to that of the platform now being cut approximately at sea level along the present coast. Grossly viewed, it slopes very gently in a seaward (westerly) direction and is marked by broad, shallow channels and by upward projections that must have appeared as low spines and reefs when the bench was being formed (Figures 2.5-12 and 2.5-13). The most prominent reef, formerly exposed in Trenches B and D at and near their intersection, is a wide, westerly-trending projection that rises 5 to 15 feet above neighboring parts of the bench surface. It is composed of massive sandstone that was relatively resistant to the ancient wave erosion.
As shown in the sections and sketches of Figure 2.5-12, the surface of the platform is nearly planar in some places but elsewhere is highly irregular in detail. The small-scale irregularities, generally 3 feet or less in vertical extent, including knob, spine, and rib like projections and various wave-scoured pits, crevices, notches, and channels. The upward projections clearly correspond to relatively hard, resistant beds or parts of beds in the sandstone section. The depressions consistently mark the positions of relatively soft silty or shaley sandstone, of very soft tuffaceous rocks, or of extensively jointed rocks. The surface traces of most faults and some of the most prominent joints are in sharp depressions, some of them with overhanging walls. All these irregularities of detail have modern analogues that can be recognized on the bedrock bench now being cut along the margins of Diablo Cove.
The interface between bedrock and overlying surficial deposits is of particular interest in the trenched area because it provides information concerning the age of youngest fault movements within the bedrock section. This interface is nowhere offset by faults revealed in the trenches, but instead has been developed irregularly across these faults after their latest movements. The consistency of this general relationship was established by highly detailed tracing and inspection of the contact as freshly exhumed by scaling of the trench walls. Gaps in exposure of the interface necessarily were developed at the four intersections of trenches; at these localities, the bedrock was carefully laid bare so that all joints and faults could be recognized and traced along the DCPP UNITS 1 & 2 FSAR UPDATE 2.5-43 Revision 21 September 2013 trench floors to points where their relationships with the exposed interface could be determined.
Corroborative evidence concerning the age of the most recent fault displacements stems from the marine deposits that overlie the bedrock bench and form the basal part of the terrace section. That these deposits rest without break across the traces of faults in the underlying bedrock was shown by the continuity of individual sedimentary beds and lenses that could be clearly recognized and traced.
Further, some of the faults are directly capped by individual boulders, cobbles, pebbles, shells, and fossil bones, none of which have been affected by fault movements. Thus, the most recent fault displacements in the plant site area occurred prior to marine planation of the bedrock and deposition of the overlying terrace sediments. As pointed out earlier, the age of the most recent faulting in this area is therefore at least 80,000 years and more probably at least 120,000 years. It might be millions of years. 2.5.2.2.5.6 Exploratory Trenching Program, Unit 2 Site Eight additional trenches were cut beneath the main terrace surface south of Diablo Canyon (Figure 2.5-13) in order to extend the scope of subsurface exploration to include all ground in the Unit 2 plant site. As in the area of the Unit 1 plant site, the trenches formed two groups; those in each group were parallel with one another and were oriented nearly normal to those of the other group. The excavations pertinent to the Unit 2 plant site can be briefly identified as follows:
- 1. North-northwest Alignment a. Trench EJ, 240 feet long, was a southerly extension of older Trench BE (originally designated as Trench B). b. Trench WU, 1300 feet long, extended southward from Trench DG (originally designated as Trench D), and its northerly part lay about 65 feet east of Trench EJ. The northernmost 485 feet of this trench was mapped in connection with the Unit 2 trenching program. c. Trench MV, 700 feet long, lay about 190 feet east of Trench WU. The northernmost 250 feet of this trench was mapped in connection with the Unit 2 trenching program. d. Trench AF (originally designated as Trench A) was mapped earlier in connection with the detailed study of the Unit 1 plant site. A section for this trench, which lay about 140 feet west of Trench EJ, was included with others in the report on the Unit 1 trenching program.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-44 Revision 21 September 2013 2. East-northeast Alignment a. Trench KL, about 750 feet long, lay 180 feet south of Trench DG (originally designated as Trench D) and crossed Trenches AF, EJ, and WU. b. Trench NO, about 730 feet long, lay 250 feet south of Trench KL and crossed Trenches AF, WU, and MV. These trenches, or parts thereof, covered the area intended for the Unit 2 power plant construction, and the intersection of Trenches WU and KL coincided in position with the center of the Unit 2 nuclear reactor structure.
All five additional trenches, throughout their aggregate length of nearly half a mile, revealed a section of surficial deposits and underlying Monterey bedrock that corresponded to the two-ply sequence of surficial deposits and Monterey strata exposed in the older trenches and along the sea cliff in nearby Diablo Cove. The trenches ranged in depth from 10 feet (or less along their approach ramps) to nearly 35 feet, and all had sloping sides that gave way downward to essentially vertical walls in the bedrock encountered 3 to 22 feet above their floors. To facilitate detailed geologic mapping, the easterly walls of Trenches EJ, WU, and MV and the southerly walls of Trenches KL and NO were trimmed to near-vertical slopes extending upward from the trench floors to levels well above the top of bedrock. These walls subsequently were scaled back by means of hand tools in order to provide fresh, clean exposures prior to mapping of the contact between bedrock and overlying unconsolidated materials. The geologic sections shown in Figures 2.5-12 and 2.5-13 correspond in position to the vertical portions of the mapped trench walls. Relationships exposed at higher levels on sloping portions of the trench walls have been projected to the vertical planes of the sections. Centerlines of intersecting trenches are shown for convenience, but the planes of the geologic sections do not contain the centerlines of the respective trenches.
- 3. Bedrock The bedrock that was continuously exposed in the lowest parts of all the exploratory trenches lies within a part of the Monterey Formation characterized by a preponderance of sandstone. It corresponds to the portion of the section that crops out along the sea cliff southward from the mouth of Diablo Canyon. The sandstone is light to medium gray where fresh, and light gray to buff and reddish brown where weathered. It ranges from silty to markedly tuffaceous, with tuffaceous units tending to dominate southward and southwestward from the central parts of the trenched area (refer to geologic section in Figure 2.5-13). Much of the sandstone is thin-bedded and platy, but the most siliceous parts of the section are characterized by a strata a foot or more in thickness.
Individual beds commonly are well defined by adjacent thin layers of more silty material.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-45 Revision 21 September 2013 Bedding is less distinct in the more tuffaceous parts of the section, some of which seem to be almost massive. These rocks typically are broken by numerous tight fractures disposed at high angles to one another so that, where weathered, their appearance is coarsely blocky rather than layered.
As broadly indicated in the geologic sections, the sandstone ranges from very hard to moderately soft, and some of it feels slightly punky when struck with a pick. All of it, however, is firm and very compact. In general, the most platy parts of the sequence are relatively hard, but the hardest and soundest rock in the area is thick-bedded to almost massive sandstone of the kind at and immediately north of the site for the intended reactor structure. This resistant rock is well exposed as distinct low ridges on the nearby hillslope adjoining the main terrace area.
Tuff, consisting chiefly of altered volcanic glass, is abundant within the bedrock section. Also widely scattered, but much less abundant, is tuff breccia, consisting typically of small fragments of older tuff, pumice, or Monterey rocks in a matrix of fresh to altered volcanic glass. These materials, which form sills, dikes, and highly irregular intrusive masses, are generally light gray to buff, gritty, and compact but distinctly softer than much of the enclosing sandstone. Individual bodies range from stringers less than a quarter of an inch thick to bulbous or mushroom-shaped masses with maximum exposed dimensions measured in tens of feet. As shown on the geologic sections, they are abundant in all the trenches.
These volcanic rocks probably are related to the Obispo Tuff, large masses of which are well exposed west and south of the trenched ground. The bodies exposed in the trenches doubtless represent a rather lengthy period of Miocene volcanism, during which the Monterey strata were repeatedly invaded by both tuff and tuff breccia. Indeed, several of the mapped tuff units were themselves intruded by dikes of younger tuff, as shown, for example, in Sections KL and NO.
- 4. Bedrock Structure The stratification of the Monterey rocks dips northward wherever it was observable in the trenches, in general, at angles of 45 to 85°. The steepness of dip increases progressively from north to south in the trenched ground, a relationship also noted along the sea cliff southward from the mouth of Diablo Canyon. Thus, the bedrock beneath the power plant site evidently lies on the southerly flank of the major syncline that was described previously. Zones of convolution and other expressions of locally intense folding were not recognized, and they probably are much less common in this general part of the section than in other (previously described) parts that include intervals of softer and more shaley rocks.
Much of the sandstone is traversed by fractures. Planar, curving, and irregular surfaces are well represented, and in places they are abundant and closely spaced. All prominent fractures and nearly all of the minor and discontinuous ones are shown on the geologic sections (Figure 2.5-13). Also shown in these sections are all recognized DCPP UNITS 1 & 2 FSAR UPDATE 2.5-46 Revision 21 September 2013 shear surfaces, faults, and other discontinuities along which the bedrock has been displaced. Such features are nowhere abundant in the trench exposures.
Most of the surfaces of movement are hairline breaks with or without thin films of clay, calcite, and/or gypsum. Displacements range from a small fraction of an inch to several inches. A few other surfaces are more prominent, with well-defined zones of fine-grained breccia and/or infilling mineral material ordinarily 1/8 inch or less in thickness. Such zones were observed to reach maximum thicknesses of 3/8 to 1/2 inch along three small faults, but only as local lenses or pockets.
Exposures are not sufficiently extensive in three dimensions for definitely determining the magnitude of slip along all the faults, but for most of them it is plainly a few inches or less. None of them appears to be more than a minor break in a bedrock section that has been folded on a large scale. Indeed, no expressions of major faulting were recognized in any of the trenches despite careful search, and the continuous bedrock exposures preclude the possibility that such features could be readily overlooked.
Most surfaces of past movement probably were active during times when the Monterey rocks were being deformed by folding, when rupture and some differential movements would be expected in a section comprising such markedly differing rock types. Some of the fault displacements may well have been older, as attested in two places by relationships involving small faults, the Monterey rocks, and tuff.
In Trench WU south of Trench KL, for example, sandstone beds were seen to have been offset about a foot along a small fault. A thin sill of tuff occupies the same stratigraphic horizon on opposite sides of this fault, but the sill has not been displaced by the fault. Instead, the tuff occupies a short segment of the fault to effect the slight jog between its positions in the strata on either side. Intrusion of the tuff plainly postdated all movements along this fault.
- 5. Terrace Deposits Marine terrace deposits of Pleistocene age form covers, generally 2 to 5 feet thick, but locally as much as 12 feet thick, over the bedrock that lies beneath the Unit 2 plant site.
These covers were observed to be continuous in some parts of all the trenches, and thin and discontinuous in a few other parts. Elsewhere, the marine sediments were absent altogether, as in the lower and more southerly parts of Trenches EJ and WU and in the lower and more westerly parts of Trenches KL and NO.
The range in lithology of these deposits is considerable, and includes bouldery rubble, gravel composed of well-rounded fragments of shells and/or Monterey rocks, beach sand, loose accumulations of shells, pebbly silt, silty to clayey sand with abundant shell fragments, and soft clay derived from underlying tuffaceous rocks. Nearly all of the deposits are at least sparsely fossiliferous, and many of them contain little other than shell material. Vertebrate fossils, chiefly vertebral and rib materials representing large marine mammals, are present locally. DCPP UNITS 1 & 2 FSAR UPDATE 2.5-47 Revision 21 September 2013 The trenches in and near the site of the reactor structure exposed a buried narrow ridge of hard bedrock that once projected westward as a bold promontory along an ancient sea coast, probably at a time when sea level corresponded approximately to the present 100 foot contour (refer to Figure 2.5-11). Along the flanks of this promontory and the face of an adjoining buried sea cliff that extends southeastward through the area in which Trenches MV and NO intersected, the marine deposits intergrade and intertongue with thicker and coarser accumulations of poorly sorted debris. This rubbly material evidently is talus that was formed and deposited along the margins of the ancient shoreline cliff.
Similar gradations of older marine deposits into older talus deposits were observable at higher levels in the easternmost parts of Trenches KL and NO, where the rubbly materials doubtless lie against a more ancient sea cliff that was formed when sea level corresponded to the present 140 foot contour. The cliff itself was not exposed, however, as it lies slightly beyond the limits of trenching.
In many places, the marine covers are overlain by younger nonmarine terrace sediments with a sharp break, but elsewhere the contact between these two kinds of deposits is a zone of dark colored material, a few inches to as much as 6 feet thick, that represents weathering and development of soils on the marine sections. Fragments of these soily materials are present here and there in the basal parts of the nonmarine section. Over large areas, the porous marine deposits have been discolored through infiltration by fine-grained materials derived from the overlying ancient soils.
The nonmarine accumulations, which form the predominant fraction of the entire terrace cover, consist mainly of slump, creep, and slope-wash debris that is characteristically loose, uncompacted, and internally chaotic. These relatively dark colored deposits are fine grained and clayey, but they contain sparse to very abundant fragments of Monterey rocks generally ranging from less than an inch to about 2 feet in maximum dimension. Toward Diablo Canyon they overlie and, in places, intertongue with silty to clayey gravels that are ancient contributions from Diablo Creek when it flowed at levels much higher than its present one. These "dirty" alluvial deposits appeared only in the most northerly parts of the more recently trenched terrace area, and they are not distinguished from other parts of the nonmarine cover on the geologic sections (Figure 2.5-13).
All the terrace deposits are soft and unconsolidated, and hence are much less resistant to erosion than is the underlying bedrock. Those appearing along the walls of the exploratory trenches showed some tendency to wash and locally to rill when exposed to heavy rainfall, but little slumping and no gross failure were noted in the trenches.
- 6. Interface Between Bedrock and Surficial Deposits As exposed continuously in the exploratory trenches, the contact between bedrock and overlying terrace deposits represents two wave-cut platforms and intervening slopes, all of Pleistocene age. The broadest surface of ancient marine erosion ranges in altitude DCPP UNITS 1 & 2 FSAR UPDATE 2.5-48 Revision 21 September 2013 from 80 to 105 feet, and its shoreward margin, at the base of an ancient sea cliff, lies uniformly within 5 feet of the 100 foot contour. A higher, older, and less extensive marine platform ranges in altitude from 130 to 145 feet, and most of it lies within the ranges of 135 to 140 feet. As noted previously, these are two of several wave-cut benches in this coastal area, each of which terminates eastward against a cliff or steep shoreline slope and westward at the upper rim of a similar but younger slope.
Available exposures indicate that the configurations of the erosional platforms are markedly similar, over a wide range of scales, to that of the platform now being cut approximately at sea level along the present coast. Grossly viewed, they slope very gently in a seaward (westerly) direction and are marked by broad, shallow channels and by upward projections that must have appeared as low spines and reefs when the benches were being formed. The most prominent reefs, which rise from a few inches to about 5 feet above neighboring parts of the bench surfaces, are composed of hard, thick-bedded sandstone that was relatively resistant to ancient wave erosion. As shown in the geologic sections (Figure 2.5-13), the surfaces of the platforms are nearly planar in some places but elsewhere are highly irregular in detail. The small scale irregularities, generally 3 feet or less in vertical extent, include knob-, spine-, and rib-like projections and various wave-scoured pits, notches, crevices, and channels. Most of the upward projections closely correspond to relatively hard, resistant beds or parts of beds in the sandstone section. The depressions consistently mark the positions of relatively soft silty or shaley sandstone, of very soft tuffaceous rocks, or of extensively jointed rocks. The surface traces of most faults and some of the most prominent joints are in sharp depressions, some of them with overhanging walls. All these irregularities of detail have modern analogues that can be recognized on the bedrock bench now being cut along the margins of Diablo Cove. The interface between bedrock and overlying surficial deposits provides information concerning the age of youngest fault movements within the bedrock section. This interface is nowhere offset by faults that were exposed in the trenches, but instead has been developed irregularly across the faults after their latest movements. The consistency of this general relationship was established by highly detailed tracing and inspection of the contact as freshly exhumed by scaling of the trench walls. Gaps in exposure of the interface necessarily were developed at the intersections of trenches as in the exploration at the Unit 1 site. At such localities, the bedrock was carefully laid bare so that all joints and faults could be recognized and traced along the trench floors to points where their relationships with the exposed interface could be determined.
Corroborative evidence concerning the age of the most recent fault displacements stems from the marine deposits that overlie the bedrock bench and form a basal part of the terrace section. That these deposits rest without break across the traces of faults in the underlying bedrock was shown by the continuity of individual sedimentary beds and lenses that could be clearly recognized and traced. As in other parts of the site area, some of the faults are directly capped by individual boulders, cobbles, pebbles, shells, and fossil bones, none of which have been affected by fault movements. Thus, the DCPP UNITS 1 & 2 FSAR UPDATE 2.5-49 Revision 21 September 2013 most recent fault displacements in the plant site area occurred before marine planation of the bedrock and deposition of the overlying terrace sediments.
The age of the most recent faulting in this area is therefore at least 80,000 years. More probably, it is at least 120,000 years, the age most generally assigned to these terrace deposits along other parts of the California coastline. Evidence from the higher bench in the plant site area indicates a much older age, as the unfaulted marine deposits there are considerably older than those that occupy the lower bench corresponding to the 100 foot terrace. Moreover, it can be noted that ages thus determined for most recent fault displacements are minimal rather than absolute, as the latest faulting actually could have occurred millions of years ago.
During the Unit 2 exploratory trenching program, special attention was directed to those exposed parts of the wave-cut benches where no marine deposits are present, and hence where there are no overlying reference materials nearly as old as the benches themselves. At such places, the bedrock beneath each bench has been weathered to depths ranging from less than 1 inch to at least 10 feet, a feature that evidently corresponds to a lengthy period of surface exposure from the time when the bench was abandoned by the sea to the time when it was covered beneath encroaching nonmarine deposits derived from hillslopes to the east.
Stratification and other structural features are clearly recognizable in the weathered bedrock, and they obviously have exercised some degree of control over localization of the weathering. Moreover, in places where upward projections of bedrock have been gradually bent or rotationally draped in response to weathering and creep, their contained fractures and surfaces of movement have been correspondingly bent. Nowhere in such a section that has been disturbed by weathering have the materials been cut by younger fractures that would represent straight upward projections of breaks in the underlying fresh rocks. Nor have such fractures been observed in any of the overlying nonmarine terrace cover.
Thus, the minimum age of any fault movement in the plant site area is based on compatible evidence from undisplaced reference features of four kinds: (a) Pleistocene wave-cut benches developed on bedrock, (b) immediately overlying marine deposits that are very slightly younger, (c) zones of weathering that represent a considerable span of subsequent time, and (d) younger terrace deposits of nonmarine origin. 2.5.2.2.5.7 Bedrock Geology of the Plant Foundation Excavations Bedrock was continuously exposed in the foundation excavations for major structural components of Units 1 and 2. Outlines and invert elevations of these large openings, which ranged in depth from about 5 to nearly 90 feet below the original ground surface, are shown in Figures 2.5-15 and 2.5-16. The complex pattern of straight and curved walls with various positions and orientations provided an excellent three-dimensional representation of bedrock structure. These walls were photographed at large scales as construction progressed, and the photographs were used directly as a geologic DCPP UNITS 1 & 2 FSAR UPDATE 2.5-50 Revision 21 September 2013 mapping base. The largest excavations also were mapped in detail on a surveyed planimetric base.
Geologic mapping of the plant excavations confirmed the conclusions based on earlier investigations at the site. The exposed section of Monterey strata was found to correspond in lithology and structure to what had been predicted from exposures at the mouth of Diablo Canyon, along the sea cliffs in nearby Diablo Cove, and in the test trenches. Thus, the plant foundation is underlain by a moderately to steeply north-dipping sequence of thin to thick bedded sandy mudstone and fine-grained sandstone. The rocks at these levels are generally fresh and competent, as they lie below the zone of intense near-surface weathering.
Several thin interbeds of claystone were exposed in the southwestern part of the plant site in the excavations for the Unit 2 turbine-generator building, intake conduits, and outlet structure. These beds, which generally are less than 6 inches thick, are distinctly softer than the flanking sandstone. Some of them show evidence of internal shearing.
Layers of tuffaceous sandstone and sills, dikes, and irregular masses of tuff and tuff breccia are present in most parts of the foundation area. They tend to increase in abundance and thickness toward the south, where they are relatively near the large masses of Obispo Tuff exposed along the coast south of the plant site.
Some of the tuff bodies are conformable with the enclosing sandstone, but others are markedly discordant. Most are clearly intrusive. Individual masses, as exposed in the excavations, range in thickness from less than 1 inch to about 40 feet. The tuff breccia, which is less abundant than the tuff, consists typically of small fragments of older tuff, pumice, or Monterey rocks in a matrix of fresh to highly altered volcanic glass. At the levels of exposure in the excavations, both the tuff and tuff breccia are somewhat softer than the enclosing sandstone.
The stratification of the Monterey rocks dips generally northward throughout the plant foundation area. Steepness of dips increases progressively and, in places, sharply from north to south, ranging from 10 to 15° on the north side of Unit 1 to 75 to 80° in the area of Unit 2. A local reversal in direction of dip reflects a small open fold or warp in the Unit 1 area. The axis of this fold is parallel to the overall strike of the bedding, and strata on the north limb dip southward at angles of 10 to 15°. The more general steepening of dips from north to south may reflect buttressing by the large masses of Obispo Tuff south of the plant site.
The bedrock of the plant area is traversed throughout by fractures, including various planar, broadly curving, and irregular breaks. A dominant set of steeply dipping to vertical joints trends northerly, nearly normal to the strike of bedding. Other joints are diversely oriented with strikes in various directions and dips ranging from 10° to vertical. Many fractures curve abruptly, terminate against other breaks, or die out within single beds or groups of beds.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-51 Revision 21 September 2013 Most of the joints are widely spaced, ranging from about 1 to 10 feet apart, but within several northerly trending zones, ranging in width from 10 to 20 feet, closely spaced near vertical fractures give the rocks a blocky or platy appearance. The fracture and joint surfaces are predominantly clean and tight, although some irregular ones are thinly coated with clay or gypsum. Others could be traced into thin zones of breccia with calcite cement.
Several small faults were mapped in the foundation excavations for Unit 1 and the outlet structure. A detailed discussion of these breaks and their relationship to faults that were mapped earlier along the sea cliff and in the exploratory trenches is included in the following section. 2.5.2.2.5.8 Relationships of Faults and Shear Surfaces Several subparallel breaks are recognizable on the sea cliff immediately south of Diablo Canyon, where they transect moderately thick-bedded sandstone of the kind exposed in the exploratory trenches to the east. These breaks are nearly concordant with the bedrock stratification but, in general, they dip more steeply (refer to detailed structure section, Figure 2.5-14) and trend more northerly than the stratification. Their trend differs significantly from much of their mapped trace, as the trace of each inclined surface is markedly affected by the local steep topography. The indicated trend, which projects eastward toward ground north of the Unit 1 reactor site, has been summed from numerous individual measurements of strike on the sea cliff exposures, and it also corresponds to the trace of the main break as observed in nearly horizontal outcrop within the tidal zone west of the cliff. The structure section shows all recognizable surfaces of faulting and shearing in the sea cliff that are continuous for distances of 10 feet or more. Taken together, they represent a zone of dislocation along which rocks on the north have moved upward with respect to those on the south as indicated by the attitude and roughness sense of slickensides. The total amount of movement cannot be determined by any direct means, but it probably is not more than a few tens of feet and could well be less than 10 feet. This is suggested by the following observed features:
(1) All individual breaks are sharp and narrow, and the strata between them are essentially undeformed except for their gross inclination. (2) Some breaks plainly die out as traced upward along the cliff surface, and others merge with adjoining breaks. At least one well-defined break butts downward against a cross-break, which in turn butts upward against a break that branches and dies out approximately 20 feet away (refer to structure section, Figure 2.5-14, for details). (3) Nearly all the breaks curve moderately to abruptly in the general direction of movement along them.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-52 Revision 21 September 2013 (4) Most of the breaks are little more than knife-edge features along which rock is in direct contact with rock, and others are marked by thin films of gouge. Maximum thickness of gouge anywhere observed is about 1/2 inch, and such exceptional occurrences are confined to short curving segments of the main break at the southerly margin of the zone. (5) No fault breccia is present; instead, the zone represents transection of otherwise undeformed rocks by sharply-defined breaks. No bedrock unit is cut off and juxtaposed against a unit of different lithology along any of the breaks. (6) Local prominence of the exposed breaks, and especially the main one, is due to slickensides, surface coatings of gypsum, and iron-oxide stains rather than to any features reflecting large-scale movements. This zone of faulting cannot be regarded as a major tectonic element, nor is it the kind of feature normally associated with the generation of earthquakes. It appears instead to reflect second-order rupturing related to a marked change in dip of strata to the south, and its general sense of movement is what one would expect if the breaks were developed during folding of the Monterey section against what amounts to a broad buttress of Obispo Tuff farther south (refer to geologic map, Figure 2.5-8). That the fault and shear movements were ancient is positively indicated by upward truncation of the zone at the bench of marine erosion along the base of the overlying terrace deposits.
As indicated earlier, bedrock was continuously exposed along several exploratory trenches. This bedrock is traversed by numerous fractures, most of which represent no more than rupture and very small amounts of simple separation. The others additionally represent displacement of the bedrock, and the map in Figure 2.5-14 shows every exposed break in the initial set of trenches along which any amount of displacement could be recognized or inferred.
That the surfaces of movement constitute no more than minor elements of the bedrock structure was verified by detailed mapping of the large excavations for the plant structures. Detailed examination of the excavation walls indicated that the faults exposed in the sea cliff south of Diablo Canyon continue through the rock under the Unit 1 turbine-generator building, where they are expressed as three subparallel breaks with easterly trend and moderately steep northerly dips (Figure 2.5-15). Stratigraphic separation along these breaks ranges from a few inches to nearly 5 feet, and, in general, decreases eastward on each of them. They evidently die out in the ground immediately west of the containment excavation, and their eastward projections are represented by several joints along which no offsets have occurred. Such joints, with eastward trend and northward dip, also are abundant in some of the ground adjacent to the faults on the south (Figure 2.5-15).
The easterly reach of the Diablo Canyon sea cliff faults apparently corresponds to the two most northerly of the north-dipping faults mapped in Trench A (Figure 2.5-14). DCPP UNITS 1 & 2 FSAR UPDATE 2.5-53 Revision 21 September 2013 Dying out of these breaks, as established from subsequent large excavations in the ground east of where Trench A was located, explains and verifies the absence of faults in the exposed rocks of Trenches B and C. Other minor faults and shear surfaces mapped in the trench exposures could not be identified in the more extensive exposures of fresher rocks in the Unit 1 containment and turbine-generator building excavations. The few other minor faults that were mapped in these large excavations evidently are not sufficiently continuous to have been present in the exploratory trenches. 2.5.2.2.6 Site Engineering Properties 2.5.2.2.6.1 Field and Laboratory Investigations In order to determine anticipated ground accelerations at the site, it was necessary to conduct field surveys and laboratory testing to evaluate the engineering properties of the materials underlying the site.
Bore holes were drilled into the rock upon which PG&E Design Class 1 structures are founded. The borings were located at or near the intersection of the then existing Unit 1 exploration trenches. (refer to Figures 2.5-11, 2.5-12, and 2.5-13 for exploratory trenching programs and boring locations.) These holes were cored continuously and representative samples were taken from the cores and submitted for laboratory testing.
The field work also included a reconnaissance to evaluate physical condition of the rocks that were exposed in trenches, and samples were collected from the ground surface in the trenches for laboratory testing. These investigations included seismic refraction measurements across the ground surface and uphole seismic measurements in the various drill holes to determine shear and compressional velocities of vertically propagated waves.
Laboratory testing, performed by Woodward-Clyde-Sherard & Associates, included unconfined compression tests, dynamic elastic moduli tests under controlled stress conditions, density and water content determinations, and Poisson's ratio tests. Tests were also carried out by Geo-Recon, Incorporated, to determine seismic velocities on selected rock samples in the laboratory. The results of seismic measurements in the field were used to construct a three-dimensional model of the subsurface materials beneath the plant site showing variations of shear wave velocity and compressional wave velocity both laterally and vertically. The seismic velocity data and elastic moduli determined from laboratory testing were correlated to determine representative values of elastic moduli necessary for use in dynamic analyses of structures.
Details of field investigations and results of laboratory testing and correlation of data are contained in Appendices 2.5A and 2.5B of Reference 27 in Section 2.3.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-54 Revision 21 September 2013 2.5.2.2.6.2 Summary and Correlation of Data The foundation material at the site can be categorized as a stratified sequence of fine to very fine grained sandstone deeply weathered to an average elevation of 75 to 80 feet, mean sea level (MSL). The rock is closely fractured, with tightly closed or healed fractures generally present below elevation 75 feet. Compressional and shear wave velocity interfaces generally are at an average elevation of 75 feet, correlating with fracture conditions.
Time-distance plots and seismic velocity profiles presenting results of each seismic refraction line and time depth plots with results for each uphole seismic survey are included in Appendices 2.5A and 2.5B of Reference 27 in Section 2.3. Compressional wave velocities range from 2350 to 5700 feet per second and shear wave velocities from 1400 to 3600 feet per second as determined by the refraction survey. These same parameters range from 2450 to 9800 and 1060 to 6050 feet per second as determined by the uphole survey. For the Hosgri Evaluation an average shear wave velocity of 3600 feet per second is used at the foundation grade. An isometric diagram summarizing results of the refraction survey for Unit 1 is also included in Appendix 2.5A of Reference 27 in Section 2.3.
Table 1 of Appendix 2.5A of Reference 27 of Section 2.3 shows calculations of Poisson's ratio and Young's Modulus based on representative compressional and shear wave velocities from the field geophysical investigations and laboratory measurements of compressional wave velocities. Table 2 of Appendix 2.5A of the same reference presents laboratory test results including density, unconfined compressive strength, Poisson's ratio and calculated values for compressional and shear wave velocities, shear modulus, and constrained modulus. Secant modulus values in Table 2 were determined from cyclic stress-controlled laboratory tests.
Compressional wave velocity measurements were made in the laboratory of four selected core samples and three hand specimens from exposures in the trench excavations. Measured values ranged from 5700 to 9500 feet per second. A complete tabulation of these results can be found in Appendix 2.5A of Reference 27 of Section 2.3. 2.5.2.2.6.3 Dynamic Elastic Moduli and Poisson's Ratio Laboratory test results are considered to be indicative of intact specimens of foundation materials. Field test results are considered to be indicative of the gross assemblage of foundation materials, including fractures and other defects. Load stress conditions are obtained by evaluating cyclic load tests. In-place load stress conditions and confinement of the material at depth are also influential in determining elastic behavior. Because of these considerations, originally recommended representative values for Young's Modulus of Elasticity and Poisson's ratio for the site were:
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-55 Revision 21 September 2013 Depth Below Bottom of Trench E 0 to approximately 15 feet 44 x 106 lb/ft2 0.20 Below 15 feet 148 x 106 lb/ft2 0.18 A single value was selected for Young's Modulus below 15 feet because the initial analyses of the seismic response of the structures utilized a single value that was considered representative of the foundation earth materials as a whole.
More detailed seismic analyses were performed subsequent to the initial analyses. These analyses, discussed in Section 3.7.2, incorporated the finite element method and made it possible to model the rock beneath the plant site in a more refined manner by accounting for changes in properties with increasing depth. To determine the refined properties of the founding materials for these analyses, the test data were reviewed and consideration was given to: (a) strain range of the materials at the site, (b) overburden pressure and confinement, (c) load imposed by the structure, (d) observation of fracture condition and geometry of the founding rock in the open excavation, (e) decreases in Poisson's ratio with depth, and (f) significant advances in state-of-the-art techniques of testing and analysis in rock mechanics that had been made and which resulted in considerably more being known about the behavior of rock under seismic strains in 1970 than in 1968 or 1969.
For the purposes of developing the mathematical models that represented the rock mass, the foundation was divided into horizontal layers based on: (a) the estimated depth of disturbance of the foundation rock below the base of the excavation, (b) changes in rock type and physical condition as determined from bore hole logs, (c) velocity interfaces as determined by refraction geophysical surveys, and (d) estimated depth limit of fractures across which movement cannot take place because of confinement and combined overburden and structural load. Based on these considerations, the founding material properties as shown in Figure 2.5-19 were selected as being representative of the physical conditions in the founding rock. 2.5.2.2.6.4 Engineered Backfill Backfill operations were carefully controlled to ensure stability and safety. All engineered backfill was placed in lifts not exceeding 8 inches in loose depth. Yard areas and roads were compacted to 95 percent relative compaction as determined by the method specified in ASTM D1557. Rock larger than 8 inches in its largest dimension that would not break down under the compactors was not permitted. Figures 2.5-17 and 2.5-18 show the plan and profile view of excavation and backfill for major plant structures. 2.5.2.2.6.5 Foundation Bearing Pressures PG&E Design Class I structures were analyzed to determine the foundation pressures resulting from the combination of dead load, live load, and the double design DCPP UNITS 1 & 2 FSAR UPDATE 2.5-56 Revision 21 September 2013 earthquake (DDE). The maximum pressure was found to be 158 ksf and occurs under the containment structure foundation slab. This analysis assumed that the lateral seismic shear force will be transferred to the rock at the base of the slab which is embedded 11 feet into rock. This computed bearing pressure is considered conservative in that no passive lateral pressure was assumed to act on the sides of the slab. Based on the results of the laboratory tests of unconfined compressive strength of representative samples of rock at the site, which ranged from 800 to 1300 ksf, the calculated foundation pressure is well below the ultimate in situ rock bearing capacity. Adverse hydrologic effects on the foundations of PG&E Design Class I structures (there are no PG&E Design Class I embankments) can be safely neglected at this site, since PG&E Design Class I structures are founded on a substantial layer of bedrock, and the groundwater level lies well below grade, at a level corresponding to that of Diablo Creek. Additionally, the computed factors of safety (minimum of 5 under DDE) of foundation pressures versus unconfined compressive strength of rock are sufficiently high to ensure foundation integrity in the unlikely event groundwater levels temporarily rose to foundation grade.
Soil properties such as grain size, Atterberg limits, and water content need not be considered since PG&E Design Class I structures and PG&E Design Class II structures housing PG&E Design Class I equipment are founded on rock. 2.5.3 VIBRATORY GROUND MOTION 2.5.3.1 Geologic Conditions of the Site and Vicinity DCPP is situated at the coastline on the southwest flank of the San Luis Range, in the southern Coast Ranges of California. The San Luis Range branches from the main coastal mountain chain, the Santa Lucia Range, in the area north of the Santa Maria Valley and southeast of the plant site, and thence follows an alignment that curves toward the west. Owing to this divergence in structural grain, the range juts out from the regional coastline as a broad peninsula and is separated from the Santa Lucia Range by an elongated lowland that extends southeasterly from Morro Bay and includes Los Osos and San Luis Obispo Valleys. It is characterized by rugged west-northwesterly trending ridges and canyons, and by a narrow fringe of coastal terraces along its southwesterly flank.
Diablo Canyon follows a generally west-southwesterly course from the central part of the range to the north-central part of the terraced coastal strip. Detailed discussions of the lithology, stratigraphy, structure, and geologic history of the plant site and surrounding region are presented in Section 2.5.2. 2.5.3.2 Underlying Tectonic Structures Evidence pertaining to tectonic and seismic conditions in the region of the DCPP site, developed during the original design phase, is summarized later in the section, and is DCPP UNITS 1 & 2 FSAR UPDATE 2.5-57 Revision 21 September 2013 illustrated in Figures 2.5-2, 2.5-3, 2.5-4, and 2.5-5. Table 2.5-1 includes a summary listing of the nature and effects of all significant historic earthquakes within 75 miles of the site that have been reported through the end of 1972. Table 2.5-2 shows locations of 19 selected earthquakes that have been investigated by S. W. Smith. Table 2.5-3 lists the principal faults in the region that were identified during the original design phase and indicates major elements of their histories of displacement, in geological time units.
Prior to the start of construction of DCPP, Benioff and Smith (reference 5) assessed the maximum earthquakes to be expected at the site, and John A. Blume and Associates (references 6 and 7) derived the site vibratory motions that could result from these maximum earthquakes, which form the basis of the Design Earthquake. An extensive discussion of the geology of the southern Coast Ranges, the western Transverse Ranges, and the adjoining offshore region is presented in Appendix 2.5D of Reference 27 of Section 2.3. Tectonic features of the central coastal region are discussed in Section 2.5.2.1.2, Regional Geologic and Tectonic Setting. Additional information about the tectonic and seismic conditions was gathered during the Hosgri evaluation and LTSP evaluation phases, as discussed in Sections 2.5.3.9.3 and 2.5.3.9.4, respectively. 2.5.3.3 Behavior During Prior Earthquakes Physical evidence that indicates the behavior of subsurface materials, strata, and structure during prior earthquakes is presented in Section 2.5.2.2.5. The section presents the findings of the exploratory trenching programs conducted at the site.
2.5.3.4 Engineering Properties of Materials Underlying the Site A description of the static and dynamic engineering properties of the materials underlying the site is presented in Section 2.5.2.2.6, Site Engineering Properties. 2.5.3.5 Earthquake History The seismicity of the southern Coast Ranges region is known from scattered records extending back to the beginning of the 19th century, and from instrumental records dating from about 1900. Detailed records of earthquake locations and magnitudes became available following installation of the California Institute of Technology and University of California (Berkeley) seismograph arrays in 1932.
A plot of the epicenters for all large historical earthquakes and for all instrumentally recorded earthquakes of Magnitude 4 or larger that have occurred within 200 miles of DCPP site, through the end of 1972, is given in Figure 2.5-2. Plots of all historically and instrumentally recorded epicenters and all mapped faults within about 75 miles of the site, known through the end of 1972, are shown in Figures 2.5-3 and 2.5-4. DCPP UNITS 1 & 2 FSAR UPDATE 2.5-58 Revision 21 September 2013 A tabulated list of seismic events through the end of 1972, representing the computer printout from the Berkeley Seismograph Station records, supplemented with records of individual shocks of greater than Magnitude 4 that appear only in the Caltech records, is included as Table 2.5-1. Table 2.5-2 gives a summary of revised epicenters of a representative sample of earthquakes off the coast of California near San Luis Obispo, as determined by S. W. Smith. 2.5.3.6 Correlation of Epicenters With Geologic Structures Studies of particular aspects of the seismicity of the southern Coast Ranges region have been made by Benioff and Smith, Richter, and Allen. From results of these studies, together with data pertaining to the broader aspects of the geology and seismicity of central and eastern California, it can be concluded that, although the southern Coast Ranges region may be subjected to vibratory ground motion from earthquakes originating along faults as distant as 200 miles or more, the region itself is traversed by faults capable of producing large earthquakes, and that the strongest shaking possible for sites within the region probably would be caused by earthquakes no more than a few tens of miles away. Therefore, only the seismicity of the southern Coast Ranges, the adjacent offshore area, and the western Transverse Ranges is reviewed in detail.
Figure 2.5-3 shows three principal concentrations of earthquake epicenters, three smaller or more diffuse areas of activity, and a scattering of other epicenters, for earthquakes recorded through 1972. The most active areas, in terms of numbers of shocks, are the reach of the San Andreas fault north of about 35°7' latitude, the offshore area near Santa Barbara, and the offshore Santa Lucia Bank area. Notable concentrations of epicenters also are located as occurring in Salinas Valley, at Point San Simeon, and near Point Conception. The scattered epicenters are most numerous in the general vicinities of the most active areas, but they also occur at isolated points throughout the region.
The reliability of the position of instrumentally located epicenters of small shocks in the central California region has been relatively poor in the past, owing to its position between the areas covered by the Berkeley and Caltech seismograph networks. A recent study by Smith, however, resulted in relocation of nineteen epicenters in the coastal and offshore region between the latitudes of Point Arguello and Point Sur. Studies by Gawthrop (reference 29) and reported in Wagner have led to results that seem to accord generally with those achieved by Smith.
The epicenters relocated by Smith and those recorded by Gawthrop are plotted in Figure 2.5-3. This plot shows that most of the epicenters recorded in the offshore region seem to be spatially associated with faults in the Santa Lucia Bank region, the East Boundary zone, and the San Simeon fault. Other epicenters, including ones for the 1952 Bryson shock, and several smaller shocks originally located in the offshore area, were determined to be centered on or near the Sur-Nacimiento fault north of the latitude of San Simeon. DCPP UNITS 1 & 2 FSAR UPDATE 2.5-59 Revision 21 September 2013 2.5.3.7 Identification of Active Faults Faults that have evidence of recent activity and have portions passing within 200 miles of the site, as known through the end of 1972, are identified in Section 2.5.2.1.2. 2.5.3.8 Description of Active Faults Active faults that have any part passing within 200 miles of the site, as known through the end of 1972, are described in Section 2.5.2.1.2. Additional active faults were identified during the Hosgri and LTSP evaluation phases, as described in Sections 2.5.3.9.3 and 2.5.3.9.4, respectively. 2.5.3.9 Design and Licensing Basis Earthquakes The seismic design and evaluation of DCPP is based on the earthquakes described in the following four subsections. Refer to Section 3.7 for the design criteria associated with the application of these earthquakes to the structures, systems, and components. The DE, DDE, and HE are design bases earthquakes and the LTSP is a licensing bases earthquake. 2.5.3.9.1 Design Earthquake During the original design phase, Benioff and Smith, in reviewing the seismicity of the region around DCPP site, determined the maximum earthquakes that could reasonably be expected to affect the site. Their conclusions regarding the maximum size earthquakes that can be expected to occur during the life of the reactor are listed below: (1) Earthquake A: A great earthquake may occur on the San Andreas fault at a distance from the site of more than 48 miles. It would be likely to produce surface rupture along the San Andreas fault over a distance of 200 miles with a horizontal slip of about 20 feet and a vertical slip of 3 feet. The duration of strong shaking from such an event would be about 40 seconds, and the equivalent magnitude would be 8.5. (2) Earthquake B: A large earthquake on the Nacimiento (Rinconada) fault at a distance from the site of more than 20 miles would be likely to produce a 60 mile surface rupture along the Nacimiento fault, a slip of 6 feet in the horizontal direction, and have a duration of 10 seconds. The equivalent magnitude would be 7.25. (3) Earthquake C: Possible large earthquakes occurring on offshore fault systems that may need to be considered for the generation of seismic sea waves are listed below: DCPP UNITS 1 & 2 FSAR UPDATE 2.5-60 Revision 21 September 2013 Length of Distance Location Fault Break Slip, feet Magnitude to Site Santa Ynez Extension 80 miles 10 horizontal 7.5 50 miles
Cape Mendocino, NW 100 miles 10 horizontal 7.5 420 miles Extension of San Andreas fault
Gorda Escarpment 40 miles 5 vertical or 7 420 miles horizontal (4) Earthquake D: Should a great earthquake occur on the San Andreas fault, as described in "A" above, large aftershocks may occur out to distances of about 50 miles from the San Andreas fault, but those aftershocks which are not located on existing faults would not be expected to produce new surface faulting, and would be restricted to depths of about 6 miles or more and magnitudes of about 6.75 or less. The distance from the site to such aftershocks would thus be more than 6 miles. The available information suggests that the faults in this region can be associated with contrasting general levels of seismic potential. These are as follows:
(1) Level I: Potential for great earthquakes involving surface faulting over distances on the order of 100 miles: seismic activity at this level should occur only on the reach of the San Andreas fault that extends between the locales of Cajon Pass and Parkfield. This was the source of the 1857 Fort Tejon earthquake, estimated to have been of Magnitude 8. (2) Level II: Potential for large earthquakes involving faulting over distances on the order of tens of miles: seismic activity at this level can occur along offshore faults in the Santa Lucia Bank region (the likely source of the Magnitude 7.3 earthquake of 1927), and possibly along the Big Pine and Santa Ynez faults in the Transverse Ranges. Although the Rinconada-San Marcos-Jolon, Espinosa, Sur-Nacimiento, and San Simeon faults do not exhibit historical or even Holocene activity indicating this level of seismic potential, the fault dimensions, together with evidence of late Pleistocene movements along these faults, suggest that they may be regarded as capable of generating similarly large earthquakes. (3) Level III: Potential for earthquakes resulting chiefly from movement at depth with no surface faulting, but at least with some possibility of surface faulting of as much as a few miles strike length and a few feet of slip:
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-61 Revision 21 September 2013 Seismic activity at this level probably could occur on almost any major fault in the southern Coast Ranges and adjacent regions. From the observed geologic record of limited fault activity extending into Quaternary time, and from the historical record of apparently associated seismicity, it can be inferred that both the greater frequency of earthquake activity and larger shocks from earthquake source structures having this level of seismic potential probably will be associated with one of the relatively extensive faults. Faults in the vicinity of the San Luis Range that may be considered to have such seismic potential include the West Huasna, Edna, and offshore Santa Maria Basin East Boundary zone. (4) Level IV: Potential for earthquakes and aftershocks resulting from crustal movements that cannot be associated with any near-surface fault structures: such earthquakes apparently can occur almost anywhere in the region. This information forms the basis of the Design Earthquake, described in section 2.5.3.10.1. 2.5.3.9.2 Double Design Earthquake During the original design phase, in order to assure adequate reserve seismic resisting capability of safety related structures, systems, and components, an earthquake producing two-times the acceleration values of the Design Earthquake was also considered (Reference 51). 2.5.3.9.3 Hosgri Earthquake In 1976, subsequent to the issuance of the construction permit of Unit 1, PG&E was requested by the NRC to evaluate the plant's capability to withstand a postulated Richter Magnitude 7.5 earthquake centered along an offshore zone of geologic faulting, approximately 3 miles offshore, generally referred to as the "Hosgri fault." Details of the investigations associated with this fault are provided in Appendices 2.5D, 2.5E, and 2.5F of Reference 27 in Section 2.3. An overview is provided in Section 2.5.3.10.3. Note that the Shoreline Fault Zone (refer to Section 2.5.7.1) is considered to be a lesser included case under the Hosgri evaluation (Reference 55). A further assessment of the seismic potential of faults mapped in the region of DCPP site was made following the extensive additional studies of on and offshore geology and is reported in Appendix 2.5D of Reference 27 of Section 2.3. This was done in terms of observed Holocene activity, to achieve assessment of what seismic activity is reasonably probable, in terms of observed late Pleistocene activity, fault dimensions, and style of deformation.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-62 Revision 21 September 2013 2.5.3.9.4 1991 Long Term Seismic Program Earthquake PG&E performed a reevaluation of the seismic design bases of DCPP in response to License Condition No. 2.C.(7) of the Unit 1 Operating License. Details of this reevaluation, referred to as the Long Term Seismic Program, are provided in Section 2.5.7. PG&E's evaluations included the development of significant additional data applicable to the geology, seismology, and tectonics of the DCPP region, including characterization of the Hosgri, Los Osos, San Luis Bay, Olson, San Simeon, and Wilmar Avenue faults. These faults were evaluated as potential seismic sources (Reference 40, Chapter 3). However, PG&E determined that the potential seismic sources of significance to the ground motions at the site are: the Hosgri and Los Osos fault zones, and the San Luis Bay fault, based on the probabilistic seismic hazard analysis; and the Hosgri fault zone, based on the deterministic analysis. Details are provided in Reference 40, Chapters 2 and 3, and summarized in SSER 34, Section 2.5.1, "Geology" and 2.5.2, "Seismology". The NRC's review of PG&E's evaluations is documented in References 42 and 43. 2.5.3.10 Ground Accelerations and Response Spectra The seismic design and evaluation of DCPP is based on the earthquakes described in the following four subsections. Refer to Section 3.7 for the design criteria associated with the application of the DE, DDE, and HE to the structures, systems, and components and the seismic margin assessment of the LTSP. 2.5.3.10.1 Design Earthquake During the original design phase, the maximum ground acceleration that would occur at the DCPP site was estimated for each of the postulated earthquakes listed in Section 2.5.3.9, using the methods set forth in References 12 and 24. The plant site acceleration was primarily dependent on the following parameters: Gutenberg-Richter magnitude and released energy, distance from the earthquake focus to the plant site, shear and compressional velocities of the rock media, and density of the rock. Rock properties are discussed under Section 2.5.2.2.6, Site Engineering Properties. The maximum rock accelerations that would occur at the DCPP site were estimated as: Earthquake A . . . . 0.10 g Earthquake C . . . . 0.05 g Earthquake B . . . . 0.12 g Earthquake D . . . . 0.20 g
In addition to the maximum acceleration, the frequency distribution of earthquake motions is important for comparison of the effects on plant structures and equipment. In general, the parameters affecting the frequency distribution are distance, properties of the transmitting media, length of faulting, focus depth, and total energy release. Earthquakes that might reach the site after traveling over great distances would tend to DCPP UNITS 1 & 2 FSAR UPDATE 2.5-63 Revision 21 September 2013 have their high frequency waves filtered out. Earthquakes that might be centered close to the site would tend to produce wave forms at the site having minor low frequency characteristics.
In order to evaluate the frequency distribution of earthquakes, the concept of the response spectrum is used.
For nearby earthquakes, the resulting response spectra accelerations would peak sharply at short periods and would decay rapidly at longer periods. Earthquake D would produce such response spectra. The March 1957 San Francisco earthquake as recorded in Golden Gate Park (S80°E component) was the same type. It produced a maximum recorded ground acceleration of 0.13 g (on rock) at a distance of about 8 miles from the epicenter. Since Earthquake D has an assigned hypocentral distance of 12 miles, it would be expected to produce response spectra similar in shape to those of the 1957 event.
Large earthquakes centered at some distance from the plant site would tend to produce response spectra accelerations that peak at longer periods than those for nearby smaller shocks. Such spectra maintain a higher spectral acceleration throughout the period range beyond the peak period. Earthquakes A and C are events that would tend to produce this type of spectra. The intensity of shaking as indicated by the maximum predicted ground acceleration shows that Earthquake C would always have lower spectral accelerations than Earthquake A.
Since the two shocks would have approximately the same shape spectra, Earthquake C would always have lower spectral accelerations than Earthquake A, and it is therefore eliminated from further consideration. The north-south component of the 1940 El Centro earthquake produced response spectra that emphasized the long period characteristics described above. Earthquake A, because of its distance from the plant site, would be expected to produce response spectra similar in shape to those produced by the El Centro event. Smoothed response spectra for Earthquake A were constructed by normalizing the El Centro spectra to 0.10 g. These spectra, however, show smaller accelerations than the corresponding spectra for Earthquake B (discussed in the next paragraph) for all building periods, and thus Earthquake A is also eliminated from further consideration.
Earthquake B would tend to produce response spectra that emphasize the intermediate period range inasmuch as the epicenter is not close enough to the plant site to produce large high frequency (short-period) effects, and it is too close to the site and too small in magnitude to produce large low frequency (long-period) effects. The N69°W component to the 1952 Taft earthquake produced response spectra having such characteristics. That shock was therefore used as a guide in establishing the shape of the response spectra that would be expected for Earthquake B.
Following several meetings with the AEC staff and their consultants, the following two modifications were made in order to make the criteria more conservative: DCPP UNITS 1 & 2 FSAR UPDATE 2.5-64 Revision 21 September 2013 (1) The Earthquake D time-history was modified in order to obtain better continuity of frequency distribution between Earthquakes D and B. (2) The accelerations of Earthquake B were increased by 25 percent in order to provide the required margin of safety to compensate for possible uncertainties in the basic earthquake data. Accordingly, Earthquake D-modified was derived by modifying the S80°E component of the 1957 Golden Gate Park, San Francisco earthquake, and then normalizing to a maximum ground acceleration of 0.20 g. Smoothed response spectra for this earthquake are shown in Figure 2.5-21. Likewise, Earthquake B was derived by normalizing the N69°W component of the 1952 Taft earthquake to a maximum ground acceleration of 0.15 g. Smoothed response spectra for Earthquake B are shown in Figure 2.5-20. The maximum vibratory motion at the plant site would be produced by either Earthquake D-modified or Earthquake B, depending on the natural period of the vibrating body. 2.5.3.10.2 Double Design Earthquake The maximum ground acceleration and response spectra for the Double Design Earthquake are twice those associated with the design earthquake, as described in Section 2.5.3.10.1 (Reference 51). 2.5.3.10.3 Hosgri Earthquake As mentioned earlier, based on a review of the studies presented in Appendices 2.5D and 2.5E (of Reference 27 in Section 2.3) by the NRC and the United States Geologic Survey (USGS) (acting as the NRC's geological consultant), the NRC issued SSER 4 in May 1976. This supplement included the USGS conclusion that a magnitude 7.5 earthquake could occur on the Hosgri fault at a point nearest to the Diablo Canyon site. The USGS further concluded that such an earthquake should be described in terms of near fault horizontal ground motion using techniques and conditions presented in Geological Survey Circular 672. The USGS also recommended that an effective, rather than instrumental, acceleration be derived for seismic analysis.
The NRC adopted the USGS recommendation of the seismic potential of the Hosgri fault. In addition, based on the recommendation of Dr. N. M. Newmark, the NRC prescribed that an effective horizontal ground acceleration of 0.75g be used for the development of response spectra to be employed in a seismic evaluation of the plant. The NRC outlined procedures considered appropriate for the evaluation including an adjustment of the response spectra to account for the filtering effect of the large building foundations. An appropriate allowance for torsion and tilting was to be included in the analysis. A guideline for the consideration of inelastic behavior, with an associated ductility ratio, was also established.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-65 Revision 21 September 2013 The NRC issued SSER 5 in September 1976. This supplement included independently-derived response spectra and the rationale for their development. Parameters to be used in the foundation filtering calculation were delineated for each major structure. The supplement prescribed that either the spectra developed by Blume or Newmark would be acceptable for use in the evaluation with the following conditions:
(1) In the case of the Newmark spectra no reduction for nonlinear effects would be taken except in certain specific areas on an individual case basis. (2) In the case of the Blume spectra a reduction for nonlinear behavior using a ductility ratio of up to 1.3 may be employed.
(3) The Blume spectra would be adjusted so as not to fall below the Newmark spectra at any frequency. The development of the Blume ground response spectra, including the effect of foundation filtering, is briefly discussed below. The rationale and derivation of the Newmark ground response spectra is discussed in Appendix C to Supplement No. 5 of the SER.
The time-histories of strong motion for selected earthquakes recorded on rock close to the epicenters were normalized to a 0.75g peak acceleration. Such records provide the best available models for the Diablo Canyon conditions relative to the Hosgri fault zone. The eight earthquake records used are listed in the table below. Epicentral Peak Depth, Distance, Acceleration Earthquake M km Recorded at km Component g Helena 1935 6 5 Helena 3 to 8 EW 0.16 Helena 1935 6 5 Helena 3 to 8 NS 0.13 Daly City 1957 5.3 9 Golden Gate Park 8 N80W 0.13 Daly City 1957 5.3 9 Golden Gate Park 8 N10E 0.11 Parkfield 1966 5.6 7 Temblor 2 7 S25W 0.33 Parkfield 1966 5.6 7 Temblor 2 7 N65W 0.28 San Fernando 1971 6.6 13 Pacoima Dam 3 S14W 1.17 San Fernando 1971 6.6 13 Pacoima 3 N76W 1.08
The magnitudes are the greatest recorded thus far (September 1985) close in on rock stations and range from 5.3 to 6.6. Adjustments were made subsequently in the period range of the response spectrum above 0.40 sec for the greater long period energy expected in a 7.5M shock as compared to the model magnitudes.
The procedure followed was to develop 7 percent damped response spectra for each of the eight records normalized to 0.75g and then to treat the results statistically according DCPP UNITS 1 & 2 FSAR UPDATE 2.5-66 Revision 21 September 2013 to period bands to obtain the mean, the median, and the standard deviations of spectral response. At this stage, no adjustments for the size of the foundation or for ductility were made. The 7 percent damped response spectra were used as the basis for calculating spectra at other damping values.
Figures 2.5-29 and 2.5-30 show free-field horizontal ground response spectra as determined by Blume and Newmark, respectively, at damping levels from two to seven percent.
Figures 2.5-31 and 2.5-32 show vertical ground response spectra as determined by Blume and Newmark, respectively, for two to seven percent damping. The ordinates of vertical spectra are taken as two-thirds of the corresponding ordinates of the horizontal spectra. These response spectra, finalized in 1977, are described as the "1977 Hosgri response spectra." Note that the Shoreline Fault Zone (refer to Section 2.5.7.1) is considered to be a lesser included case under the Hosgri evaluation (Reference 55). 2.5.3.10.4 1991 Long Term Seismic Program Earthquake As discussed in Section 2.5.3.9.4, the Long Term Seismic Program, in response to License Condition No. 2.C.(7) determined that the governing earthquake source for the deterministic seismic margins evaluation of DCPP (84th percentile ground motion response spectrum) is the Hosgri fault. Ground motions, and the corresponding free-field response spectra for a Richter Magnitude 7.2 earthquake centered along the Hosgri fault, approximately 4.5 km from DCPP, were developed by PG&E, as documented in Reference 40. This event is referred to as the "LTSP Earthquake." As part of their review of Reference 40, the NRC concluded that spectra developed by PG&E could underestimate the ground motion (Reference 42). As a result, the final spectra, applicable to the LTSP evaluation of DCPP, is an envelope of that developed by PG&E and that developed by the NRC. Figures 2.5-33 and 2.5-34 show the 84th percentile ground motion response spectrum at 5% damping for the horizontal and vertical directions, respectively, described as the "1991 LTSP response spectra". These spectra define the current licensing basis for the LTSP. Figure 2.5-35 shows a comparison of the horizontal 1991 LTSP response spectrum with the 1977 Newmark Hosgri spectrum (based on Reference 40, Figure 7-2). This comparison indicates that the 1977 Hosgri spectrum is greater than the 1991 LTSP spectrum at all frequencies less than about 15 Hz, but the 1991 LTSP spectrum exceeds the 1977 Hosgri spectrum by approximately 10 percent for frequencies above 15 Hz. This exceedance was accepted by the NRC in SSER 34 (Reference 42), Section 3.8.1.1 (Ground-Motion Input for Deterministic Evaluations): "On the basis of PG&E's margins evaluation discussed in Section 3.8.1.7 of this SSER, the staff concludes that these high-frequency spectral exceedances are not significant." DCPP UNITS 1 & 2 FSAR UPDATE 2.5-67 Revision 21 September 2013 In addition, the NRC states in SSER 34 (Reference 42), Section 1.4 (Summary of Staff Conclusions): "The staff notes that the seismic qualification basis for Diablo Canyon will continue to be the original design basis plus the Hosgri evaluation basis, along with the associated analytical methods, initial conditions, etc. The LTSP has served as a useful check of the adequacy of the seismic margins and has generally confirmed that the margins are acceptable." Therefore, the 1991 LTSP ground motion response spectra does not replace or modify, the DE, DDE, or 1977 Hosgri response spectra described above. 2.5.4 SURFACE FAULTING 2.5.4.1 Geologic Conditions of the Site The geologic history and lithologic, stratigraphic, and structural conditions of the site and the surrounding area are described in Section 2.5.2 and are illustrated in the various figures included in Section 2.5. 2.5.4.2 Evidence for Fault Offset Substantive geologic evidence, described under Section 2.5.2.2, Site Geology, indicates that the ground at and near the site has not been displaced by faulting for at least 80,000 to 120,000 years. It can be inferred, on the basis of regional geologic history, that minor faults in the site bedrock date from the mid-Pliocene or, at the latest, from mid-Pleistocene episodes of tectonic activity. 2.5.4.3 Identification of Active Faults Three zones that include faults greater than 1000 feet in length were mapped within about 5 miles of the site. Two of these, the Edna and San Miguelito fault zones, were mapped on land in the San Luis Range. The third, consisting of several breaks associated with the offshore Santa Maria Basin East Boundary zone of folding and faulting, is described in Sections 2.5.2.1.2.3 and 2.5.2.1.5.5 under Regional Geologic and Tectonic Setting. The mapped trace of each of these structures is shown in Figures 2.5-3 and 2.5-4. Additional active faults that were identified through the studies associated with the Hosgri Evaluation and LTSP are discussed in Sections 2.5.3.9.3 and 2.5.3.9.4, respectively. 2.5.4.4 Earthquakes Associated With Active Faults The earthquakes discussions are limited to those identified during the original design phase and do not include any earthquakes recorded since 1971. DCPP UNITS 1 & 2 FSAR UPDATE 2.5-68 Revision 21 September 2013 The Edna fault or fault zone has been active at some time since the deposition of the Plio-Pleistocene Paso Robles Formation, which it displaces. It has no morphologic expression suggestive of late Pleistocene activity, nor is it known to displace late Pleistocene or younger deposits. Four epicenters of small (3.9 to 3M) shocks and 42 other epicenters for shocks of "small" or "unknown" intensity have been reported as occurring in the approximate vicinity of the Edna fault (Figures 2.5-3 and 2.5-4). Owing to the small size of the earthquakes that they represent, however, all of these epicenters are only approximately located. Further, they fall in the energy range of shocks that can be generated by fairly large construction blasts. At present, no conclusive evidence is available to determine whether the Edna fault could be classified as seismically active, or as geologically active in the sense of having undergone multiple movements within the last 500,000 years.
The San Miguelito fault has been mapped as not displacing the Plio-Pleistocene Paso Robles Formation. No instrumental epicenter has been reliably recorded from its vicinity, but the Berkeley Seismological Laboratory indicates Avila Bay as the presumed epicentral location for a moderately damaging (Intensity VII at Avila) earthquake that occurred on December 1, 1916. It seems likely, however, that this shock occurred along the offshore East Boundary zone rather than on the San Miguelito fault zone.
The East Boundary zone has an overall length of about 70 miles. Individual breaks within the zone are as much as 30 miles long, though the varying amount of displacement that occurs along specific breaks indicates that movement along them is not uniform, and it suggests that breakage may have occurred on separate, limited segments of the faults. The reach of the zone that is opposite DCPP site contains four fault breaks. These breaks range from 1 to 15 miles in length, and they have minimum distances of 2.1 to 4.5 miles from the site. The East Boundary zone is considered to be seismically active, since at least five instrumentally well located epicenters and as many as ten less reliably located other epicenters are centered along or near the zone. One of the breaks (located 3-1/2 miles offshore from the site) exhibits topographic expression that may represent a tectonic offset of the sea floor surface at a point along its trace 6 miles north of the site. Other faults in the East Boundary zone have associated erosion features, a few of which could possibly be partly of faultline origin.
The earthquake of December 1, 1916, though listed as having an epicentral location at Avila Bay, is considered more probably to have originated along either the East Boundary zone or, possibly, the Santa Lucia Bank fault. Effects of this shock at Avila included landsliding in Dairy Canyon, 2 miles north of town, and "...disturbance of waters in the Bay of San Luis Obispo." "...plaster in several cottages...was jarred loose...while some of the smokestacks on the (Union Oil Company) refinery were toppled over." It is apparently on this basis that the Berkeley listing of earthquakes assigns this shock a "large" intensity and places its approximate epicentral location at Port San Luis.
A small (Magnitude 2.9) shock that apparently originated near the East Boundary zone a short distance south of DCPP site was lightly felt at the site on September 24, 1974. DCPP UNITS 1 & 2 FSAR UPDATE 2.5-69 Revision 21 September 2013 This shock, like most of those recorded along the East Boundary zone, was not damaging.
The minor fault zone that was mapped in the sea cliff at the mouth of Diablo Creek and in the excavation for the Unit 1 turbine building has an onshore length of about 550 feet, and it probably continues for some distance offshore. It has been definitely determined to be not active. 2.5.4.5 Correlation of Epicenters With Active Faults Earthquake epicenters located within 50 miles of DCPP site, for earthquakes recorded through 1972, have been approximately located in the vicinity of each of the faults. The reported earthquakes are listed in Table 2.5-1 and as follows, and their indicated epicentral locations are shown in Figures 2.5-3 and 2.5-4: Earthquake Epicenters Reported as Being Located Approximately in the Vicinities of San Luis Obispo, Avila, and Arroyo Grande Geographic Coordinates Magni- Inten- Notes and Greenwich Date N Latitude W Longitude tude sity Mean Time (GMT) 7.10.1889 35.17° 120.58° Arroyo Grande. Shocks for several days.
12.1.1916 35.17° 120.75° VII VII at Avila. Considerable glass broken and goods in stores thrown from shelves at San Luis Obispo. Water in bay disturbed, plaster in cottages jarred loose, smoke stacks of Union Oil refinery toppled over at Avila. Severe at Port San Luis. III at Santa Maria: 22:53:00 4.26.1950 35.20° 120.60° 3.5 V V at Santa Maria. Also felt at Orcutt: 7:23:29 1.26.1971 35.20° 120.70° 3 Near San Luis Obispo: 21:53:53 1830 to 7.21.1931 35.25° 120.67° 42 epicenters
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-70 Revision 21 September 2013 Earthquake Epicenters Reported as Being Located Approximately in the Vicinity of the Offshore Santa Maria Basin East Boundary Zone Geographic Coordinates Magni- Inten- Notes and Greenwich Date N Latitude W Longitude tude sity Mean Time (GMT) 5.27.1935(30-1) 35.62° 121.64° 3 III Felt at Templeton: 16:08:00 9.7.1939(30-6) 35.46° 121.50° 3 Off San Luis Obispo County; felt at Cambria: 2:50:30 1.27.1945 34.75° 120.67° 3.9 17:50:31 12.31.1948(30-10) 35.60° 121.23° 4.6 Felt along coast from Lompoc to Moss Landing. VI at San Simeon. V at Cayucos, Creston, Moss Landing, Piedras Blancas Light Station: 14:35:46 11.17.1949 34.80° 120.70° 2.8 IV at Santa Maria. Near Priest: 5:06:60 2.5.1955(30-23) 35.86° 121.15° 3.3 West of San Simeon: 7:10:19 6.21.1957(30-25A) 35.23° 120.95° 3.7 Off Coast. Felt in San Luis Obispo, Morro Bay: 20:46:42 8.18.1958 35.60° 121.30 3.4 Near San Simeon: 5:30:42 10.25.1967 35.73° 121.45° 2.6 Near San Simeon: 23:05:39.5 (Figures in parentheses refer to events relocated by S. W. Smith, refer to Table 2.5-2). DCPP UNITS 1 & 2 FSAR UPDATE 2.5-71 Revision 21 September 2013 2.5.4.6 Description of Active Faults Data pertaining to faults with lengths greater than 1000 feet and reaches within 50 miles of the site, as identified during the original design phase, are included in Section 2.5.2.1.5, Structure of the San Luis Range and Vicinity, and in Figures 2.5-3 and 2.5-4. These data indicate the fault lengths, relationship of the faults to regional tectonic structures, known history of displacements, outer limits, and whether the faults can be considered as active. 2.5.4.7 Results of Faulting Investigation The site for Units 1 and 2 of DCPP was investigated in detail for faulting and other possibly detrimental geologic conditions. From studies made prior to design of the plant, it was determined that there was need to take into account the possibility of surface faulting in such design. The data on which this determination was based are presented in Section 2.5.2.2, Site Geology. 2.5.5 Stability of Subsurface Materials The possibility of past or potential surface or subsurface ground subsidence, uplift, or collapse in the vicinity of DCPP was considered during the course of the geologic investigations for Units 1 and 2. 2.5.5.1 Geologic Features The site is underlain by folded bedrock strata consisting predominantly of sandy mudstone and fine-grained sandstone. The existence of an unbroken and otherwise undeformed section of upper Pleistocene terrace deposits overlying a wave-cut bedrock bench at the site provides positive evidence that all folding and faulting in the bedrock antedated formation of the terrace. Local depressions and other irregularities on the bedrock surface plainly reflect erosion in an ancient surf zone.
The rocks that constitute the bedrock section are not subject to significant solution effects (i.e., development of cavities or channels that could affect the engineering or fluid conducting character of the rock) because the bedrock section does not contain thick or continuous bodies of soluble rock types such as limestone or gypsum. Voids encountered during excavation at the site were limited to thin zones of vuggy breccia and isolated vugs in some beds of calcareous mudstone. Areas where such minor vuggy conditions were present were noted at a few locations in the excavation for the Unit 2 containment and fuel handling structures (at plant grid coordinates N59, N597, E10, E005 and N59, N700, E10, E120).
The maximum size of any individual opening was 3 inches or less, and most were less than 1 inch in maximum dimension. Because of the limited extent and isolated nature of these small voids, they were not considered significant in foundation engineering or slope stability analyses. DCPP UNITS 1 & 2 FSAR UPDATE 2.5-72 Revision 21 September 2013 It has been determined by field examination that no sea caves exist in the immediate vicinity of the site. The only cave like natural features in the area are shallow pits and hollows in some of the sea cliff outcrops of resistant tuff. These features generally have dimensions of a few inches to about 10 feet. They are superficial, and have originated through differential weathering of variably cemented rock.
Several exploratory wells have been drilled for petroleum within the San Luis Range, but no production was achieved and the wells were abandoned. The area is not now active in terms of either production or exploration. The location of the abandoned wells is shown in Figure 2.5-6, and the geologic relationships in the Range are illustrated in Section A-A' of Figure 2.5-6 and in Figure 2.5-7, Section D-D'. The nearest oil-producing area is the Arroyo Grande field, about 15 miles to the southeast.
The potential for future problems of ground instability at the site, because of nearby petroleum production, can be assessed in terms of the geologic potential for the occurrence of oil within, or offshore from, the San Luis Range. In addition, assessment can be made in terms of the geologic relationships in the site as contrasted with geologic conditions in places where oil field exploitation has resulted in deformation of the ground surface.
As shown in Figures 2.5-6 and 2.5-7, the San Luis Range has the structural form of a broad synclinal fold, which in turn is made up of several tightly compressed anticlines and synclines of lesser order. The configuration is not conducive to entrapment of hydrocarbon fluids, as such fluids tend to migrate upward through bedding and fracture-controlled zones of higher primary and secondary permeability until they reach a local trap or escape into the near surface or surface environment. Within the San Luis Range, the only recognizable structural traps are in local zones where plunge reversals exist along the crests of the second-order anticlines. Such structures evidently were the actual or hoped-for targets for most of the exploratory wells that have been drilled in the San Luis Range, but none of these wells has produced enough oil or gas to record; thus, the traps have not been effective, or perhaps the strata are essentially lacking in hydrocarbon fluids. Other conditions that indicate poor petroleum prospects for the Range include the general absence of good reservoir rocks within the section and the relatively shallow basement of non petroliferous Franciscan rocks.
In the offshore, adjacent to the southerly flank of the San Luis Range, subsurface conditions are not well known, but are probably generally similar. Scattered data suggest that a structural high, perhaps defined by a west-northwest plunging anticline, may exist a few miles offshore from DCPP site. Such a feature could conceivably serve as a structural trap, if local closure were present along its axis; however, it seems unlikely that it would contain significant amounts of petroleum.
Available data pertaining to exploratory oil wells drilled in the region of the site are given here: DCPP UNITS 1 & 2 FSAR UPDATE 2.5-73 Revision 21 September 2013 Exploratory Oil Wells in the Vicinity of DCPP Site Data from exploratory wells drilled outside of oil and gas fields in California to December 31, 1963: Division of Oil and Gas, San Francisco. Mount Diablo Total Stratigraphy B. & M. Elev, Date Depth, (depth in ft) Age T R Sec Operator Well No. ft Started ft at Bottom of Hole 31S 10E 3 Tidewater "Montadoro" 365 April 6,146 Monterey 0-3800; Oil Co. 1 1954 Obispo Tuff 3800: Franciscan; U. Jurassic
30S 10E 24 Gretna "Maino- 275 March 1,575 Franciscan; Corp. Gonzales" 1 1937 Jurassic
24 Wm. H. "Spooner" 1 325 July 1,749 Jurassic Provost 1952
24 Shell Oil "Buchon" - - - - Co.
34 A. O. Lewis "Pecho" 1 177 May 2,745 Monterey 0-2612; 1937 U. Miocene 30S 11E 9 Van Stone "Souza" 1 42 Oct 1,233 Franciscan; and 1951 Jurassic Dallaston
31S 11E 15 Tidewater "Honolulu- 1,614 Jan 10,788 Monterey 0-4363; Oil Co. Tidewater- 1958 Pt. Sal 4363; U.S.L.- Obispo Tuff 4722; Heller Rincon Shale 5370; "Lease" 1 2nd Tuff 5546; 2nd Rincon Shale 6354; 3rd Tuff 10,174; L. Miocene
For the purpose of assessing the potential for the occurrence of adverse oil field related ground deformation effects at DCPP site, in the unlikely event that petroleum should be discovered and produced at a nearby location, it is useful to review the nature and causes of such ground deformation, and the types of geologic conditions at places where it has been observed. DCPP UNITS 1 & 2 FSAR UPDATE 2.5-74 Revision 21 September 2013 The general subject of surface deformation associated with oil and gas field operations has been reviewed by Yerkes and Castle (Reference 22), among others. Such deformation includes differential subsidence, development of horizontally compressive strain effects within the central parts of subsidence bowls and horizontally extensive strain effects around their margins, and development or activation of cracks and faults. Pull-apart cracks and normal faults may develop in the marginal zone of extensive strain, while reverse and thrust faults sometimes occur in the central, compressive part of subsidence bowls. These effects all can develop when extraction of petroleum, water, and sand, plus lowering of fluid pressures, result in compression within and adjacent to producing zones, and attendant subsidence of the overlying ground. Other effects, including rebound of the ground surface, fault activation, and earthquake generation, have resulted from injection of fluid into the ground for purposes of secondary recovery, subsidence control, and disposal of fluid waste.
In virtually all instances of ground-surface deformation associated with petroleum production, the producing field has been centered on an anticlinal structure, in general relatively broad and internally faulted. The strata in the producing and overlying parts of the section typically are poorly consolidated sandstone, siltstone, claystone, and shale of low structural competence. The field generally is one with relatively large production, with significant decline of fluid pressure in the producing zones.
The conditions just cited can be contrasted with those obtained in the vicinity of DCPP site, where the rocks lie along the flank of a major syncline. They consist of tight sandstone, tuffaceous sandstone, mudstone, and shale, together with large resistant masses of tuff and diabase. Bedding dips range from near horizontal to vertical and steeply overturned, as shown in Section D-D' of Figure 2.5-7 and Section A-B of Figure 2.5-10. This structural setting is unlike any reported from areas where oil-field-associated surface deformation has occurred.
The foregoing discussion leads to the following conclusions: (a) future development of a producing oil field in the vicinity of DCPP site is highly unlikely because of unfavorable geologic conditions, and (b) geologic conditions in the site vicinity are not conducive to the occurrence of surface deformation, even if nearby petroleum production could be achieved.
As was noted in Section 2.4, the rocks underlying the site do not constitute a significant groundwater reservoir, so that future development of deep rock water wells in the vicinity is not a reasonable possibility. The considerations pertaining to surface deformation resulting from water extraction are about the same as for petroleum extraction, so there is no likelihood that DCPP site could experience artificially induced and potentially damaging subsidence, uplift, collapse, or changes in subsurface effective stress related to pore pressure phenomena.
There are no mineral deposits of economic significance in the ground underlying the site.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-75 Revision 21 September 2013 Although some regional warping and uplift may well be taking place in the southern Coast Ranges, such deformation cannot be sufficiently rapid and local to impose significant effects on coastal installations. Apparent elevation of the San Luis Range has increased about 100 feet relative to sea level since the cutting of the main terrace bench at least 80,000 years ago.
Expressions of deformation preserved in the bedrock at the site include minor faults, folds, and zones of blocky fracturing in sandstone and intra-bed shearing in claystone. Zones of cemented breccia also are present, as is widespread evidence of disturbance adjacent to intrusive bodies of tuff. Local weakening of the rocks in some of these zones led to some problems during construction, but these were handled by conventional techniques such as overexcavation and rock bolting. No observed features of deformation are large or continuous enough to impose significant effects on the overall performance of the site foundation.
The foundation excavations for Units 1 and 2 were extended below the zone of intense near surface weathering so that the exposed bedrock was found to be relatively fresh and firm. The principal zones of structural weakness are associated with small bodies of altered tuff and with internally sheared beds of claystone. The claystone intra-bed shear was expressed by the development of numerous slickensided shear surfaces within parts of the beds, especially in places where the claystone had locally been squeezed into pod like masses. The shearing and local squeezing clearly are expressions of the preferential occurrence of differential adjustments in the relatively weaker claystone beds during folding of the section.
The claystone beds are localized in a part of the rock section that underlies the discharge structure and extends across the southerly part of the Unit 2 turbine-generator building, thence continuing easterly, along a strike through the ground south of the Unit 2 containment. The bedding dips 48 to 75° north within this zone. Individual claystone beds range from 1/2 inch to about 6 inches in thickness, and they occur as interbeds in the sandstone-mudstone rock section.
The relationship of the claystone layers to the foundation excavation is such that they crop out in several narrow bands across the floor and walls (refer to Figures 2.5-15 and 2.5-16). Thus, the claystone bed remains confined within the rock section, except in a narrow strip at the face of the excavation. Because of the small amount of claystone mass and the geometric relationship of the steeply dipping claystone interbeds to the foundation structures, it was determined that the finished structure would not be affected by any tendency of the claystone to undergo further changes in volume.
The only area in which claystone swelling was monitored was along the north wall of the lower part of the large slot cut for the cooling water discharge structure. There are several thin (6 inches or less) claystone interbeds in the sandstone-mudstone section. Because the orientation of the bedding and the plane of the cut face differ by only about 30°, and the bedding dips steeply into the face, opening of the cut served both to remove lateral support from the rock behind the face, and also to expose the clay beds DCPP UNITS 1 & 2 FSAR UPDATE 2.5-76 Revision 21 September 2013 to rainfall and runoff. This apparently resulted in both load relief and hydration swelling of the newly exposed claystone, which in turn caused some outward movement of the cut face. The movement then continued as gravity creep of the locally destabilized mass of rock between the claystone beds and the free face. The movement was finally controlled by installation of drilled-in lateral tie-backs, prior to placement of the reinforced concrete wall of the discharge structure.
No evidence of unrelieved residual stresses in the bedrock was noted during the excavation or subsequent construction of the plant foundation. Isolated occurrences of temporary slope instability clearly were related to locally weathered and fractured rock, hydration swelling of claystone interbeds, and local saturation by surface runoff. The Units 1 and 2 power plant facilities are founded on physically and chemically stable bedrock. 2.5.5.2 Properties of Underlying Materials Static and dynamic engineering properties of materials in the subsurface at the site are presented in Section 2.5.2.2.6, Site Engineering Properties. 2.5.5.3 Plot Plan Plan views of the site indicating exploratory boring and trenching locations are presented in Figures 2.5-8 and 2.5-11 through 2.5-15. Profiles illustrating the subsurface conditions relative to the PG&E Design Class I structures are furnished in Figures 2.5-12 through 2.5-16. Discussions of engineering properties of materials and groundwater conditions are included in Section 2.5.2.2.6, Site Engineering Properties. 2.5.5.4 Soil and Rock Characteristics Information on compressional and shear wave velocity surveys performed at the site are included in Appendices 2.5A and 2.5B of Reference 27 of Section 2.3. Values of soil modulus of elasticity and Poisson's ratio calculated from seismic measurements are presented in Table 1 of Appendix 2.5A of Reference 27 of Section 2.3, and in Figure 2.5-19. Boring and trench logs are presented in Figures 2.5-23 through 2.5-28. 2.5.5.5 Excavations and Backfill Plan and profile drawings of excavations and backfill at the site are presented in Figures 2.5-17 and 2.5-18. The engineered backfill placement operations are discussed in Section 2.5.2.2.6.4, Engineered Backfill. 2.5.5.6 Groundwater Conditions Groundwater conditions at the site are discussed in Section 2.4.13. The effect on foundations of PG&E Design Class I structures is discussed in Section 2.5.2.2.6, Site Engineering Properties. DCPP UNITS 1 & 2 FSAR UPDATE 2.5-77 Revision 21 September 2013 2.5.5.7 Response of Soil and Rock to Dynamic Loading Details of dynamic testing on site materials are contained in Appendices 2.5A and 2.5B of Reference 27 in Section 2.3. 2.5.5.8 Liquefaction Potential As stated in Section 2.5.2.2.6.5, adverse hydrologic effects on foundations of PG&E Design Class I structures can be neglected due to the structures being founded on bedrock and the groundwater level lying well below final grade.
There is a small local zone of medium dense sand located northeast of the intake structure and beneath a portion of buried ASW piping that is not attached to the circulating water tunnels. This zone is susceptible to liquefaction during design basis seismic events (References 45 and 46). The associated liquefaction-induced settlements from seismic events are considered in the design of the buried ASW piping. (References 48 and 49) 2.5.5.9 Earthquake Design Basis The earthquake design bases for the DCPP site are discussed in Section 2.5.3.9, a discussion of the design response spectra is provided in Section 2.5.3.10, and the application of the earthquake ground motions to the seismic analysis of structures, systems, and components is provided in Section 3.7. Response acceleration curves for the site resulting from Earthquake B and Earthquake D-modified are shown in Figures 2.5-20 and 2.5-21, respectively. Response spectrum curves for the Hosgri earthquake are shown in Figures 2.5-29 through 2.5-32. 2.5.5.10 Static Analysis A discussion of the analyses performed on materials at the site is presented in Section 2.5.2.2.6, Site Engineering Properties. 2.5.5.11 Criteria and Design Methods The criteria and methods used in evaluating subsurface material stability are presented in Section 2.5.2.2.6, Site Engineering Properties. 2.5.5.12 Techniques to Improve Subsurface Conditions Due to the bearing of in situ rock being well in excess of the foundation pressure, no treatment of the in situ rock is necessary. Compaction specifications for backfill are presented in Section 2.5.2.2.6.4, Engineered Backfill. DCPP UNITS 1 & 2 FSAR UPDATE 2.5-78 Revision 21 September 2013 2.5.6 SLOPE STABILITY 2.5.6.1 Slope Characteristics The only slope whose failure during a DDE could adversely affect the nuclear power plant is the slope east of the building complex (refer to Figures 2.5-17, 2.5-18, and 2.5-22). To evaluate the stability of this slope, the soil and rock conditions were investigated by exploratory borings, test pits, and a thorough geological reconnaissance by the soil consultant, Harding-Lawson Associates, and was in addition to the overall geologic investigation performed by other consultants.
The slope configuration and representative locations of the subsurface conditions determined from the exploration are shown on Plates 2, 3, and 4 of Appendix 2.5C of Reference 27 of Section 2.3. Reference 44 provides further information compiled in 1997 in response to NRC questions on landslide potential.
Bedrock is exposed along the lower portions of the cut slope up to about the lower bench at elevation 115 feet. It consists of tuffaceous siltstone and fine-grained sandstone of the Monterey Formation. Terrace gravel overlies bedrock and extends to an approximate elevation of 145 feet. Stiff clays and silty soils with gravel and rock fragments constitute the upper material on the site. The upper few feet of fine-grained soils are dark brown and expansive.
No free groundwater was observed in any of the borings which were drilled in April 1971, nor was any evidence of groundwater observed in this slope during the previous years of investigation and construction of the project. In response to an NRC request in early 1997, PG&E conducted further investigations of slope stability at the site (Reference 44). The results of the investigations showed that earthquake loading, as a result of an earthquake on the Hosgri fault zone, following periods of prolonged precipitation will not produce any significant slope failure that can impact Design Class I structures and equipment. In addition, potential slope failures under such conditions will not adversely impact other important facilities, including the raw water reservoirs, the 230 kV and 500 kV switchyards, and the intake and discharge structures. Potential landslides may temporarily block the access road at several locations. However, there is considerable room adjacent to and north of the road to reroute emergency traffic.The investigation of the cut slope included geologic mapping of the soil and rock conditions exposed on the surface of slope and existing benches. Subsurface conditions were investigated by drilling test borings and by excavating test pits in the natural slope above the plant site (refer to Figure 2.5-22). The test borings were drilled with a truck mounted, 24 inch flight auger drill rig, and the test pits were excavated with a track-mounted backhoe. Boring and Log of Test Pits 1, 2, and 3 were logged by the soil consultant; borings 2 and 3 were logged by PG&E engineering personnel. The logs of all borings were verified by the soil consultant, who examined all samples obtained from each boring. Undisturbed samples were obtained from boring 2 and each of the test pits. Because of the stiffness of the soil, hardness of the rock, and DCPP UNITS 1 & 2 FSAR UPDATE 2.5-79 Revision 21 September 2013 type of drilling equipment used, the undisturbed samples were obtained by pushing an 18-inch steel tube that measured 2.5 inches in outside diameter. A Sprague & Henwood split-barrel sampler containing brass liners was used to obtain undisturbed soil samples from the test pits. The brass liners measured 2.5 inches in outside diameter and 6 inches in height. Logs of the borings and pits are shown in Figures 2.5-23 through 2.5-27. The soils were classified in accordance with the Unified Soil Classification System presented in Figure 2.5-28. 2.5.6.2 Design Criteria and Analyses Undisturbed samples of the materials encountered in pits and borings were examined by the soil consultant in the laboratory and were subsequently tested to determine the shear strength, moisture content, and dry density. Strain controlled, unconsolidated, undrained triaxial tests at field moisture were performed on the clay to evaluate the shear strength of the materials penetrated. (The samples were maintained at field moisture since adverse moisture or seepage conditions were not encountered during this investigation nor previous investigations.) The confining stress was varied in relation to depth at which the undisturbed sample was taken. The test results are presented on the boring logs and are explained by the Key to Test Data, Figure 2.5-28.
The results of strength tests were correlated with the results developed during earlier investigations of DCPP site. Mohr circles of stresses at failure (6 to 7 percent strain) were drawn for each strength test result, and failure lines were developed through points representing one-half the deviator stresses. An average C- strength equal to a cohesion (C) value of 1000 psf and an angle of internal friction () of 29° was selected for the slope stability analysis. The analysis was checked by maintaining the angle of internal friction () constant at 19° and varying the cohesion (C) from 950 psf (weakest layer) to 3400 psf (deepest and strongest layer). Because of the presence of large gravel sizes, it was not possible to accurately determine the strength of the sand and gravel lense. However, based on tests on sand samples from other parts of the site, an angle of internal friction of 35° was selected as being the minimum available. An assumed rock strength of 5000 psf was used. This value is consistent with strength tests performed on remold rock samples from other areas of the site.
The stability of the slope was analyzed for the forces of gravity using a static method that is, the conventional method of slices. This analysis was checked using Bishop's modified method. The static method of analysis was chosen because, for the soil conditions at the site, it was judged to be more conservative than a dynamic analysis.
Because the overall strength of the rock would preclude a stability failure except along a plane of weakness which was not encountered in the borings or during the many geologic mappings of the slope, only the stability of the soil over the rock was analyzed. The strength parameters were varied as previously discussed to determine the minimum factor of safety under the most critical strength condition. For the static DCPP UNITS 1 & 2 FSAR UPDATE 2.5-80 Revision 21 September 2013 analysis excluding horizontal forces, the factor of safety was computed to be 3. When the additional unbalanced horizontal force of 0.4 times the weight of the soil within the critical surface combined with a vertical force of 0.26 times the weight was included, the minimum computed factor of safety was 1.1.
On the basis of the investigation and analysis, it was concluded that the slope adjacent to DCPP site would not experience instability of sufficient magnitude to damage adjacent safety-related structures.
The above conclusion is substantiated by additional field exploration, laboratory tests, and dynamic analyses using finite element techniques. Refer to Appendix 2.5C of Reference 27 in Section 2.3, Harding-Lawson Associates' report on this work. 2.5.6.3 Slope Stability for Buried Auxiliary Saltwater System Piping A portion of the buried ASW piping for Unit 1 ascends an approximate 2:1 (horizontal/vertical) slope to the parking area near the meteorology tower (Plates 1 and 2 of Reference 47). To ensure the stability of this slope in which the ASW piping is buried, a geotechnical evaluation, considering various design basis seismic events, was performed by Harding Lawson Associates. This evaluation is described in Reference
- 47. Based on this evaluation, it was concluded that this slope will be stable during seismic events and that additional loads resulting from permanent deformation of the slope will not impact the buried ASW piping.
2.5.7 LONG TERM SEISMIC PROGRAM On November 2, 1984, the NRC issued the Diablo Canyon Unit 1 Facility Operating License DPR-80. In DPR-80, License Condition Item 2.C.(7), the NRC stated, in part: "PG&E shall develop and implement a program to reevaluate the seismic design bases used for the Diablo Canyon Power Plant." PG&E's reevaluation effort in response to the license condition was titled the "Long Term Seismic Program" (LTSP). PG&E prepared and submitted to the NRC the "Final Report of the Diablo Canyon Long Term Seismic Program" in July 1988 (Reference 40). Between 1988 and 1991, the NRC performed an extensive review of the Final Report, and PG&E prepared and submitted written responses to formal NRC questions. In February 1991, PG&E issued the "Addendum to the 1988 Final Report of the Diablo Canyon Long Term Seismic Program" (Reference 41). In June 1991, the NRC issued Supplement Number 34 to the Diablo Canyon Safety Evaluation Report (SSER) (Reference 42) in which the NRC concluded that PG&E had satisfied License Condition 2.C.(7) of Facility Operating License DPR-80. In the SSER the NRC requested certain confirmatory analyses from PG&E, and PG&E subsequently submitted the requested analyses. The NRC's final acceptance of the LTSP is documented in a letter to PG&E dated April 17, 1992 (Reference 43). DCPP UNITS 1 & 2 FSAR UPDATE 2.5-81 Revision 21 September 2013 The LTSP contains extensive data bases and analyses that update the basic geologic and seismic information in this section of the FSAR Update. However, the LTSP material does not address or alter the current design licensing basis for the plant. In SSER 34 (Reference 42), the NRC stated, "The Staff notes that the seismic qualification basis for Diablo Canyon will continue to be the original design basis plus the Hosgri Evaluation basis, along with associated analytical methods, initial conditions, etc." As a condition of the NRC's close out of License Condition 2.C.(7), PG&E committed to several ongoing activities in support of the LTSP, as discussed in a public meeting between PG&E and the NRC on March 15, 1991 (Reference 53), described as the "Framework for the Future," in a letter to the NRC, dated April 17, 1991 (Reference 50), and affirmed by the NRC in SSER 34 (Reference 43). These ongoing activities include the following that are related to geology and seismology (Reference 42, Section 2.5.2.4): (1) To continue to maintain a strong geosciences and engineering staff to keep abreast of new geological, seismic, and seismic engineering information and evaluate it with respect to its significance to Diablo Canyon. (2) To continue to operate the strong-motion accelerometer array and the coastal seismic network. A complete listing of bibliographic references to the LTSP reports and other documents may be found in References 40, 41 and 42. 2.5.7.1 Shoreline Fault Zone In November 2008, as a result of the ongoing activities described in Section 2.5.7, the USGS, working in collaboration with the PG&E Geosciences Department, identified an alignment of microseismicity subparallel to the coastline adjacent to DCPP indicating the possible presence of a previously unidentified fault located approximately 1 km offshore of DCPP. The offshore region associated with this fault was subsequently named the Shoreline fault zone. PG&E developed estimates of the 84th percentile deterministic ground motion response spectrum for earthquakes associated with the Shoreline fault zone. The results of the study of the Shoreline fault zone are documented in Reference 52. A map showing the location of the Shoreline Fault Zone is provided in Figure 2.5-36. This report includes a comparison of the updated 84th percentile deterministic response spectra with the 1991 LTSP and 1977 Hosgri earthquake response spectra. This comparison indicates that the updated deterministic response spectra are enveloped by both the 1977 Hosgri earthquake spectrum and the 1991 LTSP earthquake spectrum. The NRC developed an independent assessment of the seismic source characteristics of the Shoreline fault and performed an independent deterministic seismic hazard DCPP UNITS 1 & 2 FSAR UPDATE 2.5-82 Revision 21 September 2013 assessment (References 54 and 55). The NRC concluded that their conservative estimates for the potential ground motions from the Shoreline fault are at or below the ground motions for which the DCPP has been evaluated previously and demonstrated to have a reasonable assurance of safety (i.e., the 1977 Hosgri earthquake and 1991 LTSP earthquake ground motion response spectra). The NRC stated that the "Shoreline scenario should be considered as a lesser included case under the Hosgri evaluation." 2.5.7.2 Evaluation of Updated Estimates of Ground Motion As an outcome of the Shoreline fault zone evaluation described in Section 2.5.7.1, the process to be used for the evaluation of new/updated geological/seismological information has been developed (References 55 and 56). The new/updated geological/seismological information, resulting from the activities described in Section 2.5.7, will be evaluated using a process that is consistent with the evaluation process defined by the NRC in Reference 57. 2.5.8 Safety Evaluation 2.5.8.1 General Design Criterion 2, 1967 Performance Standards The determination of the appropriate earthquake parameters for design of plant SSCs is addressed throughout Section 2.5, and the maximum earthquakes for the plant site are presented in Sections 2.5.3.9.1, 2.5.3.9.2, and 2.5.3.9.3. The associated design basis site free field accelerations and response spectra are presented in Sections 2.5.3.10.1, 2.5.3.10.2, and 2.5.3.10.3. The seismic design of these SSC is addressed in Section 3.7. 2.5.8.2 License Condition 2.C(7) of DCPP Facility Operating License DPR-80 Rev 44 (LTSP), Elements (1), (2) and (3) PG&E's reevaluation effort in response to the license condition was titled the "Long Term Seismic Program" (LTSP). PG&E prepared and submitted to the NRC the "Final Report of the Diablo Canyon Long Term Seismic Program" in July 1988. Between 1988 and 1991, the NRC performed an extensive review of the Final Report, and PG&E prepared and submitted written responses to formal NRC questions. In February 1991, PG&E issued the "Addendum to the 1988 Final Report of the Diablo Canyon Long Term Seismic Program". In June 1991, the NRC issued Supplement Number 34 to the Diablo Canyon Safety Evaluation Report (SSER) in which the NRC concluded that PG&E had satisfied License Condition 2.C(7) of Facility Operating License DPR-80. In the SSER the NRC requested certain confirmatory analyses from PG&E, and PG&E subsequently submitted the requested analyses. The NRC's final acceptance of the LTSP is documented in a letter to PG&E dated April 17, 1992 The commitments made as a part of the Diablo Canyon Long Term Seismic Program are detailed in Section 2.5.3.9.4 and Section 2.5.7. DCPP UNITS 1 & 2 FSAR UPDATE 2.5-83 Revision 21 September 2013 2.5.8.3 10 CFR Part 100, March 1966 - Reactor Site Criteria As described in Sections 2.5.2 through 2.5.6 above, the physical characteristics of the site, including seismology and geology have been considered. 2.
5.9 REFERENCES
- 1. R. H. Jahns, "Geology of the Diablo Canyon Power Plant Site, San Luis Obispo County, California," 1967-Supplementary Reports I and II, 1968-Supplementary Report III, Diablo Canyon PSAR, Docket No. 50-275, (Main Report and Supplementary Report I). Diablo Canyon PSAR, Docket No. 50-323, (All reports, 1966 and 1967).
- 2. R. H. Jahns, "Guide to the Geology of the Diablo Canyon Nuclear Power Plant Site, San Luis Obispo County, California," Geol. Soc. Amer., Guidebook for 66th Annual Meeting, Cordilleran Section, 1970.
- 3. Deleted in Revision 1
- 4. Deleted in Revision 1
- 5. H. Benioff and S. W. Smith, "Seismic Evaluation of the Diablo Canyon Site," Diablo Canyon Unit 1 PSAR, Docket No. 50-275. Also, Diablo Canyon Unit 2 PSAR Docket No. 50-323, 1967.
- 6. John A. Blume & Associates, Engineers, "Earthquake Design Criteria for the Nuclear Power Plant - Diablo Canyon Site," Diablo Canyon Unit 1 PSAR, Docket No. 50-275., January 12, 1967. Also, Diablo Canyon Unit 2 PSAR Docket No. 50-323.
- 7. John A. Blume & Associates, Engineers, "Recommended Earthquake Design Criteria for the Nuclear Power Plant - Unit No. 2, Diablo Canyon Site," Diablo Canyon Unit 2 PSAR, Docket No. 50-323, June 24, 1968.
- 8. Deleted in Revision 1
- 9. Deleted in Revision 1
- 10. B. M. Page, "Geology of the Coast Ranges of California," E. H. Bailey (editor), Geology of Northern California, California Division, Mines and Geology, Bull. 190, 1966, pp 255-276.
- 11. B. M. Page, "Sur-Nacimiento Fault Zone of California: Continental Margin Tectonics," Geol. Soc. Amer., Bull., Vol. 81, 1970, pp 667-690.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-84 Revision 21 September 2013 12. J. G. Vedder and R. D. Brown, "Structural and Stratigraphic Relations Along the Nacimiento Fault in the Santa Lucia Range and San Rafael Mountains, California," W. R. Dickinson and Arthur Grantz (editors), Proceedings of Conference on Geologic Problems of the San Andreas Fault System, Stanford University Publs. in the Geol. Sciences, Vol. XI, 1968, pp 242-258.
- 13. C. F. Richter, "Possible Seismicity of the Nacimiento Fault, California," Geol. Soc. Amer., Bull., Vol. 80, 1969, pp 1363-1366.
- 14. E. W. Hart, "Possible Active Fault Movement Along the Nacimiento Fault Zone, Southern Coast Ranges, California," (abs.), Geol. Soc. Amer., Abstracts with Programs for 1969, pt. 3, 1969, pp 22-23.
- 15. R. E. Wallace, "Notes on Stream Channels Offset by the San Andreas Fault, Southern Coast Ranges, California," W. R. Dickinson and Arthur Grantz (editors),
Proceedings of Conference on Geologic Problems of the San Andreas Fault System, Stanford University Publs. in the Geol. Sciences, Vol. XI, 1968, pp 242-258.
- 16. C. R. Allen, "The Tectonic Environments of Seismically Active and Inactive Areas Along the San Andreas Fault System," W. R. Dickinson and Arthur Grantz (editors), Proceedings of Conference on Geologic Problems of the San Andreas Fault System, Stanford University Publs. in the Geol. Sciences, Volume XI, 1968, pp 70-82.
- 17. Deleted in Revision 1 18. Deleted in Revision 1
- 19. L. A. Headlee, Geology of the Coastal Portion of the San Luis Range, San Luis Obispo County, California, Unpublished MS thesis, University of Southern California, 1965.
- 20. C. A. Hall, "Geologic Map of the Morro Bay South and Port San Luis Quadrangles, San Luis County, California," U.S. Geological Survey Miscellaneous Field Studies Map MF-511, 1973.
- 21. C. A. Hall and R. C. Surdam, "Geology of the San Luis Obispo-Nipomo Area, San Luis Obispo County, California," Geol. Soc. Amer., Guidebook for 63rd Ann. Meeting, Cordilleran Section, 1967.
- 22. R. F. Yerkes and R. O. Castle, "Surface Deformation Associated with Oil and Gas Field Operations in the United States in Land Subsidence," Proceedings of the Tokyo Symposium, Vol. 1, 1ASH/A1HS Unesco, 1969, pp 55-65.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-85 Revision 21 September 2013 23. C. W. Jennings, et al., Geologic Map of California, South Half, scale 1:750,000, California Div. Mines and Geology, 1972.
- 24. John H. Wiggins, Jr., "Effect of Site Conditions on Earthquake Intensity," ASCE Proceedings, Vol. 90, ST2, Part 1, 1964.
- 25. B. M. Page, "Time of Completion of Underthrusting of Franciscan Beneath Great Valley Rocks West of Salinian Block, California," Geol. Soc. Amer., Bull., Vol. 81, 1970, pp 2825-2834.
- 26. Eli A. Silver, "Basin Development Along Translational Continental Margins," W. R. Dickinson (editor), Geologic Interpretations from Global Tectonics with Applications for California Geology and Petroleum Exploration, San Joaquin Geological Society, Short Course, 1974.
- 27. T. W. Dibblee, The Riconada Fault in the Southern Coast Ranges, California, and Its Significance, Unpublished abstract of talk given to the AAPG, Pacific Section, 1972.
- 28. D. L. Durham, "Geology of the Southern Salinas Valley Area, California," U.S. Geol. Survey Prof. Paper 819, 1974, p 111.
- 29. William Gawthrop, Preliminary Report on a Short-term Seismic Study of the San Luis Obispo Region, in May 1973 (Unpublished research paper), 1973.
- 30. S. W. Smith, Analysis of Offshore Seismicity in the Vicinity of the Diablo Canyon Nuclear Power Plant, report to Pacific Gas and Electric Company, 1974.
- 31. H. C. Wagner, "Marine Geology between Cape San Martin and Pt. Sal, South-Central California Offshore; a Preliminary Report, August 1974," USGS Open File Report 74-252, 1974.
- 32. R. E. Wallace, "Earthquake Recurrence Intervals on the San Adreas Fault", Geol. Soc. Amer., Bull., Vol. 81, 1970, pp 1875-2890.
- 33. J. C. Savage and R. O. Burford, "Geodetic Determination of Relative Plate Motion in Central California", Jour. Geophys. Res., Vol. 78, No. 5, 1973, pp 832-845.
- 34. Deleted in Revision 1
- 35. Hill, et al., "San Andreas, Garlock, and Big Pine faults, California" - A Study of the character, history, and significance of their displacements, Geol. Soc. Amer., Bull., Vol. 64, No. 4, 1953, pp 443-458.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-86 Revision 21 September 2013 36. C.A. Hall and C.E. Corbato, "Stratigraphy and Structure of Mesozoic and Cenozoic Rocks, Nipomo Quadrangle, Southern Coast Ranges, California," Geol. Soc. Amer., Bull., Vol. 78, No. 5, 1969, pp 559-582. (Table 2.5-3, Sheet 1 of 2). 37. Bolt, Beranek, and Newman, Inc., Sparker Survey Line, Plates III and IV, 1973/1974. (Appendix 2.5D, to Diablo Canyon Power Plant Final Safety Analysis Report as amended through August 1980). (See also Reference 27 of Section 2.3.)
- 38. R. R. Compton, "Quatenary of the California Coast Ranges," E. H. Bailey (editor), Geology of Northern California, California Division Mines and Geology, Bull. 190, 1966, pp 277-287.
- 39. Regulatory Guide 1.70, Revision 1, Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants, USNRC, October 1972.
- 40. Pacific Gas and Electric Company, Final Report of the Diablo Canyon Long Term Seismic Program, July 1988.
- 41. Pacific Gas and Electric Company, Addendum to the 1988 Final Report of the Diablo Canyon Long Term Seismic Program, February 1991.
- 42. NUREG-0675, Supplement No. 34, Safety Evaluation Report Related to the Operation of Diablo Canyon Nuclear Power Plant, Units 1 and 2, USNRC, June 1991. 43. NRC letter to PG&E, Transmittal of Safety Evaluation Closing Out Diablo Canyon Long-Term Seismic Program, (TAC Nos. M80670 and M80671), April 17, 1992. 44. Pacific Gas and Electric Company, Assessment of Slope Stability Near the Diablo Canyon Power Plant, April 1997.
- 45. Harding Lawson Associates, Liquefaction Evaluation - Proposed ASW Bypass - Diablo Canyon Power Plant, August 23, 1996.
- 46. Harding Lawson Associates Letter, "Geotechnical Consultation - Liquefaction Evaluation - Proposed ASW Bypass - Diablo Canyon Power Plant,"
October 1, 1996.
- 47. Harding Lawson Associates Report, Geotechnical Slope Stability Evaluation - ASW System Bypass, Unit 1 - Diablo Canyon Power Plant, July 3, 1996.
- 48. License Amendment Request 97-11, Submitted to the NRC by PG&E Letters DCL-97-150, dated August 26, 1997; DCL-97-177, dated October 14, 1997; DCL-97-191, dated November 13, 1997; and DCL-98-013, dated January 29, 1998.
DCPP UNITS 1 & 2 FSAR UPDATE 2.5-87 Revision 21 September 2013 49. NRC Letter to PG&E dated March 26, 1999, granting License Amendment No. 131 to Unit 1 and No. 129 to Unit 2. 50. PG&E letter to the NRC, "Benefits and Insights of the Long Term Seismic Program," DCL-91-091, April 17, 1991. 51. John A. Blume and Associates letter to PG&E, "Earthquake Design Criteria for the Nuclear Power Plant - Diablo Canyon Site," January 12, 1967. 52. Pacific Gas and Electric Company, Report on the Analysis of the Shoreline Fault Zone - Central Coastal California, January 2011. 53. NRC Letter to PG&E, "Summary of March 15, 1991 Public Meeting to Discuss Diablo Canyon Long-Term Seismic Program (TAC Nos. 55305 and 68049)", March 22, 1991 54. NRC Office of Nuclear Regulatory Research, "Confirmatory Analysis of Seismic Hazard at the Diablo Canyon Power Plant form the Shoreline Fault Zone," Research Information Letter No. 12-01, September 2012 55. NRC letter to PG&E, "Diablo Canyon Power Plant, Unit Nos. 1 and 2 - NRC Review of Shoreline Fault (TAC Nos. ME5306 and ME5307)," October 12, 2012. 56. Pacific Gas and Electric Company letter to the NRC, "Withdrawal of License Amendment Request 11-05, Evaluation Process for New Seismic Information and Clarifying the Diablo Canyon Power Plant Safe Shutdown Earthquake,: Letter No. DCL-12-103, October 25, 2012. 57. NRC letter to All Power Reactor Licensees and Holders of Construction Permits in Active or Deferred Status, "Request of Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3, and 9.3 of the Near-Term Task Force Review of Insights from the Fukushima Dai-Ichi Accident," Marc 12, 2012.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 14 Novenmber 2001 TABLE 2.1-1 POPULATION TRENDS OF THE STATE OF CALIFORNIA AND OF SAN LUIS OBISPO AND SANTA BARBARA COUNTIES Year State of California San Luis Obispo County Santa Barbara County Notes 1940 6,907,387 33,246 70,555 (a) 1950 10,586,233 51,417 98,220 (a) 1960 15,717,204 81,044 168,962 (a) 1970 19,953,134 105,690 264,324 (a) 1980 23,668,562 155,345 298,660 (a) 1990 29,760,021 217,162 369,608 (a) 2000 33,871,648 246,681 399,347 (a) 2010 40,262,400 323,100 467,700 (b) 2025 48,626,052 426,812 603,966 (c) Notes: (a) U.S. Bureau of the Census (b) State of California Department of Finance (June 2001) (c) State of California Department of Finance Data Files (March 16, 2000) DCPP UNITS 1 & 2 FSAR UPDATE Revision 14 Novenmber 2001 TABLE 2.1-2 GROWTH OF PRINCIPAL COMMUNITIES WITHIN 50 MILES OF DCPP SITE Community Population (1960 Census) Population (1970 Census) Population (1980 Census) Population (1990 Census) Population (2000 Census) Arroyo Grande 3,291 7,454 10,350 14,378 15,851 Atascadero 5,983 10,290 15,930 23,138 26,411 Grover City 5,210 5,939 8,827 11,656 13,067 Guadalupe 2,614 3,145 3,629 5,479 5,659 Lompoc 14,415 25,284 26,267 37,649 41,103 Morro Bay 3,692 7,109 9,064 9,664 10,350 Paso Robles 6,617 7,168 9,163 18,583 24,297 Pismo Beach 1,762 4,043 5,364 7,669 8,551 San Luis Obispo 20,437 28,036 34,253 41,958 44,174 Santa Maria 20,027 32,749 39,685 61,284 77,423
DCPP UNITS 1 & 2 FSAR UPDATE Revision 14 Novenmber 2001 TABLE 2.1-3 POPULATION CENTERS OF 1,000 OR MORE WITHIN 50 MILES OF DCPP SITE
Community County Distance and Direction From the Site Population (1970 Census) Population (1980 Census) Population (1990 Census) Population (2000 Census) Baywood-Los Osos San Luis Obispo 8 miles N 3,487 10,933 15,290 14,351 Morro Bay San Luis Obispo 10 miles N 7,109 9,064 12,949 10,350 San Luis Obispo San Luis Obispo 12 miles ENE 28,036 34,253 51,173 44,174 Pismo Beach San Luis Obispo 13 miles ESE 4,043 5,364 7,699 8,551 Grover City San Luis Obispo 14 miles ESE 5,939 8,827 11,656 13,067 Oceano San Luis Obispo 15 miles ESE 2,564 4,478 6,169 7,260 Arroyo Grande San Luis Obispo 17 miles ESE 7,454 10,350 14,378 15,851 Cayucos San Luis Obispo 17 miles N 1,772 2,301 2,960 2,943 Atascadero San Luis Obispo 21 miles NNE 10,290 15,930 23,138 26,411 Guadalupe Santa Barbara 23 miles SE 3,145 3,629 5,479 5,659 Nipomo San Luis Obispo 24 miles ESE 3,642 5,247 7,109 12,626 Cambria San Luis Obispo 28 miles NNW 1,716 3,061 5,382 6,232 Santa Maria Santa Barbara 29 miles SE 39,878 39,685 61,284 77,423 Paso Robles San Luis Obispo 30 miles NNE 7,168 9,163 18,583 24,297 Orcutt Santa Barbara 33 miles SE 8,500 1,469 ---- 28,830 Vandenberg Santa Barbara 35 miles SSE 13,193 13,975 ---- 11,953 Lompoc Santa Barbara 45 miles SSE 25,284 26,267 37,649 41,103
___________ ___________ ___________ Total 180,793 203,996 280,898 351,081 DCPP UNITS 1 & 2 FSAR UPDATE Revision 14 Novenmber 2001 TABLE 2.1-4 TRANSIENT POPULATION AT RECREATION AREAS WITHIN 50 MILES OF DCPP SITE Names Visitor -Days State Parks (a) Cayucos State Beach 698,000 Hearst San Simeon State Historical Monument 795,000 Montana de Oro State Park 683,000 Morro Bay State Park 1,129,000 Morro Strand State Beach 129,000 Pismo State Beach 1,297,000 San Simeon State Beach 696,000 W. R. Hearst Memorial State Beach 213,000 County and Local Parks (b)
Atascadero Lake 300,000 Avila Beach 800,000 Cambria 15,000 Cayucos Beach 918,000 Cuesta 67,000 Lake Nacimiento 345,000 Lopez Recreation Area 379,000 Los Alamos Park 45,000 Miquelito Park 36,000 Nipomo 168,000 Ocean Park 105,000 Oceano 95,000 Rancho Guadalupe Dunes Park 48,000San Antonio Reservoir 361,000 San Miguel 54,000 Santa Margarita Lake 169,000 Shamel 130,000 Templeton 99,000 Waller 450,000 Name Visitor -Days Los Padres National Forest (c) Agua Escondido 700 American Canyon 800 Balm of Gilead 200 Brookshire Springs 1,600 Buckeye 200 Cerro Alto 15,600 French 200 Frus 700 Hi Mountain 4,800 Horseshoe Springs 1,400 Indians 600 Kerry Canyon 300 La Panza 4,400 Lazy Camp 500 Miranda Pine 2,300 Navajo 2,800 Pine Flat 300 Pine Springs 400 Plowshare Springs 300 Queen Bee 2,200 Stony Creek 1,100 Sulphur Pot 1,000 Upper Lopez 600 Wagon Flat 2,200
(a) California Department of Parks and Recreation (July 1998 through June 1999). (b) County Park Departments.
Monterey County (July 1, 1998 through June 30, 1999). San Luis Obispo and Santa Barbara Counties (July 1998 through June 1999). (c) Los Padres National Forest (July 1, 1971 through June 30, 1972. Current data is no longer compiled.). DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.1-5 1985 LAND USE CENSUS DISTANCES IN MILES FROM THE UNIT 1 CENTERLINE TO THE NEAREST MILK ANIMAL, RESIDENCE, VEGETABLE GARDEN 22-1/2 Degree(a) Radial Sector Nearest Milk Animal Nearest Residence km (mi) Residence Azimuth degree Nearest Vegetable Garden NW None 5.95 (3.7) 326 None NNW None 2.50 (1.55) 333 None N None 7.15 (4.44) 008 None NNE None 5.30 (3.3) 018.5 None NE None 8.15 (5.06) 037 None ENE None 7.15 (4.44) 062.5 None E None 7.25 (4.5) 096.5 None ESE None None -- 2 SE None None -- None (a) Sectors not shown contain no land beyond the site boundary, other than islets not used for the purposes indicated in this table. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-1 PERSISTENCE OF CALM AT DIABLO CANYON EXPRESSED AS PERCENTAGE OF TOTAL HOURLY OBSERVATIONS FOR WHICH THE MEAN HOURLY WIND SPEED WAS LESS THAN 1 MILE PER HOUR FOR MORE THAN 1 TO 10 HOURS Station EConsecutive Hours 25-foot level 250-foot level 1 5.9 4.9 2 3.8 3.1 3 2.5 2.0 4 1.8 1.2 5 1.0 0.7 6 0.7 0.4 7 0.5 0.3 8 0.3 0.2 9 0.2 0.2 10 0.1 0.1 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-2 NORMALIZED ANNUAL GROUND LEVEL CONCENTRATIONS DOWNWIND FROM DCPP SITE GROUND RELEASE Ground Level Release 10-meter wind data and Temperature Gradient (76-10 meters). For calculations with wind speeds below 1.5 meters per second stability is based on Temperature Gradient only and either building wake or wind meander is considered - with wind speed above 1.5 meters per second stability is based on measured Sigma A and Temperature Gradient with building wake only considered. Data Period May 1973 through April 1975. Midpoint of Directions from Plant for each 22.5 degree Sector Dilution Factors /Q x 10-8 sec m-3 Downwind Distance (km) NW NNW N NNE NE ENE E ESE SE 0.8 387.15 220.81 95.726 57.503 61.687 49.292 89.447 355.48 978.67 5.0 24.738 12.860 5.6009 3.2347 3.8566 2.9593 5.0400 21.388 68.029 10.0 9.2115 4.6658 2.0693 1.1535 1.4426 1.0949 1.8138 7.6144 25.269 15.0 5.3897 2.6719 1.2018 0.65477 0.84233 0.63167 1.0391 4.3081 14.651 30.0 2.3889 1.1375 0.52497 0.27935 0.36768 0.27011 0.451451.8261 6.3086 40.0 1.7484 0.82010 0.38341 0.20223 0.26689 0.19464 0.330461.3223 4.5669 50.0 1.3803 0.64135 0.30252 0.15868 0.20947 0.15208 0.261551.0377 3.5778 80.0 0.84914 0.38822 0.18632 0.09654 0.12747 0.09173 0.162220.631132.1699 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-3
MONTHLY MIXING HEIGHTS(a) AT DCPP SITE Month Morning Hours of Day(b) Afternoon Hours of Day(b) Evening Hours of Day(b) Night Hours of Day(b) January 500 9-11 600 12-16 700 17-19 500 20-8 February 600 9-11 600 12-17 800 18-20 600 21-8 March 700 8-10 800 11-17 1,000 18-20 800 21-7 April 600 7-10 700 11-18 800 19-21 700 22-6 May 500 7-11 600 12-20 700 21-23 600 24-6 June 500 7-10 500 11-20 600 21-23 500 24-6 July 500 7-9 500 10-20 700 21-23 500 24-6 August 500 7-9 600 10-20 700 21-23 600 24-6 September 500 8-10 600 11-19 800 20-22 600 23-7 October 500 8-10 600 11-19 800 20-22 500 23-7 November 500 8-10 600 11-17 700 18-20 500 21-7 December 500 9-11 600 12-17 700 18-20 500 21-8
(a) Mixing heights (in meters) derived from seasonal estimates given by Holzworth(6)
(b) Definition of morning, afternoon, evening, and nighttime hours. Hours are inclusive in local time. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-4 ESTIMATES OF RELATIVE CONCENTRATIONS (/Q sec m-3) AT SPECIFIED LOCATIONS DOWNWIND OF DCPP SITE(a, b) Direction From Site Distance, mi /Q (r - ) NW 0.5 3.87 x 10-6 326 3.6 1.71 x 10-7 NW 5.0 1.25 x 10-7 NNW 0.5 2.21 x 10-6 330 1.75 4.28 x 10-7 NNW 5.0 6.37 x 10-8 N 0.5 9.57 x 10-7 N 5.0 2.81 x 10-8 NNE 0.5 5.75 x 10-7 NNE 3.3 2.93 x 10-8 NNE 5.0 1.58 x 10-8 NE 0.5 6.17 x 10-7 035 4.9 1.64 x 10-8 NE 5.0 1.95 x 10-8 ENE 0.7 2.83 x 10-7 ENE 4.7 1.62 x 10-8 ENE 5.0 1.49 x 10-8 E 1.0 2.86 x 10-7 E 3.8 3.70 x 10-8 E 5.0 2.48 x 10-8 ESE 1.0 1.21 x 10-6 ESE 5.0 1.05 x 10-7 SE 1.1 3.10 x 10-6 124 2.0 9.42 x 10-7 SE 5.0 3.43 x 10-7 (a) Based on the models described in Reference 21 and used for Table 2.3-2 (January 1978, Amendment 57) of the DCPP FSAR.
(b) Estimates Involve Wind Data From the 10 Meter Level and Temperature Gradient From the 76m - 10m Levels.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-6 DCPP SITE PRECIPITATION DATA Mean Monthly and Annual Precipitation for Indicated Period of Record Precipitation in Inches -- Record in Years Annual Mean No. Days (a) Precipitation Greater STATIONS JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC MEAN MAX MIN Than 0.09 and 0.49 Morro Bay 2.94 2.72 1.86 1.46 0.22 0.05 0.06 0.01 0.21 0.72 2.65 2.50 15.40 24.12 6.60 31 (10) Years 14 14 14 14 14 14 13 13 13 12 13 13 Pismo Beach 3.79 3.05 2.10 1.92 0.34 0.04 0.06 0.01 0.20 0.46 1.82 2.65 16.44 27.45 6.75 28 (11) Years 11 11 11 11 11 11 12 12 12 12 12 12 San Luis Obispo 4.72 4.12 3.34 1.60 0.51 0.11 0.01 0.02 0.20 0.82 1.72 3.94 21.11 48.76 6.93 30 (14) Years 91 91 91 91 91 91 92 92 92 92 92 92 Santa Maria 2.81 2.50 2.60 1.05 0.39 0.08 0.02 0.02 0.20 0.73 1.18 2.32 13.90 28.46 4.40 25 (7) Years 69 69 69 68 68 68 68 69 69 69 69 69 Santa Margarita 6.04 5.81 5.27 3.25 0.73 0.05 0.06 0.01 0.22 1.03 3.11 6.47 32.05 49.55 7.67 34 (21) Years 20 20 20 20 21 21 21 21 20 21 21 21 Camp San Luis 3.91 3.48 3.29 1.95 0.45 0.05 0.03 0.01 0.13 0.59 2.02 3.62 19.53 29.89 10.29 32 (13) Years 18 18 18 18 18 18 17 18 18 18 18 19 (a) Values shown in parentheses are mean number of days with precipitation amounts greater than 0.49. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-7 DCPP SITE TEMPERATURE DATA Coastal Stations Morro Bay and Pismo Beach. Values Shown in Parentheses are Pismo Beach. Period of Record: Morro Bay 14 years; Pismo Beach 12 years Temperature in F Months Mean Temperature Mean Maximum Mean Minimum Extreme Maximum Extreme Minimum Mean No. of Days Above 90°F Mean No. of Days Below 32°F January 52.6 (51.7) 62.0 (61.3) 43.2 (42.0) 82 (80) 30 (24) 0 (0) 1 (2) February 53.8 (53.7) 63.0 (64.0) 44.6 (43.4) 82 (82) 30 (29) 0 (0) 0 (1) March 53.1 (54.8) 62.5 (65.5) 43.6 (44.0) 85 (88) 32 (30) 0 (0) 0 (1) April 54.1 (56.1) 63.5 (66.1) 44.7 (46.1) 93 (90) 33 (32) 0 (0) 0 (0) May 55.1 (57.3) 62.9 (67.5) 47.3 (47.1) 98 (89) 33 (36) 0 (1) 0 (0) June 57.5 (59.8) 64.4 (69.8) 50.5 (49.7) 98 (96) 40 (40) 0 (0) 0 (0) July 58.2 (60.5) 65.1 (68.7) 51.3 (52.3) 89 (104) 34 (38) 0 (0) 0 (0) August 55.5 (60.6) 66.7 (68.5) 52.7 (52.7) 94 (102) 45 (43) 0 (0) 0 (0) September 60.7 (62.1) 68.8 (71.8) 52.5 (52.3) 101 (99) 43 (41) 1 (1) 0 (0) October 60.8 (60.6) 70.5 (71.3) 51.0 (49.8) 99 (95) 38 (32) 1 (1) 0 (0) November 57.0 (58.3) 66.0 (69.4) 47.8 (47.1) 92 (91) 32 (29) 0 (0) 0 (0) December 52.4 (54.6) 61.6 (65.3) 43.2 (43.9) 79 (92) 29 (28) 0 (0) 1 (1)
Annual 55.9 (57.5) 64.8 (67.4) 47.7 (47.5) 101 (104) 29 (24) 2 (3) 2 (5) Inland Stations San Luis Obispo and Santa Maria. Values Shown in Parenthesis are Santa Maria. Period of Record: San Luis Obispo 66 years; Santa Maria 17 years. Months Mean Temperature Mean Maximum Mean Minimum Extreme Maximum Extreme Minimum Mean No. of Days Above 90°F Mean No. of Days Below 32°F January 51.8 (50.2) 62.1 (62.3) 41.5 (38.2) 84 (82) 20 (21) 0 (0) 1 (4) February 53.6 (51.6) 63.5 (63.3) 43.5 (39.9) 89 (87) 25 (24) 0 (0) 1 (4) March 54.9 (53.0) 65.2 (64.3) 44.8 (41.6) 93 (88) 28 (29) 0 (0) 0 (1) April 56.7 (55.3) 67.6 (66.3) 46.0 (44.3) 97 (97) 30 (31) 0 (0) 0 (0) May 58.6 (57.2) 69.3 (67.7) 47.8 (46.8) 100 (93) 34 (34) 0 (0) 0 (0) June 62.0 (59.8) 73.6 (70.2) 50.2 (49.4) 110 (95) 37 (36) 1 (0) 0 (0) July 64.6 (62.0) 76.9 (71.6) 52.0 (52.4) 106 (104) 42 (43) 2 (0) 0 (0) August 64.7 (61.9) 77.0 (71.5) 52.4 (52.2) 107 (93) 40 (43) 1 (0) 0 (0) September 64.9 (62.7) 77.8 (74.1) 52.0 (51.3) 110 (102) 38 (36) 4 (1) 0 (0) October 62.5 (60.0) 75.3 (72.6) 49.8 (47.4) 103 (103) 35 (30) 2 (1) 0 (0) November 58.3 (55.8) 70.7 (69.7) 45.9 (42.0) 96 (93) 24 (25) 0 (0) 0 (1) December 53.5 (52.2) 64.4 (64.8) 42.8 (39.6) 92 (90) 24 (26) 0 (0) 0 (3) Annual 58.8 (56.8) 70.3 (68.2) 47.4 (45.4) 110 (104) 20 (21) 10 (2) 2 (13) DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Air Weather Service - Directorate of Climatology Surface Winds Data Control Division TABLE 2.3-8
PERCENTAGE FREQUENCY OF OCCURRENCE DIRECTIONS BY SPEED GROUPS
23273 Santa Maria, California WBAS All Station Station Name Month Class Jan 1948 - Jun 1958 Years Total No. of Observations Speed Dir. 1-3 Knots 4-10 Knots 11-21 Knots 22-27 Knots 28-40 Knots 41 Knots and Over Total 4 Knots and Over
%
Obs Sum of Speed Mean Wind Speed, Knots N 0.5 1.1 0.7 1.8 2.2 2095 17809 8.5 NNE 0.3 1.0 0.9 0.1 2.0 2.3 2160 21637 10.0 NE 0.8 1.2 0.5 0.1 1.8 2.6 2412 18236 7.6 ENE 0.5 1.2 0.1 1.3 1.8 1637 8937 5.5 E 1.2 5.2 0.2 5.5 6.7 6230 37649 6.0 ESE 0.8 2.9 0.3 3.3 4.1 3814 24253 6.4 SE 0.8 2.9 0.8 0.1 3.8 4.6 4295 33136 7.7 SSE 0.4 0.9 0.5 1.4 1.8 1644 13935 8.5 S 0.5 0.8 0.2 1.0 1.6 1455 9343 6.4 SSW 0.4 0.7 0.2 0.9 1.3 1205 7848 6.5 SW 0.9 2.0 0.3 2.4 3.3 3119 18690 6.0 WSW 0.9 3.3 0.9 4.2 5.1 4737 34900 7.4 W 1.6 9.4 4.4 0.1 13.8 15.5 14446 127257 8.8 WNW 1.2 9.8 5.4 0.1 15.3 16.5 15458 142383 9.2 NW 0.9 4.5 1.2 5.8 6.7 6221 46750 7.5 NNW 0.3 1.0 0.2 1.1 1.5 1375 9091 6.6 CALM 21.8 20397 TOTALS 12.0 47.9 16.8 0.6 0.1 65.3 100.0 92700 571854 6.1 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Air Weather Service - Directorate of Climatology Surface Winds Data Control Division TABLE 2.3-9
PERCENTAGE FREQUENCY OF OCCURRENCE DIRECTIONS BY SPEED GROUPS
23273 Santa Maria, California WBAS Jan Station Station Name Month Class 48 49 50 51 52 53 54 55 56 57 58 Years Total No. of Observations Speed Dir. 1-3 Knots 4-10 Knots 11-21 Knots 22-27 Knots 28-40 Knots 41 Knots and Over Total 4 Knots and Over
%
Obs. Sum of Speed Mean Wind Speed, Knots N 0.4 1.9 1.4 0.1 3.3 3.7 300 2892 9.6 NNE 0.3 2.2 1.6 0.2 4.0 4.3 350 3671 10.5 NE 0.9 2.3 1.2 0.2 3.8 4.7 383 3408 8.9 ENE 0.7 2.3 0.1 2.4 3.1 254 1476 5.8 E 1.7 10.5 0.5 11.0 12.7 1042 6790 6.5 ESE 1.4 5.6 0.9 6.5 7.9 644 4443 6.9 SE 1.0 6.1 1.8 0.1 8.1 9.1 743 6108 8.2 SSE 0.4 1.3 1.0 0.1 2.4 2.8 229 2209 9.6 S 0.4 1.0 0.4 1.4 1.8 148 1070 7.2 SSW 0.3 0.7 0.4 1.1 1.4 115 964 8.4 SW 0.7 1.4 0.3 1.8 2.5 201 1308 6.5 WSW 0.5 1.6 0.4 1.9 2.4 196 1327 6.8 W 1.1 6.0 1.6 7.6 8.7 712 5493 7.7 WNW 0.7 6.7 1.8 8.5 9.3 757 6090 8.0 NW 0.6 4.0 0.7 4.7 5.4 439 3165 7.2 NNW 0.2 1.5 0.3 1.8 2.0 164 1207 7.4 CALM 18.3 1501 TOTALS 11.4 54.9 14.5 0.8 70.2 100.0 8178 51621 6.3 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Air Weather Service - Directorate of Climatology Surface Winds Data Control Division TABLE 2.3-10 PERCENTAGE FREQUENCY OF OCCURRENCE DIRECTIONS BY SPEED GROUPS 23273 Santa Maria, California WBAS Feb Station Station Name Month Class 48 49 50 51 52 53 54 55 56 57 58 Years Total No. of Observations Speed Dir. 1-3 Knots 4-10 Knots 11-21 Knots 22-27 Knots 28-40 Knots 41 Knots and Over Total 4 Knots and Over
%
Obs. Sum of Speed Mean Wind Speed, Knots N 0.6 2.1 1.6 0.1 3.8 4.4 325 3152 9.7 NNE 0.4 1.4 1.5 0.2 3.1 3.5 259 2822 10.9 NE 0.9 2.2 1.0 3.3 4.2 312 2458 7.9 ENE 0.7 2.4 2.5 3.2 240 1419 5.9 E 1.3 9.6 0.5 10.2 11.5 857 5626 6.6 ESE 1.2 4.6 0.4 0.1 5.1 6.3 472 3078 6.5 SE 1.0 4.5 1.5 0.1 6.0 7.0 524 4300 8.2 SSE 0.3 1.1 1.0 0.1 2.1 2.5 183 1758 9.6 S 0.5 1.0 0.5 1.6 2.0 152 1140 7.5 SSW 0.3 0.9 0.4 1.2 1.5 112 0841 7.5 SW 0.5 1.7 0.4 2.2 2.7 201 1393 6.9 WSW 0.4 2.5 0.6 3.1 3.5 260 1951 7.5 W 0.7 6.9 2.9 0.1 9.8 10.5 787 6984 8.9 WNW 0.7 9.8 10.5 11.3 841 7341 8.7 NW 0.8 4.5 1.0 5.5 6.3 470 3511 7.5 NWW 0.3 5.5 6.3 2.0 2.3 170 1332 7.8 CALM 17.4 1297 TOTALS 10.6 54.4 17.2 0.5 72.0 100.0 7462 49106 6.6 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Air Weather Service- Directorate of Climatology Surface Winds Data Control Division TABLE 2.3-11 PERCENTAGE FREQUENCY OF OCCURRENCE DIRECTIONS BY SPEED GROUPS 23273 Santa Maria, California WBAS Mar Station Station Name Month Class 48 49 50 51 52 53 54 55 56 57 58 Years Total No. of Observations Speed Dir. 1-3 Knots 4-10 Knots 11-21 Knots 22-27 Knots 28-40 Knots 41 Knots and Over Total 4 Knots and Over
%
Obs. Sum of Speed Mean Wind Speed, Knots N 0.5 1.5 0.9 2.4 2.9 239 2069 8.7 NNE 0.4 1.4 1.6 0.1 3.0 3.4 281 2894 10.3 NE 0.8 1.4 0.7 0.1 2.2 3.0 249 2015 8.1 ENE 0.5 1.4 0.0 1.4 1.9 153 807 5.3 E 1.0 6.2 0.2 6.4 7.4 605 3667 6.1 ESE 0.8 4.2 0.5 4.7 5.5 448 3059 6.8 SE 0.9 3.8 1.5 0.2 0.1 5.5 6.4 524 4696 9.0 SSE 0.6 1.2 0.9 0.1 0.1 2.4 3.0 242 2502 10.3 S 0.4 0.8 0.4 1.3 1.7 140 1188 8.5 SSW 0.4 0.8 0.3 0.1 1.2 1.6 129 1029 8.0 SW 0.8 1.9 0.6 2.5 3.3 266 1898 7.1 WSW 0.4 2.9 1.0 4.0 4.4 359 2917 8.1 W 1.1 6.1 4.8 0.2 11.2 12.2 999 10067 10.1 WNW 0.9 8.6 7.4 0.1 16.1 17.0 1391 14436 10.3 NW 0.8 5.3 1.8 7.1 7.9 645 5282 8.2 NNW 0.3 1.3 0.3 1.6 1.8 148 1078 7.3 CALM 16.7 1365 TOTALS 10.4 48.7 22.9 1.0 0.3 73.0 100.0 8183 59504 7.3 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Air Weather Service - Directorate of Climatology Surface Winds Data Control Division TABLE 2.3-12 PERCENTAGE FREQUENCY OF OCCURRENCE DIRECTIONS BY SPEED GROUPS 23273 Santa Maria, California WBAS Apr Station Station Name Month Class 48 49 50 51 52 53 54 55 56 57 58 Years Total No. of Observations Speed Dir. 1-3 Knots 4-10 Knots 11-21 Knots 22-27 Knots 28-40 Knots 41 Knots and Over Total 4 Knots and Over
%
Obs. Sum of Speed Mean Wind Speed, Knots N 0.4 0.9 0.4 1.4 1.7 138 1061 7.7 NNE 0.2 0.7 0.7 1.5 1.7 133 1322 9.9 NE 0.9 0.9 0.2 1.1 2.0 156 822 5.3 ENE 0.4 0.4 0.0 0.4 0.9 68 282 4.1 E 1.1 3.3 0.1 3.4 4.5 356 1814 5.1 ESE 0.6 2.5 0.2 2.7 3.4 266 1564 5.9 SE 0.8 3.2 1.1 0.1 4.4 5.2 409 3269 8.0 SSE 0.5 1.2 0.6 1.9 2.4 188 1543 8.2 S 0.5 1.1 0.4 1.5 1.9 154 1118 7.3 SSW 0.5 0.8 0.3 1.1 1.6 123 870 7.1 SW 0.8 2.8 0.9 3.7 4.4 352 2651 7.5 WSW 0.7 3.2 1.3 4.5 5.1 408 3280 8.0 W 1.7 9.0 5.5 0.2 14.7 16.3 1294 12182 9.4 WNW 1.3 10.5 7.9 0.2 18.7 20.0 1583 15873 10.0 NW 1.0 5.1 1.3 6.4 7.4 587 4502 7.7 NNW 0.3 1.1 0.1 1.2 1.5 117 731 6.2 CALM 20.0 1588 TOTALS 11.4 46.6 21.0 0.7 68.6 100.0 7920 52884 6.7 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Air Weather Service - Directorate of Climatology Surface Winds Data Control Division TABLE 2.3-13 PERCENTAGE FREQUENCY OF OCCURRENCE DIRECTIONS BY SPEED GROUPS 23273 Santa Maria, California WBAS May Station Station Name Month Class 48 49 50 51 52 53 54 55 56 57 58 Years Total No. of Observations Speed Dir. 1-3 Knots 4-10 Knots 11-21 Knots 22-27 Knots 28-40 Knots 41 Knots and Over Total 4 Knots and Over
%
Obs. Sum of Speed Mean Wind Speed, Knots N 0.4 0.5 0.3 0.8 1.2 102 763 7.5 NNE 0.2 0.5 0.2 0.7 0.9 75 509 6.8 NE 0.5 0.7 0.2 0.9 1.3 107 682 6.4 ENE 0.4 0.6 0.7 1.1 87 421 4.8 E 0.7 2.2 2.2 3.0 244 1298 5.3 ESE 0.7 1.4 0.1 1.4 2.1 173 898 5.2 SE 0.7 1.6 0.1 1.7 2.5 201 1128 5.6 SSE 0.3 0.6 0.1 0.7 1.0 83 508 6.1 S 0.7 0.9 0.2 1.1 1.8 146 850 5.8 SSW 0.5 1.1 0.2 1.2 1.7 139 820 5.9 SW 1.0 2.8 0.4 3.3 4.3 352 2071 5.9 WSW 1.1 4.4 2.0 6.5 7.5 615 5056 8.2 W 1.6 10.7 7.7 0.3 18.7 20.3 1664 16546 9.9 WNW 1.3 11.7 7.9 0.2 19.9 21.1 1730 16949 9.8 NW 1.0 4.3 1.8 6.1 7.1 581 4684 8.1 NNW 0.4 0.7 0.1 0.8 1.2 95 511 5.4 CALM 21.9 1789 TOTALS 11.5 44.6 21.5 0.6 66.7 100.0 8183 53694 6.6 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Air Weather Service - Directorate of Climatology Surface Winds Data Control Division TABLE 2.3-14 PERCENTAGE FREQUENCY OF OCCURRENCE DIRECTIONS BY SPEED GROUPS 23273 Santa Maria, California WBAS June Station Station Name Month Class 48 49 50 51 52 53 54 55 56 57 58 Years Total No. of Observations Speed Dir. 1-3 Knots 4-10 Knots 11-21 Knots 22-27 Knots 28-40 Knots 41 Knots and Over Total 4 Knots and Over
%
Obs. Sum of Speed Mean Wind Speed, Knots N 0.4 0.5 0.1 0.5 0.9 73 361 4.9 NNE 0.2 0.2 0.2 0.4 0.6 49 378 7.7 NE 0.5 0.4 0.1 0.5 1.0 83 455 5.5 ENE 0.3 0.2 0.2 0.5 43 160 3.7 E 1.0 1.3 1.4 2.3 185 780 4.2 ESE 0.4 0.6 0.6 1.0 78 326 4.2 SE 0.6 1.1 1.1 1.7 133 610 4.6 SSE 0.3 0.4 0.4 0.6 51 241 4.7 S 0.5 0.6 0.7 1.1 89 414 4.7 SSW 0.4 0.7 0.1 0.9 1.2 97 596 6.1 SW 1.4 2.7 0.4 3.1 4.5 357 2029 5.7 WSW 0.9 3.9 1.8 5.8 6.7 528 4395 8.3 W 2.1 12.3 8.0 0.1 20.4 22.5 1782 16856 9.5 WNW 1.7 13.5 10.0 0.2 23.6 25.3 2004 19743 9.9 NW 0.9 4.9 1.8 6.7 7.6 605 4861 8.0 NNW 0.3 0.3 0.1 0.4 0.7 52 290 5.6 CALM 21.6 1710 TOTALS 11.8 43.9 22.6 0.3 66.6 100.0 7919 52495 6.6 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Air Weather Service - Directorate of Climatology Surface Winds Data Control Division TABLE 2.3-15 PERCENTAGE FREQUENCY OF OCCURRENCE DIRECTIONS BY SPEED GROUPS 23273 Santa Maria, California WBAS July Station Station Name Month Class 48 49 50 51 52 53 54 55 56 57 58 Years Total No. of Observations Speed Dir. 1-3 Knots 4-10 Knots 11-21 Knots 22-27 Knots 28-40 Knots 41 Knots and Over Total 4 Knots and Over
%
Obs. Sum of Speed Mean Wind Speed, Knots N 0.5 0.6 0.6 1.1 89 352 4.0 NNE 0.3 0.4 0.4 0.7 58 246 4.2 NE 0.4 0.5 0.5 0.9 74 277 3.7 ENE 0.3 0.2 0.2 0.5 40 146 3.7 E 0.4 0.7 0.7 1.2 96 403 4.2 ESE 0.3 0.3 0.3 0.6 52 196 3.8 SE 0.3 0.7 0.7 1.0 84 370 4.4 SSE 0.1 0.3 0.3 0.5 38 175 4.6 S 0.5 0.5 0.5 1.0 83 314 3.8 SSW 0.5 0.5 0.5 1.0 82 334 4.1 SW 1.3 2.1 0.1 2.2 3.5 285 1410 4.9 WSW 1.6 4.3 0.6 4.9 6.5 533 3422 6.4 W 2.7 14.5 5.6 20.1 22.8 1863 15557 8.4 WNW 2.2 14.4 6.7 21.1 23.3 1906 16377 8.6 NW 1.2 5.2 1.5 6.7 7.9 646 4697 7.3 NNW 0.4 0.5 0.5 0.9 76 313 4.1 CALM 26.6 2177 TOTALS 12.9 45.8 14.6 60.4 100.0 8182 44589 5.4 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Air Weather Service - Directorate of Climatology Surface Winds Data Control Division TABLE 2.3-16 PERCENTAGE FREQUENCY OF OCCURRENCE DIRECTIONS BY SPEED GROUPS 23273 Santa Maria, California WBAS Aug Station Station Name Month Class 48 49 50 51 52 53 54 55 56 57 Years Total No. of Observations Speed Dir. 1-3 Knots 4-10 Knots 11-21 Knots 22-27 Knots 28-40 Knots 41 Knots and Over Total 4 Knots and Over
%
Obs. Sum of Speed Mean Wind Speed, Knots N 0.5 0.6 0.6 1.1 79 311 3.9 NNE 0.2 0.2 0.2 0.5 36 140 3.9 NE 0.5 0.4 0.4 0.9 64 228 3.6 ENE 0.3 0.5 0.5 0.7 55 235 4.3 E 0.4 0.7 0.7 1.1 83 354 4.3 ESE 0.3 0.6 0.6 0.9 69 287 4.2 SE 0.5 1.2 1.2 1.7 128 578 4.5 SSE 0.4 0.5 0.5 0.9 68 286 4.2 S 0.7 0.6 0.6 1.2 91 348 3.8 SSW 0.4 0.5 0.5 0.9 67 274 4.1 SW 1.5 3.2 0.1 3.3 4.8 356 1755 4.9 WSW 1.5 5.2 1.1 6.3 7.8 579 4012 6.9 W 2.1 14.9 5.5 20.4 22.5 1676 14120 8.4 WNW 1.1 12.5 4.8 17.3 18.4 1369 11893 8.7 NW 1.1 4.7 1.2 5.9 7.0 522 3765 7.2 NNW 0.4 0.4 0.4 0.8 60 251 4.2 CALM 28.7 2132 TOTALS 11.8 46.7 12.8 59.5 100.0 7434 38837 5.2 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Air Weather Service - Directorate of Climatology Surface Winds Data Control Division TABLE 2.3-17 PERCENTAGE FREQUENCY OF OCCURRENCE DIRECTIONS BY SPEED GROUPS 23273 Santa Maria, California WBAS Sept Station Station Name Month Class 48 49 50 51 52 53 54 55 56 57 Years Total No. of Observations Speed Dir. 1-3 Knots 4-10 Knots 11-21 Knots 22-27 Knots 28-40 Knots 41 Knots and Over Total 4 Knots and Over
%
Obs. Sum of Speed Mean Wind Speed, Knots N 0.6 0.5 0.1 0.7 1.2 89 474 5.3 NNE 0.5 0.5 0.1 0.7 1.2 85 461 5.4 NE 0.7 0.8 0.1 0.9 1.6 118 574 4.9 ENE 0.3 0.7 0.8 1.1 77 379 4.9 E 0.9 2.3 2.4 3.3 239 1191 5.0 ESE 0.7 1.4 1.4 2.1 154 716 4.6 SE 1.0 1.6 1.7 2.6 189 874 4.6 SSE 0.3 0.6 0.6 1.0 69 320 4.6 S 0.6 0.8 0.8 1.4 101 436 4.3 SSW 0.5 0.5 0.5 1.0 71 309 4.4 SW 1.2 2.1 0.1 2.2 3.4 244 1240 5.1 WSW 1.3 4.4 0.9 5.3 6.6 473 3287 6.9 W 2.1 12.7 4.6 0.1 17.3 19.4 1394 11723 8.4 WNW 1.3 10.3 5.0 0.1 15.4 16.7 1202 10714 8.9 NW 1.1 4.3 0.9 5.2 6.3 452 3068 6.8 NNW 0.5 0.5 0.5 1.0 74 342 4.6 CALM 30.1 2166 TOTALS 13.6 44.0 12.1 0.2 56.3 100.0 7197 36108 5.0 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Air Weather Service - Directorate of Climatology Surface Winds Data Control Division TABLE 2.3-18 PERCENTAGE FREQUENCY OF OCCURRENCE DIRECTIONS BY SPEED GROUPS 23273 Santa Maria, California WBAS Oct Station Station Name Month Class 48 49 50 51 52 53 54 55 56 57 Years Total No. of Observations Speed Dir. 1-3 Knots 4-10 Knots 11-21 Knots 22-27 Knots 28-40 Knots 41 Knots and Over Total 4 Knots and Over
%
Obs. Sum of Speed Mean Wind Speed, Knots N 0.4 0.7 0.5 1.2 1.6 119 1046 8.8 NNE 0.4 0.9 0.6 0.1 1.7 2.1 157 1466 9.3 NE 1.1 1.4 0.7 0.1 2.2 3.3 247 1775 7.2 ENE 0.5 1.3 1.3 1.8 132 736 5.6 E 1.7 6.0 0.2 6.3 8.0 592 3348 5.7 ESE 1.2 3.4 0.1 3.5 4.7 347 1921 5.5 SE 0.9 3.3 0.3 3.6 4.5 335 2030 6.1 SSE 0.4 0.8 0.2 1.0 1.4 102 679 6.7 S 0.5 0.7 0.3 1.0 1.5 112 726 6.5 SSW 0.5 0.5 0.2 0.7 1.1 84 496 5.9 SW 1.1 1.8 0.2 1.9 3.0 223 1173 5.3 WSW 1.0 3.2 0.7 3.9 4.9 363 2503 6.9 W 2.1 9.1 3.7 12.8 15.0 1112 9125 8.2 WNW 1.3 8.6 4.8 0.2 13.6 14.9 1109 10269 9.3 NW 0.9 4.2 1.0 5.2 6.1 454 3204 7.1 NNW 0.3 0.6 0.1 0.7 1.1 79 470 5.9 CALM 25.0 1856 TOTALS 14.3 46.5 13.7 0.5 0.0 60.7 100.0 7423 40967 5.5 ____________________________________________________________________________________________________________________ _ DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Air Weather Service - Directorate of Climatology Surface Winds Data Control Division TABLE 2.3-19 PERCENTAGE FREQUENCY OF OCCURRENCE DIRECTIONS BY SPEED GROUPS 23273 Santa Maria, California WBAS Nov Station Station Name Month Class 48 49 50 51 52 53 54 55 56 57 Years Total No. of Observations Speed Dir. 1-3 Knots 4-10 Knots 11-21 Knots 22-27 Knots 28-40 Knots 41 Knots and Over Total 4 Knots and Over
%
Obs. Sum of Speed Mean Wind Speed, Knots N 0.5 1.4 1.2 0.1 2.6 3.1 224 2109 9.4 NNE 0.5 1.7 1.7 0.3 3.7 4.2 302 3374 11.2 NE 0.8 1.8 0.8 0.4 0.2 3.2 4.0 288 2840 9.9 ENE 0.7 2.1 2.1 2.8 204 1125 5.5 E 2.1 10.2 0.6 10.8 13.0 933 6008 6.4 ESE 1.1 5.3 0.8 6.1 7.2 516 3491 6.8 SE 1.0 3.9 0.9 0.2 5.0 6.0 433 3400 7.9 SSE 0.5 1.0 0.5 1.5 2.1 148 1190 8.0 S 0.5 0.9 0.3 1.2 1.7 120 795 6.6 SSW 0.4 0.5 0.3 0.9 1.3 96 733 .6 SW 0.6 1.0 0.3 1.3 2.0 141 947 .7 WSW 0.6 2.1 0.3 2.4 3.0 219 1418 6.5 W 1.4 6.6 1.4 8.1 9.4 678 5104 7.5 WNW 1.1 7.6 3.3 10.9 12.1 868 7440 8.6 NW 0.7 3.9 0.7 4.6 5.3 379 2732 7.2 NNW 0.3 1.4 0.4 1.8 2.1 148 1127 7.6 CALM 20.7 1490 TOTALS 13.0 51.4 13.7 0.9 0.2 66.3 100.0 7187 43833 6.1 ____________________________________________________________________________________________________________________ _ DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Air Weather Service - Directorate of Climatology Surface Winds Data Control Division TABLE 2.3-20 PERCENTAGE FREQUENCY OF OCCURRENCE DIRECTIONS BY SPEED GROUPS 23273 Santa Maria, California WBAS Dec Station Station Name Month Class 48 49 50 51 52 53 54 55 56 57 Years Total No. of Observations Speed Dir. 1-3 Knots 4-10 Knots 11-21 Knots 22-27 Knots 28-40 Knots 41 Knots and Over Total 4 Knots and Over
%
Obs. Sum of Speed Mean Wind Speed, Knots N 0.5 2.0 1.6 0.1 3.8 4.3 318 3219 10.1 NNE 0.4 1.9 2.4 0.3 0.1 4.6 5.0 375 4354 11.6 NE 1.1 2.1 1.1 0.2 3.3 4.5 331 2702 8.2 ENE 1.0 2.6 0.2 2.8 3.8 284 1751 6.2 E 2.4 10.5 0.6 11.1 13.4 998 6370 6.4 ESE 1.3 5.6 1.1 6.7 8.0 595 4274 7.2 SE 0.9 4.5 2.1 0.3 0.1 7.1 8.0 592 5773 9.8 SSE 0.5 1.4 1.1 0.2 0.1 2.8 3.3 243 2524 10.4 S 0.5 0.8 0.3 1.1 1.6 119 944 7.9 SSW 0.4 0.6 0.2 0.8 1.2 90 582 6.5 SW 0.6 1.0 0.2 1.3 1.9 141 815 5.8 WSW 0.7 1.7 0.4 2.1 2.7 204 1332 6.5 W 1.1 4.4 1.0 5.4 6.5 485 3500 7.2 WNW 1.0 6.8 1.6 8.4 9.4 698 5358 7.7 NW 0.7 4.4 0.8 5.2 5.9 441 3279 7.4 NNW 0.4 1.8 0.4 2.2 2.6 192 1439 7.5 CALM 17.8 1326 TOTALS 13.5 52.2 15.0 1.2 0.3 68.7 100.0 7432 48216 6.5 ____________________________________________________________________________________________________________________ ____________ DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-21 EXTREMELY UNSTABLE (T less than -1.9°C/100M) DIABLO CANYON PERIOD OF RECORD JULY 1967-OCTOBER 1969 FREQUENCY TABLE Wind Speed, mph Row Row Direction Calm 2.0 5.1 9.6 15.1 21.1 39.6 Sums Avg CALM 3 0 0 0 0 0 0 3 0.0 22.50 0 1 7 6 0 0 0 14 7.4 45.00 0 0 1 3 1 0 0 5 9.6 67.50 0 0 0 0 0 0 0 0 0.0 90.00 0 1 2 0 0 0 0 3 3.7 112.50 0 0 1 3 11 12 9 36 19.9 135.00 0 2 3 12 24 12 14 67 17.6 157.50 0 2 5 7 6 10 4 34 15.7 180.00 0 3 5 5 4 7 3 27 13.2 202.50 0 0 2 4 1 0 0 7 9.3 225.00 0 1 1 3 3 0 0 8 10.4 247.50 0 13 1 1 3 0 0 18 4.8 270.00 0 15 7 1 3 0 0 26 4.7 292.50 0 3 12 6 12 2 0 35 10.2 315.00 0 2 4 24 39 24 7 100 16.0 337.50 0 0 1 6 6 5 3 21 16.3 360.00 0 0 1 1 2 0 0 4 11.0 ______ _____ ____ _____ _____ ______ _____ _____ _____ Column Sums 3 43 53 82 15 72 40 408 13.9 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-22 MODERATELY UNSTABLE (T -1.9 to -1.7°C/100M) DIABLO CANYON PERIOD OF RECORD JULY 1967-OCTOBER 1969 FREQUENCY TABLE Wind Speed, mph Row Row Direction Calm 2.0 5.1 9.6 15.1 21.1 39.6 Sums Avg CALM 5 0 0 0 0 0 0 5 0.0 22.50 0 0 1 1 0 0 0 2 8.0 45.00 0 0 0 2 0 0 0 2 10.0 67.50 0 0 0 1 0 0 0 1 12.0 90.00 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 1 4 1 0 6 15.5 135.00 0 1 1 3 2 0 1 8 13.0 157.50 0 0 3 4 0 0 8 15 21.3 180.00 0 2 0 2 1 1 2 8 14.2 202.50 0 1 1 0 0 0 0 2 4.5 225.00 0 7 0 2 1 0 0 10 4.5 247.50 0 2 0 0 0 0 0 2 2.5 270.00 0 3 5 0 0 0 0 8 3.7 292.50 0 0 2 5 6 0 0 13 11.8 315.00 0 2 3 5 12 4 1 27 13.9 337.50 0 0 2 0 2 1 0 5 12.8 360.00 0 0 1 1 0 0 0 2 9.0 ______ _____ _____ _____ _______ _____ _____ ____ ______ Column Sums 5 18 19 27 28 7 12 116 11.9 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-23 SLIGHTLY UNSTABLE (T -1.7 to -1.5°C/100M) DIABLO CANYON PERIOD OF RECORD JULY 1967-OCTOBER 1969 FREQUENCY TABLE Wind Speed, mph Row Row Direction Calm 2.0 5.1 9.6 15.1 21.1 39.6 Sums Avg CALM 6 0 0 0 0 0 0 6 0.0 22.50 0 0 0 1 1 0 0 2 13.0 45.00 0 1 0 1 0 0 0 2 6.5 67.50 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0.0 135.00 0 1 2 1 5 5 1 15 15.5 157.50 0 2 10 2 1 1 4 20 13.1 180.00 0 1 0 0 1 0 1 3 18.0 202.50 0 0 1 1 0 0 0 2 6.5 225.00 0 3 0 0 0 0 0 3 1.7 247.50 0 2 1 0 0 0 0 3 3.0 270.00 0 2 5 0 1 2 0 10 8.9 292.50 0 1 2 11 0 1 2 17 11.4 315.00 0 0 1 5 8 9 2 25 17.4 337.50 0 0 0 2 0 0 0 2 12.0 360.00 0 0 0 0 0 0 0 0 0.0 ______ _____ _____ _____ ______ _____ _____ ____ ______ Colum n Sums 6 13 22 24 17 18 10 110 12.3 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-24 NEUTRAL (T -1.5 to -0.5°C/100M) DIABLO CANYON PERIOD OF RECORD JULY 1967-OCTOBER 1969 FREQUENCY TABLE Wind Speed, mph Row Row Direction Calm 2.0 5.1 9.6 15.1 21.1 39.6 Sums Avg CALM 290 2 0 0 0 0 0 292 0.0 22.50 0 24 36 40 17 4 0 121 8.1 45.00 0 20 35 39 17 1 0 112 8.0 67.50 0 23 20 33 6 0 0 82 6.8 90.00 0 25 18 6 3 0 0 52 4.6 112.50 0 32 51 60 53 9 1 206 9.4 135.00 0 171 284 203 157 54 17 886 8.9 157.50 0 182 155 61 29 23 13 463 6.5 180.00 0 126 46 21 22 17 9 241 6.9 202.50 0 79 16 11 6 6 0 120 4.9 225.00 0 87 12 5 8 2 0 114 3.5 247.50 0 95 20 1 2 3 0 121 3.0 270.00 0 126 96 17 1 4 0 244 4.1 292.50 0 110 223 187 104 28 4 656 8.5 315.00 0 67 242 530 652 308 143 1942 14.2 337.50 0 42 97 210 160 98 80 687 13.9 360.00 0 41 5 63 53 6 0 218 8.7 ______ ______ _____ _____ _____ ______ _____ _____ ____ Column Sums 290 1252 1406 1487 1290 563 269 6557 9.8 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-25 SLIGHTLY STABLE (T -0.5 to 1.5°C/100M) DIABLO CANYON PERIOD OF RECORD JULY 1967-OCTOBER 1969 FREQUENCY TABLE Wind Speed, mph Row Row Direction Calm 2.0 5.1 9.6 15.1 21.1 39.6 Sums Avg CALM 405 12 0 0 0 0 0 417 0.0 22.50 0 66 92 96 58 14 2 328 8.7 45.00 0 53 94 66 29 1 0 243 6.9 67.50 0 42 58 35 21 2 0 158 6.7 90.00 0 84 40 13 4 0 0 141 3.8 112.50 0 128 57 25 9 5 0 224 4.5 135.00 0 296 279 164 47 11 5 802 5.9 157.50 0 330 129 16 1 0 4 480 3.0 180.00 0 188 16 2 1 3 1 211 2.2 202.50 0 94 13 2 0 0 0 109 1.9 225.00 0 91 12 4 3 0 0 110 2.7 247.50 0 83 16 1 0 0 0 100 2.2 270.00 0 158 33 5 3 0 0 199 2.6 292.50 0 166 154 132 99 44 12 607 8.5 315.00 0 161 344 454 497 479 304 2239 14.9 337.50 0 97 136 159 97 62 35 586 10.7 360.00 0 99 123 130 78 20 4 454 8.5 _______ _____ _____ _____ ______ _____ _____ _____ ______ Column Sums 405 2148 1596 1304 947 641 367 7408 8.6 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-26 MODERATELY STABLE (T 1.5 to 4.0°C/100M) DIABLO CANYON PERIOD OF RECORD JULY 1967-OCTOBER 1969 FREQUENCY TABLE Wind Speed, mph Row Row Direction Calm 2.0 5.1 9.6 15.1 21.1 39.6 Sums Avg CALM 117 1 0 0 0 0 0 118 0.0 22.50 0 9 9 5 6 2 0 31 8.0 45.00 0 12 10 3 3 0 0 28 5.1 67.50 0 12 6 4 1 1 0 24 5.6 90.00 0 20 12 2 0 0 0 34 3.0 112.50 0 33 16 5 0 0 0 54 3.4 135.00 0 54 52 25 2 0 0 133 4.6 157.50 0 68 17 1 0 0 0 86 2.3 180.00 0 35 6 0 0 0 0 41 1.8 202.50 0 20 0 1 0 0 0 21 1.8 225.00 0 18 3 0 0 0 0 21 2.0 247.50 0 30 2 0 0 0 0 32 1.7 270.00 0 34 4 1 0 0 0 39 2.5 292.50 0 38 28 28 8 4 3 109 7.2 315.00 0 43 65 114 167 179 170 738 17.3 337.50 0 20 39 25 15 13 0 112 8.7 360.00 0 20 14 11 7 3 0 55 6.9 ______ _____ _____ _____ _______ _____ _____ _____ ______ Column Sums 117 467 283 225 209 202 173 1676 10.1 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-27 EXTREMELY STABLE (T greater than 4.0°C/100M) DIABLO CANYON PERIOD OF RECORD JULY 1967-OCTOBER 1969 FREQUENCY TABLE Wind Speed, mph Row Row Direction Calm 2.0 5.1 9.6 15.1 21.1 39.6 Sums Avg CALM 46 0 0 0 0 0 0 46 0.0 22.50 0 9 8 6 0 0 0 23 5.2 45.00 0 8 13 3 0 0 0 24 4.6 67.50 0 11 7 1 0 0 0 19 3.5 90.00 0 13 10 1 0 0 0 24 3.7 112.50 0 14 6 1 0 0 0 21 3.3 135.00 0 36 11 2 0 0 0 49 2.9 157.50 0 23 7 1 0 0 0 31 2.8 180.00 0 29 2 0 0 0 0 31 1.5 202.50 0 13 1 0 0 0 0 14 1.7 225.00 0 12 1 0 0 0 0 13 1.6 247.50 0 13 1 0 0 0 0 14 2.2 270.00 0 22 6 2 0 0 0 30 3.0 292.50 0 12 19 14 4 3 0 52 7.4 315.00 0 19 32 73 87 94 95 400 17.7 337.50 0 16 16 12 9 6 0 59 8.5 360.00 0 9 12 5 2 0 0 28 5.7 ______ _____ _____ _____ _______ _____ _____ _____ ______ Column Sums 46 259 152 121 102 103 95 878 10.3 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-28 DISTRIBUTION OF WIND SPEED OBSERVATIONS BY STABILITY CLASS Stability Class T, °C/100M Number of Observations Extremely unstable Less than -1.9 3
Moderately unstable -1.9 to -1.7 5
Slightly unstable -1.7 to -1.5 6
Neutral -1.5 to -0.5 290
Slightly stable -0.5 to 1.5 405
Moderately stable 1.5 to 4.0 117
Extremely stable Greater than 4.0 46 (a) Observations for which the mean hourly wind speed was less than one mile per hour when stability is defined by vertical temperature gradient between the 25-foot levels at Station E period of record July 1, 1967 through October 31, 1969. (b) Total hourly observations for period of record: 17,153. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-29 DCPP SITE - STATION E 25-FOOT LEVEL OCTOBER 1969 THROUGH MARCH 1971 AND APRIL 1972 THROUGH SEPTEMBER 1972 VERTICAL ANGLE STABILITY CLASS A Direction, deg. Wind Speed, mph Row Sum Row Avg. 1.5 5.5 10.0 15.5 21.5 37.5 Calm 2 0 0 0 0 0 2 0.0 22.5 106 185 63 14 1 0 369 5.6 45.0 127 152 71 12 1 0 363 5.3 67.5 77 69 44 9 0 0 199 5.3 90.0 101 47 16 7 2 0 173 4.1 112.5 97 25 17 11 4 0 144 3.9 135.0 178 111 27 10 3 0 329 4.2 157.5 185 168 22 1 0 0 376 3.9 180.0 209 64 5 1 0 0 279 3.0 202.5 117 19 1 0 0 0 137 2.2 225.0 83 10 1 1 0 0 95 2.0 247.5 90 15 2 1 0 0 108 2.2 270.0 126 23 9 1 0 0 159 2.7 292.5 164 98 60 18 5 3 348 5.6 315.0 108 166 126 64 13 1 478 7.7 337.5 79 126 119 66 15 3 408 8.2 360.0 91 215 146 32 4 0 488 6.8 Column _____ _____ ___ ___ __ _ _____ Sums 1,940 1,493 729 238 48 7 4,455 5.7
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-30 DCPP SITE - STATION E 25-FOOT LEVEL OCTOBER 1969 THROUGH MARCH 1971 AND APRIL 1972 THROUGH SEPTEMBER 1972 VERTICAL ANGLE STABILITY CLASS B Direction, deg. Wind Speed, mph Row Sum Row Avg. 1.5 5.5 10.0 15.5 21.5 37.5 Calm 2 0 0 0 0 0 2 0.0 22.5 32 43 27 12 4 1 119 7.1 45.0 44 55 28 3 0 0 130 5.5 67.5 33 20 18 9 0 0 80 5.9 90.0 46 18 8 2 1 1 76 4.4 112.5 52 19 32 27 6 0 136 7.8 135.0 107 152 104 57 11 1 432 7.4 157.5 94 127 52 10 2 3 288 5.6 180.0 59 47 6 0 0 0 112 3.6 202.5 24 7 0 0 0 0 31 2.4 225.0 19 8 1 0 0 0 28 2.5 247.5 23 6 1 0 0 0 30 2.4 270.0 48 7 2 0 0 0 57 2.5 292.5 74 90 47 33 16 3 263 7.6 315.0 52 143 156 110 65 19 545 11.1 337.5 43 81 102 98 58 8 390 11.5 360.0 32 92 64 21 7 0 216 7.6 Column ___ ___ ___ ___ ___ ___ _____ ___ Sums 784 915 648 382 170 36 2,935 7.9
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-31 DCPP SITE - STATION E 25-FOOT LEVEL OCTOBER 1969 THROUGH MARCH 1971 AND APRIL 1972 THROUGH SEPTEMBER 1972 VERTICAL ANGLE STABILITY CLASS C Direction, deg. Wind Speed, mph Row Sum Row Avg. 1.5 5.5 10.0 15.5 21.5 37.5 Calm 2 0 0 0 0 0 2 0.0 22.5 7 12 8 2 1 0 30 7.1 45.0 24 24 6 4 0 0 58 5.3 67.5 19 17 10 5 0 0 51 5.6 90.0 18 6 3 6 0 1 34 6.2 112.5 34 4 19 16 6 3 82 8.8 135.0 76 102 134 63 29 9 413 9.3 157.5 55 96 56 20 6 0 233 6.7 180.0 21 18 2 3 1 1 46 5.4 202.5 10 4 4 0 0 0 17 3.5 225.0 8 6 0 0 0 0 14 3.5 247.5 15 4 0 0 0 0 19 2.5 270.0 32 23 4 0 1 1 61 4.3 292.5 29 94 76 73 43 2 317 10.8 315.0 49 222 388 445 390 148 1,642 15.0 337.5 35 65 114 123 93 28 458 13.6 360.0 14 27 12 7 3 0 63 7.3 Column ____ ___ ___ ___ ___ ___ _____ ____ Sums 448 724 836 767 573 192 3,540 12.0
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-32 DCPP SITE - STATION E 25-FOOT LEVEL OCTOBER 1969 THROUGH MARCH 1971 AND APRIL 1972 THROUGH SEPTEMBER 1972 VERTICAL ANGLE STABILITY CLASS D Direction, deg. Wind Speed, mph Row Sum Row Avg. 1.5 5.5 10.0 15.5 21.5 37.5 Calm 2 0 0 0 0 0 2 0.0 22.5 1 5 0 0 0 0 6 4.5 45.0 16 4 1 0 0 0 21 3.1 67.5 9 5 4 5 1 0 24 9.7 90.0 15 4 3 0 1 0 23 5.4 112.5 31 5 2 2 0 0 40 4.5 135.0 63 40 15 8 4 5 135 5.9 157.5 30 17 12 5 2 0 66 5.7 180.0 8 4 1 2 1 0 16 6.1 202.5 7 1 0 0 0 0 8 1.6 225.0 4 4 0 1 0 0 9 5.2 247.5 6 5 1 0 0 0 12 3.7 270.0 22 6 4 2 3 0 37 5.5 292.5 14 43 55 55 40 12 219 12.7 315.0 31 181 369 556 463 271 1,871 16.5 337.5 16 33 69 85 63 50 316 15.6 360.0 3 11 9 0 0 0 23 6.5 Column ___ ___ ___ ___ ___ ___ _____ ____ Sums 278 368 545 721 578 338 2,828 14.5
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-33 DCPP SITE - STATION E 25-FOOT LEVEL OCTOBER 1969 THROUGH MARCH 1971 AND APRIL 1972 THROUGH SEPTEMBER 1972 VERTICAL ANGLE STABILITY CLASS E Direction, deg. Wind Speed, mph Row Sum Row Avg. 1.5 5.5 10.0 15.5 21.5 37.5 Calm 1 0 0 0 0 0 1 0.0 22.5 0 1 0 0 0 0 1 4.0 45.0 2 1 1 0 0 0 4 3.8 67.5 0 2 3 0 0 0 5 7.6 90.0 0 0 0 0 0 0 0 0.0 112.5 10 1 0 0 0 0 11 1.9 135.0 15 3 0 0 0 0 18 2.3 157.5 7 2 1 0 2 0 12 2.8 180.0 4 1 0 0 0 0 5 2.4 202.5 2 0 0 1 0 0 3 5.3 225.0 2 2 0 0 0 0 4 3.3 247.5 2 3 1 0 0 0 6 4.6 270.0 1 0 1 1 0 0 3 8.3 292.5 2 8 8 4 11 8 41 15.8 315.0 8 30 42 105 111 47 343 17.3 337.5 3 3 5 4 2 3 20 13.2 360.0 0 0 1 0 0 0 1 8.0 Column __ __ __ ___ ___ __ ___ ____ Sums 59 57 63 115 126 58 478 14.8
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-34 DCPP SITE - STATION E 25-FOOT LEVEL OCTOBER 1969 THROUGH MARCH 1971 AND APRIL 1972 THROUGH SEPTEMBER 1972 VERTICAL ANGLE STABILITY CLASS F AND G Direction, deg. Wind Speed, mph Row Avg. Row Sum 1.5 5.5 10.0 15.5 21.5 37.5 Calm 516 0 0 0 0 0 516 0.0 22.5 5 0 0 0 0 0 5 1.2 45.0 5 1 0 0 0 0 6 2.5 67.5 11 0 0 0 0 0 11 1.7 90.0 8 1 0 0 0 0 9 1.4 112.5 15 0 0 0 0 0 15 1.6 135.0 55 3 0 0 0 0 58 1.7 157.5 32 2 1 0 0 0 35 1.9 180.0 19 0 1 0 0 0 20 1.9 202.5 11 0 0 0 0 0 11 1.4 225.0 8 0 0 0 0 0 8 1.3 247.5 11 0 0 0 0 0 11 1.0 270.0 17 0 0 0 0 0 17 1.3 292.5 9 5 5 0 2 0 22 6.5 315.0 21 18 25 32 27 15 138 13.4 337.5 15 3 4 4 2 0 28 4.8 360.0 11 4 0 0 0 0 15 2.7 Column ___ __ __ __ __ __ ___ ___ Sums 769 37 36 36 31 15 925 2.7
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-35 DCPP SITE - STATION E 25-FOOT LEVEL OCTOBER 1969 THROUGH MARCH 1971 AND APRIL 1972 THROUGH SEPTEMBER 1972 AZIMUTH ANGLE STABILITY CLASS A Direction, deg. Wind Speed, mph Row Sum Row Avg. 1.5 5.5 10.0 15.5 21.5 37.5 Calm 1 0 0 0 0 1 0.0 22.5 44 87 26 4 0 0 161 5.4 45.0 42 88 46 8 0 0 184 6.0 67.5 35 43 40 4 0 0 122 6.0 90.0 63 34 12 1 0 0 110 3.7 112.5 61 11 4 0 0 0 76 2.8 135.0 84 32 4 2 0 0 122 3.1 157.5 54 26 4 0 0 0 84 3.2 180.0 55 17 2 0 0 0 74 2.7 202.5 39 6 1 0 0 0 46 2.6 225.0 25 3 2 1 0 0 31 3.1 247.5 41 5 1 0 0 0 47 2.0 270.0 46 12 6 0 0 0 64 3.2 292.5 32 29 16 6 1 0 84 5.7 315.0 28 55 53 23 6 2 167 8.6 337.5 32 71 53 13 3 1 173 7.1 360.0 41 96 40 11 1 0 189 6.4 Column ___ ___ ___ __ __ _ _____ ___ Sums 723 615 310 73 11 3 1,735 5.2
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-36 DCPP SITE - STATION E 25-FOOT LEVEL OCTOBER 1969 THROUGH MARCH 1971 AND APRIL 1972 THROUGH SEPTEMBER 1972 AZIMUTH ANGLE STABILITY CLASS B Direction, deg. Wind Speed, mph Row Sum Row Avg. 1.5 5.5 10.0 15.5 21.5 37.5 Calm 2 0 0 0 0 0 2 0.0 22.5 31 43 18 7 0 0 99 5.9 45.0 30 38 22 2 0 0 92 5.4 67.5 24 19 13 3 0 0 59 5.1 90.0 26 12 3 5 1 0 47 5.6 112.5 22 10 4 0 1 0 37 4.7 135.0 40 14 4 1 0 0 59 3.2 157.5 25 19 1 0 0 0 45 3.7 180.0 20 5 0 0 0 0 25 2.4 202.5 20 3 0 0 0 0 23 2.5 225.0 17 2 0 0 0 0 19 2.4 247.5 21 4 2 0 0 0 27 2.8 270.0 25 9 4 0 0 0 38 3.6 292.5 22 22 9 1 0 1 55 5.7 315.0 13 23 27 20 12 3 98 10.8 337.5 19 24 31 20 4 1 99 9.1 360.0 20 64 61 16 3 0 164 8.0 Column ___ ___ ___ __ __ _ ___ ___ Sums 377 311 199 75 21 5 988 6.2
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-37 DCPP SITE - STATION E 25-FOOT LEVEL OCTOBER 1969 THROUGH MARCH 1971 AND APRIL 1972 THROUGH SEPTEMBER 1972 AZIMUTH ANGLE STABILITY CLASS C Direction,deg. Wind Speed, mph Row Sum Row Avg. 1.5 5.5 10.0 15.5 21.5 37.5 Calm 0 0 0 0 0 0 0 0.0 22.5 34 58 35 8 3 0 138 6.5 45.0 44 53 27 5 1 0 130 5.6 67.5 24 24 11 6 1 0 66 5.6 90.0 21 12 7 3 2 0 45 5.4 112.5 43 12 6 5 1 0 67 4.2 135.0 79 43 19 8 1 0 150 4.8 157.5 54 43 11 2 0 0 110 4.3 180.0 39 9 1 0 0 0 49 2.6 202.5 28 5 0 0 0 0 33 1.9 225.0 19 6 1 0 0 0 26 2.7 247.5 29 3 1 0 0 0 33 2.3 270.0 34 6 2 1 0 0 44 2.9 292.5 49 36 23 11 5 0 124 6.4 315.0 36 55 78 56 36 3 270 11.2 337.5 26 50 65 59 24 7 229 11.1 360.0 30 78 75 18 2 4 203 8.9 Column ___ ___ ___ ___ __ __ _____ ___ Sums 589 93 363 182 76 14 1,717 7.2
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-38 DCPP SITE - STATION E 25-FOOT LEVEL OCTOBER 1969 THROUGH MARCH 1971 AND APRIL 1972 THROUGH SEPTEMBER 1972 AZIMUTH ANGLE STABILITY CLASS D Direction, deg. Wind Speed, mph Row Sum Row Avg. 1.5 5.5 10.0 15.5 21.5 37.5 Calm 1 0 0 0 0 0 1 0.0 22.5 34 44 17 9 3 1 108 6.4 45.0 55 54 22 5 0 0 136 5.1 67.5 34 16 16 10 0 0 76 6.0 90.0 46 23 9 6 1 1 86 5.6 112.5 56 17 35 24 7 1 140 7.9 135.0 126 178 122 65 15 6 512 7.5 157.5 106 148 45 9 3 1 312 5.2 180.0 70 36 6 2 1 0 115 3.7 202.5 27 7 0 0 0 0 34 2.3 225.0 30 8 2 0 0 0 40 2.6 247.5 23 8 0 0 0 0 31 2.3 270.0 53 9 4 0 1 1 68 3.4 292.5 73 81 62 43 32 10 301 9.2 315.0 69 171 222 209 138 47 856 12.6 337.5 35 83 116 139 109 25 507 13.4 360.0 39 62 53 15 8 0 177 7.4 ___ ___ ___ ___ ___ __ _____ ___ Column Sums 877 945 731 536 318 93 3,500 9.0 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-39 DCPP SITE - STATION E 25-FOOT LEVEL OCTOBER 1969 THROUGH MARCH 1971 AND APRIL 1972 THROUGH SEPTEMBER 1972 AZIMUTH ANGLE STABILITY CLASS E Direction, deg. Wind Speed, mph Row Sum Row Avg. 1.5 5.5 10.0 15.5 21.5 37.5 Calm 0 0 0 0 0 0 0 0.0 22.5 11 13 4 1 0 0 29 5.2 45.0 44 32 4 2 0 0 82 4.0 67.5 28 19 17 7 0 0 71 5.8 90.0 30 8 2 0 0 1 41 3.9 112.5 47 10 11 8 2 1 79 5.6 135.0 120 116 96 56 25 7 420 8.0 157.5 105 136 69 18 6 2 336 6.1 180.0 64 41 4 3 1 1 114 4.0 202.5 20 5 2 1 0 0 28 3.3 225.0 24 10 1 0 0 0 35 3.0 247.5 22 8 2 0 0 0 32 2.9 270.0 47 23 5 2 2 0 79 4.2 292.5 72 129 106 90 54 9 460 10.2 315.0 83 319 549 696 608 292 2,547 15.5 337.5 46 63 126 120 101 61 517 14.3 360.0 20 29 13 5 0 0 67 6.0 ___ ___ _____ _____ ___ ___ _____ ____ Column Sums 783 961 1,011 1,009 799 374 4,937 12.1 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-40 DCPP SITE - STATION E 25-FOOT LEVEL OCTOBER 1969 THROUGH MARCH 1971 AND APRIL 1972 THROUGH SEPTEMBER 1972 AZIMUTH ANGLE STABILITY CLASS F AND G Direction, deg. Wind Speed, mph Row Sum Row Avg. 1.5 5.5 10.0 15.5 21.5 37.5 Calm 564 0 0 0 0 0 564 0.0 22.5 7 2 0 0 0 0 9 2.3 45.0 17 4 0 0 0 0 21 2.5 67.5 17 2 2 1 0 0 22 3.6 90.0 15 3 1 0 0 0 19 2.5 112.5 27 1 0 1 0 0 29 2.0 135.0 75 19 6 2 2 1 105 3.4 157.5 65 31 5 3 2 0 106 3.8 180.0 52 7 2 1 0 0 62 2.5 202.5 29 4 1 0 0 0 34 2.0 225.0 16 1 0 1 0 0 18 2.2 247.5 17 4 1 0 0 0 22 2.3 270.0 55 9 1 0 0 0 65 2.2 292.5 50 55 53 36 23 7 224 9.4 315.0 56 151 222 314 286 172 1,201 15.8 337.5 32 15 21 37 9 5 118 10.4 360.0 9 7 2 0 0 0 18 3.7 _____ ___ ___ ___ ___ ___ _____ ___ Column Sums 1,103 315 317 396 322 185 2,637 9.4 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 1 of 25 Revision 15 September 2003 CUMULATIVE PERCENTAGE DISTRIBUTIONS OF /Q ESTIMATES AT THE OUTER BOUNDARY OF THE LPZ AT DCPP SITE 10-meter wind data and stability categories based on measured Sigma A and Temperature Gradient (76M - 10M) values. For calculations with wind speed below 1.5 meters per second stability is based on Temperature Gradient only and building wake or a meander factor is considered - with wind speeds above 1.5 meters per second stability is based on measured Sigma A and Temperature Gradient with building wake only considered. X is downwind distance in meters, Y is sector centerline from north in degrees, and Z is terrain height defined as zero for Ground Level Releases. Data Period May 1973 through April 1975. In the following Tables Y=0.0 is equivalent to Y=360°=North. CUMULATIVE FREQUENCY DISTRIBUTION AT X=800.0 Y=315.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.60140297E-06 0.17928305E-05 50 0.0 0.0 0.34090243E-06 0.11967086E-05 0.22880003E-05 0.36180809E-05 75 0.0 0.35322555E-05 0.47339599E-05 0.52474825E-05 0.51153211E-05 0.56741301E-05 90 0.46975747E-05 0.13407243E-04 0.12096141E-04 0.11476736E-04 0.96943622E-05 0.75202488E-05 95 0.26914247E-04 0.21392218E-04 0.18613035E-04 0.16908802E-04 0.13674124E-04 0.82745992E-05 99 0.79830948E-04 0.41694584E-04 0.31726566E-04 0.28974857E-04 0.22724547E-04 0.93198487E-05 99.5 0.10060299E-03 0.48705522E-04 0.38378115E-04 0.35206263E-04 0.25349524E-04 0.97140346E-05 99.9 0.17863358E-03 0.69454283E-04 0.52891977E-04 0.55085635E-04 0.29252842E-04 0.98666351E-05 100 0.42693969E-03 0.16204809E-03 0.91344118E-04 0.63421554E-04 0.31318254E-04 0.10198001E-04 CUMULATIVE FREQUENCY DISTRIBUTION AT X=800.0 Y=337.5 Z=0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.27897920E-06 0.14245843E-05 50 0.0 0.0 0.39965435E-07 0.47623541E-06 0.11941902E-05 0.21688302E-05 75 0.0 0.11479096E-05 0.25813661E-05 0.28035602E-05 0.31818436E-05 0.30996152E-05 90 0.16196464E-06 0.73396404E-05 0.71391196E-05 0.69225625E-05 0.60822440E-05 0.39170363E-05 95 0.10839826E-04 0.13190673E-04 0.11428615E-04 0.10343385E-04 0.76751812E-05 0.42903375E-05 99 0.57332712E-04 0.28498354E-04 0.21073996E-04 0.16707505E-04 0.10494983E-04 0.51341722E-05 99.5 0.77042845E-04 0.34250028E-04 0.23407832E-04 0.18469131E-04 0.11948351E-04 0.52089890E-05 99.9 0.11422510E-03 0.46669331E-04 0.30434865E-04 0.26693204E-04 0.17508937E-04 0.54098209E-05 100 0.45017432E-03 0.59372076E-04 0.29615683E-04 0.30263240E-04 0.18352424E-04 0.55004302E-05
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 2 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=800.0 Y=0.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.20178135E-07 0.61033268E-06 50 0.0 0.0 0.0 0.84964356E-08 0.52331109E-06 0.96415260E-06 75 0.0 0.25302236E-08 0.70840883E-06 0.11574984E-05 0.13509989E-05 0.12979572E-05 90 0.0 0.30571773E-05 0.34360637E-05 0.30373176E-05 0.24284118E-05 0.16593158E-05 95 0.11744612E-06 0.66978700E-05 0.51172337E-05 0.42316142E-05 0.33221295E-05 0.19114732E-05 99 0.33281089E-04 0.14604380E-04 0.10118109E-04 0.86893342E-05 0.67918800E-05 0.23723878E-05 99.5 0.49149618E-04 0.18833016E-04 0.13381233E-04 0.12046017E-04 0.82666420E-05 0.24336141E-05 99.9 0.88619912E-04 0.34606783E-04 0.24519803E-04 0.19771018E-04 0.94038032E-05 0.25613817E-05 100 0.31923875E-03 0.49039605E-04 0.29722723E-04 0.24404493E-04 0.10373947E-04 0.25717727E-05 CUMULATIVE FREQUENCY DISTRIBUTION AT X=800.0 Y=22.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.31590432E-08 0.33214155E-06 50 0.0 0.0 0.0 0.0 0.31713915E-06 0.54789928E-06 75 0.0 0.0 0.12785688E-06 0.61485019E-06 0.78384534E-06 0.75719402E-06 90 0.0 0.14533725E-05 0.21641408E-05 0.18840965E-05 0.15855258E-05 0.10827689E-05 95 0.0 0.41104977E-05 0.33112265E-05 0.28097411E-05 0.22921749E-05 9.12460659E-05 99 0.20790569E-04 0.10313162E-04 0.76756214E-05 0.57558864E-05 0.31460195E-05 0.15083806E-05 99.5 0.36712212E-04 0.13969571E-04 0.84455642E-05 0.69937705E-05 0.38429389E-05 0.15696178E-05 99.9 0.64066669E-04 0.20981301E-04 0.12264602E-04 0.12232087E-04 0.47792591E-05 0.16129306E-05 100 0.29356778E-03 0.36696263E-04 0.18348132E-04 0.14337682E-04 0.54107604E-05 0.16385302E-05 CUMULATIVE FREQUENCY DISTRIBUTION AT X=800.0 Y=45.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.55598703E-09 0.35731915E-06 50 0.0 0.0 0.0 0.0 0.20440370E-06 0.49795892E-06 75 0.0 0.0 0.86261821E-07 0.39869042E-06 0.85617688E-06 0.81063536E-06 90 0.0 0.11350148E-05 0.24830606E-05 0.22180611E-05 0.16361364E-05 0.12692826E-05 95 0.0 0.49661339E-05 0.38527442E-05 0.31920190E-05 0.23277044E-05 0.14467960E-05 99 0.19482410E-04 0.11177684E-04 0.85418196E-05 0.70383176E-05 0.53034983E-05 0.17087514E-05 99.5 0.42459200E-04 0.15879719E-04 0.10553575E-04 0.93715735E-05 0.57840080E-05 0.20348043E-05 99.9 0.77170160E-04 0.28114708E-04 0.16107486E-04 0.15625614E-04 0.76384376E-05 0.21556871E-05 100 0.37501496E-03 0.46876870E-04 0.23438435E-04 0.15689511E-04 0.81559456E-05 0.21701553E-05 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 3 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=800.0 Y=67.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.19910218E-08 0.24889209E-06 50 0.0 0.0 0.0 0.0 0.14546737E-06 0.42911802E-06 75 0.0 0.0 0.10832360E-06 0.32727348E-06 0.79993595E-06 0.62177327E-06 90 0.0 0.88918227E-06 0.17428902E-05 0.17519760E-05 0.13282652E-05 0.91909624E-06 95 0.0 0.34773839E-05 0.31748004E-05 0.28340100E-05 0.18950996E-05 0.11182974E-05 99 0.16080114E-04 0.89836503E-05 0.65093709E-05 0.54437296E-05 0.31568488E-05 0.19424133E-05 99.5 0.32439624E-04 0.12748404E-04 0.83791401E-05 0.62988538E-05 0.35999619E-05 0.19563859E-05 99.9 0.63343803E-04 0.18939914E-04 0.11131005E-04 0.77977775E-05 0.47309759E-05 0.19899007E-05 100 0.16785040E-03 0.30303869E-04 0.11655334E-04 0.92206838E-05 0.59454760E-05 0.20108682E-05 CUMULATIVE FREQUENCY DISTRIBUTION AT X=800.0 Y=90.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.98381292E-07 0.42774644E-06 50 0.0 0.0 0.67347941E-08 0.10075223E-06 0.47905326E-06 0.81535012E-06 75 0.0 0.11733863E-06 0.85482128E-06 0.11202137E-05 0.12998180E-05 0.12833762E-05 90 0.0 0.30206447E-05 0.28861887E-05 0.27604883E-05 0.22959002E-05 0.16845443E-05 95 0.47983724E-06 0.56365625E-05 0.45940978E-05 0.41290305E-05 0.30253241E-05 0.18356177E-05 99 0.30167124E-04 0.12510503E-04 0.89678560E-05 0.74601758E-05 0.54740649E-05 0.24251367E-05 99.5 0.43825232E-04 0.15991667E-04 0.11190264E-04 0.10325079E-04 0.61040009E-05 0.25050431E-05 99.9 0.80253856E-04 0.25524816E-04 0.16437087E-04 0.13011633E-04 0.64430151E-05 0.26079852E-05 100 0.26299339E-03 0.32874173E-04 0.25596077E-04 0.17605096E-04 0.77006334E-05 0.26970001E-05 CUMULATIVE FREQUENCY DISTRIBUTION AT X=800.0 Y=112.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.21881338E-07 0.17739683E-06 0.80441509E-06 0.15274791E-05 50 0.0 0.15332762E-06 0.99273075E-06 0.15290261E-05 0.21965543E-05 0.28209042E-05 75 0.36544221E-08 0.36351485E-05 0.45084162E-05 0.49050886E-05 0.52850155E-05 0.55923738E-05 90 0.58355099E-05 0.11542677E-04 0.10774902E-04 0.99791041E-05 0.84557751E-05 0.71882914E-05 95 0.24372421E-04 0.19057174E-04 0.15440848E-04 0.13660998E-04 0.11346160E-04 0.84373014E-05 99 0.73329080E-04 0.35874895E-04 0.26128837E-04 0.22772845E-04 0.17065628E-04 0.94562383E-05 99.5 0.92018949E-04 0.41281746E-04 0.31428004E-04 0.29057730E-04 0.19443658E-04 0.98133150E-05 99.9 0.13031083E-03 0.60571503E-04 0.44662738E-04 0.35700417E-04 0.23957633E-04 0.10166443E-04 100 0.25177584E-03 0.87236898E-04 0.52296658E-04 0.39889244E-04 0.25460802E-04 0.10185076E-04 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 4 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=800.0 Y=135.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.15051785E-06 0.19566469E-05 0.29644816E-05 0.44178805E-05 0.58212872E-05 50 0.81038642E-08 0.53202129E-05 0.68629924E-05 0.74960581E-05 0.86957034E-05 0.92801483E-05 75 0.10795834E-04 0.14239811E-04 0.13835153E-04 0.13944897E-04 0.13847120E-04 0.13906842E-04 90 0.31399934E-04 0.25514790E-04 0.22496853E-04 0.20765699E-04 0.18985549E-04 0.15998783E-04 95 0.47333873E-04 0.34454075E-04 0.29741001E-04 0.27354195E-04 0.21924367E-04 0.17443468E-04 99 0.98935401E-04 0.62552077E-04 0.51852519E-04 0.41265914E-04 0.32405180E-04 0.20288542E-04 99.5 0.13996252E-03 0.73905539E-04 0.57608209E-04 0.50959148E-04 0.36743804E-04 0.21132306E-04 99.9 0.21938581E-03 0.92197675E-04 0.76897748E-04 0.72839248E-04 0.58351958E-04 0.22017281E-04 100 0.43604663E-03 0.12359285E-03 0.10618559E-03 0.90063026E-04 0.63509433E-04 0.23351851E-04 CUMULATIVE FREQUENCY DISTRIBUTION AT X=5000.0 Y=315.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.36168682E-07 0.10453664E-06 50 0.0 0.0 0.85387946E-08 0.58115610E-07 0.13548572E-06 0.22112152E-06 75 0.0 0.17811465E-06 0.27010481E-06 0.30452969E-06 0.31845224E-06 0.36362576E-06 90 0.13189924E-06 0.80447398E-06 0.75813131E-06 0.73916146E-06 0.64316288E-06 0.50780699E-06 95 0.14717771E-05 0.13776043E-05 0.12477758E-05 0.11084267E-05 0.88879460E-06 0.56026227E-06 99 0.54080638E-05 0.29498933E-05 0.22118938E-05 0.19417621E-05 0.16314389E-05 0.61426806E-06 99.5 0.72580106E-05 0.35909725E-05 0.27032129E-05 0.25552408E-05 0.19728277E-05 0.63870863E-06 99.9 0.15196728E-04 0.59458198E-05 0.44717808E-05 0.66192533E-05 0.26420630E-05 0.64619587E-06 100 0.84131505E-04 0.20947293E-04 0.10490432E-04 0.71668255E-05 0.29852199E-05 0.66191802E-06 CUMULATIVE FREQUENCY DISTRIBUTION AT X=5000.0 Y=337.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.13080108E-07 0.80222492E-07 50 0.0 0.0 0.34313286E-09 0.19187748E-07 0.69095165E-07 0.12573850E-06 75 0.0 0.35439491E-07 0.13064300E-06 0.15438911E-06 0.18920201E-06 0.17924884E-06 90 0.10963741E-08 0.41085059E-06 0.41715919E-06 0.41353013E-06 0.36168058E-06 0.22895489E-06 95 0.43192472E-06 0.78051630E-06 0.69862722E-06 0.63962761E-06 0.45303062E-06 0.26817463E-06 99 0.36181909E-05 0.18028550E-05 0.12881756E-05 0.10581916E-05 0.65855136E-06 0.29816505E-06 99.5 0.51098368E-05 0.22534186E-05 0.15325004E-05 0.11887769E-05 0.76233380E-06 0.30169258E-06 99.9 0.90557323E-05 0.33098568E-05 0.18670871E-05 0.14873640E-05 0.91363347E-06 0.31337936E-06 100 0.21146378E-04 0.37607297E-05 0.22657759E-05 0.17264520E-05 0.96313761E-06 0.31662830E-06 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 5 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=5000.0 Y=0.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.14577914E-09 0.35206888E-07 50 0.0 0.0 0.0 0.45826593E-10 0.29770831E-07 0.52756821E-07 75 0.0 0.58812052E-11 0.27133446E-07 0.58794626E-07 0.75742776E-07 0.73219780E-07 50 0.0 0.15007060E-06 0.19557928E-06 0.17316466E-06 0.12850018E-06 0.11007444E-06 95 0.59110117E-09 0.38010899E-06 0.29189255E-06 0.24359178E-06 0.19158728E-06 0.12307993E-06 99 0.17581433E-05 0.83792327E-06 0.62629374E-06 0.58788004E-06 0.49176458E-06 0.14301321E-06 99.5 0.29224684E-05 0.11764350E-05 0.91553710E-06 0.82102144E-06 0.56503490E-06 0.14409750E-06 99.9 0.56128920E-05 0.24570221E-05 0.21853366E-05 0.17620714E-05 0.10170143E-05 0.14915304E-06 100 0.42233936E-04 0.52862160E-05 0.26431080E-05 0.28504437E-05 0.10222102E-05 0.15006066E-06 CUMULATIVE FREQUENCY DISTRIBUTION AT X=5000.0 Y=22.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.20389176E-10 0.19992385E-07 50 0.0 0.0 0.0 0.0 0.13813594E-07 0.28445811E-07 75 0.0 0.0 0.23833167E-08 0.24813552E-07 0.42410218E-07 0.40333958E-07 90 0.0 0.54455477E-07 0.11946088E-06 0.10623080E-06 0.94955624E-07 0.62961988E-07 95 0.0 0.22869460E-06 0.19328428E-06 0.16950753E-06 0.13235518E-06 0.75315427E-07 99 0.11487864E-05 0.60345269E-06 0.46176353E-06 0.36859063E-06 0.18517102E-06 0.90167873E-07 99.5 0.21258884E-05 0.90078481E-06 0.56635531E-06 0.42334409E-06 0.24530493E-06 0.90845560E-07 99.9 0.40991818E-05 0.12700320E-05 0.76666845E-06 0.98082091E-06 0.37735197E-06 0.92208381E-07 100 0.23539702E-04 0.29424627E-05 0.14712314E-05 0.11320553E-05 0.37735197E-06 0.93904873E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=5000.0 Y=45.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.14582606E-11 0.20480179E-07 50 0.0 0.0 0.0 0.0 0.10482022E-07 0.29226378E-07 75 0.0 0.0 0.10083996E-08 0.14940628E-07 0.50052737E-07 0.50985456E-07 90 0.0 0.43275435E-07 0.13510913E-06 0.12896214E-06 0.10230991E-06 0.85150248E-07 95 0.0 0.27654005E-06 0.24085580E-06 0.20941150E-06 0.14324081E-06 0.93926701E-07 99 0.10752683E-05 0.72607270E-06 0.58212339E-06 0.46406512E-06 0.39380984E-06 0.12303661E-06 99.5 0.25677864E-05 0.10686435E-05 0.78176242E-06 0.65926480E-06 0.44854397E-06 0.15118201E-06 99.9 0.53723543E-05 0.19507843E-05 0.17475313E-05 0.12004366E-05 0.52173317E-06 0.15981925E-06 100 0.28810478E-04 0.36013098E-05 0.18006549E-05 0.12010714E-05 0.56730175E-06 0.16089183E-06 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 6 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=5000.0 Y=67.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.71000514E-11 0.14641117E-07 50 0.0 0.0 0.0 0.0 0.70953732E-08 0.25460412E-07 75 0.0 0.0 0.14370967E-08 0.15539950E-07 0.47672188E-07 0.39219451E-07 90 0.0 0.31356308E-07 0.95708401E-07 0.10693691E-06 0.83028453E-07 0.52725785E-07 95 0.0 0.19428228E-06 0.20763008E-06 0.16664444E-06 0.12739076E-06 0.63567370E-07 99 0.87763675E-06 0.55491716E-06 0.43887115E-06 0.35722360E-06 0.18691651E-06 0.12359015E-06 99.5 0.20100751E-05 0.87702165E-06 0.58959779E-06 0.42241618E-06 0.20926058E-06 0.12442842E-06 99.9 0.40991790E-05 0.14034076E-05 0.70586043E-06 0.50623231E-06 0.30232917E-06 0.12563163E-06 100 0.12149576E-04 0.24299152E-05 0.93458272E-06 0.58561466E-06 0.37802903E-06 0.12742345E-06 CUMULATIVE FREQUENCY DISTRIBUTION AT X=5000.0 Y=90.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.40193058E-08 0.23817272E-07 50 0.0 0.0 0.25931188E-10 0.20316566E-08 0.25079416E-07 0.43462933E-07 75 0.0 0.12126509E-08 0.35333194E-07 0.55407174E-07 0.67701819E-07 0.66386406E-07 90 0.0 0.14632678E-06 0.15654877E-06 0.15234110E-06 0.12525743E-06 0.98119585E-07 95 0.42502215E-08 0.31009449E-06 0.26077959E-06 0.23628263E-06 0.18326324E-06 0.11449896E-06 99 0.16467056E-05 0.79867789E-06 0.58171133E-06 0.52813391E-06 0.34962306E-06 0.17958166E-06 99.5 0.26262996E-05 0.10492295E-05 0.89531187E-06 0.76633961E-06 0.43603438E-06 0.18571274E-06 99.9 0.58168962E-05 0.21671476E-05 0.17486946E-05 0.11915372E-05 0.50521476E-06 0.19400682E-06 100 0.28155948E-04 0.35194935E-05 0.19037416E-05 0.12691607E-05 0.66004691E-06 0.20071275E-06 CUMULATIVE FREQUENCY DISTRIBUTION AT X=5000.0 Y=112.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.21045696E-09 0.42891095E-08 0.41060400E-07 0.84093926E-07 50 0.0 0.19965642E-08 0.40799645E-07 0.77697678E-07 0.12948186E-06 0.16824447E-06 75 0.95705752E-11 0.18900982E-06 0.26854855E-06 0.29308774E-06 0.31357575E-06 0.32824516E-06 90 0.18181407E-06 0.71684804E-06 0.64501506E-06 0.61001066E-06 0.51318074E-06 0.45536137E-06 95 0.13917124E-05 0.11540496E-05 0.95202239E-06 0.85374086E-06 0.71276997E-06 0.51387065E-06 99 0.49232312E-05 0.22464483E-05 0.19052277E-05 0.15245078E-05 0.10616695E-05 0.57821558E-06 99.5 0.62745294E-05 0.29965740E-05 0.22118547E-05 0.19582285E-05 0.12047130E-05 0.59775459E-06 99.9 0.10065412E-04 0.42593965E-05 0.29897665E-05 0.24965957E-05 0.15395262E-05 0.60724216E-06 100 0.18854073E-04 0.69515136E-05 0.40005962E-05 0.26940934E-05 0.16514177E-05 0.60842700E-06 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 7 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=5000.0 Y=135.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.23127003E-08 0.10091179E-06 0.16987104E-06 0.27334886E-06 0.38332479E-06 50 0.21753807E-10 0.29918658E-06 0.41405730E-06 0.45959354E-06 0.55291048E-06 0.61919405E-06 75 0.54507149E-06 0.90911567E-06 0.91407458E-06 0.91384572E-06 0.93934290E-06 0.97202701E-06 90 0.20855923E-05 0.17987522E-05 0.15966352E-05 0.15276491E-05 0.14050647E-05 0.11763577E-05 95 0.23725582E-05 0.26130037E-05 0.23192615E-05 0.21618853E-05 0.16822378E-05 0.12873825E-05 99 0.82008863E-05 0.53806925E-05 0.41197482E-05 0.35819121E-05 0.27855021E-05 0.15215419E-05 99.5 0.12291127E-04 0.63633797E-05 0.50722783E-05 0.40628656E-05 0.34123441E-05 0.16112281E-05 99.9 0.21577056E-04 0.95259120E-05 0.79465844E-05 0.73275551E-05 0.51353773E-05 0.17033917E-05 100 0.48696151E-04 0.12974342E-04 0.11042428E-04 0.87179824E-05 0.56531680E-05 0.17843304E-05 CUMULATIVE FREQUENCY DISTRIBUTION AT X=10000.0 Y=315.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.11898855E-07 0.39420250E-07 50 0.0 0.0 0.16825294E-08 0.17398602E-07 0.48724825E-07 0.81325879E-07 75 0.0 0.57269261E-07 0.95579821E-07 0.10819360E-06 0.11580113E-06 0.13432509E-06 90 0.26942164E-07 0.29764158E-06 0.28247553E-06 0.26897686E-06 0.24290699E-06 0.19045433E-06 95 0.50944533E-06 0.51394477E-06 0.46507063E-06 0.40625190E-06 0.33735540E-06 0.21974654E-06 99 0.20018133E-05 0.11472730E-05 0.87053417E-06 0.76213655E-06 0.63080751E-06 0.24315244E-06 99.5 0.28199247E-05 0.14036650E-05 0.10350741E-05 0.95666292E-06 0.74433427E-06 0.24778973E-06 99.9 0.60016846E-05 0.23125722E-05 0.17085695E-05 0.31087411E-05 0.12042174E-05 0.25372725E-06 100 0.44052867E-04 0.98463388E-05 0.49264872E-05 0.33393026E-05 0.13460522E-05 0.25695738E-06 CUMULATIVE FREQUENCY DISTRIBUTION AT X=10000.0 Y=337.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.38649119E-08 0.29699688E-07 50 0.0 0.0 0.30288896E-10 0.48866617E-08 0.23919647E-07 0.44517531E-07 75 0.0 0.79878504E-08 0.48146685E-07 0.55628789E-07 0.67815961E-07 0.64992946E-07 90 0.87539087E-10 0.14584339E-06 0.15432619E-06 0.15032344E-06 0.13241515E-06 0.83584041E-07 95 0.12040977E-06 0.28320778E-06 0.25935333E-06 0.23495539E-06 0.16971364E-06 0.97883003E-07 99 0.13245890E-05 0.67357894E-06 0.48515130E-06 0.40291360E-06 0.24880012E-06 0.10802484E-06 99.5 0.19078780E-05 0.87823923E-06 0.57994760E-06 0.44074397E-06 0.27561646E-06 0.11238512E-06 99.9 0.35605253E-05 0.13149829E-05 0.72390708E-06 0.52097437E-06 0.30930397E-06 0.11448327E-06 100 0.81129356E-05 0.14976467E-05 0.78242454E-06 0.62768413E-06 0.32477283E-06 0.11568238E-06 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 8 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=10000.0 Y=0.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.16834784E-10 0.12309329E-07 50 0.0 0.0 0.0 0.31556008E-11 0.10926414E-07 0.19151265E-07 75 0.0 0.27285314E-12 0.70115966E-08 0.20003114E-07 0.27724038E-07 0.26369385E-07 90 0.0 0.49454080E-07 0.68042254E-07 0.63437994E-07 0.45896854E-07 0.41167368E-07 95 0.48697504E-10 0.13497800E-06 0.10816240E-06 0.87966214E-07 0.67900999E-07 0.47427534E-07 99 0.66222321E-06 0.31061472E-06 0.23853221E-06 0.20138287E-06 0.19189895E-06 0.63146729E-07 99.5 0.10830563E-05 0.42724957E-06 0.35048373E-06 0.30563172E-06 0.21208240E-06 0.63680375E-07 99.9 0.21694095E-05 0.14475672E-05 0.93568065E-06 0.86835882E-06 0.46961736E-06 0.64146434E-07 100 0.20840351E-04 0.26050766E-05 0.13025383E-05 0.13460503E-05 0.47182988E-06 0.64146434E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=10000.0 Y=22.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.14361038E-11 0.71856725E-08 50 0.0 0.0 0.0 0.0 0.40441996E-11 0.96102717E-08 75 0.0 0.0 0.40697401E-09 0.68615691E-08 0.14953013E-07 0.14444218E-07 90 0.0 0.14685845E-07 0.40945434E-07 0.39981616E-07 0.25217113E-07 0.23196083E-07 95 0.0 0.81890562E-07 0.67836766E-07 0.60708089E-07 0.48405600E-07 0.28668552E-07 99 0.38537263E-06 0.21330425E-06 0.17496620E-06 0.13972345E-06 0.71506918E-07 0.32824058E-07 99.5 0.75938635E-06 0.32788751E-06 0.22722116E-06 0.16397127E-06 0.89498371E-07 0.33046216E-07 99.9 0.15570795E-05 0.49191385E-06 0.29049704E-06 0.40790667E-06 0.15543850E-06 0.33252277E-07 100 0.97897600E-05 0.12237197E-05 0.61186000E-06 0.46631561E-06 0.15543850E-06 0.33908496E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=10000.0 Y=45.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.15478715E-12 0.75894029E-08 50 0.0 0.0 0.0 0.0 0.30787499E-08 0.10594668E-07 75 0.0 0.0 0.17251980E-09 0.45243382E-08 0.18642215E-07 0.18259620E-07 90 0.0 0.10589190E-07 0.49752124E-07 0.47352728E-07 0.39567627E-07 0.32490437E-07 95 0.0 0.10258418E-06 0.87888225E-07 0.79934239E-07 0.54511247E-07 0.35676820E-07 99 0.41110115E-06 0.28796683E-06 0.22915549E-06 0.18589975E-06 0.16457756E-06 0.48509975E-07 99.5 0.93040444E-06 0.42667341E-06 0.29673453E-06 0.25408576E-06 0.17955091E-06 0.59185670E-07 99.9 0.20388570E-05 0.75091657E-06 0.73016986E-06 0.49865224E-06 0.19861722E-06 0.62496042E-07 100 0.11967654E-04 0.14967463E-05 0.74837357E-06 0.49891571E-06 0.21501700E-06 0.62915490E-07 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 9 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=10000.0 Y=67.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.48820513E-12 0.53997553E-08 50 0.0 0.0 0.0 0.0 0.21488484E-08 0.90656442E-08 75 0.0 0.0 0.19064900E-09 0.42332360E-08 0.16774479E-07 0.14740483E-07 90 0.0 0.88868433E-08 0.35620776E-07 0.38310301E-07 0.30575201E-07 0.19366762E-07 95 0.0 0.71241516E-07 0.74582317E-07 0.61896685E-07 0.48626674E-07 0.24230758E-07 99 0.29504389E-06 0.22101483E-06 0.16693326E-06 0.13171086E-06 0.73985177E-07 0.47917510E-07 99.5 0.72123976E-06 0.32533364E-06 0.22253283E-06 0.17043118E-06 0.80711118E-07 0.48377270E-07 99.9 0.17442262E-05 0.54720454E-06 0.29351366E-06 0.19567574E-06 0.10984843E-06 0.48791776E-07 100 0.50527960E-05 0.10105587E-05 0.38867660E-06 0.24060932E-06 0.13656671E-06 0.49360189E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=10000.0 Y=90.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.91895269E-09 0.89162064E-08 50 0.0 0.0 0.15489381E-11 0.33227221E-09 0.85072607E-08 0.14988771E-07 75 0.0 0.14541743E-09 0.10274171E-07 0.19407693E-07 0.24531005E-07 0.23121000E-07 90 0.0 0.49379487E-07 0.55943179E-07 0.53257811E-07 0.46220329E-07 0.35295201E-07 95 0.44333115E-09 0.11061496E-06 0.93854453E-07 0.86122611E-07 0.65709855E-07 0.42358931E-07 99 0.60299112E-06 0.31099250E-06 0.22322087E-06 0.20123827E-06 0.13368032E-06 0.69289285E-07 99.5 0.95648102E-06 0.41436692E-06 0.34033985E-06 0.30379016E-06 0.17566379E-06 0.71729801E-07 99.9 0.23944494E-05 0.80091729E-06 0.71727061E-06 0.51419346E-06 0.21365605E-06 0.74848742E-07 100 0.12227629E-04 0.15284531E-05 0.77249723E-06 0.51499813E-06 0.28325258E-06 0.77379980E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=10000.0 Y=112.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.20839219E-10 0.84166718E-09 0.14151624E-07 0.29900782E-07 50 0.0 0.27501934E-09 0.11402463E-07 0.25803622E-07 0.47297128E-07 0.60711443E-07 75 0.16949690E-12 0.60673813E-07 0.94820109E-07 0.10325118E-06 0.10866609E-06 0.11630510E-06 90 0.40460890E-07 0.26155215E-06 0.23049108E-06 0.21451825E-06 0.18499907E-06 0.16472660E-06 95 0.45990720E-06 0.41155283E-06 0.34330810E-06 0.30469738E-06 0.25186006E-06 0.18124632E-06 99 0.18238316E-05 0.83206919E-06 0.70830458E-06 0.56533167E-06 0.40792537E-06 0.19859812E-06 99.5 0.23300199E-05 0.10834447E-05 0.81554646E-06 0.70112458E-06 0.43298786E-06 0.20610111E-06 99.9 0.29353081E-05 0.15642336E-05 0.10322783E-05 0.92796711E-06 0.53611660E-06 0.20792345E-06 100 0.73103029E-05 0.27324531E-05 0.15486767E-05 0.10390831E-05 0.58725243E-06 0.20836592E-06 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 10 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=10000.0 Y=135.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.30513836E-09 0.33975152E-07 0.60142440E-07 0.97421378E-07 0.14158559E-06 50 0.81213882E-12 0.10084892E-06 0.14449859E-06 0.15982766E-06 0.19696233E-06 0.22543361E-06 75 0.16013809E-06 0.32541402E-06 0.32830889E-06 0.32482870E-06 0.34691823E-06 0.35846648E-06 90 0.76552914E-06 0.66848929E-06 0.60408695E-06 0.57567422E-06 0.53463327E-06 0.45199931E-06 95 0.12743885E-05 0.99710542E-06 0.89382365E-06 0.83963278E-06 0.65709690E-06 0.48823017E-06 99 0.32882863E-05 0.21611031E-05 0.16481881E-05 0.14180096E-05 0.11066504E-05 0.58373649E-06 99.5 0.49012660E-05 0.25623904E-05 0.20536236E-05 0.16799531E-05 0.13855224E-05 0.61466212E-06 99.9 0.90633584E-05 0.39299375E-05 0.32929020E-05 0.30402252E-05 0.20607076E-05 0.64537051E-06 100 0.21114320E-04 0.53340282E-05 0.45244979E-05 0.35760759E-05 0.22838203E-05 0.69248154E-06 CUMULATIVE FREQUENCY DISTRIBUTION AT X=15000.0 Y=315.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.65581034E-08 0.22620974E-07 50 0.0 0.0 0.55711591E-09 0.87253866E-08 0.28744893E-07 0.47982880E-07 75 0.0 0.28775133E-07 0.54719095E-07 0.61016749E-07 0.68279519E-07 0.77431821E-07 90 0.98195940E-08 0.16965191E-06 0.16625148E-06 0.15875236E-06 0.14214334E-06 0.11057045E-06 95 0.28281733E-06 0.30325634E-06 0.27776838E-06 0.24559421E-06 0.19655960E-06 0.12945674E-06 99 0.11925194E-05 0.69576959E-06 0.51861451E-06 0.47041817E-06 0.37303488E-06 0.15222821E-06 99.5 0.17336597E-05 0.83605255E-06 0.63974949E-06 0.57241328E-06 0.43054570E-06 0.15427327E-06 99.9 0.41135654E-05 0.13727631E-05 0.10024742E-05 0.20443877E-05 0.78021060E-06 0.15839174E-06 100 0.30345429E-04 0.64752967E-05 0.32388989E-05 0.21875321E-05 0.86791459E-06 0.16016929E-06 CUMULATIVE FREQUENCY DISTRIBUTION AT X=15000.0 Y=337.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 250.0 0.0 0.0 0.0 0.0 .19011699E-08 0.16883281E-07 50 0.0 0.0 0.66232393E-11 0.20247073E-08 0.13712853E-07 0.25553373E-07 75 0.0 0.31021297E-08 0.26537951E-07 0.30617500E-07 0.38804675E-07 0.37484096E-07 90 0.17074051E-10 0.84400710E-07 0.87690921E-07 0.88357922E-07 0.76232027E-07 0.48131973E-07 95 0.55542273E-07 0.16197566E-06 0.15089341E-06 0.13481110E-06 0.10000292E-06 0.55359607E-07 99 0.77743528E-06 0.38396513E-06 0.27873079E-06 0.23427765E-06 0.14466826E-06 0.65524091E-07 99.5 0.11094689E-05 0.51570566E-06 0.34316957E-06 0.26858902E-06 0.16511478E-06 0.69627163E-07 99.9 0.21586957E-05 0.78843152E-06 0.43353373E-06 0.30150534E-06 0.17615287E-06 0.71047509E-07 100 0.50085073E-05 0.90445928E-06 0.45224823E-06 0.37201784E-06 0.18749381E-06 0.71783518E-07 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 11 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=15000.0 Y=0.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.42491158E-11 0.68898416E-08 50 0.0 0.0 0.0 0.50700438E-12 0.60802101E-08 0.10994714E-07 75 0.0 0.0 0.29931513E-08 0.10471879E-07 0.15913940E-07 0.15212056E-07 90 0.0 0.25995199E-07 0.39465355E-07 0.37539614E-07 0.26602049E-07 0.23917156E-07 95 0.84520620E-11 0.78655887E-07 0.64125516E-07 0.50901349E-07 0.38762082E-07 0.27592829E-07 99 0.39688416E-06 0.18071910E-06 0.13130398E-06 0.12209216E-06 0.10809686E-06 0.39930477E-07 99.5 0.63648679E-06 0.24657982E-06 0.21058162E-06 0.17981279E-06 0.13211240E-06 0.40202647E-07 99.9 0.13129211E-05 0.89727888E-06 0.59065110E-06 0.57528712E-06 0.30167593E-06 0.40480511E-07 100 0.13806886E-04 0.17258608E-05 0.86293073E-06 0.87396558E-06 0.30306848E-06 0.40480511E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=15000.0 Y=22.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.33338339E-12 0.39631480E-08 50 0.0 0.0 0.0 0.0 0.18983932E-08 0.53384994E-08 75 0.0 0.0 0.13741124E-09 0.32824041E-08 0.85651628E-08 0.81658236E-08 90 0.0 0.67215353E-08 0.22862757E-07 0.21644198E-07 0.19387659E-07 0.13477994E-07 95 0.0 0.47744486E-07 0.40322814E-07 0.35388123E-07 0.26921331E-07 0.16593361E-07 99 0.20850109E-06 0.12234443E-06 0.10114360E-06 0.81633004E-07 0.41390166E-07 0.19006450E-07 99.5 0.43771365E-06 0.19947140E-06 0.13024169E-06 0.96822475E-07 0.51571217E-07 0.19195689E-07 99.9 0.91841656E-06 0.30954106E-06 0.16814755E-06 0.25093811E-06 0.95084317E-07 0.19331665E-07 100 0.60225157E-05 0.75281446E-06 0.37640723E-06 0.28525307E-06 0.95084317E-07 0.19398097E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=15000.0 Y=45.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.16775125E-13 0.43620254E-08 50 0.0 0.0 0.0 0.0 0.15074273E-08 0.62900263E-08 75 0.0 0.0 0.50292701E-10 0.18487309E-08 0.10394373E-07 0.10547602E-07 90 0.0 0.46893938E-08 0.29167751E-07 0.26986175E-07 0.22845800E-07 0.19048986E-07 95 0.0 0.59042485E-07 0.54270807E-07 0.46654009E-07 0.32093070E-07 0.21249946E-07 99 0.23026769E-06 0.16328897E-06 0.13279731E-06 0.13307749E-06 0.98863723E-07 0.29389479E-07 99.5 0.55310579E-06 0.24180156E-06 0.19961624E-06 0.15243188E-06 0.10709704E-06 0.35758887E-07 99.9 0.11425655E-05 0.44322462E-06 0.43867260E-06 0.31491277E-06 0.12175013E-06 0.37773642E-07 100 0.75579073E-05 0.94493657E-06 0.47246829E-06 0.31497882E-06 0.13047810E-06 0.38027157E-07 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 12 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=15000.0 Y=67.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.84983778E-13 0.28847238E-08 50 0.0 0.0 0.0 0.0 0.10945815E-08 0.51356537E-08 75 0.0 0.0 0.51957716E-10 0.18548296E-08 0.95388017E-08 0.86745793E-08 90 0.0 0.39902375E-08 0.20557884E-07 0.22688319E-07 0.18057346E-07 0.11139001E-07 95 0.0 0.41215444E-07 0.40739160E-07 0.35761879E-07 0.28582093E-07 0.14339826E-07 99 0.15917016E-06 0.13336694E-06 0.99734848E-07 0.77640095E-07 0.45095966E-07 0.28247744E-07 99.5 0.42300820E-06 0.19946970E-06 0.12478461E-06 0.10174961E-06 0.48676057E-07 0.28512972E-07 99.9 0.10532685E-05 0.31382297E-06 0.18011775E-06 0.12007848E-06 0.62027539E-07 0.28752943E-07 100 0.31094064E-05 0.62168124E-06 0.23910815E-06 0.14801935E-06 0.76844231E-07 0.29126156E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=15000.0 Y=90.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.35814640E-09 0.50313389E-08 50 0.0 0.0 0.26058447E-12 0.10601167E-09 0.45774478E-08 0.82628588E-08 75 0.0 0.35607323E-10 0.48928221E-08 0.10372965E-07 0.13553148E-07 0.13117738E-07 90 0.0 0.27021031E-07 0.31015087E-07 0.31375979E-07 0.26601228E-07 0.20073045E-07 95 0.98749744E-10 0.61981723E-07 0.54284722E-07 0.49494322E-07 0.39624183E-07 0.24721672E-07 99 0.34081376E-06 0.17759987E-06 0.13384806E-06 0.12186308E-06 0.83738769E-07 0.40617124E-07 99.5 0.56139402E-06 0.26591306E-06 0.19706977E-06 0.18206487E-06 0.10600883E-06 0.42088498E-07 99.9 0.13590184E-05 0.48480365E-06 0.43750231E-06 0.31885628E-06 0.13196990E-06 0.43901814E-07 100 0.76525512E-05 0.95656833E-06 0.48143238E-06 0.32095488E-06 0.17561098E-06 0.45360050E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=15000.0 Y=112.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.43523128E-11 0.30470293E-09 0.75992297E-08 0.16716541E-07 50 0.0 0.77833850E-10 0.54824341E-08 0.13232260E-07 0.27178555E-07 0.34113487E-07 75 0.0 0.32367581E-07 0.53171512E-07 0.58579150E-07 0.60095658E-07 0.64531093E-07 90 0.15921973E-07 0.14831653E-06 0.12985015E-06 0.12489033E-06 0.10569761E-06 0.94182724E-07 95 0.24518067E-06 0.23630218E-06 0.19737212E-06 0.16936474E-06 0.14695985E-06 0.10216166E-06 99 0.10542435E-05 0.48661377E-06 0.40624525E-06 0.32735522E-06 0.23301607E-06 0.11407087E-06 99.5 0.13866784E-05 0.62256959E-06 0.47548781E-06 0.39148244E-06 0.25524099E-06 0.11504034E-06 99.9 0.23214416E-05 0.91088100E-06 0.58397745E-06 0.54756902E-06 0.30177517E-06 0.11607568E-06 100 0.44572580E-05 0.16203585E-05 0.91777423E-06 0.61470507E-06 0.32979307E-06 0.11660666E-06 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 13 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=15000.0 Y=135.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.87701235E-10 0.17875784E-07 0.32972068E-07 0.54499544E-07 0.83042266E-07 50 0.0 0.54354430E-07 0.80337145E-07 0.89459093E-07 0.11152611E-06 0.13161014E-06 75 0.76664151E-07 0.18519063E-06 0.18656362E-06 0.18567346E-06 0.19885351E-06 0.20508207E-06 90 0.43765573E-06 0.38521569E-06 0.35380822E-06 0.33945889E-06 0.31262346E-06 0.26365655E-06 95 0.74108164E-06 0.58376895E-06 0.53680361E-06 0.49867924E-06 0.38944358E-06 0.28592308E-06 99 0.20399293E-05 0.12813935E-05 0.98928103E-06 0.86699043E-06 0.64731728E-06 0.34321846E-06 99.5 0.28955837E-05 0.15893529E-05 0.12666242E-05 0.10356380E-05 0.83330207E-06 0.35980611E-06 99.9 0.57216357E-05 0.24207111E-05 0.20257066E-05 0.18715227E-05 0.12421297E-05 0.37859621E-06 100 0.13350488E-04 0.32579665E-05 0.27657179E-05 0.21882661E-05 0.13833542E-05 0.40881116E-06 CUMULATIVE FREQUENCY DISTRIBUTION AT X=30000.0 Y=315.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.9 0.0 0.25466331E-08 0.95368655E-08 50 0.0 0.0 0.78097778E-10 0.29290086E-08 0.12006758E-07 0.21992719E-07 75 0.0 0.96733572E-08 0.23271738E-07 0.26817059E-07 0.29294508E-07 0.33200383E-07 90 0.15804347E-08 0.75784897E-07 0.72687101E-07 0.69492899E-07 0.62654692E-07 0.50567294E-07 95 0.11228110E-06 0.13580825E-06 0.12496923E-06 0.11077958E-06 0.87188369E-07 0.57074697E-07 99 0.54333287E-06 0.31370473E-06 0.23337026E-06 0.20854372E-06 0.16181275E-06 0.73323690E-07 99.5 0.78534606E-06 0.38627832E-06 0.29357693E-06 0.25960179E-06 0.18710909E-06 0.74192769E-07 99.9 0.18420833E-05 0.59907313E-06 0.44757218E-06 0.10596832E-05 0.39342717E-06 0.77013965E-07 100 0.16618098E-04 0.33369779E-05 0.16687000E-05 0.11220336E-05 0.43589006E-06 0.77496850E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=30000.0 Y=337.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.57549632E-09 0.73884365E-08 50 0.0 0.0 0.36937684E-12 0.42537796E-09 0.53889941E-08 0.10797148E-07 75 0.0 0.60633898E-09 0.98081117E-08 0.13246350E-07 0.16726691E-07 0.15961593E-07 90 0.53020040E-12 0.36850878E-07 0.36645520E-07 0.38873999E-07 0.32473420E-07 0.19701353E-07 95 0.14082605E-07 0.69344082E-07 0.68281850E-07 0.57674050E-07 0.43507271E-07 0.22800123E-07 99 0.35425074E-06 0.16567549E-06 0.12153515E-06 0.10311425E-06 0.63890070E-07 0.31202003E-07 99.5 0.49062709E-06 0.21010817E-06 0.15162880E-06 0.11906582E-06 0.68105351E-07 0.32523928E-07 99.9 0.93845620E-06 0.35708922E-06 0.20588476E-06 0.15175669E-06 0.90669801E-07 0.33244039E-07 100 0.23853527E-05 0.45305342E-06 0.22763510E-06 0.16396825E-06 0.99481440E-07 0.33542680E-07 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 14 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=30000.0 Y=0.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.29609935E-12 0.28636971E-08 50 0.0 0.0 0.0 0.11113838E-13 0.22228508E-08 0.47122803E-08 75 0.0 0.0 0.73223183E-09 0.38157530E-08 0.69859922E-08 0.66229759E-07 90 0.0 0.97641788E-08 0.17463666E-07 0.17415971E-07 0.11571441E-07 0.10530172E-07 95 0.15624204E-12 0.34692391E-07 0.29171744E-07 0.23136387E-07 0.16517987E-07 0.12725344E-07 99 0.16071755E-06 0.76794834E-07 0.58218461E-07 0.51091696E-07 0.47019551E-07 0.18705244E-07 99.5 0.29896370E-06 0.10925226E-06 0.93230540E-07 0.79488757E-07 0.63624952E-07 0.18805757E-07 99.9 0.58652580E-06 0.42542558E-06 0.28551841E-06 0.28332755E-06 0.14418623E-06 0.18922940E-07 100 0.67998617E-05 0.84998271E-06 0.42499136E-06 0.42281243E-06 0.14469254E-06 0.18922940E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=30000.0 Y=22.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.10799511E-13 0.15164612E-08 50 0.0 0.0 0.0 0.0 0.61131900E-09 0.21830511E-08 75 0.0 0.0 0.16979002E-10 0.87244656E-09 0.35564787E-08 0.36691099E-08 90 0.0 0.17925390E-08 0.95135775E-08 0.92867367E-08 0.84610576E-08 0.63178405E-08 95 0.0 0.19747674E-07 0.18311582E-07 0.16318879E-07 0.12306064E-07 0.74280209E-08 99 0.73414014E-07 0.58875209E-07 0.44931362E-07 0.37825529E-07 0.19342966E-07 0.87324601E-08 99.5 0.19305151E-06 0.85239321E-07 0.57500131E-07 0.45481329E-07 0.23543205E-07 0.88065910E-08 99.9 0.40763098E-06 0.14512125E-07 0.78058292E-07 0.11679180E-06 0.43894588E-07 0.88819903E-08 100 0.28030036E-05 0.35037544E-06 0.17518772E-06 0.13168375E-06 0.43894588E-07 0.89204555E-08 CUMULATIVE FREQUENCY DISTRIBUTION AT X=30000.0 Y=45.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.0 0.18662873E-08 50 0.0 0.0 0.0 0.0 0.50042726E-09 0.26730709E-08 75 0.0 0.0 0.39705583E-11 0.52659033E-09 0.46017661E-08 0.47644235E-08 90 0.0 0.10701231E-08 0.11990824E-07 0.11826288E-07 0.10011917E-07 0.81641041E-08 95 0.0 0.24349113E-07 0.24542345E-07 0.20046127E-07 0.13839816E-07 0.92468966E-08 99 0.92524488E-07 0.69798716E-07 0.60351681E-07 0.59177616E-07 0.43500155E-07 0.13539605E-07 99.5 0.23834008E-06 0.11319975E-06 0.89329035E-07 0.70118176E-07 0.51050378E-07 0.16306434E-07 99.9 0.53826830E-06 0.28328691E-06 0.19303008E-06 0.15226681E-06 0.54461015E-07 0.17222273E-07 100 0.36544034E-05 0.45681497E-06 0.22840749E-06 0.15227164E-06 0.61999003E-07 0.17337861E-07 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 15 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=30000.0 Y=67.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.22644992E-14 0.11720056E-08 50 0.0 0.0 0.0 0.0 0.31417380E-09 0.22692874E-08 75 0.0 0.0 0.52800845E-11 0.48673421E-09 0.40366999E-08 0.38441001E-08 90 0.0 0.88995789E-09 0.85814769E-08 0.10402204E-07 0.83399527E-08 0.47788618E-08 95 0.0 0.17683718E-07 0.17903890E-07 0.14717511E-07 0.11889053E-07 0.60918310E-08 99 0.54966797E-07 0.61008564E-07 0.43119574E-07 0.35202913E-07 0.19701574E-07 0.12019374E-07 99.5 0.18337704E-06 0.85349200E-07 0.53488929E-07 0.43651355E-07 0.22257193E-07 0.12152224E-07 99.9 0.49097372E-06 0.14134537E-06 0.80181849E-07 0.53454563E-07 0.25143208E-07 0.12246886E-07 100 0.14467178E-05 0.28934352E-06 0.11128594E-06 0.68891268E-07 0.31165513E-07 0.12445035E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=30000.0 Y=90.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.65864397E-10 0.20825124E-08 50 0.0 0.0 0.92840334E-14 0.11592745E-10 0.16247081E-08 0.35264047E-08 75 0.0 0.25062209E-11 0.12690611E-08 0.36838277E-08 0.57753837E-08 0.57722005E-08 90 0.0 0.98424167E-08 0.14377200E-07 0.13429144E-07 0.12304604E-07 0.88840082E-08 95 0.59097033E-11 0.28230950E-07 0.25187923E-07 0.21970269E-07 0.19115102E-07 0.10852848E-07 99 0.13526767E-06 0.80749828E-07 0.62610525E-07 0.57959785E-07 0.40544993E-07 0.17481465E-07 99.5 0.25345207E-06 0.11674047E-06 0.94287941E-07 0.81522671E-07 0.47361077E-07 0.17962108E-07 99.9 0.62218726E-06 0.22123038E-06 0.19813035E-06 0.14556815E-06 0.59094461E-07 0.18709208E-07 100 0.34936356E-05 0.43670445E-06 0.21909176E-06 0.14606115E-06 0.78980747E-07 0.19330866E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=30000.0 Y=112.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.23345361E-12 0.47088083E-10 0.28057887E-08 0.67437043E-08 50 0.0 0.62331269E-11 0.15318589E-08 0.47521667E-08 0.10813505E-07 0.14239223E-07 75 0.0 0.11210062E-07 0.22545485E-07 0.23727203E-07 0.25251463E-07 0.28560905E-07 90 0.30338845E-08 0.61439380E-07 0.58503737E-07 0.54185911E-07 0.46454740E-07 0.40374253E-07 95 0.90963283E-07 0.10561797E-06 0.86726743E-07 0.76200081E-07 0.62735467E-07 0.44272010E-07 99 0.47112485E-06 0.22302675E-06 0.16909689E-06 0.14090898E-06 0.99676811E-07 0.50122829E-07 99.5 0.65351367E-06 0.27533167E-06 0.20922118E-06 0.17070170E-06 0.11543676E-06 0.51748586E-07 99.9 0.10784406E-05 0.41844237E-06 0.29186162E-06 0.24557761E-06 0.13325729E-06 0.52903065E-07 100 0.20587149E-05 0.70244937E-06 0.40353405E-06 0.26973731E-06 0.14793858E-06 0.53056681E-07 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 16 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=30000.0 Y=135.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.69041387E-11 0.64947194E-08 0.12591528E-07 0.23224793E-07 0.36272571E-07 50 0.0 0.20490724E-07 0.33088554E-07 0.36662065E-07 0.46559546E-07 0.58065218E-07 75 0.22570859E-07 0.77671871E-07 0.77909647E-07 0.78995015E-07 0.85990962E-07 0.85851411E-07 90 0.18494472E-06 0.16740989E-06 0.15365777E-06 0.14811320E-06 0.13546395E-06 0.11276023E-06 95 0.33302257E-06 0.26129362E-06 0.23807456E-06 0.22218791E-06 0.16813664E-06 0.12399533E-06 99 0.94607157E-06 0.56286763E-06 0.45282661E-06 0.38698556E-06 0.27706278E-06 0.14644928E-06 99.5 0.13263107E-05 0.73711476E-06 0.56172013E-06 0.48058166E-06 0.37332501E-06 0.15398774E-06 99.9 0.27695505E-05 0.11265029E-05 0.93776180E-06 0.85681131E-06 0.55677998E-06 0.16290767E-06 100 0.65669201E-05 0.14959496E-05 0.12713581E-05 0.10003M147E-05 0.62457548E-06 0.17522251E-06 CUMULATIVE FREQUENCY DISTRIBUTION AT X=40000.0 Y=315.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.16415163E-08 0.70380430E-08 50 0.0 0.0 0.29444877E-10 0.19349189E-08 0.84524601E-08 0.16231006E-07 75 0.0 0.60881220E-08 0.16645327E-07 0.19264924E-07 0.20944906E-07 0.24019435E-07 90 0.71701356E-09 0.53886090E-07 0.53000878E-07 0.51506767E-07 0.45976762E-07 0.37226414E-07 95 0.75505227E-07 0.99917543E-07 0.91774098E-07 0.81905512E-07 0.63249729E-07 0.41935728E-07 99 0.41088538E-06 0.22936251E-06 0.17727916E-06 0.15149800E-06 0.11761983E-06 0.55074278E-07 99.5 0.58249861E-06 0.28886063E-06 0.21878833E-06 0.18809868E-06 0.13698002E-06 0.55732723E-07 99.9 0.13457156E-05 0.43757666E-06 0.32631584E-06 0.82002043E-06 0.30040792E-06 0.58093370E-07 100 0.12992401E-04 0.25675909E-05 0.12838909E-05 0.86207729E-06 0.33248313E-06 0.58379729E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=40000.0 Y=337.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.35253844E-09 0.53102625E-08 50 0.0 0.0 0.67349663E-13 0.23781399E-09 0.38566021E-08 0.76761992E-08 75 0.0 0.29737235E-09 0.68120087E-08 0.97082982E-08 0.12000356E-07 0.11549659E-07 90 0.0 0.26685257E-07 0.26478013E-07 0.29063639E-07 0.24013083E-07 0.13988611E-07 95 0.76828286E-08 0.51009202E-07 0.48923273E-07 0.42713317E-07 0.31614430E-07 0.15853630E-07 99 0.25945445E-06 0.12263331E-06 0.88253955E-07 0.72231558E-07 0.46019963E-07 0.23189518E-07 99.5 0.36299582E-06 0.15003980E-06 0.10998303E-06 0.91423658E-07 0.50830963E-07 0.24025013E-07 99.9 0.69772511E-06 0.27427109E-06 0.15174987E-06 0.11625650E-06 0.69469593E-07 0.24556485E-07 100 0.17996481E-05 0.34739230E-06 0.17438481E-06 0.12516523E-06 0.76494473E-07 0.24756925E-07 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 17 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=40000.0 Y=0.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.69631855E-13 0.20553141E-08 50 0.0 0.0 0.0 0.0 0.14375043E-08 0.34248908E-08 75 0.0 0.0 0.38991144E-09 0.25732849E-08 0.51838285E-08 0.49844573E-08 90 0.0 0.63576451E-08 0.12781506E-07 0.12009970E-07 0.85428482E-08 0.77559221E-08 95 0.0 0.24914229E-07 0.21519909E-07 0.17115667E-07 0.11925533E-07 0.95558512E-08 99 0.11585513E-06 0.58398037E-07 0.43353321E-07 0.38138676E-07 0.35706218E-07 0.13780717E-07 99.5 0.22897450E-06 0.80479367E-07 0.68184363E-07 0.57399269E-07 0.48447543E-07 0.13859413E-07 99.9 0.43573579E-06 0.31790933E-06 0.21758177E-06 0.21185264E-06 0.10697067E-06 0.13931686E-07 100 0.50844637E-05 0.63555797E-06 0.31777898E-06 0.31517305E-06 0.10728007E-06 0.13931686E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=40000.0 Y=22.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.22825323E-14 0.10253214E-08 50 0.0 0.0 0.0 0.0 0.37899350E-09 0.15423209E-08 75 0.0 0.0 0.60948772E-11 0.50212967E-09 0.25850413E-08 0.26817426E-08 90 0.0 0.94948893E-09 0.64822387E-08 0.66115007E-08 0.59713088E-08 0.46137707E-08 95 0.0 0.13425790E-07 0.13770709E-07 0.11709076E-07 0.89902592E-08 0.53256137E-08 99 0.47268532E-07 0.42771248E-07 0.31585852E-07 0.26871376E-07 0.14729572E-07 0.65359025E-08 99.5 0.14044599E-06 0.62980973E-07 0.42434817E-07 0.32666609E-07 0.18163774E-07 0.65801409E-08 99.9 0.32420206E-06 0.10505386E-06 0.62342622E-07 0.86487489E-07 0.32380285E-07 0.66406116E-08 100 0.20757006E-05 0.25946258E-06 0.12973129E-06 0.97140855E-07 0.32380285E-07 0.66714563E-08 CUMULATIVE FREQUENCY DISTRIBUTION AT X=40000.0 Y=45.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.0 0.13420420E-08 50 0.0 0.0 0.0 0.0 0.30277159E-09 0.19575030E-08 75 0.0 0.0 0.98163491E-12 0.26609581E-09 0.33844989E-08 0.35684173E-08 90 0.0 0.54799099E-09 0.85229992E-08 0.87782972E-08 0.71423401E-08 0.58347283E-08 95 0.0 0.17286126E-07 0.17707460E-07 0.14583417E-07 0.11001159E-07 0.67578902E-08 99 0.60002037E-07 0.51943729E-07 0.43389754E-07 0.41945697E-07 0.31346310E-07 0.10047788E-07 99.5 0.16618321E-06 0.83851432E-07 0.64742324E-07 0.49712447E-07 0.37315683E-07 0.12012599E-07 99.9 0.38219673E-06 0.23010818E-06 0.13909863E-06 0.11604084E-06 0.39791168E-07 0.12678129E-07 100 0.27849810E-05 0.34812706E-06 0.17406353E-06 0.11604232E-06 0.46856055E-07 0.12763220E-07 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 18 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=40000.0 Y=67.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.0 0.86270013E-09 50 0.0 0.0 0.0 0.0 0.18723927E-09 0.16437189E-08 75 0.0 0.0 0.19616964E-11 0.29583536E-09 0.29029823E-08 0.27648739E-08 90 0.0 0.45677395E-09 0.62707031E-08 0.75733055E-08 0.63489232E-08 0.35549321E-08 95 0.0 0.12763330E-07 0.13008794E-07 0.11139939E-07 0.89749221E-08 0.43838959E-08 99 0.33933272E-07 0.47509751E-07 0.33027465E-07 0.24448063E-07 0.15027211E-07 0.84558280E-08 99.5 0.13824439E-06 0.66054895E-07 0.40431871E-07 0.30825113E-07 0.16482073E-07 0.85466070E-08 99.9 0.38007801E-06 0.10414516E-06 0.57283035E-07 0.38188688E-07 0.17925203E-07 0.86144318E-08 100 0.10713347E-05 0.21426695E-06 0.82410338E-07 0.51015938E-07 0.21639782E-07 0.87671630E-08 CUMULATIVE FREQUENCY DISTRIBUTION AT X=40000.0 Y=90.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0. 0 0.36115860E-10 0.15164872E-08 50 0.0 0.0 0.0 0.41449916E-11 0.10705856E-08 0.26077296E-08 75 0.0 0.82237873E-12 0.68779538E-09 0.23202409E-08 0.42293387E-08 0.43136446E-08 90 0.0 0.65096906E-08 0.10405316E-07 0.10173373E-07 0.89387164E-08 0.67975172E-08 95 0.15404657E-11 0.20744508E-07 0.19049246E-07 0.16678687E-07 0.13891455E-07 0.80735063E-08 99 0.93648168E-07 0.59597937E-07 0.5060003M3E-07 0.41623515E-07 0.30180381E-07 0.12550590E-07 99.5 0.18856923E-06 0.83812040E-07 0.69579073E-07 0.59586302E-07 0.34338292E-07 0.12818862E-07 99.9 0.44919136E-06 0.16302067E-06 0.14433573E-06 0.10652877E-06 0.42909726E-07 0.13341559E-07 100 0.25566906E-05 0.31958632E-06 0.16018430E-06 0.10678951E-06 0.57358410E-07 0.13782877E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=40000.0 Y=112.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.44786206E-13 0.20067781E-10 0.18704158E-08 0.47645052E-08 50 0.0 0.20901163E-11 0.88423890E-09 0.31391185E-08 0.74166522E-08 0.10151794E-07 75 0.0 0.72699855E-08 0.16055758E-07 0.16961692E-07 0.18201654E-07 0.21012170E-07 90 0.13907424E-08 0.44147285E-07 0.42939924E-07 0.39192841E-07 0.34247254E-07 0.29138306E-07 95 0.62572951E-07 0.77944890E-07 0.62158051E-07 0.56820568E-07 0.46285223E-07 0.32769321E-07 99 0.35544366E-06 0.16516822E-06 0.12869509E-06 0.10627093E-06 0.72404021E-07 0.37315800E-07 99.5 0.48561060E-06 0.20236121E-06 0.15044947E-06 0.12279213E-06 0.86895113E-07 0.39183174E-07 99.9 0.79982300E-06 0.30243359E-06 0.23379363E-06 0.18339102E-06 0.10336390E-06 0.40233235E-07 100 0.15243104E-05 0.50295489E-06 0.29130939E-06 0.19718789E-06 0.11713684E-06 0.40354642E-07 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 19 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=40000.0 Y=135.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.17996013E-11 0.42544315E-08 0.87951726E-08 0.16500621E-07 0.26431923E-07 50 0.0 0.13923973E-07 0.23451772E-07 0.26243036E-07 0.33586602E-07 0.42776964E-07 75 0.12926265E-07 0.55918868E-07 0.56889608E-07 0.57493668E-07 0.62766333E-07 0.61176479E-07 90 0.13196137E-06 0.12335147E-06 0.11182908E-06 0.11028703E-06 0.97954683E-07 0.81658641E-07 95 0.24321042E-06 0.19214144E-06 0.17277318E-06 0.16163261E-06 0.12189474E-06 0.89847731E-07 99 0.69058160E-06 0.40855002E-06 0.32181708E-06 0.27994167E-06 0.20150475E-06 0.10477578E-06 99.5 0.10288722E-05 0.54148290E-06 0.39110370E-06 0.34589146E-06 0.27409010E-06 0.11023269E-06 99.9 0.19892714E-05 0.83666066E-06 0.69441830E-06 0.63590898E-06 0.40677452E-06 0.11642396E-06 100 0.49683067E-05 0.11077846E-05 0.94137056E-06 0.74459365E-06 0.45793308E-06 0.12506968E-06 CUMULATIVE FREQUENCY DISTRIBUTION AT X=50000.0 Y=315.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.11853969E-08 0.55911684E-08 50 0.0 0.0 0.15915338E-10 0.13169581E-08 0.67191372E-08 0.13015494E-07 75 0.0 0.43038213E-08 0.12962797E-07 0.15104355E-07 0.16195525E-07 0.18793767E-07 90 0.36273518E-09 0.42316998E-07 0.42017792E-07 0.40966444E-07 0.36742584E-07 0.29288746E-07 95 0.54992793E-07 0.78129574E-07 0.72207968E-07 0.64581457E-07 0.49703644E-07 0.32882163E-07 99 0.33280520E-06 0.18264325E-06 0.14367447E-06 0.12006387E-06 0.90980166E-07 0.44202082E-07 99.5 0.48250172E-06 0.23287839E-06 0.17397065E-06 0.15041292E-06 0.10630970E-06 0.44734783E-07 99.9 0.10621479E-05 0.34794130E-06 0.25547547E-06 0.67242036E-06 0.24399679E-06 0.46763812E-07 100 0.10739011E-04 0.20961907E-05 0.10481454E-05 0.70316611E-06 0.26973709E-06 0.46990777E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=50000.0 Y=337.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.23571856E-09 0.41648924E-08 50 0.0 0.0 0.19380348E-13 0.14101728E-09 0.30366298E-08 0.60264966E-08 75 0.0 0.17223564E-09 0.51954352E-08 0.76911952E-08 0.91056904E-08 0.90638999E-08 90 0.0 0.21044961E-07 0.20916513E-07 0.22435927E-07 0.18708000E-07 0.11039180E-07 95 0.45941526E-08 0.40792976E-07 0.38187956E-07 0.33429160E-07 0.24837654E-07 0.12232128E-07 99 0.20600692E-06 0.97148813E-07 0.70691158E-07 0.58054486E-07 0.36737926E-07 0.18491644E-07 99.5 0.28410670E-06 0.11614532E-06 0.87081730E-07 0.74278603E-07 0.39955427E-07 0.19061513E-07 99.9 0.55124275E-06 0.22283587E-06 0.11997895E-06 0.94546067E-07 0.56433741E-07 0.19482982E-07 100 0.14447642E-05 0.28267436E-06 0.14182086E-06 0.10229849E-06 0.62306071E-07 0.19628473E-07 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 20 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=50000.0 Y=0.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.25092474E-13 0.16122919E-08 50 0.0 0.0 0.0 0.0 0.99717168E-09 0.26935338E-08 75 0.0 0.0 0.22834719E-09 0.18305966E-08 0.41064112E-08 0.39980179E-08 90 0.0 0.46071484E-08 0.10087042E-07 0.96617967E-08 0.68796489E-08 0.61201533E-08 95 0.0 0.20100636E-07 0.16803586E-07 0.14196448E-07 0.98225712E-08 0.76537745E-08 99 0.87091394E-07 0.45476163E-07 0.36103128E-07 0.31477288E-07 0.28805363E-07 0.10817931E-07 99.5 0.17823288E-06 0.65993390E-07 0.54441589E-07 0.45532108E-07 0.39213191E-07 0.10876999E-07 99.9 0.36152659E-06 0.25359185E-06 0.17618959E-06 0.16722169E-06 0.84218016E-07 0.10931323E-07 100 0.40133209E-05 0.50166511E-06 0.25083256E-06 0.24891347E-06 0.84423675E-07 0.10931323E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=50000.0 Y=22.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.0 0.78266593E-09 50 0.0 0.0 0.0 0.0 0.27549363E-09 0.12099282E-08 75 0.0 0.0 0.29529669E-11 0.33172798E-09 0.19754711E-08 0.20782787E-08 90 0.0 0.62962968E-09 0.48998245E-08 0.52175260E-08 0.45992010E-08 0.36191163E-08 95 0.0 0.10249266E-07 0.10755432E-07 0.94190682E-08 0.71207644E-08 0.41645407E-08 99 0.36101284E-07 0.35021920E-07 0.26912769E-07 0.21362300E-07 0.12348206E-07 0.52444129E-08 99.5 0.11135671E-06 0.50203244E-07 0.33474695E-07 0.25565598E-07 0.15020778E-07 0.52745222E-08 99.9 0.26841957E-06 0.82788972E-07 0.52334890E-07 0.68378199E-07 0.25531119E-07 0.53263918E-08 100 0.16410777E-05 0.20513471E-06 0.10256736E-06 0.76593324E-07 0.25531119E-07 0.53520317E-08 CUMULATIVE FREQUENCY DISTRIBUTION AT X=50000.0 Y=45.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.0 0.10340857E-08 50 0.0 0.0 0.0 0.0 0.18030499E-09 0.15494794E-08 75 0.0 0.0 0.42945606E-12 0.15061261E-09 0.25657800E-08 0.29090854E-08 90 0.0 0.33783154E-09 0.64839725E-08 0.69931403E-08 0.54554761E-08 0.45059920E-08 95 0.0 0.13322733E-07 0.13732663E-07 0.11582031E-07 0.86609830E-08 0.52724012E-08 99 0.43783377E-07 0.41510184E-07 0.33729030E-07 0.32147092E-07 0.24144676E-07 0.79870048E-08 99.5 0.13243022E-06 0.66692735E-07 0.49707701E-07 0.38130608E-07 0.28835643E-07 0.94942649E-08 99.9 0.30703234E-06 0.19617551E-06 0.10707288E-06 0.93966776E-07 0.31763602E-07 0.10014510E-07 100 0.22552031E-05 0.28190198E-06 0.14095099E-06 0.93967287E-07 0.37749661E-07 0.10081720E-07 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 21 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=50000.0 Y=67.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.0 0.66957306E-09 50 0.0 0.0 0.0 0.0 0.13316517E-09 0.12845931E-08 75 0.0 0.0 0.85038216E-12 0.16582083E-09 0.22065068E-08 0.21248860E-08 90 0.0 0.25389424E-09 0.50534226E-08 0.57119536E-08 0.50176823E-08 0.28658880E-08 95 0.0 0.10465790E-07 0.10157930E-07 0.91188816E-08 0.68588584E-08 0.34008540E-08 99 0.24164102E-07 0.35183987E-07 0.27026164E-07 0.18310264E-07 0.11509790E-07 0.64450134E-08 99.5 0.11171124E-06 0.54052329E-07 0.32624158E-07 0.23696042E-07 0.13030974E-07 0.65142629E-08 99.9 0.28228010E-06 0.82283577E-07 0.44146546E-07 0.29431028E-07 0.14633770E-07 0.65637700E-08 100 0.84701344E-06 0.16940265E-06 0.65154836E-07 0.40333973E-07 0.16320641E-07 0.66900334E-08 CUMULATIVE FREQUENCY DISTRIBUTION AT X=50000.0 Y=90.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.20694460E-10 0.11800114E-08 50 0.0 0.0 0.0 0.19688175E-11 0.81600304E-09 0.20301589E-08 75 0.0 0.31775851E-12 0.43454973E-09 0.16164319E-08 0.33696921E-08 0.34307661E-08 90 0.0 0.45849120E-08 0.82456673E-08 0.81490867E-08 0.73634006E-08 0.54987304E-08 95 0.51647667E-12 0.16686656E-07 0.15317362E-07 0.13467044E-07 0.11251270E-07 0.63576735E-08 99 0.73126216E-07 0.48637965E-07 0.42723254E-07 0.32386758E-07 0.24012792E-07 0.97243422E-08 99.5 0.14855880E-06 0.67772135E-07 0.55989315E-07 0.47435265E-07 0.26773638E-07 0.98806865E-08 99.9 0.36986239E-06 0.14183593E-06 0.11295282E-06 0.83600185E-07 0.33485254E-07 0.10276274E-07 100 0.20064053E-05 0.25080067E-06 0.12563481E-06 0.83756504E-07 0.44745281E-07 0.10615800E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=50000.0 Y=112.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.12215150E-13 0.94269731E-11 0.13790900E-08 0.36257559E-08 50 0.0 0.84960749E-12 0.57637051E-09 0.22458901E-08 0.57519642E-08 0.77996631E-08 75 0.0 0.50542823E-08 0.12315439E-07 0.13372876E-07 0.14208720E-07 0.16725675E-07 90 0.75359941E-09 0.34573283E-07 0.33278660E-07 0.30816604E-07 0.27703496E-07 0.22581052E-07 95 0.44954490E-07 0.63112225E-07 0.49922416E-07 0.45039464E-07 0.36442820E-07 0.25874247E-07 99 0.29372399E-06 0.13212582E-06 0.10093214E-06 0.83105817E-07 0.58743339E-07 0.29899567E-07 99.5 0.39168447E-06 0.16215336E-06 0.11737382E-06 0.97298368E-07 0.68320730E-07 0.31828201E-07 99.9 0.64866003E-06 0.23529321E-06 0.19623712E-06 0.14293482E-06 0.86031491E-07 0.32638635E-07 100 0.12040582E-05 0.39247425E-06 0.22610521E-06 0.16602985E-06 0.97728844E-07 0.32739788E-07 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 22 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=50000.0 Y=135.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.61075624E-12 0.31693310E-08 0.66972738E-08 0.12690837E-07 0.20674896E-07 50 0.0 0.10099292E-07 0.18149407E-07 0.20214408E-07 0.26503898E-07 0.34343568E-07 75 0.83025924E-08 0.44163883E-07 0.44727006E-07 0.45825875E-07 0.49546831E-07 0.47610992E-07 90 0.10267865E-06 0.97962243E-07 0.87843659E-07 0.87005276E-07 0.77128107E-07 0.63993582E-07 95 0.19357014E-06 0.15113994E-06 0.13635895E-06 0.12813746E-06 0.95651558E-07 0.70772842E-07 99 0.54038247E-06 0.32589605E-06 0.24782901E-06 0.22050733E-06 0.16026121E-06 0.81001417E-07 99.5 0.80859462E-06 0.42909994E-06 0.30845001E-06 0.27604972E-06 0.21563494E-06 0.85226077E-07 99.9 0.16250297E-05 0.66202301E-06 0.54818537E-06 0.50672486E-06 0.31821128E-06 0.89998935E-07 100 0.40223113E-05 0.87409626E-06 0.74308213E-06 0.58785832E-06 0.35921062E-06 0.96486076E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=80000.0 Y=315.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.65276673E-09 0.35078707E-08 50 0.0 0.0 0.33894190E-11 0.60718031E-09 0.38736765E-08 0.80197466E-08 75 0.0 0.19328388E-08 0.77655038E-08 0.92039798E-08 0.10344905E-07 0.11389400E-07 90 0.76484916E-10 0.25294739E-07 0.25548477E-07 0.25730539E-07 0.22523533E-07 0.17330667E-07 95 0.29226076E-07 0.48009852E-07 0.43391363E-07 0.39309654E-07 0.30696153E-07 0.21243380E-07 99 0.20973710E-06 0.11531552E-06 0.87721560E-07 0.75226922E-07 0.55266543E-07 0.27757252E-07 99.5 0.30590235E-06 0.14711543E-06 0.10695692E-06 0.91145296E-07 0.67181190E-07 0.28096817E-07 99.9 0.63627107E-06 0.21613107E-06 0.15217483E-06 0.43817931E-06 0.15639898E-06 0.29515526E-07 100 0.70768247E-05 0.13542603E-05 0.67714234E-06 0.45366562E-06 0.17241052E-06 0.29666275E-07 CUMULATIVE FREQUENCY DISTRIBUTION AT X=80000.0 Y=337.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.84785207E-10 0.24457543E-08 50 0.0 0.0 0.0 0.45899451E-10 0.17995252E-08 0.35901322E-08 75 0.0 0.51442711E-10 0.28513145E-08 0.44887614E-08 0.54845017E-08 0.56187446E-08 90 0.0 0.12769597E-07 0.12972219E-07 0.13275660E-07 0.10979658E-07 0.66874719E-08 95 0.14491313E-08 0.25121921E-07 0.22533687E-07 0.20588466E-07 0.15167060E-07 0.73721367E-08 99 0.12983469E-06 0.61765377E-07 0.44980368E-07 0.35164355E-07 0.23213261E-07 0.11513386E-07 99.5 0.18876881E-06 0.73988758E-07 0.51687838E-07 0.46414165E-07 0.24687512E-07 0.11739687E-07 99.9 0.32741599E-06 0.13922465E-06 0.73254171E-07 0.61163576E-07 0.36286373E-07 0.12001777E-07 100 0.90657738E-06 0.18304536E-06 0.91745505E-07 0.66791301E-07 0.40278195E-07 0.12073233E-07 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 23 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=80000.0 Y=0.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.25106469E-14 0.99453712E-09 50 0.0 0.0 0.0 0.0 0.55796257E-09 0.16581954E-08 75 0.0 0.0 0.80589202E-10 0.95763264E-09 0.24900506E-08 0.25746785E-08 90 0.0 0.22760132E-08 0.61041199E-08 0.57902909E-08 0.43640469E-08 0.38284007E-08 95 0.0 0.12208240E-07 0.10959212E-07 0.91982102E-08 0.62144672E-08 0.48259530E-08 99 0.48402377E-07 0.30818953E-07 0.21944107E-07 0.20212426E-07 0.19731385E-07 0.65269639E-08 99.5 0.11177519E-06 0.42664013E-07 0.32363843E-07 0.32549750E-07 0.25111248E-07 0.65584551E-08 99.9 0.24386242E-06 0.15219257E-06 0.11290774E-06 0.10185670E-06 0.50956118E-07 0.65897545E-08 100 0.24445608E-05 0.30557010E-06 0.15278505E-06 0.15143064E-06 0.51036523E-07 0.65897545E-08 CUMULATIVE FREQUENCY DISTRIBUTION AT X=80000.0 Y=22.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.0 0.46133164E-09 50 0.0 0.0 0.0 0.0 0.12066736E-09 0.72181616E-09 75 0.0 0.0 0.52365095E-12 0.12807970E-09 0.12061769E-08 0.12459991E-08 90 0.0 0.22165453E-09 0.29164720E-08 0.31495748E-08 0.29592928E-08 0.22402589E-08 95 0.0 0.59576664E-08 0.67835089E-08 0.59894063E-08 0.43192188E-08 0.26721245E-08 99 0.17530951E-07 0.22263201E-07 0.17530020E-07 0.13612464E-07 0.84006615E-08 0.33540584E-08 99.5 0.65391646E-07 0.31685744E-07 0.21958471E-07 0.17399760E-07 0.99603028E-08 0.33648779E-08 99.9 0.16862316E-06 0.52199283E-07 0.35745270E-07 0.41626812E-07 0.15459236E-07 0.34284178E-08 100 0.99904355E-06 0.12488044E-06 0.62440222E-07 0.46377711E-07 0.15459236E-07 0.34394771E-08 CUMULATIVE FREQUENCY DISTRIBUTION AT X=80000.0 Y=45.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.0 0.62765548E-09 50 0.0 0.0 0.0 0.0 0.86242069E-10 0.94237307E-09 75 0.0 0.0 0.60965772E-13 0.47255977E-10 0.15263830E-08 0.18479362E-08 90 0.0 0.10838444E-09 0.36246495E-08 0.43227182E-08 0.32060408E-08 0.26872247E-08 95 0.0 0.74232460E-08 0.83683602E-08 0.71442834E-08 0.56041856E-08 0.31772152E-08 99 0.23824935E-07 0.25591824E-07 0.20618280E-07 0.19569001E-07 0.15346156E-07 0.49528595E-08 99.5 0.82678980E-07 0.39745835E-07 0.29984275E-07 0.22488898E-07 0.16998818E-07 0.58194978E-08 99.9 0.19101225E-06 0.12275189E-06 0.69057705E-07 0.60217360E-07 0.20355181E-07 0.61314793E-08 100 0.14452171E-05 0.18065225E-06 0.90326125E-07 0.60217417E-07 0.24044109E-07 0.61726304E-08 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 24 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=80000.0 Y=67.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.0 0.40123016E-09 50 0.0 0.0 0.0 0.0 0.57695071E-10 0.76099349E-09 75 0.0 0.0 0.11640369E-12 0.46190177E-10 0.12886678E-08 0.12265651E-08 90 0.0 0.74503903E-10 0.28157352E-08 0.34115928E-08 0.29993801E-08 0.18697315E-08 95 0.0 0.57772347E-08 0.62005761E-08 0.55078466E-08 0.41141384E-08 0.20978645E-08 99 0.11210879E-07 0.23970365E-07 0.16480179E-07 0.12894198E-07 0.64184746E-08 0.36281811E-08 99.5 0.69407463E-07 0.31309682E-07 0.20505123E-07 0.14411793E-07 0.79329112E-08 0.36715551E-08 99.9 0.19176292E-06 0.50278885E-07 0.25450035E-07 0.17403586E-07 0.90481507E-08 0.37003107E-08 100 0.51563939E-06 0.10312783E-06 0.39664567E-07 0.24554254E-07 0.95206083E-08 0.37798848E-08 CUMULATIVE FREQUENCY DISTRIBUTION AT X=80000.0 Y=90.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours(16978) 24 Hours(16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.0 0.59401772E-11 0.70902839E-09 50 0.0 0.0 0.0 0.26056636E-12 0.40447090E-09 0.12827850E-08 75 0.0 0.31595447E-13 0.16143946E-09 0.78973983E-09 0.20683550E-08 0.21955537E-08 90 0.0 0.21497186E-08 0.51419100E-08 0.51890368E-08 0.45642992E-08 0.33887582E-08 95 0.16535089E-13 0.10429602E-07 0.94783310E-08 0.87783860E-08 0.73252231E-08 0.39429153E-08 99 0.45823214E-07 0.33394400E-07 0.24858196E-07 0.21363114E-07 0.14849093E-07 0.56996932E-08 99.5 0.93907090E-07 0.46579807E-07 0.37967766E-07 0.33527250E-07 0.15856369E-07 0.57991549E-08 99.9 0.24400498E-06 0.10003M176E-06 0.67518158E-07 0.50156849E-07 0.19876644E-07 0.59569629E-08 100 0.12037644E-05 0.15047056E-06 0.75310766E-07 0.50207177E-07 0.26520990E-07 0.61537762E-08 CUMULATIVE FREQUENCY DISTRIBUTION AT X=80000.0 Y=112.5 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) 24 Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.0 0.0 0.17013136E-11 0.72735729E-09 0.21114108E-08 50 0.0 0.90145935E-13 0.24937985E-09 0.10941141E-08 0.33791445E-08 0.45784425E-08 75 0.0 0.23630458E-08 0.70595156E-08 0.79780342E-08 0.87566576E-08 0.10210552E-07 90 0.18571251E-09 0.20381883E-07 0.20710111E-07 0.18896735E-07 0.17511347E-07 0.13531970E-07 95 0.21296035E-07 0.38957580E-07 0.31680546E-07 0.28699560E-07 0.22742029E-07 0.16043234E-07 99 0.18808896E-06 0.83608597E-07 0.64716914E-07 0.50944852E-07 0.37962000E-07 0.18823801E-07 99.5 0.25296754E-06 0.10035802E-06 0.73881438E-07 0.61447224E-07 0.41299103E-07 0.20404279E-07 99.9 0.39284362E-06 0.15931448E-06 0.12458219E-06 0.88562729E-07 0.57374056E-07 0.20854820E-07 100 0.72630843E-06 0.26562009E-06 0.13284415E-06 0.11288694E-06 0.65481743E-07 0.20917575E-07 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.3-41 Sheet 25 of 25 Revision 15 September 2003 CUMULATIVE FREQUENCY DISTRIBUTION AT X=80000.0 Y=135.0 Z=0.0 Percentage of Total Hours Hourly (17127) 8 Hours (17140) 16 Hours (16978) Hours (16827) 3 Days (17161) 26 Days (16606) 25 0.0 0.53608065E-13 0.15507566E-08 0.37072401E-08 0.72642301E-08 0.12430696E-07 50 0.0 0.54108469E-08 0.10682420E-07 0.12110306E-07 0.16393336E-07 0.21119209E-07 75 0.31305785E-08 0.26878141E-07 0.27722947E-07 0.28005950E-07 0.30296825E-07 0.29032226E-07 90 0.61701087E-07 0.60302057E-07 0.54364037E-07 0.52630334E-07 0.46747747E-07 0.38486551E-07 95 0.11980205E-06 0.91934908E-07 0.84140481E-07 0.78212679E-07 0.58057847E-07 0.43278874E-07 99 0.33317684E-06 0.19935442E-06 0.14976899E-06 0.13110741E-06 0.99965803E-07 0.47624940E-07 99.5 0.48037498E-06 0.25995200E-06 0.18830934E-06 0.17129037E-06 0.13088629E-06 0.50088705E-07 99.9 0.10322974E-05 0.40344401E-06 0.33194232E-06 0.30887401E-06 0.18952687E-06 0.52885735E-07 100 0.25595009E-05 0.53274880E-06 0.45236368E-06 0.35789134E-06 0.21528973E-06 0.56458632E-07 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-42 DCPP SITE - STABILITY BASED ON VERTICAL TEMPERATURE GRADIENT MAY 1973-APRIL 1974 EXTREMELY UNSTABLE (T < -1.9°C/100M) FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.8 5.1 9.6 15.1 21.1 39.6 CALM 1 0 0 0 0 0 1 11.3 22.50 6 6 5 0 0 0 17 5.1 45.00 4 6 1 1 0 0 12 4.8 67.50 8 18 0 1 1 0 28 4.9 90.00 8 10 4 2 0 0 24 5.6 112.50 3 11 2 4 5 1 26 10.3 135.00 7 10 3 7 1 0 28 8.2 157.50 4 5 0 1 0 0 10 4.9 180.00 4 6 0 0 0 0 10 3.5 202.50 1 7 3 1 0 0 12 6.4 225.00 3 4 5 12 1 0 25 11.3 247.50 1 2 0 1 2 0 6 11.4 270.00 6 3 1 0 0 0 10 3.9 292.50 9 14 11 2 6 1 43 8.6 315.00 17 22 21 38 2 18 138 13.9 337.50 8 17 13 20 1 7 76 12.5 360.00 7 10 15 2 0 0 34 7.1 __ ___ __ __ __ __ ___ ___ Column Sums 96 51 85 92 49 27 500 9.9
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-43 DCPP SITE - STABILITY BASED ON VERTICAL TEMPERATURE GRADIENT MAY 1973-APRIL 1974 MODERATELY UNSTABLE (T -1.9° to -1.7°C/100M) FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.8 5.1 9.6 15.1 21.1 39.6 CALM 0 0 0 0 0 0 0 0.0 22.50 1 0 1 0 0 0 2 5.3 45.00 0 0 0 0 0 0 0 0.0 67.50 4 1 1 0 0 0 6 3.9 90.00 1 1 5 1 0 0 8 8.6 112.50 1 0 3 1 0 0 5 8.8 135.00 2 3 3 5 0 0 13 9.9 157.50 4 5 1 0 0 0 10 4.5 180.00 1 1 0 0 0 0 2 3.6 202.50 1 1 0 0 0 0 2 3.9 225.00 1 1 0 0 0 0 2 3.3 247.50 1 0 1 0 0 0 2 5.3 270.00 0 2 1 0 0 0 3 5.9 292.50 2 2 2 3 0 0 9 8.6 315.00 4 8 6 6 4 0 28 10.1 337.50 1 0 3 5 2 3 14 16.8 360.00 1 3 6 1 0 0 11 8.7 ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 25 28 33 22 6 3 117 9.1 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-44 DCPP SITE - STABILITY BASED ON VERTICAL TEMPERATURE GRADIENT MAY 1973-APRIL 1974 SLIGHTLY UNSTABLE (T -1.7 to -1.5°C/100M) FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.8 5.1 9.6 15.1 21.1 39.6 CALM 0 0 0 0 0 0 0 0.0 22.50 2 1 2 0 0 0 5 6.0 45.00 2 1 3 0 0 0 6 6.1 67.50 1 2 1 0 0 0 4 4.4 90.00 1 0 1 0 0 0 2 4.8 112.50 1 2 0 0 1 1 5 12.6 135.00 1 8 6 11 0 0 26 10.1 157.50 2 8 2 0 1 0 13 6.7 180.00 1 5 0 0 2 0 8 7.7 202.50 1 3 0 0 0 0 4 3.4 225.00 0 2 0 0 0 0 2 4.1 247.50 2 0 0 0 0 0 2 2.3 270.00 1 2 0 0 0 0 3 4.2 292.50 4 12 7 1 0 0 24 6.1 315.00 1 4 4 2 1 0 12 10.0 337.50 1 3 8 13 4 4 33 15.4 360.00 0 2 2 1 0 0 5 8.5 ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 21 55 36 28 9 5 154 9.2 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-45 DCPP SITE - STABILITY BASED ON VERTICAL TEMPERATURE GRADIENT MAY 1973-APRIL 1974 NEUTRAL (T -1.5 to -0.5°C/100M) FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.8 5.1 9.6 15.1 21.1 39.6 CALM 2 0 0 0 0 0 2 1.4 22.50 8 31 24 4 0 1 68 6.9 45.00 12 22 19 10 0 0 63 7.1 67.50 15 12 14 3 0 1 45 6.4 90.00 12 22 8 5 1 0 48 6.3 112.50 8 37 32 33 12 3 125 10.8 135.00 22 83 73 39 16 7 240 9.3 157.50 27 107 20 12 10 11 187 8.2 180.00 20 54 5 1 0 0 80 4.2 202.50 15 23 3 2 1 0 44 4.9 225.00 23 12 4 7 2 0 48 6.0 247.50 13 15 3 0 1 0 32 4.3 270.00 22 32 4 1 0 0 59 4.1 292.50 28 124 71 27 4 1 255 7.2 315.00 18 106 222 230 209 145 930 15.7 337.50 9 44 69 65 61 35 283 14.9 360.00 17 50 42 19 2 0 130 7.6 ___ ___ ___ ___ ___ ___ ____ ____ Column Sums 271 774 613 458 319 204 2639 11.2
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-46 DCPP SITE - STABILITY BASED ON VERTICAL TEMPERATURE GRADIENT MAY 1973-APRIL 1974 SLIGHTLY STABLE (T -0.5 to 1.5°C/100M) FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.8 5.1 9.6 15.1 21.1 39.6 CALM 8 0 0 0 0 0 8 4.9 22.50 39 125 44 7 0 0 215 5.4 45.00 52 92 48 16 3 0 211 6.0 67.50 48 39 25 20 4 0 136 6.6 90.00 56 64 25 6 2 0 153 5.1 112.50 41 95 49 29 19 1 234 8.0 135.00 34 167 109 37 5 2 354 7.5 157.50 27 99 23 8 3 1 161 6.1 180.00 25 26 5 0 0 0 56 4.0 202.50 15 10 4 0 0 0 29 4.1 225.00 21 16 3 3 3 1 47 6.1 247.50 19 16 1 2 1 0 39 4.5 270.00 19 16 6 1 0 0 42 4.6 292.50 28 116 53 39 13 5 254 8.2 315.00 48 203 202 298 275 185 1211 15.3 337.50 29 120 128 113 30 10 430 10.5 360.00 33 128 101 32 2 0 296 7.3 ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 537 1336 827 611 360 205 3876 9.8 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-47 DCPP SITE - STABILITY BASED ON VERTICAL TEMPERATURE GRADIENT MAY 1973-APRIL 1974 MODERATELY STABLE (T +1.5 to +4.0°C/100M) FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.8 5.1 9.6 15.1 21.1 39.6 CALM 0 0 0 0 0 0 0 0.0 22.50 11 15 2 0 0 0 28 4.2 45.00 14 13 7 2 2 0 38 5.9 67.50 14 7 2 0 0 0 23 3.4 90.00 24 13 1 0 0 0 38 3.3 112.50 18 26 1 0 0 0 45 3.6 135.00 15 33 22 1 0 0 71 5.8 157.50 9 20 4 0 0 0 33 5.1 180.00 9 9 0 0 0 0 18 3.8 202.50 4 2 0 0 0 0 6 2.9 225.00 3 2 0 1 0 0 6 5.2 247.50 4 3 1 0 0 0 8 4.2 270.00 2 0 3 0 0 0 5 6.8 292.50 7 20 12 14 15 9 77 13.2 315.00 13 38 72 78 81 68 350 16.6 337.50 8 23 15 12 3 0 61 8.7 360.00 4 14 4 0 0 0 22 5.4 ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 159 238 146 108 101 77 829 10.8
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-48 DCPP SITE - STABILITY BASED ON VERTICAL TEMPERATURE GRADIENT MAY 1973-APRIL 1974 EXTREMELY STABLE (T GREATER THAN 4.0°C/100M) FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.8 5.1 9.6 15.1 21.1 39.6 CALM 0 0 0 0 0 0 0 0.0 22.50 4 1 0 0 0 0 5 3.3 45.00 2 2 1 0 0 0 5 4.8 67.50 1 0 0 0 0 0 1 2.9 90.00 3 3 0 0 0 0 6 3.3 112.50 3 8 0 0 0 0 11 3.7 135.00 7 18 4 1 0 0 30 4.9 157.50 7 7 0 0 0 0 14 3.5 180.00 2 1 0 0 0 1 4 8.6 202.50 5 0 0 1 0 0 6 3.5 225.00 3 0 0 0 0 0 3 2.0 247.50 1 2 0 0 0 0 3 3.7 270.00 0 3 0 1 0 0 4 6.7 292.50 0 10 6 5 4 6 31 13.3 315.00 6 45 40 30 27 28 176 14.0 337.50 3 7 2 1 2 0 15 8.0 360.00 2 0 1 0 0 0 3 4.6 ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 49 107 54 39 33 35 317 10.7 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-49 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS A ANNUAL FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 4 5 2 0 0 0 0 11 8.9 45.00 0 1 1 3 0 0 0 0 5 11.7 67.50 0 3 1 1 0 0 0 0 5 7.4 90.00 0 1 7 1 0 0 0 0 9 10.5 112.50 0 3 2 5 5 2 0 0 17 15.4 135.00 1 9 6 9 4 1 0 0 30 12.3 157.50 1 10 1 2 0 0 0 0 14 7.2 180.00 1 6 1 1 0 1 0 0 10 7.7 202.50 0 2 0 1 0 1 0 0 4 12.6 225.00 1 3 2 1 0 0 0 0 7 6.6 247.50 0 3 0 1 0 0 0 0 4 7.8 270.00 1 2 1 1 0 0 0 0 5 7.0 292.50 1 15 2 1 3 2 0 0 24 9.3 315.00 2 11 14 20 11 24 0 0 82 17.6 337.50 2 5 10 12 13 7 0 0 49 15.5 360.00 1 6 9 3 4 0 0 0 23 10.6 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 11 84 62 64 40 8 0 0 299 13.2 Hours of Calm = 0 Sums of this table: row totals = 299 and column totals = 299
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-50 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS B ANNUAL FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 1 1 2 1 0 0 0 0 5 7.7 45.00 0 1 0 0 1 0 0 0 2 13.0 67.50 1 0 2 0 0 0 0 0 3 8.5 90.00 0 2 5 1 0 0 0 0 8 8.7 112.50 0 0 6 1 0 0 0 0 7 10.7 135.00 2 4 8 6 0 1 0 0 21 10.7 157.50 4 9 6 0 0 2 0 0 21 7.8 180.00 2 1 3 2 0 0 0 0 8 8.5 202.50 1 4 0 0 0 0 0 0 5 3.8 225.00 1 2 2 0 0 0 0 0 5 6.2 247.50 2 3 1 0 0 0 0 0 6 4.4 270.00 1 4 1 0 1 0 0 0 7 6.8 292.50 3 11 6 2 0 0 0 0 22 6.7 315.00 4 10 12 13 9 9 0 0 57 14.4 337.50 1 0 3 7 6 4 0 0 21 18.1 360.00 0 3 8 1 1 0 0 0 13 10.1 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 23 55 65 34 18 16 0 0 211 10.9 Hours of Calm = 3 Sums of this table: row totals = 211 and column totals = 211
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-51 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS C ANNUAL FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 1 1 2 1 0 0 0 0 5 8.5 45.00 1 1 3 0 0 0 0 0 5 6.7 67.50 1 0 1 0 0 0 0 0 2 4.9 90.00 1 1 1 0 0 0 0 0 3 5.1 112.50 1 2 0 1 3 1 0 0 8 14.4 135.00 1 8 0 12 0 0 0 0 31 10.2 157.50 3 15 7 2 5 0 0 0 32 8.6 180.00 2 10 1 0 2 1 0 0 16 7.8 202.50 1 3 0 0 0 0 0 0 4 3.4 225.00 2 4 0 0 0 0 0 0 6 3.7 247.50 4 2 0 0 0 0 0 0 6 3.1 270.00 1 5 1 0 0 0 0 0 7 5.3 292.50 4 14 11 3 0 0 0 0 32 7.0 315.00 1 9 15 29 27 17 2 0 100 17.9 337.50 1 1 8 29 9 6 0 0 54 17.0 360.00 0 3 3 2 0 0 0 0 8 9.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 25 79 63 79 46 25 2 0 319 12.6
Hours of Calm = 0 Sums of this table: row totals = 319 and column totals = 319
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-52 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS D ANNUAL FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 18 79 62 14 0 1 0 0 174 7.1 45.00 22 62 41 14 1 0 0 0 140 6.8 67.50 18 32 22 6 0 0 0 0 78 6.0 90.00 23 48 13 8 1 0 0 0 93 5.8 112.50 23 130 97 61 27 9 0 0 347 9.7 135.00 37 237 167 88 41 40 0 0 610 10.0 157.50 46 215 56 26 15 21 3 0 382 8.1 180.00 32 105 16 6 0 0 0 0 159 4.7 202.50 40 48 8 2 1 0 0 0 99 4.4 225.00 50 29 4 5 1 0 0 0 89 4.2 247.50 25 34 6 1 0 0 0 0 66 4.2 270.00 57 78 15 3 1 0 0 0 154 4.4 292.50 62 290 200 81 13 5 0 0 651 7.8 315.00 41 247 532 652 501 319 6 0 2298 15.6 337.50 22 143 230 202 156 77 3 0 833 13.9 360.00 31 113 101 36 3 0 0 0 284 7.6 ____ ____ ____ ____ ____ ____ ____ ____ ____ ____ Column Sums 547 1890 1570 1205 761 472 12 0 6457 11.3 Hours of Calm = 5 Sums of this table: row totals = 6457 and column totals = 6457
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-53 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS E ANNUAL FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 77 270 82 16 1 0 0 0 446 5.5 45.00 123 207 76 20 3 0 0 0 429 5.3 67.50 127 114 53 37 4 1 0 0 336 5.8 90.00 127 130 28 8 2 0 0 0 295 4.4 112.50 107 188 74 41 27 5 0 0 442 7.1 135.00 66 281 150 46 5 10 0 559 7.3 157.50 46 139 31 10 3 2 0 0 231 5.8 180.00 41 39 5 1 0 0 0 0 86 3.8 202.50 26 22 6 1 0 0 0 0 55 4.1 225.00 37 27 9 12 3 1 0 0 89 6.4 247.50 25 24 3 3 3 0 0 0 58 5.2 270.00 44 28 13 3 1 0 0 0 89 4.8 292.50 70 216 121 81 42 18 0 0 548 9.0 315.00 85 358 441 611 502 353 14 0 2364 15.4 337.50 68 253 210 169 52 11 1 0 764 9.6 360.00 78 266 171 44 3 1 0 0 563 6.8 ____ ____ ____ ____ ____ ____ ____ ____ ____ ____ Column Sums 1147 2562 1473 1103 651 402 16 0 7354 9.6 Hours of Calm = 12 Sums of this table: row totals = 7354 and column totals = 7354
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-54 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS F ANNUAL FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sum Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 22 32 9 0 0 0 0 0 63 4.6 45.00 23 24 14 2 2 0 0 0 65 5.5 67.50 28 20 3 0 1 0 0 0 52 3.9 90.00 46 24 1 1 0 0 0 0 72 3.4 112.50 41 58 6 0 0 0 0 0 105 4.0 135.00 26 66 32 1 0 0 2 0 127 6.0 157.50 19 32 4 0 0 0 0 0 55 4.5 180.00 11 14 0 0 0 0 0 0 25 3.8 202.50 11 3 0 0 0 0 0 0 14 2.6 225.00 7 9 1 6 3 0 0 0 26 8.1 247.50 5 9 3 1 1 0 0 0 19 5.8 270.00 9 3 4 0 0 0 0 0 16 4.6 292.50 14 35 29 21 22 18 0 0 139 12.6 315.00 30 83 121 147 158 176 16 0 731 17.7 337.50 16 47 30 27 10 0 0 0 130 9.1 360.00 11 29 11 0 1 0 0 0 52 5.6 ___ ___ ___ ___ ___ ___ ___ __ ____ ____ Column Sums 319 488 268 206 198 194 18 0 1691 11.4
Hours of Calm = 0 Sums of this table: row totals = 1691 and column totals = 1691
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-55 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS G ANNUAL FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 4 2 0 0 0 0 0 0 6 3.4 45.00 6 5 1 1 0 0 0 0 13 4.7 67.50 3 3 0 0 0 0 0 0 6 3.0 90.00 7 6 0 0 0 0 0 0 13 3.3 112.50 14 21 3 1 0 0 0 0 39 4.4 135.00 22 39 8 1 0 0 0 0 70 4.6 157.50 12 13 0 0 0 0 0 0 25 3.4 180.00 5 3 0 1 0 1 0 0 10 6.6 202.50 5 0 0 1 0 0 0 0 6 3.5 225.00 8 3 1 2 0 0 0 0 14 5.3 247.50 4 9 0 0 0 0 0 0 13 4.2 270.00 5 4 0 1 0 0 0 0 10 4.8 292.50 3 15 21 10 5 8 0 0 62 12.0 315.00 19 75 62 61 52 69 10 0 348 15.5 337.50 3 17 8 5 2 2 0 0 37 9.3 360.00 7 2 2 0 0 0 0 0 11 4.2 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 127 217 106 84 59 80 10 0 683 11.0 Hours of Calm = 0 Sums of this table: row totals = 683 and column totals = 683
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-56 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS A JAN. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 2 1 2 0 0 0 0 5 10.7 45.00 0 0 0 3 0 0 0 0 3 14.7 67.50 0 0 1 0 0 0 0 0 1 9.0 90.00 0 0 1 0 0 0 0 0 1 11.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 1 2 2 0 1 0 0 6 14.3 157.50 0 1 0 0 0 0 0 0 1 5.0 180.00 0 0 0 0 0 1 0 0 1 25.0 202.50 0 0 0 0 0 1 0 0 1 28.0 225.00 0 0 2 0 0 0 0 0 2 9.5 247.50 0 0 0 1 0 0 0 0 1 17.1 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 0 2 0 0 0 0 0 2 8.0 315.00 0 1 6 2 1 2 0 0 12 15.3 337.50 0 0 1 0 0 0 0 0 1 9.0 360.00 0 0 0 1 4 0 0 0 5 20.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 0 5 16 11 5 5 0 0 42 14.4
Hours of Calm = 0 Sums of this table: row totals = 42 and column totals = 42
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-57 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS B JAN. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 1 1 0 0 0 0 2 12.0 45.00 0 1 0 0 1 0 0 0 2 13.0 67.50 0 0 1 0 0 0 0 0 1 11.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 1 0 0 1 0 0 2 20.7 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 0 0 1 0 0 0 0 0 1 8.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 2 0 0 0 0 0 2 10.5 247.50 1 0 0 0 0 0 0 0 1 3.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 0 0 0 0 0 0 0 0 0.0 315.00 0 0 0 5 1 2 0 0 8 18.5 337.50 0 0 0 2 0 0 0 0 2 13.0 360.00 0 0 2 0 1 0 0 0 3 12.7 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 1 1 8 8 3 3 0 0 24 14.4
Hours of Calm = 0 Sums of this table: row totals = 24 and column totals = 24
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-58 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS C JAN. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 1 0 0 0 0 1 14.2 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 0 0 0 0 0 0 0 0.0 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 0 0 0 0 0 0 0 0 0.0 315.00 0 0 2 0 1 0 0 0 3 14.2 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 1 0 0 0 0 1 16.2 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 0 0 2 2 1 0 0 0 5 14.6 Hours of Calm = 0 Sums of this table: row totals = 5 and column totals = 5
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-59 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS D JAN. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 3 7 11 6 0 0 0 0 27 9.0 45.00 0 12 5 5 0 0 0 0 22 8.0 67.50 4 4 1 2 0 0 0 0 11 6.3 90.00 1 5 1 5 1 0 0 0 13 10.2 112.50 3 6 15 19 3 0 0 0 46 11.3 135.00 1 12 14 17 7 14 0 0 65 15.7 157.50 1 11 6 7 1 8 3 0 37 16.1 180.00 0 5 0 0 0 0 0 0 5 4.2 202.50 1 10 0 0 0 0 0 11 4.4 225.00 4 1 0 0 0 0 0 0 5 3.1 247.50 1 1 3 0 0 0 0 0 5 7.3 270.00 1 6 1 1 0 0 0 0 9 5.8 292.50 1 5 10 3 0 1 0 0 20 10.0 315.00 0 1 19 46 29 9 0 0 104 16.7 337.50 1 3 12 9 9 13 3 0 50 18.7 360.00 1 4 7 3 1 0 0 0 16 9.9 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 23 93 105 123 51 45 6 0 446 13.4
Hours of Calm = 0 Sums of this table: row totals = 446 and column totals = 446
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-60 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS E JAN. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 10 45 11 1 0 0 0 0 67 5.5 45.00 14 23 10 2 0 0 0 0 49 5.3 67.50 11 18 13 5 2 0 0 0 49 7.1 90.00 9 19 7 2 1 0 0 0 38 5.9 112.50 12 24 18 10 5 0 0 0 69 8.1 135.00 3 36 38 11 2 1 1 0 92 9.0 157.50 5 7 4 6 0 1 0 0 23 9.5 180.00 4 1 3 1 0 0 0 0 9 6.5 202.50 2 1 2 0 0 0 0 0 5 5.4 225.00 4 1 1 0 0 0 0 0 6 3.3 247.50 1 2 1 1 0 0 0 0 5 6.7 270.00 4 1 3 1 0 0 0 0 9 6.6 292.50 2 4 3 2 5 0 0 0 16 11.8 315.00 3 17 18 46 21 2 0 0 107 13.5 337.50 5 13 29 13 1 0 0 0 61 9.2 360.00 4 38 24 2 0 0 0 0 68 6.5 ___ ___ ___ ___ ___ ___` ___ ___ ___ ___ Column Sums 93 250 185 103 37 4 1 0 673 8.4
Hours of Calm = 0 Sums of this table: row totals = 673 and column totals = 673
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-61 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS F JAN. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 5 11 5 0 0 0 0 0 21 5.2 45.00 5 3 4 0 1 0 0 0 13 5.7 67.50 4 2 1 0 0 0 0 0 7 4.3 90.00 8 6 0 0 0 0 0 0 14 3.6 112.50 7 17 1 0 0 0 0 0 25 4.6 135.00 3 11 7 0 0 0 0 0 21 6.1 157.50 5 6 0 0 0 0 0 0 11 3.6 180.00 0 3 0 0 0 0 0 0 3 4.2 202.50 3 0 0 0 0 0 0 0 3 2.3 225.00 2 4 0 0 0 0 0 0 6 4.1 247.50 1 3 2 0 0 0 0 0 6 4.7 270.00 3 2 0 0 0 0 0 0 5 3.4 292.50 1 6 5 0 0 0 0 0 12 6.0 315.00 3 14 8 8 2 0 0 0 35 9.3 337.50 6 6 2 0 0 0 0 0 14 4.5 360.00 1 5 0 0 0 0 0 0 6 4.1 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 57 99 35 8 3 0 0 0 202 5.5 Hours of Calm = 0 Sums of this table: row totals = 202 and column totals = 202
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-62 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS G JAN. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 2 0 0 0 0 0 0 0 2 2.5 67.50 0 1 0 0 0 0 0 0 1 4.0 90.00 0 1 0 0 0 0 0 0 1 4.0 112.50 3 4 0 0 0 0 0 0 7 3.7 135.00 6 6 3 0 0 0 0 0 15 4.8 157.50 2 2 0 0 0 0 0 0 4 3.3 180.00 2 1 0 1 0 0 0 0 4 6.4 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 1 2 0 0 0 0 0 0 3 3.9 247.50 2 6 0 0 0 0 0 0 8 4.5 270.00 1 1 0 0 0 0 0 0 2 5.0 292.50 1 0 5 1 0 0 0 0 7 9.8 315.00 5 9 4 3 1 0 0 0 22 7.8 337.50 0 1 0 0 0 0 0 0 1 5.0 360.00 2 0 1 0 0 0 0 0 3 5.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 27 34 13 5 1 0 0 0 80 5.9 Hours of Calm = 0 Sums of this table: row totals = 80 and column totals = 80
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-63 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS A FEB. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 0 0 0 0 0 0 0 0.0 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 0 0 0 0 0 0 0 0 0.0 315.00 0 0 0 0 0 0 0 0 0 0.0 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ __ Column Sums 0 0 0 0 0 0 0 0 0 0.0
Hours of Calm = 0 Sums of this table: row totals = 0 and column totals = 0
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-64 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS B FEB. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 1 0 0 0 0 0 1 11.5 157.50 0 0 1 0 0 1 0 0 2 19.7 180.00 1 0 0 0 0 0 0 0 1 2.7 202.50 0 1 0 0 0 0 0 0 1 3.7 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 1 0 0 0 0 0 0 0 1 2.7 292.50 0 0 0 0 0 0 0 0 0 0.0 315.00 0 0 0 0 0 0 0 0 0 0.0 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 2 1 2 0 0 1 0 0 6 10.0 Hours of Calm = 0 Sums of this table: row totals = 6 and column totals = 6
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-65 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS C FEB. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 1 0 0 0 1 21.2 135.00 0 0 0 0 0 0 0 0 0 0.0 157.50 0 2 0 0 0 0 0 0 2 5.6 180.00 0 1 0 0 0 0 0 0 1 4.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 1 0 0 0 0 0 0 1 3.6 247.50 1 0 0 0 0 0 0 0 1 2.6 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 0 0 0 0 0 0 0 0 0.0 315.00 0 0 0 0 1 0 0 0 1 23.8 337.50 0 0 0 1 0 0 0 0 1 17.2 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 1 4 0 1 2 0 0 0 8 10.4 Hours of Calm = 0 Sums of this table: row totals = 8 and column totals = 8
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-66 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS D FEB. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 2 7 12 2 0 0 0 0 23 7.6 45.00 0 3 8 4 0 0 0 0 15 9.9 67.50 0 1 3 1 0 0 0 0 5 9.5 90.00 2 4 0 1 0 0 0 0 7 5.6 112.50 0 11 3 4 6 0 0 0 24 10.9 135.00 0 14 25 16 7 9 0 0 71 12.8 157.50 2 27 18 5 2 8 0 0 62 10.6 180.00 4 11 9 3 0 0 0 0 27 6.8 202.50 1 4 2 0 0 0 0 0 7 5.4 225.00 4 5 0 1 0 0 0 0 10 4.4 247.50 1 3 0 0 0 0 0 0 4 3.8 270.00 1 2 3 1 0 0 0 0 7 7.5 292.50 5 11 1 0 0 0 0 0 17 4.1 315.00 0 13 12 32 22 8 0 0 87 15.1 337.50 0 4 24 34 19 33 0 0 114 18.6 360.00 4 12 13 8 0 0 0 0 37 8.4 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 26 132 133 112 56 58 0 0 517 12.3
Hours of Calm = 0 Sums of this table: row totals = 517 and column totals = 517
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-67 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS E FEB. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 8 42 16 1 0 0 0 0 67 5.4 45.00 21 29 19 4 1 0 0 0 74 5.8 67.50 19 19 7 7 0 0 0 0 52 5.5 90.00 27 24 4 0 0 0 0 0 55 3.7 112.50 20 24 4 1 4 0 0 0 53 5.4 135.00 6 10 2 7 1 0 0 0 26 7.9 157.50 0 10 4 1 1 0 0 0 16 7.4 180.00 1 0 0 0 0 0 0 0 1 1.7 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 1 1 1 1 0 0 0 0 4 8.1 247.50 1 2 0 0 0 0 0 0 3 3.2 270.00 1 2 0 0 1 0 0 0 4 7.3 292.50 3 2 3 1 3 0 0 0 12 10.0 315.00 3 13 22 30 35 4 0 0 107 14.6 337.50 4 17 23 26 10 1 0 0 81 11.4 360.00 8 26 44 8 0 0 0 0 86 8.2 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 123 221 149 87 56 5 0 0 641 8.2
Hours of Calm = 0 Sums of this table: row totals = 641 and column totals = 641
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-68 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS F FEB. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 5 1 0 0 0 0 0 6 4.5 45.00 1 4 1 2 1 0 0 0 9 8.9 67.50 2 3 0 0 0 0 0 0 5 3.5 90.00 7 4 0 0 0 0 0 0 11 2.8 112.50 5 1 1 0 0 0 0 0 7 3.2 135.00 4 3 0 0 0 0 0 0 7 3.4 157.50 0 2 0 0 0 0 0 0 2 5.8 180.00 1 0 0 0 0 0 0 0 1 2.2 202.50 1 0 0 0 0 0 0 0 1 2.9 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 2 1 0 0 0 0 0 0 3 3.1 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 1 1 0 0 0 0 0 0 2 3.0 315.00 1 3 7 9 9 1 0 0 30 14.7 337.50 0 8 3 1 0 0 0 0 12 6.9 360.00 0 2 0 0 0 0 0 0 2 4.8 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 25 37 13 12 10 1 0 0 98 7.8
Hours of Calm = 0 Sums of this table: row totals = 98 and column totals = 98
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-69 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS G FEB. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 1 1 0 0 0 0 0 0 2 3.0 135.00 0 2 0 0 0 0 0 0 2 4.0 157.50 1 0 0 0 0 0 0 0 1 2.8 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 0 0 0 0 0 0 0 0 0.0 315.00 0 3 4 0 3 0 0 0 10 11.8 337.50 0 6 2 0 0 0 0 0 8 6.2 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 2 12 6 0 3 0 0 0 23 8.1
Hours of Calm = 0 Sums of this table: row totals = 23 and column totals = 23
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-70 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS A MARCH FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 1 0 0 0 0 0 0 1 6.1 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 1 0 0 0 0 0 0 1 6.5 135.00 0 1 0 0 3 0 0 0 4 17.8 157.50 0 1 1 1 0 0 0 0 3 10.7 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 1 0 0 0 0 0 0 1 3.8 292.50 0 1 0 0 0 0 0 0 1 7.0 315.00 0 0 0 0 0 0 0 0 0 0.0 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 1 0 0 0 0 0 0 1 3.5 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 0 7 1 1 3 0 0 0 12 10.9
Hours of Calm = 0 Sums of this table: row totals = 12 and column totals = 12
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-71 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS B MARCH FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 1 0 0 0 0 0 0 1 3.9 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 1 0 0 0 0 0 0 1 3.2 112.50 0 0 2 0 0 0 0 0 2 10.8 135.00 0 0 0 1 0 0 0 0 1 12.2 157.50 0 1 1 0 0 1 0 0 3 12.8 180.00 0 0 1 2 0 0 0 0 3 14.4 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 1 0 0 0 0 0 0 1 4.8 270.00 0 1 0 0 0 0 0 0 1 3.1 292.50 0 1 1 0 0 0 0 0 2 7.7 315.00 0 0 2 2 3 4 0 0 11 21.4 337.50 0 0 0 0 4 1 0 0 5 23.6 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 0 6 7 5 7 6 0 0 31 16.1
Hours of Calm = 0 Sums of this table: row totals = 31 and column totals = 31
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-72 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS C MARCH FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 1 0 0 0 0 0 0 0 1 2.8 112.50 0 0 0 1 1 0 0 2 15.5 135.00 0 0 0 0 0 0 0 0 0 0.0 157.50 1 3 3 1 4 0 0 0 12 11.8 180.00 1 3 1 0 0 1 0 0 6 8.6 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 1 0 0 0 0 0 0 1 4.6 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 1 0 0 0 0 0 0 1 5.5 292.50 0 0 2 1 0 0 0 0 3 11.3 315.00 0 5 2 15 17 13 2 0 54 20.2 337.50 0 0 0 14 4 2 0 0 20 18.2 360.00 0 1 0 0 0 0 0 0 1 5.9 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 3 14 8 32 26 16 2 0 101 17.2 Hours of Calm = 0 Sums of this table: row totals = 101 and column totals = 101
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-73 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS D MARCH FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 1 7 3 0 0 0 0 0 11 5.7 45.00 3 9 9 0 0 0 0 0 21 6.4 67.50 1 2 0 1 0 0 0 0 4 7.3 90.00 2 3 3 0 0 0 0 0 8 5.9 112.50 1 6 11 9 9 1 0 0 37 13.2 135.00 1 13 30 24 20 11 0 0 99 14.6 157.50 1 20 7 5 9 1 0 0 43 10.5 180.00 1 10 2 1 0 0 0 0 14 5.6 202.50 4 4 1 1 0 0 0 0 10 5.1 225.00 5 4 0 0 0 0 0 0 9 2.9 247.50 4 1 2 1 0 0 0 0 8 6.4 270.00 1 4 2 1 0 0 0 0 8 6.5 292.50 4 24 13 4 3 1 0 0 49 8.0 315.00 5 25 42 78 97 28 0 0 275 16.3 337.50 4 15 50 48 53 7 0 0 177 14.7 360.00 1 23 8 1 0 0 0 0 33 6.7 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 39 170 183 174 191 9 0 0 806 13.2
Hours of Calm = 0 Sums of this table: row totals = 806 and column totals = 806
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-74 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS E MARCH FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 3 26 7 2 0 0 0 0 38 5.4 45.00 9 24 10 3 0 0 0 0 46 5.7 67.50 5 6 4 3 0 0 0 0 18 6.6 90.00 4 10 3 2 0 0 0 0 19 6.3 112.50 5 16 6 12 7 0 0 0 46 10.0 135.00 6 35 22 9 2 4 0 0 78 9.1 157.50 4 18 5 1 2 0 0 0 30 6.7 180.00 2 2 0 0 0 0 0 0 4 3.1 202.50 4 1 1 0 0 0 0 0 6 4.2 225.00 3 1 0 0 0 0 0 0 4 2.9 247.50 1 1 0 0 0 0 0 0 2 3.7 270.00 2 1 2 0 0 0 0 0 5 5.2 292.50 1 10 8 2 0 0 0 0 21 6.7 315.00 3 19 14 22 19 4 0 0 81 13.4 337.50 1 10 20 17 6 1 0 0 55 11.8 360.00 0 20 13 7 0 0 0 0 40 8.1 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 53 200 115 80 36 9 0 0 493 8.8
Hours of Calm = 0 Sums of this table: row totals = 493 and column totals = 493
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-75 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS F MARCH FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 1 2 0 0 0 0 0 3 9.7 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 1 1 0 0 0 0 0 0 2 3.0 112.50 0 1 0 0 0 0 0 0 1 3.3 135.00 0 0 1 0 0 0 0 0 1 8.0 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 1 0 0 0 0 0 0 0 1 2.4 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 3 0 2 3 0 0 0 8 13.2 315.00 1 3 2 2 7 0 0 0 15 14.4 337.50 0 2 0 0 0 0 0 0 2 6.1 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 3 11 5 4 10 0 0 0 33 11.6 Hours of Calm = 0 Sums of this table: row totals = 33 and column totals = 33
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-76 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS G MARCH FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 0 0 0 0 0 0 0 0.0 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 0 0 0 0 0 0 0 0 0.0 315.00 0 0 3 1 1 0 0 0 5 12.6 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 0 0 3 1 1 0 0 0 5 12.6 Hours of Calm = 0 Sums of this table: row totals = 5 and column totals = 5
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-77 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS A APRIL FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 1 0 0 0 0 0 0 1 6.0 157.50 0 5 0 0 0 0 0 0 5 5.5 180.00 0 4 1 0 0 0 0 0 5 5.6 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 1 0 0 0 0 0 0 1 5.1 247.50 0 2 0 0 0 0 0 0 2 5.0 270.00 1 1 0 0 0 0 0 0 2 3.1 292.50 0 2 0 1 0 0 0 0 3 7.7 315.00 0 1 2 0 0 0 0 3 9.0 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 1 17 3 1 0 0 0 0 22 6.0
Hours of Calm = 0 Sums of this table: row totals = 22 and column totals = 22
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-78 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS B APRIL FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 3 1 0 0 0 0 0 4 5.8 157.50 0 3 4 0 0 0 0 0 7 7.1 180.00 0 0 1 0 0 0 0 0 1 7.1 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 1 0 0 0 0 0 0 1 4.0 292.50 1 4 2 0 0 0 0 0 7 5.8 315.00 1 4 6 2 2 2 0 0 17 12.5 337.50 0 0 0 0 1 1 0 0 2 24.5 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 2 15 14 2 3 3 0 0 39 9.9
Hours of Calm = 0 Sums of this table: row totals = 39 and column totals = 39
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-79 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS C APRIL FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 1 0 0 0 0 0 0 1 5.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 1 2 0 0 0 0 0 3 8.6 157.50 0 1 1 1 0 0 0 0 3 7.9 180.00 0 2 0 0 0 0 0 0 2 5.6 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 2 0 0 0 0 0 0 0 2 2.9 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 1 1 0 0 0 0 0 2 7.9 292.50 1 2 2 0 0 0 0 0 5 7.4 315.00 0 0 7 12 6 4 0 0 29 17.0 337.50 0 0 0 0 1 0 0 0 1 19.2 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 3 8 13 13 7 4 0 0 48 13.3
Hours of Calm = 0 Sums of this table: row totals = 48 and column totals = 48
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-80 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS D APRIL FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 14 4 1 0 0 0 0 19 6.2 45.00 1 4 2 0 0 0 0 0 7 5.3 67.50 4 0 3 0 0 0 0 0 7 4.9 90.00 1 2 0 0 0 0 0 0 3 3.7 112.50 1 10 23 0 0 0 0 0 34 8.5 135.00 2 17 7 1 0 0 0 0 27 6.5 157.50 4 9 5 3 0 0 0 0 21 6.6 180.00 1 4 1 2 0 0 0 0 8 7.3 202.50 2 3 0 0 0 0 0 0 5 3.4 225.00 1 2 1 0 0 0 0 0 4 5.5 247.50 1 2 0 0 0 0 0 0 3 4.2 270.00 3 1 2 0 1 0 0 0 7 7.2 292.50 4 13 12 6 0 0 0 0 35 7.8 315.00 1 17 61 71 66 69 0 0 285 17.5 337.50 3 24 63 39 25 9 0 0 163 12.9 360.00 4 13 21 1 0 0 0 0 39 7.2 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 33 135 205 124 92 78 0 0 667 12.9 Hours of Calm = 0 Sums of this table: row totals = 667 and column totals = 667
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-81 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS E APRIL FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 7 21 10 0 0 0 0 0 38 5.5 45.00 13 14 3 4 0 0 0 0 34 5.3 67.50 7 4 2 1 0 0 0 0 14 5.0 90.00 7 6 1 0 0 0 0 0 14 3.8 112.50 7 13 4 3 0 0 0 0 27 5.7 135.00 6 5 6 1 0 0 0 0 18 6.1 157.50 1 3 1 0 0 0 0 0 5 4.4 180.00 3 0 0 0 0 0 0 0 3 3.0 202.50 1 1 0 0 0 0 0 0 2 3.5 225.00 0 1 0 0 0 0 0 0 1 4.8 247.50 0 1 0 1 0 0 0 0 2 9.5 270.00 2 0 0 1 0 0 0 0 3 7.3 292.50 0 1 7 9 1 0 0 0 18 12.9 315.00 3 7 19 38 48 42 0 0 157 18.7 337.50 2 12 15 23 11 6 0 0 69 13.6 360.00 14 20 28 5 0 0 0 0 67 6.8 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 73 109 96 86 60 48 0 0 472 11.5
Hours of Calm = 1 Sums of this table: row totals = 472 and column totals = 472
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-82 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS F APRIL FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 2 2 0 0 0 0 0 0 4 4.6 45.00 3 3 3 0 0 0 0 0 9 5.2 67.50 6 4 0 0 0 0 0 0 10 3.2 90.00 5 5 0 0 0 0 0 0 10 3.7 112.50 3 0 0 0 0 0 0 0 3 2.7 135.00 3 1 1 0 0 0 0 0 5 5.0 157.50 2 1 0 0 0 0 0 0 3 3.4 180.00 3 1 0 0 0 0 0 0 4 3.4 202.50 1 1 0 0 0 0 0 0 2 3.0 225.00 1 0 0 0 0 0 0 0 1 2.9 247.50 0 1 0 0 0 0 0 0 1 5.2 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 1 2 2 2 0 0 0 7 12.7 315.00 3 3 12 9 22 15 0 0 64 18.2 337.50 1 3 3 1 0 0 0 0 8 7.4 360.00 0 3 1 0 0 0 0 0 4 6.3 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 33 29 22 12 24 15 0 0 135 11.4
Hours of Calm = 0 Sums of this table: row totals = 135 and column totals = 135
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-83 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS G APRIL FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 2 0 0 0 0 0 0 0 2 2.4 45.00 0 0 1 0 0 0 0 0 1 8.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 2 2 0 0 0 0 0 0 4 3.5 112.50 0 1 0 0 0 0 0 0 1 3.6 135.00 0 1 0 0 0 0 0 0 1 4.0 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 1 0 0 0 0 0 0 0 1 1.6 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 3 1 0 0 0 0 0 4 5.9 315.00 0 8 8 3 10 2 0 0 31 13.6 337.50 0 1 2 0 0 0 0 0 3 9.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 5 16 12 3 10 2 0 0 48 10.6
Hours of Calm = 0 Sums of this table: row totals = 48 and column totals = 48
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-84 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS A MAY FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 0 0 0 0 0 0 0 0.0 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 1 0 0 0 0 0 0 0 1 3.0 315.00 1 4 0 0 0 0 0 0 5 4.8 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 2 4 0 0 0 0 0 0 6 4.5
Hours of Calm = 0 Sums of this table: row totals = 6 and column totals = 6
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-85 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS B MAY FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 0 0 0 0 0 0 0 0.0 157.50 0 1 0 0 0 0 0 0 1 4.0 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 1 0 0 0 0 0 0 1 3.8 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 2 0 0 0 0 0 0 2 4.1 292.50 0 0 0 0 0 0 0 0 0 0.0 315.00 0 0 0 0 0 0 0 0 0 0.0 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 0 4 0 0 0 0 0 0 4 4.0
Hours of Calm = 0 Sums of this table: row totals = 4 and column totals = 4
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-86 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS C MAY FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 0 0 0 0 0 0 0 0.0 157.50 0 1 0 0 0 0 0 0 1 6.5 180.00 0 1 0 0 0 0 0 0 1 4.4 202.50 0 1 0 0 0 0 0 0 1 3.1 225.00 0 1 0 0 0 0 0 0 1 3.8 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 1 0 0 0 0 0 0 1 5.4 292.50 0 2 1 0 0 0 0 0 3 5.6 315.00 0 0 0 0 0 0 0 0 0 0.0 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 0 7 1 0 0 0 0 0 8 5.0
Hours of Calm = 0 Sums of this table: row totals = 8 and column totals = 8
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-87 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS D MAY FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 3 2 0 0 0 0 0 5 6.1 45.00 3 1 0 0 0 0 0 0 4 2.6 67.50 0 7 0 0 0 0 0 0 7 3.6 90.00 3 3 1 0 0 0 0 0 7 4.4 112.50 2 15 2 0 0 0 0 0 19 5.3 135.00 8 25 5 0 0 0 0 0 38 4.8 157.50 9 12 1 0 0 0 0 0 22 3.8 180.00 3 13 0 0 0 0 0 0 16 3.7 202.50 4 3 0 0 0 0 0 0 7 3.0 225.00 6 1 0 0 0 0 0 0 7 2.7 247.50 4 5 0 0 0 0 0 0 9 3.4 270.00 9 12 1 0 0 0 0 0 22 3.5 292.50 8 32 25 6 0 0 0 0 71 6.9 315.00 2 23 72 94 79 80 2 0 352 17.7 337.50 1 15 22 8 18 11 0 0 75 15.0 360.00 2 5 2 0 0 0 0 0 9 4.7 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 64 175 133 108 97 91 2 0 670 12.8
Hours of Calm = 0 Sums of this table: row totals = 670 and column totals = 670
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-88 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS E MAY FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 4 11 5 0 0 0 0 0 20 5.2 45.00 5 3 1 0 0 0 0 0 9 4.1 67.50 4 2 1 0 0 0 0 0 7 4.1 90.00 2 3 1 0 0 0 0 0 6 5.0 112.50 1 12 5 1 0 0 0 0 19 6.3 135.00 6 22 1 1 0 0 0 0 30 4.6 157.50 3 7 2 0 0 0 0 0 12 4.8 180.00 5 2 0 0 0 0 0 0 7 2.9 202.50 3 4 0 0 0 0 0 0 7 4.2 225.00 5 3 0 0 0 0 0 0 8 2.9 247.50 6 2 0 0 0 0 0 0 8 2.8 270.00 6 3 1 0 0 0 0 0 10 3.9 292.50 7 32 2 10 6 1 0 0 58 8.3 315.00 13 42 47 45 47 56 0 0 250 15.7 337.50 5 27 23 15 9 1 0 0 80 9.8 360.00 6 28 8 1 0 0 0 0 43 5.6 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 81 203 97 73 62 58 0 0 574 10.6
Hours of Calm = 0 Sums of this table: row totals = 574 and column totals = 574
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-89 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS F MAY FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 1 1 0 0 0 0 0 0 2 3.9 45.00 0 0 1 0 0 0 0 0 1 7.1 67.50 0 1 0 0 0 0 0 0 1 3.9 90.00 1 1 0 0 0 0 0 0 2 3.1 112.50 0 1 0 0 0 0 0 0 1 6.3 135.00 0 4 3 0 0 0 0 0 7 6.6 157.50 0 0 1 0 0 0 0 0 1 7.5 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 1 0 1 0 0 0 0 2 9.3 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 2 0 0 0 0 0 2 10.3 292.50 1 3 1 5 4 2 0 0 16 15.2 315.00 2 6 10 15 14 37 0 0 84 20.6 337.50 0 1 1 4 1 0 0 0 7 13.7 360.00 1 1 0 0 0 0 0 0 2 3.1 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 6 20 19 25 19 39 0 0 128 17.2
Hours of Calm = 0 Sums of this table: row totals = 128 and column totals = 128
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-90 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS G MAY FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 1 0 0 0 0 0 0 0 1 2.6 45.00 0 1 0 0 0 0 0 0 1 4.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 1 0 0 0 0 0 0 0 1 2.6 112.50 1 3 3 1 0 0 0 0 8 7.3 135.00 2 3 2 0 0 0 0 0 7 5.3 157.50 1 0 0 0 0 0 0 0 1 2.5 180.00 0 0 0 0 0 1 0 0 1 24.4 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 1 0 0 0 0 0 0 0 1 3.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 1 0 0 0 0 0 0 0 1 2.7 292.50 0 2 2 1 0 1 0 0 6 10.5 315.00 3 9 15 8 7 19 0 0 61 16.5 337.50 0 2 1 1 0 2 0 0 6 14.7 360.00 0 1 0 0 0 0 0 0 1 5.8 ___ ____ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 11 21 23 11 7 23 0 0 96 13.5 Hours of Calm = 0 Sums of this table: row totals = 96 and column totals = 96
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-91 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS A JUNE FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 1 0 0 0 0 0 0 1 4.0 90.00 0 1 1 0 0 0 0 0 2 9.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 3 1 0 0 0 0 0 4 6.2 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 1 0 0 0 0 0 0 1 5.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 2 0 0 0 0 0 0 2 4.0 315.00 0 1 1 0 0 0 0 0 2 8.0 337.50 1 1 0 0 2 0 0 0 4 12.5 360.00 0 1 0 0 0 0 0 0 1 5.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 1 11 3 0 2 0 0 0 17 7.7
Hours of Calm = 0 Sums of this table: row totals = 17 and column totals = 17
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-92 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS B JUNE FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 0 0 0 0 0 0 0 0.0 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 2 0 0 0 0 0 0 2 4.2 315.00 0 1 1 0 0 0 0 0 2 9.0 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 0 3 1 0 0 0 0 0 4 6.6 Hours of Calm = 0 Sums of this table: row totals = 4 and column totals = 4
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-93 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS C JUNE FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 0 0 0 0 0 0 0 0.0 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 0 2 0 0 0 0 0 0 2 4.2 202.50 0 1 0 0 0 0 0 0 1 3.7 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 0 0 0 0 0 0 0 0 0.0 315.00 0 0 0 0 0 0 0 0 0 0.0 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 0 3 0 0 0 0 0 0 3 4.1 Hours of Calm = 0 Sums of this table: row totals = 3 and column totals = 3
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-94 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS D JUNE FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 2 0 0 0 0 0 0 2 3.6 45.00 0 3 0 0 0 0 0 0 3 4.5 67.50 2 1 0 0 0 0 0 0 3 2.8 90.00 1 3 1 1 0 0 0 0 6 7.1 112.50 0 7 11 2 0 0 0 0 20 8.5 135.00 4 19 10 3 0 0 0 0 36 6.3 157.50 6 17 3 0 0 0 0 0 26 4.6 180.00 3 6 0 0 0 0 0 0 9 3.5 202.50 2 1 0 0 0 0 0 0 3 3.2 225.00 4 3 0 0 0 0 0 0 7 3.1 247.50 3 2 0 0 0 0 0 0 5 3.2 270.00 8 8 0 0 0 0 0 0 16 3.4 292.50 3 18 19 0 0 0 0 0 40 6.9 315.00 8 29 62 73 47 37 0 0 256 15.3 337.50 2 10 8 13 11 3 0 0 47 13.5 360.00 1 7 1 0 0 0 0 0 9 5.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sum 47 136 115 92 58 40 0 0 488 11.5 Hours of Calm = 0 Sums of this table: row totals = 488 and column totals = 488
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-95 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS E JUNE FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 4 5 4 0 0 0 0 0 13 5.2 45.00 4 1 0 0 0 0 0 0 5 2.6 67.50 3 0 0 0 0 0 0 0 3 2.3 90.00 4 2 0 0 0 0 0 0 6 2.8 112.50 4 12 10 3 0 0 0 0 29 6.7 135.00 4 16 8 1 0 0 0 0 29 5.9 157.50 4 13 3 0 0 0 0 0 20 5.0 180.00 4 4 0 0 0 0 0 0 8 3.4 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 1 2 0 0 0 0 0 0 3 3.7 247.50 3 0 0 0 0 0 0 0 3 2.4 270.00 4 0 0 0 0 0 0 0 4 2.4 292.50 7 22 11 4 2 1 0 0 47 7.7 315.00 7 29 46 87 60 66 7 0 302 17.8 337.50 10 19 10 6 2 0 0 0 47 7.4 360.00 4 21 1 1 0 1 0 0 28 5.6 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 67 1 46 93 107 64 68 7 0 547 12.6
Hours of Calm = 0 Sums of this table: row totals = 547 and column totals = 547
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-96 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS F JUNE FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 1 0 0 0 0 0 0 0 1 3.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 1 0 0 0 0 0 1 4.3 112.50 0 3 2 0 0 0 0 0 5 6.7 135.00 1 3 3 0 0 0 0 0 7 6.2 157.50 0 0 1 0 0 0 0 0 1 10.1 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 1 0 0 0 0 0 0 1 3.7 292.50 0 0 2 2 1 0 0 0 5 14.2 315.00 1 8 3 21 23 24 6 0 86 21.2 337.50 2 2 3 5 6 0 0 0 18 13.1 360.00 1 0 2 0 0 0 0 0 3 7.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 6 18 16 28 30 24 6 0 128 17.6
Hours of Calm = 0 Sums of this table: row totals = 128 and column totals = 128
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-97 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS G JUNE FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 1 0 0 0 0 0 0 1 4.7 112.50 1 2 0 0 0 0 0 0 3 3.1 135.00 2 3 0 0 0 0 0 0 5 4.1 157.50 3 2 0 0 0 0 0 0 5 3.7 180.00 1 0 0 0 0 0 0 0 1 1.8 202.50 3 0 0 0 0 0 0 0 3 1.6 225.00 1 0 0 0 0 0 0 0 1 1.1 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 1 3 4 0 1 0 0 9 14.2 315.00 1 15 11 18 13 30 7 0 95 19.7 337.50 2 1 2 1 1 0 0 0 7 9.3 360.00 1 0 0 0 0 0 0 0 1 2.4 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 15 25 16 23 14 31 7 0 131 16.2
Hours of Calm = 0 Sums of this table: row totals = 131 and column totals = 131
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-98 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS A JULY FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 2 0 0 0 0 0 0 2 5.1 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 1 0 0 0 0 0 0 1 4.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 2 0 0 3 0 0 0 5 14.9 315.00 0 0 3 10 7 11 0 0 31 20.8 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 0 5 3 10 10 11 0 0 39 18.8 Hours of Calm = 0 Sums of this table: row totals = 39 and column totals = 39
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-99 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS B JULY FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 1 0 0 0 0 0 1 12.0 135.00 1 0 2 0 0 0 0 0 3 6.8 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 1 0 0 0 0 0 0 1 4.0 225.00 1 0 0 0 0 0 0 0 1 2.9 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0.0 292.50 0 3 1 0 0 0 0 0 4 6.5 315.00 0 0 0 0 0 0 0 0 0 0.0 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 2 4 4 0 0 0 0 0 10 6.5
Hours of Calm = 0 Sums of this table: row totals = 10 and column totals = 10
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-100 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS C JULY FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 1 0 0 0 0 0 0 0 1 2.5 135.00 0 0 1 0 0 0 0 0 1 7.1 157.50 0 1 0 0 0 0 0 0 1 4.6 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 1 0 0 0 0 0 0 0 1 2.6 270.00 1 1 0 0 0 0 0 0 2 3.6 292.50 1 3 1 0 0 0 0 0 5 5.2 315.00 0 1 0 0 1 0 0 0 2 10.7 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 4 6 2 0 1 0 0 0 13 5.5
Hours of Calm = 0 Sums of this table: row totals = 13 and column totals = 13
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-101 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS D JULY FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 3 6 0 0 0 0 0 0 9 3.4 45.00 4 0 0 0 0 0 0 0 4 2.4 67.50 1 1 0 0 0 0 0 0 2 3.9 90.00 1 3 0 0 0 0 0 0 4 4.3 112.50 2 22 8 5 0 0 0 0 37 7.1 135.00 6 21 17 2 0 0 0 0 46 6.6 157.50 7 29 4 0 0 0 0 0 40 5.0 180.00 7 10 0 0 0 0 0 0 17 3.3 202.50 3 2 0 0 0 0 0 0 5 2.5 225.00 9 5 1 0 0 0 0 0 15 3.5 247.50 3 5 0 0 0 0 0 0 8 3.2 270.00 6 8 0 0 0 0 0 0 14 3.4 292.50 9 46 23 14 0 0 0 0 92 7.5 315.00 7 55 84 49 56 39 3 0 293 14.4 337.50 4 18 8 3 0 0 0 0 33 6.8 360.00 7 8 0 0 0 0 0 0 15 3.5 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 79 239 145 73 56 39 3 0 634 9.8 Hours of Calm = 0 Sums of this table: row totals = 634 and column totals = 634
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-102 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS E JULY FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 1 2 0 0 0 0 0 0 3 3.8 45.00 1 1 0 0 0 0 0 0 2 3.2 67.50 1 0 0 0 0 0 0 0 1 2.1 90.00 5 2 0 0 0 0 0 0 7 2.7 112.50 3 7 3 0 0 0 0 0 13 5.8 135.00 6 15 9 2 0 0 0 0 32 5.9 157.50 4 15 2 0 0 0 0 0 21 4.7 180.00 6 6 0 0 0 0 0 0 12 3.3 202.50 3 2 1 0 0 0 0 0 6 3.9 225.00 3 2 0 0 0 0 0 0 5 2.7 247.50 2 4 0 0 0 0 0 0 6 3.3 270.00 7 4 2 0 0 0 0 0 13 3.6 292.50 15 24 25 15 2 2 0 0 83 8.2 315.00 15 59 83 86 80 74 5 0 402 15.9 337.50 7 20 11 7 0 0 0 0 45 7.3 360.00 5 6 3 0 0 0 0 0 14 4.9 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 84 169 139 110 82 76 5 0 665 12.1
Hours of Calm = 0 Sums of this table: row totals = 665 and column totals = 665
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-103 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS F JULY FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 1 0 0 0 0 0 1 9.3 135.00 1 5 2 0 0 0 0 0 8 5.7 157.50 0 1 0 0 0 0 0 0 1 6.8 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 1 0 0 0 0 0 0 0 1 2.7 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 1 0 0 0 0 0 0 0 1 1.9 270.00 1 0 0 0 0 0 0 0 1 2.5 292.50 1 3 4 1 0 4 0 0 13 14.0 315.00 2 6 3 12 8 31 4 0 66 22.0 337.50 0 0 0 1 0 0 0 0 1 17.0 360.00 0 0 0 0 1 0 0 0 1 19.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 7 15 10 14 9 35 4 0 94 18.5
Hours of Calm = 0 Sums of this table: row totals = 94 and column totals = 94
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-104 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS G JULY FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 1 0 0 0 0 0 0 1 3.1 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 2 1 0 0 0 0 0 3 6.5 157.50 0 2 0 0 0 0 0 0 2 4.6 180.00 0 1 0 0 0 0 0 0 1 6.4 202.50 0 0 0 1 0 0 0 0 1 12.2 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 0 0 0 0 0 0 0 0 0.0 315.00 0 1 1 0 2 3 1 0 8 23.0 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 0 7 2 1 2 3 1 0 16 14.7 Hours of Calm = 0 Sums of this table: row totals = 16 and column totals = 16
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-105 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS A AUG. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 0 0 0 0 0 0 0 0.0 157.50 0 1 0 0 0 0 0 0 1 5.8 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 1 0 0 0 0 0 0 1 4.2 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 5 0 0 0 0 0 0 5 4.4 315.00 1 2 0 0 0 1 0 0 4 9.7 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 1 9 0 0 0 1 0 0 11 6.4
Hours of Calm = 0 Sums of this table: row totals = 11 and column totals = 11
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-106 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS B AUG. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 0 0 0 0 0 0 0 0.0 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 1 0 0 0 0 0 0 1 3.7 225.00 0 1 0 0 0 0 0 0 1 3.5 247.50 0 2 0 0 0 0 0 0 2 4.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 1 0 0 0 0 0 0 0 1 2.5 315.00 0 1 0 0 0 0 0 0 1 5.4 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 1 5 0 0 0 0 0 0 6 3.8
Hours of Calm = 0 Sums of this table: row totals = 6 and column totals = 6
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-107 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS C AUG. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 1 0 0 0 0 0 1 7.9 157.50 0 0 1 0 0 0 0 0 1 7.7 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 2 0 0 0 0 0 0 2 4.4 270.00 0 1 0 0 0 0 0 0 1 3.2 292.50 0 1 2 1 0 0 0 0 4 9.6 315.00 0 0 0 0 0 0 0 0 0 0.0 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 0 4 4 1 0 0 0 0 9 7.3
Hours of Calm = 0 Sums of this table: row totals = 9 and column totals = 9
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-108 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS D AUG. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 3 4 0 0 0 0 0 0 7 3.1 45.00 2 3 0 0 0 0 0 0 5 3.2 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 1 1 0 0 0 0 0 0 2 3.3 112.50 3 3 0 0 0 0 0 0 6 3.2 135.00 0 13 5 2 0 0 0 0 20 6.9 157.50 7 21 1 0 0 0 0 0 29 4.3 180.00 5 15 0 0 0 0 0 0 20 3.7 202.50 11 5 0 0 0 0 0 0 16 3.1 225.00 5 4 0 0 0 0 0 0 9 3.0 247.50 5 5 0 0 0 0 0 0 10 2.9 270.00 13 15 3 0 0 0 0 0 31 4.2 292.50 17 75 43 25 5 1 0 0 166 7.8 315.00 9 33 79 67 36 14 0 0 238 12.9 337.50 2 17 3 0 0 0 0 0 22 6.0 360.00 4 11 0 0 0 0 0 0 15 3.5 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 87 225 134 94 41 15 0 0 596 8.7
Hours of Calm = 2 Sums of this table: row totals = 596 and column totals = 596
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-109 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS E AUG. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 8 7 0 0 0 0 0 0 15 3.2 45.00 8 4 0 0 0 0 0 0 12 3.3 67.50 3 0 1 0 0 0 0 0 4 3.5 90.00 5 1 0 0 0 0 0 0 6 2.5 112.50 7 2 3 0 0 0 0 0 12 4.2 135.00 5 11 6 1 0 0 0 0 23 5.9 157.50 7 18 2 0 0 0 0 0 27 4.4 180.00 5 4 0 0 0 0 0 0 9 3.4 202.50 2 2 0 0 0 0 0 0 4 3.0 225.00 4 4 1 0 0 0 0 0 9 4.3 247.50 5 3 0 0 0 0 0 0 8 3.3 270.00 6 4 2 0 0 0 0 0 12 4.5 292.50 11 52 19 10 7 8 0 0 107 9.3 315.00 18 68 75 107 70 61 2 0 401 15.0 337.50 10 31 7 0 0 0 0 0 48 5.3 360.00 14 17 0 0 0 0 0 0 31 4.1 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 118 228 116 118 77 69 2 0 728 11.0 Hours of Calm = 3 Sums of this table: row totals = 728 and column totals = 728
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-110 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS F AUG. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 1 0 0 0 0 0 1 7.6 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 0 0 0 0 0 0 0 0.0 157.50 1 4 0 0 0 0 0 0 5 4.3 180.00 1 3 0 0 0 0 0 0 4 4.4 202.50 0 1 0 0 0 0 0 0 1 3.4 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 1 0 0 0 0 0 1 9.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 1 2 2 3 6 9 0 0 23 20.3 315.00 2 1 5 5 14 22 6 0 55 24.3 337.50 2 0 0 1 0 0 0 0 3 6.8 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 7 11 9 9 20 31 6 0 93 20.3
Hours of Calm = 0 Sums of this table: row totals = 93 and column totals = 93
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-111 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS G AUG. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 0 0 0 0 0 0 0 0.0 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 3 0 1 0 0 0 0 4 6.7 292.50 0 1 0 0 2 3 0 0 6 20.1 315.00 0 0 0 1 2 0 1 0 4 24.0 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 0 4 0 2 4 3 1 0 14 17.4
Hours of Calm = 0 Sums of this table: row totals = 14 and column totals = 14
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-112 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS A SEPT. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 0 0 0 0 0 0 0 0.0 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 0 1 0 0 0 0 0 0 1 4.4 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 1 0 0 0 0 0 0 0 1 2.4 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 2 0 0 0 0 0 0 2 6.5 315.00 0 0 0 0 0 3 0 0 3 28.7 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 1 3 0 0 0 3 0 0 7 15.1
Hours of Calm = 0 Sums of this table: row totals = 7 and column totals = 7
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-113 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS B SEPT. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 0 0 0 0 0 0 0 0.0 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 1 0 0 0 0 0 0 1 3.8 315.00 1 0 0 0 0 0 0 0 1 2.9 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 1 1 0 0 0 0 0 0 2 3.3 Hours of Calm = 0 Sums of this table: row totals = 2 and column totals = 2
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-114 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS C SEPT. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 0 0 0 0 0 0 0 0.0 157.50 0 1 0 0 0 0 0 0 1 7.0 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 2 0 0 0 0 0 0 0 2 2.2 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 1 2 2 0 0 0 0 0 5 6.1 315.00 0 0 1 0 0 0 0 0 1 11.2 337.50 0 0 0 1 0 0 0 0 1 16.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 3 3 3 1 0 0 0 0 10 6.9
Hours of Calm = 0 Sums of this table: row totals = 10 and column totals = 10
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-115 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS D SEPT. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 4 2 0 0 0 0 0 0 6 3.5 45.00 1 2 0 0 0 0 0 0 3 3.2 67.50 0 2 0 0 0 0 0 0 2 3.5 90.00 1 2 0 0 0 0 0 0 3 3.6 112.50 5 21 4 1 0 0 0 0 31 5.2 135.00 9 54 9 1 0 0 0 0 73 5.4 157.50 3 15 4 0 0 0 0 0 22 5.0 180.00 3 14 0 0 0 0 0 0 17 3.5 202.50 7 3 0 0 0 0 0 0 10 2.8 225.00 6 1 0 0 0 0 0 0 7 2.9 247.50 1 5 1 0 0 0 0 0 7 4.8 270.00 3 7 1 0 0 0 0 0 11 4.1 292.50 3 30 23 13 3 0 0 0 72 8.9 315.00 4 24 42 40 24 6 0 0 140 12.6 337.50 1 15 5 2 0 0 0 0 23 6.3 360.00 4 4 0 0 0 0 0 0 8 3.5 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 55 201 89 57 27 6 0 0 435 8.0
Hours of Calm = 0 Sums of this table: row totals = 435 and column totals = 435
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-116 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS E SEPT. FREQUENCY TABLE
Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 7 13 1 0 0 0 0 0 21 3.9 45.00 6 9 1 0 0 0 0 0 16 4.0 67.50 5 6 1 1 0 0 0 0 13 5.0 90.00 8 3 0 0 0 0 0 0 11 2.9 112.50 7 15 1 0 0 0 0 0 23 4.2 135.00 8 20 10 0 0 0 0 0 38 5.2 157.50 4 11 5 0 0 0 0 0 20 5.5 180.00 1 3 0 0 0 0 0 0 4 3.7 202.50 3 4 0 1 0 0 0 0 8 4.3 225.00 9 1 0 0 0 0 0 0 10 2.6 247.50 2 3 0 1 1 0 0 0 7 8.0 270.00 6 2 0 1 0 0 0 0 9 4.5 292.50 4 27 17 10 2 1 0 0 61 8.6 315.00 4 36 46 52 56 27 0 0 221 15.0 337.50 3 25 10 7 1 1 0 0 47 7.8 360.00 2 12 1 0 0 0 0 0 15 4.4 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 79 190 93 73 60 29 0 0 524 9.7 Hours of Calm = 2 Sums of this table: row totals = 524 and column totals = 524
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-117 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS F SEPT. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 4 2 0 0 0 0 0 0 6 3.3 45.00 3 3 0 0 0 0 0 0 6 3.5 67.50 2 0 0 0 0 0 0 0 2 1.5 90.00 4 1 0 0 0 0 0 0 5 2.6 112.50 2 5 0 0 0 0 0 0 7 4.1 135.00 2 3 1 0 0 0 0 0 6 5.3 157.50 1 9 0 0 0 0 0 0 10 5.3 180.00 1 5 0 0 0 0 0 0 6 4.3 202.50 2 0 0 0 0 0 0 0 2 1.7 225.00 2 1 0 0 0 0 0 0 3 3.3 247.50 1 2 0 0 0 0 0 0 3 4.0 270.00 1 0 1 0 0 0 0 0 2 5.2 292.50 2 7 1 1 3 0 0 0 14 9.7 315.00 2 14 40 1 28 38 0 0 153 17.2 337.50 1 5 6 1 1 0 0 0 14 9.2 360.00 3 5 0 0 0 0 0 0 8 4.2 ___ ___ ____ ___ ___ ___ ___ ___ ___ ____ Column Sums 33 62 49 33 32 8 0 0 247 12.8
Hours of Calm = 0 Sums of this table: row totals = 247 and column totals = 247
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-118 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS G SEPT. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 1 1 0 0 0 0 0 0 2 4.4 45.00 2 1 0 0 0 0 0 0 3 4.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 2 1 0 0 0 0 0 0 3 2.9 135.00 1 6 0 0 0 0 0 0 7 4.0 157.50 0 1 0 0 0 0 0 0 1 3.1 180.00 1 0 0 0 0 0 0 0 1 1.8 202.50 1 0 0 0 0 0 0 0 1 2.5 225.00 1 0 0 0 0 0 0 0 1 1.8 247.50 1 1 0 0 0 0 0 0 2 4.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 1 2 1 1 3 0 0 8 17.8 315.00 1 4 7 9 4 10 1 0 36 17.8 337.50 1 0 0 0 1 0 0 0 2 11.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 12 16 9 10 6 13 1 0 67 13.1
Hours of Calm = 0 Sums of this table: row totals = 67 and column totals = 67
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-119 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS A OCT. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 0 0 0 0 0 0 0 0.0 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 1 0 0 0 0 0 0 0 1 2.8 202.50 0 1 0 0 0 0 0 0 1 4.9 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 0 0 0 0 0 0 0 0 0.0 315.00 0 0 0 0 0 0 0 0 0 0.0 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 1 1 0 0 0 0 0 0 2 3.8
Hours of Calm = 0 Sums of this table: row totals = 2 and column totals = 2
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-120 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS B OCT. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 5 1 0 0 0 0 6 10.2 90.00 0 0 1 0 0 0 0 0 1 8.2 112.50 1 0 0 0 0 0 0 0 1 3.0 135.00 2 0 0 0 0 0 0 0 2 3.0 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 1 0 0 0 0 0 1 9.3 292.50 0 0 1 2 0 0 0 0 3 13.8 315.00 0 2 2 1 0 0 0 0 5 8.6 337.50 0 0 0 0 0 0 0 0 0 0.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 3 2 10 4 0 0 0 0 19 9.1 Hours of Calm = 0 Sums of this table: row totals = 19 and column totals = 19
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-121 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS C OCT. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 1 0 1 0 0 0 0 2 8.7 157.50 0 1 0 0 0 0 0 0 1 3.2 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 1 0 1 0 0 0 0 2 8.2 315.00 0 0 0 0 0 0 0 0 0 0.0 337.50 1 0 0 0 0 0 0 0 1 2.0 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 1 3 0 2 0 0 0 0 6 6.5
Hours of Calm = 0 Sums of this table: row totals = 6 and column totals = 6
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-122 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS D OCT. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 3 0 0 0 0 0 0 3 4.4 45.00 2 6 1 0 0 0 0 0 9 4.5 67.50 0 3 0 0 0 0 0 0 3 3.5 90.00 4 4 4 0 0 0 0 0 12 5.7 112.50 5 17 12 2 0 0 0 0 36 6.7 135.00 4 25 21 5 0 0 0 0 55 7.1 157.50 2 18 1 0 0 0 0 0 21 4.7 180.00 3 7 0 0 0 0 0 0 10 3.4 202.50 2 6 1 0 0 0 0 0 9 4.8 225.00 4 2 0 2 0 0 0 0 8 5.0 247.50 0 1 0 0 0 0 0 0 1 3.3 270.00 8 10 0 0 0 0 0 0 18 3.5 292.50 5 25 23 6 0 1 0 0 60 7.9 315.00 3 22 29 31 4 18 1 0 108 13.8 337.50 1 11 9 2 0 0 0 0 23 7.7 360.00 0 3 1 0 0 0 0 0 4 5.4 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 43 163 102 48 4 19 1 0 380 8.4
Hours of Calm = 2 Sums of this table: row totals = 380 and column totals = 380
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-123 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS E OCT. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 7 28 2 2 0 0 0 0 39 5.0 45.00 10 17 1 4 2 0 0 0 34 6.2 67.50 27 23 0 2 0 1 0 0 53 4.1 90.00 20 22 4 1 0 0 0 0 47 4.1 112.50 17 15 11 3 2 0 0 0 48 6.7 135.00 7 53 22 8 0 0 0 0 90 6.6 157.50 5 9 0 0 0 0 0 0 14 3.7 180.00 5 6 0 0 0 0 0 0 11 3.3 202.50 4 4 2 0 0 0 0 0 10 4.7 225.00 3 2 5 10 1 0 0 0 21 11.8 247.50 3 1 1 0 2 0 0 0 7 9.2 270.00 4 2 0 0 0 0 0 0 6 3.1 292.50 12 20 20 8 6 3 0 0 69 9.4 315.00 11 23 21 37 19 9 0 0 120 12.9 337.50 14 24 13 4 2 0 0 0 57 6.7 360.00 5 16 6 2 0 0 0 0 29 6.1 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 154 265 108 81 34 13 0 0 655 7.6
Hours of Calm = 3 Sums of this table: row totals = 655 and column totals = 655
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-124 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS F OCT. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 4 4 2 0 0 0 0 0 10 4.9 45.00 3 1 1 0 0 0 0 0 5 4.4 67.50 5 5 0 0 1 0 0 0 11 5.1 90.00 4 1 0 1 0 0 0 0 6 5.2 112.50 5 12 1 0 0 0 0 0 18 4.3 135.00 3 10 5 1 0 0 0 0 19 6.2 157.50 3 1 0 0 0 0 0 0 4 2.4 180.00 2 0 0 0 0 0 0 0 2 2.1 202.50 0 1 0 0 0 0 0 0 1 4.0 225.00 0 2 1 5 3 0 0 0 11 13.5 247.50 0 1 0 1 1 0 0 0 3 12.4 270.00 3 0 1 0 0 0 0 0 4 4.1 292.50 3 5 0 4 2 3 0 0 27 11.2 315.00 10 11 14 15 15 7 0 0 72 12.8 337.50 3 10 7 7 0 0 0 0 27 8.7 360.00 3 4 4 0 0 0 0 0 11 6.3 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 51 68 46 34 22 10 0 0 231 9.1
Hours of Calm = 0 Sums of this table: row totals = 231 and column totals = 231
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-125 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS G OCT. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 1 0 0 0 0 0 0 1 4.2 45.00 1 2 0 1 0 0 0 0 4 6.5 67.50 2 1 0 0 0 0 0 0 3 2.7 90.00 3 0 0 0 0 0 0 0 3 2.8 112.50 2 6 0 0 0 0 0 0 8 4.4 135.00 8 6 0 0 0 0 0 0 14 3.5 157.50 3 5 0 0 0 0 0 0 8 3.3 180.00 0 1 0 0 0 0 0 0 1 4.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 1 0 2 0 0 0 0 3 13.1 247.50 1 1 0 0 0 0 0 0 2 2.5 270.00 2 0 0 0 0 0 0 0 2 2.9 292.50 2 3 6 2 2 0 0 0 15 9.7 315.00 8 11 5 14 7 5 0 0 50 12.2 337.50 0 2 0 2 0 0 0 0 4 10.4 360.00 3 1 0 0 0 0 0 0 4 2.7 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 35 41 11 21 9 5 0 0 122 8.3
Hours of Calm = 0 Sums of this table: row totals = 122 and column totals = 122
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-126 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS A NOV. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 1 2 0 0 0 0 0 3 6.9 45.00 0 0 1 0 0 0 0 0 1 7.9 67.50 0 2 0 1 0 0 0 0 3 8.0 90.00 0 0 4 1 0 0 0 0 5 11.2 112.50 0 2 2 4 5 1 0 0 14 15.4 135.00 1 1 1 7 1 0 0 0 11 13.5 157.50 0 2 0 1 0 0 0 0 3 9.3 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 1 0 0 0 0 0 0 1 3.6 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 1 0 0 0 0 0 1 10.1 292.50 0 0 0 0 0 0 0 0 0 0.0 315.00 0 2 2 8 3 5 0 0 20 18.4 337.50 1 2 9 11 11 7 0 0 41 16.4 360.00 1 4 7 2 0 0 0 0 14 8.5 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 3 17 29 35 20 13 0 0 117 14.3
Hours of Calm = 0 Sums of this table: row totals = 117 and column totals = 117
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-127 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS B NOV. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 1 0 0 0 0 0 0 0 1 2.1 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 1 0 1 0 0 0 0 0 2 7.2 90.00 0 1 0 0 0 0 0 0 1 5.2 112.50 0 0 2 1 0 0 0 0 3 11.1 135.00 0 1 3 5 0 0 0 0 9 12.6 157.50 2 3 0 0 0 0 0 0 5 4.2 180.00 1 1 0 0 0 0 0 0 2 3.6 202.50 1 1 0 0 0 0 0 0 2 3.9 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 1 0 1 0 0 0 0 0 2 5.3 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 1 0 0 0 0 0 0 0 1 2.9 315.00 2 2 1 3 3 0 0 0 11 12.0 337.50 1 0 2 3 1 2 0 0 9 15.9 360.00 0 3 5 1 0 0 0 0 9 9.2 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 11 12 15 13 4 2 0 0 57 10.1 Hours of Calm = 0 Sums of this table: row totals = 57 and column totals = 57
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-128 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS C NOV. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 1 1 2 0 0 0 0 0 4 7.0 45.00 1 1 3 0 0 0 0 0 5 6.7 67.50 1 0 1 0 0 0 0 0 2 4.9 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 2 0 0 1 1 0 0 4 15.2 135.00 1 6 5 10 0 0 0 0 22 10.6 157.50 2 5 2 0 1 0 0 0 10 7.1 180.00 1 1 0 0 1 0 0 0 3 8.4 202.50 1 1 0 0 0 0 0 0 2 3.4 225.00 0 1 0 0 0 0 0 0 1 4.4 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 1 3 0 0 0 0 0 0 4 3.5 315.00 0 3 3 2 1 0 0 0 9 11.6 337.50 0 1 4 10 4 4 0 0 23 17.8 360.00 0 0 1 1 0 0 0 0 2 12.2 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 9 25 21 23 8 5 0 0 91 11.3
Hours of Calm = 0 Sums of this table: row totals = 91 and column totals = 91
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-129 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS D NOV. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 2 14 9 1 0 1 0 0 27 7.4 45.00 6 12 4 0 1 0 0 0 23 5.7 67.50 6 4 9 0 0 0 0 0 19 5.8 90.00 5 8 3 0 0 0 0 0 16 4.5 112.50 0 5 1 5 4 3 0 0 18 15.3 135.00 2 17 16 9 1 2 0 0 47 9.6 157.50 4 20 2 1 2 1 0 0 30 7.4 180.00 1 2 2 0 0 0 0 0 5 5.5 202.50 2 3 4 1 1 0 0 0 11 8.5 225.00 2 0 2 2 1 0 0 0 7 11.2 247.50 0 2 0 0 0 0 0 0 2 4.5 270.00 2 1 2 0 0 0 0 0 5 5.7 292.50 2 6 6 2 2 0 0 0 18 10.0 315.00 0 3 24 38 24 3 0 0 92 15.3 337.50 1 5 13 22 10 0 0 0 51 13.5 360.00 2 5 26 12 2 0 0 0 47 10.5 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 37 107 123 93 48 10 0 0 418 10.7
Hours of Calm = 0 Sums of this table: row totals = 418 and column totals = 418
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-130 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS E NOV. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 12 20 9 1 0 0 0 0 42 5.4 45.00 22 33 10 1 0 0 0 0 66 4.6 67.50 20 14 5 7 0 0 0 0 46 5.7 90.00 17 13 2 1 0 0 0 0 33 4.1 112.50 9 18 0 2 1 1 0 0 31 6.1 135.00 5 28 5 3 0 0 0 0 41 6.1 157.50 3 14 1 2 0 0 0 0 20 5.4 180.00 1 2 0 0 0 0 0 0 3 3.6 202.50 2 0 0 0 0 0 0 0 2 2.5 225.00 1 4 1 1 1 1 0 0 9 10.4 247.50 1 2 1 0 0 0 0 0 4 5.0 270.00 1 3 2 0 0 0 0 0 6 6.6 292.50 5 12 3 3 5 0 0 0 28 9.2 315.00 1 21 24 28 16 7 0 0 97 13.3 337.50 3 19 13 18 7 1 0 0 61 11.0 360.00 7 23 14 6 3 0 0 0 53 7.6 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 110 226 90 73 33 10 0 0 542 7.9
Hours of Calm = 0 Sums of this table: row totals = 542 and column totals = 542
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-131 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS F NOV. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 3 5 0 0 0 0 0 0 8 3.7 45.00 4 8 1 0 0 0 0 0 13 4.2 67.50 5 4 1 0 0 0 0 0 0 4.1 90.00 9 2 0 0 0 0 0 0 11 2.9 112.50 8 7 0 0 0 0 0 0 15 3.2 135.00 3 9 5 0 0 0 0 0 17 5.3 157.50 4 0 1 0 0 0 0 0 5 4.0 180.00 0 2 0 0 0 0 0 0 2 4.8 202.50 1 0 0 0 0 0 0 0 1 2.7 225.00 2 1 0 0 0 0 0 0 3 2.5 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 2 2 2 0 0 0 0 0 6 5.1 315.00 2 9 9 8 6 1 0 0 35 11.6 337.50 1 3 1 1 2 0 0 0 8 10.4 360.00 1 4 1 0 0 0 0 0 6 4.5 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 45 56 21 9 8 1 0 0 140 6.3
Hours of Calm = 0 Sums of this table: row totals = 140 and column totals = 140
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-132 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS G NOV. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 1 1 0 0 0 0 0 0 2 2.8 67.50 0 1 0 0 0 0 0 0 1 3.3 90.00 1 1 0 0 0 0 0 0 2 3.0 112.50 4 1 0 0 0 0 0 0 5 2.7 135.00 2 7 1 1 0 0 0 0 11 5.3 157.50 0 1 0 0 0 0 0 0 1 4.1 180.00 1 0 0 0 0 0 0 0 1 2.2 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 3 0 0 0 0 0 0 0 3 2.3 247.50 0 1 0 0 0 0 0 0 1 4.7 270.00 1 0 0 0 0 0 0 0 1 2.2 292.50 0 2 2 1 0 0 0 0 5 9.0 315.00 1 7 2 3 1 0 0 0 14 9.0 337.50 0 1 0 0 0 0 0 0 1 5.9 360.00 0 0 0 0 0 0 0 0 0 0.0 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 14 23 5 5 1 0 0 0 48 5.9
Hours of Calm = 0 Sums of this table: row totals = 48 and column totals = 48
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-133 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS A DEC. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 2 0 0 0 0 0 2 8.7 45.00 0 1 0 0 0 0 0 0 1 6.8 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 1 0 0 0 0 0 1 9.5 112.50 0 0 0 1 0 1 0 0 2 20.3 135.00 0 0 2 0 0 0 0 0 2 10.7 157.50 1 0 0 0 0 0 0 0 1 3.0 180.00 0 1 0 1 0 0 0 0 2 8.2 202.50 0 0 0 1 0 0 0 0 1 12.7 225.00 0 0 0 1 0 0 0 0 1 12.1 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 1 0 0 0 0 1 15.1 292.50 0 1 0 0 0 2 0 0 3 18.6 315.00 0 0 0 0 0 2 0 0 2 29.4 337.50 0 2 0 1 0 0 0 0 3 9.0 360.00 0 0 2 0 0 0 0 0 2 8.3 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 1 5 7 6 0 5 0 0 24 13.1
Hours of Calm = 0 Sums of this table: row totals = 24 and column totals = 24
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-134 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS B DEC. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 1 0 0 0 0 0 1 8.6 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 1 0 0 0 0 0 0 1 5.0 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 1 0 0 0 1 20.3 292.50 0 0 1 0 0 0 0 0 1 7.5 315.00 0 0 0 0 0 1 0 0 1 25.3 337.50 0 0 1 2 0 0 0 0 3 14.4 360.00 0 0 1 0 0 0 0 0 1 10.9 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 0 1 4 2 1 1 0 0 9 13.4 Hours of Calm = 0 Sums of this table: row totals = 9 and column totals = 9
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-135 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS C DEC. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 0 0 0 0 0 0 0 0 0 0.0 90.00 0 0 1 0 0 0 0 0 1 7.5 112.50 0 0 0 0 0 0 0 0 0 0.0 135.00 0 0 1 1 0 0 0 0 2 11.5 157.50 0 0 0 0 0 0 0 0 0 0.0 180.00 0 0 0 0 1 0 0 0 1 19.3 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 0 1 0 0 0 0 0 1 10.8 315.00 1 0 0 0 0 0 0 0 1 2.0 337.50 0 0 4 3 0 0 0 0 7 12.6 360.00 0 2 2 0 0 0 0 0 4 6.4 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 1 2 9 4 1 0 0 0 17 10.4
Hours of Calm = 0 Sums of this table: row totals = 17 and column totals = 17
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-136 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS D DEC. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 10 21 4 0 0 0 0 35 8.8 45.00 0 7 12 5 0 0 0 0 24 9.3 67.50 0 7 6 2 0 0 0 0 15 8.0 90.00 1 10 0 1 0 0 0 0 12 5.5 112.50 1 7 7 14 5 5 0 0 39 14.6 135.00 0 7 8 8 6 4 0 0 33 14.0 157.50 0 16 4 5 1 3 0 0 29 10.4 180.00 1 8 2 0 0 0 0 0 11 5.1 202.50 1 4 0 0 0 0 0 0 5 4.4 225.00 0 1 0 0 0 0 0 0 1 5.0 247.50 2 2 0 0 0 0 0 0 4 3.5 270.00 2 4 0 0 0 0 0 0 6 4.7 292.50 1 5 2 2 0 1 0 0 11 9.2 315.00 2 2 6 33 17 8 0 0 68 16.9 337.50 2 6 13 22 11 1 0 0 55 13.2 360.00 1 18 22 11 0 0 0 0 2 8.7 ___ ___ ___ ___ ___ ___ ___ ___ ___ ____ Column Sums 14 114 103 107 40 22 0 0 400 11.5
Hours of Calm = 0 Sums of this table: row totals = 400 and column totals = 400
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-137 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS E DEC. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 6 50 17 9 1 0 0 0 83 6.7 45.00 10 49 21 2 0 0 0 0 82 5.8 67.50 22 22 19 11 2 0 0 0 76 6.8 90.00 19 25 6 2 1 0 0 0 53 4.8 112.50 15 30 9 6 8 4 0 0 72 8.7 135.00 4 30 21 2 0 5 0 0 62 8.6 157.50 6 2 0 0 1 0 0 23 5.9 180.00 4 9 2 0 0 0 0 0 15 4.4 202.50 2 3 0 0 0 0 0 0 75 3.3 225.00 3 5 0 0 1 0 0 0 9 5.5 247.50 0 3 0 0 0 0 0 0 3 4.9 270.00 1 6 1 0 0 0 0 0 8 4.8 292.50 3 10 3 7 3 2 0 0 28 11.0 315.00 4 24 26 33 31 1 0 0 119 13.1 337.50 4 36 36 33 3 0 1 0 113 10.0 360.00 9 39 29 12 0 0 0 0 89 7.3 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 112 355 192 117 50 13 1 0 840 8.3
Hours of Calm = 0 Sums of this table: row totals = 840 and column totals = 840
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-138 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS F DEC. FREQUENCY TABLE
Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 2 2 1 0 0 0 0 0 5 5.3 45.00 4 1 1 0 0 0 0 0 6 3.8 67.50 4 1 0 0 0 0 0 0 5 2.8 90.00 7 2 1 0 0 0 0 0 10 3.6 112.50 11 11 0 0 0 0 0 0 22 3.1 135.00 6 17 4 0 0 0 2 0 29 6.9 157.50 3 8 1 0 0 0 0 0 12 4.6 180.00 2 0 0 0 0 0 0 0 2 2.8 202.50 2 0 0 0 0 0 0 0 2 2.4 225.00 0 0 0 0 0 0 0 0 0 0.0 247.50 0 1 0 0 0 0 0 0 1 6.3 270.00 1 0 0 0 0 0 0 0 1 3.0 292.50 2 2 0 1 1 0 0 0 6 8.2 315.00 1 5 8 12 10 0 0 0 36 13.8 337.50 0 7 4 5 0 0 0 0 16 9.6 360.00 1 5 3 0 0 0 0 0 9 6.4 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 46 62 23 18 11 0 2 0 162 7.4
Hours of Calm = 0 Sums of this table: row totals = 162 and column totals = 162
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-139 DCPP SITE - MAY 1973 - APRIL 1975 WIND DATA 10M, TEMP GRAD 76-10M STABILITY CLASS G DEC. FREQUENCY TABLE Mean Wind Direction Mean Wind Speed, mph Row Sums Row Avg. 1.5 5.1 9.6 15.1 21.1 29.6 40.1 50.1 22.50 0 0 0 0 0 0 0 0 0 0.0 45.00 0 0 0 0 0 0 0 0 0 0.0 67.50 1 0 0 0 0 0 0 0 1 2.9 90.00 0 0 0 0 0 0 0 0 0 0.0 112.50 0 2 0 0 0 0 0 0 2 5.3 135.00 1 3 1 0 0 0 0 0 5 5.0 157.50 2 0 0 0 0 0 0 0 2 2.6 180.00 0 0 0 0 0 0 0 0 0 0.0 202.50 0 0 0 0 0 0 0 0 0 0.0 225.00 1 0 1 0 0 0 0 0 2 5.4 247.50 0 0 0 0 0 0 0 0 0 0.0 270.00 0 0 0 0 0 0 0 0 0 0.0 292.50 0 2 0 0 0 0 0 0 2 3.3 315.00 0 8 2 1 1 0 0 0 12 8.0 337.50 0 3 1 1 0 0 0 0 5 8.1 360.00 1 0 1 0 0 0 0 0 2 5.7 ___ ___ ___ ___ ___ ___ ___ ___ ___ ___ Column Sums 6 18 6 2 1 0 0 0 33 6.3
Hours of Calm = 0 Sums of this table: row totals = 33 and column totals = 33
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-141 RANGES OF STABILITY CLASSIFICATION PARAMETERS FOR EACH STABILITY CATEGORY AT DCPP SITE
Pasquil Stability Class(a) Range, (deg) Range, (C/100m) Ri Range g = 76m - 10m U-2 A 22.5 < -1.9 < -0.02 B 22.5 > 17.5 -1.9 to -1.7 -0.02 to- .01 C 17.5 > 12.5 -1.7 to -1.5 -0.01 to -.001 D 12.5 > 7.5 -1.5 to -0.5 -0.001 to +0.005 E 7.5 > 3.8 -0.5 to +1.5 +0.005 to +0.02 F 3.8 > 2.1 +1.5 to +4.0 +0.02 to +0.07 G 2.1 > +4.0 +0.07
(a) See Reference 17, Section 2.3.7.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-142 SUMMARY OF METEOROLOGICAL DATA FOR DIFFUSION EXPERIMENTS AT DCPP SITE Date Release Time (Local Time) h (ft) Wind Dir. (deg) m (mph) H m (ft) T 250 30 (°F) Trial No. Trials with Northwesterly Flow 1 11-20-68 1552-1652 250 304 11 1000 11.7 2 11-21-68 1411-1510 250 313 15 800 3.1 3 11-22-68 1540-1632 250 303 20 400 5.9 4 11-24-68 1036-1135 250 310 19 2500 -2.0 9 03-04-69 1110-1210 250 294 16 800 -3.0 10 03-06-69 1220-1320 250 311 26 2400 -3.0 11 03-07-69 1100-1200 250 297 16 4600 -4.2 12 03-08-69 1418-1518 250 306 14 1400 -2.0 15 05-20-69 1100-1200 250 305 15 1000 -0.2 16 05-20-69 1445-1545 250 306 18 600 -0.6 17 05-21-69 1240-1340 250 308 24 800 +1.5 18 05-22-69 1230-1330 250 310 20 1000 +0.3 20 07-15-69 1412-1512 250 305 27 600 +4.5 22 07-16-69 1500-1600 250 304 16 500 +1.0 24 07-24-69 1238-1338 250 305 24 600 +1.7 25 07-25-69 1054-1155 250 306 20 1500 +0.1 Trials with Southeasterly Flow 6 01-12-69 0940-1040 250 133 15 2500 -1.3 8 02-22-69 1300-1400 250 168 9 2500 -2.7 13 04-02-69 0930-1030 250 146 10 1500 -0.4 14 04-02-69 1300-1400 250 148 9 2500 -2.2 23 07-17-69 0205-0305 250 131 8 500 +1.9 30 10-15-69 0742-0842 25 143 6 2500 +0.4 Trials with Light and Variable Winds(a) 19 07-15-69 0201-0301 250 -0.8 21 07-16-69 0433-0500 250 0.9 26 09-29-69 0037-0137 25 -1.1 27 09-30-69 0220-0322 25 +0.4 28 10-01-69 0250-0350 25 +0.3 (a) Wind speed of 2 mph was assumed. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.3-144 DCPP SITE NIGHTTIME P-G STABILITY CATEGORIES BASED ON And if the 10m Wind Speed, u is: If the Stability Class is: m/s mi/hr The Stability Class for the z is: A u<2.9 u<6.4 F 2.9 u<3.6 6.4 u<7.9 E 3.6 u 7.9 u D B u<2.4 u<5.3 F 2.4 u<3.0 5.3 u<6.6 E 3.0<u 6.6 u D C u<2.4 u<5.3 E 2.4<u 5.3<u D
D, E, F, or G wind speed not considered DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 2.4-1 PROBABLE MAXIMUM PRECIPITATION (PMP) AS A FUNCTION OF DURATION AT DCPP SITE AS DETERMINED FROM USWB HMR NO. 36 Duration, hours PMP, inches 1 4.3
3 7.1
6 9.1
12 12.0
18 14.8
24 16.6
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 1 of 43 Revision 17 November 2006 LISTING OF EARTHQAKES WITHIN 75 MILES OF THE DIABLO CANYON POWER PLANT SITE SELECTED EARTHQUAKES MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS -?/-?/1800 -?--?--? 34.50 119.67 D F SANTA BARBARA. 03/25/1806 08--?--? 34.50 119.67 D F VIII AT SANTA BARBARA. 12/21/1812 18--?--? 34.50 120.00 D F VIII AT SAN FERNANDO. 12/21/1812 19--?--? 34.50 120.00 D F IX AT SAN FERNANDO. 01/18/1815 -?--?--? 34.50 119.67 D F SANTA BARBARA; 5 SHOCKS. 01/30/1815 -?--?--? 34.50 119.67 D F SANTA BARBARA. 07/08/1815 -?--?--? 34.50 119.67 D F SANTA BARBARA; 6 SHOCKS ON THE EIGHTH AND NINTH. -?/-?/1830 -?--?--? 35.25 120.67 D F VIII AT SAN LUIS OBISPO. 07/03/1841 -?--?--? 36.30 122.30 6.3 (CALTECH FILE) 06/13/1851 -?--?--? 35.25 120.67 D F V AT SAN LUIS OBISPO. 10/26/1852 -?--?--? 35.67 121.17 D F X AT SAN SIMEON; 11 SHOCKS. 12/17/1852 -?--?--? 35.25 120.67 D F IX AT SAN LUIS OBISPO; 2 SHOCKS. 01/10/1853 -?--?--? 35.25 120.67 D F DANA RANCHO. 01/29/1853 -?--?--? 34.50 119.67 D F SANTA BARBARA. 02/01/1853 21--?--? 35.67 121.17 D F VIII AT SAN SIMEON. 02/14/1853 -?--?--? 35.25 120.67 D F SAN LUIS OBISPO. 03/01/1853 -?--?--? 34.50 119.67 D F V AT SAN LUIS OBISPO. 04/20/1854 -?--?--? 34.50 119.67 D F SANTA BARBARA. 04/29/1854 -?--?--? 34.50 119.67 D F III AT SANTA BARBARA. 05/03/1854 13-10--? 34.50 119.67 D F SANTA BARBARA; 3 SEVERE SHOCKS. 05/13/1854 -?--?--? 34.50 119.67 D F SANTA BARBARA. 05/29/1854 -?--?--? 34.50 119.67 D F SANTA BARBARA. 05/31/1854 12-50--? 34.50 119.67 D F VI AT SANTA BARBARA; 3 SHOCKS. 01/14/1855 02-30--? 35.75 120.67 D F SAN BENITO AND SAN MIGUEL. 06/25/1855 22--?--? 34.50 119.67 D F V AT SANTA BARBARA. 01/08/1857 14--?--? 34.50 119.67 D F SANTA BARBARA. 01/08/1857 17--?--? 34.50 119.67 D F SANTA BARBARA. 01/08/1857 18--?--? 34.50 119.67 D F SANTA BARBARA. 01/09/1857 07-20--? 34.50 119.67 D F IX AT SANTA BARBARA. 01/21/1857 -?--?--? 36.50 121.08 D F III AT A POINT NORTHWEST OF SAN BENITO. 03/14/1857 23--?--? 34.50 119.67 D F V AT MONTECITO AND SANTA BARBARA. 09/02/1858 -?--?--? 34.50 119.67 D F V AT SANTA BARBARA. 04/03/1860 04--?--? 36.50 121.08 D F VI AT SAN JOSE. 04/17/1860 -?--?--? 34.50 119.67 D F SANTA BARBARA. -?/-?/1862 -?--?--? 34.42 119.63 D F VIII AT GOLETA. 09/13/1869 -?--?--? 35.25 120.67 D F V AT SAN LUIS OBISPO. 09/14/1869 -?--?--? 35.25 120.67 D F SAN LUIS OBISPO. 12/15/1869 -?--?--? 35.25 120.67 F V AT SAN LUIS OBISPO. 02/06/1872 -?--?--? 34.50 119.67 D F SANTA BARBARA; FIRST SINCE APRIL 1860. 11/07/1875 -?--?--? 36.50 121.08 D F V IN SAN BENITO COUNTY. 12/21/1875 -?--?--? 34.50 119.67 D F SANTA BARBARA. 05/10/1876 -?--?--? 34.50 119.67 D F SANTA BARBARA. 05/30/1877 -?--?--? 35.67 120.67 D F V AT PASO ROBLES. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 2 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 06/24/1877 07-30--? 34.50 119.67 D F SANTA BARBARA. 01/08/1878 -?--?--? 34.50 119.67 D F SANTA BARBARA. 11/13/1880 06-30--? 34.50 119.67 D F SANTA BARBARA. 02/02/1881 -?--?--? 36.37 121.67 D F III AT SALINAS. 08/31/1881 03--?--? 34.50 119.67 D F III AT SANTA BARBARA. 09/13/1883 22-30--? 34.50 119.67 D F IV AT SANTA BARBARA. 08/03/1884 -?--?--? 34.50 119.67 D F III AT SANTA BARBARA; NIGHT. 08/04/1884 09--?--? 34.50 119.67 D F III AT SANTA BARBARA; 3 SHOCKS. 03/31/1885 -?--?--? 36.30 121.00 7.0 (CALTECH FILE) 04/07/1885 10--?--? 34.50 119.67 D F SANTA BARBARA AND SAN BUENAVENTURA. 04/09/1885 -?--?--? 35.58 121.08 D F CAMBRIA. 04/12/1885 04-05--? 36.25 120.80 D F IX IN CENTRAL CALIFORNIA; FELT OVER AN AREA OF 125,000 SQ. MI.- EPICENTER PROBABLY EAST OF KING CITY. 04/12/1885 11--?--? 36.33 119.67 D F HANFORD. 07/09/1885 09-15--? 34.50 119.67 D F V AT SANTA BARBARA. 07/09/1885 16-15--? 34.50 119.67 D F V AT SANTA BARBARA; 5 EARTHQUAKES. 10/03/1888 20-52--? 35.75 120.67 D F III AT SAN MIGUEL. 10/03/1888 21-02--? 35.75 120.67 D F VI AT SAN MIGUEL. 10/04/1888 -?--?--? 35.67 120.67 D F PASO ROBLES. 05/01/1889 19-55--? 34.67 120.42 D F SUSANVILLE. 05/26/1889 15-13--? 36.50 121.42 D F GONZALES, SAN FRANCISCO, AND SANTA CRUZ; RECORDED AT MT. HAMILTON. 07/10/1889 -?--?--? 35.17 120.58 D F ARROYO GRANDE; SHOCKS FOR SEVERAL DAYS. 09/30/1889 20-17--? 36.50 119.58 D F KINGSBURG. 01/-?/1890 23-30--? 34.50 119.67 D F SANTA BARBARA. 11/13/1892 -?--?--? 36.30 122.00 6.0 (CALTECH FILE) 05/19/1893 -?-35--? 34.17 119.50 D F VII FELT FROM SAN DIEGO TO LOMPOC, INLAND TO SAN BERNADINO. MOST SEVERE SE OF VENTURA. POSSIBLY OF SUBMARINE ORIGIN OFF THE COAST OF VENTURA COUNTY 06/01/1893 12--?--? 34.50 119.67 D F VII AT NORDHOFF (OJAI), SANTA BARBARA, AND VENTURA. 06/01/1893 12--?--? 34.50 119.67 D F NORDHOFF, SANTA BARBARA, AND VENTURA. 06/01/1893 12-10--? 34.50 119.67 D F NORDHOFF, SANTA BARBARA, AND VENTURA. 12/06/1893 04-56--? 35.67 121.33 D F PIEDRAS BLANCAS LIGHTHOUSE. 07/27/1895 -?-10--? 34.50 119.67 D F SANTA BARBARA. 12/24/1895 05-30--? 34.50 119.67 D F SANTA BARBARA. 06/24/1897 14-10--? 34.50 119.67 D F SANTA BARBARA. 07/18/1897 -?--?--? 34.50 119.67 D F CASTLE PINCKNEY. 07/20/1897 07-45--? 34.50 119.67 D F SANTA BARBARA. 05/30/1898 03-03--? 34.50 119.67 D F SANTA BARBARA. 06/04/1898 06-20--? 34.67 120.08 D F LOS OLIVOS; FELT THROUGHOUT THE SANTA YNEZ VALLEY; AT SANTA BARBARA THE HEAVIEST FOR SOME YEARS. 02/08/1899 04-55--? 36.33 121.92 D F POINT SUR LIGHT STATION. 06/05/1899 -?--?--? 35.83 120.83 D F BRADLEY. 06/25/1899 -?--?--? 35.75 120.67 D F SAN MIGUEL. 06/09/1900 -?--?--? 36.00 120.92 D F SAN ARDO. 10/18/1900 -?--?--? 35.25 120.67 D F SAN LUIS OBISPO. 03/03/1901 -?--?--? 35.25 120.67 D F SAN LUIS OBISPO. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 3 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 03/03/1901 07-45--? 36.08 120.58 D F IX AT STONE CANYON - SURFACE CRACKS IN THE GROUND; ALSO FELT AT ADELAIDA, ESTRELLA, PARKFIELD, PASO ROBLES, PORTERVILLE, SAN JOSE, SAN LUIS OBISPO, AND SAN MIGUEL. 03/05/1901 -?--?--? 35.67 120.67 D F PASO ROBLES. 03/06/1901 -?--?--? 36.00 120.92 D F SAN ARDO AND SAN LUIS OBISPO. 06/03/1901 -?--?--? 35.25 120.67 D F SAN LUIS OBISPO. 07/30/1901 19--?--? 35.25 120.67 D F SAN LUIS OBISPO. 08/14/1901 11-11--? 35.42 120.92 D F CAYUCOS, HOLLISTER, SALINAS, SAN LUIS OBISPO, AND SANTA CRUZ. 02/07/1902 -?--?--? 34.50 119.67 D F SANTA BARBARA. 02/09/1902 15--?--? 34.50 119.67 D F PINE CREST, SAN LUIS OBISPO, SANTA BARBARA, AND VENTURA. 04/06/1902 -?--?--? 35.25 120.67 D F SAN LUIS OBISPO. 07/21/1902 -?--?--? 34.75 120.00 D F PINE CREST. 07/28/1902 06-57--? 34.75 120.25 D F IX AT LOMPOC AND LOS ALAMOS; CONFINED TO THE NORTHERN PART OF SANTA BARBARA COUNTY. 07/28/1902 13--8--? 35.25 120.67 D F SAN LUIS OBISPO; AFTERSHOCK OF 06-57-?. 07/31/1902 09-20--? 34.75 120.25 D F IX AT LOS ALAMOS AND SURROUNDING COUNTRY; FISSURES, CRACKS IN THE GROUND, AND LANDSLIDES. 08/01/1902 -?--?--? 34.75 120.25 D F LOS ALAMOS. SEVERAL SHOCKS. 08/01/1902 03-30--? 34.75 120.25 D F VIII AT LOS ALAMOS. 08/02/1902 -?--?--? 34.75 120.25 D F LOS ALAMOS. 08/03/1902 -?--?--? 34.75 120.25 D F LOS ALAMOS. 08/04/1902 10 -? 34.75 120.25 D F LOS ALAMOS. 08/04/1902 11-18--? 34.75 120.25 D F LOS ALAMOS. 08/04/1902 12-15--? 34.75 120.25 D F LOS ALAMOS. 08/04/1902 21-29--? 34.75 120.25 D F LOS ALAMOS. 08/04/1902 23-40--? 34.75 120.25 D F LOS ALAMOS. 08/05/1902 -?-55--? 34.75 120.25 D F LOS ALAMOS. 08/10/1902 -?--?--? 34.75 120.25 D F LOS ALAMOS; DISTINCT EARTHQUAKE DETONATION AND TREMOR. 08/10/1902 10-40--? 34.75 120.25 D F LOS ALAMOS; HEAVY DETONATION FOLLOWED BY TREMBLING. 08/10/1902 22-40--? 34.50 119.67 D F SANTA BARBARA. 08/14/1902 10-15--? 34.75 120.25 D F LOS ALAMOS. 08/14/1902 11-05--? 34.75 120.25 D F LOS ALAMOS. 08/14/1902 11-20--? 34.75 120.25 D F LOS ALAMOS; SHOOK GROUND VIOLENTLY. 08/14/1902 21-50--? 34.75 120.25 D F LOS ALAMOS. 08/14/1902 23-50--? 34.75 120.25 D F LOS ALAMOS. 08/28/1902 -?--?--? 35.25 120.67 D F SAN LUIS OBISPO. 08/31/1902 -?--?--? 35.25 120.67 D F SAN LUIS OBISPO. 09/11/1902 05-30--? 34.25 120.25 D F V AT LOS ALAMOS. 10/21/1902 21-45--? 34.75 120.25 D F LOMPOC AND LOS ALAMOS. 10/21/1902 22-15--? 34.75 120.25 D F LOMPOC AND LOS ALAMOS. 10/22/1902 10--?--? 34.75 120.25 D F LOS ALAMOS. 12/12/1902 -?--?--? 34.75 120.25 D F VIII AT LOS ALAMOS -3 SHOCKS IN 5 MINUTES; FELT THROUGHOUT THE NORTHERN PART OF SANTA BARBARA COUNTY, ESPECIALLY AT LOMPOC, LOS ALAMOS, SAN LUIS OBISPO, SANTA BARBARA, AND SANTA MARIA. 01/11/1903 -?--?--? 35.25 120.67 D F SAN LUIS OBISPO. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 4 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 03/07/1903 -?--?--? 36.50 121.42 D F GONZALES. 03/24/1903 -?--?--? 36.50 121.42 D F GONZALES AND SANTA MARGARITA. 04/24/1903 -?--?--? 35.42 120.58 D F SANTA MARGARITA. 07/29/1903 07-13--? 35.67 121.33 D F V AT POINT PIEDRAS BLANCAS LIGHTHOUSE. 07/29/1903 10-30--? 35.67 121.33 D F POINT PIEDRAS BLANCAS LIGHTHOUSE. 08/24/1903 -?--?--? 34.67 120.08 D F LOS OLIVOS. 01/22/1904 -?--?--? 34.75 120.25 D F LOS ALAMOS. 01/23/1904 -?--?--? 34.75 120.25 D F LOS ALAMOS. 09/10/1904 -?--?--? 35.25 120.67 D F SAN LUIS OBISPO. 05/26/1905 05-49--? 35.25 120.67 D F LOS GATOS, SALINAS, SAN FRANCISCO, SAN LUIS OBISPO, SANTA CRUZ AND SOLEDAD. 07/06/1906 -?--?--? 35.25 120.67 D F SAN LUIS OBISPO. 07/22/1906 -?--?--? 35.25 120.67 D F SAN LUIS OBISPO. 08/01/1906 -?--?--? 35.25 120.67 D F SAN LUIS OBISPO. 12/07/1906 06-40--? 35.67 121.33 D F VII AT SAN LUIS OBISPO AND SANTA MARIA; DURATION 30 SECONDS, FOLLOWED BY SECOND SHOCK HALF AN HOUR LATER. +12/08/1906 06-55--? 35.75 120.67 D F SAN MIGUEL. 06/19/1907 12--?--? 36.17 120.67 D F PRIEST VALLEY. 07/02/1907 18-10--? 35.25 120.67 D F SAN LUIS OBISPO. 07/21/1907 -?--?--? 35.25 120.67 D F SAN LUIS OBISPO. 07/29/1907 05-10--? 34.75 120.00 D F PINE CREST. 08/-?/1907 -?--?--? 34.75 120.00 D F PINE CREST AND SANTA BARBARA. 12/27/1907 09-15--? 34.50 119.67 D F SANTA BARBARA; ALSO FELT AT VENTURA; REPORTED FROM OJAI AND PINE CREST. 04/27/1908 10-50--? 36.00 121.17 D F JOLON, PASO ROBLES, PRIEST VALLEY, SAN LUIS OBISPO, SANTA MARGARETA, AND SAN MIGUEL. 05/19/1908 -?--?--? 35.25 120.67 D F SAN LUIS OBISPO. 09/16/1908 -?--?--? 36.17 120.67 D F PRIEST VALLEY. 11/-?/1908 19-30--? 36.17 120.67 D F PRIEST VALLEY. 01/23/1909 14-58--? 34.50 119.67 D F PINE CREST AND SANTA BARBARA. 04/10/1909 -?--?--? 34.50 119.67 D F MONO RANCH AND SANTA PAULA CANYON. 06/17/1909 08-20--? 36.42 121.33 D F SOLEDAD. 07/03/1909 07--?--? 34.50 119.67 D F MONTECITO AND SANTA BARBARA. 07/05/1909 06-10--? 34.50 119.67 D F III AT SANTA BARBARA. 07/16/1909 10-28--? 34.50 119.67 D F IV AT LOS ANGELES AND SANTA BARBARA. 07/31/1909 19-37--? 34.50 119.67 D F IV AT OJAI AND SANTA BARBARA. 08/18/1909 -?--?--? 35.25 120.67 D F SAN LUIS OBISPO. 11/24/1909 15--?--? 36.00 121.17 D F JOLON. 03/08/1910 09-30--? 36.17 120.67 D F PRIEST VALLEY. 04/30/1910 18-25--? 36.17 120.67 D F PRIEST VALLEY; 3 SHOCKS, THE SECOND ONE QUITE VIOLENT. 11/-?/1910 -?--?--? 34.50 119.67 D F SANTA BARBARA; 2 SLIGHT QUAKES DURING NOVEMBER. 02/02/1911 -?--?--? 34.75 120.25 D F LOS ALAMOS. 03/22/1911 10-55--? 35.75 120.67 D F SAN MIGUEL; QUITE SEVERE. 06/02/1911 -?--?--? 36.17 120.67 D F PRIEST VALLEY. 06/18/1912 22-27--? 36.00 121.17 D F JOLON. (RECORDED AT BERKELEY.) 10/20/1913 11-25--? 35.25 120.67 D F BETTERAVIA, PASO ROBLES, SAN LUIS OBISPO,AND SANTA MARIA. 11/27/1913 19--?--? 34.50 119.67 D F MONO RANCH. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 5 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 12/26/1913 12--?--? 36.17 121.00 D F SAN LUCAS. 11/24/1914 04-25--? 35.25 120.67 D F II AT SAN LUIS OBISPO; ABRUPT TREMBLING, LASTING 20 SECONDS. 01/12/1915 -?--?--? 34.92 120.50 D F BETTERAVIA. 01/12/1915 04-31--? 34.75 120.25 B F VIII AT LOS ALAMOS - EPICENTER 2 OR 3 MI. EAST OF LOS ALAMOS; FELT FROM SAN JOSE TO LOS ANGELES; SHAKEN AREA IN EXCESS OF 50,000 SQ. MI. - PRACTICALLY EVERY CHIMNEY DAMAGED AT LOS ALAMOS, VII AT LOMPOC, VI-VII AT SANTA MARIA, V AT SAN LUIS OBISPO AND SANTA BARBARA, IV AT PASO ROBLES, AND II AT LOS ANGELES, WEATHER BUREAU REPORTED V-VI AT SANTA BARBARA, V AT OZENA AND SAN LUIS OBISPO, IV AT PASO ROBLES, III AT OJAI, AND II IN PRIEST VALLEY; ALSO II AT BAKERSFIELD. 01/14/1915 -?--?--? 34.92 120.50 D F BETTERAVIA. 01/15/1915 -?--?--? 34.75 120.25 D F LOS ALAMOS. 01/20/1915 -?--?--? 34.75 120.25 D F LOS ALAMOS. 01/26/1915 -?--?--? 34.75 120.25 D F LOS ALAMOS. 01/27/1915 -?--?--? 34.75 120.25 D F LOS ALAMOS. 04/21/1915 09-58--? 35.25 120.67 D F IV AT SAN LUIS OBISPO; ALSO FELT 3 MI. NW OF PRIEST VALLEY. 08/23/1915 23-15--? 34.75 119.75 D F HILL CAMP. 08/31/1915 21--?--? 34.75 119.75 D F HILL CAMP. 09/08/1915 12-45--? 35.67 120.67 D F V IN REGION EAST OF PASO ROBLES; ANTELOPE - 2 SHOCKS, FIRST THE HEAVIER, OIL CAME UP WITH WATER IN WELL AFTER SHOCK. AT SHANDON A SEATED MAN WAS SHAKEN SO HARD HE THOUGHT A PERSON WAS SHAKING HIM. AT CRESTON THE SHOCK WAS SHORT AND SHARP. A SLIGHT LANDSLIDE AT PORT SAN LUIS. WEATHER BUREAU REPORTS -PASO ROBLES V AND SAN LUIS OBISPO III-IV. 09/14/1915 -?--?--? 34.75 119.75 D F HILL CAMP; 3 HARD SHOCKS - EARTH TREMBLED FOR 15 MINUTES AFTERWARDS. 02/27/1916 13-26--? 34.75 120.25 D F LOS ALAMOS. 03/01/1916 19-15--? 34.75 120.25 D F LOS ALAMOS. 05/06/1916 03-45--? 34.75 120.25 D F III AT LOS ALAMOS. FELT BY MANY AT EL ROBLAR RANCH, 2 MI. SE OF LOS ALAMOS. 08/06/1916 -?--?--? 36.00 121.00 7.0 (CALTECH FILE) 10/24/1916 13-03--? 35.25 120.67 D F II AT SAN LUIS OBISPO; PROBABLY NEXT SHOCK, WITH TIME ERROR. 10/24/1916 13-30--? 36.00 121.17 D F V AT JOLON; III AT A POINT 3.5 MI. NW OF PRIEST VALLEY. 12/01/1916 22-53--? 35.17 120.75 D F VII AT AVILA - CONSIDERABLE GLASS BROKEN AND GOODS IN STORES THROWN FROM SHELVES. FELT AT SAN LUIS OBISPO; WATER IN BAY DISTURBED, PLASTER IN COTTAGES JARRED LOOSE, SMOKESTACKS OF UNION OIL CO. REFINERY TOPPLED OVER. SEVERE AT PORT SAN LUIS; III AT SANTA MARIA. 02/01/1917 05-18--? 34.92 120.42 D F III AT SANTA MARIA. 04/05/1917 19--?--? 34.67 120.33 D F IV AT SANTA RITA; ALSO FELT AT LOMPOC. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 6 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 04/13/1917 03-59--? 34.25 119.67 D F VI AT SANTA BARBARA CHANNEL REGION; FELT OVER AN AREA OF COAST SOUTH AND EAST OF SANTA BARBARA AS FAR AS VENTURA, AND ON SANTA CRUZ ISLAND. 04/21/1917 06-59--? 34.25 119.67 D F V AT SANTA BARBARA CHANNEL; PERCEPTIBLE OVER AN AREA OF PERHAPS 4000 SQ. MI. 07/07/1917 20-57--? 35.25 120.50 D F LOPEZ CANYON; ALSO AT SAN LUIS OBISPO. 07/07/1917 21-02--? 35.25 120.50 D F LOPEZ CANYON. 07/07/1917 21-15--? 35.25 120.50 D F LOPEZ CANYON. 07/08/1917 03-20--? 34.92 120.42 D F II AT SANTA MARIA. 07/08/1917 11-29--? 35.25 120.50 D F IV IN LOPEZ CANYON. 07/09/1917 22-22--? 35.25 120.50 D F VII IN LOPEZ CANYON; IV AT SAN LUIS OBISPO. 07/09/1917 22-38--? 35.25 120.50 D F LOPEZ CANYON. 07/10/1917 -?-43--? 35.25 120.50 D F LOPEZ CANYON. 07/10/1917 -?-45--? 35.25 120.50 D F LOPEZ CANYON. 07/26/1917 08-31--? 34.92 120.42 D F V AT SANTA MARIA - FURNITURE MOVED. IV AT LOS OLIVOS - AWAKENED SLEEPERS AT SAN LUIS OBISPO 12/05/1918 02-38--? 35.67 120.67 D F IV AT PASO ROBLES; II AT SAN LUIS OBISPO. 12/05/1918 04-30--? 35.25 120.67 D F SAN LUIS OBISPO. 03/01/1919 04-19--? 36.17 120.67 D F IV IN PRIEST VALLEY. 03/15/1919 07-53--? 35.25 120.67 D F SAN LUIS OBISPO. 07/31/1919 21-31--? 36.33 120.67 D F V IN SAN BENITO COUNTY; FELT AT IDRIA - ORIGIN SOME DISTANCE FROM IDRIA 08/26/1919 12-12--? 34.50 119.67 D F V IN SANTA BARBARA COUNTY - FELT AT OJAI, SAN LUIS OBISPO (3 SHOCKS), SANTA BARBARA. 08/26/1919 14.57--? 34.50 119.67 D F V IN SANTA BARBARA COUNTY - THIS SHOCK STRONGER AT SANTA BARBARA THAN PREVIOUS SHOCK. BUILDINGS AND WHARVES SWAYED; FELT AT OJAI. 12/18/1919 07-15--? 35.67 120.67 D F PASO ROBLES. 01/30/1920 23-30--? 34.50 119.67 D F III AT SANTA BARBARA. 01/30/1920 23-33--? 34.50 119.67 D F II AT SANTA BARBARA. 01/30/1920 23-35--? 34.50 119.67 D F II AT SANTA BARBARA. 01/30/1920 23-38--? 34.50 119.67 D F II AT SANTA BARBARA. 01/31/1920 01--?--? 34.50 119.67 D F III AT SANTA BARBARA. 01/31/1920 01-03--? 34.50 119.67 D F III AT SANTA BARBARA. 01/31/1920 01-07--? 34.50 119.67 D F III AT SANTA BARBARA. 03/20/1920 07-04--? 35.25 120.67 D F II AT SAN LUIS OBISPO. 05/07/1920 01-59--? 35.25 120.67 D F IV AT SAN LUIS OBISPO. 06/28/1920 09-01--? 35.25 120.67 D F V AT SAN LUIS OBISPO. 12/01/1920 01-30--? 35.17 119.50 D F VI AT TAFT - MANY PEOPLE MADE "SEASICK", DISHES SHAKEN FROM SHELVES, IV AT MARICOPA. 12/05/1920 11-58--? 34.50 119.67 D F V IN SANTA BARBARA COUNTY MOUNTAINS, V AT LOMPOC, LOS ALAMOS, MARICOPA, OJAI, AND SANTA BARBARA. 12/06/1920 -?--?--? 35.25 120.67 D F SAN LUIS OBISPO. 03/10/1922 11-21-20 35.75 120.25 C 6.5 43 F IX IN CHOLAME VALLEY REGION OF SAN ANDREAS FAULT. FELT OVER AN AREA OF 100,000 SQ. MI. - CRACKS IN THE GROUND AND NEW SPRINGS. VII-VIII AT PARKFIELD AND SHANDON. VI-VII AT SAN LUIS OBISPO AND SIMMLER, AND V AT LOS ANGELES. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 7 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 03/16/1922 23-10--? 35.75 120.33 D F VI IN CHOLAME VALLEY - RATHER STRONG AFTERSHOCKS, V AT PASO ROBLES AND SAN LUIS OBISPO, AND IV AT ANTELOPE VALLEY; ALSO IV AT SHANDON. 03/19/1922 11--?--? 35.67 120.67 D F III AT PASO ROBLES. 03/23/1922 10--?--? 35.67 120.67 D F III AT PASO ROBLES. 03/25/1922 12--?--? 35.67 120.67 D F III AT PASO ROBLES. 05/31/1922 01-25--? 35.67 120.67 D F III AT PASO ROBLES; 2 SHOCKS. 07/05/1922 19--?--? 34.75 120.25 D F LOS ALAMOS. 07/09/1922 12--?--? 34.75 120.25 D F LOS ALAMOS. 07/11/1922 03--?--? 34.75 120.25 D F LOS ALAMOS. 07/11/1922 15-30--? 34.75 120.25 D F LOS ALAMOS. 08/18/1922 05-12--? 35.75 120.33 D F VII IN CHOLAME VALLEY; V AT PASO ROBLES AND SAN LUIS OBISPO. 08/20/1922 21-14--? 35.50 120.67 D F III AT ATASCADERO. 09/04/1922 10-15--? 35.67 120.67 D F IV AT PASO ROBLES. 09/05/1922 09-05--? 35.25 120.67 D F V AT SAN LUIS OBISPO; 2 SHOCKS. 12/29/1922 11--?--? 35.67 120.67 D F III AT PASO ROBLES. 12/29/1922 12--?--? 35.67 120.67 D F III AT PASO ROBLES. 03/12/1923 06--?--? 34.75 120.25 D F LOS ALAMOS. 05/04/1923 22-45--? 35.25 120.67 D F V AT SAN LUIS OBISPO; 2 SHOCKS, SECOND EQUALED INTENSITY II. 05/08/1923 05-02--? 35.75 120.33 D F II AT CHOLAME. 06/16/1923 20-40--? 35.67 120.67 D F IV AT PASO ROBLES - DURATION 15-20 SECONDS. 06/25/1923 13-21--? 35.25 120.67 D F II AT SAN LUIS OBISPO. 12/19/1923 07-35--? 34.92 120.42 D F II AT SANTA MARIA - DURATION 20 SECONDS. 07/02/1924 58-02--? 34.50 119.67 D F SANTA BARBARA. 12/30/1924 12-17--? 34.50 119.67 D F SANTA BARBARA. 12/30/1924 14-15--? 34.50 119.67 D F SANTA BARBARA. 06/29/1925 14-42-16 34.30 119.80 B 6.3 1 F IX AT SANTA BARBARA; FELT OVER AN AREA OF 100,000 SQ. MI. - RECORDED WORLD-WIDE. RUPTURE AT DEPTH ON THE MESA AND RECORDED WORLD-WIDE. RUPTURE AT DEPTH ON THE MESA AND SANTA YNEZ FAULTS (BAILEY WILLIS); A FEW DEATHS, SEVERAL MILLION DOLLARS DAMAGE; IX AT GOLETA, NAPLES, AND SANTA BARBARA; VIII AT GAVIOTA, MIRAMAR, AND SANTA YNEZ, LOS ALAMOS, LOS OLIVOS; VII AT ARROYO GRANDE, NIPOMO, ORCOTT, ALAMOS, LOS OLIVOS; VII AT ARROYO GRANDE, NIPOMO, ORCOTT, ALAMOS, LOS OLIVOS; VII AT ARROYO GRANDE, NIPOMO, ORCOTT, PISMO BEACH, SANTA MARIA, AND VENTURA, AND VI AT AVILA, LOMPOC, AND PORT SAN LUIS. 06/29/1925 15-20--? 35.25 120.67 D F III AT SAN LUIS OBISPO. 06/29/1925 16-35--? 34.50 119.67 D F SANTA BARBARA; II AT OXNARD. 06/29/1925 18-54--? 34.50 119.67 D F IV AT SANTA BARBARA; II AT OXNARD - STRONGEST AFTERSHOCK OF THE DAY. 06/30/1925 01-37--? 34.50 119.67 D F SANTA BARBARA. 06/30/1925 02-47--? 34.50 119.67 D F SANTA BARBARA. 06/30/1925 09-19--? 34.50 119.67 D F SANTA BARBARA - VIOLENT; FELT AT OJAI AND OXNARD. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 8 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 07/03/1925 16-38--? 34.50 119.67 D F VII AT SANTA BARBARA; III AT PASADENA AND OJAI - STIFF TREMOR AT VENTURA. 07/03/1925 18-21--? 34.50 119.67 D F VII AT SANTA BARBARA - STRONGEST AFTERSHOCK; FELT AT LOS ANGELES, OJAI, AND PASADENA. 07/03/1925 18-46--? 34.50 119.67 D F SANTA BARBARA. 07/04/1925 19-18--? 34.50 119.67 D F SANTA BARBARA - ANOTHER SHOCK FELT LATER IN DAY. 07/05/1925 12--?--? 34.50 119.67 D F SANTA BARBARA; 11 SHOCKS IN THE NEXT 19 HOURS. 07/06/1925 21-45--? 34.50 119.67 D F SANTA BARBARA - SEVERAL FAIRLY SEVERE SHOCKS. 07/09/1925 -?--?--? 34.50 119.67 D F SANTA BARBARA. 07/20/1925 09-50--? 34.50 119.67 D F SANTA BARBARA. 07/29/1925 14--?--? 34.50 119.67 D F V AT WASIOJA - CEMENT WALK CRACKED. 07/30/1925 09-50--? 34.50 119.67 D F SANTA BARBARA. 07/30/1925 12--?--? 34.50 119.67 D F SANTA BARBARA. 08/13/1925 11--?--? 34.50 119.67 D F SANTA BARBARA - 5 LIGHT SHOCKS DURING NIGHT; THE STRONGEST TOOK PLACE JUST BEFORE 11--?--?. 10/04/1925 -?-50--? 34.50 119.67 D F SANTA BARBARA. 10/08/1925 21-30--? 34.50 119.67 D F SANTA BARBARA. 10/30/1925 09-45--? 34.50 119.67 D F SANTA BARBARA. 10/30/1925 13-30--? 34.50 119.67 D F SANTA BARBARA AND VENTURA. 02/18/1926 18-18--? 34.17 119.50 D F VII ORIGIN AT SEA, SW OF VENTURA; FELT ALONG COAST FROM SAN LUIS OBISPO ON NW TO SOUTH OF SANTA ANA, A DISTANCE OF 200 MI. AT SANTA BARBARA WINDOWS OF A SCHOOL WERE BROKEN, WATER PIPE IN ROUNDHOUSE WAS BROKEN. THERE WAS DAMAGE TO TELEPHONE EQUIPMENT AT SIMI. ALSO FELT AT LOS ANGELES, PASADENA, SANTA MONICA, SANTA SUSANA, AND VENTURA. 04/29/1926 12-18--? 34.67 120.17 D F IV AT BUELLTON. 06/18/1926 -?--?--? 34.50 119.67 D F SANTA BARBARA. 06/24/1926 15-30--? 34.50 119.67 D F V AT SANTA BARBARA. 06/29/1926 23-21--? 34.50 119.67 D F VII-VIII AT SANTA BARBARA - ONE PERSON KILLED BY FALLING CHIMNEY. VI AT BUELLTON AND VENTURA; ALSO FELT AT CAMARILLO, LOS ANGELES, OJAI, OXNARD, PORT HUENEME, AND SANTA PAULA - POSSIBLY SUBMARINE ORIGIN; FELT OVER AN AREA OF 30,000 SQ. MI. 07/03/1926 23--?--? 34.50 119.67 D F II AT SANTA BARBARA. 07/06/1926 17-45--? 34.50 119.67 D F V AT SANTA BARBARA. 07/25/1926 -?--?--? 36.30 120.30 (CALTECH FILE) 08/06/1926 17-42--? 34.50 119.67 D F IV IN SANTA BARBARA REGION; 2 SHOCKS AT OJAI - LASTED 30 SECONDS AT VENTURA WITH SHARP SHOCK AT SANTA BARBARA. 08/09/1926 04-12--? 34.50 119.67 D F V AT SANTA BARBARA; 2 SHOCKS AT VENTURA. 10/22/1926 10-10--? 35.67 120.67 D F III AT PASO ROBLES. 10/22/1926 -?--?--? 36.45 122.00 (CALTECH FILE) 12/09/1926 -?-03--? 35.67 120.67 D F IV AT PASO ROBLES - PROBABLY MISTIMED REPORT OF SHOCK AT -? 41-?. 12/09/1926 -?-41--? 35.25 120.67 D F NE OF SAN LUIS OBISPO; AT SAN LUIS OBISPO DURATION 20 SECONDS; FELT AT COALINGA WITH ORIGIN ABOUT 120 MI. FROM MT HAMILTON. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 9 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 12/27/1926 09-19--? 36.17 120.33 D F VI NEAR COALINGA; FELT OVER AN AREA OF 25,000 SQ. MI. FELT AT FIREBAUGH, FRESNO, LOS BANOS, MENDOTA, OAKDALE, OILFIELDS, PORTERVILLE, AND SAN LUIS OBISPO. 11/04/1927 11--?--? 34.58 120.67 D F LOMPOC, POINT ARGUELLO, AND SAN LUIS OBISPO. 11/04/1927 11-30--? 34.58 120.67 D F LOMPOC. 11/04/1927 13-50-53 34.54 121.40 A 7.3 3 F X AT SEA, WEST OF POINT ARGUELLO. AREA SHAKEN WITH INTENSITY VI OR GREATER WAS 40,000 SQ. MI. A SMALL SEA WAVE WAS PRODUCED, RECORDED ON TIDE GAUGES AT SAN DIEGO AND SAN FRANCISCO, AND OBSERVED AS 6 FEET HIGH AT SURF; IX AT HONDA, ROBERDS RANCH, SURF, AND WHITE HILLS, VIII AT ARLIGHT, ARROYO GRANDE, BERROS, BETTERAVIA, CAMBRIA, CASMALIA, CAYUCOS, GUADOCEANO, PISMO BEACH, POINT CONCEPTION, SAN JULIAN RANCH, SAN LUIS OBISPO, AND SANTA MARIA, VI-VII AT GUADOCEANO, PISMO BEACH, POINT CONCEPTION, SAN JULIAN RANCH, SAN LUIS OBISPO, AND SANTA MARIA, VI-VII AT ALUPE, HALCYON, HARRISTON, HUASNO, LOMPOC, LOS ALAMOS, LOS OLIVOS, MORRO BAY, NIPOMO, ADELAIDA, ATASCADERO, BAKERSFIELD, BICKNELL, BUTTONWILLOW,CARPINTERIA CHOLAME, CRESTON, EDNA GAVIOTA, GOLETA, HARMONY, KING CITY, LAS CRUCES, NAPLES, OXNARD, PASO ROBLES, REWARD, SANTA BARBARA, SANTA MARGARITA, SANTA YNEZ, SOLVANG, TAFT, TEMPLETON, VENTURA, AND WASIOJA, AND IV-V AT ANNETTE, BIG SUR, CASTROVILLE, COALINGA, FELLOWS, GONZALES, GORMAN, HOLLISTER, LOCKWOOD, LUCIA, MCKITTRICK, MONTEREY, PARKFIELD, PATTIWAY, PORT SAN LUIS, POZO, PRIEST, SALINAS, SANGER, SAN LUCAS, SAN SIMEON, SANTA PAULA, SCHEIDECK, SESPE, SIMMLER, SOLEDAD, AND TEHACHAPI. DATA FROM BSSA V. 17, P. 258 AND V. 20, P. 53. 11/04/1927 14-12--? 34.58 120.67 D F SANTA MARIA - AFTERSHOCK. 11/04/1927 14-14--? 34.58 120.67 D F SANTA MARIA - AFTERSHOCK. 11/04/1927 15--?--? 34.58 120.67 D F SAN LUIS OBISPO - AFTERSHOCK. 11/04/1927 15-42--? 34.58 120.67 D F SANTA MARIA - AFTERSHOCK. 1/05/1927 08-17--? 34.58 120.67 D F POINT ARGUELLO - AFTERSHOCK; MILD AT SURF. 11/05/1927 09--?--? 34.58 120.67 D F POINT ARGUELLO - AFTERSHOCK; REPORTED FROM PASO ROBLES TO HADLEY TOWER. 11/05/1927 11-37--? 34.58 120.67 D F POINT ARGUELLO - AFTERSHOCK; REPORTED FROM SURF TO HADLEY TOWER, AND SOUTH OF SAN LUIS OBISPO. 11/06/1927 -?-06--? 34.67 120.17 D F IV AT BUELLTON. 11/06/1927 02-25--? 34.67 120.17 D F POINT ARGUELLO - AFTERSHOCK; STRONGEST IMMEDIATE AFTERSHOCK AT LOMPOC. 11/06/1927 03-10--? 34.67 120.17 D F IV AT BUELLTON. 11/06/1927 22-10--? 34.67 120.17 D F OFF POINT CONCEPTION. 11/06/1927 22-50--? 34.67 120.17 D F IV AT BUELLTON. 11/06/1927 23-10--? 34.67 120.17 D F OFF POINT CONCEPTION. 11/08/1927 10-10--? 34.67 120.17 D F IV AT BUELLTON - SHARP BUMPING AT 10-02--?, AROUSED NEARLY ALL. AT LOMPOC MANY AWAKENED BY SHOCK AT 10-15--?. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 10 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 11/19/1927 03-32--? 34.92 120.42 D F VII AT SANTA MARIA - CENTERED TO NW OF ORIGIN OF NOVEMBER 4 QUAKE -WEAKER, YET NEARLY AS STRONG AT SANTA MARIA,AND VI AT BETTERAVIA AND BICKNELL; REPORTED FROM SAN MIGUEL AND PARKFIELD ON THE NORTH TO SANTA BARBARA CHANNEL ON THE SOUTH. 12/05/1927 11-45--? 34.58 120.67 D F IV AT POINT ARGUELLO, AND IV AT BUELLTON WITH 2 SHOCKS 15 SECONDS APART; FELT AT GUADALUPE, SANTA MARGARITA, SANTA MARIA AND SURF. 12/31/1927 10-10--? 34.58 120.67 D F V AT POINT ARGUELLO. 03/15/1928 12-03--? 34.92 120.42 D F SANTA MARIA. 03/15/1928 12-20--? 34.50 119.67 D F SANTA BARBARA. 03/16/1928 14-30--? 34.92 120.42 D F SANTA MARIA. 03/29/1928 06-25--? 34.92 120.42 D F VII AT SANTA MARIA. 06/09/1928 08-22--? 35.17 119.50 D F TAFT. 06/09/1928 08-31--? 35.17 119.50 D F TAFT. 06/09/1928 12-25--? 35.17 119.50 D F TAFT. 09/03/1928 04-01-54 34.50 122.50 D 5.0 1 OFF POINT ARGUELLO - LICK OBSERVATORY S-P= 39 SECONDS. 11/02/1928 05--?--? 34.67 120.42 D F LOMPOC. 05/28/1929 07-10--? 36.17 120.33 D F COALINGA. 07/03/1929 09-24--? 34.50 119.67 D F SANTA BARBARA. 07/12/1929 13-10--? 36.17 120.33 D F COALINGA. 08/28/1929 18-10--? 34.50 119.67 D F SANTA BARBARA. 09/09/1929 05-15--? 34.50 119.67 D F GAVIOTA, NAPLES, AND SANTA BARBARA. 09/16/1929 03-16--? 35.42 120.92 D F CAYUCOS. 09/16/1929 06-15--? 35.42 120.92 D F CAYUCOS. 10/05/1929 20-03--? 36.17 120.33 D F COALINGA AND LIGHTHIPE. 10/06/1929 21-14--? 36.17 120.33 D F COALINGA. 10/07/1929 08--?--? 36.17 120.33 D F COALINGA. 10/07/1929 11-30--? 34.83 120.42 D F ORCUTT. 10/11/1929 17-55--? 36.17 120.33 D F COALINGA. 10/15/1929 22-02--? 36.17 120.67 D F COALINGA, KETTLEMEN HILLS, OILFIELDS, AND PRIEST VALLEY,. 11/07/1929 06-30--? 36.33 119.67 D F HANFORD. 11/09/1929 02-30--? 36.17 120.33 D F BITTER WATER, COALINGA, AND MCKITTRICK. 11/20/1929 22-50--? 36.42 121.00 D F BITTER WATER. 11/24/1929 09-54--? 36.42 121.00 D F LONOAK, BITTER WATER, AND LEWIS CREEK. 11/26/1929 08-05--? 36.42 121.00 D F V AT BITTER WATER AND SAN ARDO; FELT FROM HOLLISTER TO SANTA MARGARITA. 11/26/1929 09--?--? 36.42 120.83 D F HERNANDEZ. 11/26/1929 18-06--? 36.42 121.00 D F BITTER WATER. 12/05/1929 07-40--? 36.33 119.67 D F HANFORD. 03/11/1930 23-59--? 36.42 121.25 D F PINNACLES. 06/21/1930 05-15--? 34.83 120.50 D F CASMALIA. 08/05/1930 11-25--? 34.42 119.50 D F NEAR SANTA BARBARA - FELT OVER AN AREA OF 9000 SQ. MI. V-VI AT CARPINTERIA, GOLETA, OJAI, OXNARD, AND SANTA BARBARA,. 08/08/1930 16.46--? 34.42 119.67 D F SANTA BARBARA AND GOLETA. 08/18/1930 13-09--? 34.33 120.58 D F OFF POINT CONCEPTION; V OVER A LAND AREA OF 500 SQ. MI. NEAR POINT CONCEPTION. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 11 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 08/28/1930 05-15--? 36.42 121.33 D F SOLEDAD. 09/02/1930 13-35--? 35.00 121.00 D F OFF COAST - FELT AT HALCYON AND SAN LUIS OBISPO. 09/09/1930 05-27--? 34.42 119.50 D F SANTA BARBARA. 10/02/1930 14-18--? 34.58 120.67 D F OFF POINT ARGUELLO - FELT AT HALCYON. 10/28/1930 13-57--? 35.42 120.92 D F OFF COAST NEAR CAYUCOS - FELT AT NIPOMO. 12/08/1930 01-23--? 34.50 119.67 D F GOLETA AND SANTA BARBARA. 12/08/1930 01-29--? 34.50 119.67 D F GOLETA AND SANTA BARBARA. 02/21/1931 08-10--? 35.67 121.33 D F NW OF SAN LUIS OBISPO - FELT AT BRYSON AND PIEDRAS BLANCAS. 02/23/1931 10-01--? 35.83 120.50 D F OVER AN AREA OF 5000 SQ. MI.; V AT CAYUCOS, PARKFIELD, AND TEMPLETON. 02/23/1931 10-33--? 35.83 120.50 D F SAME AS ABOVE. 04/05/1931 03--?--? 36.17 121.00 D F SE OF KING CITY. 07/15/1931 18-40--? 35.00 120.58 D F GUADALUPE, NIPOMO, AND SANTA MARGARITA. 07/21/1931 03-25--? 35.25 120.67 D F SAN LUIS OBISPO. 07/21/1931 12-08--? 35.25 120.67 D F IV AT HALCYON, LOS ALAMOS, NIPOMO, OCEANO, AND TEMPLETON:ALSO FELT AT CAMBRIA, GAVIOTA, PIEDRAS BLANCAS, PORT SAN LUIS, SAN LUIS OBISPO, SANTA MARGARITA, AND SANTA MARIA 09/03/1931 13-50--? 34.50 119.67 D F SANTA BARBARA. 09/10/1931 14-35--? 35.50 120.67 D F ATASCADERO. 09/30/1931 14-35--? 35.50 120.67 D F ATASCADERO. 10/13/1931 12-25--? 36.33 121.67 D F JAMESBURG. 10/18/1931 19-58--? 36.33 121.67 D F IV AT HOLLISTER, JAMESBURG, AND SPRECKLES; ALSO FELT AT APTOS, CARMEL, CHUALAR, MOSS LANDING, MONTEREY, PARAISO, SALINAS, AND SANTA CRUZ. 12/04/1931 -?-53--? 36.50 121.67 D F 10 MI. S OF SPRECKELS. FELT AT HOLLISTER, METZ, PIGEON POINT, SPRECKELS, AND SANTA CRUZ. 02/04/1932 16-02-58 34.55 119.73 C 3.0 1 F SANTA BARBARA AND VENTURA. 02/05/1932 04-14-45 35.83 121.47 C 3.5 1 F COAST OF MONTEREY COUNTY; FELT AT PIEDRAS BLANCAS LIGHT AND SALMON CREEK. 02/05/1932 06-46-54 35.83 121.47 C 3.5 1 F COAST OF MONTEREY COUNTY; FELT AT PIEDRAS BLANCAS LIGHT AND SALMON CREEK. 02/05/1932 07-10--? 35.83 121.47 C F AFTERSHOCK OF PRECEDING. 02/26/1932 16-58--? 36.00 121.00 5.0 F IV AT APTOS, ASILOMAR, CARMEL, DEL MONTE, GONZALES, METZ, MONTEREY, PACIFIC GROVE, AND PEBBLE BEACH. 03/13/1932 23-09-24 34.44 120.17 B 3.5 1 F OFF POINT CONCEPTION; FELT AT BUELLTON. 04/21/1932 03-36-20 35.50 120.67 D 3.0 F ATASCADERO. 05/06/1932 03-37-08 36.00 120.50 C 3.0 1 F PARKFIELD. 06/27/1932 05-17-25 36.00 122.00 D 4.0 COAST OF MONTEREY COUNTY. 10/24/1932 04-45--? 35.75 120.75 D F PASO ROBLES. 01/30/1933 17--?--? 34.67 120.42 D F LOMPOC. 02/26/1933 09-34-32 36.40 121.30 D F III AT HOLLISTER, SALINAS, AND SPRECKLES. 04/12/1933 10-03--? 36.33 121.75 D F IV AT PORTERVILLE AND VISALIA. 06/26/1933 06-26--? 34.42 120.50 D F V AT BUELLTON AND POINT CONCEPTION. 06/26/1933 06-29--? 34.42 120.50 D F V AT BUELLTON AND POINT CONCEPTION. 01/09/1934 12-48--? 35.13 120.08 C 3.0 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 12 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 01/12/1934 12-50--? 34.45 120.15 D F IV AT LOS ALAMOS. 02/01/1934 16-09--? 34.55 119.53 B 3.5 F II AT SANTA BARBARA. 02/11/1934 15-16--? 34.55 119.53 C 2.0 03/20/1934 11-48--? 36.00 120.00 D 3.0 05/06/1934 20-14--? 35.83 120.75 B 3.5 05/10/1934 11-28--? 34.50 119.58 C 3.0 05/19/1934 06-37--? 34.58 120.75 D 3.0 05/24/1934 06-52--? 34.42 119.75 C 2.5 05/24/1934 09-04--? 34.42 119.75 C 2.5 05/24/1934 11-18--? 34.42 119.75 C 2.0 06/05/1934 09-51--? 35.80 120.33 D F COALINGA AND KETTLEMAN HILLS; ALSO FELT AT MONTEREY AND SANTA CRUZ. 06/05/1934 11-30--? 35.80 120.33 D F SAN MIGUEL AND SHANDON. 06/05/1934 11-47--? 35.80 120.33 B 3.0 06/05/1934 13-46--? 35.80 120.33 C 3.0 06/05/1934 21-30--? 35.80 120.33 D F SAN MIGUEL. 06/05/1934 21-48--? 35.80 120.33 B 5.0 F V AT ADELAIDA, PARKFIELD, AND PRIEST, IV AT ATASCADERO, AVENAL, BIG SUR, BRYSON, CARMEL, HANFORD, KING CITY, LEMOORE, LONOAK, PARAISO, SAN MIGUEL, SANTA CRUZ, SHANDON, AND TEMPLETON, III AT APTOS, BOULDER CREEK, CAMBRIA, CHUALAR, COALINGA, GONZALES, HOLLISTER, MONTEREY, MORRO BAY, PASO ROBLES, SALINAS, SAN FRANCISCO, SAN JOAQUIN VALLEY, SAN LUIS OBISPO, SOLEDAD, SPRECKLES, ETC.; NOT FELT AT ANTIOCH, ETC., BAKERSFIELD, FRESNO, GILROY, LIVERMORE, LOS GATOS, MARICOPA, MERCED, MODESTO, MORGAN HILL, REDWOOD CITY, SAN JOSE, SANTA MARIA, TULARE, OR WATSONVILLE. 06/05/1934 22-52--? 35.80 120.33 C 4.0 F VI AT ADELAIDA; IV AT ATASCADERO. 06/05/1934 23-30--? 35.80 120.33 D F V AT LEMOORE; ALSO FELT AT CASTROVILLE. 06/06/1934 -?-55--? 35.80 120.33 C 3.0 06/06/1934 16-40--? 35.80 120.33 C 3.5 06/06/1934 22-40--? 35.80 120.33 C 3.5 F ADELAIDA, GRAEAGLE, AND PAYNES CREEK. 06/07/1934 22-30--? 35.80 120.33 D F STONE CANYON. 06/08/1934 04-15--? 35.80 120.33 D F IV AT GONZALES AND MCKITTRICK. 06/08/1934 04-30--? 35.80 120.33 B 5.0 F VI TO VII AT CHOLOME RANCH, PARKFIELD, AND STONE CANYON DURATION 30 SECONDS, DAMAGE SLIGHT, V AT ATASCADERO, AT ANTELOPE, BIG SUR, CAMBRIA, CASTROVILLE, DELANO, MONTEREY, PASO ROBLES, SAN LUIS OBISPO, SANTA BARBARASANTA MARGARITA, SANTA MARIA, SOLEDAD, TAFT, VENTURA, VISALIA, ETC., AND III OR LESS AT ARVIN, BAKERSFIELD, FRESNO, KERNVILLE, LOMPOC, LOS ANGELES, MENDOTA, PORTERVILLE, SALINAS, SAN BENITO, SANTA ANA, SANTA BARBARA, TULARE, WATSONVILLE, ETC.; NOT FELT AT BIG BASIN, CAJON, COYOTE, GILROY, HUNTINGTON BEACH, INDEPENDENCE, INYOKERN, LANCASTER, MERCED, POMONA, OR SAN JOSE. 06/08/1934 04-37--? 35.60 121.30 D F IV AT PIEDRAS BLANCAS, SAN LUIS OBISPO, AND SANTA CRUZ; ALSO FELT AT BRYSON AND LOS ALAMOS. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 13 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 06/08/1934 04-45--? 35.80 120.33 D F ATASCADERO, COALINGA, LOCKWOOD, PASO ROBLES, PORT SAN LUIS, PRIEST, SAN MIGUEL, AND WESTHAVEN. 06/08/1934 04-47--? 35.80 120.33 B 6.0 F WITHIN A RADIUS OF 250 KM FROM THE EPICENTER NEAR THE SOUTHEASTERN ANGLE OF MONTEREY COUNTY; VII TO VIII AT PARKFIELD, VI AT COALINGA, KETTLEMAN CITY, LEMOORE, AND STONE CANYON, V AT ATASCADERO, DUDLEY, HOLLISTER, KING CITY, OILFIELDS, SAN MIGUEL, SEASIDE, SHALE PUMP STATION, AND SHANDON, IV AT ANTELOPE, AVILA, CANOGA PARK, HANFORD, LOS ALAMOS, MARICOPA, MORRO BAY, NIPOMO, PASO ROBLES, PRIEST, SAN LUIS OBISPO, SANTA CRUZ, SANTA MARIA, SOLEDAD, VISALIA ETC., AND III OR LESS AT APTOS, FRESNO, KERNVILLE, LONE PINE, LOS BANOS, MENDOTA, MONTEREY, OAKLAND HARBOR, SALINAS, SAN BENITO, SANTA ANA, TEHACHAPI, TULARE, ETC. 06/08/1934 05--?--? 35.60 121.30 D F PIEDRAS BLANCAS LIGHT; ALSO BRYSON, KERNVILLE, LA PANZA, LEMOORE, PARKFIELD, SANDBERG, AND SAN FERNANDO. 06/08/1934 05-20--? 35.80 120.33 D F III AT ATASCADERO. 06/08/1934 05-23--? 35.80 120.33 C 3.5 F ATASCADERO AND SAN MIGUEL. 06/08/1934 05-36--? 35.80 120.33 C 3.0 06/08/1934 05-42--? 35.80 120.33 B 4.5 F ATASCADERO, BIG SUR, COALINGA, KING CITY, PASO ROBLES, AND WESTHAVEN. 06/08/1934 05-50--? 35.80 120.33 D F IV AT ATASCADERO; ALSO FELT AT COALINGA AND SAN LUIS OBISPO. 06/08/1934 09-30--? 35.80 120.33 B 4.0 F ATASCADERO AND PARKFIELD. 06/08/1934 15-30--? 35.80 120.33 C 3.5 06/08/1934 16-30--? 35.80 120.33 D F PARKFIELD. 06/08/1934 23-23--? 35.80 120.33 B 4.0 F NEAR PARKFIELD. 06/10/1934 06-47--? 35.80 120.33 C 3.0 06/10/1934 08-03--? 35.80 120.33 B 4.5 F NEAR PARKFIELD; IV AT SAN MIGUEL. 06/10/1934 20-02--? 35.80 120.33 D F IV AT SAN MIGUEL; ALSO PARKFIELD AND WOODY. 06/11/1934 03-25--? 35.80 120.33 C 3.0 06/12/1934 10-47--? 35.80 120.33 C 3.5 06/14/1934 14-55--? 35.80 120.33 C 4.0 F IV AT ATASCADERO; ALSO FELT AT SAN MIGUEL AND TEMPLETON. 06/14/1934 15-54--? 35.80 120.33 C 4.0 F III AT ATASCADERO AND SAN MIGUEL. 06/14/1934 19-26--? 35.80 120.33 C 4.5 F ATASCADERO AND TEMPLETON. 06/14/1934 22-02--? 35.80 120.33 C 3.5 F ATASCADERO. 06/15/1934 04-48--? 35.80 120.33 C 3.0 06/16/1934 23-03--? 36.50 121.00 D 4.0 F IV AT HOLLISTER AND MONTEREY, AND III AT GONZALES, PARKFIELD, AND SALINAS. 07/02/1934 18-44--? 35.80 120.33 B 3.0 08/04/1934 -?-18--? 35.80 120.33 B 3.0 08/21/1934 03-37--? 36.08 120.58 D F IV IN STONE CANYON. 08/25/1934 18-52--? 34.42 119.75 C 2.5 08/26/1934 03-02--? 35.57 119.85 B 3.0 09/06/1934 23-24--? 36.00 120.55 C 3.0 09/16/1934 14-38--? 35.83 120.33 C 3.5 10/07/1934 -?-18--? 34.55 120.78 C 3.5 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 14 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 10/08/1934 04-57--? 34.50 119.58 C 2.0 10/10/1934 10-52--? 34.55 120.78 C 3.0 10/19/1934 15-39--? 35.80 120.33 C 3.0 11/04/1934 22-17--? 34.53 119.67 B 3.0 11/21/1934 01-02--? 34.58 119.62 B 2.5 12/01/1934 13-05--? 36.00 121.50 D F 15 MI. S OF PARAISO; V AT PIEDRAS BLANCAS LIGHT AND IV AT PARAISO. 12/02/1934 16-07--? 35.97 120.58 C 4.0 F SAN MIGUEL. 12/03/1934 01-54--? 35.95 121.50 C 4.5 F IV AT BRYSON, KING CITY, AND PARAISO; ALSO FELT AT PARKFIELD, PASO ROBLES, SAN LUCAS, AND SAN MIGUEL. 12/17/1934 11-10--? 34.58 120.33 B 4.5 F VI AT LOS ALAMOS. 12/17/1934 13-51--? 34.58 120.33 C 2.5 F LOS ALAMOS. 12/17/1934 15-16--? 34.55 119.67 C 2.5 12/17/1934 15-35--? 34.58 120.33 C 2.5 12/18/1934 03-09--? 34.58 120.33 C 4.0 F LOS ALAMOS. 12/18/1934 04-34--? 34.58 120.33 C 3.0 F LOS ALAMOS. 12/18/1934 05-28--? 34.58 120.33 C 3.0 F LOS ALAMOS. 12/19/1934 20-39--? 34.28 119.50 B 2.5 12/20/1934 12-37--? 34.58 120.33 C 2.5 F LOS ALAMOS. 12/20/1934 12-39--? 34.58 120.33 C 3.0 12/20/1934 22-21--? 34.58 120.33 C 3.0 12/23/1934 16-08--? 34.58 120.33 C 2.5 12/24/1934 10-22--? 34.58 120.33 B 3.0 F LOS ALAMOS. 12/24/1934 16-26--? 35.93 120.48 B 5.0 F IV AT LOS ALAMOS AND SHANDON; ALSO FELT AT KING CITY TEMPLETON. 12/25/1934 04-03--? 34.58 120.33 C 3.0 01/06/1935 04-04--? 35.98 120.48 C 4.0 F IV AT PARKFIELD; ALSO FELT AT SHANDON. 01/06/1935 04-25--? 35.90 120.45 D F IV AT PARKFIELD. 01/06/1935 04-40--? 35.98 120.48 C 4.0 F IV AT PARKFIELD AND III AT SHANDON. 01/07/1935 -?-11--? 35.75 119.67 D 3.0 01/23/1935 03-16--? 34.58 120.33 C 3.5 F IV AT LOS ALAMOS. 01/27/1935 09-49--? 34.50 119.62 B 2.5 02/18/1935 04-02--? 35.93 120.48 C 3.5 02/19/1935 14-17--? 35.93 120.48 D 3.0 02/28/1935 19-06--? 35.80 120.33 C 3.0 03/03/1935 11-26--? 36.42 121.75 C 3.0 03/06/1935 23-14--? 34.43 119.87 C 3.5 F III AT SANTA BARBARA. 03/19/1935 03-59--? 34.55 120.78 B 4.0 OFF POINT ARGUELLO. 04/05/1935 10-13--? 35.93 120.48 C 3.5 05/05/1935 12-58--? 34.58 119.68 C 2.5 05/18/1935 04-36--? 34.58 120.33 B 3.5 F IV AT LOS ALAMOS. 05/19/1935 03-44--? 34.58 120.33 C 3.0 05/20/1935 23-44--? 34.58 120.33 C 3.0 05/27/1935 16-08--? 35.37 120.97 C 3.0 F III AT TEMPLETON. 06/10/1935 02-02--? 35.33 119.83 C 3.5 06/18/1935 08-52--? 34.60 119.60 C 2.0 06/23/1935 23-53--? 34.55 119.68 C 3.0 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 15 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 06/30/1935 23-28--? 36.00 121.00 D 4.0 F SE OF SALINAS; III AT HOLLISTER. 07/25/1935 04-16--? 35.80 120.33 C 3.0 F V AT PARKFIELD. 07/28/1935 06--?--? 35.70 121.12 B 4.0 F SAN SIMEON. 08/06/1935 19-05--? 34.62 119.62 C 3.0 F SANTA BARBARA. 08/07/1935 22-30--? 34.55 120.78 C 3.5 08/09/1935 17-14--? 36.17 120.98 C 3.5 F PRIEST VALLEY. 08/31/1935 09-28--? 34.50 119.70 C 2.5 10/18/1935 09-24--? 35.80 120.70 D 3.5 F IV AT PARKFIELD - AFTERSHOCK. 10/22/1935 18-37--? 35.93 120.48 C 4.0 F PARKFIELD. 10/25/1935 19-43--? 36.40 121.55 D F 13 MI. W OF SOLEDAD; IV AT SAN BENITO. 10/26/1935 10-46--? 35.85 121.40 D F AFTERSHOCK. 12/22/1935 06-54--? 34.55 120.78 C 3.0 02/03/1936 09-12--? 34.75 119.75 C 2.5 02/21/1936 23-06--? 34.42 119.67 C 3.0 02/22/1936 -?-18--? 34.42 119.67 C 3.0 02/22/1936 -?-21--? 34.42 119.67 C 2.5 02/22/1936 -?-23--? 34.42 119.67 C 3.0 02/22/1936 04-55--? 34.42 119.67 C 3.0 03/06/1936 03-45--? 35.90 120.40 D 3.0 03/17/1936 01-55--? 36.50 120.92 C 4.0 F IV AT CHUALAR, HOLLISTER, AND TRES PINOS. 03/18/1936 09-07--? 35.93 120.48 C 2.5 03/27/1936 -?-58--? 34.55 120.78 C 3.0 03/29/1936 09-26--? 34.50 119.62 C 2.5 05/20/1936 17-22--? 35.93 120.48 C 3.0 05/23/1936 04-41--? 36.17 120.92 C 4.0 F IV AT KING CITY. 05/27/1936 19-55--? 36.50 121.17 C 4.5 SAN BENITO COUNTY. 06/24/1936 12-23--? 35.12 120.08 C 3.0 F SAN LUIS OBISPO CO.; IV AT LOS ALAMOS. 07/13/1936 18-09--? 34.50 119.60 D 2.5 07/22/1936 04-03--? 34.50 119.80 C 2.5 07/30/1936 09-36--? 34.57 119.63 C 3.0 09/07/1936 16-47--? 34.37 120.38 C 3.0 09/09/1936 04-54--? 34.37 120.38 C 4.0 F LOS ALAMOS. 09/10/1936 21-21--? 34.40 120.40 D 3.0 09/12/1936 13-56--? 34.75 120.33 C 3.5 09/15/1936 -?-09--? 34.50 120.50 D 2.5 10/16/1936 15-30--? 34.83 120.58 C 4.0 NEAR CASMALIA. 10/16/1936 15-36--? 34.83 120.58 C 3.0 10/17/1936 01-17--? 34.83 120.58 C 3.0 10/19/1936 14-01--? 34.83 120.58 C 3.0 11/01/1936 15-10--? 34.55 120.78 B 4.0 OFF POINT ARGUELLO. 11/02/1936 01-29--? 34.55 120.78 C 3.0 11/05/1936 14-30--? 35.85 121.40 D F HOLLISTER. 11/08/1936 16-51--? 34.55 120.78 C 3.0 11/08/1936 22-43--? 34.55 120.78 C 3.0 11/18/1936 17-15--? 35.35 120.60 D F POZO, SAN LUIS OBISPO, AND SANTA MARGARITA. 11/18/1936 18-02--? 34.70 120.25 C 4.5 F IV AT ARROYO GRANDE, ATASCADERO, BETTERAVIA, LOS ALAMOS OCEANO, POZO, SAN LUIS OBISPO, AND SANTA MARGARITA. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 16 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 11/22/1936 02-16--? 34.58 120.78 C 3.5 11/25/1936 21-51--? 34.58 120.78 C 3.0 12/23/1936 17-16--? 35.93 120.48 B 3.5 12/26/1936 01-12--? 34.55 119.68 C 2.5 01/12/1937 15-44--? 34.50 120.80 D 3.0 01/28/1937 17-36--? 34.43 119.87 C 2.5 02/16/1937 17-40--? 34.55 120.78 C 4.0 OFF POINT ARGUELLO. 02/17/1937 03-33--? 36.50 121.58 C 4.5 F 9 MI. SE OF PAICINE; FELT AT ANTELOPE, HOLLISTER, AND PANOCHE. 02/20/1937 09-58--? 35.93 120.48 C 4.0 F PARKFIELD AND PASO ROBLES. 02/22/1937 18-10--? 36.17 121.53 C 4.0 F KING CITY. 02/24/1937 13-37--? 34.50 119.70 C 2.0 02/25/1937 03-20--? 34.50 119.70 C 2.0 03/26/1937 21-35--? 34.60 119.70 C 3.5 03/31/1937 17-43--? 34.50 119.70 C 3.0 04/17/1937 08-30--? 34.60 119.70 C 2.5 04/30/1937 08-16--? 34.50 119.70 D 2.5 05/31/1937 15-33--? 36.50 120.70 C 3.0 06/02/1937 09-32--? 34.40 119.70 C 2.5 07/31/1937 14-18--? 34.22 119.55 C 3.0 07/31/1937 15-14--? 34.22 119.55 C 2.5 08/15/1937 19-01--? 36.50 120.70 D 3.0 08/22/1937 01-56--? 35.00 121.00 D 3.5 09/16/1937 02-48--? 35.93 120.48 B 3.5 F NEAR PARKFIELD; FELT AT BRADLEY. 09/18/1937 13-29--? 36.50 121.50 D 4.0 F 9 MI. SE OF PAICINES; FELT AT CHUALAR, SALINAS, AND SPRECKLES. 09/22/1937 02-41--? 34.50 119.70 C 3.0 09/29/1937 22-39--? 34.50 119.70 C 3.0 10/13/1937 08-32--? 34.40 119.70 C 2.5 11/01/1937 21-40--? 36.50 121.40 D F 6 MI. N OF GONZALES. 11/03/1937 10--?--? 36.15 121.00 D F V AT SAN LUCAS; FELT ALSO AT KING CITY AND SAN ARDO. 11/22/1937 04-12--? 34.55 120.78 C 4.5 F OFF POINT ARGUELLO; V AT BUELLTON, GOLETA, PISMO BEACH, POINT D SANTA MARIA, AND IV AT ARLIGHT, BETTERAVIA, BICKNELL, E, GAVIOTA, GUADALUPE, LOMPOC, LOS ALAMOS, LOS OLIVOS, SANTA URF. 11/22/1937 04-51--? 34.55 120.78 C 3.5 11/28/1937 09-55--? 34.55 120.78 C 3.5 12/03/1937 15-28--? 34.55 120.78 C 4.0 F OFF POINT ARGUELLO; FELT AT GAVIOTA AND POINT CONCEPTION. 12/03/1937 21-13--? 34.55 120.78 C 3.5 12/05/1937 01-36--? 36.00 121.00 D 3.5 F 19 MI. S OF LOS BANOS; V AT LOS BANOS. 12/05/1937 01-37--? 36.00 121.00 D 4.0 SAN BENITO COUNTY. 12/05/1937 02-05--? 36.00 121.00 D 3.0 F 19 MI. S OF LOS BANOS. 12/24/1937 11-57--? 34.50 120.80 D 4.0 F OFF POINT ARGUELLO. FELT AT CASMALIA, LOS ALAMOS, POINT CONCEPTION. 12/25/1937 13-01--? 36.00 120.00 D 3.0 01/01/1938 01-59--? 34.55 120.78 C 3.5 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 17 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 01/18/1938 04-35--? 34.55 120.78 B 3.5 01/24/1938 04-38--? 34.55 120.78 C 3.5 01/25/1938 12-24--? 34.55 120.78 C 3.5 02/01/1938 18-14--? 34.55 120.78 C 3.5 02/20/1938 14--?--? 34.55 120.78 C 3.5 02/21/1938 10-59--? 35.93 120.78 C 3.0 03/04/1938 15-14--? 34.30 119.57 C 2.5 03/04/1938 18-25--? 34.30 119.57 C 2.5 04/12/1938 01-50--? 34.55 120.78 C 3.5 05/10/1938 10-32--? 36.20 121.30 D 4.5 F BIG SUR, HOLLISTER, KING CITY, PINNACLES, SALINAS, SOLEDAD, SOQUEL, AND TRES PINOS-6 SHOCKS FELT AT PINNACLES. 05/10/1938 10-41--? 36.20 121.30 D 4.0 F SAN BENITO. 05/13/1938 19-34--? 36.20 121.30 D 4.0 MONTEREY COUNTY. 05/27/1938 22-03--? 36.20 120.00 D 3.5 06/01/1938 05-17--? 34.55 119.68 D F SANTA BARBARA. 06/01/1938 06-17--? 34.55 119.68 D 3.0 06/06/1938 02-55--? 34.50 119.67 C 3.0 09/16/1938 06-11--? 36.40 121.20 D 4.0 F PINNACLES. 09/27/1938 10-21--? 34.50 119.70 C 2.5 09/27/1938 12-23--? 36.30 120.90 C 5.0 F OVER AN AREA OF 9000 SQ. MI. OF WEST-CENTRAL CALIFORNIA, ALONG THE COAST AS FAR NORTH AS PESCADERO AND SOUTH TO SAN LUIS OBISPO. INLAND IT WAS FELT AT COALINGA, MENDOTA, AND STEVENSON, WITH A V AT BIG SUR, BRYSON, CHUALAR, GONZALES, GREENFIELD, HARMONY, HOLLISTER, JOLON, LOCKWOOD, PAICINES, PARAISO, PINNACLES, SAN ARDO, SAN BENITO, SAN LUCAS, SOLEDAD, AND SPRECKLES, AND IV AT BEN LOMOND, CAMBRIA, CARMEL, CASTROVILLE, DOS PALOS, GILROY, KING CITY, LOS BANOS, MENDOTA, MONTEREY, PASO ROBLES, PRIEST, SALINAS, SAN LUIS OBISPO, TRES PINOS, WATSONVILLE, ETC. 09/27/1938 16-20--? 36.45 121.25 D F PAICINES AND PINNACLES. 09/29/1938 12-12--? 34.55 120.78 C 4.0 OFF POINT ARGUELLO. 10/02/1938 18-45--? 34.33 119.58 C 4.0 F SANTA BARBARA AND SUMMERLAND. 10/24/1938 13-40--? 36.45 121.25 D F HOLLISTER AND PINNACLES. 10/28/1938 10-07--? 35.80 120.33 C 3.5 11/01/1938 22-46--? 35.12 120.08 C 3.0 11/16/1938 13-39--? 35.80 120.33 C 3.0 11/22/1938 15-30--? 35.93 120.48 B 4.5 F NEAR PARKFIELD; FELT AT ATASCADERO, CAMBRIA, CRESTON, MORRO BAY, PARKFIELD, PASO ROBLES, SAN MIGUEL, AND SHANDON. 01/01/1939 -?-53--? 34.58 120.33 C 3.0 01/21/1939 07-08--? 36.45 121.25 D F PINNACLES. 01/22/1939 15-52--? 34.40 119.70 C 2.5 02/05/1939 03-30--? 35.65 120.65 D F PASO ROBLES. 02/09/1939 06-44--? 35.93 120.48 C 3.0 F NEAR PARKFIELD. 02/12/1939 03-12--? 34.42 119.83 B 3.0 F GOLETA AND SANTA BARBARA . 03/24/1939 02-49--? 34.55 120.78 C 3.5 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 18 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 03/25/1939 03-45--? 36.45 121.25 D F PINNACLES. 03/30/1939 10-11--? 34.50 119.80 C 2.5 05/02/1939 18-49--? 35.93 120.48 C 4.0 F IV AT PARKFIELD. 05/03/1939 07-55--? 34.55 120.78 C 3.0 05/03/1939 12-39--? 35.65 120.65 D F PASO ROBLES. 05/18/1939 23--?--? 35.80 120.33 C 3.0 06/15/1939 21-12--? 34.50 119.70 C 2.5 06/17/1939 04-30--? 34.75 120.25 D F LOS ALAMOS. REPORTS OF SEVERAL SHOCKS. 06/24/1939 12-55--? 35.85 120.85 D F BRADLEY. 06/24/1939 13-02--? 36.40 121.00 C 5.5 F OVER AN AREA OF 10,000 SQ. MI. IN WEST-CENTRAL CALIFORNIA, ALONG THE COAST AS FAR NORTH AS HALF MOON BAY AND SOUTH TO ESTERO BAY. INLAND IT WAS FELT AT COALINGA, TRANQUILITY, AND VOLTA, WITH A VII AT HOLLISTER, VI AT KING CITY AND PAICINES, V AT CAYUCOS, SOLEDAD, AND SPRECKLES, AND IV AT PAICINES, V AT CAYUCOS, SOLEDAD, AND SPRECKLES, AND IV AT CAMBRIA, CARMEL, CASTROVILLE, CHUALAR, GILROY, GONZALES, LOCKWOOD, MILPITAS, MONTEREY, NIPOMO, PASO ROBLES, PINNACLES, SALINAS, SAN ARDO, SAN BENITO, SAN JUAN, SAN MIGUEL, SAN SIMEON, SANTA CRUZ, TRES PINOS, AND WATSONVILLE. 07/04/1939 10-49--? 36.40 121.00 C 4.0 F HOLLISTER, PAICINES, AND SALINAS. 07/10/1939 18-33--? 36.40 121.25 D F PINNACLES. 07/24/1939 09-30--? 36.25 121.80 D F BIG SUR. 07/24/1939 13--?--? 36.00 121.15 D F JOLON. 09/06/1939 01-53-43 34.58 120.42 C 3.0 09/07/1939 02-50-30 35.42 121.08 C 3.0 F OFF SAN LUIS OBISPO CO.; FELT AT CAMBRIA. 09/08/1939 01-57--? 34.75 120.25 D F LOS ALAMOS. 09/08/1939 05--?--? 34.75 120.25 D F LOS ALAMOS. 09/12/1939 -?--?-47 34.25 119.75 C 3.0 09/24/1939 11-57-40 36.40 121.00 D 3.5 10/06/1939 04-39--? 35.80 121.50 D 3.5 10/17/1939 19-21-41 34.55 120.78 C 3.5 10/17/1939 20-42-43 34.55 120.78 C 4.0 OFF POINT ARGUELLO. 11/02/1939 14-02--? 34.40 120.50 D F POINT CONCEPTION LIGHT STATION. 11/04/1939 14-11-33 36.20 120.90 D 3.0 F SALINAS AND SAN LUCAS. 12/14/1939 03-45-18 36.10 120.00 D 3.0 12/25/1939 15-36-23 34.28 119.83 C 3.5 12/28/1939 12-15-38 35.80 120.33 B 5.0 F OVER AN AREA OF 15,000 SQ. MI. IN WEST-CENTRAL CALIFORNIA, ON THE COAST FROM SANTA CRUZ SOUTH TO POINT ARGUELLO, AND INLAND TO LOST HILLS AND FRESNO. V AT COALINGA, FRESNO, GREENFIELD, PRIEST, SAN ARDO, AND SAN LUCAS, AND IV AT APTOS, ATASCADERO, BIG SUR, CAMBRIA, CARMEL, CASTROVILLE, CAYUCOS, CHUALAR, GONZALES, HOLLISTER, KING CITY, MENDOTA, MONTEREY, MORRO BAY, PARKFIELD, PASO ROBLES, PINNACLES, SALINAS, SAN JUAN BAUTISTA, SAN LUIS OBISPO, SANTA CRUZ, SOLEDAD, TAFT, ETC. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 19 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 12/29/1939 04--?--? 36.40 121.25 D F PINNACLES. 12/30/1939 15-24-37 35.80 120.33 D 3.5 F NEAR PARKFIELD. FELT AT SAN LUCAS. 02/27/1940 11-40-25 34.25 119.50 B 3.0 05/21/1940 10-05-34 35.28 120.48 B 4.0 F ATASCADERO, CAMBRIA, CAYUCOS, MORRO BAY, PASO ROBLES, PISMO BEACH, AND SAN LUIS OBISPO. 06/16/1940 09-25-04 34.55 120.78 C 4.0 F OFF POINT ARGUELLO; FELT AT GUADALUPE AND LOS ALAMOS. 06/26/1940 08-56--? 36.08 120.32 C 3.5 06/28/1940 04-06-42 34.55 120.78 C 3.0 08/13/1940 22-07-29 36.23 120.32 B 4.0 (DEPT. OF WATER RESOURCES DATA.) 08/31/1940 08-52-46 34.55 120.78 B 3.5 09/07/1940 10-36-30 36.50 121.50 D 3.5 09/07/1940 10-38-36 36.50 121.50 D 3.5 09/07/1940 13-02-06 36.50 121.50 D 4.5 F CARMEL AND SALINAS. 10/20/1940 22-18-45 34.55 120.78 C 3.0 11/10/1940 10-25-10 34.35 119.77 C 4.0 F SANTA BARBARA CHANNEL; FELT AT GOLETA, PARADISE CAMP, AND SANTA BARBARA. 11/17/1940 21-23-43 35.00 119.50 C 3.0 01/29/1941 08-54-01 34.48 119.53 B 3.0 02/04/1941 03-19-12 34.55 119.68 C 3.0 02/04/1941 03-42-09 34.55 119.68 C 3.0 02/08/1941 15-58-50 34.55 119.68 C 3.5 F SANTA BARBARA. 02/09/1941 23-49-18 34.50 119.70 C 2.0 02/11/1941 06-43-30 34.27 119.57 B 3.5 F SANTA BARBARA. 02/12/1941 20-10-24 34.40 119.70 C 3.0 02/14/1941 22-19-06 34.40 119.70 C 2.5 05/07/1941 16-17-34 34.55 120.78 C 3.5 05/15/1941 03-29--? 36.15 120.35 D F COALINGA. 05/15/1941 06--?--? 36.15 120.35 D F COALINGA. 07/01/1941 07-50-57 34.33 119.58 A 6.0 F SANTA BARBARA; FELT OVER AN AREA OF 20,000 SQ. MI. VIII AT CARPINTERIA AND SANTA BARBARA, VII AT GOLETA AND VENTURA, VI AT FILLMORE, KEYSTONE, LOS ALAMOS, OJAI, OXNARD, PORT HUENEME, SANTA PAULA, SUMMERLAND, AND WHEELER SPRINGS, AND V AT ACTON, ALTADENA, ARLIGHT, ARTESIA, ARVIN, BETTERAVIA, BUELLTON, BURBANK, CAMARILLO, CANOGA PARK, CASMALIA, CAYUCOS, CHATSWORTH, COMPTON, EL SEGUNDO, GAVIOTA, GLENDALE, HERMOSA BEACH, INGLEWOOD, LA CRESCENTA, LAGUNA BEACH, LANCASTER, LOMITA, LOMPOC, LONG BEACH, LOS ANGELES, LOS OLIVOS, MAYWOOD, MCKITTRICK, MONTALVO, MOORPARK, NEWBURY PARK, NEWPORT, NIPOMO, NORTH HOLLYWOOD, OCEANO, ORCUTT, PASADENA, PATTIWAY, IRU, POINT CONCEPTION, SANDBERG, SAN NICHOLAS ISLAND, SAN PEDRO, SANTA ANA, SANTA MARIA, SANTA MONICA, SANTA YNEZ, SIERRA MADRE, SIMI, STANTON, SUNLAND, SURF, TEHACHAPI, UPPER SESPE MOUNTAINS, VALYERMO, WHEELER RIDGE, AND WHITTIER. 07/01/1941 07-57--? 34.33 119.58 B 3.0 07/01/1941 07-58--? 34.33 119.58 B 3.5 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 20 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 07/01/1941 08-05--? 34.33 119.58 B 3.0 07/01/1941 08-07--? 34.33 119.58 B 3.0 07/01/1941 08-10--? 34.33 119.58 B 3.0 07/01/1941 08-13--? 34.33 119.58 B 3.0 07/01/1941 08-15--? 34.33 119.58 B 3.0 07/01/1941 08-19--? 34.33 119.58 B 4.0 F AFTERSHOCK OF 07-50-57 (THIS DATE). 07/01/1941 08-21--? 34.33 119.58 B 4.0 F AFTERSHOCK OF 07-50-57. 07/01/1941 08-25--? 34.33 119.58 B 3.5 07/01/1941 08-30--? 34.33 119.58 B 4.0 F AFTERSHOCK OF 07-50-57. MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 07/01/1941 08-48--? 34.33 119.58 B 4.0 F AFTERSHOCK OF 07-50-57. 07/01/1941 08-58--? 34.33 119.58 B 4.0 F AFTERSHOCK OF 07-50-57. 07/01/1941 09-05--? 34.33 119.58 B 4.0 F AFTERSHOCK OF 07-50-57. 07/01/1941 09-45--? 34.33 119.58 B 4.0 F AFTERSHOCK OF 07-50-57. 07/01/1941 10-25--? 34.33 119.58 B 4.0 F AFTERSHOCK OF 07-50-57. 07/01/1941 12-37--? 34.33 119.58 B 3.0 07/01/1941 14-22--? 34.33 119.58 B 3.0 07/01/1941 18-13--? 34.33 119.58 B 3.0 07/01/1941 18-20--? 34.33 119.58 B 4.0 F AFTERSHOCK OF 07-50-57. 07/01/1941 19-48--? 34.33 119.58 B 3.0 07/01/1941 20-15--? 34.33 119.58 B 3.5 07/01/1941 22-51--? 34.33 119.58 B 3.5 07/01/1941 23-54--? 34.33 119.58 B 4.5 F AFTERSHOCK OF 07-50-57; FELT AT FILLMORE, GAVIOTA, LOS ALAMOS, AND SANTA BARBARA. 07/02/1941 -?-17--? 34.33 119.58 B 3.0 07/02/1941 04-33--? 34.33 119.58 B 3.5 07/02/1941 08-45--? 34.33 119.58 B 3.5 07/02/1941 11-41--? 34.33 119.58 B 3.0 07/02/1941 22-19--? 34.33 119.58 B 4.0 F AFTERSHOCK OF 07-50-57. 07/03/1941 -?-25--? 34.33 119.58 B 3.5 07/03/1941 19-26--? 34.33 119.58 B 4.0 F AFTERSHOCK OF 07-50-57. 07/07/1941 01-06--? 34.33 119.58 B 3.0 07/07/1941 06-25--? 34.33 119.58 B 3.5 07/08/1941 19-37--? 34.33 119.58 B 3.0 07/12/1941 16-18--? 34.33 119.58 B 4.5 F AFTERSHOCK OF 07-50-57; FELT AT FILLMORE, GLENDALE, MONTROSE, SATICOY, SAUGUS, AND WHEELER SPRINGS. 07/12/1941 16-41--? 34.33 119.58 B 3.0 07/12/1941 21-07--? 34.33 119.58 B 3.0 07/12/1941 21-12--? 34.33 119.58 B 3.0 07/13/1941 06-11--? 34.33 119.58 B 3.5 07/16/1941 23-10--? 34.33 119.58 B 3.0 07/17/1941 18-31--? 34.33 119.58 B 3.0 07/27/1941 12-44--? 34.33 119.58 B 3.0 07/31/1941 13-23--? 34.33 119.58 B 3.0 08/02/1941 12-31-19 34.33 119.58 C 3.0 08/09/1941 05-05-24 34.33 119.58 C 3.5 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 21 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 08/12/1941 22-35-24 34.33 119.58 C 3.5 08/19/1941 10-20-25 34.33 119.58 C 3.0 08/25/1941 06-58-22 34.33 119.58 C 3.0 08/27/1941 17-11-02 34.33 119.58 C 3.0 08/29/1941 08-43-24 34.60 120.30 C 3.0 09/08/1941 03-12-45 34.33 119.58 B 4.5 F AFTERSHOCK OF 07/01/41, 07-50-57. V AT GOLETA AND SANTA BARBARA; FELT STRONGLY AT LOS ALAMOS AND SUMMERLAND. 09/08/1941 03-14-23 34.33 119.58 B 4.0 F TWIN SHOCK OF 03-12-45; SAME "FELT" REPORT. 09/08/1941 04-45-16 34.33 119.58 B 3.5 F SANTA BARBARA. 09/09/1941 03-23-17 34.33 119.58 B 3.5 F SANTA BARBARA. 09/09/1941 13-44-46 34.33 119.58 B 3.0 09/14/1941 01-45-18 34.33 119.58 B 4.0 F AFTERSHOCK OF 07/01/41, 07-50-57. 09/14/1941 02-20-42 34.33 119.58 B 3.0 09/15/1941 01-37-02 34.33 119.58 B 4.0 F GOLETA, SANTA BARBARA, AND SUMMERLAND. 09/15/1941 01-55-18 34.33 119.58 B 3.0 09/15/1941 02-49-06 34.33 119.58 B 3.5 09/16/1941 07-27--? 34.33 119.58 B 3.5 09/25/1941 05-12-56 34.33 119.58 B 4.0 F GOLETA AND SANTA BARBARA. 10/07/1941 12-05-42 34.33 119.58 3.0 10/19/1941 23-22-19 34.33 119.58 B 3.0 11/05/1941 16-36--? 35.00 121.00 D 3.5 F OFF POINT CONCEPTION; FELT AT SAN SIMEON. 11/17/1941 17-30-27 34.33 119.58 C 3.0 11/18/1941 18-08-10 34.33 119.58 C 4.0 F CARPINTERIA AND SANTA BARBARA. 11/21/1941 16-56-03 34.33 119.58 C 4.0 F GOLETA AND SANTA BARBARA. 11/25/1941 20-01-48 34.33 119.58 C 3.0 11/28/1941 06-33--? 35.00 120.00 D 3.5 12/08/1941 -?-29-42 36.00 121.00 D 3.5 12/22/1941 -?-54-09 35.93 120.48 C 4.0 F NEAR PARKFIELD-NOT RECORDED ON BERKELEY NETWORK. 01/06/1942 09-20--? 36.15 120.65 D F PRIEST VALLEY-RECORDED AT TINEMAHA. 01/06/1942 09-23--? 36.15 120.65 D F PRIEST VALLEY-RECORDED AT TINEMAHA. 01/08/1942 18-21-05 34.13 119.58 C 2.5 01/18/1942 11-35--? 36.40 121.25 D F PINNACLES. 01/18/1942 16-50--? 36.40 121.25 D F PINNACLES. 02/19/1942 18-33--? 36.40 121.25 D F PINNACLES. 03/09/1942 05-57-42 34.30 119.60 3.0 03/25/1942 -?--?--? 36.40 121.25 D F PINNACLES; LIGHT SHOCK. 04/19/1942 04-02-47 34.30 119.60 D 3.0 04/22/1942 05-32-52 35.30 119.50 D 3.0 05/08/1942 17-19-13 34.33 119.58 C 3.0 06/06/1942 06-42-11 34.35 119.85 C 3.0 F GOLETA. 06/29/1942 21-07-30 35.60 120.80 D 4.0 F IV AT CAMBRIA AND SAN LUIS OBISPO. 07/19/1942 10-42-07 36.40 121.10 D 1.6 SW OF LLANADA. 09/15/1942 10-36-33 36.13 122.18 B 3.0 SW OF KING CITY. 10/04/1942 10--?--? 34.60 120.00 D F IV AT SANTA YNEZ PEAK. 10/11/1942 23-48-23 36.48 121.40 C 1.9 FORESHOCK OF QUAKE ON OCTOBER 15 AT 13-53-56. 10/15/1942 13-53-56 36.48 121.40 B 4.3 F IV AT BIG SUR, GONZALES, GREENFIELD, HOLLISTER, SALINAS, AND SOLEDAD. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 22 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 10/18/1942 08--?--? 36.00 121.00 D F CAMBRIA. 10/18/1942 12-01-42 36.00 121.00 D F V AT CAMBRIA. 10/19/1942 10-23--? 34.50 119.65 D F V AT SANTA BARBARA. 10/20/1942 10-25--? 36.00 121.00 D F V AT CAMBRIA. 10/26/1942 01-09-01 36.40 121.60 D 1.8 DEPTH ABOUT 12 KM. 12/02/1942 11-46--? 34.33 119.58 C 3.5 F V AT SANTA BARBARA. 12/06/1942 16-57-49 35.93 120.48 C 3.5 01/24/1943 06-55-57 34.33 119.58 C 3.0 03/16/1943 09-27-47 34.28 119.60 C 3.0 04/01/1943 13-39-66 34.68 121.75 B 3.1 OFF COAST, WEST OF POINT ARGUELLO. 06/29/1943 02-50-53 36.50 121.10 D 3.1 SW OF LLANADA. 07/05/1943 16-30-29 36.38 121.83 C 3.9 SOUTH OF SALINAS. 07/15/1943 -?-44-42 36.00 120.15 D F NEAR AVENAL. 08/07/1943 16-59-47 34.28 119.57 C 3.5 08/12/1943 15-56-33 34.75 121.15 C 3.5 08/27/1943 08-16-53 34.43 119.87 C 3.5 F IV AT SANTA BARBARA. 09/13/1943 12-40--? 35.65 120.65 D F PASO ROBLES, POSSIBLY GUN FIRE. 09/18/1943 17-07-16 34.37 119.58 C 3.0 10/22/1943 12--?--? 36.00 120.90 D F SAN ARDO; 2 SHOCKS. 10/26/1943 22-10--? 34.75 120.25 D F LOS ALAMOS. 10/31/1943 17-54-06 35.80 120.40 D 3.5 10/31/1943 20--?--? 36.40 121.00 D F LONOAK. 11/08/1943 11-33-46 36.00 119.92 C 3.0 F KETTLEMAN HILLS; FELT AT AVENAL. 11/30/1943 21-57-18 36.30 120.50 D 4.0 NEAR COALINGA. 12/01/1943 04-51--? 36.50 121.10 D F SAN BENITO. 01/04/1944 18-06-40 34.10 120.40 D 3.3 02/18/1944 16-29-37 34.10 119.52 C 2.1 02/21/1944 13--?-11 36.17 120.93 C 3.8 WEST OF PRIEST. 03/06/1944 21-32-16 36.40 121.25 C 3.4 NE OF PARAISO. 04/03/1944 02-33--? 34.50 121.40 D 4.0 OFF POINT ARGUELLO. 04/12/1944 15-33-10 34.27 119.52 C 4.0 F OFF CARPINTERIA; FELT EAST OF SANTA BARBARA. 06/13/1944 08-27-32 34.67 120.50 C 4.6 F NEAR LOMPOC; VI AT LOS ALAMOS AND IV AT SANTA MARIA. 06/13/1944 08-46-43 34.67 120.50 C 4.0 F AFTERSHOCK OF 08-27-32. 06/13/1944 11-07-24 34.67 120.50 C 4.4 F AFTERSHOCK OF 08-27-32. 07/11/1944 22-33--? 36.50 121.10 D F SAN BENITO. 07/15/1944 19-22-37 34.37 119.62 C 3.1 09/04/1944 02-47-46 35.00 120.00 D 3.4 F LOS ALAMOS. 09/04/1944 05--?--? 35.00 120.00 D F LOS ALAMOS. 09/15/1944 14-12-42 34.70 120.20 D 2.6 F KETTLEMAN HILLS REGION; FELT AT PARKFIELD. 09/18/1944 01-30--? 35.00 120.00 D 3.5 11/04/1944 08-12-01 36.33 120.08 C 3.4 11/08/1944 16-12-36 34.33 119.72 C 3.1 11/28/1944 10-36--? 35.80 120.00 D 3.3 11/30/1944 18-53-15 34.72 120.42 C 4.1 F NEAR LOS ALAMOS; FELT AT LOS ALAMOS AND LOS OLIVOS. 12/02/1944 15-09-12 35.80 120.00 D 3.2 01/27/1945 17-50-31 34.75 120.67 C 3.9 02/25/1945 20-18-38 36.00 120.48 C 3.6 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 23 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 04/15/1945 22-59-57 34.13 119.83 C 3.1 06/11/1945 03-54-52 34.50 120.80 D 3.2 07/11/1945 16-13--? 35.67 121.25 D 4.0 F NEAR SAN SIMEON; IV AT CAMBRIA. 07/28/1945 02-33-48 34.70 120.10 D 4.2 F EAST OF SANTA MARIA; IV AT LOS ALAMOS. 09/04/1945 12-38-31 34.32 119.63 C 3.2 09/07/1945 11-34-20 35.83 120.75 C 4.2 F NEAR BRADLEY; IV AT CAMBRIA, PARKFIELD, PASO ROBLES, AND SAN MIGUEL. 11/04/1945 -?-46-34 36.38 121.28 C 3.3 NEAR SOLEDAD. 02/09/1946 02-55-28 34.33 119.92 C 2.5 02/10/1946 11-01-19 36.50 121.00 D 4.2 F OVER AN AREA OF 2000 SQ. MI. IN WEST CENTRAL CALIFORNIA. V AT SAN BENITO, AND IV AT BIG SUR, CHUALAR, GREENFIELD, HOLLISTER, LONOAK, SAN LUCAS, SAN MIGUEL, SANTA CRUZ, AND SOLEDAD. 02/15/1946 12-07-00 35.90 121.45 D F PARKFIELD; LIGHT SHOCK. 04/19/1946 12-50--? 34.00 120.40 D F SANTA MARIA. 07/08/1946 19-59-44 34.83 120.53 C 3.2 08/06/1946 04-55-07 34.95 120.18 C 2.8 F E OF SANTA MARIA; FELT AT LOS ALAMOS. 09/02/1946 10-09-47 34.18 119.62 C 3.0 09/09/1946 11-20--? 34.90 120.40 D F SANTA MARIA. 09/19/1946 06-35-44 35.83 119.67 C 3.2 10/24/1946 18-26-50 34.37 119.62 C 2.7 11/22/1946 09-47-59 34.83 120.68 D 3.0 11/27/1946 14-44-51 35.50 120.92 C 4.3 F NEAR CAYUCOS; V AT MORRO BAY AND SANTA MARGARITA; ALSO FELT ATASCADERO, LOS ALAMOS, PISMO BEACH, AND SAN LUIS OBISPO. 12/13/1946 -?-40-01 34.17 119.53 C 3.5 01/06/1947 21-05-47 35.85 120.47 C 3.6 01/13/1947 19-38-31 34.32 119.65 C 2.2 01/14/1947 20-49-27 34.23 119.65 C 2.7 01/18/1947 12--?-42 34.20 121.50 D 3.3 01/19/1947 19-32--? 35.60 120.30 D 3.1 F PASO ROBLES. 02/05/1947 06-14--? 38.23 120.65 B 5.0 F VI AT LONOAK, V AT COALINGA, IDRIA, AND KING CITY, AND IV AT BIG SUR, HURON, PARKFIELD, SAN ARDO, AND WESTHAVEN.NEAR COALINGA - AFTERSHOCK OF 2/5/47 OF 06-14--?. 02/25/1947 11-45-18 36.20 120.50 D 4.2 03/23/1947 16-04-51 35.15 121.30 D 3.7 03/27/1947 09-16-46 35.00 121.00 D 4.2 F OFF COAST; V AT LOMPOC. 04/29/1947 07-44--? 34.33 119.55 C 3.2 06/25/1947 18-39-53 34.25 119.50 C 3.1 F NEAR CARPINTERIA. 06/25/1947 13-41-21 34.25 119.50 C 3.6 F NEAR CARPINTERIA. 06/25/1947 18-48-26 34.25 119.50 C 2.5 06/25/1947 20-55-16 34.25 119.50 C 3.2 F NEAR CARPINTERIA. 06/25/1947 20-55-54 34.25 119.50 C 3.8 07/13/1947 05-35--? 36.08 121.10 D 3.4 SOUTH OF KING CITY. 07/14/1947 05-40-06 35.92 119.92 C 4.0 F KETTLEMAN HILLS; IV AT KETTLEMAN CITY. 10/6/1947 18-39--? 36.50 121.23 A 3.2 EAST OF GONZALES. 12/14/1947 05-42--? 36.45 121.08 B 3.4 SW OF LLANADA. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 24 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 12/16/1947 09-21-03 36.25 120.77 C 3.6 F IV AT SAN LUCAS. 12/18/1947 19-30-06 36.12 120.90 D F IV AT PARKFIELD. 12/25/1947 06-05--? 35.60 121.10 D F CAMBRIA. 12/25/1947 06-20--? 35.60 121.10 D F CAMBRIA. 01/11/1948 05-37-28 36.43 121.48 B 4.3 F IV AT HOLLISTER. 02/01/1948 17--?-54 34.42 119.92 C 3.0 02/15/1948 08-04-06 35.88 120.37 A 3.4 EAST OF PARKFIELD. 03/07/1948 07-46-22 36.10 120.40 D 3.0 NEAR COALINGA. 03/10/1948 23-24-34 34.43 119.73 C 2.6 03/18/1948 09-35-05 34.40 119.60 C 2.8 03/29/1948 02-40--? 35.85 121.40 D F IV AT HOLLISTER. 04/23/1948 15-23-43 34.10 120.93 C 3.7 05/05/1948 06-47-06 34.45 119.72 B 2.7 05/07/1948 12--?-32 36.20 121.90 D 3.0 WEST OF PRIEST. 05/09/1948 11-10--? 34.75 120.25 D F V AT LOS ALAMOS. 07/14/1948 11-05-37 34.67 120.92 C 3.2 07/17/1948 05-26-31 34.55 120.05 C 3.4 07/28/1948 01-30-57 36.05 120.53 C 3.1 SE OF PRIEST. 07/29/1948 13-16-23 35.12 120.47 C 3.4 08/04/1948 10-22-57 35.92 120.33 C 3.6 09/03/1948 23-42-26 34.33 119.53 C 3.9 F SANTA BARBARA. 09/17/1948 15-41-01 34.40 119.62 C 3.1 10/27/1948 03-05--? 34.75 120.25 D F IV AT LOS ALAMOS. 10/29/1948 03-04-59 34.10 120.40 D 3.4 F V AT ARLIGHT AND POINT ARGUELLO LIGHT STATION. 11/02/1948 19-06-45 34.37 119.58 C 2.9 12/04/1948 06-44-20 34.43 119.72 C 2.8 12/04/1948 23-32-51 34.42 119.50 C 2.7 12/20/1948 04-42-46 35.80 121.50 C 4.5 F OFF COAST, NEAR PIEDRAS BLANCAS POINT; III AT SAN SIMEON. 12/31/1948 14-35-46 35.67 121.40 B 4.6 F ALONG THE COAST FROM LOMPOC TO MOSS LANDING; VI AT SAN SIMEON AND V AT CAYUCOS, CRESTON, MOSS LANDING, AND PIEDRAS BLANCAS LIGHT STATION. 01/25/1949 04-29--? 34.90 120.40 D F V AT ORCUTT AND SANTA MARIA. 03/27/1949 06-31-16 34.25 119.62 C 2.6 04/06/1949 14-07--? 35.00 120.00 2.6 04/08/1949 13-17-07 34.60 120.35 C 3.2 F IV AT LOS ALAMOS. 04/14/1949 01-46-12 34.28 119.52 C 2.6 04/23/1949 09-18-09 36.38 121.37 C 3.7 NORTH OF PARAISO. 05/06/1949 04-23-46 34.50 121.00 C 3.4 05/10/1949 06-20--? 35.90 120.40 D F SANTA MARIA - SLIGHT. 05/10/1949 11--?--? 35.90 120.40 D F SANTA MARIA - SLIGHT. 05/16/1949 03-01-03 34.72 120.02 C 3.2 05/17/1949 23-57-55 35.63 121.15 D 4.1 F IV AT SAN SIMEON. 06/27/1949 10-35-31 35.80 121.10 D 4.5 F V AT SAN ARDO AND SAN MIGUEL; ALSO FELT AT PASO ROBLES, SAN LUIS OBISPO, AND SANTA MARGARITA. 07/21/1949 16-50--? 36.15 120.35 D F IV AT COALINGA. 07/21/1949 17-01--? 36.15 120.35 D F IV AT COALINGA. 07/24/1949 03-04-05 36.00 120.00 D 2.3 SE. KINGS C0. AFTER SHOCK AT 06-26--?, MAG. 2.0. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 25 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 07/27/1949 18-21-35 34.53 120.37 C 3.6 08/01/1949 -?-07-24 36.90 121.20 D 3.0 SOUTH OF KING CITY. 08/07/1949 01-38-43 36.50 121.50 D 2.3 NO. MONTEREY CO. 08/10/1949 09-17-39 36.50 121.00 C 2.6 CENTRAL SAN BENITO CO. 08/22/1949 03--?--? 36.00 120.00 D F KETTLEMAN HILLS. FIFTH SHOCK IN 2 WEEKS. 08/26/1949 16-52-32 34.50 120.50 D 4.2 F NEAR POINT CONCEPTION. VI AT ARLIGHT AND SURF. IV AT GUADALUPE, LOMPOC, AND LOS ALAMOS. 08/27/1949 14-15--? 34.50 120.50 D F ARLIGHT. SLIGHT SHOCK. 08/27/1949 14-51-46 34.50 120.50 D 4.9 F NEAR POINT CONCEPTION. VI AT ARLIGHT, LOMPOC, AND SUDDEN. V AT COSMALIA, LOS ALAMOS, NIPOMO, SANTA BARBARA, AND SURF. 08/29/1949 12-07-20 36.00 120.10 D 3.0 F IV IN AVENAL AND KETTLEMAN CITY. 10/28/1949 08-07-02 36.80 120.90 C 2.6 NW OF PRIEST. 11/17/1949 05-06-06 34.80 120.70 D 2.8 F IV AT SANTA MARIA. 12/28/1949 09-17-12 36.20 120.70 D 2.6 NEAR PRIEST. 02/19/1950 08-29-44 34.50 120.70 D 3.5 03/09/1950 23-43-19 36.35 121.22 C 3.2 F NORTH OF KING CITY; V AT ROBLES DEL RIO. 03/22/1950 01-31-57 35.97 120.63 C 3.7 03/29/1950 12-43-20 35.97 120.88 D 3.5 04/15/1950 11-56-32 35.75 119.62 C 4.6 F NE OF LOST HILLS; V AT ASH MOUNTAIN, (SEQUOIA NATIONAL PARK), KERNVILLE, AND SHAFTER, AND IV AT BUTTONWILLOW, JAWBONE AQUEDUCT STATION, LOST HILLS, THREE RIVERS, AND VISALIA. 04/21/1950 13-17-29 34.38 119.58 B 3.0 F IV AT SANTA BARBARA. 04/26/1950 07-23-29 35.20 120.60 C 3.5 F V AT SANTA MARIA; ALSO FELT AT ORCUTT. 04/26/1950 07-38--? 35.20 120.60 D F SANTA MARIA. 05/21/1950 18-59-03 34.57 119.63 C 2.6 05/21/1950 19-26-48 35.88 119.73 C 3.4 05/24/1950 01-46-57 36.43 120.77 C 2.9 SE OF LLANADA. 07/13/1950 15-01-47 34.33 119.50 C 2.8 F OFF CARPINTERIA; V AT MONTECITO; ALSO FELT AT SANTA BARBARA AND NEARBY AREAS. 08/01/1950 21-08-43 36.20 122.23 B 2.0 OFF COAST, WEST OF BIG SUR. 08/02/1950 06-50-48 34.67 120.63 C 3.3 08/23/1950 09-10--? 34.40 119.50 D F IV AT RINCON POINT; FELT AT CARPINTERIA. 09/24/1950 04-45--? 34.50 120.50 D F III AT ARLIGHT. 09/24/1950 12-23--? 34.22 119.58 C 3.3 09/24/1950 21-51-44 36.20 120.50 D 2.9 EAST OF PRIEST. 10/20/1950 08-23-25 36.33 121.07 C 2.7 SOUTH OF KING CITY. 11/21/1950 04-30--? 30.90 120.40 D F SANTA MARIA. 03/02/1951 02-13-44 36.10 120.60 D 3.1 SE OF PRIEST 03/04/1951 13-32--? 34.90 120.40 D F IV AT SANTA MARIA; 2 SHOCKS. 03/05/1951 09-50--? 34.90 120.40 D F IV AT SANTA MARIA. 03/10/1951 05-35--? 34.50 120.50 D F IV AT ARLIGHT. 03/15/1951 13-50-43 35.02 120.48 C 3.8 F IV AT LOS ALAMOS. 03/26/1951 06-07-34 34.62 119.50 C 3.5 F IV AT OJAI AND SUMMERLAND; FELT AT VENTURA. 05/04/1951 03-28-36 36.20 120.20 D 3.1 FORESHOCK OF QUAKE AT 20-08-10. 05/04/1951 20-08-10 36.20 120.20 D 3.2 EAST OF COALINGA. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 26 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 05/06/1951 03-18-03 36.40 120.40 D 2.8 NORTH OF COALINGA. 05/25/1951 05-11-18 36.30 120.30 D 3.1 NORTH OF COALINGA. 05/29/1951 05-08-24 35.08 119.65 C 3.2 F ELKHORN HILLS; IV IN CUYAMA VALLEY. 05/31/1951 06-28-42 36.30 120.20 D 2.7 NE OF COALINGA. 06/16/1951 19-01-17 34.40 120.08 C 3.3 06/19/1951 06-13-47 35.97 120.42 C 3.6 SOUTH OF COALINGA. 07/01/1951 -?-13-19 36.20 120.95 B 3.2 EAST OF KING CITY. 07/07/1951 05-53-33 34.75 120.75 C 3.5 08/02/1951 05-09-25 36.35 121.27 B 3.9 F NEAR GREENFIELD; IV AT BIG SUR, AT 7 MI. S OF HOLLISTER, AND ROBLES DEL RIO. 08/08/1951 19-42--? 34.80 120.40 D F IV AT ORCUTT. 08/09/1951 09-20-48 36.15 121.75 C 2.2 NEAR BIG SUR. 08/25/1951 01-04-10 36.47 121.15 B 3.1 SW OF LLANADA. 08/28/1951 22-12-27 34.60 121.00 D 3.5 F OFF POINT ARGUELLO; III AT LOS ALAMOS. 09/18/1951 02-30--? 36.25 121.80 D F IV AT BIG SUR. 09/19/1951 22-50--? 36.25 121.80 D F IV AT BIG SUR. 10/03/1951 13-44-33 35.92 120.52 C 3.8 10/26/1951 16-25-40 34.42 119.73 C 3.0 11/17/1951 03-19-48 34.70 120.50 D 2.5 F NEAR LOMPOC; III AT LOS ALAMOS. 11/25/1951 23-15-39 35.33 119.50 B 3.8 12/20/1951 04-13-06 36.00 120.05 C 3.7 01/24/1952 -?-32-38 34.18 119.88 C 2.7 01/30/1952 11-05-33 36.30 121.13 C 2.7 NEAR KING CITY. 01/31/1952 20-09-02 34.18 119.53 C 2.6 01/31/1952 21-33-12 36.40 121.40 C 3.6 SOUTHEAST CF SOLEDAD. 02/09/1952 22-26-39 34.07 120.75 C 3.6 03/25/1952 09-18-50 34.18 120.95 C 3.6 04/02/1952 05-21-10 36.45 121.25 B 3.1 NEAR SOLEDAD. 05/07/1952 05-45--? 34.40 119.60 D F IV AT MONTECITO AND SUMMERLAND. 06/18/1952 04--?--? 34.60 120.65 D F IV AT POINT ARGUELLO LIFEBOAT STATION. 07/01/1952 15-29-24 34.30 119.80 D 3.1 07/15/1952 06-07-55 36.42 121.00 C 2.5 ABOUT 15 MI. NE OF KING CITY. 07/27/1952 18-15-14 34.18 119.70 C 3.1 07/27/1952 20-20-35 34.22 119.67 C 3.2 07/27/1952 20-30-05 34.20 119.67 B 3.5 08/07/1952 19-l6-12 34.33 120.68 C 3.6 F OFF POINT CONCEPTION; IV AT LOS ALAMOS. 08/11/1952 21-42-29 34.17 119.67 C 3.1 08/23/1952 20-10--? 34.85 119.50 D F IV AT VENTUCOPA - SECOND SHOCK AT 21-20--?. 08/30/1952 14-58-11 34.35 119.62 B 3.3 09/01/1952 12-03--? 34.30 119.60 D 3.0 09/12/1952 21--?-15 34.25 119.70 C 3.0 09/14/1952 11-46-06 35.90 120.30 D 3.3 10/09/1952 14-46-02 34.20 122.20 D 4.6 (DEPT. OF WATER RESOURCES DATA) DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 27 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 11/22/1952 07-46-37 35.73 121.20 B 6.0 F 6 MI. NORTH OF SAN SIMEON, NEAR BRYSON; FELT OVER AN AREA OF 20,000 SQ. MI. VII AT BRADLEY AND BRYSON, VI AT ARROYO GRANDE, ATASCADERO, CAMBRIA, CAMP COOKE, CARMEL VALLEY, CAYUCOS, CHUALAR, CRESTON, GORDA STATION, GUADALUPE, HARMONY, HEARST RANCH, KING CITY, LOCKWOOD, LONOAK, MORRO BAY, OCEANO, PARKFIELD, PASO ROBLES, PISMO BEACH, SALINAS, SAN ARDO, SAN LUIS OBISPO, SAN SIMEON, SANTA MARGARITA, AND TEMPLETON, AND V AT AVENAL, BEN LOMOND, BIG SUR, BUELLTON, BUTTONWILLOW, CARUTHERS, CASMALIA, CHOLAME, COALINGA, CORCORAN, DOS PALOS, HOLLISTER, HUASNA, KETTLEMAN CITY, LOMPOC, LOST HILLS, LUCIA, MARICOPA, MONTEREY, MOSS LANDING, NIPOMO, ORCUTT, PAICINES, RIVERDALE, SAN MIGUEL, SANTA CRUZ, SANTA MARIA, SHAFTER, STRATFORD, SUDDEN, AND SURF. 11/22/1952 08-02-40 35.73 121.20 B 3.2 SAN SIMEON AFTERSHOCK. 11/22/1952 08-29-47 35.73 121.20 B 3.1 SAN SIMEON AFTERSHOCK. 11/22/1952 08-53-04 35.73 121.20 B 3.4 F SAN SIMEON AFTERSHOCK; IV AT ARVIN, CALIENTE, JOLON, LOST HILLS, MALIBU, MARICOPA, MCFARLAND, MIRACLE HOT SPRINGS, MORGAN HILL, NIPOMO, PISMO BEACH, AND SHAFTER. 11/22/1952 11-08-44 35.73 121.20 B 3.1 SAN SIMEON AFTERSHOCK. 11/22/1952 11-45-31 35.73 121.20 B 3.1 SAN SIMEON AFTERSHOCK. 11/22/1952 12-34-44 35.73 121.20 B 3.0 SAN SIMEON AFTERSHOCK. 11/22/1952 13-37-31 35.73 121.20 B 4.0 F SAN SIMEON AFTERSHOCK; V AT CALIENTE, MIRACLE HOT SPRINGS, AND WHEELER SPRINGS. 11/22/1952 19-25-21 35.73 121.20 B 3.9 SAN SIMEON AFTERSHOCK. 11/22/1952 19-36-27 35.70 121.20 D 3.1 SAN SIMEON AFTERSHOCK. 11/22/1952 23-39-20 35.70 121.20 D 3.1 SAN SIMEON AFTERSHOCK. 11/23/1952 09-22-35 36.00 120.90 D 3.2 20 MI. SE OF KING CITY. 11/23/1952 18-40-19 35.67 121.17 C 4.2 SAN SIMEON AFTERSHOCK. 11/25/1952 19-17-54 36.20 120.00 D 3.2 11/25/1952 20-14-45 35.73 121.20 C 3.6 SAN SIMEON AFTERSHOCK. 11/25/1952 21-59-17 35.73 121.20 C 4.4 SAN SIMEON AFTERSHOCK. 11/26/1952 13-32-09 35.73 121.20 C 3.5 SAN SIMEON AFTERSHOCK. 11/27/1952 17-37-05 35.70 121.20 D 3.3 SAN SIMEON AFTERSHOCK. 11/28/1952 10-22-33 35.90 121.20 D 3.0 SAN SIMEON AFTERSHOCK. 11/29/1952 16--?--? 36.00 121.15 D F IV AT JOLON - TIME MAY BE 04--?--? ON 11/30/1952. 11/29/1952 23-15-58 35.70 121.20 D 3.5 SAN SIMEON AFTERSHOCK. 12/05/1952 01-05-57 36.50 120.70 D 3.0 14 MI. SE OF LLANADA. 12/06/1952 23-50--? 35.66 120.65 D F IV AT PASO ROBLES; FELT AT ADELAIDA. 12/12/1952 -?-27-07 36.40 120.97 B 3.0 F 17 MI. NE OF KING CITY; III AT LONOAK. 12/25/1952 16-44-10 34.40 121.40 D 3.6 01/12/1953 13-05-18 35.80 121.10 D 3.2 14 MI. NE OF SAN SIMEON. 01/24/1953 -?--?--? 35.90 121.00 D F TEN SHOCKS REPORTED FELT FROM 1/24 TO 1/31 AT BRYSON (E. WEFERLING RANCH). 01/29/1953 20-31-19 35.80 121.10 D 3.1 14 MI. NE OF SAN SIMEON. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 28 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 02/03/1953 14-50-18 35.47 120.75 C 4.1 F 12 MI. NNW OF SAN LUIS OBISPO; V AT ATASCADERO, BRYSON, CRESTON, MORRO BAY, SANTA MARGARITA, AND IV AT CAYUCOS, PASO ROBLES, SAN LUIS OBISPO, AND TEMPLETON. 02/05/1953 02-54-12 35.90 121.00 D 2.8 F IV AT BRYSON (E. WEFERLING RANCH). 02/15/1953 15-30--? 35.90 121.00 D F BRYSON (E. WEFERLING RANCH). 02/17/1953 08-06--? 35.90 121.00 D F III AT BRYSON (PLEYTO SCHOOL) - SEVERAL MILD SHOCKS REPORTED FELT DAILY SINCE SHOCK OF 11/21/52, 23-46-38 (NOT LISTED). 02/18/1953 14-10--? 35.90 121.00 D F BRYSON (E. WEFERLING RANCH) - MILD. 03/01/1953 18-53--? 35.90 121.00 D F V AT BRYSON. 03/04/1953 03-40--? 35.90 121.00 D F BRYSON (PLEYTO SCHOOL) - LIGHT. 03/15/1953 21--?-32 34.87 121.53 C 3.7 03/18/1953 05-03--? 35.90 121.00 D F III AT BRYSON (PLEYTO SCHOOL). 03/29/1953 17-19-48 35.90 120.20 D 3.7 04/08/1953 -?-59-20 34.80 120.60 D 3.6 F NEAR CASMALIA; IV AT LOS ALAMOS. 04/15/1953 -?-29-10 35.83 121.07 C 3.1 F 14 MI. NNE OF SAN SIMEON; IV AT BRYSON. 04/15/1953 05-30--? 35.90 121.00 D F BRYSON - LIGHT. 04/29/1953 05-26-53 36.00 121.15 C 3.5 F 14 MI. S OF KING CITY - USCGS GIVES TIME AS 05-26-52, LOCATION AS N35.8 121.2W, REPORT AS NEAR BRYSON; V AT PLEYTO SCHOOL. 22 MI. NE OF KING CITY. 05/01/1953 22-16-51 36.40 120.80 D 3.0 05/08/1953 08-15--? 34.65 120.45 D F III AT LOMPOC. 05/14/1953 03-36--? 36.00 120.00 D 3.3 05/14/1953 09-36-09 35.75 121.08 B 3.7 F 9 MI. NE OF SAN SIMEON - USCGS GIVES N35.52 121.28W, OFF CAMBRIA; V AT BRYSON. 05/15/1983 07-15--? 35.90 121.00 D F IV AT BRYSON (PLEYTO SCHOOL). 05/28/1953 03-51-13 35.88 120.50 B 4.3 F 20 MI. SW OF COALINGA; IV AT PASO ROBLES AND III AT SAN MIGUEL. 05/28/1953 07-58-33 35.88 120.50 C 3.5 F AFTERSHOCK OF 03-51-13; FELT AT SAN MIGUEL. 05/29/1953 10-20-16 35.90 121.20 D 2.9 20 MI. SOUTH OF KING CITY. 05/31/1953 23-51-17 36.10 120.40 D 3.2 NEAR COALINGA. 06/04/1953 11-40--? 35.50 120.50 D F V AT CRESTON - PROBABLY A BLAST. 06/06/1953 20-26-33 36.00 120.30 D 2.9 10 MI. SOUTH OF COALINGA. 06/19/1953 11-24-50 36.30 120.70 D 2.8 20 MI. EAST OF KING CITY. 06/22/1953 15-22-35 35.93 120.38 C 4.3 F 15 MI. WSW OF COALINGA; FELT AT COALINGA AND PASO ROBLES. 07/01/1953 22-17-20 34.60 121.35 D 3.2 F OFF POINT ARGUELLO; IV AT POINT ARGUELLO LIGHT STATION. 08/14/1953 01-40-06 36.30 120.30 D 2.9 8 MI. NORTH OF COALINGA. 08/14/1953 09-22-50 36.50 121.20 D 2.3 20 MI. NORTH OF KING CITY. 09/02/1953 09-41-20 35.90 120.80 D 3.0 30 MI. SE OF KING CITY. 09/03/1953 11--?--? 35.50 120.50 D F CRESTON. 09/04/1953 03-54-25 35.90 120.32 C 3.5 F 15 MI. SOUTH OF COALINGA; IV AT CRESTON AND PASO ROBLES. 09/22/1953 07-36-58 36.40 121.20 D 3.8 NORTH OF KING CITY. 09/23/1953 06-21-51 35.70 121.10 D 3.5 F NEAR SAN SIMEON; V AT BRYSON. 10/01/1953 03-56-15 36.25 121.83 C 3.4 F 25 MI. S OF MONTEREY; IV AT BIG SUR. 10/16/1953 03-45-35 35.95 120.53 C 3.4 SOUTHWEST OF COALINGA. 10/21/1953 16-02-38 34.32 119.70 B 4.0 F OFF SANTA BARBARA; V AT SANTA BARBARA AND VICINTIY, AND IV AT GOLETA AND LOS PRIETOS RANGER STATION. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 29 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 10/24/1953 13-24-30 35.90 121.10 D 3.6 SOUTH OF KING CITY. 10/25/1953 08-43-25 36.50 121.50 D 3.2 NORTHWEST OF KING CITY. 11/02/1953 -?-52-06 36.40 121.30 D 3.4 NORTHWEST OF KING CITY. 01/04/1954 23-03-11 36.12 120.63 B 3.2 14 MI. WEST OF COALINGA. 01/05/1954 -?-23-23 35.93 120.00 C 3.0 SOUTHEAST OF COALINGA. 01/15/1954 22-02-18 36.50 121.23 C 2.6 NORTH OF KING CITY. 01/24/1954 19-06-45 35.78 121.08 C 3.1 30 MI. SOUTH OF KING CITY. 01/26/1954 09-43-22 34.50 120.33 C 3.8 F W OF LAS CRUCES; III AT SANTA YNEZ. 03/09/1954 19-55-30 35.90 120.50 D 3.6 F 16 MI. SSE OF COALINGA; FELT NEAR PARKFIELD. 03/15/1954 22-43-50 35.00 120.70 D 3.4 03/18/1954 12-07-53 35.40 120.90 D 3.0 NORTHWEST OF SAN LUIS OBISPO. 04/01/1954 12-04-38 36.05 120.20 C 3.3 6 MI. SOUTHEAST OF COALINGA. 04/09/1954 07-38-23 35.78 121.08 D 3.1 10 MI. NORTHEAST OF SAN SIMEON. 04/09/1954 14-58--? 35.90 121.00 D F IV AT BRYSON (PLEYTO SCHOOL); SECOND SHOCK REPORTED FELT AT 23-40--?. 04/20/1954 09-32-18 36.63 121.03 D 2.6 12 MI. NORTHEAST OF KING CITY. 05/10/1954 14-24-28 36.08 120.80 C 3.1 F NE OF SAN ARDO - SLIGHT AT KING CITY. 06/04/1954 11-58-38 36.45 121.13 C 3.5 16 MI. SOUTHWEST OF LLANADA. 07/05/1954 07-25-39 36.20 121.80 D 3.2 30 MI. SOUTH OF MONTEREY. 08/13/1954 13-36-44 34.25 120.50 C 3.2 08/13/1954 13-44-23 34.25 120.50 C 3.2 08/19/1954 11-45-08 34.25 120.50 C 3.2 08/21/1954 22-50-49 35.47 121.33 B 3.3 40 MI. SOUTH OF HOLLISTER. 08/22/1954 08-34-40 34.33 120.67 C 3.8 08/22/1954 12-36-07 34.33 120.67 C 3.8 12/22/1954 21-12-24 36.00 121.00 D 3.7 F SE OF KING CITY; III AT KING CITY. 12/22/1954 21-12-28 36.00 120.60 D 3.8 01/07/1955 14-50-22 34.40 119.60 D 3.0 01/18/1955 13-30--? 36.20 121.85 D F IV REPORTED FELT AT BIG SUR. 02/05/1955 07-10-19 35.80 121.40 C 3.3 WEST OF SAN SIMEON. 02/27/1955 03-17-51 36.25 120.83 C 2.9 F EAST OF KING CITY; IV IN PRIEST VALLEY. 03/02/1955 03-30--? 36.00 120.70 D F IV REPORTED FELT IN INDIAN VALLEY. 03/02/1955 15-59-01 36.00 120.93 B 4.8 F 18 MI. SE OF KING CITY; FELT OVER 7000 SQ. MI. OF W CENTRAL CALIF. USCGS MAG. 5.1. VI AT ADELAIDA, BRYSON, INDIAN VALLEY, SAN ARDO, SAN LUCAS, AND TEMPLETON. 03/02/1955 20-02-53 36.00 120.93 B 3.7 AFTERSHOCK OF QUAKE AT 15-59-01. 03/05/1955 08-46-36 36.10 121.10 D 2.0 SOUTH OF KING CITY. 03/06/1955 10-47-32 35.92 120.90 D 3.2 SOUTHEAST OF KING CITY. 04/04/1955 20-56-56 36.08 121.00 C 3.2 SOUTHEAST OF KING CITY. 04/27/1955 09-28-08 35.90 121.20 D 2.8 SOUTHWEST OF KING CITY. 05/14/1955 20--?--? 36.35 121.85 D F IV REPORTED FELT AT BIG SUR AND SANTA CRUZ. 05/16/1955 18-22-52 35.92 120.58 C 3.0 SOUTHWEST OF COALINGA. 05/30/1955 09-38-29 36.25 121.25 C 3.0 WEST OF KING CITY. 05/31/1955 01-45-53 36.40 121.25 B 3.0 NORTH OF KING CITY. 06/13/1955 14-55-12 36.30 121.30 C 2.5 NORTH OF KING CITY. 06/19/1955 05-36-33 35.62 121.10 C 2.5 SOUTHEAST OF SAN SIMEON. 07/06/1955 11-29-18 36.50 121.42 C 3.4 SOUTH OF HOLLISTER. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 30 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 07/06/1955 13-18-53 36.50 121.50 D 2.7 SOUTH OF HOLLISTER. 07/28/1955 12-07-52 36.50 121.40 D 2.6 SOUTH OF HOLLISTER. 09/21/1955 18-06-52 36.50 121.00 D 3.3 NORTH OF KING CITY. 10/22/1955 07-04-18 36.22 120.33 C 4.2 F V AT AND 14 MI. NW OF COALINGA. 11/02/1955 19-40-06 36.00 120.92 A 5.2 F 55 MI. NNW OF SAN LUIS OBISPO; FELT OVER 7000 SQ. MI. OF COASTAL W CENTRAL CALIF. VI AT ADELAIDA RD. (14 MI. W OF PASO ROBLES), BRYSON, KING CITY, PASO ROBLES, SAN ARDO, SAN LUCAS, AND SAN MIGUEL. 11/18/1955 09-03-30 35.90 120.50 D 2.9 SOUTHWEST OF COALINGA. 11/19/1955 07-20--? 34.50 119.65 D F REPORTED FELT AT SANTA BARBARA. 11/19/1955 10-59-41 36.03 120.90 C 3.3 SOUTHEAST OF KING CITY. 11/21/1955 21-14-18 36.10 119.90 D 3.5 12/11/1955 20-10-38 36.27 120.72 C 3.5 NORTHWEST OF COALINGA. 12/16/1955 14-43-11 36.03 120.87 C 3.8 F SOUTHWEST OF KING CITY; FELT AT ATASCADERO, PASO ROBLES, AND SAN MIGUEL. 12/29/1955 13-33-17 36.45 121.25 C 3.4 NORTH OF KING CITY. 02/14/1956 22-15-08 36.50 121.10 D 2.8 SOUTHWEST OF LLANADA. 03/15/1956 15-26-11 36.50 121.20 D 2.6 SOUTHEAST OF HOLLISTER. 04/03/1956 09-26-02 36.45 121.23 B 2.7 SOUTH OF HOLLISTER. 04/10/1956 11-24-21 36.43 121.48 C 2.9 SOUTHEAST OF MONTEREY. 04/10/1956 20-53-21 36.30 121.00 D 2.9 NORTHEAST OF KING CITY. 05/01/1956 15-06-33 36.50 121.00 D 2.5 SOUTH OF HOLLISTER. 05/04/1956 08-16-14 35.75 121.07 B 3.1 NORTHEAST OF SAN SIMEON. 05/04/1956 08-16-16 35.95 120.93 D 3.5 05/15/1956 10-45--? 34.90 120.40 D F REPORTED FELT AT SANTA MARIA. 06/11/1956 -?-48-37 36.00 120.97 C 3.2 SOUTHEAST OF KING CITY. 06/15/1956 23-42-03 36.30 121.80 D 2.8 SOUTH OF MONTEREY. 07/09/1956 23-15--? 35.10 120.50 D F III REPORTED FELT NEAR HUASNA. 07/23/1956 08-03-48 36.30 121.30 D 4.7 F NW OF KING CITY; FELT OVER 4000 SQ. MI. OF COASTAL CENTRAL CALIF. V AT BIG SUR, CHUALAR, GONZALES, GREENFIELD, 7.5 MI. S OF HOLLISTER, KING CITY, PASO ROBLES, SAN BENITO, AND SAN JUAN BAUTISTA. 07/23/1956 08-20-37 36.50 121.40 D 3.1 AFTERSHOCK OF QUAKE AT 08-03-48. 07/31/1956 -?-40-43 34.15 119.60 C 3.2 07/31/1956 17-25--? 35.10 120.50 D F IV REPORTED FELT AT HUASNA. 08/09/1956 -?-08-49 34.37 119.80 B 4.0 F OFF SANTA BARBARA; IV AT LOS PRIETOS RANGER STATION. 08/10/1956 23-24-03 35.90 121.30 D 3.0 SOUTHWEST OF KING CITY. 08/20/1956 05-10-33 36.48 121.48 B 3.2 F NEAR GONZALES; IV AT PINNACLES NATIONAL MONUMENT. 09/15/1956 -?-34-37 36.30 120.30 D 2.7 NORTH OF COALINGA. 10/10/1956 20-02-24 34.70 121.00 D 3.8 11/12/1956 10-13--? 36.30 120.10 C 3.3 11/16/1956 03-23-09 35.95 120.47 B 5.0 F SW OF COALINGA; FELT OVER 8000 SQ. MI. FROM HOLY CITY TO BETTERAVIA TO FIREBAUGH. VI AT KING CITY, MEE RANCH (LONOAK), AND SAN LUCAS. 11/19/1956 13-53-53 35.98 120.57 C 3.3 F SOUTHWEST OF COALINGA; III AT ADELAIDA (15 MI. WEST OF PASO ROBLES). 11/20/1956 03-42-44 34.70 120.50 C 3.6 F IV AT LOS ALAMOS; III FELT AT 07-42--?, 11/21/1956. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 31 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 12/11/1956 10-56-53 35.88 120.47 C 4.1 NEAR PARKFIELD. 12/28/1956 13-39-37 35.90 121.10 D 2.6 NORTHEAST OF SAN SIMEON. 01/01/1957 09-25--? 35.50 120.65 D F REPORTED FELT AT ATASCADERO. 01/29/1957 21-19-53 35.87 122.12 C 4.9 F OFF COAST NW OF SAN SIMEON; FELT OVER 5000 SQ. MI. OF COASTAL CENTRAL CALIF. V AT BIG SUR, CAMBRIA, CARMEL VALLEY, HARMONY, KING CITY, LUCIA, MARINA, AND SEASIDE, AND IV GENERALLY FROM MOSS LANDING TO 20 MI. W OF COALINGA TO SAN LUIS OBISPO. 02/03/1957 07-57-12 34.50 121.20 C 3.9 02/08/1957 04-45-38 36.50 121.20 D 2.8 NORTH OF KING CITY. 02/08/1957 21-20--? 36.50 122.00 D F SHARP SHOCK FELT MONTEREY PEN. (BSSA). 02/09/1957 08-10--? 35.50 120.65 D F IV REPORTED FELT AT ATASCADERO. 02/14/1957 -?-31-30 35.10 119.80 D 2.4 02/14/1957 10-30-27 36.00 120.60 C 3.6 02/16/1957 11-43-50 34.30 119.53 C 3.5 03/09/1957 14-38-28 34.70 119.60 C 2.9 03/09/1957 14-59-21 34.70 119.60 C 2.4 04/05/1957 -?-40--? 34.75 120.25 D F IV REPORTED FELT AT LOS ALAMOS. 06/21/1957 20-46-42 35.10 120.90 D 3.7 F OFF COAST; FELT AT SAN LUIS OBISPO AND MORRO BAY. 07/02/1957 09-18-22 34.37 119.88 B 3.4 F W OF SANTA BARBARA; FELT AT SANTA BARBARA. 07/02/1957 12-59-05 34.37 119.88 B 3.3 07/02/1957 13-58-28 34.37 119.88 B 3.2 07/21/1957 01-29-20 36.43 121.22 B 3.1 NORTH OF KING CITY. 08/03/1957 09-31-22 36.25 120.88 C 2.5 EAST OF KING CITY. 08/18/1957 03-05-25 34.47 120.13 C 3.4 08/18/1957 11-08-23 34.47 120.13 C F N OF GAVIOTA; FELT AT CACHUMA RESERVOIR. 08/21/1957 07-36-54 36.47 121.52 C 3.6 NORTHWEST OF KING CITY. 08/28/1957 01-13-57 34.58 121.00 C 3.5 09/12/1957 21-36--? 35.50 121.00 D F II FELT AT P G AND E PLANT, MORRO BAY. 09/21/1957 06-54-26 36.40 121.10 D 2.8 NORTH OF KING CITY. 09/21/1957 15-32--? 35.50 121.00 D F II FELT AT P G AND E PLANT, MORRO BAY. 09/25/1957 23-33-31 36.50 121.50 D 2.7 SOUTH OF HOLLISTER. 10/01/1957 12-55-57 36.47 121.23 C 3.3 SOUTHWEST OF LLANADA. 10/05/1957 14-42--? 34.75 120.25 D F IV REPORTED FELT AT LOS ALAMOS. 10/19/1957 -?-04-38 36.10 120.87 B 3.3 SOUTHEAST OF KING CITY. 10/28/1957 11-41-02 34.33 120.00 C 2.8 11/05/1957 23-50-52 34.72 120.33 C 3.4 11/18/1957 01-11-42 36.38 121.23 C 3.1 NORTHWEST OF KING CITY. 11/18/1957 07-26-32 36.50 121.70 D 3.3 SOUTHEAST OF MONTEREY. 12/31/1957 22-32-55 36.40 121.00 D 2.9 NORTHEAST OF KING CITY. 01/07/1958 17-13-16 35.70 120.80 D 3.0 NORTH OF SAN LUIS OBISPO. 01/18/1958 08-12--? 35.55 120.65 D F REPORTED FELT AT PASO ROBLES. 01/21/1958 21-22-08 36.40 120.50 D 2.9 NORTHWEST OF COALINGA. 01/23/1958 07-06-46 34.38 119.58 B 2.6 F E OF SANTA BARBARA; IV AT SANTA BARBARA. 01/28/1958 07-12-54 36.50 121.10 D 2.2 SOUTHWEST OF LLANADA. 03/26/1958 13-12-30 36.20 120.30 D 2.4 NEAR COALINGA. 03/27/1958 20-26-14 35.90 121.50 D 2.8 NORTHWEST OF SAN SIMEON. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 32 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 03/31/1958 17-38-23 36.50 121.10 D 2.7 SOUTHWEST OF LLANADA. 04/10/1958 08-32-33 36.45 121.12 C 2.9 SOUTHWEST OF LLANADA. 06/05/1958 17-12-50 36.40 121.10 D 3.1 NORTH OF KING CITY. 06/15/1958 07-02-33 36.50 121.38 C 2.9 FORESHOCK OF QUAKE AT 07-05-34. 06/18/1958 07-05-34 36.50 121.38 C 3.3 SOUTH OF HOLLISTER. 06/21/1958 01-03-31 36.40 120.40 D 2.1 SOUTHWEST OF FRESNO. 07/02/1958 17-56-26 36.50 121.30 D 2.8 SOUTHWEST OF LLANADA. 08/08/1958 18-43-01 36.30 121.20 D 2.7 FORESHOCK OF 13-43 RECORDS MIXED. 08/08/1958 13-43-15 36.30 121.20 D 3.9 F NORTHWEST OF KING CITY; IV AT BIG SUR. 08/18/1958 05-30-42 35.80 121.30 D 3.4 NEAR SAN SIMEON. 09/01/1958 11-31-42 36.10 120.80 D 3.2 SOUTHEAST OF KING CITY. 09/21/1958 07-24-55 36.35 121.12 C 4.0 F NORTH OF KING CITY; VI AT SAN BENITO; ALSO FELT AT SOLEDAD. 09/21/1958 14-23-01 36.50 121.05 C 2.7 SOUTHWEST OF LLANADA. 10/03/1958 04-25-51 34.37 119.50 B 3.7 F FROM CARPINTERIA TO GOLETA. 10/10/1958 13-05-16 35.93 120.50 B 4.5 F SOUTHWEST OF COALINGA; FELT OVER AN AREA OF APPROXIMATELY 3500 SQ. MI. OF THE SOUTHWEST-CENTRAL REGION OF CALIFORNIA - APPEARS TO HAVE BEEN FELT MORE STRONGLY AT PARKFIELD THAN ELSEWHERE; V AT ADELAIDA, CAMP ROBERTS, COALINGA, HARMONY, LONE PINE INN, OILFIELD, PARKFIELD, PASO ROBLES, AND SAN ARDO. 10/15/1958 16-16-44 35.50 121.20 D 3.2 NEAR SAN SIMEON. 11/06/1958 20-11-57 36.08 120.88 C 3.1 SOUTHEAST OF KING CITY. 11/16/1958 09-34-04 34.50 119.83 C 4.0 F NW OF SANTA BARBARA; FELT OVER 600 SQ. MI. FROM SANTA YNEZ TO VENTURA; V AT CARPINTERIA, GOLETA, AND SANTA BARBARA. 11/27/1958 06-04-26 36.37 121.15 C 3.9 F WEST OF LLANADA; FELT SLIGHTLY AT CARMEL. 11/27/1958 13-39-01 36.20 120.80 D 3.1 EAST OF KING CITY. 12/15/1958 14-58-49 36.20 120.40 D 3.0 NEAR COALINGA. 12/15/1958 15-24-01 36.20 120.40 D 3.0 F NEAR COALINGA; IV AT COALINGA. 12/30/1958 01-34-15 35.92 119.80 C 3.2 01/11/1959 05-18-26 36.20 120.80 D 2.5 WEST OF COALINGA. 02/07/1959 05-51-02 36.10 120.00 D 3.0 SOUTHEAST OF KING CITY. 02/27/1959 21-35-01 36.25 120.75 C 3.1 SOUTHEAST OF LLANADA. 03/13/1959 02-44-27 35.80 120.30 D 2.5 SOUTH OF COALINGA. 03/14/1959 02-43-41 35.70 121.30 D 3.6 WEST OF SAN SIMEON. 03/20/1959 05-12-09 36.48 121.17 B 2.9 SOUTHWEST OF LLANADA. 03/25/1959 05-34-17 34.25 119.58 C 2.5 F SANTA BARBARA CHANNEL; IV AT CARPINTERIA. 04/08/1959 07-41-57 36.37 121.20 B 3.4 NORTH OF KING CITY. 04/09/1959 14-03-11 36.38 121.15 C 2.5 NORTH OF KING CITY. 04/21/1959 09-36-23 36.40 120.40 D 3.0 NORTH OF COALINGA. 04/21/1959 12-31-10 36.10 121.10 D 2.2 NEAR KING CITY. 04/22/1959 19-04-25 36.20 120.90 D 2.6 NEAR KING CITY. 05/13/1959 14-28-10 36.48 121.03 C 2.6 SOUTHWEST OF LLANADA. 05/14/1959 01-34-09 36.50 121.20 D 2.4 SOUTHWEST OF LLANADA. 05/20/1959 10-15-55 36.30 120.40 D 2.6 NORTHWEST OF COALINGA. 06/01/1959 03-47-24 36.50 121.23 C 2.4 SOUTHWEST OF LLANADA. 06/20/1959 15-01-17 36.50 121.30 D 2.9 SOUTH OF VINEYARD. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 33 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 06/21/1959 09-24-07 34.32 119.67 B 3.3 07/18/1959 01-11-47 36.50 121.30 D 2.5 SOUTH OF VINEYARD. 08/05/1959 03--?-34 35.95 120.48 C 3.5 F SOUTHEAST OF COALINGA (NEAR PARKFIELD; FELT STRONGEST AT PARKFIELD; IV FELT AT PASO ROBLES). 09/05/1959 05-45-34 36.50 121.70 D 3.8 SOUTHWEST OF VINEYARD. 10/01/1959 04-35-35 34.43 120.57 B 4.5 F OFF POINT CONCEPTION; VI AT GAVIOTA PASS AND V AT GAVIOTA, GOLETA, AND LOMPOC. 10/01/1959 05-52-55 34.20 119.50 C 3.2 10/11/1959 02-03-09 36.45 121.12 C 4.1 F SOUTHWEST OF LLANADA; FELT AT SALINAS. 10/24/1959 23-12-54 36.47 121.40 C 3.2 SOUTH OF HOLLISTER. 10/25/1959 03-33-13 36.50 121.20 D 2.4 SOUTHEAST OF VINEYARD. 10/25/1959 03-34-02 36.50 121.32 C 3.0 SOUTH OF VINEYARD. 10/26/1959 09-56-01 36.40 121.10 D 3.0 SOUTHEAST OF VINEYARD. 11/25/1959 09-28-22 35.20 121.20 D 3.5 SOUTH OF KING CITY. 11/26/1959 07-02-05 36.40 121.40 D 2.7 SOUTH OF VINEYARD. 12/11/1959 05-55-26 35.60 120.60 D 3.5 SOUTHEAST OF VINEYARD. 12/25/1959 20-38-28 36.00 120.60 D 3.1 SOUTHEAST OF VINEYARD. 12/29/1959 14-53-08 35.75 120.30 C 3.5 F NEAR CHOLAME; FELT AT PASO ROBLES. 01/02/1960 22-51-48 35.40 121.20 D 4.0 NW OF SAN LUIS OBISPO. 01/04/1960 12-18-20 36.20 120.70 D 3.2 WEST OF COALINGA. 02/14/1960 08-34-30 35.80 121.70 D 2.8 WEST OF SAN SIMEON. 02/25/1960 06-34-31 36.50 121.20 D 2.7 SOUTHWEST OF LLANADA. 02/28/1960 02-55-32 34.33 119.95 C 3.1 03/21/1960 20-46-39 36.50 120.73 C 2.5 SOUTHEAST OF LLANADA. 03/26/1960 21-39-21 36.22 121.00 C 2.7 EAST OF KING CITY. 03/29/1960 11-46-42 36.50 121.10 C 2.4 SOUTHEAST OF VINEYARD. 03/31/1960 08-35-09 36.40 121.20 D 2.6 SOUTHEAST OF VINEYARD. 04/02/1960 13-02-10 35.97 120.33 C 2.7 SOUTH OF COALINGA. 04/02/1960 19-01-12 36.20 120.60 D 3.4 WEST OF COALINGA. 04/09/1960 08-01-14 36.50 121.13 B 3.6 SOUTHEAST OF HOLLISTER. 05/04/1960 09-44-32 36.42 120.72 C 3.4 SOUTHEAST OF LLANADA. 05/15/1960 06-07-23 36.43 121.27 C 2.5 SOUTH OF VINEYARD. 06/11/1960 17-39-48 36.30 120.90 D 3.7 SOUTHEAST OF VINEYARD, DIABLO RANGE. 06/19/1960 19-51-20 36.20 121.90 D 2.6 SOUTHWEST OF BIG SUR. 06/24/1960 18-13-12 36.45 121.22 B 3.5 SOUTHEAST OF VINEYARD. 07/14/1960 03-22-23 35.60 120.40 D 3.0 NORTHEAST OF SAN LUIS OBISPO. 07/20/1960 -?-59-36 35.80 119.80 D 2.8 NORTHEAST OF SAN LUIS OBISPO. 07/30/1960 02-16-29 36.43 120.28 C 2.5 SOUTHWEST OF FRESNO. 08/09/1960 08-59-47 36.20 120.20 D 3.2 EAST OF COALINGA. 08/10/1960 03-03-50 36.47 121.40 D 3.2 SOUTH OF VINEYARD. 08/26/1960 08-57-24 38.33 121.13 C 3.0 SOUTHEAST OF VINEYARD. 09/10/1960 01-18-22 36.47 121.05 C 2.7 SOUTHEAST OF HOLLISTER. 09/10/1960 20-49-12 36.45 121.28 D 2.8 SOUTHWEST OF LLANADA. 10/08/1960 -?-02-29 36.50 121.67 C 3.0 SOUTHWEST OF VINEYARD. 11/03/1960 07-13-40 36.43 121.07 C 2.7 SOUTH-SOUTHWEST OF LLANADA. 11/18/1960 04-36-44 36.38 121.20 C 3.0 NORTH-NORTHWEST OF KING CITY. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 34 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 12/01/1960 14-23-49 34.33 119.85 B 3.2 OFF SANTA BARBARA. 12/15/1960 08-28-08 36.40 121.30 D 3.0 SOUTH OF HOLLISTER. 12/27/1960 03-57-55 36.00 121.10 D 3.3 SOUTH OF KING CITY. 01/06/1961 20-46-36 35.80 120.20 D 3.4 SE OF PARKFIELD. 02/02/1961 12-31--? 36.35 121.20 D 2.2 NORTHWEST OF KING CITY. 02/21/1961 15-46-58 34.37 119.53 C 2.8 SE OF SANTA BARBARA. 03/14/1961 04-15--? 36.40 121.20 D 3.4 SOUTHEAST OF VINEYARD. 03/29/1961 16--?-11 36.50 121.50 D 2.5 SOUTH OF VINEYARD. 04/07/1961 12-21-19 36.20 120.40 D 2.9 NORTH OF COALINGA. 04/08/1961 04-55-26 36.00 121.20 D 2.7 SOUTH OF KING CITY. 04/08/1961 09-29-47 36.10 120.43 B 3.4 NEAR COALINGA. 04/08/1961 12-52-16 36.12 120.43 C 2.7 AFTERSHOCK OF QUAKE AT 09-29-47. 04/11/1961 09-08-11 36.00 120.10 D 2.7 SOUTHEAST OF KING CITY. 04/12/1961 04-59-08 35.92 120.50 C 2.6 SOUTHWEST OF COALINGA. 04/19/1961 18-16-35 36.40 121.58 C 3.3 SOUTHEAST OF MONTEREY. 05/25/1961 14-19-05 36.33 121.00 C 3.4 NORTHEAST OF KING CITY. 05/25/1961 14-19-35 36.33 121.00 B 3.4 NORTHEAST OF KING CITY. 06/01/1961 06-47-20 36.33 121.32 B 2.7 NORTHWEST OF KING CITY. 06/01/1961 14-11-30 36.45 121.20 C 2.6 NORTH OF KING CITY. 06/18/1961 12-50-59 36.18 120.83 C 2.1 EAST OF KING CITY. 06/25/1961 13-15-26 36.48 121.35 C 3.6 F SOUTH OF HOLLISTER; FELT IN HOLLISTER AREA. INTENSITY IV 7.5 MI. SOUTH OF HOLLISTER AT HARRIS RANCH. 06/26/1961 11-30-22 35.77 122.00 C 2.5 OFF SAN SIMEON COAST. 07/22/1961 18-01-55 36.40 121.20 C 4.0 F NORTHEAST OF PARAISO; FELT AT PINNACLES NATIONAL MONUMENT (ABOUT 25 MI. SOUTHEAST OF HOLLISTER). 07/31/1961 -?-07-09 35.82 120.37 C 4.7 F SAN LUIS OBISPO; FELT OVER AN AREA OF 5000 SQ. MI. OF WEST CENTRAL CALIFORNIA. INTENSITY V AT ATASCADERO, CHOLAME, CRESTON, PARKFIELD, SAN LUIS OBISPO, AND TEMPLETON. 08/01/1961 06-12-54 36.43 120.85 C 3.1 SOUTH OF LLANADA. 08/17/1961 17-14-45 36.33 120.95 B 3.1 NORTHEAST OF KING CITY. 09/14/1961 15-12-20 34.32 119.63 C 2.7 09/14/1961 15-14-38 34.32 119.63 C 2.8 09/27/1961 02-02-06 36.33 121.25 C 2.7 EAST OF PARAISO. 09/29/1961 15-39-58 36.33 120.88 B 2.4 SOUTH OF LLANADA. 10/12/1961 06-31-11 35.80 121.30 D 2.3 NORTH OF SAN SIMEON. 10/29/1961 11-47-33 36.33 120.92 C 2.0 EAST OF PARAISO. 11/05/1961 10-43-57 36.03 120.10 D 2.0 EAST OF LLANADA. 11/29/1961 04-49-03 35.15 120.13 C 3.0 SOUTHEAST OF KING CITY. 12/06/1961 03-27-30 36.43 121.85 B 2.4 SOUTH OF MONTEREY. 12/14/1961 07-28-44 36.48 121.08 B 2.1 SOUTHWEST OF LLANADA. 01/04/1962 03-56-10 36.40 121.40 C 3.0 11 NORTHWEST OF KING CITY. 01/31/1962 08-33-15 34.88 120.68 C 3.6 02/01/1962 06-37-57 34.88 120.68 C 4.5 F WEST OF GUADALUPE; FELT OVER AN AREA OF 3000 SQ. MI. V AT ARROYO GRANDE, AVILA BEACH, CASMALIA, GROVER CITY, GUADALUPE, HALCYON, OCEANO, POINT ARGUELLO, AND SHELL 02/01/1962 07-58-12 34.38 120.68 C 3.7 02/04/1962 11-43-34.1 36.42 121.27 C 3.2 12 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 35 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 02/07/1962 13--?-70 34.30 122.10 D 3.9 03/05/1962 07-44-01 34.60 121.60 4.5 F OFF COAST NEAR LOMPOC; V AT MORRO BAY AND PISMO BEACH. 03/06/1962 03-40-22 34.60 121.60 D 3.6 03/10/1962 08-07-21 34.60 121.60 D 4.2 OFF COAST NEAR LOMPOC. 03/10/1962 13-40-48 34.60 121.60 D 4.0 OFF COAST NEAR LOMPOC. 03/10/1962 15-24-21 34.60 121.60 D 3.5 03/12/1962 21-32-09 34.60 121.60 D 3.9 03/23/1962 22-10-18 34.28 120.20 C 2.9 03/24/1962 03-38-41.8 36.20 119.78 B 3.4 19 SOUTH OF FRESNO. 04/02/1962 03-06-03.2 36.25 120.10 B 3.7 16 F EAST OF COALINGA; V IN TEHACHAPI. 04/15/1962 08-41-02.3 36.42 120.62 B 4.7 23 F SOUTHEAST OF LLANADA; V AT IDRIA. 05/04/1962 20-52-32 35.27 119.55 B 2.8 05/05/1962 -?-55-20 34.20 121.50 D 3.3 09/03/1962 17-53-33.1 36.47 121.07 C 2.6 8 F SOUTHWEST OF LLANADA; FELT IN HOLLISTER. 09/11/1962 01-34-31 36.03 121.23 B 3.3 16 SOUTHWEST OF KING CITY. 09/16/1962 18-12-35 34.48 119.68 B 4.0 F NEAR SANTA BARBARA; V AT LOS PRIETOS. 09/16/1962 18-17-09 34.48 119.68 C 2.2 09/16/1962 18-31-17 34.52 119.77 B 2.9 09/21/1962 05-07-18 34.47 119.58 B 3.0 09/29/1962 19-47-32 34.47 119.70 B 2.9 10/13/1962 17-49-39.5 36.35 120.42 B 3.7 17 NORTHEAST OF PRIEST. 12/15/1962 -?-40-20.9 36.47 120.63 B 2.9 13 NORTH OF PRIEST. 01/09/1963 06-04-25.7 35.98 120.35 B 3.2 14 F SE OF PRIEST; III AT WHEELER RIDGE. 02/09/1963 02-52-14.5 35.98 121.69 C 2.8 8 OFF COAST S OF BIG SUR. 02/12/1963 03-44-30.9 36.50 121.32 B 2.6 10 S OF VINEYARD. 02/22/1963 15-56-21.9 35.11 121.44 C 3.3 15 OFF COAST, SW OF MORRO BAY. 02/22/1963 15-56-36.0 35.67 120.83 D 3.6 04/04/1963 01--?-58 35.80 121.50 2.5 6 NW OF SAN SIMEON. 04/10/1963 01-38-56.8 36.42 121.05 2.9 11 SW OF LLANADA. 04/11/1963 14-02-31.8 36.20 120.87 2.9 13 NW OF PRIEST. 04/20/1963 16-37-33.0 36.38 120.96 3.0 14 SOUTH OF LLANADA. 05/10/1963 10-17-57.1 36.37 120.98 2.5 9 SOUTH OF LLANADA. 06/01/1963 05-19--0.2 34.33 119.54 B 2.0 07/02/1963 12--?-24.9 34.86 119.80 C 2.0 07/04/1963 03-20-41.0 34.77 120.02 C 3.2 07/06/1963 23-32-30.4 34.78 120.63 B 3.3 08/15/1963 21-02-32.2 35.97 121.02 3.6 15 NEAR JOLON; FORESHOCK OF FOLLOWING-- 08/15/1963 21-21-32.1 35.91 121.06 3.9 18 F NEAR JOLON; FELT AT HARRIS RANCH. 08/16/1963 08-12-13.6 36.06 121.01 3.2 10 NEAR JOLON; AFTERSHOCK OF PRECEDING. 09/06/1963 03-54-34 36.22 121.48 2.6 8 WEST OF PARAISO. 11/01/1963 14-05-56.0 35.56 120.23 3.4 9 EAST OF ATASCADERO. 11/01/1963 14-06--0.4 35.75 120.47 C 3.2 11/18/1963 07-31-38.5 36.22 120.30 C 3.5 F IV 15 MI. NE OF SAN MIGUEL. 11/18/1963 10-54-45.4 36.38 120.32 2.7 11 NE OF COALINGA. 11/19/1963 03-33-09.2 36.42 121.03 2.9 10 SW OF LLANADA. 12/12/1963 17-10-48.5 34.98 119.51 C 3.1 02/10/1964 05-47-25.0 35.75 120.94 3.9 19 NE OF PASO ROBLES. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 36 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 03/20/1964 13-15-51.0 36.40 121.03 2.6 7 SW OF LLANADA. 04/28/1964 15-01-48.3 36.23 121.08 2.8 7 NEAR KING CITY. 05/07/1964 17-53-58.3 36.43 120.54 2.5 5 N OF PRIEST. 06/06/1964 11-47-39.0 34.63 121.40 D 4.3 06/20/1964 09-21-51.4 34.13 120.67 C 3.1 07/24/1964 07-09-35.9 36.47 121.18 2.9 15 NE OF PARAISO. 08/30/1964 03-41-10.4 36.29 121.94 2.9 7 OFF COAST NW OF POINT SUR. 09/12/1964 01-45-53.5 36.08 120.49 3.1 10 SE OF PRIEST. 10/17/1964 23-43-22.6 36.21 120.92 3.3 14 NW OF PRIEST. 11/08/1964 01-19-19.0 36.00 120.00 4.0 15 E OF AVENAL. 11/08/1964 13-45-51.1 36.34 121.32 3.1 16 NEAR PARAISO. 11/18/1964 01-47-34.0 35.98 121.13 2.7 8 SW OF KING CITY. 11/25/1964 12-49-41.8 36.21 120.78 2.8 15 NW OF PRIEST. 12/05/1964 13-55-57.5 36.02 121.08 2.6 12 W OF SAN ARDO. 12/11/1964 03-35-38.8 34.24 119.76 B 3.5 12/25/1964 11-21-13.2 35.97 121.18 2.6 5 N OF LAKE NACIMIENTO. 12/27/1964 18-58-59.4 36.46 121.06 2.6 7 SW OF LLANDA. 01/13/1965 04-20-48.2 36.45 120.58 2.6 9 NE OF PRIEST. 01/26/1965 08-34-30.7 35.72 120.54 3.0 12 SE OF PRIEST. 01/26/1965 08-36-36.6 35.92 120.27 C 3.1 01/26/1965 08-38-16.4 36.04 120.26 C 3.1 02/21/1965 18-39-18.3 35.67 120.43 3.1 12 E OF PASO ROBLES. 03/28/1965 02-32-21.0 36.20 120.40 3.5 (USCGS) 04/06/1965 20-49-24.4 35.95 121.46 2.5 7 N OF SAN SIMEON. 04/08/1965 01-05-40.6 36.03 121.40 3.0 10 N OF SAN SIMEON. 04/09/1965 12-50-19.3 36.03 120.64 3.0 10 S OF PRIEST. 04/18/1965 03-58-52.4 36.50 121.23 2.7 7 NEAR PINNACLES NATIONAL MONUMENT 04/24/1965 07-29-47.1 34.91 120.14 C 3.6 05/12/1965 17-55-08.7 35.49 121.17 3.0 6 SW OF SAN SIMEON. 06/07/1965 15-06-47.6 36.50 121.13 2.5 10 NEAR PINNACLES NATIONAL MONUMENT. 06/20/1965 02-56-43.5 36.33 120.37 2.7 11 N OF COALINGA. 06/30/1965 15-21-27.7 36.35 120.71 2.5 9 N OF PRIEST. 07/23/1965 05-31-52.7 35.71 121.23 3.4 13 N OF SAN SIMEON. 07/24/1965 15-25-57.4 36.36 120.98 2.5 7 SW OF LLANADA. 08/01/1965 06-47-27.3 36.23 120.85 2.5 7 NW OF PRIEST. 08/01/1965 13-28-32.9 36.23 120.84 2.5 6 AFTERSHOCK OF 06-47-27.3. 08/13/1965 07-36-08.4 36.46 121.08 2.6 9 SW OF LLANADA. 08/13/1965 13-46-16.5 34.35 119.63 B 3.7 F IV AT CARPINTERIA AND SANTA BARBARA. 08/13/1965 21-28-51.8 36.48 121.13 2.4 8 W OF LLANADA. 08/15/1965 23-06-52.5 36.00 120.20 4.0 F AT PAICINES. 08/21/1965 20-09-35.4 36.46 121.07 2.5 8 SW OF LLANADA. 09/06/1965 18--?-57.8 35.96 120.36 C 3.4 09/12/1965 08-50-05.5 36.49 121.12 2.5 7 W OF LLANADA. 09/19/1965 15-42-07.8 35.98 120.34 C 4.8 F V AT ARMONA, AVENAL, CHOLAME, KETTLEMAN CITY, AND STRATFORD. 10/22/1965 02-29-22 36.00 121.70 2.7 6 OFF COAST, W OF KING CITY. 12/02/1965 22-29-13.0 36.20 121.68 2.8 9 W OF PARAISO. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 37 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 01/28/1966 01-49-47.4 35.83 120.45 3.0 F PARKFIELD SEQUENCE; MC EVILLY, ET AL, (1967) THE PARKFIELD, CALIFORNIA EARTHQUAKE OF 1966, BULL. SEISM. SOC. AM. 02/01/1966 -?-20-44.3 36.03 120.57 2.9 PARKFIELD SEQUENCE - SEE 01/28/1966 AT 01-49-47.4. 02/14/1966 -?-24-03.9 36.02 120.57 2.4 PARKFIELD SEQUENCE - SEE 01/28/1966 AT 01-49-47.4. 02/25/1966 01-34-38.0 36.05 120.63 2.4 PARKFIELD SEQUENCE - SEE 01/28/1966 AT 01-49-47.4. 03/31/1966 21-38-45.2 36.05 120.60 2.5 PARKFIELD SEQUENCE - SEE 01/28/1966 AT 01-49-47.4. 04/05/1966 20-44-58.7 36.24 120.85 2.7 9 10 KM NW OF PRIEST (UC BERKELEY SEISMOGRAPH STATION (SS)). 04/12/1966 15-31-39.8 36.07 120.70 2.3 PARKFIELD SEQUENCE. 05/11/1966 17-37-01.1 35.98 120.57 2.3 PARKFIELD SEQUENCE. 05/23/1966 08-07-37.6 36.02 120.57 2.5 PARKFIELD SEQUENCE. 05/23/1966 08-11-07.0 36.02 120.57 2.2 PARKFIELD SEQUENCE. 05/27/1966 15-36-03.7 35.98 120.49 2.7 PARKFIELD SEQUENCE. 06/18/1966 16-32-17.6 35.96 120.53 2.0 PARKFIELD SEQUENCE. 06/20/1966 23-19-18.8 36.33 120.96 2.8 9 NE OF KING CITY. 06/24/1966 21-42-50.4 36.50 120.85 3.1 10 SE OF LLANADA. 06/28/1966 01--?-31.5 35.95 120.52 3.1 F PARKFIELD SEQUENCE; FELT AT CHOLAME, PARKFIELD, VALLETON, AND WORK RANCH. 06/28/1966 01-14-55 35.95 120.50 1.8 PARKFIELD SEQUENCE. 06/28/1966 04-08-55.2 35.97 120.50 5.1 PARKFIELD SEQUENCE FIRST MAIN SHOCK (FELT REPORTS FOR THE 2 MAIN SHOCKS ARE NOT SEPARATED.) FELT OVER 20,000 SQ. MI., MINOR SURFACE FAULTING ALONG SAN ANDREAS FAULT FROM PARKFIELD TO CHOLAME (20 MI.), MAXIMUM DISPLACEMENT 4 IN. VII AT CHOLAME AND PARKFIELD, VI AT ANNETTE, BITTERWATER VALLEY, COALINGA, HIDDEN VALLEY RANCH, PASO ROBLES, SAN LUIS OBISPO, SAN MIGUEL, SHAFTER, SHANDON, SLACK CANYON, VALLETON, WAITI RANCH, AND WORK RANCH, AND V AT ADELAIDA, ALPAUGH, ARROYO GRANDE, ATASCADERO, AVILA BEACH, BAKERSFIELD, BAYWOOD PARK, BRYSON, BURREL, BUTTONWILLOW, EARLIMART, FELLOWS, FRAZIER PARK, GREENFIELD, HARMONY, INDIAN VALLEY, KETTLEMAN CITY, KING CITY, LAPANZA, LOST MARICOPA, MEE RANCH, MORRO BAY, MOSS LANDING, MUSICK, NIPOMO, OCEANO, OLD RIVER, PANOCHE, PINE CANYON, PISMO BEACH, POZO, PRIEST VALLEY, SAN ARDO, SAN JOAQUIN, SAN LUCAS, SAN SIMEON, SIMMLER, STRATFORD, TEMPLETON, AND VANDENBURG A.F.B. 06/28/1966 04-09-53 35.95 120.50 PARKFIELD SEQUENCE. 06/28/1966 04-18-34.0 35.95 120.53 2.6 F PARKFIELD SEQUENCE - FELT AT CANTUA CREEK AND SOQUEL. 06/28/1966 04-26-13.4 35.95 120.50 5.5 F PARKFIELD SEQUENCE - SECOND MAIN SHOCK. 06/28/1966 04-26-28 35.95 120.50 PARKFIELD SEQUENCE. 06/28/1966 04-26-34 35.95 120.50 PARKFIELD SEQUENCE. 06/28/1966 04-27-37 35.95 120.50 PARKFIELD SEQUENCE. 06/28/1966 04-27-58 35.95 120.50 PARKFIELD SEQUENCE. 06/28/1966 04-28-19 35.95 120.50 PARKFIELD SEQUENCE. 06/28/1966 04-28-36 35.95 120.50 4.5 PARKFIELD SEQUENCE. 06/28/1966 04-28-46 35.95 120.50 PARKFIELD SEQUENCE. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 38 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 06/28/1966 04-29-13 35.95 120.50 PARKFIELD SEQUENCE. 06/28/1966 04-31-55 35.95 120.50 3.0 PARKFIELD SEQUENCE. 06/28/1966 04-32-50 35.95 120.50 3.5 F PARKFIELD SEQUENCE - FELT AT CANTUA CREEK, CHOLAME, AND HERNANDEZ. 06/28/1966 04-34-59.1 35.81 120.40 3.0 PARKFIELD SEQUENCE. 06/28/1966 04-39-08.1 35.95 120.50 3.0 F PARKFIELD SEQUENCE - FELT AT PARKFIELD AND WORK RANCH. 06/28/1966 04-42-33.6 35.83 120.38 2.4 PARKFIELD SEQUENCE. 06/28/1966 04-43-54.8 35.95 120.57 2.7 PARKFIELD SEQUENCE. 06/28/1966 04-46-22 35.95 120.50 3.0 PARKFIELD SEQUENCE. 06/28/1966 04-51-43 35.95 120.50 2.4 PARKFIELD SEQUENCE. 06/28/1966 05--?-59.5 35.85 120.40 3.1 PARKFIELD SEQUENCE. 06/28/1966 05-03-44.7 35.88 120.45 2.4 PARKFIELD SEQUENCE. 06/28/1966 05-09-48.3 35.83 120.13 2.5 PARKFIELD SEQUENCE. 06/28/1966 05-12-42.5 35.92 120.47 2.9 PARKFIELD SEQUENCE. 06/28/1966 05-17-05 35.95 120.50 2.1 PARKFIELD SEQUENCE. 06/28/1966 05-21-05 35.95 120.50 2.0 PARKFIELD SEQUENCE. 06/28/1966 05-29-14.9 35.92 120.48 2.1 PARKFIELD SEQUENCE. 06/28/1966 05-37-04.6 35.88 120.44 2.5 PARKFIELD SEQUENCE. 06/28/1966 05-40-19.4 35.94 120.48 2.7 PARKFIELD SEQUENCE. 06/28/1966 05-45-59.1 35.75 120.33 3.2 PARKFIELD SEQUENCE. 06/28/1966 05-48-26 35.95 120.50 2.2 PARKFIELD SEQUENCE. 06/28/1966 05-51-34.0 35.86 120.44 2.1 PARKFIELD SEQUENCE. 06/28/1966 05-52-06 35.95 120.50 2.3 PARKFIELD SEQUENCE. 06/28/1966 05-52-58 35.95 120.50 2.4 PARKFIELD SEQUENCE. 06/28/1966 05-56--? 35.95 120.50 2.1 PARKFIELD SEQUENCE. 06/28/1966 06-11-03.5 35.81 120.35 2.6 PARKFIELD SEQUENCE. 06/28/1966 06-32-17.9 35.94 120.52 3.4 F PARKFIELD SEQUENCE - FELT AT CHOLAME, COALINGA, AND PARKFIELD. 06/28/1966 06-35-11.4 35.80 120.38 3.0 PARKFIELD SEQUENCE. 06/28/1966 06-39-31.2 35.90 120.47 2.2 PARKFIELD SEQUENCE. 06/28/1966 07-01-03.8 35.92 120.48 2.2 PARKFIELD SEQUENCE. 06/28/1966 07-33-52.7 35.90 120.45 2.7 PARKFIELD SEQUENCE. 06/28/1966 07-41-43 35.95 120.50 2.3 PARKFIELD SEQUENCE. 06/28/1966 07-45-48.3 35.90 120.47 3.0 F PARKFIELD SEQUENCE - FELT AT CHOLAME AND PARKFIELD. 06/28/1966 08-14-48.6 35.83 120.42 2.4 PARKFIELD SEQUENCE. 06/28/1966 08-47-52.4 35.85 120.42 2.0 PARKFIELD SEQUENCE. 06/28/1966 08-54-49.5 35.92 120.50 2.3 PARKFIELD SEQUENCE. 06/28/1966 08-59-52.3 35.85 120.42 2.5 PARKFIELD SEQUENCE. 06/28/1966 09-31-26.5 35.77 120.35 2.4 PARKFIELD SEQUENCE. 06/28/1966 09-35-54.3 35.77 120.36 2.2 PARKFIELD SEQUENCE. 06/28/1966 09-56-09.7 35.83 120.40 2.5 PARKFIELD SEQUENCE. 06/28/1966 10-15-53.3 35.92 120.53 2.1 PARKFIELD SEQUENCE. 06/28/1966 10-20-16.4 35.85 120.42 2.3 PARKFIELD SEQUENCE. 06/28/1966 10-23-22.8 35.55 120.42 2.0 PARKFIELD SEQUENCE. 06/28/1966 10-23-22.8 35.94 120.48 2.5 PARKFIELD SEQUENCE. 06/28/1966 10-46-22.9 35.94 120.50 2.0 PARKFIELD SEQUENCE. 06/28/1966 11-15-13.9 35.85 120.42 2.0 PARKFIELD SEQUENCE. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 39 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 06/28/1966 11-28-41.4 35.85 120.38 2.0 PARKFIELD SEQUENCE. 06/28/1966 11-30-14.0 35.90 120.47 2.2 PARKFIELD SEQUENCE. 06/28/1966 12-31-52.1 35.94 120.48 2.5 PARKFIELD SEQUENCE. 06/28/1966 12-52-22.0 35.97 120.53 2.3 PARKFIELD SEQUENCE. 06/28/1966 13-48-22 35.97 120.53 2.7 PARKFIELD SEQUENCE. 06/28/1966 14-13-09.3 35.94 120.48 2.6 PARKFIELD SEQUENCE. 06/28/1966 14-21-36.3 35.94 120.48 2.2 PARKFIELD SEQUENCE. 06/28/1966 14-51-53.6 35.90 120.47 2.3 PARKFIELD SEQUENCE. 06/28/1966 18-12-19.4 35.92 120.50 2.3 PARKFIELD SEQUENCE. 06/28/1966 18-22-32.4 35.92 120.50 2.0 PARKFIELD SEQUENCE. 06/28/1966 18-54-55.3 35.88 120.45 2.5 PARKFIELD SEQUENCE. 06/28/1966 19-59-37.8 35.92 120.47 2.8 PARKFIELD SEQUENCE. 06/28/1966 20--?-38.7 35.92 120.48 2.5 PARKFIELD SEQUENCE. 06/28/1966 20-46-56.4 35.77 120.40 3.1 F PARKFIELD SEQUENCE - FELT AT BAR B RANCH AND WORK RANCH. 06/28/1966 22-01-13.9 35.85 120.44 2.0 PARKFIELD SEQUENCE. 06/28/1966 22-37-56.7 35.88 120.42 2.0 PARKFIELD SEQUENCE. 06/28/1966 23-57-22.3 35.77 120.35 2.5 PARKFIELD SEQUENCE. 06/29/1966 -?-17-32.6 35.85 120.44 2.3 PARKFIELD SEQUENCE. 06/29/1966 02-19-39.9 35.92 120.52 3.6 F PARKFIELD SEQUENCE - FELT AT CHOLAME, PARKFIELD, AND WORK RANCH. 06/29/1966 04-06-40.3 35.92 120.53 2.8 PARKFIELD SEQUENCE. 06/29/1966 07-28-59.4 35.92 120.48 2.3 PARKFIELD SEQUENCE. 06/29/1966 08-55-52.4 35.88 120.45 2.9 PARKFIELD SEQUENCE. 06/29/1966 09-20-50.1 35.78 120.36 2.5 PARKFIELD SEQUENCE. 06/29/1966 10-13-44.0 35.97 120.50 2.3 PARKFIELD SEQUENCE. 06/29/1966 10-56-58.8 35.75 120.33 3.0 PARKFIELD SEQUENCE. 06/29/1966 12-30-09.0 35.94 120.50 2.4 PARKFIELD SEQUENCE. 06/29/1966 13-11-59.7 35.82 120.38 3.1 F PARKFIELD SEQUENCE - FELT AT CHOLAME AND PARKFIELD. 06/29/1966 15-18-38.9 35.95 120.33 2.0 PARKFIELD SEQUENCE. 06/29/1966 15-34-22.2 35.92 120.48 2.3 PARKFIELD SEQUENCE. 06/29/1966 16-03-30.1 35.86 120.45 2.1 PARKFIELD SEQUENCE. 06/29/1966 17-10-28.3 35.82 120.36 2.0 PARKFIELD SEQUENCE. 06/29/1966 19-53-25.9 35.95 120.53 5.0 F PARKFIELD SEQUENCE - FELT AT ADELAIDA, BITTERWATER, CHOLAME, COALINGA, FRESNO, MEE RANCH, MORRO BAY, SAN LUIS OBISPO, SAN MIGUEL, SANTA MARGARITA, SHANDON, AND WORK RANCH. 06/29/1966 20-44-40.0 35.74 120.28 2.5 PARKFIELD SEQUENCE. 06/29/1966 23-48-12.0 35.74 120.28 2.3 PARKFIELD SEQUENCE. 06/30/1966 01-17-36.1 35.86 120.45 4.1 PARKFIELD SEQUENCE. 06/30/1966 03-36-16.8 35.92 120.47 2.6 PARKFIELD SEQUENCE. 06/30/1966 05-04-12.9 35.88 120.45 2.0 PARKFIELD SEQUENCE. 06/30/1966 06-07-21.5 35.94 120.48 2.4 PARKFIELD SEQUENCE. 06/30/1966 06-23-32.4 35.90 120.47 2.1 PARKFIELD SEQUENCE. 06/30/1966 07-37-12.1 35.90 120.47 2.0 PARKFIELD SEQUENCE. 06/30/1966 08-01-38.4 35.90 120.47 2.9 PARKFIELD SEQUENCE. 06/30/1966 11-07-55.1 35.78 120.33 2.8 PARKFIELD SEQUENCE. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 40 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 06/30/1966 13-26-05.7 35.78 120.35 2.3 PARKFIELD SEQUENCE. 06/30/1966 13-29-56.6 35.86 120.40 2.0 PARKFIELD SEQUENCE. 06/30/1966 13-40-50.9 35.83 120.38 2.1 PARKFIELD SEQUENCE. 06/30/1966 16-05-02.7 35.97 120.50 2.3 PARKFIELD SEQUENCE. 06/30/1966 19-06-17.5 35.86 120.42 2.1 PARKFIELD SEQUENCE. 07/01/1966 09-41-21.9 35.94 120.52 3.2 F PARKFIELD SEQUENCE - FELT AT WORK RANCH. 07/02/1966 12-08-34.8 35.79 120.33 3.7 F PARKFIELD SEQUENCE - FELT AT PARKFIELD. 07/02/1966 12-16-15.8 35.81 120.35 3.4 F PARKFIELD SEQUENCE - FELT AT PARKFIELD. 07/02/1966 12-25-06.8 35.80 120.35 3.1 F PARKFIELD SEQUENCE - FELT AT PARKFIELD. 07/05/1966 18-54-54.5 35.92 120.48 3.0 F PARKFIELD SEQUENCE - FELT AT PARKFIELD. 07/25/1966 22-49-39 36.40 120.30 2.5 4 NE OF COALINGA. 07/27/1966 08 0.2 35.90 120.48 3.0 PARKFIELD SEQUENCE. 08/03/1966 12-39-05.8 35.80 120.38 3.4 F PARKFIELD SEQUENCE; V AT CHOLAME, PARKFIELD, AND WORK RANCH. 08/04/1966 -?-54-24.5 35.74 121.35 3.0 8 NW OF SAN SIMEON. 08/07/1966 17-03-24.9 35.94 120.55 3.0 PARKFIELD SEQUENCE. 08/19/1966 22-51-20.1 35.90 120.45 3.3 PARKFIELD SEQUENCE. 09/07/1966 -?-20-50.5 35.83 119.94 3.2 9 SE OF COALINGA. 09/18/1966 15-09-55.7 35.74 120.35 3.1 PARKFIELD SEQUENCE. 10/27/1966 12-06-03.9 35.94 120.50 3.8 F PARKFIELD SEQUENCE; V AT ATASCADERO, AVENAL, COALINGA, PARKFIELD, SAN MIGUEL, TEMPLETON, AND WORK RANCH. 11/05/1966 13-31-31.2 35.94 120.50 3.3 PARKFIELD SEQUENCE. 11/18/1966 23-39-42.3 35.75 120.33 3.3 PARKFIELD SEQUENCE. 12/30/1966 10-23-48 36.47 120.40 2.5 4 N OF COALINGA. 01/08/1967 23-03-50.9 35.90 120.40 2.8 8 35 KM SE OF PRIEST (UC BERKELEY SS). 01/09/1967 23-18-59.5 35.86 120.10 3.1 9 SE OF COALINGA. 02/01/1967 13-55-54.1 35.70 120.25 3.0 8 NE OF SAN LUIS OBISPO. 02/26/1967 15-17-53.9 36.40 121.06 2.5 9 SW OF LLANADA. 03/13/1967 21-59-48.4 36.00 120.61 3.1 8 F 15 KM S OF PRIEST (UC BERKELEY SS). IV AT SAN MIGUEL; FELT AT INDIAN VALLEY AND RANCHITO CANYON. 03/21/1967 02-24-28.3 36.21 120.85 2.8 8 17 KM NW OF PRIEST (UC BERKELEY SS). 03/23/1967 11-39-56.4 36.16 120.18 3.0 5 20 KM E OF COALINGA. 04/13/1967 09-06-42.5 36.15 120.80 2.7 8 13 KM W OF PRIEST (UC BERKELEY SS). 05/17/1967 14-16-52.2 35.95 120.73 3.0 6 30 KM S OF PRIEST (UC BERKELEY SS). 06/03/1967 20-10-53.0 35.71 121.48 2.6 7 OFF COAST NW OF SAN SIMEON. 06/06/1967 06-11-38.5 35.81 120.43 3.0 10 F 40 KM SE OF PRIEST (UC BERKELEY SS); IV AT WORK RANCH; FELT IN INDIAN VALLEY, SOUTHERN MONTEREY COUNTY, AND VINEYARD CANYON. 06/13/1967 12-54-10.7 35.81 121.50 3.3 10 OFF COAST, 35KM NW OF SAN SIMEON. 07/24/1967 07-08-52.9 35.96 120.50 3.7 9 PARKFIELD AREA. 07/28/1967 14-44-40.1 35.75 121.38 3.0 6 NEAR SAN SIMEON. 08/01/1967 22-14-13.0 35.75 121.40 2.7 6 NW OF SAN SIMEON. 08/08/1967 18-11-20.3 36.42 120.42 2.5 7 N OF COALINGA. 08/12/1967 18-57-40.4 35.80 120.45 4.1 18 F PARKFIELD AREA; V AT ESTRELLA AREA, HOG CANYON ROAD TO PARKFIELD, AND SHANDON, AND IV AT CHOLAME. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 41 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 08/12/1967 23-21-07.8 36.11 120.80 2.8 6 SE OF KING CITY. 08/12/1967 23-22-05.3 36.13 120.76 2.5 7 SE OF KING CITY. 08/17/1967 23-12-02.7 35.91 121.50 2.6 5 NW OF SAN SIMEON. 08/25/1967 02-28-14.4 35.81 121.27 2.7 6 NW OF SAN SIMEON. 08/25/1967 16-35-27.8 36.05 120.00 3.2 7 SE OF COALINGA. 08/25/1967 16-40-50.2 36.01 119.95 3.0 7 SE OF COALINGA. 08/31/1967 18-10-40.4 35.86 121.35 2.8 7 NW OF SAN SIMEON. 09/09/1967 21-35-05.6 35.81 121.63 2.4 3 OFF SHORE SAN SIMEON. 10/14/1967 12-02-43.6 36.50 120.61 2.7 5 NEAR MT. CIERVO. 10/21/1967 12-05-21.8 35.83 120.46 3.1 7 PARKFIELD AREA. 10/25/1967 23-05-30.5 35.73 121.45 2.6 4 NEAR SAN SIMEON. 11/11/1967 22-10-06.8 36.50 120.81 3.3 9 S OF PANOCHE VALLEY. 11/11/1967 22-33-47.5 36.48 120.78 2.8 6 S OF PANOCHE VALLEY. 11/12/1967 07-11-20.4 36.48 120.80 2.6 7 S OF PANOCHE VALLEY. 11/14/1967 -?--?-51.7 35.78 120.53 3.1 3 PARKFIELD. 11/25/1967 15-27-43.4 36.46 121.06 2.5 6 BEAR VALLEY. 12/21/1967 05-13-11.3 35.36 120.85 2.6 3 S OF SAN SIMEON. 12/21/1967 19-08-53.8 35.91 119.53 3.1 5 NW OF DELANO. 12/21/1967 23-58-60.2 35.93 120.56 3.0 3 PARKFIELD. 12/31/1967 23-48-13.5 35.75 120.45 4.3 3 F PARKFIELD AREA; V AT CRESTON, PARKFIELD, SALINAS DAM, SAN MIGUEL, SHANDON, TEMPLETON, AND WORK RANCH. 02/03/1968 19-07-26.4 35.73 121.25 2.8 5 NEAR SAN SIMEON. 02/23/1968 20-20-57.9 35.86 121.31 2.5 7 EAST OF HOLLISTER. 03/25/1968 11-32-07.4 36.37 120.70 3.6 8 F SE OF LLANADA; MAXIMUM INTENSITY V. 03/28/1968 04-53-26.5 36.36 120.19 3.1 5 F SE OF COALINGA; FELT AT AVENAL - INTENSITY IV. 04/14/1968 06-20-54.6 36.18 121.65 2.5 6 SE OF MONTEREY. 04/23/1968 15-09-14.9 35.52 120.82 3.4 7 SE OF SAN SIMEON. 04/27/1968 14-32-37.4 36.22 120.83 2.7 7 NW OF PRIEST (UC BERKELEY SS). 04/28/1968 06-31-32.9 35.46 120.83 3.5 7 NW OF SAN LUIS OBISPO. 05/31/1968 07-07-37.9 35.80 120.60 3.0 5 S OF COALINGA. 06/11/1968 11-43-28.1 35.90 121.70 3.3 9 OFFSHORE, NW OF SAN SIMEON. 06/22/1968 12-50-50.1 36.43 121.04 2.9 9 S OF LLAN 07/03/1968 17-52-52 35.80 121.50 2.5 7 NW OF SAN SIMEON. 07/29/1968 04-27-51.9 36.38 120.69 2.7 9 N OF PRIEST (UC BERKELEY SS). 07/29/1968 05-29-19.9 36.37 120.70 2.8 9 N OF PRIEST (UC BERKELEY SS). 07/31/1968 -?-49-25.4 36.37 120.70 2.9 9 N OF PRIEST (UC BERKELEY SS). 08/19/1968 16-30-18.2 36.40 121.91 3.3 9 S OF CARMEL. 09/01/1968 21-56-24.4 36.45 121.02 2.7 8 E OF PINNACLES NATIONAL MONUMENT. 11/06/1968 08-58-23.2 35.88 120.45 2.8 10 F NEAR PARKFIELD; FELT NEAR SAN MIGUEL. 11/10/1968 04-06-03.9 35.70 121.18 3.2 9 NEAR SAN SIMEON. 11/17/1968 01-03-47.0 36.29 120.94 3.0 6 NEAR KING CITY. 12/11/1968 12-19-52.4 35.81 120.48 3.0 10 NEAR PARKFIELD. 12/16/1968 01-14-10.9 36.17 120.85 2.7 7 W OF PRIEST (UC BERKELEY SS). 01/09/1969 09-42-47.2 35.94 120.57 3.8 7 F CHOLAME VALLEY; FELT IN PARKFIELD AND SLACK CANYON - MAXIMUM INTENSITY V. 02/04/1969 -?-45-25 36.40 120.38 3.0 4 NORTH OF COALINGA. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 42 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 06/19/1969 07-05-08 36.12 119.58 3.5 8 F NEAR TULARE; FELT IN CORCORAN, DINUBA, HANFORD, IVANHOE, LEMON COVE, STRATHMORE, AND TIPTON. MAXIMUM INTENSITY IV. 06/24/1969 14-25-37 36.42 120.13 3.0 4 SOUTHWEST OF FRESNO. 07/16/1969 04-06-35 35.83 120.28 3.2 7 15 KM SOUTHEAST OF PARKFIELD. 09/06/1969 13-44-45 35.30 121.10 3.8 10 F 50 KM WEST OF SAN LUIS OBISPO. 09/16/1969 03-32-24 36.18 120.80 2.5 8 13 KM WEST OF PRIEST (UC BERKELEY SS). 10/02/1969 06--?-58.9 36.32 120.32 3.3 10 10 KM NORTH OF COALINGA. 11/17/1969 20-49-10.4 36.43 121.05 4.4 10 F NNE OF KING CITY; FELT IN MONTEREY - SWAYED BUILDINGS IN SALINAS 11/19/1969 06-23-50 36.45 121.52 4.2 8 F GONZALES AND SALINAS VALLEY; FELT IN SALINAS AND SANTA CRUZ - RATTLED WINDOWS IN MONTEREY. 11/26/1969 -?-06-59 36.48 120.60 2.5 6 50 KM NORTHEAST OF KING CITY. 11/30/1969 15-11-54 35.30 120.90 2.5 10 20 KM EAST OF KING CITY; 2 SMALL FORESHOCKS RECORDED. 12/10/1969 13-25-31 35.75 120.40 3.5 7 40 KM SOUTH OF COALINGA. 12/14/1969 19-07-57 35.92 120.68 3.2 9 20 KM NORTH OF PASO ROBLES. 01/29/1970 02-49-12.9 36.11 120.99 2.5 6 20 KM SOUTHWEST OF KING CITY. 02/01/1970 21-19-45.7 36.41 121.08 2.6 12 30 KM EAST OF PARAISO. 02/08/1970 -?-14-13.3 36.40 120.97 2.7 13 25 KM SOUTH OF LLANADA. 02/09/1970 16--?-46.1 35.77 120.35 3.1 16 60 KM SOUTH OF PRIEST (UC BERKELEY SS). 02/14/1970 15-44-58.0 36.09 120.64 2.8 14 5 KM SOUTH OF PRIEST (UC BERKELEY SS). 04/18/1970 13-16-53.4 36.49 120.01 3.0 15 35 KM SOUTHWEST OF FRESNO. 04/21/1970 22-29-25.9 35.66 120.43 3.0 8 65 KM SOUTH OF PRIEST (UC BERKELEY SS). 04/23/1970 03-25-18.9 35.97 121.45 2.5 10 25 KM SOUTHWEST OF KING CITY. 05/27/1970 10-42-19.3 35.99 120.91 3.4 8 40 KM SOUTHWEST OF PRIEST (UC BERKELEY SS). 07/20/1970 23-24-55 35.95 121.57 2.5 5 8 KM SOUTH OF LOPEZ POINT - OFFSHORE. 07/21/1970 05-24-16.1 35.99 121.57 2.5 5 5 KM SOUTHEAST OF LOPEZ POINT. 08/05/1970 06-47-36.4 35.82 119.94 2.9 8 KETTLEMAN HILLS. 08/05/1970 16-51-45.7 36.23 121.69 3.0 11 25 KM SOUTHWEST OF PARAISO. 08/13/1970 05-06-19.8 36.17 121.70 3.7 11 20 KM WEST OF LOPEZ POINT. 09/05/1970 11-29-11 36.20 120.10 3.1 4 EAST-NORTHEAST OF COALINGA. 09/10/1970 23-45-59 36.40 120.50 3.2 11 30 KM NORTHWEST OF COALINGA. 09/11/1970 15-20-08 35.98 120.05 3.3 9 8 KM EAST OF AVENAL. 09/16/1970 18-22-10.7 35.96 121.27 2.6 7 NEAR MILPITAS. 10/07/1970 17-57-06.3 36.30 121.40 2.5 9 30 KM NORTHWEST OF KING CITY. 12/01/1970 06-05-59 35.38 121.13 3.3 7 F 25 KM WEST OF MORRO BAY; INTENSITY V AT BRYSON - NO DAMAGE. 12/12/1970 22-29-20 35.65 121.55 2.5 6 30 KM WEST OF SAN SIMEON. 01/02/71 06-27-37.5 3555.1' 12032.2' 3.0 10 km NW of Parkfield 01/16/71 05-33-27.8 3600' 12012' 3.1 Kettleman Hills 01/26/71 21-53-53 3512' 12042' 3.0 Near San Luis Obispo. 01/31/71 12-22-49.5 3555.6' 12030.6' 3.0 NW of Parkfield; sharp, rapid jolting at Shandon. 04/05/71 01-40-34.2 3624.8' 12059.0' 3.0 20 km SE of Pinnacles National Monument. 04/19/71 09-35-58.8 3613.7' 12050.3' 3.0 25 km E of King City. 04/29/71 02-13-15.7 3630.3' 12032.5' 3.0 40 km NW of Coalinga. 06/20/71 12-41-39.8 353' 12020' 3.4 Near Cholame. 07/06/71 09-24-35 3534' 12135' 3.0 SW of San Simeon. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-1 Sheet 43 of 43 Revision 17 November 2006 MM/DD/YY HR/MN/SE NORTH LAT WEST LONG QUALITY MAG. STA. REC. FELT MAXIMUM INTENSITY - COMMENTS 07/21/71 09-14-26.2 3613.7' 12050.8' 3.2 Near Coalinga. 08/06/71 20-03-16.3 3600.8' 12002.2' 3.0 Near Coalinga. 10/06/71 14-43-30.6 3551.3' 12022.5' 3.5 S of Coalinga; intensity IV at Cholame, Parkfield, and Shandon. 10/21/71 22-09-45.4 3558.8' 12050.2' 3.7 SE of King City; intensity V at San Ardo (small objects shifted) and intensity IV at Jolon, King City, Lockwood, Pine Canyon, and San Lucas. 11/07/71 14-03-30.4 3531.2' 11950.2' 4.0 SE of Coalinga. 11/18/71 04-03-52.4 3614.5' 12050.6' 3.4 NE of King City. 11/30/71 09-45-42.8 3603.6' 11953.4' 3.0 SE of Coalinga. END OF SELECTED EARTHQUAKES
END OF QUAKES PROGRAM FOR SELECTION OF EARTHQUAKES
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-2 Sheet 1 of 2 Revision 11 November 1996 SUMMARY, REVISED EPICENTERS OF REPRESENTATIVE SAMPLES OF EARTHQUAKES OFF THE COAST OF CALIFORNIA NEAR SAN LUIS OBISPO Original Hypocenter Revised Hypocenter Date Event Number Lat. Long. Distance Hypocenter Moved, km Error Ellipse km Mag., ML May 27, 1935 1 35.370 120.960 66NW 7 x 14 3.0 35.621 121.639 Sept. 7, 1939 6 35.420 121.070 40W 8 x 8 3.0 35.459 121.495 Oct. 6, 1939 7 35.800 121.500 54NW 16 x 31 3.5 36.232 121.763 July 11, 1945 8 35.670 121.250 21NW 7 x 24 4.0 35.809 121.408
Mar. 23, 1947 12 35.150 121.300 66S 12 x 24 3.7 34.577 121.137 Mar. 27, 1947 15 35.000 121.000 32SW 20 x 20 4.2 34.739 120.896 Dec. 20, 1948 9 35.800 121.500 16SE 9 x 38 4.5 35.683 121.364
Dec. 31, 1948 10 35.670 121.400 17SE 8 x 29 4.6 35.598 121.226 Nov. 22, 1952 Bryson Earthquake 17 35.730 35.830 35.836 121.190 121.170 121.204 U.C. Berkeley Richter (1969) 12N 7 x 24 6.0 Mar. 13, 1954 21 35.000 120.690 19E 9 x 18 3.4 34.960 120.490
Mar. 5, 1955 23 35.600 121.400 38NE 15 x 29 3.3 35.863 121.149 June 21, 1957 25A 35.100 120.900 15NW 10 x 19 3.7 35.255 120.951 Jan. 2, 1960 26 35.400 121.190 44NE 15 x 29 4.0 35.778 121.066 Feb. 1, 1962 52 34.880 120.670 22NW 6 x 16 4.5 35.031 120.846 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-2 Sheet 2 of 2 Revision 11 November 1996 Original Hypocenter Revised Hypocenter Date Event Number Lat. Long. Distance Hypocenter Moved, km Error Ellipse km Mag., ML Mar. 5, 1962 54 34.600 121.590 17E 8 x 10 4.5 34.622 121.416 Mar. 10, 1962 54A 34.600 121.590 22NE 6 x 20 4.2 34.667 121.372 Feb. 22, 1963 28 35.110 121.440 42S 7 x 28 3.3 34.730 121.400 Sept. 6, 1969 31 35.300 121.090 9NE 5 x 10 3.6 35.355 121.033 Oct. 22, 1969 56 34.830 121.340 23SW 14 x 50 5.4 34.649 121.471
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-3 Sheet 1 of 2 Revision 11 November 1996 DISPLACEMENT HISTORY OF FAULTS IN THE SOUTHERN COAST RANGES OF CALIFORNIA
Fault Distance From Diablo Site, miles Time of Principal Activity Youngest Formation Cut By Fault Oldest Formation Capping Fault San Andreas 45 Mid-Tertiary - present Currently active Faults in ground between San Andreas and Sur-Nacimiento-Rinconada, La Panza, Cuyama, Red Hills, East Huasna 18-45 Tertiary Pleistocene (possible Holocene) (Ref. 14) Not Known Sur-Nacimiento (zone) 18 Late Mesozoic, (Benioff-subduction zone) Pleistocene (possible Holocene) (Ref. 14) Late Quaternary terrace deposits (Ref. 11) West Huasna-Suey 11 Late Tertiary Post late-Miocene Late Quaternary terrace deposits (Ref. 36) Edna 4.5 Late Tertiary Plio-Pleistocene (Paso Robles Fm) Late Pleistocene (Ref. 20) Miguelito 5 Late Tertiary Early Pliocene (Miguelito Member of Careaga Fm) (Ref. 21) Poss. capped by mid-Pliocene Squire Member of Careaga Fm; Plio-Pleistocene Paso Robles Fm DCPP UNITS 1 & 2 FSAR UPDATE TABLE 2.5-3 Sheet 2 of 2 Revision 11 November 1996
Fault Distance From Diablo Site, miles Time of Principal Activity Youngest Formation Cut By Fault Oldest Formation Capping Fault Faulting in the Mesozoic rocks near Pt. San Luis 4 Mesozoic Mesozoic Late Pleistocene (Ref. 20) Unnamed faults near Pt. San Simeon 35 Probable Tertiary Not known; possible Holocene Not known Offshore structural zone 4.5 Late Tertiary Possible Holocene (Ref. 19) (northern part) Holocene-upper Pliocene (Ref. 19) (southern part) Faults in the Santa Maria Basin 40 Not known Possible Pleistocene (orcutt Fm) (Ref. 23) Pleistocene-Holocene
Revision 11 November 1996 Revision 14 November 2001 FSAR UPDATE UNITS 1 AND 2 DIABLO CANYON SITE FIGURE 2.1-4 POPULATION DISTRIBUTION 0 TO 10 MILES 2000 CENSUS PLANT SITE MORRO BAY NNE NE ENE E ESE SE 10 2 3 4 5 1 3334AVILA BEACH3104936871 5664 BAYWOOD PARKN NNW NW 49282 2572 NRC Zone 6 2 Revision 14 November 2001 FSAR UPDATE UNITS 1 AND 2 DIABLO CANYON SITE FIGURE 2.1-5 POPULATION DISTRIBUTION 0 TO 10 MILES 2010 PROJECTED PLANT SITE MORRO BAY NNE NE ENE E ESE SE 10 2 3 4 5 1 3334AVILA BEACH41165401154 7505 BAYWOOD PARKN NNW NW 412299 3408 NRC Zone 6 2 Revision 14 November 2001 FSAR UPDATE UNITS 1 AND 2 DIABLO CANYON SITE FIGURE 2.1-6 POPULATION DISTRIBUTION 0 TO 10 MILES 2025 PROJECTED PLANT SITE MORRO BAY NNE NE ENE E ESE SE 10 2 3 4 5 1 3334AVILA BEACH52483451473 9576 BAYWOOD PARKN NNW NW 415693 4348 NRC Zone 6 2 Revision 14 November 2001 1324 FSAR UPDATEUNITS 1 AND 2 DIABLO CANYON SITE FIGURE 2.1-7 POPULATION DISTRIBUTION 10 TO 50 MILES 2000 CENSUS 3599 N NNW NW NNENE ENE EESE SE SSE 5842 50126 5333 69700 5122846129882040541 63471388 12874142 6768 95131256 11356494 3769159 686 159 1544 168 795 1229 2390 22522 10561563 3402482 338 MORROBAY LOMPOCSANTAMARIA GROVERBEACHSAN LUISOBISPOPASO ROBLES ATASCADERO 0 0 95 47 0 123 PLANT SITE 1020304050 NRC Zones 6 7 8 9 10 1324 Revision 14 November 2001 2047 FSAR UPDATEUNITS 1 AND 2 DIABLO CANYON SITE FIGURE 2.1-8 POPULATION DISTRIBUTION 10 TO 50 MILES 2010 PROJECTED 4427 N NNW NW NNENE ENE EESE SE SSE 7852 67369 7093 92701 6915854063983446014 81371650 15475162 7428 128243243 16001633 41911288 909 211 2047187 1018 1900 3372 33659 16332345 6821522 366 MORROBAY LOMPOCSANTAMARIA GROVERBEACHSAN LUISOBISPOPASO ROBLES ATASCADERO 0 0 105 51 0 135 PLANT SITE 1020304050 NRC Zones 6 7 8 9 10 2047 Revision 14 November 2001 2047 FSAR UPDATEUNITS 1 AND 2 DIABLO CANYON SITE FIGURE 2.1-9 POPULATION DISTRIBUTION 10 TO 50 MILES 2025 PROJECTED 5436 N NNW NW NNENE ENE EESE SE SSE 10451 89669 9168 123370940726557912421 54435 103091999 19204187 8200 174660932 23028802 48414302 1206 280 2714217 1292 3000 4853 51539 25703615 10517 586 411 MORROBAY LOMPOCSANTAMARIA GROVERBEACHSAN LUISOBISPOPASO ROBLES ATASCADERO 0 0 122 57 0 156 PLANT SITE 1020304050 NRC Zones 6 7 8 9 10 3231
Revision 13 April 2000 FSAR Update UNITS 1 AND 2 DIABLO CANYON SITE FIGURE 2.1-15 LOW POPULATION ZONE
FSAR UPDATE UNITS 1 AND 2 DIABLO CANYON SITE FIGURE 2.3-4 LOCATION OF METEOROLOGICALMEASUREMENT SITES AT DIABLO CANYON AND VICINITY Revision 20 November 2011
Revision 11 November 1996FIGURE 2.5-1 PLANT SITE LOCATION AND TOPOGRAPHY UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 2.5-2 EARTHQUAKE EPICENTERS WITHIN 200 MILES OF PLANT SITE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 2.5-3 FAULTS AND EARTHQUAKE EPICENTERS WITHIN 75 MILES OF PLANT SITE (FOR EARTHQUAKES WITH ASSIGNED MAGNITUDES) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 2.5-4 FAULTS AND EARTHQUAKE EPICENTERS WITHIN 75 MILES OF PLANT SITE (FOR EARTHQUAKES WITH ASSIGNED INTENSITIES ONLY) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 2.5-5 GEOLOGIC AND TECTONIC MAP OF SOUTHERN COAST RANGES IN THE REGION OF PLANT SITE (SHEET 1 OF 2) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 2.5-5 GEOLOGIC AND TECTONIC MAP OF SOUTHERN COAST RANGES IN THE REGION OF PLANT SITE (SHEET 2 OF 2) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE
Revision 11 November 1996 FIGURE 2.5-7 GEOLOGIC SECTION THROUGH EXPLORATORY OIL WELLS IN THE SAN LUIS RANGE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 2.5-8 GEOLOGIC MAP OF DIABLO CANYON COASTAL AREA UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 2.5-9 GEOLOGIC MAP OF SWITCHYARD AREA UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 2.5-10 GEOLOGIC SECTION THROUGH THE PLANT SITE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 2.5-11 SITE EXPLORATION FEATURES AND BEDROCK CONTOURS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 2.5-12 GEOLOGIC SECTIONS AND SKETCHES ALONG EXPLORATORY TRENCHES UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 2.5-13 GEOLOGIC SECTION THROUGH ALONG EXPLORATORY TRENCHES UNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 2.5-14 RELATIONSHIPS OF FAULTS AND SHEARS AT PLANT SITE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 2.5-15 GEOLOGIC MAP OF EXCAVATIONS FOR PLANT FACILITIES UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 2.5-16 GEOLOGIC SECTIONS THROUGH EXCAVATIONS FOR PLANT FACILITIES UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 2.5-17 PLAN OF EXCAVATION AND BACKFILL UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 2.5-18 SECTION A-A EXCAVATION AND BACKFILL UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 2.5-19 SOIL MODULE OF ELASTICITY AND POISSON'S RATIO UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 2.5-20 SMOOTH RESPONSE ACCELERATION SPECTRA - EARTHQUAKE "B" UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 2.5-21 SMOOTH RESPONSE ACCELERATION SPECTRA - EARTHQUAKE "D" MODIFIEDUNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 2.5-22 POWER PLANT SLOPE PLAN UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 2.5-23 POWER PLANT SLOPE LOG OF BORING 1 UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 2.5-24 POWER PLANT SLOPE LOG OF BORING 2 UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 2.5-25 POWER PLANT SLOPE LOG OF BORING 3 UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 2.5-26 POWER PLANT SLOPE LOG OF TEST PITS 1 & 2 UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 2.5-27 POWER PLANT SLOPE LOG OF TEST PIT 3 UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 2.5-28 POWER PLANT SLOPE SOIL CLASSIFICATION CHART AND KEY TO TEST AREA UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 2.5-29 FREE FIELD SPECTRA HORIZONTAL HOSGRI 7.5M/BLUME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 2.5-30 FREE FIELD SPECTRA HORIZONTAL HOSGRI 7.5M/NEWMARK UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 2.5-31 FREE FIELD SPECTRA VERTICAL HOSGRI 7.5M/BLUME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 2.5-32 FREE FIELD SPECTRA VERTICAL HOSGRI 7.5M/NEWMARK UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE
NOTES: 1. This figure is based on Reference 42, Figure 2.4 FIGURE 2.5-33 FREE FIELD SPECTRUM HORIZONTAL 1991 LTSP (84TH PERCENTILE NON-EXCEEDANCE) AS MODIFIED PER SSER-34UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 21 September 2013
NOTES: 1. This Figure is based on Reference 42, Figure 2.5. FIGURE 2.5-34 FREE FIELD SPECTRUM VERTICAL 1991 LTSP (84TH PERCENTILE NON-EXCEEDANCE) AS MODIFIED PER SSER-34 UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 21 September 2013 NOTES: 1. This Figure is based on Reference 40, Figure 7-2; however, the LTSP response spectrum has been adjusted in accordance with Reference 42, Figure 2.5. 2. This Figure is for comparison purposes only. Do not use for design.
- 3. Legend: 1977 Hosgri (Newmark) corresponds to the spectrum shown in Figure 2.5-30 1991 LTSP corresponds to the spectrum shown in Figure 2.5-33 FIGURE 2.5-35 FREE FIELD SPECTRA HORIZONTAL LTSP (PG&E 1998) GROUND MOTION VS. HOSGRI (NEWMARK 1977)UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 21 September 2013 NOTE: 1. This figure is based on Reference 52, Figure 1-1. Revision 21 September 2013FIGURE 2.5-36 MAP OF SHORELINE FAULT STUDY AREA UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE DCPP UNITS 1 & 2 FSAR UPDATE i Revision 21 September 2013 Chapter 3 DESIGN OF STRUCTURES, COMPONENTS, EQUIPMENT, AND SYSTEMS CONTENTS Section Title Page 3.1 CONFORMANCE WITH AEC GENERAL DESIGN CRITERIA 3.1-1
3.1.1 Single Failure Criteria 3.1-2 3.1.1.1 Definitions 3.1-2 3.1.1.2 Applicability 3.1-3
3.1.2 Overall Plant Requirements 3.1-4 3.1.2.1 Criterion 1, 1967 - Quality Standards (Category A) 3.1-4 3.1.2.2 Criterion 2, 1967 - Performance Standards (Category A) 3.1-4 3.1.2.3 Criterion 3, 1971 - Fire Protection (Category A) 3.1-5 3.1.2.4 Criterion 4, 1967 - Sharing of Systems (Category A) 3.1-6 3.1.2.5 Criterion 5, 1967 - Records Requirements (Category A) 3.1-6
3.1.3 Protection by Multiple Fission Product Barriers 3.1-7 3.1.3.1 Criterion 6, 1967 - Reactor Core Design (Category A) 3.1-7 3.1.3.2 Criterion 7, 1967 - Suppression of Power Oscillations (Category B) 3.1-7 3.1.3.3 Criterion 8, 1967 - Overall Power Coefficient (Category B) 3.1-8 3.1.3.4 Criterion 9, 1967 - Reactor Coolant Pressure Boundary (Category A) 3.1-8 3.1.3.5 Criterion 10, 1967 - Containment (Category A) 3.1-9
3.1.4 Nuclear and Radiation Controls 3.1-9 3.1.4.1 Criterion 11, 1967 - Control Room (Category B) 3.1-9 3.1.4.2 Criterion 12, 1967 - Instrumentation and Control Systems (Category B) 3.1-11 3.1.4.3 Criterion 13, 1967 - Fission Process Monitors and Controls (Category B) 3.1-11 3.1.4.4 Criterion 14, 1967 - Core Protection Systems (Category B) 3.1-12 3.1.4.5 Criterion 15, 1967 - Engineered Safety Features Protection Systems (Category B) 3.1-12 3.1.4.6 Criterion 16, 1967 - Monitoring Reactor Coolant Pressure Boundary (Category B) 3.1-13 3.1.4.7 Criterion 17, 1967 - Monitoring Radioactivity Releases (Category B) 3.1-13 3.1.4.8 Criterion 18, 1967 - Monitoring Fuel and Waste Storage (Category B) 3.1-14 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 CONTENTS (Continued) Section Title Page ii Revision 21 September 2013 3.1.5 Reliability and Testability of Protection Systems 3.1-14 3.1.5.1 Criterion 19, 1967 - Protection Systems Reliability (Category B) 3.1-14 3.1.5.2 Criterion 20, 1967 - Protection Systems Redundancy and Independence (Category B) 3.1-14 3.1.5.3 Criterion 21, 1967 - Single Failure Definition (Category B) 3.1-15 3.1.5.4 Criterion 22, 1967 - Separation of Protection and Control Instrumentation Systems (Category B) 3.1-15 3.1.5.5 Criterion 23, 1967 - Protection Against Multiple Disability of Protection Systems (Category B) 3.1-16 3.1.5.6 Criterion 24, 1967 - Emergency Power for Protection Systems (Category B) 3.1-16 3.1.5.7 Criterion 25, 1967 - Demonstration of Functional Operability of Protection Systems (Category B) 3.1-17 3.1.5.8 Criterion 26, 1967 - Protection Systems Fail-Safe Design (Category B) 3.1-17
3.1.6 Reactivity Control 3.1-17 3.1.6.1 Criterion 27, 1967 - Redundancy of Reactivity Control (Category A) 3.1-18 3.1.6.2 Criterion 28, 1967 - Reactivity Hot Shutdown Capability (Category A) 3.1-18 3.1.6.3 Criterion 29, 1967 - Reactivity Shutdown Capability (Category A) 3.1-18 3.1.6.4 Criterion 30, 1967 - Reactivity Holddown Capability (Category B) 3.1-19 3.1.6.5 Criterion 31, 1967 - Reactivity Control Systems Malfunction (Category B) 3.1-19 3.1.6.6 Criterion 32, 1967 - Maximum Reactivity Worth of Control Rods (Category A) 3.1-20
3.1.7 Reactor Coolant Pressure Boundary 3.1-20 3.1.7.1 Criterion 33, 1967 - Reactor Coolant Pressure Boundary Capability (Category A) 3.1-20 3.1.7.2 Criterion 34, 1967 - Reactor Coolant Pressure Boundary Rapid Propagation Failure Prevention (Category A) 3.1-21 3.1.7.3 Criterion 35, 1967 - Reactor Coolant Pressure Boundary Brittle Fracture Prevention (Category A) 3.1-22 3.1.7.4 Criterion 36, 1967 - Reactor Coolant Pressure Boundary Surveillance (Category A) 3.1-23
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 CONTENTS (Continued) Section Title Page iii Revision 21 September 2013 3.1.8 Engineered Safety Features 3.1-23 3.1.8.1 Criterion 37, 1967 - Engineered Safety Features Basis For Design (Category A) 3.1-24 3.1.8.2 Criterion 38, 1967 - Reliability and Testability of Engineered Safety Features (Category A) 3.1-24 3.1.8.3 Criterion 39, 1967 - Emergency Power for Engineered Safety Features (Category A) 3.1-25 3.1.8.4 Criterion 40, 1967 - Missile Protection (Category A) 3.1-26 3.1.8.5 Criterion 41, 1967 - Engineered Safety Features Performance Capability (Category A) 3.1-27 3.1.8.6 Criterion 42, 1967 - Engineered Safety Features Components Capability (Category A) 3.1-28 3.1.8.7 Criterion 43, 1967 - Accident Aggravation Prevention (Category A) 3.1-28 3.1.8.8 Criterion 44, 1967 - Emergency Core Cooling Systems Capability (Category A) 3.1-29 3.1.8.9 Criterion 45, 1967 - Inspection of Emergency Core Cooling Systems (Category A) 3.1-30 3.1.8.10 Criterion 46, 1967 - Testing of Emergency Core Cooling System Components (Category A) 3.1-31 3.1.8.11 Criterion 47, 1967 - Testing of Emergency Core Cooling Systems (Category A) 3.1-31 3.1.8.12 Criterion 48, 1967 - Testing of Operational Sequence of Emergency Core Cooling Systems (Category A) 3.1-32 3.1.8.13 Criterion 49, 1967 - Containment Design Basis (Category A) 3.1-32 3.1.8.14 Criterion 50, 1967 - NDT Requirement for Containment Material (Category A) 3.1-33 3.1.8.15 Criterion 51, 1967 - Reactor Coolant Pressure Boundary Outside Containment (Category A) 3.1-34 3.1.8.16 Criterion 52, 1967 - Containment Heat Removal Systems (Category A) 3.1-34 3.1.8.17 Criterion 53, 1967 - Containment Isolation Valves (Category A) 3.1-35 3.1.8.18 Criterion 54, 1967 - Containment Leakage Rate Testing (Category A) 3.1-38 3.1.8.19 Criterion 55, 1967 - Containment Periodic Leakage Rate Testing (Category A) 3.1-38 3.1.8.20 Criterion 56, 1967 - Provisions for Testing of Penetrations (Category A) 3.1-39 3.1.8.21 Criterion 57, 1967 - Provisions for Testing of Isolation Valves (Category A) 3.1-39 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 CONTENTS (Continued) Section Title Page iv Revision 21 September 2013 3.1.8.22 Criterion 58, 1967 - Inspection of Containment Pressure- Reducing Systems (Category A) 3.1-39 3.1.8.23 Criterion 59, 1967 - Testing of Containment Pressure-Reducing Systems Components (Category A) 3.1-40 3.1.8.24 Criterion 60, 1967 - Testing of Containment Spray Systems (Category A) 3.1-40 3.1.8.25 Criterion 61, 1967 - Testing of Operational Sequence of Containment Pressure-Reducing Systems (Category A) 3.1-41 3.1.8.26 Criterion 62, 1967 - Inspection of Air Cleanup Systems (Category A) 3.1-41 3.1.8.27 Criterion 63, 1967 - Testing of Air Cleanup Systems Components (Category A) 3.1-41 3.1.8.28 Criterion 64, 1967 - Testing Air Cleanup Systems (Category A) 3.1-42 3.1.8.29 Criterion 65, 1967 - Testing of Operational Sequence of Air Cleanup Systems (Category A) 3.1-42
3.1.9 Fuel and Waste Storage Systems 3.1-42 3.1.9.1 Criterion 66, 1967 - Prevention of Fuel Storage Criticality (Category B) 3.1-42 3.9.1.2 Criterion 67, 1967 - Fuel and Waste Storage Decay Heat (Category B) 3.1-43 3.1.9.3 Criterion 68, 1967 - Fuel and Waste Storage Radiation Shielding (Category B) 3.1-43 3.1.9.4 Criterion 69, 1967 - Protection Against Radioactivity Release from Spent Fuel and Waste Storage (Category B) 3.1-43
3.1.10 Plant Effluents 3.1-44 3.1.10.1 Criterion 70, 1967 - Control of Releases of Radioactivity to the Environment (Category B) 3.1-44
3.1.11 References 3.1-44
3.2 CLASSIFICATION OF STRUCTURES, SYSTEMS, AND COMPONENTS 3.2-1
3.2.1 Seismic Classification 3.2-1
3.2.2 System Quality Group Classifications 3.2-5 3.2.2.1 Design Class I, Quality/Code Class I Fluid Systems and Fluid System Components 3.2-6 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 CONTENTS (Continued) Section Title Page v Revision 21 September 2013 3.2.2.2 Design Class I, Quality/Code Class II Fluid Systems and Fluid System Components 3.2-6 3.2.2.3 Design Class I, Quality/Code Class III Fluid Systems and Fluid System Components 3.2-7 3.2.2.4 Other Fluid Systems and Fluid System Components 3.2-8 3.2.2.5 Summary of System Quality Group Classifications 3.2-8
3.2.3 References 3.2-9
3.2.4 Reference Drawings 3.2-10
3.3 WIND AND TORNADO LOADINGS 3.3-1
3.3.1 Wind Loadings 3.3-1 3.3.1.1 Containment Structure 3.3-1 3.3.1.2 Other Buildings 3.3-1
3.3.2 Tornado Loadings 3.3-3 3.3.2.1 Applicable Design Parameters 3.3-3 3.3.2.2 Determination of Forces on Structures 3.3-6 3.3.2.3 Tornado Analysis 3.3-8 3.3.2.4 Supplementary Analysis of Additional Tornado Missiles: Estimated Maximum Missile Velocity, Required Barrier Thickness 3.3-26
3.3.3 References 3.3-28
3.4 WATER LEVEL (FLOOD) DESIGN 3.4-1
3.4.1 Flood Elevations 3.4-1
3.4.2 Phenomena Considered in Design Load Calculations 3.4-1
3.4.3 Flood Force Application 3.4-1
3.4.4 Flood Protection 3.4-1
3.4.5 References 3.4-2
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 CONTENTS (Continued) Section Title Page vi Revision 21 September 2013 3.5 MISSILE PROTECTION 3.5-1 3.5.1 Missile Barriers and Loadings 3.5-1 3.5.1.1 Missiles Generated Within the Containment 3.5-1 3.5.1.2 Missiles Generated Outside the Containment 3.5-2 3.5.1.3 Missiles Generated by Natural Phenomena 3.5-4 3.5.1.4 Site Proximity Missiles 3.5-4
3.5.2 Missile Selection 3.5-4 3.5.2.1 Missiles Postulated Within the Containment Structure 3.5-5 3.5.2.2 Missiles Postulated Outside the Containment 3.5-6
3.5.3 Selected Missiles 3.5-14 3.5.3.1 Typical Characteristics of Missiles Postulated Within the Containment Structure 3.5-14 3.5.3.2 Typical Characteristics of Missiles Postulated Outside the Containment Structure 3.5-14 3.5.4 Barrier Design Procedures 3.5-15 3.5.4.1 Determination of Loadings for Missiles Generated Within the Containment Structure 3.5-15 3.5.4.2 Determination of Loadings for Missiles Generated Outside the Containment Structure 3.5-17
3.5.5 Missile Barrier Features 3.5-17
3.5.6 References 3.5-18
3.5.7 Reference Drawings 3.5-19
3.6 PROTECTION AGAINST DYNAMIC EFFECTS ASSOCIATED WITH THE POSTULATED RUPTURE OF PIPING 3.6-1
3.6.1 Systems in Which Design Basis Piping Breaks Occur 3.6-1 3.6.1.1 High-Energy Piping Inside Containment 3.6-1 3.6.1.2 High-Energy Piping Outside Containment 3.6-2 3.6.1.3 Moderate-Energy Piping 3.6-3
3.6.2 Design Basis Piping Break Criteria 3.6-4 3.6.2.1 General Criteria 3.6-4 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 CONTENTS (Continued) Section Title Page vii Revision 21 September 2013 3.6.2.2 Specific Criteria 3.6-7 3.6.3 Design Loading Combinations 3.6-10 3.6.3.1 High-Energy Piping Breaks Inside Containment 3.6-10 3.6.3.2 High-Energy Piping Breaks Outside Containment 3.6-11
3.6.4 Dynamic Analyses 3.6-12 3.6.4.1 Reactor Coolant Loop Piping Breaks 3.6-12 3.6.4.2 Other High-Energy Piping Breaks Inside Containment 3.6-15 3.6.4.3 High-Energy Piping Breaks Outside Containment 3.6-16
3.6.5 Protective Measures 3.6-19 3.6.5.1 Piping Breaks 3.6-19 3.6.5.2 Pipe Restraint Design Criteria 3.6-22 3.6.5.3 Protective Provisions for Vital Equipment 3.6-23 3.6.5.4 Pipe Whip Restraints and Spray Barriers 3.6-24 3.6.5.5 Differences Between Unit 1 and Unit 2 Pipe Break Protection Features Outside Containment 3.6-24 3.6.6 References 3.6-25
3.6.7 Reference Drawings 3.6-26
3.7 SEISMIC DESIGN 3.7-1
3.7.1 Seismic Input 3.7-1 3.7.1.1 Design Response Spectra 3.7-1 3.7.1.2 Design Response Spectra Derivation 3.7-2 3.7.1.3 Critical Damping Values 3.7-3 3.7.1.4 Bases for Site-Dependent Analysis 3.7-5 3.7.1.5 Soil-Supported Design Class I Structures 3.7-5 3.7.1.6 Soil-Structure Interaction 3.7-5 3.7.1.7 Hosgri Evaluation 3.7-5
3.7.2 Seismic System Analysis 3.7-5 3.7.2.1 Seismic Analysis Methods 3.7-5 3.7.2.2 Natural Frequencies and Response Loads 3.7-18 3.7.2.3 Procedures Used to Lump Masses 3.7-22 3.7.2.4 Rocking and Translational Response Summary 3.7-23 3.7.2.5 Methods Used to Couple Soil with Seismic-System Structures 3.7-23 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 CONTENTS (Continued) Section Title Page viii Revision 21 September 2013 3.7.2.6 Development of Floor Response Spectra 3.7-23 3.7.2.7 Differential Seismic Movement of Interconnected Components 3.7-23 3.7.2.8 Effects of Variations on Floor Response Spectra 3.7-23 3.7.2.9 Use of Constant Vertical Load Factors 3.7-23 3.7.2.10 Method Used to Account for Torsional Effects 3.7-23 3.7.2.11 Comparison of Responses 3.7-24 3.7.2.12 Methods for Seismic Analysis of Dams 3.7-24 3.7.2.13 Methods to Determine Design Class I Structure Overturning Moments 3.7-24 3.7.2.14 Analysis Procedure for Damping 3.7-24 3.7.2.15 Combination of Components of Earthquake Motion for Structures 3.7-25
3.7.3 Seismic Subsystem Analysis 3.7-25 3.7.3.1 Determination of Number of Earthquake Cycles 3.7-25 3.7.3.2 Basis for Selection of Forcing Frequencies 3.7-25 3.7.3.3 Procedure for Combining Modal Responses 3.7-26 3.7.3.4 Root Mean Square Basis 3.7-26 3.7.3.5 Design Criteria and Analytical Procedures for Piping 3.7-26 3.7.3.6 Basis for Computing Combined Response 3.7-29 3.7.3.7 Amplified Seismic Responses 3.7-29 3.7.3.8 Use of Simplified Dynamic Analysis 3.7-30 3.7.3.9 Modal Period Variation 3.7-30 3.7.3.10 Torsional Effects of Eccentric Masses 3.7-30 3.7.3.11 Piping Outside Containment Structure 3.7-30 3.7.3.12 Interaction of Other Piping with Design Class I Piping 3.7-31 3.7.3.13 System Interaction Program 3.7-31 3.7.3.14 Field Location of Supports and Restraints 3.7-31 3.7.3.15 Seismic Analyses for Fuel Elements, Control Rod Assemblies, and Control Rod Drives 3.7-32 3.7.4 Seismic Instrumentation Program 3.7-37 3.7.4.1 Comparison with NRC Regulatory Guide 1.12 3.7-37 3.7.4.2 Location and Description of Instrumentation 3.7-37 3.7.4.3 Control Room Operator Notification 3.7-37 3.7.4.4 Comparison of Measured and Predicted Responses 3.7-37
3.7.5 Seismic Design Control 3.7-38 3.7.5.1 Equipment Purchased Directly by PG&E 3.7-38 3.7.5.2 Equipment Supplied by Westinghouse 3.7-38 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 CONTENTS (Continued) Section Title Page ix Revision 21 September 2013 3.7.6 Seismic Evaluation to Demonstrate Compliance with the Hosgri Earthquake Requirements Utilizing a Dedicated Shutdown Flowpath 3.7-39 3.7.6.1 Post-Hosgri Shutdown Requirements and Assumed Conditions 3.7-39 3.7.6.2 Post-Hosgri Safe Shutdown Flowpath 3.7-39
3.7.7 References 3.7-41
3.8 DESIGN OF DESIGN CLASS I STRUCTURES 3.8-1
3.8.1 Containment Structure 3.8-1 3.8.1.1 Description of the Containment 3.8-1 3.8.1.2 Applicable Codes, Standards, and Specifications 3.8-9 3.8.1.3 Loads and Loading Combinations 3.8-12 3.8.1.4 Design and Analysis Procedures 3.8-16 3.8.1.5 Structural Acceptance Criteria 3.8-21 3.8.1.6 Materials, Quality Control, and Special Construction Techniques 3.8-23 3.8.1.7 Testing and Inservice Surveillance Requirements 3.8-36
3.8.2 Other Design Class I Structures (Auxiliary Building) 3.8-39 3.8.2.1 Description of the Auxiliary Building 3.8-39 3.8.2.2 Applicable Codes, Standards, and Specifications 3.8-40 3.8.2.3 Loads and Loading Combinations 3.8-41 3.8.2.4 Design and Analysis Procedures 3.8-45 3.8.2.5 Structural Acceptance Criteria 3.8-46 3.8.2.6 Materials, Quality Control, and Special Construction Techniques 3.8-48
3.8.3 Outdoor Water Storage Tanks 3.8-51 3.8.3.1 Description of the Outdoor Water Storage Tanks 3.8-51 3.8.3.2 Applicable Codes, Standards, and Specifications 3.8-51 3.8.3.3 Loads and Loading Combinations 3.8-52 3.8.3.4 Design and Analysis Procedures 3.8-53 3.8.3.5 Structural Acceptance Criteria 3.8-53 3.8.3.6 Materials, Quality Control, and Special Construction Techniques 3.8-54
3.8.4 Foundations and Concrete Supports 3.8-54 3.8.4.1 Foundations for Design Class I Tanks 3.8-55 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 CONTENTS (Continued) Section Title Page x Revision 21 September 2013 3.8.4.2 Concrete and Structural Steel Supports 3.8-56 3.8.5 Design Class II Structures Containing Design Class I Equipment 3.8-56 3.8.5.1 Turbine Building 3.8-57 3.8.5.2 Intake Structure 3.8-63
3.8.6 Pipeway Structures 3.8-67 3.8.6.1 Description of Pipeway Structures 3.8-67 3.8.6.2 Applicable Codes, Standards, and Specifications 3.8-68 3.8.6.3 Loads and Loading Combinations 3.8-68 3.8.6.4 Design and Analysis Procedures 3.8-70 3.8.6.5 Structural Acceptance Criteria 3.8-71 3.8.6.6 Materials, Quality Control, and Construction Techniques 3.8-71
3.8.7 Safety-Related Masonry Walls 3.8-72 3.8.7.1 Description of Safety-Related Masonry Walls 3.8-72 3.8.7.2 Applicable Codes, Standards, and Specifications 3.8-72 3.8.7.3 Loads and Loading Combinations 3.8-73 3.8.7.4 Design and Analysis Procedures 3.8-74 3.8.7.5 Structural Acceptance Criteria 3.8-75 3.8.7.6 Materials, Quality Control, and Special Construction Techniques 3.8-75
3.8.8 Permanent Spent Fuel Storage Racks 3.8-76 3.8.8.1 Description of the Spent Fuel Pool and Racks 3.8-76 3.8.8.2 Applicable Codes, Standards, and Specifications 3.8-76 3.8.8.3 Loads and Loading Combinations 3.8-77 3.8.8.4 Design and Analysis of Racks 3.8-77 3.8.8.5 Materials, Quality Control, and Special Construction Techniques 3.8-79 3.8.8.6 Design and Analysis of Pool Structure 3.8-79
3.8.9 References 3.8-79
3.8.10 Reference Drawings 3.8-82
3.9 MECHANICAL SYSTEMS AND COMPONENTS 3.9-1
3.9.1 Dynamic System Analysis and Testing 3.9-1 3.9.1.1 Vibration Operational Test Programs 3.9-1 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 CONTENTS (Continued) Section Title Page xi Revision 21 September 2013 3.9.1.2 Dynamic Testing Procedure 3.9-3 3.9.1.3 Dynamic System Analysis Methods for Reactor Internals 3.9-4 3.9.1.4 Correlation of Test and Analytical Results 3.9-8 3.9.1.5 Analysis Methods Under LOCA Loadings 3.9-12 3.9.1.6 Analytical Methods for ASME Code Class I Components 3.9-12 3.9.1.7 Design and Analysis Details for the Pressurizer Safety and Relief System 3.9-12
3.9.2 ASME Code Class II and III Components 3.9-14 3.9.2.1 Plant Conditions and Design Loading Combinations 3.9-14 3.9.2.2 Design Loading Combinations 3.9-15 3.9.2.3 Design Stress Limits 3.9-15 3.9.2.4 Analytical and Empirical Methods for the Design of Pumps and Valves 3.9-17 3.9.2.5 Design and Installation Criteria, Pressure-Relieving Devices 3.9-19 3.9.2.6 Stress Levels for Design Class I Components and Supports 3.9-19 3.9.2.7 Field Run Piping Systems 3.9-22 3.9.3 Core and Reactor Internals 3.9-23 3.9.3.1 Core and Internals Integrity Analysis (Mechanical Analysis) 3.9-23 3.9.3.2 Faulted Conditions 3.9-25 3.9.3.3 Reactor Internals Response Under LOCA and Seismic Excitations 3.9-25 3.9.3.4 Acceptance Criteria 3.9-31 3.9.3.5 Methods of Analysis 3.9-32 3.9.3.6 Control Rod Drive Mechanisms 3.9-35
3.9.4 Non-Design Class I Components 3.9-35
3.9.5 Miscellaneous Pressurized Gas Containers 3.9-35 3.9.6 References 3.9-35
3.10 SEISMIC DESIGN OF DESIGN CLASS I INSTRUMENTATION, HVAC, AND ELECTRICAL EQUIPMENT 3.10-1
3.10.1 Seismic Design Criteria 3.10-1
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 CONTENTS (Continued) Section Title Page xii Revision 21 September 2013 3.10.2 Seismic Analyses, Testing Procedures, and Restraint Measures 3.10-2 3.10.2.1 Nuclear Reactor Instrumentation and Protection Systems 3.10-2 3.10.2.2 Main Control Board and Console 3.10-9 3.10.2.3 Hot Shutdown Panel 3.10-11 3.10.2.4 Local Instrument Panels 3.10-12 3.10.2.5 Instrument Panels PIA, PIB, and PIC 3.10-13 3.10.2.6 Diesel Generator Excitation Cubicle and Control Cabinet 3.10-14 3.10.2.7 Design Class I AC Electrical Distribution Equipment 3.10-14 3.10.2.8 Design Class I DC Electrical Equipment 3.10-18 3.10.2.9 Main Annunciator 3.10-20 3.10.2.10 Electrical Penetrations 3.10-21 3.10.2.11 Pressure and Differential Pressure Transmitters 3.10-21 3.10.2.12 Raceway Supports 3.10-23 3.10.2.13 Fire Pump Controller 3.10-25 3.10.2.14 Local Starters 3.10-25 3.10.2.15 Ventilation Control Logic and Relay Cabinet 3.10-26 3.10.2.16 Fan Cooler Motors 3.10-26 3.10.2.17 Pump Motors 3.10-27 3.10.2.18 Electric Cables 3.10-28 3.10.2.19 Motor-Operated Valves 3.10-28 3.10.2.20 Control Room Ventilation System 3.10-29 3.10.2.21 Subcooled Margin Monitors 3.10-30 3.10.2.22 Postaccident Monitoring Panels PAM1 and PAM2 3.10-30 3.10.2.23 Pilot Solenoid Valves 3.10-30 3.10.2.24 Process Solenoid Valves 3.10-31 3.10.2.25 Containment Hydrogen Monitoring System 3.10-31 3.10.2.26 Containment Purge Exhaust 3.10-32 3.10.2.27 Limit Switches 3.10-32 3.10.2.28 Containment High-Range Radiation Monitoring System 3.10-32 3.10.2.29 Pressurizer Safety Relief Valve Position Indication 3.10-32 3.10.2.30 Heating, Ventilating, and Air Conditioning Equipment 3.10-33 3.10.2.31 Electric Hydrogen Recombiner System 3.10-35 3.10.2.32 Reactor Vessel Level Instrumentation System 3.10-35 3.10.2.33 Incore Flux Mapping Cabinets and Transfer Device 3.10-37
3.10.3 References 3.10-37
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 CONTENTS (Continued) Section Title Page xiii Revision 21 September 2013 3.11 ENVIRONMENTAL DESIGN OF MECHANICAL AND ELECTRICAL EQUIPMENT 3.11-1
3.11.1 Equipment Identification 3.11-4 3.11.1.1 Bounding List Development 3.11-5 3.11.1.2 Exemptions 3.11-6 3.11.1.3 Cable and Terminations 3.11-6 3.11.1.4 Class 1E Electrical Equipment Qualification List Maintenance 3.11-7
3.11.2 Qualification Tests and Analyses 3.11-8 3.11.2.1 Accident Environments 3.11-8 3.11.2.2 Normal Environments 3.11-8 3.11.2.3 NUREG-0588 Category II Qualification 3.11-9 3.11.2.4 NUREG-0588 Category I Qualification 3.11-9
3.11.3 Qualification Test Results 3.11-10 3.11.4 Loss of Ventilation 3.11-10 3.11.5 References 3.11-10
DCPP UNITS 1 & 2 FSAR UPDATE xiv Revision 21 September 2013 Chapter 3 TABLES Table Title 3.1-1 General Design Criteria Applicability
3.1-2 Matrix of 1971 GDCs to 1967 GDCs
3.2-1 Design Classification of Structures, Systems, and Components
3.2-2 Design and Quality Group Classifications
3.2-3 Deleted in Revision 11
3.3-1 Comparison of Auxiliary Building Wind Pressure Values, Uniform Building Code, and ASCE Paper 3269 3.3-2 Tornado Resisting Capability of Structures, Systems and Components
3.3-3 Tornado Failure Analysis - Component Cooling Water Surge Tank and Related Instrumentation 3.3-4 Tornado Review - Failure Analysis for Exposed Raceways and Instrumentation 3.3-5 Summary of the Velocity Characteristics of Hypothetical Tornado-Borne Missiles for 250 MPH Tornado Wind Velocity 3.3-6 Required Thickness of a Reinforced Concrete Missile Barrier to Preclude Missile Perforation or the Creation of Secondary Missiles 3.5-1 Deleted in Revision 20
3.5-2 Control Rod Drive Shaft - Missile Characteristics
3.5-3 Control Rod Drive Shaft and Mechanism - Missile Characteristics
3.5-4 Valve - Missile Characteristics
3.5-5 Piping Temperature Element Assembly - Missile Characteristics
3.5-6 Characteristics of Other Missiles Postulated Within Reactor Containment
3.5-7 Building Design Data Used in Turbine Missile Impact Analysis DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 TABLES (Continued) Table Title xv Revision 21 September 2013 3.5-8 Industry Turbine Valve Failure Rates 3.6-1 Checklist of Dynamic Effects from Postulated Rupture of Pipe Connected to the Reactor Coolant System 3.6-2 Checklist of Dynamic Effects of Other Postulated Pipe Ruptures Inside the Containment 3.6-3 Deleted in Revision 16
3.6-4 Deleted in Revision 10
3.6-5 Deleted in Revision 16
3.6-6 Pipe Break Protection Features on Unit 2 Different from Unit 1
3.7-1 Containment and Auxiliary Building Criteria Comparison 3.7-1A Turbine Building Criteria Comparison 3.7-1B Intake Structure Criteria Comparison
3.7-1C Outdoor Storage Tanks Criteria Comparison
3.7-2 Containment Structure, Periods of Vibration
3.7-3 Containment Structure, Maximum Absolute Accelerations
3.7-4 Containment Structure, Maximum Displacements
3.7-5 Containment Structure, Maximum Shell Forces and Moments - DE Analysis 3.7-6 Containment Structure, Maximum Shell Forces and Moments - DDE Analysis 3.7-7 Containment Structure, Maximum Total Shears
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 TABLES (Continued) Table Title xvi Revision 21 September 2013 3.7-8 Containment Structure, Maximum Total Overturning Moments 3.7-8A Periods of Vibration and Percent Participation Factors
3.7-8B Containment Exterior Structure, Maximum Horizontal and Vertical Accelerations 3.7-8C Containment Exterior Structure, Maximum Horizontal and Vertical Displacements 3.7-8D Containment Exterior Structure, Maximum Shell Forces and Moments
3.7-8E Containment Exterior Structure, Maximum Total Shears and Maximum Overturning Moments 3.7-8F Containment Exterior Structure, Maximum Total Torsional Moments and Axial Forces 3.7-8G Containment Interior Structure, Maximum Absolute Horizontal Accelerations and Displacements 3.7-8H Containment Interior Structure, Maximum Total Shears, Overturning Moments, and Torsional Moments 3.7-8I Vertical Dynamic Analysis - Frame No. 6, Unit 1
3.7-8J Vertical Dynamic Analysis - Annulus Frame No. 6, Summary of Modal Participation Factors 3.7-8K Containment Annulus Structures, Units 1 and 2, Natural Frequencies for Horizontal Seismic Ground Motion 3.7-8L Polar Gantry Crane Maximum Displacements, Hosgri
3.7-8M Polar Gantry Crane Maximum Forces, Hosgri-Unloaded Condition
3.7-8N Polar Gantry Crane Maximum Forces, Hosgri-Loaded Condition
3.7-8O Fuel Handling Crane Support Structure, Maximum Absolute Accelerations DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 TABLES (Continued) Table Title xvii Revision 21 September 2013 3.7-8P Fuel Handling Crane Support Structure, Maximum Relative Displacements 3.7-9 Auxiliary Building, Periods of Vibration - DE Analysis 3.7-10 Auxiliary Building Horizontal Model Periods and Participation Factors - HE Analysis 3.7-11 Auxiliary Building Vertical Model Periods and Participation Factors - HE Analysis 3.7-11A Fuel Handling Crane Support Structure, Horizontal Model Frequencies of Vibration - DE, DDE, and HE Analysis 3.7-11B Fuel Handling Crane Support Structure, Vertical Model Frequencies of Vibration - DE, DDE, and HE Analysis 3.7-12 Auxiliary Building, Maximum Absolute Accelerations - DE Analysis 3.7-13 Auxiliary Building, Maximum Relative Displacements - DE Analysis 3.7-14 Auxiliary Building, Maximum Story Shears - DE Analysis
3.7-15 Auxiliary Building Maximum Overturning Moments - DE Analysis
3.7-16 Auxiliary Building Maximum Torsional Moments - DE Analysis
3.7-17 Auxiliary Building Maximum Absolute Accelerations - HE Analysis
3.7-18 Auxiliary Building Maximum Absolute Accelerations - HE Analysis
3.7-19 Auxiliary Building Maximum Relative Displacement - HE Analysis
3.7-20 Auxiliary Building Maximum Relative Displacement - HE Analysis
3.7-21 Auxiliary Building Maximum Story Shears - HE Analysis
3.7-22 Auxiliary Building Maximum Overturning Moments - HE Analysis
3.7-23 Auxiliary Building Maximum Torsional Moments - HE Analysis
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 TABLES (Continued) Table Title xviii Revision 21 September 2013 3.7-23A Turbine Building Horizontal Model, Frequencies of Vibration, HE Analysis 3.7-23B Turbine Building Vertical Model, Frequencies of Vibration, HE Analysis
3.7-23C Turbine Building Horizontal Model, Maximum Absolute Accelerations, HE Analysis 3.7-23D Turbine Building Horizontal Model, Maximum Relative Displacements, HE Analysis 3.7-23E Turbine Pedestal Model, Frequencies of Vibration, HE Analysis
3.7-23F Turbine Pedestal Model, Maximum Relative Displacements, HE Analysis
3.7-23G Intake Structure Significant Periods of Vibration and Percent Participation Factors 3.7-23H Intake Structure Maximum Relative Displacement and Maximum Absolute Accelerations (Hosgri) 3.7-23I Outdoor Water Storage Tanks, Summary of Significant Periods and Percent Participation Factors, Refueling Water Storage Tank 3.7-23J Outdoor Water Storage Tanks, Summary of Significant Periods and Percent Participation Factors, Firewater and Transfer Tank 3.7-24 Fundamental Mode Frequency Range for RCL Primary Equipment
3.8-1 Testing of Reinforcing Bars for Design Class I Concrete Structures - Comparison of Program Used on Diablo Canyon Power Plant with Regulatory Guide 1.15 3.8-2 Mechanical (Cadweld) Splices in Reinforcing Bars of Concrete Containments - Comparison of Program Used on Diablo Canyon Power Plant with Safety Guide 10 3.8-3 Nondestructive Examination of Primary Containment Liner Welds - Comparison of Program Used on Diablo Canyon Power Plant with Safety Guide 19 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 TABLES (Continued) Table Title xix Revision 21 September 2013 3.8-4 Containment Building Base Slab Stress Ratios 3.8-5 Containment Building Internal Structure Stress Ratios
3.8-5A Containment Building Pipeway Structure Stress Ratios
3.8-5B Containment and Auxiliary Buildings Comparison of Displacements and Separations 3.8-6 Verification of Computer Programs
3.8-6A Average Concrete Strength Containment and Interior Structure
3.8-6B Steel Strength Data Containment and Interior Structure
3.8-7 Fuel Handling Crane Support Structure Stress Ratios
3.8-8 Auxiliary Building Slabs Stress Ratios - DE 3.8-9 Auxiliary Building Slabs Stress Ratios - DDE
3.8-10 Auxiliary Building Slabs Stress Ratios - HE
3.8-11 Auxiliary Building Slabs Stress Ratios - DE
3.8-12 Auxiliary Building Slabs Stress Ratios - DDE
3.8-13 Auxiliary Building Slabs Stress Ratios - HE
3.8-14 Auxiliary Building N-S Concrete Walls Stress Ratios - DE
3.8-15 Auxiliary Building N-S Concrete Walls Stress Ratios - DDE
3.8-16 Auxiliary Building N-S Concrete Walls Stress Ratios - HE
3.8-17 Auxiliary Building Columns Stress Ratios
3.8-18 Auxiliary Building Shear Dissipation to Foundation - DE, N-S
3.8-19 Auxiliary Building Shear Dissipation to Foundation - DE, E-W
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 TABLES (Continued) Table Title xx Revision 21 September 2013 3.8-20 Auxiliary Building Shear Dissipation to Foundation - DDE, N-S 3.8-21 Auxiliary Building Shear Dissipation to Foundation - DDE, E-W
3.8-22 Auxiliary Building Shear Dissipation to Foundation - HE, N-S
3.8-23 Auxiliary Building Shear Dissipation to Foundation - HE, E-W
3.8-23A Auxiliary and Turbine Buildings Comparison of Displacements and Separations 3.8-24 Ductility
3.8-25 Refueling Water Storage Tank Stress Ratios
3.8-26 Turbine Building Structural Steel Members Stress Ratios
3.8-27 Turbine Building Concrete Members Stress Ratios 3.8-27A Turbine Building and Turbine Pedestal (Unit 1) Comparison of Displacements and Separations at El 140 ft 3.8-28 Capabilities and Ductilities of Flow Straighteners
3.8-29 Deleted in Revision 10
3.9-1 Load Combinations and Acceptance Criteria for Pressurizer Safety and Relief Valve Piping 3.9-2 Hosgri and DDE Seismic Loading Combinations and Structural Criteria
3.9-3 Hosgri and DDE Loading Combinations and Structural Criteria
3.9-4 DE Seismic Loading Combinations and Structural Criteria
3.9-5 DE Seismic Loading Combinations and Structural Criteria
3.9-6 Normal Conditions Loading Combinations and Structural Criteria
3.9-7 Normal Conditions Loading Combinations and Structural Criteria
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 TABLES (Continued) Table Title xxi Revision 21 September 2013 3.9-8 Tank Design 3.9-9 List of Active Valves
3.9-10 Maximum Deflections Allowed for Reactor Internal Support Structures
3.9-11 Pressurized Gas Containers (Above 100 psig)
3.9-12 Mechanical Equipment Seismic Qualification Results
3.10-1 Westinghouse Supplied Class IE Instrumentation and Electrical Equipment Seismic Capabilities 3.10-2 Equipment Seismic Qualification Results: Electrical, Instrumentation, and Controls 3.10-3 HVAC Equipment Seismic Qualification Results 3.11-1 Deleted in Revision 7 3.11-2 Deleted in Revision 7
3.11-3 Deleted in Revision 4
3.11-4 Deleted in Revision 7
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 FIGURES Figure Title xxii Revision 21 September 2013 3.2-1(a) Piping Schematic Legend 3.2-2(a) Piping Schematic - Condensate System 3.2-3(a) Piping Schematic - Feedwater System 3.2-4(a) Piping Schematic - Turbine Steam Supply System 3.2-5(a) Piping Schematic - Extraction Steam and Heater Drip System 3.2-6(a) Piping Schematic - Auxiliary Steam 3.2-7(a) Piping Schematic - Reactor Coolant System 3.2-8(a) Piping Schematic - Chemical and Volume Control System 3.2-9(a) Piping Schematic - Safety Injection System 3.2-10(a) Piping Schematic - Residual Heat Removal System 3.2-11(a) Piping Schematic - Nuclear Steam Supply Sampling System 3.2-12(a) Piping Schematic - Containment Spray System 3.2-13(a) Piping Schematic - Spent Fuel Pool Cooling System 3.2-14(a) Piping Schematic - Component Cooling Water System 3.2-15(a) Piping Schematic - Service Cooling Water System 3.2-16(a) Piping Schematic - Makeup Water System 3.2-17(a) Piping Schematic - Saltwater Systems 3.2-18(a) Piping Schematic - Fire Protection Systems 3.2-19(a) Piping Schematic - Liquid Radwaste System 3.2-20(a) Piping Schematic - Lube Oil Distribution and Purification
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 FIGURES (Continued) Figure Title xxiii Revision 21 September 2013 3.2-21(a) Piping Schematic - Diesel Engine-Generator Systems 3.2-22(a) Piping Schematic - Turbine and Generator-Associated Systems 3.2-23(a) Piping Schematic - Ventilation and Air Conditioning Systems 3.2-24(a) Piping Schematic - Gaseous Radwaste System 3.2-25(a) Piping Schematic - Compressed Air System 3.2-26(a) Piping Schematic - Nitrogen and Hydrogen System 3.2-27(a) Piping Schematic - Oily Water Separator and Turbine Building Sump System 3.3-1 Turbine Building Framing Modifications for Tornado Resistance - Elevation 3.3-2 Turbine Building Framing Modifications for Tornado Resistance - Section 3.3-3 Layout of Vulnerable Main Steam Relief Valves and Cable Trays Outside of Plant 3.3-4 Schematic Layout of Cable Spreading and Switchgear Rooms in Turbine Building (2 Sheets) 3.5-1 Integrated Head Assembly, Reactor Missile Shield
3.5-1A Deleted in Revision 20
3.5-2 Containment Structure, Pressurizer Missile Shield
3.5-3 Deleted in Revision 3
3.5-4 Deleted in Revision 3
3.5-5 Deleted in Revision 11A
3.5-6(a) Auxiliary Feedwater Pump Turbine Missile Shield DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 FIGURES (Continued) Figure Title xxiv Revision 21 September 2013 3.6-1 Loss-of-Coolant Accident Boundary Limits 3.6-2(a) Containment Structure Pipe Rupture Restraints 3.6-3 Typical Pipe Rupture Restraint
3.6-3A Pipe Rupture Restraint Typical Rod Arrangement
3.6-3B Pipe Rupture Restraint Typical U-Bolt
3.6-3C Pipe Rupture Restraint Crushable Bumper Arrangement
3.6-4 Primary Coolant Loop Breaks
3.6-5(a) HELB Compartment Pressurization Study El. 85 ft Turbine Building 3.6-6(a) HELB Compartment Pressurization Study El. 104 ft Turbine Building 3.6-7(a) HELB Compartment Pressurization Study El. 119 ft Turbine Building 3.6-8(a) HELB Compartment Pressurization Study El. 140 ft Turbine Building 3.6-9(a) HELB Compartment Pressurization Study El. 60 ft Auxiliary and Containment Building 3.6-10(a) HELB Compartment Pressurization Study El. 73 ft Auxiliary and Containment Building 3.6-11(a) HELB Compartment Pressurization Study El. 85 ft Auxiliary and Containment Building 3.6-12(a) HELB Compartment Pressurization Study El. 91 and 100 ft Auxiliary, Containment and Fuel Handling Bldg. 3.6-13(a) HELB Compartment Pressurization Study El 115 ft Auxiliary, Containment and Fuel Handling Bldg 3.6-14(a) HELB Compartment Pressurization Study El 140 ft Auxiliary, Containment and Fuel Handling Bldg 3.6-15(a) HELB Compartment Pressurization Study Section A-A Auxiliary Bldg. DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 FIGURES (Continued) Figure Title xxv Revision 21 September 2013 3.6-16 Turbine Bldg. Pressure vs. Time Response MSLB at El 140 ft 3.6-17 Turbine Bldg. Pressure vs. Time Response MSLB at El 85 ft
3.6-18 Area GE/GW Pressure vs. Time Response MSLB at El 115 ft
3.6-19 Area GE/GW Pipeway Pressure vs. Time Response MSLB at G-row Anchor 3.6-20 Area H, K Pressure vs. Time Response CVCS Letdown Line El 85 ft
3.6-21 Area H, K Pressure vs. Time Response CVCS Letdown Line El 85 ft
3.6-22 Area H, K Pressure vs. Time Response CVCS Letdown Line El 85 ft
3.6-23 Area H, K Pressure vs. Time Response Aux. Steam Line K, El 100 ft
3.6-24 Area J Pressure vs. Time Response Aux. Steam Line in Turbine Driven Aux. FW Pump Room 3.6-25 Area J Pressure vs. Time Response Aux. Steam Line in Motor Drive Aux. FW Pump Room 3.6-26 Area L Pressure vs. Time Response Aux. FW Pump Steam Supply El 115 ft 3.6-27 Deleted in Revision 11
3.6-28 Turbine Bldg. Temperature vs. Time Response MSLB at El 85 ft
3.6-29 Turbine Bldg. Temperature vs. Time Response MSLB at El 85 ft
3.6-30 Turbine Bldg. Long Term Temperature vs. Time Response
3.6-31 Area GE/GW Temperature vs. Time Response MSLB at El 115 ft
3.6-32 Area GE/GW Temperature vs. Time Response MSLB at El 115 ft
3.6-33 Area GE/GW Long Term Temperature vs. Time Response
3.6-33A Deleted in Revision 19 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 FIGURES (Continued) Figure Title xxvi Revision 21 September 2013 3.6-33B Deleted in Revision 19 3.6-34 Area H, K Temperature vs. Time Response CVCS Letdown Line El 85 ft
3.6-35 Area H, K Temperature vs. Time Response CVCS Letdown Line El 85 ft
3.6-36 Area H, K Temperature vs. Time Response CVCS Letdown Line El 85 ft
3.6-37 Area H, K Temperature vs. Time Response Aux. Steam Line El 100 ft
3.6-38 Area H, K Long Term Temperature vs. Time Response CVCS Letdown Line El 85 ft 3.6-39 Area H, K Long Term Temperature vs. Time Response Aux. Steam Line El 100 ft 3.6-40 Area J Temperature vs. Time Response Aux. Steam Line in Turbine Driven Aux. FW Pump Room 3.6-41 Area J Temperature vs. Time Response Aux. Steam Line in Turbine Driven Aux. FW Pump Room 3.6-42 Area J Long Term Temperature vs. Time Response
3.6-43 Area L Temperature vs. Time Response Aux. FW Pump Steam Supply Line at El 115 ft 3.6-44 Area L Long Term Temperature vs. Time Response Aux. FW Pump Steam Supply Line at El 115 ft 3.7-1 Free Field Ground Motion, DE Analysis
3.7-2 Free Field Ground Motion, DDE Analysis
3.7-3 Comparison of Spectra, 2% Damping Ratio
3.7-4 Comparison of Spectra, 5% Damping Ratio
3.7-4A Containment and Intake Structure, Design Response Spectra, Horizontal Hosgri 7.5M/Blume DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 FIGURES (Continued) Figure Title xxvii Revision 21 September 2013 3.7-4B Auxiliary Building Design Response Spectra, Horizontal Hosgri 7.5M/Blume 3.7-4C Turbine Building Design Response Spectra, Horizontal Hosgri 7.5M Blume 3.7-4D Containment and Intake Structure, Design Response Spectra, Horizontal Hosgri 7.5M/Newmark 3.7-4E Auxiliary Building Design Response Spectra, Horizontal Hosgri 7.5M/Newmark 3.7-4F Turbine Building Design Response Spectra, Horizontal Hosgri 7.5M/Newmark 3.7-4G Containment and Intake Structure Horizontal Time-History Hosgri 7.5M/Blume 3.7-4H Auxiliary Building Horizontal Time-History Hosgri 7.5M/Blume 3.7-4I Turbine Building Horizontal Time-History Hosgri 7.5M/Blume
3.7-4J Containment and Intake Structures Horizontal Time-History Hosgri 7.5M/Newmark 3.7-4K Auxiliary Building Horizontal Time-History Hosgri 7.5M/Newmark
3.7-4L Turbine Building Horizontal Time-History Hosgri 7.5M/Newmark
3.7-4M Vertical Time-History Hosgri 7.5M/Newmark
3.7-4N Containment and Intake Structure Comparison of Spectra, Blume
3.7-4O Auxiliary Building, Comparison of Spectra, Blume
3.7-4P Turbine Building, Comparison of Spectra, Blume
3.7-4Q Containment and Intake Structure, Comparison of Spectra, Newmark
3.7-4R Auxiliary Building, Comparison of Spectra, Newmark
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 FIGURES (Continued) Figure Title xxviii Revision 21 September 2013 3.7-4S Comparison of Spectra, Vertical Newmark 3.7-4T Turbine Building, Comparison of Spectra, Newmark
3.7-5 Containment Structure, Finite Element Model
3.7-5A Containment Structure, Finite Element Model
3.7-5B Containment Exterior Structure, Mathematical Model
3.7-5C Containment Interior Structure Mathematical Model
3.7-5D Containment Interior Structure, Vertical Mathematical Model
3.7-5E Frame Analysis for Vertical Response
3.7-6 Containment Structure, Mode Shapes 3.7-7 Containment Structure, Shell Forces and Moments 3.7-7A Polar Crane Three-Dimensional Nonlinear Model
3.7-8 Containment Structure, Typical Spectra
3.7-9 Containment Structure, Typical Spectra
3.7-10 Containment Structure, Typical Spectra
3.7-11 Containment Structure, Typical Spectra
3.7-12 Containment Structure, Typical Spectra
3.7-12A Exterior Structure Horizontal Response Spectra Hosgri 7.5M/Newmark
3.7-12B Exterior Structure Horizontal Response Spectra Hosgri 7.5M/Newmark
3.7-12C Exterior Structure Vertical Response Spectra Hosgri 7.5M/Blume
3.7-12D Exterior Structure Vertical Response Spectra Hosgri 7.5M/Newmark
3.7-12E Interior Structure Horizontal Response Spectra Hosgri 7.5M/Blume DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 FIGURES (Continued) Figure Title xxix Revision 21 September 2013 3.7-12F Interior Structure Torsional Response Spectra Hosgri 7.5M/Newmark 3.7-12G Interior Concrete Structure Vertical Response Spectra Hosgri 7.5M/Newmark 3.7-12H Containment Annulus Structure - Unit 1
3.7-12I Containment Annulus Structure - Unit 2
3.7-12J Containment Annulus Vertical Response Spectra Hosgri 7.5M/Newmark
3.7-12K Containment Annulus Vertical Response Spectra Hosgri 7.5M/Newmark
3.7-12L Polar Crane Hosgri Horizontal Spectrum
3.7-12M Polar Crane DDE Horizontal Spectrum
3.7-12N Pipeway Structure Response Spectra Hosgri 7.5M/Blume 3.7-12O Pipeway Structure Response Spectra Hosgri 7.5M/Blume
3.7-12P Pipeway Structure Response Spectra Hosgri 7.5M/Blume
3.7-12Q Pipeway Structure Response Spectra Hosgri 7.5M/Blume
3.7-12R Pipeway Structure Response Spectra Hosgri 7.5M/Blume
3.7-12S Pipeway Structure Response Spectra Hosgri 7.5M/Blume
3.7-13 Auxiliary Building, Mathematical Model
3.7-13A Auxiliary Building, Flexible Slab Model
3.7-13B Auxiliary Building, Fuel Handling Crane Support Structure Model
3.7-14 Outdoor Water Storage Tanks: Refueling Water Tank, Axisymmetric Model 3.7-15 Outdoor Water Storage Tanks: Fire Water and Transfer Tank, Axisymmetric Model DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 FIGURES (Continued) Figure Title xxx Revision 21 September 2013 3.7-15A Outdoor Water Storage Tanks: Refueling Water Tank 3.7-15B Half Tank Computer Model
3.7-15C Turbine Building Unit 1 Portion, Horizontal Model
3.7-15D Turbine Building Unit 1 Portion, Horizontal Model
3.7-15E Turbine Building Vertical Model Plan El 140 ft
3.7-15F Turbine Building Vertical Model El Line 3.5
3.7-15G Turbine Pedestal Seismic Analysis Model
3.7-15H Intake Structure Top Deck Mathematical Model
3.7-15I Intake Structure Transverse Section AA Mathematical Model 3.7-16 Auxiliary Building, Horizontal Spectra 3.7-17 Auxiliary Building, Horizontal Spectra
3.7-18 Auxiliary Building, Torsional Spectra
3.7-19 Auxiliary Building, Torsional Spectra
3.7-20 Auxiliary Building, Horizontal Spectra
3.7-21 Auxiliary Building, Horizontal Spectra
3.7-21A Auxiliary Building E-W Hosgri Horizontal Spectra
3.7-21B Auxiliary Building E-W Hosgri Horizontal Spectra
3.7-21C Auxiliary Building E-W Hosgri Torsional Spectra
3.7-21D Auxiliary Building E-W Hosgri Torsional Spectra
3.7-21E Auxiliary Building Hosgri Vertical Spectra
3.7-21F Auxiliary Building Hosgri Vertical Spectra DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 FIGURES (Continued) Figure Title xxxi Revision 21 September 2013 3.7-21G Auxiliary Building Hosgri Vertical Spectra 3.7-21H Auxiliary Building N-S Hosgri Torsional Spectra
3.7-21I Auxiliary Building N-S Hosgri Torsional Spectra
3.7-22 Auxiliary Building Horizontal Spectra
3.7-23 Auxiliary Building Horizontal Spectra
3.7-24 Auxiliary Building Horizontal Spectra
3.7-25 Auxiliary Building Horizontal Spectra
3.7-25A Turbine Building Hosgri E-W Spectra El 119 ft
3.7-25B Turbine Building Hosgri E-W Spectra El 140 ft 3.7-25C Turbine Building Hosgri E-W Spectra Roof Level 3.7-25D Turbine Building Hosgri N-S Spectra El 119 ft
3.7-25E Turbine Building Hosgri N-S Spectra El 140 ft
3.7-25F Turbine Building Hosgri N-S Spectra Roof Level
3.7-25G Turbine Building Hosgri Vertical Spectra El 119 ft
3.7-25H Turbine Building Hosgri Vertical Spectra El 140 ft
3.7-25I Turbine Building Hosgri Vertical Spectra El 193 ft
3.7-25J Turbine Building DDE E-W Spectra El 104 ft
3.7-25K Turbine Building DDE E-W Spectra El 140 ft
3.7-25L Turbine Building DDE N-S Spectra El 104 and 107 ft
3.7-25M Turbine Building DDE N-S Spectra El 140 ft
3.7-25N Intake Structure Response Spectra Hosgri 7.5M/Blume DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 FIGURES (Continued) Figure Title xxxii Revision 21 September 2013 3.7-25O Intake Structure Response Spectra Hosgri 7.5M/Newmark 3.7-25P Intake Structure Vertical Response Spectra Hosgri 7.5M/Blume/Newmark Envelope 3.7-25Q Intake Structure Response Spectra Hosgri 7.5M/Newmark
3.7-25R Intake Structure Response Spectra Hosgri 7.5M/Newmark
3.7-25S Intake Structure Response Spectra Design Earthquake
3.7-25T Intake Structure Response Spectra Design Earthquake
3.7-26 Typical Piping Mathematical Model
3.7-27 Reactor Internals, Mathematical Model
3.7-27A Reactor Pressure Vessel Shell Submodel 3.7-27AA Deleted in Revision 20
3.7-27B Core Barrel Submodel for Unit 1
3.7-27C Core Barrel Submodel for Unit 2
3.7-27D Internals (Innermost) Submodel
3.7-27DD Deleted in Revision 20
3.7-27E Assembled Finite Element System Model
3.7-27EE Deleted in Revision 20
3.7-27F Schematic Representation of Computer Model Used to Analyze Core Dynamic Response 3.7-28 Reactor Internals, First Mode of Vibration
3.7-29 Derivation of Design Response Spectra for a Typical Piping System
3.8-1 Containment Structure, Reinforcing Steel Arrangement DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 FIGURES (Continued) Figure Title xxxiii Revision 21 September 2013 3.8-2 Containment Structure, Typical Reinforcing Loop 3.8-3 Containment Structure, Dome Spherical Triangle
3.8-4 Containment Structure, Dome and Cylinder Bars
3.8-5 Containment Structure, Liner Stud Arrangement
3.8-6 Containment Structure, Typical Piping Penetration
3.8-7 Containment Structure, Typical Piping Penetration
3.8-8 Deleted in Revision 19
3.8-9 Deleted in Revision 19
3.8-10 Containment Structure, Typical Instrumentation Penetration 3.8-11 Containment Structure, Fuel Transfer Tube Penetration 3.8-12 Containment Structure, Hexagonal Collars
3.8-13 Containment Structure, Access Hatch Sleeves
3.8-14 Containment Structure, Embedded Beams Cylinder-Base Slab Juncture
3.8-15 Containment Structure, Reinforcing Steel Base Slab and Wall
3.8-16(a) Interior Concrete Outline - Plan at El. 119 ft and 140 ft, Containment Structure Areas G and F 3.8-17(a) Interior Concrete Outline Main Sections Containment Structure 3.8-18(a) Interior Concrete Reinforcing Typical Details and Drawing List Containment Structure 3.8-19(a) Interior Concrete Reinforcing Sections and Details Containment Structure 3.8-20(a) Concrete Outline and Reinforcing Annulus Platform at El. 140 ft, Containment Structure Areas F and G DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 FIGURES (Continued) Figure Title xxxiv Revision 21 September 2013 3.8-21 Internal Structure, Annulus Platform - El 101 and 106 ft (2 Sheets) 3.8-22 Internal Structure, Annulus Platform - El 117 and 140 ft (2 Sheets)
3.8-23(a) Containment Structure, Polar Crane 3.8-24 Deleted in Revision 11
3.8-25 Deleted in Revision 11
3.8-26 Deleted in Revision 11
3.8-27 Containment Structure, Membrane Forces Dead Load and Pressure
3.8-28 Containment Structure, Membrane Forces DE and DDE Earthquakes
3.8-29 Containment Structure, Membrane Forces Hosgri Earthquake 3.8-30 Containment Structure, Membrane Forces Accident Condition 1 3.8-31 Containment Structure, Membrane Forces Accident Condition 2
3.8-32 Containment Structure, Membrane Forces Accident Condition 3
3.8-33 Containment Structure, Membrane Forces Accident Condition 4
3.8-34 Containment Structure, Membrane Forces Wind Load
3.8-35 Containment Structure, Equipment Hatch Analytical Model
3.8-36 Deleted in Revision 11
3.8-37 Containment Structure, Exterior Shell Stresses Accident Condition 1
3.8-38 Containment Structure, Exterior Shell Stresses, Accident Condition 2 and 3 3.8-39 Containment Structure, Exterior Shell Stresses, Accident Condition 3
3.8-40 Equipment Hatch Hexagonal Plate Maximum Stresses
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 FIGURES (Continued) Figure Title xxxv Revision 21 September 2013 3.8-41 Equipment Hatch Hoop Reinforcement Stresses 3.8-42 Equipment Hatch Diagonal Reinforcement Stresses
3.8-43 Containment Base Slab Model
3.8-44 Containment Structure, Typical Rebar Strain Gauge
3.8-45(a) Auxiliary Building, Concrete Outline - Plan at El 100 ft Areas H and K 3.8-46(a) Auxiliary Building, Concrete Outline - Plan at El 115 ft Areas J, GE, and GW 3.8-47(a) Auxiliary Building, Concrete Outline - Plans at El 85, 100, 115, and 140 ft - Area L 3.8-48(a) Auxiliary Building, Concrete Outline - Section Areas J and K 3.8-49(a) Auxiliary Building, Concrete Outline - Section Areas H and K 3.8-50(a) Auxiliary Building, Concrete Reinforcing - Plan at El 115 ft - Areas J, GE, and GW 3.8-51(a) Auxiliary Building, Concrete Reinforcing - Plan at El 115 ft - Areas H and K 3.8-52(a) Auxiliary Building, Concrete Reinforcing - Plan at El 115 and 140 ft - Area L 3.8-53(a) Auxiliary Building, Concrete Reinforcing - Miscellaneous Sections - Area K 3.8-54(a) Auxiliary Building, Concrete Reinforcing - Sections Areas H, K, and GE 3.8-55(a) Auxiliary Building, Control Room - Sections 3.8-56(a) Auxiliary Building, Spent Fuel Pool - Concrete Reinforcing 3.8-57(a) Auxiliary Building, Crane Support Structure - Elevations and Details 3.8-58(a) Auxiliary Building, Crane Support Structure - Section and Details DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 FIGURES (Continued) Figure Title xxxvi Revision 21 September 2013 3.8-59(a) Auxiliary Building, Refueling Areas Overhead Crane 3.8-60 Auxiliary Building, Floor Plan El 100 ft
3.8-61 Auxiliary Building, Floor Plan El 115 ft
3.8-62 Auxiliary Building, Floor Plan El 140 ft
3.8-63 Auxiliary Building, Load Dissipation to Foundation, Hosgri N-S
3.8-64 Auxiliary Building, Load Dissipation to Foundation, Hosgri E-W
3.8-65(a) Design Class I Tanks Concrete Foundations 3.8-66 Turbine Building Plan El 85 ft
3.8-67 Turbine Building Plan El 104 ft 3.8-68 Turbine Building Plan El 119 ft 3.8-69 Turbine Building Plan El 140 ft
3.8-70 Turbine Building Plan at Lower Chord of Roof Truss
3.8-71 Turbine Building Typical Section
3.8-72(a) Intake Structure Plan at Top Deck El +17.5 ft 3.8-73(a) Intake Structure Plan at Pump Deck El -2.1 ft 3.8-74(a) Intake Structure Plan at Invert Area El -31.5 ft 3.8-75 Intake Structure Transverse Section A
3.8-76 Intake Structure Transverse Section B
3.8-77 Intake Structure Transverse Section C
3.8-78 Intake Structure Wave Scale Model, Plan - Invert
3.8-79 Intake Structure Wave Scale Model, Transverse Section DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 FIGURES (Continued) Figure Title xxxvii Revision 21 September 2013 3.8-80 Pipeway Structure Layout 3.8-81 Rack Dynamic Model
3.8-82 Multi-Rack Model
3.8-83(a) Safety Related Masonry Walls, Turbine Bldg - Unit 1 3.8-84(a) Safety Related Masonry Walls, Turbine Bldg - Unit 2 3.8-85(a) Safety Related Masonry Walls, Auxiliary Bldg 3.9-1 Vibration Checkout, Functional Test Inspection Data - Unit 1
3.9-2 Vibration Checkout, Functional Test Inspection Data - Unit 2
3.9-3 Thermal Shield, Modal Shape n=4 Obtained from Shaker Test - Unit 1 3.9-4 Thermal Shield, Maximum Amplitude of Vibration During Preoperational Tests - Unit 1 NOTE:
(a) This figure corresponds to a controlled engineering drawing that is incorporated by reference into the FSAR Update. See Table 1.6-1 for the correlation between the FSAR Update figure number and the corresponding controlled engineering drawing number.
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 3 APPENDICES Appendix Title xxxviii Revision 21 September 2013 3.1A AEC GENERAL DESIGN CRITERIA -1971 3.11A Deleted in Revision 7
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-1 Revision 21 September 2013 Chapter 3 DESIGN OF STRUCTURES, COMPONENTS, EQUIPMENT, AND SYSTEMS 3.1 CONFORMANCE WITH AEC GENERAL DESIGN CRITERIA The Diablo Canyon Power Plant (DCPP) units are designed to comply with the Atomic Energy Commission (AEC) (now the Nuclear Regulatory Commission, or NRC) General Design Criteria (GDCs) for Nuclear Power Plant Construction Permits, published in July 1967. Sections 3.1.1 through 3.1.10, therefore, provide a listing of these criteria and a discussion of conformance. The DCPP design basis is the 1967 GDCs. Subsequent commitments to GDCs issued later (e.g., 1971 GDC, and the 1987 revision to GDC 4) are noted in the discussion of the related 1967 GDCs beginning in Section 3.1.2 and as detailed in other FSAR sections specific to systems and detailed analysis.
The GDCs are discussed in Sections. Sections 3.1.2 through 3.1.10 are grouped as presented in the proposed 10 CFR 50 Appendix A 1967 Groups. Note that where later editions of the GDC were implemented in the DCPP licensing basis, they have been incorporated in the Sections 3.1.2 through 3.1.10 related to the 1967 Group. Table 3.1-1, at the end of this section, provides a quick reference to the current license basis applicability of the GDCs. Although regulatory correspondence often refers to the 1971 criteria because NRC review is typically based on the current GDCs at the time, the DCPP licensing basis remains the 1967 GDCs except as follows:
GDC 3, 1971 - Fire Protection GDC 4, 1987 Revision - Environmental and Missile Design Basis (LBB) GDC 17, 1971 - Electric Power Systems GDC 18, 1971 - Inspection and Testing of Electric Power Systems GDC 19, 1971 - Control Room Habitability (Accident Dose) GDC 54, 1971 - Piping Systems Penetrating Containment GDC 55, 1971 - Reactor Coolant Pressure Boundary Penetrating Containment GDC 56, 1971 - Primary Containment Isolation GDC 57, 1971 - Closed System Isolation Valves Table 3.1-2 provides a matrix listing of the 1971 criterion to related 1967 criterion. Submittal of the FSAR using RG 1.70 Rev 1 format and content was expected by the NRC as part of the initial DCPP licensing process, even though the NRC acknowledged in NUREG-0675 (SER-00) that the DCPP design basis was the 1967 GDCs. DCPP included, as part of the original FSAR, Appendix 3.1A, "AEC General Design Criteria - 1971", which was a summary of the extent to which the original DCPP principal design features (the 1967 GDCs plus additional design features) for plant structures, systems and components (SSCs) conformed to the intent of the AEC "General Design Criteria DCPP UNITS 1 & 2 FSAR UPDATE 3.1-2 Revision 21 September 2013 for Nuclear Power Plants" published in February 1971 as Appendix A to 10 CFR Part 50 (i.e., the 1971 GDCs). Appendix 3.1A provides a summary discussion for each criterion of how the DCPP principal design features (the 1967 GDCs plus additional design features) conform to the intent of the 1971 general design criterion. Any exceptions to the 1971 GDCs that DCPP identified and the NRC approved in writing resulting from earlier DCPP design or construction commitments are identified in the discussion of the corresponding criterion in Appendix 3.1A. The summary provided in the original FSAR in Appendix 3.1A was reviewed by the NRC to conclude that DCPP's design conformed to the intent of the 1971 GDCs. The degree to which the DCPP design (the 1967 GDCs plus additional design features) conforms to the intent of the 1971 GDCs, as summarized in Appendix 3.1A, establishes additional DCPP licensing basis which must be reviewed when evaluating facility changes. 3.1.1 SINGLE FAILURE CRITERIA Each of the engineered safety features (ESF) is designed to tolerate a single failure during the period of recovery following an accident without loss of its protective function. This period of recovery consists of two segments: the short-term period and the long-term period. During the short-term period, the single failure is limited to a failure of an active component to complete its function as required. Should the single failure occur during the long-term period rather than the short-term, the related engineered safety system is designed to tolerate an active failure or a passive failure without loss of its protective function. 3.1.1.1 Definitions The following definitions apply to the single failure criterion and to the GDC:
(1) Active Failure - The failure of a powered component, such as a piece of mechanical equipment, component of the electrical supply system, or instrumentation and control equipment, to act on command to perform its design function. Examples include the failure of a motor-operated valve to move to its correct position, the failure of an electrical breaker or relay to respond, the failure of a pump, fan, or diesel generator to start, etc. (2) Passive Failure - The structural failure of a static component that limits the component's effectiveness in carrying out its design function. When applied to a fluid system, this means a break in the pressure boundary resulting in abnormal leakage not exceeding 50 gpm for 30 minutes. Such leak rates are assumed for residual heat removal (RHR) pump seal failure.
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-3 Revision 21 September 2013 (3) Accident - Any natural or accidental event of infrequent occurrence and its related consequences which affect the plant operation and require the use of ESF. Such events, analyzed independently and not assumed to occur simultaneously, include the loss-of-coolant accident (LOCA), steam line ruptures, steam generator tube ruptures, etc. A loss of normal (main generator) and all offsite ac power may be an isolated occurrence or may be concurrent with any event requiring ESF use if the event should cause turbine trip and grid failure. (4) Short-term - The first 24 hours following the incident, during which time automatic actions are performed, system responses are checked, type of incident is identified, and preparations for long-term recovery operation are made. (5) Long-term - The remainder of the recovery period following the short-term. In comparison with the short-term where the main concern is to remain within NRC specified site criteria, the long-term period of operation involves bringing the plant to cold shutdown conditions. (6) Recovery Period - The time necessary to bring the plant to a cold shutdown. The recovery period is the sum of the short- and long-term periods defined above. 3.1.1.2 Applicability The single failure criterion applies to the following safety-related fluid systems discussed in this FSAR Update: System Section Containment Isolation Systems 6.2.4 Emergency Core Cooling System 6.3 Containment Spray System 6.2.2 Containment Fan Coolers 6.2 Auxiliary Feedwater System 6.5 Auxiliary Saltwater System 9.2.7 Component Cooling Water System 9.2.2 Chemical and Volume Control System (Boric Acid Injection Portion) 9.3.4 Diesel Fuel Oil System 9.5.4
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-4 Revision 21 September 2013 3.1.2 OVERALL PLANT REQUIREMENTS GDCs related to the overall plant are presented in this section. A summary discussion of conformance follows each 1967 criterion in the following subsections 3.1.2 through 3.1.10. The detailed conformance of the GDCs are further discussed in the other FSAR sections specific to systems and analyses. 3.1.2.1 Criterion 1, 1967 - Quality Standards (Category A) Those systems and components of reactor facilities that are essential to the prevention of accidents which could affect the public health and safety, or mitigation of their consequences, shall be identified and then designed, fabricated, and erected to quality standards that reflect the importance of the safety function to be performed. Where generally recognized codes or standards on design, materials, fabrication, and inspection are used, they shall be identified. Where adherence to such codes or standards does not suffice to ensure a quality product in keeping with the safety functions, they shall be supplemented or modified as necessary. Quality assurance programs, test procedures, and inspection acceptance levels to be used shall be identified. A showing of sufficiency and applicability of codes, standards, quality assurance programs, test procedures, and inspection acceptance levels used is required.
Discussion All systems and components of DCPP Units 1 and 2 are classified according to their importance in the prevention and mitigation of accidents. Those items vital to safe shutdown and isolation of the reactor, or whose failure might cause or increase the severity of a LOCA, or result in an uncontrolled release of excessive amounts of radioactivity, are designated Design Class I. Those items important to the reactor operation, but not essential to safe shutdown and isolation of the reactor or control of the release of substantial amounts of radioactivity, are designated Design Class II. Those items not related to reactor operation or safety are designated Design Class III.
Design Class I systems and components are essential to the protection of the health and safety of the public. Consequently, they are designed, fabricated, inspected, erected, and the materials selected to the applicable provisions of recognized codes, good nuclear practice, and to quality standards that reflect their importance. Discussions of applicable codes and standards as well as code classes are given in Section 3.2 for the major items and components. The quality assurance (QA) program conforms with the requirements of 10 CFR 50 Appendix B, Quality Assurance Criteria for Nuclear Power Plants. Details of the QA program are provided in Chapter 17. 3.1.2.2 Criterion 2, 1967 - Performance Standards (Category A) Those systems and components of reactor facilities that are essential to the prevention of accidents which could affect the public health and safety, or to mitigation of their consequences, shall be designed, fabricated, and erected to performance standards that DCPP UNITS 1 & 2 FSAR UPDATE 3.1-5 Revision 21 September 2013 will enable the facility to withstand, without loss of the capability to protect the public, the additional forces that might be imposed by natural phenomena such as earthquakes, tornadoes, flooding conditions, winds, ice, and other local site effects. The design bases so established shall reflect (a) appropriate consideration of the most severe of these natural phenomena that have been recorded for the site and the surrounding area, and (b) an appropriate margin for withstanding forces greater than those recorded to reflect uncertainties about the historical data and their suitability as a basis for design.
Discussion All systems and components designated Design Class I are designed so that there is no loss of function for ground acceleration associated with two times the design earthquake (DE) acting in the horizontal and vertical directions simultaneously. The ESF is included in the above. The working stresses for Class I items are kept within code allowable values for the DE. Similarly, measures are taken in the plant design to protect against possible effects of tsunamis, lightning storms, strong winds, and other natural phenomena.
The site characteristics are discussed in Chapter 2. Wind design criteria and flood design criteria are found in Sections 3.3 and 3.4, respectively. 3.1.2.3 Criterion 3, 1971 - Fire Protection Structures, systems, and components important to safety shall be designed and located to minimize, consistent with other safety requirements, the probability and effect of fires and explosions. Noncombustible and heat resistant materials shall be used wherever practical throughout the unit, particularly in locations such as the containment and control room. Fire detection and fighting systems of appropriate capacity and capability shall be provided and designed to minimize the adverse effects of fires on structures, systems, and components important to safety. Firefighting systems shall be designed to assure that their rupture or inadvertent operation does not significantly impair the safety capability of these structures, systems, and components. Discussion GDC 3 (1971) is invoked by 10 CFR 50.48, Fire Protection. The fire protection program for DCPP satisfies the requirements of GDC 3 (1971) by complying with the guidelines of Appendix A to NRC Branch Technical Position (BTP) (APCSB) 9.5-1, and with the provisions of 10 CFR 50 Appendix R, Sections III.G, J, L, and O, as stipulated by Operating License Conditions 2.C(5) and 2.C(4) for Units 1 and 2, respectively. Approved deviations from Appendix A to BTP (APCSB) 9.5-1, and Appendix R sections are identified in Supplement Numbers 8, 9, 13, 23, 27, and 31 to the Safety Evaluation Report (NUREG-0675).
The probability of fires and explosions is minimized by extensive use of noncombustible and fire resistant materials, by physical isolation and protection of flammable fluids, by DCPP UNITS 1 & 2 FSAR UPDATE 3.1-6 Revision 21 September 2013 providing both automatic and manual fire extinguishing systems, and by use of fire detection systems.
Electrical insulation is made of fire retardant, self-extinguishing materials. All exposed electrical raceways are metal and have fire stops liberally applied. Electrical conductors have adequate ratings and overcurrent protection to prevent breakdown or excessive heating.
Electrical equipment for safety systems is physically arranged to minimize the effect of a potential fire. Vital interconnecting circuits are located to avoid potential fire hazards as much as possible, with mutually redundant circuits placed in separate raceways. The facility is equipped with a fire protection system (FPS) for controlling any fire that might originate in plant equipment. This system is described in Section 9.5.1.
The containment and auxiliary building ventilation systems are operated from the control room. Critical areas of the plant have detectors and alarms to alert the control room operator of the possibility of fire, so that prompt action can be taken to prevent significant damage. 3.1.2.4 Criterion 4, 1967 - Sharing of Systems (Category A) Reactor facilities shall not share systems or components unless it is shown safety is not impaired by the sharing.
Discussion Those systems or components that are shared, either between the two units or functionally within a single unit, are designed in such a manner that plant safety is not impaired by the sharing. A list of shared systems and components is provided in Section 1.2.2.10. 3.1.2.5 Criterion 5, 1967 - Records Requirements (Category A) Records of the design, fabrication, and construction of essential components of the plant shall be maintained by the reactor operator or under its control throughout the life of the reactor.
Discussion Records of the design, fabrication, construction, and testing of Design Class I components of the plant will be maintained by Pacific Gas and Electric Company (PG&E) or kept under its control throughout the life of the plant. Chapter 17 describes the procedures for keeping these records. Operating records to be maintained throughout the life of the plant are described in Chapter 13.
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-7 Revision 21 September 2013 3.1.3 PROTECTION BY MULTIPLE FISSION PRODUCT BARRIERS GDCs related to prevention of fission product release are presented in this section. A discussion of conformance follows each criterion. 3.1.3.1 Criterion 6, 1967 - Reactor Core Design (Category A) The reactor core shall be designed to function throughout its design lifetime, without exceeding acceptable fuel damage limits which have been stipulated and justified. The core design, together with reliable process and decay heat removal systems, shall provide for this capability under all expected conditions of normal operation with appropriate margins for uncertainties and for transient situations which can be anticipated, including the effects of the loss of power to recirculation pumps, tripping out of a turbine generator set, isolation of the reactor from its primary heat sink, and loss of all offsite power.
Discussion Each reactor core with its related control and protection systems is designed to function throughout its design lifetime without exceeding acceptable fuel damage limits. Core design, together with reliable process and decay heat removal systems, provides for this capability under all expected conditions of normal operation with appropriate margins for uncertainties and anticipated transient situations, including the effects of the loss of reactor coolant flow, trip of the turbine-generator, loss of normal feedwater, and loss of all offsite power.
The reactor control and protection instrumentation systems are designed to actuate a reactor trip for any anticipated combination of plant conditions when necessary to ensure a minimum departure from nucleate boiling ratio (DNBR) equal to or greater than the applicable limit value (refer to Sections 4.4.1.1 and 4.4.2.3) and fuel center temperatures below the melting point of UO2. Chapter 4 discusses the design bases and design evaluation of reactor components. The details of the control and protection instrumentation systems design and logic are discussed in Chapter 7. This information supports the accident analyses presented in Chapter 15. 3.1.3.2 Criterion 7, 1967 - Suppression of Power Oscillations (Category B) The core design, together with reliable controls, shall ensure that power oscillations which could cause damage in excess of acceptable fuel damage limits are not possible or can be readily suppressed.
Discussion Power oscillations of the fundamental mode are inherently eliminated by the negative Doppler and non-positive moderator temperature coefficients of reactivity. DCPP UNITS 1 & 2 FSAR UPDATE 3.1-8 Revision 21 September 2013 Oscillations due to xenon spatial effects, in the radial, diametral, and azimuthal overtone modes, are heavily damped due to the inherent design and due to the negative Doppler and non-positive moderator temperature coefficients of reactivity.
Oscillations due to xenon spatial effects, in the axial first overtone mode, may occur. Assurance that fuel design limits are not exceeded by xenon axial oscillations is provided as a result of reactor trip functions using the measured axial power imbalance as an input.
Oscillations due to xenon spatial effects, in axial modes higher than the first overtone, are heavily damped due to the inherent design and due to the negative Doppler coefficient of reactivity.
The stability of the cores against xenon-induced power oscillations and the functional requirements of instrumentation for monitoring and measuring core power distributions are discussed in Section 4.3. Details of the instrumentation design and logic are discussed in Chapter 7. 3.1.3.3 Criterion 8, 1967 - Overall Power Coefficient (Category B) The reactor shall be designed so that the overall power coefficient in the power operating range shall not be positive.
Discussion Prompt compensatory reactivity feedback effects are ensured when each reactor is critical by the negative fuel temperature effect (Doppler effect) and by the operational limit on moderator temperature coefficient of reactivity. The negative Doppler coefficient of reactivity is ensured by the inherent design using low-enrichment fuel. The limits on moderator temperature coefficient of reactivity are ensured by administratively controlling the dissolved neutron absorber concentration and control rod position.
These reactivity coefficients are discussed in Section 4.3. 3.1.3.4 Criterion 9, 1967 - Reactor Coolant Pressure Boundary (Category A) The reactor coolant pressure boundary shall be designed and constructed so as to have an exceedingly low probability of gross rupture or significant leakage throughout its design lifetime.
Discussion The reactor coolant system (RCS) boundaries are designed to accommodate the system pressures and temperatures attained under all expected modes of plant operation, including all anticipated transients, and to maintain the stresses within applicable stress limits. The reactor coolant pressure boundary materials selection and fabrication DCPP UNITS 1 & 2 FSAR UPDATE 3.1-9 Revision 21 September 2013 techniques ensure a low probability of gross rupture or significant leakage. Additional details are presented in Section 5.2.
In addition to the loads imposed on the system under normal operating conditions, abnormal loading conditions, such as seismic loading and pipe rupture, are also considered, as discussed in Sections 3.6 and 3.7. The systems are protected from overpressure by means of pressure-relieving devices as required by applicable codes.
Means are provided to detect significant uncontrolled leakage from either reactor coolant pressure boundary with indication in the control room as discussed in Section 5.2. Each RCS boundary has provisions for inspection, testing, and surveillance of critical areas to assess the structural and leaktight integrity. The details of these provisions are given in Section 5.2. For each reactor vessel, a material surveillance program conforming to applicable codes is provided. Additional details are provided in Section 5.4.
The materials of construction of the pressure-retaining boundary of the RCS are protected by control of coolant chemistry from corrosion that might otherwise reduce the system structural integrity during its service lifetime. 3.1.3.5 Criterion 10, 1967 - Containment (Category A) Containment shall be provided. The containment structure shall be designed to sustain the initial effects of gross equipment failures, such as a large coolant boundary break, without loss of required integrity and, together with other engineered safety features as may be necessary, to retain for as long as the situation requires the functional capability to protect the public. Discussion The reactor containment is a reinforced concrete structure with a steel liner that is capable of withstanding the pressure buildup resulting from a major LOCA.
The reactor containment, together with the containment spray system and the containment fan cooler system, are described in Chapter 6. The structural design criteria are presented in Chapter 3. The consequences of major LOCAs are analyzed in Chapter 15. 3.1.4 NUCLEAR AND RADIATION CONTROLS GDCs related to nuclear and radiation controls are presented in this section. A discussion of conformance follows each criterion. 3.1.4.1 Criterion 11, 1967 - Control Room (Category B) The facility shall be provided with a control room from which actions to maintain safe operational status of the plant can be controlled. Adequate radiation protection shall be provided to permit access, even under accident conditions, to equipment in the control DCPP UNITS 1 & 2 FSAR UPDATE 3.1-10 Revision 21 September 2013 room or other areas as necessary to shut down and maintain safe control of the facility without radiation exposures of personnel in excess of 10 CFR 20 limits. It shall be possible to shut the reactor down and maintain it in a safe condition if access to the control room is lost due to fire or other cause.
Discussion The plant is provided with a centralized control room common to both units that contains the controls and instrumentation necessary for operation of both units under normal and accident conditions.
The control room is continuously occupied by the operating personnel under all operating and accident conditions. Sufficient shielding, distance, and containment are provided to ensure that the control room personnel are not subject to radiation exposures in excess of 10 CFR 20 limits. Adequate radiation protection is provided to permit access and occupancy of the control room under accident conditions without personnel receiving radiation exposures in excess of 5 rem whole body, or its equivalent to any part of the body, for the duration of the accident to meet the requirements of GDC 19, 1971. Control room shielding is described in Section 12.1, and postaccident control room exposures are described in Section 15.5.
The control room ventilation system is described in Section 9.4.1. It consists of a dual system providing a large percentage of recirculated air. In the event of fire in the control room, provisions are made for 100 percent outside air makeup operation. In the event of airborne toxic gas outside the control room, provisions are made for operation with 100 percent recirculated air. In the event of airborne radioactivity outside the control room, provisions are made to isolate and pressurize the control room. The risk of fire is minimized by the use of noncombustible and fire retardant materials in the construction of the control room and its furnishings. Fire fighting equipment is located in the control room, and the use and storage of combustible supplies are minimized.
Provisions are made to enable plant operators to readily shut down and maintain the plant at safe shutdown (Mode 3) by means of controls located outside the control room. 3.1.4.1.1 Criterion 19, 1971 - Control Room A control room shall be provided from which actions can be taken to operate the nuclear power unit safely under normal conditions and to maintain it in a safe condition under accident conditions, including loss-of-coolant accidents. Adequate radiation protection shall be provided to permit access and occupancy of the control room under accident conditions without personnel receiving radiation exposures in excess of 5 rem whole body, or its equivalent to any part of the body, for the duration of the accident.
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-11 Revision 21 September 2013 Discussion Adequate radiation protection is provided to permit access and occupancy of the control room under accident conditions without personnel receiving radiation exposures in excess of 5 rem whole body, or its equivalent to any part of the body, for the duration of the accident to meet the requirements of GDC 19, 1971. Refer to Section 6.4. 3.1.4.2 Criterion 12, 1967 - Instrumentation and Control Systems (Category B) Instrumentation and controls shall be provided as required to monitor and maintain variables within prescribed operating ranges.
Discussion Reactor, control rod, boron concentration, pressurizer pressure and level, feedwater, steam dump, and turbine instrumentation and controls are provided to monitor and maintain variables within prescribed operating ranges. Reactor protection systems that receive plant instrumentation signals and automatically actuate alarms, inhibit control rod withdrawal, initiate load cutback, and/or trip the reactors as prescribed limits are approached or reached are also provided. These systems are discussed in Chapter 7. 3.1.4.3 Criterion 13, 1967 - Fission Process Monitors and Controls (Category B) Means shall be provided for monitoring and maintaining control over the fission process throughout core life and for all conditions that can reasonably be anticipated to cause variations in reactivity of the core, such as indication of position of control rods and concentration of soluble reactivity control poisons. Discussion Control over the fission process for each reactor will be maintained throughout the core life by the combination of control rods and chemical shim (boration). Adequate indication of the core reactivity status is provided by the nuclear instrumentation system (NIS). Periodic samples of boron concentration and continuous indication of RCS temperature and control rod position provide additional fission process information.
During operation, the shutdown rod banks are fully withdrawn. The control rod system automatically maintains a programmed average reactor temperature compensating for reactivity effects associated with scheduled and transient load changes. The shutdown rod banks along with the control banks are designed to shut down the reactor under conditions of normal operation and anticipated operational occurrences.
The boron system maintains the reactor in the cold shutdown state independent of the position of the control rods and can compensate for all xenon burnout transients.
The reactivity control and NIS are discussed in Chapters 4 and 7. DCPP UNITS 1 & 2 FSAR UPDATE 3.1-12 Revision 21 September 2013 3.1.4.4 Criterion 14, 1967 - Core Protection Systems (Category B) Core protection systems, together with associated equipment, shall be designed to act automatically to prevent or to suppress conditions that could result in exceeding acceptable fuel damage limits.
Discussion Operational limits for the core protection systems are defined by analyses of all plant operating and fault conditions requiring rapid rod insertion to prevent or limit core damage. The protection system design bases for all anticipated transients or faults are:
(1) Minimum DNBR shall be the applicable limit value (refer to Sections 4.4.1.1 and 4.4.2.3) (2) Cladding strain on the fuel element shall not exceed 1 percent (3) Center melt shall not occur in the fuel elements A region of permissible core operation is defined in terms of power, axial power distribution, and coolant flow and temperature. The protection systems monitor these process variables (as well as many other process and plant variables). If the region limits are approached during operation, the protection systems automatically actuate alarms, initiate load runback, prevent control rod withdrawal, and/or trip the reactor. Operation within the permissible region and complete core protection is ensured by the overtemperature T and overpower T reactor trips over the system pressure range defined by the pressurizer high-pressure and pressurizer low-pressure reactor trips, provided that the transient is slow with respect to piping delays from the core to the temperature sensors. High neutron flux and low coolant flow reactor trips provide core protection against transients that are faster than the T response. Also, thermal transients are anticipated and avoided by reactor trips actuated by turbine trip and primary coolant pump circuit breaker position. The protection systems are discussed in Section 7.2.
3.1.4.5 Criterion 15, 1967 - Engineered Safety Features Protection Systems (Category B) Protection systems shall be provided for sensing accident situations and initiating the operation of necessary engineered safety features.
Discussion An important safety function of the reactor protection system is that of processing signals used for ESF actuation and generation of the actuation demand. ESFs are discussed in Chapter 6 and Section 7.3.
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-13 Revision 21 September 2013 3.1.4.6 Criterion 16, 1967 - Monitoring Reactor Coolant Pressure Boundary (Category B) Means shall be provided for monitoring the reactor coolant pressure boundary to detect leakage.
Discussion All RCS components are designed, fabricated, inspected, and tested in conformance with the ASME Boiler and Pressure Vessel Code.
Leakage is detected by an increase in the amount of makeup water required to maintain a normal level in the pressurizer. The reactor vessel closure joint is provided with a temperature monitored leakoff between double gaskets.
Leakage into the reactor containment is drained to the reactor building sump where the level is monitored.
Leakage is also detected by measuring the airborne activity and quantity of the condensate drained from each reactor containment fan cooler unit.
These leakage detection methods are described in detail in Section 5.2. 3.1.4.7 Criterion 17, 1967 - Monitoring Radioactivity Releases (Category B) Means shall be provided for monitoring the containment atmosphere, the facility effluent discharge paths, and the facility environs for radioactivity that could be released from normal operations, from anticipated transients and from accident conditions.
Discussion The containment atmosphere, the plant vents, and the liquid and gaseous waste systems effluent discharge paths are monitored for radioactivity concentrations during all modes of operations. The monitoring systems are described in Section 11.4. The offsite radiological monitoring program is described in Section 11.6.
Waste handling systems are incorporated in each facility design for processing and/or retention of normal operation radioactive wastes with appropriate controls and monitors to ensure that releases do not exceed the limits of 10 CFR 20. The facilities are also designed with provisions to monitor radioactivity release during accidents and to prevent releases from causing exposures in excess of the guideline levels specified in 10 CFR 100.
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-14 Revision 21 September 2013 3.1.4.8 Criterion 18, 1967 - Monitoring Fuel and Waste Storage (Category B) Monitoring and alarm instrumentation shall be provided for fuel and waste storage and handling areas for conditions that might contribute to loss of continuity in decay heat removal and to radiation exposures.
Discussion The fuel and waste storage and handling areas are provided with monitoring and alarm systems for radioactivity, and the plant vents are monitored for radioactivity during all operations. The monitoring systems are described in Section 11.4.
The spent fuel pool cooling system is equipped with adequate instrumentation for normal operation. Water temperatures in the pool and at the outlet of the heat exchanger are indicated locally, and high pool temperature is alarmed in the control room. The spent fuel pool cooling system is described in Section 9.1. 3.1.5 RELIABILITY AND TESTABILITY OF PROTECTION SYSTEMS GDCs related to reliability and testing of protection systems are presented in this section. A discussion of conformance follows each criterion. 3.1.5.1 Criterion 19, 1967 - Protection Systems Reliability (Category B) Protection systems shall be designed for high functional reliability and in-service testability commensurate with the safety functions to be performed. Discussion The protection systems are designed for high functional reliability and inservice testability. Each design employs redundant logic trains and measurement and equipment diversity. Sufficient redundancy is provided to enable individual end-to-end channel tests with each reactor at power without compromise of the protective function. Built-in semiautomatic testers provide means to test the majority of system components very rapidly. The protection systems are described in Section 7.2. 3.1.5.2 Criterion 20, 1967 - Protection Systems Redundancy and Independence (Category B) Redundancy and independence designed into protection systems shall be sufficient to assure that no single failure or removal from service of any component or channel of a system will result in loss of the protection function. The redundancy provided shall include, as a minimum, two channels of protection for each protection function to be served. Different principles shall be used where necessary to achieve true independence of redundant instrumentation components.
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-15 Revision 21 September 2013 Discussion Sufficient redundancy and independence is designed into the protection systems to ensure that no single failure nor removal from service of any component or channel of a system will result in loss of the protection function. The minimum redundancy is exceeded in each protection function that is active with the reactor at power.
Functional diversity and consequential location diversity are designed into the systems. DCPP uses the Westinghouse Eagle 21 Process Protection System, which is discussed in detail in Section 7.2. 3.1.5.3 Criterion 21, 1967 - Single Failure Definition (Category B) Multiple failures resulting from a single event shall be treated as a single failure.
Discussion When evaluating the protection systems, the ESF, and their support systems, multiple failures resulting from a single event are treated as a single failure. The ability of each system to perform its function with a single failure is discussed in the sections describing the individual systems. The single failure criterion is discussed further at the beginning of Section 3.1.1. 3.1.5.4 Criterion 22, 1967 - Separation of Protection and Control Instrumentation Systems (Category B) Protection systems shall be separated from control instrumentation systems to the extent that failure or removal from service of any control instrumentation system component or channel, or of those common to control instrumentation and protection circuitry, leaves intact a system satisfying all requirements for the protection channels.
Discussion The protection systems comply with the requirements of IEEE-279, 1971, Criteria for Protection Systems for Nuclear Power Generating Stations, although construction permits for the DCPP units were issued prior to issuance of the 1971 version of the standard. Each protection system is separate and distinct from the respective control systems. The control system is dependent on the protection system in that control signals are derived from protection system measurements, where applicable. These signals are transferred to the control system by isolation amplifiers that are classified as protection system components. The adequacy of system isolation has been verified by testing or analysis under conditions of all postulated credible faults. Isolation devices that serve to protect Instrument Class IA instrument loops have all been tested. For certain applications where the isolator is protecting an Instrument Class IB instrument loop, and the isolation device is a simple linear device with no complex failure modes, the analysis was used to verify the adequacy of the isolation device. The failure or removal of any single control DCPP UNITS 1 & 2 FSAR UPDATE 3.1-16 Revision 21 September 2013 instrumentation system component or channel, or of those common to the control instrumentation system component or channel and protection circuitry, leaves intact a system that satisfies the requirements of the protection system. The protection systems and control systems are discussed in Chapter 7. 3.1.5.5 Criterion 23, 1967 - Protection Against Multiple Disability of Protection Systems (Category B) The effects of adverse conditions to which redundant channels or protection systems might be exposed in common, either under normal conditions or those of an accident, shall not result in loss of the protection function.
Discussion Physical separation and electrical isolation of redundant channels and subsystems, functional diversity of subsystems, and safe failure modes are employed in design of the reactors as defenses against functional failure through exposure to common causative factors. The redundant logic trains, reactor trip breakers, and ESF actuation devices are physically separated and electrically isolated. Physically separate channel trays, conduits, and penetrations are maintained upstream from the logic elements of each train.
The protection system components have been qualified by testing under extremes of the normal environment. In addition, components are tested and qualified according to individual requirements for the adverse environment specific to their location that might result from postulated accident conditions. The protection systems are discussed in Section 7.2. 3.1.5.6 Criterion 24, 1967 - Emergency Power for Protection Systems (Category B) In the event of loss of all offsite power, sufficient alternate sources of power shall be provided to permit the required functioning of the protection systems.
Discussion The facility is supplied with normal and standby emergency power to provide for the required functioning of the protection systems. In the event of loss of normal power, emergency ac power is supplied by six diesel generators, as described in Chapter 8. Only four diesels are required to supply the power requirements with one unit in an accident situation and to bring the other to the shutdown condition from full power.
The instrumentation and controls portions of the protection systems are supplied initially from the station batteries and subsequently from the emergency diesel generators. A single failure of any one component will not prevent the required functioning of protection systems.
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-17 Revision 21 September 2013 3.1.5.7 Criterion 25, 1967 - Demonstration of Functional Operability of Protection Systems (Category B) Means shall be included for testing protection systems while the reactor is in operation to demonstrate that no failure or loss of redundancy has occurred.
Discussion All reactor protection channels employed in power operation are sufficiently redundant so that individual testing and calibration, without degradation of the protection function or violation of the single failure criterion, can be performed with the reactors at power. Such testing discloses failures or reduction in redundancy that may have occurred. Removal from service of any single channel or component does not result in loss of minimum required redundancy. For example, a two-out-of-three function becomes a one-out-of-two function when one channel is removed.
Semiautomatic testers are built into each of the two logic trains in the reactor protection system. These testers have the capability of testing the major part of the protection system very rapidly while the reactor is at power. Between tests, the testers continuously monitor a number of internal protection system points, including the associated power supplies and fuses. Outputs of the monitors are logically processed to provide alarms for failures in one train and automatic reactor trip for failures in both trains. A self-testing provision is designed into each tester. Additional details can be found in Section 7.2. 3.1.5.8 Criterion 26, 1967 - Protection Systems Fail-Safe Design (Category B) The reactor protection systems shall be designed to fail into a safe state or into a state established as tolerable on a defined basis if conditions such as disconnection of the system, loss of energy (e.g., electric power, instrument air), or adverse environments (e.g., extreme heat or cold, fire, steam, or water) are experienced.
Discussion The protection systems are designed with due consideration of the most probable failure modes of the components under various perturbations of the environment and energy sources. Each reactor trip channel is designed on the de-energize-to-trip principle, so loss of power, disconnection, open channel faults, and the majority of internal channel short circuit faults cause the channel to go into its tripped mode. Additional defenses against loss of function are discussed under Criterion 23. The protection system details can be found in Section 7.2. 3.1.6 REACTIVITY CONTROL GDCs related to reactivity control are presented in this section. A discussion of conformance follows each criterion.
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-18 Revision 21 September 2013 3.1.6.1 Criterion 27, 1967 - Redundancy of Reactivity Control (Category A) At least two independent reactivity control systems, preferably of different principles, shall be provided.
Discussion Two independent reactivity control systems are provided for each reactor. These are rod cluster control assemblies (RCCAs) and chemical shim (boration). The RCCAs are inserted into the core by the force of gravity.
The RCCAs can compensate for the reactivity effects of fuel/water temperature changes accompanying power level changes over the full range from full load to no-load at the design maximum load change rate. Automatic control by the assemblies is, however, limited to the range of 15 to 100 percent of power rating for reasons unrelated to reactivity or reactor safety. The assemblies can also compensate for xenon burnout reactivity transients over the allowed range of travel.
The boron system maintains the reactor in the cold shutdown state independent of the position of the control rods and can compensate for all xenon burnout transients. Details of the construction of the RCCA are included in Section 4.2, with the operation discussed in Chapter 7. The means of controlling the boric acid concentration is described in Section 9.3.4. 3.1.6.2 Criterion 28, 1967 - Reactivity Hot Shutdown Capability (Category A) At least two of the reactivity control systems provided shall be capable of independently making and holding the core subcritical from any hot standby or hot operating condition, including those resulting from power changes, sufficiently fast to prevent exceeding acceptable fuel damage limits.
Discussion The RCCA system is capable of making and holding the core subcritical from all operating and hot shutdown conditions sufficiently fast to prevent exceeding acceptable fuel damage limits. The chemical shim control is also capable of making and holding the core subcritical, but at a slower rate, and is not employed as a means of compensating for rapid reactivity transients. The RCCA system is, therefore, used in protecting each core from fast transients. Details of the operation and effectiveness of these systems are included in Chapters 4 and 9. 3.1.6.3 Criterion 29, 1967 - Reactivity Shutdown Capability (Category A) At least one of the reactivity control systems provided shall be capable of making the core subcritical under any condition (including anticipated operational transients) sufficiently fast DCPP UNITS 1 & 2 FSAR UPDATE 3.1-19 Revision 21 September 2013 to prevent exceeding acceptable fuel damage limits. Shutdown margins greater than the maximum worth of the most effective control rod when fully withdrawn shall be provided.
Discussion As discussed in Chapter 4, the reactors may be made subcritical by the RCCA systems sufficiently fast to prevent exceeding acceptable fuel damage limits, under all anticipated conditions, with the most reactive RCCA fully withdrawn. 3.1.6.4 Criterion 30, 1967 - Reactivity Holddown Capability (Category B) At least one of the reactivity control systems provided shall be capable of making and holding the core subcritical under any conditions with appropriate margins for contingencies.
Discussion The boron reactivity (chemical shim) control systems are capable of making and holding the core subcritical under any anticipated condition and with appropriate margin for contingencies. These means are discussed in detail in Chapters 4 and 9. Normal reactivity shutdown capability is provided by rapid control rod insertion. The chemical shim control system permits the necessary shutdown margin to be maintained during long-term xenon decay and plant cooldown. 3.1.6.5 Criterion 31, 1967 - Reactivity Control Systems Malfunction (Category B) The reactivity control systems shall be capable of sustaining any single malfunction, such as, unplanned continuous withdrawal (not ejection) of a control rod, without causing a reactivity transient which could result in exceeding acceptable fuel damage limits.
Discussion Reactor shutdown by RCCA insertion is completely independent of the normal control function, since the trip breakers interrupt power to the drive mechanisms regardless of existing control signals. The protection system is designed to limit reactivity transients so that DNBR will exceed the applicable limit value (refer to Sections 4.4.1.1 and 4.4.2.3) for any single malfunction in either reactor control system.
The analysis presented in Chapter 15 shows that for postulated dilution during refueling, startup, or manual or automatic operation at power, the operator has ample time to determine the cause of dilution, terminate the source of dilution, and initiate reboration before the shutdown margin is lost. The facility reactivity control systems are discussed further in Chapter 7, and analyses of the effects of the other possible malfunctions are discussed in Chapter 15. The analyses show that acceptable fuel damage limits are not exceeded in the event of a single malfunction of either system. DCPP UNITS 1 & 2 FSAR UPDATE 3.1-20 Revision 21 September 2013 3.1.6.6 Criterion 32, 1967 - Maximum Reactivity Worth of Control Rods (Category A) Limits, which include considerable margin, shall be placed on the maximum reactivity worth of control rods or elements and on rates at which reactivity can be increased to ensure that the potential effects of a sudden or large change of reactivity cannot: (a) rupture the reactor coolant pressure boundary, or (b) disrupt the core, its support structures, or other vessel internals sufficiently to impair the effectiveness of emergency core cooling.
Discussion The maximum reactivity worth of control rods and the maximum rates of reactivity insertion employing control rods and boron removal are limited to values that could not cause rupture of the RCS boundary or disruptions of the core or vessel internals to a degree that could impair the effectiveness of emergency core cooling.
The appropriate reactivity insertion rate for the withdrawal of RCCA and the dilution of the boric acid in the RCS are determined by safety analyses for the facility. The analyses include appropriate graphs that show the permissible manual withdrawal limits and overlap of function of the several RCCA banks as a function of power. These data on reactivity insertion rates, dilution, and withdrawal limits are also discussed in Section 4.3. The capability of the chemical and volume control system to avoid an inadvertent excessive rate of boron dilution is discussed in Chapter 9. The relationship of the reactivity insertion rates to plant safety is discussed in Chapter 15.
Assurance of core cooling capability following accidents, such as rod ejection, steam line break, etc., is provided by keeping the reactor coolant pressure boundary stresses within faulted condition limits as specified by applicable ASME codes. Structural deformations are also checked and are limited to values that do not jeopardize the operation of needed safety features. 3.1.7 REACTOR COOLANT PRESSURE BOUNDARY GDCs related to the reactor coolant pressure boundary are presented in this section. A discussion of conformance follows each criterion. 3.1.7.1 Criterion 33, 1967 - Reactor Coolant Pressure Boundary Capability (Category A) The reactor coolant pressure boundary shall be capable of accommodating without rupture, and with only limited allowance for energy absorption through plastic deformation, the static and dynamic loads imposed on any boundary components as a result of any inadvertent and sudden release of energy to the coolant. As a design reference, this sudden release shall be taken as that which would result from a sudden reactivity insertion such as rod ejection (unless prevented by positive mechanical means), rod dropout, or cold water addition. DCPP UNITS 1 & 2 FSAR UPDATE 3.1-21 Revision 21 September 2013 Discussion Each reactor coolant boundary is shown in Chapter 15 to be capable of accommodating, without rupture, the static and dynamic loads imposed as a result of a sudden reactivity insertion such as a rod ejection.
The operation of each reactor is such that the severity of an ejection accident is inherently limited. Since control rod clusters are used to control load variations and core depletion is followed with boron dilution, only the RCCAs in the controlling groups are inserted in the core at power, and these rods are only partially inserted. Rod insertion limit monitors are provided as an administrative aid to the operator to ensure that this condition is met. 3.1.7.2 Criterion 34, 1967 - Reactor Coolant Pressure Boundary Rapid Propagation Failure Prevention (Category A) The reactor coolant pressure boundary shall be designed to minimize the probability of rapidly propagating type failures. Consideration shall be given: (a) to the notch-toughness properties of materials extending to the upper shelf of the Charpy transition curve, (b) to the state of stress of materials under static and transient loadings, (c) to the quality control specified for materials and component fabrication to limit flaw sizes, and (d) to the provisions for control over service temperature and irradiation effects that may require operational restrictions.
Discussion Close control is maintained over material selection and fabrication for the RCS. RCS materials exposed to the coolant are corrosion-resistant stainless steel or Inconel. The nil ductility transition temperature (NDTT) of the reactor vessel material samples are established by Charpy V-notch and drop weight tests. The materials testing is consistent with 10 CFR 50, Appendices G and H. These tests also ensure that only materials with adequate toughness properties are used.
As part of the reactor vessel specification, certain additional tests, not specified by the applicable ASME codes, are performed:
(1) Ultrasonic Testing In addition to code requirements, the performance of a 100 percent volumetric ultrasonic test of reactor vessel plate for shear wave and a post-hydrotest ultrasonic map of all welds in the pressure vessel are required.
Cladding bond ultrasonic inspection to more restrictive requirements than code is also required to preclude interpretation problems during inservice inspection. DCPP UNITS 1 & 2 FSAR UPDATE 3.1-22 Revision 21 September 2013 (2) Radiation Surveillance Program In the surveillance programs, the evaluation of the radiation damage is based on pre-irradiation and post-irradiation testing of Charpy V-notch and tensile specimens. These programs are directed toward evaluation of the effect of radiation on the fracture toughness of reactor vessel steels based on the transition temperature approach and the fracture mechanics approach, and are in accord with ASTM-E-185, Recommended Practice for Surveillance Tests for Nuclear Reactor Vessels. The fabrication and quality control techniques used in the fabrication of each RCS, described in Section 5.2, are equivalent to those used for the reactor vessel. The inspections of reactor vessel, pressurizer, piping, pumps, and steam generator are governed by ASME code requirements.
The allowable heatup and cooldown rates as well as the static loading stresses during plant life are predicted, using conservative values for the change in ductility transition temperature due to irradiation. 3.1.7.3 Criterion 35, 1967 - Reactor Coolant Pressure Boundary Brittle Fracture Prevention (Category A) Under conditions where reactor coolant pressure boundary system components constructed of ferritic materials may be subjected to potential loadings, such as a reactivity-induced loading, service temperatures shall be at least 120°F above the nil ductility transition temperature of the component material if the resulting energy release is expected to be absorbed by plastic deformation, or 60°F above the NDTT of the component material if the resulting energy release is expected to be absorbed within the elastic strain energy range.
Discussion Sufficient testing and analysis of materials employed in RCS components have been performed to ensure that the required NDTT limits specified in the criterion are met. Removable test capsules installed in the reactor vessel are removed and tested at various times in the plant lifetime to determine the effects of operation on system materials. Details of the testing and analysis programs are included in Chapter 5. Close control is maintained over material selection and fabrication for the RCS. Materials exposed to the coolant are corrosion-resistant stainless steel or Inconel. Materials testing consistent with 10 CFR 50 ensures that only materials with adequate toughness properties are used.
The fabrication and quality control techniques used in the fabrication of the RCS are equivalent to those used for the reactor vessel. The inspections of reactor vessel, steam generators, pressurizer, pumps, and piping are governed by ASME code requirements.
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-23 Revision 21 September 2013 3.1.7.4 Criterion 36, 1967 - Reactor Coolant Pressure Boundary Surveillance (Category A) Reactor coolant pressure boundary components shall have provisions for inspection, testing, and surveillance by appropriate means to assess the structural and leaktight integrity of the boundary components during their service lifetime. For the reactor vessel, a material surveillance program conforming with ASTM-E-185-66 shall be provided.
Discussion The design of the reactor coolant pressure boundary provides for accessibility during service life to the entire internal surface of the reactor vessel and certain external zones of the vessel, including the nozzle to reactor coolant piping welds and the top and bottom heads, except where control rod drive or instrument penetrations prevent access. The reactor arrangement within each containment provides sufficient space for inspection of the external surfaces of the reactor coolant piping, except for the area of pipe within the primary shielding concrete. The inspection capability complements the leakage detection systems in assessing the pressure boundary components' integrity.
Monitoring of the NDT temperature properties of each core region plate, forging, weldment, and associated heat-treated zones are performed in accordance with ASTM-E-185, Recommended Practice for Surveillance Tests on Structural Materials in Nuclear Reactors. Samples of reactor vessel plate materials are retained and cataloged in case future engineering development shows the need for further testing.
The material properties surveillance program includes not only the conventional tensile and impact tests, but also fracture mechanics specimens. The observed shifts in NDTT of the core region materials with irradiation are used to confirm the calculated limits to startup and shutdown transients.
To define permissible operating conditions below NDTT, a pressure range is established that is bounded by a lower limit for pump operation and an upper limit that satisfies reactor vessel stress criteria. To allow for thermal stresses during heatup or cooldown of the reactor vessel, an equivalent pressure limit is defined to compensate for thermal stress as a function of rate of change of coolant temperature. Since the normal operating temperature of the reactor vessel is well above the maximum expected NDTT brittle fracture during normal operation, it is not considered to be a credible mode of failure. Additional details can be found in Section 5.2. 3.1.8 ENGINEERED SAFETY FEATURES GDCs related to ESFs are presented in this section. A discussion of conformance follows each criterion.
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-24 Revision 21 September 2013 3.1.8.1 Criterion 37, 1967 - Engineered Safety Features Basis for Design (Category A) Engineered safety features shall be provided in the facility to back up the safety provided by the core design, the reactor coolant pressure boundary, and their protection systems. As a minimum, such engineered safety features shall be designed to cope with any size reactor coolant pressure boundary break up to and including the circumferential rupture of any pipe in that boundary assuming unobstructed discharge from both ends.
Discussion Engineered safety features are provided to cope with any size reactor coolant pipe break up to and including the circumferential rupture of any pipe in that boundary assuming unobstructed discharge from both ends, and to cope with any steam or feedwater line break up to and including the main steam or feedwater headers.
Limiting the release of fission products from the reactor fuel is accomplished by the emergency core cooling system (ECCS) which, by cooling the core, keeps the fuel in place and substantially intact and limits the metal-water reaction to an acceptable amount. A reinforced concrete, steel-lined containment structure is provided and encloses the entire RCS. It is designed to sustain, without loss of required integrity, all effects of gross equipment failures up to and including the rupture of the largest pipe in the RCS. ESFs are described in Chapter 6. 3.1.8.2 Criterion 38, 1967 - Reliability and Testability of Engineered Safety Features (Category A) All engineered safety features shall be designed to provide high functional reliability and ready testability. In determining the suitability of a facility for a proposed site, the degree of reliance upon and acceptance of the inherent and engineered safety afforded by the systems, including engineered safety features, will be influenced by the known and the demonstrated performance capability and reliability of the systems, and by the extent to which the operability of such systems can be tested and inspected where appropriate during the life of the plant.
Discussion A comprehensive program of testing has been formulated for all equipment and instrumentation vital to the functioning of ESFs. The program consists of startup tests of system components and integrated tests of the system. Periodic tests of the activation circuitry and system components, throughout the station lifetime, with maintenance performed as necessary, ensure that the initially high reliability will be maintained and that the system will perform on demand. Details of the test program are provided in the Technical Specifications (Reference 1). The ESFs are described in Chapter 6. DCPP UNITS 1 & 2 FSAR UPDATE 3.1-25 Revision 21 September 2013 3.1.8.3 Criterion 39, 1967 - Emergency Power for Engineered Safety Features (Category A) Criterion 39, 1967 is no longer part of the DCPP license basis and has been replaced by GDC-17, 1971 and GDC-18, 1971. 3.1.8.3.1 Criterion 17, 1971 - Electric Power Systems An onsite electric power system and an offsite electric power system shall be provided to permit functioning of structures, systems, and components important to safety. The safety function for each system (assuming the other system is not functioning) shall be to provide sufficient capacity and capability to assure that (1) specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational occurrences and (2) the core is cooled and containment integrity and other vital functions are maintained in the event of postulated accidents. The onsite electric power supplies, including the batteries, and the onsite electric distribution system, shall have sufficient independence, redundancy, and testability to perform their safety functions assuming a single failure. Electric power from the transmission network to the onsite electric distribution system shall be supplied by two physically independent circuits (not necessarily on separate rights of way) designed and located so as to minimize to the extent practical the likelihood of their simultaneous failure under operating and postulated accident and environmental conditions. A switchyard common to both circuits is acceptable. Each of these circuits shall be designed to be available in sufficient time following a loss of all onsite alternating current power supplies and the other offsite electric power circuit, to assure that specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded. One of these circuits shall be designed to be available within a few seconds following a loss-of-coolant accident to assure that core cooling, containment integrity, and other vital safety functions are maintained. Provisions shall be included to minimize the probability of losing electric power from any of the remaining supplies as a result of, or coincident with, the loss of power generated by the nuclear power unit, the loss of power from the transmission network, or the loss of power from the onsite electric power supplies. Discussion The DCPP Offsite Power System is designed to supply offsite electrical power by two physically independent circuits. The 230-kV system provides startup and standby power, and is immediately available following a design basis accident to assure that core cooling, containment integrity, and other vital safety functions are maintained. The 500-kV system provides for transmission of the plant's electric power output. The 500-kV connection also provides a delayed access source of offsite power after the main generator is disconnected. A combination of the 230-kV and the 500-kV circuits provides independent sources of offsite power as required by GDC 17, 1971. DCPP UNITS 1 & 2 FSAR UPDATE 3.1-26 Revision 21 September 2013 The onsite emergency power source consists of three diesel generators for each unit. Both offsite and onsite systems have sufficient independence, capacity, and testability to permit the operation of the ESFs assuming a failure of a single active component in each power system. The combination of two 230-kV lines plus the 500-kV system provides a high degree of assurance that offsite power will be available when required. The 230-kv and 500-kV systems meet the requirements of 1971 GDC 17. Further details are provided in Chapter 8. 3.1.8.3.2 Criterion 18, 1971 - Inspection and Testing of Electric Power Systems Electric power systems important to safety shall be designed to permit appropriate periodic inspection and testing of important areas and features, such as wiring, insulation, connections, and switchboards, to assess the continuity of the systems and the condition of their components. The systems shall be designed with a capability to test periodically (1) the operability and functional performance of the components of the systems, such as onsite power sources, relays, switches, and buses, and (2) the operability of the systems as a whole and, under conditions as close to design as practical, the full operation sequence that brings the systems into operation, including operation of applicable portions of the protection system, and the transfer of power among the nuclear power unit, the offsite power system, and the onsite power system. Discussion The electric power system and its components have provisions for periodic inspection and testing. Electric power components have been provided with convenient and safe features for inspecting and testing to meet the requirements of GDC 18, 1971. 3.1.8.4 Criterion 40, 1967 - Missile Protection (Category A) Protection for engineered safety features shall be provided against dynamic effects and missiles that might result from plant equipment failures.
Discussion Use of conservative design methods, segregated routing of piping, provision of missile shield walls, and use of engineered hangers and pipe restraints are incorporated in the design to accommodate dynamic effects of postulated accidents. The various sources of missiles that might affect ESFs have been identified, and protective measures have been devised to minimize these effects (see Section 3.5).
Electrical raceways containing circuits for the ESFs have not been installed in zones where provision against dynamic effects must be made, with a few exceptions. When routing through such zones was necessary, metallic conduits only were used, and conduits containing redundant circuits were separated physically as far as practical. DCPP UNITS 1 & 2 FSAR UPDATE 3.1-27 Revision 21 September 2013 3.1.8.4.1 Criterion 4, 1987 revision - Environmental and Dynamic Effects Design Bases Structures, systems, and components important to safety shall be designed to accommodate the effects of and to be compatible with the environmental conditions associated with normal operation, maintenance, testing, and postulated accidents, including loss-of-coolant accidents. These structures, systems, and components shall be appropriately protected against dynamic effects, including the effects of missiles, pipe whipping, and discharging fluids, that may result from equipment failures and from events and conditions outside the nuclear power unit. However, dynamic effects associated with postulated pipe ruptures in nuclear power units may be excluded from the design basis when analyses reviewed and approved by the Commission demonstrate that the probability of fluid system piping rupture is extremely low under conditions consistent with the design basis for the piping.
Discussion General Design Criterion (GDC) 4, 1987 revision, "Environmental and dynamic effects design bases," states in part, that
...dynamic effects associated with postulated pipe ruptures in nuclear power units may be excluded from the design basis when analyses reviewed and approved by the Commission demonstrate that the probability of fluid system piping rupture is extremely low under conditions consistent with the design basis for the piping.
The leak-before-break (LBB) methodology was applied to the primary loops of DCPP Units 1 and 2. The following postulated breaks were eliminated: the six terminal ends in the cold, hot, and crossover legs; a split in the steam generator inlet elbow; and the loop closure weld in the crossover leg. Reference PG&E letter dated March 16, 1992 (DCL-92-059).
The NRC allows the application of LBB technology on the primary piping systems under the broad-scope revision to 10 CFR Part 50, Appendix A, GDC 4 revision (52 FR 4128841295; October 27, 1987). Use of LBB at DCPP has been approved by the NRC in a safety evaluation dated March 2, 1993. 3.1.8.5 Criterion 41, 1967 - Engineered Safety Features Performance Capability (Category A) Engineered safety features such as emergency core cooling and containment heat removal systems shall provide sufficient performance capability to accommodate partial loss of installed capacity and still fulfill the required safety function. As a minimum, each engineered safety feature shall provide this required safety function assuming a failure of a single active component.
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-28 Revision 21 September 2013 Discussion The overall capacity of the ESF meets the requirements of 10 CFR 100 for the occurrence of any rupture of a reactor coolant or steam system pipe, including the double-ended rupture of a reactor coolant pipe, known as the design basis accident (DBA). Additional details can be found in Chapters 6 and 15. 3.1.8.6 Criterion 42, 1967 - Engineered Safety Features Components Capability (Category A) Engineered safety features shall be designed so that the capability of each component and system to perform its required function is not impaired by the effects of a loss of coolant accident.
Discussion Instrumentation, motors, cables, and penetrations located inside the containment are selected to meet the most adverse accident conditions to which they may be subjected. These items are either protected from containment accident conditions or are designed to withstand, without failure, exposure to the worst combination of temperature, pressure, and humidity expected during the required operational period.
The ECCS pipes serving each loop are anchored at the missile barrier in each loop area to restrict potential accident damage to the portion of piping beyond this point. The anchorage is designed to withstand, without failure, the thrust force exerted by any branch line severed from the reactor coolant pipe and discharging fluid to the atmosphere, and to withstand a bending moment equivalent to that producing failure of the piping under the action of a free-end discharge to atmosphere or motion of the broken reactor coolant pipe to which the emergency core cooling pipes are connected. This prevents possible failure at any point upstream from the support point including the branch line connection into the piping header. Chapter 6 contains the details of the containment structure and ESFs. 3.1.8.7 Criterion 43, 1967 - Accident Aggravation Prevention (Category A) Engineered safety features shall be designed so that any action of the engineered safety features that might accentuate the adverse aftereffects of a loss of normal cooling is avoided.
Discussion The reactor is maintained subcritical following a pipe rupture accident. Introduction of borated cooling water into the core does not result in a net positive reactivity addition. The control rods insert and remain inserted. The supply of water by the ECCS to cool hot core cladding does not produce significant water-metal reactions. The delivery of cold emergency core cooling water to the reactor vessel following accidental expulsion of DCPP UNITS 1 & 2 FSAR UPDATE 3.1-29 Revision 21 September 2013 reactor coolant does not cause further loss of integrity of the RCS boundary. The ESFs are discussed in detail in Chapter 6. 3.1.8.8 Criterion 44, 1967 - Emergency Core Cooling Systems Capability (Category A) At least two emergency core cooling systems, preferably of different design principles, each with a capability for accomplishing abundant emergency core cooling, shall be provided. Each emergency core cooling system and the core shall be designed to prevent fuel and clad damage that would interfere with the emergency core cooling function and to limit the clad metal-water reaction to negligible amounts for all sizes of breaks in the reactor coolant pressure boundary, including the double-ended rupture of the largest pipe. The performance of each emergency core cooling system shall be evaluated conservatively in each area of uncertainty. The systems shall not share active components and shall not share other features or components unless it can be demonstrated that (a) the capability of the shared feature or component to perform its required function can be readily ascertained during reactor operation, (b) failure of the shared feature or component does not initiate a loss of coolant accident, and (c) capability of the shared feature or component to perform its required function is not impaired by the effects of a loss of coolant accident and is not lost during the entire period this function is required following the accident.
Discussion By combining the use of passive accumulators with two centrifugal charging pumps (CCP1 and CCP2), two safety injection pumps, and two RHR pumps, emergency core cooling is provided even if there should be a failure of any single component in any system. The ECCS employs a passive system of accumulators that do not require any external signals or source of power for their operation to cope with the short-term cooling requirements of large reactor coolant pipe breaks. Two independent and redundant high-pressure flow and pumping systems, each capable of the required emergency cooling, are provided for small break protection and to keep the core submerged after the accumulators have discharged following a large break. These systems are arranged so that the single failure of any active component does not interfere with meeting the short-term cooling requirements.
Borated water is injected into the RCS by accumulators, safety injection pumps, RHR pumps, and charging pumps. Pump design includes consideration of fluid temperature and containment pressure in accordance with AEC Safety Guide (SG) 1. The failure of any single active component or the development of excessive leakage during the long-term cooling period does not interfere with the ability to meet necessary long-term cooling objectives with one of the systems.
The primary function of the ECCS is to deliver borated cooling water to the reactor core in the event of a LOCA. This limits the fuel cladding temperature and thereby ensures that DCPP UNITS 1 & 2 FSAR UPDATE 3.1-30 Revision 21 September 2013 the core will remain intact and in place, with its essential heat transfer geometry preserved. This protection is afforded for:
(1) All pipe break sizes up to and including the hypothetical circumferential rupture of a reactor coolant loop (2) A loss of coolant associated with a rod ejection accident The basic criteria for LOCA evaluations are (a) no cladding melting will occur, (b) zirconium-water reactions will be limited to an insignificant amount, and (c) the core geometry will remain essentially in place and intact so that effective cooling of the core will not be impaired. The zirconium-water reactions will be limited to an insignificant amount so that the accident: (1) Does not interfere with the emergency core cooling function to limit cladding temperatures (2) Does not produce hydrogen in an amount that, when burned, would cause the containment pressure to exceed the design value For any rupture of a steam pipe and the associated uncontrolled heat removal from the core, the ECCS adds shutdown reactivity so that with a stuck rod, no offsite power, and minimum ESF, there is no consequential damage to the primary system and the core remains in place and intact. With no stuck rod, offsite power, and all equipment operating at design capacity, there is insignificant cladding rupture. The ECCS is described in Section 6.3. Chapter 15 provides the analysis for the LOCA.
3.1.8.9 Criterion 45, 1967 - Inspection of Emergency Core Cooling Systems (Category A) Design provisions shall be made to facilitate physical inspection of all critical parts of the emergency core cooling system, including reactor vessel internals and water injection nozzles.
Discussion Design provisions facilitate access to the critical parts of the reactor vessel internals, injection nozzles, pipes, and valves for visual or nondestructive inspection.
The components outside containment are accessible for leaktightness inspection during operation of the reactor.
Details of the inspection program for the reactor vessel internals are included in Section 5.4. Information on inspection for the ECCS is provided in Section 6.3.
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-31 Revision 21 September 2013 3.1.8.10 Criterion 46, 1967 - Testing of Emergency Core Cooling System Components (Category A) Design provisions shall be made so that active components of the emergency core cooling system, such as pumps and valves, can be tested periodically for operability and required functional performance.
Discussion The design provides for periodic testing of both active and passive components of the ECCS for operability and functional performance.
Preoperational performance tests of the components were performed in the manufacturer's shop. Initial system flow tests demonstrate proper functioning of the system. Thereafter, periodic tests demonstrate that components are functioning properly.
Each active component of the ECCS may be individually actuated on the normal power source at any time during plant operation to demonstrate operability. The centrifugal charging pumps are part of the charging system, and this system is in continuous operation during plant operation. The test of the safety injection pumps employs the minimum flow recirculation test line that connects back to the refueling water storage tank (RWST). Remotely operated valves are exercised and actuation circuits tested. The automatic actuation circuitry, valves, and pump breakers also may be checked during integrated system tests performed during a planned cooldown of the RCS.
Details of the ECCS are found in Section 6.3. Performance under accident conditions is evaluated in Chapter 15. Periodic testing procedures are listed in Section 13.5. 3.1.8.11 Criterion 47, 1967 - Testing of Emergency Core Cooling Systems (Category A) A capability shall be provided to test periodically the delivery capability of the emergency core cooling system at a location as close to the core as is practical.
Discussion Design provisions include special instrumentation, testing, and sampling lines to perform tests during plant shutdown to demonstrate proper operation of the ECCS. A test signal is applied to initiate automatic action. The test demonstrates the operation of the valves, pump circuit breakers, and automatic circuitry. In addition, the periodic recirculation to the RWST can verify that the safety injection pumps attain required discharge heads. During a refueling outage the full flow capability of each injection pump can be verified. Details of the ECCS are found in Section 6.3. Performance under accident conditions is evaluated in Chapter 15. DCPP UNITS 1 & 2 FSAR UPDATE 3.1-32 Revision 21 September 2013 3.1.8.12 Criterion 48, 1967 - Testing of Operational Sequence of Emergency Core Cooling Systems (Category A) A capability shall be provided to test under conditions as close to design as practical the full operational sequence that would bring the emergency core cooling system into action, including the transfer to alternate power sources.
Discussion The design provides for capability to test initially, to the extent practical, the full operational sequence up to design conditions, including transfer to alternative power sources for the ECCS, to demonstrate the state of readiness and capability of the system. This functional test is performed with the RCS initially cold and at low pressure. The ECCS valving is set to initially simulate the system alignment for plant power operation.
Details of the ECCS are found in Section 6.3. 3.1.8.13 Criterion 49, 1967 - Containment Design Basis (Category A) The containment structure, including access openings and penetrations, and any necessary containment heat removal systems shall be designed so containment structure can accommodate, without exceeding the design leakage rate, pressures and temperatures resulting from the largest credible energy release following a loss of coolant accident, including a considerable margin for effects from metal-water or other chemical reactions that could occur as a consequence of failure of emergency core cooling systems. Discussion The containment, including access openings and penetrations, has a design pressure of 47 psig. The greatest transient peak pressure associated with a postulated rupture of the piping in the RCS and the calculated effects of metal-water reaction do not exceed this value. The containment is strength tested at 54 psig.
The reactor containment structure and penetrations, with the aid of containment heat removal systems, are designed to limit radiation doses resulting from leakage of radioactive fission products from the containment to below 10 CFR 100 values, assuming the largest credible energy release following a LOCA, including a margin to cover the effects of metal-water or other undefined energy sources. The containment design is described in detail in Section 3.8.1.
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-33 Revision 21 September 2013 3.1.8.14 Criterion 50, 1967 - NDT Requirement for Containment Material (Category A) Principal load carrying components of ferritic materials exposed to the external environment shall be selected so that their temperatures under normal operating and testing conditions are not less than 30°F above nil ductility transition (NDT) temperature.
Discussion The selection and use of containment structure materials comply with the applicable codes and standards.
The nil ductility transition temperature (NDTT) requirement of Criterion 50 reflects the requirements of the ASME B&PV Code, Section III, 1968 Edition for Class B (containment) vessels. Section N-1210 requires an NDTT at least 30°F below the lowest service temperature. NDTT may be determined either by Charpy V-notch test or dropweight test. Using the Charpy V-notch test, acceptance criteria specified by the Code depend on the material specification and range from 15 to 20 ft-lbs minimum average.
During construction, Charpy V-notch test temperature for material exposed to external environments was established by subtracting 30°F from the lowest service temperature. The lowest service temperature was taken to be the design 24-hour mean-low ambient temperature for the site of 30°F. Thus the Charpy V-notch test temperature was 0°F. The containment liner is enclosed within the containment structure and thus not directly exposed to the temperature of the external environment and not subject to Criterion 50, 1967. Nevertheless, the design specification required Charpy V-notch tests at 20°F for the containment liner. This corresponds to a lowest service temperature of 50°F during operation.
During construction, compliance with Criterion 50, 1967 and the ASME Code was ensured by specifying appropriate test temperatures and minimum acceptance values for Charpy V-notch tests as part of the material specification. Mill test reports showing the Charpy V-notch test results were provided as documentation.
ASME Section III requirements have evolved over the years to reflect the industry's better understanding of the behavior of ferritic steel materials. The current ASME Code requirements for notch toughness testing for metallic containment vessels are contained in Subsection NE-2300. ASME has determined that an adequate level of toughness is ensured by performing the Charpy V-notch tests at or below the lowest service temperature rather than 30°F below the lowest service temperature as previously required. Acceptance criteria are based on material thickness rather than material specification and range from 20 to 25 ft.-lbs. minimum average or 20-25 mils lateral expansion minimum average. Notch toughness testing is not required for material 5/8 inch or less in thickness. For repair, replacement, or alteration or ferritic containment material subject to Criterion 50, 1967, the notch toughness testing requirements of NE-2300 will be used in DCPP UNITS 1 & 2 FSAR UPDATE 3.1-34 Revision 21 September 2013 lieu of the original requirements. Charpy V-notch testing will be performed at or below the lowest service temperature and materials 5/8 inch or less in thickness will be exempt from Charpy V-notch testing.
The concrete containment structure is not susceptible to a low temperature brittle fracture.
Further information on containment structure materials appears in Section 3.8.1. 3.1.8.15 Criterion 51, 1967 - Reactor Coolant Pressure Boundary Outside Containment (Category A) If part of the reactor coolant pressure boundary is outside the containment, appropriate features as necessary shall be provided to protect the health and safety of the public in case of an accidental rupture in that part. Determination of the appropriateness of features such as isolation valves and additional containment shall include consideration of the environmental and population conditions surrounding the site.
Discussion The reactor coolant pressure boundary is defined as those piping systems and components that contain reactor coolant at design pressure and temperature. With the exception of the reactor coolant sampling lines, the entire reactor coolant pressure boundary, as defined above, is located entirely within the containment structure. All sampling lines are provided with remotely operated valves for isolation in the event of a failure. These valves also close automatically on a containment isolation signal. Sampling lines are only used during infrequent sampling and can readily be isolated. All other piping and components that may contain reactor coolant are low-pressure, low temperature systems which would yield minimal environmental doses in the event of failure.
The sampling system and low-pressure systems are described in Chapter 9. An analysis of malfunctions in these systems is included in Chapter 15. 3.1.8.16 Criterion 52, 1967 - Containment Heat Removal Systems (Category A) Where active heat removal systems are needed under accident conditions to prevent exceeding containment design pressure, at least two systems, preferably of different principles, each with full capacity, shall be provided.
Discussion Two separate heat removal systems, the containment spray system (CSS) and the containment fan coolers, are provided to remove heat from the containment following an accident. The design cooling rates of the two systems at the containment design pressure DCPP UNITS 1 & 2 FSAR UPDATE 3.1-35 Revision 21 September 2013 and temperature conditions are the same. The heat removal capability of either system is sufficient to rapidly reduce the containment pressure following an accident.
A second purpose served by the CSS is to remove radioactive iodine isotopes from the containment atmosphere should these fission products be released in the event of an accident. The system is designed to deliver enough sodium hydroxide mixed with the borated spray water from the RWST to provide pH control for iodine removal when mixed with the other sources of water in the containment recirculation sump. The containment heat removal systems are described in Section 6.2. 3.1.8.17 Criterion 53, 1967 - Containment Isolation Valves (Category A) Penetrations that require closure for the containment function shall be protected by redundant valving and associated apparatus.
Discussion Penetrations that require closure for the containment function are provided with at least two barriers. Additional details can be found in Section 6.2.
The Containment Isolation System is designed to meet the 1971 General Design Criteria (GDC) requirements with exceptions. Where exceptions are noted, the exceptions do not meet the 1971 GDC because of commitments to design and construction made prior to the issuance of the 1971 GDC; these exceptions comply with the 1967 GDC. Refer to Section 6.2.4.
3.1.8.17.1 Criterion 54, 1971 - Piping Systems Penetrating Containment Piping systems penetrating primary reactor containment shall be provided with leak detection, isolation, and containment capabilities having redundancy, reliability, and performance capabilities which reflect the importance to safety of isolating these piping systems. Such piping systems shall be designed with a capability to test periodically the operability of the isolation valves and associated apparatus and to determine if valve leakage is within acceptable limits. Discussion The containment isolation design provides for a double barrier at the containment penetration in those fluid systems that are not required to function following a design basis event. All piping systems penetrating the containment are provided with test vents and test connections or have other provisions to allow periodic leakage testing. Those automatic isolation valves that do not restrict normal plant operation are periodically tested to ensure operability. Refer to Section 6.2.4 for further discussion. DCPP UNITS 1 & 2 FSAR UPDATE 3.1-36 Revision 21 September 2013 3.1.8.17.2 Criterion 55, 1971 - Reactor Coolant Pressure Boundary Penetrating Containment Each line that is part of the reactor coolant pressure boundary and that penetrates primary reactor containment shall be provided with containment isolation valves as follows, unless it can be demonstrated that the containment isolation provisions for a specific class of lines, such as instrument lines, are acceptable on some other defined basis: (1) One locked closed isolation valve inside and one locked closed isolation valve outside containment; or (2) One automatic isolation valve inside and one locked closed isolation valve outside containment; or (3) One locked closed isolation valve inside and one automatic isolation valve outside containment. A simple check valve may not be used as the automatic isolation valve outside containment; or (4) One automatic isolation valve inside and one automatic isolation valve outside containment. A simple check valve may not be used as the automatic isolation valve outside containment. Isolation valves outside containment shall be located as close to containment as practical and upon loss of actuating power, automatic isolation valves shall be designed to take the position that provides greater safety. Other appropriate requirements to minimize the probability or consequences of an accidental rupture of these lines or of lines connected to them shall be provided as necessary to assure adequate safety. Determination of the appropriateness of these requirements, such as higher quality in design, fabrication, and testing, additional provisions for inservice inspection, protection against more severe natural phenomena, and additional isolation valves and containment, shall include consideration of the population density, use characteristics, and physical characteristics of the site environs. Discussion The reactor coolant pressure boundary is defined as those piping systems and components that contain reactor coolant at design pressure and temperature. With the exception of the reactor coolant sampling lines, the entire reactor coolant pressure boundary, as defined above, is located entirely within the containment structure. All sampling lines are provided with remotely operated valves for isolation in the event of a failure. These valves also close automatically on a containment isolation signal. Sampling lines are only used during infrequent sampling and can readily be isolated. Further details are provided in Section 6.2.4. DCPP UNITS 1 & 2 FSAR UPDATE 3.1-37 Revision 21 September 2013 3.1.8.17.3 Criterion 56, 1971 - Primary Containment Isolation Each line that connects directly to the containment atmosphere and penetrates primary reactor containment shall be provided with containment isolation valves as follows, unless it can be demonstrated that the containment isolation provisions for a specific class of lines, such as instrument lines, are acceptable on some other defined basis: (1) One locked closed isolation valve inside and one locked closed isolation valve outside containment; or (2) One automatic isolation valve inside and one locked closed isolation valve outside containment; or (3) One locked closed isolation valve inside and one automatic isolation valve outside containment. A simple check valve may not be used as the automatic isolation valve outside containment; or (4) One automatic isolation valve inside and one automatic isolation valve outside containment. A simple check valve may not be used as the automatic isolation valve outside containment. Isolation valves outside containment shall be located as close to containment as practical and upon loss of actuating power, automatic isolation valves shall be designed to take the position that provides greater safety. Discussion The containment pressure and vacuum relief lines for each unit are exceptions to Criterion 56. These lines are provided with two automatic isolation valves, one inside and one outside the containment. These lines, as do all lines penetrating the containment, fall into a specific class of lines as discussed in Section 6.2.4. 3.1.8.17.4 Criterion 57, 1971 - Closed System Isolation Valves Each line that penetrates primary reactor containment and is neither part of the reactor coolant pressure boundary nor connected directly to the containment atmosphere shall have at least one containment isolation valve which shall be either automatic, or locked closed, or capable of remote manual operation. This valve shall be outside containment and located as close to the containment as practical. A simple check valve may not be used as the automatic isolation valve. Discussion Each line that penetrates the reactor containment in each unit, and is neither part of the reactor coolant pressure boundary nor connected directly to the containment atmosphere, has at least one containment isolation valve located outside the containment as close to DCPP UNITS 1 & 2 FSAR UPDATE 3.1-38 Revision 21 September 2013 the containment as practicable. The RHR system, the component cooling water line penetrations to the excess letdown heat exchanger and to the containment fan coolers, and the auxiliary feedwater supply lines are excepted. The cooling water supply to the excess letdown heat exchanger utilizes a check valve outside of containment rather than an isolation valve. The CCW supply and return lines to the containment fan coolers and the auxiliary feedwater lines to the steam generators use local manual valves as isolation valves per GDC 53, 1967. Refer to Section 6.2.4 for further discussion. 3.1.8.18 Criterion 54, 1967 - Containment Leakage Rate Testing (Category A) Containment shall be designed so that an integrated leakage rate test can be conducted at design pressure after completion and installation of all penetrations and the leakage rate measured over a sufficient period of time to verify its conformance with required performance.
Discussion The containment structure design permits preoperational leakage rate tests, including an integrated leakage rate test of the containment structure and sensitive leakage rate tests of the penetrations and weld channels.
The integrated leakage rate test, which is at design pressure and could extend to a period of at least 24 hours, verifies that the structure leakage rate is less than the allowable value. Subsequent leakage tests are conducted at a pressure greater than or equal to 25 psig. A sensitive leakage rate test can be performed by pressurizing the double penetrations, the spaces between resilient seals on penetrations, and the weld channels at slightly above design pressure. This test would be conducted with the containment structure at atmospheric pressure.
The leakage rate tests and the sensitive leakage rate test demonstrate the integrity of the double leakage barriers provided by the penetrations and the overall integrity of the containment structure. The criterion for acceptance is that the measured leakage rate be less than 0.10 percent of the containment free volume per day.
Further details of the integrated leakage rate test and the sensitive leakage rate test provisions appear in Section 3.8. 3.1.8.19 Criterion 55, 1967 - Containment Periodic Leakage Rate Testing (Category A) The containment shall be designed so that integrated leakage rate testing can be done periodically at design pressure during plant lifetime.
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-39 Revision 21 September 2013 Discussion The containment structure is provided with testable weld channels and penetrations so that periodic sensitive leakage rate tests at design pressure can be made of those areas where leakage may occur. The containment structure is designed to permit periodic full integrated leakage rate tests at reduced pressure. 3.1.8.20 Criterion 56, 1967 - Provisions for Testing of Penetrations (Category A) Provisions shall be made for testing penetrations which have resilient seals or expansion bellows to permit leaktightness to be demonstrated at design pressure at any time.
Discussion All penetrations are provided with a volume that can be pressurized to test for leaktightness. There are three configurations used: (a) weld channels over the penetration welds, (b) an annular space between the penetration insert and the sleeve, which is sealed at both ends, and (c) double resilient seals with a gap between the seals.
Further details appear in Section 3.8. 3.1.8.21 Criterion 57, 1967 - Provisions for Testing of Isolation Valves (Category A) Capability shall be provided for testing functional operability of valves and associated apparatus essential to the containment function for establishing that no failure has occurred and for determining that valve leakage does not exceed acceptable limits. Discussion Capability is provided to the extent practical for testing the functional operability of valves and associated apparatus and the leakage during periods of reactor shutdown.
Initiation of containment isolation employs coincidence circuits that allow checking of the operability and calibration of one channel at a time. Removal or bypass of one signal channel places that channel in the tripped mode. Section 6.2 describes in detail the testing of isolation valves. 3.1.8.22 Criterion 58, 1967 - Inspection of Containment Pressure-Reducing Systems (Category A) Design provisions shall be made to facilitate the periodic physical inspection of all important components of the containment pressure-reducing systems, such as, pumps, valves, spray nozzles, torus, and sumps.
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-40 Revision 21 September 2013 Discussion Where practicable, all active components and passive components of the containment cooling system are inspected periodically to demonstrate system readiness. The pressure-containing systems are inspected for leaks from pump seals, valve packing, flanged joints, and safety valves. During operational testing of the containment spray pumps, the portions of the system subjected to pump pressure are inspected for leaks. The containment fan coolers are normally in use, which provides an additional check on the readiness of the system. Five fan coolers are provided. Each is sized for one-quarter the capacity needed to maintain the containment temperature below 120°F during normal plant operation. Following a LOCA, two of the five fan coolers provide sufficient capacity to maintain containment pressure below design value when used in conjunction with one containment spray pump during the injection phase. During the recirculation phase, containment spray operation is not required.
Additional details are found in Section 6.2. 3.1.8.23 Criterion 59, 1967 - Testing of Containment Pressure-Reducing Systems Components (Category A) The containment pressure-reducing systems shall be designed so that active components, such as pumps and valves, can be tested periodically for operability and required functional performance.
Discussion To the extent practicable, active components of the containment fan coolers are given preoperational performance tests after installation. Since these coolers are in use during normal operation, they are continually subjected to operational tests. The same is true of the component cooling water system that supplies the cooling water for the fan coolers. Each unit can be isolated during plant operation and subjected to a leak test to determine that the leaktight integrity of the unit has not been lost.
Similarly, active components in the CSS are given preoperational performance tests after installation. Periodic tests demonstrate that components are functioning properly. Tests are performed after any component maintenance affecting operability. The containment systems are described in detail in Section 6.2. 3.1.8.24 Criterion 60, 1967 - Testing of Containment Spray Systems (Category A) A capability shall be provided to test periodically the delivery capability of the containment spray system at a position as close to the spray nozzles as is practical.
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-41 Revision 21 September 2013 Discussion Permanent test lines for all the containment spray loops are located so that all components up to the isolation valves at the containment can be tested.
The air test lines for checking that spray nozzles are not obstructed are connected upstream of the spray ring isolation valves. Airflow through the nozzles is monitored by positive means. Details of the CSS are found in Section 6.2. 3.1.8.25 Criterion 61, 1967 - Testing of Operational Sequence of Containment Pressure-Reducing Systems (Category A) A capability shall be provided to test under conditions as close to the design as practical the full operational sequence that would bring the containment pressure-reducing systems into action, including the transfer to alternate power sources.
Discussion The design provides for capability to test, to the extent practicable, the full operational sequence for the CSS and the containment fan coolers to demonstrate the state of readiness for those sections of the systems not normally functioning during plant operation. Containment systems are described in detail in Section 6.2. 3.1.8.26 Criterion 62, 1967 - Inspection of Air Cleanup Systems (Category A) Design provisions shall be made to facilitate physical inspection of all critical parts of containment air cleanup systems, such as, ducts, filters, fans, and dampers. Discussion The CSS, utilizing sodium hydroxide, serves as the air cleanup system. Where practical, all components of the CSS are inspected periodically to demonstrate system readiness. Special attention is given to critical parts such as pipes, pumps, nozzles, and storage facilities for sodium hydroxide. Additional details are found in Section 6.2. 3.1.8.27 Criterion 63 , 1967- Testing of Air Cleanup Systems Components (Category A) Design provisions shall be made so that active components of the air cleanup systems, such as fans and dampers, can be tested periodically for operability and required functional performance.
Discussion The CSS, utilizing sodium hydroxide, serves as the air cleanup system. The active components in the CSS are given preoperational performance tests after installation. DCPP UNITS 1 & 2 FSAR UPDATE 3.1-42 Revision 21 September 2013 Permanent test lines for all containment spray loops are located so that all components up to the isolation valves at the containment may be tested. The nozzles are tested by airflow that is monitored by positive means. The fan coolers are normally in use, which provides a check on the operability of the system. Additional details are found in Section 6.2. 3.1.8.28 Criterion 64, 1967 - Testing Air Cleanup Systems (Category A) A capability shall be provided for in situ periodic testing and surveillance of the air cleanup systems to ensure: (a) filter bypass paths have not developed and (b) filter and trapping materials have not deteriorated beyond acceptable limits.
Discussion The CSS water flow can be tested through the permanent test lines, permitting the test of the system up to the isolation valves at the containment. Permanent air testing lines, connected upstream of the containment isolation valves, permit operability testing of piping and nozzles beyond the isolation valves. Periodically, a sample of the sodium hydroxide solution is tested to ensure proper concentration. The fan coolers are normally in use and, therefore, the readiness of the system is verified. Additional details are found in Section 6.2. 3.1.8.29 Criterion 65, 1967 - Testing of Operational Sequence of Air Cleanup Systems (Category A) A capability shall be provided to test, under conditions as close to design as practical, the full operational sequence that would bring the air cleanup systems into action, including the transfer to alternate power sources and the design air flow delivery capability. Discussion The CSS design provides for the capability to test initially, to the extent practicable, the full operational sequence from the CSS to demonstrate the state of readiness of the system. The fan cooler system is normally in use, which verifies its readiness. Details are contained in Section 6.2. 3.1.9 FUEL AND WASTE STORAGE SYSTEMS GDC for fuel and waste storage systems are presented in this section. A discussion of conformance follows each criterion. 3.1.9.1 Criterion 66, 1967 - Prevention of Fuel Storage Criticality (Category B) Criticality in new and spent fuel storage shall be prevented by physical systems or processes. Such means as geometrically safe configurations shall be emphasized over procedural controls.
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-43 Revision 21 September 2013 Discussion During reactor vessel head removal and while loading and unloading fuel from the reactor, the boron concentration in the refueling water and the spent fuel pool is maintained at not less than that required to shut down the core to a keff = 0.95. Borated water is used to fill the spent fuel storage pools at a concentration comparable to that used in the reactor cavity and refueling canal during refueling operations. The fuel is stored vertically in an array with sufficient center-to-center distance between assemblies to ensure that, including uncertainties, a keff of less than or equal to 0.95 if the fuel racks are flooded with borated water, and a keff < 1.0, even if unborated water is used to fill the pool. The fuel storage and handling details are found in Section 9.1. 3.1.9.2 Criterion 67, 1967 - Fuel and Waste Storage Decay Heat (Category B) Reliable decay heat removal systems shall be designed to prevent damage to the fuel in storage facilities that could result in radioactivity release to plant operating areas or the public environs.
Discussion Refueling water provides a reliable and adequate cooling medium for spent fuel transfer, and heat removal is provided by an auxiliary cooling system. Natural radiation and convection is adequate for cooling the holdup tanks. The auxiliary systems are discussed in detail in Chapter 9. 3.1.9.3 Criterion 68, 1967 - Fuel and Waste Storage Radiation Shielding (Category B) Shielding for radiation protection shall be provided in the design of spent fuel and waste storage facilities as required to meet the requirements of 10 CFR 20.
Discussion The spent fuel pool is designed to provide a sufficient depth of water over the top of the active portion of a spent fuel assembly during handling operations so that, in all cases, operator dose levels will be within the requirements of 10 CFR 20. Fuel handling and storage is described in Chapter 9. Shielding design is described in Chapter 12. 3.1.9.4 Criterion 69, 1967 - Protection Against Radioactivity Release from Spent Fuel and Waste Storage (Category B) Containment of fuel and waste storage shall be provided if accidents could lead to release of undue amounts of radioactivity to the public environs.
DCPP UNITS 1 & 2 FSAR UPDATE 3.1-44 Revision 21 September 2013 Discussion The spent fuel area is enclosed and maintained under negative pressure. All ventilation air is passed through HEPA filters prior to being released to the plant vent. In the event of an accident, high activity would be detected by the radiation monitor (see Section 11.4), and the exhaust air would be diverted through charcoal filters. For radioactive waste storage, refer to the detailed discussion in Chapter 11. Failure of a gas decay tank has been postulated and analyzed in Chapter 15. 3.1.10 PLANT EFFLUENTS The general design criterion related to plant effluents is presented in this section. A discussion of conformance follows the criterion. 3.1.10.1 Criterion 70, 1967 - Control of Releases of Radioactivity to the Environment (Category B) The facility design shall include those means necessary to maintain control over the plant radioactive effluents, whether gaseous, liquid, or solid. Appropriate holdup capacity shall be provided for retention of gaseous, liquid, or solid effluents, particularly where unfavorable environmental conditions can be expected to require operational limitations upon the release of radioactive effluents to the environment. In all cases, the design for radioactivity control shall be justified (a) on the basis of 10 CFR 20 requirements for normal operations and for any transient situation that might reasonably be anticipated to occur and (b) on the basis of low probability of occurrence except that reduction of the recommended dosage levels may be required where high population densities or very large cities can be effected by the radioactive effluents. Discussion Waste handling systems are incorporated in the facility design for processing and/or retention of radioactive wastes from normal operation, with appropriate controls and monitors to ensure that releases do not exceed the limits of 10 CFR 20. The radioactive waste processing system, the design criteria, and amounts of estimated releases of radioactive effluents to the environment are described in Chapter 11. Details of the monitoring system are found in Section 11.4.
The facility is designed to prevent radioactivity release during accidents from exceeding the limits of 10 CFR 100. The containment system, which forms a barrier to the escape of fission products should a loss of coolant occur, is described in Section 6.2. Postulated accidents that could release radioactivity to the environment are analyzed in Chapter 15. 3.1.11 REFERENCES 1. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended. DCPP UNITS 1 & 2 FSAR UPDATE 3.1-45 Revision 21 September 2013 2. Deleted in Revision 3.
- 3. Deleted in Revision 3.
- 4. Deleted in Revision 20
- 5. Diablo Canyon Plant Units 1 and 2 Final Safety Analysis Report (FSAR), July 1973.
- 6. Diablo Canyon Plant Units 1 and 2 FSAR Amendment 85, 1980.
DCPP UNITS 1 & 2 FSAR UPDATE 3.2-1 Revision 15 September 2003 3.2 CLASSIFICATION OF STRUCTURES, SYSTEMS, AND COMPONENTS This section provides a guide to the classification of the DCPP structures, systems, and components (SSCs).
Criterion 1 of the July 1967 GDC requires that systems and components essential to the prevention of accidents be designed, fabricated, erected, and tested to quality standards commensurate with the importance of the safety functions to be performed. This section describes how Criterion 1 has been implemented by relating the classifications of SSCs to the various criteria, codes, regulations, and standards that dictate specific quality requirements.
In this regard, it is recognized that during the design and construction of DCPP Units 1 and 2, significant industry and regulatory changes were made in establishing common methods of classification, e.g., ANSI N18.2(1), SG 26(2), SG 29(3), and NRC Regulatory Guide (RG) 1.143(6). These methods all differ slightly in detail from those used for the DCPP, but the form and intent of all are equivalent, as will be shown in the following discussion of: (a) the seismic classification of SSCs, and (b) the system quality group classification of pressure-containing components of fluid systems.
Classifications of instruments and controls and requirements for them are discussed in Section 7.1. 3.2.1 SEISMIC CLASSIFICATION Criterion 2 of the July 1967 GDC, and Appendix A to 10 CFR 100, Seismic and Geologic Siting Criteria for Nuclear Power Plants, require that nuclear power plant SSCs important to safety be designed to withstand the effects of earthquakes. Specifically, Appendix A to 10 CFR 100 requires that all nuclear power plants be designed so that, if the safe shutdown earthquake (SSE) occurs, all structures and components important to safety remain functional. Plant features important to safety are those necessary to ensure (a) the integrity of the reactor coolant pressure boundary, (b) the capability to shut down the reactor and maintain it in a safe shutdown condition, or (c) the capability to prevent or mitigate the consequences of accidents that could result in potential offsite exposures comparable to the guideline exposures of 10 CFR 100.
The SSE of Appendix A to 10 CFR 100 is equivalent to the DCPP double design earthquake (DDE) (see References 9 and 10 for final resolution of issues raised in Supplemental Safety Evaluation Reports 7, 8, and 31 relative to the SSE). Similarly, the operating basis earthquake (OBE) of Appendix A to 10 CFR 100 is equivalent to the DCPP DE.
DCPP's capability to withstand a postulated Richter magnitude 7.5 earthquake centered along an offshore zone of geologic faulting known as the "Hosgri Fault" has been reviewed. Guidance for determining the SSCs designed to remain functional in the DCPP UNITS 1 & 2 FSAR UPDATE 3.2-2 Revision 15 September 2003 event of an SSE is provided in SG 29. These plant features, including their foundations and supports, are designated as Seismic Category I in SG 29. DCPP SSCs, and their seismic design classifications comply with the intent of SG 29. However, since DCPP design and construction had progressed substantially prior to the issuance of SG 29, different terminology is often used.
Plant features that correspond to Seismic Category I, as identified in SG 29, are designed to remain functional during the design basis earthquakes that they are required to withstand: the DE (equivalent to the OBE of SG 29), the DDE (equivalent to the SSE of SG 29), and/or the postulated Hosgri earthquake (HE). Design Class I plant features are designed to maintain their structural integrity in the event of both the DE/DDE and HE. They may or may not be designed to remain operable for the DE/DDE or HE; the design basis function of the equipment determines whether it is qualified for active or passive function for a DE/DDE and/or an HE.
All plant features designated as Design Class I are also Seismic Category I. SSCs not identified as Seismic Category I in SG 29, are referred to by the guide as Nonseismic Category I features. Under the DCPP classification system, Design Class II features may or may not be Seismic Category I.
SSCs important to reactor operation but not essential to safe shutdown and isolation of the reactor, and failure of which would not result in the release of substantial amounts of radioactivity, are classified as Design Class II.
SSCs not related to reactor operation or safety are classified as Design Class III. Power and auxiliary service piping systems (as defined in ANSI B31.1, Paragraph 100.1), which might otherwise be considered as Design Class III, are classified as Design Class II (i.e., Design Class III is not used for power and auxiliary service piping systems).
In addition, Appendix B to 10 CFR 50, Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants, requires that SSCs important to safety be designed and constructed in accordance with the quality assurance requirements described in Appendix B. Therefore, as described in Chapter 17, the requirements of the DCPP Quality Assurance Program apply to all SSCs classified as Design Class I. This ensures that plant features important to safety have met the requirements of Appendix B. Specific quality assurance requirements may also be applied to selected Design Class II features.
The general applicability and requirements of the design class, quality/code class classification, and seismic category are provided in Tables 3.2-1 and 3.2-2.
The classifications of specific SSCs are provided in the DCPP Q-List (see Reference 8). The DCPP Q-List is controlled by a written PG&E procedure. The procedure requires that all non-editorial changes to the contents of the Q-List be reviewed pursuant to the DCPP UNITS 1 & 2 FSAR UPDATE 3.2-3 Revision 15 September 2003 requirements of 10 CFR 50.59. Access to the Q-List is available through hard copy or electronically at PG&E. The piping schematic drawings are illustrated in Figures 3.2-1 through 3.2-27.
The piping symbol system that appears on all piping schematics and drawings to indicate piping fabrication, erection, and test criteria can be correlated to the design and quality code classes as follows: Piping Schematic Correlation Piping Design Quality Code Symbol Class Class A I I B I II @(a) I/II II/None C I III D I III E II None F II None G II None G1 II None H II None J I III -(b) I Not Applicable -(b) II or III None Those SSCs, including their foundations and supports, that have been classified as Design Class I and designed to remain functional in the event a DDE or HE occurs, and to which the requirements of the Quality Assurance Program apply, are:
(1) The reactor coolant pressure boundary
(2) The reactor core and reactor vessel internals (3) Systems [see Note (i)](c) or portions of systems that are required for emergency core cooling, postaccident containment heat removal, or postaccident containment atmosphere cleanup [see Note (v)] (a) The symbol '@' is referred to in the FSAR Update and the Q-List. However, this symbol is not used on the piping schematics for Code Class designation; the line is bubbled (i.e., 0-) and the notes describe the applicable code(s). (b) For HVAC system ductwork symbols, see Figures 3.2-1A and 3.2-2A. (c) See Notes at the end of this subsection. (a) The 1971 edition of the ASME Boiler and Pressure Vessel Code, Section III, Nuclear Power Plant Components, uses the term Class I in lieu of Class A. DCPP UNITS 1 & 2 FSAR UPDATE 3.2-4 Revision 15 September 2003 (4) Systems or portions of systems that are required for reactor shutdown and residual heat removal (5) Those portions of the main steam, feedwater, and steam generator blowdown systems extending from and including the secondary side of the steam generators up to and including the outermost containment isolation valves, and connected piping up to and including the first valve (including a safety or relief valve) that is either normally closed or capable of automatic closure during all modes of normal reactor operation [see Note (v)] (6) Auxiliary saltwater, component cooling water, and auxiliary feedwater systems or portions of these systems that are required for emergency core cooling, postaccident containment heat removal, postaccident containment atmosphere cleanup, and residual heat removal (7) Component cooling water system and seal water systems, or portions of these systems that are required for functioning of other systems or components important to safety (8) Those portions of systems (other than the radioactive waste management systems) that contain or may contain radioactive material and whose postulated failure could result in conservatively calculated potential offsite exposures in excess of 0.5 rem whole body (or its equivalent to parts of the body) at the site boundary or beyond (9) Systems or portions of systems that are required to supply fuel for emergency equipment (10) Systems or portions of systems that are required for (a) post accident monitoring of RG 1.97 Category 1 variables and (b) actuation of systems important to safety (11) The protection system [see Note (ii)]
(12) The spent fuel storage pool structure, including the spent fuel racks.
(13) The reactivity control systems, i.e., control rods, control rod drives, and boron injection system, that are required to achieve safe shutdown of the plant (14) The control room, including its associated vital equipment and life support systems, and any structures or equipment inside or outside of the control room whose failure could result in incapacitating injury to the operators (15) Reactor containment structure, including penetrations [see Note (iv)]
DCPP UNITS 1 & 2 FSAR UPDATE 3.2-5 Revision 15 September 2003 (16) Systems or portions of systems that are required to provide heating, ventilating, and/or air conditioning for safety-related equipment/areas (17) Portions of the onsite electric power system, including the onsite electric power sources, that provide the emergency electric power needed for functioning of plant features included in Items (1) through (16) above (18) Portions of the spent fuel pool cooling system used to remove spent fuel decay heat from the spent fuel pool, and portions of the refueling water purification system used to recirculate and cleanup the contents of the refueling water storage tank Notes: (i) A system boundary includes those portions of the system required to accomplish the specified safety function and connected piping up to and including the first valve (including a safety or relief valve) that is either normally closed or capable of automatic closure when the safety function is required. (ii) For purposes of these criteria, the protection system encompasses all electrical and mechanical devices and circuitry (from sensors to actuation devices input terminals) involved in generating those signals associated with the protective function. These signals include those that actuate reactor trip and, in the event of a serious reactor accident, that actuate ESFs such as containment isolation, safety injection, pressure reduction, and air cleaning. (iii) SSCs that form interfaces between Design Class I and Design Class II or III features are designed to Design Class I requirements. (iv) Certain valves in these systems that are used for accident mitigation only, and do not support safe shutdown following an HE, were qualified for active function for an HE to provide increased conservatism in accordance with Reference 7. 3.2.2 SYSTEM QUALITY GROUP CLASSIFICATIONS GDC 1 requires that systems and components essential to the prevention of accidents be designed, fabricated, erected, and tested to quality standards commensurate with the importance of the safety functions to be performed. This section describes the quality classification system that has been used to implement quality standards that satisfy Criterion 1 for DCPP fluid systems and fluid system components. The discussion also shows the relationship of this classification system to fluid system and fluid system components classification systems in ANSI N18.2, Nuclear Safety Criteria for the Design of Stationary Pressurized Water Reactor Plants(1), and SG 26. DCPP UNITS 1 & 2 FSAR UPDATE 3.2-6 Revision 15 September 2003 DCPP SSCs are classified as Design Class I, II, or III. Design Class I is Seismic Category I and is further categorized as PG&E Quality/Code Class I, II, or III.
Design Classes II or III are usually Nonseismic Category I and have no PG&E quality/code class designation. Specific requirements as dictated by the quality standards applicable to the respective commercial (ASME, ANSI, or ASA) code classes are also applicable. However, some Design Class II components have been seismically designed, e.g., items in the Seismically Induced Systems Interaction Program, specific components required for post-HE shutdown, CCW header C components, and items that were designed for the DE pursuant to RG 1.143. For this reason, there is not a direct correlation between design class and seismic category (except that all Design Class I features are Seismic Category I). In addition, the classification of Seismic Category I does not indicate which of the three design basis earthquakes a feature has been qualified for, nor whether that qualification is for passive or active function (except that all electrical Class 1E and Instrument Class IA components are qualified to remain operable for all three design basis earthquakes). The design basis function of the equipment determines the type of seismic qualification required. These classifications and their relationships are illustrated in Table 3.2-2 and discussed below. 3.2.2.1 Design Class I, Quality/Code Class I Fluid Systems and Fluid System Components 10 CFR 50.55a requires that certain components of the reactor coolant pressure boundary be designed, fabricated, erected, and tested in accordance with the requirements for Class A(a) components of Section III of the ASME Boiler and Pressure Vessel Code, or the most recently available industry codes and standards. Code Class I has been applied to those components of the reactor coolant pressure boundary and implements the quality standards that satisfy the requirements of Section 50.55a, 10 CFR 50. DCPP Code Class I components of the reactor coolant pressure boundary are listed in the DCPP Q-List(8), along with the industry codes and standards used for their design, fabrication, erection, and test. The Code Class I classification includes the components of the reactor coolant pressure boundary identified as Safety Class I in ANSI N18.2 and Quality Group A in SG 26. 3.2.2.2 Design Class I, Quality/Code Class II Fluid Systems and Fluid System Components Generally, Code Class II has been applied to include fluid systems and fluid system components that are either:
(1) Part of the reactor coolant boundary, but excluded from Code Class I requirements by Section 50.55a of 10 CFR 50 (2) Not part of the reactor coolant pressure boundary, but part of:
DCPP UNITS 1 & 2 FSAR UPDATE 3.2-7 Revision 15 September 2003 (a) Systems or portions of systems(b) that are required for emergency core cooling, postaccident containment heat removal, or postaccident containment atmosphere cleanup (b) Systems or portions of systems that are required for reactor shutdown and residual heat removal (c) Those portions of the main steam, feedwater, and steam generator blowdown systems extending from and including the secondary side of steam generators up to and including the outermost containment isolation valves, and connected piping up to and including the first valve (including a safety or relief valve) that are either normally closed or capable of automatic closure during all modes of normal reactor operation (d) Systems or portions of systems that are connected to the reactor coolant pressure boundary and are not capable of being isolated from the boundary during all modes of normal reactor operation by two valves, each of which is either normally closed or capable of automatic closure Code Class II fluid systems and fluid system components are listed in the DCPP Q-List (see Reference 8), along with the industry codes and standards used for their design, fabrication, erection, and testing. 3.2.2.3 Design Class I, Quality/Code Class III Fluid Systems and Fluid System Components Generally, Code Class III has been applied to include fluid systems and fluid system components not part of the reactor coolant pressure boundary, nor included in Code Class II, but part of:
(1) Auxiliary saltwater, component cooling water, and auxiliary feedwater systems, or portions of these systems that are required for (a) emergency core cooling, (b) postaccident containment heat removal, (c) postaccident containment atmosphere cleanup, and (d) residual heat removal from the reactor (2) Systems or portions of systems that are connected to the reactor coolant pressure boundary and are capable of being isolated from the boundary during all modes of normal reactor operation by two valves, each of which is either normally closed or capable of automatic closure (b) The system boundary includes those portions of the system required to accomplish the specified safety function and connected piping up to and including the first valve (including a safety or relief valve) that is either normally closed or capable of automatic closure when the safety function is required.
DCPP UNITS 1 & 2 FSAR UPDATE 3.2-8 Revision 15 September 2003 (3) Those portions of systems other than radioactive waste management systems that contain or may contain radioactive material, and whose postulated failure could result in conservatively calculated potential offsite exposures in excess of 0.5 rem whole body (or its equivalent to parts of the body) at the site boundary or beyond (4) Component cooling water system and seal water systems, or portions of these systems, that are required for functioning of other systems or components important to safety (5) Portions of the spent fuel pool cooling system required for spent fuel cooling, and the refueling water purification system whose postulated failure could result in a loss of refueling water storage tank inventory Code Class III fluid systems and fluid system components are listed in the DCPP Q-List (see Reference 8), along with the industry codes and standards used for their design, fabrication, erection, and testing. 3.2.2.4 Other Fluid Systems and Fluid System Components Fluid systems and fluid system components that are not part of the reactor coolant pressure boundary, not essential to shut down the reactor and maintain it in a safe condition, and not essential to prevent or mitigate the consequences of accidents that could result in potential offsite exposures comparable to the guideline exposures of 10 CFR 100, are not included in the Design Class I classification. These other systems and components are classified as Design Class II or III and are listed in the DCPP Q-List (see Reference 8), along with the industry codes and standards used for their design, fabrication, erection, and testing. They comprise a design class, but have not been assigned a code class. Design Class II includes the fluid systems and fluid system components identified as Quality Group D in SG 26 and as radioactive waste management system in RG 1.143, i.e., those fluid systems and fluid system components that contain or may contain radioactive material, but whose failure would not result in calculated potential exposures in excess of 0.5 rem whole body (or its equivalent to parts of the body) at the site boundary. These fluid systems and fluid system components are in conformance with the accepted industry codes and standards in effect during the design and construction of DCPP. If they were designed and constructed to codes and standards outside of the requirements of SG 26 or RG 1.143, additional quality standards have normally been applied so that the intent has been met. 3.2.2.5 Summary of System Quality Group Classifications Table 3.2-2 summarizes the design and quality group classifications applied to the DCPP SSCs and their relationships to the other methods of classification. DCPP UNITS 1 & 2 FSAR UPDATE 3.2-9 Revision 15 September 2003 Generally, codes and standards were applied prior to issuance of the latest codes and standards, such as the 1971 edition of the ASME Boiler and Pressure Vessel Code, Section III, Nuclear Power Plant Components. In some cases, fluid systems and components were designed and built to codes and standards outside the requirements of SG 26, ANSI N18.2, and RG 1.143 definitions. The classification for those fluid systems and fluid system components that do not fall within the strict definition of SG 26, ANSI N18.2, and RG 1.143 were established prior to ANSI N18.2, SG 26, RG 1.143, and the issuance of revised industry codes and standards. For these fluid systems and fluid system components, the design specifications specified the accepted industry codes and standards in effect during the design and construction of DCPP.
While some portions of the fire protection system components are designated Design Class I, the system is not required to ensure the integrity of the reactor coolant pressure boundary or to shut down the reactor and maintain it in a safe shutdown condition. Fire protection features meet the requirements defined in BTP APCSB 9.5-1 (Reference 5) after 1979 and, where designated Design Class I, are designed to withstand the effects of an HE. 3.
2.3 REFERENCES
- 1. Nuclear Safety Criteria for the Design of Stationary Pressurized Water Reactor Plants. N18.2 American Nuclear Society, August 1970 Draft.
- 2. Quality Group Classifications and Standards for Water, Steam, and Radioactive Waste Containing Components of Nuclear Power Plants, SG 26, Atomic Energy Commission. 3. Seismic Design Classification, SG 29, US Atomic Energy Commission.
- 4. Spent Fuel Storage Facility Design Basis, RG 1.13, Nuclear Regulatory Commission.
- 5. Guidelines for Fire Protection for Nuclear Power Plants, BTP APCSP 9.5-1, Nuclear Regulatory Commission.
- 6. Design Guidance for Radioactive Waste Management Systems, Structures, and Components Installed in Light-Water-Cooled Nuclear Power Plants, RG 1.143, Nuclear Regulatory Commission.
- 7. PG&E Letter to the NRC, DCL-92-198 (LER 1-92-015).
- 8. Classification of Structures, Systems, and Components for Diablo Canyon Power Plant Units 1 and 2 (Q-List), PG&E.
DCPP UNITS 1 & 2 FSAR UPDATE 3.2-10 Revision 15 September 2003 9. Letter from NRC (L. F. Miller) to PG&E (G. M. Rueger), dated December 13, 1993,
Subject:
NRC Inspection of Diablo Canyon Units 1 and 2 (Report No. 50-275, 50-323/93-31) [pages 1 and 2].
- 10. Letter from NRC (A. W. Beach) to PG&E (G. M. Rueger), dated August 15, 1994,
Subject:
NRC Inspection Report 50-275/94-18; 50-323/94-18 (Notice of Violation) [pages 14 and 15]. 3.2.4 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures. DCPP UNITS 1 & 2 FSAR UPDATE 3.3-1 Revision 21 September 2013 3.3 WIND AND TORNADO LOADINGS All seismic Design Class I structures exposed to wind forces are designed to withstand the effects of the design wind, as required by GDC 2. Although a tornado design criterion was not required for the granting of construction permits, the tornado resisting capabilities of Design Class I structures and certain other structures have been reviewed. 3.3.1 WIND LOADINGS The design wind specified has a velocity of 80 mph based on a recurrence interval of 100 years and is in accordance with Reference 8. Section 2.3 gives information on winds recorded at the site during the period of operation of the meteorological facility. A gust factor of 1.1 was applied to the design wind. The resulting dynamic pressures, q, for the design wind velocity distribution, developed in accordance with Reference 1, are given in Table 3.3-1. 3.3.1.1 Containment Structure Wind loads for the containment structure were developed in accordance with Reference 1 for the design wind. Methods and results of force calculations are discussed in Section 3.8. 3.3.1.2 Other Buildings Wind loads for buildings other than the containment structure and the turbine building were developed in accordance with the International Conference of Building Officials Uniform Building Code (UBC) - 1967 Edition. This code designates the site as being in a 20 pound per square foot (psf) zone. To provide added conservatism, it was assumed for design purposes that the site is in a 25 psf zone. This resulted in the following distribution of wind loading with height above ground (the ground - or the base for wind distribution - was conservatively assumed to be at sea level):
Height Wind Load Above Sea Level, (On Flat Surfaces), ft psf 0-29 20 30-49 25 50-99 30 100-499 40
These wind pressures were considered to act upon the gross area of the vertical projection of each Design Class I structure measured above the average level of the adjoining ground. The roof of each Design Class I structure was designed for an uplift DCPP UNITS 1 & 2 FSAR UPDATE 3.3-2 Revision 21 September 2013 pressure equal to three fourths of the wind pressure for the vertical projection, assumed to act over the entire roof area.
A comparison of the UBC wind pressure values with those obtained for the design wind, using the recommendations of ASCE Transactions Paper Number 3269, Wind Forces on Structures (Reference 1), is shown for the auxiliary building in Table 3.3-1. Wind values using the ASCE paper are shown in the table column labeled "1.3q" (1.3 is the drag coefficient recommended by the ASCE paper). The top of the building is 105 feet above the ground surface. The comparison shows that the UBC wind pressures are greater than those recommended in the ASCE paper up to about 70 feet above the ground surface. At greater heights, the ASCE paper wind pressures are more than the UBC pressures. Design of the building considering both the UBC and ASCE paper wind pressures is discussed in Section 3.8.
Since the Design Class II turbine building could potentially be a hazard to adjacent Design Class I structures, the turbine building is designed to withstand a design wind velocity essentially the same as that used for Design Class I structures. Due to the turbine building's unique size, shape, and configuration, UBC and ASCE Transaction Paper Number 3269 criteria are not used to derive wind pressures for this building. The magnitude and distribution of wind pressure loads on the turbine building are based on recommendations given in the United States Navy Design Manual DM-2 (Reference 10), except for the following conservatisms:
- The base for the vertical wind distribution is taken at sea level, rather than the ground elevation at the structure as specified in DM-2.
- A uniform wind pressure based on the average elevation of the roof is considered, rather than using the wind pressure variation with height specified in DM-2.
The turbine building design wind pressures, acting on the exterior surfaces of the building, are as follows:
Main Framing Windward side 25 psf Leeward side 15 psf suction Roof 20 psf suction
Girts and Purlins Windward side 35 psf Leeward side 30 psf suction Roof 35 psf suction
DCPP UNITS 1 & 2 FSAR UPDATE 3.3-3 Revision 21 September 2013 3.3.2 TORNADO LOADINGS Although a tornado design criterion was not required as a condition of the granting of a construction permit, and despite the low probability of occurrence of tornadoes in California, a review of Design Class I and certain non-Design Class I structures was undertaken. The objective of the review was to establish capabilities of the Design Class I structures as designed and constructed to withstand tornado wind pressure and the associated atmospheric pressure drop and tornado-borne missile effects. Additionally, the consequences of tornado-induced failures on the ability to safely shut down the reactor, and/or limit radioactive releases to 10 CFR Part 100 guidelines, are discussed where appropriate.
Additionally, based on the following evaluations performed subsequent to the following review, PG&E has demonstrated that there is a low probability of tornadoes occurring at DCPP:
(1) The station blackout evaluation (Reference 11), using the methodology of NUMARC 87-00 (Reference 12), determined that the annual expectation of tornadoes of severity f2 or greater (i.e., wind speeds greater than or equal to 113 mph) in events per square mile for DCPP is equal to 1.0 x 10 7. As a result, a tornado has not been considered an initiator for a station blackout. The NRC's acceptance of the station blackout evaluation is documented in Reference 13. (2) The Individual Plant Examination for External Events (Reference 14) determined that the annual frequency of excessive tornado winds (i.e., wind speeds greater than or equal to 200 mph) was less than 3.2 x 10-7 per year. As a result, it was judges that a tornado wind-induced scenario is an insignificant contributor to overall core damage frequency and there are no plant vulnerabilities to high winds. The NRC's acceptance of the Individual Plant Examination for External Events evaluation is documented in Reference 15.
Although the reported tornado probabilities are significantly less than the threshold for a credible event, the evaluation of DCPP's tornado effects is still considered as part of DCPP's design and licensing basis. 3.3.2.1 Applicable Design Parameters 3.3.2.1.1 Tornado Winds As previously discussed, there is no DCPP commitment to a specific design basis tornado windspeed. However, the NRC, in the evaluation of PG&E's tornado design criteria, used the methodology of WASH-1300, Technical Basis for Internal Regional Tornado Criteria, dated May 1974, to develop a conservative estimate of a tornado windspeed appropriate for DCPP. The NRC estimated that the design basis tornado DCPP UNITS 1 & 2 FSAR UPDATE 3.3-4 Revision 21 September 2013 windspeed (at a probability level of 10-7 per year) is about 200 miles per hour for the region at the plant site. The 200 mph tornado includes a 157 mph rotational component, a 43 mph translational component, and a differential pressure of 0.86 psi applied at a rate of 0.36 psi per second. Due to the low probability, the postulated tornado is unlikely to strike the site.
Based on the NRC's estimate, PG&E has used 200 mph as the tornado windspeed for determination of the acceptability of certain vital structures, systems, and components (SSCs) required for safe shutdown of the plant.
The general equation for tornado loads is:
()mmpifpPAqCqCW'++= (3.3-1) where:
A = area exposed to wind Cp = effective external pressure coefficient Cpi = internal pressure coefficient qf = effective external velocity pressure qm = effective velocity pressure for calculating internal pressure pm = equivalent elastic missile impact loading No gust factors or variation of wind velocity with height are assumed for tornadoes in evaluating overall response. However, in evaluating small structures (plan dimension less than 80 feet, and area less than 6400 square feet) or critical portions of large structures, an appropriate gust factor is used. Pressure coefficients are taken from Bechtel Corporation Topical Reports BC-TOP-3 and BC-TOP-3A (References 2 and 9). The internal pressure coefficients used in the review include the combined effects on internal pressures from both wind and atmospheric pressure drop. The magnitude and sign of the internal pressure coefficient selected depends on the ratio of open to solid area of the exterior walls, and on which of the following combinations is critical:
(1) Maximum wind load alone (2) Maximum wind + one-half maximum pressure drop without building depressurization (3) Maximum pressure drop with building depressurization (4) Maximum wind + one-half maximum pressure recovery without building repressurization These combinations conservatively represent the effects of the transient atmospheric pressure history. In cases (2) and (4), no building internal pressure equalization is assumed in combining maximum wind with pressure drop or pressure recovery. It is DCPP UNITS 1 & 2 FSAR UPDATE 3.3-5 Revision 21 September 2013 physically impossible for maximum atmospheric pressure drop to occur simultaneously with maximum wind.
The coefficients relating atmospheric pressure drop to velocity pressure are applied to the resultant (rotational plus translational) wind component. This procedure is conservative because only the rotational component causes an atmospheric pressure drop.
The maximum atmospheric pressure drop depends on the wind speed and relative structure size:
- For large structures, the pressure drop is 2.1q, where q is the velocity pressure, corresponding to a pressure range of 1.2 psi to 3.4 psi for tornado wind speeds of 175 mph to 300 mph.
- For small structures and local portions of large structures, the pressure drop is 3.4q, corresponding to a pressure range of 1.9 psi to 5.4 psi for tornado wind speeds of 175 mph to 300 mph.
Velocity pressures (q) are converted to wind speeds (V) using the formula:
q = 0.00256 V2 (3.3-2) where: q = velocity pressure (psf) V = wind speed (mph) 3.3.2.1.2 Tornado Missiles Hypothetical tornado borne missiles considered are:
(1) 108 pound, 4- x 12-inch x 10 feet board at tornado wind velocity
(2) 76-pound, 3-inch x 10 feet schedule 40 pipe at one-third tornado wind velocity (3) 4000 pound auto up to 25 feet above ground - frontal area 20 square feet at one-sixth tornado wind velocity Only one missile is assumed to act at a time. Additional site-specific tornado missiles, such as siding and pull box or hatch covers, are evaluated to determine if they are more severe than the three listed hypothetical missiles. In cases where they were found to be more severe, the site-specific missiles have been included in the determination of the tornado resisting capabilities of SSCs. The maximum velocities for the site-specific missiles are determined using the methods described in Reference 16. If a site-specific DCPP UNITS 1 & 2 FSAR UPDATE 3.3-6 Revision 21 September 2013 missile associated with a pull box or hatch cover is found to result in the calculated tornado resisting capability of exposed SSCs falling below 200 mph, the cover is anchored to prevent it from becoming airborne at wind speeds up to 200 mph. However, capabilities of less than 200 mph for certain SSCs have been found acceptable, based on the tornado analysis described in Section 3.3.2.3 and need not be evaluated for higher wind speeds. These SSCs are identified in Table 3.3-2. 3.3.2.2 Determination of Forces on Structures 3.3.2.2.1 Tornado Wind Forces The basic technical references employed in the tornado review are Topical Reports BC-TOP-3 and BC-TOP-3A.
The safe wind force capability is conservatively determined by deriving the uniform static load applied over the full height of the structure's projected area combined with atmospheric pressure drop at which induced stress in the critical element equals 0.9 Fy in bending and tension and 0.5 Fy in shear in the case of steel, or ACI 318-71 stress levels in the case of concrete structures. For the combined effect of wind and tornado-induced missiles, 1.0 Fy in bending and tension and 0.6 Fy in shear are used. Additionally, overall stability is checked by comparing the overturning moment of the wind forces to the resisting moment due to dead load only. Live and dead loads are considered to act simultaneously with tornado loadings. A load factor of unity is used in this load combination and is justified by the short duration and low probability of tornado loads.
3.3.2.2.2 Forces Derived From Tornado Missile Loading Guidelines for this determination include the derived capability of structures or components for wind loads and an evaluation of the weight, weight to maximum cross-sectional area, and weight to minimum impact area of the potential missile. Tornado missiles produce impulsive load effects that are converted to equivalent elastic loads to be combined with wind loads only at locations where exterior walls protect interior Design Class I components. Missile penetration capabilities are evaluated using the modified Petry formula for concrete, and the Ballistic Research Laboratories and Stanford formula for steel. For concrete structures, the missile impact load is converted to an equivalent elastic load, Pm, using the following procedures: (1) Estimate average impact force: Xg2VWF2i= (3.3-3) DCPP UNITS 1 & 2 FSAR UPDATE 3.3-7 Revision 21 September 2013 where: W = missile weight V = missile impact velocity X = impact penetration as determined by modified Petry formula g = acceleration of gravity (2) Calculate duration of impact force: VX2ti= (3.3-4) (3) Determine dynamic load factor (DLF) versus the ratio of ti/T, where T is the target period and a rectangular impulse is assumed (4) Calculate equivalent static load as the product of impact force, Fi, and the DLF (5) Calculate equivalent elastic load Pm: Pm = Fi x DLF/10 for bending (3.3-5) Pm = Fi x DLF/7.5 for shear (3.3-6) The elastic indices of 10 for bending and 7.5 for shear are based on tests (3) that indicate that when using an elastic impulsive analysis, very high fictitious elastic stress will result. These tests indicate that the fictitious stresses corresponding to an elastic impulsive analysis are generally more than 10 times the usual static ultimate values. (6) Calculate the ultimate buckling load of the missile, Pb. If Pm is less than Pb, use Pm. If Pm is greater than Pb, use Pb in evaluating structural capability. For steel structures, missile impact loads are converted to equivalent static loads and structural response is evaluated using conventional methods, such as conservation of momentum and energy balance techniques, with due consideration for type of impact (elastic or plastic). 3.3.2.2.3 Piping Analysis Design Class I piping in locations exposed to the weather is evaluated against the following tornado-related effects: (1) 200 mph tornado wind loading, and (2) impact by tornado-induced missiles. Primary stresses associated with the first loading is evaluated on limiting pipe spans between supports against 120 percent of the normal allowable stress, as specified by the ANSI B31.1 piping code. Active piping supports DCPP UNITS 1 & 2 FSAR UPDATE 3.3-8 Revision 21 September 2013 (i.e., seismic snubbers) are assumed to resist these first two effects. The second effect, tornado-induced missile impact, is evaluated via the methods described in ANSI N-177 (Reference 4). This evaluation considers the impact interaction energy to determine: (1) crushing of the pipe wall, (2) crushing of the missile, and (3) penetration of the pipe wall. The first two effects are evaluated against material yield strength, and the penetration effect is evaluated via the Ballistic Research Laboratory formula as described in "Design of Structures for Missile Impact," Topical Report BC-TOP-9A, Revision 2, Bechtel Power Corporation, September 1974 (Reference 17). 3.3.2.2.4 Tornado Resisting Capability Table 3.3-2 lists tornado resisting capabilities in terms of safewind velocities for Design Class I structures and Design Class II structures containing Design Class I components. In all cases, the safewind velocity includes wind pressure and associated atmospheric pressure drop effects, and is based on the element of the structure with the minimum capability. For almost all cases, the capability to resist the combined effects of a tornado and the most severe of the tornado-induced missiles is also given in terms of safewind velocity in Table 3.3-2. An expanded list of tornado-borne missiles has also been evaluated for maximum velocity developed and penetration and spalling of reinforced concrete missile barriers. This supplementary analysis is discussed in Section 3.3.2.4. 3.3.2.3 Tornado Analysis The consequences of failure of items in Table 3.3-2 with low or intermediate resistance to tornadoes and tornado-induced missiles have been analyzed. The purpose of this analysis is to determine whether such failure would compromise the capability of shutting the plant down safely.
In this determination, it is conservatively assumed that both units are operating at full power when the tornado strikes, with no prior initiation of shutdown procedures. The tornado is generally assumed to first cause complete loss of offsite power and a turbine trip, as described in Sections 15.2.9 and 8.3 (Tables 8.3-2 and 8.3-3). The plant is assumed to proceed to hot shutdown and then to cold shutdown (if necessary), in accordance with procedures for loss of offsite power operation. The effects of failure of items in Table 3.3-2 have been analyzed for two cases: (a) following loss of offsite power, and (b) as the initiating event for plant shutdown.
Recorded tornadoes in California, and in the continental US in general, have traveled from the south or southwest to the north or northeast. In the analysis of consequences, this direction is postulated as the tornado path; and credit is taken qualitatively for protection afforded to external equipment or exposed components by structures in the postulated path. In addition, the postulated flight path of a site-specific missile, between its installed location and potential targets, is considered in the determination of the vulnerability of external equipment or exposed components. DCPP UNITS 1 & 2 FSAR UPDATE 3.3-9 Revision 21 September 2013 3.3.2.3.1 Major Findings of the Tornado Analysis The following are the major findings of the tornado analysis:
(1) The maximum postulated tornado wind velocity (300 mph) will not cause a LOCA or structural damage impairing containment integrity. (2) All Design Class I structures, or structures housing Design Class I components, are capable of withstanding the wind effects of at least a 225 mph tornado without failure of major structural elements. Their resistance to the tornado-induced missiles corresponds to at least a 150 mph wind velocity with the exception of the fuel handling area steel structure, which has a capability of 127 mph wind velocity. Structures are arranged on the plant site and protected in such a manner that the collapse of structures that do not have tornado-resisting capability will not affect those that must withstand the tornado effects. (3) At calculated safewind velocities of equipment and structures, certain missiles more severe than the three hypothetical missiles are generated, but these site-specific missiles have been included in the determination of the safe-wind velocities. However, in order to ensure that the calculated safe-wind velocity for certain exposed safe shutdown SSCs (e.g., the containment pipeway structure, the exposed portions of main steam leads 1 and 2, and the exposed portions of the feedwater piping) is greater than or equal to 200 mph, certain hatch and pull box covers have been anchored to prevent their becoming tornado-induced missiles. (4) Loss of the following Design Class I equipment, with low or intermediate tornado resistance, will not compromise the capability of shutting down the plant safely. Such loss does not produce radioactive releases greater than those resulting from loss of offsite power operation. Loss of offsite power is a limiting Condition II fault discussed in Section 15.2.9: (a) Outdoor tanks (b) Plant vent (c) Control room ventilation system (d) Auxiliary building and fuel handling area ventilation systems (e) Miscellaneous instrumentation controls and instrument conduits associated with steam and feedwater lines of steam generators 1 and 2 (f) Piping and instrumentation on the CCWS surge tank.
DCPP UNITS 1 & 2 FSAR UPDATE 3.3-10 Revision 21 September 2013 (g) Auxiliary feedwater system piping, valves and instrumentation in the FE and FW areas (h) 480-V switchgear and 125-Vdc inverter room ventilation system (i) Containment penetrations
(j) 4.16-kV switchgear/cable spreading room HVAC system (k) 10 percent steam dump valves (PCV-19 to PCV-22) (5) The externally located Design Class I relief valves on the main steam system are susceptible to damage in the highly unlikely event of a direct impact from one of the tornado-induced missiles. The failure of a single relief valve is a Condition II fault and will result in a safety injection signal (Section 15.2.14). (6) The following components of the emergency power system were evaluated for tornado-induced damage: (a) Diesel generators (b) 4.16-kV vital switchgear and cable spreading rooms. Such damage would not be expected to affect more than one diesel generator or more than one vital 4.16-kV bus. This degree of damage will not affect the shutdown capability of the plant, even if all offsite power is lost. However, tornado missile barriers have been provided to preclude tornado-induced damage to the diesel generators for missiles associated with a 200 mph tornado. Additional girts have been added to the turbine building steel framing at the 4.16-kV switchgear and cable spreading rooms to prevent the exterior siding from becoming a missile during a 200 mph tornado. The analysis method used is described in Reference 9. The turbine building framing modifications are shown in Figures 3.3-1 and 3.3-2. 3.3.2.3.2 Detailed Results of the Tornado Analysis 3.3.2.3.2.1 Auxiliary Building The major portion of the auxiliary building, except for doors and louvers, is capable of withstanding a 300 mph tornado. The rooms housing the battery room ventilation supply and exhaust fans at elevation 163 ft-6 in. are capable of withstanding a 240 mph tornado. All Design Class I equipment within the building is behind concrete walls or within concrete enclosures. The component cooling water surge tank and the 480-V DCPP UNITS 1 & 2 FSAR UPDATE 3.3-11 Revision 21 September 2013 switchgear/125-Vdc inverter room ventilation system located on the roof of the auxiliary building are evaluated for tornado effects in Sections 3.3.2.3.2.2 and 3.3.2.3.2.13, respectively.
Venting to limit effects of atmospheric pressure drop was not included in the design of the auxiliary building, nor assumed in the subsequent analysis of the structure. With the assumption of no venting and the selection of corresponding internal pressure coefficients, the building is conservatively shown to be capable of sustaining at least a 3.4 psi pressure drop. If venting through openings and louvers were assumed, the capability would exceed 300 mph.
The auxiliary building houses equipment for three safety-related ventilation systems. Air intake or exhaust louvers for these systems have limited tornado-resisting capability. The safety-related ventilation systems within the auxiliary building potentially affected by tornado are: (a) the main auxiliary building ventilation system (see Section 9.4.2), (b) the control room ventilation system (see Section 9.4.1), and (c) the fuel handling building ventilation system (see Section 9.4.4). Section 3.3.2.3.2.3 has additional information on fuel handling building ventilation system tornado capabilities. The consequences of tornado damage affecting these ventilation systems are discussed below.
The main auxiliary building ventilation equipment that is potentially vulnerable to tornado damage is located in the auxiliary building at elevation 140 ft. Air intake openings and equipment access panels create potential tornado vulnerability for this area, although the containment, turbine building, and fuel handling building structures provide protection from tornado missiles. Separation of the redundant auxiliary building ventilation supply fans ensures that cooling air to safe shutdown equipment would be available should a tornado generated missile damage one supply fan. Damage to the ventilation control components could cause inlet vane dampers to fail open, but supply fans would continue to run. Although intake louvers will yield and could be forced inward at tornado wind speeds, blockage of the auxiliary building intake openings is considered highly unlikely.
Control room ventilation equipment is located in the auxiliary building at elevation 154 ft-6 in. in a mechanical equipment room. Rooms to the east of the mechanical equipment room contain condenser units required for control room cooling, but not required for ventilation.
Three types of louvers are part of the control room HVAC (see Figure 9.4-1): (a) inlet louvers tied by ductwork to dampers and inlet filter banks, (b) exhaust louvers tied by ductwork to dampers, and (c) inlet and outlet louvers associated with the aircooled condensers.
At a wind speed of about 100 mph, the louver yields in bending, or the louver attachment to the louver frame yields. A deformed louver assembly could be blown inward at a higher wind speed and could damage related components, such as filters DCPP UNITS 1 & 2 FSAR UPDATE 3.3-12 Revision 21 September 2013 and dampers, or buckle attached ductwork. The redundant supply fans are not considered vulnerable to such damage because of their physical location in relation to the inlet and exhaust louvers, and because of the number of components (dampers, filters, etc.) in the ductwork between the louvers and the fans. Complete blockage of the ducts by the damaged louvers is highly unlikely. As a result, the control room HVAC is most likely to continue operation in Mode 1 following a tornado.
Without a simultaneous control room fire or accident, operation of other components is not required to maintain adequate temperature conditions for personnel or instrumentation in the control room during post-tornado shutdown. The redundant aircooled condensers are not considered vulnerable to damage from being hit by displaced louvers. A condenser could be damaged by a tornado-induced missile penetrating through the louvers.
Multiple missiles would be required to render inoperative more than one of the four condensers serving the control room HVAC systems of the two units. Even if all inlet ducts were blocked by damage or by loss of air to the pneumatic dampers, and if all aircooled condensers were rendered inoperative, operators would take appropriate action based on plant conditions.
Fuel handling building ventilation equipment located in Area L of the auxiliary building at elevation 100 ft is potentially vulnerable to tornado damage because of supply fan air intake openings.
These air intake openings are fully shielded to the south (Unit 1) and north (Unit 2) by the containment structures. Significant shielding is afforded these air intakes by the pipeway structure and turbine building to the west. The fuel handling building supply fans are located in a compartment beneath the air intakes and are not vulnerable to the effects of a tornado missile. In the unlikely event that a missile were to enter the fuel handling building ventilation equipment through the air intake, supply fan discharge ducting and dampers could be impacted. While damage to the ducting could occur that could degrade system performance, the supply fans would still be expected to provide adequate air flow to the fuel handling building vital equipment.
The battery room ventilation equipment in the fan rooms on the auxiliary building roof on elevation 163 ft-4 in. is nonsafety-related and damage to this equipment due to a tornado does not affect the safe shutdown capability of the plant. 3.3.2.3.2.2 Component Cooling Water System Surge Tank The surge tank of the CCWS (Section 9.2.2) is supported horizontally at the L-line on the roof of the auxiliary building (see Figures 1.2-21 and 1.2-25). A baffle at the tank's mid-length extends about 40 percent up the tank volume to divide it into two compartments. Each compartment has its own liquid level instrumentation (see Figure 3.2-14) and a 6-inch surge line to one of the two independent vital trains of the CCWS. Each surge line is fed by a makeup line with an air-operated level control valve. DCPP UNITS 1 & 2 FSAR UPDATE 3.3-13 Revision 21 September 2013 This connection is made inside the auxiliary building. The high-level alarm actuates above the top of the tank divider.
The pressurized tank vent discharges through a normally closed back-pressure control valve onto the roof of the auxiliary building. The roof is surrounded by a parapet and sloped toward a series of 4-inch roof drains. These drains feed into common 6-inch drain lines to the storm sewer and then to the discharge structure.
In case of radioactivity in the CCWS, the vent valve closes. Any overflow from the CCWS discharges through a relief valve at the top of the tank into a drain line to the auxiliary building sump. The foundation under the surge tank is sloped toward two 4-inch drains feeding a common 4-inch drain line also to the auxiliary building sump. The tank has an aluminum skirt from its horizontal diameter to the foundation to prevent rain water from flowing into the auxiliary building sump.
As shown in Table 3.3-2, the tank is capable of withstanding a 250 mph wind velocity, or a 200 mph wind plus associated tornado-induced missiles. The weakest element of the tank structure is the anchorage, which fails in bearing on concrete and results in only minor displacement of the tank. It is highly unlikely that such displacement would result in either rupture of the relief valve header or surge lines.
The surge lines run from beneath the surge tank, along the auxiliary building roof, and down the outside wall to elevation 140 feet-4 inches, where they enter the auxiliary building. These lines are exposed to tornado-induced missiles after they exit from beneath the surge tank until they enter the auxiliary building. The relief valve header, the vent and valve, and the two sets of liquid level instrumentation are on the east side of the surge tank and are susceptible to damage by tornado-induced missiles. Tubing, valves, and instrumentation added for surge tank nitrogen/air pressurization are also susceptible to damage by tornado-induced missiles. The tank does provide considerable protection in the postulated path of the tornado, particularly to instrumentation taps located below the operating liquid level of the tank. An exposed raceway carries the common vital conduit from the surge tank to the control room.
Failures of the raceway, the liquid level instrumentation, the nitrogen/air pressurization components, and pipes and valves are analyzed in Table 3.3-3. This analysis demonstrates that the CCWS would continue to operate satisfactorily even with postulated tornado damage. The CCWS surge tank is readily accessible from the control room, so immediate assessment of any damage following a tornado is possible.
Release of radioactivity to the discharge structure can result only if the operating portion of the CCWS is radioactively contaminated and if an instrumentation line breaks below the normal liquid level in the surge tank at a point not close to the tank.
Release of water to the auxiliary building sump or 115 ft yard drains could result if a surge line were ruptured by a tornado missile outside of the auxiliary building. Failure of the surge lines are analyzed in Table 3.3-3. DCPP UNITS 1 & 2 FSAR UPDATE 3.3-14 Revision 21 September 2013 3.3.2.3.2.3 Fuel Handling Area Analysis of the basic structure of the fuel handling area, with partial loss of siding, provides a conservative estimate of capability to withstand a wind velocity in excess of 250 mph. Under combined wind and missile load, the worst case analysis, based on elastic behavior, shows resistance to at least a 127 mph wind velocity. Because of the conservatism inherent in the assumptions for these calculations, the resistance to tornado-induced missiles is believed to be considerably higher.
Purlins, girts, siding, roofing, doors, and louvers are damaged at lower wind velocities. They are not essential to the overall structural integrity of the fuel handling area and do not produce missiles more severe than the hypothetical missiles. The metal siding and roofing do not provide significant missile protection for the building contents.
Analysis of potential water loss from the spent fuel pool shows that the water cover remaining over the fuel provides adequate protection against both fuel damage and pool liner penetration from tornado missiles. Water lost from the spent fuel pool can be replenished from on-site water supplies. Therefore, the capability of the fuel handling building ventilation system to maintain a negative pressure in the fuel handling area is not required after a tornado.
The fuel handling building ventilation exhaust ducts and fuel handling area radiation monitors have limited tornado resisting capability. Failure of these components does not affect safe shutdown capability and does not result in significant radiation releases since damage to the spent fuel does not occur as a result of a tornado.
3.3.2.3.2.4 Containment Structure The containment structure, including equipment, personnel, and escape hatches, is capable of withstanding the combined effect of a 270 mph wind velocity and tornado-induced missiles. The containment pipeway structure is capable of withstanding the combined effect of a 200-mph wind velocity and tornado-induced missiles.
Containment pipe penetrations for main steam and feedwater lines for steam generators 1 and 2 and some non-vital and spare electrical penetrations are located within the pipeway structure. No other containment penetrations are exposed to the effects of a tornado. As described in Section 3.3.2.3.2.7, the main steam and feedwater piping have capability to withstand the combined effect of a 200-mph wind velocity and a missile. The non-vital circuits within the electrical penetrations are not required for safe shutdown of the plant. The electrical penetrations for both units are significantly shielded by the turbine building, containment structure, and the auxiliary building. In addition, the pipeway structure affords additional local protection for these penetrations. Therefore, tornado induced damage to these penetrations is considered extremely unlikely and would not affect safe shutdown capability.
DCPP UNITS 1 & 2 FSAR UPDATE 3.3-15 Revision 21 September 2013 Note that in order to maintain a minimum capability of 200 mph for these SSCs, certain pullbox and hatch covers have been anchored in order to prevent them from becoming tornado-induced missiles. 3.3.2.3.2.5 Plant Vent The containment exhaust vent (plant vent) is anchored securely to the containment and can withstand loads from a wind velocity of greater than 300 mph. The internal framing supporting the duct will yield at a wind velocity of about 125 mph, but the duct remains functional at higher wind velocities. The tornado-induced missiles would damage and penetrate the vent. The plant vent handles exhaust from the auxiliary building, fuel handling areas, and penetration area ventilation fans, steam air ejector and gland steam condenser, containment purge system, and gas decay system. The plant vent contains sample probes for the plant vent gas and particulate radiation monitor. The containment purge, steam ejector line, and the gas decay system have radiation monitors prior to discharge to the plant vent.
The fuel handling area and penetration area ventilation systems do not need to be operated while the plant is brought to a safe shutdown condition. The damage to the plant vent will not prevent the auxiliary building ventilation system from exhausting. The containment purge system is normally operated only during extended plant shutdowns, and operation during safe shutdown procedures is not necessary. The remaining process flows exhausted through the plant vent are not necessary for and are unrelated to attaining safe shutdown capability. It is therefore concluded that the plant can be safely shut down without additional radiation exposure to the public, even if the plant vent and its radiation monitoring capabilities are damaged by a tornado. 3.3.2.3.2.6 Design Class I Raceways and Instrumentation Exposed Design Class I raceways are attached to the support structure for the main steam and feedwater lines outside the containment (see Figure 3.3-3). These raceways carry control wiring to actuate various mechanical components of the steam, feedwater, and auxiliary feedwater systems. These items are shadowed from two directions as indicated in Figure 3.3-3. Some of this equipment is located in exposed instrumentation panels on the outside of the containment.
A failure analysis has been performed on these raceways and panels. Two cases were examined: (a) failure with the plant operating normally, and (b) failure with the plant already being shut down due to loss of all offsite power caused by the tornado. The results of this analysis, given in Table 3.3-4, indicate that the plant can be shut down safely.
Main steam pressure transmitters, main feedwater flow transmitters, and auxiliary feedwater flow transmitters associated with steam generators 1 and 2 are located within mechanical panels at elevation 85 ft beneath the pipeway structure. The equivalent transmitters for steam generators 3 and 4 are within the auxiliary building structure and DCPP UNITS 1 & 2 FSAR UPDATE 3.3-16 Revision 21 September 2013 are not vulnerable to tornado damage. In addition, main steam line radiation monitors are located adjacent to main steam lines 1 and 2 near the containment pipe penetrations.
The steam generator pressure transmitters (PT-514 to PT-516 & PT-524 to PT-526) provide a safety injection and main steam isolation signal on low steam generator pressure using two-out-of-three logic. A safety injection signal will be actuated only upon loss of at least two of the three redundant pressure transmitters associated with each steam lead. The safety injection signal can be classed as spurious and is a
Condition II fault discussed in Section 15.2.15. Steam generator pressure indicators for steam generators 3 and 4 are not affected by the tornado, and these steam generators would be used to attain safe shutdown.
The main feedwater system would receive isolation signals as a result of the safety injection signal being produced. With the main feedwater isolation valves closed and the FW pumps tripped, the main feedwater flow transmitters (FT-510, FT-511, FT-520 and FT-521) do not provide relevant information. These transmitters, while conservatively designated as Instrument Class 1A, do not have any safety-related functions.
The auxiliary feedwater flow transmitters (FT-50 and FT-77) provide control room indication and do not have any protective functions. If these transmitters are lost, steam generator level (especially wide range steam generator level, which is recorded) would provide an assessment of the status of the auxiliary feedwater system to steam generators 1 and 2. If steam generator 1 and/or 2 level cannot be controlled due to damage to auxiliary feedwater system components in the pipeway structure, auxiliary feedwater to steam generator 1 and/or 2 can be secured and the plant can be safely shutdown using steam generators 3 and 4.
The main steam line radiation monitors are provided to detect primary-to-secondary radiation releases resulting from a steam generator tube rupture accident. Such an accident condition is not assumed to occur concurrently with extreme weather conditions. Therefore, tornado-induced failure of these instruments is of no consequence and does not affect safe shutdown capability.
A seismic trip sensor located in the pipeway area is one of three sensors that generate a reactor trip signal if seismic accelerations exceed a predetermined level using two-out-of-three logic. Loss of power to these sensors will not result in a trip signal. Damage to this instrument and its resultant output signal is of no consequence and does not affect safe shutdown capability. 3.3.2.3.2.7 External Design Class I Piping and Valves Main steam leads 1 and 2, and associated feedwater piping, penetrate the containment at elevation 129 feet. This piping is carried to the turbine building at elevation DCPP UNITS 1 & 2 FSAR UPDATE 3.3-17 Revision 21 September 2013 112 feet-6 inches on a support structure external to the containment (see Figures 1.2-5 and 1.2-21 for Unit 1, and Figures 1.2-10 and 1.2-28 for Unit 2). This piping and associated steam relief valves are Design Class I up to and including the first isolation valves outside the containment. On main steam leads 1 and 2, the relief valves are located directly on the piping. On main steam leads 3 and 4, which are enclosed within the auxiliary building, the relief valves are located on separate headers on the roof of the enclosure at elevation 143 feet (see Figures 1.2-4 and 1.2-21).
Analysis of the main steam and main feedwater piping for wind stress indicates a negligible stress increase, even for the 200-mph wind velocity. The capability of this piping to withstand combined tornado wind and tornado-induced missile impact is limited to 200 mph. At this wind velocity, the piping is capable of supporting all loadings associated with the most severe tornado-induced missile without penetration of the pipe wall. In order to maintain this capability, certain pullbox and hatch covers have been anchored to prevent them from becoming tornado-induced missiles.
The 4-inch main steam piping to the AFW pump turbine is vulnerable to damage from a tornado missile. A break in this piping would be considered a minor secondary pipe break, which is a Condition III fault discussed in Section 15.3.2. A breach in this 4-inch main steam piping could cause a loss of the AFW pump 1 turbine. The motor-driven AFW pump 3 supplying steam generators 3 and 4 would still be available for plant shutdown. In addition, AFW pump 2 would be available, although there is a potential for wind induced damage to its level control valves as discussed below.
The steam generator safety relief valve spindles are considered vulnerable to direct impact by a missile. Such impact could result in severance of the spindle. However, this is not expected to result in a valve discharge or pressure boundary leakage. The relief valves represent extremely small targets for a missile and a direct hit is considered extremely unlikely. The relief valve headers for leads 3 and 4 of both units are almost completely protected by the containment and auxiliary building concrete structures, particularly from the south and southwest. The containment for Unit 1 also provides considerable protection from those directions to the relief valves on leads 1 and 2 for that unit.
The single failure of a steam generator safety relief valve is a Condition II fault (Section 15.2.14). The occurrence causes a safety injection signal.
The mechanical portions of other externally located valves associated with leads 1 and 2 are not considered susceptible to tornado or tornado missile damage. The following other events related to these valves are considered: (a) loss of air supply to main steam isolation valve, (b) rupture of the bypass line around a main steam isolation valve, (c) failure of the motor operator on a main feedwater isolation valve, and (d) loss of air supply to main feedwater control and bypass valves.
The main steam isolation valve is held open by compressed air. The valve has an integral pneumatic supply to hold the valve open (or to open it one time, if closed), upon DCPP UNITS 1 & 2 FSAR UPDATE 3.3-18 Revision 21 September 2013 loss of the main air supply. Such loss would, therefore, have no consequences. If the integral pneumatic supply is damaged, the valve is driven shut by an internally mounted spring. The inadvertent closing of a main steam isolation valve is similar to the inadvertent closing of a turbine stop valve, a Condition II fault whose consequences are discussed in Section 15.2-7.
The bypass around a main steam isolation valve is a 3-inch line. Its rupture by missile impact qualifies as a minor secondary system pipe break, as analyzed in Section 15.3.2. The consequences of such a break are considerably less than those of a 6-inch-diameter break, which is the limiting case in that section and is equivalent to the inadvertent opening of a steam relief valve.
Failure of the motor operator on a main feedwater isolation valve causes the valve to remain as is. The valve is normally open during plant operation. A Design Class I feedwater control/bypass valve and a Design Class I check valve are installed upstream of each main feedwater isolation valve. These valves provide additional means of isolating the feedwater line and provide the pressure boundary for operation of the auxiliary feedwater system if the isolation valve were to fail open. Therefore damage to the isolation valve operator or a loss of power that would cause it to fail "as-is" would have no affect on the integrity of the feedwater line or operation of the auxiliary feedwater system.
The air operators on the main feedwater control and bypass valves fail in the closed position upon loss of air or loss of dc power to the trip solenoid. The isolation valve and check valve installed downstream of each control/bypass valve provide additional means of isolating each feedwater line. A malfunction of the feedwater control or bypass valves, such as accidental full opening, is a highly unlikely consequence of tornado damage since these valves fail closed. However, this type of malfunction (a Condition II fault) is discussed in Section 15.2.10.
The auxiliary feedwater (AFW) system piping and valves located in the FE and FW areas, at approximately 130 ft elevation (supply to SGs 1 and 2), were identified as potentially vulnerable to tornado wind and induced missile effects. This piping has been analyzed to withstand over 300 mph wind velocity. Hence, it is very unlikely that these components will be damaged due to tornado winds. However, the AFW piping and valves in these areas are still susceptible to tornado-induced missile damage. On the basis that only one missile will occur at a time, such damage is limited to only one train of the AFW system. Thus, there will be no complete loss of AFW system function because redundant trains are available.
The following events related to AFW valves have been considered: (a) failure of the motor operator on an auxiliary feedwater control valve, (b) failure of the electro-hydraulic auxiliary feedwater level control valves, and (c) failure of the motor-operated steam supply valve to the turbine-driven auxiliary feedwater pump.
DCPP UNITS 1 & 2 FSAR UPDATE 3.3-19 Revision 21 September 2013 The motor-operated AFW level control valves (LCV-106 and LCV-107) for the turbine-driven AFW pump are normally open. These valves are used for remote manual throttling to maintain an appropriate steam generator level if the turbine-driven AFW pump is utilized. In case of loss of power to these valves, the turbine-driven AFW pump can be secured if necessary and secondary system decay heat removal can be accomplished using steam generators 3 and 4 and motor-driven AFW pump 3. None of these components are vulnerable to tornado damage as they are contained within the auxiliary building structure.
The electro-hydraulic AFW level control valves (LCV-110 and LCV-111) for the motor-driven pump that supplies AFW to steam generators 1 and 2 fail in the open position on loss of power. These valves are used for remote manual throttling to maintain an appropriate steam generator level if the motor-driven AFW pump to steam generators 1 and 2 is utilized. In case of loss of power to these valves, the motor-driven AFW pump can be secured if necessary and secondary system decay heat removal can be accomplished using steam generators 3 and 4 and motor-driven AFW pump 3. None of these components are vulnerable to tornado damage since they are contained within the auxiliary building structure.
Loss of remote manual control to the above noted AFW level control valves may result in some excess in feedwater injection from the AFW system. A much greater excess in feedwater injection, such as results from inadvertent full opening of a main feedwater supply valve, is a Condition II fault discussed in Section 15.2.10.
Failure of the motor operator on the steam supply valves to the turbine-driven AFW pump (FCV-37) causes the normally open valve to remain in the as-is position. The valve is not required to change position for operation of the AFW system. Therefore, damage to this valve operator or its electrical circuitry does not affect safe shutdown capability.
Loss of air supply or power to the 10 percent steam dump valves (PCV-19 to PCV-22) will cause the valves to remain in their closed position. This is the preferred failure mode, as opposed to the steam dump valves failing open causing uncontrolled depressurization of the steam generators. Steam generator pressure transmitters PT-516A and PT-526A provide nonsafety-related control signals to the 10 percent steam dump valves and could be damaged by a tornado. If the control schemes for these valves are damaged, the plant would remain at hot standby using the steam generator safety relief valves for secondary system heat removal until the secondary system is depressurized by manual operation of these valves using their handwheels. Therefore, tornado-induced damage to the 10 percent steam dump valve control scheme does not adversely affect safe shutdown capability.
The steam generator blowdown tank vent condenser and the 3/4-inch CCW supply and return piping are located outdoors at elevation 140 ft above the auxiliary building. This piping is part of CCW Header C and as such is a non-essential heat load. Tornado damage to the supply lines, return lines, or the steam generator blowdown tank vent DCPP UNITS 1 & 2 FSAR UPDATE 3.3-20 Revision 21 September 2013 condenser was evaluated to confirm that the CCW system leakage will be significantly less than the maximum acceptable system leakage. Therefore, tornado-induced damage to these components does not adversely affect CCW system operation.
Four-inch diameter containment hydrogen purge lines are located outdoors at elevation 140 ft above the auxiliary building. This system is used if accident conditions produce potentially explosive hydrogen concentrations inside containment. Given that extreme weather conditions do not have the capability to result in inside-containment accidents, the use of these lines would not be required after a tornado. Therefore, tornado-induced damage to these lines is of no consequence. 3.3.2.3.2.8 Turbine Building Analysis of the basic structure of the turbine building, with partial loss of siding, provides a conservative estimate of capability to withstand a wind velocity of 225 mph. Under combined wind and missile load, the worst-case analysis based on elastic behavior shows resistance to at least 175 mph.
The 24-inch concrete walls of the turbine building can resist a combined wind and missile load corresponding to a wind velocity of 272 mph. The corresponding value for 12-inch concrete walls is 200 mph.
Purlins, girts, siding, roofing, doors, and louvers are potentially damaged by tornado wind velocities less than 175 mph. The siding system at the exterior walls (north and east for Unit 1, south and east sides for Unit 2) protecting the vital 4.16-kV switchgear and cable spreading rooms can withstand tornado winds with a velocity up to 200 mph. The roofing, siding, and louvers cannot withstand the tornado-induced missiles discussed in Section 3.3.2.1.2.
The turbine building contains major components of the emergency power system, described in Chapter 8, which are: (a) the three 4.16-kV vital buses (buses F, G, and H) for each unit, including associated switchgear, and (b) the six diesel generators, three for each unit. The possibility of tornado-related damage to these emergency power system components, and the potential effect on safe shutdown capability, has been considered and are discussed below. Such damage has potential impact on safe shutdown capability only if all offsite power is lost.
Vital 4.16-kV switchgear for the emergency power system is located at elevation 119 feet between column lines D and G (see Figures 1.2-14 and 1.2-18). Cable spreading rooms associated with this switchgear are located immediately below the switchgear at elevation 107 feet (see Figures 1.2-15 and 1.2-19). Both the switchgear and the cable spreading rooms are located above the concrete portion of the turbine building wall. Exterior turbine building walls in these areas consist of steel siding installed on a structural steel framework. Separation between components associated with each of the bus sections is provided by reinforced 8-inch concrete block partitions, as shown in Figure 3.3-4. DCPP UNITS 1 & 2 FSAR UPDATE 3.3-21 Revision 21 September 2013 As shown in Figures 1.2-2 through 1.2-32, the turbine building structure provides protection from tornado-generated missiles above, below, and on two sides of the 4.16-kV switchgear and cable spreading rooms. The remaining two sides (north and east side for Unit 1, south and east side for Unit 2) are enclosed by steel siding on a structural steel framework. Some protection is provided by the structural steel, but tornado-generated missiles could penetrate the siding and damage emergency power system components. On the north and south sides (north side for Unit 1, south side for Unit 2), only components associated with bus H are directly exposed to such damage. On the east side, the ends of compartments housing components associated with buses F, G, and H are similarly exposed to tornado-generated missiles.
Concrete block partitions between vital buses minimize the possibility that tornado-generated missiles penetrating the north or south (north for Unit 1, south for Unit 2) turbine building walls would damage components associated with buses F and G.
The containment building for each unit and the auxiliary building provide a substantial amount of tornado missile protection for the east turbine building wall. In addition, the topography of the site reduces the likelihood that tornado-generated missiles would damage emergency power system components by penetrating the east wall of the turbine building.
Tornado-related damage would not be expected to affect more than one vital 4.16-kV bus. Such damage would not affect the capability for safe shutdown, even with the loss of offsite power. The diesel generators are located in the west side of the turbine building, three between column lines 1 and 5 (Figure 1.2-16) and three between column lines 31 and 35 (Figure 1.2-20). The diesel generators in each group are separated from each other by 10-inch concrete walls. The exterior walls to the north, south, and east protecting the EDGs are constructed of minimum 12-inch concrete capable of withstanding 200 mph tornado wind and missile loads. Openings in the west walls of the turbine building between these column lines, and between floor elevations 85 and 107 feet, for diesel generators are protected by tornado missile barriers. The tornado missile barriers, consisting of closely spaced beams, are provided to protect the diesel generator compartments and their air intakes at elevation 85 ft at the west wall of the turbine building. The barriers are designed to withstand the combined effects of a 200 mph wind and tornado missiles.
The diesel generator compartment ventilation system (see Section 9.4.7) uses the diesel generator silencer rooms and an external plenum as the exhaust air flow path to the atmosphere. The external plenum, located at the west wall of the building, is integral with the turbine building structural framing and is enclosed on three sides and the bottom with corrugated metal siding. The east side of the plenum is open to the diesel generator silencer rooms at elevation 107 feet and the top is open to the DCPP UNITS 1 & 2 FSAR UPDATE 3.3-22 Revision 21 September 2013 atmosphere. The plenum was added in order to improve the operation of the ventilation system when the diesel engines are operating under extreme weather conditions.
The external plenum, including the steel framing, girts, siding, and turning vanes, is designed for the effects of 200 miles per hour tornado wind loads. The design is performed in accordance with the methodology given in BC-TOP-3A (Reference 9). The tornado wind speed corresponds to that used for the design of the added girts, which support the siding at the vital 4.16-kV switchgear and cable spreading rooms (see Section 3.3.2.3.1 and Table 3.3-2).
Due to its exposed location, the exhaust air plenum may be vulnerable to damage by a tornado-generated missile. The impact of a missile on the plenum could result in localized damage to the framing, which supports the plenum, or puncture of the siding, which forms the exterior boundary of the plenum. However, the plenum represents a small vulnerable area for missile impact, and is not designed for missile loads.
Since the only function of the ventilation exhaust plenum is to provide a directed flow path for the ventilation air to exhaust to the atmosphere, the maintenance of an airtight pressure boundary is not required. The primary requirement is that damage to the structure would not result in blockage of the flow path. It is unlikely that damage to the exhaust plenum by a missile would block the flow path sufficiently to have a significant impact on the function of the plenum. In the unlikely event that a tornado-generated missile did cause sufficient damage to the plenum to impact airflow, such damage would not be expected to affect more than one diesel generator and would not compromise the capability to achieve safe shutdown of the plant. The diesel exhaust lines routed above elevation 107 ft are potentially vulnerable to tornado wind loads if the turbine building siding is blown off. Analyses demonstrate that the exhaust lines will not be affected by tornado wind loads. A tornado missile striking one of these lines has less significant consequences than the missile striking components within a 4.16-kV switchgear room.
The electrical conduits for EDG 2-3 at elevation 140 ft are routed close to the concrete floor and are shielded from tornado influences to some extent by CRPS piping and other raceways. The containment structure and the auxiliary building provide significant shielding for these raceways. The consequences of tornado damage of these conduits are no more significant than the missile striking components within a 4.16-kV switchgear room.
Banks of large diameter conduits from the 4.16-kV cable spreading rooms routed through the nonvital 12-kV switchgear room are separated by electrical division and are encased in rigid fireproofed vaults that afford some protection against tornado debris and minor missiles. This room is constructed of 12-inch reinforced concrete capable of withstanding tornado wind and missile loads. However, exhaust air louvers in the east wall provide a pathway for a tornado missile to strike banks of conduits routed directly in front of the wall penetrations. These wall penetrations are afforded a significant amount DCPP UNITS 1 & 2 FSAR UPDATE 3.3-23 Revision 21 September 2013 of shielding by the main and auxiliary transformers to the east. It is not credible for a tornado missile to strike more than one bank of conduits because of the spatial separation between the redundant conduits. The consequences of this tornado missile damage, which could affect one electrical division, are no more significant than a missile striking components within a 4.16-kV switchgear room.
The 4.16-kV switchgear room/cable spreading room ventilation system supply fans and supply ducting at elevation 119 ft and exhaust ducting at elevation 140 ft could be vulnerable to the effects of a tornado if the building siding is blown off. Compartment heatup analyses demonstrate that loss of this ventilation equipment does not jeopardize electrical equipment in these compartments due to elevated temperatures. Therefore, this ventilation system equipment is not required for safe shutdown of the plant. The CCW heat exchangers and associated CCW and ASW piping, valves, and instrumentation are protected from the effects of tornado because of their location within the turbine building.
Plant protection system inputs from the main turbine first stage pressure are protected from the effects of tornado wind and missiles. The process tubing is routed in protected areas within the turbine building and is enclosed within a protective barrier. The sensing transmitters and signal circuitry are contained within the CCW heat exchanger room. 3.3.2.3.2.9 Outdoor Design Class I Tanks Design Class I tanks located at the east end of the auxiliary building (Figure 1.2-2) include the condensate storage tank, the fire water storage and transfer tank, and the refueling water storage tank. These are concrete-protected steel tanks capable of withstanding a wind velocity of about 170 mph. They are also capable of withstanding a 150 mph wind with combined tornado-induced missiles. These capabilities do not take credit for the concrete encasement. When the concrete encasement is considered, these tanks are capable of withstanding a wind velocity of 300 mph. The anchorages that prevent the tanks from overturning have a design capacity greater than a 300 mph wind load. Based on these considerations, a tank failure producing an instantaneously large leak and flood is extremely unlikely, particularly as the tanks are concrete-protected. The 5.0-million-gallon Design Class II raw water reservoir provides a backup source of water supply.
The refueling water storage tank (Section 6.3.2) is normally used to supply borated water to the refueling canal for refueling operations when the plant is already in a safe shutdown condition. Its Design Class I function is to supply borated water to ECCS pumps and containment spray pumps following a safety injection signal.
The fire water storage and transfer tank, with a 300,000 gallon capacity (Section 9.5.1), is the shared backup source of fire water. The normal source of fire water is the shared raw water reservoir. The fire water storage and transfer tank inventory may also be used to supplement the condensate storage tank for AFW and as a source of makeup DCPP UNITS 1 & 2 FSAR UPDATE 3.3-24 Revision 21 September 2013 water to the spent fuel pool. While tornado-induced damage to the fire water storage and transfer tank is considered extremely unlikely, such damage would not affect safe shutdown capability of the units. The raw water reservoir provides an alternate capability for the functions performed by this tank.
The condensate storage tank (Section 9.2.6) supplies normal makeup and rejection requirements of the steam plant. Its Design Class I function is to provide 200,000 gallons for Unit 1 and 166,000 gallons for Unit 2 (out of a total capacity of 425,000 gallons) for the auxiliary feedwater system during the plant cooldown to 350°F. While tornado-induced damage to the condensate storage tank is considered extremely unlikely, such damage would not affect safe shutdown capability. The raw water reservoir provides an alternate capability for the function performed by this tank.
The raw water reservoir is the backup source of auxiliary feedwater. The reservoir (Section 9.2.3) is below grade, concrete- and PVC-lined, and divided into two compartments to permit maintenance without removing the reservoir from service.
The total potential demand on the reservoir resulting from total loss of water inventory in the condensate storage tanks for both units is 392,000 gallons. This amount of water represents less than 10 percent of the capacity of both compartments in the reservoir and about 16 percent of one compartment. Based on APED-5696, Tornado Protection for the Spent Fuel Storage Pool (Reference 5), a relatively large and shallow pool, such as the raw water reservoir, is susceptible to partial dewatering by a tornado of specific size and path. A detailed analysis of water loss has not been made since simultaneous, essentially complete loss of water from both tanks and from the reservoir is not considered credible. 3.3.2.3.2.10 Intake Structure The intake structure and the ASW pump room vent shaft extensions are capable of withstanding the combined effect of a 240-mph wind velocity and a missile. The gantry crane for servicing equipment within the structure is susceptible to overturning at a wind velocity above 110 mph in its anchored position. In this position the crane is located near the north end of the craneway approximately 80 feet from the vent shaft above the intake structure; damage to the structure or to its components from the crane is considered extremely unlikely. The crane is kept in its anchored position when not in use. 3.3.2.3.2.11 Design Class II Outdoor Electrical Equipment In addition to the structures listed in Table 3.3-2, the tornado-resisting capability of Design Class II outdoor electrical equipment has been evaluated. This capability ranges from greater than 250 mph for main transformers, to about 100 mph for such equipment as the isophase bus duct structure. No missiles more severe than the hypothetical missiles are generated by a tornado-induced failure of this equipment. In addition, no Design Class I equipment is endangered by any such failure. DCPP UNITS 1 & 2 FSAR UPDATE 3.3-25 Revision 21 September 2013 3.3.2.3.2.12 Control Room Pressurization Equipment The control room pressurization system (CRPS) fans, ductwork, dampers and associated controls located on the turbine building operating deck and the auxiliary building roof have the potential of being damaged by the effects of a tornado.
The CRPS is used to minimize radioactive contamination in the control room following an accident. Since a tornado is not assumed to occur concurrently with an accident or cause an accident producing significant releases, operation of the CRPS after a tornado is not required. The control room ventilation system can operate in ventilation mode 1 (normal ventilation) or ventilation mode 3 (100 percent recirculation) if the CRPS is impaired. Either mode of ventilation operation is acceptable under these circumstances. Although tornado protection of the CRPS is not required functionally, PG&E committed to design the system considering tornado missile effects.
The CRPS is of the "dual air inlet" type where two widely spaced inlets are located on opposite sides of potential radioactive gas sources. Because damage to the ducting might affect the capability of the system to protect the operators and because the duct is not considered to have a redundant counterpart, the CRPS ductwork is protected against tornado missiles.
Only one missile is assumed to act at any time (see Section 3.3.2.1.2). Missile protection is only provided where the single missile may damage both redundant components. CRPS instrumentation is installed such that a single missile will not damage both redundant components. The electrical cable and conduits are considered small targets having a low probability of impact. Also the Class I electrical conduit separation criteria provides a degree of assurance that a single tornado missile will not damage redundant circuits.
On the basis of low probability, tornado design criteria were not required for the granting of construction permits for DCPP (Reference Section 3.3). Standard Review Plan (SRP) 3.5.1.4, Revision 0, dated November 24, 1975, states:
"...at the operating license stage, applicants who were not required at the construction permit stage to design to one of the above missile spectra...should show the capability of the existing structures and components to withstand at least missiles 'C' and 'F'..."
Missiles "C" and "F" are:
Missile Horizontal Velocity, ft/sec C Steel rod, 1-in. diameter, 3-ft long, 8 lb 259 F Utility pole, 14-in. diameter, 35 ft long, 1500 lb 241
DCPP UNITS 1 & 2 FSAR UPDATE 3.3-26 Revision 21 September 2013 As shown in Table 3.3-5, missile "F" will attain a maximum missile elevation of 5 feet above ground elevation. CRPS equipment located on the turbine operating deck, elevation 140 ft, is well above the 5 foot limitation and would not be affected by missile "F." Therefore, the only missile for consideration is the 1-inch diameter steel rod. 3.3.2.3.2.13 480-V Switchgear and 125-Vdc Inverter Room Ventilation System The portion of the ventilation system for the 480-V switchgear and 125-Vdc inverter rooms (see Section 9.4.9) located on the auxiliary building roof is potentially vulnerable to the effects of a tornado. Potentially affected equipment includes the redundant supply and exhaust fans, dampers, ducting, and instrumentation and electrical raceways supporting the operation of the ventilation system.
This ventilation equipment is shielded on four sides by the containment structure, the turbine building, a ventilation fan room, and the fuel handling building superstructure. Based on this protected location, the Seismic Category I design of the system, and component redundancy, it is highly unlikely that a tornado would damage this system such that a complete loss of function would occur.
If a failure of these ventilation systems did occur, it would be apparent since the equipment temperature monitoring system would alert control room personnel to elevated temperatures in these areas. The equipment temperature monitoring system is powered from vital power and is unaffected by tornadic influences.
Compartment heatup analyses demonstrate that sufficient time is available for plant personnel to take appropriate actions, based on plant conditions, before electrical equipment function is affected from overheating. 3.3.2.4 Supplementary Analysis of Additional Tornado Missiles: Estimated Maximum Missile Velocity, Required Barrier Thickness The following expanded list of tornado-borne missiles has also been analyzed to determine the maximum velocity attained and the thickness of a reinforced concrete missile barrier necessary to preclude perforation or the generation of secondary missiles. The previously discussed three hypothetical missiles (see Section 3.3.2.1.2) are approximately the same as items (1), (6), and (7) in the following list:
(1) 4- x 12-inch plank, 12 feet long, with a density of 50 lb/ft3 (2) Utility pole 13.5 inches in diameter by 35 feet long with a density of 43 lb/ft3 (3) 1-inch solid steel rod, 3 feet long, with a density of 490 lb/ft3 (4) 6-inch Schedule 40 pipe, 15 feet long, with a density of 490 lb/ft3 DCPP UNITS 1 & 2 FSAR UPDATE 3.3-27 Revision 21 September 2013 (5) 12-inch Schedule 40 pipe, 15 feet long, with a density of 490 lb/ft3 (6) 3-inch Schedule 40 pipe, 15 feet long, with a density of 490 lb/ft3 (7) 4000-pound automobile with a volume of 1.67 x 6 x 17 ft The analysis employed in developing the maximum missile velocity is based on methods described in Reference 6. The tornado characteristics used as initial conditions include a constant tangential wind speed of 250 mph.
A three-dimensional, right-circular-cylinder representation is assumed for the funnel cloud. Vertical and radial velocity components are taken from Bates & Swanson (Reference 7).
The vertical component varies with elevation. The radial component varies from a peak value at the outside surface and drops abruptly to zero at the inside surface of the funnel cloud. With this model, the tornado missile forcing function and, consequently, the potential missile destructive forces do not significantly vary with elevation, since the vertical velocity component and its variation with elevation are small relative to the tangential velocity component.
The calculation of the ejection velocity of the postulated missile from the tornado vortex described above is based on solving the equation of motion for the missile. The missile is assumed to accelerate as it follows the path of the maximum tangential wind speed at the surface of the funnel cloud. It is ejected when the pressure differential and aerodynamic forces acting on the missile are overcome by centrifugal forces. Further assumptions are: (a) the missiles do not tumble, and present the maximum value of Cd A/W while in flight, and (b) the ejection velocity thus determined is the maximum velocity attained by the missile.
Modified missile velocities are calculated for those missiles incapable of being sustained after initial injection into the tornado wind field. Injection is calculated by assuming a 0.2-second impulse due to the aerodynamic lift force. From this calculation, an initial height for missile injection can be determined. Subsequent suspension and increase or decrease in elevation is determined by a new force balance including lift and gravity forces acting on the missile at the initial injection height. For the nonsustained missile, the modified horizontal velocity upon its return to the elevation of origin is then computed. Horizontal and vertical velocity components are decoupled in this latter calculation for simplicity. This approach is justified because the vertical wind speed is small compared to its horizontal component.
The required thickness of a reinforced concrete barrier to preclude perforation due to end-on impact of the additional tornado-induced missiles is computed by the modified Petry formula. The estimated thickness required to prevent the formation of secondary missiles is conservatively taken as 1.5 times the thickness required to preclude perforation. This approximation is based on a comparison of the thickness required to DCPP UNITS 1 & 2 FSAR UPDATE 3.3-28 Revision 21 September 2013 prevent perforation and spalling of concrete targets. These thicknesses were determined for various missile types with velocities ranging from 40 to 250 fps. Calculations were based on the Army Corps of Engineers and National Defense Research Committee formulas. Although these formulas are applicable for missile velocities exceeding 500 fps, they represented the only available basis for estimating the thickness required to prevent secondary missile generation.
The results of the supplementary analysis of additional missiles are presented in Tables 3.3-5 and 3.3-6. 3.
3.3 REFERENCES
- 1. ASCE Committee Report, Wind Forces on Structure, Transactions of the ASCE, Paper No. 3269, 1961.
- 2. Tornado and Extreme Wind Design Criteria for Nuclear Power Plants, Topical Report BC-TOP-3, Bechtel Corporation.
- 3. Fundamentals of Protective Design, TM-855-1, Department of the Army Technical Manual, July 1965.
- 4. Plant Design Against Missiles, ANS-N177, American Nuclear Society, Hinsdale, Illinois, April 1974 Draft.
- 5. D. R. Miller and W. A. Williams, Tornado Protection for the Spent Fuel Storage Pool, General Electric Company, APED-5696, San Jose, California, November 1968.
- 6. A. J. H. Lee, A General Study of Tornado Generated Missiles, ASCE Specialty Conference on Structural Design of Nuclear Plant Facilities, Chicago, Illinois, December 1973.
- 7. F. C. Bates and A. E., Swanson, "Tornado Design Consideration for Nuclear Power Plants," American Nuclear Society, 10, November 1967, pp. 712-13.
- 8. H. C. S. Thom, "New Distribution of Extreme Winds in the United States," Journal of the Structural Division, Proc. of the ASCE, Vol. 94, No. ST 7, 1968, pp. 1787-1801.
- 9. Tornado and Extreme Wind Design Criteria for Nuclear Power Plants, Topical Report BC-TOP-3A, Bechtel Corporation, Revision 3, August 1974.
- 10. US Navy Design Manual DM-2, Navy Structural Engineering Design Manual, December 1967.
DCPP UNITS 1 & 2 FSAR UPDATE 3.3-29 Revision 21 September 2013 11. PG&E Letter DCL-92-084 to the NRC, Revised Response to Station Blackout, April 13, 1992.
- 12. Guidelines and Technical Bases for NUMARC Initiatives Addressing Station Blackout at Light Water Reactors, Nuclear Management and Resources Council, NUMARC 87-00, Revision 0.
- 13. NRC Letter to PG&E, Supplemental Safety Evaluation of PG&E Response to Station Blackout Rule (10 CFR 50.63) for Diablo Canyon (TAC Nos. M68537 and M68538), May 29, 1992.
- 14. PG&E Letter DCL-94-133 to the NRC, Response to Generic Letter 88-20, Supplement 4, Individual Plant Examination of External Events for Severe Accident Vulnerabilities, June 27, 1994.
- 15. NRC Letter ro PG&E, Review of Diablo Canyon Individual Plant Examination of External Events (IPEEE) Submittal (TAC Nos. M83614 and M83615), December 4, 1997.
- 16. E. Simiu and Robert H. Scanlan, Wind Effects on Structures, John Wiley and Sons, Inc., Third Edition, 1996.
- 17. Design of Structures for Missile Impact, Topical Report BC-TOP-9A, Bechtel Corporation, Revision 2, September 1974.
DCPP UNITS 1 & 2 FSAR UPDATE 3.4-1 Revision 15 September 2003 3.4 WATER LEVEL (FLOOD) DESIGN Safety-related structures, components, and equipment are designed to withstand the effects of potential flooding, as required by GDCs 2 and 4. 3.4.1 FLOOD ELEVATIONS The discussion in Section 2.4 demonstrates that Diablo Creek is adequate to handle the probable maximum flood (PMF), and that yard and roof drainage designs are such that it is not possible to develop sufficient ponding to flood safety-related buildings. Thus, the depth of water at the plant location for the PMF is zero.
The intake structure is designed with an elevated air intake so that the Design Class I auxiliary saltwater pumps can operate during the design combination tsunami-storm wave runup to elevation +48 feet mean low-low water (MLLW) (+45.4 feet mean sea level (MSL)). These pumps are located below elevation zero feet MSL. The pumps are mounted at a nominal floor elevation -2.1 feet MSL, and each pump is housed in a separate watertight compartment. The location and arrangement of this equipment are shown in Figure 9.2-2. 3.4.2 PHENOMENA CONSIDERED IN DESIGN LOAD CALCULATIONS Sections 2.4.3, 2.4.5, and 2.4.6 discuss the characteristics of the storm waves and tsunami flooding that were considered in the design of the intake structure and auxiliary saltwater pump compartments.
3.4.3 FLOOD FORCE APPLICATION The hydraulic forces on the intake structure resulting from the design flood conditions and when the breakwaters are assumed to be degraded to MLLW were determined by hydraulic scale model tests and reported in References 1, 2, and 3. As discussed in Section 2.4.6.6, analysis of wave splash-up from the hydraulic scale model tests was performed as documented in Reference 4 to demonstrate that ingestion of sufficient seawater through the intake structure snorkels into the auxiliary saltwater (ASW) pump rooms is extremely unlikely to jeopardize operation of the ASW pumps. 3.4.4 FLOOD PROTECTION Sections 2.4.5 and 2.4.6 describe flooding protection provisions for safety-related structures, systems, and components associated with sea wave activity and tsunami. Isolation from effects of flooding due to leakage or rupture of piping is discussed in Section 9.2.
During excavation for the Unit 1 containment structure, some seepage of ground water was encountered. Since the flow of water into the excavation was slight, no special provisions for the base slab were considered necessary. However, to provide the DCPP UNITS 1 & 2 FSAR UPDATE 3.4-2 Revision 15 September 2003 capability to detect the presence of water in the future, two collector loops were installed under each containment structure: one at approximate elevation 52 feet (bottom of the reactor cavity), and one at approximate elevation 74 feet (bottom of the base slab). The loops at each containment structure are connected to observation wells which may be monitored. The observation wells are capped to contain radon gas emitted from the wells. Provisions are made on the cap plate to be able to monitor the wells, and, if water should accumulate, to allow groundwater to be pumped from the wells. 3.
4.5 REFERENCES
- 1. O. J. Lillevang, et al, Height Limiting Effect of Sea Floor Terrain Features and of Hypothetically Extensively Reduced Breakwaters on Wave Action at Diablo Canyon Seawater Intake, March 15, 1982.
- 2. F. Raichlen, Investigation of Wave Structure Interactions for the Cooling Water Intake Structure of the Diablo Canyon Nuclear Power Plant, December 1982.
- 3. E. Matsuda, Wave Effects on the Intake Structure, January 1983.
- 4. R. J. Ryan, Investigations of Seawater Ingestion into the Auxiliary Saltwater Pump Room Due to Splash Run-up During the Design Flood Events at Diablo Canyon, January 1983.
DCPP UNITS 1 & 2 FSAR UPDATE 3.5-1 Revision 21 September 2013 3.5 MISSILE PROTECTION The DCPP design provides missile protection in conformance with 10 CFR 50, Appendix A, GDCs 2 and 4. 3.5.1 MISSILE BARRIERS AND LOADINGS This section presents the structures, shields, and barriers that are designed to withstand missile effects. The sources of potential missiles are also discussed, including consideration of (a) accident/incident-generated missiles inside and outside the containment, in Sections 3.5.1.1 and 3.5.1.2; (b) environmental load (or tornado) generated missiles in Section 3.5.1.3; and (c) site proximity missiles from industrial, transportation, and military facilities in Section 3.5.1.4. 3.5.1.1 Missiles Generated Within the Containment For missiles generated within the containment, the principal design bases are that missiles generated coincident with a LOCA shall not cause loss of function of any engineered safety feature (ESF) or loss of containment integrity. The containment is defined as the containment structure, liner and penetrations, the steam generator shell, the steam generator steam-side instrumentation connections, and the steam, feedwater, blowdown, and steam generator drain piping within the containment structure.
Other than the ECCS lines that must circulate cooling water to the reactor vessel, the ESFs are located outside the crane wall. The ECCS lines are routed outside of the crane wall so that the penetrations are in the vicinity of the loop to which they are attached. Physical separation together with barrier protection provided by the refueling cavity walls and various structural beams serve to minimize the potential for missiles generated in one loop damaging adjacent loops. The portion of the steam and feedwater lines within the containment has been routed behind barriers that separate them from all reactor coolant piping.
The lower steam generator shell connecting lines are routed so that they are not in the direct path of any postulated missile.
The systems located inside the containment structure have been examined to identify and classify potential missiles. The basic approach is to ensure design adequacy against generation of missiles, rather than to allow missile formation and then try to contain their effects.
Catastrophic failure of the reactor vessel, steam generators, pressurizer, reactor coolant pump casings, or piping leading to generation of missiles is not considered credible. Massive and rapid failure of these components is incredible because of the material characteristics, inspections, quality control during fabrication, erection, operation, conservative design, and prudent operation as applied to the particular component. With the acceptance of the DCPP leak-before-break analysis by the DCPP UNITS 1 & 2 FSAR UPDATE 3.5-2 Revision 21 September 2013 NRC (Reference 13), the dynamic effects of breaks in the main reactor coolant loop piping no longer have to be considered in the design basis analysis. Only the dynamic effects from RCS branch line breaks have to be considered (see Section 3.6.2.1.1.1). The reactor coolant pump flywheel is not considered a source of missiles for the reasons discussed in Section 5.2. 6. Nuts and bolts are of no concern because of the small amount of stored elastic energy.
Components considered to have a potential for missile generation inside the reactor containment are listed as follows:
(1) CRDM, drive shaft, and the drive shaft and drive mechanism latched together (2) Certain valve bonnets
(3) Temperature and pressure sensor assemblies
(4) Pressurizer heaters The structures designed to withstand missile effects within the containment are:
(1) The integrated head assembly missile shield provided over the control rod drive mechanisms is intended to block missiles defined in Tables 3.5-2 and 3.5-3 (2) The pressurizer housing is designed to provide both a radiation shield and to block missiles listed in Table 3.5-4 (3) The polar crane wall, fuel transfer canal walls, and operating floor at elevation 140 feet constitute barriers for temperature elements and other missiles described in Tables 3.5-5 and 3.5-6, to prevent them from reaching the containment liner 3.5.1.2 Missiles Generated Outside the Containment The systems located outside the containment structure have been reviewed to determine the possible sources and consequences of missiles. Catastrophic failure of pressure vessels and system piping outside the containment structure is not considered credible as a source of missiles because of the conservative design, material characteristics, inspection during erection, and prudent operation. Pressurized gas containers of significant quantities are summarized in Table 3.9-11. Thrust loads resulting from a postulated failure of the largest connected pipe or manifold have been calculated to produce stresses no larger than yield in the container hold-down structure; therefore, no significant missiles are postulated from any of these containers. As shown in Table 3.9-11, other protective measures to prevent the loss of function of adjacent equipment essential for a safe and maintained reactor shutdown include compliance DCPP UNITS 1 & 2 FSAR UPDATE 3.5-3 Revision 21 September 2013 with Occupational Safety and Health Administration (OSHA) regulations in 29 CFR 1910. Many of the tanks listed in Table 3.9-11 are in locations remote from such safety-related equipment.
Components considered to have a potential for missile generation outside the containment structure are:
(1) Main turbine
(2) Main feedwater pump turbine
(3) Auxiliary feedwater pump turbine Design Class I structures and equipment outside the containment were reviewed to determine those that could possibly be affected by potential missiles. Those structures and items of equipment that could be affected were analyzed as follows: 3.5.1.2.1 Potential Missiles from the Main Turbines Based on the main turbine design, factory test procedures, the redundancy in control systems, and routine plant testing and inspection, the probability of the generation of main turbine missiles is so remote that turbine missiles are not considered credible events. See Section 3.5.2.2.1 for a discussion of the main turbine missile analysis. 3.5.1.2.2 Potential Missiles from the Main Feedwater Pump Turbines Due to the location of the main feedwater pump turbines on the west side of the turbine building at elevation 85 feet, failure of these turbines and the subsequent release of a missile would not endanger the nuclear safety of DCPP Units 1 or 2. 3.5.1.2.3 Potential Missiles from the Auxiliary Feedwater Pump Turbine For DCPP Units 1 or 2, the only equipment in the area of the turbine-driven auxiliary feedwater pump whose damage could prevent safe shutdown of the plant are the two motor-driven auxiliary feed pumps. These pumps are located 30 feet from the turbine-driven pump. With this amount of separation, a rotor fragment would have to be ejected within a 6° rotational span from the turbine casing in order to impinge directly on the nearest motor-driven pump.
The disk fragments would be most likely to damage the first motor-driven auxiliary feed pump in the direct line from the turbine pump, leaving the second motor-driven auxiliary feed pump fully operational. Reactor coolant system (RCS) decay heat can be dissipated safely with the flow from one motor-driven feed pump.
A missile barrier is provided over the pump turbines to contain any potential missiles generated by disk failure. DCPP UNITS 1 & 2 FSAR UPDATE 3.5-4 Revision 21 September 2013 3.5.1.3 Missiles Generated by Natural Phenomena Tornado-generated missiles are discussed in Section 3.3.2. 3.5.1.4 Site Proximity Missiles Nearby industrial, transportation, and military facilities are described in Section 2.2. There are no such facilities within 5 miles of the site. As discussed below, the probability of missiles originating from these facilities striking safety-related structures or components on the site is so small that missile loadings from this source have not been included in structure or component design bases.
The nearest industrial installation is the Port San Luis tanker loading pier, which is located approximately 6-1/2 miles from the site. This loading pier ceased operation in 1998. In addition, petroleum products and crude oil are no longer stored at Avila Beach, since the storage tanks there were removed in 1999.
The closest airport is San Luis County Airport, which is located about 12 miles east of the site. The approach route for the majority of traffic using this airport passes approximately 8 miles from the site and is separated from the site by the surrounding coastal mountains. An infrequently used approach route passes within approximately 4 miles of the site, with traffic maintaining an altitude of more than 3000 feet at the point of closest approach. At this distance from an airport, crash probabilities approach those from overflights. Consequently, the probability of an aircraft striking safety-related structures or components on the site is extremely small. Vandenberg Air Force Base is located about 36 miles south of the site. Missiles are fired from Vandenberg within a range of directions from 180° to 260°. The site is on a bearing of 330° from Vandenberg, so launch paths of normally functioning missiles do not pass over the site.
In the event that a launched missile deviates from the intended trajectory, it is destroyed. Discussions with representatives of Vandenberg Air Force Base indicate that very few missiles deviate from the planned flight path and that they have confidence in the ability of destruct procedures to destroy any malfunctioning missiles above or very close to the base. Consequently, the probability of missiles originating from this source striking safety-related structures or components on the site is extremely small. 3.5.2 MISSILE SELECTION The missiles selected for each structure and the basis for their selection are discussed below. DCPP UNITS 1 & 2 FSAR UPDATE 3.5-5 Revision 21 September 2013 3.5.2.1 Missiles Postulated Within the Containment Structure Gross failure of a control rod mechanism housing sufficient to allow a control rod to be rapidly ejected from the core is not considered credible for the following reasons:
(1) All control rod drive mechanisms are shop pressure-tested at 3107 psig, whereas the RCS operates at 2250 psig.
(2) The pressure housings were individually hydrotested. The lower latch housing to nozzle connection is hydrotested during hydrotest of the completed replacement reactor vessel closure head. (3) Stress levels in the mechanisms are not affected by system transients at power, or by thermal movement of the coolant loops. (4) The mechanism housings are made of Type 304 stainless steel. This material exhibits excellent fracture notch toughness at all temperatures that will be encountered. (5) The CRDM housing plug is an integral part of the rod travel housing. However, if it is postulated that the top of the rod travel housing portion of the control rod drive mechanism becomes ruptured and is forced upward by the water jet, the following sequence of events is assumed. The drive shaft and control rod cluster are forced out of the core by the differential pressure of 2250 psi across the drive shaft. (The drive shaft and control rod cluster, latched together, are assumed fully inserted when the accident starts.) After approximately 12 feet of travel, the rod cluster control spider hits the underside of the upper support plate. Upon impact, the flexure arms in the coupling joining the drive shaft and control cluster fracture, freeing the drive shaft from the control rod cluster. The control cluster is stopped by the upper support plate, but the drive shaft continues to be accelerated upward to be stopped by the integrated head assembly missile shield.
Valve stems are not considered a credible source of missiles. All of the isolation valves installed in the RCS have stems with backseats. This effectively eliminates the possibility of ejecting valve stems even if the stem threads fail.
Valves are designed against bonnet-body connection failure and subsequent bonnet ejection by means of:
(1) using the design practice of ASME Section VIII for bolting
(2) using the design practice of ASME Section VIII for flange design
DCPP UNITS 1 & 2 FSAR UPDATE 3.5-6 Revision 21 September 2013 (3) controlling the torque load during the bonnet body connection stud tightening process The pressure-containing parts are designed in accordance with requirements established by either the ASA 16.5 Code or the MSS-SP-66 Code, except for the accumulator check valves which are designed for requirements specified in the ASME Code, Section III, 1968 Edition.
Whereas valve missiles are not generally postulated due to the above discussion, exceptions are the valves in the region where the pressurizer extends above the operating deck. Valves in this region are the pressurizer safety valves, the motor-operated isolation valves in the relief line, the air-operated relief valves, and the air-operated spray valves. Although failure of these valves is also considered incredible, failure of the valve bonnet-body bolts is postulated and provisions are made to ensure integrity of the containment liner from the resultant bonnet missile.
The only credible source of jet-propelled missiles from the reactor coolant piping and piping systems connected to the RCS is that represented by the temperature and pressure sensor element assemblies. The resistance temperature element assemblies can be "with well" and "without well."
A temperature sensor element is installed on the reactor coolant pumps close to the radial bearing assembly. A hole is drilled in the gasket and sealed on the internal end by a steel plate. In evaluating missile potential, it is assumed that this plate could break and the pipe plug on the external end of the hole could become a missile. In addition, it is assumed that the weldment between the instrumentation well and the pressurizer wall could fail and the well and sensor assembly could become a jet-propelled missile.
Finally, it is assumed that the pressurizer heaters could become loose and become jet-propelled missiles. 3.5.2.2 Missiles Postulated Outside the Containment 3.5.2.2.1 Main Turbine The HP turbines and generators for DCPP Units 1 and 2 are manufactured by Siemens-Westinghouse Electric Corporation. The low pressure (LP) turbines A, B, and C, originally supplied by Siemens-Westinghouse, have been retrofitted with Alstom rotors and its casings.
Factory test procedures, redundancy in the control system, and routine testing of the main steam valves and the mechanical emergency overspeed protective system while the unit is carrying load, make generation of missiles by a turbine runaway that might penetrate the turbine casing highly improbable. DCPP UNITS 1 & 2 FSAR UPDATE 3.5-7 Revision 21 September 2013 Three important criteria contribute to preventing destructive overspeed of a turbine: (1) Factory test procedures Destructive testing is performed on material specimens taken from disc forgings in addition to an ultrasonic test of each disc or forging following major heat treatment. These test procedures ensure sound disks with mechanical properties (tensile strength, yield strength, ductility, and impact strength), which meet specified levels. (2) Redundancy in the control system As a minimum, all Siemens-Westinghouse steam turbines are provided with a main speed governing channel to close the governing (and intercept) valves, plus a mechanical emergency overspeed trip system to close the separate stop and governing (plus reheat stop and intercept) valves. On a unit trip, two separate main steam line valves (stop and governing valves) are tripped closed to provide a redundant system. It should be noted that each stop, governing, reheat stop, and intercept valve is spring closed; thus, it is only necessary to dump the high-pressure fluid from under the servoactuators to close the valves. (3) Routine testing of the main steam valves and the mechanical emergency overspeed protective system Functional tests of the main turbine steam inlet valves are performed semi-annually while the unit is carrying load, according to the Siemens-Westinghouse instructions for the DCPP steam turbines. References 9, 10, 11, and 12 contain an update on the industry turbine valve failure rates and assessment of the turbine destructive overspeed probabilities, and forms the basis of the turbine valve testing frequency for DCPP. Furthermore, a routine LP rotor inspection program for both DCPP units assures that the integrity of LP rotors is maintained. The Alstom LP rotor inspection intervals are based upon fleet and industry experience. Being of an integral welded disc design, the Alstom rotors are not susceptible to the same types and degree of stress corrosion cracking (SCC) failure mechanisms as the OEM Siemens-Westinghouse shrunk-on disc design. In addition, Alstom's advanced technology in fir tree design and manufacturing processes (such as cold-working rotor grooves of last stage blading) improves the mechanical integrity of the blade attachment. Nevertheless, the inspection interval for DCPP's Alstom rotors and disc areas is conservatively based upon worst case DCPP UNITS 1 & 2 FSAR UPDATE 3.5-8 Revision 21 September 2013 hypothetical SCC failure mechanisms, crack initiation, size and growth rates, in keeping with the OEM's methodology for determining inspection intervals.
The resulting disc inspection program, committed to by PG&E, eliminates the potential for operational development of disc crack to a critical depth. Rotor and disc forgings are subject to inspection and testing both at the forging suppliers and manufacturer's facilities. Thus, an LP disc failure at a speed less than or equal to the design overspeed is not considered a credible event. 3.5.2.2.1.1 Turbine Trip System Steam Valves The following steam valves are provided for the DCPP turbine-generator units:
(1) Separate stop-throttle and control valves. This provides complete redundancy in the main steam inlet lines. (2) Separate reheat stop and interceptor valves. This provides complete redundancy between the moisture-separator reheater and the LP turbine inlets. Speed Sensors The control system includes four separate speed sensors mounted on the turbine stub shaft located in the turbine front pedestal, as follows: (1) Three electromagnetic pickups (for speed governing and overspeed trip input to the turbine control system) (Section 10.2.2.6.4) (2) Mechanical overspeed trip weight (spring-loaded bolt) Turbine Steam Valve Closure Valve closure is provided by: (1) The overspeed protective controller, which calls for fully closed interceptor and governor valves at 103 percent of rated speed (2) Should the speed exceed approximately 111 percent of rated speed, the interceptor and governor valves are tripped closed by both the mechanical overspeed trip and a backup electrical trip from the main speed governing channel. In addition, the mechanical overspeed trip closes the turbine stop valves and the reheater stop valves
DCPP UNITS 1 & 2 FSAR UPDATE 3.5-9 Revision 21 September 2013 3.5.2.2.1.2 Main Turbine Failure Probability Because of the extensive overspeed and backup controls and routine testing of the turbine inlet valves and overspeed protective system, acceleration beyond design overspeed (120 percent of rated speed) to the destructive overspeed (approximately 151 percent for Alstom rotors) is not considered a credible event.
Because of the LP disc inspection program and preoperational forging inspection described in Section 3.5.2.2.1, generation of a missile at design overspeed or less is not considered a credible event.
The possibility that a postulated crane fall or falling construction debris could damage elements of the turbine trip system in an earthquake has been considered in relation to the main turbine failure probability. The turbine building crane is parked away from the steam inlet valves during turbine operation to preclude damage to the valves from a postulated crane fall. Review of the vulnerability of the main turbine inlet valves and the overspeed trip system to falling debris indicates that no postulated structural debris could prevent a trip for the following reasons:
(1) The siding and roofing of the turbine building are constructed to withstand design wind loads, which are in excess of the loads they would experience during an earthquake. Therefore, falling corrugated metal roofing or siding is not considered a credible event.
(2) The main steam stop valves and the overspeed trip mechanism are located on the high-pressure (HP) turbine. Falling debris, such as rivets and small scrap metal, would not damage the stop valve bodies, actuators, or trip mechanism in a manner that would prevent valve closure. (3) The reheat stop valves are located below the turbine deck which protects them from falling debris. (4) The intercept valves are located above each LP turbine, but their operation is not necessary for stopping the main turbine on a turbine overspeed trip. (5) The electrohydraulic (EH) fluid system piping that supplies high-pressure oil to the main turbine steam inlet valves runs both above and below the turbine deck. Because most of the EH piping is either below the turbine deck or sheltered by the valve bodies and inlet piping, it is highly unlikely that said debris would impact the EH piping. In the extremely unlikely event that such debris were to impact the EH piping, the piping would have to be crimped completely shut to prevent the trip system from operating. This is not considered a credible event. A partially crimped line would not disable the trip system. A broken or punctured line would result DCPP UNITS 1 & 2 FSAR UPDATE 3.5-10 Revision 21 September 2013 in a loss of EH pressure resulting in HP stop valve and re-heat stop valve closure, thus stopping the main turbine. The falling debris considered included corrugated metal roofing, rivets, and small scrap metal that may have been left after the turbine building roof was constructed.
In summary, the probability of generation of an HP turbine missile by speed in excess of the design overspeed, or of an LP turbine missile of any kind, is extremely remote. These are not considered credible events. 3.5.2.2.1.3 Potential Missiles Analyses and tests regarding the generation and effects of missiles caused by the main turbine accelerating to design overspeed have been carried out by both Alstom and Siemens-Westinghouse Electric Corporation. The analyses and tests described below consider the potential sources of missiles resulting from postulated failures of the HP turbine rotor and the LP turbine disks or blade loss at design overspeed (120 percent of rated speed) and the capability of the turbine casings to contain the postulated missiles. Experimental Results Siemens-Westinghouse conducted a test program at its research laboratories to evaluate the missile-containing ability of its steam turbines. The tests involved spinning alloy steel disks to failure within various carbon steel containments. The disks were notched to ensure failure in a given number of segments at the desired speed. Test results were correlated with various parameters descriptive of the missile momentum and energy and the geometry of the missile and containment. The containments were of varying geometry but all were axisymmetric and concentric with the rotation axis of the disk. They ranged in complexity from a circular cylinder to containments that approximated actual turbine construction.
From these tests, logical criteria were evolved for predicting the missile-containing ability of various turbine structures. In addition, the tests also served to determine the mode of failure that certain structural shapes common to turbine construction undergo when hit by a missile. This is important since the mode of failure has a great influence on the amount of energy absorbed by the containment.
Fracture of the Siemens-Westinghouse disks into 90, 120, and 180° segments was considered. Calculations show that the 90° fragments pose the greatest threat as external missiles.
A 120° segment has an initial translational kinetic energy 12.5 percent greater than that of a 90° segment; however it also has a 33 percent greater rim periphery, resulting in greater energy loss when penetrating the turbine casing. Therefore, 90° and 120° DCPP UNITS 1 & 2 FSAR UPDATE 3.5-11 Revision 21 September 2013 segments have nearly equal kinetic energy leaving the turbine casing; but since a 90° segment has smaller impact area, it represents a more severe missile.
The initial translational kinetic energy of a half disk is equal to that of a quarter disk. Because of kinematic considerations, a half disk segment will always impact with the rotor after fracture. The 180° segment, due to its larger size, will subject the stationary parts to greater deformation. As a result, the 180° segment will leave the turbine casing with lower energy than the 90° segment.
For the purpose of evaluating the missile-containing ability of the turbine structure, the shrunk-on disks have been postulated to fail in four quarters. Before failure, a disk has a total energy, which is purely rotational, of 1/2(I2), where I is the mass moment of inertia of the disk about its axis of rotation and is the angular velocity of the turbine at the postulated failure speed. After failure, the mass center of each fragment translates at a velocity of r, r being the distance from the rotation axis of the disk to the mass center of the fragment. In addition, the fragment rotates about its center of mass with an angular velocity of . The initial rotational energy of the disc is partitioned into both the translational and rotational kinetic energy of the fragments.
Test results and analytical considerations indicate that the translational kinetic energy of a fragment is of much greater importance than the rotational kinetic energy in predicting the ability of the fragment to penetrate the turbine casing. Rotational kinetic energy tends to be dissipated as a result of friction forces developed between the fragment surfaces and stationary parts.
These principles apply to fragments that would be generated by failure of the HP turbine rotor. Alstom has also evaluated the probability of generating LP turbine missiles, providing finite element analyses, inspection results and operating experience in References 14 through 19. Alstom rotors are far less vulnerable to SCC, as compared to the Siemens-Westinghouse rotors, due to improved design features, materials, manufacturing, and factory inspection techniques. Therefore, the Alstom rotor inspection intervals are longer than the original Seimens-Westinghouse intervals.
In Reference 14, Alstom presents criterion governing nuclear LP rotor disc inspection intervals. Since there are no field failures or indications of SCC in the relevant directions which might produce a missile, Alstom developed hypothetical cases to set criteria governing crack growth rate, critical crack size, and fraction of crack size allowed. In this manner, Alstom's missile analysis is equivalent to the methodology used by Seimens-Westinghouse.
From this analysis, Alstom produced an inspection interval versus missile generation probability chart (Figure 9, Reference 14). This shows that the maximum allowable inspection interval could be as long as 25 years and still meet the minimum requirements of RG 1.115. A low pressure turbine rotor inspection program for DCPP Units 1 and 2 assures that the integrity of the LP rotors is maintained. The Alstom DCPP UNITS 1 & 2 FSAR UPDATE 3.5-12 Revision 21 September 2013 criteria governing LP turbine rotor inspection sets forth recommendations based on crack growth rate, critical crack size, and fraction of critical crack size allowed. The LP turbine program inspection frequency derived from the missile analysis governs the maximum interval between inspections. DCPP will follow the vendor recommendation. The Alstom (single) inner cylinder does not enclose the last stage blades (LSBs), which are significantly more massive than the Siemens-Westinghouse LSBs, making loss of a LSB an unacceptable event. Given the blade mass and projected exit velocity during a hypothetical blade loss event, it is likely the blade would penetrate the outer housing. Alstom has incorporated several LSB design features, such as tangential fir tree entry, snubber location and design, and blade frequency tuning to prevent resonant conditions which might lead to high cycle fatigue crack growth. Additionally, operational avoidance regions are procedurally enforced, improved UT factory inspection techniques will detect manufacturing defects, and routine maintenance inspections will preclude undetected crack propagation. A fracture mechanics deterministic analysis presented in Reference 15 substantiates that this type of missile generation from a LSB loss is not a credible event. High-pressure Turbine Analysis The HP turbine element is of double-flow design. Steam enters at the center of the turbine element through four inlet pipes, two in the base and two in the cover. These pipes feed four double-flow nozzle chambers flexibly connected to the turbine casing. Steam leaving the nozzle chambers passes through the Rateau control stage and flows through the reaction blading. The reaction blading is mounted in the blade rings which in turn are mounted in the turbine casing.
The HP rotor is made of NiCrMoV alloy steel. The specified minimum mechanical properties are as follows: Tensile strength, psi, min 100,000 Yield strength, psi, min (0.2% offset) 80,000 Elongation in 2 inches, %, min 18 Reduction of area, %, min 45 Impact strength, Charpy V-notch, ft-lb (min at room temperature) 60 50% fracture appearance transition temperature, °F, max 50 The main body of the rotor weighs approximately 100,000 pounds. The approximate values of the transverse centerline diameter, the maximum diameter, and the main body length are 36 and 138 inches, respectively.
DCPP UNITS 1 & 2 FSAR UPDATE 3.5-13 Revision 21 September 2013 The blade rings and the casing cover and base are made of carbon steel castings. The specified minimum mechanical properties are as follows:
Tensile strength, psi, min 70,000 Yield strength, psi, min 36,000 Elongation in 2 inches, %, min 22 Reduction of area, %, min 35
Bend test specimens are capable of being bent cold through an angle of 90° and around a pin 1 inch in diameter without cracking on the outside of the bent portion. The approximate weights of the four blade rings, the casing cover, and the casing base are 80,000 pounds, 115,000 pounds, and 115,000 pounds, respectively.
The casing cover and base are tied together by means of more than 100 studs. The stud material is an alloy steel having the following mechanical properties: 2.5 Inches and Less 2.5 Inches to 4 Inches 4 Inches to 7 Inches Tensile strength, psi, min 125,000 115,000 110,000Yield strength, psi, min (0.2% offset) 105,000 95,000 85,000 Elongation in 2 inches, %, min 16 16 16 Reduction of area, %, min 50 50 45
The studs have lengths ranging from 17 to 66 inches and diameters ranging from 2.75 to 4.5 inches. About 90 percent of them have diameters ranging between 2.5 and 4 inches. The total stud cross-sectional area is approximately 900 in2, and the total stud free-length volume is approximately 36,000 in3. Calculations were performed to determine the effects of a postulated failure of the HP turbine rotor at design overspeed (120 percent of rated speed). These calculations show that all fragments generated by any postulated failure of the HP turbine rotor would be contained by the HP turbine blade rings and casing. 3.5.2.2.2 Auxiliary Feedwater Pump Turbine The DCPP Units 1 and 2 turbine-driven auxiliary feedwater pumps are driven by Terry Steam Turbine Company turbines with a casing constructed of A216 WCB cast steel with a minimum thickness of 0.9375 inches. The turbine disc is a solid forging of A294 Class A-5 steel into which the "buckets" are milled. The shafts of the turbines are constructed of SA 4140 steel.
When required to operate, the turbines run at speeds ranging from 4000 to 4260 rpm. The overspeed trip on the turbine is a centrifugal weight type, which is set at 4950 plus or minus 50 rpm.
DCPP UNITS 1 & 2 FSAR UPDATE 3.5-14 Revision 21 September 2013 The construction and periodic testing of the turbine make it an improbable source of missiles. It is calculated that the probability of missile generation is less than 10-7 events per year. Hence, using NRC criteria, such an event need not be postulated. However, if failure of the turbine did occur, the most severe missile generated is assumed to be a 90° segment of the rotor. 3.5.3 SELECTED MISSILES The characteristics for each selected missile, such as origin, weight, dimensions, impact velocity and orientation, and material composition, are described below. 3.5.3.1 Typical Characteristics of Missiles Postulated Within the Containment Structure The characteristics of the control rod drive shaft (with the disconnect rod) missile are given in Table 3.5-2; those of the control rod drive shaft and the disconnect rod latched to the drive mechanism are given in Table 3.5-3.
The missile characteristics of the bonnets of the valves in the region where the pressurizer extends above the operating deck are given in Table 3.5-4.
The missile characteristics of the piping temperature element sensor assemblies are given in Table 3.5-5. A 10 degree expansion half-angle water jet has been assumed. The missile characteristics of the piping pressure element assemblies are less severe than those shown in Table 3.5-5. The missile characteristics of the reactor coolant pump temperature element, the instrumentation well of the pressurizer, and the pressurizer heaters are given in Table 3.5-6. A 10-degree expansion half-angle water jet has been assumed. 3.5.3.2 Typical Characteristics of Missiles Postulated Outside the Containment Structure 3.5.3.2.1 Disc Quadrant From Auxiliary Feedwater Pump Turbine As noted in Section 3.5.2.2, the probability of generating a missile from the auxiliary feedwater turbine is less than the NRC threshold value for credible events. Nevertheless, an evaluation of the auxiliary feedwater turbine's ability to generate a missile has resulted in the following conclusions. A disc rupture at the maximum turbine speed, consistent with a single failure of the turbine control system, will not generate a missile capable of penetrating the turbine casing. However, the postulation of multiple control system failures leads to the rupture of the turbine disc at a speed of 14,000 rpm. The resulting missile is capable of penetrating the turbine casing. The missile characteristics are as follows:
DCPP UNITS 1 & 2 FSAR UPDATE 3.5-15 Revision 21 September 2013 Velocity = 549 fps Impact area = 54.1 in2 Weight = 43.2 lb (includes 13.2 lb for the turbine casing) 3.5.4 BARRIER DESIGN PROCEDURES The barriers are designed to prevent penetration by the postulated missiles. The design procedures are described below: 3.5.4.1 Determination of Loadings for Missiles Generated Within the Containment Structure The steam generator shell for the original steam generators (OSGs) was calculated to resist penetration of the postulated missiles using the method illustrated in ORNL-NSIC-5, page 6-158. The shells for the replacement steam generators (RSGs) are fabricated with materials similar to or in some cases improved from those used for the OSGs. In addition, the RSG shells are approximately as thick as the OSG shells, are made from SA-508 forging material that is equivalent to the SA-533 plate material used in the OSG shells, and do not have longitudinal weld seams in the cylindrical sections as do the OSGs.
In conclusion, the RSGs are judged to be at least as resistive to missile penetration as the OSGs.
The missile shield structure over the control rod drive mechanisms was evaluated using a formula derived from the Ballistic Research Laboratories (BRL) formula: d670ET32k (3.5-11) where:
T = required steel wall thickness, in. Ek = kinetic energy of missile, ft-lb d = diameter of missile, in.
The governing missile, a 1.75-inch-diameter control rod drive shaft with a maximum kinetic energy of 60,200 foot-pounds (shield located 4 feet above housing), requires a shield thickness of 1.31 inches. However, a 2.0 inch-thick shield was provided.
The pressurizer housing and other concrete structures were evaluated for perforation by a missile using (BRL) formula: 4/31000VddW'f427P5121/2c (3.5-12) DCPP UNITS 1 & 2 FSAR UPDATE 3.5-16 Revision 21 September 2013 where: P = required thickness of concrete slab, in. fc' = compressive strength of concrete, psi W, d, V = weight (lb), diameter (in.), and velocity (ft/sec) of missile, respectively The most powerful missile among those listed in Tables 3.5-4 through 3.5-6 is the 3-inch motor-operated isolation valve bonnet, weighing 400 pounds and having a velocity of 135 ft/sec and a 28 square inch impact area. This missile could perforate 6.7 inches of 5000 psi strength concrete; the minimum thickness of the target is 24 inches.
In addition to the check for perforation, the overall structural response is evaluated by using the method of Reference 4. For this purpose, the penetration depth is calculated by using the modified Petry formula (Reference 2): VAKDp1 (3.5-13) where:
D = depth of penetration, ft K1 = experimentally obtained material coefficient Ap = weight to impact area ratio, lb/ft V = 215000V1lg2 = velocity factor V = missile velocity, ft/sec The calculation procedure is illustrated below for a missile believed to produce the largest response:
Missile in. motor-operated isolation valve bonnet Weight - W = 400 lb Impact area - A = 28 in2 = 0.195 ft2 Velocity - V = 135 fps ft0.205215,0001351Lg2,050102.82Dft/lb2,050AWAlb/ft10 2.82K232p331 DCPP UNITS 1 & 2 FSAR UPDATE 3.5-17 Revision 21 September 2013 Because the velocity is assumed to reduce linearly from the initial value of V, the time t1 of the impulse or the duration of the dynamic force F1 is determined by the equation: sec0.0031350.2052V2Dt1 (3.5-14) The dynamic force is calculated by the equation: kips5500.20532.221350.4D2gVWF22i (3.5-15) The factor K, by which the value of Fi can be reduced to determine an equivalent static load P, is given by the equation: 7.220.0030.030.7130.510.003p0.030.516t0.7T10.51tT0.512K11 (3.5-16) where: the ductility ratio = 3, and the structure's natural period T = 0.03 sec The value of the static load is then: 767.22550P kips (3.5-17) 3.5.4.2 Determination of Loadings for Missiles Generated Outside the Containment Structure Although the original design of certain Design Class I reinforced concrete structures outside containment included consideration of potential missile penetration and spalling effects, subsequent analyses and evaluations have determined that the generation of main turbine missiles outside of the turbine casing are not credible events. 3.5.5 MISSILE BARRIER FEATURES The structures designed to withstand missile effects within the containment are:
(1) A missile shield is provided over the control rod drive mechanisms. The shield is located 4 feet above the control rod drive mechanism housing and consists of a primary shielding element made of 2-inch steel plate that is part of the integrated head assembly structure. See Figure 3.5-1.
DCPP UNITS 1 & 2 FSAR UPDATE 3.5-18 Revision 21 September 2013 (2) The pressurizer housing, shown in Figure 3.5-2, consists of 12-inch- and 18-inch-thick reinforced concrete walls forming an irregular polygon and a 24-inch-thick concrete slab above the top of pressurizer. A 66-inch by 105-inch opening is provided in the top slab to prevent pressure buildup. The opening is not in the path of the potential missiles. (3) The polar crane wall, fuel transfer canal walls, and operating floor at elevation 140 feet are shown on the concrete outline drawings in Section 3.8.2. A structure designed to withstand missile effects outside containment is a missile shield barrier provided over the auxiliary feedwater pump turbine. The Unit 1 missile shield is a barrel-vault design and is formed from 1-inch-diameter bars sandwiched between 1 x 2 x 24-inch plates as shown in Figure 3.5-6. The Unit 2 missile shield is formed from horizontal layers of 4 x 1/2-inch steel bars supported on 12-inch-thick concrete walls. Analysis of the missile shield indicates that they are capable of retaining the missile postulated in Section 3.5.3.2. 3.
5.6 REFERENCES
- 1. Deleted in Revision 20
- 2. Amirikian, A., Design of Protective Structures, Bureau of Yards and Docks Publications No. NAVDOCKS P-51, Department of the Navy, Washington, D.C., 1950. 3. ORNL-NSIC-22, Missile Generation and Protection in Light-Water-Cooled Power Reactor Plants, Oak Ridge National Laboratory, September 1968. 4. Williamson, R. A. and Alvy, R. R., Impact Effect of Fragments Striking Structural Elements, Holmes and Narver, Revised November 1973.
- 5. WCAP-9241 (Proprietary), Evaluation of the Reactor Coolant System for Postulated Loss-of-Coolant Accidents for the DCPP Nuclear Power Plant, December 1977.
- 6. Binder, Fluid Mechanics, Prentice Hall, 1973, p. 271.
- 7. C. Hagg and G. O. Sankey, "The Containment of Disk Burst Fragments by Cylindrical Shells," Transactions of the ASME, ASME Paper No. 73-WA-PWR-2, August 1973.
- 8. WCAP-11525, Probabilistic Evaluation of Reduction in Turbine Valve Test Frequency, June 1987.
DCPP UNITS 1 & 2 FSAR UPDATE 3.5-19 Revision 21 September 2013 9. R. K. Rodibaugh and C. V. Tran, Update of BB-95/96 Turbine Valve Failure Rates and Effect on Destructive Overspeed Probabilities, WOG-TVTF-93-17, August 6, 1993.
- 10. R. L. Haessler and C. V. Tran, Update and Evaluation of BB-95/96 Turbine Valve Failure Data Base, WOG BB-95/96, February 1997.
- 11. R. L. Haessler, Final Update and Evaluation of BB-95/96 Turbine Valve Failure Data Base, WOG TUTF-00-014, October 16, 2000.
- 12. WCAP-16054, Probabilistic Analysis of Reduction in Turbine Valve Test Frequencies for Nuclear Plants with Siemens-Westinghouse BB-95/96 Turbines, April 2003.
- 13. NRC letter to PG&E, Leak-Before-Break Evaluation of Reactor Coolant System Piping for DCPP Units 1 and 2, from Sheri R. Peterson to Gregory M. Rueger, March 2, 1993.
- 14. Alstom Report: "Diablo Canyon - 1200 MW at 1800 RPM, LP-Rotor Missile Analysis", DC 6020487-37.
- 15. Alstom Report: "Diablo Canyon Missile Analysis: Customer Questions about Last Stage Blades", DC 6020487-36.
- 16. Alstom Study: "ND56R Geometrical Description and Mechanical Integrity of the L-1 Blade", DC 6020487-40. 17. Alstom Study: "ND56R Geometrical Description and Stress Calculations of the L-0 Blade", DC 6020487-41.
- 18. Alstom Study: "Diablo Canyon Stress Corrosion Cracking (SCC) Initiation at the Bottom of Rotor Grooves", DC 6020487-43.
- 19. Alstom Study: "Diablo Canyon - 1200 MW @ 1800 RPM; Stress Analysis of the LP-Rotors", DC 6020487-29. 3.5.7 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures.
DCPP UNITS 1 & 2 FSAR UPDATE 3.6-1 Revision 19 May 2010 3.6 PROTECTION AGAINST DYNAMIC EFFECTS ASSOCIATED WITH THE POSTULATED RUPTURE OF PIPING Special measures have been taken in the design and construction of the plant to protect the public against the consequences of dynamic effects associated with postulated piping ruptures both inside and outside the containment. The plant is designed so that a postulated piping failure will not cause the loss of needed functions of safety-related systems and structures, and so that the plant can be safely shut down in the event of such failure.
For moderate energy systems, protection from the jet spray and flooding effects due to critical cracks is incorporated into the design. This section presents the design bases and design measures established for DCPP for protection against these dynamic effects in conformance with 10 CFR 50, Appendix A, GDC 4. 3.6.1 SYSTEMS IN WHICH DESIGN BASIS PIPING BREAKS OCCUR 3.6.1.1 High-Energy Piping Inside Containment The following systems have been evaluated with regard to the dynamic effects of pipe whip and blowdown reactive forces associated with a ruptured pipe:
(1) Reactor coolant system (RCS) (a) Primary reactor coolant loops (see Section 3.6.2.1.1.1) (b) Pressurizer surge line (c) Pressurizer spray line
(d) Pressurizer relief and safety valve lines
(e) Drains greater than 1-inch in diameter (2) Chemical and volume control system (CVCS) (a) Charging line and auxiliary spray line
(b) Reactor coolant pumps seal water injection
(c) Letdown line
(d) Excess letdown line
(e) Reactor coolant pumps - seal vent and leakoff, greater than 1 inch in diameter DCPP UNITS 1 & 2 FSAR UPDATE 3.6-2 Revision 19 May 2010 (3) Safety injection system (SIS) (a) Accumulator injection lines
(b) Safety injection lines (4) Residual heat removal (RHR) system (a) Residual heat removal supply
(b) Residual heat removal return (5) Turbine steam supply system (a) Main steam lines
(b) Feedwater lines
(c) Steam generator blowdown lines 3.6.1.2 High-Energy Piping Outside Containment The following criteria and definitions apply to the selection of high-energy piping systems outside containment for evaluation of the dynamic effects associated with postulated pipe rupture:
(1) (a) All systems having a service temperature greater than 200°F or an operating pressure greater than 275 psig are considered (b) Open crack breaks are postulated to occur in the most adverse locations in piping having fluid temperature or pressure greater than the above (c) Design basis breaks, in addition to crack breaks, are postulated in those portions of high-energy systems where both temperature and pressure exceed these levels (d) The criteria for determining the location of design basis breaks are defined later in this section (2) Piping that is either encased in concrete or protected by barriers from safety-related SSCs is considered to be adequately designed (3) Piping that is physically located so that unrestrained motion (pipe whip) could occur in any direction about a plastic hinge formed after a pipe DCPP UNITS 1 & 2 FSAR UPDATE 3.6-3 Revision 19 May 2010 rupture, but that could not impact any safety-related structure, component, or system is considered to be adequately designed The systems that contain high-energy lines located outside of the containment in which both open crack and design bases breaks are postulated to occur are:
(1) Condensate system
(2) Feedwater system
(3) Turbine steam supply system (main steam, steam generator blowdown system, and auxiliary feedwater turbine steam supply piping up to stop valve FCV 95) (4) Extraction steam and heater drip system
(5) Chemical and volume control system
(6) Turbine and generator associated systems Open crack breaks are also postulated in the auxiliary steam system, as it contains piping at a temperature that exceeds 200°F and in the auxiliary feedwater piping (pressure greater than 275 psig).
No design basis breaks or crack breaks are postulated downstream of stop valve FCV-95 in the auxiliary feedwater pump turbine steam supply because it is not pressurized during startup, shutdown, or normal plant operating conditions. 3.6.1.3 Moderate-Energy Piping Through-wall cracks are postulated to occur in moderate energy systems, i.e., any pipe larger than 1-inch in diameter with fluid temperature less than or equal to 200°F and pressure less than or equal to 275 psig, to determine the effect of resulting spray or flooding on safety-related equipment.
The RHR system, and its associated normally pressurized branch piping is analyzed as a moderate-energy system because the RHR system is only a high-energy system for a very small period of time. The system is also seismic Design Class I, dual-purpose, designed and constructed to meet ANSI B31.7, Class II requirements.
DCPP UNITS 1 & 2 FSAR UPDATE 3.6-4 Revision 19 May 2010 3.6.2 DESIGN BASIS PIPING BREAK CRITERIA 3.6.2.1 General Criteria 3.6.2.1.1 High-Energy Piping Inside Containment The containment and all essential equipment within the containment, particularly components of the reactor coolant pressure boundary and other safety-related components, are protected against the dynamic and environmental effects of pipe whip resulting from postulated rupture of piping. The criteria for minimizing these effects are described in Section 3.6.5. In March 1993, the DCPP leak-before-break evaluation (Reference 11) was accepted by the NRC (Reference 12), so that the dynamic effects associated with breaks in the main reactor coolant loop piping are no longer part of the DCPP design basis and no longer need to be protected against, although protection from the dynamic effects of RCS branch line and other high energy line breaks must still be provided (see Section 3.6.2.1.1.1).
Engineered safety features (ESFs) are provided for core cooling and boration, pressure reduction, and activity confinement in the event of a loss of reactor coolant or a steam or feedwater line break accident, to ensure that the public is protected in accordance with 10 CFR 100 guidelines. These safety systems have been designed to provide protection for an RCS pipe rupture of a size up to and including a double-ended severance of an RCS main loop. 3.6.2.1.1.1 Reactor Coolant System Main Loop Piping (Leak-Before-Break) In November 1984, the NRC issued NUREG-1061 assessing the applicability of leak-before-break analysis to nuclear power plant piping systems. Effective May 1986, the NRC revised 1971 General Design Criterion 4 to allow the use of leak-before-break methodology for excluding the dynamic effects of postulated ruptures in reactor coolant loop piping in PWRs from the design basis. A draft revision to Standard Review Plan 3.6.3 was subsequently issued outlining the scope of the plant specific evaluation required to obtain NRC acceptance of the use of leak-before-break exclusion. Westinghouse performed the required evaluation for the DCPP main reactor coolant loops (Reference 11), and PG&E submitted the evaluation to the NRC on March 16, 1992, requesting elimination of the dynamic effects of postulated ruptures in the main reactor coolant loop piping from the DCPP design basis. On March 2, 1993, the NRC accepted the analysis and granted permission to eliminate the dynamic effects of those breaks from the DCPP design basis.
The scope of application of the DCPP leak-before-break exemption is limited in nature. It applies to the dynamic effects of breaks in the main reactor coolant loop piping only, and can be used only for purposes of exempting consideration of the dynamic loads resulting from such breaks in the equipment and structural design bases, and for exempting consideration of the dynamic effects of those breaks in the protection of equipment. It applies to the main RCS loop piping only, and does not apply to breaks in DCPP UNITS 1 & 2 FSAR UPDATE 3.6-5 Revision 19 May 2010 branch lines off the main loop lines. Hence, the effects of pipe whip, pipe break reaction forces, jet impingement, decompression waves within the ruptured pipe, missile generation, and dynamic subcompartment pressurization due to main loop piping breaks no longer have to be considered in the DCPP design basis (Reference 13); however, those effects resulting from branch line breaks still must be considered. The inclusion of pipe whip restraints and jet impingement barriers in the design of the plant to protect equipment in containment from the effects of pipe whip and jet impingement resulting from main reactor coolant loop pipe breaks is no longer required. In addition, dynamic LOCA loads resulting from main reactor coolant loop breaks now need not be included in the dynamic load combinations for equipment and structural analyses, although those loads resulting from branch line breaks must still be included. Snubbers on steam generators and reactor coolant pumps whose only design function is the mitigation of thrust loads associated with main reactor coolant loop pipe breaks are no longer required. However, the use of the leak-before-break exemption is specifically not allowed for purposes of accident analysis or for purposes of environmental qualification of equipment. Static post-LOCA peak containment pressure resulting from main RCS loop breaks must still be included in load combinations where that pressure is a consideration in the structural design. The ECCS and ESF systems must still be capable of mitigating the effects resulting from the original design basis double-ended guillotine breaks in the main reactor coolant loops, and the equipment required to mitigate a LOCA must still be environmentally qualified to the conditions resulting from such breaks.
The acceptability of the leak-before-break evaluation is based on a number of reactor coolant system design and operating characteristics which are expected to remain fairly constant over the life of the plant and which are controlled by procedures and licensing and design basis documents. These include main coolant loop piping materials and mechanical properties, as-built configuration, assumed seismic loads and load combinations, reactor coolant system chemistry, and reactor coolant system operating parameters. To maintain the validity of the leak-before-break evaluation, these characteristics should not change significantly in a nonconservative direction. If such a change occurs or is made by design or procedure change, its effect on the assumptions made in the leak-before-break analysis should be evaluated. The leak-before-break analysis also assumes that the DCPP reactor coolant system leak detection system has the capability to detect an increase in reactor coolant system leakage into the containment of 1 gpm. The current design basis for this system indicates that it has this capability (see Section 5.2.7). Operability of this system is controlled by the plant Technical Specifications.
As a part of the Unit 2 Steam Generator Replacement Project, the reactor coolant loop piping was reanalyzed, which resulted in new reactor coolant loop loads. These new loads, along with steam generator replacement related temperature changes, were used to determine the impact on the existing DCPP leak-before-break analysis. The results determined that the leak-before-break recommended margins remained satisfied. Therefore, the conclusions reached in the existing Reference 11 report remain valid with the replacement steam generator installation. DCPP UNITS 1 & 2 FSAR UPDATE 3.6-6 Revision 19 May 2010 3.6.2.1.1.2 Reactor Coolant System Connected Piping The piping connections to the primary reactor coolant loops fall into the general categories illustrated in Figure 3.6-1. These categories are defined by the direction of flow to or from the primary reactor coolant loops and by the associated valve configuration. A rupture of these lines conceivably could cause uncontrolled loss of reactor coolant depending on the precise location of the break and the line configuration.
In establishing the dynamic effects criterion, uncontrolled loss of reactor coolant is assumed to occur for a pipe break out to the restraint of the second automatic isolation valve (Case II, Figure 3.6-1) on outgoing lines, and out to and including the second check valve on incoming lines normally with flow (Case III, Figure 3.6-1). This criterion takes credit for only one of the two valves performing its intended function. However, for the letdown line pipe break analysis, credit for successful closure of isolation valves LCV-459 and LCV-460 is not required (they would be considered to be fail-as-is valves in Figure 3.6-1, Case II). The HELB analysis showed that accident mitigation and plant shutdown could be successfully accomplished for a letdown line break downstream of these valves even in the event they should not close. For normally closed isolation or incoming check valves (Cases I and IV, Figure 3.6-1), uncontrolled loss of reactor coolant is assumed to occur for pipe breaks on the reactor side of the valve.
It is assumed that a break of the piping associated with ESFs does not occur during the injection phase following a loss of coolant. During the recirculation phase, a leak or equivalent break resulting in a maximum flow of 50 gpm is assumed. This value is based on the flow that could result from the complete failure of a RHR pump seal. The radiation dose analysis for this seal failure is discussed in Section 15.5. 3.6.2.1.1.3 Other High-Energy Piping Inside Containment Breaks were postulated at all terminal ends and all high stress points in accordance with RG 1.46 (Reference 1). Subsequent to receipt of NRC approval on March 13, 1987, break locations were postulated based on stress level as recommended in NRC BTP MEB 3-1 (Reference 8). Subsequent to the issuance of NRC Generic Letter 87-11 on June 19, 1987, break locations are postulated as recommended in BTP MEB 3-1 Rev. 2 (Reference 9). 3.6.2.1.2 High-Energy Piping Outside Containment The criteria that apply to the evaluation of the dynamic effects associated with postulated high-energy pipe rupture outside the containment are in accordance with those given in References 4, 5, and 6.
DCPP UNITS 1 & 2 FSAR UPDATE 3.6-7 Revision 19 May 2010 3.6.2.1.3 Moderate-Energy Piping The moderate-energy lines were reviewed to determine the effects of an assumed leak at the worst location with respect to the equipment required for safe shutdown. The effects of water spray on the equipment and potential compartment flooding were considered. 3.6.2.2 Specific Criteria The specific criteria for determining pipe break location, type, and area are discussed below. 3.6.2.2.1 Primary Reactor Coolant Piping 3.6.2.2.1.1 Locations Where Design Basis Piping Breaks Are Postulated to Occur To provide integrity and design adequacy of the primary reactor coolant loop piping and equipment supports in the event of a highly improbable pipe rupture accident, a number of pipe rupture locations were postulated in the original design. The primary reactor coolant loop was analyzed for the design pipe breaks listed in this section and shown in Figure 3.6-4. However, as discussed in Section 3.6.2.1.1.1 above, due to the acceptance of the DCPP leak-before-break evaluation by the NRC (Reference 12), the dynamic effects of breaks in the main reactor coolant loop piping no longer have to be analyzed; only the effects from RCS branch line breaks have to be considered.
The piping of the reactor coolant loops was designed to ANSI B31.1. Design was completed prior to the issuance of RG 1.46 and the nuclear piping Codes B31.7 and the ASME Code III, to which the break criteria of the Westinghouse Report WCAP-8082 (Reference 3) specifically apply. Consequently, these documents were not available when the discrete break locations for the reactor coolant loop (RCL) were determined. However, a comparison of the postulated break locations for the RCL and those of WCAP-8082 shows that the break locations are similar and provide protection equivalent to the criteria of RG 1.46. (Again, however, due to the acceptance of the DCPP leak-before-break evaluation by the NRC, the dynamic effects of breaks in the main reactor coolant piping no longer have to be analyzed; only the effects from RCS branch line breaks have to be considered. Since the breaks postulated for the original analyses are more severe than those that are now required to be considered, the original analyses are conservative.)
These discrete break locations and types were determined by an engineering approach that employed, as its basis, stress and fatigue analyses, system considerations, operational characteristics, and loading conditions. The breaks in the hot and cold legs were placed in the straight run outside of the primary shield wall. These circumferential breaks were chosen so as to allow full double-ended pipe separation and full discharge flow rather than limited area breaks and limited flow which would be obtained from a break inside the shield wall or at the reactor vessel nozzles. These RCL break locations DCPP UNITS 1 & 2 FSAR UPDATE 3.6-8 Revision 19 May 2010 were chosen for the piping dynamic analysis. The criteria used to determine the break locations on the RCL provided equivalent conservatism and result in equivalent protection to the criteria of RG 1.46. The dynamic analyses of the primary RCL piping and equipment supports for each of these break locations provided assurance of the protection of public health and safety. (Again, however, due to the acceptance of the DCPP leak-before-break evaluation by the NRC, the dynamic effects of breaks in the main reactor coolant piping no longer have to be analyzed; only the effects from RCS branch line breaks have to be considered. Since the breaks postulated for the original analyses are more severe than those that are now required to be considered, the original analyses are conservative.) 3.6.2.2.1.2 Types of Breaks and Break Areas Assumed for Postulated Primary Coolant Loop Failure for Piping Dynamic Analysis The types of breaks assumed in the original analysis for postulated primary coolant loop failure for the piping dynamic analysis included:
(1) Straight portion of hot leg piping - guillotine (2) Straight portion of cold leg piping - guillotine
(3) Steam generator inlet nozzle - guillotine
(4) Steam generator outlet nozzle - guillotine
(5) Reactor coolant pump inlet nozzle - guillotine (6) 50° elbow - longitudinal
(7) Flow entrance to the 90° elbow - guillotine
(8) RHR primary loop connection - guillotine
(9) Safety injection/primary coolant loop connection - guillotine
(10) Pressurizer surge/primary coolant loop connection - guillotine
(11) Loop closure weld in crossover leg - guillotine The break length for the longitudinal breaks was considered to be equal to two pipe diameters. For the breaks listed in this section, the break area is conservatively assumed to be equal to the cross-sectional area of the pipe. However, as discussed in Section 3.6.2.1.1.1 above, due to the acceptance of the DCPP leak-before-break evaluation by the NRC (Reference 12), the locations, types, and areas of breaks in the main reactor coolant loop piping no longer have to be defined for purposes of performing dynamic effects analyses. As a consequence, only branch line breaks (8), DCPP UNITS 1 & 2 FSAR UPDATE 3.6-9 Revision 19 May 2010 (9), and (10) above remain within the design basis for dynamic effects and require dynamic effects analyses.
A break at each of the reactor vessel inlet and outlet nozzles was postulated in addition to those listed above. These breaks were assumed to be limited in area by the primary shield wall restraints. The purpose of postulating breaks at these locations was to determine mass and energy release information for use in the evaluation of the asymmetric pressure loading on the reactor vessel. Under the leak-before-break exemption, these breaks and the resulting asymmetric pressure loadings no longer need to be considered. 3.6.2.2.2 Other High-Energy Piping Inside Containment Breaks were postulated at all terminal ends and all high stress points in accordance with RG 1.46. Subsequent to receipt of NRC approval on March 13, 1987, break locations were postulated based on stress level as recommended in NRC BTP MEB 3-1. Subsequent to the issuance of NRC Generic Letter 87-11 on June 19, 1987, break locations are postulated as recommended in BTP MEB 3-1 Rev. 2. 3.6.2.2.3 High-Energy Piping Outside Containment The selection of design basis breaks in each of the systems identified in Section 3.6.1.2 is generally based on results of the piping stress analyses. These analyses consider effects of pressure, deadweight, thermal expansion during normal operation, upset and test conditions, and the DE. Subsequent to receipt of NRC approval on March 13, 1987, break locations were postulated based on stress level as recommended in BTP MEB 3-1. Subsequent to the issuance of NRC Generic Letter 87-11 on June 19, 1987, break locations are postulated as recommended in BTP MEB 3-1 Rev. 2. Where such stress analyses were not available, the breaks were postulated to occur at such fittings that could result in the most severe consequences in such systems. Crack breaks were postulated to occur in the most adverse orientations and locations throughout the piping. 3.6.2.2.4 Moderate-Energy Piping Through-wall cracks were assumed to have an area equal to 1/2d x 1/2t, where "d" is the nominal pipe diameter and "t" is the nominal pipe wall thickness. The control room ventilation and pressurization system is not required to be protected from moderate-energy pipe breaks from either unit. In the event that an MELB occurs, and the control room becomes uninhabitable due to the impairment of the HVAC system, safe shutdown can be controlled from the hot shutdown remote control panel.
DCPP UNITS 1 & 2 FSAR UPDATE 3.6-10 Revision 19 May 2010 3.6.3 DESIGN LOADING COMBINATIONS 3.6.3.1 High-Energy Piping Breaks Inside Containment The design loading combinations, the design condition categories, and design stress limits applied to components, supports, and pipe whip restraints of essential components and piping of high-energy fluid systems within the containment, are described in Sections 3.9 and 5.2. Section 5.2 addresses Class A components while Section 3.9 addresses the remaining components. A discussion of potential missiles is presented in Section 3.5.
In the original design, to achieve an adequate primary RCL design, a dynamic analysis, as described in Section 3.6.4.1, was performed on the RCL/support system described below for the pipe break cases discussed in Section 3.6.2.2.1.2 to determine component and component support loadings. However, as discussed in Section 3.6.2.1.1.1 above, due to the acceptance of the DCPP leak-before-break evaluation by the NRC (Reference 12), dynamic analyses to determine the RCS component and component support loadings resulting from breaks in the main reactor coolant loops are no longer separately required. Only dynamic analyses for RCS branch line breaks are still required. The support structure design analyses discussed in the following three subsections were based on the original design requirements, and do not reflect the subsequent leak-before-break exemption. Since the breaks postulated for the original analyses are more severe than those that are now required to be considered, the original analyses are conservative. 3.6.3.1.1 Reactor Vessel Support Structure The reactor vessel support structure is designed to resist thrusts that are considered to originate from the following three sources: (a) the reactions of the blowdown forces in the primary RCL piping that are eventually transmitted to the reactor nozzles, (b) the forces within the reactor pressure vessel shell acting on the reactor internals and shell wall, and (c) the effects of reactor vessel cavity asymmetric pressurization.
The superposition of these effects, in time-history form, permits accurate determination of the loads transmitted to the reactor vessel support structure. The design and details of the reactor vessel support structure are further discussed in Section 5.5.13. 3.6.3.1.2 Steam Generator Support Structure The steam generators are supported in a manner that allows for thermal expansion of the equipment from cold to operating condition. Each steam generator is supported such that the rupture of steam, feedwater, blowdown, or instrument piping as a result of thrust forces created by the rupture of a primary RCL pipe is prevented. The steam generators are also supported in a manner that prevents rupture of a primary RCL pipe as a result of thrust forces created by the rupture of a steam or feedwater line.
DCPP UNITS 1 & 2 FSAR UPDATE 3.6-11 Revision 19 May 2010 Guides and restraints are employed, where required, to limit the motion of the steam generators under the reaction forces that result from a primary RCL pipe break, to a distance that is compatible with the flexibility of the steam and feedwater piping. Also, the motion of the steam generators, under the reaction forces due to a steam or feedwater pipe break, is limited to a distance that is compatible with the flexibility of the primary reactor coolant piping. The design and details of the steam generator support structures are further discussed in Section 5.5.13. 3.6.3.1.3 Reactor Coolant Pump Support Structure Each reactor coolant pump is supported in a manner that would limit its displacement short of the primary shield, secondary shield, steam generator, steam generator supports, equipment and piping in adjacent loops, and hot leg of the affected loop as a result of a rupture occurring in either the pump suction or discharge piping. The design and details of the reactor coolant pump support structures are further discussed in Section 5.5.13. 3.6.3.2 High-Energy Piping Breaks Outside Containment Piping response analyses are performed on high-energy piping systems at those postulated break locations for which unrestrained pipe motion about a plastic hinge could impact or endanger vital systems. Factors and criteria that are considered are:
(1) The dynamic nature of the loading.
(2) Pipe impact effects due to gaps in piping restraints. (3) Nonlinear (elastic-plastic) pipe and restraint material properties and the effect of rapid strain rate on material properties. (4) For circumferential breaks in a pipe, whip occurs upon attainment of 50 percent of uniform ultimate strain at a plastic hinge due to loading from the blowdown reactive forces. The pipe whip is characterized by unrestrained motion of the pipe about the hinge in the direction governed by the vector thrust of the break force. (5) For longitudinal breaks, failure occurs upon attainment of a hinge mechanism with 50 percent of uniform ultimate strain on each hinge. (6) Lower-bound piping material properties are used for the prediction of pipe whips. (7) Both lower- and upper-bound piping material properties are used for the prediction of loads on anchors and restraints. DCPP UNITS 1 & 2 FSAR UPDATE 3.6-12 Revision 19 May 2010 (8) Piping loads on the rupture restraints are limited to the equivalent of 50 percent of uniform ultimate strain in the restraint materials. The nonlinear material properties of the restraint are considered. (9) The load combinations and allowable limits used in evaluating Design Class I concrete structures for the effects of the postulated high-energy pipe breaks are discussed in Section 3.8. (10) Load combinations and allowable limits used in evaluating those Design Class I steel structures outside the containment whose function is to provide protection against the effects of the postulated high-energy pipe break are discussed Section 3.8. 3.6.4 DYNAMIC ANALYSES The dynamic effects of pipe breaks described previously in Sections 3.6.1 and 3.6.2 were analyzed using the methods described below. 3.6.4.1 Reactor Coolant Loop Piping Breaks In the original design, the primary coolant loop pipe break hydraulic analysis described below in Sections 3.6.4.1.1, 3.6.4.1.2, and 3.6.4.1.3 was performed to determine the resulting dynamic thrust and jet forces and dynamic asymmetric pressure loadings. However, as discussed in Section 3.6.2.1.1.1 above, due to the acceptance of the DCPP leak-before-break evaluation by the NRC (Reference 12), the dynamic effects of breaks in the main reactor coolant loop piping no longer have to be considered in the design basis analyses. Analyses such as those described below are now only required for RCS branch line breaks. Since the breaks postulated for the original analyses are more severe than those that are now required to be considered, the original analyses are conservative. 3.6.4.1.1 Thrust-Time Relationship The blowdown forces caused by a rupture of a primary RCL pipe include the specific jet thrust at the break location and the internal hydraulic forces resulting from the acceleration of the fluid within the broken and unbroken loops.
Hydraulic forcing functions are calculated for the ruptured and intact RCLs as a result of a postulated LOCA. These forces result from the transient flow and pressure histories in the RCS. The calculation is performed in two steps. The first step is to calculate the transient pressure, mass flow rates, and thermodynamic properties as a function of time. In the second step, the results obtained from the hydraulic analysis, along with input of areas and direction coordinates, are used to calculate the time-history of forces at appropriate locations in the RCLs.
DCPP UNITS 1 & 2 FSAR UPDATE 3.6-13 Revision 19 May 2010 The analysis is performed on integrated analytical models including the steam generator and reactor coolant pump, the associated supports and restraints, and the attached piping. An elastic-dynamic, three-dimensional model of the reactor coolant loop is constructed. The boundary of the analytical model is, in general, the interface between the foundation concrete and the support structure. The deformation of the reinforced concrete foundation supports is considered, where applicable to the RCL model.
The steps in the analytical method are:
(1) The initial deflected position of the RCL model is defined by applying the initial steady state condition of the unbroken reactor coolant loop model.
(2) Natural frequencies and normal modes of the broken loop are determined.
(3) The initial deflection, natural frequencies, normal modes, and time-history forcing functions are used to determine the time-history forcing dynamic deflection response of the lumped mass representation of the RCL. (4) The forces imposed on the equipment supports and restraints by the loop are obtained by multiplying the support stiffness matrix and the time-history of the displacement vector at the support point. (5) The time-history dynamic deflections at mass points are treated as an imposed deflection condition on the ruptured loop RCL model and internal forces, deflections, and stresses at each end of the members on the RCL piping systems are computed. The results are used to verify the adequacy of the piping, equipment supports, and restraints.
The hydraulic model represents the behavior of the coolant fluid within the RCS. Key parameters calculated by the hydraulic model are pressure, mass flow rate, and density. These parameters are supplied to the thrust calculation, together with appropriate plant layout information, to determine the time-dependent loads exerted by the fluid on the loops. In evaluating the hydraulic forcing functions during a postulated LOCA, the pressure and momentum flux terms are dominant. The inertia and gravitational terms are taken into account in evaluation of the local fluid conditions in the hydraulic model.
The blowdown hydraulic analysis provides the basic information concerning the dynamic behavior of the reactor core environment for the loop forces, reactor kinetics, and core cooling analysis. This analysis requires the ability to predict the flow, quality, and pressure of the fluid throughout the reactor system.
The MULTIFLEX 3.0 computer code performs a comprehensive, space-time dependent analysis of a LOCA and is designed to treat all phases of the blowdown. The stages are: (a) a subcooled stage where the rapidly changing pressure gradients in the DCPP UNITS 1 & 2 FSAR UPDATE 3.6-14 Revision 19 May 2010 subcooled fluid exert an influence upon the RCS internals and support structures, and (b) a two-phase depressurization stage, and (c) a saturated stage.
The code employs a one-dimensional analysis in which the entire RCS is divided into control volumes. The fluid properties are considered uniform and thermodynamic equilibrium is assumed in each element. Pump characteristics, pump coastdown and cavitation, and core and steam generator heat transfer, including the W-3 DNB correlation, in addition to the reactor kinetics, are incorporated in the code. The MULTIFLEX code is described and referenced in Section 5.2.1.10.2. The blowdown hydraulic loads on primary loop components are computed from the following equation: m2Ag144m14.7P144AF (3.6-1) which includes both the static and dynamic effects. The symbols and units are:
F = force, lbf A = aperture area, ft2 P = system pressure, psia m = mass flow rate, lb/sec = Density, lbm/ft3 g = gravitational constant = 32.174 ft/sec2 Am = mass flow area, ft2 In the model to compute forcing functions, the main RCL system is represented by a similar model as employed in the blowdown analysis. The entire loop layout is described in a global coordinate system. Each node is fully described by: (a) blowdown hydraulic information, and (b) the orientation of the steamlines of the force nodes in the system, which includes flow areas and projection coefficients along the three axes of the global coordinate system. Each node is modeled as a separate control volume with one or two flow apertures associated with it. Two apertures are used to simulate a change in flow direction and area. Each force is divided into its x, y, and z components using the projection coefficients. The force components are then summed over the total number of apertures in any one node to give a total x force, total y force, and total z force. These thrust forces serve as input to the piping/restraint dynamic analysis.
The dynamic analysis of RCLs employs displacement method, lumped parameter, and stiffness matrix formulation and assumes that all components behave in a linear elastic manner. DCPP UNITS 1 & 2 FSAR UPDATE 3.6-15 Revision 19 May 2010 3.6.4.1.2 Jet Dynamic Force A jet dynamic force will result from any of the pipe breaks postulated above. The force, caused by the momentum change of fluid flowing through the break, is a function of the upstream fluid conditions, fluid enthalpy, source pressure, pipe flow restrictions, friction, and dimensions. Structural barriers and physical separation by plant layout have been used in the design to limit the effects of impingement. Where necessary, the jet forces resulting from the pipe break have been computed using the following method:
Jet dynamic forces on structures are calculated:
Fj = Cj (1.26 PA) (3.6-2) where:
Fj = jet dynamic force acting on a structure Cj = factor to account for the dynamic nature of the load. In determining the value of Cj, inelastic behavior is assumed P = system operating pressure A = cross-sectional area of pipe
The above loads were considered in the structural design as described in Section 3.8. 3.6.4.1.3 Asymmetric Pressure Loading Pressure differentials may develop between structural subcompartments as a result of reactor coolant pipe breaks. Evaluation of these pressure differentials is given in Section 6.2.1. 3.6.4.2 Other High-Energy Piping Breaks Inside Containment Blowdown forces and jet impingement forces due to the postulated piping breaks in lines inside containment (other than the RCLs) were calculated from the formula:
FB = CT PoA (see Reference 2) (3.6-3) where:
FB = steady state blowdown force, lb CT = steady state thrust coefficient
= 2.0 for subcooled water, or 1.26 for saturated steam/water (see Reference 2)
Po = line pressure at time 0 A = cross-sectional flow area of pipe with a full-area break
DCPP UNITS 1 & 2 FSAR UPDATE 3.6-16 Revision 19 May 2010 Moments required to form a plastic hinge were calculated from the formula: oypRISKM (3.6-4) where:
Mp = plastic moment K = Mp/My where My is the moment to produce yielding on the extreme fiber Sy = yield stress of material at temperature I = moment of inertia of piping = /4 (Ro4 - Ri4) Ro = outside radius of pipe Ri = inside radius of pipe K = 2.5 for materials in the piping systems 3.6.4.3 High-Energy Piping Breaks Outside Containment Analysis to determine the effects of a rupture of high-energy piping breaks outside containment was originally reported in Reference 7. Pipe break effects analyzed include pipe whip, jet impingement, compartment pressurization, water flooding, and the environmental effects of pressure, temperature, and humidity.
The analyses on pipe whip, jet impingement, and water flooding were reverified to reflect the current as-built condition, and modifications were made as necessary. In this reanalysis, in addition to the method used in Reference 5 of Reference 7, the methods as described in ANSI/ANS 58.2 are also used to verify the jet impingement temperature.
The analyses on compartment pressurization and the environmental effects of pressure, temperature and humidity have been re-done and the results of these analyses totally supersede the analyses as reported in Reference 7. These analyses and their results are reported in Sections 3.6.4.3.2 and 3.6.4.3.3. Because of the similarity of Units 1 and 2, these results can also apply to Unit 2. 3.6.4.3.1 Blowdown Forces Fluid blowdown thrust time-histories resulting from a pipe rupture are determined using PRTHRUST, a computer code derived from RELAP3. The assumptions used for these analysis together with representative mathematical models and typical results are presented in Reference 7.
Pipe whip analyses of the main steam and feedwater piping, between the containment and the turbine building, resulting from ruptures at the identified locations were determined using computer program PIPERUP. PIPERUP determines the nonlinear, elastic-plastic response of three-dimensional piping restraint systems to the fluid blowdown force time-histories defined above. Gaps between the piping and rupture restraints, as well as nonlinear properties of the restraints are included in the analysis. DCPP UNITS 1 & 2 FSAR UPDATE 3.6-17 Revision 19 May 2010 A description of the analytical methods used in the analyses, mathematical models of the piping systems, and representative results are also presented in Reference 7. 3.6.4.3.2 Compartment Pressurization A definition of the worst case overpressure condition is required for the areas subjected to high-energy line breaks in order to evaluate the structural capability of essential structures required to maintain their integrity following the break. The potentially affected areas of the plant were modeled as compartments connected by vent paths that communicate with the break compartment in the multicompartment computer program FLUD or PCFLUD. This program calculates the conditions that will exist in the compartments over the duration of release of mass and energy from the postulated break. Figures 3.6-5 through 3.6-15 illustrate the compartment designations for the various models used in the analysis. Because of the similarity between Units 1 and 2, the compartment designations also apply to Unit 2. 3.6.4.3.2.1 Main Steam and Feedwater Piping The controlling design basis break locations in the main steam piping between the containment and turbine stop valves in regard to compartment overpressure are as follows:
(1) Auxiliary building, Area GW, containment penetration (2) Auxiliary building, Area GW, G-line anchor (3) Turbine building, Area D, elevation 85 feet (4) Turbine building, Area D, elevation 140 feet Mass and energy release were calculated for each of the above breaks assuming the worst case operating conditions with the flow constrictions at the containment penetration and G-line anchor considered in addition to the available means of detection and automatic isolation. The consequent pressurization of compartments was determined and the results are illustrated in Figures 3.6-16 through 3.6-19.
Pressurization effects due to feedwater line breaks are bounded by the above results for the main steam lines. 3.6.4.3.2.2 Other High-Energy Piping The controlling break locations for other high-energy lines are as follows:
(1) Chemical and volume control system (DER in letdown line) - Auxiliary building, Area K, letdown heat exchange room DCPP UNITS 1 & 2 FSAR UPDATE 3.6-18 Revision 19 May 2010 (2) Auxiliary steam supply system (crack) - Auxiliary building, Area J, auxiliary feedwater pump rooms
- Auxiliary building, Area K, elevation 100 feet open area (3) Turbine steam supply system (DER in line 593)
- Auxiliary building, Area L, radiation monitor room Mass and energy release were calculated for each of the above breaks assuming the worst case operating conditions and considering the available means of detection and isolation system. In the case of the CVCS break, an automatic detection/isolation system as described in Section 7.6 is utilized to minimize the release. The consequent pressurization of compartments was determined and the results are illustrated in Figures 3.6-20 through 3.6-26. Pressurization effects due to other high-energy line breaks in Area GE/GW and the turbine building are bounded by the results for the main steam line breaks.
3.6.4.3.3 Environmental Conditions A definition of the worst case environmental conditions of temperature and humidity is required for the area subjected to the high-energy line breaks to evaluate essential safety-related equipment required to shutdown the plant following the break. 3.6.4.3.3.1 Main Steam and Feedwater Piping The controlling break locations in the main steam piping between the containment and turbine stop valves for consideration of adverse environmental effects are as follows:
(1) Auxiliary building, Area GW, elevation 115 feet (crack break) (2) Turbine building, Area D, elevation 85 feet (DER) (3) Turbine building, Area D, elevation 140 feet (DER)
Mass and energy release were calculated for each of the above breaks assuming the worst case operating conditions. The consequent compartment temperature and relative humidity were determined using the computer program FLUD or PCFLUD. Bounding temperature profiles for the affected areas are illustrated in Figures 3.6-28 through 3.6-33. The maximum relative humidity of 100 percent was applied in the evaluation of essential safety-related equipment with the exception of compartments 3 and 4, as shown in Figures 3.6-6 and 3.6-7, which will be at 60 percent relative humidity. New MSLB analyses accounting for the elimination of the boron injection tank (BIT) utilized the computer program LOFTRAN to determine the mass and energy releases in the GE/GW compartment. Bounding temperature profiles for the DCPP UNITS 1 & 2 FSAR UPDATE 3.6-19 Revision 19 May 2010 RSGs were calculated using the computer program GOTHIC and are summarized in the table below: Compartment Peak Temperature, °F(a) GW 115 ft 453.7 GE 115 ft 329.1 GW 100 ft 356.5 GE 100 ft 306.3 GW 85 ft 261.7 Pipeway 425.5 (a) For clarity, only peak instantaneous temperature, as determined over the analysis time duration (2000 second maximum time duration), for the limiting case for each analyzed compartment, is included herein. Complete analysis results, including pertinent temperature profiles for each compartment for each of the 60 base case scenarios included in the analysis, reside in applicable PG&E calculations. 3.6.4.3.3.2 Other High-Energy Piping The controlling break locations for the other high-energy lines for consideration of adverse environmental effects are those identified in Section 3.6.4.3.2.2. The consequent temperature and relative humidity in the affected compartments were determined in the FLUD analysis. Bounding temperature profiles for the affected areas are illustrated in Figures 3.6-34 through 3.6-40. The maximum relative humidity of 100 percent was applied in the evaluation of essential safety-related equipment. 3.6.5 PROTECTIVE MEASURES 3.6.5.1 Piping Breaks 3.6.5.1.1 High-Energy Piping Breaks Inside Containment It is essential that the equipment support structures (reactor pressure vessel, steam generator, and reactor coolant pump) be protected from the impact of large whipping pipes or be designed to resist such impact. This protection is accomplished by separation of equipment and piping, or by providing pipe restraints to prevent the formation of a plastic hinge mechanism. With the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 12), protection of equipment and support structures from the whipping of main reactor coolant loop piping is no longer required, although protection from the dynamic effects of RCS branch line and other high energy line breaks must still be provided. If any branch pipes are supported from equipment support structures, the reaction force resulting from a rupture of these lines is considered in designing the equipment supports. Small pipes are assumed to cause no significant damage to equipment supports.
DCPP UNITS 1 & 2 FSAR UPDATE 3.6-20 Revision 19 May 2010 To ensure the continued integrity of the vital components and the engineered safety systems, consideration is given to the consequential effects of the pipe break itself in order to meet the following criteria:
(1) The minimum performance capabilities of the engineered safety systems must not be reduced below that required to protect against the postulated break. (2) The containment(a) leaktightness must not be decreased below the design value, if the break leads to a loss of reactor coolant. (3) An RCS pipe break must not cause a steam-feedwater system pipe break and vice versa.
The fluid discharge from ruptured piping would produce reaction and thrust forces in the piping systems. The effects of these forces have been considered in ensuring that the general criteria and performance of engineered safety systems are satisfied.
In addition to the three criteria on the consequential effects of the pipe break itself, as given above, propagation of damage must be limited in type and/or degree as follows:
(1) A pipe break that is not a loss of reactor coolant must not cause a loss of reactor coolant, or a steam or feedwater line break.
(2) Branch lines connected to the RCS are defined as "large" if they have an inside diameter greater than 4 inches. Large piping is restrained so that: (a) propagation of the break to the unaffected loops is prevented
(b) propagation of the break in the affected loop is permitted to occur but must not exceed 20 percent of the area of the line that initially ruptured (3) Branch lines connected to the RCS are defined as "small" if they have an inside diameter equal to or less than 4 inches. Small lines are restrained or arranged to meet the following requirements in addition to (1) and (2) above: (a) Break propagation must be limited to the affected leg.
(a) The containment is defined here as the containment structure liner and penetrations, the steam generator shell including instrumentation connections, the feedwater, blowdown, and steam generator drain lines within the containment structure.
DCPP UNITS 1 & 2 FSAR UPDATE 3.6-21 Revision 19 May 2010 (b) Propagation of the break in the affected leg is permitted, but must be limited to a total break area of 12.5 square inches (4-inch inside diameter). (c) Damage to the high-head safety injection lines connected to the other leg of the affected loop or to the other loops must be prevented. (d) Propagation of the break to high-head safety injection lines connected to the affected leg must be prevented if the line break results in a loss of core cooling capability due to a spilling injection line. (4) Where restraints are necessary to prevent impact causing unacceptable damage to essential systems and components, they are installed such that a plastic hinge (unrestrained rotation) on the pipe at the two support points closest to the break will not be formed (see Section 3.6.5.2). Pipes are allowed to form plastic hinges in areas or arrangements where: (a) Whipping free sections cannot reach equipment or other pipes for which protection is required. (b) Protective barriers prevent the whipping pipe from impacting components or pipes requiring protection. (c) The internal energy of the pipe is insufficient to impair the function of any equipment or structure, i.e., the operating temperature is less than 200°F and the operating pressure is below 275 psig. Pursuant to RG 1.46, lines hitting equal or larger size lines of the same schedule will not cause failure of the line being hit, e.g., failure of a 2-inch line will not cause subsequent failure of another 2-inch line or a line of larger size. The reverse, however, is assumed to be probable; i.e., a 4-inch line, should it fail and whip as a result of the fluid discharged through the break, is assumed to cause failure of smaller lines, such as neighboring 3-inch or 2-inch lines, unless additional justification is provided. 3.6.5.1.2 High-Energy Piping Breaks Outside Containment The safety-related features requiring protection from high-energy pipe breaks outside containment are discussed in Reference 7.
DCPP UNITS 1 & 2 FSAR UPDATE 3.6-22 Revision 19 May 2010 3.6.5.2 Pipe Restraint Design Criteria 3.6.5.2.1 Inside Containment Where the requirements as outlined above cannot be satisfied by judicious routing of the piping, pipe whip restraints are designed and located as outlined below. Note that with the acceptance of the DCPP main RCS loop leak-before-break analysis by the NRC (Reference 12), pipe whip restraints are not required on main reactor coolant loop piping since breaks in this piping are no longer assumed to occur for evaluation of dynamic effects. Pipe whip effects due to breaks in RCS branch lines and other high energy lines must still be evaluated. 3.6.5.2.1.1 Location of Pipe Whip Restraints Restraints are located at each zone of the piping over 1 inch in size where formation of a plastic hinge could endanger a structure, component, or system vital to safety. Design was completed prior to issuance of RG 1.46 in May 1973. The piping design on all of these systems is based on ANSI B31.1-1967. 3.6.5.2.1.2 Design of Restraint Structures Restraint structures consist of steel rods, U-bolts, crushable bumpers, and steel frames. In determining their design load, the pipe rupture restraints are considered independent of dead and live load supports and of seismic restraints.
In equation form, Y = Yr (3.6-5) where: Y = section strength required to resist design loads Yr = the equivalent static load on a pipe rupture restraint generated by the reaction on the broken high-energy pipe during a postulated break. The load, Yr, includes a dynamic impact factor (DIF). Unless otherwise justified, the DIF equals 2 for restraints where rods, U-bolts, or crushable bumpers are provided, and 3 for restraints without U-bolts, rods, or crushable bumpers and a gap larger than 1/2 inch; Yr = (DIF) (K)(P)(A), where K is the thrust coefficient. Maximum strain of steel rods and U-bolts is limited to 50 percent of the strain corresponding to the maximum tested ultimate strength of the material. Crushable bumper deformation is limited to two-thirds of the effective crushing length of the bumper. For nonlinear analysis of steel frames, the allowable stress is the minimum specified yield stress of the material. Due to the high rate of strain that the restraint DCPP UNITS 1 & 2 FSAR UPDATE 3.6-23 Revision 19 May 2010 would experience after pipe rupture, the static yield strength of the frame material is increased by 5 percent. 3.6.5.2.1.3 Summary of Pipe Whip Effects Lines that are classified as high-energy have been evaluated against RG 1.46 as the minimum design criteria. Tables 3.6-1 and 3.6-2 are checklists of pipe whip effects from postulated pipe ruptures inside the containment. 3.6.5.2.2 High-Energy Piping Breaks Outside Containment Pipe restraint design criteria for high-energy piping outside containment are given in Reference 7. 3.6.5.3 Protective Provisions for Vital Equipment 3.6.5.3.1 High-Energy Piping Breaks Inside Containment The piping is routed so that whipping of two free sections cannot reach equipment or other pipes for which protection is required. Barriers are used, where available, to prevent the whipping pipe from impacting equipment or piping requiring protection. For example, the crane wall, operating floor, and refueling cavity walls serve as barriers between the RCLs and the containment liner. Note that with the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 12), protection of vital equipment from whipping of the main reactor coolant loop piping is not required since breaks in this piping are no longer assumed to occur for evaluation of dynamic effects. Pipe whip effects due to breaks in RCS branch lines and other high energy lines must still be evaluated. Except for ECCS lines attached to main RCLs, the engineered safety features are located outside of the crane wall. The ECCS lines that penetrate the crane wall are routed outside of the crane wall so as to penetrate it in the vicinity of the loop to which they are attached. The results of analyses demonstrate that pipe whip resulting from a postulated break in an ECCS line inside the crane wall will not cause damage in excess of that allowed by the established criteria. 3.6.5.3.2 High-Energy Piping Breaks Outside Containment The piping anchors, rupture restraints, and restraint attachments are analyzed as described in Reference 7. Safety-related building structures are analyzed in accordance with the design load combinations described in Section 3.8.
Affected equipment and conduits have also been investigated to ensure their operability in the post-break temperature, pressure, and humidity environment(a). (a) The pressure transmitter PT 432 is incorrectly designated as essential in Section 6.1.1.4 of Reference 7. This transmitter is not essential for the satisfactory operation of the auxiliary feedwater system. DCPP UNITS 1 & 2 FSAR UPDATE 3.6-24 Revision 19 May 2010 3.6.5.3.3 Moderate-Energy Piping Breaks The effects of spray or flooding from postulated ruptures of moderate-energy piping were evaluated to indicate probable loss of function of any safety-related equipment. If the loss of function of the equipment could be tolerated due to system redundancies, equipment environmental qualification, etc., no action was required. If the loss of function could not be tolerated, a design modification was required to protect the vulnerable equipment. Following a detailed review and plant walkdown, no modifications were required (Reference 10). 3.6.5.4 Pipe Whip Restraints and Spray Barriers 3.6.5.4.1 Inside Containment For piping inside containment, the analysis shows that the locations of restraints are adequate to prevent unacceptable damage from all whips that could result from postulated breaks (see Figure 3.6-2 and Tables 3.6-1 and 3.6-2). Restraint structures consist of ASTM A304 steel rods or U-bolts, or crushable bumpers, and steel frames of ASTM A36, ASTM A441, or ASTM A516 Grade 70 material. Bumpers are 1-1/2 inch square, thin-walled A151 Grade 1010 carbon steel tubing welded together to form a multi-cell cross-section. Typical restraint structures are shown in Figures 3.6-3A to 3.6-3C. Tested properties of the ASTM A304 material are as follows:
Elastic modulus 28,000 ksi Yield strength 34 to 46 ksi Tensile strength 76 to 94 ksi 3.6.5.4.2 Outside Containment For piping outside the containment, the analysis shows that the locations of restraints are adequate to prevent unacceptable damage from all whips that could result from postulated breaks. A typical restraint is shown in Figure 3.6-3. 3.6.5.4.3 Moderate-Energy Piping Breaks Based on a detailed review and a plant walkdown, it was determined that no impingement shields (i.e., barriers) were necessary to protect vital equipment from moderate-energy pipe breaks (Reference 10). Due to system redundancy and equipment environmental qualification, the postulated MELBs would not affect the capability to achieve a safe shutdown. 3.6.5.5 Differences Between Unit 1 and Unit 2 Pipe Break Protection Features Outside Containment DCPP Units 1 and 2 were designed to be mirror images of each other. This similarity allowed use of the same type of analysis to determine the consequence of a pipe break DCPP UNITS 1 & 2 FSAR UPDATE 3.6-25 Revision 19 May 2010 outside containment. The two units were not built simultaneously, which accounts for some of the design differences between them.
The major difference in protection on Unit 2 was that, for several locations, jet impingement barriers were eliminated from the Unit 2 design. However, for these locations, safety-related equipment was separated from piping systems whose failure could produce jets. Other main differences are in the change in the Unit 2 reheater drain system and location of essential equipment, instrumentation, and electrical conduit.
The reheater drain piping systems of Units 1 and 2 in the turbine building are not mirror images of each other.
Table 3.6-6, Pipe Break Protection Features on Unit 2 Different from Unit 1, describes the design features of the units that are different, compares the protection features of the units, and justifies the protection features employed for Unit 2. 3.
6.6 REFERENCES
- 1. NRC RG 1.46, Protection Against Pipe Whip Inside Containment, May 1973.
- 2. Moody, ASME Paper G9-HT-31, 1969.
- 3. WCAP-8082, Pipe Breaks for the LOCA Analysis of the Westinghouse Primary Coolant Loop, Westinghouse Nuclear Energy Systems, June 1973. 4. Letter dated December 18, 1972, including the attachment "General Information Required for Consideration of the Effects of a Piping System Break Outside Containment" (Docket Nos. 50-275 and 50-323) from A. Giambusso of the AEC to F. T. Searls of PG&E.
- 5. Letter dated January 29, 1973, including the errata sheet for "General Information Required for Consideration of the Effects of a Piping System Break Outside Containment" (Docket Nos. 50-275 and 50-323) from P. Kniel of the AEC to F. T. Searls of PG&E.
- 6. Enclosure 3 to letter dated August 13, 1973, "Structural Design Criteria for Evaluating the Effects of High Energy Pipe Breaks on Category I Structures Outside Containment" (Docket Nos. 50-275 and 50-323) from A. Giambusso of the AEC to F. T. Searls of PG&E.
DCPP UNITS 1 & 2 FSAR UPDATE 3.6-26 Revision 19 May 2010 7. Nuclear Services Corporation, Evaluation for Effects of Postulated Pipe Break Outside Containment for Diablo Canyon Unit 1, Revision 2, June 1974. (Subsequent to Revision 2, the following references were issued to complete the overall justification of the effects of postulated pipe breaks outside containment: Nuclear Services Corporation, Evaluation for the Effects of Postulated Pipe Break Outside Containment for Diablo Canyon Unit 1, Revision 3, April 13, 1977; Pacific Gas and Electric Company, Design Criteria Memoranda T-29 and T-12.)
- 8. Standard Review Plan 3.6.2, BTP MEB 3-1, Postulated Break and Leakage Locations in Fluid System Piping Inside and Outside Containment, July 1981.
- 9. Standard Review Plan 3.6.2, BTP MEB 3-1 Rev. 2, Postulated Break and Leakage Locations in Fluid System Piping Inside and Outside Containment, June 1987.
- 10. "Reanalysis of Moderate Energy Line Break (MELB) Requirements," PG&E Memorandum, January 18, 1991.
- 11. WCAP-13039, Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for DCPP Units 1 and 2, Westinghouse Electric Corporation, November 1991.
- 12. Letter dated March 2, 1993, "Leak-Before-Break Evaluation of Reactor Coolant System Piping for DCPP Units 1 and 2," (Docket Nos. 50-275 and 50-323), from Sheri R. Peterson of the NRC to Gregory M. Rueger of PG&E. 13. NRC Inspection Manual, Part 9900: 10 CFR Guidance, LBB Analysis, "Definition of Leak-Before-Break Analysis and Its Application to Plant Piping Systems,"
issued September 26, 1996.
- 14. Deleted in Revision 19 3.6.7 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures.
DCPP UNITS 1 & 2 FSAR UPDATE 3.7-1 Revision 21 September 2013 3.7 SEISMIC DESIGN 3.7.1 SEISMIC INPUT This section describes the DE, the DDE, and the postulated 7.5M HE.
In addition to the above three earthquakes, PG&E conducted, as described below, a program to reevaluate the seismic design for DCPP. On November 2, 1984, the NRC issued the DCPP Unit 1 Facility Operating License DPR-80. In License Condition 2.C(7) of DPR-80, the NRC stated, in part: "PG&E shall develop and implement a program to reevaluate the seismic design bases used for the Diablo Canyon Power Plant."
PG&E's reevaluation effort in response to the license condition was titled the "Long Term Seismic Program" (LTSP). PG&E prepared and submitted to the NRC the "Final Report of the Diablo Canyon Long Term Seismic Program" in July 1988 (Reference 19). The NRC reviewed the Final Report between 1988 and 1991, and PG&E prepared and submitted written responses to NRC questions resulting from that review. In February 1991, PG&E issued the "Addendum to the 1988 Final Report of the Diablo Canyon Long Term Seismic Program." (Reference 20) In June 1991, the NRC issued Supplement 34 to the Diablo Canyon Safety Evaluation Report (SSER) (Reference 21), in which the NRC concluded that PG&E had satisfied License Condition 2.C(7) of DPR-80. In the SSER the NRC requested certain confirmatory analyses from PG&E, and PG&E subsequently submitted the requested analyses. The NRC's final acceptance of the LTSP is documented in a letter to PG&E dated April 17, 1992 (Reference 22). The LTSP contains extensive databases and analyses that update the basic geologic and seismic information in this FSAR Update. However, the LTSP material does not alter the design bases for DCPP. In SSER 34 (Reference 21), the NRC states, "The Staff notes that the seismic qualification basis for Diablo Canyon will continue to be the original design basis plus the Hosgri evaluation basis, along with associated analytical methods, initial conditions, etc."
PG&E committed to the NRC in a letter dated July 16, 1991 (Reference 23), that certain future plant additions and modifications, as identified in that letter, would be checked against insights and knowledge gained from the LTSP to verify that the plant margins remain acceptable.
A completed listing of bibliographic references to the LTSP reports and other documents are provided in References 19, 20, and 21. 3.7.1.1 Design Response Spectra Section 2.5.2 provides a discussion of the earthquakes postulated for the DCPP site and the effects of these earthquakes in terms of maximum free-field ground motion accelerations and corresponding response spectra at the plant site. The maximum DCPP UNITS 1 & 2 FSAR UPDATE 3.7-2 Revision 21 September 2013 vibratory accelerations at the plant site would result from either Earthquake B or Earthquake D-modified, depending on the natural period of the vibrating body. Response acceleration spectra curves for horizontal free-field ground motion at the plant site from Earthquake B, Earthquake D-modified, and HE are presented in Figures 2.5-20, 2.5-21, and 2.5-29 through 32, respectively.
For design purposes, the response spectra for each damping value from Earthquake B and Earthquake D-modified are combined to produce an envelope spectrum. The acceleration value for any period on the envelope spectrum is equal to the larger of the two values from the Earthquake B spectrum and the Earthquake D-modified spectrum. Vertical free field ground accelerations, and the vertical free-field ground motion response spectra are assumed to be two-thirds of the corresponding horizontal spectra.
The DE is the hypothetical earthquake that would produce these horizontal and vertical vibratory accelerations. The DE corresponds to the operating basis earthquake (OBE), as described in Appendix A to 10 CFR 100 (Reference 7).
To ensure adequate reserve energy capacity, Design Class I structures and equipment are reviewed for the DDE. The DDE is the hypothetical earthquake that would produce accelerations twice those of the DE. The DDE corresponds to the SSE, as described in Appendix A to 10 CFR 100 (Reference 7).
PG&E was requested by the NRC to evaluate the plant's capability to withstand a postulated Richter magnitude 7.5 earthquake centered along an offshore zone of geologic faulting, generally referred to as the Hosgri Fault. This evaluation is discussed in the various chapters when it is specifically referred to as the Hosgri evaluation or Hosgri event evaluation. Acceleration response spectra curves for horizontal and vertical free field ground motion at the plant site from the HE are the Newmark and Blume spectra described in Section 2.5. The vertical free field response spectra are two-thirds of the corresponding horizontal spectra. 3.7.1.2 Design Response Spectra Derivation The free-field ground motion acceleration time-histories used in the dynamic analyses of the containment structure, auxiliary building, turbine building, and intake structure are developed by the following procedure: The response spectra for 2 percent damping for Earthquake B and Earthquake D-modified are enveloped to produce a single response spectrum (DE intensity). A time-history is then developed that produces a spectrum with no significant deviation from the smooth DE-envelope spectrum. This procedure eliminates undesirable peaks and valleys that exist in the response spectrum calculated directly from Earthquake B and Earthquake D-modified records.
A similar procedure is used to obtain a free-field ground motion acceleration time-history for the DDE. The free-field ground motion acceleration time-histories for the DE and DCPP UNITS 1 & 2 FSAR UPDATE 3.7-3 Revision 21 September 2013 DDE are shown in Figures 3.7-1 and 3.7-2, respectively. Comparison of the response spectrum computed from the time-history with the smoothed envelope spectrum is shown in Figure 3.7-3 (2 percent damping) and in Figure 3.7-4 (5 percent damping). These spectra are calculated at period intervals of 0.01 seconds, which adequately define the spectra.
For the HE evaluation of containment structure, auxiliary building, turbine building, and intake structure, the horizontal input motions are reduced from free-field motions to account for the presence of the structures that have large foundations. These reduced inputs have been derived by spatial averaging of acceleration across the foundations of each structure by the Tau filtering procedure (Reference 12). The resulting horizontal response spectra for these structures are shown in Figures 3.7-4A through 3.7-4F.
For HE evaluation of outdoor water storage tanks and smaller structures, the horizontal design response spectra are the free-field horizontal response spectra. HE vertical design response spectra are the free-field vertical response spectra. For design purposes, the Newmark spectra are used, or alternately the Blume spectra are used, with adjustment in certain frequency ranges as necessary so that they do not fall below the corresponding Newmark spectra.
Acceleration time-histories used in the analysis of the containment and intake structures, auxiliary building, and turbine building are shown in Figures 3.7-4G through 3.7-4M. Comparison of the response spectrum computed from each time-history with the corresponding design response spectrum for 7 percent damping is shown in Figures 3.7-4N through 3.7-4T.
3.7.1.3 Critical Damping Values The specific percentages of critical damping used for Design Class I SSCs, and the Design Class II turbine building and intake structure are listed in the following table:
Type of Structure % of Critical Damping DE DDE HE Containment structures and all internal concrete structures 2.0 5.0 7.0
Other conventionally reinforced concrete structures above ground, such as shear walls or rigid frames 5.0 5.0 7.0 Welded structural steel assemblies 1.0 1.0 4.0
Bolted or riveted steel assemblies 2.0 2.0 7.0
Mechanical components (PG&E purchased) 2.0 2.0 4.0
Vital piping systems (except reactor coolant loop)(a) 0.5 0.5 3.0(b) DCPP UNITS 1 & 2 FSAR UPDATE 3.7-4 Revision 21 September 2013 Type of Structure % of Critical Damping DE DDE HE Reactor coolant loop(a)(c) 1.0 1.0 4.0 Replacement Steam Generators(f) 2.0 4.0 4.0 Integrated Head Assembly(g) 4.9 6.85 6.85 CRDMs(h) 5.0 5.0 5.0 Foundation rocking (containment structure only)(d) 5.0 5.0 NA(e) (a) ASME Code Case N-411 damping may be used provided it is applied to all earthquake cases and used in response spectrum modal superposition analysis. When used, pipe displacements are checked for adequacy of clearances and pipe mounted equipment accelerations are verified against project qualification criteria. For equipment and components modeled inline, damping should be consistent with RG 1.61; a composite damping value may be used for the analysis of these piping systems. A log of calculations is kept that indicates which calculations have used Code Case N-411 damping. Request for NRC approval for the use of ASME Code Case N-411 was made in letter DCL-86-009, dated January 22, 1986. NRC approval was granted by letter on April 7, 1986 (b) Two percent of critical damping is used for piping less than or equal to 12 inches in diameter. (c) Although a damping value of 1 percent is used for the DE and DDE analyses of the reactor coolant loop (RCL), damping values of greater than 4 percent have been measured experimentally for the RCL in full-size power plants (Reference 8). These testing programs have been reviewed and approved by the NRC. The damping values recommended in RG 1.61 are acceptable for use in analysis of mechanical equipment and systems. (References 24-26) (d) Five percent of critical damping is used for structures founded on rock for the purpose of computing the response in the rocking mode, and 7 percent of critical damping is used for the purpose of computing the response in the translation mode. (e) Analysis utilizes fixed base. (f) These values are valid for replacement steam generator (RSG) internals and shell components up to the RSG nozzle to pipe/tube connections in the RCS, MS, and FW systems and the interface between the RSG shell and upper and lower lateral and lower vertical supports. The restrictions imposed by WCAP 7921-AR (Reference 8) shall be observed when applying these values. (Reference 27) DCPP UNITS 1 & 2 FSAR UPDATE 3.7-5 Revision 21 September 2013 (g) Damping values for the IHA are based on Regulatory Guide 1.61, Revision 1 (Reference 31), Tables 1 and 2, using a weighted average for "Welded Steel or Bolted Steel with Friction Connections" and "Bolted Steel with Bearing Connections". See PG&E Document 6023227-19 (Reference 30) for computation of weighted average value. Computation of weighted average value was approved in Reference 32. (h) Damping values for the CRDMs are based on Regulatory Guide 1.61, Revision 1, (Reference 31) as approved in Reference 33. 3.7.1.4 Bases for Site-Dependent Analysis Site conditions used to develop the shape of site seismic design response spectra are described in Section 2.5.2. 3.7.1.5 Soil-Supported Design Class I Structures All Design Class I plant structures are founded on rock or on concrete fill. 3.7.1.6 Soil-Structure Interaction Soil-structure interaction effects are considered as described in Section 3.7.2.1.7. 3.7.1.7 Hosgri Evaluation The criteria and methods used to review the major structures for response to the postulated 7.5M HE are discussed in this chapter. A comparison of the DE and the DDE criteria with the HE evaluation criteria is given in Table 3.7-1 for the containment and auxiliary building, Tables 3.7-1A for the turbine building, 3.7-1B for the intake structure, and 3.7-1C for the outdoor water storage tanks, respectively. 3.7.2 SEISMIC SYSTEM ANALYSIS In accordance with Revision 1 to RG 1.70, paragraphs under the headings below Seismic Analysis Methods and Description of Seismic Analyses, apply to all seismic analysis performed, i.e., both seismic system analysis and seismic subsystem analysis. Paragraphs under subsequent headings in this section provide discussion of specific topics applicable to seismic system analysis. Discussion of specific topics applicable to seismic subsystem analysis is provided in Section 3.7.3. The seismic analysis of Design Class I SSCs is based on input motions of the DE, DDE, and HE described in Section 3.7.1. 3.7.2.1 Seismic Analysis Methods Four dynamic methods of seismic analysis are used for Design Class I SSCs: time-history modal superposition, response spectrum modal superposition, response spectrum single-degree-of-freedom, and the method for rigid equipment and piping. DCPP UNITS 1 & 2 FSAR UPDATE 3.7-6 Revision 21 September 2013 The concept of modal analysis and each of the four methods of seismic analysis are discussed in subsequent paragraphs. 3.7.2.1.1 Modal Analysis The structure, system, or component is represented as a mathematical model that is in the form of lumped masses interconnected by springs or finite elements. The mathematical model typically has one, two, or three degrees of freedom for each lumped mass or node point, but could have as many as six degrees of freedom for each lumped mass or node point.
Each multiple-degree-of-freedom (multidegree) system has the same number of normal modes as it has degrees of freedom. The characteristics of a normal mode of vibration is that, under certain conditions, the multidegree system could vibrate freely in that mode alone, and during such vibration the ratio of displacements of any two masses is constant with time. These ratios define the characteristic shape of the mode. For any vibration of the multidegree system, the motion in any of the individual normal modes can be treated as an independent single-degree-of-freedom system, and the complete motion of the multidegree system can be obtained by superimposing the independent motions of the individual modes.
The natural frequencies and characteristic shapes are determined by solution of the equations of motions for free vibrations. 3.7.2.1.2 Time-History Modal Superposition The time-history of response in each mode is determined from the acceleration time-history input by integration of the equations of motion. The modal responses are combined by algebraic sum to produce an accurate summation at each step. 3.7.2.1.3 Response Spectrum Modal Superposition The response spectrum is a plot, for all periods of vibration, of the maximum acceleration experienced by a single-degree-of-freedom vibrating body during a particular earthquake. The response spectrum modal superposition method of analysis applies to multidegree systems and is based on the concept of modal analysis. The modal equation of motion for a multidegree system is analogous to the equation of motion for a single degree of freedom. The maximum response in each mode is calculated, and modal responses (displacements, accelerations, shears, moments, etc.) are combined by the square root of the sum of the squares (SRSS) method. 3.7.2.1.4 Response Spectrum, Single-Degree-of-Freedom Many components can be accurately represented by a single-degree-of-freedom mathematical model. The response spectrum method of analysis is applicable and the concept of modal analysis is not required. DCPP UNITS 1 & 2 FSAR UPDATE 3.7-7 Revision 21 September 2013 3.7.2.1.5 Static Equivalent Method When it can be shown that a sub-system is rigid, a static analysis may be performed. The zero period acceleration obtained from the applicable response spectra curve may be used in static calculations. 3.7.2.1.6 Application All Design Class I structures, components, systems, and piping are designed by time-history modal superposition, response spectrum modal superposition, response spectrum single-degree-of-freedom, or the method for rigid equipment and piping, except the following:
(1) Mechanical equipment whose seismic adequacy is verified by testing as described in Section 3.9 (2) Electrical and instrumentation equipment whose seismic adequacy is verified as described in Section 3.10 (3) Certain Design Class I piping less than 2-1/2 inches in diameter that is restrained according to criteria described in Section 3.7.2.1.7.4 (4) Reactor internals, fuel elements, control rod drive assemblies, and control rod drives, as described in Section 3.7.3.15. 3.7.2.1.7 Description of Seismic Analyses 3.7.2.1.7.1 Design Class I Structures Dynamic analyses by the time-history modal superposition method were performed for the containment structure and the auxiliary building. Acceleration time-histories were obtained at specific points in the structures, and response spectra were calculated from these. In order to provide for possible variations in the parameters used in the dynamic analyses, such as mass values, material properties, and material sections, the calculated spectra were modified. For DE and DDE analyses, it is estimated that the calculated period of the structure could vary by approximately 10 percent, and to account for this the peaks of the spectra were correspondingly widened. Similarly, for HE analyses, peaks of the spectra are widened 5 percent on the low period side and 15 percent on the high period side. The modified spectra, known as "smooth spectra,"
are used in the design of Design Class I equipment and piping located in the containment structure and auxiliary building.
A detailed analytical static model of the auxiliary building was used to distribute the seismic inertial forces and moments to various walls, diaphragms, and columns, as described in Section 3.8.2.4.
Allowable stresses for Design Class I structures are presented in Section 3.8. DCPP UNITS 1 & 2 FSAR UPDATE 3.7-8 Revision 21 September 2013 Containment Structure Model (1) DE and DDE events The containment structure calculations relative to responses to DE and DDE events are performed with a computer program for analysis of axisymmetric structures by the finite element method. The foundation rock mass and the containment structure are modeled as one structure system to consider the effect of rock-structure interaction, as shown in Figure 3.7-5. The boundary dimensions of the model are selected such that they do not have a significant effect on the response of the structure. The exterior shell and internal structure are modeled using shell elements with four degrees of freedom at each nodal point. There are a total of 156 nodal points and 140 elements in the model. The weight of mechanical equipment in the structure is included in the calculation of equivalent mass density for the structure elements. Values of elastic constants for the rock mass and their variation with depth are based on field measurements made at the plant site (see Section 2.5). To substantiate that the coupling effect is small at the reactor pressure vessel (RPV) elevation, two floor response spectra were generated for a decoupled interior concrete structure model and a coupled RPV and the interior concrete structure model, respectively. The RPV model is a simplified one-degree-of-freedom system, with its natural frequency matching the fundamental mode of the DCPP vessel. The RPV model is attached to Node 2 of the interior concrete structure model at the vessel support elevation by the spring of the vessel model. Floor response spectra for the decoupled and the coupled models were very similar, indicating that the coupling effect at this low elevation is very small. More importantly, the response spectra magnitude of the decoupled model is consistently higher than the coupled model between 0.05 to 0.40 seconds, and is equal at all other natural periods. This shows that, indeed, the decoupled model is more conservative.
(2) Hosgri event The dynamic analysis for HE is performed for exterior shell, interior concrete structures, and the annulus steel structure. The description of these structural components is given in Section 3.8.1. The elements used in the analysis of exterior shell consist of annular rings of shell elements as shown in Figure 3.7-5A. The model consists of 27 nodal points and 26 elements. A typical shell element has four degrees-of-freedom as shown in Figure 3.7-7. The axisymmetric model is used to compute the translational response of the structure due to the horizontal and vertical ground motion. Since the center of mass and the DCPP UNITS 1 & 2 FSAR UPDATE 3.7-9 Revision 21 September 2013 center of rigidity coincide, the translational analysis does not yield any torsional response. The torsional responses are obtained from separate lumped mass models as shown in Figure 3.7-5B. These lumped mass models account for 5 percent and 7 percent accidental eccentricities. The responses from axisymmetric model and the lumped mass models are combined by absolute sum for 5 percent eccentricity and by SRSS for 7 percent eccentricity. The dynamic analysis of containment internal structure is divided into two parts: concrete interior structure and annulus steel structure. (a) Concrete interior structure mainly comprised of reactor cavity walls and crane wall is represented by an axisymmetric model as shown in Figure 3.7-5A. The model as shown in Figure 3.7-5A contains 22 nodal points and 22 elements. Because the center of mass and the center of rigidity coincide, the analysis does not yield torsional modes. Therefore, a separate lumped mass model, as shown in Figure 3.7-5C, is used to consider torsional response.
Figure 3.7-5D is used to compute vertical responses of the concrete interior structures due to the HE. The lumped mass stick with model points 1, 7, 18, 29, and 40 represent the concrete walls. The annulus steel is modeled by five frames located along the circumference as shown. This model was developed at an early stage of the project to estimate vertical responses of both annulus steel and concrete structures from the HE. However, subsequently detailed models were developed for the annulus steel as described later and the model of Figure 3.7-5D is used for the vertical analysis of the concrete interior structures only. The models of Figures 3.7-5A, 3.7-5C, and 3.7-5D represent concrete interiors up to elevation 140 feet which is the operating floor of the containment. The secondary shield walls housing the steam generators do extend above elevation 140 feet; however, the mass of these walls above elevation 140 feet is small compared to the total concrete mass and, therefore, lumping the mass at elevation 140 feet of the walls that extend above elevation 140 feet has little effect on the dynamic behavior of concrete internals below elevation 140 feet. (b) Several models are developed for the vertical dynamic analysis of annulus steel. Each model represents a steel frame with a column at the outside perimeter, crane wall at the inside perimeter, and the radial beam. Figure 3.7-5E represents a typical model. DCPP UNITS 1 & 2 FSAR UPDATE 3.7-10 Revision 21 September 2013 The horizontal responses of the annulus steel are considered to be the same as the concrete interior structures as computed from model of Figure 3.7-5A. This consideration is supported by: The study results showing that the amplification above 20 Hz for the annulus steel is negligible; and The modal analysis of steel frames shows that the first mode of vibration, which is the predominant mode, is approximately 20 Hz. (3) Input boundary motions In the seismic analysis of the finite element model, for DE and DDE, the motions at the boundary of the rock mass are required as input. These boundary motions are derived using procedures described in the following steps: (a) The finite element model of the rock mass only (without the structure) is subjected to a unit impulse acceleration acting at the rock mass boundaries. As a result, the acceleration time-history (impulse response that reflects the rock mass properties) is obtained at the center nodal point on the surface of the rock mass. (b) The impulse response function, together with the desired free-field ground motion, is used as input to a deconvolution program. The required boundary motion is obtained as the output. This boundary motion, when used as input to the nodes along the horizontal and vertical boundaries of the rock mass model, produces a time-history at the center nodal point on the surface of the model that is equivalent to the free-field motion. To check the accuracy of the derived boundary motion, the rock mass without the structure is analyzed using this motion as input, and the computed free-field ground motion at the center nodal point on the surface of the rock mass is obtained. The computed free-field spectrum is calculated for this surface motion and compared with the DE- or DDE-smoothed spectrum. Due to approximations involved in the analytical methods used to derive the boundary motions, the computer spectra show slight deviations from the desired smoothed spectra. To account for these deviations, the structural response results are then conservatively scaled upward by appropriate correction factors. The boundary motions derived from the procedure described above are used to complete the analysis of the containment structure. DCPP UNITS 1 & 2 FSAR UPDATE 3.7-11 Revision 21 September 2013 For the HE, the analytical models are considered fixed as shown in Figures 3.7-5A, 3.7-5B, 3.7-5C, and 3.7-5D. The analysis is performed using the input motions as specified in Section 3.7.1.2. Containment Polar Crane The polar crane as described in Sections 9.1.4 and 3.8.1 is an overhead gantry crane, supported by the crane wall inside the containment.
A nonlinear time-history analysis is performed for the crane to consider the possibility of wheel uplift and/or slack in the hook cable. The crane structure model is shown in Figure 3.7-7A. Structural members are represented as beam elements; wheel assemblies as nonlinear gap elements with compression stiffness only, and a hook cable is represented as a truss element with no compression capability. A step-by-step integration procedure is employed to determine the response. The time-step for integration is 0.005 sec. Seismic input is provided by simultaneous, independent time-histories in three directions (two horizontal and one vertical). These time-histories are developed at the top of the crane wall from the dynamic analysis described in Section 3.7.2.1.7.1 above. Pipeway Structure To obtain seismic responses in the pipeway structure, a combined model is used consisting of containment exterior shell, pipeway-framing members, and the mainsteam and feedwater piping which are supported by the framing members. The three-dimensional pipeway structure model consists of steel platforms supported on structural steel columns, containment shell and auxiliary and turbine buildings. This structure is represented in the model by beam elements (approximately 900). Oversized holes are provided to support pipeway structure beams on the auxiliary and turbine buildings. Accordingly, the model is decoupled from auxiliary and turbine buildings in the horizontal direction. The horizontal coupling between pipeway framing model and containment model is achieved by rigid links. The main steam and feedwater lines are included in the model since they represent significant masses for the pipeway structure.
The combined containment-pipeway structure model was excited by acceleration time-history at the containment base.
(1) DE and DDE events Equivalent static analyses of the pipeway structure are performed for the DE and DDE events as described in Section 3.8.6. The adequacy of these analyses is confirmed by a time-history dynamic analysis.
DCPP UNITS 1 & 2 FSAR UPDATE 3.7-12 Revision 21 September 2013 (2) Hosgri event The response spectra are generated using the time-history dynamic analysis method. The effect of accidental torsion is included as discussed for the containment structure model in Section 3.7.2.1.7.1. These response spectra are used for qualification of equipment and components. The structural qualification is performed using the response spectrum dynamic modal superposition method for the Unit 1 pipeway structure and using the equivalent static method for the Unit 2 pipeway structure. Auxiliary Building The dynamic time-history analysis of the auxiliary building is performed with a computer program for analysis of a spring and lumped mass model. Two horizontal models and a vertical model, shown in Figure 3.7-13, are used. Each model is fixed at the base (elevation 85 feet). Each horizontal model consists of five lumped masses with two degrees of freedom at each mass point, one translational degree of freedom in the horizontal direction, and one rotational degree of freedom about the vertical axis. The vertical model for HE evaluation consists of five lumped masses with one translational degree of freedom in the vertical direction at each mass point.
The masses are represented as the mass of the slab plus one-half of the walls immediately above and below the slab, with an appropriate live load on each floor to account for the effect of small pieces of equipment, concrete pads for equipment, tanks, pumps, and incidental weight not otherwise considered. Weights of cranes, storage tanks, and other large pieces of equipment are included at the appropriate mass points. Location of the centers of masses and rigidities are calculated to consider torsional modes of vibration. Mass moments of inertia and torsional rigidities are calculated by conventional structural analysis methods.
The soil at elevation 100 feet is represented by soil springs as shown in Figure 3.7-13. The stiffnesses of these foundation springs are derived by considering the case of a rigid plate on a semi-infinite elastic half-space with a horizontal surface (References 2, 3, and 4). The auxiliary building is a broad-based and comparatively low-rise structure, and therefore rocking is insignificant.
For HE evaluation, dynamic time-history analysis of flexible floor slabs is performed using finite element models composed of plate elements. Columns supporting the slabs are represented by springs. In each model, masses of slab, equipment, piping, and other items are concentrated at appropriate nodal points. A typical flexible slab model is shown in Figure 3.7-13A. Input excitation is the vertical acceleration time-history at the slab supports, obtained from the vertical analysis of the auxiliary building model.
Dynamic time-history analysis of the fuel handling area crane support structure is performed using one model to represent six end-bay frames and a second model to represent six middle bay frames. Each model is fixed at its base and uses beam and DCPP UNITS 1 & 2 FSAR UPDATE 3.7-13 Revision 21 September 2013 truss elements to represent all significant structural members. Structure masses are concentrated at appropriate nodal points. The model representing the middle bay frames is shown in Figure 3.7-13B. Input excitations are translational and rotational acceleration time-histories at elevation 140 feet obtained from analysis of the auxiliary building model. Outdoor Water Storage Tanks The axisymmetric and 3-D SAP IV mathematical models used in the HE finite element analysis are shown in Figures 3.7-14, 3.7-15, 3.7-15A, and 3.7-15B. The axisymmetric model using the AXIDYN computer program is used to analyze the effects of gravity loading, hydrostatic pressure, structure inertial forces, and hydrodynamic loads consisting of impulsive and convective pressures caused by the seismic event. The fluid impulsive effects are modeled as effective fluid inertia masses attached to appropriate concrete elements (see Reference 13). The 3-D SAP IV model is used to assess the effects of the nonaxisymmetric vault opening on the stresses in and around the opening area. The loads determined from dynamic analysis using axisymmetric model are input as static loads in the 3-D SAP IV model. All tanks except the firewater and transfer tank are analyzed as fixed base models.
The exterior tank of the firewater and transfer tank is analyzed as a fixed base, whereas the inner steel tank is pinned at the base in the finite-element analyses.
For horizontal direction, a response spectrum, modal superposition analysis is performed with an axisymmetric model to determine the combined dynamic effects of structure inertial forces and impulsive pressures due to the horizontal earthquake. Gravity, hydrostatic pressure, and convective pressure loads are analyzed statically. The tanks analyzed are refueling water storage tank and firewater and transfer tank. No additional analysis is done for condensate tank since it is similar to refueling water storage tank.
For the SAP IV nonaxisymmetric model, an equivalent, static, lateral load analysis based on accelerations computed from the axisymmetric model analysis is performed for the refueling water storage tank to determine the structure response maxima. The results of this analysis are applicable to other outdoor water storage tanks because they have similar vault openings and are of comparable size. The axisymmetric analyses have shown that responses of these tanks are generally similar to refueling tank.
Since the fundamental period is approximately 0.033 sec in the vertical direction, the empty tanks are determined to be rigid in that direction. Considering the possibility that fluid may not act as a rigid mass during vertical motion, effects of the vertical earthquake are obtained by scaling the results of the analysis for gravity loading and hydrostatic pressure by a factor of 1.0 for the HE (2/3 x 0.75 x amplification factor of 2). For the DE and the DDE, HE finite-element analysis results are used as the basis for evaluation. The HE responses are adjusted by the ratio of peak spectral accelerations for the DE, or the DDE, and by appropriate damping ratios. DCPP UNITS 1 & 2 FSAR UPDATE 3.7-14 Revision 21 September 2013 3.7.2.1.7.2 Turbine Building and Intake Structure The turbine building and the intake structure are Design Class II. However, Design Class I equipment is located inside: component cooling water (CCW) heat exchangers, 4160V vital switchgear, emergency diesel generators, and other Class I systems in the turbine building, and auxiliary saltwater (ASW) pumps, piping, and instrumentation in the intake structure. In order to provide assurance that the function of Design Class I equipment will not be adversely affected, these structures are reviewed to ensure that they would not collapse in the unlikely event of an HE. The vulnerability of the main turbine steam valves to seismically induced falling debris is reviewed and is described in Section 3.5.
The structural evaluation of the turbine building and intake structure for the HE earthquake was performed using the response spectrum dynamic modal superposition method. In addition, a time-history dynamic analysis is performed to generate DE, DDE, and HE response spectra. Turbine Building Turbine building horizontal analyses use one model to represent the Unit 1 portion of the building, which extends from column line 1 to 19, and a second model to represent the Unit 2 portion of the building, which extends from column line 19 to 35. The models are fixed at the base and are composed of truss, beam, and plane stress elements. The Unit 1 horizontal model, shown in Figures 3.7-15C and 3.7-15D, has a total of approximately 500 nodal points and 1000 elements. The Unit 2 horizontal model is similar. Four models representing different areas of the building are used to represent the building in the vertical direction. The models are fixed at the base and consist of plate, beam, and truss elements. Three of the models are three-dimensional extending the full building height and width, and together represent the building from column lines 1 to 17 and 19 to 35. The fourth model is two-dimensional extending to elevation 140 feet only and represents the building between column lines 17 and 19. The vertical model used to represent the building between lines 1 and 5 and between lines 31 and 35 is shown in Figures 3-7.15E and 3.7-15F. This model has over 500 nodes and over 1100 elements. Additional models are used to represent bridge crane effects. Analyses consider that both the Unit 1 and the Unit 2 bridge cranes may be located in the Unit 1 or the Unit 2 portion of the building with one of the cranes lifting 135 tons.
Structural evaluation of the turbine pedestal for the HE earthquake is performed using the response spectrum dynamic modal superposition method. The possibility of impingement between the turbine building structure and the turbine pedestal is considered in the response calculations, with the assumption that limited local structural damage, such as concrete chipping or spalling, is permissible provided the overall safety of the structures or the Class I equipment is not impaired. Three-dimensional fixed base models are used to evaluate loading of the pedestals in the horizontal and DCPP UNITS 1 & 2 FSAR UPDATE 3.7-15 Revision 21 September 2013 vertical directions. The model shown in Figure 3.7-15G represents the Unit 1 turbine pedestal. The Unit 2 model is similar. Pedestal members are modeled as beam elements with rigid joints to account for the stiff zones at beam-column intersections. Pedestal and turbine-generator masses are included at appropriate nodal points. The models each include approximately 270 nodes and 210 elements. Intake Structure The seismic analysis of the intake structure was carried out by initially separating the structure into two basic parts: (a) the pump-deck base, consisting of the massive land-side portion of the structure, from elevation -31.5 feet to the -2.1-foot pump-deck level; and (b) the remainder of the structural system. The analysis demonstrated that the massive pump-deck base below the 2.1-foot level would not amplify the ground motion. Hence, the pump-deck base need not be considered in the analysis of the remainder of the structure.
The three-dimensional mathematical model is used for the north-south and east-west/vertical analysis. Figures 3.7-15H and 3.7-15I show a typical finite element model. The model is fixed at the base and uses typical finite-element methods of discretization suitable for the structural system. Floor slabs and walls are modeled as flat-plate elements primarily to capture in-plane behavior. The slabs are shown to be rigid in the vertical direction by a separate simplified analysis. Some thick shear walls near the symmetry plane of the structure in the east-west direction are modeled as three-dimensional solid elements. There are six degrees of freedom for each node - three translational and three rotational degrees of freedom. For the north-south analysis, the effect of the virtual mass of contained water has been considered by including the total mass of water tributary to the transverse flow straighteners (or piers). This method is considered reasonable because the relatively short distance between piers inhibits the tendency of the water to slosh and thereby reduce its virtual mass. A high-tide condition, with sea level at elevation +3.4 feet (MSL), is assumed for the analysis.
For the east-west/vertical analysis, the effect of water due to an earthquake is considered negligible because it is assumed that the water can flow in and out of the structure and will exert relatively little force on the structure.
Static and dynamic lateral earth pressures on the east wall of the intake structure are considered in the calculation of the in-place shear stress for the east-west walls and roof slabs. The earth pressure influence is combined by SRSS method with the seismic forces.
DCPP UNITS 1 & 2 FSAR UPDATE 3.7-16 Revision 21 September 2013 3.7.2.1.7.3 Design Class I Mechanical Equipment Reactor Coolant Loop The RCLs and their support systems are analyzed for seismic loads based on a three-dimensional, multi-mass elastic dynamic model, as discussed in Section 5.2. Table 3.7-24 shows the fundamental mode frequency ranges for RCL primary equipment (steam generator, reactor coolant pump, and reactor pressure vessel). The stress analyses for faulted condition loadings of these components from a Hosgri earthquake are provided in Section 5.2.1.15. The analyses of the reactor internals, fuel elements, control rod drive assemblies, and control rod drives are described in Section 3.7.3.15. Other Design Class I Mechanical Equipment Design Class I mechanical equipment is grouped into: (a) equipment purchased directly by PG&E, and (b) equipment supplied by Westinghouse.
(1) Equipment purchased directly by PG&E Equipment is considered rigid if all natural periods are equal to or less than 0.05 seconds for the DE and the DDE, and 0.03 seconds for the HE.
Rigid equipment is designed for the maximum acceleration of the supporting structure at the equipment location. Flexible equipment is analyzed by response spectrum methods. Hydrodynamic analysis of rigid tanks is performed using the methods described in Reference 6. Flexible tanks were analyzed by the methods described in Reference 13. Load combinations and allowable stresses for Design Class I equipment are given in Section 3.9. (2) Equipment supplied by Westinghouse Electric Corporation The seismic response of Design Class I piping and components is determined by response spectrum methods. The system is evaluated for the simultaneous occurrence of one horizontal and the vertical seismic input motions. For each mode, the results for the vertical excitation are added absolutely to the separate results for the north-south or east-west directions. The larger of the two values so determined at each point in the model is considered as the earthquake response. Details of the response spectrum analyses are as follows: (a) If a component falls within one of the many categories that has been previously analyzed using a multi-degree-of-freedom model and shown to be relatively rigid, the equipment specification for the component is checked to ensure that the equivalent static g-values specified are larger than the building floor response spectrum DCPP UNITS 1 & 2 FSAR UPDATE 3.7-17 Revision 21 September 2013 values and therefore are conservative. Equipment is considered to be rigid relative to the building if its natural frequencies are all greater than 20 cycles per second for the DE and DDE, and 33 cycles per second for HE. (b) If the component cannot be categorized as similar to a previously analyzed component that has been shown to be relatively rigid, an analysis is performed as described below. Design Class I mechanical equipment, including heat exchangers, pumps, tanks, and valves, are analyzed using a multi-degree-of-freedom modal analysis. Appendages, such as motors attached to motor-operated valves, are included in the models. The natural frequencies and normal modes are obtained using analytical techniques developed to solve eigenvalue-eigenvector problems. A response spectrum analysis is then performed using horizontal and vertical umbrella spectra that encompass the appropriate floor response spectra developed from the building time-history analyses. The simultaneous occurrence of horizontal and vertical motions are included in the analyses. These response spectra are combined with the modal participation factors and the mode shapes to give the structural response for each mode from which the modal stresses are determined. The combined total seismic response is obtained by adding the individual modal responses utilizing the SRSS method. Under certain conditions, the natural frequency of the equipment is not calculated. Under those conditions, using the appropriate damping value, the peak value of acceleration response curve is used to calculate the inertia forces. This method of calculation is termed the pseudo-dynamic method. Components and supports of the RCS are designed for the loading combinations given in Section 5.2. Components are designed in complete accordance with the ASME Boiler and Pressure Vessel Code, Section III, Nuclear Vessels, and the USAS Code for Pressure Piping. The allowable stress limits for these components and supports are also given in Section 5.2. The loading combinations and stress limits for other components and supports are given in Section 3.9. The Hosgri evaluation of the RCS is discussed in Section 5.2. All components and supports of the RCS satisfy criteria demonstrating qualification for the HE. DCPP UNITS 1 & 2 FSAR UPDATE 3.7-18 Revision 21 September 2013 3.7.2.1.7.4 Design Class I Piping Criteria The following criteria determine the type of seismic analysis performed for Design Class I piping:
(1) 2-1/2 inches in diameter and larger Seismic analysis is performed by the response spectrum, modal superposition method. (2) Less than 2-1/2 inches in diameter Seismic analysis is performed by the response spectrum modal superposition method for all Unit 2 piping. In Unit 1, piping less than 2-1/2 inches in diameter was analyzed by sampling criteria in which systems representing the worst case configurations or reflecting generic concerns were selected for analysis by the response spectrum modal superposition method. The remainder was qualified by criteria that limit the periods of free vibration to valves that assure only moderate amplification of piping responses. Model Three dimensional mathematical models are used in the response spectrum modal superposition analyses. A typical mathematical model is shown in Figure 3.7-26. Valves and valve operators are included where appropriate in the piping models as eccentric masses. Pipe supports, restraints and equipment having a natural frequency of 20 Hz or greater are modeled as being rigid restraints. Where Design Class II piping connects to Design Class I piping, sufficient Design Class II piping is included in the model to assure qualification of the Design Class I piping and code boundary. Allowable Stresses Load combinations and allowable stresses for Design Class I piping are given in Section 3.9.
3.7.2.2 Natural Frequencies and Response Loads The natural frequencies and seismic response results summarized in the following sections for the major plant structures are representative of the seismic analyses performed for the operating license review (Reference 18), but may not reflect minor changes associated with subsequent plant modifications.
DCPP UNITS 1 & 2 FSAR UPDATE 3.7-19 Revision 21 September 2013 Containment Structure (1) DE and DDE The natural periods for all significant modes of the containment structure are listed in Table 3.7-2. The corresponding mode shapes are shown in Figure 3.7-6. The shell forces and moments in a typical element of the model are defined in Figure 3.7-7.
The containment structure seismic analysis provides acceleration time-histories, maximum absolute accelerations, displacements, shell forces and moments, total shears, and total overturning moments. These maximum response values are listed in Tables 3.7-3 through 3.7-8 for the nodal points indicated in Figure 3.7-5. Acceleration response spectra for the containment are calculated from the acceleration time-histories, and corresponding smooth spectra are prepared. Typical smooth spectra are shown in Figures 3.7-8 through 3.7-12. (2) HE The natural periods and significant modes of vibration are listed in Table 3.7-8A. Modes having a period of vibration less than 0.03 sec (frequency greater than 33 Hz) are considered to be insignificant. As shown in Table 3.7-8A three sets of periods are given for the exterior shell: (a) Translational mode determined from model of Figure 3.7-5A (b) Torsional and translational mode determined from Figure 3.7-5B (c) Vertical modes determined from Figure 3.7-5D Table 3.7-8B gives the horizontal and vertical maximum absolute accelerations and Table 3.7-8C gives the maximum relative horizontal and vertical displacement. Table 3.7-8D gives the maximum shell forces and moments. Tables 3.7-8E and 3.7-8F give the maximum total shear forces, overturning moments, torsional moments, and axial forces for the containment shell. The horizontal floor response spectra, including the effects of accidental torsion of the structure, at the inside face of the exterior shell are shown in Figures 3.7-12A and 3.7-12B. To develop these spectra, the translational spectra are combined with the torsional spectra from the 5 percent and 7 percent accidental eccentricities. DCPP UNITS 1 & 2 FSAR UPDATE 3.7-20 Revision 21 September 2013 The combined translational and torsional spectra are then combined on an SRSS basis with the horizontal component due to the vertical input to yield the spectra shown in Figures 3.7-12A and 3.7-12B. The vertical floor spectra are shown in Figures 3.7-12C and 3.7-12D. Tables 3.7-8G and 3.7-8H show the accelerations, displacements, stress, and moments for the containment interior structures as a result of the horizontal dynamic analysis. For the interior structure, the Newmark input generally produces a higher structure response than does the Blume input. Figures 3.7-12E through 3.7-12G show the response spectra for the interior structure at elevation 140 feet, which is the operating floor for the containment. The spectra are for the horizontal, torsional, and vertical response. For the annulus structural steel frames, a separate vertical dynamic analysis is carried out for each frame as shown in Figures 3.7-12H and 3.7-12I for Units 1 and 2, respectively. Tables 3.7-8I and 3.7-8J list the frequencies and participation factors for frame number 6 which is a typical annulus steel radial frame. After the response spectra are generated in the vertical direction for each radial frame, they are enveloped according to their locations. As shown in Figures 3.7-12H and 3.7-12I, the annulus is divided into the five major sectors (called sector frames) and the response spectra for any sector frame at given elevation are derived from enveloping the response spectra of radial frames located in that sector. Typical enveloped response spectra are shown in Figures 3.7-12J and 3.7-12K. As discussed earlier, the annulus structure does not amplify the horizontal motion of the interior concrete. Therefore, the horizontal spectra for the concrete interior structures are used for the annulus steel. Table 3.7-8K lists the natural frequencies for horizontal seismic motion. As mentioned in Section 3.7.2.1.7, the first mode frequencies are approximately 20 Hz or higher and, therefore, for the rationale given earlier, the annulus is considered rigid in the horizontal direction. Containment Polar Crane Maximum displacements for various nodes for the polar crane are given in Table 3.7-8L. The member forces and bending moments are shown in Tables 3.7-8M and Table 3.7-8N. The typical response spectra are shown in Figures 3.7-12L and 3.7-12M. DCPP UNITS 1 & 2 FSAR UPDATE 3.7-21 Revision 21 September 2013 Pipeway Structure The modal analysis indicates that the minimum frequency of the model is 1.6 Hz and there are 100 modes below 33 cps indicating many closely spaced modes. The containment structure and the piping modes are included in the results since a composite model is analyzed as discussed in Section 3.7.2.1.7.1. The mode shapes indicate there are no global structural modes of the pipeway structure itself; instead, there are many local modes. The input horizontal acceleration time-histories are scaled up by a factor of 1.06 to approximate the accidental eccentricity of masses. Five input cases are considered for the seismic analysis: The Blume horizontal time-history in E-W and N-S direction, the Newmark horizontal time-history in E-W and N-S direction, and the Newmark time-history in the vertical direction. Typical response spectra for pipeway structure are shown in Figures 3.7-12N through 3.7-12S. Auxiliary Building The natural periods for all significant modes of the auxiliary building are listed in Tables 3.7-9 through 3.7-11. Frequencies for significant modes of the fuel handling crane support structure are listed in Tables 3.7-11A and 3.7-11B. Acceleration response spectra for the auxiliary building are calculated from the acceleration time-histories at the mass points and corresponding smooth spectra are developed. Typical spectra are shown in Figures 3.7-16 through 3.7-25 and 3.7-21A through 3.7-21I. Maximum absolute accelerations, relative displacements, story shears, overturning moments, and torsional moments in the auxiliary building are listed in Tables 3.7-12 through 3.7-23. Maximum absolute accelerations and relative displacements in the fuel handling crane support structure are listed in Tables 3.7-8O and 3.7-8P; the displacements are obtained from static analysis of the detailed model described in Section 3.8.2.4. Turbine Building Natural frequencies of vibration in the horizontal direction in all significant modes of the Unit 1 portion of the building, for the condition where two bridge cranes are centered near column line 10.6, are listed on Table 3.7-23A. Corresponding horizontal frequencies for the Unit 2 portion of the building are similar. Natural frequencies of vibration in the vertical direction for all significant modes of the building between column lines 1 and 5 are listed on Table 3.7-23B. Corresponding vertical frequencies for the Unit 2 portion of the building are similar. DCPP UNITS 1 & 2 FSAR UPDATE 3.7-22 Revision 21 September 2013 Acceleration response spectra for the turbine building are calculated from acceleration time-histories at the mass points and corresponding smooth spectra are developed. Typical spectra are shown in Figures 3.7-25A through 3.7-25M. Maximum absolute accelerations and relative displacements in the Unit 1 portion of the building are listed in Tables 3.7-23C and 3.7-23D. Corresponding accelerations and displacements in the Unit 2 end of the building are similar.
Natural periods for all significant modes of the turbine pedestal model are listed in Table 3.7-23E. Maximum relative displacements of the pedestal model are listed in Table 3.7-23F. Intake Structure The natural periods and participation factors for all significant modes of the intake structure are listed in Tables 3.7-23G. Acceleration response spectra for the intake structure are calculated from the acceleration time-histories at the selected mass points, and corresponding smooth spectra are developed as specified in Figure 3.7-4A. Typical spectra are shown in Figures 3.7-25N through 3.7-25T. Maximum absolute acceleration, relative maximum displacements are listed in Table 3.7-23H. Outdoor Water Storage Tanks The natural periods for significant modes of the refueling water storage tanks and fire water and transfer tank are listed in Tables 3.7-23I and 3.7-23J. 3.7.2.3 Procedures Used to Lump Masses 3.7.2.3.1 Structures The mass of the structure is assumed to be concentrated at particular locations on the model. These locations coincide with either floor levels, significant points where dynamic response is required as input for piping and equipment, nodal points in the finite element model, or any other points required to accurately define the natural frequencies and mode shapes for the significant modes. The torsional effect for containment, auxiliary building, turbine building, and intake structure is considered as discussed in Section 3.7.2.10. 3.7.2.3.2 Equipment and Piping The mass of the equipment and piping systems is assumed to be concentrated at particular locations on the model. These locations coincide with either actual masses such as pumps, motors, valve restraints and anchors, or any other points required to accurately define the natural frequencies and mode shapes of the significant modes.
DCPP UNITS 1 & 2 FSAR UPDATE 3.7-23 Revision 21 September 2013 3.7.2.4 Rocking and Translational Response Summary Methods used to consider soil-structure interaction for Design Class I structures are described in Section 3.7.2.1.7.1. 3.7.2.5 Methods Used to Couple Soil with Seismic-System Structures The procedures used to represent the containment structure and surrounding rock mass as a finite element model, and the procedures used to derive the stiffnesses of foundation springs for the auxiliary building are described in Section 3.7.2.1.7.1. 3.7.2.6 Development of Floor Response Spectra Floor response spectra are developed using time-history modal superposition analyses as described in Section 3.7.2.1.7.1. 3.7.2.7 Differential Seismic Movement of Interconnected Components Components and supports of the RCS are designed for the loading combinations and stress limits given in Section 5.2. The loading combinations and stress limits for other components and supports are given in Section 3.9. 3.7.2.8 Effects of Variations on Floor Response Spectra Consideration of the effects on floor response spectra of possible variations in the parameters used for the structural analysis is discussed in connection with the development of smooth spectra in Section 3.7.2.1.7.1. 3.7.2.9 Use of Constant Vertical Load Factors The Design Class I structures are heavy, massive, reinforced concrete, rigid-type structures and are founded on competent hard rock. For such structures, insignificant amplification of vertical motions can be expected, the critical factor in design being the response of the structures to horizontal earthquake motions. The containment structure and auxiliary building including Class I systems and components are designed for DE and DDE, using a vertical static coefficient equal to two-thirds of the peak horizontal ground motion, unless otherwise noted. For the HE, a dynamic analysis in the vertical direction is carried out as discussed in Section 3.7.2.1.7.1. 3.7.2.10 Method Used to Account for Torsional Effects The containment structure is essentially axisymmetric and therefore has insignificant torsional response. The torsional response of the auxiliary building is calculated by use of a combined translational and torsional mathematical model in the seismic system time-history modal superposition analysis, as described in Section 3.7.2.1.7.1.
DCPP UNITS 1 & 2 FSAR UPDATE 3.7-24 Revision 21 September 2013 For the Hosgri evaluation of Design Class I structures, the effect of accidental torsion is included as an additional eccentricity in the mathematical models. The additional eccentricity is the greater of 5 percent of the building dimension in the direction perpendicular to the applied loads, when torsional and translational effects are
combined together, and the 7 percent of the building dimension in the direction perpendicular to the applied loads, when torsional and translational effects are computed independently and combined by the SRSS method.
For Hosgri evaluation of the Design Class II turbine building, including the turbine pedestal and the intake structure, a torsional response is calculated by the use of finite element models which include both translation and torsion. In addition, the effect of accidental eccentricity is accounted for by a 10 percent increase in the structural responses for the turbine building and intake structure. For the turbine pedestal, a static torsional moment corresponding to a 5 percent eccentricity is added to the dynamic analysis in each horizontal direction. 3.7.2.11 Comparison of Responses Time-history analyses only are performed for Design Class I structures. Response spectrum analyses are not performed because the time-history produces spectra that represent reasonably the criteria response spectra. 3.7.2.12 Methods for Seismic Analysis of Dams There are no dams associated with the DCPP. 3.7.2.13 Methods to Determine Design Class I Structure Overturning Moments The maximum overturning moments for Design Class I structures are determined as part of the time-history modal superposition analyses. Vertical earthquake is considered to act concurrently with the maximum horizontal overturning moments. 3.7.2.14 Analysis Procedure for Damping Structures are analyzed using modal superposition techniques, and element or material-associated damping ratios are given in Section 3.7.1.3. "Composite" or modal damping ratios in structural systems comprised of different element material types are selected based on an inspection of the significant mode shapes, and on the assumption that the contribution of each material to the composite effective modal damping is proportional to the elastic energy induced in each material. The following criteria and procedures are applied on a-mode-by mode basis to evaluate and conservatively determine composite damping values:
(1) Where a particular mode primarily indicates response of a single element type, the damping ratio corresponding to that element type is assigned to DCPP UNITS 1 & 2 FSAR UPDATE 3.7-25 Revision 21 September 2013 that mode. Where all but a negligible amount of the elastic energy is induced in, for example, concrete or rock, the damping ratio appropriate to these materials is applied. Similarly, where a lightly damped material exhibits a major portion of the elastic energy of the mode, a conservative choice is made to use the damping ratio of that material for that mode. In most cases for this plant, the modes are well defined according to material types; composite damping values can be selected on the basis of a visual inspection of mode shapes and no additional numerical computations are required. (2) In a few instances, the above criteria cannot be applied because a particular mode indicates response of several element types. The damping ratio for that mode is conservatively estimated based on the degree of participation of the different elements. Table 3.7-10 lists the participation factors for the auxiliary building. The elastic energy induced in the different elements is estimated and the composite damping values assigned in proportion to the elastic energy. (3) Mass-weighted composite modal-damping is used for the DE and DDE analysis of the turbine building. The approach described above is consistent with currently accepted techniques, and in all cases the damping values are selected conservatively. The use of this approach results in design that can conservatively resist the seismic motions postulated for the DCPP.
3.7.2.15 Combination of Components of Earthquake Motion For Structures For DE and DDE analysis maximum structural response due to one horizontal and the vertical component of earthquake motion are combined by the absolute sum method. For HE analysis the maximum structural responses due to each of the three components of earthquake motion are combined by the SRSS method. 3.7.3 SEISMIC SUBSYSTEM ANALYSIS 3.7.3.1 Determination of Number of Earthquake Cycles Where fatigue is a criterion, it is assumed that there are 20 occurrences of the DE, each producing 20 cycles of maximum response. 3.7.3.2 Basis for Selection of Forcing Frequencies Design Class I equipment and piping is analyzed by the response spectrum method or the pseudo-dynamic method, using floor response spectra, unless it can be shown to be rigid, as discussed in Section 3.7.2.1. Accordingly, a special procedure to avoid certain frequencies is not needed. DCPP UNITS 1 & 2 FSAR UPDATE 3.7-26 Revision 21 September 2013 3.7.3.3 Procedure for Combining Modal Responses The method and procedure for combining modal responses are described in Sections 3.7.2.1 and 3.7.3.4. 3.7.3.4 Root Mean Square Basis Closely spaced modes in Design Class I piping are analyzed by the response spectrum modal superposition method where all modal responses are combined by the SRSS method to obtain total response.
A study was conducted to evaluate the effects of combining modes with closely spaced modal frequencies by the absolute sum method. For closely spaced modes, the combined total response was obtained by taking the absolute sum of the closely spaced modes and then taking the SRSS with all other modes. Twenty-nine piping systems were studied, representing approximately 10 percent of the total number of piping systems analyzed. Of these 29 piping systems, 8 systems had no closely spaced frequencies and 8 systems had closely spaced frequencies which were in the rigid period range and therefore required no further study.
The remaining 13 systems had some modal frequencies in the flexible range that could be termed closely spaced. Of these, 5 systems had low seismic stresses with an adequate margin of safety, so that any possible increase in seismic stresses due to a combination of closely spaced frequencies by the absolute sum method would not affect the safety of the piping systems. In addition, 6 systems had closely spaced frequencies, but study of the mode shapes revealed that the seismic stresses would not be significantly affected by the absolute sum of these modal responses. For the 2 remaining systems, it was not possible to positively conclude that the effects of combining the modes with closely spaced frequencies by absolute sum would be minimal by inspecting the stresses or mode shapes. Therefore, these 2 systems were reanalyzed by computer, and it was found that if the seismic responses of the modes with closely spaced frequencies were combined by the absolute sum method, the increase in stress would be less than 1 percent.
It was therefore concluded that the combination of modal responses of piping systems by the SRSS method is adequate and conservative. 3.7.3.5 Design Criteria and Analytical Procedures for Piping Stresses induced in Design Class I piping from relative movement of anchor points (points where all degrees of freedom are fixed), whether due to building or equipment movement, are considered with stresses calculated in the piping response spectrum modal superposition analyses.
DCPP UNITS 1 & 2 FSAR UPDATE 3.7-27 Revision 21 September 2013 PG&E has developed specific guidelines for the design of Class I pipe supports that account for such items as allowable deflections, forces, gaps, and moments imposed on the supports. Allowable stresses and loads are described in more detail in Section 3.9.
A study (Reference 9) has also been performed to evaluate the stresses in piping systems, assuming failure of a single hydraulic or mechanical pipe snubber during a seismic event. Results of the study indicate that the probability of a snubber failing to snub and causing a pipe failure was sufficiently low that no additional design restraints had to be imposed.
As an additional control, hydraulic snubbers are visually inspected and functionally tested. These surveillance requirements are detailed in the DCPP Equipment Control Guidelines (see Chapter 16).
At the request of the NRC in April 18, 1984, in its order to modify Facility Operating License No. DPR-76, PG&E developed a program to review the small and large bore pipe supports for the specific concerns raised by that order.
The specific items requested by the NRC were as follows:
(1) PG&E shall complete the review of all small-bore piping supports which were reanalyzed and requalified by computer analysis. The review shall include consideration of the additional technical topics, as appropriate, contained in License Condition No. 7 below. (2) PG&E shall identify all cases in which rigid supports are placed in close proximity to other rigid supports or anchors. For these cases PG&E shall conduct a program that assures loads shared between these adjacent supports and anchors result in acceptable piping and support stresses.
Upon completion of this effort, PG&E shall submit a report to the NRC Staff documenting the results of the program. Design procedures were revised to address this issue. (3) PG&E shall identify all cases in which snubbers are placed in close proximity to rigid supports and anchors. For these cases, utilizing snubber lock-up motion criteria acceptable to the staff, PG&E shall demonstrate that acceptable piping and piping support stresses are met. Upon completion of this effort, PG&E shall submit a report to the NRC Staff documenting the results. Design procedures were revised to address this issue. (4) PG&E shall identify all pipe supports for which thermal gaps have been specifically included in the piping thermal analyses. For these cases the licensee shall develop a program for periodic inservice inspection to DCPP UNITS 1 & 2 FSAR UPDATE 3.7-28 Revision 21 September 2013 assure that these thermal gaps are maintained throughout the operating life of the plant. PG&E shall submit to the NRC Staff a report containing the gap-monitoring program. Rather than establishing a gap-monitoring program, the piping analysis and procedures were modified to eliminate the thermal gaps in the analyses.
(5) PG&E shall provide to the NRC the procedures and schedules for the hot walkdown of the main steam system piping. PG&E shall document the main steam hot walkdown results in a report to the NRC Staff. (6) PG&E shall conduct a review of the "Pipe Support Design Tolerance Clarification" program (PSDTC) and "Diablo Problem" system (DP) activities. The review shall include specific identification of the following: (a) Support changes, which deviated from the defined PSDTC program scope; (b) Any significant deviations between as-built and design configurations stemming from the PSDTC or DP activities; and (c) Any unresolved matters identified by the DP system. The purpose of this review is to ensure that all design changes and modifications have been resolved and documented in an appropriate manner. Upon completion PG&E shall submit a report to the NRC Staff documenting the results of this review. (7) PG&E shall conduct a program to demonstrate that the following technical topics have been adequately addressed in the design of small and large-bore piping supports: (a) Inclusion of warping normal and shear stresses due to torsion in those open sections where warping effects are significant. (b) Resolution of differences between the AISC Code and Bechtel criteria with regard to allowable lengths of unbraced angle sections in bending. (c) Consideration of lateral/torsional buckling under axial loading of angle members. (d) Inclusion of axial and torsional loads due to load eccentricity where appropriate.
DCPP UNITS 1 & 2 FSAR UPDATE 3.7-29 Revision 21 September 2013 (e) Correct calculation of pipe support fundamental frequency by Rayleigh's method. (f) Consideration of flare bevel weld effective throat thickness as used on structural steel tubing with an outside radius of less than 2T. The above considerations were incorporated in the applicable design procedures. All of the above specific concerns were addressed and resolved to the satisfaction of the NRC. 3.7.3.6 Basis for Computing Combined Response As a minimum, mechanical equipment is designed for a vertical static coefficient equal to 2/3 of the peak horizontal ground motion for DE and DDE analysis. For HE analysis, specific vertical floor response spectra are used. Horizontal and vertical responses are combined by absolute sum.
Equipment is reviewed for a vertical force determined from a response spectrum, as described in Section 3.7.2.1.7.3, 3.7.3.15, and 5.2.
The horizontal and vertical responses of Design Class I piping are determined from the two-dimensional response spectrum modal superposition analyses described in Section 3.7.2.1.7.4. Response spectra at the applicable piping support attachment elevations are enveloped to obtain the final design response spectra. The vertical and one horizontal response are combined by absolute sum on the modal level. Modal responses are combined by the SSRS method. The two two-dimensional results are then enveloped to obtain the total response. Figure 3.7-26 shows a typical piping mathematical model. Figure 3.7-29 illustrates the derivation of the design response spectra for a typical piping system.
In many cases, earthquake piping stresses due to DDE are not directly calculated. Instead, the results from the DE piping analysis are doubled to represent the DDE. This approach was chosen because review of the design spectra showed that the DDE accelerations did not exceed twice the DE accelerations. Since pipe stress is linear with accelerations, this approach is conservative. 3.7.3.7 Amplified Seismic Responses Components that can be adequately characterized as a single-degree-of-freedom system are considered to have a modal participation of one.
DCPP UNITS 1 & 2 FSAR UPDATE 3.7-30 Revision 21 September 2013 3.7.3.8 Use of Simplified Dynamic Analysis All methods of seismic analysis used for Design Class I structures, components, systems, and piping are described in Section 3.7.2.
Two methods of dynamic seismic analysis are used for Design Class I components and piping that are different than multiple-degree-of-freedom, modal analysis methods. The first of these is the response spectrum, single-degree-of-freedom method used for components whose dynamic behavior can be accurately represented by a single-degree-of-freedom mathematical model. The second of these is the method for rigid components where the component is designed for the maximum acceleration experienced by the supporting structure at the location of support, if all natural periods of the component are less than, or equal to, 0.05 seconds (33 Hz for HE in piping analysis).
The pseudo-dynamic method of analysis is used for certain items of mechanical equipment as described in Section 3.7.2. The basis for this method is described in Section 3.7.2.1.7.3.
Certain Unit 1 Design Class I piping less than 2-1/2 inches in diameter is restrained according to criteria described in Section 3.7.2.1.7.4. 3.7.3.9 Modal Period Variation Consideration of the effects on floor response spectra of possible variations in the parameters used for structural analysis is discussed in connection with the development of smooth spectra in Section 3.7.2.1.7.1. 3.7.3.10 Torsional Effects of Eccentric Masses Where appropriate, valves and valve operators are included as eccentric masses in the mathematical models for piping seismic analysis, as described in Section 3.7.2.1.7.4. 3.7.3.11 Piping Outside Containment Structure The procedures used to determine piping stresses resulting from relative movement between anchor points (points where all degrees-of-freedom are fixed) are discussed in Section 3.7.3.5. The forces exerted by piping on anchor points, including the containment structure penetrations, are included in the evaluation of stresses for Design Class I structures.
Buried Design Class I piping is confined by sand backfill in rock trenches. The piping material is ASTM A-53 or A-106 carbon steel.
DCPP UNITS 1 & 2 FSAR UPDATE 3.7-31 Revision 21 September 2013 3.7.3.12 Interaction of Other Piping With Design Class I Piping Mathematical models for Design Class I piping seismic analyses normally originate and terminate at anchor points. Where Design Class II piping connects to Design Class I piping sufficient Design Class II piping is included in the mathematical model to assure qualification of the Design Class I piping and code boundary. 3.7.3.13 System Interaction Program PG&E developed a program to consider seismically-induced physical interactions between nonsafety-related SSCs and Design Class I SSCs. The methodology and results of this interaction study are presented in Reference 10 and are summarized as follows. The objective of the program was to establish confidence that when subjected to seismic events of severity up to and including the HE, SSCs important to safety shall not be prevented from performing their intended safety functions as a result of physical interactions caused by seismically induced failures of nonsafety-related SSCs. In addition, safety-related SSCs shall not lose the redundancy required to compensate for single failures as a result of such interactions.
To accomplish the program, PG&E defined as targets all SSCs required to safely shut down the plant and maintain it in a safe shutdown condition, and certain accident-mitigating systems. Initial plant operating modes of normal operation, shutdown, and refueling were considered in the selection of the target equipment. All nonsafety-related SSCs were defined as sources.
Interactions between source and target equipment were postulated by an interdisciplinary Interaction Team. The Interaction Team postulated interactions during walkdowns of the target equipment, using previously established guidelines and criteria. The Interaction Team also recommended resolutions to the postulated interactions. The findings of the Interaction Team were evaluated during a subsequent office-based technical evaluation. Any modifications deemed necessary were reviewed after completion by the Interaction Team to ensure that no new interactions were created by the modifications themselves.
The program was subjected to an independent audit by PG&E's Quality Assurance Department and a review by an Independent Review Board which reported its findings to a managing consultant who, in turn, reported his findings to PG&E management. 3.7.3.14 Field Location of Supports and Restraints Seismic supports and restraining devices for Design Class I piping are located as follows:
DCPP UNITS 1 & 2 FSAR UPDATE 3.7-32 Revision 21 September 2013 3.7.3.14.1 Two Inches in Diameter and Less Field-routed and vendor-furnished piping 2 inches and less in diameter is supported by the piping installation contractor's field personnel in accordance with criteria supplied by PG&E's engineering staff on Approved for Construction drawings. These criteria specify size, type, spacing, and permissible locations for seismic supports and restraining devices. Prior to initial fuel loading, the completed installation of this piping was reviewed by an experienced piping engineer from PG&E's engineering staff to ensure compliance with the criteria and the observance of good design practice. 3.7.3.14.2 Larger Than 2 Inches in Diameter The size, type, and location of each support or restraining device on each line is shown on Approved for Construction drawings.
The procedures followed during development of the Approved for Construction drawings provide assurance that the field location and the seismic design of supports and restraining devices are consistent with the assumptions made in the seismic analysis. These procedures are:
(1) The locations of supports and restraining devices are established on preliminary drawings. (2) The locations shown on the preliminary drawings are used to develop the mathematical model for the seismic analysis, and the seismic analysis is performed. If the results show piping stresses higher than allowable, adjustments are made in the location, and/or the type of support or restraining device, and the seismic analysis is repeated.
(3) The reactions calculated as part of the seismic analysis, combined with other loads, are used for final design of piping supports and restraining devices. (4) When the design is complete, drawings are issued as Approved for Construction to the piping installation contractor. Installation of supports and restraining devices is in accordance with Approved for Construction drawings. 3.7.3.15 Seismic Analyses for Fuel Elements, Control Rod Assemblies, and Control Rod Drives 3.7.3.15.1 Reactor Vessel Internals Evaluation - DE, DDE, and HE Nonlinear dynamic seismic analysis of the reactor pressure vessel (RPV) system includes the development of the system finite element model and the synthesized time DCPP UNITS 1 & 2 FSAR UPDATE 3.7-33 Revision 21 September 2013 history accelerations. Both of these developments for the seismic time history analysis are discussed below.
The basic mathematical model for seismic analysis is essentially similar to a LOCA model in that the seismic model includes the hydrodynamic mass matrices in the vessel/barrel downcomer annulus to account for the fluid-solid interactions. On the other hand, the fluid-solid interactions in the LOCA analysis are accounted through the hydraulic forcing functions generated by Multiflex Code (Reference 3). Another difference between the LOCA and seismic models is the difference in loop stiffness matrices. The seismic model uses the unbroken loop stiffness matrix, whereas the LOCA model uses the broken loop stiffness matrix. Except for these two differences, the RPV system seismic model is identical to that of LOCA model.
The RPV system finite element model for the nonlinear time history dynamic analysis consists of three concentric structural sub-models connected by nonlinear impact elements and linear stiffness matrices. The first sub-model, shown in Figure 3.7-27A, represents the reactor vessel shell and its associated components. The reactor vessel is restrained by four reactor vessel supports (situated beneath alternate nozzles) and by the attached primary coolant piping. Also shown in Figure 3.7-27A is a typical RPV support mechanism.
The second sub-model, shown in Figure 3.7-27B, represents the reactor core barrel, thermal shield, lower support plate, tie plates, and the secondary support components for Unit 1 (PGE); whereas, for Unit 2 (PEG) the second sub-model is shown in Figure 3.7-27C (core barrel with neutron pads instead of thermal shield). These sub-models are physically located inside the first, and are connected to them by stiffness matrices at the vessel/internals interfaces. Core barrel to reactor vessel shell impact is represented by nonlinear elements at the core barrel flange, upper support plate flange, core barrel outlet nozzles, and the lower radial restraints.
The third and innermost sub-model, shown in Figure 3.7-27D, represents the upper support plate assembly consisting of guide tubes, upper support columns, upper and lower core plates, and the fuel. The fuel assembly simplified structural model incorporated into the RPV system model preserves the dynamic characteristics of the entire core. For each type of fuel design the corresponding simplified fuel assembly model is incorporated into the system model. The third sub-model is connected to the first and second by stiffness matrices and nonlinear elements.
As mentioned earlier, fluid-structure or hydroelastic interaction is included in the reactor pressure vessel model for seismic evaluations. The horizontal hydroelastic interaction is significant in the cylindrical fluid flow region between the core barrel and the reactor vessel annulus. Mass matrices with off-diagonal terms (horizontal degrees-of-freedom only) attach between nodes on the core barrel, thermal shield and the reactor vessel. The mass matrices for the hydroelastic interactions of two concentric cylinders are developed using the work of Reference 36. The diagonal terms of the mass matrix are DCPP UNITS 1 & 2 FSAR UPDATE 3.7-34 Revision 21 September 2013 similar to the lumping of water mass to the vessel shell, thermal shield, and core barrel. The off-diagonal terms reflect the fact that all the water mass does not participate when there is no relative motion of the vessel and core barrel. It should be pointed out that the hydrodynamic mass matrix has no artificial virtual mass effect and is derived in a straight-forward, quantitative manner.
The matrices are a function of the properties of two cylinders with the fluid in the cylindrical annulus, specifically, inside and outside radius of the annulus, density of the fluid, and length of the cylinders. Vertical segmentation of the reactor vessel and the core barrel allows inclusion of radii variations along their heights and approximates the effects beam mode deformation. These mass matrices were inserted between the selected nodes on the core barrel, thermal shield, and the reactor vessel as shown in Figure 3.7-27E.
The seismic evaluations are performed by including the effects of simultaneous application of time history accelerations in three orthogonal directions. For the DE, DDE and HE, the Westinghouse generated synthesized time history accelerations at the reactor vessel support were used. The detailed seismic analyses results of the RPV system are documented in Reference 34.
The WECAN computer code, which is used to determine the response of the reactor vessel and its internals, is a general-purpose finite element code. In the finite element approach, the structure is divided into a finite number of discrete members or elements. The inertia and stiffness matrices, as well as the force array, are first calculated for each element in the local coordinates. Employing appropriate transformations, the element global matrices and arrays are assembled into global structural matrices and arrays, and used for dynamic solution of the system equations. The results of the nonlinear seismic dynamic analyses include the transient displacements and impact loads for various elements of the mathematical model. These displacements, impact loads, and linear component loads (forces and moments) are then used by cognizant organizations for detailed component evaluations to assess the structure of the reactor vessel, reactor internals, and the fuel. Note that the linear component forces and moments are not the direct output from the modal superposition analysis but rather are obtained by post-processing the data saved from the nonlinear time history analysis. From the modal analysis (free vibration analysis), the system eigenvalues and eigenvectors are stored on a magnetic tape to be used later in the modal superposition analysis. The validity of a complex system structural model is generally verified by comparing the calculated fundamental frequency of the system with the available test data frequency. The fundamental core barrel frequency of a four-loop thermal shield core barrel is known from test data to be approximately 6.6 to 7.0 Hz. The results of Diablo Canyon Unit 1 modal analysis show that the core barrel fundamental beam mode frequency is close to 7.0 Hz, thereby verifying the applicability of the system model for the desired analysis.
DCPP UNITS 1 & 2 FSAR UPDATE 3.7-35 Revision 21 September 2013 Note that the preceding paragraphs describe RPV and internals system dynamic analyses for which the WECAN computer code was used. Current analyses (such as the dynamic analyses performed in support of the replacement vessel head project) utilize the ANSYS computer code. The methodology used to develop the ANSYS system models is consistent with the methodology used to develop historic WECAN models. The direct time integration method is used in ANSYS to solve the dynamic equations of motion for the system; whereas the nonlinear mode superposition method is used in WECAN to solve the dynamic equations of motion for the system. 3.7.3.15.2 Fuel Assembly Evaluation The fuel assembly design adequacy under DDE and HE conditions was assessed through a combination of mechanical tests and analyses. The information obtained from the fuel assembly and component structural tests provided the fundamental mechanical constants for the finite element model used in the fuel analysis.
The analysis of the fuel is performed in two steps. The first step involves analysis of the detailed reactor core model, which includes the reactor vessel, internals, and a simplified model of the fuel (Figures 3.7-27A thru 3.7-27E). This dynamic analysis uses seismic time history motion at the reactor vessel support elevation (Elevation 102 ft.). The second step of the fuel analysis involves running a detailed fuel assembly model using the WEGAP code. This detailed model (Figure 3.7-27F) conservatively represents an entire row of full-length fuel assemblies (15 total).
The fuel assembly model consists of a series of beam elements with torsional springs located at the various fuel assembly grid elevations to simulate the fuel assembly dynamic characteristics. The values of the mechanical constants such as the rigidity modulus and the torsional stiffness were selected to accurately represent the experimentally determined fuel assembly modal stiffness and natural frequencies.
The time history motion for the upper and lower core plates and core barrel are simultaneously applied to the simulated fuel assembly model as illustrated in Figure 3.7-27F. These input motions were obtained from the time history analysis of the reactor vessel and internals finite element model.
The maximum grid impact forces and the fuel assembly maximum deflection are determined with the reactor core model.
Because of the basic fuel assembly design configuration, the assembly impacting is restricted to the grid locations. The seismic and LOCA loads at each grid were combined using the SRSS method to obtain the design maximum loads. These loads are compared with the allowable grid load, which is determined based on the test data using 95 percent confidence level on the true mean criteria. The results of the Unit 1 and Unit 2 evaluations indicated the possibility of some deformation of fuel grids at a small number of specific locations. An analysis of the effects of this grid deformation has shown the core geometry will remain coolable (Reference 29). Note that with the DCPP UNITS 1 & 2 FSAR UPDATE 3.7-36 Revision 21 September 2013 acceptance of the DCPP leak-before-break analysis by the NRC, dynamic LOCA loads resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis structural analyses and included in the loading combinations (see Section 3.6.2.1.1.1). Only the much smaller LOCA loads from RCS branch line breaks have to be considered. 3.7.3.15.3 Control Rod Drive Mechanism Evaluation The replacement CRDMs were evaluated using a combination of linear and nonlinear finite element models which included the CRDM housings, RPV head adapters, and the integrated head assembly. The following models and analysis methods were employed for the specified earthquakes: (1) DE and DDE: The horizontal analyses for the DE and DDE were based on a nonlinear model. The horizontal DE and DDE acceleration time-histories at the seismic plate elevation and the reactor vessel support elevation were used as inputs to the model. The vertical analyses for the DE and DDE were based on a linear model. The vertical DE and DDE response spectra at the reactor vessel head elevation were used as input to the model. (2) HE: The horizontal and vertical analyses for the HE were based on a linear model. The horizontal and vertical HE response spectra at the seismic plate elevation and the reactor vessel head elevation were used as input to the model. 3.7.3.15.4 CRDM Support System Evaluation The integrated head assembly CRDM seismic support structure, tie rods, and head lifting legs were evaluated using linear elastic 3-D finite element models of the support system. Tension-only capability of the tie rods was modeled. The loading from the CRDMs was addressed through the inclusion of a simplified representation of the pressure housings, including the appropriate lumped masses.
In general, the qualification was based on the response spectrum superposition method using the envelope of the spectra at the 140 foot elevation of the containment interior concrete (attachment point for the tie rods for the tie rods to the reactor cavity walls) and on the reactor vessel lifting lugs and pads (attachment point for the integrated head assembly ring beam to the head) for the DE, DDE, HE, and LOCA load cases. These analyses were supplemented with the time history modal superposition method for the determination of DDE loads for selected connections.
DCPP UNITS 1 & 2 FSAR UPDATE 3.7-37 Revision 21 September 2013 3.7.4 SEISMIC INSTRUMENTATION PROGRAM 3.7.4.1 Comparison With NRC Regulatory Guide 1.12, Revision 2 The seismic instrumentation consists of strong motion triaxial accelerometers that sense and record ground motions. This instrumentation meets the intent of RG 1.12, Revision
- 2. Enhancements to the seismic instrumentation have been made to improve the system effectiveness. The enhancements include supplemental accelerometers and rapid processing of the ground motion data. The enhancements exceed the intent of RG 1.12, Revision 2, and are not considered part of the licensing basis.
3.7.4.2 Location and Description of Instrumentation Seismic instrumentation is provided in accordance with RG 1.12, Revision 2, paragraph 1.2. All instruments are rigidly mounted so their records can be related to movement of the structures and ground motion. All are accessible for periodic servicing and for obtaining readings. 3.7.4.2.1 Strong Motion Triaxial Accelerometers Strong motion triaxial accelerometers provide time-histories of acceleration for each of three orthogonal directions. These histories are recorded in the accelerometer housings. The instruments start recording upon actuation of a seismic trigger which has an adjustable threshold. Six strong motion triaxial accelerometers are provided in accordance with RG 1.12. Revision 2, paragraph 1.2. Supplemental accelerometers provide ground motion data beyond the regulatory guidance and are not part of the licensing commitment, 3.7.4.3 Control Room Operator Notification Operation of the strong motion triaxial accelerometers (ESTA01 or ESTA28) will activate an annunciator in the control room and provide indications on the earthquake force monitor (EFM) in the RSI panel. The EFM will display the acceleration levels for all areas of both the Unit 1 containment base sensor (ESTA01) and the free field sensor (ESTA28). For the Emergency Plan event classification, it also provides a status of level exceedance for any axis on both sensors within a few minutes. The setpoint thresholds are set in accordance with Emergency Plan Action Levels. . 3.7.4.4 Comparison of Measured and Predicted Responses In the event of an earthquake that produces significant ground motions, all seismic instruments are read and the readings compared to the corresponding design values. This comparison, together with information provided by other plant instrumentation and an inspection of safety-related systems, forms the basis for a judgment on severity, level, and the effects of the earthquake.
DCPP UNITS 1 & 2 FSAR UPDATE 3.7-38 Revision 21 September 2013 3.7.5 SEISMIC DESIGN CONTROL 3.7.5.1 Equipment Purchased Directly by PG&E The position of PG&E's engineering staff in the corporate structure is shown in Figures 17.1-1 and 17.1-2. The procedures for specifying technical and quality assurance requirements in purchase orders and specifications are included in Sections 17.4, 17.5, and 17.8.
The seismic design requirements developed from the structure seismic system analysis are included in the purchase order or specification for Design Class I equipment. The purchase order or specification requires that the manufacturer submit seismic qualification data of the equipment to be furnished, for review by the responsible PG&E engineer. The procurement is approved only when all seismic design criteria are met. 3.7.5.2 Equipment Supplied by Westinghouse The following procedure is implemented for Design Class I mechanical equipment that falls within one of the many categories analyzed as described in Section 3.7.2 and shown to be rigid (frequency > 33 Hz).
(1) Equivalent static acceleration factors for the horizontal and vertical directions must be checked against those in the Design Criteria Memoranda (DCM). Westinghouse must certify the adequacy of the equipment to meet the seismic requirements as described in Section 3.7.2 for DE, DDE, and HE. (2) Westinghouse must check to ensure that the given equivalent static acceleration factors are less than or equivalent to those given in the equipment analysis. (3) Westinghouse must perform the necessary reanalysis to the procedures and criteria presented herein for those cases, where required, due to revised DE, DDE, and HE seismic response spectra.
All other Design Class I equipment must be analyzed or tested as described in Sections 3.7.2 and 3.10.
Design control measures and design documentation for all Design Class I SSCs are in accordance with formalized quality assurance procedures. These procedures are presented in Chapter 17, Quality Assurance.
DCPP UNITS 1 & 2 FSAR UPDATE 3.7-39 Revision 21 September 2013 3.7.6 SEISMIC EVALUATION TO DEMONSTRATE COMPLIANCE WITH THE HOSGRI EARTHQUAKE REQUIREMENTS UTILIZING A DEDICATED SHUTDOWN FLOWPATH 3.7.6.1 Post-Hosgri Shutdown Requirements and Assumed Conditions In response to a request from the NRC, PG&E evaluated the ability of DCPP to shut down following the occurrence of a 7.5M earthquake due to a seismic event on the Hosgri fault. This evaluation is presented in Reference 15, which was amended several times after it was first issued in order to respond to questions by the NRC and reflect agreements made at meetings with the NRC. The final document describes the method proposed by PG&E to shut down the plant after the earthquake, assuming a loss of all offsite power, but no concurrent accident, using only equipment qualified to remain operable following such an earthquake.
For this purpose, valves that are required to operate to achieve shutdown following the earthquake were qualified for active function to the Hosgri parameters, whereas other valves, which might have an active function for postaccident mitigation, but were not required to operate to achieve shutdown following the earthquake, were qualified for passive function (pressure boundary integrity) to the Hosgri parameters. This is consistent with the DCPP design basis stated in FSAR Section 3.7.1.1 that the DDE is the SSE for DCPP, and that the guidelines presented in RG 1.29 apply to the DDE.
In addition, pursuant to the NRC request, it was necessary to demonstrate that DCPP could be shut down following an HE in order to protect the health and safety of the public. The Hosgri evaluation presented in Reference 15 demonstrated this. To provide increased conservatism, PG&E has subsequently qualified all active valves for active function for an HE pursuant to a commitment made in Reference 17. 3.7.6.2 Post-Hosgri Safe Shutdown Flowpath The flowpath qualified to enable shutdown of the plant following an HE is defined in Chapter 5 of Reference 15. For this purpose, safe shutdown was defined as cold shutdown. It assumes concurrent loss of offsite power, a single active failure, but no concurrent accident or fire. Local manual operation of equipment from outside the control room is acceptable for taking the plant from hot standby to cold shutdown. 3.7.6.2.1 Hot Standby Hot standby is achieved by feeding the steam generators using the auxiliary feedwater system and by release of steam to the atmosphere through the 10 percent steam dump valves. Although other long term cooling water sources may be available, only the seismically qualified condensate storage tank and firewater storage tank are assumed to be available.
DCPP UNITS 1 & 2 FSAR UPDATE 3.7-40 Revision 21 September 2013 3.7.6.2.2 Cold Shutdown Cold shutdown is achieved by use of the normal charging system flow path. Depressurization is performed using auxiliary spray (alternatively, the PORVs may be used). Boration to cold shutdown concentration is accomplished using boric acid from the boric acid storage tanks via the emergency borate valve 8104 and using a centrifugal charging pump (CCP1 or CCP2) charging through valves FCV-128, HCV-142, 8108, 8107, and 8146 or 8147. Sampling capability to verify boron concentration is available. While reactor coolant pump seal injection flow would be available, the seal water return flow path and the normal letdown flow path are assumed not to be available. Calculations have shown that even with letdown unavailable, by taking credit for shrinkage of the reactor coolant during cooldown, sufficient volume is available in the reactor coolant system to borate to cold shutdown using 4 percent boric acid.
Once the RCS is less than or equal to 390 psig and 350°F, the normal RHR system is placed into service, along with the portions of the component cooling water and auxiliary salt water systems which support RHR operation. 3.7.6.2.3 Single Active Failure Systems and components used to perform the post-Hosgri shutdown described above have redundant counterparts except for components along the normal charging flowpath, which lacks redundancy since its redundant flow path for emergency boration is the high pressure safety injection flow path. Use of that redundant flow path is not postulated for post-Hosgri shutdown, however, so adequate redundancy had to be incorporated into the normal charging flowpath to enable cold shutdown following the HE. For this purpose, the Hosgri evaluation assumed that manual bypass valves 8387B or 8387C would be used in the event that fail-open valve FCV-128 was to fail closed. Manual bypass valve 8403 would be used in the event that fail-closed valve HCV-142 was to fail closed. Fail-open valve FCV-110A and manual bypass valve 8471 would be used in the event that motor-operated valve 8104 was to fail closed. Valves 8146 and 8147 were assumed redundant for normal charging, and valves 8145 and 8148 were assumed redundant for pressurizer auxiliary spray. Valves with pneumatic operators, which are required to operate to achieve shutdown, were fitted with seismically qualified air or nitrogen accumulators to enable their operation in spite of the loss of their instrument air or nitrogen supply. Although some of these valves do not have safety-related operators since they are not required for accident mitigation, they are seismically qualified to ensure their operability for post-Hosgri shutdown. 3.7.6.2.4 Equipment Required for Post-Hosgri Shutdown The equipment determined to be required to achieve post-Hosgri cold shutdown in the manner described above is presented in Sections 7.3 and 9.2 of Reference 15. Some minor revisions to the list of valves required have been made, and are reflected in the latest revision of the active valve list, FSAR Table 3.9-9. Instrument Class IA, DCPP UNITS 1 & 2 FSAR UPDATE 3.7-41 Revision 21 September 2013 Instrument Class IB, Category 1, and on a case-by-case basis, Instrument Class ID instrumentation are qualified to the Hosgri parameters, and assumed to be operable following an HE. Additional instrumentation determined to be required is presented in Section 7.3 of Reference 15. Some revisions have been made to that list; the revised list of required instrumentation is presented in Reference 16. The electrical Class 1E system is also qualified to the Hosgri parameters, and is assumed to be operable following an HE. 3.
7.7 REFERENCES
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- 2. Lawrence Livermore Laboratory, Soil-Structure Interaction: The Status of Current Analysis Methods and Research, NUREG/CR-1780, January 1981. (Section by J. M. Roesset.)
- 3. J. E. Luco, Independence Functions for a Rigid Foundation on a Layered Medium, Nuclear Engineering and Design, Vol. 31, 1974.
- 4. R. V. Whitman and F. E. Richardt, Design Procedures for Dynamically Loaded Foundations, Journal of Soil Mechanics and Foundations Division, SM6, Nov. 1967.
- 5. G. Bohm, Seismic Analysis of Reactor Internals for Pressurized Water Reactors, First National Congress of Pressure Vessel and Piping Technology, ASME Panel on Seismic Analysis & Design of Pressure Vessel and Piping Components, San Francisco, May 10-12, 1971.
- 6. U.S. Atomic Energy Commission (Division of Reactor Development) Publication TID - 7024, Nuclear Reactors and Earthquakes.
- 7. Appendix A to 10 CFR 100, Seismic and Geologic Siting Criteria for Nuclear Power Plants.
- 8. Damping Values of Nuclear Power Plant Components, WCAP-7921-AR, May 1974.
- 9. Stress Evaluation of Piping Systems Assuming Single Snubber Failures, Letter dated January 24, 1978, from P.A. Crane (PG&E) to J.F. Stolz (NRC).
- 10. Description of the Systems Interaction Program for Seismically Induced Events, Revision 4, August 29, 1980.
- 11. Answer to the NRC Staff Questions on the Westinghouse Evaluation of the Effect of Grid Deformation on ECCS Performance, transmitted via letter May 11, 1978, P.A. Crane to J.F. Stolz.
DCPP UNITS 1 & 2 FSAR UPDATE 3.7-42 Revision 21 September 2013 12. Supplement No. 5 to the Safety Evaluation of the Diablo Canyon Nuclear Power Station, Units 1 and 2, Nuclear Regulatory Commission, Division of Reactor Licensing, Washington, DC, September 1976.
- 13. "Dynamics of Fixed-Base Liquid Storage Tanks," Velestsos, A.S. and T.Y. Yang; Proceedings of U.S.-Japan Seminar on Earthquake Engineering Research with Emphasis on Lifeline Systems, Tokyo, November 1976.
- 14. Westinghouse 1981 ECCS Evaluation Model Using the BASH Code, WCAP-10266-P-A, Rev. 2, March 1987.
- 15. Seismic Evaluation for Postulated 7.5M Hosgri Earthquake, DCPP Units 1&2, PG&E.
- 16. PG&E Design Change Package N-47546.
- 17. PG&E Letter to the NRC, DCL-92-198 (LER 1-92-015).
- 18. Phase I Final Report - Design Verification Program, Diablo Canyon Power Plant, Revision 14, transmitted via letter dated October 14, 1983, J. O. Schuyler (PG&E) to D. G. Eisenhut (NRC).
- 19. Final Report of the Diablo Canyon Long Term Seismic Program, July 1988, PG&E.
- 20. Addendum to the 1988 Final Report of the Diablo Canyon Long Term Seismic Program, February 1991, PG&E.
- 21. NUREG-0675, Supplement Number 34, Safety Evaluation Report Related to the Operation of Diablo Canyon Nuclear Power Plant, Units 1 and 2, NRC, June 1991.
- 22. NRC letter to PG&E, "Transmittal of Safety Evaluation Closing Out Diablo Canyon Long-Term Seismic Program," April 17, 1992.
- 23. PG&E letter to the NRC, "Long Term Seismic Program - Future Plant Modifications," DCL-91-178, July 16, 1991.
- 24. Supplement No. 7 to the Safety Evaluation of the Diablo Canyon Nuclear Power Station, Units 1 and 2, Nuclear Regulatory Commission, Division of Reactor Licensing, Washington, DC, May 1978.
- 25. Supplement No. 8 to the Safety Evaluation of the Diablo Canyon Nuclear Power Station, Units 1 and 2, Nuclear Regulatory Commission, Division of Reactor Licensing, Washington, DC, November 1978.
DCPP UNITS 1 & 2 FSAR UPDATE 3.7-43 Revision 21 September 2013 26. Damping Values for Seismic Design of Nuclear Power Plants, Regulatory Guide 1.61, USAEC, October 1973.
- 27. PG&E Licensing Basis Impact Evaluation 2005-03, "Replacement Steam Generator Seismic Damping Values," May 25, 2005.
- 28. Deleted in Revision 20
- 29. WCAP-16946-P, Revision 2, Diablo Canyon Vessel Closure Head and Integrated Head Assembly Project - Impact of IHA on Reactor Vessel, Internals, Fuel, and Loop Piping, September 2010.
- 30. PG&E Document 6023227-19, "Damping Values for Use in the Integrated Head Assembly Seismic Response Analysis at Diablo Canyon Power Plant (DCPP)
Units 1 and 2."
- 31. Damping Values for Seismic Design of Nuclear Power Plants, Regulatory Guide 1.61, Revision 1, USNRC. 32. License Amendment Nos. 208 (DPR-80) and 210 (DPR-82), "Damping Values for the Seismic Design and Analysis of the Reactor Vessel Integrated Head Assembly," USNRC, September 29, 2010.
- 33. License Amendment Nos. 207 (DPR-80) and 209 (DPR-82), "Critical Damping Values for Control Rod Drive Mechanism Pressure Housings," USNRC, July 30, 2010 34. Bhandari, D. R., et aI., System Dynamic Seismic and LOCA Analyses of Reactor Pressure Vessel System for the Pacific Gas and Electric Company Diablo Canyon Power Plants (DCPP) Units 1 & 2, WCAP-14693, Revision 1, February 11, 1997 (Westinghouse Proprietary Class 2).
- 35. Deleted in Revision 21
- 36. Fritz, R. J., The Effects of Liquids on the Dynamic Motions of Immersed Solids, Trans. ASME, Journal of Engineering for Industry, 1972, pp. 167-173. 37. PG&E Calculation No. 2252 C-2 (SAP Calc. No. 9000041232), "Polar Crane ANSR Analyses Results and Spectra Generation for DE, DDE, & HE Cases."
- 38. PG&E Calculation No. 2252 C-3 (SAP Calc. No. 9000041233), "Seismic Evaluation of the Unit 1 Containment Polar Crane Design for 1R17 Modifications and Added Mass." 39. PG&E Calculation No. 2252C-4 (SAP Calc. No. 9000041234), "U2 Polar Crane ANSR Analyses Results & Spectra Gen for DE, DDE & HE Cases."
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-1 Revision 21 September 2013 3.8 DESIGN OF DESIGN CLASS I STRUCTURES Figure 1.2-2 shows the location of all structures for DCPP Units 1 and 2. The design classification of plant structures is given in the DCPP Q-List (see Reference 8 of Section 3.2). In the Q-List, the following Design Class I structures are shown:
(1) Containment structure
(2) Auxiliary building See Section 3.1 for discussion of the design of DCPP structures in conjunction with AEC General Design Criteria. The design of the containment structure is discussed in Section 3.8.1; the auxiliary building design is discussed in Section 3.8.2; and the Class I outdoor storage tanks, including the condensate storage, refueling water storage, and fire water tanks, are discussed in Section 3.8.3. The foundations and concrete supports of Class I structures are discussed in Section 3.8.4. Section 3.8.5 discusses the Design Class II turbine building and intake structure, both of which contain Design Class I equipment and components.
Note that the analytical results summarized in the following sections for the major plant structures are representative of the evaluations performed for the operating license review (Reference 31), but may not reflect minor changes associated with subsequent plant modifications. 3.8.1 CONTAINMENT STRUCTURE 3.8.1.1 Description of the Containment The reactor containment for each unit is a steel-lined, reinforced concrete building of cylindrical shape with a dome roof that completely encloses the reactor and RCS. It ensures that essentially no leakage of radioactive materials to the environment would result even if gross failure of the RCS were to occur simultaneously with an earthquake of intensity twice the maximum postulated.
The containment structures for Units 1 and 2 are essentially identical, as mirror images. The following discussion applies to either unit:
The concrete outline and equipment locations are shown in Chapter 1. The exterior shell consists of a 142-foot-high cylinder, topped with a hemispherical dome. The minimum thickness of the concrete walls is 3.6 feet, and the minimum thickness of the concrete roof is 2.5 feet. Both have a nominal inside diameter of 140 feet and a nominal inside height of 212 feet. The concrete floor pad is 153 feet in diameter with a minimum thickness of 14.5 feet, with the reactor cavity near the center. The inside of the dome, cylinder, and base slab is lined with welded steel plate, which forms a leaktight membrane. The nominal thickness of the steel liner is 3/8-inch on the wall and dome and the nominal thickness of the steel liner on the base slab is 1/4-inch. DCPP UNITS 1 & 2 FSAR UPDATE 3.8-2 Revision 21 September 2013 The containment is designed and will be maintained for a maximum internal pressure of 47 psig and a temperature of 271°F, coincident with a Double Design Earthquake. The internal concrete structure approximates a 106-foot-diameter, 51-foot-high cylinder, with a slab on top. However, there are multiple openings and walls, such as the reactor support and the stainless steel lined refueling canal, which complicate the shape. The walls and top slab are generally 3 feet thick. This structure provides support for the reactor and components of the RCS, provides radiation shielding, and provides protection for the liner from postulated missiles originating from the RCS.
A polar crane is mounted on top of the internal concrete cylinder wall. The support of the polar crane, its connection to the concrete, and provisions to resist seismic forces are shown in Figure 3.8-23 and described in Section 9.1.4. Seismic analysis for the polar crane is discussed in Section 3.7.
The piping and electrical connections between equipment inside the containment structure and other parts of the plant are made through specially designed, leaktight penetrations. In addition to the piping and electrical penetrations, other penetrations are the 18-foot 6-inch diameter equipment hatch, the 9-foot 7-inch diameter personnel hatch, the 5-foot 6-inch diameter personnel emergency hatch, and the fuel transfer tube.
The 6-foot 7-inch by 13-foot ventilation duct is attached to the outside of the structure, extending from an elevation 25 feet above the base slab to the top of the dome. The duct is fabricated from steel plate with stiffeners.
A system of lightning rods is installed on the dome to protect against lightning damage. The following paragraphs describe the various parts of the structure: 3.8.1.1.1 Exterior Shell (1) Reinforcing Steel The reinforcing steel arrangement is designed to provide continuous reinforcement for tensile and shear membrane forces in the cylinder and dome. The reinforcing in the cylinder wall consists of horizontal hoop bars, and inclined bars, oriented 60° from the horizontal. In Figure 3.8-1, layers (4) and (6) are the Number 18 hoop bars, spaced at 8-1/2 inches center-to-center vertically, and layers (3) and (5) are the inclined Number 18 bars spaced at 8-1/2 inches center-to-center, all spacing measured normal to the bars. The dome reinforcing is accomplished by extending the inclined bars past the springline and over the dome. After crossing the dome, the same bar once again becomes an inclined bar in the cylinder. A layer (3) bar becomes a layer (5) bar after crossing the dome, as shown in DCPP UNITS 1 & 2 FSAR UPDATE 3.8-3 Revision 21 September 2013 Figure 3.8-2. No inclined bars are terminated at the springline or in the dome. The dome steel layout is based on the division of a sphere into 20 equilateral spherical triangles, as shown in Figure 3.8-3. At the springline, two sides of the triangles make an angle of 30° with the vertical. Thus, an inclined cylinder bar is parallel to the sides of the triangles at the springline. The inclined cylinder bars are extended into the dome so that they are always parallel to one side of a spherical triangle. Figure 3.8-4 shows the five types of bars in the dome. When these five types are superimposed, there are three layers of reinforcing steel at every point above the pentagon ABCDE in Figure 3.8-3. Below pentagon ABCDE, the inclined bars make up two layers at every point, and bars similar to the cylinder hoop bars are used to provide reinforcing in the third direction. Layers (1) and (2) (Figure 3.8-1) are inclined at 30° to the vertical and extend from the base slab to elevation 172 feet. These bars, spaced at 17 inches center-to-center, provide additional capacity to resist earthquake forces. Above elevation 170 feet, Number 4 bars are spaced at 12 inches center-to-center horizontally and vertically. (2) Splices All Number 18 bars are spliced by Cadwelding using "T-Series" sleeves, designed to develop the full tensile strength of the bar. As a general rule, splices are staggered a minimum of 3 feet. For all penetrations except the equipment and personnel hatches, the Number 18 reinforcing bars are bent around openings. For the equipment and personnel hatch openings, a 2.5-inch-thick hexagonal collar, widened to 4 inches thick at the edges, is provided to transfer the reinforcing bar forces around the opening as shown in Figures 3.8-12 and 3.8-13. The reinforcing bars are Cadwelded to special studs threaded into the 4-inch edge of the hexagonal collar. 3.8.1.1.2 Liner All liner seams are full penetration butt-welded, and are covered with steel channels welded to the inside of the structure. These "leak chase" channels provide a sensitive and accurate means of detecting leakage. They are arranged in zones so that one zone at a time may be pressurized to test the integrity of the liner plate welds.
The liner in the dome and cylinder wall is anchored by welded studs that extend into the concrete wall past the innermost layers of reinforcing steel. Three types of studs are used: a 3/8-inch diameter with an 8-1/2-inch shaft and a plain 4-inch "L" shaped arm, a DCPP UNITS 1 & 2 FSAR UPDATE 3.8-4 Revision 21 September 2013 3/8-inch diameter with an 8-1/2-inch shaft and a threaded end, and a 1/2-inch diameter with an 11-inch shaft and a threaded end. All threaded studs are provided with an anchorage at the threaded end, and provide resistance to pullout that is equal to or greater than the 3/8-inch stud with a 4-inch arm. The studs are spaced a maximum of 19.6 inches on center (plus a placement tolerance of 1/2 inch) in a pattern that is compatible with the reinforcing steel, as shown in Figure 3.8-5.
For all penetrations in the exterior shell, a thickened plate is welded into the liner. 3.8.1.1.3 Penetrations In general, a penetration consists of a sleeve embedded in the concrete wall and welded to the containment structure liner. The pipe, electrical conductor cartridge, duct, or access hatch passes through the embedded sleeve and one or both ends of the resulting annulus are closed off by welded end plates, bolted flanges, or flued heads. Typical electrical and piping penetrations are shown in Figures 3.8-6 through 3.8-10, and the fuel transfer tube penetration is shown in Figure 3.8-11. The penetrations are designed to maintain the same high degree of leaktight integrity afforded by the containment structure itself. 3.8.1.1.3.1 Electrical Penetrations Electrical penetrations are either canister types or feed-through modules that allow electrical conductors to pass through the containment boundary. Penetrations are qualified for a single seal pressure boundary. The canister and feed-through modules are connected to the header plate, which is welded to the containment penetration sleeve. All penetrations are provided with a connection to allow periodic leak testing. The weld connecting the sleeve to the liner plate is provided with a leak chase channel for leak testing. 3.8.1.1.3.2 Piping Penetrations Piping penetrations are provided for all piping passing through the containment boundary. Typical piping penetrations are shown in Figures 3.8-6 and 3.8-7. Several small pipes may pass through a single embedded sleeve to minimize the number of penetrations required. Welded end plates or flued heads are used to provide end closure. The welded joints are covered with a leak chase channel to allow periodic testing. The weld connecting the sleeve to the liner plate also has a leak chase channel.
Pipes carrying hot fluids through penetrations are designed to maintain the temperature of the concrete adjacent to the sleeve below 200°F under normal operating conditions. Pipes and penetrations are anchored, as required, to resist the forces and movements incident at the penetration under normal and accident conditions, and to limit the loads imposed on the containment structure liner. Piping loads are transferred to the DCPP UNITS 1 & 2 FSAR UPDATE 3.8-5 Revision 21 September 2013 penetration sleeve and thence to anchors in the concrete wall rather than to the containment structure liner. 3.8.1.1.3.3 Equipment and Personnel Access Hatches The equipment hatch is furnished with a double-gasketed flange and bolted dished door. Equipment up to a diameter of approximately 18 feet can be transferred into and out of the containment structure through this hatch. The hatch barrel is embedded in the containment structure wall and welded to the liner. Provision is made for pressurizing the space between the double gaskets of the door flanges and the weld seam leak chase channels at the sleeve-to-liner joint.
The two personnel hatches are double door, mechanically-latched, welded steel assemblies.
A quick-acting type equalizing valve connects each personnel hatch with the interior of the containment vessel for the purpose of equalizing pressure in the two systems when entering or leaving. The personnel hatch doors are interlocked to prevent simultaneous opening. Remote indicating lights and annunciators situated in the control room indicate the door operational status. Provision is made to permit bypassing the door interlocking system to allow doors to be left open during a plant cold shutdown. Each door hinge is capable of independent three-dimensional adjustment to assist proper seating. A lighting and communication system operating from an external supply is provided in the lock interior. Emergency access, to either the inner door from the containment interior, or to the outer door from outside, is possible by the use of special door unlatching tools. All doors on the personnel hatches are double gasketed and provided with fittings to allow pressurization of the space between the double gaskets. 3.8.1.1.3.4 Special Penetrations (1) Fuel Transfer Tube Penetration A fuel transfer tube penetration is provided for fuel movement between the refueling canal in the containment structure and the spent fuel pool. The penetration consists of a 20-inch-diameter stainless steel pipe installed inside a 24-inch-diameter pipe sleeve as shown in Figure 3.8-11. The inner pipe acts as the transfer tube and is fitted with a quick-opening hatch in the refueling canal and a standard gate valve in the spent fuel pool. This arrangement prevents leakage through the transfer tube in the event of an accident. The outer pipe is welded to the containment liner and provision is made, by use of a special seal ring to permit pressure testing all welds essential to the integrity of the penetration. Bellows expansion joints are provided on the pipes to compensate for any differential movement between the two pipes or other structures. DCPP UNITS 1 & 2 FSAR UPDATE 3.8-6 Revision 21 September 2013 (2) Containment Supply and Exhaust Purge Ducts The ventilation system purge duct is equipped with two quick-acting tight-sealing valves (one inside and one outside the containment) to be used for isolation purposes. These valves are normally closed during reactor operation. They are manually opened for containment purging but are automatically closed upon a signal of high containment pressure or high containment radiation level. The space between the valves can be pressurized to check the integrity of the penetration. In addition, the shaft seals of the purge valves are equipped with double seals with provision for testing the space between. (3) Spare Penetrations Capped spare penetrations are provided. The welds between the sleeve and the liner and between the sleeve and the cap are covered with leak chase channels. All spaces that are equipped for pressurization of penetrations and penetration sleeves are included in the same system of pressurization zones as the liner seam leak chase channels. Several spare penetrations are also provided with capped, blind flanged or valved and capped end connections. These are 10 CFR 50 Appendix J Type B penetrations and are leak rate tested in accordance with Appendix J, Option B, as modified by approved exemptions. (4) Mini-Equipment Hatches (Penetrations 58 and 60) The mini-equipment hatch penetrations are provided to facilitate the passage of electrical cables and compressed air/water hoses into containment during refueling outages to support maintenance activities. Each of the two penetrations are comprised of flange connections on both sides of containment. The in-containment flanges are equipped with double O-Rings, which form a double containment isolation boundary. The in-containment blind flanges are provided with pressure test connections to permit pressure testing between the O-Rings. During plant outages, a temporary configuration is used to provide a containment pressure seal while the penetration blind flange is removed from service. Both the O-Rings and temporary blind flange assemblies prevent leakage through the penetrations in the event of an accident.
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-7 Revision 21 September 2013 3.8.1.1.4 Base Slab and Shell-Base Slab Connection The seams on the base slab and reactor cavity liner are full penetration butt-welded and are covered with leak chase channels. The leak chase channels are arranged in zones in the same manner as those on the exterior shell liner.
There are two penetrations through the base slab for recirculation lines. These are similar to penetrations used in the exterior shell. Weld seams between the liner and the penetration sleeve and between the penetration sleeve and internal, are covered with leak chase channels. The volume in the end of the penetration internal has a fitting for pressurization. These leak chase channels and the volume in the end of the penetration internal are connected in the zones of pressurization used for liner leak chase channels.
The detail of the shell-base slab connection is shown in Figure 3.8-14. The vertical wide flange steel beams provide a gradual transition of load carrying elements between the base slab and the cylinder, and resist the radial bending moments and shears. The beams are keyed and grouted in a groove at the base slab and extend approximately 20 feet up the wall. They do not participate in resisting either uplift due to pressure, or shear and tension forces due to earthquake.
The 3-foot 8-inch thick cylinder wall is designed to offer minimum bending resistance at the junction with the base slab. To achieve this the wall is divided into three layers, with the contact surface between the layers designed as a slip surface. The 12-inch inner layer, next to the liner plate, provides stiffness to the liner plate. The L-shaped stud anchors, welded to the liner plate, and layers (1) and (2) of the wall reinforcing bars are in this layer. The middle layer is the wide flange steel beams. The voids between the beam webs are filled with concrete. The outer layer is 20 inches thick. Layers (3) through (6) of the wall reinforcing bars are in this layer. The slip surface between layers is provided by covering both flanges of the steel beams with two sheets of Johns-Manville #60 asbestos sheet packing. This packing is graphite coated on one side, and the two sheets are placed with the graphite-coated sides in contact. PG&E has successfully used this means of providing sliding supports on penstock piers for several years. The inert nature of the material, and the fact that it is completely isolated from the atmosphere by a minimum of 20 inches of concrete, combine to ensure that it will be fully effective throughout the lifetime of the plant.
The detail at the bottom of each of these three layers is shown in Figure 3.8-14. The innermost and outermost layers have a 1-inch neoprene pad to allow slight rotation without crushing of the concrete. The center layers, consisting of the beams, have a 5-inch-deep pocket in which the beams are placed and grouted.
The diagonal wall reinforcing extends to the bottom of the base slab for anchorage, as shown in Figure 3.8-15. The base slab bars are bent up at 45° and passed through the diagonal bars. The ends of the base slab bars are provided with a mechanical anchorage consisting of a Cadweld sleeve and a steel plate. DCPP UNITS 1 & 2 FSAR UPDATE 3.8-8 Revision 21 September 2013 The shell liner is anchored to the base slab by Number 14 rebar welded to the bottom course liner plate, which is 3/4-inch-thick. These rebars are embedded 8-1/2 feet in the base slab concrete. 3.8.1.1.5 Internal Structure The internal structure that is shown in Figures 3.8-16 through 3.8-22 consists of the following parts:
(1) The lower operating floor at elevation 91 feet is a 2-foot-thick concrete slab placed over the containment structure base slab liner.
(2) The circular crane wall is a 3-foot-thick, 106-foot-OD reinforced concrete wall, concentric with the exterior shell, and extending vertically from the containment structure base slab liner at elevation 89 feet to the main operating floor at elevation 140 feet. The runway for the 200-ton polar gantry crane is located on top of the circular crane wall. This wall is anchored to the containment structure base slab by Number 18 reinforcing bars. This anchorage is developed through the containment structure base slab liner by means of Cadweld sleeves welded to each side of the liner at the same locations. The polar crane is shown in Figure 3.8-23. (3) The reactor shield wall is a 34-foot-OD, 17-foot-ID reinforced concrete wall. This wall is anchored to the containment structure base slab in the same manner as the circular crane wall. (4) The fuel transfer canal is a stainless steel lined cavity that can be filled with water during refueling. The vertical walls of the fuel transfer canal are 4 feet thick. (5) The main operating floor at elevation 140 feet is a 3-foot-thick concrete slab supported by the circular crane wall and the fuel transfer canal walls. This slab is thickened locally up to 7 feet near openings. (6) Main steam line restraint towers are reinforced concrete buttresses extending from the main operating floor at elevations 140 to 184 feet. (7) Annulus platforms are structural steel platforms at elevations 117 and 140 feet, located between the circular crane wall and the exterior shell. Steel framing is also provided at elevations 106 feet 8 inches and 101 feet 5 inches for support of piping. Figures 3.8-21 and 3.8-22 provide the structural steel framing details for these platforms. DCPP UNITS 1 & 2 FSAR UPDATE 3.8-9 Revision 21 September 2013 3.8.1.1.6 Polar Crane The polar crane structural steel frame consists of:
(1) Two main box girders 120 feet long, 10 feet deep and 4 feet wide, spaced 24 feet apart (2) Four gantry legs, 52 feet long and made of tapered box sections supporting the girders (3) Two sill beams, 28 feet long with box sections to connect the gantry legs
(4) Four tie beams connecting main girders and gantry legs The arrangement as described above is shown in Figure 3.8-23.
The sill beams are supported by two wheel assemblies each and are restrained by guide struts. These struts allow the wheels to uplift during a seismic event but guide the wheels back on to the rail. 3.8.1.2 Applicable Codes, Standards, and Specifications 3.8.1.2.1 Codes and Standards The following codes and standards were used, insofar as they are applicable, in the design and/or construction of the containment structure: (1) ACI Standard Building Code Requirements for Reinforced Concrete (ACI 318-63) (2) Manual of Standard Practice for Detailing Reinforced Concrete Structures (ACI 315-65) (3) Recommended Practice for Evaluation of Compression Test Results of Field Concrete (ACI 214-65) (4) Inspection of the Cadweld Rebar Splice (Erico Products, Inc., RB-5M 768)
(5) Recommended Practices for Welding Reinforcing Steel, Metal Inserts, and Connections in Reinforced Concrete Construction, American Welding Society, AWS D 12.1-61 (6) AISC Specification for the Design, Fabrication, and Erection of Structural Steel for Buildings, February 12, 1969 DCPP UNITS 1 & 2 FSAR UPDATE 3.8-10 Revision 21 September 2013 (7) Construction of the containment structure liner conforms to the applicable parts of Part UW, "Requirements for Unfired Pressure Vessels Fabricated by Welding," Section VIII, ASME Boiler and Pressure Vessel Code, 1968 Edition, including Addenda through Summer 1968 (8) Those parts of penetration insert plates, penetration sleeves, airlocks, and access hatches, which form part of the pressure boundary, conform to Class B requirements of Section III, ASME Boiler and Pressure Vessel Code, 1968 Edition, including Addenda through Summer 1968 (9) Code for Welding in Building Construction, AWS D 1.0-69. Work performed prior to December 12, 1969 is in accordance with the earlier edition, AWS D 1.0-66. For inspection of non-ASME structural welds or new non-ASME work performed after January 1, 1988, the guidelines of Nuclear Construction Issues Group (Visual Weld Acceptance Criteria, Vol. 1-3, EPRI Report No. NP-5380, September 1987) (Reference 27) may be used except for those cases where: (a) Fatigue is a governing design condition
(b) The weld allowables are permitted to be higher than those allowed by AWS D1.1 (such as the full penetration welds evaluation for the HE) (c) The weld is part of work performed in the ASME Section XI Inservice Inspection Program. (10) Stud welding is in accordance with the Supplement to American Welding Society Specifications AWS D 1.0-66 and AWS D 2.0-66 on Requirements for Stud Welding (11) Materials, and the quality control tests for materials conform to ASTM standards (12) Pressure tests of the containment structure, leak chase channels, double penetration volumes, volumes between double seals, and volumes between double isolation valves are in accordance with the requirements of ANSI N45.4-1972, Leakage Rate Testing of Containment Structures for Nuclear Reactors, dated March 16, 1972 (13) SG 12, Instrumentation for Earthquake, dated March 10, 1971
(14) SG 18, Structural Acceptance Test for Concrete Primary Reactor containments, dated October 27, 1971 DCPP UNITS 1 & 2 FSAR UPDATE 3.8-11 Revision 21 September 2013 (15) ASME Section III, Division 2, 1980 (16) ASME Section III, Division 1, Subsection NE, 1974
(17) American Petroleum Institute (API) Code 650, Welded Steel Tanks for Oil Storage (18) United States of America Standards Institute (USASI) - N6.2 Safety Standard for the Design, Fabrication and Maintenance of Steel Containment Structures, for Stationary Nuclear Power Reactors 3.8.1.2.2 Regulatory Guides The following guidance documents were issued after construction at the DCPP was partially completed:
(1) SG 10, Mechanical (Cadweld) Splices in Reinforcing Bars of Concrete Containments, dated March 10, 1971 (2) RG 1.15, Testing of Reinforcing Bars for Category I Concrete Structures, dated December 28, 1972 (3) SG 19, Nondestructive Examination of Primary Containment Liner Welds, dated August 11, 1972 (4) RG 1.55, Concrete Placement in Category I Structures, dated June 1973 Because the corresponding programs for the DCPP were conservatively formulated, the inspection provided essentially equals, and in many cases exceeds, that provided by the regulatory position in the guides. Detailed comparisons of the program used for the DCPP with the regulatory position of RG 1.15, SG 10, and SG 19 are presented in Tables 3.8-1 through 3.8-3, respectively. The quality assurance program for the DCPP meets the requirements of RG 1.55. In regard to RG 1.55, the references used for guidance are those listed in Appendix A of the RG, as they existed at the time of the Preliminary Safety Analysis Report (PSAR).
3.8.1.2.3 ACI-ASME for Containments The technical requirements of the code (Reference 3) were derived from the Building Code Requirements for Reinforced Concrete (ACI 318-71), from Section III, Division 1, of the ASME Boiler and Pressure Vessel Code, and from other codes and standards commonly applied to containment structure design, fabrication, and examination. The requirements for the DCPP containment structures are based on those same codes and standards, except that in many cases an earlier edition was applied to DCPP.
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-12 Revision 21 September 2013 Tables 3.8-1, 3.8-2, and 3.8-3 compare the DCPP programs for reinforcing steel, Cadweld splices, and nondestructive examination of the liner with the regulatory position in RG 1.15, SG 10, and SG 19, respectively.
The general requirements of the code require third party inspection for all containment structure fabrication and construction. For DCPP, third party inspection was provided for fabrication and installation of all containment structure penetrations in accordance with the Class B requirements of Section III, ASME Boiler and Pressure Vessel Code. 3.8.1.3 Loads and Loading Combinations 3.8.1.3.1 Design Loads The following loads were considered in the design of the containment structure: 3.8.1.3.1.1 Dead Loads Dead loads consist of the weight of concrete, reinforcing steel, steel liner, structural steel, and permanent equipment loads. Equipment loads are supplied by the manufacturers. 3.8.1.3.1.2 Live Loads Live loads consist of temporary equipment loads and a uniform load to account for the miscellaneous temporary loadings that may be placed on the structure.
3.8.1.3.1.3 Internal Pressure Due to Loss-of-Coolant Accident The design peak internal pressure used for design purposes is 47 psig, which is greater than any of the peak pressures calculated in the detailed analysis reported in Chapter 6.
For design purposes, a maximum pressure differential of 15 psi due to the hypothetical LOCA was assumed to exist between the volume within the circular crane wall and the surrounding containment structure volume. The pressurizer enclosure maximum pressure differential was assumed to be 4 psi due to the vent openings provided. These values are greater than the values calculated in the detailed analysis reported in Chapter 6. 3.8.1.3.1.4 Loads Due to Thermal Expansion These are loads resulting from the internal temperatures associated with normal operation and the hypothetical LOCA. The maximum internal atmospheric temperature during normal operation is 120°F. The temperature transients associated with the LOCA pressure and temperature are shown in Appendix 6.2C of this FSAR Update. The analyses of Appendix 6.2C correspond to a design load factor of 1.0. To determine the temperature transients for load factors equal to 1.25 and 1.5, steam tables are used. DCPP UNITS 1 & 2 FSAR UPDATE 3.8-13 Revision 21 September 2013 3.8.1.3.1.5 Loads Due to Postulated Pipe Ruptures and Missile Impact Design of the internal structure includes calculation of the effects of forces from postulated pipe ruptures transmitted through pipe restraints and equipment supports, jet forces for postulated pipe ruptures, and forces resulting from postulated missile impact. The forces from postulated pipe ruptures are calculated as described in Section 3.6. The forces from postulated missile impact are calculated as described in Section 3.5. 3.8.1.3.1.6 Earthquake Loads Earthquake loads are based on a time-history modal superposition analysis of the containment structure and surrounding rock mass, as appropriate, as described in Section 3.7.2. 3.8.1.3.1.7 Wind Loads Wind loads are determined in accordance with the criteria presented in Section 3.3. 3.8.1.3.1.8 Test Pressure Internal pressure is applied to test the structural integrity of the containment vessel up to 115 percent of the design pressure. For this structure, the test pressure is 54 psig. 3.8.1.3.1.9 Negative Pressure Negative pressure consists of loading from an internal negative pressure of 3.5 psig. This negative pressure has taken into account the Technical Specification limit on lower bound containment pressure and on inadvertent containment spray actuations, which would result in a 70°F temperature decrease. 3.8.1.3.1.10 Crane Operating Loads Crane-operating loads include:
(1) Live load impact = (LI) = 0.2L
(2) Lateral operating load = (LAT) = 0.1 (L+TD)
(3) Longitudinal operating load = (LONG) = 0.1 (L+TD) where:
L = Crane rated live load TD = Trolley dead weight
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-14 Revision 21 September 2013 3.8.1.3.2 Loading Combinations The following loading combinations are used in design of the containment structure elements. 3.8.1.3.2.1 Operating Conditions (1) Exterior Structure and Base Slab
Dead load, thermal load, DE, and negative pressure are considered as follows:
C = D + TO + DE + NP (3.8-1) where: C = required capacity of section based on the methods described in Section 3.8.1.5.1 D = dead load of structure and equipment loads TO = thermal loads during normal operating conditions DE = loads resulting from the DE NP = load due to negative pressure (2) Internal Structure
For concrete structures, dead load, live load, thermal load, and DE load are considered as follows: C = D + L + TO + DE (3.8-2) For annulus steel structures, the load combinations are: C = D + TO + TH + FL (3.8-3) C = D + TO + TH + FV + RVOT + DE (3.8-4) where: FL = friction loads applied in the direction of thermal movements FV = fast valve closure load L = live load RVOT = relief valve opening thrust load TH = restrained thermal loads of the supported piping DCPP UNITS 1 & 2 FSAR UPDATE 3.8-15 Revision 21 September 2013 (3) Polar Crane C = D + TD + L + LI
C = D + TD + L + LAT
C = D + TD + L + LONG
C = D + TD + DE 3.8.1.3.2.2 Accident Conditions (1) Exterior Shell and Base Slab U = 1.0D +/- 0.05D + 1.5PA + 1.0T" (3.8-5) U = 1.0D +/- 0.05D + 1.25PA + 1.0T' + 1.25DE (3.8-6) U = 1.0D +/- 0.05D + 1.0PA + 1.0T + 1.0DDE (3.8-7) U = 1.0D +/- 0.05D + 1.0PA + 1.0T + 1.0HE (3.8-8) where:
U = required load capacity of section based on the methods described in Section 3.8.1.5.2 PA = load due to accident pressure T = load due to maximum temperature associated with 1.0PA T' = load due to maximum temperature associated with 1.25PA T" = load due to maximum temperature associated with 1.5PA DDE = loads resulting from the DDE HE = loads resulting from the HE (2) Internal Structure For concrete structures, dead load, live load, earthquake load, compartment pressurization, pipe reactions associated with a postulated pipe rupture, jet forces, and missile loads are considered wherever occurring as follows: U = D + L + DDE + CP + R + J + M (3.8-9) U = D + L + HE + CP + R + J + M (3.8-10) DCPP UNITS 1 & 2 FSAR UPDATE 3.8-16 Revision 21 September 2013 For annulus steel structures, the load combinations are: U = D + DDE + THA + FV + RVOT (3.8-11)
U = D + HE (3.8-12) where: CP = compartment pressurization associated with a pipe break R = pipe reactions associated with a postulated pipe rupture J = jet impingement load M = missile impact load THA = restrained thermal expansion loads of the supported piping (3) Polar Crane
U = D + TD + DDE + TO U = D + TD + L + HE where: TO = thermal load induced by the temperature differential between the crane structure and supporting concrete structure, during operating condition U = capacity of the section as determined from an increase of allowable stresses by a factor of 1.7 3.8.1.4 Design and Analysis Procedures 3.8.1.4.1 Analysis of Containment Cylinder and Dome For the loading conditions described in Section 3.8.1.3.2, the exterior wall is subjected to membrane forces and moments. These forces and moments are shown in Figures 3.8-27 through 3.8-34, and have been calculated based on the overall elastic behavior of containment exterior wall and dome in accordance with the conventional close form solution. An exception is that at the juncture of cylinder wall and base slab, the meridional moment and shear forces are computed as described in Section 3.8.1.3.1.4.
The stresses in the reinforcing steel and concrete subject to the above membrane forces and moments are computed by assuming that the concrete cracks under tension. This involved resolving compatibility and equilibrium equations by an iterative method. The stress analysis is performed with two sets of assumptions: (a) the effect of the liner plate is neglected, and (b) the liner plate is included as a stress-carrying element. Since DCPP UNITS 1 & 2 FSAR UPDATE 3.8-17 Revision 21 September 2013 the thicknesses of the cylinder and dome are small in comparison with the radii of curvature, they are analyzed as a thin walled shell structure.
(1) Internal pressure and dead load The calculated membrane forces due to axisymmetric loads, such as internal pressure and dead load, are shown in Figure 3.8-27. (2) Earthquake Membrane forces are from the finite element, time-history modal superposition analysis described in Section 3.7.2. The plots of these membrane forces in the cylinder and dome due to the DE, DDE, and HE are shown in Figures 3.8-28 and 3.8-29, respectively. Shear forces in the dome due to the vertical input were calculated. Vertical input produces only radial shear, but no membrane shear. Radial shears were negligible when compared to membrane shears. (3) Wind Membrane forces from wind are shown in Figure 3.8-34. These are less than the membrane forces due to an earthquake. (4) Temperature Temperature loads are considered thermal gradients in the reinforced section, including the liner plate. The analysis procedure for thermal load is described in Section 3.8.1.4.4.
The combined membrane forces for the four accident loading conditions are shown in Figures 3.8-30, 3.8-31, 3.8-32, and 3.8-33. 3.8.1.4.2 Liner Anchors The liner anchors are designed so that they have sufficient strength and flexibility to withstand any combination of liner stress and deformation that can be reasonably assumed to occur under accident loading conditions. The liner plate system is evaluated by developing allowable loads for attached threaded studs to support the mechanical or piping system. The load transfer mechanism from the external mechanical loads through the liner plate to the concrete stud system is developed to ensure the transfer of all loads into the concrete shell with all elements remaining elastic, while maintaining the leaktight boundary.
The concrete anchors are capable of accommodating the displacement of the liner plate under the operating and accident loading conditions.
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-18 Revision 21 September 2013 3.8.1.4.3 Equipment and Personnel Hatch Openings Membrane forces are transferred around the equipment hatch and personnel hatch openings by means of hexagonal-shaped steel collars to which the reinforcing steel is attached.
The analysis of the equipment hatch and personnel hatch openings takes into account the following:
(1) Direct membrane forces in the shell
(2) Force concentrations in the shell
(3) Bending effect in the shell The area of the containment shell adjacent to the opening is extended beyond the opening far enough to make the effects of the opening negligible. This area is represented by a finite element mesh consisting of three parallel layers of plate elements which are interconnected by transverse beam elements representing the transverse normal and shear stiffness of concrete wall. The outer surface represents the hexagonal plate and outside reinforcement, the inner surface represents the sleeve, the liner plate and the inner reinforcement, and the intermediate layer represents the additional reinforcement around the opening. The hexagonal plate, sleeve, and liner plate are modeled by isotropic plate elements, and the reinforcement by orthotropic elements, in which the principal directions coincide with the directions of the reinforcement. The stiffness of concrete in the membrane directions is not included, because under tension the concrete is assumed to be cracked. The finite element model is shown in Figure 3.8-35. The analysis is performed by using BSAP/CE 800 computer program.
For axisymmetric loading, the vertical boundaries are restrained in the hoop direction. For the application of tangential shear force, the lower horizontal boundaries are restrained in the vertical and tangential directions. The vertical movement of the lower horizontal boundary is always restrained.
The internal pressure is applied to a large area of the shell wall adjacent to the opening and on the hatch. Since the hatch is not a part of the model, this pressure is transferred to the nodal point around the opening as nodal loads. The pressure on the containment shell and the nodal loads around the opening are applied in the radial direction. By examining the equilibrium of the sector of the wall isolated for modeling, having boundary conditions as described above, hoop membrane forces are induced to the model at the boundary conditions in which the following equation of equilibrium is met: N = pR (3.8-13) DCPP UNITS 1 & 2 FSAR UPDATE 3.8-19 Revision 21 September 2013 where: N = hoop force p = internal pressure R = radius of cylinder The isostress plots are shown in Figures 3.8-40 through 3.8-42. These stresses are the results of the load combination shown by Equation 3.8-5, which controls the stress evaluation. 3.8.1.4.4 Juncture of Cylinder and Base Slab At the base of the cylinder, radial expansion from internal pressure is considered compatible with the stiffness of the base slab. In this region, the cylinder undergoes a transition from a very small radial displacement at the base slab to full membrane displacement a short distance up from the base slab. This displacement results in longitudinal curvature in the cylinder.
A system consisting of structural steel wide flange beams, embedded in the bottom 20 feet of the concrete cylinder wall and keyed into the base slab, as shown in Figure 3.8-14, provides radial shear strength. These structural steel beams are located continuously around the circumference of the cylinder and provide bending and shear strength adequate to ensure the integrity of the wall in the transition region. 3.8.1.4.5 Base Slab The containment base slab is evaluated by performing static analysis of the model shown in Figure 3.8-43. The model is divided into discrete segments represented by beam elements in the two horizontal directions, which simulate the two way action of the base slab. The interconnecting nodal points are supported by horizontal and vertical springs which represent the properties of the underlying foundation rock. The horizontal and vertical stiffness of the containment shell, crane wall, and the reactor cavity are also represented by beams in the respective directions. The base slab model is analyzed for load combinations pertaining to the containment exterior structure as described in Sections 3.8.1.3.2.1 and 3.8.1.3.2.2.
The seismic loads resulting from the containment and the interior structures are applied at the appropriate nodal points. When these loads cause tension at the supports, the springs are released and an iterative analysis is performed until equilibrium is achieved. The results of the analyses are shown in Table 3.8-4, along with the corresponding allowable values.
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-20 Revision 21 September 2013 3.8.1.4.6 Internal Structure 3.8.1.4.6.1 Concrete Structure The principal structural features and design methods of the containment internal concrete structure are as follows:
The operating deck at elevation 140 feet is supported by the 3-foot-thick, 106-foot-OD circular crane wall, 4-foot-thick fuel transfer canal walls, and structural steel columns placed on the periphery next to the containment wall. The slab within the circular crane wall is, in general, 3 feet thick. Because of irregular shape, it is represented by approximate models with negative moments based on clamped edges and positive moments based on hinged edges. Because of large openings, it was necessary to thicken parts of the slab to 7 feet, and these parts are treated as beams spanning between the circular crane wall and fuel transfer canal walls. Outside the circular crane wall the operating deck consists of a 1-foot 6-inch-thick concrete slab supported on the circular crane wall and on steel beams on the periphery; steel grating is placed over steel beams. Lateral forces are transmitted to the circular crane wall through diaphragm action of concrete slabs. The circular crane wall provides support for the operating floor at elevation 140 feet and also acts as a primary system transmitting lateral loads into the base. 3.8.1.4.6.2 Annulus Structure The principal structural features and design methods of the annulus structure are: The structure consists of four main framing levels at elevations 140, 117, 106, and 101 feet. This framing system is located between the circular crane wall and the containment exterior shell. The operating deck at elevation 140 feet consists mainly of a 1-foot 6-inch-thick concrete slab supported on the circular crane wall and on steel beams by columns on the periphery near the exterior containment shell. Portions of the floor consist of steel grating supported on steel beams.
The framing system is anchored to the crane wall which provides all lateral support; lateral forces are transmitted to the circular crane wall through diaphragm action of the concrete slab at elevation 140 feet, and by structural framing system at other floor elevations. Vertical support is provided by the crane wall around the inner perimeter and by the concrete base slab at elevation 90.5 feet around the outer perimeter of the annulus. The annulus framing system is not attached to the exterior shell of the containment.
The annulus structure is modeled into a three-dimensional computer model and is analyzed by the BSAP computer program for Unit 1 and the GT STRUDL and SAP2000 computer programs for Unit 2, using a method of equivalent static loads to represent seismic forces. Stresses in internal structure of containment building, including selected structural steel elements in the annulus framing system, are listed in Table 3.8-5. DCPP UNITS 1 & 2 FSAR UPDATE 3.8-21 Revision 21 September 2013 3.8.1.4.7 Polar Crane The polar crane is analyzed using a conventional frame analysis technique. The seismic analysis is described under Section 3.7. 3.8.1.4.8 Computer Programs The main computer programs used for static and dynamic analyses of containment structure are listed in Table 3.8-6. The table also describes the general function of the programs and their respective verification measures. 3.8.1.5 Structural Acceptance Criteria The structural acceptance criteria for the containment structure exterior shell and internal structure are as follows: 3.8.1.5.1 Operating Conditions For operating conditions, the containment structure is designed for the allowable stresses of the applicable code such as ACI 318-63, AISC Specification for the Design, Fabrication, and Erection of Structural Steel for Buildings, and ASME Boiler and Pressure Vessel Code, except that the increase in allowable stress or decrease in load factor usually allowed for load combinations involving earthquake or wind forces is not used. 3.8.1.5.2 Accident Conditions For accident conditions, the containment structure is designed for overall elastic behavior under all load combinations, except at the juncture of containment exterior wall and base slab where inelastic analysis was performed by taking into consideration cracking of concrete under tension.
For structural elements designed by strength method, the yield stress of the material is reduced by factors, which are determined as follows: Exterior shell reinforcing, structural steel embedded in exterior shell, and liner plate = 0.95 Other structural steel = 0.90(a) Reinforced concrete in base slab and factor in accordance internal structure with ACI 318-63 (a) See footnote in discussion of loading combinations in Section 3.8.2. DCPP UNITS 1 & 2 FSAR UPDATE 3.8-22 Revision 21 September 2013 The yield strength values of material under a non-Hosgri event are governed by the following codes: Reinforced concrete ACI 318-63
Structural steel AISC
Hexagonal collars of equipment ASME Sect. III, Div. 2, and and personnel hatches ASME Sect. III, Div. 1
Penetration sleeves ASME Sect. III, Div. 1
Liner plate Table CC-3720-1(b) ASME Sect. III, Div. 2 The yield strength of steel and the ultimate strength of concrete for the HE are taken as the average values of properly substantiated test results. However, in no case are the yield values used in strength computations of structural steel greater than 70 percent of the corresponding average ultimate strength values determined by the tests. The factors described above are still applicable in the HE. The average strength values for concrete are shown in Table 3.8-6A. The minimum and average yield and ultimate strength values for reinforcing and structural steel are shown in Table 3.8-6B.
For structural steel and concrete elements designed by normal working strength method, the allowable stresses determined by AISC and ACI 318-63 codes, respectively, are increased by 1.6 for the DDE and 1.7 for the HE, except for shear in structural steel which is determined by the Von Mises criterion as outlined in the commentary of AISC. 3.8.1.5.3 Factors of Safety The factors of safety for the exterior shell and internal structure of the containment structure are at least as great as indicated by the load factors given in Section 3.8.1.3.2. The calculated stresses for the exterior shell are given in Figures 3.8-37 through 3.8-39, and the calculated stresses for the internal structure are given in Table 3.8-5.
Separations between the containment structure and the auxiliary building are adequate to ensure these structures will not impact each other when subject to design load combinations. Calculated displacements, separations, and factors of safety against impact are shown in Table 3.8-5B.
The relative seismic displacements between the containment structure exterior shell and the internal structure have been calculated as the sum of the maximum seismic displacement of each structure. Except for a few localized areas, the minimum cold gap (b) Table CC-3720-1 is referred to establish acceptable design strain levels for the liner plate. The construction of the liner plate is pursuant to the specifications of Section 3.8.1.2.1(7). DCPP UNITS 1 & 2 FSAR UPDATE 3.8-23 Revision 21 September 2013 between the internal structure and the exterior shell is 2 inches. The factors of safety against contact for all areas, including the localized areas, are greater than 2.33 for the governing seismic event, the DDE, after thermal effects on the gap are considered. The calculated factors of safety for the HE are greater than those for the DDE. 3.8.1.6 Materials, Quality Control, and Special Construction Techniques During the first 16 months of construction, a PG&E civil engineer was assigned to the construction site on a full-time basis. This engineer was familiar with, and had participated in, the design of the containment structure. For the period he was on site, he was part of the Quality Assurance Department (described in Chapter 17) and his responsibilities included performing audits on the various construction quality assurance programs. This engineer was qualified as ANSI Level II for radiographic, magnetic particle, ultrasonic, and dye penetrant methods of nondestructive testing. In addition, other engineers from PG&E who were involved in the design of the containment structure maintained daily contact with the site by telephone calls, and made periodic visits to the site during construction.
Inspectors from PG&E's engineering staff performed regularly scheduled shop inspections on materials and components for the containment structure.
PG&E's construction staff provided a complete staff of resident engineers, field engineers, quality control engineers, and inspectors for supervision and inspection of construction operations at the site. Their responsibilities for quality control of the containment structure were as follows:
(1) To inspect materials delivered to the jobsite and examine supplier's certified test reports of physical and chemical properties (2) To inspect handling and placing of concrete, reinforcing bars, embedded items, and forms (3) To maintain an adequate force of qualified supervisory personnel at all times (4) To maintain qualified personnel, as a part of its field engineering force, to perform a thorough inspection of each significant construction operation (5) To supervise and be fully responsible for the quality of work performed by contractors (6) To maintain records of inspections that were performed Many of PG&E's construction personnel at the site attended a formal course of instruction in radiographic, magnetic particle, ultrasonic, and dye penetrant methods of DCPP UNITS 1 & 2 FSAR UPDATE 3.8-24 Revision 21 September 2013 nondestructive testing. PG&E technicians staffed the onsite materials laboratory where tests on cement, aggregate, concrete, and reinforcing steel were performed.
3.8.1.6.1 Concrete Concrete is a dense, durable mixture of sound aggregate, cement, water, and such admixtures as may be found advantageous. The concrete design strengths used in the containment structure are: Exterior Shell 3,000 psi Base Slab 5,000 psi Internal Structures 5,000 psi The concrete compressive strength and the modulus of elasticity values used in the analysis for load combinations, including the HE, are given in Table 3.8-6A.
Concrete construction meets, as a minimum, the requirements of ACI 318-63, Building Code Requirements for Reinforced Concrete.
(1) Cement Cement is clean, fresh, Type II, low alkali, moderate heat, Portland cement conforming to the specifications of ASTM C 150, except that the PG&E specification is more stringent in requiring that the compressive strengths for any mill-run or bin be not less than 1,700 psi at 3 days, 2,700 psi at 7 days, and 4,000 psi at 28 days, and that the loss on ignition be less than 2 percent. In addition, the following Optional Chemical Requirements of ASTM C 150 are required by PG&E specification: (a) Total alkalis of the cement, calculated as the percent of Na2O + 0.658 times the percent of K2O, is limited to 0.60 percent. (b) The sum of tricalcium silicate and tricalcium aluminate is limited to 58 percent. During manufacture, samples of cement were taken once each shift, or at the rate of one sample for every 2,000 barrels. After the quality history was established, in accordance with Section 5 of the Federal Test Method Standard Number 158a, testing was performed at the reduced testing rate specified in that standard. A report of the tests made on each sample was sent to PG&E engineering research staff. In addition, each shipment of cement was accompanied by a mill certificate, and a report of the average of all the individual tests was sent with the initial delivery from each new lot or grind. Cement shipped to the batch plant was not placed in a plant bin unless it had been accepted by PG&E. In addition to the tests the cement DCPP UNITS 1 & 2 FSAR UPDATE 3.8-25 Revision 21 September 2013 manufacturer performed, PG&E made the following tests on each new lot to ensure conformance with ASTM C 150: - ASTM C 109: Compressive Strength of Hydraulic Cement Mortars (using 2-inch cube specimens) - ASTM C 114: Chemical Analysis of Hydraulic Cement - ASTM C 151: Autoclave Expansion of Portland Cement - ASTM C 191: Time of Setting of Hydraulic Cement by Vicat Needle - ASTM C 204: Fineness of Portland Cement by Air Permeability Apparatus The tests prescribed in ASTM C 114 were also performed periodically during storage to check for any effect on cement characteristics. These tests supplemented visual inspection during storage. (2) Aggregates Aggregates consist of inert materials that are clean, hard, durable, free from organic matter, not coated with clay or dirt, and conforming to ASTM Designation C 33, Standard Specification for Concrete Aggregates. In addition to the requirements of ASTM C 33, the PG&E specification requires that:
(a) Sodium Sulfate Test for Soundness (ASTM C 88). For fine aggregate, the portion retained on a Number 50 screen, be limited to a weighted average loss of no more than 8 percent after 5 cycles. For coarse aggregate, the weighted average loss after 5 cycles be no more than 10 percent (b) Sand Equivalent Test (California Division of Highways Test Method Number California 217). Sand equivalent value be at least 75 (c) The fineness modulus be within the limits of 2.6 to 2.9
(d) Los Angeles Rattler Test (ASTM C 131) for coarse aggregate. Loss by weight using Grading A, be a maximum of 10 percent by weight at 100 revolutions and 40 percent by weight at 500 revolutions DCPP UNITS 1 & 2 FSAR UPDATE 3.8-26 Revision 21 September 2013 (e) Cleanness Value (California Division of Highways Test Method Number California 227-B) for coarse aggregate. Cleanness value be at least 75 (f) Specific Gravity (ASTM C 127) for coarse aggregate. Specific gravity on a saturated surface dry basis be at least 2.60 (g) The chloride content of aggregate be no more than 440 ppm The following tests were performed by the aggregate supplier at the frequency indicated: Test ASTM Destination Frequency Screen Analysis and Fineness Modulus C 136 B Clay Lumps and Friable Particles C 142 D Minus 200 Mesh C 117 D Organic Impurities C 40 D Soft Particles C 235 D Lightweight Particles C 123 D Specific Gravity C 127 & 128 C Absorption C 127 & 128 C Unit Weight C 29 C Los Angeles Abrasion (coarse) C 131 E Soundness C 88 E Effect of Organic Impurities on Fine Aggregate C 87 F Petrographic C 295 F Sand Equivalent Test California Test Method 217 A Cleanness Value California Test Method 227-B C DCPP UNITS 1 & 2 FSAR UPDATE 3.8-27 Revision 21 September 2013 Frequency: (a) Once each 100 tons, but not more than 10, nor less than one per day of production (b) Once each 2,000 tons, but not less than one test per week during production (c) Every 10,000 tons, or once every 10 days of production
(d) Every 20,000 tons, or once every 20 days of production
(e) Once for initial source approval, then once per 30,000 tons
(f) One per deposit All tests except the Soundness Test (ASTM C 88) and Soft Particles (ASTM C 235) were also performed by PG&E on a periodic basis. Samples were taken at the place where the aggregate entered the batch bin. (3) Admixtures Admixtures conformed to the following ASTM standards: (a) Pozzolan ASTM C 618 (b) Air Entraining Agent ASTM C 260 (c) Water Reducing Agent ASTM C 494 1.1.1, Type A A certificate of compliance accompanied each load of admixture delivered to the construction site. (4) Water Water is clean and free from deleterious amounts of silt, oil, acids, alkali, salts, and organic substances. Chlorides, calculated as Cl, are limited to 1,000 ppm, and sulfates, calculated as SO4, are limited to 1,000 ppm. (5) Concrete Mixing, Placing, and Testing The contractor was required to submit concrete mix designs meeting PG&E specification requirements. The mixes were designed in accordance with Method 2, Section 308, of ACI 301. PG&E's material DCPP UNITS 1 & 2 FSAR UPDATE 3.8-28 Revision 21 September 2013 testing laboratory made sample batches of the proposed mixes and tested them according to: (a) ASTM C 192, Making and Curing Concrete Test Specimens in the Laboratory (b) ASTM C 39, Compressive Strength of Molded Concrete Cylinders
(c) ASTM C 143, Slump of Portland Cement Concrete by the Pressure Method For each design mix, 7-day and 28-day compressive strength tests were made on 6 x 12 inch cylindrical samples in the laboratory.
The contractor was required to submit lift drawings, which showed the location of all construction joints and embedded items, for approval by PG&E. The lift drawings were approved prior to concrete placement. At construction joints in all structural concrete, the surface of the hardened concrete was roughened to expose the coarse aggregate by either bush hammering, wet sandblasting, or cutting with an air-water jet. Prior to placing the next lift of concrete, the surface of the hardened, cleaned concrete was wetted and given a 1/2-inch coat of bonding mortar on all horizontal joints. The bonding mortar had the same sand-cement ratio as the concrete mix, and had a water-cement ratio such as to make a thick slurry but, at most, no greater than that for the concrete. Vertical joints in walls were provided with shear keys. Vertical joints were staggered by at least 6 inches. The concrete was batched and mixed in an automatic batching and mixing plant located at the construction site. Approved concrete mixes were punched on cards, and the appropriate card was inserted into the control console to initiate batching. The console automatically printed out the quantities of each material in the batch, and the time, date, batch number, and mix identification for each batch. Prior to plant startup, all weighing equipment was certified. This equipment was periodically checked to ensure continuing accuracy.
A full-time PG&E inspector checked the batching and mixing operation. The maximum temperature of concrete at placement was as follows: (1) 55°F, base slab
(2) 70°F, internal structure and exterior shell The concrete was placed within 45 minutes after introduction of water to the mix.
Concrete placement was inspected by PG&E inspectors. The concrete was either maintained in a moist condition for 7 days by approved methods, or coated with an approved curing compound. DCPP UNITS 1 & 2 FSAR UPDATE 3.8-29 Revision 21 September 2013 Concrete was sampled at the frequency required by ACI 301-66. Sampling concrete and making, curing, and testing specimens was in accordance with: (1) ACTM C 172 Sampling Fresh Concrete (2) ASTM C 31 Making and Curing Concrete Compressive and Flexural Strength Test Specimens in the Field (3) ASTM C 39 Compressive Strength of Molded Concrete Cylinders (4) ASTM C 143 Slump of Portland Cement Concrete (5) ASTM C 231 Air Content of Freshly Mixed Concrete by the Pressure Method All taking and testing of concrete samples was done by qualified PG&E personnel.
Compressive strength tests were evaluated in accordance with ACI 214. PG&E specifications required that 95 percent of all cylinders tested meet or exceed the specified strength for 5000 psi concrete, and 90 percent meet or exceed the specified strength for 3000 psi concrete. The correlation between field specimens and design strengths was evaluated continuously during construction.
The average strengths and coefficients of variations of concrete tested were: Design, Cement(a), Average Coefficient Number Mix psi sacks/yd Strength, psi of Variation of Tests Unit 1 7AP 5000 7.5 6500 4.3% 11 8 5000 7.5 6400 6.5% 134 8A 5000 7.0 6220 8.3% 18 8AP 5000 6.6 6120 6.4% 43 9BP 3000 6.0 3800 7.0% 87 Unit 2 8A 5000 7.0 6680 6.7% 40 8AP 5000 6.6 6200 7.1% 101 These coefficients of variation represent "excellent control" as defined in Table 2 of ACI 214-65.
Concrete in Unit 1 and 2 containments is Class AP for base slab and interior concrete and Class BP for cylinder and dome. Mixes designated 7AP, 8, 8A, and 8AP are Class AP. Mix 9BP is Class BP.
(a) Cement and pozzolan DCPP UNITS 1 & 2 FSAR UPDATE 3.8-30 Revision 21 September 2013 3.8.1.6.2 Reinforcing Steel Reinforcing steel is deformed billet-steel bar conforming to ASTM Designation A 615.
All reinforcing bars in the containment structure are Grade 60, except for the following, which are Grade 40:
(1) Liner anchorages in the base slab
(2) Anchorages on the structural steel beams embedded at the base of the containment structure wall Table 3.8-1 compares the program for testing of reinforcing bars at the DCPP to the requirements of RG 1.15, which was issued after construction at DCPP was partially complete. Table 3.8-1 also indicates those areas where the PG&E specification is more stringent than ASTM A 615.
Heat number identification was maintained on reinforcing steel from the start of manufacture through placement in the structure.
Physical and chemical test results were sent to the construction site with the first load of steel from each heat. Test values were checked by PG&E inspectors or quality control engineers.
Detailing was in accordance with ACI Standard 315-65, Manual of Standard Practice for Detailing Reinforced Concrete Structures. Bars to be bent were cold bent around pins of the following minimum diameters: (1) Stirrups and ties - four times the bar diameter
(2) Number 8 bars or smaller - six times the bar diameter
(3) Numbers 9, 10, and 11 - eight times the bar diameter
(4) Numbers 14 and 18 - ten times the bar diameter Fabrication tolerances were as follows:
(1) Cut length:
Number 14 and 18 bars 0 inch, -3/8 inch All other bars +/-1 inch (2) Depth of truss bars: Number 18 bars +/-2 inch All other bars 0 inch, -1/2 inch DCPP UNITS 1 & 2 FSAR UPDATE 3.8-31 Revision 21 September 2013 (3) Stirrups, ties, and spirals: +/-1/2 inch (4) All other bends: Number 14 and 18 bars +/-1/2 inch All other bars +/-1 inch Placement tolerances were as follows:
(1) Concrete cover to formed surfaces: Number 14 and 18 bars 1/2 inch, +2 inch All other bars +/-1/2 inch (2) Longitudinal location of bends: Number 14 and 18 bars +/-2 inch All other bars +/-1 inch (3) Depth of bars in slabs: 8 inches or less in thickness +/-1/4 inch Over 8 inches in thickness +/-1/2 inch (4) Lateral location in the plane of reinforcing: +/-2 inch Occasionally, reinforcing steel bars had to be moved to avoid interferences. In this situation, a bar could be moved, within the plane of the reinforcing layer or curtain, up to one-half the specified spacing. If this was not sufficient, the resulting arrangement was submitted to PG&E for approval. Also, if the bar had to be moved out of the reinforcing layer or curtain to avoid an interference by more than one bar diameter or the above tolerances, whichever was greater, the resulting arrangement was submitted to PG&E for approval.
Tack welding to reinforcing bars was not permitted. Reinforcing steel placement was inspected by contractor quality control inspectors and by PG&E inspectors.
The average and minimum properties of the tested Number 18 bars in the containment structure were as follows (these values are also shown in Table 3.8-6B):
(1) Yield - minimum 61,750 psi - average 66,854 psi
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-32 Revision 21 September 2013 (2) Tensile - minimum 93,750 psi - average 105,992 psi (3) Elongation - minimum 7.0% - average 9.4% 3.8.1.6.3 Splices (1) Cadweld Splices Cadweld splices were used at all locations for primary reinforcing in the exterior shell and base slab. Cadweld splices were used in a few locations in the internal structure. Quality control procedures for Cadweld splices are described in Table 3.8-2 that compares the program used at the DCPP to that required by SG 10. SG 10 was issued after construction at DCPP was partially complete. The average and minimum strengths of tested Cadweld tensile samples were: (a) Minimum tensile strength 85,000 psi (b) Average tensile strength 97,725 psi (c) Number of tests 641 (d) Number of Cadwelds placed 19,068 (2) Butt-welded Splices Butt-welded splices were used in a few locations where there was insufficient room to properly mount the Cadweld crucible. The quality control measures applied are the same as those described in Section 3.8.2.6.3 for butt-welded splices. (3) Lap Splices Lap splices are in accordance with ACI 318-63. 3.8.1.6.4 Liner, Penetration Sleeves, and Penetration Internals The containment structure liner is carbon steel, conforming to ASTM A 516, Carbon Steel Plates for Pressure Vessels for Moderate and Lower Temperature Service, Grade 70. This steel has a minimum yield strength of 38,000 psi, a minimum tensile DCPP UNITS 1 & 2 FSAR UPDATE 3.8-33 Revision 21 September 2013 strength of 70,000 psi, and a minimum elongation of 17 percent in an 8-gage length at failure. Charpy V-notch impact tests were performed at +20°F, in accordance with ASTM A 370.
Penetration sleeves conform to one of the following three material specifications:
(1) ASTM A 106, Seamless Carbon Steel Pipe for High Temperature Service, Grade B, with the additional requirement that Charpy V-notch impact tests be performed at 0°F (2) ASTM A 333, Seamless and Welded Steel Pipe for Low Temperature Service, Grade 1, except that Charpy V-notch impact tests are performed at 0°F (3) ASTM A 516, Carbon Steel Plates for Pressure Vessels for Moderate and Lower Temperature Service, Grade 70, to ASTM A 300, except that Charpy V-notch impact tests were performed at 0°F For all three material specifications, the Charpy impact tests were in accordance with the requirements of Paragraph N-330 of ASME Section III, 1968 edition.
Penetration internals conform to the following material specifications:
(1) Equipment and personnel hatches are ASME SA 516, Grade 70, to SA 300 with Charpy impact values at 0°F, in accordance with paragraph N-330 of ASME Section III, 1968 edition (2) Carbon steel flued heads are ASME SA 105, Grade II, with Charpy impact tests at 0°F, in accordance with paragraph NB-2300 of Section III, ASME B&PV Code, 1971 edition. Ultrasonic and magnetic particle inspections are performed in accordance with Paragraphs NB 2542 and NB 2545, respectively (3) Stainless steel flued heads are ASME SA 182, Grade F 304. Ultrasonic and liquid penetrant inspections are performed in accordance with Paragraphs NB 2542 and NB 2546, respectively Welded studs attached to the liner meet the requirements of ASTM A 108, Grade 1015-1018.
The Charpy impact test temperatures stated in the paragraphs above were selected to be at least 30°F below the lowest service temperature in accordance with the ASME B&PV Code, Section III, 1968 Edition for Class B (containment) vessels. For future repair, replacement, or alteration of ferritic containment pressure boundary material, the notch toughness test requirements of Section III, NE-2300 will be used in lieu of the original requirements. Charpy impact tests will be performed at or below the DCPP UNITS 1 & 2 FSAR UPDATE 3.8-34 Revision 21 September 2013 lowest service temperature and material 5/8 inch or less in thickness will be exempt from notch toughness testing. Further information on notch toughness testing of containment materials appears in Section 3.1.8.14.
Mill test reports certifying the physical and chemical properties of the liner plate delivered to the jobsite were required from the steel supplier. The average and minimum properties of liner plate are as follows:
The Charpy impact test temperature for the hexagonal collars was selected to be at least 30°F below the lowest service temperature in accordance with the ASME B&PV Code, Section III, 1968 Edition for Class B (containment) vessels. For future repair, replacement, or alteration of the hexagonal collars, the notch toughness test requirements of Section III, NE-2300 will be used in lieu of the original requirements. Charpy impact tests will be performed at or below the lowest service temperature and material 5/8 inch or less in thickness will be exempt from notch toughness testing. Further information on notch toughness testing of containment testing materials appears in Section 3.1.8.14. Reactor Pit and Floor Plates Unit 1 Unit 2 Yield Strength - minimum 43,800 psi 39,800 psi
- average 51,400 psi 55,100 psi Tensile Strength - minimum 71,000 psi 74,000 psi - average 76,500 psi 78,900 psi Elongation - minimum 19% 17% - average 25% 24%
Total number of heats 16 11 Total number of slabs 58 62 Total number of tests 58 62 Cylinder and Dome Unit 1 Unit 2 Yield Strength - minimum 41,900 psi 38,100 psi
- average 48,800 psi 46,100 psi Tensile Strength - minimum 70,200 psi 70,100 psi - average 74,900 psi 73,681 psi Elongation - minimum 19% 18% - average 26.5% 25.4%
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-35 Revision 21 September 2013 Cylinder and Dome Unit 1 Unit 2 Total number of heats 23 22 Total number of slabs 251 255 Total number of tests 251 255 Fabrication of the containment structure liner conforms to the applicable parts of Part UW, Requirements for Unfired Pressure Vessels Fabricated by Welding, Section VIII, ASME Boiler and Pressure Vessel Code.
All of the welds were visually examined by contractor quality control inspectors. All field welds were also visually examined by PG&E inspectors.
Table 3.8-3 compares the program for nondestructive testing of containment structure liner welds, including penetration sleeves and inserts, used on the DCPP to that required by SG 19, which was issued after construction at DCPP was partially complete.
Erection tolerances for the liner were as follows:
The liner of the completed structure shall be substantially round. At points not more than 4 inches above the base, the radius of the 3/4-inch liner shall be 69 feet 11-13/16 inches plus or minus 1/2-inch. The maximum diameter of the 3/8-inch liner shall not exceed 140 feet 4 inches and the minimum diameter shall not be less than 139 feet 8 inches. The liner shall be erected true and plumb. At any point the out-of-plumb shall not exceed 1/240 of the height of the point above the base. For any plate (10 feet +/- in height), the out-of-plumpness shall not exceed 1/120.
Flat spots or local out-of-roundness shall not exceed 2 inches in 15 feet of arc.
The base liner shall not deviate from a plane surface between anchorages by more than 1/240.
Stud welding was in accordance with the Supplement to AWS Specification D1.0-66. The tolerance of the location of each stud was +/- 1/2-inch. At the beginning of each work day, each welder attached at least two test studs that were then tested by bending the stud approximately 45 percent toward the plate to demonstrate the integrity of the stud-to-plate weld. If failure occurred in the weld, the welding procedure or technique was corrected and two successive studs successfully welded and tested before further studs were attached to the liner plate. These test studs were allowed to remain in place but are not considered as a part of the regular stud pattern required by the design. A 100 percent visual inspection of liner and stud anchors was made prior to pouring concrete. DCPP UNITS 1 & 2 FSAR UPDATE 3.8-36 Revision 21 September 2013 3.8.1.6.5 Structural Steel Hexagonal collars at the equipment hatch and personnel hatch meet the requirements of ASTM A 516, Grade 70, and ASTM A 300, except that Charpy V-notch impact tests were performed at 20°F. The following quality control procedures were followed in the fabrication of the hexagonal steel collars at the equipment hatch and personnel hatch openings:
(1) The 4-inch-thick plate for the edge pieces was ultrasonically examined in accordance with ASTM A 435, except that scanning covered 100 percent of the surface.
(2) Fabrication conformed to the applicable parts of Part UW, Requirements for Unfired Pressure Vessels Fabricated by Welding, of Section VIII of the ASME Boiler and Pressure Vessel Code. All welds are full penetration butt welds and were 100 percent radiographed in accordance with Paragraph UW-51. (3) The reinforcement plates were heat treated after fabrication in accordance with Paragraph UCS-56, Requirements for Postweld Heat Treatment, of Section VIII of the ASME Boiler and Pressure Vessel Code. 3.8.1.7 Testing and Inservice Surveillance Requirements After each containment structure was complete, with liner, concrete, and all electrical and piping penetrations, equipment hatch and personnel locks in place, tests were performed as discussed in the following sections. 3.8.1.7.1 Structural Integrity Test The structural integrity test was performed by pressurizing the containment structure with air up to 115 percent of design pressure, or 54 psig. During this test, structural deflections were measured, crack patterns in the concrete were measured and photographed, and strains in the liner and reinforcing steel measured electrically and recorded. The deflections, crack patterns, and strains were compared to the theoretical predictions to verify the structural integrity of the containment structure. The structural integrity test of each containment structure meets the requirements of RG 1.18, Structural Acceptance Test for Concrete Primary Reactor Containments.
The Unit 1 containment structure is a prototype concrete primary reactor containment, as defined in RG 1.18.
For the structural integrity test, the pressure was increased in increments to the maximum of 54 psig. Measurements were made at 0, 15, 25, 35, 47, and 54 psig during pressurization and again during depressurization. At each pressure level, the DCPP UNITS 1 & 2 FSAR UPDATE 3.8-37 Revision 21 September 2013 deflection and strain gage readings were made after a 1-hour wait to allow adjustment of strains. The crack patterns were recorded both before and immediately after the test and at the maximum pressure level achieved during the test.
The instrumentation for Unit 1 was as follows:
The radial and vertical growth was measured by means of calibrated targets attached to the exterior shell and sighted by means of high magnification theodolites. Radial deflections were measured at three points on each of six equally spaced meridians: at the springline, at mid-height of the cylinder, and at the top of the base slab. Vertical deflections were measured at the springline and at the top of the dome.
The radial and tangential deflections of the containment structure wall were measured at twelve locations adjacent to the equipment hatch, which is the largest opening.
The pattern of cracks that exceed 0.01-inch in width were mapped or photographed near the base-wall intersection, at mid-height of the wall, at the springline of the dome, and around the equipment hatch. At each location, an area of at least 40 square feet was mapped or photographed.
Strain measurements were made at the following locations, in accordance with the requirements for prototype containment structures:
(1) In the wall at the top of the base mat
(2) In the wall at the equipment hatch, with one gauge located approximately 0.5 times the wall thickness from the edge of the opening (3) In the wall at the level of the springline
(4) In the wall where pure membrane stress is anticipated, i.e., where there are no discontinuities Inasmuch as the concrete is assumed cracked, and the strength of the concrete is neglected, strain measurements were made on the reinforcing steel and liner, rather than in the concrete. At the equipment hatch, additional strain measurements were made on the structural steel hexagonal collar. In the wall at the top of the base slab, additional strain measurements were made on the structural steel wide flange beams.
The method used for attaching strain gauges to Number 18 reinforcing bars is shown in Figure 3.8-44.
In evaluating the results of the structural integrity test, the deflection measurements were considered the most reliable result.
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-38 Revision 21 September 2013 Strains, deflections, and crack patterns were compared to the theoretical predictions. The acceptance criterion was that actual readings had to be within 20 percent of the predicted values. This criterion was based on an evaluation of:
(1) Residual stress due to concrete shrinkage
(2) Measurement errors (3) Temperature variations (4) As-built deviations of the containment shell from a circular shape (5) Actual results of other structural integrity tests (primarily at the R. E. Ginna plant) The deflection measurement and crack mapping program for Unit 2 was identical to that for Unit 1. 3.8.1.7.2 Overall Integrated Leakage Rate Tests During the depressurization phase of the structural integrity test, the sequence was stopped at 47 psig to conduct an overall integrated leakage rate test at design pressure.
During the overall integrated leakage rate tests, the double penetration and weld seam leak chase channel zones were open to the atmosphere inside the containment structure. All leakage rate tests are conducted and evaluated in accordance with Appendix J of 10 CFR 50, Option B, as modified by approved exemptions. 3.8.1.7.3 Sensitive Leakage Rate Tests A sensitive leakage rate test can be performed at some future date with only the volume of the weld seam leak chase channels and double penetrations included in the test. A sensitive leakage rate test would be performed with penetrations and leak chase channels at not less than the peak calculated containment internal pressure (Pa), and with the containment structure at atmospheric pressure. 3.8.1.7.4 Inservice Surveillance Requirements Periodic leakage rate testing is performed in accordance with the requirements of Appendix J of 10 CFR 50. Inservice surveillance to ensure continued containment integrity is discussed in Section 6.2.1.4. Instrumentation employed to monitor containment status is described in Section 6.2.1.5.
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-39 Revision 21 September 2013 3.8.2 OTHER DESIGN CLASS I STRUCTURES (AUXILIARY BUILDING) 3.8.2.1 Description of the Auxiliary Building The auxiliary building is located between the Unit 1 and Unit 2 containment structures. It contains the control room that includes consoles and a fuel handling area for each unit. In addition, the auxiliary building contains equipment for the chemical and volume control systems, the safety injection systems, the residual heat removal systems, the component cooling water systems, the liquid radwaste systems, the gaseous radwaste system, and others.
The main floor levels in the auxiliary building are at elevations 85, 100, 115, and 140 feet. Elevations 60 and 73 feet are below ground level, which is at elevation 85 feet, except for the east side of the building where ground level is at elevation 115 feet. Floor plans at elevations 100, 115, and 140 feet are shown in Figures 3.8-60, 61, and 62.
The foundation of the auxiliary building is divided between 3 elevations. The structure is supported at elevations 85 feet (areas GE, GW, and L) 100 feet (area J), and elevation 60 feet (areas H and K).
Figure 1.2-2, Plant Layout, shows relative locations of the plant buildings. The general arrangement of equipment in the auxiliary building, including the fuel handling areas, is shown in Figures 1.2-4 through 1.2-11, Figures 1.2-21 through 1.2-26, and Figures 1.2-29 and 1.2-30. Generally, one-half of the auxiliary building is a mirror image of the other, with each half of the structure containing equipment for one unit. The control room is located at elevation 140 feet. The two fuel handling areas that contain the spent fuel pools, the fuel handling cranes, fuel racks, and related equipment are located on each side of the east end of the auxiliary building with the top of the spent fuel pools at elevation 140 feet.
The auxiliary building is a reinforced concrete shear wall structure, except for the fuel handling area crane support structure which is a structural steel moment resisting and braced frame structure supported on elevation 140 feet and extending up to elevation 188 feet. The shear walls and slabs of the auxiliary building are generally 2 feet thick. The walls of the spent fuel pools are 6 feet thick except for local areas around the fuel transfer tubes. The foundation slabs under the spent fuel pools have a minimum thickness of 5 feet. The spent fuel pool sides and bottoms are lined with stainless steel, 1/4-inch-thick on the bottoms and 1/8-inch nominal thickness on the sides. Representative concrete outlines, reinforcing steel arrangements, and structural steel details for the auxiliary building are shown in Figures 3.8-45 through 3.8-59.
The 125-ton overhead crane in the fuel handling area, shown in Figure 3.8-59, is equipped with restraints that prevent derailing from motions associated with an earthquake.
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-40 Revision 21 September 2013 The only connections between the auxiliary building and other structures are the fuel transfer tube and miscellaneous piping. The fuel transfer tube is fitted with expansion bellows that allow relative movement between the auxiliary building, the containment structure exterior shell, and the internal structure of the containment structure. The design of the expansion bellows considers the maximum axial and lateral relative deflection. Piping systems are analyzed for the maximum relative displacements of the auxiliary building and other structures, and the piping anchor points in the structures are designed to withstand the resulting forces. 3.8.2.2 Applicable Codes, Standards, and Specifications The following codes and standards are used in the design, construction, inspection, and testing of the auxiliary building:
(1) ACI Standard Building Code Requirements for Reinforced Concrete (ACI 318-63), except that design loading combinations are as described in Section 3.8.2.3.2 (2) Manual of Standard Practice for Detailing Reinforced Concrete Structures (ACI 315-65)
(3) Recommended Practice for Evaluation of Compression Test Results of Field Concrete (ACI 214-65) (4) Inspection of the Cadweld Rebar Splice (Erico Products, Inc., RB-5M768)
(5) Recommended Practices for Welding Reinforcing Steel, Metal Inserts, and Connections in Reinforced Concrete Construction, American Welding Society AWS D12.1-61 (6) AISC Specification for the Design, Fabrication, and Erection of Structural Steel for Buildings, February 12, 1969 (7) Code for Welding in Building Construction, AWS D1.0-69. Work performed prior to December 12, 1969 is in accordance with the earlier edition, AWS D1.0-66. For inspection of non-ASME structural welds or new non-ASME work performed after January 1, 1988, the guidelines of Nuclear Construction Issues Group (Visual Weld Acceptance Criteria, Vol. 1-3, EPRI Report No. NP-5380, September 1987) may be used except for those cases where: (a) Fatigue is a governing design condition.
(b) The weld allowables are permitted to be higher than those allowed by AWS D1.1 (such as the full penetration welds evaluation for HE). DCPP UNITS 1 & 2 FSAR UPDATE 3.8-41 Revision 21 September 2013 (c) The weld is part of work performed in the ASME Section XI Inservice Inspection Program. (8) Stud welding is in accordance with the Supplement to American Welding Society Specifications AWS D1.0-66 and AWS D2.0-66 on Requirements for Stud Welding (9) Materials and the quality control tests for materials conform to ASTM standards RG 1.15, Testing of Reinforcing Bars for Category I Concrete Structures (dated December 28, 1972), and RG 1.55, Concrete Placement in Category I Structures (dated June 1973), were issued after construction of the DCPP was nearly complete. A comparison of the program used for the DCPP with the regulatory position of RG 1.15 is presented in Table 3.8-1. The quality assurance program for the DCPP meets the requirements of RG 1.55. In regard to RG 1.55, the references used for guidance are those listed in Appendix A of the RG, as they existed at the time of the PSAR. 3.8.2.3 Loads and Loading Combinations 3.8.2.3.1 Design Loads The following loads are considered in the design of the auxiliary building. 3.8.2.3.1.1 Dead Loads Dead loads consist of the weight of the structure, and permanent equipment loads. 3.8.2.3.1.2 Live Loads Live loads consist of temporary equipment loads and a uniform load to account for the miscellaneous temporary loadings that may be placed on the structure. 3.8.2.3.1.3 Earthquake Loads Earthquake loads are based on a time-history modal superposition analysis. This analysis is described in Section 3.7.2. 3.8.2.3.1.4 Wind Loads Wind loads are determined in accordance with the criteria presented in Section 3.3. However, considering the UBC and ASCE Paper 3269 pressures, the forces due to wind are much less than those due to earthquake; consequently, seismic loads, rather than wind, are entered into the load combination equations.
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-42 Revision 21 September 2013 3.8.2.3.1.5 Thermal Loads Thermal loads are loads induced by local increases in temperature. Thermal loads result from normal operating conditions and from postulated accident conditions. 3.8.2.3.1.6 Pipe Reaction Loads Pipe reactions that result from hydraulic forces, thermal expansion, and seismic events, are transferred to the structure through pipe supports. Pipe reaction loads result from normal operating conditions and postulated accident conditions. 3.8.2.3.1.7 Jet and Missile Loads Jet and missile loads are localized forces on structures in the immediate vicinity of a postulated pipe break. Jet forces result from the impingement of high energy fluid on an object. Missile forces result when a part possessing kinetic energy strikes an object.
Missile forces are calculated by the methods described in Section 3.5. Jet forces and pipe reactions from a postulated broken pipe are calculated as described in Section 3.6. 3.8.2.3.1.8 Pressure Loads Pressure loads are forces generated by a postulated pipe break. Pressures from a postulated broken pipe are calculated as described in Section 3.6. 3.8.2.3.2 Loading Combinations 3.8.2.3.2.1 Normal Conditions Dead load, live load, loads from the DE, thermal loads, and pipe reactions are considered in all possible combinations. Inasmuch as working stress design is used for normal operating loads, the factored load approach is not used. For each structural member, the combination of these loads that produces the maximum stress is used for design. Stated in equation form:
C = D + L + DE + To + Ro (3.8-14) where:
C = required capacity of member based on the methods described in Section 3.8.2.5.1 D = dead load of structure and equipment loads L = live load DE = loads resulting from the DE To = thermal loads during normal operating conditions Ro = pipe reactions during normal operating conditions DCPP UNITS 1 & 2 FSAR UPDATE 3.8-43 Revision 21 September 2013 3.8.2.3.2.2 Abnormal Conditions Dead load, live load, earthquake loads, and loads associated with accidental pipe rupture are considered in the following combinations; for each structural member, the combination that produces the maximum stress is used for design: Concrete Structural Elements U = D + L + TA + RA + 1.5 PA (3.8-15) U = D + L + TA + RA + 1.25 PA + 1.0 (Yj + Ym + Yr) + 1.25 DE (3.8-16) U = D + L + TA + RA + 1.0 PA + 1.0 (Yj + Ym + Yr) + DDE (3.8-17) U = D + L + TA + RA + 1.0 PA + 1.0 (Yj + Ym + Yr) + HE (3.8-18) where:
TA = thermal loads on structure generated by a postulated pipe break, including TO RA = pipe reactions on structure from unbroken pipe generated by postulated pipe break conditions, including RO PA = pressure load within or across a compartment and/or building generated by a postulated pipe break, and including an appropriate dynamic factor (DLF) to account for the dynamic nature of the load Yj = jet load on structure generated by a postulated pipe break, including an appropriate DLF Ym = missile impact load on a structure generated by, or during, a postulated pipe break, such as a whipping pipe, including an appropriate DLF Yr = reaction on structure from broken pipe generated by a postulated pipe break, including an appropriate DLF U = ultimate strength required to resist design loads based on the methods described in ACI 318-63. See Section 3.8.2.5.2 for equation 3.8-16 through 3.8-18 DDE = loads resulting from the DDE HE = loads resulting from an HE DCPP UNITS 1 & 2 FSAR UPDATE 3.8-44 Revision 21 September 2013 Steel Structural Elements Where elastic working stress design methods are used(a)(b): AAbAaPRTLDS++++=)()(6.1 (3.8-19) ()DEYYYPRTLDrmjAAbAaS++++++++=0.16.1)()( (3.8-20) ()DDEYYYPRTLDrmjAAbAaS++++++++=0.16.1)()( (3.8-21) ()HEYYYPRTLDrmjAAbAS++++++++=0.10.17.1)( (3.8-22) Where plastic design methods are used: AAbAaPRTLDY5.190.0)()(++++= (3.8-23) ()DEYYYPRTLDrmaAAbAaY25.10.125.190.0)()(++++++++= (3.8-24) ()DDEYYYPRTLDrmAAbAajY++++++++=0.10.190.0)()( (3.8-25) ()HEYYYPRTLDrmjAAbAY++++++++=0.10.10.1)( (3.8-26) where:
S = required section strength based on elastic design methods and the allowable stresses(c) defined in Part 1 of the AISC "Specifications for the Fabrication and Erection of Structural Steel for Buildings," February 12, 1969 Y = required section strength based on plastic design methods(c) described in Part 2 of AISC Specifications for the Design, Fabrication and Erection of Structural Steel for Buildings, February 12, 1969 (a) For existing structures, the 1.6 factor applied to the required section strength, S, and the 0.90 reduction factor applied to the required section strength, Y, are increased to 1.7 and 1, respectively. In such situations, however, it is verified that deflections will not result in the loss of function of any safety-related system. (b) Thermal loads are neglected when it can be shown that they are secondary and self-limiting in nature and where the material is ductile. (c) See Section 3.8.2.5 regarding material properties used in conjunction with load combinations including HE. DCPP UNITS 1 & 2 FSAR UPDATE 3.8-45 Revision 21 September 2013 For both concrete and steel structural elements, both cases of L having its full value present during the postulated pipe rupture, or being completely absent, are checked. 3.8.2.4 Design and Analysis Procedures Structural analysis of the auxiliary building is performed by the traditional methods of engineering analysis for structural steel and reinforced concrete structures. These methods are based on the principles of equilibrium, compatibility of deformations, and predictions of material strength by the methods of the AISC Specifications for the Design, Fabrication, and Erection of Structural Steel for Buildings (AISC Code), and the ACI Standard Building Code Requirements for Reinforced Concrete (ACI Code).
The use of these codes is discussed in Section 3.8.2.5. The following sections discuss the specific design methods used for the structural steel and concrete parts of the auxiliary building. 3.8.2.4.1 Structural Steel The fuel handling area crane support structure is a 370 x 60 x 50-foot high steel framed structure clad with metal siding and covered by metal decking and built-up roofing. The structure is supported on concrete walls at elevation 140 feet on the eastern side of the auxiliary building. Lateral forces are resisted by steel cross-braced frames in the north-south direction, moment resisting frames in the east-west direction, and by the roof, which is a trussed and cross-braced diaphragm covered with metal decking.
Acceleration profiles and forces from the analyses described in Section 3.7.2.1.7.1 are applied to a detailed static model of the entire fuel handling area crane support structure to obtain forces for the stress evaluation of the structural members and connections and to obtain structural displacements. Various crane and lifted load positions are considered. The stress evaluation is carried out for the load combinations described in Section 3.8.2.3. Stresses are evaluated against the criteria in Section 3.8.2.5. The calculated stress ratios for the most critical members are given in Table 3.8-7. 3.8.2.4.2 Concrete The vertical and the lateral load-resisting system of the auxiliary building consists of reinforced concrete columns and walls tied together with reinforced concrete slabs. The evaluation of these elements is carried out for the loading combinations given in Section 3.8.2.3, according to the criteria in Section 3.8.2.5.
The seismic forces and moments are based on the response of the auxiliary building seismic models described in Section 3.7. A detailed analytical model of the auxiliary building is then developed to distribute forces and moments to the various walls, diaphragms, and columns.
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-46 Revision 21 September 2013 Slabs Slabs are evaluated separately for out-of-plane loads and in-plane loads.
For out-of-plane loads, shear stresses and moments are calculated assuming one-way or two-way slab action as appropriate. Out-of-plane capacity-to-demand ratios for selected slabs are shown in Tables 3.8-8 through 3.8-10. The slab in-plane capacities are investigated at critical sections. The selection of these sections is based on the location of numerous openings across the entire section of the diaphragm and the magnitudes of shear, moment, and axial forces on the entire section. The in-plane capacity-to-demand ratios for the concrete slabs are shown in Tables 3.8-11 through 3.8-13. Walls The critical wall elements are selected based on the magnitude of demand loads and presence of openings. The forces and moments for the governing load combination in those elements are compared to their respective capacities, and the capacity-to-demand ratios are shown in Tables 3.8-14 through 3.8-16. Concrete Columns The concrete columns are evaluated for axial and flexural loads. Flexural loads on columns due to the vertical loads are determined by considering frame action with the slabs. Flexural loads include the effect of minimum eccentricity specified by ACI 318-63. Column moments due to interstory drift are found to be negligible. Capacity-to-demand ratios for selected columns are shown in Table 3.8-17. 3.8.2.4.3 Load Dissipation to the Foundation The adequacy of the structural system, at and below elevation 85 feet, to dissipate lateral loads to the rock foundation is evaluated for the load combinations given in Section 3.8.2.3.2. The results, given in Tables 3.8-18 through 3.8-23, and illustrated for HE loads in Figures 3.8-63 and 3.8-64, indicate the adequacy of the system to dissipate the loads. 3.8.2.4.4 Computer Programs Computer programs used in the structural analysis, and the verification measures used, are listed in Table 3.8-6. 3.8.2.5 Structural Acceptance Criteria For DE and DDE load combinations, the nominal design strength for concrete and specified yield strength for reinforcing and structural steel are considered. For load combinations including HE, however, the actual material properties are used. See DCPP UNITS 1 & 2 FSAR UPDATE 3.8-47 Revision 21 September 2013 Sections 3.8.2.6.1, 3.8.2.6.2, and 3.8.2.6.4 for material properties associated with concrete, reinforcing steel, and structural steel, respectively. See Section 3.8.2.6.5 for allowable stresses for bolted connections. Ductility, when applied for HE load combinations, is in accordance with Table 3.8-24. 3.8.2.5.1 Normal Loads For normal loads, the auxiliary building is designed for the allowable working stresses of ACI 318-63, as supplemented by Section 3.8.2.5.3, and Part 1 of the AISC Code, except that the increase in allowable stress usually allowed for load combinations involving earthquake forces is not used. 3.8.2.5.2 Abnormal Loads For abnormal loads, the auxiliary building is designed for overall elastic behavior. For concrete elements, the strength design method of ACI 318-63 applies, as supplemented by Section 3.8.2.5.3. For the evaluation of steel elements using elastic design methods, the allowable stresses are defined in Part 1 of AISC Code. For the evaluation of steel elements using "plastic design," Part 2 of the same AISC specifications applies.
The capacity for the various concrete structural elements is based on the yield strength of the material, reduced by a factor, f, which provides for the possibility that small, adverse variations in material strengths, workmanship, dimensions, and control, while individually within required tolerances and the limits of good practice, occasionally may be additive. The f-factors used are in accordance with ACI 318-63. For load combinations involving Yj, Ym, and Yr, local stresses due to these concentrated loads may exceed the allowable provided there is no loss of function. See Reference 6, Enclosure Number 3, Document (B), for more detailed information concerning the acceptance criteria for these load combinations. 3.8.2.5.3 In-Plane Loads on Concrete Elements The design of slab diaphragms and shear walls for in-plane forces is not explicitly covered by ACI 318-63. Section 104 of ACI 318-63 allows criteria based on test data to be used for the design of elements not covered by its provisions. Consequently, the document entitled "Recommended Evaluation Criteria for Diablo Canyon Nuclear Power Plant Auxiliary Building Walls and Diaphragms" (Reference 7) is developed to provide criteria for evaluation of auxiliary building shear walls and floor diaphragms for in-plane seismic forces, including the simultaneous effects of out-of-plane forces.
Accordingly, the structural elements are evaluated as follows:
(1) The columns are evaluated by the provisions of ACI 318-63 for all loading conditions.
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-48 Revision 21 September 2013 (2) The slabs and walls are evaluated for out-of-plane loads according to ACI 318-63, and for in-plane loads according to Reference 7. 3.8.2.5.4 Factors of Safety The calculated capacity-to-demand ratio for selected structural elements of the auxiliary building are given in Tables 3.8-7 through 3.8-17. In all cases, these ratios are greater than the minimum allowable value of 1. Therefore, all structural elements satisfy the criteria.
The gap between the auxiliary building and the containment structure, as well as the factor of safety against the structure impacting during a seismic event, is discussed in Section 3.8.1.5.3. Separations between the auxiliary building and the turbine building are adequate to ensure these structures will not impact each other when subject to design load combinations. Calculated displacements, separations, and factors of safety against impact are shown in Table 3.8-23A. 3.8.2.6 Materials, Quality Control, and Special Construction Techniques Sections 3.8.1.6.1 and 3.8.1.6.2 for the containment structure also apply to the auxiliary building, except as superseded by information in the following paragraphs. 3.8.2.6.1 Concrete Concrete strengths are shown below. Walls and slabs below elevation 85 feet; slabs 4 feet and thicker at elevation 85 feet; slab at elevation 85 feet bounded by column lines 16.8 - 19.2 - L - H: Design f'c = 3000 psi (DE and DDE combinations) All other concrete: Design f'c = 5000 psi (DE and DDE combinations) Average 28-day strengths are used with HE load combinations. The average strengths of representative mixes are as follows: Design Strength Average 28-day Strength Number of Tests 3000 psi 3920 psi 167 5000 psi 5650 psi 368 DCPP UNITS 1 & 2 FSAR UPDATE 3.8-49 Revision 21 September 2013 3.8.2.6.2 Reinforcing Steel Reinforcing steel is ASTM A 615, Grade 40, except in some locations where Grade 60 is used. ASTM minimum values are used with DE and DDE load combinations. Average test values are used with HE load combinations. The average and minimum properties of representative bar sizes, are as follows:
#8 #11 Grade 40 Grade 60 Grade 40 Grade 60 Design Yield Strength, psi 40,000 60,000 40,000 60,000 Average Yield Strength, psi 49,655 66,189 48,302 68,582 Minimum Yield Strength, psi 41,200 60,250 42,950 61,710 Average Tensile Strength, psi 82,236 102,403 81,074 105,822 Minimum Tensile Strength, psi 74,392 96,500 72,940 94,390 Average Elongation, % 18.9 13.94 14.82 14.41 Minimum Elongation, % 13.0 11.0 8.5 9.4
Total Number of Heats 67 18 91 56 3.8.2.6.3 Splices The majority of splices in the auxiliary building are lap splices, made in accordance with ACI 318-63. Cadweld splices are used in some locations in the auxiliary building. The quality control procedures described for Cadweld splices in the containment structure also apply to Cadweld splices in the auxiliary building. Butt-welded splices are used where a section of wall has to be temporarily left open for access, and in certain other locations. Butt-welded splices are made in accordance with ACI 318-63, and the American Welding Society's Recommended Practices for Welding Reinforcing Steel, Metal Inserts, and Connections in Reinforced Concrete Construction, using the "short-arc" process or low hydrogen stick electrodes by the shielded arc process. Both processes have minimum preheat and interpass temperatures of 400°F. Completed welds are wrapped with a protective blanket of insulating material to avoid rapid cooling.
Procedure qualification and welder qualification are as follows:
(1) A welding procedure qualification test is made for each position and for each grade and size of bar. The test consists of two tension tests and one nick break test. Bars may not be rolled during welding.
(2) Welder qualification tests are made for each position, type of electrode, grade and size of bar, and joint design. Qualification for one size of bar is considered qualification for all smaller sizes. Each test consists of one tension and one nick break test. Bars may not be rolled during welding. DCPP UNITS 1 & 2 FSAR UPDATE 3.8-50 Revision 21 September 2013 (3) Tension specimens are tested to failure and must comply with the minimum tensile requirements for the grade of reinforcing steel. (4) The nick break specimen is broken and visually examined for soundness. The specimen must exhibit the following: the sum of the longest dimension of all inclusions visible in any one joint must not exceed 1/2-inch; no inclusion may be closer to the weld surface than a distance equal to the largest dimension of the inclusion; there must be no incomplete fusion or lack of penetration or cracks in the weld or base metal. Testing percentages applicable to butt-welded splices for each welder, position, and grade of bar are as follows:
(1) Two out of the first ten splices
(2) Six out of the next 90 splices
(3) Four out of second and subsequent 100 splice units Qualification for one size of bar is considered as qualification for all smaller sizes. 3.8.2.6.4 Structural Steel Structural steel is ASTM A 36 and ASTM A 441; ASTM minimum values are used with DE and DDE load combinations, and average test values are used with HE load combinations. Minimum and average values are as follows: ASTM A36 ASTM A441 Design Yield (ksi) 36 42
Testing of structural steel installed through 1977 gave the following:
ASTM A36 ASTM A441 Average Test Yield (ksi) 43.95 51.62 Average Test Ultimate (ksi) 68.04 75.91
Charpy impact tests were performed on all structural steel at the following temperature:
Framing for pipe rupture restraints 40°F Structural steel 20°F 3.8.2.6.5 Structural Bolts Structural bolts are ASTM A307, A325, and A490, allowable stresses per Table 1.5.2.1 of the AISC "Specifications for the Design, Fabrication and Erection of Structural Steel for Buildings," February 12, 1969, are used with the DE, DDE, and HE load DCPP UNITS 1 & 2 FSAR UPDATE 3.8-51 Revision 21 September 2013 combinations. However, it is acceptable to increase the allowable stresses for the Hosgri load combinations, based on the results of properly substantiated testing (References 34 through 38). 3.8.3 OUTDOOR WATER STORAGE TANKS 3.8.3.1 Description of the Outdoor Water Storage Tanks The Design Class I outdoor storage tanks, located adjacent to east of auxiliary building, are steel studded tanks with concrete shielding, as shown in Figure 3.8-65, sheets 1 and 2.
There are two refueling water storage tanks and two condensate water storage tanks, one to service each unit of the plant. The firewater and transfer tank, which serves both Units 1 and 2, is made up of two concentric cylindrical steel tanks connected by a common dome roof. The inner cylindrical tank is the firewater tank and the outer tank is the transfer tank. The structural configuration of the condensate tanks is similar to that of the refueling water storage tanks.
The Design Class I tanks are supported on concrete fill down to bed rock and are anchored to bed rock with rock anchors as shown in Figure 3.8-65, Sheet 2. 3.8.3.2 Applicable Codes, Standards, and Specifications The following codes and standards are used in the design, construction, inspection, and testing of the outdoor water storage tanks. (1) ACI Standard Building Code Requirements for Reinforced Concrete (ACI 318-63, and ACI 318-71) (2) Manual of Standard Practice for Detailing Reinforced Concrete Structures (ACI 315-65) (3) Recommended Practices for Welding Reinforcing Steel, Metal Inserts, and Connections in Reinforced Concrete Construction, American Welding Society AWS D12.1-75 (4) AISC Specification for the Design, Fabrication, and Erection of Structural Steel for Buildings, 6th and 7th Editions (5) Code for Welding in Building Construction, AWS D1.1-77, Rev. 2. Work performed prior to (December 12, 1969) is in accordance with the earlier edition, AWS D1.0-66. For inspection of non-ASME structural welds or new non-ASME work performed after January 1, 1988, the guidelines of Nuclear Construction Issues Group (Visual Weld Acceptance Criteria, DCPP UNITS 1 & 2 FSAR UPDATE 3.8-52 Revision 21 September 2013 Vol. 1-3, EPRI Report No. NP-5380, September 1987) may be used except for those cases where: (a) Fatigue is a governing design condition.
(b) The weld allowables are permitted to be higher than those allowed by AWS D1.1 (such as full penetration weld evaluation for the HE). (c) The weld is part of work performed in the ASME Section XI Inservice Inspection Program. (6) Stud loading is in accordance with the Supplement to American Welding Society Specifications AWS D1.0-66 and AWS D2.0-66 on Requirements for Stud Welding (7) Materials and quality control tests for materials conform to ASTM standards (8) ASME Section VIII, Division 2, 1974
(9) AWWA D100, American Waterworks Association, Standard to Steel Tanks, Standpipes Reservoirs and Elevated Tanks for Water Storage 3.8.3.3 Loads and Loading Combinations 3.8.3.3.1 Normal Conditions C = D + HS + 1.0 DE + 1.0 RO (3.8-27) where:
C = required load capacity of section as described in Section 3.8.3.5.1 D = dead load of tank HS = hydrostatic load DE = loads resulting from DE RO = pipe reactions during normal operating conditions, including dead, thermal, and DE loads. 3.8.3.3.2 Abnormal Conditions U = D + HS + 1.0 DDE + 1.0 RA (3.8-28) U = D + HS + 1.0 HE + 1.0 RA (3.8-29) DCPP UNITS 1 & 2 FSAR UPDATE 3.8-53 Revision 21 September 2013 where:
D and HS are defined in Section 3.8.3.3.1, and U = strength required to resist abnormal loads as described in Section 3.8.2.5.2 DDE = loads resulting from the DDE HE = loads resulting from the HE RA = pipe reactions during abnormal conditions, including dead, thermal, and DDE or HE loads 3.8.3.4 Design and Analysis Procedures Condensate storage tanks, the refueling water storage tanks, the primary water storage tanks, and the fire water and transfer water tanks were originally designed to meet the criteria based on the DE, DDE, and HE. The code used in designing the tanks was AWWA D100, 1967, with stress allowables restricted to those permitted by ASME Section VIII, Division 2. Revised security criteria called for additional resistance to bullet penetration and explosives and required all the above steel tanks, except the primary water storage tanks, to be modified with minimum reinforced concrete protection as determined by Argonne National Laboratory. The Design Class I tanks with concrete protection were reevaluated for DE, DDE, and HE using finite-element computer models as described in Section 3.7.
The stresses in the stiffeners and the steel liner plate around the vault openings were determined by hand calculation and compared with the stress allowables. The forces, moments, and stresses in the refueling water storage tank resulting from dead load, hydrostatic pressure, hydrodynamic loads, and seismic loads are listed in Table 3.8-25. These values are within the allowable limits as described in Section 3.8.3.5. 3.8.3.5 Structural Acceptance Criteria 3.8.3.5.1 Normal Loads For normal loads, the outdoor water storage tanks are designed for the allowable working stresses of the ACI 318-63 for concrete, Part 1 of the AISC Specification, 6th Edition for structural steel components, and ASME Section VIII, Division 2, 1974, for steel liner plates. 3.8.3.5.2 Abnormal Loads For abnormal loads, the outdoor water storage tanks are designed for overall elastic behavior. For concrete elements the strength design method of ACI 318-63 applies for DDE loads and of ACI 318-71 for HE loads. For the evaluation of structural steel elements using elastic design methods, for the loading condition including DDE loads, 1.6 times AISC 6th Edition, Part 1 allowables are used; whereas, for the HE load combination, Part 2 of AISC 7th Edition, the Plastic Design method applies. DCPP UNITS 1 & 2 FSAR UPDATE 3.8-54 Revision 21 September 2013 The steel liner plates are evaluated by using stress intensities as defined in ASME Section VIII, Division 2, 1974, and applying a factor of 0.9 to the minimum specified yield strength for DDE, and 1.0 to the yield strength based on test results for HE load conditions. For local stress intensities around nozzles in the vault opening area for DDE loads, a factor of 1.0 to the minimum specified yield strength applies, whereas for HE loads, a factor of 2.4 to the ASME Section VIII, Division 2, 1974, allowable values applies. 3.8.3.5.3 Factors of Safety The calculated capacity-to-demand ratios for critical structural elements of the outdoor water storage tanks are greater than the minimum allowable value of 1. Therefore, all structural elements satisfy the criteria. 3.8.3.6 Materials, Quality Control, and Special Construction Techniques The quality control measures discussed in Sections 3.8.1.6.1 and 3.8.1.6.2 for the containment structure also apply to Design Class I tanks. 3.8.3.6.1 Materials Tank Walls and Roof Dome Condensate and Inner and Outer Tank - Carbon steel liner plates and stiffeners Walls of Firewater and Transfer Tank conform to ASTM A-516 GR 60. The Condensate Storage Tanks are coated with an epoxy coating and the Fire Water and Transfer Tank is coated with Vinyl Paint. Carbon steel studs conform to ASTM A108 GR 1015- 1018. Refueling Water Tank - Stainless steel liner plates and stiffeners conform to ASTM A-240 Type 304L. Stainless steel studs conform to ASTM A276 type 304 annealed. All Tanks, Except Inner Tank of Firewater and Transfer Tank: - Concrete strength (minimum specified) fC = 4 ksi - Rebar conforms to ASTM A615, GR 60, fy = 60 ksi (minimum specified) 3.8.4 FOUNDATIONS AND CONCRETE SUPPORTS The foundation structures for the containment and the auxiliary building are included in Sections 3.8.1 and 3.8.2, respectively. The foundations of the Class I outdoor water storage tanks are described in this section.
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-55 Revision 21 September 2013 3.8.4.1 Foundations for Design Class I Tanks The following Design Class I concrete-protected steel tanks are located adjacent to the east side of the auxiliary building on reinforced concrete foundation slabs:
(1) Condensate water storage tank (one for each unit)
(2) Refueling water storage tank (one for each unit)
(3) Fire water and transfer tank (common to both units) 3.8.4.1.1 Description of the Foundation Slabs Each of the condensate water storage tanks and refueling water storage tanks has a separate, circular foundation slab. The fire water tank and the transfer tank, which serves both units, are concentric tanks on a common circular foundation slab. Each of the foundation slabs is shown in Figure 3.8-65 and consists of a 1-foot-thick reinforced concrete slab with an integral edge beam tied to a reinforced concrete wall. Each of the tanks, except for the fire water tank, is anchored to its foundation slab with ASTM A 193, Grade B7 anchor bolts. The bolt diameters are 1-1/4 inches for the condensate water storage tanks and the transfer tank, and 1-3/8 inches for the refueling water storage tanks. The wall of the fire water tank is welded to an insert plate in the foundation.
The tank foundation slabs are resting on concrete fill anchored to bedrock with rock anchors. The reinforced concrete protective walls of the steel tanks are anchored to bedrock as shown in Figure 3.8-65, Sheet 2. 3.8.4.1.2 Applicable Codes, Standards, and Specifications The foundation slabs for the Design Class I outdoor storage tanks listed are designed and constructed in accordance with the ACI 318-63. 3.8.4.1.3 Loads and Loading Combinations The foundation slabs for the Design Class I outdoor storage tanks are designed for dead loads, hydrostatic load, and seismic load:
C = DL + HS + EQ + R (3.8-30)
where:
C = total load on foundation DL = dead load of tank HS = hydrostatic load
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-56 Revision 21 September 2013 EQ = maximum seismic loads including inertial, impulsive, and convective loads R = pipe reaction load including dead, thermal, and seismic loads 3.8.4.1.4 Design and Analysis Procedures The foundation slabs with concrete fill are designed to prevent overturning and sliding of the tank and limit bearing pressure to 80 ksf. The rock anchors attaching the tank to the foundation are designed so that the maximum uplift force is within the allowable capacity provided in Figure 3.8-65, Sheet 2. 3.8.4.1.5 Structural Acceptance Criteria Stresses in the reinforced concrete foundation slabs are limited to the allowable values in ACI 318-63. 3.8.4.1.6 Materials, Quality Control, and Special Construction Techniques The quality control measures discussed in Sections 3.8.1.6.1 and 3.8.1.6.2 for the containment structure also apply to the Design Class I tank foundations.
Material strengths for the Design Class I tank foundation slabs are as follows:
(1) Concrete strength of foundation slab and concrete fill is 3000 psi.
(2) Reinforcing steel in foundation slab is ASTM A 615, Grade 40. (3) Rock anchors conform to VSL 28, strand #ER5-28, with double corrosion protection and are fully grouted with concrete strength of 4000 psi. 3.8.4.2 Concrete and Structural Steel Supports Concrete and structural steel supports for RCS components are described and evaluated in Section 5.5.14. Loading combinations for these supports are discussed in Section 5.2. 3.8.5 DESIGN CLASS II STRUCTURES CONTAINING DESIGN CLASS I EQUIPMENT The turbine building and the intake structure are Design Class II structures that contain Design Class I equipment. The turbine building contains the component cooling heat exchangers, emergency diesel generators, 4.16-kV vital switchgear, control room pressurization system, and other Class I systems. The intake structure contains the auxiliary saltwater (ASW) pumps and associated equipment.
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-57 Revision 21 September 2013 To ensure that the Design Class I equipment would not be affected by failure of the Design Class II structures, both the turbine building and the intake structure are evaluated for the HE, using responses from the dynamic analyses discussed in Section 3.7.
The capability of the intake structure to protect the ASW system during design flood events is evaluated to ensure this capability, as described in Sections 2.4 and 3.4.
The OTSC is located in the turbine building buttresses and is designed to meet seismic loading criteria. 3.8.5.1 Turbine Building 3.8.5.1.1 Description The turbine building was originally designed as a Design Class II structure using static equivalent seismic loads. Subsequently, the building was dynamically analyzed and designed to assure that it would not collapse and impair the function of Class I equipment during a DDE. Later, during the Hosgri evaluation, the building was reevaluated again and upgraded to withstand the Hosgri seismic loads. As a result of the Hosgri evaluation, buttresses and concrete walls were added to the turbine building, and internal modifications, such as reinforcing main columns, strengthening floor diaphragms, and roof and wall bracing, were made.
The turbine pedestal was originally designed as a Design Class II structure, using static equivalent seismic loads. During the Hosgri evaluation, the pedestal was reevaluated and upgraded to withstand the Hosgri seismic loads. As a result of the Hosgri evaluation, six piers were posttensioned and the pedestal-to-building separations were increased along the east and west sides of the pedestal.
The turbine building is located adjacent to the west side of the auxiliary building as shown in Figure 1.2-2, Plant Layout. The general layout of equipment in the turbine building, including the turbine generators, is shown in Figures 1.2-13 through 1.2-20, Figures 1.2-24 through 1.2-27, and Figures 1.2-30 through 1.2-32. Generally, the Unit 1 and Unit 2 portions of the turbine building are opposite hand and similar to the other, with each portion of the structure containing equipment for one unit. Exceptions are the presence of a machine shop and material storage area common to both units in the Unit 1 portion, and the OTSC in the Unit 2 portion of the structure.
Main floor levels in the turbine building are at elevations 85, 104, 119, and 140 feet. The foundation of the building is at elevation 85 feet. Representative plans at the main floor levels roof truss lower chord level, and a typical section are shown in Figures 3.8-66 through 3.8-71.
The turbine building is a reinforced concrete shear wall structure except for the superstructure, which is a structural steel moment resisting and braced frame structure DCPP UNITS 1 & 2 FSAR UPDATE 3.8-58 Revision 21 September 2013 extending from elevation 140 feet to elevation 217 feet. Shear walls generally range from 16 to 29 inches thick. Floors are 10- to 12-inch-thick reinforced concrete slabs or 1/2-inch-thick steel plate, supported on steel framing and steel columns. The reinforced concrete foundation mat is generally 3 feet thick except under the turbine pedestal, where the thickness is 10 feet. Reinforced concrete turbine pedestals, one for each unit, are located in the building; six piers of each pedestal are posttensioned. The pedestals are structurally isolated from the building floors and extend from the common foundation slab, elevation 85 feet, to elevation 140 feet. Two 135-ton overhead cranes are located in the building. 3.8.5.1.2 Applicable Codes, Standards, and Specifications The following codes and standards are used in the HE evaluation, and in the design, construction, inspection, and testing of HE modifications to the turbine building:
(1) ACI Standard Building Code Requirements for Reinforced Concrete (ACI 318-71) except that, for the HE evaluation and design, the 1973 Supplement to ACI 318 is used and design load combinations are as described in Section 3.8.5.1.3 (2) Manual of Standard Practice for Detailing Reinforced Concrete Structures (ACI 315-74)
(3) Recommended Practice for Evaluation of Compression Test Results of Field Concrete (ACI 214-65) (4) Recommended Lateral Force Requirements, 1974 Seismology Committee Structural Engineers Association of California (SEAOC) (5) Recommended Practices for Welding Reinforcing Steel, Metal Inserts, and Connections in Reinforced Concrete Construction, American Welding Society (AWS D12.1-75) (6) AISC Specification for the Design, Fabrication, and Erection of Structural Steel for Buildings, February 12, 1969, is generally used for steel structures. AISC Specification, dated November 1, 1978, is also used for evaluating selected connections. (7) Code for Welding in Building Construction (AWS D1.1 Rev. 2-77). For inspection of non-ASME structural welds or new non-ASME work performed after January 1, 1988, the guidelines of Nuclear Construction Issues Group (Visual Weld Acceptance Criteria, Vol. 1-3, EPRI Report No. NP-5380, September 1987) may be used except for those cases where: (a) Fatigue is a governing design condition DCPP UNITS 1 & 2 FSAR UPDATE 3.8-59 Revision 21 September 2013 (b) The weld allowables are permitted to be higher than those allowed by AWS D1.1 (such as full penetration weld evaluation for the HE) (c) The weld is part of work performed in the ASME Section XI Inservice Inspection Program (8) Materials and the quality control tests for materials conform to ASTM standards 3.8.5.1.3 Loads and Loading Combinations 3.8.5.1.3.1 Design Loads The following loads are considered in the HE evaluation of the turbine building. 3.8.5.1.3.1.1 Dead Loads Dead loads consist of the weight of the structure, permanent attachments and permanent equipment. 3.8.5.1.3.1.2 Live Loads Live loads consist of any actual live loads acting on the element considered. 3.8.5.1.3.1.3 Seismic Loads Seismic loads are based on a response spectrum modal superposition analysis. This analysis is described in Section 3.7.2. 3.8.5.1.3.2 Loading Combination Concrete Structural Elements U = D + L + HE (3.8-31)
where:
U = Strength determined in accordance with the methods described in ACI 318-71 and 1973 Supplement, except strength of shear walls is based on method described in Section 3(c) of the 1974 SEAOC. (See also Section 3.8.5.1.5.) D = dead load L = live load HE = loads resulting from an HE
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-60 Revision 21 September 2013 Steel Structural Elements Where plastic design methods are used:
Y = D + L + HE (3.8-32a)
Where elastic working stress design methods are used:
1.7S = D + L + HE (3.8-32b) where: S = required section strength based on elastic design methods and the allowable stresses defined in Part 1 of the AISC Specification for the Design, Fabrication, and Erection of Structural Steel for Buildings, February 12, 1969 Y = required section strength based on plastic design methods described in Part 2 of AISC Specification for the Design, Fabrication, and Erection of Structural Steel for Buildings, February 12, 1969 (See also Section 3.8.5.1.5.) 3.8.5.1.4 Design and Analysis Procedures Structural analysis of the turbine building is based on the traditional methods of engineering analysis for structural steel and reinforced concrete structures. These methods are based on the principles of equilibrium, compatibility of deformations, and predictions of material strength by the methods of the AISC Code and the ACI Code. The use of these codes is discussed in Section 3.8.5.1.5.
The lateral force resisting system of the turbine building above elevation 140 feet consists of moment resisting bents, formed by steel roof trusses and steel plate columns, steel cross-brace frames at exterior walls, and a steel bracing system in the plane of the roof truss lower chords. At and below elevation 140 feet, lateral resistance is provided by concrete and steel plate floors acting as diaphragms; by concrete shear walls; by concrete buttresses along the east and west sides of the building; and by steel cross-braced frames above elevation 104 feet at the north and south ends of the building. Vertical forces are transmitted to the foundation by the steel plate columns, concrete walls, and interior steel columns which support the steel floor framing system.
HE forces on the lateral force resisting system of the turbine building and the turbine pedestal are based on the response of the turbine building and pedestal seismic models described in Section 3.7. In some cases detailed analytical models are developed to calculate building member forces. Structural evaluation of members is performed for the load combinations described in Section 3.8.5.1.3. The evaluation considers bridge crane location and lifted load as described in Section 3.7. Members are evaluated DCPP UNITS 1 & 2 FSAR UPDATE 3.8-61 Revision 21 September 2013 against the acceptance criteria in Section 3.8.5.1.5. Results of the evaluation are shown in Tables 3.8-26 and 3.8-27.
Computer programs used in the structural analysis and the verification measures are listed in Table 3.8-6. 3.8.5.1.5 Structural Acceptance Criteria For HE load combinations actual material properties are used. Lateral force resisting elements are allowed inelastic deformation subject to the ductility limits shown in Table 3.8-24. The strength of concrete elements is determined in accordance with the methods of ACI 318-71 and the 1973 Supplement. Strength of concrete shear walls is determined in accordance with Section 3(c) of 1974 SEAOC. Strength of steel elements is determined in accordance with the AISC Code, February 12, 1969.
Calculated forces and capacities for selected structural elements of the turbine building and turbine pedestals are compared in Tables 3.8-26 and 3.8-27. Generally, the predicted forces in combination with earthquake effect do not exceed member strengths. A limited number of members are found to exhibit inelastic behavior which does not exceed the allowable ductility limits of Table 3.8-24. Therefore, all structural elements satisfy the criteria.
Separations between the turbine building's primary structure and the turbine pedestal are adequate to ensure these structures will not impact each other when subject to the HE load combination. The relative displacements between these structures are summarized in Table 3.8-27A. 3.8.5.1.6 Materials, Quality Control, and Special Construction Techniques The turbine building, including the turbine pedestals, was originally constructed prior to 1978. Following the HE evaluation of the plant, modifications to the turbine building and the turbine pedestals were made during the period 1978 to 1979. Materials installed during these two periods are described in the following paragraphs. 3.8.5.1.6.1 Concrete Design strengths of concrete are as follows:
Age, days Compressive Strength, psi Original construction: East-west walls 28 5000 Elevation 140 feet floor 60 5000 All other concrete 28 3000
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-62 Revision 21 September 2013 Hosgri Modifications: Concrete above elevation 85 feet 28 5000 All other concrete 28 3000
Modifications for sixth diesel generator addition, all associated concrete 28 4000
Average strengths are used with the HE load combination. The average strengths are as follows:
Age, days Compressive (except as noted) Strength, psi Original Construction: Turbine pedestal 6 years(a) 6000 East-west walls 28 5500 Elevation 140 feet floor 60 6590 All other concrete 28 3870
Hosgri Modifications:
Concrete above elevation 85 feet 28 5680 All other concrete 28 4260 3.8.5.1.6.2 Reinforcing Steel Reinforcing steel is ASTM A615, Grade 40, except in some locations where grade 60 is used. Average test values are used with HE load combinations. Properties of the reinforcing steel are as follows: Grade 40 Grade 60 Design yield strength, psi 40,000 60,000 Original construction Average yield strength, psi 51,400 65,900 Average tensile strength, psi 80,600 101,400 Hosgri Modifications Average yield strength, psi 51,900 67,000 Average tensile strength, psi 81,300 106,500 (a) Turbine pedestal concrete strength is based on cylinder tests of 6-year-old stored specimens. The strength is verified by rebound hammer tests and by tests of concrete core samples. DCPP UNITS 1 & 2 FSAR UPDATE 3.8-63 Revision 21 September 2013 3.8.5.1.6.3 Structural Steel Structural steel is ASTM A36 except for reinforcing bars installed at flanges of some columns along column lines A and G where ASTM A572 Grade 50, is used. Properties of the structural steel are as follows: ASTM A36 ASTM A572, Gr 50 Design yield strength, psi 36,000 50,000 Original construction Average yield strength, psi 44,000 Average tensile strength, psi 68,000
Hosgri Modifications Elevation 140 and 119 feet floor plate Average yield strength, psi 40,800 Average tensile strength, psi 69,300
Other structural steel Average yield strength, psi 44,500 55,200 Average tensile strength, psi 68,200 87,400 3.8.5.2 Intake Structure 3.8.5.2.1 Description of Intake Structure The seismic Design Class II intake structure is a reinforced concrete building constructed with 3,000 psi minimum-specified-strength concrete. The structure has plan dimensions of approximately 240 x 100 feet. The long dimension corresponds to the north-south direction, and is parallel to the seaward face of the structure. The intake structure is backfilled by rock on three sides, and has water on the fourth (western) side. The top deck of the structure has a maximum elevation of +17.5 feet. A concrete ventilation tower with steel coaxial ventilation pipe extends to an elevation of +49.4 feet. The structure is supported by a concrete mat foundation at elevation -31.5 feet. Figures 3.8-72 through 3.8-74 illustrate plans at elevations +17.5, -2.1, and -31.5 feet; Figures 3.8-75 through 3.8-77 illustrate representative sections through the structure.
The top level of the structure consists of an 18-inch-thick concrete slab, except for the roadway area where it is 24 inches thick. Openings, as shown in Figure 3.8-72, are provided to allow removal of pumps, screens, and gates. The pump deck floor at elevation -2.1 feet supports the four main circulating water pumps and the four seismic Design Class I ASW pumps. Design Class I ASW equipment is located in ventilated watertight compartments. The structure is symmetric about a vertical plane in the east-west direction through its centerline.
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-64 Revision 21 September 2013 3.8.5.2.2 Applicable Codes, Standards, and Specifications The following codes and standards were used in the Hosgri evaluation and the design, construction, inspection, and testing of the intake structure.
(1) ACI Standard Building Code Requirements for Reinforced Concrete (ACI 318-63, ACI 318-71, ACI 318-77)
(2) Manual of Standard Practice for Detailing Reinforced Concrete Structures (ACI 315-65) (3) Recommended Practices for Welding Reinforcing Steel, Metal Inserts and Connections in Reinforced Concrete Construction, American Welding Society AWS D12.1-75 (4) AISC Specification for the Design, Fabrication and Erection of Structural Steel for Buildings, February 12, 1969, and November 1, 1978 (5) Code for Welding in Building Construction, AWS D1.1-77, Rev. 2. For inspection of non-ASME structural welds or new non-ASME work performed after January 1, 1988, the guidelines of Nuclear Construction Issues Group (Visual Weld Acceptance Criteria, Vol. 1-3, EPRI Report No. NP-5380, September 1987) may be used except for those cases where: (a) Fatigue is a governing design condition (b) The weld allowables are permitted to be higher that those allowed by AWS D1.1 (such as the full penetration welds evaluation for the HE) (c) The weld is part of work performed in the ASME Section XI Inservice Inspection Program (6) Recommended Lateral Force Requirements 1974 Seismology Committee, Structural Engineers Association of California (SEAOC) (7) Materials and quality control tests for materials conform to ASTM standards 3.8.5.2.3 Loads and Loading Combination Seismic Load Combination U = D + L + HE (3.8-33)
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-65 Revision 21 September 2013 where: D = dead load of the structure and equipment loads L = live load HE = loads resulting from HE U = strength required to resist design loads as described in Section 3.8.5.2.5 Wave Load Combination U = D + L + Wf (3.8-34) where:
U, D, and L are as defined in (1) above Wf = wave force associated with breakwater degraded to MLLW 3.8.5.2.4 Design and Analysis Procedures 3.8.5.2.4.1 General Structural analysis of the intake structure is performed by the traditional methods of engineering analysis for structural steel and reinforced concrete structures. These methods are based on the principles of equilibrium, compatibility of deformations, and predictions of material strength by the methods of the AISC Code, and the ACI Code. The use of these codes is discussed in Section 3.8.5.2.5. 3.8.5.2.4.2 Seismic Forces A time-history dynamic analysis is performed with a computer program to determine the structure response spectra. A response spectrum dynamic modal superposition analysis is performed to determine structure response maxima. The analytical procedure using modal superposition methods is described in Section 3.7.2.
The demands resulting from the combination of north-south, east-west, and vertical components of the HE, in conjunction with dead loads, actual live loads, and soil pressures, are less than the yield capacity of the major portion of the structure, including the area housing the Class I ASW. The only exceptions are some of the flow straighteners (or piers) that exhibit stresses beyond code values. However, these piers demonstrate ductility properties that would preclude structural failure. The ductilities are within allowables as stated in Section 3.8.5.2.5. Table 3.8-28 presents the results of the analysis.
The intake structure is reviewed to verify that there is an adequate factor of safety against sliding and overturning, and the foundation pressure is within the allowable value of 50 ksf as described in Reference 13. DCPP UNITS 1 & 2 FSAR UPDATE 3.8-66 Revision 21 September 2013 3.8.5.2.4.3 Wave Forces As shown in Figures 3.8-78 and 3.8-79, a scaled, three-dimensional physical model of the cooling water intake basin, the intake structure, and a hypothetically damaged breakwater was constructed to examine the wave effects on the intake structure as described in References 8 and 9.
Based on the test results, the intake structure was modified to mitigate wave slam (high magnitude, high frequency) pressure behind the curtain wall and to withstand the measured pressures on the bottom of the slab.
The ASW pump compartments were modified to provide the required ventilation on the Design Class I equipment and to prevent flooding due to combined tsunami and storm wave runup conditions as described in Chapter 2. As discussed in Section 3.3.2.3.2.10, the ASW pump compartment modifications were reviewed for a tornado with missiles.
A risk analysis, as described in Reference 14, was performed to determine the frequency of vessel impact with the intake structure which houses the ASW pumps. In the analysis, the breakwater was assumed to be degraded to the MLLW level. The analysis considered only large vessels (greater than 250 tons displacement), since impact on the intake structure by smaller vessels was concluded, on the basis of a deterministic analysis, to be inconsequential to the safety-related function of the ASW pumps.
The results of risk analysis for frequency of impact indicate a frequency of 6.7 x 10-6 breakwater boundary crossings per year for storm-independent analysis and 1.9 x 10-5 breakwater boundary crossings per year for storm-dependent analysis. The probability of large vessels, therefore, crossing the degraded breakwater and impacting the intake structure is quite low. 3.8.5.2.5 Structural Acceptance Criteria For the load combinations given in Section 3.8.5.2.3, the intake structure is designed so that it does not sustain damage that would adversely affect the function of the Class I ASW system and prevent it receiving an adequate supply of water.
For load combinations with seismic force, strength is based on SEAOC 1974 concrete shear walls; ACI 318-63 and ACI 318-71 for other concrete members; and AISC, Seventh Edition, Part II for steel members. Lateral force resisting elements are allowed inelastic deformation consistent with ductility factors indicated in Table 3.8-24. For these elements, the allowable stress limitations given in the codes above need not apply.
For load combinations with wave forces, strength is based on ACI 318-71 and AISC, Seventh Edition, Part II for all structural members except for ASW pump compartment DCPP UNITS 1 & 2 FSAR UPDATE 3.8-67 Revision 21 September 2013 modifications. For the latter, strength is based on ACI 318-77 and 1.6 times AISC Eighth Edition, Part I allowable values. 3.8.5.2.6 Materials, Quality Control, and Special Construction Techniques The intake structure was originally constructed prior to 1981. As a result of January 1981 storm damage to the west-breakwater, hydraulic model studies of wave effects on the intake structure were conducted in 1982 (References 8 through 12), and the intake structure was modified to withstand these wave effects. The material strengths for these periods are provided below: Concrete Prior to 1981 Minimum specified fc' = 3000 psi @ 28 days Average test values fc' = 3630 psi 1981 modifications Minimum specified fc' = 5000 psi @ 28 days Reinforcing Steel Prior to 1981 ASTM A615, Grade 40; Minimum specified fy = 40 ksi Average test values fy = 49.6 ksi 1981 Modifications ASTM A615, Grade 60; Minimum specified fy = 60 ksi Structural Steel Prior to and after1981 ASTM A36; Minimum specified fy = 36 ksi 3.8.6 PIPEWAY STRUCTURES 3.8.6.1 Description of Pipeway Structures The pipeway structure for each unit is a steel frame structure attached to the outside of the containment shell, the auxiliary building, and the turbine building as shown in Figure 3.8-80. The pipeway structure in one unit is essentially a mirror image of the other. The primary function of the pipeway structure is to support main steam and feedwater piping. The pipeway structure has five major platforms located at elevations 109, 114, 118, 127, and 138 feet. Connections between the pipeway structure and the auxiliary and turbine buildings are provided with slotted holes oriented such that horizontal motions cannot be transmitted between the structures.
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-68 Revision 21 September 2013 3.8.6.2 Applicable Codes, Standards, and Specifications 3.8.6.2.1 Codes The following codes and standards are used, insofar as they are applicable, in the design and/or construction of the pipeway structure.
(1) AISC Specification for Design, Fabrication, and Erection of Structural Steel for Buildings, February 12, 1969 (2) ACI Standard Building Code Requirements for Reinforced Concrete (ACI-318-63)
(3) Standard code for welding in building construction (AWS D1.0-69). For inspection of non-ASME structural welds or new non-ASME work performed after January 1, 1988, the guidelines of Nuclear Construction Issues Group (Visual Weld Acceptance Criteria, Vol. 1-3, EPRI Report No. NP-5380, September 1987) may be used except for those cases where: a) Fatigue is a governing design condition.
b) The weld allowables are permitted to be higher than those allowed by AWS D1.1 (such as the full penetration weld evaluation for the HE). c) The weld is part of work performed in the ASME Section XI Inservice Inspection Program. (4) Materials, and the quality control tests for materials, conform primarily to ASTM and ASME standards. Additional materials and supplemental quality assurance requirements conform to ANSI standards 3.8.6.3 Loads and Loading Combinations 3.8.6.3.1 Design Loads The following loads are considered in the design of the pipeway structure. 3.8.6.3.1.1 Dead Loads Dead loads consist of the weight of the structure, piping, pipe rupture restraints, electrical raceways, and equipment.
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-69 Revision 21 September 2013 3.8.6.3.1.2 Live Loads Live loads are temporary loads that may be placed on the structure. These are considered small in relative magnitude and, therefore, are considered negligible. 3.8.6.3.1.3 Earthquake Loads Earthquake loads are as described in Section 3.7.2.1.7.1. 3.8.6.3.1.4 Wind Loads Wind loads are determined in accordance with the criteria presented in Section 3.3. However, the forces due to wind are much less than those due to earthquake; consequently, seismic loads, rather than wind, are entered into the load combination equations. 3.8.6.3.1.5 Thermal Loads Thermal loads are those induced by the main steam and feedwater pipes through the support system. These loads are considered negligible. 3.8.6.3.2 Loading Combinations The following loading combinations are used in the design of the pipeway structure. 3.8.6.3.2.1 Normal Conditions Dead loads and design earthquake (DE) are considered as follows:
S = D + DE (3.8-35)
where: S = required capacity of structural members based on the method described in Section 3.8.6.5.1 D = dead load DE = loads resulting from the DE 3.8.6.3.2.2 Abnormal Conditions Where elastic working stress design methods are used: 1.6S = D + DDE (3.8-36)
1.7S = D + DDE + Yr (3.8-37)
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-70 Revision 21 September 2013 1.7S = D + 1.25DE + Yr (3.8-38)
1.7S = D + HE (3.8-39) Where plastic design methods are used: 1.0Y = D + DDE + Yr (3.8-40)
1.0Y = D + 1.25DE + Yr (3.8-41) where: DDE = loads resulting from the DDE HE = loads resulting from the HE Yr = reaction on structure from a broken pipe, generated by a postulated pipe break, including an appropriate dynamic load factor (DLF) Y = required section strength based on plastic design methods described in Part 2 of the AISC specification referenced in Section 3.8.6.2.1 3.8.6.4 Design and Analysis Procedures 3.8.6.4.1 Hosgri Event Seismic forces from the response spectrum dynamic analysis described in Section 3.7.2.1.7.1 are used in the stress evaluation of the Unit 1 pipeway structure. The Unit 2 pipeway structure is evaluated using a detailed three-dimensional model and the static equivalent method of seismic analysis described in Section 3.7.2.1.7.1. The calculated stress ratios for the most critical members are given in Table 3.8-5A. 3.8.6.4.2 Design Earthquake and Double Design Earthquake Member forces are calculated using corresponding Hosgri forces adjusted in proportion to ratios of DE or DDE to HE spectral accelerations. These forces are used in the stress evaluation of the Unit 1 and 2 pipeway structures. Stresses obtained by this method are confirmed by time-history dynamic analysis described in Section 3.7.2.1.7.1. Calculated stress ratios for the most critical members are given in Table 3.8-5A. 3.8.6.4.3 Computer Programs Computer programs used in the structural analysis and the verification measures are listed in Table 3.8-6.
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-71 Revision 21 September 2013 3.8.6.5 Structural Acceptance Criteria For DE and DDE load combinations in the absence of pipe break loads (Yr), the minimum specified yield strength for structural steel is considered. For load combinations including HE or Yr, the actual material properties are used. In addition, the following conditions apply. 3.8.6.5.1 Normal Conditions For normal conditions, the pipeway structure is designed to the allowable working stresses in Part 1 of the AISC Code, February 12, 1969; however, the increase in allowable stress usually allowed for load combinations involving earthquake forces is not used. 3.8.6.5.2 Abnormal Conditions For abnormal conditions, the pipeway structure, in general, is designed for overall elastic behavior. For load combinations (3.8-37), (3.8-38), (3.8-40), and (3.8-41) of Section 3.8.6.3.2.2, the acceptance criteria described therein should be satisfied first without considering the effect of Yr. When considering the effect of Yr, local section strength capacities may be exceeded provided there is no loss of function of any safety-related system. 3.8.6.5.3 Factors of Safety The calculated capacity-to-demand ratio for the most critical members of the pipeway structure are given in Table 3.8-5A. In all cases these ratios are greater than the minimum allowable value of 1.0. Therefore, all structural elements satisfy the criteria. 3.8.6.6 Materials, Quality Control, and Construction Techniques Structural steel is ASTM A441 and ASTM A516 Grade 70. ASTM minimum specified values are used with DE and DDE load combinations in the absence of Yr. Average test values are used with load combinations that include HE or Yr. Minimum and average values are as follows: ASTM A441 ASTM A516 Minimum yield strength, psi 45,000 38,000 Average yield strength, psi 51,600 51,040
High strength bolts, nuts, and washers used for connections are predominantly ASTM A490. Some ASTM A325 bolts are also used when found acceptable. Impact tests for structural steel and high strength bolts were performed in accordance with ASTM Standard Method A370 at 0°F. Welding electrodes conform to ASTM A233, E70 series low hydrogen. DCPP UNITS 1 & 2 FSAR UPDATE 3.8-72 Revision 21 September 2013 Where indicated on drawings, nondestructive testing was performed as required utilizing ultrasonic or magnetic particle techniques.
Approved substitute for ASTM A441 structural steel is ASTM A572 Grade 42. For any new construction after May 2004, the structural steel used may be A572 Grade 42. The impact test is required for this new steel. 3.8.7 SAFETY-RELATED MASONRY WALLS In accordance with Reference 28, safety-related masonry walls (see Section 3.8.7.1) have been reevaluated and modified as necessary using conservative design and analysis procedures, and structural acceptance criteria as specified in Section 3.8.7.5. Design and analysis methods and structural acceptance criteria are in accordance with Reference 29. NRC Staff acceptance of the wall reevaluation design and analysis methods is documented in Reference 30. 3.8.7.1 Description of Safety-Related Masonry Walls Safety-related masonry walls are those walls which support safety-related piping or equipment, or whose failure could prevent a safety-related system from performing its intended safety function. Safety-related walls are located in the auxiliary and turbine buildings at locations identified in Figures 3.8-83, -84, and -85, and are evaluated in accordance with Reference 29. These walls are fire walls or nonbearing partitions serving various functions and are not required to resist tornado or missile loads and are not part of the buildings lateral force resisting system. Some of the walls support small piping, conduits, or instrumentation tubing. A few walls support concrete or metal deck ceilings. All walls are single width, 8 or 12 inches thick, fully grouted, and reinforced in the horizontal and vertical directions with steel reinforcing bars. The bottoms of all walls are tied to the building structure.
In general, walls extend to the underside of the floor structure, where lateral support is provided by a structural supporting system. A separation joint filled with compressible material is provided at the top and side boundaries of all walls where they abut the building structure floors or columns. Walls are braced with steel members. The bottoms of some walls are connected to the floor with bolted steel angles. Some walls are strengthened by steel plates bolted to each face of the wall. 3.8.7.2 Applicable Codes, Standards, and Specifications The following codes and standards are used in the design, construction, inspection, and testing of safety-related masonry walls:
(1) Building Code Requirements for Concrete Masonry Structures (ACI 531-79) and Commentary (ACI 531R-79)
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-73 Revision 21 September 2013 (2) AISC Specification for the Design, Fabrication, and Erection of Structural Steel for Buildings, February 12, 1969 (3) Materials and quality control tests for materials conform to the applicable ASTM standards 3.8.7.3 Loads and Loading Combinations 3.8.7.3.1 Design Loads The following loads are considered in the evaluation of safety-related masonry walls: 3.8.7.3.1.1 Dead Loads Dead loads consist of the weight of the wall and supported items. 3.8.7.3.1.2 Live Loads Live loads consist of occupancy loads, if any, acting on the wall. 3.8.7.3.1.3 Earthquake Loads Earthquake loads are those resulting from the HE. The loads are based on the response spectrum, single-degree-of-freedom method described in Section 3.7.2.1. The percentage of critical damping used is 7 percent.
3.8.7.3.1.4 Thermal Loads Thermal loads are loads induced by local increases in temperature resulting from normal operating and from postulated accident conditions. 3.8.7.3.1.5 Pipe Reaction Loads Pipe reactions result from hydraulic forces, thermal expansion, and seismic events. These loads are transferred to the structure through pipe supports and result from normal operating conditions and postulated accident conditions. 3.8.7.3.1.6 Pressure Loads Pressure loads are forces generated by a postulated pipe break. Pressures from a postulated broken pipe are calculated as described in Section 3.6. 3.8.7.3.1.7 Loads and Loading Combinations The following load combinations are used in evaluation of safety-related masonry walls: DCPP UNITS 1 & 2 FSAR UPDATE 3.8-74 Revision 21 September 2013 U = D + L + To + Ro + HE
U = D + L + Ta + Ra + 1.5Pa
U = D + L + Ta + Ra + 1.0Pa + HE where: U = strength determined using acceptance criteria described in Section 3.8.7.5 D = dead load L = live load To = thermal loads during normal operating conditions Ro = pipe reactions during normal operating conditions HE = loads resulting from an HE Ta = thermal loads generated by a postulated pipe break, including To Pa = pressure load generated by a postulated pipe break Ra = pipe reactions from unbroken pipes generated by postulated pipe break conditions, including Ro 3.8.7.4 Design and Analysis Procedures Evaluation of safety-related masonry walls is performed using traditional methods of engineering analysis. Proper consideration is given to boundary conditions, cracking of sections, and the dynamic behavior of the walls. Both in-plane and out-of-plane loads and interstory drift effects are considered. HE forces on the walls are based on applicable building floor response spectra generated by the analysis described in Section 3.7.2.1. In some cases, detailed models of the walls and supporting steel members are used to calculate forces and stresses in the walls.
HE forces on the walls including wall reactions are calculated by linear elastic analysis. Applied forces on the walls include the combined effects of vertical loads and horizontal out-of-plane wall deflections (P- effect). Masonry wall stiffnesses are based on best estimate (median) properties, which are:
Em = 750 f'm F'm = 1950 psi fr = 4(f'm)0.5 The stiffness and strength of walls strengthened with steel plates at each face are based on wall panel tests. Drypack grout at the top of the walls is treated as unreinforced and is not relied upon to withstand earthquake loads. An additional evaluation of the walls is performed to address the variability of material properties, workmanship, and construction tolerances. DCPP UNITS 1 & 2 FSAR UPDATE 3.8-75 Revision 21 September 2013
Computer programs used in the structural analysis and the verification measures are listed in Table 3.8-6. 3.8.7.5 Structural Acceptance Criteria In the evaluation of safety related masonry walls for load combinations, including HE or pipe break loads, actual material properties may be used.
The moment capacity of a masonry wall is not less than the moment produced by the applied loads. Moment capacity of the masonry wall is determined using the strength design method, with a strength reduction factor, , equal to 1.0. Allowable masonry shear stress is 1.3 x 1.1 (f'm)0.5, where f'm is as defined in Section 3.8.7.4. Allowable masonry bearing stress is 2.5 x 0.25 (f'm). Analysis of the behavior of masonry walls strengthened with steel plates is substantiated by tests. Allowable forces on steel members are based on 1.6 times allowable stresses defined in the AISC Code, Part 1, or 0.9 times member strengths defined in the AISC Code, Part 2. 3.8.7.6 Materials, Quality Control, and Special Construction Techniques 3.8.7.6.1 Masonry Units Masonry units are hollow, load-bearing, open-ended lightweight units of ASTM Designation C90, Grade A. The average compressive test strength of masonry units is 3400 psi on the net area. 3.8.7.6.2 Reinforcing Steel In general reinforcing steel is ASTM A615, Grade 40. The average yield strength by test is 51,400 psi.
In limited areas, reinforcing steel is ASTM A615, Grade 60. The average yield strength by test is 64,200 psi. 3.8.7.6.3 Core Fill Grout having a minimum specified compressive strength of 2000 psi is placed in all masonry unit cells. The average tested compressive strength is 3285 psi. 3.8.7.6.4 Mortar Mortar is ASTM Designation C270, Type S.
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-76 Revision 21 September 2013 3.8.7.6.5 Construction Inspection Inspection procedures meet the intent of Section 4.5 of Building Code Requirements for Concrete Masonry Structures (ACI 531-79). 3.8.8 PERMANENT SPENT FUEL STORAGE RACKS 3.8.8.1 Description of the Spent Fuel Pool and Racks The description of the SFP is provided in Sections 3.8.2.1 and 9.1.2.2. Each fuel pool has 16 high density fuel rack modules as shown in Figure 9.1-2. They are free-standing and consist of individual cells with an 8.85 by 8.85-inch square cross-section, each of which stores a single Westinghouse PWR fuel assembly. The number of cells varies from 34 to 110 per module. The cells are fabricated by welding two formed stainless steel channels, which are welded together by stainless steel gap channels to provide the required predetermined distance between the cells. Typically, each module is provided with four support legs, three of which are adjustable and one fixed. The adjustable support legs are used to achieve a leveled free-standing position on the pool floor. For ease of installation and to reduce potential interferences with liner seam welds, each rack support leg is supported on a bridge plate. Typically, each rack module is equipped with girdle bars located near the top, which are designed to accommodate seismically induced impact loads. 3.8.8.2 Applicable Codes, Standards, and Specifications The following codes and standards are used in the design and construction of the racks. (1) AISC Specification for the Design, Fabrication, and Erection of Structural Steel for Buildings, 1969 Edition (2) ASME Boiler and Pressure Vessel Code, Section III and Subsection NF, 1983 Edition (3) AEC "Spent Fuel Storage Facility Design Basis," SG 13, March 1971
(4) Westinghouse Fuel Assembly, Storage and Refueling Equipment Design Interface Specification No. F-8, Rev. 8 (5) NRC "OT Position for Review and Acceptance of Spent Fuel Storage and Handling Applications," April 14, 1978, and "Modifications to the OT Position," January 18, 1979, letters from B. K. Grimes to All Power Reactor Licensees (6) Appendix D to Standard Review Plan, Section 3.8.4, "Technical Position on Spent Fuel Pool Racks," Revision 0, July 1981, NRC DCPP UNITS 1 & 2 FSAR UPDATE 3.8-77 Revision 21 September 2013 3.8.8.3 Loads and Loading Combinations The loads and loading combinations and the corresponding acceptance criteria are as follows (Reference 20): Loading Combination Stress Limit (a) D Level A service limits D + To D + To + E (b) D + Ta + E Level B service limits D + To + Pf (c) D + Tf + E' Level D service limits D + Fd (The functional capability of the fuel racks should be demonstrated) where: D = Dead weight-induced stresses (including fuel assembly weight) Fd = Force caused by the accidental drop of the heaviest load from the maximum possible height Pf = Upward force on the racks caused by postulated stuck fuel assembly E = DE E' = HE To = Differential temperature induced loads (normal or upset condition) Ta = Differential temperature induced loads (abnormal design conditions) 3.8.8.4 Design and Analysis of Racks 3.8.8.4.1 Design Basis Rack Model The racks are analyzed using a nonlinear dynamic model as shown in Figure 3.8-81. The model simulates the rack as a single stick supported on a rigid base with supports. Impact springs are provided at the girdle bar and the baseplate locations to account for rack-to-rack and/or rack-to-wall impact. The legs are represented by 4 impact springs to account for the impact as well as frictional sliding. The rattling of the fuel assemblies in cells is considered by the use of additional impact springs. The model includes 2 mass points comprising 8 degrees of freedom. Mass 1 is located in the rack module and has 6 degrees of freedom, (i.e., 3-dimensional space with 3 linear translations and 3 rotations). Mass 2 is located at the top of the fuel and moves with 2 translational degrees of freedom. The lower mass point of the fuel assembly is lumped with the rack module mass (Reference 20). DCPP UNITS 1 & 2 FSAR UPDATE 3.8-78 Revision 21 September 2013 3.8.8.4.2 Design Basis Rack Analysis and Results Due to the complexity of the nonlinear time-history analysis, the racks, in general, are analyzed using a single rack model (Figure 3.8-81) that uses conservative model parameters. The seismic input motions are provided in the form of three orthogonal time histories at the fuel pool liner location. A minimum value of 0.2 and a maximum value of 0.8 are used for the range of friction coefficients between the rack supports and the pool liner (Reference 23). The effects of fluid are considered in accordance with the method advanced by Fritz (Reference 24). The impact springs are set at values to produce conservative impact forces. Parametric studies have been performed to evaluate the effects of various design variables such as friction coefficients, size of rack, fuel loading (partially loaded, fully loaded, or empty) on rack, spacing between racks (corner rack vs. non-corner rack), fabrication tolerance, etc. The bounding loads are obtained from those parametric analyses, which are then used for the design of rack components.
The racks have been analyzed to store LOPAR, VANTAGE 5, and ZIRLO fuel assemblies. The impact loads between the cell wall and the fuel assemblies are less than those provided by Westinghouse. 3.8.8.4.3 Multi-Rack Confirmatory Model The design basis analysis includes several conservative assumptions applied to a single rack model to obtain conservative impact loads. To confirm the adequacy of this methodology, additional multi-rack analyses have been performed (References 21 and 22). Figure 3.8-82 shows the two-dimensional dynamic model used in this analysis. Each rack is represented by four degrees of freedom simulating fuel rattling, translation, and rocking of the racks. The parameters for the model are developed in a manner similar to those used for the design basis model, except more realistic assumptions are made to compute the fluid coupling coefficients and spring constants. 3.8.8.4.4 Multi-Rack Confirmatory Analysis and Results The analyses are performed using the nonlinear time history method. The governing horizontal (east-west) and vertical ground motions are applied simultaneously to the model. Parametric studies have been performed to evaluate the effects of various friction coefficients, fuel loading on racks, sizes of racks, lateral gaps, and fabrication tolerances. The results of the analysis demonstrate that the use of conservative model parameters in the design basis analysis (Reference 20) yields conservative rack and fuel assembly impact loads.
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-79 Revision 21 September 2013 3.8.8.5 Materials, Quality Control, and Special Construction Techniques The materials for both Region 1 and Region 2 rack modules are:
Stainless steel sheet and plate ASTM A-240-304L Weld filler material ASME SFA-5-9 Type 308L and 308LSI Top part of support ASTM 479-S21800 Bottom part of support ASTM SA564-630 3.8.8.6 Design and Analysis of Pool Structure The existing pool structure was evaluated for postulated interactions of the rack modules with the structure as a result of the seismic event. The effect of the change in fuel rack mass on global dynamic response of the pool structure was considered. The change in global mass was determined to be on the order of 1 percent to 2 percent, therefore, the change in dynamic response is insignificant.
The pool walls were evaluated for the out-of-plane effects due to hydrostatic, hydrodynamic, thermal, and seismic loads. They adequately meet the loading combinations and acceptance criteria in Sections 3.8.2.3.2 and 3.8.2.5, respectively. The walls were also checked for additional impact loads that may result from the rack-to-wall impact and they meet the acceptance criteria of Section 3.8.2.5.
The liner was evaluated for the maximum vertical impact load and maximum horizontal sliding load and was determined to be adequate for leak tightness. The concrete slab that supports the liner was evaluated for the floor impact load using the allowable values specified in ACI 349-80 (Reference 25). The liner in-plane loadings that result from the sliding of the rack and thermal effects were evaluated in accordance with the allowable strains and anchor displacements as specified in ASME Section III, Division II, 1983 (Reference 26). 3.
8.9 REFERENCES
- 1. Timoshenko and Woinowsky-Krieger, Theory of Plates and Shells, McGraw-Hill, Inc., New York, 1959, Second Edition.
- 2. Deleted.
- 3. Code for Concrete Reactor Vessels and Containments, ACI Standard 359-75.
- 4. PG&E's response to Governor George Deukmejian's and Joint Intervenors' first set of interrogatories (Docket Nos. 50-275 and 50-323): Interrogatory Number 2 - Unit 1; Interrogatory Number 3 - Unit 2.
- 5. PG&E's first supplemental response to Governor Deukmejian's and Joint Intervenors' first set of interrogatories. (Docket Nos. 50-275 and 50-323.)
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-80 Revision 21 September 2013
- 6. Letter dated August 13, 1973, with enclosures, (Docket Nos. 50-275 and 50-323) from A. Giambusso of the AEC to F. T. Searls of PG&E.
- 7. Recommended Evaluation Criteria for Diablo Canyon Nuclear Power Plant Auxiliary Building Walls and Diaphragms, by Jack R. Benjamin and Associates, Inc., dated February 11, 1983, prepared for Bechtel Power Corporation, San Francisco, California.
- 8. The Height Limiting Effects of Sea Floor Terrain Features and of Hypothetically Extensively Reduced Breakwaters on Wave Action at Diablo Canyon Sea Water Intake, by Omar J. Lillevang, Fredric Raichlen, Jack C. Cox, March 15, 1982.
- 9. The Investigation of Wave-Structure Interactions for the Cooling Water Intake Structure of the Diablo Canyon Nuclear Power Plant, by Fredric Raichlen, December 1982.
- 10. Criteria for Selection of Critical Wave Directions, Omar J. Lillevang, November 2, 1982.
- 11. Wave Effects on Intake Structure at Diablo Canyon Units 1 and 2, E. N. Matsuda, January 1983.
- 12. Investigation of Seawater Injection into the Auxiliary Saltwater Pump Room Due to the Splash Runup During the Design Flood Events at Diablo Canyon, P. J. Ryan, January 1983. 13. Geotechnical Studies on Intake Structure, Water Storage Tanks, Diesel Fuel Oil Storage Tanks, for Diablo Canyon Power Plant, San Luis Obispo County, California, by Harding-Lawson Associates, April 12, 1978. 14. Frequency of Vessel Impact with the Diablo Canyon Intake Structure, by Jack R. Benjamin and Associates, December 10, 1982.
- 15. Deleted in Revision 10.
- 16. Deleted in Revision 10.
- 17. Deleted in Revision 10.
- 18. Deleted in Revision 10.
- 19. Deleted in Revision 4.
- 20. Seismic Analysis Report, Seismic Analysis of High Density Fuel Racks for PG&E for Diablo Canyon Nuclear Power Station, Rev. 3, September 3, 1986, A. Soler, TM #779.
DCPP UNITS 1 & 2 FSAR UPDATE 3.8-81 Revision 21 September 2013
- 21. "Additional Information on Rack to Rack Interaction," Enclosure 1 to PG&E Letter No. DCL-87-070, dated April 7, 1987.
- 22. "Three-Dimensional Studies (ACORN 10 and ACORN 12)," Enclosure to PG&E Letter No. DCL-87-082, dated April 23, 1987.
- 23. Rabinowicz, E., Friction Coefficient Value for a High Density Fuel Storage System, Report to General Electric Nuclear Energy Program Division, November 23, 1977.
- 24. Fritz, R.J., The Effect of Liquids on the Dynamic Motions of Immersed Solids, Journal of Engineering for Industry, pp. 167-173, February 1972.
- 25. ACI Standard 349-80, Code Requirements for Nuclear Safety Related Concrete Structures, American Concrete Institute, Detroit, Michigan.
- 26. ASME Boiler and Pressure Vessel Code, American Society of Mechanical Engineers, Section III, Division II, 1983.
- 27. EPRI NP-5380 Final Report, Visual Weld Acceptance Criteria, Volumes 1-3 (Nuclear Construction Issues Group (NCIG) NCIG-01, Revision 2, NCIG-02 Revision 2, and NCIG-03 Revision 1), September 1987.
- 28. PG&E Letter DCL-90-289, with enclosure, from J.D. Shiffer to NRC, December 14, 1990. 29. PG&E Letter DCL-91-026, with enclosure, from J.D. Shiffer to NRC, February 12, 1991.
- 30. Letter dated September 18, 1991, with enclosure, (Docket Nos. 50-275 and 50-323) from R.P. Zimmerman of NRC to J.D. Shiffer of PG&E.
- 31. Letter from PG&E (J. O. Schuyler) to the NRC (D. G. Eisenhut), Design Verification Program Phase I Final Report, Diablo Canyon Unit 1, October 14, 1983. 32. Deleted in Revision 20. 33. Deleted in Revision 20.
- 34. Enova Engineering Services, "Position Paper on Shear Strength of A325 Bolts as Specified by the 7th Edition of AISC," dated July 3, 2008.
- 35. J. W. Fisher and Associates, "Review Comments on Position Paper on Shear Strength of A325 Bolts as Specified by the 7th Edition of the AISC Manual,"
dated July 10, 2008. DCPP UNITS 1 & 2 FSAR UPDATE 3.8-82 Revision 21 September 2013
- 36. NRC (D.P. Allison) Letter to PG&E, "Summary of Meeting Held on February 4, 1977 to Discuss the Diablo Canyon Seismic Design Reevaluation," with enclosures (Docket Nos. 50-275 and 50-323), dated May 18, 1977.
- 37. NRC, Safety Evaluation Report Related to the Operation of of the Diablo Canyon Nuclear Power Station, Units 1 and 2, NUREG-0675, Supplement No. 7, dated May 1978.
- 38. Robert P. Kennedy Structural Mechanics Consulting, "Comments on Position Paper on Shear Strength of A325 Bolts as Specified by the 7th Edition of AISC,"
Report No. RPK-80704, dated July 4, 2008.
- 39. PG&E Calculation 52.15.9.11, Revision 2, "Evaluation of Fuel Handling Building Crane and Fuel Handling Building Steel Superstructure of Added Loads Due to Attachment of Redundant Tension Links for Spent Fuel Transfer Cask Handling",
Page 133.
- 40. PG&E Calculation No. 2252 C-1 (SAP Calc. No. 9000041231), "Polar Crane ANSR Model Reconstruction and Benchmarking." 3.8.10 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures.
DCPP UNITS 1 & 2 FSAR UPDATE 3.9-1 Revision 21 September 2013 3.9 MECHANICAL SYSTEMS AND COMPONENTS 3.9.1 DYNAMIC SYSTEM ANALYSIS AND TESTING A mechanical design description of the internals and core components showing the differences and similarities between the two DCPP units is presented in Section 4.2.2. The dynamic analysis techniques and methods used to determine and confirm the dynamic response of the reactor internals are presented in the following section. Detailed information of the dynamic system analysis and testing is presented in the reports listed in Section 3.9.6. Chapter 14 describes the plant initial tests and operation.
A description of the analyses used in the design of safety-related mechanical equipment, such as pumps and heat exchangers, to withstand the DE, DDE, and HE seismic loadings is provided in Section 3.7. 3.9.1.1 Vibration Operational Test Programs This section describes the nature of flow-induced vibrations in the reactor coolant loops and the analyses performed to ensure such vibrations are at an acceptable level. 3.9.1.1.1 Main Piping System, Flow-Induced Vibration Pressure pulses, from the reactor coolant pump impeller are prevented from resulting in flow-induced vibrations in the main piping systems of the RCL. The reactor coolant pump perturbing frequency is quite high when compared to the piping natural frequency. Frequency separation, therefore, ensures a very small probability of self-excited or sympathetic vibration. 3.9.1.1.2 Reactor Internals Flow-Induced Vibration The dynamic behavior of reactor components has been studied using experimental data obtained from operating reactors along with results of model tests and static and dynamic tests. The following procedures have been performed in the study of thermal shield vibration:
(1) During a test program performed with a 1/7th-scale model, the natural frequencies of the thermal shield in water and the maximum vibration amplitude were measured. (2) Shaker test programs performed on a prototype thermal shield with the actual boundary conditions provided full-scale natural frequencies and mode shapes in air. These modes were established by measuring accelerations at the center, top (support elevation), and bottom of the shield. In Figure 3.9-3, the results obtained are plotted for n = 4 and correspond to a thermal shield with eight supports which are indicated on DCPP UNITS 1 & 2 FSAR UPDATE 3.9-2 Revision 21 September 2013 the same figure. The amplitudes of vibration are fitted with a curve y = A sin 4q.
(3) Maximum displacements were measured during the preoperational reactor test and were correlated with the information obtained in the 1/7th-scale model and shaker test. (4) In Figure 3.9-4, the maximum amplitudes of vibration are plotted as measured on a thermal shield with six supports. The experimental points have been least-square fitted with a curve y = A sin 3q. In general, the study follows two parallel procedures. Frequencies and spring constants are derived analytically, and these values are confirmed from the results of the tests. Damping coefficients are established experimentally, and forcing functions are estimated from pressure fluctuations measured during operation and in models. In parallel, the responses of important reactor structures were measured during preoperational reactor tests and the frequencies and mode shapes of the structures obtained. Once all the dynamic parameters were obtained as explained above, the forcing functions could be estimated. Internals behavior during reactor operation is measured using mechanical devices and nuclear noise methods.
Some components, such as control rod guide tubes, fuel rods, and incore instrumentation tubes are subjected to cross flow and parallel flow with respect to the axis of the structure. For both cases, cross and parallel, the response is obtained after the forcing function and the damping of the system are determined.
3.9.1.1.3 Vibration Monitoring Since internals of four loop reactors are designed and manufactured to essentially the same procedures, processes, and similar drawings, the response of these structures is similar. Performance data from the instrumentation of actual reactors, as well as mechanical and flow scale models, are available (References 2, 4, and 5). The pre- and post-operational flow test examinations of the Indian Point II Plant internals, the four loop prototype plant, have been completed indicating that all the components performed as predicted. No evidence or sign of damage or incipient failure was found.
The testing programs consisted of measurements of the stresses, deflections, and responses of selected key points in the internals structures during hot functional and low power physics tests. The main purpose of this testing program was to ensure that no unexpected large amplitudes of vibration existed in the internals structure during operation. The tests were extended to provide data and results on what were assumed to be indicators of overall core support structure performance and to verify particular stress and deflection quantities.
DCPP UNITS 1 & 2 FSAR UPDATE 3.9-3 Revision 21 September 2013 3.9.1.1.4 Loose-Parts Monitoring A loose-parts monitoring system is provided for early detection of possible loose parts in the RCS, in order to reduce the probability of loose parts causing damage to RCS components. This system is described in Section 4.4.5. 3.9.1.2 Dynamic Testing Procedure During startup functional testing, piping, including supports and restraints, of certain systems was observed carefully by experienced startup personnel. At selected points of calculated maximum movement, visual inspection and/or measurements were taken and compared with those calculated to establish that stress limits are not exceeded.
If vibration was noted to cause piping or supports movements beyond those allowed, corrective action in the form of additional or redesigned supports, snubbers, etc. was taken and the system was retested to determine that vibrations have been reduced to an acceptable level. Stress analysis on the system was rerun if deemed necessary by the designer. The systems and transients included in this program are listed below:
(1) Reactor coolant pumps start
(2) Reactor coolant pumps trip
(3) Main steam turbine stop valves trip
(4) Steam dump to condenser valves open (5) Main steam safety and relief valves lift and blowdown
(6) Pressurizer relief valves lift and blow down (Unit 1 only)
(7) Auxiliary feedwater pump turbine stop valve trip
(8) Charging pumps start and trip
(9) Safety injection pumps start and trip
(10) Residual heat removal (RHR) pumps start and trip
(11) Containment spray pumps start and trip (12) Accumulators discharge to loops
(13) Pressurizer spray valves open and trip closed
(14) Pressurizer power relief valves open DCPP UNITS 1 & 2 FSAR UPDATE 3.9-4 Revision 21 September 2013 Locations of observation points for piping movements for preoperational piping vibration tests for the above systems were determined from dynamic analysis performed on the piping systems, with system stiffness and restraint locations taken into account. Observed deflections were compared with code allowable values. 3.9.1.3 Dynamic System Analysis Methods for Reactor Internals To verify structural adequacy of reactor internal components and the reactor core for Diablo Canyon Units, nonlinear LOCA and seismic dynamic analyses are performed. These dynamic analyses are performed for both LOCA cold and hot leg breaks, as well as for seismic excitations of DDE and Hosgri (HE). For faulted conditions, the response of reactor internals due to DDE and LOCA conditions are additive by the SRSS (Square Root of the Sum of Squares) method. A HE and LOCA are also considered to occur simultaneously and, therefore, the combined response is considered by SRSS. The methods and techniques for these dynamic analyses are described below. 3.9.1.3.1 LOCA (Loss-Of-Coolant-Accident) Analysis Details of the RPV system finite element model which is used in these analyses are described. Results of these analyses consist of the nodal time history displacements and the interface impact loads on the reactor vessel, reactor internals and the core. The time history displacements of all major components such as reactor vessel head, vessel bottom and the vessel/barrel nozzles are also generated for their later use in the component stress analyses. The RPV system finite element model consists of three concentric structural submodels connected by nonlinear impact elements and linear stiffness matrices. The first sub-model represents the reactor vessel shell and its associated components. The reactor vessel is restrained by four reactor vessel supports (situated beneath alternate nozzles) and the attached primary coolant piping.
The second sub-model represents the reactor core barrel, thermal shield, lower support plate, tie plates, and the secondary support components for Unit 1, whereas, for Unit 2 the second sub-model is identical to that of unit 1 except that it has core barrel with neutron pads instead of thermal shield.
These sub-models are physically located inside the first, and are connected to them by stiffness matrices at the internals support ledges. The core barrel to the reactor vessel shell impact is represented by nonlinear elements at the core barrel flange, upper support plate flange, core barrel outlet nozzles, and the lower radial restraints. In addition, vertical impact loads on the fuel assembly top and bottom nozzles.
The third and innermost sub-model represents the upper support plate assembly consisting of guide tubes, upper support columns, upper and lower core plates, and DCPP UNITS 1 & 2 FSAR UPDATE 3.9-5 Revision 21 September 2013 fuel. The third sub-model is connected to the first and second by stiffness matrices and nonlinear elements. The fluid-solid interactions in the LOCA analysis are accounted for through the hydraulic forcing functions generated by Multiflex Code (Reference 3).
The WECAN computer code, which is used to determine the response of the reactor vessel and its internals, is a general purpose finite element code. In the finite element approach, the structure is divided into a finite number of discrete members or elements. The inertia and stiffness matrices, as well as the force array, are first calculated for each element in the local coordinates. Employing appropriate transformations, the element global matrices and arrays are assembled into global structural matrices and arrays, and used for dynamic solution of the differential equation of motion for the structure.
The WECAN Code solves equations of motion using the nonlinear modal superposition theory. Initial computer runs such as dead weight analysis and the vibration (modal) analyses are made to set the initial vertical interface gaps and to calculate eigen values and eigenvectors. The modal analysis information is stored on magnetic tapes, and is used in a subsequent computer run which solves equations of motion. The first time step performs the static solution of equations to determine steady state solution under normal operating hydraulic forces. After the initial time step, WECAN calculates the dynamic solution of equations of motion, nodal displacements, and impact forces, which are stored on tape for post-processing.
Reactor internals response to both cold and hot leg pipe ruptures was analyzed. The LOCA hydraulic forcing functions used in the RPV system analyses were obtained for hypothetical breaks considered in the main loop line. However, with the acceptance of DCPP Leak-Before-Break (LBB) by USNRC (Reference 14), the dynamic effects of breaks in the main reactor coolant loop no longer have to be considered in the design basis of analyses. Only the next most limiting breaks in auxiliary lines have to be considered.
Note that the preceding paragraphs describe the RPV and internals system dynamic analyses for which the WECAN computer code was used. Current analyses (such as the dynamic analyses performed in support of the replacement reactor vessel head project) utilize the ANSYS computer code. The methodology used to develop the ANSYS system models is consistent with the methodology used to develop historic WECAN models. The direct time integration method is used in ANSYS to solve the dynamic equations of motion for the system; whereas the nonlinear mode superposition method is used in WECAN to solve the dynamic equations of motion for the system.
The breaks considered for the replacement vessel head project included: (1) the accumulator line; (2) the pressurizer surge line; and (3) the residual heat removal line. DCPP UNITS 1 & 2 FSAR UPDATE 3.9-6 Revision 21 September 2013 3.9.1.3.2 Reactor Internals Components Subjected to Horizontal Excitations The analysis methodology is summarized below for components that are subject to horizontal excitations during LOCA conditions. The components include the core barrel, guide tubes, and upper support columns. It should be noted that with the acceptance of DCPP Leak-Before-Break (Reference 14), the dynamic effects of the main reactor coolant loop piping no longer have to be considered in the design basis analysis. Only the dynamic effects of the next most limiting breaks of auxiliary lines need to be considered; and consequently the components will experience considerably less load than those from the main loop line breaks. 3.9.1.3.2.1 Core Barrel For the hydraulic analysis of the pressure transients during hot leg blowdown, the maximum pressure drop across the barrel is a uniform radial compressive impulse. The barrel was analyzed for dynamic buckling using the following conservative assumptions:
(1) The effect of the fluid environment is neglected (water stiffening is not considered).
(2) The shell is treated as simply supported. During cold leg blowdown, the upper barrel is subjected to a nonaxisymmetric expansion radial impulse that changes as the rarefaction wave propagates both around the barrel and down the outer flow annulus between vessel and barrel. The analysis of transverse barrel response to cold leg blowdown was performed as follows: (1) The upper core barrel was treated as a simply supported cylindrical shell of constant thickness between the upper flange weldment and the lower core barrel weldment. No credit was taken for the supports at the barrel midspan offered by the outlet nozzles. This assumption leads to conservative deflection estimates of the upper core barrel. (2) The upper core barrel was analyzed as a shell with four variable sections to model the support flange, upper core barrel, reduced girth weld section, and a portion of the lower core barrel. (3) The barrel with the core and neutron shield panels(a) was analyzed as a beam elastically supported at the lower radial support, and the dynamic response obtained. While the above described blowdown analyses were performed in the original analysis, with the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 14), dynamic loads resulting from pipe rupture events in the main reactor coolant loop piping (a) Neutron shield panels on Unit 2 only. DCPP UNITS 1 & 2 FSAR UPDATE 3.9-7 Revision 21 September 2013 no longer have to be considered in the design basis structural analyses. Only the much smaller loads from RCS branch line breaks have to be considered. 3.9.1.3.2.2 Guide Tubes The dynamic loads on rod cluster control guide tubes are more severe for a LOCA caused by hot leg rupture than for an accident by cold leg over the rod cluster control guide tubes. Thus, the analysis was performed only for a hot leg blowdown.
The guide tubes in closest proximity to the ruptured outlet nozzle are the most severely loaded. The transverse guide tube forces during the hot leg blowdown decrease with increasing distance from the ruptured nozzle location. A detailed structural analysis of the rod cluster control guide tubes was performed to establish the equivalent cross section properties and elastic end support conditions. An analytical model was verified both dynamically and statically by subjecting the control rod cluster tube to a concentrated force applied at the transition plate. In addition, the guide tube was loaded experimentally using a load distribution to conservatively approximate the hydraulic loading. The experimental results consist of a load deflection curve for the rod cluster control guide tube, plus verification of the deflection criteria to ensure rod cluster control insertion.
While the above described blowdown analyses were performed in the original analysis, with the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 14), dynamic loads resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis structural analyses. Only the much smaller loads from RCS branch line breaks have to be considered. 3.9.1.3.2.3 Upper Support Column Upper support columns located close to the broken nozzle during the hot leg break will be subjected to transverse loads due to cross flow. The loads applied to the columns were computed with a method similar to the one used for the guide tubes, i.e., by taking into consideration the increase in flow across the column during the accident. The columns were studied as beams with variable sections and the resulting stresses were obtained using the reduced section modulus at the slotted portions. The models used for static (or steady-state dynamic) analysis are:
- The upper support, deep beam, and upper core plate were modeled with flat shell elements, the support columns with three-dimensional beam elements, and the fuel assemblies and holddown springs with three-dimensional spring elements. Because of symmetry, a one-eighth slice of the upper package was modeled. The core plate is perforated and was modeled as a geometrically equivalent solid plate that has elastic constants modified according to the theory of perforated plates.
DCPP UNITS 1 & 2 FSAR UPDATE 3.9-8 Revision 21 September 2013
- Columns of two different lengths were modeled: the long columns connecting the plates and the short columns connecting the beam grid with the upper core plate.
- The lower support structure was modeled using a finite-element structural analysis computer program. The lower core plate and upper core support, as well as the lower part of the core barrel, was represented by flat triangular shell elements. Reduced plate strength, due to the perforations, was accounted for by using an equivalent elastic modulus and Poisson ratio in the calculations. This structure was loaded with various vertical forces, due to normal and abnormal operation, and the deflections and stresses are obtained for each case. The experimental values were converted according to basic scaling laws and applied to the prototype structure. The test values are larger, as expected, since they are obtained in the absence of the core plate and support columns structures, making the lower core support more flexible.
Using the same model, this code was also used to compute stresses and deformation due to nonuniform temperature distributions. With temperature at the component surfaces and the gradient generated by the -heat generation as input for the system code, the deflected shape of the structure was obtained. Stresses in components, such as the perforated upper and lower core plates, core support plate, and top support plate, were then computed using the stress intensification factor provided by the standard theory of perforated plates.
3.9.1.4 Correlation of Test and Analytical Results The program used to establish the integrity of reactor internals has involved extensive design analysis, model testing, and post-hot functional inspection. Additionally, a full-size reactor has been instrumented to measure the dynamic behavior of a plant the size and type of DCPP. Measured values have been compared to predicted values.
The Indian Point II reactor has been established as the prototype for the DCPP Unit 1 internals verification program. The Trojan plant (Portland General Electric Company) provides additional internals verification for Unit 2. (Unit 1 has a thermal shield similar to Indian Point II; Unit 2 has neutron panels similar to Trojan.)
The only significant differences between the DCPP units' internals and Indian Point II are the modifications resulting from the use of a 17 x 17 fuel array in place of 15 x 15, and the replacement of the annular thermal shield with neutron shield panels. The change to neutron shield panels applies only to Unit 2. The change to 17 x 17 applies to both Units 1 and 2.
DCPP UNITS 1 & 2 FSAR UPDATE 3.9-9 Revision 21 September 2013 The only structural changes in the internals resulting from the design change from the 15 x 15 to the 17 x 17 fuel assembly are in the support columns and assembly guide tubes. The new 17 x 17 guide tubes are stronger and more rigid, hence they are less susceptible to flow-induced vibration problems. The fuel assembly itself is relatively unchanged in mass and spring rate, and thus no significant deviation is expected from the 15 x 15 fuel assembly vibration characteristics.
The remainder of the core structure design is identical to the prototypes that have been tested and proven to be well within design expectations and limits.
The Trojan plant is the lead plant featuring neutron panels and 17 x 17 fuel assemblies.
The Trojan plant internals were instrumented for strain measurements on the core barrel and on the guide tube subject to highest cross flow. The data obtained provided verification of Westinghouse analysis and scale model predictions of neutron panels and 17 x 17 internals behavior in a full-size plant. The Four Loop Internals Assurance Program conducted on Indian Point II, supplemented by the Trojan data on neutron shield panels and 17 x 17 fuel assemblies, jointly satisfy the intent of RG 1.20 (Reference 12) with respect to adequate plant testing of internals similar to those employed at DCPP. The core support structures received, in addition, the normal pre- and post-hot functional testing examination for integrity in accordance with Paragraph D, "Regulations for Reactor Internals Similar to the Prototype Design," of RG 1.20. This examination included the points shown in Figure 3.9-1 for Unit 1 and Figure 3.9-2 for Unit 2, and also:
(1) All major load bearing elements of the reactor internals relied on to retain the core structure in place (2) The lateral, vertical, and torsional restraints provided within the vessel
(3) Those locking and bolting devices whose failure could adversely affect the structural integrity of the internals (4) Those other locations on the reactor internal components that are similar to those which were examined on the prototype Indian Point II and Trojan designs The interior of the reactor vessel was also examined for evidence of loose parts or foreign material. Specifically, the inside of the vessel was inspected before and after the hot functional tests, with all the internals removed, to verify that no loose parts or foreign materials were in evidence.
DCPP UNITS 1 & 2 FSAR UPDATE 3.9-10 Revision 21 September 2013 Lower Internals A particularly close inspection was made on the following items or areas, using a 5x or 10x magnifying glass or penetrant test where applicable. The locations of these areas are shown in Figures 3.9-1 and 3.9-2 for Units 1 and 2, respectively:
(1) Upper barrel flange and girthweld
(2) Upper barrel to lower barrel girthweld
(3) Upper core plate aligning pin (examine for any shadow marks, burnishing, buffing, or scoring; check for the soundness of lockwelds) (4) Irradiation specimen basket welds
(5) Baffle assembly locking devices (check for lockweld integrity)
(6) Lower barrel to core support girthweld
(7) For Unit 1, the flexible tie connections (flexures) at the lower end of the thermal shield (8) For Unit 2, the neutron shield panel locking devices and dowel pin cover plate welds (examine the connections for evidence of change in tightness of lockweld integrity) (9) Radial support key welds to barrel (10) Insert locking devices (examine soundness of lockwelds)
(11) Core support columns and instrumentation guide tubes (check all the joints for tightness and soundness of the locking devices) (12) Secondary core support assembly welds
(13) Lower radial support lugs and inserts (Examine for any shadow marks, burnishing, buffing, or scoring. Checking the integrity of the lockwelds: these members supply the radial and torsional constraint of the internals at the bottom relative to the reactor vessel while permitting axial growth between the two. One would expect to see, on the bearing surfaces of the key and keyway, burnishings, buffing, or shadowing marks that would indicate pressure loading and relative motion between the two parts. Some scoring of engaging surfaces is also possible and acceptable.) (14) For Unit 1, mounting blocks thermal shield to core barrel (examine the connections for evidence of change in tightness or lockweld integrity) DCPP UNITS 1 & 2 FSAR UPDATE 3.9-11 Revision 21 September 2013 (15) For Units 1 and 2, gaps at baffle joints (check for gaps between baffle and top former and at baffle-to-baffle joints) Upper Internals A particularly close inspection was made on the following items or areas, using a magnifying glass of 5x or 10x magnification where necessary:
The locations of these areas are shown in Figures 3.9-1 and 3.9-2 for Units 1 and 2, respectively.
(1) Thermocouple conduits, clamps, and couplings
(2) Guide tube, support column, and thermocouple column assembly locking devices (3) Support column and conduit assembly clamp welds
(4) Upper core plate alignment inserts (Examine for any shadow marks, burnishing, buffing or scoring. Check for tightness and lock device integrity) (5) Connections of the support columns, mixing devices, and orifice plates to the upper core plate (check for tightness and lock device integrity) (6) Thermocouple conduit gusset and clamp welds (7) Thermocouple end-plugs (check for tightness)
(8) Guide tube closure welds, tube-transition plate welds, and card welds Acceptance standards are the same as required in the shop by the original design drawings and specifications.
During the hot functional test, the internals were subjected to a total operating time at greater than normal full flow conditions (four pumps operating) of at least 10 days. This provides a cyclic loading of approximately 107 cycles on the main structural elements of the internals. In addition, there was some operating time with only one, two, and three pumps operating. No signs of abnormal wear were found, no harmful vibrations were detected, and no apparent structural changes took place; therefore, the four loop core support structures are considered to be structurally adequate and sound for operation.
DCPP UNITS 1 & 2 FSAR UPDATE 3.9-12 Revision 21 September 2013 3.9.1.5 Analysis Methods Under LOCA Loadings The analysis methods used to confirm the structural design adequacy of the RCS under LOCA loadings are described in Section 5.2.1. With the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 14), dynamic LOCA loads resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis structural analyses; only the much smaller LOCA loads from RCS branch line breaks have to be considered (see Section 3.6.2.1.1.1). Since the breaks postulated for the original analyses are more severe than those that are now required to be considered, the original analyses are conservative. 3.9.1.6 Analytical Methods for ASME Code Class I Components Plastic instability allowable limits given in ASME Section III are not used when dynamic analysis is performed, except as noted in Section 5.2.1.11. The analysis methods have the limits established by the ASME Section III for Normal, Upset, and Emergency conditions. For these cases, the limits are sufficiently low to ensure that the analysis is not invalidated. For ASME Code Class I components, the stress limits for faulted loading conditions are specified in Section 5.2. For ASME components other than Class I and components not covered by the ASME Code, the stress limits for faulted loading conditions are specified in Sections 3.9.2 and 3.9.3, respectively. These faulted condition limits are established in such a manner that there is an equivalence with the adopted elastic limits and consequently will not invalidate the elastic system analysis. 3.9.1.7 Design and Analysis Details for the Pressurizer Safety and Relief System The method of analysis for safety valves and relief valves suitably accounts for the time-history of loads acting during and subsequent to valve opening (i.e., less than one second). The fluid-induced forcing functions are calculated for pertinent safety valve and relief valve discharge cases using one-dimensional equations for the conservation of mass, momentum, and energy.
The calculated forcing functions are applied at locations along the associated piping. Application of these forcing functions to the associated piping model constitutes the dynamic time-history analysis.
The dynamic response of the piping system is determined for the input forcing functions. Therefore, a dynamic amplification factor is inherently accounted for in the analyses.
Snubbers or strut-type restraints are used as required. The stresses resulting from the loads produced by the sudden opening of a relief or safety valve are combined with stresses due to other pertinent loads and are shown to be allowable limits of the ANSI B31.1/B31.7 Codes. Also, the analyses show that the loads applied to the nozzles of the safety and relief valves do not exceed the maximum loads specified by the manufacturer.
DCPP UNITS 1 & 2 FSAR UPDATE 3.9-13 Revision 21 September 2013 The pressurizer safety and relief valve discharge piping systems provide overpressure protection for the RCS. The three spring-loaded safety valves, located on top of the pressurizer, are designed to prevent system pressure from exceeding design pressure by more than 10 percent. The three power-operated relief valves, also located on top of the pressurizer, are designed to prevent system pressure from exceeding the normal operating pressure by more than 100 psi. The valve outlet side is sloped to prevent the formation of water pockets. The safety valves have been converted from water-seated to steam-seated, and the water loop seal was eliminated by providing a continuous drain.
The pressurizer safety valves, manufactured by Crosby, are self-actuated, spring-loaded valves with backpressure compensation. The power-operated relief valves, manufactured by Masoneilan, are air-operated globe valves, capable of automatic operation via high pressure signal or remote manual operation. The safety valves and relief valves are located in the pressurizer cubicle and are supported by the attached piping which, in turn, is supported by a system of beams, struts, and snubbers. If the pressure exceeds the setpoints, the valves open. With a pressurizer safety valve water loop seal (now eliminated), the water slug from the loop seal discharges and the water slug, driven by high system pressure, generates transient thrust forces at each location where a change in flow direction occurs. The valve discharge conditions are considered in the analysis of the PSARV piping systems as follows: (a) the three safety valves remain closed, and (b) the three relief valves open simultaneously while the safety valves are closed. In addition to these two cases, which consider water seal discharge (water slug followed by steam), solid water from the pressurizer (cold overpressure) is also investigated. Even though the water loop seal has been eliminated, the analysis has not been revised to reflect any added margins because the valve discharge conditions without the water slug are less severe than those originally considered with the water slug.
For each pressurizer safety and relief piping system, an analytical hydraulic model is developed. The piping from the pressurizer nozzle to the relief tank nozzle is modeled as a series of single pipes. The pressurizer is modeled as a reservoir which contains stream at constant pressure (approximately 2500 psia for safety system and approximately 2350 psia for relief system) and at constant temperature of approximately 680°F. The pressurizer relief tank is modeled as a sink which contains steam and water mixture.
Fluid acceleration inside the pipe generates reaction forces on all segments of the line which are bounded at either end by an elbow or bend. Reaction forces resulting from fluid pressure and momentum variations are calculated. These forces are defined in terms of the fluid properties for the transient hydraulic analysis. Unbalanced forces are calculated for each straight segment of pipe from the pressurizer to the relief tank. The time histories of these forces are used for the subsequent structural analysis of the pressurizer safety and relief lines.
DCPP UNITS 1 & 2 FSAR UPDATE 3.9-14 Revision 21 September 2013 The structural model used in the seismic analysis of the safety and relief lines is modified for the valves thrust analysis to represent the safety and relief valve discharge. The time-history hydraulic forces are applied to the piping system lump mass points. The dynamic solution for the valve thrust is obtained by using a modified predictor-corrector-integration technique and normal mode theory.
The time-history solution is performed in subprogram FIXFM3. The input to this subprogram consists of the natural frequencies and normal modes, applied forces, and nonlinear elements. The natural frequencies and normal modes for the modified pressurizer safety and relief line dynamic model are determined with the WESTDYN program. The support loads are computed by multiplying the support stiffness matrix and the displacement vector at each support point. The time-history displacements of the FIXFM3 subprogram are used as input to the WESDYN2 subprogram to determine the internal forces, deflections, and stresses at each end of the piping elements.
The loading combinations considered in the analysis of the pressurizer safety and relief valve (PSARV) piping are given in Table 3.9-1. These load combinations are consistent with the final recommendations of the piping subcommittee of the EPRI PWR PSARV performance test program. 3.9.2 ASME CODE CLASS II AND III COMPONENTS This section discusses the design criteria for DCPP Code Class II and III components. The design of these components is based on the requirements of various codes and standards that were in effect when the items were purchased. These codes and standards have been widely used by the nuclear industry and were, to a large extent, incorporated or referenced in the 1971 edition of the ASME Boiler and Pressure Vessel Code, Section III. If the 1971 edition of the ASME Boiler and Pressure Vessel Code, Section III, had been available during the design of DCPP, all these Code Class II and III components would have been in accordance with the requirements for ASME Code Class II and III components.
The DCPP Q-List (see Reference 8 of Section 3.2) lists the codes and standards to which Code Class II and III components were designed. The quality group classifications for DCPP fluid systems and fluid systems components are described in Section 3.2.2. 3.9.2.1 Plant Conditions and Design Loading Combinations Design pressure, temperature, and other loading conditions that provide the bases for design of fluid systems or components are presented in the corresponding sections that describe the components and systems; see Chapters 6, 7, 9, and 11. Design codes, standards, and their applicability to systems and components are presented in Section 3.2.2.
DCPP UNITS 1 & 2 FSAR UPDATE 3.9-15 Revision 21 September 2013 3.9.2.2 Design Loading Combinations Design Criteria for Westinghouse Code Class II and III components, are provided in Tables 3.9-2 through 3.9-7. Table 3.9-8 provides design information for selected tanks. 3.9.2.3 Design Stress Limits Stress limits for Westinghouse ASME Code Class II and III components are provided in Table 3.9-2 through 3.9-7. Stress limits were selected to comply with the intent of ASME Code Section III and are sufficiently low to provide assurance that no gross deformation will occur in active components and that the active components(a) will operate as required following the event. The limits established for passive (inactive) components(b) are intended to ensure that violation of the pressure retaining boundary will not occur.
The designs of the condensate storage tanks, refueling water storage tanks, and the fire water and transfer tank are based on the AWWA D100, 1967 Code, with stress allowables restricted to those permitted by ASME Code Section VIII, Division 1. The design basis of these tanks is discussed in Section 3.8.3. Piping stresses resulting from the seismic analyses are combined with deadload stresses, pressure stresses, and other stresses caused by other sustained loads, as suggested in ANSI B31.1 by the following equations: hAnS1.0ZM0.75i4tPDo+ (3.9-1) hBAnS1.2ZM0.75iZM0.75i4tPDo++ (3.9-2) hBAnS1.8Z'M0.75iZM0.75i4tPDo++ (3.9-3) hBAnS2.4Z"M0.75iZM0.75i4tPDo++ (3.9-4) ASZMci (3.9-5) where: Sh = basic material allowable stress at operating temperature, psi (a) Active components are those whose operability is relied upon to perform a safety function such as safe shutdown of the reactor or mitigation of the consequences of a postulated pipe break in the reactor coolant pressure boundary. (b) Passive components are those whose operability (e.g., valve opening or closing, pump operation, or trip) are not relied upon to perform a safety function. DCPP UNITS 1 & 2 FSAR UPDATE 3.9-16 Revision 21 September 2013 P = internal pressure, psig Do = outside diameter of pipe, in tn = nominal wall thickness of pipe, in Z = section modulus, in3 i = stress intensification factor. The product of 0.75 x i shall never be taken as less than 1 MA = resultant moment loading on cross section due to deadload and other sustained loads, in-lb MB = one-half of the resultant moment due to DE loads plus one-half of the full range of the resultant moment due to DE seismic anchor movements (SAM) if not included in Equations 3.9-5 or 3.9-6 MB' = same as MB except that moments from DDE are used instead of DE and anchor movements due to DDE are excluded MB" = same as M except the moments from HE are used instead of DE and anchor movements due to HE are excluded MC = the larger of (a) the full range of resultant moment due to seismic anchor movements (SAM), or (b) the range of resultant moment due to normal thermal expansion and anchor movements plus one-half of the full range of resultant moment due to SAM, in-lb SA = f (1.25 Sc + 0.25 Sh) Sc = basic allowable stress at cold (ambient) temperature, psi f = stress range reduction factor for cyclic loading = 1 (There are no events causing more than 7000 loading cycles for DCPP) If Equation 3.9-5 is not satisfied, then the following equation must be satisfied:
)S(SZMiZM0.75i4tPDoAhCAn+++ (3.9-6) For hydrodynamic loadings the following stress equations must be satisfied:
hDAnS1.2ZM0.75iZM0.75i4tPDo++ (3.9-7) h1/22D2BAnS1.8)M(MZ0.75iZM0.75i4tPDo+++ (3.9-8) where: MD = one half of the resultant moment due to hydrodynamic loads All Design Class I pipe stresses were found to be within allowable limits specified in Equations 3.9-1 to 3.9-8.
DCPP UNITS 1 & 2 FSAR UPDATE 3.9-17 Revision 21 September 2013 3.9.2.4 Analytical and Empirical Methods for the Design of Pumps and Valves The Quality Code Class II and III pumps and valves were designed and constructed to Design Class I standards and manufactured under approved quality assurance programs. PG&E inspectors routinely performed audits, inspections, and witnessed testing of Quality Code Class II and III components as they were manufactured.
Quality Code Class II and III pumps and valves were designed in accordance with the codes and standards listed in the DCPP Q-List (see Reference 8 of Section 3.2) and Table 3.2-2. These were the codes and standards that were in effect when the items were purchased. The stress limits selected are sufficiently low to provide assurance that no gross deformations will occur in active components; therefore, the active components will perform as required.
The pumps purchased by Westinghouse were analyzed for the forces resulting from seismic accelerations in the horizontal and vertical directions applied simultaneously. The pumps were designed to have a natural frequency in excess of 30 cps to eliminate any amplification of the seismic floor accelerations in the pump support structures.
The Westinghouse pumps were subjected to a series of tests prior to installation in the plant. The in-shop tests included (a) hydrostatic tests to 150 percent of the design pressure, (b) seal leakage tests, (c) net positive suction head (NPSH) tests to develop the minimum suction head necessary to allow operation, and (d) functional performance tests.
The pumps purchased by PG&E were designed in accordance with ASME standards or PG&E power plant pump standards. The design standards required were determined for each pump by reviewing the pump service conditions. Seismic calculations provided by the manufacturers were reviewed by PG&E to ensure that the loads developed from the combination of the design seismic horizontal and vertical acceleration did not exceed those allowed by applicable codes or standard engineering practices. Seismic calculations were not requested when the seismic adequacy could be ensured by testing or a comparative review of pump design. Hydrostatic tests to 150 percent of design pressure were performed on the pumps purchased by PG&E. The pumps also were subjected to performance tests consistent with the requirements of the Hydraulic Institute Standards or PG&E's power plant pump standards.
In addition to the above described tests, which were performed prior to installation in the plant, numerous tests were performed on the pumps during the preoperational test period. Cold hydrostatic pressure tests, hot functional qualification tests, periodic inservice inspections, and periodic inservice operational tests are performed on Quality Code Class II and III pumps after installation in the plant. These tests verify the functional ability of the pumps and ensure the operability of active safety-related pumps for the design life of the plant.
DCPP UNITS 1 & 2 FSAR UPDATE 3.9-18 Revision 21 September 2013 The supports of all Quality Code Class II and III pumps were designed to withstand the effects of the DE and reviewed for the DDE and HE. These considerations prevent supports of active safety-related pumps from deflecting and impairing the operability of the pump.
The Quality Code Class II and III valves purchased by Westinghouse were designed to the pressure and temperature requirements of the American Standard Association (ASA) B16.5 or the Manufacturers Standardization Society Standard Practice No. 66 (MSS SP66). The valves were tested to the requirements of MSS SP61. These tests included hydrostatic shell and seat leakage tests.
The Quality Code Class II and III valves purchased by the Company were designed, manufactured, and tested in accordance with the Draft ASME Code for Pumps and Valves for Nuclear Power, November 1968 or later editions, the ASME Code, Section III, 1974 edition, ANSI B16.5, and/or the MSS SP66. In situ seismic testing of five representative valves was performed at the DCPP site. The purpose of this testing was to demonstrate that valves would indeed function when subjected to simulated seismic loads. Each valve was subjected to a static load applied at the center of gravity of the extended structure. The load was applied in the direction that would yield the largest deflection for the given load. While the valve was held in the deflected position, the valve was stroked. Any differences in deflected valve stroking time, line voltage, and motor current (as compared to the undeflected readings) would indicate the effect of a seismic event on valve operability. The valve was again stroked open and closed after removal of the static load to demonstrate that the valve had returned to its initial condition. The five selected valves tested by this method performed satisfactorily while subjected to the simulated load. The operability indicators of motor current, voltage, and valve stroke time were essentially the same for both the deflected and undeflected tests. During the preoperational piping dynamics effects test program described in Section 3.9.1.2, any excessive piping deflections and vibrations were noted and corrected. Since all valves are supported as part of adjoining piping, this program ensures that the deflections by the pipe (and valve) supports will not impair the operability of active safety-related valves. The attention given to the design, manufacture, and testing of the Quality Code Class II and III pumps and valves ensures that the components will operate as required during or following any expected plant transient.
An evaluation and tabulation of all active valves is presented in Tables 3.9-9 and 6.2-39. An active valve is a valve that must perform a mechanical motion in order to shut down the plant or mitigate the consequences of a postulated event. Check valves with flow through the valves secured are considered passive devices. Check valves designed to close without operator action following an accident are considered active devices. The position each valve assumes on power failure is listed in these tables. DCPP UNITS 1 & 2 FSAR UPDATE 3.9-19 Revision 21 September 2013 The design approach and criteria used to ensure the protection of all critical systems and containment from the effects of pipe whip, are presented in Section 3.6. Section 3.6 also presents the criteria for postulated pipe breaks. Section 3.6 also discusses that with the acceptance of the DCPP leak-before-break analyses by the NRC (Reference 14), the dynamic effects of breaks in the main reactor coolant loop piping no longer have to be considered in the design basis analyses (see Section 3.6.2.1.1.1). Only the dynamic effects of postulated breaks in the RCS branch lines and other high energy lines have to be considered. 3.9.2.5 Design and Installation Criteria, Pressure-Relieving Devices The main steam safety valves are located outside the primary containment directly on main steam leads 1 and 2, and on external headers on main steam leads 3 and 4. Five safety valves are provided for each steam generator, for a total of 20 safety valves. The safety valve headers and main steam lead connections were designed to ANSI B31.1-1967. Fabrication and erection were in accordance with the ASME Boiler and Pressure Vessel Code, Section I, 1968.
The safety valves are of the single discharge type and were built in accordance with ASME Boiler and Pressure Vessel Code, Section III. The valve discharge consists of an elbow attached to the safety valve outlet. The elbow discharges into a stack that is structurally independent of the valve and is oriented at approximately 36° to the vertical centerline of the safety valve. The stacks are supported to restrain the discharge reactions. Provisions are made to ensure that the safety valve discharge elbow and stack have adequate clearances during all phases of operation.
With the above safety valve discharge arrangement, the sustained blow force developed during valve operation intersects the vertical centerline of the safety valve header nozzle and the base of the header nozzle extrusion. The safety valve nozzles on the headers and on the main steam leads have been analyzed to ensure that the sustained forces developed during valve operation will not develop stresses in excess of those allowed by ANSI B31.1.
The main steam leads are anchored by the main steam flued heads which are structurally located in the reactor containment wall and are supported for the deadweight, thermal, seismic, and safety valve forces that may develop within the Design Class I portion. The two external safety valve headers on main steam leads 3 and 4 are independently supported in a similar fashion. 3.9.2.6 Stress Levels for Design Class I Components and Supports The loading combinations and acceptance criteria used for piping (except for PSARV piping) primary equipment, and primary equipment supports in the Westinghouse scope of analysis are provided in Table 5.2-5, 5.2-6, 5.2-7, and 5.2-8, and also in Table 3.9-2 through 3.9-7. The load combinations and acceptance criteria used by Westinghouse for the PSARV analysis are provided in Table 3.9-1 and are consistent with the final DCPP UNITS 1 & 2 FSAR UPDATE 3.9-20 Revision 21 September 2013 recommendations of the piping subcommittee of the EPRI PWR PSARV performance test program.
Maximum allowable stresses for various loading combinations on hangers within B31.1 Code jurisdiction are as follows:
DE DDE HE Tension 0.417 Fy 0.9 Fy Least of 1.2 Fy or 0.7 Fu Shear 0.694 Fv 1.44 Fv 1.44 Fv Compression 0.694 Fa 1.33 Fa 1.33 Fa Bending 0.694 Fb 1.5 Fb 1.88 Fb Bearing 0.625 Fy Not Applicable Not Applicable
where Fy, Fu, Fv, Fa, and Fb are from Part 5 of the AISC Steel Construction Manual, 7th Edition.
Supporting structures (supplemental steel) are in accordance with the 7th Edition of the AISC Steel Construction Manual. The stress limits and load combinations used by PG&E for equipment and equipment supports for their scope of analysis are: DE Seismic Event Component Stress Limits(a)(b)(c)(d)
(Except cast iron) Qm 1.1 S (active or inactive) (Qm or QL) + Qb 1.65 S Inactive cast iron, pressure-retaining Qp 0.1 Su components (Qm or QL) + Qb 1.5 x 0.1 Su Inactive cast iron, nonpressure-retaining components (Qm or QL) + Qb 1.0 x 0.2 Su (a) Qm = general membrane stress, ksi. This stress is equal to the average stress across the solid section under consideration. It excludes discontinuities and concentrations and is produced only by pressure and other mechanical loads. (b) QL = local membrane stress, ksi. This stress is the same as Qm except that it includes the effect of discontinuities. (c) Qb = bending stress, ksi. This stress is equal to the linear varying portion of the stress across the solid section under consideration, excludes discontinuities and concentration, and is produced only by mechanical loads. (d) S = material allowable stress listed in either 1971 or 1974 ASME Code, Section III, or the code the component was purchased and manufactured under, allowable stress values. The allowable stress shall correspond to the highest metal temperature at the section under consideration during the condition under consideration.
DCPP UNITS 1 & 2 FSAR UPDATE 3.9-21 Revision 21 September 2013 Support Element Plate and shell(e) Qm 1.0 S Qm + Qb 1.5 S Linear(f) 1974 ASME Code, Section III, Appendix XVII and Subsection NF Bolts 1974 ASME Code, Section III, Appendix XVII and/or Code Case 1644, and/or AISC Manual, 7th Edition DDE/HE Seismic Event Component Stress Limits (see notes a, b, c) Inactive Qm 2.0 S (Except cast iron) (Qm or QL) + Qb 2.4 S Active Qm 1.2 S (Except cast iron) (Qm or QL) + Qb 1.8 S Inactive cast iron, pressure-retaining Qp 0.1 Su components (Qm or QL) + Qb 2.4 x 0.1 Su Inactive cast iron, nonpressure- retaining components (Qm or QL) + Qb 2.0 x 0.2 Su Support Elements Plate and shell (see note e) Qm 1.2 S (active components) (Qm + Qb) 1.8 S (e) Plate and shell type supports: Plate and shell type component supports are supports such as vessel skirts and saddles that are fabricated from plate and shell elements and are normally subjected to a biaxial stress field. (f) S = material allowable stress listed in either 1971 or 1974 ASME Code, Section III, or the code the component was purchased and manufactured under, allowable stress values. The allowable stress shall correspond to the highest metal temperature at the section under consideration during the condition under consideration. DCPP UNITS 1 & 2 FSAR UPDATE 3.9-22 Revision 21 September 2013 Plate and shell Qm 2.0 S (inactive components) (Qm + Qb) 2.4 S Linear 1974 ASME Code, Section III, Appendix XVII, (see note f) Subsection NF and Appendix F (stresses not to exceed Sy(g) for active components) Bolts 1974 ASME Code, Section III, Appendix XVII and/or Code Case 1644 plus Appendix F and/or ASIC Manual, 7th Edition Load Combinations (3.1.1) DE + Pn + Tn + D + N + O (3.1.2) DDE + Pa + Ta + D + N + O (3.1.3) HE + Pn + D + N + O where the following loads apply, as applicable:
HE = loads from Hosgri earthquake Pn = Pressure, normal Pa = Pressure, accident Tn = Temperature, normal Ta = Temperature, accident DE = DE DDE = DDE D = Deadweight N = Nozzle O = Operating
Table 3.9-12 lists PG&E Class I equipment that has been seismically qualified. 3.9.2.7 Field Run Piping Systems All Category I piping and pipe supports designed in the field are either analyzed or designed to a conservative standard, provided by PG&E engineering staff, for seismic and thermal loads.
(g) Sy = material allowable stress listed in either 1971 or 1974 ASME Code, Section III, or the code the component was purchased and manufactured under, minimum yield stress. The yield stress shall correspond to the highest metal temperature at the section under consideration during the condition under consideration.
DCPP UNITS 1 & 2 FSAR UPDATE 3.9-23 Revision 21 September 2013 3.9.3 CORE AND REACTOR INTERNALS 3.9.3.1 Core and Internals Integrity Analysis (Mechanical Analysis) Stainless steel clad silver-indium-cadmium alloy absorber rods are resistant to radiation and thermal damage, thereby ensuring their effectiveness under all operating conditions. Rods of similar design have been successfully used in the original and reload cores of San Onofre, Connecticut Yankee, and others.
Two burnable poison rods (Reference 6) of smaller length but similar in design to those used in DCPP were exposed to in-pile test conditions in the Saxton Test Reactor in October 1967. A visual examination of the rods was made in early June 1968 and a visual and profilometer examination was made on July 30, 1968, after an exposure of 1900 effective full power hours (approximately 25 percent B10 depletion). The rods were found to be in excellent condition and profilometry results showed no dimensional variation from the initial condition.
An experimental verification of the reactivity worth calculations for borosilicate glass tubing has been accomplished. Similar rods have been successfully operated in the Ginna Reactor (Reference 7) with no evidence of deficiency. Manufacturing defects did not appear during the hot functional tests because any manufacturing defects were detected in the shop or during the assembly period. The basic program that is currently being used to ensure adequacy of manufacturing practices consists of:
(1) Extremely thorough nil ductility temperature and quality assurance programs at the internals vendors (2) Extensive visual examination at the plant site prior to hot functional testing of the primary system (3) Running the hot functional test with full flow for 240 hours that accumulates approximately 107 cycles on the majority of the core structure components (4) Reexamining all areas of the internals after the 240-hour hot functional test The response of the reactor core and vessel internals under excitation produced by a simultaneous complete severance of a reactor coolant pipe and seismic excitation for a typical Westinghouse pressurized water reactor plant internals was determined. The following mechanical functional performance requirements applied: (1) Following the DBA, the basic operational or functional requirement to be met for the reactor internals is that the plant shall be shut down and cooled in an orderly fashion so that fuel cladding temperature is kept within DCPP UNITS 1 & 2 FSAR UPDATE 3.9-24 Revision 21 September 2013 specified limits. This implies that the deformation of certain critical reactor internals must be kept sufficiently small to allow core cooling.
(2) For large breaks, the reduction in water density greatly reduces the reactivity of the core, thereby shutting down the core whether the rods are tripped or not. The subsequent reflooding of the core by the ECCS with borated water maintains the core in a subcritical state. Therefore, the main requirement is to ensure effectiveness of the ECCS. Insertion of the control rods, although not needed, gives further assurance of the ability to shut the plant down and keep it in a safe shutdown condition. (3) The functional requirements for the core structures during the DBA are shown in Table 3.9-10. The inward upper barrel deflections are controlled to ensure no contacting of the nearest rod cluster control guide tube. The outward upper barrel deflections are controlled in order to maintain an adequate annulus for the coolant between the vessel inner diameter and core barrel outer diameter. (4) The rod cluster control guide tube deflections are limited to ensure operability of the control rods. (5) To ensure no column loading of rod cluster control guide tubes, the upper core plate deflection is limited to the value shown in Table 3.9-10. (6) The reactor has mechanical provisions that are sufficient to maintain the design core and internals and to ensure that the core is intact with acceptable heat transfer geometry following transients arising from the DBA operating conditions (References 2, 8, and 13). (7) The core internals are designed to withstand mechanical loads arising from DE, DDE, and pipe ruptures (References 2, 4, 8, and 13). While these performance requirements originally had to be met for load combinations that included the contribution from a main RCS loop line break, with the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 14), dynamic loads resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis structural analyses and included in the loading combinations; only the much smaller loads from RCS branch line breaks have to be considered (see Section 3.6.2.1.1.1).
DCPP UNITS 1 & 2 FSAR UPDATE 3.9-25 Revision 21 September 2013 3.9.3.2 Faulted Conditions The following events were considered in the faulted conditions category:
(1) Loads produced by a double-ended pipe rupture of the main coolant loop DBA for both the cold and hot leg breaks. The methods of analysis adopted were related to the type of accident assumed (cold leg break or hot leg break).
(2) Response due to a DDE or HE, as described previously in the seismic analysis (3) Most unfavorable combination of DDE and DBA. Maximum stresses obtained in each case were added in the most conservative manner. Maximum stress intensities are compared with allowables for each condition. When fatigue is of concern, the applicable stress concentrations factors are utilized and peak stresses are used to establish the usage factor. Elastic analysis is used to obtain the response of the structure and the stress analysis for each component is performed on an elastic basis. For faulted conditions, stresses are above yield in a few locations. For these cases only, when deformation requirements exist, a plastic analysis is independently performed to ensure that functional requirements are maintained (guide tubes deflections and core barrel expansions). The elastic limit allowable stresses are used to compare with the results of the analysis. No inelastic stress limits are used.
These analyses showed that the stresses and deflections that would result following a faulted condition are less than those that would adversely affect the integrity of the structures. Also, the natural and applied frequencies were such that resonance problems should not occur.
While these events and event combinations were considered in the original analysis for faulted conditions, with the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 14), dynamic loads resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis structural analyses and included in the loading combinations; only the much smaller loads from RCS branch line breaks have to be considered (see Section 3.6.2.1.1.1). 3.9.3.3 Reactor Internals Response Under LOCA and Seismic Excitations The reactor vessel/internals/fuel system dynamic analyses for Diablo Canyon Units 1 & 2 were performed in the 1987-1988 timeframe to verify structural adequacy of the core during transition from 17x17 standard fuel to 17x17 VANTAGE 5 fuel. These dynamic analyses were performed for the LOCA and seismic design conditions of DE, DDE, and Hosgri; and details of these analyses are given in Reference 15. DCPP UNITS 1 & 2 FSAR UPDATE 3.9-26 Revision 21 September 2013 The system mathematical models for Diablo Canyon Units 1 & 2 used in the LOCA and seismic analyses are three-dimensional nonlinear finite element models, which are described in detail in Reference 15. The major difference between the LOCA and seismic models is that the seismic model includes the hydrodynamic mass matrices in the vessel/barrel downcomer annulus to account for the fluid-solid interactions. The fluid-solid interactions in the LOCA analysis are accounted through the hydraulic forcing functions generated by Multiflex Code (Reference 3). Another difference between the LOCA and seismic models is the difference in loop stiffness matrices. The seismic model uses the unbroken loop stiffness matrix, whereas the LOCA model uses the broken loop stiffness matrix. Except for these two differences, the RPV system seismic model is identical to that of the LOCA model.
It is important to note that the LOCA analyses described below are the analyses originally performed for the RCS faulted conditions. With the acceptance of the DCPP Leak-Before-Break (LBB) by the USNRC (Reference 14), the dynamic LOCA loads resulting from the pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis structural analyses and including the loading combinations. With LBB acceptance, the next most limiting breaks which need to be considered are the auxiliary line breaks consisting of accumulator line, pressurizer surge line and RHR line. The LOCA loads imposed on the RPV system from these auxiliary line breaks are generally significantly lower than those obtained from the main loop line breaks discussed below. This reduction in LOCA loads for the auxiliary line breaks is due to the fact that the auxiliary lines have a smaller break size, location of the breaks are farther away from the vessel nozzles, and the absence of cavity pressurization loads. It should also be noted that, in general, for faulted conditions the imposed loading on the reactor vessel and its internals due to seismic (DDE) and LOCA conditions are additive by the square root of the sum of squares (SRSS) method. A Hosgri Earthquake (HE) and LOCA are also considered to occur simultaneously and, therefore, the combined loading is considered by SRSS. Therefore, with LBB invoked, the combination of LOCA and seismic loads on the RPV system will be considerably lower than those obtained from main loop piping breaks. 3.9.3.3.1 Reactor Internals Response Under Seismic Excitations. The seismic analysis included the effects of simultaneous application of time history accelerations in three orthogonal directions. The Westinghouse generated synthesized time history accelerations for DE, DDE, and Hosgri response spectra were used in a 1987-1988 analyses. The references of these Westinghouse generated synthesized time histories are also given in Reference 15.
As mentioned earlier, fluid-structure or hydroelastic interaction is included in the reactor pressure vessel model for seismic evaluations. The horizontal hydroelastic interaction is significant in the cylindrical fluid flow region between the core barrel and the reactor vessel annulus. Mass matrices with off-diagonal terms (horizontal degrees-of-freedom DCPP UNITS 1 & 2 FSAR UPDATE 3.9-27 Revision 21 September 2013 only) attach between nodes on the core barrel, thermal shield and the reactor vessel shell (see, e.g., Figure 2-5 of Reference 15, assembled finite element model for Unit 1). The mass matrices for the hydro-elastic interactions of two concentric cylinders are developed using the work of Reference 17. For the case of an incompressible, frictionless fluid displaced in the annulus due to motion of the cylinders, the expression for the hydrodynamic mass matrix connecting the inner and outer cylinders is derived. The diagonal terms of the mass matrix are similar to the lumping of water mass to the vessel shell, thermal shield, and core barrel. The off-diagonal terms reflect the fact that all the water mass does not participate when there is no relative motion of the vessel and core barrel. It should be pointed out that the hydrodynamic mass matrix has no artificial virtual mass effect and is derived in a straight-forward, quantitative manner.
The matrices are a function of the properties of two cylinders with the fluid in the cylindrical annulus, specifically, inside and outside radius of the annulus, density of the fluid and length of the cylinders. Vertical segmentation of the reactor vessel and the core barrel allows inclusion of radii variations along their heights and approximates the effects of beam mode deformation. These mass matrices were inserted between the selected nodes on the core barrel, thermal shield, and the reactor vessel (see Figure 2-5 of Reference 15).
The WECAN computer code, which is used to determine the response of the reactor vessel and its internals, is a general purpose finite element code. In the finite element approach, the structure is divided into a finite number of discrete members or elements. The inertia and stiffness matrices, as well as the force array, are first calculated for each element in the local coordinates. Employing appropriate transformations, the element global matrices and arrays are assembled into global structural matrices and arrays, and used for dynamic solution of the differential equation of motion for the structure. Note that the preceding paragraphs describe the RPV and internals system dynamic analyses for which the WECAN computer code was used. Current analyses (such as the dynamic analyses performed in support of the replacement vessel head project) utilize the ANSYS computer code. The methodology used to develop the ANSYS system models is consistent with the methodology used to develop historic WECAN models. The direct time integration method is used in ANSYS to solve the dynamic equations of motion for the system; whereas the nonlinear mode superposition method is used in WECAN to solve the dynamic equations of motion for the system. 3.9.3.3.2 Reactor Internals Response During Loss-Of-Coolant-Accident (LOCA) Conditions The mechanical response of the reactor coolant system subjected to a LOCA transient is performed in three steps. First, the reactor coolant system is analyzed for the effects of loads induced by normal operation which include thermal, pressure and dead weight effects. From this analysis, the loop mechanical forces acting on the RPV that would result from the release of equilibrium forces at the break locations are obtained. In the second step, the loop mechanical loads, reactor internal hydraulic forces, jet DCPP UNITS 1 & 2 FSAR UPDATE 3.9-28 Revision 21 September 2013 impingement forces, and reactor cavity pressurization forces are simultaneously applied; and the RPV displacements due to the LOCA are calculated. Finally, the structural integrity of the reactor coolant loop and component supports to deal with the LOCA are evaluated by applying the reactor vessel displacements to a mathematical model of the reactor coolant loop.
In 1987-1988, the RPV system LOCA analyses for the Diablo Canyon units were performed for the most limiting breaks consisting of: (a) RPV inlet nozzle break, (b) RPV outlet nozzle break, and (c) RCP outlet nozzle break. These break locations have been determined by detailed stress and fatigue analyses of the reactor coolant loop piping system (Reference 18). As mentioned earlier, the RPV system finite element model for LOCA analysis is identical to that of the seismic model except that it does not have hydrodynamic mass matrices in the downcomer region.
In 2005, the RPV system LOCA analysis was performed for the Unit 2 barrel/baffle region conversion from downflow to the upflow configuration. For DCPP Unit 2, considering LBB acceptance, the next most limiting auxiliary line breaks are the pressurizer surge line break (98.31 in2) on the hot leg and the accumulator line break (60.13 in2) on the cold leg. Postulated residual heat removal (RHR) auxiliary line breaks are bounded by the pressurizer surge line break for Unit 2.
In order to study LOCA hydraulic forces for the DCPP Unit 2 Upflow Conversion Program, the following vessel/internal break cases were analyzed:
- 1. Pressurizer Surge Line Break
- 2. Accumulator Line Break A 1 millisecond break-opening-time (BOT) was employed in the vessel forces analyses for DCPP Unit 2, consistent with the MULTIFLEX licensing requirements. All break cases used flexible beam modeling for the core barrel. The analysis conservatively assumed a limiting full power RCS cold leg temperature of 526°F (including uncertainty) which bounds the minimum cold leg temperature of 531.9°F (excluding uncertainty) for DCPP Unit 2. These conditions bound the most severe operating conditions, which encompasses Tavg coastdown conditions. Thus, the effects of a Tavg coastdown are accounted for in the vessel forces analysis. In addition, the Delta-54 replacement steam generator (RSG) was accounted for in the analyses. Previous studies have shown that the steam generator design has a relatively insignificant effect on the vessel forces analyses, so operation of Unit 2 with either the original Model 51 steam generators or the Delta-54 stream generators is acceptable with respect to the vessel forces analyses.
Following a postulated LOCA pipe rupture, forces are imposed on the reactor vessel and its internals. These forces result from the release of the pressurized primary system coolant, and for guillotine pipe breaks from the disturbance of the mechanical equilibrium in the piping system prior to the rupture. The release of pressurized coolant results in traveling depressurization waves in the primary system. These DCPP UNITS 1 & 2 FSAR UPDATE 3.9-29 Revision 21 September 2013 depressurization waves are characterized by a wave-front with low pressure on one side and high pressure on the other. The wave-front translates and reflects throughout the primary system until the system is completely depressurized. The rapid depressurization results in transient hydraulic loads on the mechanical equipment of the system. The release of coolant resulting from a postulated RPV nozzle break also results in a pressure increase in the region surrounding the postulated break. Pressurization occurs rapidly in the cavity around the reactor vessel, which can exert an asymmetric force on the outside of the vessel.
The loads on the RPV and internals that result from the depressurization of the system and from the pressurization of the area around the break may be categorized as: (a) reactor internal hydraulic loads (vertical and horizontal), (b) reactor coolant loop mechanical loads, (c) reactor cavity pressurization loads (only for breaks at the RPV safe end locations), and (d) jet impingement loads. Description of such loads acting for a typical reactor vessel inlet or outlet nozzle is given below (for more details, see Reference 6), and these loads are combined into a single time history forcing function which are then applied to the RPV system finite element model. 3.9.3.3.2.1 Reactor Pressure Vessel Internal Hydraulic Loads Depressurization waves propagate from the postulated break location into the reactor vessel through either a hot leg or a cold leg nozzle. After a postulated cold leg break, the depressurization path for waves entering the reactor vessel is through the nozzle that contains the broken pipe and into the region between the core barrel and the reactor vessel (that is, the downcomer region). The initial wave propagates up, around, and down the downcomer annulus, then up through the region circumferentially enclosed by the core barrel, that is, the fuel region. In the case of a cold leg break, the region of the downcomer annulus close to the break depressurizes rapidly but, because of the restricted flow areas and finite wave speed (approximately 3000 feet per second), the opposite side of the core barrel remains at a high pressure. This results in a net horizontal force on the core barrel and the reactor vessel. As the depressurization wave propagates around the downcomer annulus and up through the core, the core barrel differential pressure reduces and, similarly, the resulting hydraulic forces drop.
In the case of a postulated break in the hot leg, the wave follows a similar depressurization path, passing through the outlet nozzle and directly into the upper internals region depressurizing the core and entering the downcomer annulus from the bottom exit of the core barrel. Thus, after a hot leg break, the downcomer annulus would be depressurized with very little difference in pressure forces across the outside diameter of the core barrel. A hot leg break produces less horizontal force because the depressurization wave travels directly to the inside of the core barrel (so that the downcomer annulus is not directly involved), and internal differential pressures are not as large as for a cold leg break of the same size. Since the differential pressure is less for a hot leg break, the horizontal force applied to the core barrel is less for hot leg break than for a cold leg break. For breaks in both the hot leg and cold leg, the DCPP UNITS 1 & 2 FSAR UPDATE 3.9-30 Revision 21 September 2013 depressurization waves continue to propagate by reflection and translation through the reactor vessel and loops.
The MULTIFLEX computer code (Reference 3) calculates the hydraulic transients within the entire primary coolant system. It considers subcooled, transition, and two-phase (saturated) blowdown regimes. The MULTIFLEX code employs the method of characteristics to solve the conservation laws, and assumes one-dimensionality of flow and homogeneity of the liquid-vapor mixture. The MULTIFLEX code considers a coupled fluid-structure interaction by accounting for the deflection of constraining boundaries, which are represented by separate spring-mass oscillator system. A beam model of the core support barrel has been developed from the structural properties of the core barrel; in this model, the pressure as well as the wall motions are projected onto the plane parallel to the broken nozzle. The spatial pressure variation at each time step is transformed into ten horizontal forces, which act on the ten mass points of the beam model. Each flexible wall is bounded on either side by a hydraulic flow path. The motion of the flexible wall is determined by solving the global equations of motions for the masses representing the forced vibration of an undamped beam.
The reanalysis performed in support of the conversion of the barrel/baffle region for Unit 2 has made use of the MULTIFLEX 3.0 (Reference 9) computer code. The MULTIFLEX versions are an extension of the BLODWN-2 computer code and includes mechanical structure models and their interactions with the thermal-hydraulic system. Both versions of the MULTIFLEX code share a common hydraulic modeling scheme, with differences being confined to a more realistic downcomer hydraulic network and a more realistic core barrel structural model that accounts for non-linear boundary conditions and vessel motion. Generally, this improved modeling results in lower, more realistic, but still conservative hydraulic forces on the core barrel. The NRC staff has accepted (Reference 10) the use of MULTIFLEX 3.0 for calculating the hydraulic forces on reactor vessel internals (Reference 11). 3.9.3.3.2.2 Reactor Coolant Loop Mechanical Loads The loop mechanical loads result from the release of normal operating forces present in the pipe prior to the separation as well as transient hydraulic forces in the reactor coolant system. The magnitudes of the loop release forces are determined by performing a reactor coolant loop analysis for normal operating loads (that is, pressure, thermal, and deadweight). The loads existing in the pipe at the postulated break location are calculated and are "released" at the initiation of the LOCA transient by application of the loads to the broken piping ends. These forces are applied with a ramp time of one millisecond because of the assumed instantaneous break opening time. 3.9.3.3.2.3 Reactor Cavity Pressurization Loads Reactor cavity forces arise from the steam and water that are released into the reactor cavity through the annulus around the broken pipe. These forces occur only for DCPP UNITS 1 & 2 FSAR UPDATE 3.9-31 Revision 21 September 2013 postulated breaks at the RPV nozzle safe end locations. The reactor cavity is pressurized asymmetrically, with high pressures on the side adjacent to the break. The horizontal differences in pressure across the reactor cavity result in horizontal forces on the reactor vessel. Vertical forces on the reactor vessel arise from similar variations in pressures on the upper and lower head and the tapered parts of the vessel. 3.9.3.3.2.4 Jet Impingement Loads The jet impingement load is an axial force along the broken pipe centerline that is caused by the pressure of the escaping jet of coolant acting on the exposed pipe cross section at the break location. The jet force is calculated by multiplying the saturation pressure corresponding to the temperature of the coolant at break location times the cross-sectional area of the pipe. This force is applied with a ramp time of one millisecond. 3.9.3.4 Acceptance Criteria 3.9.3.4.1 Structural Adequacy of Reactor Internal Components The reactor internal components of Diablo Canyon Units 1 and 2 are not ASME Code components because Sub-section NG of the ASME Boiler and Pressure Code edition applicable to DCPP Units reactor internals did not include design criteria for the reactor internals. However, these components were originally designed to meet the intent of the 1971 Edition of Section III of the ASME Boiler and Pressure Vessel Code with addenda through the Winter 1971. The allowable stress limits for the design basis accident (DBA) for core support structures are based on limits specified in Section 5.2.1. 3.9.3.4.2 Allowable Deflection and Stability Criteria. The criterion for acceptability in regard to mechanical integrity analyses is that adequate core cooling and core shutdown must be ensured. This implies that the deformation of reactor internals must be sufficiently small so that the geometry remains substantially intact. Consequently, the limitations established on the reactor internals are concerned principally with the maximum allowable deflections and stability of the components.
For faulted conditions, deflections of critical internal structures are limited to values given in Table 3.9-10. In a hypothesized vertical displacement of internals, energy absorbing devices limit the displacement to 1.25 inches by contacting the vessel bottom head. Upper Core Barrel The upper core barrel has the following deformation limits:
DCPP UNITS 1 & 2 FSAR UPDATE 3.9-32 Revision 21 September 2013 (1) To ensure shutdown and cooldown of the core during cold leg blowdown, the basic requirement is a limitation on the outward deflection of the barrel at the locations of the inlet nozzles connected to unbroken lines. A large outward deflection of the upper barrel in front of the inlet nozzles, accompanied with permanent strains, could close the inlet area and restrict the cooling water coming from the accumulators. Consequently, a permanent barrel deflection in front of the unbroken inlet nozzles larger than a certain limit, called "no loss of function" limit, could impair the efficiency of the ECCS. (2) During the hot leg break, the rarefaction wave enters through the outlet nozzle into the upper internals region and thus depressurizes the core and then enters the downcomer annulus from the bottom exit of the core barrel. This depressurization of the annulus region subjects the core barrel to external pressures and this condition requires a stability check of the core barrel during hot leg break. Therefore, to ensure rod insertion and to avoid disturbing the control rod cluster guide structure, the barrel should not interfere with the guide tubes. Control Rod Cluster Guide Tubes The deflection limits of the guide tubes were established from test data (see Table 3.9-10). Upper Package The local vertical deformation of the upper core plate, where a guide tube is located, shall be less than 0.100 inch. This deformation will cause the plate to contact the guide tube, since the clearance between the plate and the guide tube is 0.100 inch. This limit will prevent the guide tubes from undergoing compression. For a plate local deformation of 0.150 inch, the guide tube will be compressed and deformed transversely to the upper limit previously established. Consequently, the value of 0.150 inch is adopted as the no loss function local deformation with an allowable limit of 0.100 inch. These limits are given in Table 3.9-10. 3.9.3.5 Methods of Analysis Faulted condition LOCA analyses were originally performed for limiting breaks of the reactor vessel inlet nozzle and reactor vessel outlet nozzle with a limited displacement allowing a break area of 115 in2. Subsequent calculations of the loop displacements found the maximum displacement at the reactor vessel inlet and outlet nozzles was 81in2, confirming the 115 in2 break area was a conservative assumption. These original 115 in2 break area forces were later confirmed to be bounding relative to LOCA forces generated for 81 in2 limited displacement breaks calculated at reduced operating temperatures consistent with temperature coastdown. Although the leak-before-break analysis (Reference 14) now allows for exclusion of main loop piping breaks from the design basis, DCPP UNITS 1 & 2 FSAR UPDATE 3.9-33 Revision 21 September 2013 no credit has yet been taken for the smaller branch line areas (60 in2 for the largest cold leg branch line - the accumulator line) in the current reactor vessel LOCA forces analyses for Unit 1. When credit for this break area reduction is taken, it is expected to provide substantial margin relative to the existing design basis accident loads.
For the Unit 2 conversion to the upflow configuration, as previously mentioned, the pressurizer surge line break (98.31 in2) on the hot leg and the accumulator line break (60.13 in2) on the cold leg were analyzed with the MULTIFLEX 3.0 code. The analysis used a 1 millisecond BOT, consistent with the MULTIFLEX licensing requirements. All break cases used flexible beam modeling for the core barrel. The analysis conservatively assumed limiting full power RCS temperatures for DCPP Unit 2. These conditions bound the most severe operating conditions, which encompasses Tavg coastdown conditions. The effects of a Tavg coastdown are thus accounted for in the vessel forces analyses. Additionally, the Delta-54 RSG was included in the analyses. Previous studies have shown that the steam generator design has a relatively insignificant effect on the vessel forces analyses, so operation of either Unit 1 or Unit 2 with either the original Model 51 steam generator or the Delta-54 steam generator configuration is acceptable with respect to the vessel forces analyses. 3.9.3.5.1 Blowdown Forces Due to Cold and Hot Leg Break A USNRC approved FORTRAN-IV computer program called MULTIFLEX (Reference 3) is used to calculate the local fluid pressure, flow, and density transients that occur during a LOCA. MULTIFLEX is an extension of the BLODOWN-2 computer code and includes mechanical structure models and their interaction with the thermal-hydraulic system. The analysis is performed for the subcooled decompression period of the transient, where the hydraulic loads are the greatest. These loads are used for the structural evaluation of the reactor pressure vessel support system, in conjunction with other loads associated with a LOCA and with a safe shutdown earthquake (SSE). 3.9.3.5.2 FORCE2 and LATFORC Models for Blowdown The MULTIFLEX code evaluates the pressure and velocity transients throughout the RCS. These pressure and velocity transients are made available to the programs FORCE2 and LATFORC, which utilize detailed geometric descriptions in evaluating the loadings on the reactor internals.
LATFORC (Reference 3) is used to calculate the horizontal force components on the vessel, core barrel, and thermal shield as a function of elevation and time using the MULTIFLEX hydraulic data. The force components significant to the horizontal forces are primarily a function of the pressure times area.
FORCE2 (Reference 3) is used to calculate the vertical force components acting on the reactor vessel and internals. Each reactor component for which FORCE2 calculations are DCPP UNITS 1 & 2 FSAR UPDATE 3.9-34 Revision 21 September 2013 required is designated as an element and assigned an element number. Forces acting on each of the elements are calculated summing the effects of:
(1) The pressure differential across the element.
(2) Flow stagnation on, and unrecovered orifice losses across, the element.
(3) Friction losses along the element. The most significant assumption made for the analysis is that the thermal-hydraulic analysis has been performed to include mechanical structural models of the core barrel, which allows for fluid structure interaction in the downcomer region of the vessel to decrease the peak pressures calculated on the core barrel and vessel. No other fluid structure interaction has been modeled in the vessel LOCA forces calculation. 3.9.3.5.3 Reactor Vessel/Internals/Fuel Analysis Under LOCA Conditions The three dimensional LOCA analysis of the RPV system (i.e., reactor vessel/internals/fuel) is discussed in Section 3.9.1.3.1, and Section 3.9.1.3.2 provides insight into the description of major core support components during LOCA transients. 3.9.3.5.4 Reactor Vessel/Internals/Fuel Analysis Under Seismic Conditions The three dimensional Seismic analysis of the RPV system (i.e., reactor vessel/internals/fuel) is discussed in Section 3.7.2, and the methods of analyses for seismic loads of major subsystems are discussed in Section 3.7.3. 3.9.3.5.5 Methods and Results (Mechanical) To verify structural adequacy of the reactor internal components and the core under LOCA and seismic loading, nonlinear time history dynamic analyses of the RPV system were performed to generate component interface loads as well as the time history displacements of the lower core plate, upper core plate, and the core barrel. These time history displacements of the core plates and the barrel were then used by Nuclear Fuel Division (NFD) to determine the fuel grid impact loads and the structural adequacy of the core components.
Reference 15 documents in detail the results of RPV system LOCA and seismic analyses. From these analyses it is seen that the reactor internals component interface loads for the Diablo Canyon units during LOCA, seismic and combined (SRSS LOCA + seismic) are bounded by those of the Generic 4-Loop Stress Report (Reference 19). In the generic stress report, the four-loop reactor internals components are analyzed to meet the ASME Code stress requirements.
The results also indicate that the maximum deflections in the critical structures are below the established allowable limits (see e.g., Table 3.9-10). During the hot leg DCPP UNITS 1 & 2 FSAR UPDATE 3.9-35 Revision 21 September 2013 break, the core barrel does not buckle, and during the cold leg break has stresses that are within allowable limits. The design evaluation of the internals structure is presented in Section 4.2.2.
It should be reiterated that LOCA analyses described above are for the main loops line breaks; and with the LBB acceptance, the next most limiting breaks which need to be considered are the auxiliary line breaks consisting of the accumulator line, the pressurizer surge line, and the RHR line. The LOCA loads imposed on the RPV system from these auxiliary line breaks are generally significantly lower than those obtained from the main loop line breaks. Therefore, with LBB the combination of LOCA and seismic loads on the RPV system will yield higher margins of safety.
For DCPP Unit 2, an upflow conversion in conjunction with the upper head temperature reduction program has been implemented. The impacts due to these modifications were evaluated and documented in Reference 20. 3.9.3.6 Control Rod Drive Mechanisms The control rod drive mechanisms are Class A components designed to meet the stresses of the ASME Boiler and Pressure Vessel Code and therefore are presented in Section 4.2. 3.9.4 NON-DESIGN CLASS I COMPONENTS Several non-Design Class I components were also seismically qualified to preclude seismic interaction with Design Class I equipment and/or to ensure structural integrity of the component cooling water system. 3.9.5 MISCELLANEOUS PRESSURIZED GAS CONTAINERS Table 3.9-11 provides a summary of all storage tanks containing significant quantities (over 100 lbs) of gas under pressure in excess of 100 psig. These tanks are of both Design Class I and II. 3.
9.6 REFERENCES
- 1. Deleted.
- 2. Bohm, Indian Point Unit No. 2 Internals Mechanical Analysis for Blowdown Excitation, WCAP-7822, December 1971.
- 3. Takeuchi, K. et al., MULTIFLEX, A FORTRAN IV Computer Program for Analyzing Thermal-Hydraulic Structure System Dynamics," WCAP-8708-P-A (Westinghouse Proprietary Class 2), WCAP-8709-A, NES Class 3 (Non-Proprietary), September 1977.
DCPP UNITS 1 & 2 FSAR UPDATE 3.9-36 Revision 21 September 2013 4. Moore, Westinghouse PWR Core Behavior Following a Loss-of-Coolant Accident, WCAP-7422, September 1971.
- 5. Bohm, and J. P. Lafaille, Reactor Internals Response under a Blowdown Accident, First Intl. Conf. on Structural Mech. in Reactor Tech., Berlin, September 20-24, 1971.
- 6. Wood et al., Use of Burnable Poison Rods in Westinghouse Pressurized Water Reactors, WCAP-7113, October 1967.
- 7. Barry et al., Topical Report - Power Distribution Monitoring in the R.E. Ginna PWR, WCAP-7756, September 1971.
- 8. Gesinski, Fuel Assembly Safety Analysis for Combined Seismic and Loss-of-Coolant Accident, WCAP-7950, July 1972.
- 9. Takeuchi, K. et al., MULTIFLEX 3.0, A FORTRAN IV Computer Program for Analyzing Thermal-Hydraulic-Structural System Dynamics Advanced Beam Model," WCAP-9735, Revision 2, Westinghouse Proprietary Class 2/WCAP-9736, Revision 1, Non-Proprietary, February 1998.
- 10. Letter, T. H. Essig (USNRC) to Lou Liberatori (WOG), Safety Evaluation of Topical Report WCAP-15029, "Westinghouse Methodology for Evaluating the Acceptability of Baffle-Former-Barrel Bolting Distributions Under Faulted Load Conditions", (TAC No. MA1152)," November 10, 1998 (Enclosure 1 - Safety Evaluation Report. 11. Schwirian, R. E., et al., Westinghouse Methodology for Evaluating the Acceptability of Baffle-Former-Barrel Bolting Distributions Under Faulted Load Conditions, WCAP-15029-P-A, Westinghouse Proprietary Class 2 / WCAP-15030-NP-A, Revision 0, Non-Proprietary, January 1999.
- 12. Comprehensive Vibration Assessment Program for Reactor Internals During Preoperational and Initial Startup Testing, NRC, RG 1.20.
- 13. PG&E Letter DCL-88-288, LAR 88-08, Request to Use VANTAGE 5 Fuel Assemblies, November 29, 1989.
- 14. Letter dated March 2, 1993, Leak-Before-Break Evaluation of Reactor Coolant System Piping for DCPP Units 1 and 2, (Docket Nos. 50-275 and 50-323), from Sheri R. Peterson of the NRC to Gregory M. Rueger of PG&E.
- 15. Bhandari, D. R. ,et. Al, System Dynamic Seismic and LOCA Analyses of Reactor Pressure Vessel System for the Pacific Gas and Electric Company Diablo Canyon Power Plants (DCPP) Units 1 & 2, WCAP-14693, Revision 1, February 11, 1997 (Westinghouse Proprietary Class 2).
DCPP UNITS 1 & 2 FSAR UPDATE 3.9-37 Revision 21 September 2013 16. Deleted in Revision 21
- 17. Fritz, R. J., The Effects of Liquids on the Dynamic Motions of Immersed Solids, Trans. ASME, Journal of Engineering for Industry, 1972, pp. 167-173.
- 18. WCAP-8172-A, Pipe Breaks for the LOCA Analysis of the Westinghouse Primary Coolant Loop, January 1975.
- 19. WNEP-7904, 4 Loop Standard Generic Stress Report - Structural and Fatigue Analyses.
- 20. WCAP-16487-P, Revision 1, Diablo Canyon Nuclear Power Plant Unit 2 Upflow Conversion and Upper Head Temperature Reduction Engineering Report, March 2006.
DCPP UNITS 1 & 2 FSAR UPDATE 3.10-1 Revision 21 September 2013 3.10 SEISMIC DESIGN OF DESIGN CLASS I INSTRUMENTATION, HVAC, AND ELECTRICAL EQUIPMENT 3.10.1 SEISMIC DESIGN CRITERIA The Design Class I instrumentation, HVAC, and electrical equipment are capable of performing their nuclear safety functions during and after a DDE or the postulated 7.5M HE. The seismic levels for DDE and HE are given in Section 3.7. Instrument Class IA instrumentation is capable of performing its active nuclear safety functions during and after a DDE or HE. Instrument Class IB Category 1 instrumentation is capable of performing its active nuclear safety functions after a DDE or HE. Other Design Class I instrumentation is capable of performing the passive function of maintaining Class I pressure boundary integrity during and after a DDE or HE. In addition, some of the Design Class I instrumentation may have active seismic qualification; these instruments are identified on a case-by-case basis.
Performance criteria for Design Class I instrumentation, HVAC, and electrical equipment are as follows: (a) The reactor protection system shall be able to shut down the unit and maintain it in safe shutdown condition. (b) The electrical equipment is able to perform its required functions of providing electrical power, control, instrumentation, and protection for the ESF. (c) No device shall fail to initiate and maintain its safety function, nor shall it prevent other safety devices from performing their safety function.
The original seismic qualification of most equipment was done in accordance with IEEE 344-1971 (Reference 1) for DDE levels. As a result of changes in spectra the Design Class I equipment has been reevaluated, based on response spectra derived from the HE as well as the DDE levels discussed in Section 3.7. In the process of reevaluation, some equipment had to be requalified because: (a) its previous qualification was not adequate to envelop the HE input, or (b) concerns had been raised about the adequacy of the justification for the previous qualification methods. Requalification of the equipment, according to the guidance contained in IEEE Standard 344-1975 (Reference 2) and NRC RG 1.100 (Reference 3) was performed where necessary.
Tables 3.10-1 and 3.10-2 list instrumentation and electrical equipment that have been seismically qualified. The tables provide references to appropriate sections where qualification is described. Table 3.10-3 lists HVAC equipment that has been seismically qualified.
The seismic qualification of the equipment is based on the free-field ground motions described in Section 3.7.1. Effects of amplification of ground accelerations due to the response of the building at the location of the equipment were derived from the time-history modal superposition analyses made for the structures, as described in Section 3.7.
DCPP UNITS 1 & 2 FSAR UPDATE 3.10-2 Revision 21 September 2013 In addition to direct seismic effects on Design Class I equipment, PG&E has also given consideration to possible seismically induced physical interactions between nonsafety-related SSCs and Design Class I SSCs. The methodology and results of this interaction study are presented in Reference 4, and are provided in summary form in Section 3.7.3.13. Appropriate design modifications were performed where the study indicated safety functions of Design Class I equipment might be affected due to seismic interaction. 3.10.2 SEISMIC ANALYSES, TESTING PROCEDURES, AND RESTRAINT MEASURES The effects of seismic accelerations were determined either by physical tests, mathematical analyses, or engineering judgment. Mathematical analyses of structural elements were made for Design Class I exposed electrical raceways, for equipment supports, and also for some equipment. Physical tests of equipment were made either on one of the units being supplied or on one of a similar type. Choice of method used to determine seismic capability of the equipment and devices was based on the supplier's judgment of what would be adequate and appropriate. 3.10.2.1 Nuclear Reactor Instrumentation and Protection Systems The seismic testing of Westinghouse-supplied electrical and control equipment is documented in WCAP-8021 (Reference 5). The testing conforms to the procedures of IEEE-344-1971. The radiation monitoring cabinet and the Tracerlab scintillation detector and liquid sampler equipment are not safety-related, and these portions of WCAP-8021 are not applicable. The radiation monitoring system cabinet at DCPP has been upgraded to Design Class I (see Section 3.10.2.26). Details of the original seismic analysis and testing procedures for Design Class I instruments and electrical equipment are summarized in Table 3.10-1 and the following sections.
Typical items of equipment have been type tested under simulated seismic motion in the form of sine beats. This testing was done with conservatively large accelerations over a range of applicable frequencies and conformed to the procedures given in IEEE 344-1971. The peak test input accelerations used in those tests were checked to verify that they are larger than the requirements derived by structural analyses of DDE and HE levels. Westinghouse Electric Company, the supplier, made dynamic tests of typical samples of this equipment to confirm its seismic adequacy. Included in this test program were the racks for the nuclear instrumentation system; the process control and protection sets; the solid-state protection system cabinets and its safeguards test cabinets and auxiliary safeguards cabinets; the inverters for the power supply; pressure and differential pressure transmitters; the reactor trip switchgear; and main coolant loop resistance temperature detectors. Details of these tests are given in Table 3.10-1 and in Sections 3.10.2.1.1 to 3.10.2.1.9.
DCPP UNITS 1 & 2 FSAR UPDATE 3.10-3 Revision 21 September 2013 3.10.2.1.1 Nuclear Instrumentation As described in Reference 5, a typical two-cabinet unit of the Westinghouse nuclear instrumentation system (NIS) and radiation monitoring system (RMS) has been seismically tested. The NIS equipment was contained in one cabinet and the RMS equipment was mounted in the other cabinet. The two cabinets were attached and mounted on a two-cabinet base to simulate the support or adjoining cabinets. A typical NIS installation consists of four cabinets.
The NIS cabinet contained one source range channel, one intermediate range channel, and one power range channel located and mounted in the same configuration as the plant installation. Since any DBA described in this FSAR Update can be terminated within acceptable limits by the power range channels, only the power range channel was energized and monitored. The other NIS channels mounted in the cabinet served to simulate the mass distribution and weight in an actual installation.
Shutdown procedures contain the following provisions in the event that the source range channels are rendered inoperative due to a seismic event:
(1) The operator will take appropriate action to preclude boron dilution (2) Prior to cooldown, boric acid will be added to the reactor coolant to ensure that the concentration is sufficient to maintain the reactor in a subcritical state During seismic testing an external test signal was applied to the equipment so that the power range output signal was 100 percent full power. The test input signals, analog output signals, and bistable output signals were monitored during test. The tripping action of the bistable amplifier circuitry was checked after each series of tests to insure that the simulated earthquake had not impaired this function.
Only one instance of mechanical malfunction occurred as a result of this level of testing. Drawer latch damage occurred during side-to-side testing at higher g levels. A new fastening mechanism has been designed and the design submitted to the NRC (Reference 6). This modification was implemented at DCPP. A demonstration test for seismic operability of the NIS equipment was performed with multiple frequency, multiple axis inputs. The test, reported in Reference 7, indicated that the equipment will operate during a seismic event as required.
The neutron detector for the NIS power range channel has been tested using sinusoidal inputs in both the horizontal and vertical directions at accelerations at least equal to those calculated for the DCPP. Neutron current measurements were made during the tests, and current, resistance and capacitance checks were made after the tests. No significant changes were found and there was no mechanical damage to the detector.
DCPP UNITS 1 & 2 FSAR UPDATE 3.10-4 Revision 21 September 2013 In addition, a two-section power range excore neutron detector was tested using multiple frequency, multiple axis inputs in a support assembly which simulated a detector holder. The multiple frequency inputs were developed in accordance with the guidelines set forth in Reference 8. The test response spectra envelope the DDE and HE inputs.
During the multiple frequency test, the detector was energized from a high voltage power supply, and an AC signal was imposed in each of the two signal electrodes to determine proper electrical operability.
At the completion of the tests, there was no observable mechanical damage and the electrical recordings revealed only a transient type electrical disturbance of one of the two signals. The signal perturbations were small in amplitude and would not cause any loss of protection capability of the NIS during normal operation. Subsequent detector acceptance tests performed by the detector manufacturer did not disclose any abnormal permanent change in the electrical or neutron sensitivity characteristics. Thus the NIS Power Range Detector will operate as required during and after the DCPP postulated seismic events. 3.10.2.1.1.1 Radiation Monitoring Qualification of the radiation monitoring panels in the control room is based on shake table tests performed on the panels for Victoreen. The racks were shaketable tested with the monitoring equipment in place. See Section 3.10.2.26 3.10.2.1.2 Solid-State Protection System The three-bay, two-train SSPS was seismically tested as described in Section 2.5 of Reference 5. During the seismic test, a typical reactor trip matrix and typical safeguards actuation matrix were energized and monitored. Before each test, the circuitry was placed in a pre-trip condition. During the actual shaking, the circuitry was deliberately tripped and changed to a post-trip condition. The functional integrity of the system was thus demonstrated by observing a satisfactory change of state on demand. Relay contact positions necessary to show the operability were recorded during the tests.
No mechanical problems occurred during the vertical axis tests. In the side-to-side axis test at lower "g" levels, the two lefthand cabinet-to-base bolts repeatedly loosened and were deformed until it became necessary to replace these with more hardened bolts. During subsequent testing at these levels in the side-to-side axis, these bolts failed completely on the last sine-beat test. Before performing the front-to-back test, twelve additional cabinet-to-base bolts were installed making a total of 24 bolts fastening the cabinet to its base. This change has been incorporated into the SSPS cabinets at DCPP.
The functions monitored by recorders were: undervoltage trip, train trouble, and SI signal. Test switches were operated during the third sine beat simulating a reactor trip DCPP UNITS 1 & 2 FSAR UPDATE 3.10-5 Revision 21 September 2013 and safeguards actuation, causing a change in amplitude of the recorded signals for under voltage trip and SI.
During the front-to-back axis test, the signal indicated several momentary trips (contact closures) before the test switches were operated. Also, at 7 Hz and 9.5 Hz, this signal indicated a momentary trip and then a permanent change of state (latch up) on the first bounce on the output (slave) relays. The permanent change of state was caused by the armature of the same relays bouncing closed. This closing allowed their mechanical latch mechanism to operate. These maloperations could have initiated safeguards actuation. However, they would not have negated a valid safeguard actuation or reactor trip. Although SI was prematurely actuated, the under voltage coil tripped when called upon to do so.
The duration of the momentary contact closure was probably short enough not to cause a false safety injection signal. The probability of spurious initiation of safety injection due to any earthquake is therefore very small. The seismic tests performed have demonstrated that the postulated seismic event will not prevent a legitimate safety injection signal from being actuated, either during or after the event. Reference 9 presents an analysis of the consequences of seismic-induced actuation of protection system relays by considering the possible actuation of each contact of the relays studied and describing the resulting effect of inadvertent equipment actuation.
The relays which exhibited contact bounce and mechanical latching were replaced by a new type of relay which was seismically qualified by single-axis sine-beat and multiple frequency sine-beat testing. Input levels for the tests were determined from the measured acceleration response at the cabinet during the cabinet tests described in Section 2.5 of Reference 5. Seismic qualification of these replacement relays is documented in Reference 10.
Due to obsolescence issues, the original SSPS printed circuit boards (PCBs) can be replaced with newer vintage boards supplied by Westinghouse. The replacement PCBs have been seismically qualified by Westinghouse. The seismic qualification is documented in Reference 49. 3.10.2.1.3 Process Control and Protection Equipment Originally, seismic testing was performed using a three-cabinet unit mounted on a common base as defined in Section 2.4 of Reference 5. The three-cabinet test assembly included at least one of each type of module used in all of the various process protection and safeguards actuation channels. Both analog and bistable output signals were recorded. All reactor trips and safeguards actuation signals were continuously recorded and some bistable signals of less importance (e.g., alarms circuits) were monitored with lights. The basis for determining the functional integrity of the reactor trip and safeguards actuation signals was that these signals should remain unchanged during the test and should be capable of changing state after the test if called upon to do so. DCPP UNITS 1 & 2 FSAR UPDATE 3.10-6 Revision 21 September 2013 The tripping action of the bistable amplifier circuitry was checked after each series of tests to insure that the seismic test input had not impaired this function.
During front-to-back testing of the circuit board, an internal power supply circuit board disengaged from its connector causing complete failure of the module. Restraining clamps were installed on the circuit board and the test was repeated successfully. These clamps have since been installed on all similar modules. All recorded electrical signals performed properly during and after the tests.
In addition, as part of the overall program to demonstrate the adequacy of the seismic test previously conducted, multiple frequency, multiple axis test (Reference 11) were performed on an entire typical channel, including signal conditioning circuits and the bistables, of the process instrumentation system. The results of the bistable tests show that the electrical functions of each bistable module maintained electrical operability both during and after each seismic event. In addition, no spurious bistable actions were observed.
Subsequently, the Eagle 21 system replaced the Hagan protection system within the existing racks. The Eagle 21 system has been seismically qualified on a generic basis by Westinghouse (see References 40 through 42) in accordance with requirements from References 43 and 44. A site-specific seismic analysis was also performed to ensure that the Eagle 21 generic testing performed by Westinghouse encompasses the DCPP installed condition (see Reference 45), which included the effects of the top entry conduit stiffness. Subsequently, the Hagan process control system (PCS) in instrument racks 17 through 32 (RNO1A through RNO4E) was replaced with a programmable logic controller based system manufactured by Triconex (DDP 1000000237 and DDP 1000000501). The system chassis, I/O and hardware have been seismically qualified by Triconex (Reference 55). As part of the design change process, a site-specific seismic evaluation and seismic calculation file was completed for the installed condition. Supporting PCS equipment, such as loop power supplies, signal isolators, circuit breakers, terminal boards and line filters that support safety related equipment, was seismically qualified in accordance References 56, 57 and 58. 3.10.2.1.4 Instrument AC Inverters A prototype UPS and regulating transformer of the DCPP UPS system was tested as described in PG&E engineering seismic file No. ES-68-1.
The UPS and regulating transformer were tested while loaded at 20 kVA; and the ac output voltage, current and frequency were monitored during the seismic test. The presence of a continuous ac output voltage both during and after the test formed the basis for determining the functional integrity of the UPS system. DCPP UNITS 1 & 2 FSAR UPDATE 3.10-7 Revision 21 September 2013 During seismic testing the static inverter maintained structural integrity and functional operability. No variation or loss of 120 Vac output voltage was observed during or after the test. Therefore, the static inverter will perform its safety related functions during and after the postulated DCPP seismic events. 3.10.2.1.5 Pressure and Differential Pressure Transmitters (Westinghouse) Originally the safety related pressure transmitters provided by Westinghouse for DCPP were installed to sense the following conditions:
- Containment Pressure (CP)
- Reactor Coolant Level using the Reactor vessel Level Instrumentation System (RVLIS)
The transmitters were mounted during seismic qualification to a rigid fixture. The pressure and differential pressure transmitters tested are the following: Equipment Function Group Manufacturer Model No. Differential Pressure Transmitter CP ITT/Barton 332/351 Differential Pressure Transmitter RVLIS ITT/Barton 752
As described in Section 2.8 of Reference 13, the Barton Model 332 transmitter was seismically tested. Subsequently, the containment pressure transmitters were replaced with Rosemount differential pressure transmitter Model 1154 (refer to Section 3.10.2.11 for qualification of this model transmitter). The Barton Model 351 pressure sensors are used in conjunction with the Rosemount transmitter Model 1154 to measure containment pressure.
Seismic testing of the Barton Model 752 differential pressure transmitters is detailed in WCAP-8687, Supplement 2-E04A (Reference 15). Seismic testing was performed using multiple frequency, multiple axis tests. During seismic tests, the transmitters were pressurized to approximately mid-scale with a 2,000-psig static pressure. The output of the transmitters was monitored continuously. The Barton 752 differential pressure transmitters maintain their integrity and performed their safety-related functions as required during and after seismic testing. Subsequently, the RVLIS level transmitters manufactured by Barton were replaced with Rosemount differential pressure-transmitter Model 1153 (refer to Section 3.10.2.11 for qualification of this model transmitter). The RVLIS Rosemount transmitters retain the use of the Barton Model 353 pressure sensors. 3.10.2.1.6 Reactor Trip Switchgear Seismic testing of a typical reactor trip switchgear was performed as described in Reference 16. The basis for determining the functional integrity of the equipment was the following: (a) the breakers should trip open on loss of voltage to the undervoltage DCPP UNITS 1 & 2 FSAR UPDATE 3.10-8 Revision 21 September 2013 trip device during the testing sequence, and (b) all breaker outputs, including secondary contact outputs to the various protection system, should maintain proper contact condition of open or closed position.
The electrical functions of the equipment were monitored both during and after the seismic test (Reference 16) to ensure that the equipment was operating properly and performing the required safety related functions. This monitoring consisted of recording output signal voltages, and the input signal voltage to the undervoltage trip. The tripping action of each breaker through the undervoltage trip circuitry was checked during the after each series of test to verify that the simulated earthquake had not impaired this function.
The recordings of all electrical signals indicated proper and complete functioning of the equipment both during and after all testing. No secondary contact chattering, no false breaker closing and no false breaker opening was observed.
The test results show that the functions of this equipment were maintained within the established criteria, both during and after each simulated seismic condition. During seismic testing a modification kit was installed within the reactor trip switchgear to enhance its seismic capabilities. This modification kit has been installed in the DCPP reactor trip switchgear. 3.10.2.1.7 Resistance Temperature Detectors Resistance temperature detectors (RTDs) are ruggedly built devices designed to withstand the high temperature and pressure of the fluid in the reactor coolant system. They are also designed to withstand severe seismically induced vibration, and the reactor coolant RTDs are designed to withstand the flow-induced vibration from the reactor coolant flow.
The RTDs are mounted in the reactor coolant piping, on the containment sump wall, and on rigid support structures. The reactor coolant RTDs are installed in thermowells mounted into the main coolant piping.
The seismic testing described in Reference 35 was performed on the Weed reactor coolant RTDs. The test inputs were random frequency, biaxial sine wave vibrations for a range of 1 through 1000 Hz. During the test, the RTDs were operated and their input/output signals were monitored. No mechanical damage was observed, and the input/output signals remained within acceptable limits.
The seismic testing described in Reference 36 was performed on the Conax RTDs. The test inputs were random frequency, biaxial sine wave vibrations for a range of 1 through 200 Hz. During the test, the RTDs were operated and their input/output signals were monitored. No mechanical damage was observed, and the input/output signals remained within acceptable limits. DCPP UNITS 1 & 2 FSAR UPDATE 3.10-9 Revision 21 September 2013 3.10.2.1.8 Safeguards Test Cabinet As described in Reference 19, sine-beat testing was performed on a typical engineered safeguard test cabinet. The engineered safeguards test cabinet completed seismic testing without sustaining physical damage. The only functional anomaly observed during testing was the momentary opening of the normally closed contacts of certain test selection switches at particular frequencies.
These switches are used to set up and initiate individual tests. The normally closed contacts are used exclusively to reset the blocking relays of the engineered safeguards test cabinet upon completion of a test. When the blocking circuit is not in the test mode, the blocking relay is in the reset state. A momentary opening of the normally closed contacts, therefore, will have no effect on the state of the blocking relay.
Therefore, based on the seismic testing performed, the engineered safeguard test cabinet will perform its safety related function during and after the postulated DCPP seismic events. 3.10.2.1.9 Auxiliary Safeguards Cabinet The auxiliary safeguards cabinet is structurally identical to the safeguards test cabinet (Section 3.10.2.1.8) and the component layout of the two cabinets is essentially the same. Therefore the results obtained from the test of the safeguards test cabinet were applied to the auxiliary safeguards cabinet.
The auxiliary safeguards cabinet was later analyzed by time history analysis to qualify the use of the rotary relay in the cabinet. This analysis is described in Reference 20. The rotary relays have been tested separately using single axis, multiple frequency inputs. These tests are described in Reference 10.
The analysis response spectra of the auxiliary safeguards cabinet, at relay mount locations, was found to be enveloped by the relay test response spectra. Therefore both the auxiliary safeguards cabinet and relays will function properly during and after the DCPP postulated seismic event. 3.10.2.2 Main Control Board and Console The main control board is located within the control room at elevation 140 ft in the auxiliary building. It has two major structures: main control board (MCB) section and control console.
Seismic qualification of the MCB and central console is demonstrated by analysis as described in Reference 21. The analysis consisted of the following tasks:
DCPP UNITS 1 & 2 FSAR UPDATE 3.10-10 Revision 21 September 2013 (1) Modeling of the MCB so that its analytical frequencies correlate to those obtained from the field test (2) Response spectrum analysis of the model using the given spectra to evaluate structural adequacy (3) Modification of MCB to address overstress condition (4) Response spectrum analysis of the modified MCB model to compute loads for structural evaluation (5) Transient dynamic analysis of the modified model to generate in-equipment response spectra (IERS) for device qualification The MCB section and central console are modeled using the general purpose finite element computer code, WECAN (Reference 22). The MCB is modeled as a linearly elastic system of beam, plate and lumped mass elements.
In addition, In-situ testing of the unmodified structure was performed to identify local panel modes. This consisted of tap tests of the vertical and bench panels as described in Reference 23.
Response spectrum analyses were performed to compute structural loads using DDE and HE required response spectra. Two dimensional shocks were considered in the evaluation. Maximum elemental stresses were obtained from the two sets of response spectrum analyses. The structural analyses of the unmodified design indicated some overstress which is a result of the changes in spectra from the original HE loadings. To reconcile the overstressed conditions and simultaneously provide the additional advantage of increasing the overall structural frequencies to above the peak of the floor response spectra, modifications have been done on top of the main control board. These modifications lead to a much lower stress condition and increase the board's overall structural frequencies to values exceeding the peak of the input spectra.
The results of stress analyses for the modified design show that the maximum member stress is about 85 percent of allowable. A comparison of the required and as-built weldments demonstrates that the existing weldments exceed the required weldments. Buckling stability of all MCB structural members has also been evaluated. There exists, at least a factor of safety of three against buckling.
Transient dynamic analyses of the modified structural model and performed to obtain the IERS for use in qualifying board mounted devices. Two sets of transient analyses are performed using two directional seismic excitation with one horizontal and one vertical direction. The synthesized floor excitation is employed in a transient dynamic DCPP UNITS 1 & 2 FSAR UPDATE 3.10-11 Revision 21 September 2013 analysis using the modal superposition integration procedure. Five percent of critical damping is assumed in the analyses.
The central console is a U-shaped electrical cabinet consisting of three bolted sections, welded to the main control room floor. The structure is modeled using WECAN, similar to the main control board. Results of modal analyses of the console structural model show the lowest overall fundamental frequency to be 70 Hz.
Since the console model has no frequencies below 33 Hz, it is classified as a rigid structure, and stress evaluations are performed using the static method. Uniform static acceleration equal to the floor response spectra ZPA are applied to the console structural model. Stresses computed by the SRSS method are observed to be well below the allowables. No weldments and buckling evaluations are performed due to the obvious integrity apparent from the low stress conduit.
As all console frequencies are in the rigid range, the IERS for console mounted devices are the floor response spectra.
The IERS obtained from MCB and console analysis were used for seismically qualifying the MCB mounted devices as described in Reference 24. Qualification tests were performed to determine if the structural integrity and functional operability of the devices are maintained for the seismic level.
Devices tested were supplied by PG&E and are representative of all the Design Class I devices used in the MCB. Indicators, recorders, switches, power supply, and light box were tested. The seismic qualification was achieved by subjecting the devices to multiple frequency, multiple axis seismic testing such that the response spectrum envelops the IERS obtained from analysis. It was concluded from the tests that all of the Design Class I devices will maintain their structural integrity and functional operability during and after the postulated seismic event. In addition, three cathode ray tube (CRT) displays have been located in the central console. Seismic tests were performed to insure that these CRTs will not become missile sources. 3.10.2.3 Hot Shutdown Panel This panel is a backup panel used if the control room must be evacuated and the plant brought to a hot shutdown condition. It contains indicators, control switches, and hand-auto stations for proportional control. These give indication and control over various pumps and valves in the auxiliary feedwater, component cooling water, boration control, and containment fan cooler systems. Additionally, the 10 percent steam dump valves are controlled from the hot shutdown panel, but the control loops for that function are not Design Class I.
DCPP UNITS 1 & 2 FSAR UPDATE 3.10-12 Revision 21 September 2013 3.10.2.3.1 Qualification of the Panel The panel consists of an enclosure 5 feet 10 inches wide, 6 feet 6 inches high, and 3 feet deep, with two panels inside, one on a vertical plane, the other tilted up 30° from the horizontal. The enclosure is mounted on four channels which are welded to a box comprised of 10-inch WF beams. This box is welded to steel plates embedded in the concrete floor of the auxiliary building at elevation 100 feet.
A three-dimensional response spectra analysis has been performed on a finite element model developed for the hot shutdown control panel. This analysis has shown the subject panel is qualified for DE, DDE, and HE seismic events. 3.10.2.3.2 Qualification of Individual Instruments The types of components in the panel that are Class 1E are indicators (Westinghouse Model VX252), control switches (Cutler-Hammer Type 10250T), and hand-auto control stations. Other devices (e.g., Westinghouse Type KA-241 indicators) are not Class 1E and have no need to meet seismic qualifications. These devices are separated from Class 1E devices by a barrier.
All required devices (VX252 indicators, W-2 switches, 10250T switches) were qualified by test using multifrequency biaxial shake tests. The devices were mounted to closely simulate their mounting conditions on the panel. The indicator was calibrated before and after the tests to ensure that the tests had not affected the calibration. During the tests, an input was applied that produced a midscale output. The outputs were monitored for fluctuation, and no fluctuation or calibration shift greater than required accuracy was noted. Replacement valve manual/auto hand stations manufactured by NUS were seismically qualified in accordance with Reference 59, 60 and 61. The control switches were tested in both the neutral and the "switched" positions. The contacts were monitored for chatter during the event, and were tested for proper operation afterwards. (It should be pointed out that since the safety function of these devices is to give the operator manual control of various devices, and the operator will not be expected to change switch position during the seismic event, no requirement exists to change inputs during the event.) No malfunctions of the switches were noted. 3.10.2.4 Local Instrument Panels Local instrument panels are used as enclosures for Design Class I and non-Design Class I instrumentation throughout the plant. The panels perform no Design Class I function except to provide support for the Design Class I devices. The panels are supported at the top by fastening them to a wall or other suitable structure. The bottom is fastened to the floor or to the same structure as the top.
DCPP UNITS 1 & 2 FSAR UPDATE 3.10-13 Revision 21 September 2013 The panels were originally qualified by analysis performed by the panel vendor. The criteria for the panels were that they have a resonant frequency greater than 20 Hz, and that all stresses be below allowables.
Due to the large number of panels requiring qualification, a worst case analytical method was used. It was based on determination of the panel having the highest calculated stresses resulting from simultaneous horizontal and vertical seismic accelerations. Subsequent to their installation in the plant, several of the panels were modified to increase their stiffness.
The qualification of the panels is based on finite element models of several representative panels which include the effect of equipment mounted in the panel. The analysis took into account the various sizes, configurations, and locations, using an envelope of 2 percent DDE and 4 percent HE spectra. The results of the analyses show that all panel stresses are below allowables. In addition, the panel response at Design Class I transmitter locations was derived for comparison with the test response spectra for Design Class I transmitters in the panels (see Section 3.10.2.11). 3.10.2.5 Instrument Panels PIA, PIB, and PIC These instrument panels house various devices used to power plant transmitters and perform the necessary signal conditioning to provide alarm functions and send linear signals to indicators on the main control board. The typical parameters involved are CCW flows and heat exchanger DP, and refueling water storage tank (RWST) level, etc. Most of the components in them were originally in the power generation instrument rack (PGIR). The panels are mounted on reinforced concrete columns at about the 132-foot elevation in the cable spreading room.
The panels were originally qualified by analysis. A review of the original stress calculations indicates that nowhere would the stresses (bending or shear) due to postulated seismic loading exceed 50 percent of the yield point of the material. The relays were qualified by comparison with the same relays installed in the ventilating control panel, physically installed nearby.
The panels were reanalyzed for the current seismic criteria for both the DDE and the HE. In addition, the seismic qualifications of the devices within the panels have been reviewed to the same seismic criteria. The analysis and the review have demonstrated that the instrument panels PIA, PIB, and PIC are seismically qualified to perform their safety function after the postulated seismic conditions.
Subsequent to the original qualification testing, replacement or additional devices to the panels have been installed. These devices are qualified by testing, analyses, or a combination of the two. Their qualification is documented in the engineering seismic files associated with the panels and/or devices. DCPP UNITS 1 & 2 FSAR UPDATE 3.10-14 Revision 21 September 2013 Subsequently, design changes 1000000237 and 1000000501removed much of the instrumentation in racks PIA, PIB and PIC and transferred their functions to the Process Control System. RWST level control logic relays, CVCS Letdown Heat Exchanger Room high temperature detection/isolation control, and Aux Steam Area K high temperature detection were retained due to interface requirements that could not be incorporated into the PCS. The original Moore direct current alarms (DCAs), thermocouple transmitters (TCTs), square root transmitters (SRTs) and signal conditioners (SCTs) were removed or replaced with new Moore (CPT) PC-programmable temperature transmitter and signal isolators/converters. The Moore CPTs were seismically qualified by NLI per references 56, 57 and 58. 3.10.2.6 Diesel Generator Excitation Cubicle and Control Cabinet The diesel generator (DG) excitation cubicle and the control cabinet for DGs 1-1, 1-2, 1-3, 2-1, and 2-2, were originally seismically qualified for the DDE by the manufacturer. Subsequently, one excitation cubicle and one control cabinet were shake-table tested and qualified to the 1977 HE requirements.
The seismic qualification has been reviewed to the latest DDE and HE levels described in Section 3.7. Based on this review, it has been demonstrated that both the excitation cubicle and the control cabinet will perform their safety function during and after the specified seismic conditions.
The sixth excitation cubicle and control cabinet for DG 2-3 have been seismically qualified by shake-table testing.
3.10.2.7 Design Class I AC Electrical Distribution Equipment The following sections describe the seismic qualification of Class 1E ac electrical distribution equipment. 3.10.2.7.1 4160 V Metal-Clad Switchgear The original 4160 V metal-clad switchgear with General Electric (GE) 250 mVA 4.16 kV magneblast circuit breakers was seismically qualified by a combination of testing and analyses.
Later, it was discovered that 350 mVA circuit breakers should be used in place of the GE 250 mVA 4.16 kV magneblast circuit breakers. GE could not supply such breakers to the same switchgear. Consequently, PG&E decided to procure 350 mVA 4.16 kV breakers from NTS/PDS, which converted Japanese-made Yaskawa SF6 circuit breakers to fit the existing 4 kV switchgear. The new circuit breakers were installed during refueling outages 1R8 and 2R7.
DCPP UNITS 1 & 2 FSAR UPDATE 3.10-15 Revision 21 September 2013 New circuit breakers were seismically qualified by shake table testing (NTS report No. TR60431-95N-FR). The shake table testing was intended to achieve the following objectives.
(1) Demonstrate the structural integrity and functionality of the Yaskawa breakers. (2) Demonstrate the structural integrity of as-installed 4 kV switchgear cubicles at DCPP with the Yaskawa breakers. (3) Demonstrate the functional performance of the existing components (i.e., various relays and switches) installed in the existing 4 kV switchgear cubicles with replacement Yaskawa breakers. (4) Instrument the test 4 kV switchgear cubicles with sufficient number of accelerometers to obtain accurate information on the dynamic response (response frequencies, test response spectra) at various cubicle locations.
This information is to be used for further/future testing and analyses. (5) Take immediate corrective actions to address significant anomalies observed during the test. The initial seismic testing was performed at Wyle Laboratories in Huntsville, Alabama. Three seismic mock-up 4 kV switchgear cubicles were built to duplicate the design, material, and construction of cubicles G-5, G-12, and G-13 of Unit 1. A total of 18 OBE and SSE test runs were performed, including three runs of resonance search. Test results showed that the new breakers and mock-up cubicles successfully passed the minimum required 5 OBE tests.
For the SSE tests performed at Wyle Laboratories, excessive relay chatter at certain frequencies were noted. The excessive chatter was due to over-testing the equipment, which in turn was a result of Wyle Laboratories being unable to accurately control the test table response at 10 Hz and above due to resonance of the table. The over-test produced a significant amount of relay chatter, which caused the tripping and closing of breakers. The post test functional check showed that the breakers were functioning properly and had no structural damage.
To properly test the relays, supplemental SSE testing was performed at Farwell and Hendricks (F&H) Laboratories. The upper front doors of the G-12 and G-13 cubicles, where a majority of relays are mounted, were mounted on the F&H rigid test fixture. One 1200A breaker and one 2000A breaker, located adjacent to the test table, were fed by the relays. The SSE RRS obtained at relay locations on the G-12 and G-13 cubicles from the previous Wyle testing were reduced with the appropriate scaling factor to eliminate unnecessary over-testing. The supplemental SSE testing was successful. However, certain modifications (such as adding chokes to the breakers and removing DCPP UNITS 1 & 2 FSAR UPDATE 3.10-16 Revision 21 September 2013 the seal-ins from certain relays) were made when the new breakers were installed in the 4-kV switchgear.
Based on the above, the switchgear and its contents are qualified for the DE, DDE, Hosgri, and LTSP postulated seismic events at DCPP. 3.10.2.7.2 Potential Transformers 4160/120 V There are a total of four potential transformers associated with each 4 kV vital switchgear. There is a potential transformer for each feeder; auxiliary, startup and the diesel generator and one for the bus itself. Potential transformers are normally an integral mechanical and electrical part of metal clad switchgear. However, the auxiliary and startup potential transformers were removed from the top of the 4160 V metal clad switchgear during the initial qualification testing performed in 1978. In 1978, a potential transformer representing the auxiliary and startup potential transformer was separately shake-table tested and qualified for the Hosgri earthquake. A potential transformer representing the diesel generator and bus potential transformer was shake-table tested using a mock-up of cubicle H-7.
In 1995, a potential transformer was mounted above a mock-up of cubicle G-12 and a dummy weight, representing the weight of a potential transformer, was mounted above a mock-up of cubicle G-5. These two cubicles were included in the shake-table testing at Wyle Laboratories during the seismic qualification of the new SF6 breakers described in section 3.10.2.7.1.
The auxiliary and startup potential transformers that were originally at the 90-inch level of the vital switchgear have been relocated to rigid stands adjacent to the respective switchgear lineups. Electrically, they are still an integral part of the switchgear. The diesel generator and bus potential transformers located below the 90-inch level are still physically attached to the switchgear, with the exception of the diesel generator potential transformer on Unit 1 Bus F that was also moved to a rigid stand adjacent to the switchgear.
The seismic qualification has been reviewed for the latest DDE and HE levels. The comparison of the earlier test data with current seismic requirements and additional analysis demonstrate that the potential transformers are qualified to perform their safety function during and after the specified seismic conditions. 3.10.2.7.3 Safeguard Relay Boards Originally, one safeguard relay board from Unit 1 was shake-table tested to qualify the relay boards for the seismic requirements of the DDE. New qualified relays were introduced to replace the ones that exhibited chatter. Relays whose chatter did not impair any safety function were not replaced. As a result of the 1978 HE reevaluation, one relay board of the six installed was shake-table tested to higher levels than the original test. DCPP UNITS 1 & 2 FSAR UPDATE 3.10-17 Revision 21 September 2013 The qualification of the relay boards has been reviewed to the latest DDE and HE levels. Based on this review, it is concluded that the safeguard relay boards are seismically qualified to perform their safety function. 3.10.2.7.4 Vital 480 V Load Centers The vital 480 V load centers were originally qualified for the DDE based on seismic tests on similar equipment conducted by the manufacturer. As a result of the 1978 HE reevaluation, the equipment was further qualified by shake-table testing. During the testing, the draw-out modules of the load center were equipped with hold-down brackets to prevent slamming of the modules and subsequent chatter of contacts. Chatter was detected also on the deenergized high-speed contactors of the Unit 2 fan cooler controllers while the low-speed contactor was energized.
As a result, all draw-out modules of the 480 V vital load centers have been equipped with hold-down brackets. The containment fan cooler motor controllers have been equipped with mechanical interlocks that prevent inadvertent closure of the deenergized high-speed contactor when the low-speed contactor is energized, and likewise prevent closure of the low-speed contactor when the high-speed is energized.
The load centers were qualified using a certain type of kickout spring. Subsequently, all load center contactors in question were checked in the field and the proper kickout springs (the one used in the qualification testing) were installed where necessary.
The qualification of the load centers has been reviewed to new 1983 seismic criteria for both the DDE and the postulated HE event described in Section 3.7. The comparison of the earlier test data with current seismic requirements and additional analysis demonstrates that the vital 480 V load centers are seismically qualified to perform their safety function during and after the specified seismic conditions. The qualification meets the requirements of IEEE 344-1975 and RG 1.100. 3.10.2.7.5 Vital Load Center Transformer The vital load center transformers were originally seismically qualified for the DDE based on shake-table testing of a similar, but larger power transformer. Comparison was made which demonstrated that the test of the 1500-kVA transformers is applicable to qualify the 1000-kVA vital load center transformers installed.
The test results were further reviewed with regard to the 1977 requirements of the HE. It was found then that the earlier testing still qualified the transformer for the HE levels.
A further review of the original test with regard to current seismic requirements for both the DDE and HE concluded that the vital load center transformers are qualified for the above seismic criteria.
DCPP UNITS 1 & 2 FSAR UPDATE 3.10-18 Revision 21 September 2013 3.10.2.7.6 480 V Vital Load Center Auxiliary Relay Panels The vital load center auxiliary relay panels were originally designed and constructed to meet DDE seismic requirements.
To qualify the panels and electrical components for the 1978 HE requirements, two typical panels were shake-table tested. This requalified all relay panels.
The qualification of the relay panels has been reviewed to current seismic criteria for both the DDE and the HE. The comparison of the earlier test data with the current seismic requirements and additional analysis demonstrates that the vital load center auxiliary relay panels are qualified to perform their safety function. 3.10.2.7.7 Instrument Power AC Panelboards The instrument power ac panelboards were originally qualified for the DDE by seismic testing which includes multifrequency sine beat test and resonant frequency test. Subsequently, the equipment was requalified to the 1978 HE requirements based on comparison test data from the DDE tests above and shake-table testing for circuit breakers/panelboards of various manufacturers.
The qualification has been reevaluated to the current seismic requirements for both the DDE and the HE. The reevaluation includes the panelboard/component qualification by calculation and by comparison of 1978 shake-table test results to the current seismic criteria. The calculation verifies the equipment structure integrity, and the test results demonstrate that the current seismic criteria are met. The reevaluation concludes that the instrument power ac panelboards remain seismically qualified. 3.10.2.8 Design Class I DC Electrical Equipment The following subsections describe the seismic qualification of Class 1E dc electrical equipment. 3.10.2.8.1 Batteries There are six vital "batteries" at DCPP, three in each unit. Each "battery" consists of 60 battery cells (see Section 8.3.2.3.6.3 for 59-cell configuration). The original Class 1E station batteries were C&D Model LCU-27. They were replaced in 1983 with C&D Model LC-25 battery cells. Currently, all vital batteries are C&D Model LCUN-33 cells.
Each vital battery (60 cells) is located in its own room in the auxiliary building at elevation 115 feet. In each battery room there are currently four battery racks; three are single-tier racks that hold 12 LCUN-33 battery cells each, and the fourth is a two-step rack that holds 24 of the cells. DCPP UNITS 1 & 2 FSAR UPDATE 3.10-19 Revision 21 September 2013 The new battery cells (Model LCUN-33) were tested at Wyle Labs in Huntsville, Alabama. A rigid test rack was utilized. The test rack held four LCUN-33 cells. The new battery cells have been qualified by shake table testing for DE, DDE, and Hosgri design basis seismic events. They have also been evaluated for the LTSP requirements and were found to satisfy the LTSP acceptance criteria.
Two separate LCUN-33 tests were performed. First, unaged cells were tested to qualify the cells for installation in outage 1R5 and for a 5-year life. Next, another group of LCUN-33 cells were artificially aged and tested. The second test qualified the LCUN-33 cells for a 15-year life. The qualification was performed using the guidance of IEEE 535-1986 (Reference 51) and NRC Regulatory Guide 1.158 (Reference 52). The qualified life of the C&D LCUN-33 battery was extended to achieve a 20 year mean service life in 2006. Qualified life is determined per IEEE 535-1986 and is documented in the seismic calculation file (Reference 53). Preventive maintenance is in place to replace the batteries before the expiration of their qualified life. It is concluded that the station batteries C&D Model LCUN-33 will perform their safety function during and after DCPP design basis seismic events. 3.10.2.8.2 Station Battery Racks Each vital battery (60 cells - see Section 8.3.2.2.1.3 for 59-cell configuration) is located in its own room in the auxiliary building at elevation 115 feet. In each battery room, there are currently four battery racks. Originally, all battery racks were single-tier racks. Each rack held 15 Model LC-25 cells. Since the new LCUN-33 battery cells are wider than the old cells, the existing single-tier rack would hold only 12 of the new cells. Accordingly, one of the existing single-tier racks was replaced with a new two-step rack that will hold 24 of the new battery cells. Currently, three of the existing racks are single-tier racks that hold 12 LCUN-33 battery cells each. The fourth is a two-step rack that holds 24 of the cells.
The original single-tier racks were supplied by C&D along with the original LCU-27 battery cells. The racks have since been modified by PG&E due to the 1978 Hosgri reevaluation, new stress analysis for the current DDE and Hosgri levels, and finally as a result of replacing the battery cells with the new Model LCUN-33.
Both the single-tier and the two-step racks have been seismically qualified by analysis and are qualified for DCPP design basis seismic events. 3.10.2.8.3 Battery Chargers Originally, the battery chargers were seismically qualified for the DDE by dynamic testing. As a result of the 1978 HE reevaluation, one of the battery chargers was shake-table tested to qualify all chargers for the HE requirements. DCPP UNITS 1 & 2 FSAR UPDATE 3.10-20 Revision 21 September 2013 Further shake table testing has been done on one of the battery chargers to current seismic requirement. The testing demonstrated that the battery charger will perform its safety function during and after the postulated seismic events. The testing qualifies all Class 1E battery chargers for both DDE and HE. 3.10.2.8.4 125 V DC Switchgear The 125 Vdc switchgear was originally qualified for the DDE based on seismic tests performed on similar equipment conducted by the manufacturer.
As part of the 1978 HE reevaluation, a 125 Vdc switchgear from DCPP was shake-table tested. This switchgear is identical to the other five 125 Vdc vital switchgears installed in the plant. This test demonstrated the adequacy of the equipment's safety function during and after the postulated seismic condition.
The qualification of the dc switchgears has been re-reviewed to current seismic requirements for both the DDE and HE. The review confirms the adequacy of the qualification by comparison of the 1978 equipment test data to the current criteria. Based on the review, it is concluded that the 125 Vdc switchgears are qualified to perform their function during and after the DDE and the HE. 3.10.2.8.5 Motor Controller, 125 Vdc, for Valve FCV 95 The 125 Vdc motor controllers were installed at Units 1 and 2 in 1982. They have been seismically qualified to the seismic requirements of both the DDE and HE described in Section 3.7 by shake-table testing of one unit. The controller met all the test requirements; therefore, it is concluded that the motor controllers will perform their safety function during and after the specified seismic events. 3.10.2.9 Main Annunciator Originally, the main annunciator cabinets were seismically qualified for the DDE by dynamic analysis. Visual annunciator components similar to those mounted in the cabinets were tested in operation by the supplier. The cabinets were reanalyzed again for the 1978 HE reevaluation. As a result, some bracing was added inside the cabinets. Components of the visual annunciator were shake-table tested and qualified for the HE requirements.
The seismic qualification of the annunciator cabinets and the visual annunciator components have been reviewed to the current requirements of both the DDE and HE. As a result of this review, the annunciator cabinets were further stiffened, particularly in the longitudinal axis. The components were found to meet the new seismic requirements.
The Sequence of Events Recorder (SER) components including the printer have been qualified by shake-table testing. The SER Cathode Ray Tube display and its DCPP UNITS 1 & 2 FSAR UPDATE 3.10-21 Revision 21 September 2013 microprocessor were shake-table tested to ensure they would not become a missile hazard but are not required to operate during and after a seismic event.
Subsequently, due to problems obtaining parts for the seismically-qualified printer, PG&E replaced the printer. The printer was replaced with a seismically qualified touch screen and a computer (PC) interfacing with a nonseismically qualified desktop printer. The PC and touch screen were qualified by testing. After a seismic event, the operators will be able to view the alarms on the touch screen. Any compatible desktop printer can be obtained and used to print the data.
The main annunciator communicates via data link to remote multiplexers and visual annunciator drivers associated with the main generator, which are not seismically qualified. There is no failure mechanism of the data link, remote multiplexer, or remote visual annunciator drivers that can adversely impact the function of the main annunciator system following an earthquake. The main generator alarms provided by the multiplexers are Design Class II and are not needed to maintain the plant in a safe shutdown condition or to mitigate the consequences of seismic events (Reference 46).
The main annunciator system is considered to be important to plant operation. However, the main annunciator system is not required for safe shutdown of the reactor. To achieve high reliability, the main annunciator system is designed to remain functional during and after a Hosgri earthquake, and to operate during a momentary or extended loss of offsite power. To meet these performance goals, the main annunciator system was originally classified as a Class I system. However, since the main annunciator system is not designed to meet the single failure criterion, the system was reclassified to Class II.
3.10.2.10 Electrical Penetrations Electrical penetrations of the containment structure must withstand the forces caused by a LOCA. The header plates are made of forged steel welded to the containment steel liner and therefore have considerably more strength than is needed to meet seismic conditions. The penetrations are approximately 5 feet long and contain insulated electrical conductors of stranded copper. These conductors are supported within the penetration and at the terminal boxes attached to each end of the penetration.
The electrical penetrations were originally seismically qualified for the DDE by static analysis, meeting the requirements of paragraph 3.1.3 of IEEE 344-1971. A further seismic analysis was made for penetration of similar configurations for the Pilgrim 1 and Fitzpatrick 1 units. This analysis was used to qualify the penetration for the 1978 HE reevaluation.
Seismic testing performed by the manufacturer and a new analysis was used to qualify the penetrations to current requirements of the DDE and HE. The analysis demonstrates that the electrical penetrations will perform their safety function during and after the specified seismic conditions. DCPP UNITS 1 & 2 FSAR UPDATE 3.10-22 Revision 21 September 2013 3.10.2.11 Pressure and Differential Pressure Transmitters Seismic tests were performed on Barton Model 763 and 764 transmitters and Rosemount Model 1151, 1152, 1153, and 1154 transmitters as part of an environmental test programs conducted by their respective manufacturers. The transmitters were subjected to simultaneous independent biaxial excitation using a random test input. The test included a resonant search, 5-DEs, and 1-DDE, in each of two test positions.
The transmitters were pressurized and operational throughout the test. The output of each transmitter was monitored during the test to verify proper operation. The results of the test verified that the transmitters will operate properly for both DDE and HE excitation.
The seismic qualification of Rosemount Model 1154 transmitters is based on similarity between Model 1154 and Model 1153 Series D transmitters (Reference 37, paragraph 7.2). As documented in References 38 and 39, the Model 1153 Series D transmitters were shake table tested per IEEE 344-1975 to DCPP seismic requirements.
During the seismic testing leak test, calibration check and voltage variation tests were performed.
All tested transmitters successfully met the acceptance criteria. Anomalies observed were determined not to have an impact on the transmitters' qualification (Reference page v in Wyle Test Report No. 45592-3 -- Appendix A of Reference 38). The test response spectra curves enveloped the applicable DCPP-required response spectra curves (Reference 39). Seismic testing and analysis (Reference 50) was performed to qualify Rosemount 'Smart' transmitter model 3051C for use in Instrument Class IC Systems as defined in Section 7.1 (3). The seismic testing and analysis in Reference 50 also qualifies the use of Rosemount 'Smart' transmitter model 3051N for use in Instrument Class IA Systems as defined in Section 7.1 (1).
Seismic tests were also performed on two typical models of Barton transmitters, Models 368 and 369, pressurized to mid-range operation. The tests were performed at Wyle Laboratories on a biaxial shaking table. Results show that the requirements were met. The transmitters operated throughout the tests without malfunctioning. A helium leak test was made on the pressure boundary of the transmitter after the seismic tests. No leakage was detected. The instruments were qualified in conformance to the requirements of IEEE 344-1971, Paragraph 3, Method 2, simulated seismic test.
Additional seismic qualification tests have been performed on the Barton Model 332 pressure transmitter. These were part of a series of tests, documented in WCAP-8021, where selected types of safety-related essential equipment were subjected to vibration tests in the range of 1 to 35 Hz. DCPP UNITS 1 & 2 FSAR UPDATE 3.10-23 Revision 21 September 2013 A preliminary search of the 1 to 35 Hz frequency range, using a sinusoidal input, was performed to identify any resonant condition. Any resonant frequencies found would be included with the test frequencies of the sine beat seismic input. The amplitude of the sine beat was chosen such that it would be at least as great as the maximum acceleration that the equipment would experience during a DE horizontal ground acceleration of 0.4 g, augmented by building structural amplification. Tests were done independently for each of the two horizontal and the one vertical directions of motion. Throughout the duration of the testing, both the test and reference transmitters were energized, measuring a 50 psi input pressure on a 300 psi span. The 4 to 20 mA electric output of the transmitter was monitored during and after the test to check for any loss of function.
Based on the results of these tests, it is concluded that this transmitter will perform its required design function during, as well as following, a seismic event. 3.10.2.12 Raceway Supports The Class 1E raceway systems (safety-related) consist of conduits, cable trays, and pull boxes supported by approximately 27,000 supports in each unit. The raceway supports are constructed primarily of bolted assemblies of cold-formed channel sections either of "Superstrut" (more than 90 percent) or "Unistrut" (approximately 10 percent) brand, which are spaced at 8-1/2 feet or less, unless otherwise approved by an engineering evaluation. The supports are attached to concrete or structure steel by bolted connections or welding. Based on the similarity of structural configuration, the raceway supports are grouped into more than 400 generic types.
3.10.2.12.1 Design and Acceptance Criteria The raceway supports are required to withstand loads from DDE or HE. The supports, in their as-built conditions, are evaluated to ensure that they meet the following criteria. Loading Combination The horizontal component of seismic load (DDE or HE) either transverse or longitudinal to the raceways that results in the highest stress on the member under consideration is combined, by absolute sum, with the stresses or forces due to dead load and vertical seismic load. Response Acceleration of Support System Unless otherwise justified the floor response spectra where supports are located are used for evaluation. The horizontal response is taken as the greater of the building responses due to either the east-west or the north-south ground motion combined by absolute sum, with the corresponding torsional response, as appropriate.
DCPP UNITS 1 & 2 FSAR UPDATE 3.10-24 Revision 21 September 2013 Acceptance Criteria The specifications used to review the design of the steel members are the AISI "Specification for Design of Cold Formed Steel Structural Members" (Reference 32, Section 3.10.3) and Part 1 of the AISC "Specification for the Design, Fabrication and Erection of Structural Steel for Buildings" (Reference 33, Section 3.10.3) applicable to hot-rolled members. The allowable stress given in the AISC specification is increased by 60 percent as recommended by Standard Review Plan Section 3.8.4 (Reference 34, Section 3.10.2.12.3). The allowable stress for AISI is increased so that the margin against yielding is 1.0 or greater with the allowance for local yielding at connections. The allowable slip-shear capacity of bolted connections on strut members are established by statically testing support connections with various combination of nuts and bolt torque values. The design allowable is based on the support connection containing the type of nut (98 percent of the nuts actually used in the plant exhibit superior behavior) and the bolt torque value (more than 90 percent of the connections have significantly higher values) which very conservatively represent the as-built condition. In addition, a qualification criterion was established by performing dynamic tests on specimens having representative support configuration in determining acceptable shear capacity of the in-situ bolts. In some cases, the slip-shear capacities are based on manufacturer's recommended values. These shear capacities are for appropriate combination of nut types, bolt torque, and strut which have been verified by additional tests.
Permissible loads on conduit clamps are kept below 90 percent of the ultimate values. Clamps are also checked for interaction of pull-out and slip (either in transverse or longitudinal direction). The acceptance limit on fillet welds on cold-formed steel members is 60 percent greater than the allowable given in Section 4.2.1 of the AISI Specification. Spot-welds in composite superstrut channels are checked against allowable shear values developed from a testing program. 3.10.2.12.2 Evaluation The electrical raceway systems are evaluated for seismic loading in the transverse, longitudinal, and vertical directions by following the methodology stated below. Transverse Seismic Analysis Each of the support types are evaluated against the acceptance criteria. The seismic loads used in the evaluation of the supports are based on system frequency of the support and adjacent span of the raceway. The damping value used for conduit supports is 7 percent. For cable tray supports, two separate frequency analyses are made to determine the spectral response. In the first analysis, the system frequency is obtained based on support frequency alone and 7 percent damping is used. In the second analysis, the system frequency is generated by combining the support frequency and the tray frequency. The seismic response is obtained based on DCPP UNITS 1 & 2 FSAR UPDATE 3.10-25 Revision 21 September 2013 15 percent damped floor spectra. The second analysis is confirmatory and not a basis for the license. The larger of the two spectral values is used for evaluation.
Each support type is first evaluated for the generic case based on design, which results in maximum support response. Any support that cannot be qualified for its generic case is investigated for its as-built condition. Longitudinal Seismic Analysis All Class 1E raceway systems are walked down and documented. The longitudinal seismic load is generated based on raceway system frequency and 7 percent damping. The peak response acceleration is used if the system frequency is less than 33 Hz; otherwise, the zero period acceleration is used. The seismic load is distributed among the supports in proportion to their longitudinal stiffness. The individual supports are evaluated for structural adequacy. Vertical Seismic Analysis The vertical seismic analysis uses the same methodology as the transverse seismic analysis. 3.10.2.13 Fire Pump Controller The fire pump controllers for the plant interior system were upgraded to Class 1E when the fire protection system was upgraded. One controller was shake-table tested and qualified to 1978 HE seismic requirements. The qualification has been reviewed to the current seismic criteria for both the DDE and HE. The comparison of earlier test data with the current seismic requirements demonstrates that the fire pump controllers are seismically qualified to perform their safety function during and after the specified seismic conditions. 3.10.2.14 Local Starters Local starters were originally seismically qualified for the DDE based on shake-table testing by the manufacturer. As a result of the 1978 HE reevaluation, three representative starters were shake-table tested. The testing qualified all local starters for their respective locations. Other starters of different manufacture used for the HVAC systems were qualified by comparison to the starters tested. The qualification of the local starters has been reviewed to current seismic criteria for both the DDE and HE.
For the review of the qualification to current seismic requirements, the local starters were broken down into four groups:
DCPP UNITS 1 & 2 FSAR UPDATE 3.10-26 Revision 21 September 2013 (1) Starters located in the auxiliary and fuel handling buildings were qualified by comparison of the 1978 test data to the current seismic criteria. This includes contactors installed since the 1978 shake-table testing. (2) Starters located at the turbine building 119-foot elevation were qualified by comparison of the 1978 test data to the current seismic criteria and by comparison to identical starters shake-table tested for the turbine building 140-foot elevation. (3) Starters located at the turbine building 140-foot elevation were installed after the 1978 electrical equipment testing program. One of these starters was shake-table tested to qualify the starters for the current seismic criteria. (4) Starters located at the auxiliary building 154-foot elevation, some of which are of different manufacture, have been qualified by comparison to the starters tested. The starters tested were qualified to spectra with much higher accelerations than are required for the 154-foot elevation of the auxiliary building. The aforementioned review of the earlier seismic testing to current criteria for both the DDE and HE and additional testing demonstrates that all local starters are qualified to perform their safety function during and after the specified seismic conditions. 3.10.2.15 Ventilation Control Logic and Relay Cabinet The ventilation control logic and relay cabinets were originally vibration-tested in July 1973, and seismically qualified for the DDE. The cabinets were found to be rigid. As part of the 1978 HE reevaluation, components of the cabinets were shake-table tested again and qualified for the HE.
The seismic qualification of the ventilating control logic and relay cabinet and their components has been reviewed to the current seismic requirements of both the DDE and the HE. Based on the review, it has been concluded that the ventilation control logic and relay cabinets are seismically qualified to perform their safety function during and after the DDE and the HE.
As part of the Unit 1 and 2 AFHBVS control system replacement, a new programmable logic controller (PLC) system was installed. The seismic qualification of the Plant Operating Vent panels, POV1 and POV2, and their components were reviewed to the current seismic requirements of both the DDE and the HE. The POV panels were evaluated using analytical evaluation and the PLC was shake table tested by the supplier. Based on the review, it was concluded that the POV1 and POV2 cabinets are seismically qualified to perform their intended safety function during and after the DCPP design basis seismic events.
DCPP UNITS 1 & 2 FSAR UPDATE 3.10-27 Revision 21 September 2013 3.10.2.16 Fan Cooler Motors The fan cooler units were qualified for seismic adequacy by a combination of analysis and testing. A seismic analysis of the fan cooler unit, including the motor, was made to verify that the units will not exceed the allowable stresses or deflections. The response spectrum method of analysis was used.
The fan motor assembly natural frequencies were calculated using a lumped mass model. Because of high natural frequencies (after adding stiffeners to the fan cooler assemblies), this system was analyzed as a rigid structure and equivalent static loads were applied. An additional unbalanced load of 1 g was assumed to occur in all rotating assemblies.
Limit values were in accordance with the elastic provisions of the AISC-69 specification. Bearing limits were taken as failure by brinelling under dynamic load (basic rating) from the manufacturer's catalog.
An analysis and an impact test were also made on an end bell of the motor. Based on these results, Westinghouse concluded that the containment fan-motor-cooler assembly structure could withstand the combination of required loads. 3.10.2.17 Pump Motors Electric motors for Design Class I pumps were procured with the pumps to equipment specifications that covered the pump/motor assembly as a unit. These equipment specifications required that the equipment be adequately designed to accommodate seismic accelerations appropriate for the DE and DDE. At the time of procurement of this equipment, there were no industry standards for seismic qualification of electric motors. However, methods and criteria employed in the design of large, integral horsepower electric motors lead to motor designs that are inherently capable of tolerating high seismic loadings without loss of function. Design considerations for motors of this type include maximum torque, critical shaft speed, bearing life, vibration, and cyclical loading. These considerations lead to motor designs that would not be governed by the application of seismic loads in the range of those appropriate for DCPP. Experience with such motors in applications subject to severe vibration and shock provides additional confirmation of seismic adequacy. Based on these considerations, it is the consensus of competent engineering practice that these motors are adequately designed to perform their safety function before, during, and after the DDE or HE.
In the case of the auxiliary saltwater pumps, which are vertically mounted, calculations indicated that seismic bracing in the horizontal direction was necessary to ensure that the first vibrational mode of the pump-and-motor assembly would be in the rigid range of the design spectra. Other pump-and-motor assemblies have natural frequencies well within the rigid range. DCPP UNITS 1 & 2 FSAR UPDATE 3.10-28 Revision 21 September 2013 Analyses of pump-and-motor assemblies representative of those considered here have been performed and have shown substantial margin in stresses, deflections, and bearing loads for seismic loadings in the range of those appropriate for DCPP. Selected pump-and-motor assemblies for DCPP have also been analyzed using the appropriate floor response spectra and both static and dynamic analysis methods. For all cases analyzed, seismic adequacy has been verified. 3.10.2.18 Electric Cables Electric cables interconnecting pieces of equipment depend on raceways for support during seismic activity. Seismic criteria for raceway supports are described in Section 3.10.2.12. These cables are flexible and are fully supported along their entire length in conduit or tray. Adequate slack is provided to impose little or no tension on the wires. Where relative shifts between structures can occur, raceways are provided with flexible joints or are routed with adequate flexibility to ensure that the conductors remain undamaged and their associated supports meet their acceptance criteria. (Note that use of trays for Class 1E circuits is very limited, see Chapter 8.) 3.10.2.19 Motor-Operated Valves PG&E-purchased motor-operated valves (MOVs) whose only safety function is to maintain a pressure boundary and which are not required to change position during or after an accident (passive valves), and those whose safety function includes both maintaining a pressure boundary and changing position during or after an accident (active valves), were qualified to acceleration levels less than or equal to allowable acceleration levels provided by the vendor or established by analysis. All Westinghouse-purchased MOVs were qualified to acceleration levels less than or equal to allowable acceleration levels provided by Westinghouse.
Limitorque MOV operators of the type installed on active Design Class I valves in DCPP Units 1 and 2 have been seismically qualified by test. Tests were conducted on various sized operators at g-levels from 3 to 10 g.
Operators were tested both while operating and while energized and not operating. The testing was single axis, performed along each of three mutually perpendicular major axes. Sine sweep testing was utilized over a range from 5 to 35 Hz, and was followed by 1- to 2-minute sinusoidal vibration at 34 Hz or at any resonant frequency below 35 Hz.
The test results for the MOV operators have been considered in the analysis of piping systems. The mass and resonant frequency of the operator is used as input in the piping analysis. The resulting acceleration levels are compared to the allowable levels to verify that the operator will function as required. DCPP UNITS 1 & 2 FSAR UPDATE 3.10-29 Revision 21 September 2013 3.10.2.20 Control Room Ventilation System The control relay and power panels are seismically qualified to the current seismic requirements for both the DDE and the HE. The qualification of the power panels is based on: shake-table testing on the similar equipment performed by the manufacturer, onsite resonance frequency test on the similar panelboard, extensive shake-table testing of electro-mechanical equipment containing circuit breakers or circuit breaker panelboards and testing of circuit breakers to the extent of the shake-table limit.
The qualification of the control relay panels is based on the actual shake-table testing of similar ventilation control relay cabinet installed in DCPP, containing the same control relays. Timing relays not found in this shake-test are seismically qualified based on the qualification of 4-kV switchgear equipment in which the identical timing relays were installed.
Test specimens similar to the installed equipment were evaluated for their adequacy of qualification. By comparison of the test data from those shake-table tests to the current seismic requirements, the test results of these equipment demonstrate that the specified seismic criteria are met for both the DDE and HE. It should be noted that the equipment is only needed for the control room ventilation and pressurization (CRVP) after an earthquake and not during the earthquake. Therefore it is concluded that the CRVP control relay and power panels are qualified to perform their safety function after the postulated seismic events such as the DDE and the HE.
The radiation and chlorine monitoring panel has been qualified by seismic simulation testing of a test specimen similar to the panel installed at the DCPP. The panel test specimen was welded to the test table and bolted to an adjacent structure in order to simulate the actual plant mounting conditions. The panel test specimen contained the following instruments: one radiation rate readout (Nuclear Measurements Corporation Model GA-2TMO), one radiation rate readout (Technical Associates Model FML-554), one chlorine analyzer (Capital Controls Model 1030), and one switch reset module. Dummy weights were used to simulate random biaxial seismic simulation tests in accordance with IEEE std. 344-1975. The function of the instruments was verified before and after the testing. The test response spectra have been verified to envelop the DDE and HE required response spectra. The chlorine detection function has been eliminated and the detectors are abandoned in place.
The radiation detector associated with the Nuclear Measurements radiation rate readout described above was also subjected to random biaxial seismic simulation tests. The test specimen was bolted to a rigid steel plate in order to simulate the mounting arrangement used at DCPP. The function of the device was verified before and after the test. The test table response spectra have been verified to envelop the DDE and HE required response spectra.
The radiation detector associated with the Technical Associates radiation readout and the chlorine detector associated with the Capitol Controls chlorine analyzer have also DCPP UNITS 1 & 2 FSAR UPDATE 3.10-30 Revision 21 September 2013 been submitted to random biaxial seismic simulation tests. These two detectors were mounted into a 14-inch steel duct in order to simulate the mounting arrangement used at the DCPP. The function of the detectors was verified before and after the tests. The test response spectra envelops the required response spectra for both the DDE and HE cases. The chlorine detection function has been eliminated and the detectors are abandoned in place. 3.10.2.21 Subcooled Margin Monitors The subcooled margin monitors (SCMMs) are located in PAM Panels 3 and 4. Subcooled margin is calculated and displayed by the reactor vessel level instrumentation system (RVLIS); therefore, seismic qualification of each SCMM is covered by the seismic qualification of the RVLIS cabinets (see Section 3.10.2.32.1).
Train A of the SCCM provides output to a recorder on PAM1. PAM1 seismic qualification is addressed in Section 3.10.2.22.
Train B of the SCCM provides output to a display on VB2. This display was qualified by testing. 3.10.2.22 Postaccident Monitoring Panels PAM1 and PAM2 These panels are located in the main control room and house various indicators and recorders used for postaccident monitoring. Typical parameters involved are reactor vessel level, containment hydrogen gas concentration, containment gross activity, etc. The panels were manufactured for PG&E by Trayer Engineering, Inc. Design Class I indicators and recorders were manufactured by Westinghouse and other qualified suppliers. Panel PAM1, with its associated instruments, was qualified by random biaxial seismic simulation tests. The tests were performed at Wyle Laboratories. The function of the devices was verified before and after seismic testing. The test response spectra have been verified to envelop the DDE and HE required response spectra.
Panel PAM2 has been qualified by an analysis that showed that the panel is rigid, with no resonant frequencies below 33 Hz. In addition, a static analysis was performed that showed that the combined seismic stresses do not exceed the allowable limits. The Design Class I instruments mounted in PAM2 have been qualified by seismic simulation tests. The test response spectra obtained from these random biaxial tests have been verified to envelop the DDE and HE spectra. 3.10.2.23 Pilot Solenoid Valves Pilot solenoid valves are used to control the air supply to air-operated control valves. The pilot valves can be mounted either on or off the control valve actuator. The DCPP UNITS 1 & 2 FSAR UPDATE 3.10-31 Revision 21 September 2013 required acceleration level for the pilot valves is 9 g's, which is based on the maximum allowable response for control valve actuators having Design Class I pilot valves.
The pilot solenoid valves have been qualified by tests performed on a variety of valve models by both the vendor, ASCO, and PG&E. The tests consisted typically of sine beat tests performed over the frequency range of 1 to 33 Hz. The minimum acceleration value met or exceeded the required level for the valves except at low frequencies, where the level was limited by testing machine capabilities. The function of the valves was verified before and after the testing. 3.10.2.24 Process Solenoid Valves Design Class I process solenoid valves are used as containment isolation valves in the post-LOCA sampling system and containment hydrogen monitoring system. The valves were manufactured by Valcor Engineering.
The valves are located both inside and outside of containment. The valves inside containment are mounted to the annulus steel structure. The valves outside of containment are mounted to the exterior of the containment structure. The required acceleration level for the valves is an envelope of the DDE- and HE-required response spectra for both these locations.
The valves were qualified by a test performed by the vendor as part of an environmental qualification program. The test used a random biaxial input, with the devices mounted to the test table simulating an actual installation. The test procedure conformed with IEEE 344-1975. The test levels were sufficient to qualify the valves to their required acceleration level. The function of the valves was verified before and after the testing. 3.10.2.25 Containment Hydrogen Monitoring System The containment hydrogen monitoring system (CHMS) consists of two redundant systems each consisting of an analyzer panel and a remote control panel. The analyzer panels are anchored to the floor in plant area GE at elevation 100 ft. The remote control panels for both systems are mounted in a panel (RCHMC) located in the post-LOCA sampling room in plant area GE at elevation 85 ft.
The Containment hydrogen monitoring system is Class II, Type C, Category 3, non safety related. The analyzer panels are Class II and anchorage of the analyzer panel has been seismically evaluated. Although the panel inserts for the Containment hydrogen monitor are non-safety related, the remote control panel (RCHMC) is Class I for the Class I circuits powering the related containment isolation valves.
The RCHMC panel has been structurally analyzed which includes the seismic mounting of non-safety related panel inserts. A detailed stress analysis was conducted that showed that the rack assembly is structurally adequate to withstand the DDE and HE loads. DCPP UNITS 1 & 2 FSAR UPDATE 3.10-32 Revision 21 September 2013 3.10.2.26 Containment Purge Exhaust Each monitor consists of a detector assembly and a Local Radiation Processor (LRP) located in Area L on the 100 ft elevation. The remote readout is located in the Radiation Monitoring System panel (RNRMS) in the Control Room. The detectors and LRPs are qualified by analysis based on a test simulation performed on similar equipment. The Control Room mounted equipment is qualified based on shaketable tests on the RNRMS panels performed for Victoreen. See Section 3.10.2.1.1.1. 3.10.2.27 Limit Switches Limit switches are used to detect the position of control valves. Limit switches for motor-operated valves that are an integral part of the actuator are qualified as part of the assembly (see Section 3.10.2.19). Limit switches for air-operated valves and for motor-operated valves that are mounted on the valve actuator are qualified separately. The required acceleration level for these limit switches is 9 g, which is based on the maximum response allowable for valves having Class 1E limit switches.
Class 1E limit switches have been qualified by testing performed on several different styles. Tests have been performed by both the vendor and PG&E. These tests typically consisted of sine beats or sine dwells at 9 g peak acceleration over the frequency range of 1 to 33 Hz. Test acceleration levels met or exceeded the required level except at low frequency ranges where the level was limited to test machine capabilities. The test specimens were functionally tested before and after the vibration testing.
3.10.2.28 Containment High-Range Radiation Monitoring System The containment high-range radiation monitoring system is used to monitor ambient gamma radiation in the containment following a LOCA. The system consists of two redundant detectors located in the containment at elevation 145 ft and a remote readout located in the postaccident monitoring panel PAM2 in the main control room. The system was supplied and qualified by Victoreen.
The radiation detectors and readouts have been qualified by random biaxial seismic simulation tests that were conducted as part of an environmental qualification test program. The test response spectra have been verified to envelop the required DDE and HE response spectra. There were no malfunctions experienced throughout the seismic tests. The test conformed to IEEE 344-1975. 3.10.2.29 Pressurizer Safety Relief Valve Position Indication The pressurizer safety relief valve position indication system is an acoustic flow detection system that verifies valve position by sensing flow through the pressurizer relief lines. There are three channels, one for each relief valve. The system consists of four components: detector, charge converter, signal conditioner, and remote readout. DCPP UNITS 1 & 2 FSAR UPDATE 3.10-33 Revision 21 September 2013 The detector is an accelerometer attached to the pressurizer relief line by a metal strap. The charge converters for all three channels are housed in a stainless steel enclosure, which is mounted to the wall adjacent to the pressurizer at elevation 145 ft in the containment. The signal conditioner is located in panel RCRM in the main control room. The remote readout is mounted in the main control board. All components of the system were supplied and qualified by Technology for Energy Corporation.
The equipment comprising the system was qualified as part of an environmental qualification program conducted by the vendor. The seismic portion of the testing was conducted in accordance with IEEE 344-1975. All of the system components were qualified by tests consisting of random input, independent triaxial excitation. Tests were conducted at Structural Dynamics Research Corporation. The test response spectra from these tests have been verified to envelop the applicable DDE and HE spectra. The function of the devices was verified before and after the testing. 3.10.2.30 Heating, Ventilating, and Air Conditioning Equipment The qualification of safety-related heating, ventilating, and air conditioning (HVAC) equipment is reviewed according to DE, DDE, and HE criteria. This HVAC equipment is associated with the following safety-related systems:
(1) Forced draft shutter (2) Diesel generator compartment ductwork (3) Auxiliary saltwater compartment ventilation (4) 4-kV switchgear ventilation (5) 480 Vac switchgear ventilation (6) Auxiliary building-fuel handling building ventilation (7) Control room ventilation and pressurization system The equipment and components of Class 1 HVAC systems are listed in Table 3.10-3.
They have been reviewed for seismic qualification in accordance with the spectra, defined in Section 3.7.
The equipment listed in the table is organized into qualifying groups consisting of similar types of equipment. The component subject to the worst-case qualifying condition in each group has been reviewed for compliance with acceptance criteria. This worst-case analysis in turn envelops the other components in the respective groups.
All the items in the table were reviewed for identification of the qualifying spectra. Where the most current spectra exceed the conditions under which the component was DCPP UNITS 1 & 2 FSAR UPDATE 3.10-34 Revision 21 September 2013 previously analyzed, a new analysis was initiated. The results of the analysis confirmed the qualification of the component or identified a physical modification. Where analysis is not appropriate, equipment testing was used to demonstrate the design performed under the qualifying seismic conditions. 3.10.2.30.1 HVAC Duct and Duct Supports The Class I HVAC duct system consists of ducts and approximately 2,000 supports in both units. HVAC ducts are made of cold-formed steel conforming to ASTM A525, A526, and A527 with the thickness varying depending upon the duct size. The duct supports are mostly structural steel angles. Supports are attached to concrete or structural steel by bolted connections or by welding. The ducts are fastened to the supports by means of screws, rivets, or stitch welds. 3.10.2.30.1.1 Design and Acceptance Criteria The duct and duct supports are evaluated in their as-built condition to meet the following criteria: Loading Combination The ducts are evaluated for the concurrent dead weight, seismic load, and pressure load. The duct supports are evaluated for dead weight and seismic load. The pressure load is the negative operating pressure of the HVAC system and is not included in the evaluation of the duct supports. The seismic loads evaluated are DDE and HE loads. The horizontal component of seismic load (DDE or HE), either transverse or longitudinal to the ducts, that results in the highest stress in the member under consideration is combined, by absolute sum, with the stresses due to vertical seismic load. As an alternative, the seismic loads from each of the three directions are combined by SRSS method. Response Acceleration of Support System The applicable floor response spectra where the supports are located are used for evaluation of HVAC duct and duct supports. The corresponding horizontal spectra are combined, by absolute sum, with the corresponding torsional response, as appropriate. Acceptance Criteria The AISI "Specification for Design of Cold-formed Steel Structural Members" is used to evaluate the design of cold-formed steel members, and part 1 of the AISC "Specification for the Design, Fabrication, and Erection of Structural Steel for Buildings" is used for the design of hot-rolled members. The allowable stresses given in AISI and AISC Specification are increased by 60 percent. DCPP UNITS 1 & 2 FSAR UPDATE 3.10-35 Revision 21 September 2013 3.10.2.30.1.2 Evaluation For duct supports, the seismic loading is evaluated for vertical plus transverse horizontal loads and vertical plus longitudinal horizontal loads. The frequency of the coupled duct and duct support system is used in determining the spectral response. The damping values used are 2 percent for DDE and 7 percent for HE. 3.10.2.31 Electric Hydrogen Recombiner System The model B electric hydrogen recombiner system (EHRS) is designed to control and reduce post-LOCA containment hydrogen levels. The system consists of three components; control panel, power supply, and recombiner. Two model B EHRSs are provided for the DCPP site.
The recombiner was subjected to multiple frequency multiple axis testing in accordance with IEEE 344-1975. The results of the seismic testing are provided in Reference 25. The recombiner was energized and at operating temperature before, during, and after each seismic test. Following the entire testing, the recombiner was inspected for damage. No disabling damage was found. An air flow test was conducted after testing and the results show no loss of air flow. The test response spectra were checked to envelope the DDE and HE response spectra, to confirm its seismic adequacy.
The power supply and control panel were tested at the same time as documented in Reference 26. Testing was done with conservatively large accelerations over a range of applicable frequencies and conformed to the procedures given in IEEE 344-1971. The peak test input accelerations used in the power supply and control panel tests were checked to verify that they are larger than the requirements derived by DDE and HE loadings.
After each seismic test the power supply was visually inspected for structural integrity and functional operability. Both units were found to operate satisfactorily. 3.10.2.32 Reactor Vessel Level Instrumentation System The RVLIS consists of the following instrumentation:
- RVLIS/incore thermocouple cabinets (including remote display)
- Reactor coolant level differential pressure transmitters (see Section 3.10.1.5)
- Surface mounted RTDs
- High volume sensors
- Differential pressure indicating switches (hydraulic isolators)
Typical items of the above instrumentation and electronic equipment have been type tested using multiple frequency, multiple axis seismic testing. Testing was performed in accordance with the procedures given in IEEE 344-1975. The test response spectra DCPP UNITS 1 & 2 FSAR UPDATE 3.10-36 Revision 21 September 2013 obtained from those tests were checked to envelope the DDE and HE response spectra. 3.10.2.32.1 RVLIS/Incore Thermocouple Cabinets Two RVLIS/incore thermocouple cabinets (PAMs 3 and 4) are provided for DCPP application. Located within each cabinet are the microprocessor electronics, reactor coolant pump (RCP) status panel, and a remote display. The above RVLIS instrumentation is only required to operate normally before and after seismic excitation. The RCP status panel assembly is shown to be operational by the signals recorded during testing and the functional checks made after each simulated SSE. The remote display electronics must function normally by providing microprocessor output display formatted information.
The results of seismic testing of the original RVLIS/incore thermocouple cabinets are provided in Reference 27. The original remote display was not included in the cabinet tested. The original remote display was tested later to worst-case (maximum) in-cabinet response for the RVLIS/incore thermocouple cabinets. The seismic testing of the original remote display is documented in Reference 28.
Because the original Westinghouse-supplied system is obsolete and due to the lack of availability of replacement components, the obsolete RVLIS/incore thermocouple systems were replaced. The replacement processors, signal conditioners, and displays are seismically qualified by testing and analysis as documented in References 47, 48, 54 and PG&E Calculation IS-66. 3.10.2.32.2 Surface Mounted RTDs There are 14 surface mounted RTDs used in RVLIS to measure the temperature of the reference leg impulse lines. As described in Reference 29, the surface mounted RTDs were subjected to single frequency, multiple axis sinusoidal tests and multiple frequency, multiple axis seismic tests. The RTDs tested were operational throughout all phases of the test sequence. Measurement of performance was by a evaluation of the recorded RTD output, periodic static calibrations, and numerous insulation surface mounted RTDs maintain their structural integrity and functional accuracy required. 3.10.2.32.3 High Volume Sensors The high volume sensors are bellows designed for large volumetric displacement to accommodate thermal expansion postulated postaccident environment. The safety related performance requirement is that the sensor must maintain this pressure boundary and sensing interface between the process and filled pressure/differential pressure system without introducing any sensing errors.
DCPP UNITS 1 & 2 FSAR UPDATE 3.10-37 Revision 21 September 2013 The results of seismic testing are provided in Reference 30. Based upon the information provided therein, the high volume pressure sensor can successfully fulfill its safety related requirements during and after seismic testing. 3.10.2.32.4 Differential Pressure Indication Switches The differential pressure indicating switches (hydraulic isolators) are used to seal off full process pressure in either direction and will actuate switches to indicate a unbalanced condition. The safety-related performance requirement for RVLIS is that the switch provide the isolation function without contributing a sensing error to the accuracy of a downstream pressure of differential pressure transmitter.
During the seismic test, adherence to this requirement is verified by monitoring the output of two reference transmitters receiving the pressure signal. While no safety related use is made of the switch contacts in the reactor vessel level indicating system, testing was designed to demonstrate the suitability of indicating switch use for other applications.
Seismic testing of the hydraulic isolators is provided in Reference 31. The hydraulic isolators sustained no physical damage during the seismic testing and performed their process sensing line isolation function successfully, with no leakage of the water fill. 3.10.2.33 Incore Flux Mapping Cabinets and Transfer Device The incore flux mapping cabinets and flux mapping transfer device are non-safety related but have been seismically qualified for structural integrity for HE loadings. The incore flux mapping cabinet is structurally identical to the NIS cabinets (see Section 3.10.2.1.1). The weight distribution of equipment within the cabinet would produce essentially the same dynamic results. Therefore the results obtained from the test of the NIS cabinets are applicable for the incore flux mapping cabinet structure.
The flux mapping transfer device is an assembly used to support control equipment to drive detectors into and out of thimbles in the reactor core. The flux mapping transfer device has been evaluated to maintain its structural integrity to withstand the HE for DCPP. 3.
10.3 REFERENCES
- 1. The Institute of Electrical and Electronic Engineers, Inc., IEEE Standard 344-1971, Trial Use Guide For Seismic Qualification of Class I Electric Equipment for Nuclear Power Generating Stations.
- 2. IEEE Standard 344-1975, Recommended Practices for Seismic Qualification of Class IE Equipment for Nuclear Power Generating Stations.
DCPP UNITS 1 & 2 FSAR UPDATE 3.10-38 Revision 21 September 2013 3. USNRC RG 1.100, Revision 1, Seismic Qualification of Electrical Equipment for Nuclear Power Plants, August 1977. 4. Description of the Systems Interactions Program for Seismically Induced Events, Revision 4, August 1980.
- 5. Seismic Testing of Electrical and Control Equipment (PG&E Plants), WCAP-8021, May 1973.
- 6. Letter No. NS-CE-1609, Eicheldinger (Westinghouse) to Stolz (NRC),
Subject:
"Drawer Securing Method for NIS Rack," November 1977.
- 7. Seismic Operability Demonstration Testing of the Nuclear Instrumentation System Bistable Amplifier, WCAP-8830, October 1976.
- 8. General Method of Developing Multifrequency Biaxial Test Inputs for Bistables, WCAP-8624, September 1975.
- 9. Consequences of Seismic-Induced Actuation of Protection Systems Relays on the Diablo Canyon Nuclear Plant, Westinghouse Electric Corporation, July 1975.
- 10. Seismic Qualification of the Rotary Relay for Use in the Solid State Protection System, WCAP-8694, January 1976.
- 11. Deleted in Revision 21. 12. Deleted.
- 13. Seismic Testing of Electrical and Control Equipment, High Seismic Plants, WCAP-8921, December 1971.
- 14. Equipment Qualification Test Report Pressure Sensor, WCAP-8687, Supplement 2-E21A, Revision 1, March 1982.
- 15. Equipment Qualification Test Report Barton Differential Pressure Transmitter - Qualification Group B, WCAP-8687, Supplement 2-E04A, Revision 2, March 1983.
- 16. Seismic Testing of Electrical and Control Equipment, Type DB Reactor Trip Switchgear, WCAP-8821, Supplement 4, August 1974.
- 17. Deleted.
- 18. Deleted.
DCPP UNITS 1 & 2 FSAR UPDATE 3.10-39 Revision 21 September 2013 19. Seismic Testing of Electrical and Control Equipment Engineering Safeguards Test Cabinet for PG&E Plants, WCAP-8021, Supplement 1, May 1977. 20. Seismic Qualification of the Rotary Relay for Use in the Trojan and Diablo Canyon Auxiliary Safeguard Cabinets, WCAP-8941, February 1977.
- 21. Seismic Qualification of the Diablo Canyon Main Control Board, Central Console, WCAP-10358, August 1983.
- 22. Benchmark Problem Solutions Employed for Verification of the WECAN Code, WCAP-8929, June 1977.
- 23. Forced Vibration Testing of the Diablo Canyon Unit 1 Main Control Board, ANCO Engineers Inc., Document No. A-000047, May 1983.
- 24. Seismic Qualification Test Report for Diablo Canyon Main Control Board and Central Console Mounted Class 1E Devices, WCAP-8941, February 1977.
- 25. Qualification Testing for Model B Electric Hydrogen Recombiner, WCAP-9346, July 1978.
- 26. Electric Hydrogen Recombiner for PWR Containments Equipment Qualification Report, WCAP-7709-L, Supplement 2, September 1973.
- 27. Equipment Qualification Test Report, Reactor Vessel Level Instrumentation System/Incore Thermocouple Cabinet With 8080 Microprocessor Electronics and Reactor Cabinet Pump Station Panel, WCAP-8687, Supplement 2-E51A, July 1984.
- 28. Equipment Qualification Test Report, Remote Digital Display for the 8080 Microprocessor Electronics, WCAP-8687, Supplement 2-E46A, July 1984.
- 29. Equipment Qualification Test Report, Surface Mounted RTDs, WCAP-8687, Supplement 2-E48A, January 1983.
- 30. Equipment Qualification Test Report, High Volume Sensor-Group A, WCAP-8687, Supplement 2-E48A, January 1983.
- 31. Equipment Qualification Test Report, Differential Pressure Indicating Switch-Group, WCAP-8687, Supplement 2-E49A, January 1983.
- 32. American Iron and Steel Institute, Specification for the Design of Cold-Rolled Steel Structural Members, AISI, Washington, D.C., 1968.
DCPP UNITS 1 & 2 FSAR UPDATE 3.10-40 Revision 21 September 2013 33. American Institute of Steel Construction, Specification for the Design, Fabrication and Erection of Structural Steel for Buildings, AISC, Chicago, IL, Seventh Edition.
- 34. Office of Nuclear Reactor Regulation, Standard Review Plan, Section 3.8.4, NRC, Washington, D.C. (November 1975).
- 35. Seismic Confirmation of Weed Resistance Temperature Detectors For Diablo Canyon Unit 1 and Unit 2 Bypass Elimination System, WCAP-12714, Revision 2, February 1993.
- 36. Seismic Qualification Test Report of Class lE RTD and Thermocouple Temperature Sensors for Conax Corp., Report No. IPS-1165, Rev. A, June 18, 1984.
- 37. Rosemount Report D8400102, Qualification Report for Pressure Transmitter Model 1154, (PG&E DC 6000784-117).
- 38. Rosemount Report D8300040, Qualification Report for Pressure Transmitters Rosemount Model 1153 Series D, (PG&E DC 6000784-7-1).
- 39. PG&E Seismic Calculation No. IS-35, "Seismic Qualification of Rosemount Transmitters."
- 40. Equipment Qualification Test Report, Eagle 21 Process Protection System (Environmental and Seismic Testing), WCAP-8687, Supplement 2-E69A, Revision 0, May 1988.
- 41. Equipment Qualification Test Report, Eagle 21 Process Protection System (Environmental and Seismic Testing), WCAP-8687, Supplement 2-E69B, Revision 0, February 1990.
- 42. Equipment Qualification Test Report, Eagle 21 Process Protection System (Environmental and Seismic Testing), WCAP-8687, Supplement 2-E69C, Revision 0, February 1991.
- 43. Seismic Qualification of Electrical Equipment for Nuclear Power Plants, NRC Regulatory Guide 1.100, Revision 2, June 1988. 44. Recommended Practices for Seismic Qualification of Class 1E Equipment for Nuclear Power Generating Stations, IEEE 344-1987. 45. Seismic Conformation of Eagle 21 Digital Process Protection System Upgrade for Pacific Gas and Electric Company Diablo Canyon Power Plant Units 1 and 2, WCAP-13384, Revision 0, PG&E, September 1992.
DCPP UNITS 1 & 2 FSAR UPDATE 3.10-41 Revision 21 September 2013 46. PG&E Specification 1021-J-NPG, "Specification for Furnishing and Delivering Remote Multiplexer and Visual Annunciator Equipment Associated with the Main Annunciator Systems for Diablo Canyon Power Plant, Units 1 and 2." 47. Trentec Test Report No. 8Q017.0, dated 11/98.
- 48. Altran Calculation No. 98250-C-001, Revision 0, dated May 1999. 49. PG&E Seismic Calculation No. ES-66, "Seismic Qualification of Westinghouse Supplied SSPS Cabinets." 50. PG&E Seismic Calculation No. IS-88, "Seismic Qualification of Model 3015C/3015N Rosemount Transmitters."
- 51. IEEE Standard 535-1986, IEEE Standard for Qualification of Class 1E Lead Storage Batteries for Nuclear Power Generating Stations.
- 52. USNRC RG 1.158, Revision 0, Qualification of Safety-Related Lead Acid Storage Batteries for Nuclear Power Plants, February 1989.
- 53. PG&E Seismic Calculation No. ES-15-1, "C&D Model LCUN-33 Vital Batteries and Two Steps Battery Rack."
- 54. QualTech Test Report No. S1203.0, Revision 0, dated 02/24/2012. 55. Triconex Tricon v10 Seismic Test Report Document No. 9600164-526, Revision 1. 56. Qualification of Rack Mounted Electrical Components at Process Control Racks RNO1A through RNO4D, Specification 10101-M-NPG, Revision 3.
- 57. NLI Qualification Report QR-01913272-1 Rev. 5(PG&E Document Number 663222-267).
- 58. NLI Supplemental Qualification Report SQR-01913272-1, Revision 3 (PG&E Document Number 663222-268).
- 59. Specification for Furnishing and Delivering Manual/Auto Stations for Diablo Canyon Power Plant Units 1 & 2 10083-J-NPG, Rev. 4.
- 60. AMS826, AMS826/1 and AMS826/2 Qualification Report Rev. 3 (PG&E Document Number 6021767-6).
- 61. AMS827 Qualification Report Rev. 2 (PG&E Document Number 6021767-8).
DCPP UNITS 1 & 2 FSAR UPDATE 3.11-1 Revision 21 September 2013 3.11 ENVIRONMENTAL DESIGN OF MECHANICAL AND ELECTRICAL EQUIPMENT This section provides information on the environmental aspects of DCPP equipment design. Relevant background information is presented first. This information is necessary to understand the evolutionary nature of regulatory requirements in this area, and the impact of this evolution on DCPP.
Fundamental requirements for the environmental design of equipment are embodied in the following 1967 GDCs (Reference 1):
- 1967 GDC 1: "Quality Standards"
- 1967 GDC 5: "Records Requirements"
- 1967 GDC 26: "Protection Systems Fail-Safe Design" The 1967 GDCs predated the promulgation, in February 1971, of 10 CFR 50, Appendix A (Reference 2) and were applied in the original design of DCPP. DCPP conforms with 1967 GDCs 1, 5, and 26 as stated in Section 3.1.
For purposes of an informative comparison, PG&E evaluated its conformance with the 1971 GDCs contained in 10 CFR 50, Appendix A. This evaluation is documented in Appendix 3.1A, and in PG&E's letter to the NRC dated September 10, 1981 (Reference 3). The 1971 GDCs applicable to the environmental design of equipment are:
- 1971 GDC 1: "Quality Standards and Records"
- 1971 GDC 2: "Design Basis for Protection Against Natural Phenomena"
- 1971 GDC 4: "Environmental and Missile Design Bases"
- 1971 GDC 23: "Protection System Failure Modes" DCPP conforms with the intent of these 1971 GDCs as stated in Appendix 3.1A.
The capability of safety-related equipment to perform as required in accident environments is of particular concern. Established engineering specification and design practices, backed up by a comprehensive quality assurance program and years of actual operating experience (in the nuclear as well as other industries), afford high confidence that equipment will perform satisfactorily in its normal service environment. In addition, redundant trains of safety-related equipment are provided so that random single failures of equipment can be accommodated. Postulated nuclear plant accidents, however, can result in significant increases in environmental parameters (temperature, pressure, humidity, radiation, etc.). The adverse conditions necessarily affect redundant equipment in different safety trains, and there is no comparable wealth of demonstrated equipment operation in such adverse environments. For these reasons, additional assurance of safety-related equipment operability in accident environments is warranted. Electric equipment is the most susceptible to DCPP UNITS 1 & 2 FSAR UPDATE 3.11-2 Revision 21 September 2013 failure in extreme environments. In April 1971 the IEEE issued a Trial-Use Standard 323-1971, General Guide for Qualifying Class I Electric Equipment for Nuclear Power Generating Stations (Reference 4). IEEE 323-1971 established standards for the environmental qualification (EQ) of safety-related electric equipment. EQ confirms through tests and/or analysis that equipment is capable of fulfilling its design function despite exposure to adverse accident environment conditions. PG&E committed to IEEE 323-1971 for DCPP.
The IEEE subsequently revised IEEE 323-1971. IEEE 323-1974 (Reference 5) was issued in December 1973 and contained substantial, detailed additional information. In November 1974, the NRC endorsed the later standard in Revision 0 of RG 1.89, Qualification of Class 1E Equipment for Nuclear Power Plants (Reference 6). However, this initial version of RG 1.89 exempted DCPP from conformance with IEEE 323-1974. The guide invoked the 1974 standard only on plants whose construction permit Safety Evaluation Report (SER) was dated July 1, 1974, or after. The construction permit SERs for DCPP Units 1 and 2 were dated January 23, 1968, and November 18, 1969, respectively.
In response to concerns in the late 1970s, the NRC reexamined EQ as an "area of regulatory review which heretofore had not been adequately addressed." Among other things, this effort produced the document NUREG-0588, Interim Staff Position on Environmental Qualification of Safety-Related Electrical Equipment, (For Comment version) (Reference 7), dated December 1979.
NUREG-0588 contains two "categories" of regulatory positions. Category I positions supplement IEEE 323-1974 for equipment qualified in conformance with that standard, and Category II positions supplement IEEE 323-1971 for equipment qualified in conformance with the earlier standard. As discussed above, PG&E had been exempted from the 1974 standard in accordance with RG 1.89, Rev. 0; therefore the Category II positions were applicable to DCPP. An NRC letter to All Construction Permit and Operating License Applicants dated February 5, 1980 (Reference 8), announced issuance of the NUREG and stated that "the staff will require that applicants for operating licenses document the degree to which their qualification programs comply with the staff's positions described in NUREG-0588, and their basis for any deviations." An NRC letter to PG&E, dated March 3, 1980 (Reference 9), announced a "Change in Review Procedures" for EQ documentation for DCPP. The letter requested that PG&E analyze the adequacy of its EQ program and identify, for each item required to be qualified, the degree to which the program "complies with the [NRC] staff's position described in NUREG-0588." On May 23, 1980, the NRC issued Commission Memorandum and Order CLI-80-21 (Reference 10), which sanctioned the positions in the "For Comment" version of the NUREG.
PG&E complied as directed by the NRC. In letters dated November 13, 1980 (Reference 11), June 10, 1981 (Reference 12), and September 2, 1981 (Reference 13), PG&E supplied item-by-item comparisons of its EQ program and the NUREG-0588 Category II positions. The letter of September 2, 1981, transmitted PG&E's DCPP UNITS 1 & 2 FSAR UPDATE 3.11-3 Revision 21 September 2013 Environmental Qualification Report (Revision 1) (Reference 14) to the NRC. In addition to the item-by-item NUREG-0588 comparison, this report consolidated and summarized extensive information concerning the development and implementation of the EQ program for DCPP. NRC review and acceptance of the DCPP EQ program was documented in Appendix B of SSER No. 15, dated September 1981 (Reference 15). In 1983, the NRC issued 10 CFR 50.49 (Reference 16) to codify requirements for the environmental qualification of electric equipment important to safety. This regulation now forms the basis of the EQ program at DCPP. The regulation applies to the following three categories of equipment:
- Safety-related electric equipment ("Class 1E"): This equipment is that relied upon to remain functional during and following design basis events to ensure (a) the integrity of the reactor coolant pressure boundary, (b) the capability to shut down the reactor and maintain it in a safe shutdown condition, and (c) the capability to prevent or mitigate the consequences of accidents that could result in potential offsite exposures comparable to the 10 CFR 100 guidelines.
- Nonsafety-related electric equipment whose failure under postulated environmental conditions could prevent satisfactory accomplishment of the safety functions specified above by the safety-related equipment.
- Certain postaccident monitoring equipment as described in RG 1.97, Revision 3 (Reference 17).
The regulation explicitly excludes equipment located in a mild environment. A mild environment is defined as an environment that would at no time be significantly more severe than the environment that would occur during normal plant operation, including anticipated operational occurrences.
Also significant in 10 CFR 50.49 are the provisions in its paragraphs (k) and (l):
"(k) Applicants for and holders of operating licenses are not required to requalify electric equipment important to safety in accordance with the provisions of this section [i.e., in accordance with 10 CFR 50.49] if the Commission has previously required qualification of the equipment in accordance with 'Guidelines for Evaluating Environmental Qualification of Class 1E Electrical Equipment in Operating Reactors,' November 1979 (DOR Guidelines), or NUREG-0588 (For Comment version), 'Interim Staff Position on Environmental Qualification of Safety-Related Electrical Equipment.'" [Underscore added.] "(l) Replacement equipment must be qualified in accordance with the provisions of this section unless there are sound reasons to the contrary."
DCPP UNITS 1 & 2 FSAR UPDATE 3.11-4 Revision 21 September 2013 Based on these provisions, DCPP is required only to upgrade the qualification level of replacement equipment installed after the effective date of the rule (February 22, 1983), provided that the equipment is required to be environmentally qualified, and provided there are no sound reasons to the contrary. "Upgrading" means bringing the qualification level of the equipment into conformance with the standards contained in IEEE 323-1974 supplemented by the Category I positions in NUREG-0588.
Qualification of equipment installed prior to February 22, 1983, need only be to the level specified by IEEE 323-1971 supplemented by the Category II positions in NUREG-0588. Guidance relative to what constitutes "sound reasons" for not upgrading the qualification level of replacement equipment is contained in Revision 1 of RG 1.89 (Reference 18). New (i.e., nonreplacement) equipment that is required to be qualified, and that was/is installed after February 22, 1983, is required to be qualified to the level of IEEE 323-1974 and NUREG-0588 Category I.
Although the applicable GDC apply also to safety-related mechanical equipment, 10 CFR 50.49 does not prescribe any additional testing or documentation requirements for mechanical equipment. Electric equipment (the subject of the regulation) is inherently much more susceptible to failure in an adverse environment. However, 10 CFR 50.49 does cover:
- Environmental sealing appurtenances (e.g., gaskets, o-rings, conduit seals) for electric equipment that are required to demonstrate the environmental qualification of the associated electric equipment item
- Mechanical components that are integral to and required for the operation of electromechanical devices (e.g., switches, relays, valve operators, solenoid valves, pressure detectors, etc.)
The function of serving as part of the reactor coolant pressure boundary is considered to be a purely mechanical function. Hence, components that fulfill this function alone (i.e., that are not otherwise required to be environmentally qualified) are outside of the scope of 10 CFR 50.49. 10 CFR 50.49 is thus now the governing regulation for EQ at DCPP. PG&E has certified its compliance with the regulation as required by NRC Generic Letter 84-24, "Certification of Compliance to 10 CFR 50.49, Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants" (Reference 19). The PG&E certification is documented in letter DCL-85-072 to the NRC dated February 22, 1985 (Reference 20). In 1991, PG&E issued DCM T-20, Environmental Qualification, Revision 0 (Reference 21), to document in detail the design bases and PG&E commitments for the EQ program at DCPP. 3.11.1 EQUIPMENT IDENTIFICATION The methodology described below was used to develop the EQ master list for DCPP. This methodology is documented in the DCPP Environmental Qualification Report, Revision 1 (Reference 14), dated September 1981. DCPP UNITS 1 & 2 FSAR UPDATE 3.11-5 Revision 21 September 2013 3.11.1.1 Bounding List Development In determining the safety-related electrical equipment that would require environmental qualification, PG&E considered the following items:
- Accidents and transients analyzed in the FSAR Update
- Electrical equipment required to achieve or support: emergency reactor shutdown containment isolation containment and reactor heat removal prevention of a significant release of radioactive material to the environment
- Electrical equipment required to perform safety-related actions noted in emergency procedures At DCPP, a Class IA classification is assigned to instrumentation required to perform a safety function (including, but not limited to, the protection system and the engineered safety features system). This encompasses Class 1E instrumentation and related mechanical equipment (e.g., valves, etc.). In addition, PG&E assigns a Class 1E classification to electrical equipment other than instrumentation (e.g., cables, motors, etc.). The PG&E document Classification of Structures, Systems, and Components for Diablo Canyon Units 1 and 2 (Q-List) (Reference 22) defines the design classification criteria and lists the classification associated with DCPP mechanical, electrical, and instrumentation and control systems and components.
To develop the bounding list of equipment that would be considered for environmental qualification, PG&E prepared a list of all Class IA safety functions at DCPP, a list of the systems needed to perform the safety functions, and a list of the electrical equipment needed for those systems to operate. The equipment list was developed by integrating the Class IA list with the Class 1E equipment other than instrumentation for the required systems.
PG&E also conducted a review of its emergency operating procedures to identify all of the equipment included in these procedures. The instruments (for RG 1.97 Type A/Category 1 variables only) identified in this review, combined with the integrated IA/1E classification listing discussed above, was used as the base list of equipment eligible for environmental qualification at DCPP. (Note that activities related to compliance with NRC RG 1.97, Revision 3, proceeded independently and resulted in other instruments being added to the EQ list.)
DCPP UNITS 1 & 2 FSAR UPDATE 3.11-6 Revision 21 September 2013 3.11.1.2 Exemptions PG&E then performed case-by-case evaluations to determine which of the identified equipment items may be exempted from qualification. In making these determinations, PG&E utilized certain evaluation criteria that were provided as guidelines by the NRC Staff. The list of exempt devices was developed by verifying whether specific equipment meets any of the following three criteria:
- The equipment does not perform essential safety functions in a harsh environment, and any failure of such equipment in a harsh environment will not impact safety-related functions or mislead an operator.
- The equipment performs its function before it is exposed to a harsh environment, the sufficiency of any time margin provided is adequately justified, and the subsequent failure of the equipment as a result of the exposure to the harsh environment does not degrade other safety functions or mislead the operator.
- The safety-related function of a particular piece of equipment can be accomplished by some other designated equipment that has been adequately qualified and satisfies the single failure criterion.
PG&E identified a number of devices that satisfied the above criteria and, therefore, could be exempted from environmental qualification. 3.11.1.3 Cable and Terminations Consideration was also given to the wiring and terminations associated with each equipment item that was required to be qualified. As part of the initial NUREG-0588 qualification effort, PG&E chose the following course of action related to sealing for wiring and terminations.
All devices qualified to function in a harsh environment have environmentally qualified electrical sealing assemblies added unless they are qualified with their own sealing system, or do not require seals to maintain their environmental qualification (for example, equipment qualified for a harsh radiation environment only). All Class 1E wiring terminations for EQ equipment inside containment are made by means of environmentally qualified splices, thus avoiding terminal blocks, except for (a) terminal blocks within devices that have the sealing assemblies mentioned above, and (b) terminal blocks inside vendor-supplied equipment assemblies that were procured and environmentally qualified as an assembly. Connections between circuit conductors and the electrical containment penetrations, both inside and outside containment, are also made by means of qualified splices.
Wire and cable used for Class 1E application inside containment and in areas with potential for harsh environment outside containment were generically qualified to DCPP UNITS 1 & 2 FSAR UPDATE 3.11-7 Revision 21 September 2013 perform their safety function while being exposed to the postulated accident environment. Cable EQ files are segregated according to cable manufacturer. PG&E's procedures assure that only such qualified wire and cable are used for Class 1E application in these areas.
Class 1E cables and associated cable devices (penetrations, splices, seals, etc.) requiring environmental qualification were identified by a search of purchase documents and added to the list of equipment items requiring qualification. 3.11.1.4 Class 1E Electrical Equipment Qualification List Maintenance To facilitate maintaining the DCPP EQ master list as a living document (i.e., to maintain it current on an ongoing basis), the SAP Functional Locations along with Controlled Drawing 050909 constitute the DCPP "Class 1E Electrical Equipment Qualification List." A hardcopy output of this EQ Masterlist information is available as a living document. Controlled Drawing 050909 lists the EQ equipment that does not have tag numbers (i.e., electrical cables, connectors, splices) and provides guidance to print a hardcopy of the EQ Masterlist Information and a report of changes since the last masterlist review.
There are two important "notes" that may be assigned to equipment on the EQ master list:
* "Note 11" - identifies devices that are located in a mild area; environmental qualification is not required. * "Note 16" - identifies devices that are located in an area subject to a harsh environment but that are not required to function for accident mitigation or postaccident monitoring of the event that causes the harsh environment.
Note 16 is also ascribed to devices that complete their required safety function prior to being exposed to the harsh environment. The bases for "partial qualification" are also documented in the EQ files. Partial qualification is applied when the equipment item is only required to function for specific accidents that may cause a harsh environment. The EQ File for the item, therefore, contains a partial exemption to a specific design basis accident.
Changes to the EQ master list can occur as a result of plant design changes, maintenance, or as a consequence of revised postaccident environment analyses. For example:
- Design changes that add new equipment to the plant will result in additions to the list if the equipment is within the scope of 10 CFR 50.49(b).
- Design changes or reanalyses that add or eliminate areas of harsh environment can result in changes in the list.
DCPP UNITS 1 & 2 FSAR UPDATE 3.11-8 Revision 21 September 2013
- Design changes that change equipment location (either to a harsh environment from a mild environment, or vice versa) can result in changes in the list.
- Design changes (or analyses) that change equipment functional requirements can result in additions to or deletions from the list, or in changes to the "Note 16" assignments.
- Maintenance activities can result in equipment replacement/upgrade with consequent changes to the list (new vendor, model number, etc.).
Design and maintenance activities are procedurally controlled to ensure that any associated impact on EQ program implementation is identified, evaluated, and tracked. 3.11.2 QUALIFICATION TESTS AND ANALYSES 3.11.2.1 Accident Environments Fundamental to the environmental qualification of equipment is the determination of the changes in environmental parameters to which the equipment would be subjected in the event of an accident. The environmental parameters considered are pressure, temperature, humidity, radiation, caustic spray, and submergence. Extensive modeling has been performed to determine the time-dependent behavior of these parameters following postulated accidents. This information is compiled and maintained in the following two controlled PG&E documents:
- DCM T-20, Environmental Qualification (Reference 21): Appendix A of DCM T-20 is titled "Environmental Conditions for EQ of Electric Equipment"
- DCM T-12, Pipe Break (HELB/MELB), Flooding, and Missiles (Reference 23) These documents are living documents and are revised as changes occur in the derived postaccident environmental conditions. Such changes can occur as a result of plant design changes or new/revised analyses, and are evaluated for EQ impact.
Consequent actions are taken as required to assure that equipment required to be environmentally qualified remains environmentally qualified. 3.11.2.2 Normal Environments Normal service environments are of concern with respect to environmental qualification because of their effect on equipment's qualified life. Equipment items requiring qualification typically comprise various different materials: metals, plastics, elastomers, etc. The non-metallic materials are often susceptible to slow degradation over time as a result of exposure to elevated temperatures or DCPP UNITS 1 & 2 FSAR UPDATE 3.11-9 Revision 21 September 2013 radiation. This degradation can limit the capability of an equipment item to fulfill its design function in an accident environment. Qualified life is thus defined as "the period of time for which satisfactory performance can be demonstrated for a specific set of service conditions" (Reference 5). Qualified life does not include the time period for which the equipment item would be required to perform during and following an accident; EQ testing and analyses are based on the assumption that the accident for which the item would be required would occur right at the end of the item's qualified life. Thus, an item having a ten-year qualified life, for example, can be relied on until the very end of the tenth year.
The normal environments used for equipment environmental qualification are specified in Appendix A of DCM T-20 (Reference 21). A qualified life has been determined for every equipment item that requires environmental qualification. Equipment having a qualified life less than the 40-year life of the plant is replaced or refurbished, in accordance with applicable maintenance procedures, prior to the end of its qualified life. Procedures also ensure that any other required maintenance on an environmentally qualified equipment item be performed such that the item remains qualified.
PG&E uses 103 Rads total integrated dose (TID) outside containment as the threshold gamma exposure above which qualification for a radiation environment is required (Reference 14). Note that the basis for the radiation environment qualification of nonelectronic electrical devices subject to a gamma TID of between 103 and 104 Rads is documented in Design Calculation EZ-02 (Reference 25). 3.11.2.3 NUREG-0588 Category II Qualification Equipment within the scope of 10 CFR 50.49 installed before February 22, 1983, is required, as a minimum, to be environmentally qualified in accordance with the standards contained in IEEE 323-1971 (Reference 4) supplemented by the Category II positions contained in NUREG-0588 (Reference 7). This is the minimum level of qualification for equipment at DCPP. Qualification to a higher level is at the discretion of PG&E for this equipment. 3.11.2.4 NUREG-0588 Category I Qualification New (i.e., nonreplacement) equipment within the scope of 10 CFR 50.49 installed after (and including) February 22, 1983, is required to be environmentally qualified in accordance with the standards contained in IEEE 323-1974 (Reference 5) supplemented by the Category I positions contained in NUREG-0588 (Reference 7). Replacement equipment, for equipment within the scope of 10 CFR 50.49, installed after (and including) February 22, 1983, is required to be environmentally qualified in accordance with the standards contained in IEEE 323-1974 (Reference 5) supplemented by the Category I positions contained in NUREG-0588 (Reference 7), unless there are sound reasons to the contrary. Acceptable "sound reasons to the DCPP UNITS 1 & 2 FSAR UPDATE 3.11-10 Revision 21 September 2013 contrary" are delineated in RG 1.89, Revision 1 (Reference 18), and are documented, if invoked, in the applicable EQ file. 3.11.3 QUALIFICATION TEST RESULTS EQ testing and analysis have demonstrated that all equipment identified as requiring environmental qualification is capable of fulfilling its design function despite exposure to harsh accident environment conditions. Requirements for documentation are delineated in IEEE 323-1971 and the Category II positions in NUREG-0588, or in IEEE 323-1974 and the NUREG-0588, Category I positions, as applicable.
Dedicated EQ files have been established to document the environmental qualification of equipment based on the results of testing and analyses. The files are segregated on a discipline basis and according to manufacturer. The files include qualification summaries, test reports, applicable correspondence, and information that associates the installed equipment with the qualification documents.
The EQ files are prepared and maintained in accordance with procedures and are readily available to engineering and maintenance personnel. They are maintained as quality records (Reference 24). 3.11.4 LOSS OF VENTILATION Safety provisions of the HVAC systems are discussed in Section 9.4. 3.
11.5 REFERENCES
- 1. "General Design Criteria for Nuclear Power Plant Construction Permits," published in the Federal Register for public comment by the AEC on July 11, 1967 (see 32FR10213).
- 2. Title 10 of the U.S. Code of Federal Regulations, Part 50, Appendix A, "General Design Criteria for Nuclear Power Plants," promulgated in the Federal Register on February 20, 1971 (see 36FR3255).
- 3. PG&E (Mr. Philip A. Crane, Jr.) letter to NRC (Mr. Frank J. Miraglia, Jr., Chief, Licensing Branch No. 3, Division of Licensing), dated September 10, 1981, re:
"An Itemized Review of the Diablo Canyon Power Plant's Compliance with the Requirements of 10 CFR Parts 20, 50 and 100."
- 4. IEEE Trial-Use Standard 323-1971, General Guide for Qualifying Class I Electric Equipment for Nuclear Power Generating Stations, dated April 1971.
- 5. IEEE Standard 323-1974, IEEE Standard for Qualifying Class 1E Equipment for Nuclear Power Generating Stations, dated December 1973.
DCPP UNITS 1 & 2 FSAR UPDATE 3.11-11 Revision 21 September 2013 6. RG 1.89, Qualification of Class 1E Equipment for Nuclear Power Plants, AEC, Revision 0, dated November 1974.
- 7. NRC, Interim Staff Position on Environmental Qualification of Safety-Related Electrical Equipment, NUREG-0588, For Comment version, dated December 1979.
- 8. NRC (Mr. D.F. Ross, Jr., Acting Director, Division of Project Management, Office of Nuclear Reactor Regulation) letter to All Construction and Operating License Applicants dated February 5, 1980, re: "Issuance of NUREG-0588,
'Interim Staff Position on Equipment Qualification of Safety-Related Electrical Equipment.'"
- 9. NRC (Mr. John F. Stolz, Chief, Light Water Reactors Branch No. 1, Division of Project Management) letter to PG&E (Mr. John C. Morrissey) dated March 3, 1980, re: "Change in Review Procedures for Equipment Qualification Documentation for the Diablo Canyon Nuclear Power Plants, Units 1 & 2."
- 10. NRC, Commission Memorandum and Order CLI-80-21, dated May 23, 1980, re: "Petition for Emergency and Remedial Action."
- 11. PG&E (Mr. Philip A. Crane, Jr.) letter to NRC (Mr. A. Schwencer, Acting Chief, Licensing Branch No. 3, Division of Licensing, Office of Nuclear Reactor Regulation) dated November 13, 1980, re: "PG&E's review of the DCPP Environmental Qualification Program Using NUREG-0588 as the Basis for the Evaluation." 12. PG&E (Mr. Philip A. Crane, Jr.) letter to NRC (Mr. Frank J. Miraglia, Jr., Chief, Licensing Branch No. 3, Division of Licensing, Office of Nuclear Reactor Regulation) dated June 10, 1981, re: "Transmittal of the DCPP Environmental Qualification Report (Rev. 0)."
- 13. PG&E (Mr. Philip A. Crane, Jr.) letter to NRC (Mr. Frank J. Miraglia, Jr., Chief, Licensing Branch No. 3, Division of Licensing, Office of Nuclear Reactor Regulation) dated September 2, 1981, re: "Transmittal of the DCPP Environmental Qualification Report (Rev. 1)."
- 14. DCPP Environmental Qualification Report, Revision 1, dated September 1981.
- 15. NRC, Safety Evaluation Report Related to the Operation of Diablo Canyon Nuclear Power Plant, Units 1 and 2, NUREG-0675, Supplement No. 15, dated September 1981.
DCPP UNITS 1 & 2 FSAR UPDATE 3.11-12 Revision 21 September 2013 16. Title 10 of the U.S. Code of Federal Regulations, Section 50.49 (10 CFR 50.49), "Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants," promulgated in the Federal Register on January 21, 1983 (see 48FR2729), effective February 22, 1983.
- 17. RG 1.97, Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident, NRC, Revision 3, dated May 1983.
- 18. RG 1.89, Environmental Qualification of Certain Electric Equipment Important to Safety for Nuclear Power Plants, NRC, Revision 1, dated June 1984.
- 19. NRC Generic Letter 84-24, "Certification of Compliance to 10 CFR 50.49, Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants," dated December 27, 1984.
- 20. PG&E (Mr. J.D. Shiffer) letter DCL-85-072 to NRC (Mr. Darrell G. Eisenhut, Director, Division of Licensing, Office of Nuclear Reactor Regulation) dated February 22, 1985, re: "Response to NRC Generic Letter 84-24."
- 21. DCPP Design Criteria Memorandum T-20, Environmental Qualification, PG&E.
- 22. PG&E controlled document, Classification of Structures, Systems, and Components for Diablo Canyon Units 1 and 2 (Q-List); see also Reference 8 of Section 3.2. 23. DCPP Design Criteria Memorandum T-12, Pipe Break (HELB/MELB), Flooding, and Missiles, PG&E. 24. PG&E (Mr. J. O. Schuyler) letter DCL-84-088 to NRC (Mr. John B. Martin, Regional Administrator, NRC Region V) dated March 1, 1984, re: "Response to NRC Inspection Report 50-275/83-40."
- 25. Calculation EZ-02, Environmental Qualification Requirements: Bases for 'Note 11' and 'Note 16' Devices; Bases for the Required Post DBA Operating Time and 'Minimum Required Qualification Time'; Review of Potential 10 CFR 50.49(b)(2) Devices; and Radiation of Non-Electronic Devices Subject to a TID between 103 and 104 Rads.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 20 November 2011 TABLE 3.1-1 GENERAL DESIGN CRITERIA APPLICABILITY 1967 GDC GROUP 1967 GDC 1971 GDC 1987 GDC Overall Plant Requirements 1 2 3 (a) 4 5 Protection by Multiple Fission Product Barriers 6 to 10 Nuclear and Radiation Controls 11 19 (b) 12 to 18 Reliability and testability of protection systems 19 to 26 Reactivity Control 27 to 32 Reactor Coolant Pressure Boundary 33 to 36 Engineered Safety features 37 38 17 (c) 18 (c) 40 4 (d) 41-65 Fuel and Waste Storage Systems 66 to 69 Plant Effluents 70 (a) GDC 3 - 1971 replaces GDC 3 - 1967 (b) GDC 11 - 1967 is supplemented by GDC 19 - 1971 for Dose (c) GDC 17 - 1971 and GDC 18 - 1971 replace GDC 39-1967 (d) GDC 40 - 1967 is supplemented by GDC 4 - 1987 for LBB only. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.1-2 MATRIX OF 1971 GDCs to ASSOCIATED 1967 GDCs Sheet 1 of 6 Revision 20 November 2011 1971 GDC Number 1971 GDC Title Associated 1967 GDC 1967 GDC Title 1 Quality Standards and Records 1 5 Quality Standards. Records Requirements. 2 Design Basis for Protection Against Natural Phenonema 2 Performance Standards. 3 Fire Protection 3 Fire Protection 4 Environmental and Missile Design Bases 40 Missile Protection. 5 Sharing of Structures, Systems, and Components 4 Sharing of Systems. 6 to 9 (Not issued, not used). --- --- 10 Reactor Design. 6 Reactor Core Design. 11 Reactor Inherent Protection. 8 Overall Power Coefficient 12 Suppression of Reactor Power Oscillations. 7 Suppression of Power Oscillations. 13 Instrumentation and Control. 12 13 14 15 Instrumentation and Control Systems. Fission Process Monitors and Controls. Core Protection Systems. Engineered Safety Features Protection Systems. 14 Reactor Coolant Pressure Boundary. 9 Reactor Coolant Pressure Boundary. 15 Reactor Coolant System Design. No direct association with 1967 GDC. --- 16 Containment Design. 10 49 Containment. Containment Design Basis. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.1-2 MATRIX OF 1971 GDCs to ASSOCIATED 1967 GDCs Sheet 2 of 6 Revision 20 November 2011 1971 GDC Number 1971 GDC Title Associated 1967 GDC 1967 GDC Title 17 Electric Power Systems. 39 (Superseded by 1971 Criterion 17 and 18). Emergency Power for Engineered Safety Features. 18 Inspection and Testing of Electric Power Systems. 39 (Superseded by 1971 Criterion 17 and 18). --- 19 Control Room. 11 Control Room. 20 Protection System Functions. 14 15 20 21 25 Core Protection Systems. Engineered Safety Features Protection Systems. Protection Systems Redundancy and Independence. Single Failure Definition. Demonstration of Functional Operability of Protection Systems. 21 Protection System Reliability and Testability. 19 Protection Systems Reliability. 22 Protection System Independence. 20 21 22 23 Protection Systems Redundancy and Independence. Single Failure Definition. Separation of Protection and Control Instrumentation Systems. Protection Against Multiple Disability of Protection Systems. 23 Protection System Failure Modes. 26 Protection Systems Fail-Safe Design. 24 Separation of Protection and Control Systems. 22 Separation of Protection and Control Instrumentation Systems. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.1-2 MATRIX OF 1971 GDCs to ASSOCIATED 1967 GDCs Sheet 3 of 6 Revision 20 November 2011 1971 GDC Number 1971 GDC Title Associated 1967 GDC 1967 GDC Title 25 Protection System Requirements for Reactivity Control Malfunctions. 31 Reactivity Control Systems Malfunction. 26 Reactivity Control System Redundancy and Capability. 27 28 29 Redundancy of Reactivity Control. Reactivity Hot Shutdown Capability. Reactivity Shutdown Capability. 27 Combined Reactivity Control Systems Capability. 30 Reactivity Holddown Capability. 28 Reactivity Limits. 30 Reactivity Holddown Capability. 29 Protection Against Anticipated Operational Occurrences. 19 20 Protection Systems Reliability. Reactivity Shutdown Capability. 30 Quality of Reactor Coolant Pressure Boundary. 9 16 Reactor Coolant Pressure Boundary. Monitoring Reactor Coolant Pressure Boundary. 31 Fracture Prevention of Reactor Coolant Pressure Boundary. 34 35 Reactor Coolant Pressure Boundary Rapid Propagation Failure Prevention. Reactor Coolant Pressure Boundary Brittle Fracture Prevention. 32 Inspection of Reactor Coolant Presssure Boundary. 36 Reactor Coolant Pressure Boundary Surveillance. 33 Reactor Coolant Makeup. No direct association with 1967 GDC. --- 34 Residual Heat Removal. No direct association with 1967 GDC. --- DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.1-2 MATRIX OF 1971 GDCs to ASSOCIATED 1967 GDCs Sheet 4 of 6 Revision 20 November 2011 1971 GDC Number 1971 GDC Title Associated 1967 GDC 1967 GDC Title 35 Emergency Core Cooling. 37 44 Engineered Safety Features Basis for Design. Emergency Core Cooling Systems Capability. 36 Inspection of Emergency Core Cooling System. 45 Inspection of Emergency Core Cooling Systems. 37 Testing of Emergency Core Cooling System. 38 46 47 48 Reliability and Testability of Engineered Safety Features. Testing of Emergency Core Cooling System Components. Testing of Emergency Core Cooling Systems. Testing of Operational Sequence of Emergency Core Cooling Systems. 38 Containment Heat Removal. 49 52 Containment Design Basis. Containment Heat Removal Systems. 39 Inspection of Containment Heat Removal System. 58 Inspection of Containment Pressure-Reducing Systems. 40 Testing of Containment Heat Removal System. 59 60 61 Testing of Containment Pressure-Reducing Systems. Testing of Containment Spray Systems. Testing of Operational Sequence of Containment Pressure-Reducing Systems. 41 Containment Atmosphere Cleanup. 37 Engineered Safety Features Basis for Design. 42 Inspection of Containment Atmosphere Cleanup Systems. 62 Inspection of Air Cleanup Systems.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.1-2 MATRIX OF 1971 GDCs to ASSOCIATED 1967 GDCs Sheet 5 of 6 Revision 20 November 2011 1971 GDC Number 1971 GDC Title Associated 1967 GDC 1967 GDC Title 43 Testing of Containment Atmosphere Cleanup Systems. 63 64 65 Testing of Air Cleanup Systems Components. Testing of Air Cleanup Systems. Testing of Operational Sequence of Air Cleanup Systems. 44 Cooling Water. No direct correlation with 1967 GDC. --- 45 Inspection of Cooling Water System. No direct association with 1967 GDC. --- 46 Testing of Cooling Water System. No direct association with 1967 GDC. --- 47 to 49 (Not issued, not used). --- --- 50 Containment Design Basis. 49 Containment Design Basis. 51 Fracture Prevention of Containment Pressure Boundary. 50 NDT Requirement for Containment Material. 52 Capability for Containment Leakage Rate Testing. 54 55 Containment Leakage Rate Testing. Containment Periodic Leakage Rate Testing. 53 Provisions for Containment Testing and Inspection. 56 Provisions for Testing Penetrations. 54 Piping Systems Penetrating Containment. 57 Provisions for Testing of Isolation Valves.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.1-2 MATRIX OF 1971 GDCs to ASSOCIATED 1967 GDCs Sheet 6 of 6 Revision 20 November 2011 1971 GDC Number 1971 GDC Title Associated 1967 GDC 1967 GDC Title 55 Reactor Coolant Pressure Boundary Penetrating Containment. 51 57 Reactor Coolant Pressure Boundary Outside Containment. Provisions for Testing Isolation Valves. 56 Primary Containment Isolation. 53 Containment Isolation Valves. 57 Closed System Isolation Valves. 53 Containment Isolation Valves. 58 to 59 (Not issued, not used). --- --- 60 Control of Releases of Radioactive Materials to the Environment. 17 70 Monitoring Radioactivity Releases. Control of Releases of Radioactivity to the Environment. 61 Fuel Storage and Handling and Radioactivity Control. 68 69 Fuel and Waste Storage Radiation Shielding. Protection Against Radioactivity Release from Spent Fuel and Waste Storage. 62 Prevention of Criticality in Fuel Storage and Handling. 66 Prevention of Fuel Storage Criticality. 63 Monitoring Fuel and Waste Storage. 18 Monitoring Fuel and Waste Storage. 64 Monitoring Radioactivity Releases. 17 Monitoring Radioactivity Releases. DCPP UNITS 1 & 2 FSAR UPDATE Revision 13 April 2000 TABLE 3.2-1 DESIGN CLASSIFICATION OF STRUCTURES, SYSTEMS, AND COMPONENTS Sheet 1 of 2 Design Class I Design Class II Design Class III Applicability Plant features important to safety, including plant features required to assure (1) the integrity of the reactor coolant pressure boundary, (2) the capability to shut down the reactor and maintain it in a safe shutdown condition, or (3) the capability to prevent or mitigate the consequences of accidents which could result in potential offsite exposures comparable to the guideline exposures of 10 CFR 100.
Plant features important to reactor operation, but not essential to safety, including plant features not required to be Design Class I. Plant features not related to reactor operation or safety. DCPP UNITS 1 & 2 FSAR UPDATE Revision 13 April 2000 TABLE 3.2-1 Sheet 2 of 2 Design Class I Design Class II Design Class III Requirements 1. Quality Standards - Plant features required to meet AEC GDC-1. 1. Quality Standards - Plant features not required to meet AEC GDC-1. 1. Quality Standards - Plant features not required to meet AEC GDC-1.
- 2. Quality Assurance - Plant features required to meet Appendix B to 10 CFR 50. 2. Quality Assurance - Plant features not required to meet Appendix B to 10 CFR 50. Specific QA requirements may be applied to selected features. 2. Quality Assurance - Plant features not required to meet Appendix B to 10 CFR 50. 3. Seismic Design - Plant features required to meet GDC-2 and Appendix A to 10 CFR 100. Plant features designed to withstand effects of double design earthquake (DDE). Features are also designed to maintain their structural integrity (and in some cases their operability) during a Hosgri earthquake. 3. Seismic Design - Plant features not required to meet GDC-2 and Appendix A to 10 CFR 100. Plant features not designed to withstand effects of design earthquakes except for items as required by RG.
1.143, and for selected features where specifically designated. 3. Seismic Design - Plant features not required to meet GDC-2 and Appendix A to 10 CFR 100. Plant features not designed to withstand effects of design Earthquakes, except where specifically designated. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.2-2 Sheet 1 of 4 Revision 16 June 2005 DESIGN AND QUALITY GROUP CLASSIFICATIONS Seismic Design Quality Group PG&E Engineering Classification(a) Classification(f) Remarks ANSI NRC Reg. Guide N18.2 1.26 Design Quality/Code Piping NRC Reg. Safety Quality Other Codes Class Class Symbol Guide 1.29 Group Group and Standards I I NONE(b) Category I 1 A ASA B31.1-1955; ASME B&PV Code, Section III-1971 I I A(h) Category I 1 A ANSI B31.1-1967; B31.7-1969 with 1970 Addenda, Class I I II B Category I 2 B ANSI B31.7-1969 with 1970 Addenda, Class II I II @(g) Category I 2 B ANSI B31.1-1967; ASME B&PV Code Section I-1968; Section III-1968 I III C Category I 3 C ANSI B31.7-1969 With 1970 Addenda, Class III I III D(i) Category I 3 C ANSI B31.1-1967; ANSI B31.7- 1969 with 1970 Addenda, Class III II(d) - G Category I(j) ANSI B31.1-1967 and NFPA Standards I III J(k) Category I - - ANSI B31.1-1967 II - E Non-Category I NNS - ANSI B31.1, 1967
II - F Non-Category I(e) NNS D (c) ANSI B31.1 1967; RG Guide 1.143 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.2-2 Sheet 2 of 4 Revision 16 June 2005 Seismic Design Quality Group PG&E Engineering Classification(a) Classification(f) Remarks ANSI NRC Reg. Guide N18.2 1.26 Design Quality/Code Piping NRC Reg. Safety Quality Other Codes Class Class Symbol Guide 1.29 Group Group and Standards II(d) - G1 Non-Category I - - NFPA Standards II - H Non-Category I NNS D (c) ANSI B31.1-1967; RG Guide 1.143 II - - Non-Category I - - Applicable industry codes and standards III - - Non-Category I - - Applicable industry codes and standards II - @(m) Non-Category I NNS - ASME B&PV Code, Section I-1980 Notes: (a) General Design Criterion 2 (1967), Appendix A to 10 CFR 50, and Appendix A to 10 CFR 100.
(b) Reactor coolant loop and pressurizer surge line piping. Design to ASA B31.1-1955 using Nuclear (N) Code Cases N-7, N-9, and N-10. Fabrication, erection, and inspection to ASME B&PV Code Section III-1971. (c) Radioactive system (PG&E QA Class R). Future activities such as repair, replacement, maintenance, or testing shall be performed per RG. 1.143 for those portions of the systems designated as F or H in Figures 3.2-1 through 3.2-27. (d) The fire protection system may not have been designed or constructed under a quality assurance program meeting all requirements of 10 CFR 50, Appendix B. However, activities such as repair, replacement, maintenance, or testing shall be performed in accordance with the QA recommendations described in Appendix A to NRC Branch Technical Position 9.5.1 and PD OM8 (PG&E QA Class G). Quality requirements administered shall be commensurate with the safety function of the SSC. (e) Seismic qualification requires Design Earthquake analysis. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.2-2 Sheet 3 of 4 Revision 16 June 2005 (f) Regulatory Guide 1.26 (formerly AEC Safety Guide 26) establishes quality group classifications for reactor coolant pressure boundary and remaining safety-related components containing radioactive material, water, or steam. Other systems not covered by this guide include instrument and service air, diesel engine and its generators and auxiliary support systems, diesel fuel, emergency and normal ventilation, fuel handling, and radioactive waste management systems. The Code Class I classification generally includes the fluid systems and components identified as Safety Class I in ANSI N18.2 and Quality Group A in AEC Safety Guide 26. However, the classification and quality standards for Diablo Canyon fluid systems and components were established prior to the existence of these documents and, therefore, do not always fall within their strict definitions. All Code Class I fluid systems and components are in accordance with the accepted industry codes and standards that were in effect during the design and construction of Diablo Canyon. If fluid systems and components were designed and constructed to codes and standards outside of the requirements of the above-mentioned documents, additional quality standards have normally been applied, so that their intent has been met. The Code Class II classification generally includes the fluid systems and components identified as Safety Class 2a in ANSI N18.2 and Quality Group B in AEC Safety Guide 26. However, the classification and quality standards for Diablo Canyon fluid systems and components were established prior to the existence of these documents and, therefore, do not always fall within their strict definitions. All Code Class II fluid systems and components are in accordance with the accepted industry codes and standards that were in effect during the design and construction of Diablo Canyon. If fluid systems and components were designed and constructed to codes and standards outside of the requirements of the above-mentioned documents, additional quality standards have normally been applied, so that their intent has been met. The Code Class III classification generally includes the fluid systems and components identified as Safety Classes 2b and 3 in ANSI N18.2 and Quality Group C in AEC Safety Guide 26. However, the classification and quality standards for Diablo Canyon fluid systems and components were established prior to the existence of these documents and, therefore, do not always fall within their strict definitions. All Code Class III fluid systems and components are in accordance with the accepted industry codes and standards that were in effect during the design and construction of Diablo Canyon. If fluid systems and components were designed and constructed to codes and standards outside of the requirements of the above- mentioned documents, additional quality standards have normally been applied, so that their intent has been met. An exception exists to the above for Quality Code Class III piping Code Class D piping. These are systems or portions of systems which were originally constructed as Design Class II and were subsequently upgraded to Design Class I because of later requirement. For such piping, the design analysis is in accordance with Design Class I criteria. All construction, repair, or replacement performed after the upgrade is in accordance with Design Class I requirements. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.2-2 Sheet 4 of 4 Revision 16 June 2005 (g) Feedwater piping from the (final) main feedwater check valve to the steam generator; auxiliary feedwater from the main feedwater line back to the second check valve; main steam piping from the steam generator to the main steam isolation valve; steam generator blowdown piping from the steam generator to the first valve outside containment; design to ANSI B31.1-1967; fabrication, erection, and inspection to ASME B&PV Code Section I-1968. Requirements for the main steam safety valves are in accordance with ASME B&PV Code Section III-1968. (h) Design to ANSI B31.1-1967. Fabrication, erection, and inspection to ANSI B31.7-1969 with 1970 Addenda, Class I.
(i) This piping code class applies to: (1) the spent fuel pool cooling loop; (2) the auxiliary feedwater pump suction piping from the fire water storage tank; and (3) the refueling water purification loop from and to the refueling water storage tank. This piping was upgraded from Design Class II Code Class E. B31.1 applies for work performed prior to the upgrade. B31.7 applies to work performed after the upgrade. (j) Piping is seismically qualified for the Hosgri earthquake.
(k) Piping originally installed as Design Class II and has been qualified seismically for the Hosgri earthquake, but is Design Class I for repair, replacement, and new construction. (l) Certain Design Class II and III SSCs have seismic qualification requirements and may be designated as Seismic Category I; these SSCs are designated as QA Class S. (m) Auxiliary Boiler 0-2 and its external piping conforms to ASME B&PV Code Section I-1980 through summer 1980 Addenda.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Table 3.3-1 COMPARISON OF AUXILIARY BUILDING WIND PRESSURE VALUES, UNIFORM BUILDING CODE, AND ASCE PAPER 3269 Height Above UBC Dynamic Pressure(d) Ground Surface(a) Wind Pressure(c) q 1.3 q 30 40.0 19.8 25.8 50 40.0 25.7 33.4 70 40.0 30.5 39.7 90 40.0 34.7 45.1 100 40.0 36.6 47.6 150 40.0 45.0 NA(b) 200 40.0 52.1 NA(b) 212 40.0 53.7 NA(b) (a) Ground surface (plant grade) is 85 feet above mean sea level (MSL).
(b) Not applicable because the highest part of the auxiliary building is 105 feet above the ground surface. (c) UBC Pressure is based on 1967 Edition, considering the site to be in a 25 psf zone instead of the code prescribed 20 psf zone and considering the ground surface to be at MSL instead of the actual ground surface at the structure. (d) Dynamic pressure is based on ASCE paper #3269, considering a design wind speed of 80 mph and a gust factor of 1.1.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.3-2 Sheet 1 of 4 Revision 16 June 2005 TORNADO RESISTING CAPABILITY OF STRUCTURES, SYSTEMS AND COMPONENTS SAFE WIND VELOCITY Structure More than 300 mph 300 mph 250 mph 200 mph 175 mph Less than 175 mph(a) or Wind & Wind & Wind & Wind & Wind & Wind & No. Component Wind Missile Wind Missile Wind Missile Wind Missile Wind Missile Wind Missile 1. Auxiliary Bldg. (a) Reinforced concrete between El. 85' & 165' X 275 (b) Battery room ventilation system fan room X 240 (c) Control room X 275 (d) Doors & louvers X (e) Component cooling water surge tank X X (f) Auxiliary building supply fan room equipment X (g) Control room ventilation equipment X (h) Fuel handling building supply fan room equipment X 2. Fuel Handling Area (a) Steel frame(b) 260 127 (b) Roof purlins X (c) Girts, siding, roofing X DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.3-2 Sheet 2 of 4 Revision 16 June 2005 SAFE WIND VELOCITY Structure More than 300 mph 300 mph 250 mph 200 mph 175 mph Less than 175 mph(a) or Wind & Wind & Wind & Wind & Wind & Wind & No. Component Wind Missile Wind Missile Wind Missile Wind Missile Wind Missile Wind Missile (d) Doors & Louvers X (e) Fuel handling building ventilation equipment X 3. Containment (a) Reinforced concrete X 275
(b) Equipt., personnel &
escape hatches X 272 (c) Exhaust vent 125
(d) Exterior Class I raceway and instruments X (e) Main steam and feedwater piping X X (f) Auxiliary feedwater piping X (g) Pipe penetrations X 275 (h) Pipeway X
- 4. Turbine Bldg.
(a) Steel frame(b) 225 X (b) Exterior concrete walls:
12" thick X X 24" thick X 270
(c) Girts, louvers siding, purlins DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.3-2 Sheet 3 of 4 Revision 16 June 2005 SAFE WIND VELOCITY Structure More than 300 mph 300 mph 250 mph 200 mph 175 mph Less than 175 mph(a) or Wind & Wind & Wind & Wind & Wind & Wind & No. Component Wind Missile Wind Missile Wind Missile Wind Missile Wind Missile Wind Missile (d) Siding in 4.16-kV swgr.
and cable spreading room areas X (e) 4.16-kV switchgear/cable spreading room HVAC system X 5. Outdoor Tanks (a) Condensate storage(b) X 150 (b) Refueling water storage(b) X 150 (c) Fire water and transfer storage(b) X 150 6. Intake Structure (a) Reinforced concrete incl. aux. Saltwater pumps compartment X 240 (b) ASW pump room shaft extensions 240 7. Miscellaneous Design Class I Piping (a) CCW piping to SG blowdown tank(b) X (b) Containment hydrogen purge lines(b) X DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.3-2 Sheet 4 of 4 Revision 16 June 2005 SAFE WIND VELOCITY Structure More than 300 mph 300 mph 250 mph 200 mph 175 mph Less than 175 mph(a) or Wind & Wind & Wind & Wind & Wind & Wind & No. Component Wind Missile Wind Missile Wind Missile Wind Missile Wind Missile Wind Missile 8. 480-V Switchgear and 125-Vdc Inverter Room Ventilation System X 9. Control Room Pressurization System(b) X ______________________
Notes:
(a) Structures, systems and components with an "X" in the "Less than 175 safewind velocity" typically do not have quantified analyses of tornado wind and missile resisting capability. (b) A safe-wind velocity of combined wind and missile of less than 200 mph is acceptable for this SSC.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.3-3 Sheet 1 of 3 Revision 15 September 2003 TORNADO FAILURE ANALYSIS - COMPONENT COOLING WATER SURGE TANK AND RELATED INSTRUMENTATION Component & Failure Consequences (1) Loss of vital conduit to control room (a) Loss of liquid level indication and annunciators in control room. Any makeup to CCWS still indicated by annunciator on supply valves (LCV-69 and LCV-70). (b) Loss of automatic and manual actuation to, and position indication from vent valve (RCV-16). Valve fails closed and any overflow from CCWS discharges through relief valve to auxiliary building sump. (2) Loss of control air to makeup valve (LCV-69 or LCV-70) (a) One or both of the normally closed valves fail closed. (b) Makeup is not required during a tornado event and CCW system is maintained in normal operating mode. (c) Manual makeup bypass valves may be used.
(3) Loss of air supply to level controllers (LC-59 or LC-60) and control air to vent valve (RCV-16) (a) One or both of the normally closed makeup valves (LCV-69 and LCV-70) fail closed.
(b) Normally open RCV-16 fails closed.
(c) Makeup is not required during a tornado event and CCW system is maintained in normal operating mode. (d) Tank overpressure protection is maintained by surge tank relief valve (RV-45). (4) Loss of level instrumentation (one set) (a) Makeup valve fails closed. Makeup to CCWS through redundant valve, which annunciates in the control room.
(b) Loss of liquid level indication and annunciator on one compartment of CCWS surge tank. (c) Any leakage from instrument taps close to tank flows to the auxiliary building sump; other breaks leak to roof drains. (d) Operate on redundant system. Manually isolate compartment with damaged instrumentation, if possible. (e) Potential loss of N2 pressurization - see item (10).
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.3-3 Sheet 2 of 3 Revision 15 September 2003 Component & Failure Consequences (5) Break in vent line, isolation valve or back-pressure regulator (a) A break between the back-pressure regulator and vent isolation valve will cause surge tank pressure to decrease and the low surge tank pressure alarm to annunciate in the control room. This break can be isolated from the surge tank by closing the vent isolation valve. (b) A break upstream of the vent isolation valve will cause surge tank pressure to decrease and the low surge tank pressure alarm to annunciate in the control room. The CCW system will continue to operate, but surge tank pressure must be restored to declare the system operable. (6) Break in relief (a) Surge tank pressure will decrease and low surge valve or header tank pressure annunciate in the control room. CCW system will continue to operate; surge tank pressure will have to be restored to declare the system operable. (b) Pressurization required to mitigate consequences of LOCA. LOCA not postulated simultaneously with a tornado. (7) Break in one redundant surge line (a) A maximum of 6,200 gallons of liquid discharged to the yard drains via the 164 ft and 140 ft roof drains. (b) Manually isolate that compartment of the surge tank. (c) Operate within an action statement with the redundant side of the surge tank and makeup water system until the faulted condition can be repaired. (d) Potential loss of N2 pressurization - see item (10). (8) Break in two redundant Surge Lines (a) A maximum of 8,100 gallons of liquid discharged to the yard drains via the 164 ft and 140 ft roof drains. (b) Technical Specifications require CFCUs (and hence the CCW system) be operable in Modes 1-4. Commence plant shutdown to Mode 5 (cold shutdown) and remain in cold shutdown until both surge lines have been repaired. (9) Loss of all level instrumentation (a) Makeup valves fail closed. (b) Loss of liquid level indication and annunciators in the control room. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.3-3 Sheet 3 of 3 Revision 15 September 2003 Component & Failure Consequences (c) Instrument tap breaks close to tank leak to auxiliary building sump; other breaks leak to roof drains.
(d) Some inventory probably remains in surge tank. System continues to operate satisfactorily with no makeup required. (e) Backup indication of adequate liquid level from pressure measurement at CCW pump discharge with low pressure annunciator in control room. (f) Alternate makeup through manual bypass valves around makeup valves. (g) Potential loss of N2 pressurization - see item (10).
(10) Loss of nitrogen/ instrument air pressurization (a) CCW system continues to function normally; CCW surge tank pressure annunciated in the control room. (b) Pressure required to mitigate the consequences of a LOCA; a LOCA is not postulated simultaneously with a tornado.
(c) Failure of nitrogen/instrument air supply pressure regulators will not cause CCW system pressurization or prevent normal CCW system operation.
DCPP UNITS 1 & 2 FSAR UPDATE Sheet 1 of 2 TABLE 3.3-4 Revision 12 September 1998 TORNADO REVIEW - FAILURE ANALYSIS FOR EXPOSED RACEWAYS AND INSTRUMENTATION Component No. Dwg. No. (a) Description Normal Mode Failure Mode Consequences FCV-24 FCV-25 3.2-04(31-B) 3.2-04(31-A) (7.3.42) SG 1 and 2 main steam isolation bypass valves (redundant solenoid valves) Close Close None - not involved in plant shutdown FCV-37 3.2-04(31-C) (7.3-18) SG 2 steam supply valve turbine-driven AFW pump Open In place None - backed up by FCV-38 coming from main steam line from SG 3 FCV-41 FCV-42 3.2-04(31-A) 3.2-04(31-B) (7.3-42) SG 1 and 2 main steam isolation valves (redundant solenoid valves) Open Open None - not involved in plant shutdown unless there is a steam line break FCV-438 FCV-439 3.2-03(45-D) 3.2-03(45-D) SG 1 and 2 main FW isolation valves Open In place None - backed up by FCV-510 and FCV-520 and MFP trip FCV-510 FCV-520 3.2-03(38-C) 3.2-03(38-D) SG 1 and 2 main feedwater control valves Open Close Closing causes reactor trip followed by turbine trip FCV-1510 FCV-1520 3.2-03(38-B) 3.2-03(38-D) SG 1 and 2 feedwater bypass valves Close Close None LCV-106 LCV-107 LCV-110 LCV-111 3.2-03(46-C) 3.2-03(46-C) 3.2-03(46-C) 3.2-03(46-B) SG 1 and 2 supply valves from turbine driven AFW pumps SG 1 and 2 supply valves from motor-driven AFW pumps Open Open As-is Open Simultaneous loss of signal to valves LCV-106, 107, 110, and 111 results in inability to modulate AFW flow and may result in some excess feedwater addition DCPP UNITS 1 & 2 FSAR UPDATE Sheet 2 of 2 TABLE 3.3-4 Revision 12 September 1998 Component No. Dwg. No. (a) Description Normal Mode Failure Mode Consequences PCV-19 PCV-20 PCV-21 PCV-22 10% atmospheric steam dump valves Close Close Backed up by main steam safety valves FT-50 FT-77 3.2-03(48-C) 3.2-03(48-C) AFW lead 1 and 2 flow transmitters Other indication available to monitor SG level; backup - shutdown with SGs 3 and 4 FT-510 FT-511 FT-520 FT-521 3.2-03(39-C) (7.2-1,Sh.7) 3.2-03(39-C) SG 1 and 2 main feedwater flow transmitters (redundant) None - if already switched to AFW by loss of all offsite power PT-514 PT-515 PT-516 PT-524 PT-525 PT-526 3.2-04(31-A)
3.2-04(31-B) SG 1 and 2 steam pressure transmitters Loss of two pressure transmitters on either loop to initiate safety injection signal and steam line isolation signal PT-516A PT-526A 3.2-04(31-A) (7.2-1,Sh.7) 3.2-04(31-B) SG 1 and 2 steam pressure transmitters for 10% steam dump logic Loss of transmitters causes loss of automatic control of the atmospheric dump valve; backed up by main steam safety valve
(a) 3.2-04 denotes P&ID; (31-A) is grid location of P&ID; (7.3-42) denotes instrumentation logic diagram common to SG 1 and 2 components DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.3-5 Sheet 1 of 2 Revision 16 June 2005 SUMMARY OF THE VELOCITY CHARACTERISTICS OF ADDITIONAL TORNADO-BORNE MISSILES FOR 250 MPH TORNADO WIND VELOCITY Input Data Result Modified Design Maximum Additional Ejection Injection Missile Missile Missile Missile Tornado-borne Velocity, Height, Suspension Velocity, Velocity, Elevation, Missile Cl Cd Ap m W fps ft ft fps fps ft Plank 4 x 12 x 12 ft = 50 lb/ft3 0.5 1.0 12.0 1.55 200 247 14 Yes - 247 68 Utility Pole 13.5 in. x 35 ft lg. = 43 lb/ft3 0.7 0.37 39.4 1.34 1500 144 5 No 65 65 5 1 in. SolidStl. Rod 3 ft Lg.
= 490 lb/ft2 0.7 1.12 0.25 15.20 8 203 7 Yes - 203 92 6 in. Pipe Sch. 40, 15 ft lg. = 490 lb/ft3 0.7 0.37 8.29 2.47 285 149 6 No 84 84 6 12" Pipe Sch. 40, 15 ft lg. = 490 lb/ft3 0.7 0.38 15.9 1.74744 134 3 No 42 42 3 3 in. Pipe Sch. 40, 15 ft lg. = 490 lb/ft3 0.7 0.37 4.38 3.54 114 165 11 Yes 165 24 4000# Auto 1.67 x 6 x 17 ft 0.7 0.70 102 0.73 4000 165 5 Yes 165 37 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.3-5 Sheet 2 of 2 Revision 16 June 2005 LEGEND:
C1 = Lift coefficient (dimensionless) Cd = Drag coefficient (dimensionless) Ap = Maximum projected area of the missile (ft2) m = W/g x 1/V1 = /g (slug/ft3) W = Total weight of the missile (lb) V1 = Total volume of the missile (ft3) g = 32.2 ft/sec2
DCPP UNITS 1 & 2 FSAR UPDATE Revision 16 June 2005 TABLE 3.3-6 REQUIRED THICKNESS OF A REINFORCED CONCRETE MISSILE BARRIER TO PRECLUDE MISSILE PERFORATION OR THE CREATION OF SECONDARY MISSILES Input Data For 250 MPH Tornado Results (Inches) Thickness Weight Penetration Without Min. Additional Missile of Min. Impact Into An Just Creating Design Tornado-Borne Velocity, Missile, Area, Infinite Perforated Secondary Thickness, Missile ft/sec lbs ft2 Thick Conc. Thickness Missiles in. Plank 247 200 0.333 2.7 5.5 8.2 9
Utility Pole 65 1500 0.93 0.6 1.2 1.7 6 1 in. Solid Stl Rod 203 8 0.00545 4.7 9.4 14.1 15 6 in. Pipe 84 285 0.239 0.7 1.4 2.1 6 12 in. Pipe 42 744 0.885 0.1 0.3 0.4 6 3 in. Pipe 165 114 0.0667 3.7 7.4 11.2 12 4000 lb Auto 165 4000 10.0 0.9 1.7 2.6 6
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.5-2 CONTROL ROD DRIVE SHAFT - MISSILE CHARACTERISTICS Diameter = 1.75 inches Length = 300 inches Weight = 120 pounds Drive Shaft Travel Drive Shaft Drive Shaft Outside Housing(a) Velocity Kinetic Energy ft ft/sec ft-lb 1 151 42,900 2 162 49,000 3 171 55,000 4 179 60,200 5 189 66,500 (a) Distance from top of rod travel housing to bottom of missile shield
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.5-3 CONTROL ROD DRIVE SHAFT AND MECHANISM - MISSILE CHARACTERISTICS Missile weight: 1500 pounds Impact OD: 3.75 inches Travel ft Drive Shaft Velocity ft/sec Drive Shaft Kinetic Energy ft-lb 1 14.3 4,600 2 20.2 9,200 3 24.8 13,800 4 28.6 18,400 5 32.0 23,000 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.5-4 VALVE - MISSILE CHARACTERISTICS Flow Weight Discharge Thrust Impact Wt. to Imp. Velocity Missile Description lb Area, in2 Area, in2 Area, in2 Area Ratio fps Safety relief valve bonnet, 350 2.86 80 24 14.6 110 (3 in. x 6 in. x 6 in.)
3 in. motor-operated isolation 400 5.5 113 28 14.1 135 valve bonnet (plus motor and stem) (3 in.)
2 in. air-operated relief 75 1.8 20 20 3.75 115 valve bonnet (plus stem)
3 in. air-operated spray 120 5.5 50 50 2.4 190 valve bonnet (plus stem)
4 in. air-operated spray 200 9.3 50 50 4.0 190 valve bonnet
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.5-5 PIPING TEMPERATURE ELEMENT ASSEMBLY - MISSILE CHARACTERISTICS
- 1. For a tear around the weld between the boss and the pipe:
Characteristics "without well" "with well" Flow discharge area, in2 0.11 0.60 Thrust area, in2 7.1 9.6 Missile weight, lb 11.0 15.2 Area of impact, in2 3.14 3.14 Missile weightImpact area, psi 3.5 4.84 Velocity, fps 20.0 120.0
- 2. For a tear at the junction between the temperature element assembly and the boss for the "without well" element and at the junction between the boss and the well for the "with well" element:
Characteristics "without well" "with well" Flow discharge area, in2 0.11 0.60 Thrust area, in2 3.14 3.14 Missile weight, lb 4.0 6.1 Area of impact, in2 3.14 3.14 Missile weightImpact area, psi 1.27 1.94 Velocity, fps 75.0 120.0
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.5-6 CHARACTERISTICS OF OTHER MISSILES POSTULATED WITHIN REACTOR CONTAINMENT Reactor Coolant Pump Instrument Temperature Well of Pressurizer Element Pressurizer Heaters Weight, lb 0.25 5.5 15.0 Discharge area, in2 0.50 0.442 0.80 Thrust area, in2 0.50 1.35 2.4 Impact area, in2 0.50 1.35 2.4 Missile weightImpact area, psi 0.5 4.1 6.25 Velocity, fps 260.0 100.0 55.0
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.5-7 BUILDING DESIGN DATA USED IN TURBINE MISSILE IMPACT ANALYSIS Largest Impact Angle (Measured Barrier Thickness Material From Surface) Fuel handling 0.5 in. Celotex board 90° building roof 2.0 in. Zonolite (light weight concrete) (composite roof) 0.125 in. Metal decking
Auxiliary bldg. 40 in. Concrete (area H, El. 163'-4") 90° roof (various 33 in. Concrete (area K, El. 140'-0") locations) 18 in. Concrete (vent. room area K, El. 165'-10")
Control room north 36 in. Concrete 25° and south wall
Auxiliary bldg. north 36 in. Concrete 22° and south wall
Turbine bldg. 12 in. Concrete 90° deck @ el. 140 ft-0 in.
Containment side 44 in. Concrete and 0.25 in. steel liner (heavily 90° el. 140 ft-0 in. reinforced with woven No. 18 reinforcing bar)
Top of containment 30 in. Concrete and 0.25 in. steel liner (heavily 90° reinforced with woven No. 18 reinforcing bar)
DCPP UNITS 1 & 2 FSAR UPDATE Revision 12 September 1998 TABLE 3.5-8 INDUSTRY TURBINE VALVE FAILURE RATES Turbine Valve Type and Failure Mode Number of Reported Failures Valve-Hours of Service(a) Failure Rates Stop Valve Disk Fails 6 4.58E+06 1.57E-06 Stop Valve Spring Fails 0 4.58E+06 2.18E-07(b) Stop Valve Sticks Open 0 4.58E+06 2.18E-07(b) Control Valve Spring Bolt Fails 4 6.16E+06 7.79E-07 Control Valve Sticks Open 0 6.16E+06 1.62E-07(b)
(a) Estimated hours provided by Westinghouse in letter dated November 14, 1997.
(b) The failure rates are calculated based on an assumed failure of 1.0 incident for numeric stability in the risk assessment computer code. The actual value should read 0.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.6-1 Sheet 1 of 9 Revision 11 November 1996 CHECKLIST OF DYNAMIC EFFECTS FROM POSTULATED RUPTURE OF PIPE CONNECTED TO THE REACTOR COOLANT SYSTEM
Large Break (>4 in.
Is the Contain- Is Break Propagation Prevented and Low-head Safety Injection Maintained to the Un-
Is Break Propagation in the Affected Loop
Is Damage to Steam System Prevented?
Is the Integrity of Supports Maintained?
Is Line Restrained to Meet Criteria with Regulatory ID) Resulting in a Loss of Coolant Location Description Loop Size in. ment Liner Protected? affected Loops? Limited to 20%? Steam Line Feed Line Aux Feed Blow- down Level Taps Sample Line SG Pump Guide 1.46 as a Minimum? Pressurizer Hot leg to 2 14 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes surge (16)(a) pressurizer
Accumulator Check valve 1 10 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes injection (253) 8948A to cold leg
Accumulator Check valve 2 10 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes injection (254) 8948B to cold leg
Accumulator Check valve 3 10 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes injection (255) 8948C to cold leg
Accumulator Check valve 4 10 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes injection (256) 8948D to cold leg
Residual heat Hot leg to 4 14 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes removal supply valve 8702 (109)
Low-head safety Loop to 1 6 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes injection (235) check valve
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.6-1 Sheet 2 of 9 Revision 11 November 1996
Large Break (>4 in.
Is the Contain- Is Break Propagation Prevented and Low-head Safety Injection Maintained to the Un-
Is Break Propagation in the Affected Loop
Is Damage to Steam System Prevented?
Is the Integrity of Supports Maintained?
Is Line Restrained to Meet Criteria with Regulatory ID) Resulting in a Loss of Coolant Location Description Loop Size in. ment Liner Protected? affected Loops? Limited to 20%? Steam Line Feed Line Aux Feed Blow- down Level Taps Sample Line SG Pump Guide 1.46 as a Minimum? Low-head safety Loop to 2 6 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes injection (236) check valve Low-head safety Loop to 3 6 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes injection (237) check valve Low-head safety Loop to 4 6 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes injection (238) check valve Pressurizer Pressurizer - 6 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes (b) relief line to 1171 (730) takeoff Pressurizer Pressurizer - 6 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes (b) safety lines to safety (727, 728, 729) valves Accumulator Accumulator 1 10 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes injection to check (253, 1294) valve 8948A to cold leg Accumulator Accumulator 2 10 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes injection to check (254, 1295) valve 8938B to cold leg DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.6-1 Sheet 3 of 9 Revision 11 November 1996
Large Break (>4 in.
Is the Contain- Is Break Propagation Prevented and Low-head Safety Injection Maintained to the Un-
Is Break Propagation in the Affected Loop
Is Damage to Steam System Prevented?
Is the Integrity of Supports Maintained?
Is Line Restrained to Meet Criteria with Regulatory ID) Resulting in a Loss of Coolant Location Description Loop Size in. ment Liner Protected? affected Loops? Limited to 20%? Steam Line Feed Line Aux Feed Blow- down Level Taps Sample Line SG Pump Guide 1.46 as a Minimum? Accumulator Accumulator 3 10 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Loop 4 Yes injection to check only (255, 1296) valve 8948C to cold leg
Accumulator Accumulator 4 10 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Loop 3 Yes injection to check only (256, 1297) valve 8948D to cold leg
Residual heat Valve 8702 4 14 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes removal supply to cont. (109, 927) pen. 27
Residual heat Accumulator 3 8, 14 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes No (e) removal return disch. to (2576, 120) cont. pen. 26
Residual heat Accumulator 4 8, 12 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes No (e) removal return disch. to (2575, 120) cont. pen. 26
Low-head safety Loop isol. - 6 Yes - - - - - - - - - - (c) injection (235) valve to cont. pen. 24
Low-head safety Loop isol. - 6 Yes - - - - - - - - - - (c) injection (236) valve to cont. pen. 24
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.6-1 Sheet 4 of 9 Revision 11 November 1996
arge Break (>4 in.
Is the Contain- Is Break Propagation Prevented and Low-head Safety Injection Maintained to the Un-
Is Break Propagation in the Affected Loop
Is Damage to Steam System Prevented?
Is the Integrity of Supports Maintained?
Is Line Restrained to Meet Criteria with Regulatory ID) Resulting in a Loss of Coolant Location Description Loop Size in. ment Liner Protected? affected Loops? Limited to 20%? Steam Line Feed Line Aux Feed Blow- down Level Taps Sample Line SG Pump Guide 1.46 as a Minimum? Low-head safety Loop isol. - 6 Yes - - - - - - - - - - (c) injection (237) valve to cont. pen. 25
Low-head safety Loop isol. - 6 Yes - - - - - - - - - - (c) injection (238) valve to cont. pen. 25
Pressurizer From 4x6 to - 6 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes (d) relief line header (23) (17)
Pressurizer Safety valve - 6 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes (d) safety line to header (19, 20, 21) (23)
Pressurizer Cold Leg to 1 4 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes spray (12, 15) pressurizer
Pressurizer Cold leg to 2 4 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes spray (14) pressurizer DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.6-1 Sheet 5 of 9 Revision 11 November 1996
Large Break (>4 in.
Is the Contain- Is Break Propagation Prevented and Low-head Safety Injection Maintained to the Un-
Is Break Propagation in the Affected Loop
Is Damage to Steam System Prevented?
Is the Integrity of Supports Maintained?
Is Line Restrained to Meet Criteria with Regulatory ID) Resulting in a Loss of Coolant Location Description Loop Size in. ment Liner Protected? affected Loops? Limited to 20%? Steam Line Feed Line Aux Feed Blow- down Level Taps Sample Line SG Pump Guide 1.46 as a Minimum? Charging (50) Check valve 3 3 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Loop 4 Yes 8379A to RC only piping
Charging (246) Check valve 4 3 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Loop 3 Yes 8379B to RC only piping
Auxiliary spray Check valve - 2 Yes Yes - - Yes Yes Yes Yes Yes Yes Yes (e) (51) 8377 to line (15)
RC pump seal Check valve 1 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes (e) water injection (54) 8368 to RC pump
RC pump seal water injection (55) Check valve 8368 to RC pump 2 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes (e) RC pump seal water injection (58) Check valve 8368 to RC pump 3 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes (e) DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.6-1 Sheet 6 of 9 Revision 11 November 1996
Large Break (>4 in.
Is the Contain- Is Break Propagation Prevented and Low-head Safety Injection Maintained to the Un-
Is Break Propagation in the Affected Loop
Is Damage to Steam System Prevented?
Is the Integrity of Supports Maintained?
Is Line Restrained to Meet Criteria with Regulatory ID) Resulting in a Loss of Coolant Location Description Loop Size in. ment Liner Protected? affected Loops? Limited to 20%? Steam Line Feed Line Aux Feed Blow- down Level Taps Sample Line SG Pump Guide 1.46 as a Minimum? RC pump seal Check valve 4 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes (e) water injec- 8368 to RC tion (57) pump
Letdown (24) RC piping to 2 3 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes (e) to support downstream of valve LCV 460
Excess RC piping to 2 1 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes (e) letdown (63) to support downstream of valve LCV 8167
RC seal vent Pump to valve - - - - - - - - - - - - - (d) (1495)
RC seal vent Pump to valve - - - - - - - - - - - - - (d) (1496)
RC seal vent Pump to valve - - - - - - - - - - - - - (d) (1497)
RC seal vent Pump to valve - - - - - - - - - - - - - (d) (1498)
RC leakoff (58) - - - - - - - - - - - - - (d) DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.6-1 Sheet 7 of 9 Revision 11 November 1996
Large Break (>4 in.
Is the Contain- Is Break Propagation Prevented and Low-head Safety Injection Maintained to the Un-
Is Break Propagation in the Affected Loop
Is Damage to Steam System Prevented?
Is the Integrity of Supports Maintained?
Is Line Restrained to Meet Criteria with Regulatory ID) Resulting in a Loss of Coolant Location Description Loop Size in. ment Liner Protected? affected Loops? Limited to 20%? Steam Line Feed Line Aux Feed Blow- down Level Taps Sample Line SG Pump Guide 1.46 as a Minimum? RC leakoff (59) - - - - - - - - - - - - - - (d) RC leakoff (60) - - - - - - - - - - - - - - (d) RC leakoff (61) - - - - - - - - - - - - - - (d) Drain 958 RC piping 1 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes (e) downstream of valve
Drain 959 RC piping 2 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes (e) downstream of valve
Drain 960 RC piping 3 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes (e) downstream of valve
Drain 961 RC piping 4 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes (e) downstream of valve
Pressurizer 1171 take 3 2 Yes - - - Yes Yes Yes Yes Yes Yes Yes Yes relief lines off to (1171, 1172, valve (N.C.) 1195)
Charging high- Upstream of 3 3 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes (e) head SIS check valve (50, 49) 8379A DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.6-1 Sheet 8 of 9 Revision 11 November 1996
Large Break (>4 in.
Is the Contain- Is Break Propagation Prevented and Low-head Safety Injection Maintained to the Un-
Is Break Propagation in the Affected Loop
Is Damage to Steam System Prevented?
Is the Integrity of Supports Maintained?
Is Line Restrained to Meet Criteria with Regulatory ID) Resulting in a Loss of Coolant Location Description Loop Size in. ment Liner Protected? affected Loops? Limited to 20%? Steam Line Feed Line Aux Feed Blow- down Level Taps Sample Line SG Pump Guide 1.46 as a Minimum? Charging high- Upstream of 4 3 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes (e) head SIS check valve (246) 8379B
Auxiliary Charging - 2 - - - - - - - - - - - (d) spray (51) line to isolation valve RC pump seal Upstream 1 - - - - - - - - - - - - (d) water injec- of check tion (54) valve
RC pump seal Upstream 2 - - - - - - - - - - - - (d) water injec- of check tion (55) valve
RC pump seal Upstream 3 - - - - - - - - - - - - (d) water injec- of check tion (56) valve
RC Pump seal Upstream 4 - - - - - - - - - - - - (d) water injec- of check tion (57) valve
Letdown (24) Beyond re- 2 3 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes straint downstream of isolation valve DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.6-1 Sheet 9 of 9 Revision 11 November 1996
Large Break (>4 in.
Is the Contain- Is Break Propagation Prevented and Low-head Safety Injection Maintained to the Un-
Is Break Propagation in the Affected Loop
Is Damage to Steam System Prevented?
Is the Integrity of Supports Maintained?
Is Line Restrained to Meet Criteria with Regulatory ID) Resulting in a Loss of Coolant Location Description Loop Size in. ment Liner Protected? affected Loops? Limited to 20%? Steam Line Feed Line Aux Feed Blow- down Level Taps Sample Line SG Pump Guide 1.46 as a Minimum? Excess Beyond re- 2 1 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes (f) letdown (63) straint downstream of isolation valve Pressurizer Downstream - 3 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes relief lines of valves (1171, 1172, (N.C.) 1195)
(a) PG&E line number.
(b) Affected area limited by enclosure.
(c) Operates only during the injection and recirculation phase following a LOCA. Rupture not postulated.
(d) Due to pressure and flow conditions in these pipes during operation of these lines, whipping is not assumed to occur.
(e) Whipping allowed with no services affected.
(f) Whipping allowable with no services affected with restraints at valves to prevent LOCA.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.6-2 Sheet 1 of 3 Revision 19 May 2010 CHECKLIST OF DYNAMIC EFFECTS OF OTHER POSTULATED PIPE RUPTURES INSIDE THE CONTAINMENT Is Break Propagation Is Line Is Loss of Prevented to Is Safety Is the Is Inte- Restrained to Steam System Coolant Steam Piping Injection Contain- grity of Is Cold Meet Criteria Break Not Prevented in the Maintained ment the Steam Is Boration Shutdown with Regulatory Resulting in a Location From Unaffected to All RC Liner Generator Capability Capability Guide 1.46 as Loss of Coolant Description Loop Size Occurring? Loops? Loops? Protected? Maintained? Maintained? Maintained? a Minimum? Main steam line (225)(a) From steam generator nozzle to containment penetration 4 28 Yes Yes Yes Yes Yes Yes Yes Yes Main steam line (226) From steam generator nozzle to containment penetration 3 28 Yes Yes Yes Yes Yes Yes Yes Yes Main steam line (227) From steam generator nozzle to containment penetration 2 28 Yes Yes Yes Yes Yes Yes Yes Yes Main steam line (228) From steam generator nozzle to containment penetration 1 28 Yes Yes Yes Yes Yes Yes Yes Yes Feedwater line (554) From steam generator nozzle to containment penetration 1 16 Yes Yes Yes Yes Yes Yes Yes Yes Feedwater line (555) From steam generator nozzle to containment penetration 2 16 Yes Yes Yes Yes Yes Yes Yes Yes DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.6-2 Sheet 2 of 3 Revision 19 May 2010 Is Break Propagation Is Line Is Loss of Prevented to Is Safety Is the Is Inte- Restrained to Steam System Coolant Steam Piping Injection Contain- grity of Is Cold Meet Criteria Break Not Prevented in the Maintained ment the Steam Is Boration Shutdown with Regulatory Resulting in a Location From Unaffected to All RC Liner Generator Capability Capability Guide 1.46 as Loss of Coolant Description Loop Size Occurring? Loops? Loops? Protected? Maintained? Maintained? Maintained? a Minimum? Feedwater line (556) From steam generator nozzle to containment penetration 4 16 Yes Yes Yes Yes Yes Yes Yes Yes Feedwater line (557) From steam generator nozzle to containment penetration 3 16 Yes Yes Yes Yes Yes Yes Yes Yes Steam generator blowdown line (1059) From steam generator nozzle to containment penetration 1 2 Yes Yes Yes Yes Yes Yes Yes (b) Steam generator blowdown line (1060) From steam generator nozzle to containment penetration 2 2 Yes Yes Yes Yes Yes Yes Yes (b) Steam generator blowdown line (1061) From steam generator nozzle to containment penetration 3 2 Yes Yes Yes Yes Yes Yes Yes (b) Steam generator blowdown line (1062) From steam generator nozzle to containment penetration 4 2 Yes Yes Yes Yes Yes Yes Yes (b)
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.6-2 Sheet 3 of 3 Revision 19 May 2010 Is Break Propagation Is Line Is Loss of Prevented to Is Safety Is the Is Inte- Restrained to Steam System Coolant Steam Piping Injection Contain- grity of Is Cold Meet Criteria Break Not Prevented in the Maintained ment the Steam Is Boration Shutdown with Regulatory Resulting in a Location From Unaffected to All RC Liner Generator Capability Capability Guide 1.46 as Loss of Coolant Description Loop Size Occurring? Loops? Loops? Protected? Maintained? Maintained? Maintained? a Minimum?
(a) PG&E line number. (b) In case of pipe rupture, pipe is allowed to whip with no services affected.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.6-6 Revision 11 November 1996 PIPE BREAK PROTECTION FEATURES ON UNIT 2 DIFFERENT FROM UNIT 1 Area Description Protection Feature Used Turbine Reheater drain system has dif- Protection features used were ferent configuration, due to pi- the same as for Unit 1. The ping layout, causing different same vital structures, line numbers to appear for Unit 2. equipment, etc., were protected from pipe whip and jet impingement. GE/GW Cables and conduits servicing vi- Protection was accomplished tal equipment were routed below through separation. the floor at el. 115 feet and re-turned through floor penetrations.
GE/GW Elimination of containment barrier Vital conduits affected by jet plates, two on MS and two on FW. impingement were rerouted.
GE/GW Elimination of impingement bar- Vital conduits were rerouted, rier surrounding the main steam vital equipment was relocated line riser pipes. away from the jet impingement.
GE/GW Elimination of impingement sleeve Conduits and instrumentation end barriers on main steam and were relocated away from feedwater line. Required only on sleeve end jet impingement. MS nodes 4070 and 3180, and FW node 1403.
FW Elimination of sleeve and barriers Conduits were rerouted away on main steam and feedwater lines. from sleeve end jet impinge-Required only on MS nodes 1180 and ment. 2187, and FW nodes 1213 and 1113.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-1 CONTAINMENT AND AUXILIARY BUILDING CRITERIA COMPARISON Parameters HE DE DDE Seismic input, 0.75g 0.2g 0.4g horizontal
Seismic input, 2/3 of horizontal Static - 2/3 Static-2/3 vertical dynamic amplification of horizontal of horizontal considered ground spectra ground spectra
Accidental 5% and 7% eccentri- Not considered Not considered torsion city
Foundation Tau = 0.040(a) Not applicable Not applicable filtering
Response 3-D SRSS 2-D ABSUM 2-D ABSUM combination
Damping values 7% 2% concrete(b) 5% concrete 2% steel 2% steel
Ductility Allowed in some areas Not considered Not considered
Material Based on test values Min specified Min specified properties values values
Response spectra +5%, -15% 10% 10% broadening (based on frequency)
Response spectra 10% (for 10% (for peaks clip containment containment only) only)
(a) 0.052 for auxiliary building.
(b) 5% for auxiliary building.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-1A TURBINE BUILDING CRITERIA COMPARISON Parameters HE DE and DDE(a) Seismic input, 0.75g 0.2g (DE) horizontal 0.4g (DDE)
Seismic input, 2/3 of horizontal Static - 2/3 vertical dynamic amplification of horizontal Considered ground spectra
Accidental 5% and 7% eccentricity, Not considered torsion or equivalent Note (b)
Foundation Tau = 0.080 (Blume input) Not applicable filtering Tau = 0.067 (Newmark input)
Response 3-D SRSS 2-D ABSUM combination
Damping values 7% 5% concrete 2% steel
Ductility Concrete 1.3 Not considered Steel 3 (6 locally)
Material Based on test values Min specified properties values
Response spectra +5%, -15% 10% broadening (based on frequency)
Response spectra 10% peaks clip (a) DE and DDE analysis is performed only to generate response spectra for systems qualification.
(b) Equivalent method is used as described in Section 3.7.2.10.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-1B INTAKE STRUCTURE CRITERIA COMPARISON DE and DDE for Systems Parameters Hosgri Qualifications Only Seismic input, Hosgri 7.5M DE (0.20g) horizontal DDE (0.40g)
Seismic input, 2/3 of horizontal Static 2/3 of ground vertical spectra with Tau = 0.0 horizontal spectra Dynamic amplification Considered
Accidental torsion Horizontal floor Not considered response spectra increased by 10%
Foundation filtering Tau - 0.04 Not applicable
Response combination 3-D-SRSS Not applicable
Damping values % 7% 5% critical
Ductility Concrete 1.3; Steel 3, Not considered with up to 6 locally(a) Material properties Based on test values Minimum specified values
Floor response spectra +5%, -15% Structural peaks clipped broadening (based on frequency) 10% and widened by 10%
(a) Or as may be required to demonstrate that function of Design Class I equipment will not be adversely affected.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-1C OUTDOOR STORAGE TANKS CRITERIA COMPARISON Parameters Hosgri DE and DDE Seismic input, Hosgri 7.5M DE (0.20g) horizontal DDE (0.40g)
Seismic input, 2/3 ZPA (0.75g) of Static 2/3 ZPA of vertical horizontal spectra with horizontal ground Amplification considered spectra Tau = 0.0
Accidental torsion Not applicable Not applicable
Response combination 3-D SRSS 2-D ABSUM
Damping 7%-All tanks with 5%-All tanks with concrete cover concrete cover
4%-Firewater tank 1%-Firewater tank without concrete without concrete cover cover
Material properties Based on test values Minimum specified values
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-2 CONTAINMENT STRUCTURE PERIODS OF VIBRATION Period, T, Mode No. in sec 1 0.255 2 0.093 3 0.088 4 0.073 5 0.060 6 0.058 7 0.057 8 0.051 9 0.051 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Table 3.7-3 CONTAINMENT STRUCTURE MAXIMUM ABSOLUTE ACCELERATIONS Maximum Absolute Nodal Elevation, Acceleration, g Structure Point(a) ft DE Analysis DDE Analysis Exterior 2 301.64 1.275 2.083 structure 8 274.37 1.032 1.736 10 258.27 0.907 1.567 14 231.00 0.743 1.177 17 205.58 0.837 1.358 23 181.08 0.911 1.369 26 155.83 0.866 1.292 34 130.58 0.713 1.080 37 109.67 0.492 0.793
Interior 19-22 140.00 0.735 1.195 structure 24 127.00 0.597 0.982 27-30 114.00 0.478 0.773 32 110.00 0.455 0.726 38 102.00 0.384 0.601
Base slab 47-58 88.58 0.291 0.483 (a) See Figure 3.7-5. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Table 3.7-4 CONTAINMENT STRUCTURE MAXIMUM DISPLACEMENTS Maximum Displacement Nodal Elevation, Inches Structure Point(a) ft DE Analysis DDE Analysis Exterior 2 301.64 0.666 1.063 structure 8 274.37 0.602 0.967 10 258.27 0.562 0.911 14 231.00 0.480 0.807 17 205.58 0.389 0.695 23 181.08 0.314 0.587 26 155.83 0.248 0.459 34 130.58 0.180 0.327 37 109.67 0.115 0.212
Interior 19-22 140.00 0.083 0.139 structure 24 127.00 0.069 0.114 27-30 114.00 0.056 0.090 32 110.00 0.053 0.084 38 102.00 0.043 0.068
Base slab 47-58 88.58 0.030 0.050 (a) See Figure 3.7-5. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Table 3.7-5 CONTAINMENT STRUCTURE MAXIMUM SHELL FORCES AND MOMENTS(a) - DE ANALYSIS Nodal(b) Elevation, Shell Moments, kip-ft/ft Shell Forces, kips/ft Point ft MSS MTT MST FSS FTT FST 2 301.64 0.21 0.21 28.99 2.74 3.84 3.75 8 274.37 0.33 0.44 2.96 14.47 32.07 23.85 10 258.27 1.76 0.91 1.63 21.04 40.91 32.80 14 231.00 9.17 2.94 0.36 37.68 42.73 48.97 17 205.58 5.74 1.26 0.27 63.59 33.27 66.44 23 181.08 7.58 2.54 0.31 91.25 37.79 79.59 26 155.83 5.69 1.49 0.50 110.72 36.31 91.43 34 130.58 4.31 1.01 0.27 151.69 31.20 108.65 37 109.67 8.26 2.75 0.19 174.13 18.99 122.66 57 88.58 1.01 0.14 2.23 209.79 63.73 127.22 (a) See Figure 3.7-7.
(b) See Figure 3.7-5.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Table 3.7-6 CONTAINMENT STRUCTURE MAXIMUM SHELL FORCES AND MOMENTS(a) - DDE ANALYSIS Nodal(b) Elevation, Shell Moments, kip-ft/ft Shell Forces, kips/ft Point ft MSS MTT MST FSS FTT FST 2 301.64 0.36 0.37 47.17 4.30 6.33 6.04 8 274.37 0.62 0.76 4.77 22.00 53.37 39.37 10 258.27 2.71 1.46 2.63 32.58 67.71 54.58 14 231.00 15.29 4.92 0.50 60.01 71.93 83.06 17 205.58 8.14 1.64 0.37 103.39 53.31 110.30 23 181.08 11.39 3.96 0.45 154.79 56.72 132.95 26 155.83 8.27 2.21 0.77 190.50 54.24 162.53 34 130.58 6.07 1.36 9.42 251.35 46.24 195.36 37 109.67 15.95 5.31 0.34 282.88 30.75 217.34 57 88.58 1.74 0.23 4.18 338.73 110.90 220.62 (a) See Figure 3.7-7.
(b) See Figure 3.7-5.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Table 3.7-7 CONTAINMENT STRUCTURE MAXIMUM TOTAL SHEARS Associated(a) Elevation, Maximum Shears, kips x 103 Structure Nodel Point ft DE Analysis DDE Analysis Exterior 2 301.64 0.19 0.66 structure 8 274.37 5.81 9.38 10 258.27 8.49 13.91 14 231.00 11.39 19.55 17 205.58 15.00 25.02 23 181.08 17.95 29.98 26 155.83 20.63 36.66 34 130.58 24.53 44.18 37 109.67 27.83 49.42 57 88.58 29.55 51.39
Interior 19 & 22 140.00 8.06 13.23 structure 27 & 30 114.00 10.27 16.87 49 & 54 88.58 18.85 30.96
Total base shear 49, 54, & 57 88.58 35.05 59.99 (a) See Figure 3.7-5. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 Table 3.7-8 CONTAINMENT STRUCTURE MAXIMUM TOTAL OVERTURNING MOMENTS Maximum Overturning Associated(a) Elevation, Moment kips-ft x 106 Structure Nodel Point ft DE Analysis DDE Analysis Exterior 2 301.64 0.00 0.00 structure 8 274.37 0.12 0.18 10 258.27 0.27 0.41 14 231.00 0.61 0.97 17 205.58 1.03 1.67 23 181.08 1.48 2.50 26 155.83 1.79 3.08 34 130.58 2.45 4.07 37 109.67 2.82 4.58 57 88.58 3.39 5.48
Interior 19 & 22 140.00 0.06 0.10 structure 27 & 30 114.00 0.20 0.33 49 & 54 88.58 0.76 1.24
Total O.T.M. 49, 54 & 57 88.58 3.48 5.62 at base (a) See Figure 3.7-5. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-8A PERIODS OF VIBRATION AND PERCENT PARTICIPATION FACTORS Containment Exterior Structure Translational(a) Coupled Translation(b) Vertical Horizontal Model Plus Torsion Model Model Percent Percent Mode Period Participation Period Participation Period Participation No (sec) Factor (sec) Factor (sec) Factor 1 0.225 44.97 0.217 58.85 0.081 51.72 2 0.081 22.75 0.109 0.32 0.051 16.72 3 0.053 3.73 0.074 25.86 0.046 2.62 4 0.053 7.88 0.041 12.35 0.046 3.81 5 0.047 1.96 0.039 5.63 0.044 11.84 6 0.045 0.043 0.043 0.05 7 0.043 9.91 0.040 7.96 8 0.041 1.66 0.038 3.15 9 0.037 1.70 0.035 1.25 10 0.036 1.71 0.035 0.88 11 0.033 1.18 12 0.032 2.12 (a) Axisymmetric model (see Figure 3.7-5A). (b) Lumped-mass model with 5% accidental eccentricity (see Figure 3.7-5B).
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-8B CONTAINMENT EXTERIOR STRUCTURE MAXIMUM ABSOLUTE HORIZONTAL AND VERTICAL ACCELERATIONS Absolute Horizontal Acceleration (g) Absolute Vertical Acceleration (g) Nodal(b) Elevation Blume-Hosgri(a) Vertical Blume-Hosgri Vertical Point (ft) Horizontal Input Input Horizontal Input Input 2 301.64 2.21 0.02 0.075 1.600 8 274.37 2.07 0.15 0.450 1.020 10 258.27 1.95 0.28 0.511 0.882 14 231.00 1.70 0.28 0.532 0.810 17 205.58 1.44 0.11 0.475 0.759 19 181.08 1.23 0.14 0.416 0.703 20 155.83 1.00 0.17 0.334 0.633 22 130.58 0.80 0.18 0.228 0.575 23 109.67 0.75 0.16 0.122 0.538
(a) Effective horizontal acceleration at containment shell due to absolute sum of horizontal response and torsional response from 5% eccentricity. (b) See Figure 3.7-5A.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-8C CONTAINMENT EXTERIOR STRUCTURE MAXIMUM HORIZONTAL AND VERTICAL DISPLACEMENTS Horizontal Displacement (in.) Vertical Displacement (in.) Nodal(a) Elevation Blume-Hosgri Vertical Blume-Hosgri Vertical Point (ft) Horizontal Input Input Horizontal Input Input 2 301.64 1.120 0.002 0.032 0.108 8 274.37 1.012 0.009 0.198 0.076 10 258.27 0.943 0.020 0.228 0.066 14 231.00 0.802 0.020 0.240 0.056 17 205.58 0.642 0.008 0.221 0.049 19 181.08 0.515 0.009 0.195 0.041 20 155.83 0.379 0.011 0.158 0.031 22 130.58 0.253 0.012 0.109 0.020 23 109.67 0.151 0.012 0.058 0.010 (a) See Figure 3.7-5A.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-8D CONTAINMENT EXTERIOR STRUCTURE MAXIMUM SHELL FORCES AND MOMENTS Shell Forces (kip/ft)(a) Shell Moments (kip-ft/ft)(a) Blume-Hosgri Vertical Blume-Hosgri Vertical Nodal(b) Elevation Horizontal Input Input Horizontal Input Input Point (ft) FSS FTT FST FSS FTT FST MSS MTT MST MSS MTT MST 2 301.64 4.48 7.35 6.85 26.04 10.32 0 0.80 0.39 57.55 3.68 2.94 0 8 274.37 23.05 59.90 44.80 27.97 28.90 0 0.72 0.86 5.87 2.66 1.09 0 10 258.27 34.80 77.10 53.15 31.00 28.24 0 2.85 1.59 3.24 3.12 1.36 0 14 231.00 65.60 86.55 101.00 42.95 9.45 0 17.40 5.42 0.64 11.24 1.24 0 17 205.58 118.00 51.40 143.00 57.41 13.38 0 7.80 1.27 0.23 5.86 1.12 0 19 181.08 185.50 47.00 73.50 63.95 11.60 0 11.75 3.86 0.32 3.14 1.40 0 20 155.83 235.00 40.15 200.00 65.85 7.89 0 12.40 2.96 0.69 3.51 1.37 0 22 130.58 325.50 37.80 219.50 66.95 10.76 0 5.99 1.13 0.27 2.08 2.32 0 23 109.67 376.00 36.25 240.50 67.06 0 0 19.05 6.26 0.26 6.99 2.78 0 (a) See Figure 3.7-7.
(b) See Figure 3.7-5A.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-8E CONTAINMENT EXTERIOR STRUCTURE MAXIMUM TOTAL SHEARS AND MAXIMUM OVERTURNING MOMENTS Maximum Shear Force (kips x 103)(a) Maximum Overturning Moment (kip-ft x 106)(a) Nodal(b) Elevation Blume-Hosgri Blume-Hosgri Point (ft) Horizontal Input Horizontal Input 2 301.64 0.34 -- 8 274.37 10.50 0.18 10 258.27 15.94 0.44 14 231.00 23.67 1.06 17 205.58 32.49 1.91 19 181.08 39.44 3.00 20 155.83 45.39 3.80 22 130.58 49.70 5.26 23 109.67 55.05 6.08 27 88.58 55.81 7.31 (a) Vertical Input does not produce a net shear force.
(b) See Figure 3.7-5A.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-8F CONTAINMENT EXTERIOR STRUCTURE MAXIMUM TOTAL TORSIONAL MOMENTS AND AXIAL FORCES Blume-Hosgri Nodal(b) Elevation Total Torsional Moment (kip-ft x 103)(a) Point (ft) Horizontal Input Axial Force(kips x 103)(c) 2 301.64 5.49 1.52 8 274.37 67.61 9.93 10 258.27 136.94 12.82 14 231.00 216.36 19.36 17 205.58 293.17 25.88 19 181.08 353.32 28.83 20 155.83 400.00 29.69 22 130.58 427.78 30.18 23 109.67 439.99 30.23
(a) Vertical input does not produce a net torque.
(b) See Figure 3.7-5A.
(c) Due to vertical input.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-8G CONTAINMENT INTERIOR STRUCTURE MAXIMUM ABSOLUTE HORIZONTAL ACCELERATIONS AND DISPLACEMENTS Newmark-Hosgri Horizontal Torsional Nodal(a) Elevation Acceleration Acceleration Displacement Rotation Point (ft) (g) (rad/sec2) (in.) (rad x 10-5) 28 140.00 0.92 0.07 0.06 1.21 34 114.00 0.70 0.05 0.03 0.82 (a) See Figure 3.7-5A.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-8H CONTAINMENT INTERIOR STRUCTURE MAXIMUM TOTAL SHEARS, OVERTURNING MOMENTS, AND TORSIONAL MOMENTS(a) Overturning Moment Torsional Moment(c) Shear (kips x 103) (kip-ft x 103) (kip-ft x 103) Nodal(b) Elevation Blume- Newmark- Blume- Newmark- Blume- Newmark- Point (ft) Hosgri Hosgri Hosgri Hosgri Hosgri Hosgri 34 114.00 6.52 6.64 74.55 78.82 136.68 146.48 37 114.00 10.80 11.23 227.89 239.55 48 88.58 10.08 10.40 219.60 229.31 266.06 283.99 49 88.58 13.26 13.73 544.10 560.76 (a) Due to horizontal input only.
(b) See Figure 3.7-5A.
(c) Values obtained from lumped-mass model shown in Figure 3.7-5C.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-8I UNIT 1 VERTICAL DYNAMIC ANALYSIS - FRAME NO. 6 SUMMARY OF MODAL PARTICIPATION FACTORS AND FREQUENCIES Mode Frequency X-Direction Y-Direction Z-Direction X-Rotation Y-Rotation Z-Rotation 1 11.4 0.00 0.00 0.71 0.0 -541.0 0.0 2 16.8 0.00 0.00 0.09 0.0 -63.0 0.0 3 20.6 0.00 0.00 -0.08 0.0 54.0 0.0 4 21.9 0.00 0.00 0.09 0.0 -65.0 0.0 5 24.1 0.00 0.00 0.03 0.0 -31.0 0.0 6 24.4 0.00 0.00 -0.01 0.0 13.0 0.0 7 24.9 0.00 0.00 -0.03 0.0 22.0 0.0 8 26.2 0.00 0.00 -0.01 0.0 -5.0 0.0 9 28.4 0.00 0.00 -0.50 0.0 304.0 0.0 10 29.3 0.00 0.00 0.20 0.0 -124.0 0.0 11 33.2 0.00 0.00 -0.04 0.0 30.0 0.0 NOTE: X is in the Radial direction. Y is in the Longitudinal direction. Z is in the Vertical direction.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-8J UNIT 2 VERTICAL DYNAMIC ANALYSIS - ANNULUS FRAME 6 SUMMARY OF MODAL PARTICIPATION FACTORS AND FREQUENCIES Mode Frequency X-Direction Y-Direction Z-Direction X-Rotation Y-Rotation Z-Rotation 1 11.6 .00 0.70 .00 .00 .00 82.0 2 16.0 .00 -0.09 .00 .00 .00 -7.7 3 16.46 .00 0.07 .00 .00 .00 6.6 4 22.9 .00 -0.07 .00 .00 .00 -13.0 5 23.87 .00 0.02 .00 .00 .00 -2.0 6 24.0 .00 0.00 .00 .00 .00 7.0 7 27.8 .00 0.00 .00 .00 .00 -8.1 8 32.28 .00 0.08 .00 .00 .00 -15.0 NOTE: X is in the Radial direction. Y is in the Longitudinal direction. Z is in the Vertical direction.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-8K CONTAINMENT ANNULUS STRUCTURES UNITS 1 AND 2 NATURAL FREQUENCIES FOR HORIZONTAL SEISMIC GROUND MOTION Unit Elevation Mode Frequency (cps) 1 101 1 20.95 2 21.69 106 1 20.16 2 21.47 117 1 20.24 2 22.78 2 101 1 22.46 2 22.79 106 1 19.98 2 22.20 117 1 19.98 2 25.79 DCPP UNITS 1 & 2 FSAR UPDATE Revision 21 September 2013 TABLE 3.7-8L Sheet 1 of 2 POLAR GANTRY CRANE MIXIMUM DISPLACEMENTS, HOSGRI (UNIT 1) Longitudinal Transverse Vertical Direction Direction Direction Condition Node (in.) (in.) (in.) Unloaded 31 6.16 6.11 1.77 32 6.29 6.11 2.10 39 6.16 5.27 1.49 40 6.30 5.28 1.47 47 6.16 5.40 1.71 48 6.29 5.40 1.81 75 - - 1.57 76 - - 1.92 77 - - 1.71 78 - - 1.81 Loaded, 31 6.61 5.22 1.69 200 tons 32 6.67 5.22 1.74 39 6.62 4.76 2.12 40 6.68 4.76 2.09 47 6.62 4.56 1.12 48 6.67 4.56 1.24 75 - - 1.49 76 - - 1.34 77 - - 1.12 78 - - 1.26 Notes: 1. All displacements are measured relative to base of crane. 2. For node numbers, refer to Figure 3.7-7A. 3. See PG&E Calculation No. 2252C-2 (Reference 37). DCPP UNITS 1 & 2 FSAR UPDATE Revision 21 September 2013 TABLE 3.7-8L Sheet 2 of 2 POLAR GANTRY CRANE MAXIMUM DISPLACEMENTS, HOSGRI (UNIT 2) Longitudinal Transverse Vertical Direction Direction Direction Condition Node (in.) (in.) (in.) Unloaded 31 6.16 6.11 1.77 32 6.29 6.11 2.10 39 6.16 5.27 1.49 40 6.30 5.28 1.47 47 6.16 5.40 1.71 48 6.29 5.40 1.81 75 - - 1.57 76 - - 1.92 77 - - 1.71 78 - - 1.81 Loaded, 31 6.61 5.22 1.69 200 tons 32 6.67 5.22 1.74 39 6.62 4.76 2.12 40 6.68 4.76 2.09 47 6.62 4.56 1.12 48 6.67 4.56 1.24 75 - - 1.49 76 - - 1.34 77 - - 1.12 78 - - 1.26 Notes:
- 1. All displacements are measured relative to base of crane.
- 2. For node numbers, refer to Figure 3.7-7A. 3. See Civil Calculation 2252C-4 (Reference 39).
DCPP UNITS 1 & 2 FSAR UPDATE Revision 21 September 2013 TABLE 3.7-8M Sheet 1 of 2 POLAR GANTRY CRANE MAXIMUM FORCES, HOSGRI - UNLOADED CONDITION (UNIT 1) Bending Moment Bending MomentType of Axial Force About Axis Y About Axis Z Element Element Node (kips) (kip-in.) (kip-in.) Girder Beam 13 35 212 111,700 17,950 Girder Beam 18 36 172 122,900 18,100 Gantry Leg 2 11 679 23,240 15,810 Gantry Leg 3 15 637 24,660 81,950 Gantry Leg 6 12 635 24,020 16,270 Gantry Leg 7 16 575 25,060 86,170 Gantry Leg 29 59 646 27,740 81,400 Gantry Leg 28 63 720 26,000 16,140 Gantry Leg 33 60 679 26,140 80,930 Gantry Leg 32 64 703 24,080 16,590 Sill Beam 11 9 38 28,800 2,652 Sill Beam 26 68 39 29,470 2,914 Leg Tie BM 10 20 15 28,640 7,176 Leg Tie BM 25 57 6 26,750 4,227 Girder Tie BM 9 34 9 8,853 12,080 Girder Tie BM 24 50 8 14,280 13,480 Trolley 22 71 56 23,280 3,480 Notes: 1. For node and element numbers, refer to Figure 3.7-7A. 2. See PG&E Calculation No. 2252C-3 (Reference 38). 3. Y-axis represents the major axis of cross section. Z-axis represents the minor axis. DCPP UNITS 1 & 2 FSAR UPDATE Revision 21 September 2013 TABLE 3.7-8M Sheet 2 of 2 POLAR GANTRY CRANE MAXIMUM FORCES, HOSGRI - UNLOADED CONDITION (UNIT 2) Bending Moment Bending MomentType of Axial Force About Axis Y About Axis Z Element Element Node (kips) (kip-in.) (kip-in.) Girder Beam 13 35 212 111,700 17,950 Girder Beam 18 36 172 122,900 18,100 Gantry Leg 2 11 679 23,240 15,810 Gantry Leg 3 15 637 24,660 81,950 Gantry Leg 6 12 635 24,020 16,270 Gantry Leg 7 16 575 25,060 86,170 Gantry Leg 29 59 646 27,740 81,400 Gantry Leg 28 63 720 26,000 16,140 Gantry Leg 33 60 679 26,140 80,930 Gantry Leg 32 64 703 24,080 16,590 Sill Beam 11 9 38 28,800 2,652 Sill Beam 26 68 39 29,470 2,914 Leg Tie BM 10 20 15 28,640 7,176 Leg Tie BM 25 57 6 26,750 4,227 Girder Tie BM 9 34 9 8,853 12,080 Girder Tie BM 24 50 8 14,280 13,480 Trolley 22 71 56 23,280 3,480 Notes: 1. For node and element numbers, refer to Figure 3.7-7A. 2. See PG&E Calculation No. 2252C-4 (Reference 39). 3. Y-axis represents the major axis of cross section. Z-axis represents the minor axis. DCPP UNITS 1 & 2 FSAR UPDATE Revision 21 September 2013 TABLE 3.7-8N Sheet 1 of 2 POLAR GANTRY CRANE MAXIMUM FORCES, HOSGRI - LOADED CONDITION (UNIT 1) Bending Moment Bending MomentType of Axial Force About Axis Y About Axis Z Element Element Node (kips) (kip-in.) (kip-in.) Girder Beam 14 39 190 210,700 25,310 Girder Beam 19 40 181 219,000 25,570 Gantry Leg 3 15 824 27,550 105,000 Gantry Leg 4 21 698 10,750 114,700 Gantry Leg 7 16 881 28,290 107,000 Gantry Leg 8 22 675 10,380 115,700 Gantry Leg 30 51 670 11,710 149,700 Gantry Leg 29 59 762 26,430 113,900 Gantry Leg 34 52 681 11,570 147,900 Gantry Leg 33 60 738 25,230 112,100 Sill Beam 11 9 45 34,760 2,410 Sill Beam 26 68 47 30,560 2,370 Leg Tie BM 10 20 15 36,710 7,683 Leg Tie BM 25 58 6 24,640 4,626 Girder Tie BM 9 33 9 11,530 13,550 Girder Tie BM 24 50 7 15,900 14,850 Trolley 22 71 57 88,950 3,269 Notes: 1. For node and element numbers, refer to Figure 3.7-7A. 2. See PG&E Calculation No. 2252C-3 (Reference 38). 3. Y-axis represents the major axis of cross section. Z-axis represents the minor axis. DCPP UNITS 1 & 2 FSAR UPDATE Revision 21 September 2013 TABLE 3.7-8N Sheet 2 of 2 POLAR GANTRY CRANE MAXIMUM FORCES, HOSGRI - LOADED CONDITION (UNIT 2) Bending Moment Bending MomentType of Axial Force About Axis Y About Axis Z Element Element Node (kips) (kip-in.) (kip-in.) Girder Beam 14 39 190 210,700 25,310 Girder Beam 19 40 181 219,000 25,570 Gantry Leg 3 15 824 27,550 105,000 Gantry Leg 4 21 698 10,750 114,700 Gantry Leg 7 16 881 28,290 107,000 Gantry Leg 8 22 675 10,380 115,700 Gantry Leg 30 51 670 11,710 149,700 Gantry Leg 29 59 762 26,430 113,900 Gantry Leg 34 52 681 11,570 147,900 Gantry Leg 33 60 738 25,230 112,100 Sill Beam 11 9 45 34,760 2,410 Sill Beam 26 68 47 30,560 2,370 Leg Tie BM 10 20 15 36,710 7,683 Leg Tie BM 25 58 6 24,640 4,626 Girder Tie BM 9 33 9 11,530 13,550 Girder Tie BM 24 50 7 15,900 14,850 Trolley 22 71 57 88,950 3,269 Notes: 1. For node and element numbers, refer to Figure 3.7-7A. 2. See PG&E Calculation No. 2252C-4 (Reference 39). 3. Y-axis represents the major axis of cross section. Z-axis represents the minor axis. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-8O FUEL HANDLING CRANE SUPPORT STRUCTURE MAXIMUM ABSOLUTE ACCELERATIONS Acceleration,(a)g Load Case Location NS EW Vertical HE El 188 ft 1.7 1.6 1.1
Columns, 1.6 1.3 0.6 El 166 ft
DE El 188 ft 0.8 0.5 (b)
Columns, 0.7 0.4 (b) El 166 ft
(a) Accelerations are average of accelerations from models 2.1 and 2.2.
(b) DE vertical equivalent static analysis coefficient is 0.13 g. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-8P FUEL HANDLING CRANE SUPPORT STRUCTURE MAXIMUM RELATIVE DISPLACEMENTS Load Displacements(a), in. Case Location NS EW HE El 188 ft 2.0 8.8
Columns, 1.8 7.1 El 166 ft
DE El 188 ft 0.9 2.8
Columns, 0.9 2.3 El 166 ft (a) Displacements are from static analysis of detailed fuel handling crane support structure model described in Section 3.8.2.4. Displacements are relative to elevation 140 ft. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-9 AUXILIARY BUILDING PERIODS OF VIBRATION - DE ANALYSIS N-S Direction W Direction Translational Translational Period, T, Participation Period, T, Participation Mode No. (sec) Factor (sec) Factor 1(a) 0.641 0.0 0.688 8.6 2(a) 0.327 8.9 0.641 0.0 3 0.073 48.1 0.072 68.7 4 0.059 48.7 0.065 0.0 5 0.037 20.0 0.040 20.6 6 0.031 1.5 0.031 0.0 (a) Steel superstructure modes (one translational and the other torsional).
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-10 AUXILIARY BUILDING HORIZONTAL MODEL PERIODS AND PARTICIPATION FACTORS - HE ANALYSIS COUPLED - TRANSLATIONAL PLUS TORSION North-South Model North-South Model East-West Model with 5% Eccentricity to East with 5% Eccentricity to West with 5% Eccentricity Translation Translation Translation Mode Period Participation Period Participation Period Participation No. (sec) Factor (sec) Factor (sec) Factor 1(a) .641 -0.0 .641 0.0 .688 8.6 2(a) .327 8.9 .327 8.9 .641 0.0 3 .070 -41.2 .075 -47.6 .074 60.2 4 .061 54.7 .056 49.4 .062 33.2 5 .036 -19.7 .037 -19.4 .039 -20.8 6 .030 -3.8 .030 7.0 .030 3.1 7 .025 -15.3 .026 14.6 .028 -17.9 8 .024 19.6 .023 -19.2 .023 14.8 9 .015 2.8 .016 7.8 .017 11.3 10 .014 13.9 .014 -11.7 .014 9.0 (a) Steel superstructure modes (one translational and the other torsional).
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-11 AUXILIARY BUILDING VERTICAL MODEL PERIODS AND PARTICIPATION FACTORS - HE ANALYSIS Mode Period Participation Number(a) (sec) Factor 1(b) 0.085 -6.0 2 0.033 67.9 (a) Only modes below 33 Hz are listed. (b) Steel superstructure roof mode. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-11A FUEL HANDLING CRANE SUPPORT STRUCTURE HORIZONTAL MODELS FREQUENCIES OF VIBRATION(a) DE, DDE, AND HE ANALYSES Model 2.1 Model 2.2 First(b) Modal Modal Fundamental Effective Effective Modal Frequency Mass Frequency Mass Direction (cps) % (cps) (%) E-W 1.6 85.0 1.6 86.0 N-S 3.1 88.0 2.7(a) 92.0 (a) For Model 2.2 see Figure 3.7-13B. Model 2.1 represents six end bay frames and is similar. (b) Other modes have insignificant contributions, and are not included.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-11B FUEL HANDLING CRANE SUPPORT STRUCTURE VERTICAL MODEL FREQUENCIES OF VIBRATION(a)(b) DE, DDE, AND HE ANALYSES Model 2.1 Model 2.2 Modal Modal Effective Effective Frequency Mass Frequency Mass (hz) (% of roof) (hz) (% of roof) 10.6 19 10.1 23 16.9 23 16.6 26 20.7 2 22.8 1 (a) Only significant modes with frequencies less than 33 hz are shown. For models 2.1 and 2.2, 99 modes and 105 modes were extracted, respectively, with frequencies up to 105 hz. (b) For model 2.2, see Figure 3.7-13B. Model 2.1 represents six end bay frames and is similar.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-12 AUXILIARY BUILDING MAXIMUM ABSOLUTE ACCELERATIONS-DE ANALYSIS Maximum Absolute Accelerations N-S Direction E-W Direction Horizontal Rotational Horizontal Mass(a) Elevation, Acceleration, Acceleration Acceleration, Point ft g rad/sec2 g 6 188.0 0.554 0.0004 0.313 1 163.0 0.375 0.0217 0.435 2 140.0 0.300 0.0187 0.324 3 115.0 0.259 0.0115 0.291 4 100.0 0.230 0.0055 0.257 (a) See Figure 3.7-13. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-13 AUXILIARY BUILDING MAXIMUM RELATIVE DISPLACEMENTS-DE ANALYSIS Maximum Relative Displacement N-S Direction E-W Direction Horizontal Horizontal Mass(a) Elevation, Translation, Rotation Translation, Point ft in. radians x 10-6 in. 6 188.0 0.575 1.624 1.447 1 163.0 0.022 4.087 0.025 2 140.0 0.015 3.308 0.018 3 115.0 0.009 2.014 0.012 4 100.0 0.004 0.975 0.006 (a) See Figure 3.7-13. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-14 AUXILIARY BUILDING MAXIMUM STORY SHEARS-DE ANALYSIS Maximum Story Shears, kips x 103 Element(a) N-S Direction E-W Direction 5 1.3 0.7 1 3.8 4.8 2 26.3 24.6 3 40.0 42.7 4 28.5 28.4 (a) See Figure 3.7-13. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-15 AUXILIARY BUILDING MAXIMUM OVERTURNING MOMENTS-DE ANALYSIS Maximum O.T. Moments, kips - ft x 106 Element(a) N-S Direction E-W Direction 5 0.06 0.04 1 0.08 0.10 2 0.74 0.68 3 1.32 1.30 4 1.76 1.74 (a) See Figure 3.7-13. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-16 AUXILIARY BUILDING MAXIMUM TORSIONAL MOMENTS DUE TO EARTHQUAKE IN N-S DIRECTION-DE ANALYSIS Maximum Torsional Moments, Element(a) kip - ft x 105 5 0.004 1 0.265 2 14.080 3 19.810 4 9.139
(a) See Figure 3.7-13.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-17 AUXILIARY BUILDING MAXIMUM ABSOLUTE ACCELERATIONS - HE ANALYSIS EARTHQUAKE IN N-S DIRECTION Blume-Hosgri Newmark-Hosgri Blume-Hosgri Newmark-Hosgri Horizontal Horizontal Rotational Rotational Acceleration, Acceleration, Acceleration, Acceleration, Mass(a) Elevation, g g rad/sec2 rad/sec2 Point ft 5% E 5% W 5% E 5% W 5% E 5% W 5% E 5% W 6 188.0 1.57 1.56 1.37 1.36 - - - - 1 163.0 1.13 1.10 1.25 1.21 .0981 .1477 .1102 .1646 2 140.0 0.84 0.77 0.90 0.84 .0604 .0895 .0710 .1018 3 115.0 0.71 0.70 0.72 0.66 .0370 .0516 .0431 .0590 4 100.0 0.67 0.66 0.58 0.61 .0175 .0239 .0206 .0275 (a) See Figure 3.7-13.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-18 AUXILIARY BUILDING MAXIMUM ABSOLUTE ACCELERATIONS - HE ANALYSIS EARTHQUAKE IN E-W DIRECTION Blume-Hosgri Newmark-Hosgri Blume-Hosgri Newmark-Hosgri Horizontal Horizontal Rotational Rotational Mass(a) Elevation, Acceleration, Acceleration, Acceleration, Acceleration, Point ft g g rad/sec2 rad/sec2 6 188.0 1.11 1.24 .0015 .0017 1 163.0 1.11 1.22 .1162 .1292 2 140.0 0.94 1.00 .0769 .0881 3 115.0 0.72 0.75 .0452 .0527 4 100.0 0.66 0.62 .0213 .0246 (a) See Figure 3.7-13.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-19 AUXILIARY BUILDING MAXIMUM RELATIVE DISPLACEMENTS - HE ANALYSIS EARTHQUAKE IN N-S DIRECTION Blume-Hosgri Newmark-Hosgri Horizontal Horizontal Blume-Hosgri Newmark-Hosgri Translation, Translation, Rotation Rotation Mass(a) Elevation, in. in. radians x 10-6 radians x 106 Point ft 5% E 5% W 5% E 5% W 5% E 5% W 5% E 5% W 6 188.0 1.63 1.62 1.42 1.42 - - - - 1 163.0 0.06 0.06 0.06 0.07 9.589 18.901 10.961 21.001 2 140.0 0.04 0.04 0.04 0.04 8.034 14.091 9.135 15.472 3 115.0 0.02 0.02 0.02 0.02 4.785 8.530 5.468 9.361 4 100.0 0.01 0.01 0.01 0.01 2.256 4.044 2.576 4.444 (a) See Figure 3.7-13.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-20 AUXILIARY BUILDING MAXIMUM RELATIVE DISPLACEMENTS - HE ANALYSIS EARTHQUAKE IN E-W DIRECTION Blume-Hosgri Newmark-Hosgri Horizontal Horizontal Blume-Hosgri Newmark-Hosgri Mass(a) Elevation, Translation, Translation Rotation Rotation Point ft in. in. radians x 10-6 radians x 106 6 188.0 5.08 5.63 6.153 6.897 1 163.0 0.07 0.07 14.616 16.354 2 140.0 0.05 0.05 11.219 12.484 3 115.0 0.03 0.03 7.078 7.873 4 100.0 0.02 0.02 3.471 3.854 (a) See Figure 3.7-13.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-21 AUXILIARY BUILDING MAXIMUM STORY SHEARS - HE ANALYSIS Earthquake in N-S Direction Earthquake in E-W Direction Blume-Hosgri Newmark-Hosgri Blume-Hosgri Newmark-Hosgri Shear Shear Shear Shear kips x 103 kips x 103 kips x 103 kips x 103 Element(a) 5% E 5% W 5% E 5% W 5% 5% 5 3.6 3.6 3.2 3.2 2.6 2.9 1 12.4 12.4 13.7 13.6 12.3 13.6 2 65.6 58.4 71.9 63.3 71.0 76.2 3 106.2 100.0 115.2 101.5 115.0 122.5 4 84.5 86.7 90.2 85.8 75.8 80.2 (a) See Figure 3.7-13.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-22 AUXILIARY BUILDING MAXIMUM OVERTURNING MOMENTS - HE ANALYSIS Earthquake in N-S Direction Earthquake in E-W Direction Blume-Hosgri Newmark-Hosgri Blume-Hosgri Newmark-Hosgri Moment Moment Moment Moment kips x 106 kips x 106 kips x 106 kips x 106 Element(a) 5% E 5% W 5% E 5% W 5% 5% 5 0.18 0.17 0.15 0.15 0.12 0.14 1 0.27 0.27 0.30 0.29 0.27 0.29 2 1.85 1.66 2.05 1.74 1.96 2.11 3 3.41 3.12 3.73 3.21 3.65 3.90 4 4.68 4.42 5.11 4.46 4.80 5.15 (a) See Figure 3.7-13.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-23 AUXILIARY BUILDING MAXIMUM TORSIONAL MOMENTS - HE ANALYSIS Earthquake in N-S Direction Earthquake in E-W Direction Blume-Hosgri Newmark-Hosgri Blume-Hosgri Newmark-Hosgri Torsional Moment Torsional Moment Torsional Moment Torsional Moment kips x 105 kips x 105 kips x 105 kips x 105 Element(a) 5% E 5% W 5% E 5% W 5% 5% 5 0.01 0.02 0.01 0.02 0.01 0.02 1 0.82 1.71 0.89 1.88 1.30 1.45 2 35.36 60.41 39.93 66.53 44.98 50.14 3 48.24 85.27 55.16 93.73 68.81 76.67 4 21.14 38.00 24.14 41.73 32.59 36.19 (a) See Figure 3.7-13.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-23A Sheet 1 of 2 TURBINE BUILDING HORIZONTAL MODEL (LOADED CRANE CASE 2)(a) FREQUENCIES OF VIBRATION(b) - HE ANALYSIS(d) Mode Frequency Participation Factor No. Hz North-South East-West 1(c) 1.39 0.00 3.01 4(c) 3.32 2.59 0.00 18 5.81 -4.75 0.77 19 5.86 -0.02 -3.32 21 6.03 -0.32 -2.29 22 6.19 0.76 -2.60 23 6.37 -1.16 0.81 24 6.43 -2.66 -0.66 26 6.78 0.24 -1.74 27 7.10 -2.02 0.50 28 7.18 1.08 -1.32 29 7.32 -2.13 0.62 30 7.36 1.02 -0.03 31 7.43 -1.51 -0.61 32 7.57 0.44 -2.59 33 7.62 1.83 1.42 36 7.99 -2.04 -0.95 38 8.32 -1.70 -0.94 39 8.38 -3.16 -0.70 40 8.47 2.47 1.17 44 9.09 0.30 -1.78 56 10.71 0.28 -1.54 65 11.52 1.54 -0.14 82 13.10 -0.39 2.02 83 13.15 0.29 -1.43 89 14.02 0.01 1.79 92 14.32 -0.11 1.87 93 14.78 0.33 1.04 100 16.60 -0.31 1.54 101 16.74 0.13 2.00 102 16.81 0.52 -1.78 103 17.03 1.65 -0.22 104 17.26 -1.46 -0.54 111 18.16 0.12 1.11 115 18.93 -1.68 -0.10 147 22.29 1.00 -0.41 165 23.89 -0.89 0.49 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-23A Sheet 2 of 2
(a) For Case 2, the Unit 1 crane has a 15-ton load and is located at column line 9, and the Unit 2 crane has a 50-ton load and is located at column line 12.2. (b) 210 modes were extracted with frequencies ranging from 1.39 Hz to 33.01 Hz. Shown above are the modes with the twenty highest participation factors in each direction. The cumulative modal masses of the 210 modes represent 95% of the total weight of the building. (c) Modes 1 and 4 are the principal modes of the superstructure.
(d) Note that the results in this table correspond with the seismic analysis performed for the operating license review (Reference 18) and may not reflect the latest as-built configuration of the turbine building. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-23B TURBINE BUILDING VERTICAL MODEL NO. 1 FREQUENCIES OF VIBRATION(a) - HE ANALYSIS(c) Mode Frequency No. Hz Participation Factor 1(b) 2.80 0.65 2(b) 2.80 0.38 5(b) 5.07 -0.48 15 7.48 2.00 17 7.75 -1.55 21 8.71 1.04 23 9.16 -0.55 33 10.70 -0.40 35 10.87 0.52 40 11.38 0.53 54 13.34 -0.36 59 14.02 0.43 61 14.23 0.57 62 14.40 0.31 63 14.46 -0.87 64 14.56 0.28 78 16.68 0.30 83 17.36 -0.65 89 18.29 0.48 115 22.03 -0.29 (a) 187 modes were extracted, ranging from 2.80 Hz to 33.01 Hz. Shown above are the modes with the 20 highest participation factors. The cumulative modal mass of the 187 modes represents 94% of the total weight of the building. (b) Modes 1, 2, and 5 represent significant modes for the superstructure and overhead crane.
(c) Note that the results in this table correspond to the seismic analysis performed for the operating license review (Reference 18) and may not reflect the latest as-built configuration of the turbine building. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-23C Sheet 1 of 2 TURBINE BUILDING MODEL LOADED CRANE CASES MAXIMUM ABSOLUTE ACCELERATIONS - HE ANALYSIS(b) Acceleration(a), Elevation, Location g ft Bent Line N-S E-W Vertical 104 & 107 1 to 5 A-G -- 1.16 1.54 5 to 15 A-G -- 1.18 1.99 15 to 17 A-G -- 1.06 2.49 17 to 19 A-G -- 1.11 -- 1 to 19 A-G 1.22 -- -- 119 & 123 1 to 5 A-G -- 1.84 2.16 5 to 15 A-G -- 2.08 2.35 15 to 17 A-G -- 1.83 2.43 17 to 19 A-G -- 1.68 1.30 1 to 19 A-G 2.20 -- -- 140 1 to 5 A-G -- 1.37 1.68 5 to 15 A-G -- 2.19 1.91 15 to 17 A-G -- 1.24 1.29 17 to 19 A-G -- 1.11 1.32 1 to 19 A-G 1.91 -- -- 159 1.9 to 4.8 G -- 1.29 0.73 5.7 to 15 G -- 2.51 0.70 16 to 19 G -- 1.51 0.59 1.9 to 19 G 1.57 -- -- 193 1.9 to 4.8 A, G -- -- 0.91 5.7 to 15 A, G -- -- 0.70 16 to 19 A, G -- -- 0.59 Roof 1 to 1.9 A-D 3.97 1.60 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-23C Sheet 2 of 2
(a) Acceleration values are zero period accelerations of floor response spectra. At and below elevation 140 feet, values are for the case of a single unloaded crane; values for the case of two cranes with one crane loaded are similar. (b) Note that the results in this table correspond to the seismic analysis performed for the operating license review (Reference 18) and may not reflect the latest as-built configuration of the turbine building.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-23D TURBINE BUILDING MODELS LOADED CRANE CASES MAXIMUM RELATIVE DISPLACEMENTS - HE ANALYSIS(b) Displacement(a), Elevation, Location in. ft Bent Line N-S E-W Vertical 104 & 107 1 to 5 A-G 0.08 0.07 0.25 5 to 15 A-G 0.07 0.16 0.75 15 to 17 A-G 0.04 0.13 1.31 17 to 19 A-G 0.06 0.68 -- 119, 123, 1 to 5 A-G 0.25 0.23 0.52 & 125 5 to 15 A-G 0.60 0.42 0.82 15 to 17 A-G 0.80 0.35 0.62 17 to 19 A-G 0.90 1.02 0.45 140 1 to 5 A-G 0.22 0.18 0.37 5 to 15 A-G 0.20 0.58 0.03 15 to 17 A-G 0.20 0.28 0.13 17 to 19 A-G 0.20 0.83 0.42 159 1 to 5 G 0.42 2.06 0.39 5 to 15 G 0.42 3.22 0.31 15 to 17 G 0.41 2.97 0.06 17 to 19 G 0.42 3.98 -- 193 1 to 5 A-G 1.92 5.89 0.13 5 to 15 A-G 1.09 8.76 0.05 15 to 17 A-G 1.21 9.64 0.08 17 to 19 A-G 1.32 11.46 -- Roof 1 to 1.9 A-D 2.60 3.64 -- (a) Displacement values are based on response spectrum analysis.
(b) Note that the results in this table correspond to the seismic analysis performed for the operating license review (Reference 18) and may not reflect the latest as-built configuration of the turbine building.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-23E TURBINE PEDESTAL MODEL FREQUENCIES OF VIBRATION(a) - HE ANALYSIS Mode Frequency Participation Factor No. (Hz) N-S E-W Vertical 1 3.09 -- 27.2 -- 2 3.54 -- 3.6 -- 3 4.23 27.6 -- 0.4 11 15.14 0.3 -- -14.1 12 15.96 -0.3 -- 8.0 23 20.94 -0.5 -- 12.1 25 21.69 -- -- -9.1 27 22.06 -- 4.0 -- 30 23.36 -0.2 -- -8.0 36 26.11 -- -3.4 -- 45 30.34 2.1 -- 2.2 46 30.54 2.4 -- -5.2 47 30.94 -2.7 -- 4.0 49 31.89 -3.5 -- 3.0 50 32.14 -- 2.7 --
(a) 50 modes were extracted, ranging in frequency from 3.09 Hz to 32.14 Hz. Shown above are the modes with the five highest participation factors for each direction.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 12 September 1998 TABLE 3.7-23F TURBINE PEDESTAL MODEL MAXIMUM RELATIVE DISPLACEMENTS - HE ANALYSIS North-South East-West Vertical Nodal Direction Direction Direction Point(a) (in.) (in.) (in.) 9 .71 1.30 0.006 35 .73 1.22 0.006 58 .74 1.40 0.006 81 .75 1.63 0.006 102 .76 1.59 0.005 123 .76 1.67(c) 0.005 (a) Nodal points are identified in Figure 3.7-15G.
(b) Vertical displacement includes dead load displacement.
(c) Effects of load redistribution are included.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-23G SIGNIFICANT PERIODS OF VIBRATION AND PERCENT PARTICIPATION FACTORS INTAKE STRUCTURE North-South Model East-West Vertical Model Percent East-West Percent Vertical Percent Mode Period Participation Period Participation Participation Number (sec) Factor (sec) Factor Factor 2 0.081 0.5 0.081 0.0 0.1 3 0.081 0.1 0.081 0.0 0.0 4 0.081 0.2 0.081 0.0 0.0 5 0.080 1.1 0.080 0.0 0.0 6 0.079 2.5 0.079 0.0 0.3 7 0.078 0.8 0.078 0.0 0.1 9 0.069 0.1 0.065 0.1 0.1 10 0.066 2.1 0.065 0.4 0.0 11 0.065 3.5 0.064 0.2 0.0 12 0.064 0.2 0.064 0.0 0.0 13 0.064 0.4 0.064 0.0 0.0 14 0.064 0.0 0.064 0.0 0.0 15 0.064 0.2 0.063 0.4 0.1 17 0.063 0.0 0.063 0.1 0.1 18 0.063 0.3 0.062 0.4 0.0 19 0.060 0.7 0.060 0.1 0.9 21 0.049 0.8 0.049 1.7 0.7 22 0.049 1.4 0.048 2.1 0.6 23 0.048 1.1 0.048 0.3 0.0 24 0.047 2.7 0.047 2.4 0.6 25 0.047 2.1 0.046 3.4 1.4 33 0.034 1.4 0.033 7.4 35 0.032 1.6 0.032 3.0 5.4 36 0.031 3.4 0.031 1.3 4.7
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-23H MAXIMUM RELATIVE DISPLACEMENTS AND MAXIMUM ABSOLUTE ACCELERATIONS (HOSGRI) INTAKE STRUCTURE North-South East-West Vertical North-South East-West Vertical Nodal Elevation Displacement Displacement Displacement Acceleration Acceleration Acceleration Point(a) (ft) (in.) (in.) (in.) (g) (g) (g) 330 +32.0 0.025 0.044 0.010 2.36 2.15 0.65 312 +24.4 0.016 0.029 0.008 1.50 1.55 0.65 71 +17.5 0.120 0.011 0.010 1.58 0.66 0.61 73 +17.5 0.065 0.011 0.007 0.94 0.66 0.54 74 +17.5 0.058 0.011 0.005 0.85 0.66 0.51 284 +17.5 0.009 0.019 0.007 0.64 1.00 0.62 363 +11.0 0.008 0.012 0.003 0.64 0.87 0.54 80 -2.1 0.133 0.007 0.010 1.71 0.70 0.59 83 -2.1 0.066 0.005 0.006 0.98 0.71 0.52 87 -16.8 0.251 0.003 0.005 3.14 0.72 0.52 89 -16.8 0.050 0.002 0.003 1.12 0.73 0.50 (a) See Figure 3.7-15F.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-23I OUTDOOR WATER STORAGE TANKS SUMMARY OF SIGNIFICANT PERIODS AND PERCENT PARTICIPATION FACTORS REFUELING WATER STORAGE TANK Modal Period Participation Mode No. (sec) Factor % 1 0.132 50.7 2 0.052 22.6 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.7-23J OUTDOOR WATER STORAGE TANKS SUMMARY OF SIGNIFICANT PERIODS AND PERCENT PARTICIPATION FACTORS FIREWATER AND TRANSFER TANK Load Case 1(a) Load Case 2(b) Modal Modal Period Participation Period Participation Mode No. (sec.) Factor % (sec.) Factor % 1 0.12124 54.91 0.1234 48.4 2 0.04985 21.26 0.06318 6.21 (a) Load Case 1: Inner and outer tanks are filled with water up to design level (b) Load Case 2: Inner tank is filled to design level, outer tank is empty
DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 Table 3.7-24 FUNDAMENTAL MODE FREQUENCY RANGES FOR RCL PRIMARY EQUIPMENT Frequency, Hz
Steam Generator 6.7 - 9.0 Reactor coolant pump 6.7 - 7.2
Reactor pressure vessel 16.8 - 17.0
DCPP UNITS 1 & 2 FSAR UPDATE Sheet 1 of 2 TABLE 3.8-1 Revision 11 November 1996 TESTING OF REINFORCING BARS FOR DESIGN CLASS I CONCRETE STRUCTURES COMPARISON OF PROGRAM USED ON DIABLO CANYON POWER PLANT WITH REGULATORY GUIDE 1.15 Diablo Canyon Power Plan Regulatory Guide 1.15 The number of test specimens required for accept- At least one full-diameter specimen from each bar ance is in accordance with ASTM A 615, Deformed size should be tested for each 50 tons or fraction Billet-Steel Bars for Concrete-Reinforcement, Amer- thereof of reinforcing bars that are produced from ican Society for Testing and Materials. Additional each heat and used in Category I structures. samples were tested as part of the splice testing program. The requirements for acceptance testing are more stringent than ASTM A 615 in that all tests must be conducted using the full section of the bar.
Test procedures are in accordance with ASTM The test procedures should be in accordance with A 615-68. ASTM A 370-68, Standard Methods and Definitions for Mechanical Testing of Steel Products, American Society for Testing and Materials.
Acceptance standards are in accordance with The acceptance standards should be in accordance ASTM A 615-68 using full sections of the bars as with ASTM A 615-72, Standard Specification for rolled. Bend test requirements described in Item Deformed Billet-Steel Bars for Concrete Reinforce- 3, Sheet 2 of 2, are more stringent than those in ment, American Society for Testing and Materials, Supplemental Requirements (S-1) of ASTM A 615-72. including Supplemental Requirement (S-1)(a) using full sections of the bars as rolled. DCPP UNITS 1 & 2 FSAR UPDATE Sheet 2 of 2 TABLE 3.8-1 Revision 11 November 1996 Diablo Canyon Power Plan Regulatory Guide 1.15 In addition to the requirements of ASTM A 615, the Where any material property such as yield strength Company specification requires the following: to tensile strength ratio, ductility, weldability or other similar property is relied upon by the
- 1. Grade 60 bars be limited in carbon and designer or constructor, then the reinforcing bar manganese content to a maximum of 0.45% chemistry should be controlled to the extent and 1.3% respectively. required to achieve the desired material property, and confirmatory testing should be performed.
- 2. Performance of a check analysis, which is listed as an option in ASTM A 615.
- 3. No. 14 and No. 18 bars be subjected to a 90° bend test using a pin having a diameter eight times the diameter of the bar.
Deformations were inspected during production to Deformations of the reinforcing bars should be ensure conformance with ASTM A 615. inspected to assure their compliance with ASTM A 615-72 and with the licensee's specifications pertinent to bonding and other purposes which are dependent on the deformation characteristics.
Adequacy of deformations for splicing was Adequacy of deformations for splicing will be demonstrated by the tensile tests of the Cadweld demonstrated by the tensile tests of the splices. splices. See Table 3.8-2. mechanical splice. See Safety Guide 10, "Mechanical (Cadweld) Splices in Reinforcing Bars of Category I Concrete Structures." (a) Supplemental Requirement (S-1) is for a 90° bend test, using a pin diameter 10 times the bar diameter, on No. 14 and No. 18 bars. DCPP UNITS 1 & 2 FSAR UPDATE Sheet 1 of 5 Revision 11 November 1996 TABLE 3.8-2 MECHANICAL (CADWELD) SPLICES IN REINFORCING BARS OF CONCRETE CONTAINMENTS COMPARISON OF PROGRAM USED ON DIABLO CANYON POWER PLANT WITH SAFETY GUIDE 10 Diablo Canyon Power Plant Safety Guide 10 Prior to production splicing, each operator was 1. Crew Qualification - Each member of splicing crew instructed by a representative of the manufacturer. (or each crew if the members work as a crew) should prepare two qualification splices for each of the Each operator (a crew consisted of an operator and splice positions (e.g., horizontal, vertical, diagonal) a helper) prepared one qualification splice for to be used. The qualification splices should be made each of the splice positions for which he was qual- using the same materials (e.g., bar, sleeve, powder) as ified. The qualification splice was made using the those to be used in the structure. The completed same materials as those used in the structures. qualification splices should meet the requirements The completed qualification splices had to pass specified by the designer of the containment structure visual inspection and develop the minimum tensile and approved by the licensee, pass visual inspection strength of the reinforcing steel. A manufac- as provided by Paragraph 2 below, and meet the turer's representative was present for at least tensile tests as provided by Paragraph 3 below. the first 20 production splices for each crew to verify that proper procedures were being used and quality splices obtained.
All completed splices were visually inspected in 2. Visual Inspection - All completed mechanical splices accordance with the recommendations of the Erico should be inspected at both ends of the splice Co. inspection manual RB-5M 768, Inspection of the sleeve and at the tap hole in the center of the splice Cadweld Rebar Splice. This visual inspection sleeve in accordance with the requirements included both ends of the sleeve, the tap hole, specified by the designer of the containment and measurement of void area. structure and approved by the licensee.
In addition, at least twice daily for each Cadweld Among the items should be included in these crew, an inspector observed the entire splicing specifications are longitudinal centering of operation including cleaning of rebar ends, spacing of sleeve on the spliced ends, allowable voids rebar, centering of rebar ends, loading the crucible, in filler metal, extent of leaking of filler metal, DCPP UNITS 1 & 2 FSAR UPDATE Sheet 2 of 5 Revision 11 November 1996 TABLE 3.8-2 Diablo Canyon Power Plant Safety Guide 10 and firing the charge. The Cadweld procedure permissible gap between rebar ends, cartridge specified for the DCPP includes placing a mark size, gas blowout, amount of packing and 12 inches 1/4-inch back from the end of the bar. slag at the tap hole. Splices that fail to pass visual This line was used as a reference to determine if inspection should be discarded and replaced, and should the bar ends are centered in the sleeve. not be used as tensile test samples.
Acceptance criteria for splice tensile tests is as 3. Tensile Testing - Splice samples may be production follows: splices (i.e., those cut directly from in place reinforcing) or sister splices (i.e., those removable No splice in the test series may have a tensile splices made in-place next to production splices value below 125% of the specified yield and under the same conditions). point stress, and no more than 5 % of the splices tested may have an ultimate tensile Splice samples should be subjected to tensile strength less than 85% of that specified. tests in accordance with the sampling fre-The average tensile strength of all splices in quency specified in Paragraph 4a or Paragraph the test series must equal or exceed the ASTM 4b below, to determine conformance with the specified minimum ultimate strength. following acceptance standards:
- a. The tensile strength of each sample tested should be equal or exceed 125 percent of the minimum yield strength specified in the ASTM standard appropriate for the grade of reinforcing bar using loading rates set forth in ASTM Specification A 370 dated August 15, 1968.
- b. The average tensile strength of each group of 15 consecutive samples should equal or exceed the guaranteed ultimate tensile strength specified for the reinforcing bar.
DCPP UNITS 1 & 2 FSAR UPDATE Sheet 3 of 5 Revision 11 November 1996 TABLE 3.8-2 Diablo Canyon Power Plant Safety Guide 10 If any sample tested fails to meet the provi-sions of Paragraph 3a above, the procedure of Paragraph 5a below should be followed.
If the average tensile strength of the 15 samples tested fails to meet the provisions of Paragraph 3b above, the procedure of Paragraph 5b below should be followed.
Testing frequency for each crew, position, and 4. Tensile Test Frequency - Separate test cycles grade of bar was as follows: should be established for mechanical splices in horizontal, vertical, and diagonal bars, for One out of the first 10 splices. This splice must each bar size, and for each splicing crew as be a production splice for No. 18, Grade 60 bars follows: and a sister splice for other sizes and grades of bar. a. Test Frequency for Production Splice Test Samples. If only production splices are Three out of the next 90 splices for No. 18, Grade tested, the sample frequency should be: 60 bars and one out of the next 90 splices for all other sizes and grades of bar. 1 of the first 10 splices 1 of the next 90 splices Three out of second and subsequent 100 splice 2 of the next and subsequent units of 100 units for No. 18, Grade 60 bars and one out of sec- splices ond and subsequent 100 splice units for all other sizes and grades of bar. b. Test Frequency for Combinations of Produc-tion and Sister Splices. If production and At least 25% of the total number of No. 18, sister splices are tested, the sample Grade 60 test splices must be made by cutting out frequency should be: DCPP UNITS 1 & 2 FSAR UPDATE Sheet 4 of 5 Revision 11 November 1996 TABLE 3.8-2 Diablo Canyon Power Plant Safety Guide 10 production splices on a random basis. The remain- 1 production splice of the first 10 production splices ing test splices may be made by having test bars 1 production and 3 sister splices, for the tie wired alongside the production bars and spliced next 90 production splices in sequence with those bars. The minimum length of 3 splices, either production or sister splices, for the spliced bars is 3 feet. the next and subsequent units of 100 splices.
At least 1/4 of the total number of splices tested should be production splices.
In the event a splice should fail the tensile test 5. Procedure for Substandard Tensile Test Results criteria, the specimen was to be examined by a test-ing laboratory. Based on the results of this inves- a. If any production or sister splice tested fails to tigation, additional splices by the crew responsible, meet the tensile test specification of Paragraph 3a as directed by the Engineer, were to be taken from and the observed rate of splices that fail the the structure to ensure that there are no other tensile test at that time does not exceed 1 for defective splices. The procedures of the crew each 15 consecutive test samples, the sampling responsible for making the failed splice were to be procedure should be started anew. reviewed, and if necessary, the crew retrained and requalified. If any production or sister splice used for testing fails to meet the tensile test specification in Paragraph 3a, and the observed rate of splices that fail the tensile test exceeds 1 for each 15 consecutive test samples, mechanical splicing should be stopped. In addition, the adjacent production splices on each side of the last failed splice and 4 other splices distributed uniformly throughout the balance of the 100 production splices under investigation should be tested,
DCPP UNITS 1 & 2 FSAR UPDATE Sheet 5 of 5 Revision 11 November 1996 TABLE 3.8-2 Diablo Canyon Power Plant Safety Guide 10 and an independent laboratory analysis should be made to identify the cause of all failures. The results of these tests should be evaluated by the designer of the containment structure and the licensee to determine the required corrective action. The designer and the licensee should specify the extent of repairs necessary and the actions required to prevent further failures from the identified causes.
- b. If two or more splices from any of these 6 additional splice samples fail to meet the tensile test specification of Paragraph 3a, the balance of the 100 production splices under investigation should be rejected and replaced.
When mechanical splicing is resumed, the sampling procedure should be started anew.
If the average tensile strength of the 15 consecutive samples fails to meet the provisions of paragraph 3b above, the designer of the containment structure and the licensee should evaluate and assess the acceptability of the reduced average tensile strength with respect to the required strength at the location from which the samples were taken.
DCPP UNITS 1 & 2 FSAR UPDATE Sheet 1 of 10 TABLE 3.8-3 Revision 11 November 1996 NONDESTRUCTIVE EXAMINATION OF PRIMARY CONTAINMENT LINER WELDS COMPARISON OF PROGRAM USED ON DIABLO CANYON POWER PLANT WITH SAFETY GUIDE 19 Diablo Canyon Power Plant Safety Guide 19 1. Nondestructive Examination of Liner Seam Welds For each welder and welding position, the first 10 a. For each welder and welding position (flat, feet of weld was examined radiographically. There- horizontal, and overhead), the first 10 after, a minimum of 10% of the welding (to at feet of weld, and one spot (not less than least include all intersections of joints) was 12 inches in length) in each additional 50 progressively examined radiographically as welding foot increment of weld (weld test unit) or was performed. This was done on a random basis fraction thereof should be examined with the location specified in such a manner that radiographically in accordance with the an approximately equal number of radiographs were techniques prescribed in Section V, "Non-taken from the work of each welder. The techniques destructive Examination," of the ASME of radiographic examination of welds were in Boiler and Pressure Vessel Code (ASME B&PV accordance with Paragraph UW-51 of Section VIII, Code). In any case, a minimum of 2 percent ASME Boiler and Pressure Vessel Code (ASME B&PV of all liner seam welds should be examined Code). See Notes 1 and 2. by radiography. Where radiographic examination of liner seal welds b. Where radiographic examination of liner was not feasible, a minimum 10% of the seam welds is not feasible or where the welding (to at least include all locations where weld is located in areas which will not be there are welded backing strip splices and inter- accessible after construction, the entire sections) was examined by magnetic particle or liq- length of weld should be examined by the uid penetrant testing. Magnetic particle testing magnetic particle method or by the ultra-was in accordance with Appendix VI of Section VIII, sonic method in accordance with the tech-ASME B&PV Code. Liquid penetrant testing was in niques prescribed in Section V of the ASME accordance with Appendix VIII of Section VIII, BP&V Code for such examination methods. ASME B&PV Code. See Notes 1 and 2. DCPP UNITS 1 & 2 FSAR UPDATE Sheet 2 of 10 TABLE 3.8-3 Revision 11 November 1996 Diablo Canyon Power Plant Safety Guide 19 All liner seam welds were tested for leaktightness c. All liner seam welds should be tested for in accordance with the following method: leaktightness in accordance with the following method (or other methods of equivalent sensitivity): Immediately preceding the test, a soap solution Immediately preceding the test, a soap solution is applied to the weld. The application of the (or other appropriate solution) should be applied soap solution must not precede the vacuum box to the weld. A vacuum box containing a viewing by more than 3 minutes. The vacuum box, which window should be placed over the area to be contains a viewing window, is placed over the tested and evacuated to produce at least 5 psi area to be tested and evacuated to a 5 psi dif- differential with the atmospheric pressure. Leaks ferential with the atmospheric pressure. in welds, if present, should be detected by forma-tion of bubbles. The solution used for the test should have bubble formation properties adequate for identification of leaks. The test solution should be checked every hour, with a suitable test leak to verify the bubble formation property of the solution used. Leak chase channels are installed over the liner d. Where leak chase system channels are installed over welds. Upon completion of one zone of leak chase liner welds, channel-to-liner plate welds should be channels, the zone was tested at the containment tested for leak- tightness by pressurizing the structure design pressure of 47 psi. The accept- channels to containment design pressure. If any ance criteria is that there be no loss of pressure indicated loss of channel test pressure occurs within 2 hours as indicated by a pressure gauge. within 2 hours, as evidenced by a test gauge, the channel-to-liner welds should be soap bubble tested in accordance with the above procedure. DCPP UNITS 1 & 2 FSAR UPDATE Sheet 3 of 10 TABLE 3.8-3 Revision 11 November 1996 Diablo Canyon Power Plant Safety Guide 19 2. Nondestructive Examination of Penetration, Airlock, and Access Opening Welds All welds in penetration, airlocks, and access a. All welds in penetration, airlocks, and openings that are not backed by concrete were fully access openings that are not backed by con-examined in accordance with Class B requirements of crete, such as welds between penetrations Section III, ASME B&PV Code. See Notes 1, 2, 3, and flued fittings and pipelines, should be and 4. fully examined in accordance with examina-tion methods of NE-5120 of Section III of All welds between flued heads and pipelines were the ASME B&PV Code employing the techniques fully examined in accordance with the Class II prescribed in Section V of that code. requirements of ANSI B 31.7, Nuclear Power Piping. Welds backed by concrete in the vicinity of b. All welds in the vicinity of penetrations and penetrations were examined as follows: access openings that are backed by concrete, such as welds between penetration and 1. Welds between the penetration sleeve and insert reinforcing plate,(a) penetration and liner, plate were fully examined in accordance with reinforcing plate and liner, liner insert and the Class B requirements of Section III, ASME liner, reinforcing plate and frames for airlocks B&PV Code. See Notes 1, 2, and 4. and access openings, and liners and frames for airlocks and access openings, should be fully 2. Welds between the insert plate and the liner examined (1) in accordance with Paragraph 2a were examined under the same criteria as liner above or (2) by magnetic particle, or liquid seam welds. penetrant when a nonmagnetic weld is used, in accordance with the techniques prescribed All welds backed by concrete in the containment in Section V of the ASME B&PV Code. structure are carbon steel. (a) Thickened liner insert which provides local reinforcement. DCPP UNITS 1 & 2 FSAR UPDATE Sheet 4 of 10 TABLE 3.8-3 Revision 11 November 1996 Diablo Canyon Power Plant Safety Guide 19 Examination of welds in penetrant assemblies and c. All welds in bellow type expansion joints in the vicinity of penetrations is described in the provided in penetration assemblies or preceding paragraphs. appurtenances to the containment vessel should be magnetic-particle or liquid- penetrant tested when a nonmagnetic weld is used, in accordance with the techniques prescribed in Section V of ASME B&PV Code for such examination methods. 3. Qualification of Welders and Welding Procedures The qualification of welders, welding machine The qualification of welders, welding machine operators, and welding procedures was in accord- operators, and welding procedures should be in ance with Section IX, "Welding Qualifications," of accordance with Section IX, "Welding Qualifica-the ASME B&PV Code. See Note 2. tions," of the ASME B&PV Code.
- 4. Qualification of Nondestructive Examination Personnel Nondestructive examinations were performed by Nondestructive examination should be performed personnel qualified in accordance with the appro- by personnel designated by the licensee or his priate parts of the ASME B&PV Code. See Notes 1 agent and qualified in accordance with the pro-and 2. visions of Section V of the ASME B&PV Code.
- 5. Selection of Spots for Radiographic Examination The spots of liner seam welds to be radiographi- The spots of liner seam welds to be radiograph-cally examined were selected on a random basis with ically examined should be randomly selected, the locations selected such that all intersections but no two spots in adjacent weld test units DCPP UNITS 1 & 2 FSAR UPDATE Sheet 5 of 10 TABLE 3.8-3 Revision 11 November 1996 Diablo Canyon Power Plant Safety Guide 19 of joints were examined, and an approximately equal should be closer than 10 feet and their loca-number of radiographs were taken from the work of tions should be recorded.
each welder. The location covered by each radiograph was recorded.
- 6. Time of Examination Nondestructive examinations were done progressively as welding was performed. All examinations should be performed as soon as practicable after the linear increment of weld to be examined is completed. 7. Acceptance Standards a. Containment Liner Seam Welds Examined by Radiography Where a spot in the seam weld is judged acceptable Where a spot in the seam weld is judged in accordance with Paragraph UW-51 of Section VIII, acceptable in accordance with the refer-ASME B&PV Code, the entire weld test unit repre- enced standards of NE-5120 of Section III sented by this spot radiograph is considered of the ASME B&PV Code, the entire weld test acceptable. See Notes 2 and 3. unit represented by this spot radiograph is considered acceptable. b. Containment Liner Seam Welds Examined by Ultrasonic or Magnetic Particle Where a spot in the seam weld examined by magnetic Seam welds examined by ultrasonic or magne-particle or liquid penetrant method is judged tic particle methods are considered acceptable DCPP UNITS 1 & 2 FSAR UPDATE Sheet 6 of 10 TABLE 3.8-3 Revision 11 November 1996 Diablo Canyon Power Plant Safety Guide 19 acceptable, in accordance with the acceptance cri- provided the examinations meet the teria referenced in Section VIII, ASME B&PV Code, acceptance standards referenced for such the entire weld seam represented by the examination examination methods in NE-5120 of Section is considered acceptable. See Notes 2 and 3. III of the ASME B&PV Code.
- c. Soap Bubble Leak Tests of Containment Liner Welds The acceptance criterion for the vacuum box test is that no leaks be detected. Liner welds are considered acceptable pro-vided no leakage is detected by soap bubble tests (or by other methods of equivalent sensitivity). d. Penetration, Airlock, and Access Opening Welds Penetration, airlock, and access opening welds that Penetration, airlock, and access opening are not backed by concrete are considered accept- welds are considered acceptable provided able provided the examinations meet the acceptance the examinations meet the acceptance stand-standards referenced for Class B vessels in Section ards referenced in NE-5120 of Section III III, ASME B&PV Code. See Notes 2, 3, and 4. of the ASME B&PV Code. Welds in bellows type expansion joints are considered accept- Welds between flued heads and pipelines are con- able if the examinations meet the acceptance sidered acceptable provided the examinations meet standards referenced in magnetic particle the acceptance standards referenced for Class II and liquid penetrant methods in NE-5120 of piping in ANSI B31.7, Nuclear Power Piping. Section III.
DCPP UNITS 1 & 2 FSAR UPDATE Sheet 7 of 10 TABLE 3.8-3 Revision 11 November 1996 Diablo Canyon Power Plant Safety Guide 19 Welds between the penetration sleeve and insert plate are considered acceptable provided the exam-inations meet the acceptance standards referenced for Class B vessels in Section III, ASME B&PV Code. See Note 2.
- 8. Repair and Reexamination a. Containment Liner Seam Welds Examined by Radiography If a radiographed spot failed to meet the specified When a radiographed spot fails to meet the specified acceptance standards, two additional spots of the acceptance standards, two additional spots should same length were radiographically examined in the be radiographically examined in the same weld same weld seam at locations away from the original test unit at locations at least one foot removed spot, but in welds performed by the same welder or (on each side) from the original spot. The welder operator. The locations of these additional locations of these additional spots should be spots were determined as provided for the original determined by the examiner using the same spot examination. procedure followed in the selection of the original spot for examination and the examination results should determine the following corrective actions: If the two additional spots examined showed welding (1) If the two additional spots examined meet the that meets the specified acceptance standards, the specified acceptance standards, the entire weld entire weld represented by the three radiographs is unit represented by the three spot radiographs judged acceptable. The defective welding disclosed is considered acceptable. However, the by the first of the three radiographs was removed defective welding disclosed by the first of the and repaired. three radiographs should be repaired by welding.
DCPP UNITS 1 & 2 FSAR UPDATE Sheet 8 of 10 TABLE 3.8-3 Revision 11 November 1996 Diablo Canyon Power Plant Safety Guide 19 If either of the two additional spots examined (2)If either of the two additional spots showed welding that does not comply with the speci- examined fails to meet the specified fied acceptance standards, the entire portion of the acceptance standards, the entire weld seam represented was considered unacceptable or, test unit is considered unacceptable. optionally, the entire weld represented was com-pletely radiographed and defective welding corrected The entire weld should be removed and to meet the specific acceptance standards. the joint should be rewelded or, optionally, the entire weld unit may be completely radiographed and defect- ive welding only need be repaired. Repair welding was performed using a qualified (3)Repair welding should be performed procedure. The rewelded joints or weld repaired using a procedure as specified under areas were completely reradiographed and meet the regulatory position 3. above. The weld specified acceptance standards. repaired areas in each weld test unit should be spot radiographed at one selected location to meet the accept- ance criteria specified in regulatory position 7.a. or 8.a. (1). above. b.Containment Liner Seam Welds Examined by Ultrasonic or Magnetic Particle If a weld that had been examined did not comply with When a weld which has been examined does the specified acceptance standards, additional examination not comply with the specified acceptance was performed to the same extent as required for standards, the weld should be repaired and radiography. The weld was repaired and reexamined reexamined in accordance with the provi-in accordance with the provisions of Section VIII of the sions of Section III of the ASME B&PV Code. ASME B&PV Code. See Notes 2 and 3. DCPP UNITS 1 & 2 FSAR UPDATE Sheet 9 of 10 TABLE 3.8-3 Revision 11 November 1996 Diablo Canyon Power Plant Safety Guide 19 c. Soap Bubble Tests of Containment Liner Welds If a weld was judged unacceptable because leakage is Welds judged unacceptable because leakage is detected by the soap bubble test (see regulatory position 7.c. repaired. Repair welding was performed using a pro- above) should be repaired. Repair welding should be cedure qualified as specified for production welds. performed using a qualified procedure as specified The weld repaired areas were reexamined by soap under regulatory position 3. above. The weld bubble leakage retesting. repaired areas should be reexamined by soap bubble leakage retesting. d. Penetration, Airlock and Access Opening Welds If a weld was judged unacceptable on a penetration Welds judged acceptable in accordance with sleeve airlock, or access opening, the weld was regulatory position 7.d. should be repaired repaired and reexamined in accordance with the and reexamined in accordance with the pro-provisions for Class B vessels of Section III of visions of Section III of the ASME B&PV the ASME B&PV Code. See Notes 2 and 3. Code.
- 9. Records Retention of records is discussed in Chapter 17. Records of radiographs and other nondestructive examinations including those for repaired defective welds should be retained by the licensee in compliance with the provisions of Section XVII, "Quality Assurance Records," of Appendix B to 10 CFR Part 50, "Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants."
DCPP UNITS 1 & 2 FSAR UPDATE Sheet 10 of 10 TABLE 3.8-3 Revision 11 November 1996 Notes:
- 1. Section V, ASME B&PV Code, which provides techniques for nondestructive examination applicable to all sections of the ASME B&PV Code, was first published in July 1971. Although it may eventually replace the corresponding parts of other sections of the ASME B&PV Code, the individual sections still contain techniques for nondestructive examinations.
- 2. References in the table to ASME B&PV Code for the Diablo Canyon plant refer to 1968 Edition, including addenda through Summer 1968.
- 3. NE-5120, Section III, ASME B&PV Code, requires examination technique and acceptance criteria in accordance with Section VIII, ASME B&PV Code (Paragraph UW-51 for radiography).
- 4. Class B requirements of Section III, ASME B&PV Code, specify radiographic examination and acceptance criteria in accordance with Paragraph UW-51, Section VIII, ASME B&PV Code.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-4 CONTAINMENT BUILDING BASE SLAB STRESS RATIOS(a) Accident Operating Accident With Hosgri Moment Moment Moment Moment Moment Moment Stress Beam Demand Capacity Demand Capacity Demand Capacity Ratio No.(b) (ft-k) (ft-k) (ft-k) (ft-k) (ft-k) (ft-k) 62 15,293 37,640 12,827 36,925 20,134 41,250 -- -50,600 -37,772 -156,900 -44,967 -175,875 2.05 225 59,630 88,835 75,492 279,275 109,844 314,000 -- -18,275 -- -54,375 -- -61,083 1.49 43 12,126 51,880 56,623 167,925 69,444 188,124 -- -18,275 -- -54,375 -- -61,083 2.71 24 14,483 25,940 64,157 83,963 68,263 94,062 -- -9,138 -- -27,188 -- -30,541 1.31 129 23,425 88,835 76,480 279,275 93,238 314,000 -- -18,275 -- -54,375 -- -61,083 3.65 216 23,013 37,640 19,780 36,925 26,007 41,250 -- -50,600 -21,785 -156,900 -67,471 -175,875 1.59 171 1,898 6,675 -- 22,155 5,831 24,750 -6,884 -30,360 -37,497 -94,140 -55,206 -105,525 1.91
(a) Stress Ratio = Capacity Demand
(b) See Figure 3.8-38: + = Tension on bottom - = Tension on top
DCPP UNITS 1 & 2 FSAR UPDATE 3 TABLE 3.8-5 Sheet 1 of 3 Revision 11 November 1996 CONTAINMENT BUILDING INTERNAL STRUCTURE STRESS RATIOS IN SELECTED ELEMENTS Description Load Stress of Member Location of Member Combination(a) Demand Capacity Ratio(b) Rebar in 3-ft Crane wall: concrete wall 1. Vertical bar D + L + DDE + CP 58 ksi 60 ksi 1.03
- 2. Hoop bar + R + J + M 54 ksi 60 ksi 1.11 4-ft concrete Fuel transfer canal:
wall 1. Wall @ N & S from D + L + DDE + CP 343 k-ft 381 k-ft 1.11 el 113 ft-1 1/2 in. to el + R + J + M 140 ft
- 2. Wall @ W from D + L + DDE + CP 162 k-ft 216 k-ft 1.33 el 113 ft-1 1/2 in. to el + R + J + M 140 ft Rebar in 2-ft Fuel transfer canal wall D + L + DDE + CP 22 ksi 60 ksi 2.72 concrete wall @ W from el 88 ft to el + R + J + M 113 ft-1 1/2 in. 3-ft concrete Fuel transfer canal floor D + L + DDE + CP 258 k-ft 269 k-ft 1.04 slab @ el 113 ft-1 1/2 in. + R + J + M 4-ft Concrete Fuel transfer canal floor D + L + DDE + CP 306 k-ft 381 k-ft 1.24 Slab @ el 104 ft + R + J + M Rebar in 6-ft Reactor cavity wall:
concrete wall 1. Vertical bar D+L+DDE+CP+R+J+M 15 ksi 60 ksi 4.0 2. Hoop bar D + L + DDE + CP 26 ksi 60 ksi 2.3 + R + J + M 3-ft concrete Floor @ el 140 ft D + L + DE + T 46 k-ft 93 k-ft 2.02 slab (a) Load combinations with Hosgri do not govern. (b) Stress Ratio = Capacity Demand DCPP UNITS 1 & 2 FSAR UPDATE 3 TABLE 3.8-5 Sheet 2 of 3 Revision 11 November 1996 Description Load Stress of Member Location of Member Combination(a) Demand Capacity Ratio(b) 4 ft 6 in. Floor @ el 140 ft D + L + DE + T 156 k-ft 229 k-ft 1.46 concrete slab
5 ft concrete Floor @ el 140 ft D + L + DDE + CP 328 k-ft 500 k-ft 1.52 slab + R + J + M
10 in. Annulus platform @ el 130 ft D + L + DE + T 10 k-ft 39 k-ft 3.90 concrete slab
1 ft 6 in. Annulus platform @ el 140 ft D + L + DE + T 35 k-ft 57 k-ft 1.62 concrete slab
W21x73 Annulus platform @ el 130 ft D + L + DE + T 22 ksi 24 ksi 1.09
+ TH + FV + RVOT
W21x62 " " 8 ksi 22 ksi 2.75
W12x40 " " 9 ksi 22 ksi 2.44
W12x65 Annulus platform column " 124 k (Unit 1) 268 ksi 2.16
W12x65 " " 205 k (Unit 2) 268 ksi 1.31
W12x99 " " 212 k (Unit 1) 366 k 1.73
W21x55 Annulus platform @ el 140 ft " 24 ksi (Unit 1) 27 ksi 1.12
W21x82 " " 11 ksi (Unit 1) 22 ksi 2.00
W21x68 " " 17 ksi (Unit 1) 22 ksi 1.29
W21x96 " " 23 ksi (Unit 1) 27 ksi 1.17
DCPP UNITS 1 & 2 FSAR UPDATE 3 TABLE 3.8-5 Sheet 3 of 3 Revision 11 November 1996 Description Load Stress of Member Location of Member Combination(a) Demand Capacity Ratio(b) W24x100 Annulus platform @ el 140 ft D + DDE + THA + 28 (Unit 2) 37.4 1.34 FV + RVOT
W21x96 " " 18 (Unit 2) 37.4 2.08
W21x68 " " 21 (Unit 2) 37.4 1.78
W21x55 " " 16 (Unit 2) 37.4 2.33
W24x100 " D + HE 21 (Unit 2) 44.8 2.13
W21x96 " " 20 (Unit 2) 44.8 2.21
W21x68 " " 17 (Unit 2) 44.8 2.64
W21x55 " " 13 (Unit 2) 44.8 3.45
W12x65 Annulus platform column D + DDE + THA + 260 (Unit 2) 45.6 1.75 FV + RVOT
W12x99 " " 270 (Unit 2) 45.6 1.69
W12x65 " D + HE 357 (Unit 2) 55.7 1.56
W12x99 " D + HE 365 (Unit 2) 55.7 1.53
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.8-5A Revision 11 November 1996 CONTAINMENT BUILDING PIPEWAY STRUCTURE STRESS RATIOS IN SELECTED MEMBERS Description Location of Member Load Stress of Membe r Unit Elevation Combination Ratio(a) W8 x 40 1 114 D + DE 1.10 W8 x 40 1 114 D + DE 1.07 W8 x 40 1 114 D + DE 1.07 W14 x 111 2 109 D + DE 1.72 W14 x 111 2 109 D + DE 1.79 W14 x 111 2 109 D + DE 1.59 W8 x 40 1 114 D + DDE 1.11 W8 x 40 1 114 D + DDE 1.20 W8 x 40 1 114 D + DDE 1.20 W14 x 111 2 109 D + DDE 2.78 W14 x 111 2 109 D + DDE 1.89 W14 x 111 2 109 D + DDE 1.92 W8 x 40 1 114 D + DDE + Yr 1.06 W14 x 111 1 119 D + DDE + Yr 1.27 W14 x 202 1 119 D + DDE + Yr 1.32 W14 x 202 2 114 D + DDE + Yr 1.52 W8 X 17 2 109 D + DDE + Yr 1.11 W14 x 111 2 109 D + DDE + Yr 1.25 W8 x 40 1 114 D + HE 1.05 W8 x 40 1 114 D + HE 1.09 W8 x 40 1 114 D + HE 1.05 W14 x 111 2 109 D + HE 1.03 W10 x 31 2 109 D + HE 1.06 W12 x 106 2 138 D + HE 1.11
(a) Stress ratio = Capacity Demand
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.8-5B Revision 12 September 1998 CONTAINMENT AND AUXILIARY BUILDINGS COMPARISON OF DISPLACEMENTS AND SEPARATIONS Maximum Relative Seismic Displacement(a) Minimum Minimum Factor of Safety Elevation (ft) DDE HE Separation (in.)(c) Against Contact(e) 188 6.76 9.59 22 2.06 140 0.44 0.37 8 5.29 115 0.27 0.23 2(d) 3.05 100 0.17 0.11 1.25(d) 4.12 (a) Maximum relative seismic displacements are calculated as sum of maximum containment and auxiliary building displacements.
(b) Not Used.
(c) Minimum separation is measured at normal ambient temperature and pressure.
(d) Except for a few localized areas, the minimum separation is 4 inches at elevations 100 ft and 115 ft.
(e) The factor of safety is determined from the relative seismic displacements after the thermal and pressure effects are conservatively accounted for.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.8-6 Sheet 1 of 3 Revision 21 September 2013 VERIFICATION OF COMPUTER PROGRAMS Program Name General Function Verification Measure AISCBM/CE401 Analysis, design, and investigation of structural steel framing system in accordance with AISC specification Bechtel Verification Manual ANSR Linear/nonlinear static and dynamic analysis finite-element program URS/Blume QA Manual AXIDYN Static and dynamic analysis of axisymmetric structures URS/Blume QA Manual BLUME SAP IV General-purpose linear elastic finite-element static and dynamic analysis URS/Blume QA Manual BSAP/CE800 General-purpose linear elastic finite-element static and dynamic analysis Bechtel Verification Manual BSAP-POST/ CE201&CE217 Postprocessing for BSAP computer program Bechtel Verification Manual CECAP/CE987 Computes stress in rebars and liner plate by considering cracking in concrete Bechtel Verification Manual Drain-2D Nonlinear 2-D static and dynamic analysisURS/Blume QA Manual FINEL/CE801 Performs finite element static analysis by considering cracking and yielding Bechtel Verification Manual LOCAL STRESS/ME210 Calculates local stress in cylindrical shells due to external loading Bechtel Verification Manual SMIS Matrix manipulation program URS/Blume QA Manual SPECTRA/CE802 Computes response spectra from acceleration time-histories Bechtel Verification Manual STAND/ME425 Design and evaluation of pipe support base plate with concrete anchor bolt assemblies Bechtel Verification Manual DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.8-6 Sheet 2 of 3 Revision 21 September 2013 Program Name General Function Verification Measure THERMAL STRESS/ ME643 Performs thermal and stress analysis for 2-D plane or axisymmetric structures Bechtel Verification Manual BECHTEL ANSYS/ CE798 Large general-purpose linear/nonlinear static and dynamic analysis Bechtel Verification Manual BECHTEL STRUDL/ CE901 Finite element static/dynamic analysis, and design of structures Bechtel Verification Manual EASE2/E2SPEC Linear elastic finite-element static and dynamic analysis computer program Verification by Control Data Corporation PG&E STRUDL General purpose static and dynamic structural analysis Partial verification of program as originally received. Complete verification performed on a case-by-case basis for each application. GTSTRUDL/CE701 General-purpose static and dynamic finite element code Verification by Control Data Corporation PIPERUP Performs nonlinear elastic/plastic analysis of 3-D piping system subject to static/dynamic time-history forcing functions Nuclear Services Corporation Verification Manual STARDYNE/CE991 General-purpose finite-element static and dynamic analysis Bechtel Verification Verification RAP Pipe whip restraint design program Nuclear Services Corporation Verification Manual WECAN Modal superposition time history analysis and static analysis of structure Westinghouse Verification Manual ADDA Postprocessor to sum the time history responses for two different sets of modes Westinghouse Verification Manual DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.8-6 Sheet 3 of 3 Revision 21 September 2013 Program Name General Function Verification Measure TAPES To reformat the time history response tapes from ADDA for input to GENSPC Westinghouse Verification Manual GENSPC2 To calculate the modal response spectra Westinghouse Verification Manual COMBSPC To combine the response spectra by SRSS Westinghouse Verification Manual SPREAD To transform the scale of the spectra from frequency to period and plot the combined response spectra Westinghouse Verification Manual MARG3 Qualification analysis of structure Westinghouse Verification Manual SAP90 General-purpose linear elastic finite-element static and dynamic analysis Computers and Structures, Inc. Verification Manual SAP2000 General-purpose linear and non-linear finite-element program for static and dynamic analysis Computers and Structures, Inc. Verification Manual PC-SPECTRA Pre- and post-processor for response spectra data PG&E Nuclear Computer Program Acceptance Report PC-ANSR Linear/Nonlinear static and dynamic analysis finite-element program PG&E Calculation No. 2252C-1 (Reference 40) DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.8-6A Revision 21 September 2013 AVERAGE CONCRETE STRENGTH CONTAINMENT AND INTERIOR STRUCTURE Average fc' (test value) Ec(a) Component (psi) (psi) Base slab to elevation 87 ft 6330 4.53 x 106 Skin pour at elevation 89 ft 6330 4.53 x 106 Interior 6330 4.53 x 106 Skin pour 3850 3.54 x 106 Soldier beams 3850 3.54 x 106 Exterior walls 3850 3.54 x 106 Dome 3850 3.54 x 106 (a) Ec = 57,000 (fc')1/2 per AC1 318-71, in psi DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.8-6B Revision 11 November 1996 STEEL STRENGTH DATA CONTAINMENT AND INTERIOR STRUCTURE
Designation Yield (psi) Ultimate (psi) Structure of Steel Minimum Average Minimum Average Reinforcing Steel Containment (1 and 2) ASTM 615, 61,750 66,854 93,750 105,992 Exterior #18s Grade 60 Containment (1 and 2) Grade 60 62,820 68,079 96,795 105,556 Interior #11s
Structural Steel ASTM A36 36,100 43,950 58,200 68,040 ASTM A441 42,100 51,620 67,200 75,910 ASTM A516 45,800 51,040 72,200 79,170
DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 3.8-7 AUXILIARY BUILDING FUEL HANDLING CRANE SUPPORT STRUCTURE STRUCTURAL MEMBERS AND ANCHORAGES STRESS RATIOS Description Of Members And Their Functions Stress Ratios(a) (b) Hosgri DDE DE Top Chord Roof 1.7 1.5 1.9 B R Bottom Chord Roof 1.1 1.2 1.3 A C East-West Elevation Diagonals 1.1 1.1 1.4 E S N-S Truss Diagonals, West and East Exterior/Interior 1.9 1.6 2.0 East-West Truss Diagonals 1.1 1.3 1.1 East-West Truss Knee 1.1 1.3 1.5 C North South Trusses, Top 3.4 4.0 4.2 H O North South Trusses, Bottom 3.2 4.0 4.3 R D East-West Trusses, Top 1.1 1.6 1.9 S East-West Trusses, Bottom 1.1 1.4 1.8 L & V A E Frame Horizontals, West and East Sides 4.5 4.8 5.9 T R E T Vertical Columns 1.0 1.1 1.0 R I A C East-West Truss Struts 1.2 1.4 1.6 L A L B A Axial Tensions 1.0 1.1 1.6 A N S C Axial Compressions 1.3 1.4 1.7 E H O Lateral Shears 1.9 2.2 2.3 R A G E (a) Stress Ratio = Capacity Demand (b) Refer to Calculation 52.15.7.1.1.15 for stress ratios. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-8 AUXILIARY BUILDING SLABS STRESS RATIOS(a)(b) OUT-OF-PLANE LOADS (DE) Shear, psi Moment, kips-ft Slab Location Member Demand Capacity Demand Capacity Stress Ratio El 73 ft Area bounded by column(c) Slab 49 60 24 30 1.2 lines H, U, 15.7, 16.8 Beam 48 60 100 140 1.2 El 85 ft Area bounded by column Slab 64 78 82 120 1.2 lines H, U, 16.8, 19.2 El 100 ft & 115 ft Area bounded by column(c) Slab 48 78 75 88 1.2 lines H, T, 10.7, 15.7 Beam 70 120 340 470 1.4 El 115 ft Area bounded by column Slab 45.0 78.0 27.0 32.00 1.2 lines U, V, 15.7, 20.3 El 115 ft Area bounded by column Slab 59 78 56 67 1.2 lines H, L.5, 15.7, 20.3 Beam 170 210 2,000 2,400 1.2 El 140 ft Area bounded by column(c) Slab 120 130 2,050 2,390 1.1 lines H, T, 10.7, 15.7 Beam 130 140 1450 1640 1.1 El 140 ft Area bounded by column(c) Slab 55 78 59 77 1.3 lines R, V, 15.7, 17.4 Beam 89 97 2,010 2,240 1.1 El 140 ft Area bounded by column Slab 57.0 78.0 382.0 455.00 1.2 lines H, L, 15.7, 20.3 El 154-1/2 ft Area bounded by column Slab 30 78 14 17 1.2 lines L, R, 15.7, 17.4 Beam 60 78 76 100 1.3 El 163-1/3 ft Area bounded by column Composite(d) 9,300 14,000 2,260 2,300 1.02 lines H, L, 15.7, 20.3 Beam (a) Stress ratio = Capacity for shear or moment, whichever is smaller. Demand (b) This does not include the effects of pipe break loads which are evaluated locally in accordance with provisions of Reference 6. (c) Counterpart in Unit 2 is similar. (d) These values are for structural steel beams embedded in the slab.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-9 AUXILIARY BUILDING SLABS STRESS RATIOS(a)b) OUT-OF-PLANE LOADS (DDE) Shear, psi Moment, kips-ft Slab Location Member Demand Capacity Demand Capacity Stress Ratio El 73 ft Area bounded by column(c) Slab 53 91 27 56 1.7 lines H, U, 15.7, 16.8 Beam 53 93 110 260 1.8 El 85 ft Area bounded by column Slab 72 120 93 220 1.7 lines H, U, 16.7, 19.2 El 100 ft & 115 ft Area bounded by column(c) Slab 51 120 81 167 2.1 lines H, T, 10.7, 15.7 Beam 130 200 360 900 1.5 El 115 ft Area bounded by column Slab 49 120 30 62 2.1 lines U, V, 15.7, 20.3 El 115 ft Area bounded by column Slab 66 120 63 130 1.8 lines H, L.5, 15.7, 20.3 Beam 190 330 2,200 4,600 1.7 El 140 ft Area bounded by column(c) Slab 120 190 2,110 4,310 1.6 lines H, T, 10.7, 15.7 Beam 130 200 1,500 3,140 1.5 El 140 ft Area bounded by column(c) Slab 56 120 60 150 2.1 lines R, V, 15.7, 17.4 Beam 93 150 2,110 4,030 1.9 El 140 ft Area bounded by column Slab 61 120 411 858 2.0 lines H, L, 15.7, 20.3 El 154-1/2 ft Area bounded by column Slab 32 120 15 33 2.2 lines L, R, 15.7, 17.4 Beam 64 120 81 190 1.9 El 163-1/3 ft Area bounded by column Composite(d) 11,000 20,000 2,200 3,100 1.4 lines H, L, 15.7, 20.3 Beam (a) Stress ratio = Capacity for shear or moment, whichever is smaller. Demand (b) This does not include the effects of pipe break loads which are evaluated locally in accordance with provisions of Reference 6. (c) Counterpart in Unit 2 is similar. (d) These values are for structural steel beams embedded in the slab.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-10 AUXILIARY BUILDING SLABS STRESS RATIOS(a)(b) OUT-OF-PLANE LOADS (HE) Shear, psi Moment, kips-ft Slab Location Member Demand Capacity Demand Capacity Stress Ratio El 73 ft Area bounded by column(c) Slab 65 110 32 56 1.7 lines H, U, 15.7, 16.8 Beam 63 110 130 260 1.7 El 85 ft Area bounded by column Slab 91 130 120 270 1.4 lines H, U, 16.8, 19.2 El 100 ft & 115 ft Area bounded by column(c) Slab 68 130 110 200 1.8 lines H, T, 10.7, 15.7 Beam 170 220 480 1,100 1.3 El 115 ft Area bounded by column Slab 60.0 130.00 36.0 74.00 2.0 lines U, V, 15.7, 20.3 El 115 ft Area bounded by column Slab 100 130 120 150 1.2 lines H, L.5, 15.7, 20.3 Beam 300 360 4,300 5,500 1.2 El 140 ft Area bounded by column(c) Slab 160 200 2,720 5,220 1.3 lines H, T, 10.7, 15.7 Beam 170 200 2,140 3,770 1.2 El 140 ft Area bounded by column(c) Slab 72 130 79 180 1.8 lines R, V, 15.7, 17.4 Beam 145 160 3,280 4,870 1.1 El 140 ft Area bounded by column Slab 105.0 130.00 710.0 1,062.00 1.2 lines H, L, 15.7, 20.3 El 154-1/2 ft Area bounded by column(c) Slab 65 130 29 41 1.4 lines L, R, 15.7, 17.4 Beam 92 130 150 230 1.4 El 163-1/3 ft Area bounded by column Composite(d) 16,000 24,000 3,900 4,200 1.1 lines H, L, 15.7, 20.3 Beam (a) Stress ratio = Capacity for shear or moment, whichever is smaller. Demand (b) This does not include the effects of pipe break loads which are evaluated locally in accordance with provisions of Reference 6. (c) Counterpart in Unit 2 is similar. (d) These values are for structural steel beams embedded in the slab.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-11 AUXILIARY BUILDING SLABS STRESS RATIOS(f) IN-PLANE LOADS (DE) Shear(c), Moment(d), kip k-ft Elevation, Section(e)(g) Stress ft Number Demand Capacity(a) Demand Capacity(b) Ratio 100 1-a 60 2,200 2,650 25,300 9.5 100 1-b 170 2,300 5,700 21,600 3.8 100 2-a 320 2,880 9,500 91,900 9.0 100 2-b 110 1,060 700 6,350 9.1 100 2-c 10 220 50 600 >10.0 115 1 300 2,240 7,350 23,200 3.2 115 2-a 240 4,350 200 50,900 >10.0 115 2-b 120 490 2,100 4,100 2.0 115 3-a 260 1,260 2,650 7,700 2.9 115 3-b 280 1,280 2,150 18,100 4.6 115 4 1,460 8,100 29,700 289,000 5.5 140 1 380 2,240 2,500 4,800 1.9 140 2-a 320 4,130 5,100 64,000 >10.0 140 2-b 270 2,100 3,050 13,800 4.5 140 3-a 160 430 1,950 4,950 2.5 140 3-b 390 1,530 5,900 16,300 2.8 140 4 1,840 8,580 39,500 443,000 4.7 (a) Shear capacity is calculated for the section subjected to demand moment and axial force. (b) Moment capacity is calculated for the section subjected to demand axial force. (c) Shear capacities and demands are rounded to the nearest 10 kips or 3 significant digits. (d) Moment capacities and demands are rounded to the nearest 50 ft-kips or 3 significant digits. (e) Section location is shown on Figures 3.8-60 through 3.8-62. (f) Stress ratio = Capacity for shear or moment, whichever is smaller Demand (g) Component in Unit 2 is similar. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-12 AUXILIARY BUILDING SLABS STRESS RATIOS(f) IN-PLANE LOADS (DDE) Shear(c), Moment(d), Kip k-ft Elevation, Section(e)(g) Stress ft Number Demand Capacity(a) Demand Capacity(b) Ratio 100 1-a 110 3,710 3,400 73,300 >10.0 100 1-b 310 3,770 9,850 63,100 6.4 100 2-a 610 4,800 14,900 303,000 7.9 100 2-b 200 1,770 1,250 17,000 8.9 100 2-c 10 370 50 1,100 >10.0 115 1 500 3,730 15,400 88,700 5.8 115 2-a 430 7,240 3,550 167,000 >10.0 115 2-b 240 1,130 4,500 16,500 3.7 115 3-a 330 2,090 2,900 12,000 4.1 115 3-b 450 2,140 2,350 42,600 4.8 115 4 2,920 13,500 60,000 1,000,000 4.6 140 1 750 3,730 4,250 43,300 5.0 140 2-a 840 6,890 6,150 200,000 8.2 140 2-b 510 3,500 5,550 36,200 6.5 140 3-a 240 720 2,550 10,300 3.0 140 3-b 590 2,550 8,900 46,400 4.3 140 4 3,700 14,300 79,000 1,110,000 3.9 (a) Shear capacity is calculated for the section subjected to demand moment and axial force. (b) Moment capacity is calculated for the section subjected to demand axial force. (c) Shear capacities and demands are rounded to the nearest 10 kips or 3 significant digits. (d) Moment capacities and demands are rounded to the nearest 50 ft-kips or 3 significant digits. (e) Section location is shown on Figures 3.8-60 through 3.8-62. (f) Stress ratio = Capacity for shear or moment, whichever is smaller Demand (g) Component in Unit 2 is similar. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-13 AUXILIARY BUILDING SLABS STRESS RATIOS(f) IN-PLANE LOADS (HE) Shear(c), Moment(d), Kip k-ft Elevation, Section(e)(g) Stress ft Number Demand Capacity(a) Demand Capacity(b) Ratio 100 1-a 170 4,350 3,650 86,100 >10.0 100 1-b 510 4,500 13,000 65,000 5.0 100 2-a 930 5,580 18,500 180,000 6.0 100 2-b 290 1,830 1,500 13,300 6.3 100 2-c 20 360 100 1,250 >10.0 115 1 770 3,730 25,000 88,500 3.5 115 2-a 710 7,700 11,300 231,000 >10.0 115 2-b 400 1,120 8,050 16,400 2.0 115 3-a 480 2,330 3,100 14,500 4.7 115 3-b 820 2,500 3,200 48,900 3.0 115 4 3,940 15,500 117,000 1,170,000 3.9 140 1 1,120 3,870 9,200 38,000 3.5 140 2-a 1,170 8,010 7,300 240,000 6.8 140 2-b 900 4,150 7,750 43,100 4.6 140 3-a 450 830 3,250 13,800 1.8 140 3-b 970 3,010 11,300 50,700 3.1 140 4 5,210 14,500 157,000 1,160,000 2.8 (a) Shear capacity is calculated for the section subjected to demand moment and axial force (b) Moment capacity is calculated for the section subjected to demand axial force (c) Shear capacities and demands are rounded to the nearest 10 kips or 3 significant digits (d) Moment capacities and demands are rounded to the nearest 50 ft-kips or 3 significant digits (e) Section location is shown on Figures 3.8-60 through 3.8-62 (f) Stress ratio = Capacity for shear or moment, whichever is smaller Demand (g) Component in Unit 2 is similar
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-14 AUXILIARY BUILDING CONCRETE WALLS STRESS RATIOS (DE)(a) Shear, psi Moment 103, k-ft Elev., Wall Location ft Demand Capacity(b) Demand Capacity(b) Stress Ratio On line H (15.7-20.3) 100 120 230 57 188 1.9 85 160 330 9 173 1.9 On line J (11.7-15.7)(c) 100 130 270 35 126 2.0 85 150 280 47 126 1.8 On line T(6.4-15.7)(c) 100 75 200 141 343 2.4 85 85 220 164 664 2.6 On line T (16.8-19.2) 100(d) 55 210 15 65 3.8 On line U.5 (10.3-12.9)(c) 100(d) 45 155 20 113 3.4 On line V (15.7-20.3) 100 50 100 32 250 2.0 85 50 90 67 245 1.8 On line V (6.4-15.7)(c) 100(d) 70 360 82 200 2.4 On line 6.4 (V-S)(c) 100 80 250 85 158 1.9 85 100 340 20 31 1.6 On line 10.3 (T-V)(c) 100(d) 80 250 54 146 2.7 On line 12.9 (T-V)(c) 100(d) 80 240 54 145 2.7 On line 15.7 (H-T.6)(c) 100 110 250 382 782 2.1 85 110 220 481 818 1.7 On line 15.7 (H-T.6)(c) 100 110 260 7 19 2.3 85 60 170 12 19 1.6 (a) Stress ratio = Capacity for shear or moment, whichever is smaller Demand (b) Axial demand effect is included in the capacities (c) Counterpart in Unit 2 is similar (d) Wall does not extend below elevation 100 ft DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-15 AUXILIARY BUILDING CONCRETE WALLS STRESS RATIOS (DDE)(a) Shear, psi Moment 103, k-ft Elev., Wall Location ft Demand Capacity(b) Demand Capacity(b) Stress Ratio On line H (15.7-20.3) 100 240 390 114 407 1.6 85 310 550 178 556 1.8 On line J (11.7-15.7)(c) 100 250 450 62 253 1.8 85 290 460 90 253 1.6 On line T (6.4-15.7) (c) 100 140 340 273 987 2.4 85 170 370 316 1086 2.2 On line T (16.8-19.2) 100(d) 110 350 31 147 3.2 On line U.5(10.3-12.9) (c) 100(d) 85 260 40 244 3.0 On line V (15.7-20.3) 100 90 170 63 394 1.9 85 100 150 133 327 1.5 On line V (6.4-15.7) (c) 100(d) 140 600 133 400 3.0 On line 6.4 (V-S) (c) 100 160 420 141 333 2.4 85 190 570 34 92 2.7 On line 10.3 (T-V) (c) 100(d) 160 420 105 280 2.6 On line 12.9 (T-V) (c) 100(d) 160 410 106 268 2.5 On line 15.7 (H-T.6) (c) 100 220 420 553 1205 1.9 85 220 370 740 1155 1.6 On line 15.7 (U-V) (c) 100 220 430 13 32 1.9 85 115 290 23 30 1.3 (a) Stress ratio = Capacity for shear or moment, whichever is smaller Demand (b) Axial demand effect is included in the capacities (c) Counterpart in Unit 2 is similar (d) Wall does not extend below elevation 100 ft
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-16 AUXILIARY BUILDING CONCRETE WALLS STRESS RATIOS (HE)(a) Shear, psi Moment 103, k-ft Elev., Wall Location ft Demand Capacity(b) Demand Capacity(b) Stress Ratio On line H (15.7-20.3) 100 400 480 176 504 1.2 85 510 630 270 682 1.2 On line J (11.7-15.7)(c) 100 390 500 107 313 1.3 85 440 580 145 313 1.3 On line T (6.4-15.7) (c) 100 190 310 438 860 1.6 85 230 320 493 979 1.4 On line T (16.8-19.2) 100(d) 150 350 42 168 2.3 On line U.5 (10.3-12.9) (c) 100(d) 130 190 60 197 1.5 On line V (15.7-20.3) 100 140 200 90 489 1.4 85 150 170 182 405 1.15 On line V (6.4-15.7) (c) 100(d) 220 640 291 500 1.7 On line 6.4 (V-S) (c) 100 380 460 301 434 1.2 85 390 450 63 84 1.15 On line 10.3 (T-V) (c) 100(d) 330 480 220 339 1.4 On line 12.9 (T-V) (c) 100(d) 270 460 199 324 1.6 On line 15.7 (H-T.6) (c) 100 330 520 666 1494 1.6 85 320 450 859 1425 1.4 On line 15.7 (U-V) (c) 100 340 480 19 36 1.4 85 160 300 30.5 32.6 1.07 (a) Stress ratio = Capacity for shear or moment, whichever is smaller Demand (b) Axial demand effect is included in the capacities (c) Counterpart in Unit 2 is similar (d) Wall does not extend below elevation 100 ft DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-17 AUXILIARY BUILDING COLUMNS STRESS RATIOS(a) Stress Ratio Column Location(b) DE DDE HE 14 - J.7 2.9 3.7 2.6 15 - N 5.3 7.7 4.8 15 - R.8 3.6 3.3 2.5 15 - J.7 1.04 1.8 1.3 15 - S 1.9 2.9 2.3 (a) Stress ratio = Capacity Demand
(b) Counterpart in Unit 2 is similar DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-18 AUXILIARY BUILDING SHEAR DISSIPATION TO FOUNDATION (DE NORTH-SOUTH) Shear Demand at Elevation 85 ft. Shear from Upper Level Inertial Building Direct Torsional Torsional + Load at Portion Shear, Shear, Direct Shear, El 85 ft, Total, Remarks Location(a) kips kips(b) kips kips kips Central 23,600 1,800 25,400 4,400 29,800 Capacity is Portion 57,900 kips 2,300 500 2,800 600 Load is directly North 900 100 1,000 600 10,900 dissipated to Wing 200 200 400 the foundation 4,700 4,700 600 600 2,300 500 2,800 600 Load is directly South 900 100 1,000 600 10,900 dissipated to Wing 200 200 400 the foundation 4,700 4,700 600 600 Shear Capacity at Elevation 85 ft (Central Portion) Capacity of diaphragm to dissipate shear force by bearing 4,700 + 18,000 = 22,700 to the foundation at elevation 85 ft (kips) by rebar tension 1,100 + 1,100 = 2,200 Shear capacity of walls below elevation 85 ft (kips) 33,000 Total shear capacity at and below elevation 85 ft (kips) 57,900 (a) For building portion location only, see Figures 3.8-63 and 3.8-64 (b) Torsional shears on only one side of the center of rigidity are considered DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-19 AUXILIARY BUILDING SHEAR DISSIPATION TO FOUNDATION (DE EAST-WEST) Shear Demand at Elevation 85 ft. Shear from Upper Level Inertial Building Direct Torsional Torsional + Load at Portion Shear, Shear, Direct Shear, El 85 ft, Total, Remarks Location(a) kips kips kips kips kips Central 35,500 35,500 4,400 39,900 Capacity is Portion 76,200 kips 900 900 600 Load is directly North 1,100 1,100 600 4,400 dissipated to Wing 400 400 400 the foundation 400 400 900 900 600 Load is directly South 1,100 1,100 600 4,400 dissipated to Wing 400 400 400 the foundation 400 400
Shear Capacity at Elevation 85 ft (Central Portion) Capacity of diaphragm to dissipate shear force 4,100 to the foundation at elevation 85 ft (kips) 4,100
Shear capacity of walls below elevation 85 ft (kips) 68,000
Total shear capacity at and below elevation 85 ft (kips) 76,200 (a) For building portion location only, see Figures 3.8-63 and 3.8-64 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-20 AUXILIARY BUILDING SHEAR DISSIPATION TO FOUNDATION (DDE NORTH-SOUTH) Shear Demand at Elevation 85 ft. Shear from Upper Level Inertial Building Direct Torsional Torsional + Load at Portion Shear, Shear, Direct Shear, El 85 ft, Total, Remarks Location(a) kips kips(b) kips kips kips Central 46,500 3,700 50,200 9,200 59,400 Capacity is Portion 115,700 kips 4,300 1,000 5,300 1,100 Load is directly North 1,600 300 1,900 1,100 21,000 dissipated to Wing 400 100 500 800 the foundation 9,100 9,100 1,200 1,200 4,300 1,000 5,300 1,100 Load is directly South 1,600 300 1,900 1,100 21,000 dissipated to Wing 400 100 500 800 the foundation 9,100 9,100 1,200 1,200
Shear Capacity at Elevation 85 ft (Central Portion) Capacity of diaphragm to dissipate shear force by bearing 11,000 + 42,000 = 53,000 to the foundation at elevation 85 ft (kips) by rebar tension 1,000 + 1,900 = 3,800
Shear capacity of walls below elevation 85 ft (kips) 58,000
Total shear capacity at and below elevation 85 ft (kips) 115,700 (a) For building portion location only see Figures 3.8-63 and 3.8-64 (b) Torsional shears on only one side of the center of rigidity are considered DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-21 AUXILIARY BUILDING SHEAR DISSIPATION TO FOUNDATION (DDE EAST-WEST) Shear Demand at Elevation 85 ft. Shear from Upper Level Inertial Building Direct Torsional Torsional + Load at Portion Shear, Shear, Direct Shear, El 85 ft, Total, Remarks Location(a) kips kips kips kips kips Central 68,700 68,700 9,200 77,900 Capacity is Portion 128,000 kips 1,600 1,600 1,100 8,300 Load is directly North 2,100 2,100 1,100 dissipated to Wing 900 900 800 the foundation 700 700 1,600 1,600 1,100 8,300 Load is directly South 2,100 2,100 1,100 dissipated to Wing 900 900 800 the foundation 700 700
Shear Capacity at Elevation 85 ft (Central Portion) Capacity of diaphragm to dissipate shear force 7,000 to the foundation at elevation 85 ft (kips) 7,000
Shear capacity of walls below elevation 85 ft (kips) 114,000
Total shear capacity at and below elevation 85 ft (kips) 128,000
(a) For building portion location only see Figures 3.8-63 and 3.8-64
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-22 AUXILIARY BUILDING SHEAR DISSIPATION TO FOUNDATION (HE NORTH-SOUTH)((a) Shear Demand at Elevation 85 ft. Shear from Upper Level Inertial Building Direct Torsional Torsional + Load at Portion Shear, Shear, Direct Shear, El 85 ft, Total, Remarks Location(a) kips kips(b) kips kips kips Central 63,000 9,000 72,000 12,500 84,500 Capacity is Portion 136,800 kips 5,700 2,300 8,000 1,600 Load is directly North 2,100 500 2,600 1,600 29,500 dissipated to Wing 500 300 800 1,000 the foundation 12,200 12,200 1,700 1,700 5,700 2,300 8,000 1,600 Load is directly South 2,100 500 3,600 1,600 29,500 dissipated to Wing 500 300 800 1,000 the foundation 12,200 12,200 1,700 1,700 Shear Capacity at Elevation 85 ft (Central Portion) Capacity of diaphragm to dissipate shear force by bearing 14,600 + 48,400 = 63,000 to the foundation at elevation 85 ft (kips) by rebar tension 2,940 + 2,400 = 4,800
Shear capacity of walls below elevation 85 ft (kips) 69,000
Total shear capacity at and below elevation 85 ft (kips) 136,800
(a) For illustration, see Figures 3.8-63 and 3.8-64. (b) Torsional shears on only one side of the center of rigidity are considered.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-23 AUXILIARY BUILDING SHEAR DISSIPATION TO FOUNDATION (HE EAST-WEST)(a) Shear Demand at Elevation 85 ft. Shear from Upper Level Inertial Building Direct Torsional Torsional + Load at Portion Shear, Shear, Direct Shear, El 85 ft, Total, Remarks Location(a) kips kips(b) kips kips kips Central 84,700 5,300 90,000 12,500 102,500 Capacity is Portion 154,200 kips North 2,000 1,600 3,600 1,600 Load is directly Wing 2,500 1,900 4,400 1,600 14,900 dissipated to 1,100 600 1,700 1,000 the foundation 900 100 1,000 2,000 2,000 1,600 Load is directly South 2,500 2,500 1,600 10,700 dissipated to Wing 1,100 1,100 1,000 the foundation 900 900
Shear Capacity at Elevation 85 ft (Central Portion) Capacity of Diaphragm to Dissipate Shear Force 8,600 to the Foundation at Elevation 85 ft (kips) 8,600
Shear Capacity of Walls Below Elevation 85 ft (kips) 137,000 Total Shear Capacity at and Below Elevation 85 ft (kips) 154,200 (a) For illustration, see Figures 3.8-63 and 3.8-64. (b) Torsional shears on only one side of the center of rigidity are considered.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-23A AUXILIARY BUILDING AND TURBINE BUILDING COMPARISON OF DISPLACEMENTS AND SEPARATIONS Minimum Factor of Maximum Total Safety Displacement (in.)(a) Against Elevation (ft) DDE HE Separation (in.) Contact 163 2.7 4.5 8.0 1.78 140 0.9 0.9 8.0 8.89 115 0.7 1.1 8.0 7.27 100 0.5 0.7 3.0 4.29 (a) Displacements are calculated as sum of maximum auxiliary and turbine building displacements.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-24 DUCTILITY(a) Blume Newmark Structure Ductility Ductility Containment 1.3(b) 1.0(b) Auxiliary Building 1.3(b) 1.0(b) Class I Class II Turbine Building (c) 1.0(b) (c) Intake (c) 1.0(b) (c, d) (a) Ductilities are on story basis; however, floor response spectra were, in general, computed on an elastic analysis basis. (b) Under normal conditions Newmark ductility is 1.0 maximum; higher ductility may be considered for special cases where supporting evidence justifies its use. Blume ductility for Class I structures is 1.3, and may be used only in specific situations. (c) Concrete 1.3; steel 3, with up to 6 locally.
(d) Or as may be required to demonstrate that function of Design Class I equipment will not be adversely affected.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-25 REFUELING WATER STORAGE TANK STRESS RATIO(a) DL + HS + DE + RA DL + HS + DDE + RA DL + HS + HE + RA Force Stress Stress Stress Component Material Demand Capacity Ratio Demand Capacity Ratio Demand Capacity Ratio Longitudinal force, Concrete 63.5 96.0 1.51 121.2 216.0 1.78 133.3 216.0 1.62 Kips/ft Circumferential Concrete 54.4 96.0 1.76 71.5 216.0 3.02 79.6 216.0 2.71 force, kips/ft In plane shear Concrete 26.1 45.5 1.74 52.1 77.4 1.49 58.9 77.4 1.31 force, kips/ft Longitudinal moment, Concrete 40.4 78.2 1.94 56.3 179.7 3.19 58.6 179.7 3.07 Kips-ft/ft Stress intensity Steel 6.4 16.7 2.61 11.2 22.5 2.01 15.4 40.6 2.64 outside vault opening area, Kips/in2 Stress intensity Steel 12.1 16.7 1.38 20.5 22.5 1.10 34.0 40.6 1.19 within vault opening area, Kips/in2 (a) Stress Ratio = Capacity Demand
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-26 TURBINE BUILDING STRUCTURAL STEEL MEMBERS STRESS RATIOS (HE) Member Description Stress Ratios(a) Exterior columns, lines A and G (b) East-west roof trusses - chords 1.2(c) East-west roof trusses - diagonals 1.0(c) North-south walls diagonal tension bracing 1.1(c) North-south walls diagonal compression bracing 1.0(c) Crane runway girder (b) Floor beams (b) (a) Stress Ratio = Capacity Demand
(b) Inelastic deformation occurs, ductility meets limits of Table 3.8-24.
(c) Effects of force redistribution are included. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-27 TURBINE BUILDING CONCRETE MEMBERS STRESS RATIOS (HE)(a) Member Location Stress Ratios(b)
Wall, line A Elev. 85 ft (20-30.3) 1.9
Wall, line G Elev. 85 ft (20-30.3) 1.3
Wall, line 19 Elev. 123 ft (A-G) 1.1
Buttress, line 27 Elev. 85 ft 1.5
Floor slab Elev. 140 ft line 21 (A-C), 1.2 line C (19-21) 1.5(c) Turbine Pedestal Frame 6 (See Figure 3.7-15G) 1.0(d) (a) Stress Ratio = Capacity for shear or moment, whichever is smaller. Demand
(b) Axial demand effect is included in the capacity.
(c) Effects of concrete cracking are considered.
(d) Effects of force distribution are included.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-27A TURBINE BUILDING AND TURBINE PEDESTAL (UNITS 1 & 2)(a) COMPARISON OF DISPLACEMENTS AND SEPARATIONS AT EL 140 FT HE ANALYSIS Factor of Side of Maximum Calculated Safety Pedestal Displacement, in.(b) Minimum Against Location Building Pedestal Total Separation, in.(c) Contact East 0.53 1.67 2.20 2.88 1.31 West 0.58 1.67 2.25 3.00 1.33
North 0.20 0.73 0.93 1.25 1.34
South 0.21 0.76 0.97 1.31 1.35 (a) Values shown are for Unit 1 or Unit 2, whichever has the lowest factor of safety. (b) Displacements are an envelope of maximum displacements calculated using Newmark-Hosgri design response spectra. (c) Separations are an envelope of minimum as-built separations.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.8-28 INTAKE STRUCTURE CAPACITIES AND DUCTILITIES OF FLOW STRAIGHTENERS (OR PIERS)(1) P U Pier (Tension) M Mallow (Ductility) 1 129.0 10,600 15,600 N/A 2 81.5 14,300 15,900 N/A 3 44.6 15,700 16,100 N/A 4 24.1 16,400 16,200 1.24 5 39.1 17,300 16,100 1.33 6 141.0 17,700 15,500 1.44 7 146.0 16,300 15,400 1.32 Notes: (1) These values are due to the Newmark earthquake, which governs for all piers:
P = Axial tension, kips
M = Moment, in.-kips (value of M based on linear analysis)
Mallow = Factored (0=0.90) ultimate moment capacity including tension effects u = Ductility of tensile steel (ratio between calculated strain to yield strain) DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-1 Page 1 of 2 Revision 12 September 1998 LOAD COMBINATIONS AND ACCEPTANCE CRITERIA FOR PRESSURIZER SAFETY AND RELIEF VALVE PIPING Plant/System Piping Allowable Combination Operation Condition Load Combination Stress Intensity Upstream of Valves 1 Normal N 1.0 Sh 2 Upset N + DE + SOTU 1.2 Sh 3 Emergency N + SOTE 1.8 Sh 4 Faulted N + MAX(DDE, HOSGRI) 2.4 Sh + SOTF 5 Faulted(Note 5) N + LOCA + MAX(DDE, 2.4 Sh HOSGRI) + SOTF Downstream of Valves 1 Normal N 1.0 Sh 2 Upset N + SOTU 1.2 Sh 3 Upset N + DE + SOTU 1.8 Sh 4 Emergency N + SOTE 1.8 Sh 5 Faulted N + MAX(DDE, HOSGRI) 2.4 Sh + SOTF 6 Faulted(Note 5) N + LOCA + MAX(DDE, 2.4 Sh HOSGRI) + SOTF
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-1 Page 2 of 2 Revision 12 September 1998 NOTES:
(1) This table is applicable to the seismically designed portion of downstream non-Category I piping necessary to isolate the response, and to assure acceptable valve loading on the discharge nozzle. (2) See SOT definitions and other load abbreviations.
(3) The bounding number of valves (and discharge sequence if setpoints are significantly different) for the applicable system operating transient defined on this page should be used. (4) Use SRSS for combining dynamic load responses.
(5) The LOCA loads used in this load combination in the original analyses were the loads resulting from breaks in the main reactor coolant loop. With the acceptance of the DCPP leak-before-break analyses by the NRC, LOCA loads resulting from breaks in the main RCS loop piping no longer have to be considered in the design basis structural analyses and included in the load combinations. Only the LOCA loads from RCS branch line breaks have to be considered.
Abbreviations N = Sustained loads during normal plant operation SOT = System Operating Transient SOTU = Relief Valve Discharge Transient SOTE = Safety Valve Discharge Transient SOTF = Max (SOTU; SOTE) DE = Design Earthquake DDE = Double Design Earthquake HOSGRI = Hosgri earthquake LOCA = Loss-of-coolant accident Sh = Basic material allowable stress at maximum (hot) temperature
DCPP UNITS 1 & 2 FSAR UPDATE Sheet 1 of 3 TABLE 3.9-2 Revision 11 November 1996 HOSGRI AND DDE SEISMIC LOADING COMBINATIONS AND STRUCTURAL CRITERIA MECHANICAL EQUIPMENT(1) COMPONENT LOADING COMBINATIONS CRITERIA (2, 3) (4) (7, 8, 9, 10, 11, 12, 13, 14) Tanks, Heat Exchangers, Deadweight + Pressure m 2.0S Filters, Demineralizers + HOSGRI/DDE + Nozzle/Piping Loads (m or L) + b 2.4S Active Pumps Deadweight + Pressure m 1.2S + HOSGRI/DDE + Nozzle/Piping Loads (m or L) + b 1.8S + Operating Loads
Inactive Pumps Deadweight + Pressure m 2.0S + HOSGRI/DDE + Nozzle/Piping Loads (m or L) + m 2.4S + Operating Loads
Active Valves Deadweight + Pressure Extended Structure: m 1.2S + HOSGRI/DDE + Nozzle/Piping Loads (m or L) + Operating Loads(12) + b 1.8S or Sy (higher of) Pressure Boundary: ANSI B16.5 or MSS-SP-66 Valve Nozzles: (5) Bolting: m 2.0S Inactive Valves Deadweight + Pressure Extended Structure: m 2.0S + HOSGRI/DDE + Nozzle/Piping Loads (m or L) + Operating Loads(12) + b 2.4S Pressure Boundary: ANSI B16.5 or MSS-SP-66 Valve Nozzles: (6) Bolting: m 2.0S DCPP UNITS 1 & 2 FSAR UPDATE Sheet 2 of 3 TABLE 3.9-2 Revision 11 November 1996 COMPONENT LOADING COMBINATIONS CRITERIA (2, 3) (4) (7, 8, 9, 10, 11, 12, 13, 14) Inactive Cast Iron Deadweight + Pressure p 0.1 Su Pressure Retaining + HOSGRI/DDE + Nozzle/Piping Loads (m or L) + b 2.4 x 0.1 Su Components + Operating Loads(12) Inactive Cast Iron Deadweight + Pressure (m or L) + b 2.0 x 0.2 Su Non-pressure Retaining + HOSGRI/DDE + Nozzle/Piping Loads Components + Operating Loads(12)
Notes: (1) See Chapter 5 Table 5.2-8 for structural components.
(2) Active: Mechanical equipment which is needed to go from normal full power operation to safe shutdown following the earthquake and which must perform mechanical motions during the course of accomplishing its design function. (3) Inactive: Mechanical Equipment which is not required to perform mechanical motions in taking the plant from normal full power operation to safe shutdown following the earthquake. (4) Nozzle loads shall include piping loads transmitted to the component during the HOSGRI/DDE earthquake.
(5) Piping loads at piping/active-valve interfaces shall be limited such that maximum fiber stresses in the piping at the interface are less than the piping yield strength at temperature (Sy). (6) Valves, being stronger than the attached piping and having a proven history without any gross failures of pressure boundaries, can safely transmit piping loads without compromising their pressure retaining integrity. Therefore piping integrity assures valve integrity. (7) m = General membrane stress. This stress is equal to the average stress across the solid section under consideration, excludes discontinuities and concentrations and is produced only by mechanical loads. DCPP UNITS 1 & 2 FSAR UPDATE Sheet 3 of 3 TABLE 3.9-2 Revision 11 November 1996 Notes: (Cont'd) (8) L = Local membrane stress. This stress is equal to the same as m except that it includes the effect of discontinuities.
(9) b = Bending stress. This stress is equal to the linear varying portion of the stress across the solid section under consideration, excludes discontinuities and concentrations, and is produced only by mechanical loads.
(10) S = 1971 or 1974 ASME Code allowable stress. The allowable stress shall correspond to the highest metal temperature at the section under consideration during the condition consideration. (11) Sy = 1971 or 1974 ASME Code minimum yield stress. The yield stress shall correspond to the highest metal temperature at the section under consideration during the condition consideration. (12) Except racked-out valves.
(13) p = Local membrane stress. This stress is equal to the average stress across the solid section under consideration. It excludes discontinuities and concentrations and is produced only by pressure.
(14) Su = Material minimum tensile strength listed in either the code the component was purchased and manufactured under, or ASME Code Section III. DCPP UNITS 1 & 2 FSAR UPDATE Sheet 1 of 2 TABLE 3.9-3 Revision 11 November 1996 HOSGRI AND DDE SEISMIC LOADING COMBINATIONS AND STRUCTURAL CRITERIA MECHANICAL EQUIPMENT SUPPORTS AND STRUCTURAL COMPONENT(1) ELEMENT LOADING COMBINATIONS CRITERIA (4, 5) (6, 7, 8, 9, 10, 11, 12, 13) Linear(3) Deadweight + HOSGRI/DDE 1974 ASME Code Appendix XVII, Subsection NF, and + Nozzle/Piping Loads Appendix F or AISC Manual, 7th Edition(11) (Stresses not to exceed Sy for active components supports) Plate and shell(2) Deadweight + HOSGRI/DDE m 1.2S (active components) + Nozzle/Piping Loads (m + b) 1.8S or Sy Plate and shell Deadweight + HOSGRI/DDE m 2.0S (inactive components) + Nozzle/Piping Loads (m + b) 2.4S Bolts Deadweight + HOSGRI/DDE 1974 ASME Code Section III, Appendix XVII, Code Case 1644-6
+ Nozzle/Piping Loads and Appendix F, or AISC Manual, 7th Edition
Notes:
(1) Includes reactor cavity manipulator crane, spent fuel pit bridge crane, flux mapping transfer devices and rcs seal table and parts. qualification of reactor cavity manipulator crane, spent fuel pit bridge crane, and flux mapping transfer device, not required for DDE (required for HOSGRI only in order to insure structural integrity and preclude seismic interaction). (2) Plate and shell type supports: Plate and shell type components supports are supports such as vessel skirts and saddles which are fabricated from plate and shell elements and are normally subjected to a biaxial stress field. DCPP UNITS 1 & 2 FSAR UPDATE Sheet 2 of 2 TABLE 3.9-3 Revision 11 November 1996 Notes (Continued): (3) Linear type support: A linear type component support is defined as acting under essentially as single components of direct stress. Such elements may also be subjected to shear stresses. Examples of such structural elements are: tension and compression struts, beams and columns subjected to bending, trusses, frames, rings, arches, and cables. (4) Nozzle loads shall be those nozzle loads acting on the supported components during the HOSGRI/DDE earthquake. (5) Plus operating loads, as applicable. (6) m = General membrane stress. This stress is equal to the average stress across the solid section under consideration, excludes discontinuities and concentrations and is produced only by mechanical loads. (7) b = Bending stress. This stress is equal to the linear varying portion of the stress across the solid section under consideration, excludes discontinuities and concentrations, and is produced only by mechanical loads. (8) S = 1971 or 1974 ASME Code allowable stress value. The allowable stress shall correspond to the highest metal temperature at the section under consideration during the condition under consideration. (9) Sy = 1971 or 1974 ASME Code minimum yield stress. The yield stress shall correspond to the highest metal temperature at the section under consideration during the condition under consideration. (10) For the reactor cavity manipulator crane, the spent fuel pit bridge crane, and the flux mapping transfer device, the stress limits for the above loading combinations are obtained by increasing the normal condition allowable stresses by a factor of 1.7. (11) The reference, "AISC Manual, 7th Edition," where used in this section, refers to the AISC Code, Part 5, "Specification for the Design, Fabrication and Erection of Structural Steel for Buildings," 1969 version. (12) p = Local membrane stress. This is equal to the average stress across the solid section under consideration. It excludes discontinuities and concentrations and is produced only by pressure. (13) Su = Material minimum tensile strength listed in either the code the component was purchased and manufactured under, or ASME Code Section III. DCPP UNITS 1 & 2 FSAR UPDATE Sheet 1 of 3 TABLE 3.9-4 Revision 11 November 1996 DE SEISMIC LOADING COMBINATIONS AND STRUCTURAL CRITERIA MECHANICAL EQUIPMENT(1) COMPONENT LOADING COMBINATIONS CRITERIA (2, 3) (4) (7, 8, 9, 10, 11, 12, 13, 14) Tanks, heat-exchangers Deadweight + Pressure m 1.0S(13) filters, demineralizers + DE + Nozzle/Piping Loads. (m or L) + b 1.65S Active pumps Deadweight + Pressure m 1.1S + DE + Nozzle/Piping Loads (m or L) + b 1.65S + Operating Loads.
Inactive pumps Deadweight + Pressure m 1.1S + DE + Nozzle/Piping Loads (m or m) + b 1.65S + Operating Loads.
Active valves Deadweight + Pressure Extended structure: m 1.1S + DE + Nozzle/Piping Loads (m or L) + Operating Loads.(12) + b 1.0Sy Pressure boundary: ANSI B16.5 or MSS-SP-66 valve nozzles: (6) bolting: b 2.0S Inactive valves Deadweight + Pressure Extended structure: b 1.1S + DE + Nozzle/Piping Loads (m or L) + Operating Loads.(12) + b 1.0Sy Pressure boundary: ANSI B16.5 or MSS-SP-66 valve nozzles: (6) bolting: m 2.0S DCPP UNITS 1 & 2 FSAR UPDATE Sheet 2 of 3 TABLE 3.9-4 Revision 11 November 1996 COMPONENT LOADING COMBINATIONS CRITERIA (2, 3) (4) (7, 8, 9, 10, 11, 12, 13, 14) Inactive cast iron, Deadweight + Pressure p 0.1 Su pressure retaining + DE + Nozzle/Piping Loads (m or L) + b 1.5 x 0.1 Su components + Operating Loads(12) Inactive cast iron Deadweight + Pressure non-pressure retaining + DE + Nozzle/Piping Loads (m or L) + b 1.0 x 0.2 Su Components + Operating Loads(12) Notes: (1) See Chapter 5, Table 5.2.8 for sructural components. (2) Active: Mechanical equipment which is needed to go from normal full power operation to safe shutdown following the earthquake and which must perform mechanical motions during the course of accomplishing its design function. (3) Inactive: Mechanical equipment which is not required to perform mechanical motions in taking the plant from normal full power operations to safe shutdown following the earthquake. (4) Nozzle loads shall include piping loads transmitted to the component during the DE earthquake. (5) Deleted. (6) Valves, being stronger than the attached piping and having a proven history without any gross failures of pressure boundaries, can safely transmit piping loads without compromising their pressure retaining integrity. Therefore, piping integrity assures valve integrity. (7) m = General membrane stress. This stress is equal to the average stress across the solid section under consideration, excludes discontinuities and concentrations and is produced only by mechanical loads. (8) L = Local membrane stress. This stress is the same as m except that it includes the effect of discontinuities. DCPP UNITS 1 & 2 FSAR UPDATE Sheet 3 of 3 TABLE 3.9-4 Revision 11 November 1996 Notes (Continued): (9) b = Bending stress. The stress is equal to the linear varying portion of the stress across the solid section under consideration, excludes discontinuities and concentrations, and is produced only by mechanical loads. (10) Sy = 1971 or 1974 ASME code allowable stress value. The allowable stress shall correspond to the highest metal temperature at the section under consideration during the condition under consideration. (11) Except racked-out valves.
(12) The primary membrane stress limit for pressure vessels under DE loading is conservatively selected to be lower than the level permitted by the present ASME Code, in order to insure that it is also conservative with respect to earlier editions of the code of which these components were designed. (13) p = Local membrane stress. This is equal to the average stress across the solid section under consideration. It excludes discontinuities and concentrations and is produced only by pressure. (14) Su = Material minimum tensile strength listed in either the code the component was purchased and manufactured under, or ASME Code Section III. DCPP UNITS 1 & 2 FSAR UPDATE Sheet 1 of 2 TABLE 3.9-5 Revision 11 November 1996 DE SEISMIC LOADING COMBINATION STRUCTURAL CRITERIA MECHANICAL EQUIPMENT SUPPORTS AND STRUCTURAL COMPONENTS(1) ELEMENT LOADING COMBINATIONS CRITERIA (2, 3) (4,5) (6,7, 8) Linear(3) Deadweight + DE + Pressure 1974 ASME Code Section III Appendix XVII, + Nozzle/Piping Loads Subsection NF or AISC Manual, 7th Edition. Plate and shell(2) Deadweight + DE + Pressure m 1.0S (active components) + Nozzle/Piping Loads (m + b) 1.5S Plate and shell Deadweight + DE + Pressure m 1.0S (inactive components) + Nozzle/Piping Loads (m + b) 1.5S Bolts Deadweight + DE + Pressure 1974 ASME Code Section III Appendix XVII, Code
+ Nozzle/Piping Loads Case 1644-6 or AISC Manual, 7th Edition.
DCPP UNITS 1 & 2 FSAR UPDATE Sheet 2 of 2 TABLE 3.9-5 Revision 11 November 1996 Notes: (1) Includes RCS seal table and parts. Qualification of reactor cavity manipulator crane and spent fuel pit bridge crane and flux mapping transfer device not required for DE. Structural integrity insured by HOSGRI qualification. (2) Plate and shell type supports: Plate and shell type component supports are supports such as vessel skirts and saddles which are fabricated from plate and shell elements and are normally subjected to a biaxial stress field. (3) Linear type support: A linear type component support is defined as acting under essentially a single component of direct stress. Such elements may also be subjected to shear stresses. Examples of such structural elements are: tension and compression struts, beams and columns subjected to bending, trusses, frames, rings, arches, and cables. (4) Nozzle loads shall be those nozzle loads acting on the supported component during the DE earthquake.
(5) Plus Operating Loads, as applicable.
(6) m = General membrane stress. This stress is equal to the average stress across the solid section under consideration, excludes discontinuities and concentrations and is produced only by mechanical loads. (7) b = Bending stress. This stress is equal to the linear varying portion of the stress across the solid section under consideration, excludes discontinuities and concentrations, and is produced only by mechanical loads.
(8) Sy = 1971 or 1974 code allowable stress value. The allowable stress shall correspond to the highest metal temperature at the section under consideration during the condition under consideration.
DCPP UNITS 1 & 2 FSAR UPDATE Sheet 1 of 3 TABLE 3.9-6 Revision 11 November 1996 NORMAL CONDITIONS LOADING COMBINATIONS AND STRUCTURAL CRITERIA MECHANICAL EQUIPMENT(1) COMPONENT LOADING COMBINATIONS CRITERIA (2, 3) (4) (7, 8, 9, 10, 11, 12, 13) Tanks, heat-exchangers Deadweight + Pressure + Nozzle/ m 1.0S filters, demineralizers Piping Loads. (m or L) + b 1.5S Active pumps Deadweight + Pressure + Nozzle/ m 1.0S Piping Loads + Operating Loads. (m or L) + b 1.5S Inactive pumps Deadweight + Pressure + Nozzle/ m 1.0S Piping Loads + Operating Loads. (m or L) + b 1.5S Active valves Deadweight + Pressure + Nozzle/ Extended Structure: m 1.0S Piping Loads + Operating Loads. (m or L) + b 1.5S Pressure Boundary: ANSI B16.5 or MSS-SP-66 Valve Nozzles: (6) Bolting: m 2.0S Inactive valves Deadweight + Pressure + Nozzle/ Extended Structure: m 1.1S Piping Loads + Operating Loads. (m or L) + b 1.5S Pressure Boundary: ANSI B16.5 or MSS-SP-66 Valve Nozzles: (6) Bolting: m 2.0S DCPP UNITS 1 & 2 FSAR UPDATE Sheet 2 of 3 TABLE 3.9-6 Revision 11 November 1996 COMPONENT LOADING COMBINATIONS CRITERIA (2, 3) (4) (7, 8, 9, 10, 11, 12, 13) Inactive cast iron, Deadweight + Pressure p 0.1 Su pressure retaining + Nozzle/Piping Loads (m or L) + b 1.5 x 0.1 Su Components + Operating Loads(12) Inactive cost iron Deadweight + Pressure (m or L) + b 1.0 x 0.2 Su non-pressure retaining + Nozzle/Piping Loads Components + Operating Loads(12) Notes: (1) See Chapter 5, Table 5.2.8 for structural components.
(2) Active: Mechanical equipment which is needed to go from normal full power operation to safe shutdown following the earthquake and which must perform mechanical motions during the course of accomplishing its design function. (3) Inactive: Mechanical equipment which is not required to perform mechanical motions in taking the plant from normal full power operations to safe shutdown following the earthquake. (4) Nozzle loads shall include piping loads transmitted to the component during the normal conditions.
(5) Deleted.
(6) Valves, being stronger than the attached piping and having a proven history without any gross failures of pressure boundaries, can safely transmit piping loads without compromising their pressure retaining integrity. Therefore, piping integrity assures valve integrity. DCPP UNITS 1 & 2 FSAR UPDATE Sheet 3 of 3 TABLE 3.9-6 Revision 11 November 1996 Notes (Continued): (7) m = General membrane stress. This stress is equal to the average stress across the solid section under consideration, excludes discontinuities and concentrations and is produced only by mechanical loads. (8) L = Local membrane stress. This stress is the same as m except that it includes the effect of discontinuities. (9) b = Bending stress. The stress is equal to the linear varying portion of the stress across the solid section under consideration, excludes discontinuities and concentrations, and is produced only by mechanical loads. (10) S = 1971 or 1974 ASME code allowable stress value. The allowable stress shall correspond to the highest metal temperature at the section under consideration during the condition under consideration. (11) Sy = 1971 or 1974 ASME code yield stress value. The yield stress shall correspond to the highest metal temperature at the section under consideration during the condition under consideration. (12) Sp = Local membrane stress. This is equal to the average stress across the solid section under consideration. It excludes discontinuities and concentrations and is produced only by pressure. (13) Su = Material minimum tensile strength listed in either the code the component was purchased and manufactured under, or ASME Code Section III. DCPP UNITS 1 & 2 FSAR UPDATE Sheet 1 of 2 TABLE 3.9-7 Revision 11 November 1996 NORMAL CONDITIONS LOADING COMBINATIONS AND STRUCTURAL CRITERIA MECHANICAL EQUIPMENT SUPPORTS AND STRUCTURAL COMPONENTS(1) ELEMENT LOADING COMBINATIONS CRITERIA (4, 5) (6, 7, 8) Linear(3) Deadweight + Nozzle/Piping Loads 1974 ASME Code Appendix XVII, Subsection NF or AISC Manual, 7th Edition
Plate and shell(2) Deadweight + Nozzle/Piping Loads m 1.0S (and/or 1974 ASME Code, (active components) (m + b) 1.5S Subsection NF) Plate and shell Deadweight + Nozzle/Piping Loads m 1.0S (and/or 1974 ASME Codes, (inactive components) (m + b) 1.5S Subsection NF) Bolts Deadweight + Nozzle/Piping Loads 1974 ASME Code Appendix XVII, Code Case 1644-6 or AISC Manual, 7th Edition DCPP UNITS 1 & 2 FSAR UPDATE Sheet 2 of 2 TABLE 3.9-7 Revision 11 November 1996 Notes: (1) Includes RCS seal table and parts. Qualification of reactor cavity manipulator crane and spent fuel pit bridge crane and flux mapping transfer device not required for DE. Structural integrity insured by HOSGRI qualification. (2) Plate and shell type supports: Plate and shell type component supports are supports such as vessel skirts and saddles which are fabricated from plate and shell elements and are normally subjected to a biaxial stress field. (3) Linear type support: A linear type component support is defined as acting under essentially a single component of direct stress. Such elements may also be subjected to shear stresses. Examples of such structural elements are: tension and compression struts, beams and columns subjected to bending, trusses, frames, rings, arches, and cables. (4) Nozzle loads shall be those nozzle loads acting on the supported component during the normal conditions.
(5) Plus Operating Loads, as applicable.
(6) m = General membrane stress. This stress is equal to the average stress across the solid section under consideration, excludes discontinuities and concentrations and is produced only by mechanical loads. (7) b = B ending stress. This stress is equal to the linear varying portion of the stress across the solid section under consideration, excludes discontinuities and concentrations, and is produced only by mechanical loads.
(8) S = 1971 or 1974 code allowable stress value. The allowable stress shall correspond to the highest metal temperature at the section under consideration during the condition under consideration. DCPP UNITS 1 & 2 FSAR UPDATE Sheet 1 of 3 TABLE 3.9-8 Revision 11 November 1996 TANK DESIGN ASME Code Storage Design Tank Plate Allowable Design Function Code Material Stress, (psi) Code Boric acid ASME Sec. VIII, Div. 1 ASTM A240 T304 16,000 ASME Sec. VIII, Div. 1 (no code stamp)
Liquid holdup ASME Sec. III, Class C ASTM A240 T304 16,000 ASME Sec. VIII, Div. 1
Component cooling water surge ASME Sec. VIII, ASTM A285 Gr. C 13,750 ASME Sec. VIII, Div. 1
Waste gas decay ASME Sec. III, Class C ASTM A285 Gr. C 13,750 ASME Sec. VIII, Div. 1
Diesel fuel oil storage UL 58 ASTM A36 12,650 ASME Sec. VIII, Div. 1 (underground)
Volume control ASME Sec. III, Class C ASTM A240 T304 16,000 ASME Sec. VIII, Div. 1
DCPP UNITS 1 & 2 FSAR UPDATE Sheet 2 of 3 TABLE 3.9-8 Revision 11 November 1996 ASME Code Storage Design Tank Plate Allowable Design Function Code Material Stress, (psi) Code Accumulator ASME Sec. III, Class C ASTM A516 Gr. 70 17,500 ASME Sec. VIII, Div. 1 W/ A240 T304 Cladding
Boron injection ASME Sec. III, Class C ASTM A516 Gr. 70 17,500 ASME Sec. VIII, Div. 1 W/ A240 T304L Cladding Spray additive ASME Sec. VIII, Div. 1 ASTM A240 T304 16,000 ASME Sec. VIII, Div. 1 (no code stamp)
Transfer storage & firewater AWWA D100 ASTM A516 Gr. 60 19,500 ASME Sec. VIII, Div. 2
Reactor coolant ASME Sec. III, Class C ASTM A240 T304 16,000 ASME Sec. VIII, Div. 1 drain tank
Waste concentrates holding ASME Sec. III, Class C ASTM A240 T304 16,000 ASME Sec. VIII, Div. 1
DCPP UNITS 1 & 2 FSAR UPDATE Sheet 3 of 3 TABLE 3.9-8 Revision 11 November 1996 ASME Code Storage Design Tank Plate Allowable Design Function Code Material Stress, (psi) Code Spent Resin Storage ASME Sec. III, Class C ASTM A240 T304 16,000 ASME Sec. VIII, Div. 1
Equipment Drain Receiver ASME Sec. VIII, Div. 1 ASTM A240 T304 16,000 ASME Sec. VIII, Div. 1 (no code stamp)
- 1. ASME Section III - American Society of Mechanical Engineers, Boiler and Pressure Vessel, Section III (1968, 1971). 2. ASME Section VIII - American Society of Mechanical Engineers, Boiler and Pressure Vessel Code, Section VIII (1968, 1971) Div. 1. 3. UL Underwriters Standards, Steel Underground Tanks for Flammable and Combustible Liquids.
- 4. AWWAD100 - American Waterworks Association, Standard for Steel Tanks, Standpipes Reservoirs and Elevated Tanks for Water Storage.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 1 of 25 Revision 19 May 2010 LIST OF ACTIVE VALVES Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments AUX FW PUMP 1 FCV-15 3.2-4 Globe - Speed NA Open 11 TURBINE GOV Governor MSIV BYPASS - LEAD 4 FCV-22 3.2-4 Globe 3 Air Closed Closed MSIV BYPASS - LEAD 3 FCV-23 3.2-4 Globe 3 Air Closed Closed MSIV BYPASS - LEAD 2 FCV-24 3.2-4 Globe 3 Air Closed Closed MSIV BYPASS - LEAD 1 FCV-25 3.2-4 Globe 3 Air Closed Closed MAIN STM LEAD 2 TO FCV-37 3.2-4 Gate 4 Motor FA Operable 10, 25 AUX FW PUMP 1 TURBINE MAIN STM LEAD 3 TO FCV-38 3.2-4 Gate 4 Motor FA Operable 10, 25 AUX FW PUMP 1 TURBINE MAIN STEAM FCV-41 3.2-4 Swing 28 Air See Closed 7 ISOL LEAD 1 Check Note 7 MAIN STEAM FCV-42 3.2-4 Swing 28 Air See Closed 7 ISOL LEAD 2 Check Note 7 MAIN STEAM FCV-43 3.2-4 Swing 28 Air See Closed 7 ISOL LEAD 3 Check Note 7 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 2 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments MAIN STEAM FCV-44 3.2-4 Swing 28 Air See Closed 7 ISOL LEAD 4 Check Note 7 MN STM TO AUX FCV-95 3.2-4 Gate 4 Motor FA Open 11 FW PUMP 1 TURBINE BORIC ACID BLENDER INLET FCV-110A 3.2-8 Globe 2 Air Open Open 23 STEAM GEN NO. 1 FCV-151 3.2-8 Globe 3 Air Closed Closed TO BLOWDN TANK AUX FP TURB 1 STM INLET FCV-152 3.2-4 Globe 4 Manual NA Open 11 STEAM GEN NO. 2 FCV-154 3.2-4 Globe 3 Air Closed Closed TO BLOWDN TANK STEAM GEN NO. 3 FCV-157 3.2-4 Globe 3 Air Closed Closed TO BLOWDN TANK STEAM GEN NO. 4 FCV-160 3.2-4 Globe 3 Air Closed Closed TO BLOWDN TANK CTMT H2 SAMPLE FCV-235 3.2-23 Globe 3/8 Solenoid Closed Operable SUPPLY IN CTMT CTMT H2 SAMPLE FCV-236 3.2-23 Globe 3/8 Solenoid Closed Operable SUPPLY OUT CTMT DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 3 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments CTMT H2 SAMPLE FCV-237 3.2-23 Globe 3/8 Solenoid Closed Operable RETURN OUT CTMT CTMT H2 SAMPLE FCV-238 3.2-23 Globe 3/8 Solenoid Closed Operable SUPPLY IN CTMT CTMT H2 SAMPLE FCV-239 3.2-23 Globe 3/8 Solenoid Closed Operable SUPPLY OUT CTMT CTMT H2 SAMPLE FCV-240 3.2-23 Globe 3/8 Solenoid Closed Operable RETURN OUT CTMT STM GEN 4 BD FCV-244 3.2-4 Globe 3/4 Air Closed Closed SAMPLE OS CNTMT STM GEN 3 BD FCV-246 3.2-4 Globe 3/4 Air Closed Closed SAMPLE OS CNTMT STM GEN 2 BD FCV-248 3.2-4 Globe 3/4 Air Closed Closed SAMPLE OS CNTMT STM GEN 1 BD FCV-250 3.2-4 Globe 3/4 Air Closed Closed SAMPLE OS CNTMT RC DRN PPS FCV-253 3.2-19 Ball 2-1/2 Air Closed Closed DISCH IN CNTMT RC DRN PPS FCV-254 3.2-19 Ball 2-1/2 Air Closed Closed DISCH OUT CNTMT DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 4 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments RC DRN TANK VENT HEADER FCV-255 3.2-19 Ball 3/4 Air Closed Closed IN CONTAINMENT RC DRN TANK VENT HEADER FCV-256 3.2-19 Ball 3/4 Air Closed Closed OUT CONTAINMENT RC DRN TANK GAS ANALYZER FCV-257 3.2-19 Ball 1/2 Air Closed Closed OUT CONTAINMENT RC DRN TANK GAS ANALYZER FCV-258 3.2-19 Ball 1/2 Air Closed Closed IN CONTAINMENT RC DRN TANK N2 SUPPLY FCV-260 3.2-19 Ball 3/4 Air Closed Closed OUT CONTAINMENT CCW SUPPLY HEADER C FCV-355 3.2-14 B'fly 20 Motor FAI Closed CCW TO RC PUMPS FCV-356 3.2-14 B'fly 10 Motor FAI Closed RCP THERMAL BARRIER FCV-357 3.2-14 Globe 6 Motor FAI Closed CCW RETURN EXCESS LETDOWN FCV-361 3.2-14 B'fly 4 Air Closed Closed HT EXCH CCW RETURN RCP OIL COOLER FCV-363 3.2-14 B'fly 6 Motor FAI Closed CCW RETURN RHR HT EXCHANGER 2 FCV-364 3.2-14 B'fly 12 Air 21 Functional 10 CCW RETURN DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 5 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments RHR HT EXCHANGER 3 FCV-365 3.2-14 B'fly 12 Air 21 Functional 10 CCW RETURN CCW SUPPLY HEADER A FCV-430 3.2-14 B'fly 30 Motor FAI Open CCW SUPPLY HEADER B FCV-431 3.2-14 B'fly 30 Motor FAI Open RAW WATER STG RES FCV-436 3.2-3 B'fly 8 Manual FAI Open AUX FEED PUMP 1 RAW WATER STG RES FCV-437 3.2-3 B'fly 8 Manual FAI Open AUX FEED PUMPS 2 & 3 MAIN FEEDWATER FCV-438 3.2-3 Gate 16 Motor FAI Closed 5 ISOLATION LEAD 1 MAIN FEEDWATER FCV-439 3.2-3 Gate 16 Motor FAI Closed 5 ISOLATION LEAD 2 MAIN FEEDWATER FCV-440 3.2-3 Gate 16 Motor FAI Closed 5 ISOLATION LEAD 3 MAIN FEEDWATER FCV-441 3.2-3 Gate 16 Motor FAI Closed 5 ISOLATION LEAD 4 AUX SALTWATER FCV-495 3.2-17 B'fly 24 Motor FAI Operable PUMPS CROSS AUX. SALTWATER FCV-496 3.2-17 B'fly 24 Motor FAI Operable PUMPS CROSS DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 6 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments CNT BLDG SUMP PP FCV-500 3.2-19 Ball 2 Air Closed Closed DISCHARGE IN CNTMT CNT BLDG SUMP PP FCV-501 3.2-19 Ball 2 Air Closed Closed DISCHARGE OUT CNTMT STEAM GEN 1 FCV-510 3.2-3 Globe 16 Air Closed Closed MAIN FW SUPPLY STEAM GEN 2 FCV-520 3.2-3 Globe 16 Air Closed Closed MAIN FW SUPPLY STEAM GEN 3 FCV-530 3.2-3 Globe 16 Air Closed Closed MAIN FW SUPPLY STEAM GEN 4 FCV-540 3.2-3 Globe 16 Air Closed Closed MAIN FW SUPPLY CNT WEST FCV-584 3.2-25 Ball 2 Air Closed Closed INSTRUMENT AIR AUX SW TO CCW FCV-602 3.2-17 B'fly 24 Air Open 21, 22 HT EXCH NO. 1 AUX SW TO CCW FCV-603 3.2-17 B'fly 24 Air Open 21, 22 HT EXCH NO. 2 CNTMT FIRE WATER FCV-633 3.2-18 Globe 3 Air Closed 21, 22 ISOLATION
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 7 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments RHR PUMP 1 RECIRC FCV-641A 3.2-10 Globe 2 Motor FAI Functional RHR PUMP 2 RECIRC FCV-641B 3.2-10 Globe 2 Motor FAI Functional CNTMT ISO CHPS EXHAUST FCV-658 3.2-23 Gate 4 Motor FAI Functional CNTMT ISO CHPS EXHAUST FCV-659 3.2-23 Gate 4 Motor FAI Functional CONT PURGE SUPPLY IC FCV-660 3.2-23 B'fly 48 Air Closed Closed CONT PURGE SUPPLY OC FCV-661 3.2-23 B'fly 48 Air Closed Closed CONT VAC/PRESS RELIEF 1C FCV-662 3.2-23 B'fly 12 Air Closed Closed CONT PRESSURE RELIEF OC FCV-663 3.2-23 B'fly 12 Air Closed Closed CONT VACUUM RELIEF OC FCV-664 3.2-23 B'fly 12 Air Closed Closed CNTMT ISO CHPS EXHAUST FCV-668 3.2-23 Gate 4 Motor FAI Functional CNTMT ISO CHPS EXHAUST FCV-669 3.2-23 Gate 4 Motor FAI Functional CNT AIR SAMPLE FCV-678 3.2-23 Ball 1 Air Closed Closed 5 (INSIDE CNT) CNT AIR SAMPLE FCV-679 3.2-23 Ball 1 Air Closed Closed 5 (OUTSIDE CNT)
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 8 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments CNT AIR SAMPLE FCV-681 3.2-23 Ball 1 Air Closed Closed 5 (OUTSIDE CNT) POST-LOCA SAMPLING SYST FCV-696 3.2-19 Globe 3/8 Solenoid Closed Closed 5 POST-LOCA SAMPLING SYST FCV-697 3.2-19 Globe 3/8 Solenoid Closed Closed 5 POST-LOCA SAMPLING SYST FCV-698 3.2-23 Globe 3/8 Solenoid Closed Closed 5 POST-LOCA SAMPLING SYST FCV-699 3.2-23 Globe 3/8 Solenoid Closed Closed 5 POST-LOCA SAMPLING SYST FCV-700 3.2-23 Globe 3/8 Solenoid Closed Closed 5 RCP OIL COOLER FCV-749 3.2-14 B'fly 6 Motor FAI Closed CCW RETURN RCP THERMAL FCV-750 3.2-14 Globe 6 Motor FAI Closed BARRIER CCW RETURN STEAM GEN NO. 1 FCV-760 3.2-4 Globe 3 Air Closed Closed BLOWDOWN AND SAMPLE STEAM GEN NO. 2 FCV-761 3.2-4 Globe 3 Air Closed Closed BLOWDOWN AND SAMPLE STEAM GEN NO. 3 FCV-762 3.2-4 Globe 3 Air Closed Closed BLOWDOWN AND SAMPLE
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 9 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments STEAM GEN NO. 4 FCV-763 3.2-4 Globe 3 Air Closed Closed BLOWDOWN AND SAMPLE STEAM GEN NO. 1 MAIN FCV-1510 3.2-3 Globe 6 Air Closed Closed FW SUPPLY BY-PASS STEAM GEN NO. 2 MAIN FCV-1520 3.2-3 Globe 6 Air Closed Closed FW SUPPLY BY-PASS STEAM GEN NO. 3 MAIN FCV-1530 3.2-3 Globe 6 Air Closed Closed FW SUPPLY BY-PASS STEAM GEN NO. 4 MAIN FCV-1540 3.2-3 Globe 6 Air Closed Closed FW SUPPLY BY-PASS CHG PUMPS DISCH TO HCV-142 3.2-4 Globe 3 Air Closed 21 23 REGEN HT EXCH RHR TO COLD LEGS 3 & 4 HCV-637 3.2-10 Ball 8 Air Open Open RHR TO COLD LEGS 1 & 2 HCV-638 3.2-10 Ball 8 Air Open Open DSL FO DAY TK 1-2 HEADER B LCV-85 3.2-21 Ball 1-1/2 Air Closed Functional DSL FO DAY TK 2-1 HEADER B LCV-86 3.2-21 Ball 1-1/2 Air Closed Functional DSL FO DAY TK 1-3 HEADER B LCV-87 3.2-21 Ball 1-1/2 Air Closed Functional DSL FO DAY TK 1-2 HEADER A LCV-88 3.2-21 Ball 1-1/2 Air Closed Functional DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 10 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments DSL FO DAY TK 2-1 HEADER A LCV-89 3.2-21 Ball 1-1/2 Air Closed Functional DSL FO DAY TK 1-3 HEADER A LCV-90 3.2-21 Ball 1-1/2 Air Closed Functional AUX FEEDWATER FROM LCV-106 3.2-3 Globe 2 Motor FAI Operable 4 TURB AFW PP TO SG 1 AUX FEEDWATER FROM LCV-107 3.2-3 Globe 2 Motor FAI Operable 4 TURB AFW PP TO SG 2 AUX FEEDWATER FROM LCV-108 3.2-3 Globe 2 Motor FAI Operable 4 TURB AFW PP TO SG 3 AUX FEEDWATER FROM LCV-109 3.2-3 Globe 2 Motor FAI Operable 4 TURB AFW PP TO SG 4 AUX FEEDWATER FROM LCV-110 3.2-3 Globe 2 Electro Open Operable 4 MOTOR AFW PP TO SG 1 Hydraulic AUX FEEDWATER FROM LCV-111 3.2-3 Globe 2 Electro Open Operable 4 MOTOR AFW PP TO SG 2 Hydraulic VOLUME CONTROL TANK LCV-112B 3.2-8 Gate 4 Motor FAI Closed 5 TO CHARG PUMPS VOLUME CONTROL TANK LCV-112C 3.2-8 Gate 4 Motor FAI Closed 5 TO CHARG PUMPS AUX FEEDWATER FROM LCV-113 3.2-3 Globe 2 Electro Open Operable 4 MOTOR AFW PP TO SG 4 Hydraulic DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 11 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments AUX FEEDWATER FROM LCV-115 3.2-3 Globe 2 Electro Open Operable 4 MOTOR AFW PP TO SG 3 Hydraulic STEAM GEN 1 PCV-19 3.2-4 Globe 8 Air Closed Functional 10% ATM STM DUMP 21 STEAM GEN 2 PCV-20 3.2-4 Globe 8 Air Closed Functional 10% ATM STM DUMP 21 STEAM GEN 3 PCV-21 3.2-4 Globe 8 Air Closed Functional 10% ATM STM DUMP 21 STEAM GEN 4 PCV-22 3.2-4 Globe 8 Air Closed Functional 10% ATM STM DUMP 21 PRESSURIZER POWER- PCV-455C 3.2-7 Globe 3 Air Closed Functional 8,12 OPERATED RELIEF 21 PRESSURIZER POWER- PCV-456 3.2-7 Globe 3 Air Closed Functional 8,12 OPERATED RELIEF 21 CONT PURGE EXHAUST 1C RCV-11 3.2-23 B'fly 48 Air Closed Closed CONT PURGE EXHAUST OC RCV-12 3.2-23 B'fly 48 Air Closed Closed MAIN STM SAFETY LEAD 1 RV-3 3.2-4 Relief 6 Spring NA Operable 9 MAIN STM SAFETY LEAD 1 RV-4 3.2-4 Relief 6 Spring NA Operable 9 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 12 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments MAIN STM SAFETY LEAD 1 RV-5 3.2-4 Relief 6 Spring NA Operable 9 MAIN STM SAFETY LEAD 1 RV-6 3.2-4 Relief 6 Spring NA Operable 9 MAIN STM SAFETY LEAD 2 RV-7 3.2-4 Relief 6 Spring NA Operable 9 MAIN STM SAFETY LEAD 2 RV-8 3.2-4 Relief 6 Spring NA Operable 9 MAIN STM SAFETY LEAD 2 RV-9 3.2-4 Relief 6 Spring NA Operable 9 MAIN STM SAFETY LEAD 2 RV-10 3.2-4 Relief 6 Spring NA Operable 9 MAIN STM SAFETY LEAD 3 RV-11 3.2-4 Relief 6 Spring NA Operable 9 MAIN STM SAFETY LEAD 3 RV-12 3.2-4 Relief 6 Spring NA Operable 9 MAIN STM SAFETY LEAD 3 RV-13 3.2-4 Relief 6 Spring NA Operable 9 MAIN STM SAFETY LEAD 3 RV-14 3.2-4 Relief 6 Spring NA Operable 9 CCW SURGE TK RV RV-45 3.2-14 Relief 3 Spring NA Operable MAIN STM SAFETY LEAD 4 RV-58 3.2-4 Relief 6 Spring NA Operable 9 MAIN STM SAFETY LEAD 4 RV-59 3.2-4 Relief 6 Spring NA Operable 9 MAIN STM SAFETY LEAD 4 RV-60 3.2-4 Relief 6 Spring NA Operable 9 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 13 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments MAIN STM SAFETY LEAD 4 RV-61 3.2-4 Relief 6 Spring NA Operable 9 MAIN STM SAFETY LEAD 1 RV-222 3.2-4 Relief 6 Spring NA Operable 9 MAIN STM SAFETY LEAD 2 RV-223 3.2-4 Relief 6 Spring NA Operable 9 MAIN STM SAFETY LEAD 3 RV-224 3.2-4 Relief 6 Spring NA Operable 9 MAIN STM SAFETY LEAD 4 RV-225 3.2-4 Relief 6 Spring NA Operable 9 FIRE WATER TANK CROSSTIE 8X42B 3.2-18 Gate 8 Manual NA Open (FP-0-306) FIRE WATER TANK 8X42B 3.2-18 Gate 8 Manual NA Open CROSSTIE BYPASS (FP-0-307) PRESSURIZER POWER 8000A 3.2-7 Gate 3 Motor FAI Operable RELIEF ISO PRESSURIZER POWER 8000B 3.2-7 Gate 3 Motor FAI Operable RELIEF ISO PRESSURIZER POWER 8000C 3.2-7 Gate 3 Motor FAI Operable RELIEF ISO PRESSURIZER SAFETY 8010A 3.2-7 R.V. 6 Spring NA Functional 9 PRESSURIZER SAFETY 8010B 3.2-7 R.V. 6 Spring NA Functional 9 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 14 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments PRESSURIZER SAFETY 8010C 3.2-7 R.V. 6 Spring NA Functional 9 PRESSURIZER RELIEF 8029 3.2-7 Ball 3 Air Closed Closed TK PRIMARY WTR PRESSURIZER RELIEF 8034A 3.2-7 Globe 3/8 Air Closed Closed TK GAS ANALYZER IC PRESSURIZER RELIEF 8034B 3.2-7 Globe 3/8 Air Closed Closed TK GAS ANALYZER OC PRESSURIZER RELIEF 8045 3.2-7 Dia- 3/4 Air Closed Closed TK N2 SUPPLY phragm REACTOR VESSEL 8078A 3.2-7 Globe 1 Solenoid Closed Operable HEAD VENT SYS REACTOR VESSEL 8078B 3.2-7 Globe 1 Solenoid Closed Operable HEAD VENT SYS REACTOR VESSEL 8078C 3.2-7 Globe 1 Solenoid Closed Operable HEAD VENT SYS REACTOR VESSEL 8078D 3.2-7 Globe 1 Solenoid Closed Operable HEAD VENT SYS REACTOR COOL PPS 8100 3.2-7 Gate 4 Motor FAI Closed SEAL WTR RET
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 15 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments BORIC ACID TO 8104 3.2-8 Globe 2 Motor FAI Operable CHARGING PPS CENTRIFUGAL I 8105 3.2-8 Globe 2 Motor FAI Functional 5 CHG PPS RECRC CENTRIFUGAL 8106 3.2-8 Globe 2 Motor FAI Functional 5 CHG PPS RECRC CHG PPS DISCH 8107 3.2-8 Gate 3 Motor FAI Functional TO LETDOWN HX CHG PPS DISCH 8108 3.2-8 Gate 3 Motor FAI Functional TO LETDOWN HX REACT COOL PPS 8112 3.2-8 Gate 4 Motor FAI Closed SEAL WTR RET LETDOWN LINE RV 8117 3.2-8 Relief 2 Spring Open Closed RCP SEAL WTR RTN RV 8121 3.2-8 Relief 2 Spring Open Closed SEAL WTR HX INLET RV 8123 3.2-8 Relief 2 Spring Open Closed CHARGING PUMP 8125 3.2-8 Relief 3/4 Spring Open Closed SUCTION HEADER PRESSURIZER AUX SPRAY 8145 3.2-8 Globe 2 Air Closed Operable 21 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 16 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments CHG PUMP TO 8146 3.2-8 Globe 3 Air Open Operable LOOP 4 COLD LEG 21 CHG PUMP TO 8147 3.2-8 Globe 3 Air Open Operable LOOP 3 COLD LEG 21 RCS PRESSURIZER 8148 3.2-8 Globe 2 Air Closed Operable AUX SPRAY 21 LETDOWN LINE ISOL 8149A 3.2-8 Globe 2 Air Closed Closed LETDOWN LINE ISOL 8149B 3.2-8 Globe 2 Air Closed Closed LETDOWN LINE ISOL 8149C 3.2-8 Globe 2 Air Closed Closed LETDOWN LINE ISOL 8152 3.2-8 Globe 2 Air Closed Closed CCP 1 FCV-128 8387B 3.2-8 Globe 3 Manual NA Functional 23 MANUAL BYPASS CCP 2 FCV-128 8387C 3.2-8 Globe 3 Manual NA Functional 23 MANUAL BYPASS HCV-142 MANUAL BYPASS 8403 3.2-8 Globe 3 Manual NA Functional 23 MANUAL EMERGENCY 8471 3.2-08 Diaphragm 2 Manual NA Functional 23 BORATE VALVE DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 17 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments BA TRANSFER PUMP 8476 3.2-8 Diaphragm 2 Manual NA Open 23 SUCTION CROSSTIE RHR PP 1 SUCT 8700A 3.2-10 Gate 14 Motor FAI Operable RHR PP 2 SUCT 8700B 3.2-10 Gate 14 Motor FAI Operable RHR SUCTION FROM 8701 3.2-10 Gate 14 Motor FAI Operable LOOP 4 HOT LEG RHR SUCTION FROM 8702 3.2-10 Gate 14 Motor FAI Operable LOOP 4 HOT LEG RHR DISCHARGE TO 8703 3.2-10 Gate 12 Motor FAI Functional 10, 19 HOT LEGS 1 & 2 RHR SUCTION PIPING RV 8707 3.2-10 Relief 3 Spring Open Closed RHR COOLDOWN LINE RV 8708 3.2-10 Relief 3/4 Spring Open Closed RHR HT EXCH 1 TO 8716A 3.2-10 Gate 8 Motor FAI Operable RCS HOT LEGS 1 & 2 RHR HT EXCH 2 TO 8716B 3.2-10 Gate 8 Motor FAI Operable RCS HOT LEGS 1 & 2 CHARGING INJECT 8801A 3.2-9 Gate 4 Motor FAI Open LINE DISCHARGE DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 18 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments CHARGING INJECT 8801B 3.2-9 Gate 4 Motor FAI Open LINE DISCHARGE SAFETY INJECT PUMP 1 8802A 3.2-9 Gate 4 Motor FAI Operable 19 DISCH TO HOT LEGS 1 & 2 SAFETY INJECT PUMP 2 8802B 3.2-9 Gate 4 Motor FAI Operable 19 DISCH TO HOT LEGS 3 & 4 CHARG PUMPS TO 8803A 3.2-9 Gate 4 Motor FAI Open 10 CHARGING INJECT LINE CHARG PUMPS TO 8803B 3.2-9 Gate 4 Motor FAI Open 10 CHARGING INJECT LINE RHR HT EXCH 1 8804A 3.2-9 Gate 8 Motor FAI Functional 13 TO CHG PPS SUCT RHR HT EXCH 2 8804B 3.2-9 Gate 8 Motor FAI Functional 13 TO CHG PPS SUCT RWST TO CHARG PUMP SUCT 8805A 3.2-9 Gate 8 Motor FAI Open 10 RWST TO CHARG PUMP SUCT 8805B 3.2-9 Gate 8 Motor FAI Open 10 CHARGING PPS SIS 8807A 3.2-9 Gate 4 Motor FAI Functional 10, 13 PPS SUC CROSSTIE DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 19 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments CHARGING PPS SIS 8807B 3.2-9 Gate 4 Motor FAI Functional 10, 13 PPS SUC CROSSTIE RHR HT EXCH 1 TO 8809A 3.2-9 Gate 8 Motor FAI Functional 20 COLD LEGS 1 & 2 RHR HT EXCH 2 TO 8809B 3.2-9 Gate 8 Motor FAI Functional 20 COLD LEGS 3 & 4 SIS PUMP 1 DISCH 8821A 3.2-9 Gate 4 Motor FAI Functional TO COLD LEGS SIS PUMP 2 DISCH 8821B 3.2-9 Gate 4 Motor FAI Functional TO COLD LEGS SIS PUMP DISCH 8835 3.2-9 Gate 4 Motor FAI Open 14 TO COLD LEGS SI PUMP DISCHARGE RV 8851 3.2-9 Relief 3/4 Spring Open Closed SI PUMP DISCHARGE RV 8853A 3.2-9 Relief 3/4 Spring Open Closed SI PUMP DISCHARGE RV 8853B 3.2-9 Relief 3/4 Spring Open Closed ACCUM RV 8855A 3.2-9 Relief 1 Spring Open Closed ACCUM RV 8855B 3.2-9 Relief 1 Spring Open Closed ACCUM RV 8855C 3.2-9 Relief 1 Spring Open Closed DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 20 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments ACCUM RV 8855D 3.2-9 Relief 1 Spring Open Closed RHR HT EXCH 8856A 3.2-10 Relief 2 Spring Open Closed OUTLET RELIEF RV RHR HT EXCH OUTLET RELIEF 8856B 3.2-10 Relief 2 Spring Open Closed SI PUMP SUCT HEADER RV 8858 3.2-9 Relief 3/4 Spring Open Closed ACCUM TEST IN CTMT 8871 3.2-9 Globe 3/4 Air Closed Closed ACCUM N2 SUPPLY HEADER 8880 3.2-9 Globe 1 Air Closed Closed SAFETY INJECTION TEST LINE 8883 3.2-9 Globe 3/4 Air Closed Closed 5 SAFETY INJECT 8923A 3.2-9 Gate 6 Motor FAI Operable PUMP NO. 1 SUCT SAFETY INJECT 8923B 3.2-9 Gate 6 Motor FAI Operable PUMP NO. 2 SUCT ACCUM TEST OUTSIDE 8961 3.2-9 Globe 3/4 Air Closed Closed CONTAINMENT SAFETY INJECT PUMP 8974A 3.2-9 Globe 2 Motor FAI Operable MIN. RECIRC. VALVES SAFETY INJECT PUMP 8974B 3.2-9 Globe 2 Motor FAI Operable MIN. RECIRC. VALVES DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 21 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments RWST TO SAFETY 8976 3.2-9 Gate 8 Motor FAI Open 14 INJECTION PUMP SUCT RWST TO RHR PUMP 8980 3.2-9 Gate 12 Motor FAI Operable 14 SUCTION CNTMT SUMP TO 8982A 3.2-10 Gate 14 Motor FAI Operable RHR PP1 SUCT CNTMT SUMP TO 8982B 3.2-10 Gate 14 Motor FAI Operable RHR PP2 SUCT SPRAY ADDITIVE SYSTEM 8987 3.2-12 Relief 3/4 Spring Open Close SPRAY ADD TK OUT ISOL 8994A 3.2-12 Gate 3 Motor FAI Open 10 SPRAY ADD TK OUT ISOL 8994B 3.2-12 Gate 3 Motor FAI Open 10 CNTMT SPRAY PP 1 DISCHG 9001A 3.2-12 Gate 8 Motor FAI Open 10 CNTMT SPRAY PP 2 DISCHG 9001B 3.2-12 Gate 8 Motor FAI Open 10 RHR HT EXCH 1 9003A 3.2-12 Gate 8 Motor FAI Open 10 TO CONT SPRAY RHR HT EXCH 2 9003B 3.2-12 Gate 8 Motor FAI Open 10 TO CONT SPRAY DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 22 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments RCS SAMPLE 9351A 3.2-11 Globe 3/8 N2 Closed Operable (21) 23 RCS SAMPLE 9351B 3.2-11 Globe 3/8 N2 Closed Operable (21) 23 PRESS STEAM 9354A 3.2-7 Globe 3/8 Air Closed Closed SPACE IN CONTMT PRESS STEAM 9354B 3.2-7 Globe 3/8 Air Closed Closed SPACE OUT CONTMT PRESS LIQUID 9355A 3.2-7 Globe 3/8 Air Closed Closed SPACE IN CONTMT PRESS LIQUID 9355B 3.2-7 Globe 3/8 Air Closed Closed SPACE OUT CONTMT HOT LEGS 1 & 4 9356A 3.2-7 Globe 3/8 Closed Operable IN CONTMT SAMPLE N2 21 HOT LEGS 1 & 4 9356B 3.2-7 Globe 3/8 Closed Operable IN CONTMT SAMPLE N2 21 ACCUM SAMPLE HDR 9357A 3.2-9 Globe 3/8 Air Closed Closed IN CONTAINMENT ACCUM SAMPLE HDR 9357B 3.2-9 Globe 3/8 Air Closed Closed OUT CONTAINMENT DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 23 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments CCW PUMP SUCT CROSSTIE CCW-4 & -5 3.2-14 B'fly 20 Manual NA Closed VALVE (2 VALVES ON LINES 97 & 2285) CCW PUMP 1-2 DISCH CCW-16 3.2-14 B'fly 20 Manual NA Closed ISOLATION (TO HDR B) CCW PUMP 1-3 DISCH CCW-17 3.2-14 B'fly 20 Manual NA Closed ISOLATION (TO HDR B) CCW PUMP 1-1 DISCH CCW-18 3.2-14 B'fly 20 Manual NA Closed ISOLATION (TO HDR A) CCW PUMP 1-2 DISCH CCW-19 3.2-14 B'fly 20 Manual NA Closed ISOLATION (TO HDR A) CCW HDR C SUPPLY CCW-23 3.2-14 B'fly 24 Manual NA Closed FROM HDR A CCW HDR C SUPPLY CCW-24 3.2-14 B'fly 24 Manual NA Closed FROM HDR B MAIN STEAM LEAD ONE 10% MS-1015 3.2-4 Gate 8 Manual NA Closed STEAM DUMP ISOLATION Note 24 MAIN STEAM LEAD TWO 10% MS-2015 3.2-4 Gate 8 Manual NA Closed STEAM DUMP ISOLATION Note 24 MAIN STEAM LEAD THREE 10% MS-3015 3.2-4 Gate 8 Manual NA Closed STEAM DUMP ISOLATION Note 24 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 24 of 25 Revision 19 May 2010 Failure Valve Size Actuator Valve Position Position for Safe Analysis System or Service Description Identification FSAR Fig. No. Body Type in. Type On Failure Shutdown(a) Comments MAIN STEAM LEAD FOUR 10% MS-4015 3.2-4 Gate 8 Manual NA Closed STEAM DUMP ISOLATION Note 24 (a) The valves whose positions are listed in this column are those valves whose operability is relied on to perform an active function such as safe shutdown of the reactor or mitigation of the consequences of a Design Basis Accident coincidental with loss of offsite power. An entry of "functional" or equivalently "operable" means that the valve must be capable of being opened and/or closed to perform its active function. For DCPP, safe shutdown is defined as Mode 3 following an accident (SSER 7 and SSER 22), Mode 5 following a Hosgri earthquake (Section 3.7.6.2), and Mode 3, followed by Mode 5 within 72 hours, following an Appendix R fire (10 CFR 50, Appendix R). Failure Analysis Comment Notes: 1. Deleted in Revision 9. 2. Deleted in Revision 9. 3. Deleted in Revision 9. 4. Valve is provided for control. Failure, open or close, is remedied by redundant train and EOP RNO actions. 5. Valve provides isolation. Failure to close is remedied by valve in series. 6. Deleted in Revision 9. 7. Locally mounted air accumulators protected against compressed air system failure by check valves can hold open the main steam isolation valves for a short duration of time after the compressed air system is lost. In the event of loss of all air to the main steam isolation valves, the valves will fail closed. 8. These valves are provided for controlled steam release. Failure to open is remedied by redundant valves. Failure to close is remedied by closure of series valve or system shutdown. 9. These valves provide vessel protection. Failure to open is remedied by redundant valves in parallel. Valve size limits flow on failure to close. 10. Valve provides isolation. Failure to close (or stay closed) is remedied by a redundant valve in series. Failure to open (or stay open) is remedied by a redundant line (or system). 11. Valve opens to start device. Failure to open is remedied by use of redundant system. 12. Air-operated valve operation is not required for safe shutdown. 13. Used during recirculation mode. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-9 Page 25 of 25 Revision 19 May 2010 Failure Analysis Comment Notes (continued) 14. Valve provides isolation. Failure to stay open could defeat system function. "Hot" short could close valve, but is not considered credible. 15. Deleted in Revision 9. 16. Deleted in Revision 9. 17. Deleted in Revision 9. 18. Deleted in Revision 9. 19. Valves operated (opened) during changeover from cold leg recirculation to hot leg injection. Failure to stay closed during cold leg injection or cold leg recirculation could defeat system function. "Hot" short could open valve but is not considered credible. 20. Valve 8809A operated (closed) during the changeover from cold leg injection to cold leg recirculation. Valve 8809B operated (closed) during the changeover from cold leg recirculation to hot leg recirculation. Failure of one valve to stay open during cold leg injection remedied by redundant system. 21. Air operated valves required to operate or maintain position after a loss of the compressed air system are supplied with compressed gas from the backup air/nitrogen supply system. See Section 9.3.1.6 for details. 22. If one of the CCW heat exchangers is valved out-of-service, then backup air is supplied to the respective CCW heat exchanger saltwater inlet valve to maintain the valve closed. This ensures all ASW flow is directed to in-service CCW heat exchangers. 23. Valve does not have an active safety function to support accident mitigation or Mode 3 safe shutdown. Valve is active to support achieving post-Hosgri cold shutdown in the manner defined in the Hosgri Report. Valve needs to be seismically qualified for active function for Hosgri only. 24. Valve has an active safety function to support accident mitigation or Mode 3 safe shutdown. Valve is passive to support achieving post-Hosgri cold shutdown in the manner defined in the Hosgri Report. 25. Normal position for Safe Shutdown is Open. For Containment Isolation and the condition described in section 6.5.3.4, valve must be Operable. Abbreviations: FCV = Flow control valve RCP = Reactor coolant pump B'fly = Butterfly LCV = Level control valve FAI = Fail as is RC = Reactor coolant PCV = Pressure control valve PP & PPS = Pump(s) CCW = Component cooling water HCV = Hand control valve CNT = Containment RHR = Residual heat removal RV = Relief valve CHG = Charging AWF = Auxiliary feedwater TCV = Temperature control valve DSL FO = Diesel fuel oil NA = Not applicable
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 3.9-10 MAXIMUM DEFLECTIONS ALLOWED FOR REACTOR INTERNAL SUPPORT STRUCTURES FOR FAULTED CONDITIONS Allowable No Loss of Function Deflection, Deflection, Component Inches Inches Upper Barrel Radial inward 4.1 8.2 Radial outward 1.0 1.0
Upper Core Plate 0.100(a) 0.150 Rod Cluster Control Guide Tubes 1.0 1.75 (a) Only to ensure that the plate will not touch a guide tube. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-11 Page 1 of 2 Revision 15 September 2003 PRESSURIZED GAS CONTAINERS (Above 100 psig) Deviations from OSHA Vessel Type Relief Stored Attached Piping 29 CFR Design Design Design Operating Vessel Relief Set- Energy Vessel Design Largest Section Vessel Class Code Pressure Pressure Volume(c) Device(a) point ft-lb(ea) Location Class Size 1910 CO2 storage I ASME B&PV 363 psig 300 psig 7.5 ton Relief valve 341 psig N.A.(b) Turbine II 6 in. None tanks (Cardox) Code Sec. Pop safety 357 psig building VIII
Diesel genera- I ASME B&PV 342 psig 250 psig 53 cu ft Relief valve 260 psig 3 x 106 Turbine I 2 in. None tor starting air Code Sec. building receivers VIII Diesel genera- I ASME B&PV 342 psig 250 psig 106 cu ft Relief valve 260 psig 5.9 x 106 Turbine I 2 in. None tor turbochar- Code Sec. building ger booster air VIII receivers
Air plant II ASME B&PV 120 psig 110 psig 650 cu ft Relief valve 115 psig 12.6 x106 Turbine III 4 in. None receiver Code Sec. building VIII-Div. I
N2 storage II ASME B&PV 2450 psig 2200 psig 51 cu ft Relief valve 2450 psig 34.5 x106 Yard vault III 3/4 in. None vessels Code Sec. per vessel rupture disk 3500 psig VIII Case 5% 1205 Instrument II ASME B&PV 120 psig 105 psig 152 cu ft Relief valve 110 psig 3 x106 Auxiliary III 2 in. None air receivers Code Sec. per receiver building & VIII 2 receivers intake Structure H2 storage vessels II ASME B&PV Code Sec VIII Case1205 2450 psig 2200 psig 51 cu. ft. per vessel 6 vessels Relief Valve Rupture Disc 2450 psig 3500 psig 5% 34.5 x 106 Yard Vault III 3/4 in. None DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.9-11 Page 2 of 2 Revision 15 September 2003 Deviations from OSHA Vessel Type Relief Stored Attached Piping 29 CFR Design Design Design Operating Vessel Relief Set- Energy Vessel Design Largest Section Vessel Class Code Pressure Pressure Volume(c) Device(a) point ft-lb(ea) Location Class Size 1910 H2 bottles II ICC Std. 3225 psig 2000 psig 6.7 cu. ft. Relief Valve 3200 psig 6,000 Turbine II 3/4 in. None standard 3A bottle Building commercial 4 bottles bottles (rental)
CO2 bottles II ICC Std. 3225 psig 2000 psig 75 lb C02 Relief Valve 3200 psig 2.245x106 Intake III 1/2 in. None standard commer- 3A per vessel (Calc. M-634) Structure cial bottles 11 vessels (rental) Compressed II ASME B&PV 3873 psig 3500 psig 21 cu. ft. Relief Valve 3870 psig 23.4 x 106 Unit 2 III 3/4 in. None breath air Code Sec. per vessel Turbine storage vessels VIII 9 vessels Building
Carbon dioxide II ICC Std. 2265 psig 2000 psig 1.5 cu. ft. Relief Valve 2200 psig Turbine II 2 in. None Storage bottles 3AA-2265 per bottle Building 16 bottles Elev. 85'
N2 storage II ICC Std. 3500 psig 2800 psig 1.5 cu. ft. Relief Valve 3000 psig Aux Bldg II 1 in. None bottles 3AA-3500 per bottle 4 bottles
Argon storage II ICC Std. 2015 psig 2000 psig 1.5 cu. ft. Relief Valve 2015 psig Penetration II 1 in. None bottles 3AA-2015 per bottle Area 5 bottles (a) Relief setpoint and capacity based on the applicable design code.
(b) Filled with liquid, which requires heat input to flash.
(c) Table lists significant gas quantities greater than 100 lbs net weight DCPP UNITS 1 & 2 FSAR UPDATE Page 1 of 5 TABLE 3.9-12 Revision 11 November 1996 MECHANICAL EQUIPMENT SEISMIC QUALIFICATION RESULTS UNIT 1 Location Qualifying Damping Building/ Qualification Spectra Value Equipment Elevation, ft Method HE, DDE, DE Used Feedwater System
AFW Pump (Motor Driven) Aux/100 A DE R DDE R HE R
AFW Pump Motor Aux/100 A DE R DDE R HE R
AFW Pump (Turbine-driven) Aux/100 A DE R DDE R HE R
AFW Pump Turbine Aux/100 A DE R DDE R HE R
CVC System
Boric Acid Tank and Heater Aux/115 A DE 2 DDE 2 HE 4
Safety Injection System
SI Pump Lube Oil Filter Stand Aux/85 A DE R DDE R HE R DCPP UNITS 1 & 2 FSAR UPDATE Page 2 of 5 TABLE 3.9-12 Revision 11 November 1996 Location Qualifying Damping Building/ Qualification Spectra Value Equipment Elevation, ft Method HE, DDE, DE Used Component Cooling System
CCW Pump Aux/73 A DE R DDE R HE R
CCW Pump Motor Aux/73 A DE R DDE R HE R
CCW Heat Exchanger Turb/85 A DE 2 DDE 2 HE 4
CCW Surge Tank Aux/163 A DE R DDE R HE R
CCW Pump Lube Oil Cooler Aux/73 A DE R DDE R HE R
Makeup Water System
Makeup Water Transfer Aux/100 A DE R Pump and Motor DDE R HE R DCPP UNITS 1 & 2 FSAR UPDATE Page 3 of 5 TABLE 3.9-12 Revision 11 November 1996 Location Qualifying Damping Building/ Qualification Spectra Value Equipment Elevation, ft Method HE, DDE, DE Used Saltwater System
ASW Pump and Motor Intake/-2 A DE R DDE R HE 4
Fire Protection System
Fire Pump Aux/115 A DE R DDE R HE R
Fire Pump Motor Aux/115 A DE R DDE R HE R
Portable Fire Pump (diesel) MSS/85 T DE R DDE R HE R
Diesel Generator System
Diesel Generator Turb/85 A, T DE 2 DDE 2 HE 4
DCPP UNITS 1 & 2 FSAR UPDATE Page 4 of 5 TABLE 3.9-12 Revision 11 November 1996 Location Qualifying Damping Building/ Qualification Spectra Value Equipment Elevation, ft Method HE, DDE, DE Used Diesel Transfer Pump MSS/77 A DE R DDE R HE R
Diesel Transfer Pump Motor MSS/77 A DE R DDE R HE R
Diesel Transfer Filter MSS/77 A DE R DDE R HE R
Diesel Transfer Strainer MSS/77 A DE R DDE R HE R
Priming Tank Turb/85 A DE R DDE R HE R
Starting Air Receiver Turb/85 A DE 2 DDE 2 HE 4
Turbocharger Air Receiver Turb/85 A DE R DDE R HE R
DCPP UNITS 1 & 2 FSAR UPDATE Page 5 of 5 TABLE 3.9-12 Revision 11 November 1996 Location Qualifying Damping Building/ Qualification Spectra Value Equipment Elevation, ft Method HE, DDE, DE Used Ventilation System
Containment H2 Purge Aux/100 A DE R Supply Filters DDE R HE R Containment H2 Purge Aux/115 A DE R Exhaust Filters DDE R HE R Containment Fan Cooler Box Cont/140 A DE R DDE R HE R Gaseous Radwaste System
Waste Gas Compressor Aux/60 A DE(a) R Waste Gas Moisture Aux/60 A DE(a) R Separator
Waste Gas Decay Tank Aux/60 A DE(a) R (a) Qualified for DE only per Regulatory Guide 1.143. (b) Legend: A = Qualification by analysis (Qualification Method Column) T = Qualification by testing R = Rigid DCPP UNITS 1 & 2 FSAR UDPATE TABLE 3.10-1 Sheet 1 of 2 Revision 12 September 1998 WESTINGHOUSE SUPPLIED CLASS IE INSTRUMENTATION AND ELECTRICAL EQUIPMENT SEISMIC CAPABILITIES
Equipment Elev./Bldg. Qualification Method Qualifying Spectra HE, DDE, DE FSAR Reference Nuclear Instrumentation System Cabinet 140'/Aux. T / A HE, DDE, DE 3.10.2.1.1 Radiation Monitoring System Cabinets 140'/Aux. T HE, DDE, DE 3.10.2.1.1.1 Two-section Power Range Excore Neutron Detector 102'/Cont. T HE, DDE, DE 3.10.2.1.1 Solid State Protection System 140'/Aux. T HE, DDE, DE 3.10.2.1.2
Process Control and Protection System 128'/Aux. T / A HE, DDE, DE 3.10.2.1.3 Cont. Pressure Transmitter - Transmitter 109.67'/Cont. Exterior T HE, DDE, DE 3.10.2.1.5 - Sensor 109.67'/Cont. T HE, DDE, DE 3.10.2.1.5
Reactor Coolant Level Differential Pressure Transmitter 100'/Aux. T HE, DDE, DE 3.10.2.1.5 Reactor Trip Switchgear 115'/Aux. T HE, DDE, DE 3.10.2.1.6
Main Coolant Loop Resistance Temperature Detectors 117'/Cont. T HE, DDE, DE 3.10.2.1.7 Safeguards Test Cabinet 140'/Aux. T HE, DDE, DE 3.10.2.1.8
Aux. Safeguards Cabinet 128'/Aux. T / A HE, DDE, DE 3.10.2.1.9 Main Control Board 140'/Aux. T / A HE, DDE, DE 3.10.2.2 Electric Hydrogen Recombiner 140'/Cont. T HE, DDE, DE 3.10.2.31 DCPP UNITS 1 & 2 FSAR UDPATE TABLE 3.10-1 Sheet 2 of 2 Revision 12 September 1998
Equipment Elev./Bldg. Qualification Method Qualifying Spectra HE, DDE, DE FSAR Reference Hydrogen Recombiner Control Panel and Power Supply 100'/Aux. T HE, DDE, DE 3.10.2.31 Reactor Vessel Level Instrumentation System/Incore Thermocouple Cabinets (PAMS 3 & 4) 140'/Aux. T HE, DDE, DE 3.10.2.32 Surface Mounted Resistance Temperature Detectors 140'/Cont. T HE, DDE, DE 3.10.2.32.2 High Volume Sensors 127'/Cont. T HE, DDE, DE 3.10.2.32.3 Hydraulic Isolators 89'/GW T HE, DDE, DE 3.10.2.32.4 Flux Mapping Transfer Device 127'/Cont. A HE 3.10.2.33 Incore Flux Mapping Cabinets 140'/Cont. A HE 3.10.2.33 A = Qualification by analysis (Qualification Method Column) T = Qualification by testing DE = Design Earthquake DDE = Double Design Earthquake HE = Hosgri Earthquake
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.10-2 Sheet 1 of 4 Revision 12 September 1998 EQUIPMENT SEISMIC QUALIFICATION RESULTS: ELECTRICAL, INSTRUMENTATION, AND CONTROLS
Equipment Bldg./Elev. Qualification Method Qualifying Spectra HE, DDE, DE FSAR Reference Main annunciator Aux/128 T / A HE, DDE, DE 3.10.2.9
Battery chargers Aux/115 T HE, DDE, DE 3.10.2.8.3
Station battery Aux/115 T / A HE, DDE, DE 3.10.2.8.1
DC switchgear Aux/115 T / A HE, DDE, DE 3.10.2.8.4
Diesel generators a) Excitation cabinet Turb/85 T / A HE, DDE, DE 3.10.2.6 b) Engine control cabinet Turb/85 T / A Electrical penetrations Cont/Various A HE, DDE, DE 3.10.2.10 Emergency light packs Various T HE, DDE, DE --
Fire pump controller Aux/115 T HE, DDE, DE 3.10.2.13
Hot shutdown panel Aux/100 T / A HE, DDE, DE 3.10.2.3
Heat trace distribution panel Aux/Various A HE, DDE, DE N/A Instrument power ac panelboards Aux/115 T / A HE, DDE, DE 3.10.2.7.7 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.10-2 Sheet 2 of 4 Revision 12 September 1998
Equipment Bldg./Elev. Qualification Method Qualifying Spectra HE, DDE, DE FSAR Reference Instrument panels PIA, PIB & PIC Aux/128 A HE, DDE, DE 3.10.2.5
Instrument (Panels A & B) Aux/128 T / A
Local instrument panels Various A HE, DDE, DE 3.10.2.4
Local starters (LPF 36) Turb/119 T HE, DDE, DE 3.10.2.14
Local starters (LPS 96) Turb/140 T HE, DDE, DE 3.10.2.14
Local starters (LPG 66) E1 100/J Aux/ Various T / A HE, DDE, DE 3.10.2.14
Local starter 125 Vdc (FCV 95) Aux/100 T HE, DDE, DE 3.10.2.8.5
Limit switches Various T HE, DDE, DE 3.10.2.27 P&P transmitters Various T HE, DDE, DE 3.10.2.11 Safeguards relay board Turb/119 T / A HE, DDE, DE 3.10.2.7.3
Ventilation control a) Logic cabinet (POV1, POV2) Aux/140 T / A HE, DDE, DE 3.10.2.15 b) Relay cabinet (RCV1, RCV2) Aux/128 T / A HE, DDE, DE 3.10.2.15 c) Electro-mechanical devices Aux/Various T / A HE, DDE, DE 3.10.2.15
Vital load center (480 Vac MCC) Aux/100 T / A HE, DDE, DE 3.10.2.7.4 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.10-2 Sheet 3 of 4 Revision 12 September 1998
Equipment Bldg./Elev. Qualification Method Qualifying Spectra HE, DDE, DE FSAR Reference Vital load center transformer (480 V) Aux/100 T / A HE, DDE, DE 3.10.2.7.5
Auxiliary relay panels (SPF, SPG, SPH) Aux/100 T / A HE, DDE, DE 3.10.2.7.6
Fan cooler starter Aux/100 T / A
Vital switchgear (4.16 kV) Turb/119 T / A HE, DDE, DE 3.10.2.7.1
Potential transformers Turb/119 T / A HE, DDE, DE 3.10.2.7.2
Air circuit breaker (pressurizer heaters) Aux/100 A HE, DDE, DE -- Solenoid valves Various T HE, DDE, DE 3.10.2.23
Postaccident monitor panels and instrument (PAMs 1 & 2) Aux/140 T / A HE, DDE, DE 3.10.2.22 Containment H2 monitors GW/85 GE/100 T / A HE, DDE, DE 3.10.2.25 Containment high-range radiation detector F/145 T HE, DDE, DE 3.10.2.28 Containment purge exhaust detectors and LRP L/100 T / A HE, DDE, DE 3.10.2.26 Instrument AC UPS Aux/115 T HE, DDE, DE 3.10.2.1.4 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 3.10-2 Sheet 4 of 4 Revision 12 September 1998
Equipment Bldg./Elev. Qualification Method Qualifying Spectra HE, DDE, DE FSAR Reference Control room air supply radiation monitors H/158 T HE, DDE, DE 3.10.2.20 Control room pressurization Turb/145 T HE, DDE, DE 3.10.2.20
Radiation monitors H/140 T HE, DDE, DE 3.10.2.20
Control room vent & press. control & power panels Various T / A HE, DDE, DE 3.10.2.20 Pressurizer SRV F/146 T HE, DDE, DE 3.10.2.29
Position margin monitor H/140
Sub-cooled margin monitor (calculators) H/140 T HE, DDE, DE 3.10.2.21 Process solenoid valves G/110 GW/110 T HE, DDE, DE 3.10.2.24 A = Qualification by analysis (Qualification Method Column) T = Qualification by testing DE = Design Earthquake DDE = Double Design Earthquake HE = Hosgri Earthquake
DCPP UNITS 1 & 2 FSAR UPDATE Page 1 of 31 TABLE 3.10-3 HVAC EQUIPMENT SEISMIC QUALIFICATION SPECTRA RESULTS Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Supply Fan 1 (S-1) L/85 A HE, DDE, DE (b) Supply Fan 1 (2S-1) L/85 C HE, DDE, DE (b) Supply Fan 2 (S-2) L/85 A HE, DDE, DE (b) Supply Fan 2 (2S-2) L/85 C HE, DDE, DE (b) Supply Fan 31 (S-31) K/140 A HE, DDE, DE (b) Supply Fan 32 (S-32) K/140 A HE, DDE, DE (b) Supply Fan 33 (S-33) K/140 C HE, DDE, DE (b) Supply Fan 34 (S-34) K/140 C HE, DDE, DE (b) Supply Fan 39 (S-39) K/156 A HE, DDE, DE (b) Supply Fan 40 (S-40) K/156 A HE, DDE, DE (b) Supply Fan 41 (S-41) K/156 C HE, DDE, DE (b) Supply Fan 42 (S-42) K/156 C HE, DDE, DE (b) Exhaust Fan 1 (E-1) L/128 A HE, DDE, DE (b) Exhaust Fan 1 (2E-1) L/128 C HE, DDE, DE (b) Exhaust Fan 2 (E-2) L/128 A HE, DDE, DE (b) Exhaust Fan 2 (2E-2) L/128 C HE, DDE, DE (b) Exhaust Fan 4 (E-4) L/140 A HE, DDE, DE (b) Exhaust Fan 4 (2E-4) L/140 C HE, DDE, DE (b) Exhaust Fan 5 (E-5) L/140 A HE, DDE, DE (b) Exhaust Fan 5 (2E-5) L/140 C HE, DDE, DE (b) Exhaust Fan 6 (E-6) L/140 A HE, DDE, DE (b) Exhaust Fan 6 (2E-6) L/140 C HE, DDE, DE (b) Exhaust Fan 101 (E-101) ISA/15 A HE, DDE, DE (b) Exhaust Fan 102 (E-102) ISA/15 A HE, DDE, DE (b) DCPP UNITS 1 & 2 FSAR UPDATE Page 2 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Exhaust Fan 103 (E-103) ISA/15 A HE, DDE, DE (b) Exhaust Fan 104 (E-104) ISA/15 A HE, DDE, DE (b) Supply Fan 43 (S-43) H/163 A HE, DDE, DE (b) Supply Fan 44 (S-44) H/163 A HE, DDE, DE (b) Supply Fan 45 (S-45) H/163 C HE, DDE, DE (b) Supply Fan 46 (S-46) H/163 C HE, DDE, DE (b) Exhaust Fan 43 (E-43) H/163 A HE, DDE, DE (b) Exhaust Fan 44 (E-44) H/163 A HE, DDE, DE (b) Exhaust Fan 45 (E-45) H/163 C HE, DDE, DE (b) Exhaust Fan 46 (E-46) H/163 C HE, DDE, DE (b) Supply Fan 35 (S-35) K/157 A HE, DDE, DE (b) Supply Fan 36 (S-36) K/157 A HE, DDE, DE (b) Supply Fan 37 (S-37) K/157 C HE, DDE, DE (b) Supply Fan 38 (S-38) K/157 C HE, DDE, DE (b) Supply Fan 67 (S-67) A/119 A HE, DDE, DE (b) Supply Fan 67 (2S-67) A/119 C HE, DDE, DE (b) Supply Fan 68 (S-68) A/119 A HE, DDE, DE (b) Supply Fan 68 (2S-68) A/119 C HE, DDE, DE (b) Supply Fan 69 (S-69) A/119 A HE, DDE, DE (b) Supply Fan 69 (2S-69) A/119 C HE, DDE, DE (b) Compressor Unit 35 (CP-35) K/156 A HE, DDE, DE (b) Compressor Unit 36 (CP-36) K/156 A HE, DDE, DE (b) Compressor Unit 37 (CP-37) K/156 C HE, DDE, DE (b) Compressor Unit 38 (CP-38) K/156 C HE, DDE, DE (b) Condenser Unit 35 (CR-35) K/157 A HE, DDE, DE (b) Condenser Unit 36 (CR-36) K/157 A HE, DDE, DE (b) DCPP UNITS 1 & 2 FSAR UPDATE Page 3 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Condenser Unit 37 (CR-37) K/157 C HE, DDE, DE (b) Condenser Unit 38 (CR-38) K/157 C HE, DDE, DE (b) Mode Damper 78 in. (1A) L/128 A HE, DDE, DE (b) Mode Damper 78 in. (2-1A) L/128 C HE, DDE, DE (b) Mode Damper 78 in. (1B) L/128 A HE, DDE, DE (b) Mode Damper 78 in. (2-1B) L/128 C HE, DDE, DE (b) Mode Damper 132x144 (3) L/122 A HE, DDE, DE (b) Mode Damper 132x144 (2-3) L/122 C HE, DDE, DE (b) Mode Damper 96x144 (5A) L/107 A HE, DDE, DE (b) Mode Damper 96x144 (2-5A) L/107 C HE, DDE, DE (b) Mode Damper 96x144 (5B) L/107 A HE, DDE, DE (b) Mode Damper 96x144 (2-5B) L/107 C HE, DDE, DE (b) Mode Damper 108x144 (6) L/122 A HE, DDE, DE (b) Mode Damper 108x144 (2-6) L/122 C HE, DDE, DE (b) Mode Damper 108x144 (9) L/122 A HE, DDE, DE (b) Mode Damper 108x144 (2-9) L/122 C HE, DDE, DE (b) Backdraft Damper for Supply Fan S-31 96x72 K/146 A HE, DDE, DE (b) Backdraft Damper for Supply Fan S-32 96x72 K/146 A HE, DDE, DE (b) Backdraft Damper for Supply Fan S-33 96x72 K/146 C HE, DDE, DE (b) Backdraft Damper for Supply Fan S-34 96x72 K/146 C HE, DDE, DE (b) Backdraft Damper for Exhaust Fan E-1 90x66 L/121 A HE, DDE, DE (b) Backdraft Damper for Exhaust Fan 2E-1 90x66 L/121 C HE, DDE, DE (b) DCPP UNITS 1 & 2 FSAR UPDATE Page 4 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Backdraft Damper for Exhaust Fan E-2 90x66 L/121 A HE, DDE, DE (b) Backdraft Damper for Exhaust Fan 2E-2 90x66 L/121 C HE, DDE, DE (b) Backdraft Damper for Exhaust L/143 A HE, DDE, DE (b) Fan E-4 56x44 Backdraft Damper for Exhaust L/143 A HE, DDE, DE (b) Fan 2E-4 56x44 Backdraft Damper for Exhaust L/154 A HE, DDE, DE (b) Fan E-5 56x44 Backdraft Damper for Exhaust L/154 A HE, DDE, DE (b) Fan 2E-5 56x44 Backdraft Damper for Exhaust L/154 A HE, DDE, DE (b) Fan E-6 56x44 Backdraft Damper for Exhaust L/154 A HE, DDE, DE (b) Fan 2E-6 56x44 Forced Draft Shutter Damper 30x48 G/96 A HE, DDE, DE (b) Forced Draft Shutter Damper 30x48 G/96 C HE, DDE, DE (b) Fire Damper 46x14 (FD-4) H/125 A HE, DDE, DE (b) Fire Damper 46x14 (2FD-4) H/125 C HE, DDE, DE (b) Fire Damper 46x14 (FD-5) H/125 A HE, DDE, DE (b) Fire Damper 46x14 (2FD-5) H/125 C HE, DDE, DE (b) Fire Damper 46x14 (FD-6) H/125 A HE, DDE, DE (b) Fire Damper 46x14 (2FD-6) H/125 C HE, DDE, DE (b) Carbon Tray Filters (EFC-1) L/115 A HE, DDE, DE (b) Carbon Tray Filters (2EFC-1) L/115 C HE, DDE, DE (b) DCPP UNITS 1 & 2 FSAR UPDATE Page 5 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Carbon Tray Filters (EFC-5) L/148 A HE, DDE, DE (b) Carbon Tray Filters (2EFC-5) L/148 C HE, DDE, DE (b) Carbon Tray Filters (EFC-6) L/148 A HE, DDE, DE (b) Carbon Tray Filters (2EFC-6) L/148 C HE, DDE, DE (b) Astrocel-Hepa Filters (EFH-1) L/126 A HE, DDE, DE (b) Astrocel-Hepa Filters (2EFH-1) L/126 C HE, DDE, DE (b) Astrocel-Hepa Filters (EFH-2a) L/126 A HE, DDE, DE (b) Astrocel-Hepa Filters (2EFH-2a) L/126 C HE, DDE, DE (b) Astrocel-Hepa Filters (EFH-2b) L/105 A HE, DDE, DE (b) Astrocel-Hepa Filters (2EFH-2b) L/105 C HE, DDE, DE (b) Astrocel-Hepa Filters (EFH-4) L/150 A HE, DDE, DE (b) Astrocel-Hepa Filters (2EFH-4) L/150 C HE, DDE, DE (b) Astrocel-Hepa Filters (EFH-5) L/148 A HE, DDE, DE (b) Astrocel-Hepa Filters (2EFH-5) L/148 C HE, DDE, DE (b) Astrocel-Hepa Filters (EFH-6) L/148 A HE, DDE, DE (b) Astrocel-Hepa Filters (2EFH-6) L/148 C HE, DDE, DE (b) Varicel-Roughing Filter (EFR-4) L/154 A HE, DDE, DE (b) Varicel-Roughing Filter (2EFR-4) L/154 C HE, DDE, DE (b) Varicel-Roughing Filter (EFR-5) L/154 A HE, DDE, DE (b) Varicel-Roughing Filter (2EFR-5) L/154 C HE, DDE, DE (b) Varicel-Roughing Filter (EFR-6) L/154 A HE, DDE, DE (b) Varicel-Roughing Filter (2EFR-6) L/154 C HE, DDE, DE (b) Filter Housing With Filters (FU-39) K/155 A HE, DDE, DE (b) Filter Housing With Filters (FU-41) K/155 C HE, DDE, DE (b) DCPP UNITS 1 & 2 FSAR UPDATE Page 6 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Filter Box (FB-29) H/163 A HE, DDE, DE (b) Filter Box (2FB-29) H/163 C HE, DDE, DE (b) Electric Duct Heater (EH-30) L/137 A HE, DDE, DE (b) Chromalox Model TDH-54C (2EH-30) J/138 C HE, DDE, DE (b) Supply Fan 96 for CRPS (OS-96) A/140 C HE, DDE, DE (b) Supply Fan 97 for CRPS (OS-97) A/140 C HE, DDE, DE (b) Supply Fan 98 for CRPS (OS-98) A/140 A HE, DDE, DE (b) Supply Fan 99 for CRPS (OS-99) A/140 A HE, DDE, DE (b) Mode Damper 72 in. and Actuator (2A) L/132 A HE, DDE, DE (b) Mode Damper 72 in. and Actuator (2-2A) L/132 C HE, DDE, DE (b) Mode Damper 72 in. and Actuator (2B) L/132 A HE, DDE, DE (b) Mode Damper 72 in. and Actuator (2-2B) L/132 C HE, DDE, DE (b) Mode Damper 90x66 and Actuator (7) L/102 A HE, DDE, DE (b) Mode Damper 90x66 and Actuator (2-7) L/102 C HE, DDE, DE (b) Mode Damper 10 in. (13A) K/97 A HE, DDE, DE (b) Mode Damper 10 in. (2-13A) K/97 C HE, DDE, DE (b) Mode Damper 10 in. (13B) K/97 A HE, DDE, DE (b) Mode Damper 10 in. (2-13B) K/97 C HE, DDE, DE (b) Mode Damper 10 in. (14A) GE/81 A HE, DDE, DE (b) Mode Damper 10 in. (2-14A) GE/81 C HE, DDE, DE (b) Mode Damper 10 in. (14B) GE/81 A HE, DDE, DE (b) Mode Damper 10 in. (2-14B) GE/81 C HE, DDE, DE (b) Mode Damper 14 in. (15A) GE/70 A HE, DDE, DE (b) DCPP UNITS 1 & 2 FSAR UPDATE Page 7 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Mode Damper 14 in. (2-15A) GE/70 C HE, DDE, DE (b) Mode Damper 14 in. (15B) GE/70 A HE, DDE, DE (b) Mode Damper 14 in. (2-15B) GE/70 C HE, DDE, DE (b) Mode Damper 48 in. (35) L/107 A HE, DDE, DE (b) Mode Damper 48 in. (2-35) L/107 C HE, DDE, DE (b) Mode Damper 54 in. and Actuator (29) L/150 A HE, DDE, DE (b) Mode Damper 54 in. and Actuator (2-29) L/150 C HE, DDE, DE (b) Mode Damper 54 in. and Actuator (30) L/150 A HE, DDE, DE (b) Mode Damper 54 in. and Actuator (2-30) L/150 C HE, DDE, DE (b) Mode Damper 54 in. and Actuator (31) L/150 A HE, DDE, DE (b) Mode Damper 54 in. and Actuator (2-31) L/150 C HE, DDE, DE (b) Mode Damper 72x100 (4A) L/107 A HE, DDE, DE (b) Mode Damper 72x100 (2-4A) L/107 C HE, DDE, DE (b) Mode Damper 72x100 (4B) L/107 A HE, DDE, DE (b) Mode Damper 72x100 (2-4B) L/107 C HE, DDE, DE (b) Mode Damper 72x75 (8A) L/133 A HE, DDE, DE (b) Mode Damper 72x75 (2-8A) L/133 C HE, DDE, DE (b) Mode Damper 72x75 (8B) L/115 A HE, DDE, DE (b) Mode Damper 72x75 (2-8B) L/115 C HE, DDE, DE (b) Mode Damper 90x66 (10) L/110 A HE, DDE, DE (b) Mode Damper 90x66 (2-10) L/110 C HE, DDE, DE (b) Mode Damper 40x84 (12) K/90 A HE, DDE, DE (b) Mode Damper 40x84 (2-12) K/90 C HE, DDE, DE (b) Mode Damper 46x40 (16A) K/95 A HE, DDE, DE (b) DCPP UNITS 1 & 2 FSAR UPDATE Page 8 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Mode Damper 46x40 (2-16A) K/95 C HE, DDE, DE (b) Mode Damper 46x40 (16B) K/95 A HE, DDE, DE (b) Mode Damper 46x40 (2-16B) K/95 C HE, DDE, DE (b) Mode Damper 26x54 (17A) K/94 A HE, DDE, DE (b) Mode Damper 26x54 (2-17A) K/94 C HE, DDE, DE (b) Mode Damper 26x54 (17B) K/94 A HE, DDE, DE (b) Mode Damper 26x54 (2-17B) K/94 C HE, DDE, DE (b) Mode Damper 96x72 (20) K/146 A HE, DDE, DE (b) Mode Damper 96x72 (2-24) K/146 C HE, DDE, DE (b) Mode Damper 96x72 (21) K/146 A HE, DDE, DE (b) Mode Damper 96x72 (2-21) K/146 C HE, DDE, DE (b) Mode Damper 54x100 (22A) K/141 A HE, DDE, DE (b) Mode Damper 54x100 (2-22A) K/141 C HE, DDE, DE (b) Mode Damper 54x100 (22B) K/132 A HE, DDE, DE (b) Mode Damper 54x100 (2-22B) K/132 C HE, DDE, DE (b) Mode Damper 40x40 (23) K/135 A HE, DDE, DE (b) Mode Damper 40x40 (2-23) K/135 C HE, DDE, DE (b) Mode Damper 40x40 (23B) K/135 A HE, DDE, DE (b) Mode Damper 40x40 (2-23B) K/135 C HE, DDE, DE (b) Mode Damper 14x44 (24) K/111 A HE, DDE, DE (b) Mode Damper 14x44 (2-24) K/111 C HE, DDE, DE (b) Mode Damper 14x44 (24B) K/111 A HE, DDE, DE (b) Mode Damper 14x44 (2-24B) K/111 C HE, DDE, DE (b) Mode Damper 48x40 (26A) K/87 A HE, DDE, DE (b) Mode Damper 48x40 (2-26A) K/87 C HE, DDE, DE (b) Mode Damper 48x40 (26B) K/87 A HE, DDE, DE (b) Mode Damper 48x40 (2-26B) K/87 C HE, DDE, DE (b) Mode Damper 30x48 (25) K/95 A HE, DDE, DE (b) Mode Damper 30x48 (2-25) K/95 C HE, DDE, DE (b) Mode Damper 30x48 (25B) K/95 A HE, DDE, DE (b) DCPP UNITS 1 & 2 FSAR UPDATE Page 9 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Mode Damper 30x48 (2-25B) K/95 C HE, DDE, DE (b) Mode Damper 42x64 (33) L/108 A HE, DDE, DE (b) Mode Damper 42x64 (2-33) L/108 C HE, DDE, DE (b) Mode Damper 42x64 (34) L/105 A HE, DDE, DE (b) Mode Damper 42x64 (2-34) L/105 C HE, DDE, DE (b) Backdraft Damper for Supply L/95 A HE, DDE, DE (b) Fan S-1 64x42 Backdraft Damper for Supply L/95 C HE, DDE, DE (b) Fan 2S-1 64x42 Backdraft Damper for Supply L/95 A HE, DDE, DE (b) Fan S-2 64x42 Backdraft Damper for Supply L/95 C HE, DDE, DE (b) Fan 2S-2 64x42 Backdraft Damper 14 in. (OBD-1) A/149 A HE, DDE, DE (b) Backdraft Damper 14 in. (OBD-2) A/149 A HE, DDE, DE (b) Backdraft Damper 14 in. (OBD-3) A/149 C HE, DDE, DE (b) Backdraft Damper 14 in. (OBD-4) A/149 A/149 C HE, DDE, DE (b) Quadrant Damper (QD 10 in. ) K/110 A HE, DDE, DE (b) Quadrant Damper (QD 20 in. ) K/82 A HE, DDE, DE (b) Quadrant Damper (QD 14 in. ) K/82 A HE, DDE, DE (b) Quadrant Damper (QD 14 in. ) K/111 A HE, DDE, DE (b) Quadrant Damper (QD 16 in. ) K/111 A HE, DDE, DE (b) Quadrant Damper (QD 12 in. ) K/112 A HE, DDE, DE (b) Quadrant Damper (QD 12 in. ) K/130 A HE, DDE, DE (b) (e) Quadrant Damper (QD 10 in. ) K/132 A HE, DDE, DE (b) (e) DCPP UNITS 1 & 2 FSAR UPDATE Page 10 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Quadrant Damper (QD 14 in. ) K/132 A HE, DDE, DE (b) (e) Quadrant Damper (QD 12 in. ) K/134 A HE, DDE, DE (b) (e) Quadrant Damper (QD 16 in. ) K/134 A HE, DDE, DE (b) (e) Quadrant Damper (QD 16 in. ) K/131 A HE, DDE, DE (b) (e) Quadrant Damper (QD 20 in. ) K/134 A HE, DDE, DE (b) (e) Quadrant Damper (QD 14 in. ) K/134 A HE, DDE, DE (b) (e) Quadrant Damper (QD 14 in. ) K/70 A HE, DDE, DE (b) Quadrant Damper (QD 14 in. ) GE/70 A HE, DDE, DE (b) Quadrant Damper (QD 14 in. ) H/79 A HE, DDE, DE (b) Quadrant Damper (QD 20 in. ) H/65 A HE, DDE, DE (b) Quadrant Damper (QD 28 in. ) J/132 A HE, DDE, DE (b) Quadrant Damper (QD 16 in. ) L/141 A HE, DDE, DE (b) Quadrant Damper (QD 14 in. ) GE/70 A HE, DDE, DE (b) Quadrant Damper (QD 18 in. ) K/132 C HE, DDE, DE (b) Quadrant Damper #52 (QD 48x24) J/111 A HE, DDE, DE (b) Quadrant Damper #2-52 (QD 48x24) J/111 A HE, DDE, DE (b) Quadrant Damper #54 (QD 42x42) J/134 A HE, DDE, DE (b) Quadrant Damper #2-54 (QD 42x42) J/134 A HE, DDE, DE (b) Quadrant Damper #46 (QD 38x14) J/123 A HE, DDE, DE (b) Quadrant Damper #2-46 (QD 38x14) J/123 A HE, DDE, DE (b) Quadrant Damper #33 (QD 40x40) K/135 A HE, DDE, DE (b) Quadrant Damper #2-33 (QD 40x40) K/135 A HE, DDE, DE (b) Quadrant Damper #34 (QD 14x10) K/136 A HE, DDE, DE (b) Quadrant Damper #2-34 (QD 14x10) K/136 A HE, DDE, DE (b) Quadrant Damper #35 (QD 46x14) K/134 A HE, DDE, DE (b) Quadrant Damper #2-35 (QD 46x14) K/134 A HE, DDE, DE (b) Quadrant Damper #24 (QD 14x14) K/109 A HE, DDE, DE (b) Quadrant Damper #2-24 (QD 14x14) K/109 A HE, DDE, DE (b) Quadrant Damper #31 (QD 54x100) K/132 A HE, DDE, DE (b) Quadrant Damper #2-31 (QD 54x100) K/132 C HE, DDE, DE (b)
DCPP UNITS 1 & 2 FSAR UPDATE Page 11 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Quadrant Damper #25 (QD 14x30) K/111 A HE, DDE, DE (b) Quadrant Damper #2-25 (QD 14x30) K/111 A HE, DDE, DE (b) Quadrant Damper #66 (QD 24x44) K/92 A HE, DDE, DE (b) Quadrant Damper #2-67 (QD 24x44) K/92 A HE, DDE, DE (b) Quadrant Damper #5 (QD 58x32) K/81 A HE, DDE, DE (b) Quadrant Damper #2-5 (QD 58x32) K/81 C HE, DDE, DE (b) Quadrant Damper #64 (QD 44x32) K/81 A HE, DDE, DE (b) Quadrant Damper #2-64 (QD 44x32) K/81 A HE, DDE, DE (b) Quadrant Damper #6 (QD 24x32) K/81 A HE, DDE, DE (b) Quadrant Damper #2-6 (QD 24x32) K/81 A HE, DDE, DE (b) Quadrant Damper #4 (QD 44x26) K/82 A HE, DDE, DE (b) Quadrant Damper #2-4 (QD 44x26) K/82 A HE, DDE, DE (b) Quadrant Damper #53 (QD 72x100) L/100 A HE, DDE, DE (b) Quadrant Damper #2-53 (QD 72x100) L/100 C HE, DDE, DE (b) Volume Damper (VD 24x24) H/123 A HE, DDE, DE (b) Volume Damper (VD 24x24) H/124 A HE, DDE, DE (b) Volume Damper (VD 27x21) H/124 A HE, DDE, DE (b) Quadrant Damper #19 (QD 38x44) K/96 A HE, DDE, DE (b) Quadrant Damper #2-19 (QD 38x44) K/96 A HE, DDE, DE (b) Quadrant Damper #15 (QD 20x12) K/97 A HE, DDE, DE (b) Quadrant Damper #2-15 (QD 20x12) K/97 A HE, DDE, DE (b) Quadrant Damper #20 (QD 20x44) K/97 A HE, DDE, DE (b) Quadrant Damper #2-20 (QD 20x44) K/97 A HE, DDE, DE (b) Quadrant Damper #14 (QD 72x24) K/96 A HE, DDE, DE (b) Quadrant Damper #2-14 (QD 72x24) K/96 A HE, DDE, DE (b) Quadrant Damper #28 (QD 18x16) K/113 A HE, DDE, DE (b) Quadrant Damper #2-28 (QD 18x16) K/113 A HE, DDE, DE (b) Quadrant Damper #29 (QD 16x18) K/112 A HE, DDE, DE (b) Quadrant Damper #2-29 (QD 16x18) K/112 A HE, DDE, DE (b) DCPP UNITS 1 & 2 FSAR UPDATE Page 12 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Quadrant Damper #37 (QD 32x30) K/132 A HE, DDE, DE (b) Quadrant Damper #2-37 (QD 32x30) K/132 A HE, DDE, DE (b) Quadrant Damper #45 (QD 38x38) J/120 A HE, DDE, DE (b) Quadrant Damper #2-45 (QD 38x38) J/120 A HE, DDE, DE (b)
Quadrant Damper (QD 24x24) H/130 C HE, DDE, DE (b) (f) Quadrant Damper (QD 18x24) H/130 C HE, DDE, DE (b) (f) Quadrant Damper #36 (QD 22x30) K/131 A HE, DDE, DE (b) Quadrant Damper #2-36 (QD 22x30) K/131 A HE, DDE, DE (b) Quadrant Damper #10 (QD 46x30) K/78 A HE, DDE, DE (b) Quadrant Damper #2-10 (QD 46x30) K/78 A HE, DDE, DE (b) Quadrant Damper #11 (QD 18x30) K/79 A HE, DDE, DE (b) Quadrant Damper #2-11 (QD 18x30) K/79 A HE, DDE, DE (b) Quadrant Damper #12 (QD 6x30) K/79 A HE, DDE, DE (b) Quadrant Damper #2-12 (QD 6x30) K/79 A HE, DDE, DE (b) Quadrant Damper #3 (QD 20x32) K/69 A HE, DDE, DE (b) Quadrant Damper #2-3 (QD 20x32) K/69 A HE, DDE, DE (b) Quadrant Damper #55 (QD 30x12) H/61 A HE, DDE, DE (b) Quadrant Damper #2-55 (QD 30x12) H/61 A HE, DDE, DE (b) Quadrant Damper #40 (QD 16x40) J/152 A HE, DDE, DE (b) Quadrant Damper #2-40 (QD 16x40) J/152 A HE, DDE, DE (b) Quadrant Damper #27 (QD 40x42) K/110 A HE, DDE, DE (b) Quadrant Damper #2-27 (QD 40x42) K/110 A HE, DDE, DE (b) DCPP UNITS 1 & 2 FSAR UPDATE Page 13 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Quadrant Damper #26 (QD 36x42) K/110 A HE, DDE, DE (b) Quadrant Damper #2-26 (QD 36x42) K/110 A HE, DDE, DE (b) Quadrant Damper #18 (QD 40x26) K/97 Quadrant Damper #2-18 (QD 40x26) K/97 Quadrant Damper #2 (QD 30x66) H/69 A HE, DDE, DE (b) Quadrant Damper #2-2 (QD 30x66) H/69 A HE, DDE, DE (b) Quadrant Damper #1 (QD 24x72) K/69 A HE, DDE, DE (b) Quadrant Damper #2-1 (QD 24x72) K/69 A HE, DDE, DE (b) Quadrant Damper #43 (QD 86x48) K/132 A HE, DDE, DE (b) Quadrant Damper #2-43 (QD 86x48) K/132 C HE, DDE, DE (b) Quadrant Damper #42 (QD 36x18) K/132 A HE, DDE, DE (b) Quadrant Damper #2-42 (QD 36x18) K/132 A HE, DDE, DE (b) Quadrant Damper #8 (QD 36x18) K/81 A HE, DDE, DE (b) Quadrant Damper #2-8 (QD 36x18) K/81 A HE, DDE, DE (b) Quadrant Damper #9 (QD 36x18) K/81 A HE, DDE, DE (b) Quadrant Damper #2-9 (QD 36x18) K/81 A HE, DDE, DE (b) Quadrant Damper #41 (QD 56x50) L/143 A HE, DDE, DE (b) Quadrant Damper #2-41 (QD 56x50) L/143 C HE, DDE, DE (b) Quadrant Damper #65 (QD 60x30) J/152 A HE, DDE, DE (b) Quadrant Damper #2-65 (QD 60x30) J/152 C HE, DDE, DE (b) Quadrant Damper #49 (QD 38x30) J/156 A HE, DDE, DE (b) Quadrant Damper #2-49 (QD 38x30) J/156 C HE, DDE, DE (b) Quadrant Damper #7 (QD 84x72) K/85 A HE, DDE, DE (b) Quadrant Damper #2-7 (QD 84x72) K/85 C HE, DDE, DE (b) Quadrant Damper #13 (QD 54x48) K/86 A HE, DDE, DE (b) DCPP UNITS 1 & 2 FSAR UPDATE Page 14 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Quadrant Damper #2-13 (QD 54x48) K/86 C HE, DDE, DE (b) Quadrant Damper #32 (QD 37x78) K/131 A HE, DDE, DE (b) Quadrant Damper #2-32 (QD 37x78) K/131 A HE, DDE, DE (b) Motorized Damper 24 in. (2) H/156 A HE, DDE, DE (b) Motorized Damper 24 in. (2-2) H/156 A HE, DDE, DE (b) Motorized Damper 24 in. (2A) H/160 A HE, DDE, DE (b) Motorized Damper 24 in. (2-2A) H/160 A HE, DDE, DE (b) Motorized Damper 18 in. (3) H/156 A HE, DDE, DE (b) Motorized Damper 18 in. (2-3) H/156 A HE, DDE, DE (b) Motorized Damper 18 in. (3A) H/160 A HE, DDE, DE (b) Motorized Damper 18 in. (2-3A) H/160 A HE, DDE, DE (b) Motorized Damper 24 in. (7) H/161 A HE, DDE, DE (b) Motorized Damper 24 in. (2-7) H/161 A HE, DDE, DE (b) Motorized Damper 24 in. (7A) H/159 A HE, DDE, DE (b) Motorized Damper 24 in. (2-7A) H/159 A HE, DDE, DE (b) Motorized Damper 18 in. (8) H/163 A HE, DDE, DE (b) Motorized Damper 18 in. (2-8) H/163 A HE, DDE, DE (b) Motorized Damper 18 in. (8A) H/163 A HE, DDE, DE (b) Motorized Damper 18 in. (2-8A) H/163 A HE, DDE, DE (b) Motorized Damper 14 in. for CRPS (1) A/143 A HE, DDE, DE (b) Motorized Damper 14 in. for CRPS (2-1) A/143 C HE, DDE, DE (b) Motorized Damper 14 in. for CRPS (1A) A/149 A HE, DDE, DE (b) Motorized Damper 14 in. for CRPS (2-1A) A/149 C HE, DDE, DE (b) Motorized Damper 14 in. for CRPS (1B) A/143 A HE, DDE, DE (b) Motorized Damper 14 in. for CRPS (2-1B) A/143 C HE, DDE, DE (b) Motorized Damper 14 in. for CRPS (1C) A/149 A HE, DDE, DE (b) Motorized Damper 14 in. for CRPS (2-1C) A/149 C HE, DDE, DE (b) Limitorque Actuator for H/156 T HE, DDE, DE (b) DCPP UNITS 1 & 2 FSAR UPDATE Page 15 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Motorized Damper (2) Limitorque Actuator for H/156 T HE, DDE, DE (b) Motorized Damper (2-2) Limitorque Actuator for H/160 T HE, DDE, DE (b) Motorized Damper (2A) Limitorque Actuator for H/160 T HE, DDE, DE (b) Motorized Damper (2-2A) Limitorque Actuator for H/156 T HE, DDE, DE (b) Motorized Damper (3) Limitorque Actuator for H/156 T HE, DDE, DE (b) Motorized Damper (2-3) Limitorque Actuator for H/160 T HE, DDE, DE (b) Motorized Damper (3A) Limitorque Actuator for H/161 T HE, DDE, DE (b) Motorized Damper (2-3A) Limitorque Actuator for H/160 T HE, DDE, DE (b) Motorized Damper (7) Limitorque Actuator for H/161 T HE, DDE, DE (b) Motorized Damper (2-7) Limitorque Actuator for H/159 T HE, DDE, DE (b) Motorized Damper (7A) Limitorque Actuator for H/159 T HE, DDE, DE (b) Motorized Damper (2-7A) Limitorque Actuator for H/163 T HE, DDE, DE (b) Motorized Damper (8) Limitorque Actuator for H/163 T HE, DDE, DE (b) Motorized Damper (2-8) Limitorque Actuator for H/163 T HE, DDE, DE (b) Motorized Damper (8A) Limitorque Actuator for H/163 T HE, DDE, DE (b) Motorized Damper (2-8A) Motorized Damper 18x16 (4) H/163 A HE, DDE, DE (b) Motorized Damper 18x16 (2-4) H/163 C HE, DDE, DE (b) Motorized Damper 36x24 (5) H/163 A HE, DDE, DE (b) DCPP UNITS 1 & 2 FSAR UPDATE Page 16 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Motorized Damper 36x24 (2-5) H/163 C HE, DDE, DE (b) Motorized Damper 36x24 (6) H/159 A HE, DDE, DE (b) Motorized Damper 36x24 (2-6) H/159 C HE, DDE, DE (b) Motorized Damper 70x16 (9) H/159 A HE, DDE, DE (b) Motorized Damper 70x16 (2-9) H/159 C HE, DDE, DE (b) Motorized Damper 70x16 (9A) H/159 A HE, DDE, DE (b) Motorized Damper 70x16 (2-9A) H/159 C HE, DDE, DE (b) Motorized Damper 70x20 (10) H/157 A HE, DDE, DE (b) Motorized Damper 70x20 (2-10) H/157 C HE, DDE, DE (b) Motorized Damper 70x20 (10A) H/157 A HE, DDE, DE (b) Motorized Damper 70x20 (2-10A) H/157 C HE, DDE, DE (b) Motorized Damper 70x16 (11) H/159 A HE, DDE, DE (b) Motorized Damper 70x16 (2-11) H/159 C HE, DDE, DE (b) Motorized Damper 70x16 (11A) H/159 A HE, DDE, DE (b) Motorized Damper 70x16 (2-11A) H/159 C HE, DDE, DE (b) Motorized Damper 70x20 (12) H/157 A HE, DDE, DE (b) Motorized Damper 70x20 (2-12) H/157 C HE, DDE, DE (b) Motorized Damper 70x20 (12A) H/157 A HE, DDE, DE (b) Motorized Damper 70x20 (2-12A) H/157 C HE, DDE, DE (b) Motorized Damper 22x12 (13) H/159 A HE, DDE, DE (b) Motorized Damper 22x12 (2-13) H/159 C HE, DDE, DE (b) Motorized Damper 22x12 (14) H/159 A HE, DDE, DE (b) Motorized Damper 22x12 (2-14) H/159 C HE, DDE, DE (b) Balancing Damper 14 in. (1-15) H/163 A HE, DDE, DE (b) Balancing Damper 14 in. (2-15) H/163 C HE, DDE, DE (b) Balancing Damper 14 in. (1-16) A/141 A HE, DDE, DE (b) Balancing Damper 14 in. (2-16) A/141 C HE, DDE, DE (b) Shut-off Damper (48X48) (HD-43) H/168 A HE, DDE, DE (b) Shut-off Damper (48X48) (HD-44) H/168 A HE, DDE, DE (b) Shut-off Damper (48X48) (HD-45) H/168 C HE, DDE, DE (b) Shut-off Damper (48X48) (HD-46) H/168 C HE, DDE, DE (b) DCPP UNITS 1 & 2 FSAR UPDATE Page 17 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Back Draft Damper (E-21) GW/96 A HE, DDE, DE (b) Back Draft Damper (48X48) (BDD-43) H/168 A HE, DDE, DE (b) Back Draft Damper (48X48) (BDD-44) H/168 A HE, DDE, DE (b) Back Draft Damper (48X48) (BDD-45) H/168 C HE, DDE, DE (b) Back Draft Damper (48X48) (BDD-46) H/168 C HE, DDE, DE (b) Barber Colman Actuator for K/166 T HE, DDE, DE (b) Motorized Damper 4 Barber Colman Actuator for K/166 C HE, DDE, DE (b) Motorized Damper 2-4 Barber Colman Actuator for K/166 T HE, DDE, DE (b) Motorized Damper 5 Barber Colman Actuator for K/166 C HE, DDE, DE (b) Motorized Damper 2-5 Barber Colman Actuator for K/166 T HE, DDE, DE (b) Motorized Damper 6 Barber Colman Actuator for K/166 C HE, DDE, DE (b) Motorized Damper 2-6 Barber Colman Actuator for K/159 T HE, DDE, DE (b) Motorized Damper (9) Barber Colman Actuator for K/159 T HE, DDE, DE (b) Motorized Damper (2-9) Barber Colman Actuator for K/159 T HE, DDE, DE (b) Motorized Damper (9A) Barber Colman Actuator for K/159 T HE, DDE, DE (b) Motorized Damper (2-9A) Barber Colman Actuator for H/157 T HE, DDE, DE (b) Motorized Damper (10) Barber Colman Actuator for H/157 T HE, DDE, DE (b) Motorized Damper (2-10) Barber Colman Actuator for H/157 T HE, DDE, DE (b) Motorized Damper (10A) DCPP UNITS 1 & 2 FSAR UPDATE Page 18 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Barber Colman Actuator for H/157 T HE, DDE, DE (b) Motorized Damper (2-10A) Barber Colman Actuator for K/159 T HE, DDE, DE (b) Motorized Damper (11) Barber Colman Actuator for K/159 T HE, DDE, DE (b) Motorized Damper (2-11) Barber Colman Actuator for K/159 T HE, DDE, DE (b) Motorized Damper (11A) Barber Colman Actuator for K/159 T HE, DDE, DE (b) Motorized Damper (2-11A) Barber Colman Actuator for H/157 T HE, DDE, DE (b) Motorized Damper (12) Barber Colman Actuator for H/157 T HE, DDE, DE (b) Motorized Damper (2-12) Barber Colman Actuator for H/157 T HE, DDE, DE (b) Motorized Damper (12A) Barber Colman Actuator for H/157 T HE, DDE, DE (b) Motorized Damper (2-12A) Barber Colman Actuator for K/159 T HE, DDE, DE (b) Motorized Damper (13) Barber Colman Actuator for K/159 T HE, DDE, DE (b) Motorized Damper (2-13) Barber Colman Actuator for K/159 T HE, DDE, DE (b) Motorized Damper (14) Barber Colman Actuator for K/159 T HE, DDE, DE (b) Motorized Damper (2-14) Limitorque Actuator for A/143 T HE, DDE, DE (b) Motorized Damper (1) Limitorque Actuator for A/143 C HE, DDE, DE (b) Motorized Damper (2-1) Limitorque Actuator for A/149 T HE, DDE, DE (b) Motorized Damper (1A) Limitorque Actuator for A/149 C HE, DDE, DE (b) Motorized Damper (2-1A) Limitorque Actuator for A/143 T HE, DDE, DE (b) Motorized Damper (1B) Limitorque Actuator for A/143 C HE, DDE, DE (b) DCPP UNITS 1 & 2 FSAR UPDATE Page 19 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Motorized Damper (2-1B) Limitorque Actuator for A/149 T HE, DDE, DE (b) Motorized Damper (1C) Limitorque Actuator for A/149 C HE, DDE, DE (b) Motorized Damper (2-1C) Pneumatic Contromatics Operator L/91 T HE, DDE, DE (b) for Fan S-1 Pneumatic Contromatics Operator L/91 C HE, DDE, DE (b) for Fan 2S-1 Pneumatic Contromatics Operator L/91 T HE, DDE, DE (b) for Fan S-2 Pneumatic Contromatics Operator L/91 C HE, DDE, DE (b) for Fan 2S-2 Pneumatic Contromatics Operator K/150 T HE, DDE, DE (b) for Fan S-31 Pneumatic Contromatics Operator K/150 C HE, DDE, DE (b) for Fan S-33 Pneumatic Contromatics Operator K/150 T HE, DDE, DE (b) for Fan S-32 Pneumatic Contromatics Operator K/150 C HE, DDE, DE (b) for Fan S-34 Pneumatic Contromatics Operator L/135 T HE, DDE, DE (b) for Fan E-1 Pneumatic Contromatics Operator L/135 C HE, DDE, DE (b) for Fan 2E-1 Pneumatic Contromatics Operator L/135 T HE, DDE, DE (b) for Fan E-2 Pneumatic Contromatics Operator L/135 C HE, DDE, DE (b) for Fan 2E-2 Pneumatic Contromatics Operator L/146 T HE, DDE, DE (b) for Fan E-4 Pneumatic Contromatics Operator L/146 C HE, DDE, DE (b) for Fan 2E-4 DCPP UNITS 1 & 2 FSAR UPDATE Page 20 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Pneumatic Contromatics Operator L/146 T HE, DDE, DE (b) for Fan E-5 Pneumatic Contromatics Operator L/146 C HE, DDE, DE (b) for Fan 2E-5 Pneumatic Contromatics Operator L/146 T HE, DDE, DE (b) for Fan E-6 Pneumatic Contromatics Operator for Fan 2E-6 L/146 C HE, DDE, DE (b) Fire Damper 12x14 (FD-128) K/73 A HE, DDE, DE (b) Fire Damper 12x14 (2FD-128) K/73 C HE, DDE, DE (b) Motor for Supply Fan OS-96 (CRPS) A/140' A HE, DDE, DE (b) Motor for Supply Fan OS-97 (CRPS) A/140' A HE, DDE, DE (b) Motor for Supply Fan OS-98 (CRPS) A/140' A HE, DDE, DE (b) Motor for Supply Fan OS-99 (CRPS) A/140' A HE, DDE, DE (b) Fire Damper 46x14 (FD-1) H/111 A HE, DDE, DE (b) Fire Damper 46x14 (2FD-1) H/111 C HE, DDE, DE (b) Fire Damper 46x14 (FD-2) H/111 A HE, DDE, DE (b) Fire Damper 46x14 (2FD-2) H/111 C HE, DDE, DE (b) Fire Damper 46x14 (FD-3) H/110 A HE, DDE, DE (b) Fire Damper 46x14 (2FD-3) H/110 C HE, DDE, DE (b) Fire Damper 32x68 (FD-24) J/100 A HE, DDE, DE (b) Fire Damper 32x68 (2FD-24) J/100 C HE, DDE, DE (b) Motors for Fans E-43, E-44, H/163 A HE, DDE, DE (b) S-43 and S-44 Motors for Fans E-45, E-46, H/163 C HE, DDE, DE (b) S-45 and S-46 DCPP UNITS 1 & 2 FSAR UPDATE Page 21 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Fire Damper 42x24 (FD-25) A/135 A HE, DDE, DE (b) Fire Damper 42x24 (2FD-25) A/135 C HE, DDE, DE (b) Fire Damper 42x24 (FD-26) A/135 A HE, DDE, DE (b) Fire Damper 42x24 (2FD-26) A/135 C HE, DDE, DE (b) Fire Damper 42x24 (FD-27) A/135 A HE, DDE, DE (b) Fire Damper 42x24 (2FD-27) A/135 C HE, DDE, DE (b) Fire Damper 36x39 (FD-19) A/140 A HE, DDE, DE (b) Fire Damper 36x39 (2FD-19) A/140 C HE, DDE, DE (b) Fire Damper 36x39 (FD-20) A/140 A HE, DDE, DE (b) Fire Damper 36x39 (2FD-20) A/140 C HE, DDE, DE (b) Fire Damper 36x39 (FD-21) A/140 A HE, DDE, DE (b) Fire Damper 36x39 (2FD-21) A/140 C HE, DDE, DE (b) Fire Damper 14x10 (FD-26) H/151 T HE, DDE, DE (b) Fire Damper 14x10 (2FD-26) H/151 T HE, DDE, DE (b) Fire Damper 20x10 (FD-27) H/153 T HE, DDE, DE (b) Fire Damper 20x10 (2FD-27) H/153 T HE, DDE, DE (b) Fire Damper 12x12 (FD-28) H/158 T HE, DDE, DE (b) Fire Damper 12x12 (2FD-28) H/158 T HE, DDE, DE (b) Varicel-Roughing Filter (EFR-1) L/120 A HE, DDE, DE (b) Varicel-Roughing Filter (2EFR-1) L/120 C HE, DDE, DE (b) Varicel-Roughing Filter (EFR-2a) L/122 A HE, DDE, DE (b) Varicel-Roughing Filter (2EFR-2a) L/122 C HE, DDE, DE (b) Varicel-Roughing Filter (EFR-2b) L/104 A HE, DDE, DE (b) Varicel-Roughing Filter (2EFR-2b) L/104 C HE, DDE, DE (b) Electric Duct Heater (EH-27) H/163 A HE, DDE, DE (b) Electric Duct Heater (2EH-27) H/163 A HE, DDE, DE (b) Electric Duct Heaters Tech. Support A HE, DDE, DE (a) (b) (OEH-28A & 28B) Center/109 DCPP UNITS 1 & 2 FSAR UPDATE Page 22 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Mode Damper 8 in. dia (0-17) Tech. Support A HE, DDE, DE (a) (b) Center/109 Ceiling Registers & Diffusers Aux./Varies A HE, DDE, DE (b) Wall Registers & Diffusers(Unit 1) Ceiling Registers & Diffusers Aux./Varies A, C HE, DDE, DE (b) Wall Registers & Diffusers (Unit 2) Aluminum Air Outlets (26" wide Aux./Varies A HE, DDE, DE (b) or less) "Metalaire" Aluminum Air Outlets (26" wide Aux./Varies C HE, DDE, DE (b) or less) "Metalaire" for Unit 2 Air Monitors (AM FE-5001, Aux./Varies A HE, DDE, DE (b) 5013, 5015, 5016, 5018A, 5018B, 5019 and 5020) and Flow Evaluators (FE-5014, 5017A and 5017B). Air Monitors (AM 2-FE-5001, Aux./Varies C HE, DDE, DE (b) 5002, 5003, 5004, 5005, 5006, 5007, 5008, 5009, 5010, 5011, 5012, 5013, 5015, 5019 and 5020) and Flow Evaluators (2-FE-5014, 5017A, 5017B, 5018A, 5018B). Air Flow Controllers Johnson Service R-317-1 for Fans Aux./Varies T HE, DDE, DE (b) Pressure Reducing Valve Johnson Service R-130-A for Fan & Dampers Aux./Varies T HE, DDE, DE (b) (g) Restrictors Johnson Service T-5210-100 for Fans Aux./Varies T HE, DDE, DE (b) DCPP UNITS 1 & 2 FSAR UPDATE Page 23 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Solenoid Valves ASCO HT-8316-B15, C15 and D45; HT-8320-A20, A24 and A185; and HT-8331-A45 for Fans & Dampers Aux./Varies T HE, DDE, DE (b) Speed Controllers ASCO VO221 Aux./Varies T HE, DDE, DE (b) Speed Controllers ASCO V0222 and VO223 Aux./Varies C HE, DDE, DE (b) Position Switches NAMCO D-2400-X-R2-WS for Dampers Aux./Varies T, C HE, DDE, DE (b) Brandt Air Flow Controller (Pi-DPT-2000) Aux./Varies T, A HE, DDE, DE (b) Portion of Refrigerant Piping with Solenoid Valve Exp. Valve with Sight Glass H/158 T HE, DDE, DE (b) Position Switches Allen-Bradley 802T-HW1 for Dampers Aux./Varies T HE, DDE, DE (b) Position Switches Allen-Bradley 802T-HW1 for Dampers Aux./Varies C HE, DDE, DE (b) Air Flow Switches Dwyer 1638 & 1640 for Fans Aux./Varies, Turbine bldg., Technical Support Center/Varies T, A HE, DDE, DE (a) (b) Air Flow Switches McDonald-Miller AF1-S for Fans Aux./Varies T, A HE, DDE, DE (a) (b) Thermostats Barber Colman TC-1191 H/145 T HE, DDE, DE (b) Thermostats Penn A28AA K/145 T HE, DDE, DE (b) DCPP UNITS 1 & 2 FSAR UPDATE Page 24 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Thermostats Penn T26J-2 A/124 T HE, DDE, DE (b) Thermostats Penn T26S-18 A/124 C HE, DDE, DE (b) Thermostats Johnson Controls T26S-18C A/124 C HE, DDE, DE (h) Control Relay Cabinets for H/157 T, A HE, DDE, DE (b) CRC-1 and CRC-3 Control Relay Cabinets for H/157 T, A HE, DDE, DE (b) CRC-6 and CRC-8 Common Control Relay H/157 T, A HE, DDE, DE (b) Cabinets for CCRC-2 Common Control Relay H/157 T, A HE, DDE, DE (b) Cabinets for CCRC-7 Control Panels for H/156 T HE, DDE, DE (b) Compressors CP-35 & CP-36 Control Panels for H/156 T HE, DDE, DE (b) Compressors CP-37 & CP-38 Heating Relay in Cabinet 3 H/157 T HE, DDE, DE (b) Thermostat Honeywell Model H/154 T HE, DDE, DE (b) T675A1565 & T6031A1029 Motors for Fans Aux./Varies T HE, DDE, DE (b) S-1, S-2, S-31, S-32, S-39, Intake Structure/Varies S-40, E-1, E-2, E-4, E-5, E-6, E-101, E-102, E-103 and E-104 Motors for Fans Aux./Varies C HE, DDE, DE (b) 2S-1, 2S-2, S-33, S-34, S-41, S-42, Intake Structure/Varies DCPP UNITS 1 & 2 FSAR UPDATE Page 25 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes 2E-1, 2E-2, 2E-4, 2E-5 and 2E-6 Motors for Fans Aux./Varies & T, C, A HE, DDE, DE (b) CR-35, CR-36, S-35, S-36, S-67, S-68, S-69 Turbine /Varies Motors for Fans Aux./Varies & C, A HE, DDE, DE (b) CR-37, CR-38, S-37, S-38, 2S-67, 2S-68, 2S-69 Turbine/Varies Flex connection in 48-in. L/Varies A HE, DDE, DE (b) Purge Air Supply Duct (Bldg. Displ. Per FC-1 & FC-2 DCM C-28) Flex connection in 48-in. L/Varies C HE, DDE, DE (b) Purge Air Supply Duct (Bldg. Displ. per 2FC-1 & 2FC-2 DCM C-28) Flex connection in 12-in. L/Varies A HE, DDE, DE (b) Excess Pressure Relief Duct FC-3 & FC-4 (Bldg. Displ. per Flex connection in 12-in. L/Varies C HE, DDE, DE (b) Excess Pressure Relief Duct 2FC-3 & 2FC-4 (Bldg. Displ. per Flex Connections in 14-in. Pipes Turbine bldg. A HE, DDE, DE (b) OFC-11, through OFC-16, OFC-18 /varies (Bldg. Displ. per through OFC-21 DCM C-28) Flex Connection in 14-in. Between A HE, DDE, DE (b) Pipe OFC-17 Aux. bldg. & (Bldg. Displ. per Turbine bldg./ 167 DCM C-28) Flex Connection in 14-in. Aux. bldg./163 A HE, DDE, DE (b) (d) Pipe OFC-22 (Bldg. Displ. Per DCM C-28) Flex Connection in 14-in. Aux. bldg./163 A HE, DDE, DE (b) (d) Pipe OFC-22 Unit 2 (Bldg. Displ. Per DCM C-28) DCPP UNITS 1 & 2 FSAR UPDATE Page 26 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Nutherm/Cleveland Airflow Switches Model H/169 T, A HE, DDE, DE (a) (b) AFS-951-1 for over heater in CRPS Motors for Compressors CP-35 H/154 A HE, DDE, DE (b) and CP-36 Motors for Compressors CP-37 H/154 C HE, DDE, DE (b) and CP-38 Fire Damper 24x12 (FD-7) H/110 A HE, DDE, DE (b) Fire Damper 24x12 (2FD-7) H/110 C HE, DDE, DE (b) Fire Damper 24x12 (FD-8) H/110 A HE, DDE, DE (b) Fire Damper 24x12 (2FD-8) H/110 C HE, DDE, DE (b) Fire Damper 24x12 (FD-9) H/110 A HE, DDE, DE (b) Fire Damper 24x12 (2FD-9) H/110 C HE, DDE, DE (b) Fire Damper (FD-34) H/127 T HE, DDE, DE (b) Fire Damper (2FD-34) H/127 C HE, DDE, DE (b) Fire Damper (FD-36) H/127 T HE, DDE, DE (b) Fire Damper (2FD-36) H/127 C HE, DDE, DE (b) Fire Damper (FD-38) H/126 T HE, DDE, DE (b) Fire Damper (FD-39) H/126 T HE, DDE, DE (b) Fire Damper (FD-40) H/123 T HE, DDE, DE (b) Fire Damper (FD-43) A/119 T HE, DDE, DE (b) Fire Damper (2FD-43) A/119 C HE, DDE, DE (b) Fire Damper (FD-44) A/119 T HE, DDE, DE (b) Fire Damper (2FD-44) A/119 C HE, DDE, DE (b) Fire Damper (FD-45) A/119 T HE, DDE, DE (b) Fire Damper (2FD-45) A/119 C HE, DDE, DE (b) Fire Damper (FD-10) H/121 A HE, DDE, DE (b) Fire Damper (2FD-10) H/121 C HE, DDE, DE (b) DCPP UNITS 1 & 2 FSAR UPDATE Page 27 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Fire Damper (FD-11) H/121 A HE, DDE, DE (b) Fire Damper (2FD-11) H/121 C HE, DDE, DE (b) Fire Damper (FD-12) H/121 A HE, DDE, DE (b) Fire Damper (2FD-12) H/121 C HE, DDE, DE (b) Smoke Damper (SD-26) H/151 A HE, DDE, DE (b) Smoke Damper (2SD-26) H/151 C HE, DDE, DE (b) Smoke Damper (SD-27) H/151 A HE, DDE, DE (b) Smoke Damper (2SD-27) H/151 C HE, DDE, DE (b) Smoke Damper (SD-35) H/127 A HE, DDE, DE (b) Smoke Damper (2SD-35) H/127 C HE, DDE, DE (b) Smoke Damper (SD-37) H/127 A HE, DDE, DE (b) Smoke Damper (2SD-37) H/127 C HE, DDE, DE (b) Pneumatic Bettis Actuator for Aux/Varies T HE, DDE, DE (b) Damper (4A) Pneumatic Bettis Actuator for Aux/Varies T HE, DDE, DE (b) Damper (2-4A) Pneumatic Bettis Actuator for T HE, DDE, DE (b) Damper (4B) Pneumatic Bettis Actuator for Aux/Varies T HE, DDE, DE (b) Damper (2-4B) Pneumatic Bettis Actuator for T HE, DDE, DE (b) Damper (8A) Pneumatic Bettis Actuator for Aux/Varies T HE, DDE, DE (b) Damper (2-8A) Pneumatic Bettis Actuator for T HE, DDE, DE (b) Damper (8B) Pneumatic Bettis Actuator for Aux/Varies T HE, DDE, DE (b) Damper (2-8B) Pneumatic Bettis Actuator for T HE, DDE, DE (b) Damper (10) Pneumatic Bettis Actuator for Aux/Varies T HE, DDE, DE (b) Damper (2-10) DCPP UNITS 1 & 2 FSAR UPDATE Page 28 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Power Regulator Co. Actuator Aux/Varies T HE, DDE, DE (b) for Damper (12) Power Regulator Co. Actuator T HE, DDE, DE (b) for Damper (16A) Power Regulator Co. Actuator Aux/Varies C HE, DDE, DE (b) for Damper (2-16A) Power Regulator Co. Actuator T HE, DDE, DE (b) for Damper (16B) Power Regulator Co. Actuator Aux/Varies C HE, DDE, DE (b) for Damper (2-16B) Power Regulator Co. Actuator T HE, DDE, DE (b) for Damper (17A) Power Regulator Co. Actuator Aux/Varies C HE, DDE, DE (b) for Damper (2-17A) Power Regulator Co. Actuator T HE, DDE, DE (b) for Damper (17B) Power Regulator Co. Actuator Aux/Varies C HE, DDE, DE (b) for Damper (2-17B) Power Regulator Co. Actuator T HE, DDE, DE (b) for Damper (20) Power Regulator Co. Actuator Aux/Varies C HE, DDE, DE (b) for Damper (2-20) Power Regulator Co. Actuator Aux/Varies T HE, DDE, DE (b) for Damper (21) Power Regulator Co. Actuator Aux/Varies C HE, DDE, DE (b) for Damper (2-21) Power Regulator Co. Actuator T HE, DDE, DE (b) for Damper (22A) Power Regulator Co. Actuator Aux/Varies C HE, DDE, DE (b) for Damper (2-22A) Power Regulator Co. Actuator T HE, DDE, DE (b) for Damper (22B) Power Regulator Co. Actuator Aux/Varies C HE, DDE, DE (b) for Damper (2-22B) Power Regulator Co. Actuator T HE, DDE, DE (b) DCPP UNITS 1 & 2 FSAR UPDATE Page 29 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes for Damper (23A) Power Regulator Co. Actuator Aux/Varies C HE, DDE, DE (b) for Damper (2-23) Power Regulator Co. Actuator T HE, DDE, DE (b) for Damper (23B) Power Regulator Co. Actuator Aux/Varies C HE, DDE, DE (b) for Damper (2-23B) Power Regulator Co. Actuator T HE, DDE, DE (b) for Damper (24A) Power Regulator Co. Actuator Aux/Varies C HE, DDE, DE (b) for Damper (2-24) Power Regulator Co. Actuator T HE, DDE, DE (b) for Damper (24B) Power Regulator Co. Actuator Aux/Varies C HE, DDE, DE (b) for Damper (2-24B) Power Regulator Co. Actuator T HE, DDE, DE (b) for Damper (25A) Power Regulator Co. Actuator Aux/Varies C HE, DDE, DE (b) for Damper (2-25) Power Regulator Co. Actuator T HE, DDE, DE (b) for Damper (25B) Power Regulator Co. Actuator Aux/Varies C HE, DDE, DE (b) for Damper (2-25B) Power Regulator Co. Actuator T HE, DDE, DE (b) for Damper (26A) Power Regulator Co. Actuator Aux/Varies C HE, DDE, DE (b) for Damper (2-26A) Power Regulator Co. Actuator T HE, DDE, DE (b) for Damper (26B) Power Regulator Co. Actuator Aux/Varies C HE, DDE, DE (b) for Damper (2-26B) Power Regulator Co. Actuator T HE, DDE, DE (b) for Damper (33) Power Regulator Co. Actuator Aux/Varies C HE, DDE, DE (b) for Damper (2-33) Power Regulator Co. Actuator T HE, DDE, DE (b) for Damper (34) DCPP UNITS 1 & 2 FSAR UPDATE Page 30 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Power Regulator Co. Actuator Aux/Varies C HE, DDE, DE (b) for Damper (2-34) Pneumatic Parker-Hannifin L/127 A HE, DDE, DE (b) Actuator for Mode Damper (1A) Pneumatic Parker-Hannifin L/127 A HE, DDE, DE (b) Actuator for Mode Damper (2-1A) Pneumatic Parker-Hannifin L/131 C HE, DDE, DE (b) Actuator for Mode Damper (1B) Pneumatic Parker-Hannifin L/131 C HE, DDE, DE (b) Actuator for Mode Damper (2-1B) Pneumatic Parker-Hannifin K/97 A HE, DDE, DE (b) Actuator for Damper (13A) Pneumatic Parker-Hannifin K/97 C HE, DDE, DE (b) Actuator for Damper (2-13A) Pneumatic Parker-Hannifin K/97 A HE, DDE, DE (b) Actuator for Damper (13B) Pneumatic Parker-Hannifin K/97 C HE, DDE, DE (b) Actuator for Damper (2-13B) Pneumatic Parker-Hannifin K/81 A HE, DDE, DE (b) Actuator for Damper (14A) Pneumatic Parker-Hannifin K/81 C HE, DDE, DE (b) Actuator for Damper (2-14A) Pneumatic Parker-Hannifin K/81 A HE, DDE, DE (b) Actuator for Damper (14B) Pneumatic Parker-Hannifin K/81 C HE, DDE, DE (b) Actuator for Damper (2-14B) Pneumatic Parker-Hannifin Aux/70 A HE, DDE, DE (b) Actuator for Damper (15A) Pneumatic Parker-Hannifin Aux/70 C HE, DDE, DE (b) Actuator for Damper (2-15A) Pneumatic Parker-Hannifin Aux/70 A HE, DDE, DE (b) Actuator for Damper (15B) Pneumatic Parker-Hannifin Aux/70 C HE, DDE, DE (b) Actuator for Damper (2-15B) DCPP UNITS 1 & 2 FSAR UPDATE Page 31 of 31 TABLE 3.10-3 Revision 21 September 2013 Equipment Location(c) Building/ Elevation, ft Qualification Method(c) Qualifying Spectra(c) Notes Position Switches L/115 T HE, DDE, DE (b) NAMCO SL-3B1W & SL-170D for Dampers (a) Turbine building, Unit 2, response spectra applicable for Qualification Spectra of equipment in the Technical Support Center. (b) Envelope of 4% HE and 2% DDE Acceleration used in Qualification Spectra. Per DCM T-10 acceptance criteria, DE stresses shall not exceed the maximum allowable stress values specified in building codes (Uniform Building Code, 1973 and AISC, 1969). Increase in allowable stresses, permitted by code for seismic loads, shall not be used. In lieu of these, DDE and Hosgri stresses shall not exceed 90% of the yield strength and 150% of the AISC allowable stress, respectively. (c) Legend: ISA = Intake structure area A = Qualification Spectra by analysis (Qualification Method column) T = Qualification Spectra by testing C = Comparison with similarly qualified equipment DE = Design Earthquake DDE = Double Design Earthquake HE = Hosgri Earthquake
The letters in the Location column refer to standard area designations as defined in Figure 1.2-3, Piping and Mechanical Area Location Plan. (d) Tag number of flexible connection OFC-22 has been duplicated.
(e) Quadrant dampers supported on flexible slab.
(f) Applicable to Units 1 and 2.
(g) Due to obsolescence of Johnson air pressure reducing regulators, Fisher 67CSR regulators may be installed. (h) Due to obsolescence of Penn thermostats, Johnson Controls T26S-18C thermostats may be installed. Revision 13 April 2000 Revision 13 April 2000FIGURE 3.3-1 TURBINE BUILDING FRAMING MODIFICATIONS FOR TORNADO RESISTANCE - ELEVATIONUNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 13 April 2000FIGURE 3.3-2 TURBINE BUILDING FRAMING MODIFICATIONS FOR TORNADO RESISTANCE - SECTION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 3.3-3 LAYOUT OF VULNERABLE MAIN STEAM RELIEF VALVES AND CABLE TRAY OUTSIDE OF PLANT UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 3.3-4 (SHEET 1 OF 2) SCHEMATIC LAYOUT OF CABLE SPREADING AND SWITCHGEAR ROOMS IN THE TURBINE BUILDING UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 3.3-4 (SHEET 2 OF 2) SCHEMATIC LAYOUT OF CABLE SPREADING AND SWITCHGEAR ROOMS IN THE TURBINE BUILDING UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE
Missile Shield Missile Shield FIGURE 3.5-1 INTEGRATED HEAD ASSEMBLY REACTOR MISSILE SHIELD UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 20 November 2011 Revision 11 November 1996FIGURE 3.5-2 CONTAINMENT STRUCTURE PRESSURIZER MISSILE SHIELD UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-1 LOSS OF COOLANT ACCIDENT BOUNDARY LIMITS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-3 TYPICAL PIPE RUPTURE RESTRAINT UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-3A PIPE RUPTURE RESTRAINT TYPICAL ROD ARRANGEMENT UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-3B PIPE RUPTURE RESTRAINT TYPICAL U-BOLT UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-3C PIPE RUPTURE RESTRAINT CRUSHABLE BUMPER ARRANGEMENT UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE RV = REACTOR VESSEL SG = STEAM GENERATOR RCP = REACTOR COOLANT PUMP Revision 12 September 1998 FIGURE 3.6-4 PRIMARY COOLANT LOOP BREAKS (See Section 3.6.2.2.1) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 3.6-16 TURBINE BUILDING PRESSURE vs. TIME RESPONSE MSLB AT ELEVATION 140' (DER) STEAM WITH ENTRAINMENT UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-17 TURBINE BUILDING PRESSURE vs. TIME RESPONSE MSLB AT ELEVATION 85' (DER) STEAM WITH ENTRAINMENT UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-18 AREA GE/GW PRESSURE vs. TIME RESPONSE MSLB AT ELEVATION 115' (DER) STEAM WITH ENTRAINMENT UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-19 AREA GE/GW PRESSURE vs. TIME RESPONSE MSLB AT G-ROW ANCHOR (DER) STEAM WITH ENTRAINMENT UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-20 AREA H, K PRESSURE vs. TIME RESPONSE CVCS LETDOWN LINE IN AREA K AT ELEVATION 85' (DER) UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-21 AREA H, K PRESSURE vs. TIME RESPONSE CVCS LETDOWN LINE IN AREA K AT ELEVATION 85' (DER) UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-22 AREA H, K PRESSURE vs. TIME RESPONSE CVCS LETDOWN LINE IN AREA K AT ELEVATION 85' (DER) UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-23 AREA H, K PRESSURE vs. TIME RESPONSE AUXILIARY STEAM LINE IN AREA K AT ELEVATION 100' (CRACK BREAK) UNIT 1 DIABLO CANYON SITE FSAR UPDATE FSAR UPDATE UNIT 1 DIABLO CANYON SITE FIGURE 3.6-24 AREA J PRESSURE vs. TIME RESPONSE AUXILIARY STEAM LINE IN TURBINE DRIVEN AUXILIARY FW PUMP ROOM (CRACK BREAK) Revision 12 September 1998 Revision 11 November 1996FIGURE 3.6-25 AREA J PRESSURE vs. TIME RESPONSE AUXILIARY STEAM LINE IN MOTOR DRIVEN AUXILIARY FW PUMP ROOM, (CRACK BREAK)UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-26 AREA L PRESSURE vs. TIME RESPONSE AUXILIARY FW PUMP STEAM SUPPLY LINE AT ELEVATION 115" (DER) UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-28 TURBINE BUILDING TEMPERATURE vs. TIME RESPONSE MSLB AT ELEVATION 85" (DER) STEAM WITHOUT ENTRAINMENT UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-29 TURBINE BUILDING TEMPERATURE vs. TIME RESPONSE MSLB AT ELEVATION 85" (SPLIT RUPTURE) UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-30 TURBINE BUILDING LONG TERM TEMPERATURE vs. TIME RESPNSES UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-31 AREA GE/GW TEMPERATURE vs. TIME RESPONSE MSLB AT ELEVATION 115' (DER), STEAM WITHOUT ENTRAINMENT UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-32 AREA GE/GW TEMPERATURE vs. TIME RESPONSE MSLB AT ELEVATION 115' (PLIT RUPTURE) UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 3.6-33 AREA GE/GW LONG TERM TEMPERATURE vs. TIME RESPONSE UNIT 1 DIABLO CANYON SITEFSAR UPDATE Revision 11 November 1996FIGURE 3.6-34 AREA H, K TEMPERATURE vs. TIME RESPONSE CVCS LETDOWN LINE BREAK IN AREA K AT ELEVATION 85', (DER) UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-35 AREA H, K TEMPERATURE vs. TIME RESPONSE CVCS LETDOWN LINE IN AREA K AT ELEVATION 85', (DER) UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-36 AREA H, K TEMPERATURE vs. TIME RESPONSE CVCS LETDOWN LINE IN AREA K AT ELEVATION 85' (DER) UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 3.6-37 AREA H, K TEMPERATURE vs. TIME RESP0NSE AUXILIARY STEAM LINE IN AREA K AT ELEVATION 100' (CRACK BREAK) UNIT 1 DIABLO CANYON SITE FSAR UPDATE FSAR UPDATE UNIT 1 DIABLO CANYON SITE FIGURE 3.6-38 AREA H, K LONG TERM TEMPERATURE vs. TIME RESPONSE CVCS LETDOWN LINE IN AREA K AT ELEVATION 85 FT (DER) Revision 12 September 1998 Revision 11 November 1996 FIGURE 3.6-39 AREA H, K LONG TERM TEMPERATURE vs. TIME RESP0NSE AUXILIARY STEAM LINE IN AREA K AT ELEVATION 100' (CRACK BREAK) UNIT 1 DIABLO CANYON SITE FSAR UPDATE FSAR UPDATE UNIT 1 DIABLO CANYON SITE FIGURE 3.6-40 AREA J TEMPERATURE vs. TIME RESPONSE AUXILIARY STEAM LINE IN TURBINE DRIVEN AUXILIARY FW PUMP ROOM (CRACK BREAK) Revision 12 September 1998 Revision 11 November 1996FIGURE 3.6-41 AREA J TEMPERATURE vs. TIME RESP0NSE AUXILIARY STEAM LINE IN MOTOR DRIVEN AUXILIARY FW PUMP ROOM, (CRACK BREAK)UNIT 1 DIABLO CANYON SITE FSAR UPDATE FSAR UPDATE UNIT 1 DIABLO CANYON SITE FIGURE 3.6-42 AREA J LONG TERM TEMPERATURE vs. TIME RESPONSE Revision 12 September 1998 Revision 11 November 1996FIGURE 3.6-43 AREA L TEMPERATURE vs. TIME RESP0NSE AUXILIARY FW PUMP STEAM SUPPLY LINE AT ELEVATION 115', (DER) UNIT 1 DIABLO CANYON SITE FSAR UPDATE FSAR UPDATE UNIT 1 DIABLO CANYON SITE FIGURE 3.6-44 AREA L LONG TERM TEMPERATURE vs. TIME RESPONSE AUXILIARY FW PUMP STEAM SUPPL LINE AT ELEVATION 115', (DER) Revision 12 September 1998
FIGURE 3.7-7A POLAR CRANE THREE DIMENSIONAL NONLINEAR MODEL UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013
FIGURE 3.7-27A REACTOR PRESSURE VESSEL SHELL SUBMODEL UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 20 November 2011 FIGURE 3.7-27B CORE BARREL SUBMODEL UNIT 1 DIABLO CANYON SITEFSAR UPDATE Revision 20 November 2011 Revision 19 May 2010UNIT 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 3.7-27C CORE BARREL SUBMODEL FIGURE 3.7-27D INTERNALS (INNERMOST) SUBMODEL UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 20 November 2011 FIGURE 3.7-27E ASSEMBLED FINITE ELEMENT SYSTEM MODEL UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 20 November 2011
DCPP UNITS 1 & 2 FSAR UPDATE
APPENDIX 3.1A AEC GENERAL DESIGN CRITERIA - 1971
DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-1 Revision 21 September 2013 Appendix 3.1A AEC GENERAL DESIGN CRITERIA - 1971 As stated and described in Diablo Canyon Power Plant (DCPP) UFSAR Section 3.1, the DCPP units are designed to comply with the "General Design Criteria for Nuclear Power Plant Construction Permits," published by the Atomic Energy Commission (AEC) in July, 1967. Appendix 3.1A briefly discusses the extent to which the original DCPP principal design features (the 1967 GDCs plus additional design features) for plant structures, systems and components (SSCs) conform to the intent of the AEC "General Design Criteria for Nuclear Power Plants" published in February 1971 as Appendix A to 10 CFR Part 50 (i.e., the 1971 GDCs). Submittal of the FSAR using RG 1.70, Rev 1 format and content was expected by the NRC as part of the initial DCPP licensing process, even though the NRC acknowledged in NUREG-0675 (SER-00) that the DCPP design basis was the 1967 GDCs. Each 10 CFR Part 50, Appendix A 1971 GDC is addressed below including a summary of how the DCPP principal design features (the 1967 GDCs plus additional design features) demonstrates conformance to the intent of or exceptions to the criterion. The discussion of each GDC refers to sections of the FSAR presenting the details of the DCPP Units 1 and 2 designs. FSAR Table 3.1-2 provides a matrix listing of the 1971 GDC to the related 1967 GDC. Any exceptions to the 1971 GDCs that DCPP identified and the NRC approved in writing resulting from earlier DCPP design or construction commitments are identified in the discussion of the corresponding criterion in this Appendix. The discussion of how the plant design conformed to the intent of the 1971 GDCs was included in the original FSAR in Appendix 3.1A, and was reviewed by the NRC to conclude that DCPP's design conformed to the intent of the 1971 GDCs. The degree to which the DCPP design conforms to the intent of the 1971 GDCs, as summarized in this Appendix, establishes additional DCPP licensing basis which must be reviewed when evaluating facility changes. Criterion 1, 1971 - Quality Standards and Records Structures, systems, and components important to safety shall be designed, fabricated, erected, and tested to quality standards commensurate with the importance of the safety functions to be performed. Where generally recognized codes and standards are used, they shall be identified and evaluated to determine their applicability, adequacy, and sufficiency and shall be supplemented or modified as necessary to assure a quality product in keeping with the required safety function. A quality assurance program shall be established and implemented in order to provide adequate assurance that these structures, systems, and components will satisfactorily perform their safety function. Appropriate records of the design, fabrication, erection and testing of structures, systems, and components important to safety shall be maintained by or under the control of the nuclear power unit licensee throughout the life of the unit. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-2 Revision 21 September 2013 Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 1. SSCs have been designed, fabricated, erected, and tested to quality levels commensurate with their relationship to safety. The appropriate codes employed for various items have been supplemented where required. A quality assurance program consistent with the 10 CFR 50, Appendix B, requirements has been employed and appropriate records have been made and are being maintained directly by PG&E or are under PG&E's control. All systems and components of DCPP Units 1 and 2 are classified according to their importance in the prevention and mitigation of accidents. Those items vital to safe shutdown and isolation of the reactor, or whose failure might cause or increase the severity of a LOCA, or result in an uncontrolled release of excessive amounts of radioactivity, are designated PG&E Design Class I. Those items important to the reactor operation, but not essential to safe shutdown and isolation of the reactor or control of the release of substantial amounts of radioactivity, are designated PG&E Design Class II. Those items not related to reactor operation or safety are designated PG&E Design Class III. PG&E Design Class I systems and components are essential to the protection of the health and safety of the public. Consequently, they are designed, fabricated, inspected, erected, and the materials selected to the applicable provisions of recognized codes, good nuclear practice, and to quality standards that reflect their importance. Discussions of applicable codes and standards as well as code classes are given in Section 3.2 for the major items and components. The quality assurance (QA) program conforms to the requirements of 10 CFR 50 Appendix B, Quality Assurance Criteria for Nuclear Power Plants. Details of the QA program are provided in Chapter 17. Records of the design, fabrication, construction and testing of PG&E Design Class I components of the plant will be maintained by Pacific Gas and Electric Company or under its control throughout the life of the plant. Chapter 17 of the UFSAR describes the procedures for keeping these records. Operating records to be maintained throughout the life of the plant are described in Chapter 13 of the UFSAR. This criterion is associated with 1967 GDCs 1 and 5. Criterion 2, 1971 - Design Basis for Protection Against Natural Phenomena Structures, systems, and components important to safety shall be designed to withstand the effects of natural phenomena such as earthquakes, tornadoes, hurricanes, floods, tsunami, and seiches without loss of capability to perform their safety functions. The design bases for these structures, systems, and components shall reflect: (1) Appropriate consideration of the most severe of the natural phenomena that have been historically reported for the site and surrounding area, with DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-3 Revision 21 September 2013 sufficient margin for the limited accuracy, quantity, and period of time in which the historical data have been accumulated, (2) Appropriate combinations of the effects of normal and accident conditions with the effects of the natural phenomena, and (3) The importance of the safety functions to be performed. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 2. The components, structures and systems important to safety have been designed to accommodate without loss of capability the most severe natural phenomena recorded for the site and surrounding areas with appropriate combinations of postulated accidents and natural phenomena. The importance of the safety functions of the various items has been considered. The site characteristics are discussed in Chapter 2. Wind design criteria and flood design criteria are found in Sections 3.3 and 3.4, respectively. Seismic design is discussed in Section 3.7. This criterion is associated with 1967 GDC 2. Criterion 3, 1971 - Fire Protection Structures, systems, and components important to safety shall be designed and located to minimize, consistent with other safety requirements, the probability and effect of fires and explosions. Noncombustible and heat-resistant materials shall be used wherever practical throughout the unit, particularly in locations such as the containment and control room. Fire detection and fighting systems of appropriate capacity and capability shall be provided and designed to minimize the adverse effects of fires on structures, systems, and components important to safety. Firefighting systems shall be designed to assure that their rupture or inadvertent operation does not significantly impair the safety capability of these structures, systems, and components. Discussion The DCPP Units 1 and 2 designs conform to the requirements of 10 CFR 50.48, which invokes the requirements Criterion 3, 1971. GDC 3 (1971) is invoked by 10 CFR 50.48, Fire Protection. The fire protection program for DCPP satisfies the requirements of GDC 3 (1971) by complying with the guidelines of Appendix A to NRC Branch Technical Position (BTP) (APCSB) 9.5-1, and with the provisions of 10 CFR 50 Appendix R, Sections III.G, J, L, and O, as stipulated by Operating License Conditions 2.C(5) and 2.C(4) for Units 1 and 2, respectively. Approved deviations from Appendix A to BTP (APCSB) 9.5-1, and Appendix R sections DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-4 Revision 21 September 2013 are identified in Supplement Numbers 8, 9, 13, 23, 27, and 31 to the Safety Evaluation Report (NUREG-0675). The probability of fires and explosions is minimized by extensive use of noncombustible and fire resistant materials, by physical isolation and protection of flammable fluids, by providing both automatic and manual fire extinguishing systems, and by use of fire detection systems. Electrical insulation is made of fire retardant, self-extinguishing materials. All exposed electrical raceways are metal and have fire stops liberally applied. Electrical conductors have adequate ratings and overcurrent protection to prevent breakdown or excessive heating. Electrical equipment for safety systems is physically arranged to minimize the effect of a potential fire. Vital interconnecting circuits are located to avoid potential fire hazards as much as possible, with mutually redundant circuits placed in separate raceways. The facility is equipped with a fire protection system (FPS) for controlling any fire that might originate in plant equipment. This system is described in Section 9.5.1. The containment and auxiliary building ventilation systems are operated from the control room. Critical areas of the plant have detectors and alarms to alert the control room operator of the possibility of fire, so that prompt action can be taken to prevent significant damage. This criterion is associated with 1967 GDC 3. Criterion 4, 1971 - Environmental and Missile Design Bases Structures, systems, and components important to safety shall be designed to accommodate the effects of and to be compatible with the environmental conditions associated with normal operation, maintenance, testing, and postulated accidents, including loss-of-coolant accidents. These structures, systems, and components shall be appropriately protected against dynamic effects, including the effects of missiles, pipe whipping, and discharging fluids, that may result from equipment failures and from events and conditions outside the nuclear power unit. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 4. The safety-related components, structures, and systems are designed to accommodate all normal or routine environmental conditions as well as those associated with postulated accidents. The designs include provisions to protect, where appropriate, those safety-related items from dynamic effects resulting from component failures and specific credible outside events and conditions. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-5 Revision 21 September 2013 Use of conservative design methods, segregated routing of piping, provision of missile shield walls, and use of engineered hangers and pipe restraints are incorporated in the design to accommodate dynamic effects of postulated accidents. The various sources of missiles that might affect ESFs have been identified, and protective measures have been devised to minimize these effects (see Section 3.5). The basic approach for protection of Class 1E equipment and cables from missiles is to ensure design adequacy against generation of missiles. Where missiles cannot be contained within parent equipment, missile protection is attained by routing or placing Class 1E cables and equipment in non-missile prone areas or by shielding the equipment. This criterion is associated with 1967 GDC 40. Criterion 5, 1971 - Sharing of Structures, Systems and Components Structures, systems, and components important to safety shall not be shared between nuclear power units unless it can be shown that such sharing will not significantly impair their ability to perform their safety functions, including, in the event of an accident in one unit, an orderly shutdown and cooldown of the remaining units. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 5. Those SSCs that are shared are designed in such a manner that plant safety is not impaired by the sharing. A list of shared components and systems is given in Section 1.2. This criterion is associated with 1967 GDC 4. Criterion 10, 1971 - Reactor Design The reactor core and associated coolant, control, and protection systems shall be designed with appropriate margin to assure that specified acceptable fuel design limits are not exceeded during any condition of normal operation, including the effects of anticipated operational occurrences. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 10. Appropriate fuel margins are included in each design. Each reactor core with its related control and protection systems is designed to function throughout its design lifetime without exceeding acceptable fuel damage limits. Core design, together with reliable process and decay heat removal systems, provides for this capability under all expected conditions of normal operation with appropriate margins for uncertainties and anticipated transient situations, including the effects of the DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-6 Revision 21 September 2013 loss of reactor coolant flow, trip of the turbine generator, loss of normal feedwater and loss of offsite power. The reactor control and protection instrumentation systems are designed to initiate a reactor shutdown for any anticipated combination of plant conditions when necessary to assure a minimum DNB ratio equal to or greater than the applicable limit value (see Sections 4.4.1.1 and 4.4.2.3) and fuel center temperatures below the melting point of UO2. Chapter 4 discusses the design bases and design evaluation of reactor components. The details of the control and protection instrumentation systems design and logic are discussed in Chapter 7. This information supports the accident analyses presented in Chapter 15. This criterion is associated with 1967 GDC 6. Criterion 11, 1971 - Reactor Inherent Protection The reactor core and associated coolant systems shall be designed so that in the power operating range the net effect of the prompt inherent nuclear feedback characteristics tends to compensate for a rapid increase in reactivity. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 11. A negative reactivity coefficient is a basic feature of each design. Prompt compensatory reactivity feedback effects are ensured when each reactor is critical by the negative fuel temperature effect (Doppler effect) and by the operational limit on moderator temperature coefficient of reactivity. The negative Doppler coefficient of reactivity is ensured by the inherent design using low-enrichment fuel. The limits on moderator temperature coefficient of reactivity are ensured by administratively controlling the dissolved neutron absorber concentration and control rod position. These reactivity coefficients are discussed in Section 4.3. This criterion is associated with 1967 GDC 8. Criterion 12, 1971 - Suppression of Reactor Power Oscillations The reactor core and associated coolant, control and protection systems shall be designed to assure that power oscillations which can result in conditions exceeding specified acceptable fuel design limits are not possible or can be reliably and readily detected and suppressed. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-7 Revision 21 September 2013 Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 12. The designs include provisions to detect and control those power oscillations that might exceed acceptable fuel design limits during operation. Oscillations due to xenon spatial effects, in the radial, diametral, and azimuthal overtone modes, are heavily damped due to the inherent design and due to the negative Doppler and non-positive moderator temperature coefficients of reactivity. Oscillations due to xenon spatial effects, in the axial first overtone mode, may occur. Assurance that fuel design limits are not exceeded by xenon axial oscillations is provided as a result of reactor trip functions using the measured axial power imbalance as an input. Oscillations due to xenon spatial effects, in axial modes higher than the first overtone, are heavily damped due to the inherent design and due to the negative Doppler coefficient of reactivity. The stability of the cores against xenon-induced power oscillations and the functional requirements of instrumentation for monitoring and measuring core power distributions are discussed in Section 4.3. Details of the instrumentation design and logic are discussed in Chapter 7. This criterion is associated with 1967 GDC 7. Criterion 13, 1971 - Instrumentation and Control Instrumentation shall be provided to monitor variables and systems over their anticipated range for normal operation, for anticipated operational occurrences, and for accident conditions as appropriate to assure adequate safety, including those variables and systems that can affect the fission process, the integrity of the reactor core, the reactor coolant pressure boundary, and the containment and its associated systems. Appropriate controls shall be provided to maintain these variables and systems within prescribed operating ranges. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 13. Appropriate instrumentation and control systems have been provided to monitor and control pertinent variables and systems over normal range of operation and postulated accident conditions. Reactor, control rod, boron concentration, pressurizer pressure and level, feedwater, steam dump, and turbine instrumentation and controls are provided to monitor and maintain variables within prescribed operating ranges. Reactor protection systems that DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-8 Revision 21 September 2013 receive plant instrumentation signals and automatically actuate alarms, inhibit control rod withdrawal, initiate load cutback, and/or trip the reactors as prescribed limits are approached or reached are also provided. These systems are discussed in Chapter 7. The reactivity control and nuclear instrumentation system are discussed in Chapters 4 and 7. This criterion is associated with 1967 GDCs 12, 13, 14, and 15. Criterion 14, 1971 - Reactor Coolant Pressure Boundary The reactor coolant pressure boundary shall be designed, fabricated, erected, and tested so as to have an extremely low probability of abnormal leakage, of rapidly propagating failure, and of gross rupture. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 14. The design, fabrication, erection, and testing employed on each reactor coolant pressure boundary and the extensive quality control measures employed during each of the above phases ensure that these pressure boundaries have extremely low probabilities of abnormal leakage, rapidly propagating failure, and gross rupture. In addition to the loads imposed on the system under normal operating conditions, abnormal loading conditions, such as seismic loading and pipe rupture, are also considered, as discussed in Sections 3.6 and 3.7. The systems are protected from overpressure by means of pressure-relieving devices as required by applicable codes. Means are provided to detect significant uncontrolled leakage from either reactor coolant pressure boundary with indication in the control room as discussed in Section 5.2. Each RCS boundary has provisions for inspection, testing, and surveillance of critical areas to assess the structural and leaktight integrity. The details of these provisions are given in Section 5.2. For each reactor vessel, a material surveillance program conforming to applicable codes is provided. Additional details are provided in Section 5.4. The materials of construction of the pressure-retaining boundary of the RCS are protected by control of coolant chemistry from corrosion that might otherwise reduce the system structural integrity during its service lifetime. This criterion is associated with 1967 GDC 9. Criterion 15, 1971 - Reactor Coolant System Design The reactor coolant system and associated auxiliary, control, and protection systems shall be designed with sufficient margin to assure that the design conditions of the DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-9 Revision 21 September 2013 reactor coolant pressure boundary are not exceeded during any condition of normal operation, including anticipated operational occurrences. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 15. Each reactor coolant system (RCS) design and associated pertinent systems include sufficient margin to assure that the appropriate design limits of the reactor coolant pressure boundary are not exceeded during normal operation, including transients as defined in Chapter 15. Reactor internals analysis and testing are described in Section 3.9. The reactor coolant system is discussed in Chapter 5. No direct association exists with the 1967 GDC for this criterion. Criterion 16, 1971 - Containment Design Reactor containment and associated systems shall be provided to establish an essentially leaktight barrier against the uncontrolled release of radioactivity to the environment and to assure that the containment design conditions important to safety are not exceeded for as long as postulated accident conditions require. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 16. The reactor containment is a reinforced concrete structure with a steel liner that provides an essentially leaktight barrier against the uncontrolled release of radioactivity to the environment under any postulated accident condition. The reactor containment structure and penetrations, with the aid of containment heat removal systems, are designed to limit radiation doses resulting from leakage of radioactive fission products from the containment to below 10 CFR 100 values, assuming the largest credible energy release following a LOCA, including a margin to cover the effects of metal water or other undefined energy sources. The containment design is described in detail in Section 3.8.1. This criterion is associated with 1967 GDCs 10 and 49. Criterion 17, 1971 - Electric Power Systems An onsite electric power system and an offsite electric power system shall be provided to permit functioning of structures, systems, and components important to safety. The safety function for each system (assuming the other system is not functioning) shall be to provide sufficient capacity and capability to assure that (1) specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational occurrences and (2) the core is cooled DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-10 Revision 21 September 2013 and containment integrity and other vital functions are maintained in the event of postulated accidents. The onsite electric power supplies, including the batteries, and the onsite electric distribution system, shall have sufficient independence, redundancy, and testability to perform their safety functions assuming a single failure. Electric power from the transmission network to the onsite electric distribution system shall be supplied by two physically independent circuits (not necessarily on separate rights of way) designed and located so as to minimize to the extent practical the likelihood of their simultaneous failure under operating and postulated accident and environmental conditions. A switchyard common to both circuits is acceptable. Each of these circuits shall be designed to be available in sufficient time following a loss of all onsite alternating current power supplies and the other offsite electric power circuit, to assure that specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded. One of these circuits shall be designed to be available within a few seconds following a loss-of-coolant accident to assure that core cooling, containment integrity, and other vital safety functions are maintained. Provisions shall be included to minimize the probability of losing electric power from any of the remaining supplies as a result of, or coincident with, the loss of power generated by the nuclear power unit, the loss of power from the transmission network, or the loss of power from the onsite electric power supplies. Discussion The DCPP Units 1 and 2 designs conform to Criterion 17 instead of 1967 GDC 39. This is an exception to the commitments to 1967 GDCs. The DCPP Offsite Power System is designed to supply offsite electrical power by two physically independent circuits. The 230-kV system provides startup and standby power, and is immediately available following a design basis accident to assure that core cooling, containment integrity, and other vital safety functions are maintained. The 500-kV system provides for transmission of the plant's electric power output. The 500-kV connection also provides a delayed access source of offsite power after the main generator is disconnected. A combination of the 230-kV circuits and the 500-kV circuits provides independent sources of offsite power as required by GDC 17, 1971. The onsite emergency power source consists of three diesel generators for each unit. Both offsite and onsite systems have sufficient independence, capacity, and testability to permit the operation of the ESFs assuming a failure of a single active component in each power system. The combination of two 230-kV lines plus the 500-kV system provides a high degree of assurance that offsite power will be available when required. The 230-kV and 500-kV systems meet the requirements of 1971 GDC 17. Further details are provided in Chapter 8. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-11 Revision 21 September 2013 This criterion supersedes 1967 GDC 39. Criterion 18, 1971 - Inspection and Testing of Electric Power Systems Electric power systems important to safety shall be designed to permit appropriate periodic inspection and testing of important areas and features, such as wiring, insulation, connections, and switchboards, to assess the continuity of the systems and the condition of their components. The systems shall be designed with a capability to test periodically (1) the operability and functional performance of the components of the systems, such as onsite power sources, relays, switches, and buses, and (2) the operability of the systems as a whole and, under conditions as close to design as practical, the full operational sequence that brings the systems into operation, including operation of applicable portions of the protection system, and the transfer of power among the nuclear power unit, the offsite power system, and the onsite power system. Discussion The DCPP Units 1 and 2 designs conform to Criterion 18. The electric power system and its components have provisions for periodic inspection and testing. Electric power components have been provided with convenient and safe features for inspecting and testing to meet the requirements of GDC 18, 1971. Further details are provided in Chapter 8. Criterion 19, 1971 - Control Room A control room shall be provided from which actions can be taken to operate the nuclear power unit safely under normal conditions and to maintain it in a safe condition under accident conditions including loss-of-coolant accidents. Adequate radiation protection shall be provided to permit access and occupancy of the control room under accident conditions without personnel receiving radiation exposures in excess of 5 rem whole body, or its equivalent to any part of the body, for the duration of the accident. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 19. A centralized control room common to both units contains the controls and instrumentation necessary for operation of both units under normal and accident conditions, including loss of coolant accidents (LOCAs). Adequate radiation protection is provided to ensure that control room personnel are not subject to radiation exposures in excess of 10 CFR 20 limits. Provisions are made so that plant operators can readily maintain the plant at safe shutdown (MODE 3) condition from a location outside the control room. The DCPP Units 1 and 2 designs conform to Criterion 19 for accident dose. Adequate radiation protection is provided to permit access and occupancy of the control room DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-12 Revision 21 September 2013 under accident conditions without personnel receiving radiation exposures in excess of 5 rem whole body, or its equivalent to any part of the body, for the duration of the accident to meet the requirements of GDC 19, 1971. Refer to Section 6.4. This criterion is associated with 1967 GDC 11. Criterion 20, 1971 - Protection System Functions The protection system shall be designed (1) to initiate automatically the operation of appropriate systems including the reactivity control systems, to assure that specified acceptable fuel design limits are not exceeded as a result of anticipated operational occurrences and (2) to sense accident conditions and to initiate the operation of systems and components important to safety. Discussion The DCPP Units 1 and 2 protection system designs comply with the intent of Criterion 20. The systems will automatically actuate alarms, inhibit control rod withdrawal, initiate load cutback, or trip the reactor as a result of anticipated operational occurrences. The systems will also sense accident conditions and initiate engineered safety features (ESF) operation if required. ESF and the protection systems are discussed in Chapters 6 and 7, respectively. Operational limits for the core protection systems are defined by analyses of all plant operating and fault conditions requiring rapid rod insertion to prevent or limit core damage. The protection systems are discussed in UFSAR Section 7.2. This criterion is associated with 1967 GDCs 14, 15, 20, 21, and 25. Criterion 21, 1971 - Protection System Reliability and Testability The protection system shall be designed for high functional reliability and inservice testability commensurate with the safety functions to be performed. Redundancy and independence designed into the protection system shall be sufficient to assure that (1) no single failure results in loss of protection function and (2) removal from service of any component or channel does not result in loss of the required minimum redundancy unless the acceptable reliability of operation of the protection system can be otherwise demonstrated. The protection system shall be designed to permit periodic testing of its functioning when the reactor is in operation, including a capability to test channels independently to determine failures and losses of redundancy that may have occurred. Discussion The DCPP Units 1 and 2 protection system designs comply with the intent of Criterion 21. Each protection system is comprised of redundant independent logic trains of high functional reliability capable of tolerating a single failure without loss of the DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-13 Revision 21 September 2013 protection function, or removal from service of a single component or channel without loss of required minimum redundancy. Independent end-to-end channel tests can be performed with the reactor at power. The majority of system components can be tested very rapidly by use of built-in semiautomatic testers. Removal from service of any single channel or component does not result in loss of minimum required redundancy. For example, a two-of-three function becomes a one-of-two function when one channel is removed. Semiautomatic testers are built into each of the two logic trains in a protection system. These testers have the capability of testing the major part of the protection system very rapidly while the reactor is at power. Between tests, the testers continuously monitor a number of internal protection system points including the associated power supplies and fuses. Outputs of the monitors are logically processed to provide alarms for failures in one train and automatic reactor trip for failures in both trains. Additional details can be found in Section 7.2. This criterion is associated with 1967 GDC 19. Criterion 22, 1971 - Protection System Independence The protection system shall be designed to assure that the effects of natural phenomena, and of normal operating, maintenance, testing, and postulated accident conditions on redundant channels do not result in loss of the protection function, or shall be demonstrated to be acceptable on some other defined basis. Design techniques, such as functional diversity or diversity in component design and principles of operation, shall be used to the extent practical to prevent loss of the protection function. Discussion The DCPP Units 1 and 2 protection system designs comply with the intent of Criterion 22. Independent, redundant, and separate subsystems have been provided. Extensive measurement, equipment, and location diversity is employed in each design. These design techniques are defenses against loss of the protective function through the effects of natural phenomena, normal operation, maintenance, and testing. Physical separation and electrical isolation of redundant channels and subsystems, functional diversity of subsystems, and safe failure modes are employed in design of the reactors as defenses against functional failure through exposure to common causative factors. The redundant logic trains, reactor trip breakers, and ESF actuation devices are physically separated and electrically isolated. Physically separate channel trays, conduits, and penetrations are maintained upstream from the logic elements of each train. The protection system components have been qualified by testing under extremes of the normal environment. In addition, components are tested and qualified according to individual requirements for the adverse environment specific to their location that might DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-14 Revision 21 September 2013 result from postulated accident conditions. The protection systems are discussed in Section 7.2. This criterion is associated with 1967 GDCs 20, 21, 22, and 23. Criterion 23, 1971 - Protective System Failure Modes The protection system shall be designed to fail into a safe state or into a state demonstrated to be acceptable on some other defined basis if conditions such as disconnection of the system, loss of energy (e.g., electric power, instrument air), or postulated adverse environments (e.g., extreme heat or cold, fire, pressure, steam, water, and radiation) are experienced. Discussion The DCPP Units 1 and 2 protection system designs comply with the intent of Criterion 23. Each system is designed with due consideration of the most probable failure modes of the components under various perturbations of energy sources and environment. Each trip channel is designed to trip on de-energization. Loss of power, disconnection, open channel faults, and the majority of internal channel short circuit faults cause a channel to go into its tripped mode. Components of each system are qualified by testing for the environments that might result from postulated accident conditions. The protection system details can be found in Section 7.2. This criterion is associated with 1967 GDC 26 Criterion 24, 1971 - Separation of Protection and Control Systems The protection system shall be separated from control systems to the extent that failure of any single control system component or channel, or failure or removal from service of any single protection system component or channel which is common to the control and protection systems leaves intact a system satisfying all reliability, redundancy, and independence requirements of the protection system. Interconnection of the protection and control systems shall be limited so as to assure that safety is not significantly impaired. Discussion The DCPP Units 1 and 2 protection and control system designs comply with the intent of Criterion 24. Failure of or removal from service of any single component or channel of either the protection system or the control system leaves intact a system satisfying the reliability, redundancy, and independence requirements of the protection system. The protection system is separate and distinct from the control system. The control system is dependent on the protection system in that control system signals are derived from protection system measurements where applicable. Interconnection is DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-15 Revision 21 September 2013 through isolation amplifiers that are classified as protection system components. The adequacy of systems isolation has been verified by testing under the conditions of maximum credible faults. The protection systems comply with the requirements of IEEE Standard 279-1971 "Criteria for Protection Systems for Nuclear Power Generation Stations" although construction permits for the Diablo Canyon units were issued prior to issuance of the 1971 version of the standard. The protection systems and control systems are discussed in Chapter 7. This criterion is associated with 1967 GDC 22. Criterion 25, 1971 - Protection System Requirements for Reactivity Control Malfunctions The protection system shall be designed to assure that specified acceptable fuel design limits are not exceeded for any single malfunction of the reactivity control systems, such as accidental withdrawal (not ejection or dropout) of control rods. Discussion The DCPP Units 1 and 2 designs comply with the intent of Criterion 25. Reactor shutdown with control shutdown rods is completely independent of control functions. The reactor trip breakers interrupt power to all rod drive mechanisms regardless of the status of existing control signals. The design is such that the systems can withstand accidental withdrawal of control groups or unplanned dilution of soluble boron without exceeding acceptable fuel design limits. The facility reactivity control systems are discussed further in Chapter 7, and analyses of the effects of the other possible malfunctions are discussed in Chapter 15. The analyses show that acceptable fuel damage limits are not exceeded in the event of a single malfunction of either system. This criterion is associated with 1967 GDC 31. Criterion 26, 1971 - Reactivity Control System Redundancy and Capability Two independent reactivity control systems of different design principles shall be provided. One of the systems shall use control rods, preferably including a positive means for inserting the rods, and shall be capable of reliably controlling reactivity changes to assure that under conditions of normal operation, including anticipated operational occurrences, and with appropriate margins for malfunctions such as stuck rods, specified acceptable fuel design limits are not exceeded. The second reactivity control system shall be capable of reliably controlling the rate of reactivity changes resulting from planned, normal power changes (including xenon burnout) to assure acceptable fuel design limits are not exceeded. One of the systems shall be capable of holding the reactor core subcritical under cold conditions. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-16 Revision 21 September 2013 Discussion The DCPP Units 1 and 2 designs comply, with the possible exception of the preferred rod insertion means, with the intent of Criterion 26. Two independent reactivity control systems of different design principles are provided for each reactor design. One of the systems uses control rods; the other system uses dissolved boron. The boron system is capable of maintaining the reactor in a subcritical status under cold shutdown conditions. The rod control system maintains a programmed average reactor temperature with scheduled and transient load changes; the boron system is capable of controlling the rate of reactivity change resulting from planned normal power changes including xenon burnout. The control rods are inserted by gravity. The rod cluster control assembly system is capable of making and holding the core subcritical from all operating and hot shutdown conditions sufficiently fast to prevent exceeding acceptable fuel damage limits. The chemical shim control is also capable of making and holding the core subcritical, but at a slower rate, and is not employed as a means of compensating for rapid reactivity transients. The rod cluster control assembly system is, therefore, used in protecting each core from fast transients. Details of the construction of the rod cluster control assembly are included in Section 4.2, with the operation discussed in Chapter 7. The means of controlling the boric acid concentration is described in Section 9.3.4. This criterion is associated with 1967 GDCs 27, 28, and 29. Criterion 27, 1971 - Combined Reactivity Control Systems Capability The reactivity control systems shall be designed to have a combined capability, in conjunction with poison addition by the emergency core cooling system, of reliably controlling reactivity changes to assure that under postulated accident conditions and with appropriate margin for stuck rods the capability to cool the core is maintained. Discussion The DCPP Units 1 and 2 designs comply with the intent of Criterion 27. Appropriate reactivity margin is available for each unit under postulated accident conditions to ensure that the capability to cool the core is maintained. Such margin includes an allowance for the most reactive rod control cluster being stuck out of the core. The boron reactivity (chemical shim) control systems are capable of making and holding the core subcritical under any anticipated conditions and with appropriate margin for contingencies. These means are discussed in detail in Chapters 4 and 9. Normal reactivity shutdown capability is provided by rapid control rod insertion. The chemical shim control system permits the necessary shutdown margin to be maintained during long-term xenon decay and plant cooldown. This criterion is associated with 1967 GDC 30. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-17 Revision 21 September 2013 Criterion 28, 1971 - Reactivity Limits The reactivity control systems shall be designed with appropriate limits on the potential amount and rate of reactivity increase to assure that the effects of postulated reactivity accidents can neither (1) result in damage to the reactor coolant pressure boundary greater than limited local yielding nor (2) sufficiently disturb the core, its support structures or other reactor pressure vessel internals to impair significantly the capability to cool the core. These postulated reactivity accidents shall include consideration of rod ejection (unless prevented by positive means), rod dropout, steam line rupture, changes in reactor coolant temperature and pressure, and cold water addition. Discussion The DCPP Units 1 and 2 designs comply with the intent of Criterion 28. For each unit, the maximum reactivity worth of control rods and the maximum rates of reactivity insertion employing both control rods and boron removal are limited to values that prevent rupture of the coolant pressure boundary or disruption of the core or internals to a degree that could impair the effectiveness of the emergency core cooling system (ECCS). The appropriate reactivity insertion rate for withdrawal of rods and the dilution of boron in the coolant system are discussed in Chapter 15. The boron reactivity (chemical shim) control systems are capable of making and holding the core subcritical under any anticipated condition and with appropriate margin for contingencies. These means are discussed in detail in Chapters 4 and 9. This criterion is associated with 1967 GDC 30. Criterion 29, 1971 - Protection Against Anticipated Operational Occurrences The protection and reactivity control systems shall be designed to assure an extremely high probability of accomplishing their safety functions in the event of anticipated operational occurrences. Discussion The DCPP Units 1 and 2 designs comply with the intent of Criterion 29. The protection and reactivity control systems for each plant are designed to ensure an extremely high probability of fulfilling their intended functions. The design principles of diversity and redundancy coupled with a rigorous quality assurance program support this probability as does operating experience in plants using the same basic design. The protection systems are described in Section 7.2. This criterion is associated with 1967 GDCs 19 and 20. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-18 Revision 21 September 2013 Criterion 30, 1971 - Quality of Reactor Coolant Pressure Boundary Components which are part of the reactor coolant pressure boundary shall be designed, fabricated, erected, and tested to the highest quality standards practical. Means shall be provided for detecting and, to the extent practical, identifying the location of the source of reactor coolant leakage. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 30. The quality levels employed in the design, fabrication, erection and testing for each reactor coolant pressure boundary are extremely comprehensive. Systems are included in the plant to detect and, to the extent practical, to locate leakage. All RCS components are designed, fabricated, inspected, and tested in conformance with the ASME Boiler and Pressure Vessel Code. Leakage is detected by an increase in the amount of makeup water required to maintain a normal level in the pressurizer. The reactor vessel closure joint is provided with a temperature monitored leakoff between double gaskets. Leakage into the reactor containment is drained to the reactor building sump where the level is monitored. Leakage is also detected by measuring the airborne activity and quantity of the condensate drained from each reactor containment fan cooler unit. These leakage detection methods are described in detail in Section 5.2. This criterion is associated with 1967 GDCs 9 and 16. Criterion 31, 1971 - Fracture Prevention of Reactor Coolant Pressure Boundary The reactor coolant pressure boundary shall be designed with sufficient margin to assure that when stressed under operating, maintenance, testing, and postulated accident conditions (1) the boundary behaves in a nonbrittle manner and (2) the probability of rapidly propagating fracture is minimized. The design shall reflect consideration of service temperatures and other conditions of the boundary material under operating, maintenance, testing, and postulated accident conditions and the uncertainties in determining (1) material properties, (2) the effects of irradiation on material properties, (3) residual, steady-state and transient stresses, and (4) size of flaws. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 31. Each reactor coolant boundary is designed so that, for all normal operating and postulated accident DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-19 Revision 21 September 2013 modes, the boundary behaves in a nonbrittle manner and so that the probability of rapidly propagating failure is minimized. Service temperature and pressure, irradiation, cyclic loading, seismic, blowdown and thermal forces from postulated accidents, residual stresses, and code allowable material discontinuities have all been considered in the design, with appropriate margins for each. Sufficient testing and analysis of materials employed in RCS components have been performed to ensure that the required NDTT limits specified in the criterion are met. Removable test capsules installed in the reactor vessel are removed and tested at various times in the plant lifetime to determine the effects of operation on system materials. Details of the testing and analysis programs are included in Chapter 5. Close control is maintained over material selection and fabrication for the RCS. Materials exposed to the coolant are corrosion-resistant stainless steel or Inconel. Materials testing consistent with 10 CFR 50 ensures that only materials with adequate toughness properties are used. The fabrication and quality control techniques used in the fabrication of the RCS are equivalent to those used for the reactor vessel. The inspections of reactor vessel, steam generators, pressurizer, pumps, and piping are governed by ASME code requirements. This criterion is associated with 1967 GDCs 34 and 35. Criterion 32, 1971 - Inspection of Reactor Coolant Pressure Boundary Components which are part of the reactor coolant pressure boundary shall be designed to permit (1) periodic inspection and testing of important areas and features to assess their structural and leaktight integrity, and (2) an appropriate material surveillance program for the reactor pressure vessel. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 32. Each reactor coolant pressure boundary is periodically inspected under the provisions of ASME Section XI. The DCPP Inservice Inspection (ISI) and Testing Program plans for the first ten-year interval conformed to the extent practicable with the 1977 Edition of Section XI with Addenda through Summer 1978. The Inservice Inspection Program plan for the second ten-year interval conformed to the extent practicable with the 1989 Edition of Section XI without Addenda. The Inservice Inspection Program plan for the third ten-year interval will conform to the extent practicable with the 2001 Edition of Section XI with 2002 and 2003 Addenda. A reactor vessel metal surveillance program will be employed in accordance with ASTM 185, Recommended Practice for Surveillance Tests on Structural Materials in Nuclear Reactors. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-20 Revision 21 September 2013 Monitoring of the NDT temperature properties of each core region plate, forging, weldment, and associated heat-treated zones are performed in accordance with ASTM E 185, Recommended Practice for Surveillance Tests on Structural Materials in Nuclear Reactors. Samples of reactor vessel plate materials are retained and cataloged in case future engineering development shows the need for further testing. The material properties surveillance program includes not only the conventional tensile and impact tests, but also fracture mechanics specimens. The observed shifts in NDTT of the core region materials with irradiation are used to confirm the calculated limits to startup and shutdown transients. To define permissible operating conditions below NDTT, a pressure range is established that is bounded by a lower limit for pump operation and an upper limit that satisfies reactor vessel stress criteria. To allow for thermal stresses during heatup or cooldown of the reactor vessel, an equivalent pressure limit is defined to compensate for thermal stress as a function of rate of change of coolant temperature. Because the normal operating temperature of the reactor vessel is well above the maximum expected NDTT brittle fracture during normal operation, it is not considered to be a credible mode of failure. Additional details can be found in Section 5.2. This criterion is associated with 1967 GDC 36. Criterion 33, 1971 - Reactor Coolant Makeup A system to supply reactor coolant makeup for protection against small breaks in the reactor coolant pressure boundary shall be provided. The system safety function shall be to assure that specified acceptable fuel design limits are not exceeded as a result of reactor coolant loss due to leakage from the reactor coolant pressure boundary and rupture of small piping or other small components which are part of the boundary. The system shall be designed to assure that for onsite electric power system operation (assuming offsite power is not available) and for offsite electric power system operation (assuming onsite power is not available) the system safety function can be accomplished using the piping, pumps, and valves used to maintain coolant inventory during normal reactor operation. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 33. The normal flowpath for each RCS charging system can be used to ensure appropriate makeup protection against small breaks. The RCS charging system is discussed in Section 9.3. No direct association exists with the 1967 GDC. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-21 Revision 21 September 2013 Criterion 34, 1971 - Residual Heat Removal A system to remove residual heat shall be provided. The system safety function shall be to transfer fission product decay heat and other residual heat from the reactor core at a rate such that specified acceptable fuel design limits and the design conditions of the reactor coolant pressure boundary are not exceeded. Suitable redundancy in components and features, and suitable interconnections, leak detection, and isolation capabilities shall be provided to assure that for onsite electric power system operation (assuming offsite power is not available) and for offsite electric power system operation (assuming onsite power is not available) the system safety function can be accomplished, assuming a single failure. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 34. Each residual heat removal (RHR) system, consisting of two redundant trains of pumps and heat exchangers, has appropriate heat removal capacity to ensure fuel protection. This system supplements the normal steam and power conversion system (SPCS) which is used for the first cooldown. The auxiliary feedwater system (AFS) complements the SPCS in this function. The systems together accommodate the single failure criteria. The RHR system is discussed in Section 5.5. No direct association exists with the 1967 GDC. Criterion 35, 1971 - Emergency Core Cooling A system to provide abundant emergency core cooling shall be provided. The system safety function shall be to transfer heat from the reactor core following any loss of reactor coolant at a rate such that (1) fuel and clad damage that could interfere with continued effective core cooling is prevented and (2) clad metal-water reaction is limited to negligible amounts. Suitable redundancy in components and features, and suitable interconnections, leak detection, isolation, and containment capabilities shall be provided to assure that for onsite electric power system operation (assuming offsite power is not available) and for offsite electric power system operation (assuming onsite power is not available) the system safety function can be accomplished, assuming a single failure. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 35. Appropriate core cooling systems have been designed for each plant so as to provide for the removal of core thermal loads and for the limiting of metal-water reactions to an insignificant level. Suitable redundancy is provided in core cooling systems. The charging accumulator DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-22 Revision 21 September 2013 and safety injection systems will accommodate a single active failure and still fulfill their intended safety function. The RHR system will accommodate a single passive or active failure and still fulfill its intended safety function. By combining the use of passive accumulators with two centrifugal charging pumps (CCP1 and CCP2), two safety injection pumps, and two RHR pumps, emergency core cooling is provided even if there should be a failure of any single component in any system. The ECCS employs a passive system of accumulators that do not require any external signals or source of power for their operation to cope with the short-term cooling requirements of large reactor coolant pipe breaks. Two independent and redundant high-pressure flow and pumping systems, each capable of the required emergency cooling, are provided for small break protection and to keep the core submerged after the accumulators have discharged following a large break. These systems are arranged so that the single failure of any active component does not interfere with meeting the short-term cooling requirements. Borated water is injected into the RCS by accumulators, safety injection pumps, RHR pumps, and charging pumps. Pump design includes consideration of fluid temperature and containment pressure in accordance with AEC Safety Guide (SG) 1, November 1970. The failure of any single active component or the development of excessive leakage during the long term cooling period does not interfere with the ability to meet necessary long-term cooling objectives with one of the systems. The primary function of the ECCS is to deliver borated cooling water to the reactor core in the event of a LOCA. This limits the fuel cladding temperature and thereby ensures that the core will remain intact and in place, with its essential heat transfer geometry preserved. This protection is afforded for: (1) All pipe break sizes up to and including the hypothetical circumferential rupture of a reactor coolant loop (2) A loss of coolant associated with a rod ejection accident The basic criteria for LOCA evaluations are (a) no cladding melting will occur, (b) zirconium-water reactions will be limited to an insignificant amount, and (c) the core geometry will remain essentially in place and intact so that effective cooling of the core will not be impaired. The zirconium-water reactions will be limited to an insignificant amount so that the accident: (1) Does not interfere with the emergency core cooling function to limit cladding temperatures (2) Does not produce hydrogen in an amount that, when burned, would cause the containment pressure to exceed the design value DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-23 Revision 21 September 2013 For any rupture of a steam pipe and the associated uncontrolled heat removal from the core, the ECCS adds shutdown reactivity so that with a stuck rod, no offsite power, and minimum ESF, there is no consequential damage to the primary system and the core remains in place and intact. With no stuck rod, offsite power, and all equipment operating at design capacity, there is insignificant cladding rupture. The ECCS is described in Section 6.3. Chapter 15 provides the analysis for the LOCA. This criterion is associated with 1967 GDCs 37 and 44. Criterion 36, 1971 - Inspection of Emergency Core Cooling System The emergency core cooling system shall be designed to permit appropriate periodic inspection of important components, such as spray rings in the reactor pressure vessel, water injection nozzles, and piping, to assure the integrity and capability of the system. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 36. They provide for inspection of the emergency core cooling branch line connections to the RCS for each plant in accordance with the provision of ASME Section XI. These are the areas of principal stress in the system due to temperature gradients. The remainder of the systems are verified as to integrity and functioning by means of periodic testing as described in the Technical Specifications. Design provisions facilitate access to the critical parts of the reactor vessel internals, injection nozzles, pipes, and valves for visual or nondestructive inspection. The components outside containment are accessible for leaktightness inspection during operation of the reactor. Details of the inspection program for the reactor vessel internals are included in Section 5.4. Information on inspection for the ECCS is provided in Section 6.3. This criterion is associated with 1967 GDC 45. Criterion 37, 1971 - Testing of Emergency Core Cooling System The emergency core cooling system shall be designed to permit appropriate periodic pressure and functional testing to assure (1) the structural and leaktight integrity of its components, (2) the operability and performance of the active components of the system, and (3) the operability of the system as a whole and, under conditions as close to design as practical, the performance of the full operational sequence that brings the system into operation, including operation of applicable portions of the protection system, the transfer between normal and emergency power sources, and the operation of the associated cooling water system. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-24 Revision 21 September 2013 Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 37. Periodic tests demonstrate the integrity, operability, and performance of each active component. Each system as a whole, and the entire operational sequence of actuation, power transfer, and cooling water operation are tested in several phases rather than in one phase during periodic testing. The design provides for periodic testing of both active and passive components of the ECCS for operability and functional performance. Preoperational performance tests of the components were performed in the manufacturer's shop. Initial system flow tests demonstrate proper functioning of the system. Thereafter, periodic tests demonstrate that components are functioning properly. Each active component of the ECCS may be individually actuated on the normal power source at any time during plant operation to demonstrate operability. The centrifugal charging pumps are part of the charging system, and this system is in continuous operation during plant operation. The test of the safety injection pumps employs the minimum flow recirculation test line that connects back to the refueling water storage tank (RWST). Remotely operated valves are exercised and actuation circuits tested. The automatic actuation circuitry, valves, and pump breakers also may be checked during integrated system tests performed during a planned cooldown of the RCS. Details of the ECCS are found in Section 6.3. Performance under accident conditions is evaluated in Chapter 15. Design provisions include special instrumentation, testing, and sampling lines to perform tests during plant shutdown to demonstrate proper operation of the ECCS. A test signal is applied to initiate automatic action. The test demonstrates the operation of the valves, pump circuit breakers, and automatic circuitry. In addition, the periodic recirculation to the RWST can verify that the safety injection pumps attain required discharge heads. During a refueling outage the full flow capability of each injection pump can be verified. This criterion is associated with 1967 GDCs 38, 46, 47, and 48. Criterion 38, 1971 - Containment Heat Removal A system to remove heat from the reactor containment shall be provided. The system safety function shall be to reduce rapidly, consistent with the functioning of other associated systems, the containment pressure and temperature following any loss-of-coolant accident and maintain them at acceptably low levels. Suitable redundancy in components and features, and suitable interconnections, leak detection, isolation, and containment capabilities shall be provided to assure that for onsite electric power system operation (assuming offsite power is not available) and for DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-25 Revision 21 September 2013 offsite electric power system operation (assuming onsite power is not available) the system safety function can be accomplished, assuming a single failure. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 38. Two diverse heat removal systems, each composed of redundant components, are provided. These are the containment spray system (100 percent capacity pumping systems) and the containment fan cooler system (five units provided, two required for accident heat removal). The reactor containment structure and penetrations, with the aid of containment heat removal systems, are designed to limit radiation doses resulting from leakage of radioactive fission products from the containment to below 10 CFR 100 values, assuming the largest credible energy release following a LOCA, including a margin to cover the effects of metal water or other undefined energy sources. The containment design is described in detail in Section 3.8.1. Two separate heat removal systems, the containment spray system (CSS) and the containment fan coolers, are provided to remove heat from the containment following an accident. The design cooling rates of the two systems at the containment design pressure and temperature conditions are the same. The heat removal capability of either system is sufficient to rapidly reduce the containment pressure following an accident. The containment heat removal systems are described in Section 6.2. This criterion is associated with 1967 GDCs 49 and 52. Criterion 39, 1971 - Inspection of Containment Heat Removal System The containment heat removal system shall be designed to permit appropriate periodic inspection of important components, such as the torus, pumps, spray nozzles, and piping to assure the integrity and capability of the system. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 39 except for limited areas. Four or fewer fan cooler units are continually operating and are rotated in service to provide continuous verification of operability and integrity. Access for routine maintenance and inspection has been provided. The containment spray system integrity will be verified by means of periodic testing as described in the Technical Specifications. Access has been provided for routine maintenance and inspection except for the spray ring headers and nozzles for which no inspection provision was made, except that provisions were made to smoke or air test these headers and nozzles periodically. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-26 Revision 21 September 2013 Where practicable, all active components and passive components of the containment cooling system are inspected periodically to demonstrate system readiness. The pressure containing systems are inspected for leaks from pump seals, valve packing, flanged joints, and safety valves. During operational testing of the containment spray pumps, the portions of the system subjected to pump pressure are inspected for leaks. The containment fan coolers are normally in use, which provides an additional check on the readiness of the system. Additional details are found in Section 6.2. This criterion is associated with 1967 GDC 58. Criterion 40, 1971 - Testing of Containment Heat Removal System The containment heat removal system shall be designed to permit appropriate periodic pressure and functional testing to assure (1) the structural and leaktight integrity of its components, (2) the operability and performance of the active components of the system, and (3) the operability of the system as a whole, and, under conditions as close to the design as practical, the performance of the full operational sequence that brings the system into operation, including operation of applicable portions of the protection system, the transfer between normal and emergency power sources, and the operation of the associated cooling water system. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 40. Periodic tests demonstrate the integrity, operability, and performance of the containment heat removal systems. To the extent practicable, active components of the containment fan coolers are given preoperational performance tests after installation. Since these coolers are in use during normal operation, they are continually subjected to operational tests. The same is true of the component cooling water system that supplies the cooling water for the fan coolers. Each unit can be isolated during plant operation and subjected to a leak test to determine that the leaktight integrity of the unit has not been lost. Similarly, active components in the containment spray system are given preoperational performance tests after installation. Periodic tests demonstrate that components are functioning properly. Tests are performed after any component maintenance affecting operability. Permanent test lines for all the containment spray loops are located so that all components up to the isolation valves at the containment can be tested. The air test lines for checking that spray nozzles are not obstructed are connected upstream of the spray ring isolation valves. Airflow through the nozzles is monitored by positive means. The containment systems are described in detail in Section 6.2. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-27 Revision 21 September 2013 This criterion is associated with 1967 GDCs 59, 60, and 61. Criterion 41, 1971 - Containment Atmosphere Cleanup Systems to control fission products, hydrogen, oxygen, and other substances which may be released into the reactor containment shall be provided as necessary to reduce, consistent with the functioning of other associated systems, the concentration and quality of fission products released to the environment following postulated accidents, and to control the concentration of hydrogen or oxygen and other substances in the containment atmosphere following postulated accidents to assure that containment integrity is maintained. Each system shall have suitable redundancy in components and features, and suitable interconnections, leak detection, isolation, and containment capabilities to assure that for onsite electric power system operation (assuming offsite power is not available) and for offsite electric power system operation (assuming onsite power is not available) its safety function can be accomplished, assuming a single failure. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 41. The containment spray system and containment fan coolers, provide controls on, and means for, reduction of fission products and other substances. The containment spray system removes radioactive iodine isotopes from the containment atmosphere should these fission products be released in the event of an accident. The system is designed to deliver enough sodium hydroxide mixed with the borated spray water from the refueling water storage tank to provide pH control for iodine removal when mixed with the other sources of water in the containment recirculation sump. The containment spray system, including required auxiliary systems, is designed to tolerate a single active failure during the injection phase following a LOCA or steam line break without loss of protective function. The containment spray pumps are of the horizontal centrifugal type and are driven by electric motors. The motors are powered from separate vital buses. The containment fan cooler system consists of five identical fan coolers, each including cooling coils, fan and drive motor, locked open air flow dampers and pressure relief dampers, duct distribution system, instrumentation, and control. The containment fan cooler system and the containment spray system operate during the injection phase following a LOCA to reduce the containment ambient temperature and pressure. While performing this cooling function, the containment heat removal system also helps limit offsite radiation levels by reducing the pressure differential DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-28 Revision 21 September 2013 between containment and outside atmosphere, thus reducing the driving force for leakage of fission products from the containment atmosphere. The fan cooler units are powered from vital buses and have a standby unit. Used in conjunction with one another during the injection phase, one containment spray pump and two containment fan cooler units will provide the heat removal capability to maintain the postaccident containment pressure below the design value of 47 psig. The containment systems are described in Section 6.2. Diversity of electric power supplies is discussed in Chapter 8. This criterion is associated with 1967 GDC 37. Criterion 42, 1971 - Inspection of Containment Atmosphere Cleanup Systems The containment atmosphere cleanup systems shall be designed to permit appropriate periodic inspection of important components, such as filter frames, ducts, and piping to assure the integrity and capability of the systems. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 42. Nondestructive examination is performed on the components of the systems in accordance with the requirements of the applicable codes as described in Section 3.2. The containment spray system is designed so that component surveillance can be performed periodically to demonstrate system readiness. The pressure-containing portions of the system are tested periodically to check for leakage. This testing includes the portions of the system that would circulate radioactive water from the containment sump, if recirculation spray was required. Access is available for visual inspection of the fan cooler components, including fans, cooling coils, enclosure dampers, and ductwork. Because these units are in use during power operation, continuous checks of their status are available. Additional details are found in Section 6.2. This criterion is associated with 1967 GDC 62. Criterion 43, 1971 - Testing of Containment Atmosphere Cleanup Systems The containment atmosphere cleanup systems shall be designed to permit appropriate periodic pressure and functional testing to assure (1) the structural and leaktight integrity of its components, (2) the operability and performance of the active components of the systems such as fans, filters, dampers, pumps, and valves and (3) the operability of the systems as a whole and, under conditions as close to design as DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-29 Revision 21 September 2013 practical, the performance of the full operational sequence that brings the systems into operation, including operation of applicable portions of the protection system, the transfer between normal and emergency power sources, and the operation of associated systems. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 43. Periodic tests demonstrate the integrity, operability, and performance of the containment atmosphere cleanup systems. The containment spray system, utilizing sodium hydroxide, serves as the air cleanup system. The active components in the containment spray system are given preoperational performance tests after installation. Permanent test lines for all containment spray loops are located so that all components up to the isolation valves at the containment may be tested. The nozzles are tested by airflow that is monitored by positive means. The fan coolers are normally in use, which provides a check on the operability of the system. Additional details are found in Section 6.2. Design provisions have been made, to the extent practicable, to facilitate access for periodic visual inspection of all important components of the containment fan cooler system. Testing of any components, after maintenance or as a part of a periodic inspection program, may be performed at any time, since the containment fan cooler system units are in operation on an essentially continuous schedule during normal plant operation. This criterion is associated with 1967 GDCs 63, 64, and 65. Criterion 44, 1971 - Cooling Water A system to transfer heat from structures, systems, and components important to safety, to an ultimate heat sink shall be provided. The system safety function shall be to transfer the combined heat load of these structures, systems, and components under normal operating and accident conditions. Suitable redundancy in components and features, and suitable interconnections, leak detection, and isolation capabilities shall be provided to assure that for onsite electric power system operation (assuming offsite power is not available) and for offsite electric power system operation (assuming onsite power is not available) the system safety function can be accomplished, assuming a single failure. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 44. A PG&E Design Class I component cooling water (CCW) system is provided to transfer heat from reactor coolant, engineered safety features, and the containment to the PG&E Design DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-30 Revision 21 September 2013 Class I auxiliary saltwater (ASW) system. The latter system discharges to the Pacific Ocean, which is the ultimate heat sink. The CCW system is designed to provide cooling water to vital and nonvital components and to operate in all plant operating modes, including normal power operation, plant cooldown, and emergencies, including a LOCA or MSLB. Safety analyses for containment peak pressure demonstrate that only one ASW pump and one CCW heat exchanger is required to provide sufficient heat removal from containment to mitigate a MSLB or LOCA. The CCW system is designed to continue to perform its safety function following an accident assuming a single active failure during the short-term recovery period and either a single active or passive failure during the long-term recovery period. Refer to Section 3.1.1 for a description of DCPP single failure criteria and definition of terms. During normal operation and up to 24 hours after an accident (the short-term recovery period), the CCW headers are crosstied. This configuration will withstand a single active failure without the loss of safety function. For a passive failure (up to a 200 gpm leak for 20 minutes), operator mitigation action (consisting of valve manipulations) is credited to stop leaks. The CCW piping design includes valving for isolating cooling water flow associated with individual components and for complete isolation of a header. The CCW system components that are considered vital are redundant. The three CCW pump motors are on separate vital 4.16 kV buses that have diesel generator standby power sources. A radiation monitor associated with each of the two CCW pump discharge headers monitors the CCW system for radioactive in-leakage. Additional details are found in Section 9.2. No direct correlation exists with the 1967 GDC. Criterion 45, 1971 - Inspection of Cooling Water System The cooling water system shall be designed to permit appropriate periodic inspection of important components, such as heat exchangers and piping, to assure the integrity and capability of the system. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 45. The component cooling water pumps, heat exchangers, associated valves, large piping, and instrumentation are located outside the containment and are therefore accessible for maintenance and inspection during power operation. Cooling water systems are discussed in Section 9.2. No direct association exists with the 1967 GDC. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-31 Revision 21 September 2013 Criterion 46, 1971 - Testing of Cooling Water System The cooling water system shall be designed to permit appropriate periodic pressure and functional testing to assure (1) the structural and leaktight integrity of its components, (2) the operability and the performance of the active components of the system, and (3) the operability of the system as a whole and under conditions as close to design as practical, the performance of the full operational sequence that brings the system into operation for reactor shutdown and for loss-of-coolant accidents, including operation of applicable portions of the protection system and the transfer between normal and emergency power sources. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 46. System design permits periodic hydrostatic testing of the cooling water system during plant shutdown. The system is pressurized during power operation. The emergency control functions can be tested out to the final actuated device as described in Chapter 7. No direct association exists with the 1967 GDC. Criterion 50, 1971 - Containment Design Basis The reactor containment structure, including access openings, penetrations, and the containment heat removal system shall be designed so that the containment structure and its internal compartments can accommodate, without exceeding the design leakage rate and, with sufficient margin, the calculated pressure and temperature conditions resulting from any loss-of-coolant accident. This margin shall reflect consideration of (1) the effects of potential energy sources which have not been included in the determination of the peak conditions, such as energy in steam generators and energy from metal-water and other chemical reactions that may result from degraded emergency core cooling functioning, (2) the limited experience and experimental data available for defining accident phenomena and containment responses, and (3) the conservatism of the calculational model and input parameters. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 50. The containment structure has been designed with sufficient margins to accommodate the calculated pressure and temperature conditions resulting from any LOCA. The containment, including access openings and penetrations, has a design pressure of 47 psig. The greatest transient peak pressure associated with a postulated rupture of the piping in the RCS and the calculated effects of metal-water reaction do not exceed this value. The containment is strength tested at 54 psig. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-32 Revision 21 September 2013 The reactor containment structure and penetrations, with the aid of containment heat removal systems, are designed to limit radiation doses resulting from leakage of radioactive fission products from the containment to below 10 CFR 100 values, assuming the largest credible energy release following a LOCA, including a margin to cover the effects of metal water or other undefined energy sources. The containment design is described in detail in Section 3.8.1. This criterion is associated with 1967 GDC 49. Criterion 51, 1971 - Fracture Prevention of Containment Pressure Boundary The reactor containment boundary shall be designed with sufficient margin to assure that under operating, maintenance, testing, and postulated accident conditions (1) its ferritic materials behave in a nonbrittle manner and (2) the probability of rapidly propagating fracture is minimized. The design shall reflect consideration of service temperatures and other conditions of the containment boundary material during operation, maintenance, testing, and postulated accident conditions, and the uncertainties in determining (1) material properties, (2) residual, steady-state, and transient stresses, and (3) size of flaws. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 51. The concrete containment structure is not susceptible to low-temperature brittle fracture. The independence of the reinforcing steel minimizes the possibility of rapidly propagating fracture. The steel liner is not directly exposed to the temperature of the environs. The selection and use of containment structure materials comply with the applicable codes and standards. The containment liner is enclosed within the containment structure and thus not directly exposed to the temperature of the external environment and not subject to Criterion 50, 1967. Nevertheless, the design specification required Charpy V notch tests at 20°F for the containment liner. This corresponds to a lowest service temperature of 50°F during operation. Further information on containment structure materials appears in Section 3.8. This criterion is associated with 1967 GDC 50. Criterion 52, 1971 - Capability for Containment Leakage Rate Testing The reactor containment and other equipment which may be subjected to containment test conditions shall be designed so that periodic integrated leakage rate testing can be conducted at containment design pressure. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-33 Revision 21 September 2013 Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 52. The containment design will accommodate both initial strength testing at 1.15 times design pressure and periodic leakage rate testing. The containment is provided with testable weld channels and penetrations so that sensitive leakage rate tests can be made of these areas where leakage could occur. Periodic leakage rate testing will be performed over the life of the units in accordance with the requirements of Appendix J to 10 CFR 50, Option B, as modified by approved exemptions. The leakage rate tests and the sensitive leakage rate test demonstrate the integrity of the double leakage barriers provided by the penetrations and the overall integrity of the containment structure. The criterion for acceptance is that the measured leakage rate be less than 0.10 percent of the containment free volume per day. Further details of the integrated leakage rate test and the sensitive leakage rate test provisions appear in Section 3.8. This criterion is associated with 1967 GDCs 54 and 55. Criterion 53, 1971 - Provisions for Containment Testing and Inspection The reactor containment shall be designed to permit (1) appropriate periodic inspection of all important areas, such as penetrations, (2) an appropriate surveillance program, and (3) periodic testing at containment design pressure of the leaktightness of penetrations which have resilient seals and expansion bellows. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 53. The containment design includes provision for testing and inspecting penetrations, liner plate areas, and areas of seals and expansion bellows. All penetrations are provided with a volume that can be pressurized to test for leaktightness. There are three configurations used: (a) weld channels over the penetration welds, (b) an annular space between the penetration insert and the sleeve, which is sealed at both ends, and (c) double resilient seals with a gap between the seals. Further details appear in Section 3.8. Periodic leakage rate testing is performed in accordance with the requirements of Appendix J of 10 CFR 50. Applicable surveillance requirements for such testing are included in the Technical Specifications. This criterion is associated with 1967 GDC 56. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-34 Revision 21 September 2013 Criteria 54, 1971 - Piping Systems Penetrating Containment Piping systems penetrating primary reactor containment shall be provided with leak detection, isolation, and containment capabilities having redundance, reliability, and performance capabilities which reflect the importance to safety of isolating these piping systems. Such piping systems shall be designed with a capability to test periodically the operability of the isolation valves and associated apparatus and to determine if valve leakage is within acceptable limits. Discussion The DCPP Units 1 and 2 designs conform to Criterion 54 except where specifically indicated in Section 6.2.4. The containment isolation design provides for a double barrier at the containment penetration in those fluid systems that are not required to function following a design basis event. All piping systems penetrating the containment are provided with test vents and test connections or have other provisions to allow periodic leakage testing. Those automatic isolation valves that do not restrict normal plant operation are periodically tested to ensure operability. Section 6.2 describes in detail the testing of isolation valves. This criterion is associated with 1967 GDC 57. Criterion 55, 1971 - Reactor Coolant Pressure Boundary Penetrating Containment Each line that is part of the reactor coolant pressure boundary and that penetrates primary reactor containment shall be provided with containment isolation valves as follows, unless it can be demonstrated that the containment isolation provisions for a specific class of lines, such as instrument lines, are acceptable on some other defined basis: (1) One locked closed isolation valve inside and one locked closed isolation valve outside containment; or (2) One automatic isolation valve inside and one locked closed isolation valve outside containment; or (3) One locked closed isolation valve inside and one automatic isolation valve outside containment. A simple check valve may not be used as the automatic isolation valve outside containment; or (4) One automatic isolation valve inside and one automatic isolation valve outside containment. A simple check valve may not be used as the automatic isolation valve outside containment. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-35 Revision 21 September 2013 Isolation valves outside containment shall be located as close to containment as practical and upon loss of actuating power, automatic isolation valves shall be designed to take the position that provides greater safety. Other appropriate requirements to minimize the probability or consequences of an accidental rupture of these lines or of lines connected to them shall be provided as necessary to assure adequate safety. Determination of the appropriateness of these requirements, such as higher quality in design, fabrication, and testing, additional provisions for inservice inspection, protection against more severe natural phenomena, and additional isolation valves and containment, shall include consideration of the population density, use characteristics, and physical characteristics of the site environs. Discussion The DCPP Units 1 and 2 designs conform to Criterion 55 except where specifically indicated in Section 6.2.4. The reactor coolant pressure boundary is defined as those piping systems and components that contain reactor coolant at design pressure and temperature. With the exception of the reactor coolant sampling lines, the entire reactor coolant pressure boundary, as defined above, is located entirely within the containment structure. All sampling lines are provided with remotely operated valves for isolation in the event of a failure. These valves also close automatically on a containment isolation signal. Sampling lines are only used during infrequent sampling and can readily be isolated. See Section 6.2 for details on conformance. This criterion is associated with 1967 GDCs 51 and 57. Criterion 56, 1971 - Primary Containment Isolation Each line that connects directly to the containment atmosphere and penetrates primary reactor containment shall be provided with containment isolation valves as follows, unless it can be demonstrated that the containment isolation provisions for a specific class of lines, such as instrument lines, are acceptable on some other defined basis: (1) One locked closed isolation valve inside and one locked closed isolation valve outside containment; or (2) One automatic isolation valve inside and one locked closed isolation valve outside containment; or (3) One locked closed isolation valve inside and one automatic isolation valve outside containment. A simple check valve may not be used as the automatic isolation valve outside containment; or (4) One automatic isolation valve inside and one automatic isolation valve outside containment. A simple check valve may not be used as the automatic isolation valve outside containment. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-36 Revision 21 September 2013 Isolation valves outside containment shall be located as close to containment as practical and upon loss of actuating power, automatic isolation valves shall be designed to take the position that provides greater safety. Discussion The DCPP Units 1 and 2 designs conform to Criterion 56 except where specifically indicated in Section 6.2.4. These include the containment pressure and vacuum relief lines for each unit. These lines are provided with two automatic isolation valves, one inside and one outside the containment. These lines, as do all lines penetrating the containment, fall into a specific class of lines as discussed in Section 6.2.4. This criterion is associated with 1967 GDC 53. Criterion 57, 1971 - Closed System Isolation Valves Each line that penetrates primary reactor containment and is neither part of the reactor coolant pressure boundary nor connected directly to the containment atmosphere shall have at least one containment isolation valve which shall be either automatic, or locked closed, or capable of remote manual operation. This valve shall be outside containment and located as close to the containment as practical. A simple check valve may not be used as the automatic isolation valve. Discussion The DCPP Units 1 and 2 designs conform to Criterion 57 except where specifically indicated in Section 6.2.4. Each line that penetrates the reactor containment in each unit, and is neither part of the reactor coolant pressure boundary nor connected directly to the containment atmosphere, has at least one containment isolation valve located outside the containment as close to the containment as practicable. The RHR system, the component cooling water line penetrations to the excess letdown heat exchanger and to the containment fan coolers, and the auxiliary feedwater supply lines are excepted. The cooling water supply to the excess letdown heat exchanger utilizes a check valve outside of containment rather than an isolation valve. The CCW supply/return lines to the containment fan coolers and the auxiliary feedwater lines to the steam generators use local manual valves as isolation valves per 1967 GDC 53. See Section 6.2.4 for details on conformance. This criterion is associated with 1967 GDC 53. Criterion 60, 1971 - Control of Releases of Radioactive Materials to the Environment The nuclear power unit design shall include means to control suitably the release of radioactive materials in gaseous and liquid effluents and to handle radioactive solid wastes produced during normal reactor operation, including anticipated operational occurrences. Sufficient holdup capacity shall be provided for retention of gaseous and DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-37 Revision 21 September 2013 liquid effluents containing radioactive materials, particularly where unfavorable site environmental conditions can be expected to impose unusual operational limitations upon the release of such effluents to the environment. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 60. An extensive treatment system has been incorporated in the design for processing liquid wastes. Gaseous wastes are processed by appropriate holdup. Solid wastes are solidified in concrete (except for clothing, paper, etc.) for eventual disposition in licensed burial grounds. The containment atmosphere, the plant vents, and the liquid and gaseous waste systems effluent discharge paths are monitored for radioactivity concentrations during all modes of operations. The monitoring systems are described in Section 11.4. The offsite radiological monitoring program is described in Section 11.6. Waste handling systems are incorporated in each facility design for processing and/or retention of normal operation radioactive wastes with appropriate controls and monitors to ensure that releases do not exceed the limits of 10 CFR 20. The facilities are also designed with provisions to monitor radioactivity release during accidents and to prevent releases from causing exposures in excess of the guideline levels specified in 10 CFR 100. The containment system, which forms a barrier to the escape of fission products should a loss of coolant occur, is described in Section 6.2. Postulated accidents that could release radioactivity to the environment are analyzed in Chapter 15. This criterion is associated with 1967 GDCs 17 and 70. Criterion 61, 1971 - Fuel Storage and Handling and Radioactivity Control The fuel storage and handling, radioactive waste, and other systems which may contain radioactivity shall be designed to assure adequate safety under normal and postulated accident conditions. These systems shall be designed (1) with a capability to permit appropriate periodic inspection and testing of components important to safety, (2) with suitable shielding for radiation protection, (3) with appropriate containment, confinement, and filtering systems, (4) with a residual heat removal capability having reliability and testability that reflects the importance to safety of decay heat and other residual heat removal, and (5) to prevent significant reduction in fuel storage coolant inventory under accident conditions. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 61. The fuel storage facility meets the requirements of Safety Guide 13, March 1971. Radioactive waste DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-38 Revision 21 September 2013 treatment systems that contain or confine leakage under normal and accident conditions are located in the auxiliary building. Adequate shielding is provided. The associated ventilation equipment includes charcoal filtration that minimizes radioactive material release associated with a postulated fuel handling accident. The spent fuel area is enclosed and maintained under negative pressure. All ventilation air is passed through HEPA filters prior to being released to the plant vent. In the event of an accident, high activity would be detected by the radiation monitor (see Section 11.4), and the exhaust air would be diverted through charcoal filters. For radioactive waste storage, refer to the detailed discussion in Chapter 11. Failure of a gas decay tank has been postulated and analyzed in Chapter 15. Waste handling systems are incorporated in the facility design for processing and/or retention of radioactive wastes from normal operation, with appropriate controls and monitors to ensure that releases do not exceed the limits of 10 CFR 20. The radioactive waste processing system, the design criteria, and amounts of estimated releases of radioactive effluents to the environment are described in Chapter 11. Details of the monitoring system are found in Section 11.4. Refueling water provides a reliable and adequate cooling medium for spent fuel transfer, and heat removal is provided by an auxiliary cooling system. Natural radiation and convection is adequate for cooling the holdup tanks. Active components of the spent fuel pool cooling and cleanup system are either in continuous or intermittent use during normal system operation. Periodic visual inspection and preventive maintenance are conducted using normal industry practice. System piping is arranged so that failure of any pipeline cannot inadvertently drain the spent fuel pool below the water level required for radiation shielding. Demineralized makeup water can be added directly to the spent fuel pool by a PG&E Design Class I source. This criterion is associated with 1967 GDCs 68 and 69. Criterion 62, 1971 - Prevention of Criticality in Fuel Storage and Handling Criticality in the fuel storage and handling system shall be prevented by physical systems or processes, preferably by use of geometrically safe configurations. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 62. Fuel storage and transfer systems are configured to preclude criticality. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-39 Revision 21 September 2013 During reactor vessel head removal and while loading and unloading fuel from the reactor, the boron concentration in the refueling water and the spent fuel pool is maintained at not less than that required to shut down the core to a keff = 0.95. Borated water is used to fill the spent fuel storage pools at a concentration comparable to that used in the reactor cavity and refueling canal during refueling operations. The fuel is stored vertically in an array with sufficient center-to-center distance between assemblies to ensure that, including uncertainties, a keff of less than or equal to 0.95 if the fuel racks are flooded with borated water, and a keff < 1.0, even if unborated water is used to fill the pool. The fuel storage and handling details are found in Section 9.1. This criterion is associated with 1967 GDC 66. Criterion 63, 1971 - Monitoring Fuel and Waste Storage Appropriate systems shall be provided in fuel storage and radioactive waste systems and associated handling area (1) to detect conditions that may result in loss of residual heat removal capability and excessive radiation levels and (2) to initiate appropriate safety actions. Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 63. Failure in the spent fuel pool cooling system and high radiation level in the spent fuel pool or radioactive waste areas are alarmed locally and in the control room. The fuel and waste storage and handling areas are provided with monitoring and alarm systems for radioactivity, and the plant vents are monitored for radioactivity during all operations. The monitoring systems are described in Section 11.4. The spent fuel pool cooling system is equipped with adequate instrumentation for normal operation. Water temperatures in the pool and at the outlet of the heat exchanger are indicated locally, and high pool temperature is alarmed in the control room. The spent fuel pool cooling system is described in Section 9.1. This criterion is associated with 1967 GDC 18. Criterion 64, 1971 - Monitoring Radioactivity Releases Means shall be provided for monitoring the reactor containment atmosphere, spaces containing components for recirculation of loss-of-coolant accident fluids, effluent discharge paths, and the plant environs for radioactivity that may be released from normal operations, including anticipated operational occurrences, and from postulated accidents. DCPP UNITS 1 & 2 FSAR UPDATE 3.1A-40 Revision 21 September 2013 Discussion The DCPP Units 1 and 2 designs conform to the intent of Criterion 64. The containment atmospheres, the plant vents, and the waste effluents are monitored for radioactivity concentration during all operations. Radiation detection instruments are located in areas of the plant that house equipment containing or processing radioactive materials. These instruments continually detect, compute, and record operating radiation levels. The data from the offsite monitoring program are reported annually. The reports include the basic data on sampling locations, organism collected, counting data, gross activity levels, identification of gamma emitting isotopes, and the associated counting errors. The monitoring systems are described in Section 11.4. The offsite radiological monitoring program is described in Section 11.6. This criterion is associated with 1967 GDC 17. DCPP UNITS 1 & 2 FSAR UPDATE Chapter 4 REACTOR CONTENTS Section Title Page i Revision 21 September 2013 4.1 SUMMARY DESCRIPTION 4.1-1 4.1.1 References 4.1-4
4.2 MECHANICAL DESIGN 4.2-1 4.2.1 Fuel 4.2-2 4.2.1.1 Design Bases 4.2-2 4.2.1.2 Description and Design Drawings 4.2-6 4.2.1.3 Design Evaluation 4.2-12 4.2.1.4 Testing and Inspection Plan 4.2-21
4.2.2 Reactor Vessel Internals 4.2-22 4.2.2.1 Design Bases 4.2-22 4.2.2.2 Description and Drawings 4.2-23 4.2.2.3 Design Loading Conditions 4.2-27 4.2.2.4 Design Loading Categories 4.2-29 4.2.2.5 Design Criteria Bases 4.2-30
4.2.3 Reactivity Control System 4.2-30 4.2.3.1 Design Bases 4.2-30 4.2.3.2 Description and Drawings 4.2-33 4.2.3.3 System Evaluation 4.2-40 4.2.3.4 Testing and Inspection Plan 4.2-48 4.2.3.5 Instrumentation 4.2-49
4.2.4 References 4.2-50
4.3 NUCLEAR DESIGN 4.3-1
4.3.1 Design Bases 4.3-1 4.3.1.1 Fuel Burnup 4.3-2 4.3.1.2 Negative Reactivity Feedbacks (Reactivity Coefficients) 4.3-2 4.3.1.3 Control of Power Distribution 4.3-3 4.3.1.4 Maximum Controlled Reactivity Insertion Rate 4.3-4 4.3.1.5 Shutdown Margins 4.3-5 4.3.1.6 Stability 4.3-6 4.3.1.7 Anticipated Transients Without Scram 4.3-7
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 4 CONTENTS (Continued) Section Title Page ii Revision 21 September 2013 4.3.2 Description 4.3-7 4.3.2.1 Nuclear Design Description 4.3-7 4.3.2.2 Power Distribution 4.3-8 4.3.2.3 Reactivity Coefficients 4.3-19 4.3.2.4 Control Requirements 4.3-22 4.3.2.5 Control 4.3-25 4.3.2.6 Control Rod Patterns and Reactivity Worths 4.3-27 4.3.2.7 Criticality of Fuel Assemblies 4.3-28 4.3.2.8 Stability 4.3-30 4.3.2.9 Vessel Irradiation 4.3-33
4.3.3 Analytical Methods 4.3-33 4.3.3.1 Fuel Temperature (Doppler) Calculations 4.3-34 4.3.3.2 Macroscopic Group Constants 4.3-35 4.3.3.3 Spatial Few-Group Diffusion Calculations 4.3-37
4.3.4 References 4.3-38 4.4 THERMAL AND HYDRAULIC DESIGN 4.4-1 4.4.1 Design Bases 4.4-1 4.4.1.1 Departure from Nucleate Boiling Design Basis 4.4-1 4.4.1.2 Fuel Temperature Design Basis 4.4-3 4.4.1.3 Core Flow Design Basis 4.4-3 4.4.1.4 Hydrodynamic Stability Design Basis 4.4-3 4.4.1.5 Other Considerations 4.4-4
4.4.2 Description 4.4-4 4.4.2.1 Summary Comparison 4.4-4 4.4.2.2 Fuel Cladding Temperatures 4.4-4 4.4.2.3 Departure from Nucleate Boiling Ratio 4.4-8 4.4.2.4 Flux Tilt Considerations 4.4-14 4.4.2.5 Void Fraction Distribution 4.4-15 4.4.2.6 Core Coolant Flow Distribution 4.4-15 4.4.2.7 Core Pressure Drops and Hydraulic Loads 4.4-15 4.4.2.8 Correlation and Physical Data 4.4-16 4.4.2.9 Thermal Effects of Operational Transients 4.4-18 4.4.2.10 Uncertainties in Estimates 4.4-19 4.4.2.11 Plant Configuration Data 4.4-21
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 4 CONTENTS (Continued) Section Title Page iii Revision 21 September 2013 4.4.3 Evaluation 4.4-22 4.4.3.1 Core Hydraulics 4.4-22 4.4.3.2 Influence of Power Distribution 4.4-23 4.4.3.3 Core Thermal Response 4.4-25 4.4.3.4 Analytical Techniques 4.4-25 4.4.3.5 Hydrodynamic and Flow-Power Coupled Instability 4.4-29 4.4.3.6 Temperature Transient Effects Analysis 4.4-30 4.4.3.7 Potentially Damaging Temperature Effects During Transients 4.4-30 4.4.3.8 Energy Release During Fuel Element Burnout 4.4-31 4.4.3.9 Energy Release During Rupture of Waterlogged Fuel Elements 4.4-31 4.4.3.10 Fuel Rod Behavior Effects from Coolant Flow Blockage 4.4-32 4.4.3.11 Pressurization Analyses for Shutdown Conditions 4.4-32
4.4.4 Testing and Verification 4.4-33 4.4.4.1 Testing Prior to Initial Criticality 4.4-33 4.4.4.2 Initial Power Plant Operation 4.4-33 4.4.4.3 Component and Fuel Inspections 4.4-33 4.4.5 Instrumentation Requirements 4.4-33 4.4.5.1 Incore Instrumentation 4.4-33 4.4.5.2 Overtemperature and Overpower T Instrumentation 4.4-34 4.4.5.3 Instrumentation to Limit Maximum Power Output 4.4-34 4.4.5.4 Loose Parts Monitoring 4.4-35
4.4.6 References 4.4-36
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 4 TABLES Table Title iv Revision 21 September 2013 4.1-1 Reactor Design Comparison 4.1-2 Analytical Techniques in Core Design
4.1-3 Design Loading Conditions for Reactor Core Components
4.2-1 Maximum Deflections Allowed for Reactor Internal Support Structures
4.3-1 Nuclear Design Parameters (Typical)
4.3-2 Unit 1 - Reactivity Requirements for Rod Cluster Control Assemblies
4.3-3 Unit 2 - Reactivity Requirements for Rod Cluster Control Assemblies
4.3-4 Axial Stability Index PWR Core With a 12-ft Height
4.3-5 Typical Neutron Flux Levels (n/cm2 sec) at Full Power 4.3-6 Comparison of Measured and Calculated Doppler Defects 4.3-7 Benchmark Critical Experiments
4.3-8 Saxton Core II Isotopics, Rod MY, Axial Zone 6
4.3-9 Critical Boron Concentrations, at HZP, BOL
4.3-10 Comparison of Measured and Calculated Rod Worth
4.3-11 Comparison of Measured and Calculated Moderator Temperature Coefficients at HZP, BOL 4.4-1 Unit 1 - Void Fractions at Nominal Reactor Conditions with Design Hot Channel Factors 4.4-2 Unit 2 - Void Fractions at Nominal Reactor Conditions with Design Hot Channel Factors. 4.4-3 Comparison of THINC-IV and THINC-I Predictions with Data from Representative Westinghouse Two- and Three-loop Reactors DCPP UNITS 1 & 2 FSAR UPDATE Chapter 4 FIGURES Figure Title v Revision 21 September 2013 4.2-1 Fuel Assembly Cross Section 4.2-2 Fuel Assembly Outline - LOPAR
4.2-2A 17 x 17 VANTAGE 5/LOPAR Fuel Assembly Comparison
4.2-3 Fuel Rod Schematic - LOPAR
4.2-3A 17 x 17 VANTAGE 5/LOPAR Fuel Rod Assembly Comparison
4.2-4 Typical Clad and Pellet Dimensions, as a Function of Exposure
4.2-5 Representative Fuel Rod Internal Pressure and Linear Power Density for the Lead Burnup Rod as a Function of Time 4.2-6 Removable Rod Compared to Standard Rod
4.2-7 Removable Fuel Rod Assembly Outline 4.2-8 Location of Removable Rods Within an Assembly
4.2-9 Unit 1 - Lower Core Support Assembly
4.2-10 Unit 2 - Lower Core Support Assembly
4.2-11 Unit 2 - Neutron Shield Pad Lower Core Support Structure
4.2-12 Unit 1 - Upper Core Support Structure
4.2-13 Unit 2 - Upper Core Support Structure
4.2-14 Plan View of Upper Core Support Structure
4.2-15 Rod Cluster Control and Drive Rod Assembly with Interfacing Components 4.2-16 Rod Cluster Control Assembly Outline
4.2-17 Absorber Rod
4.2-18 Burnable Absorber Assembly DCPP UNITS 1 & 2 FSAR UPDATE Chapter 4 FIGURES (Continued) Figure Title vi Revision 21 September 2013 4.2-18A Wet Annular Burnable Absorber Rod 4.2-19 Burnable Absorber Rod Sections
4.2-20 Primary Source Assembly
4.2-21 Secondary Source Assembly
4.2-21A Secondary Source Assembly
4.2-22 Thimble Plug Assembly
4.2-23 Control Rod Drive Mechanism
4.2-23A Deleted in Revision 20
4.2-24 Control Rod Drive Mechanism Schematic 4.2-24A Deleted in Revision 20 4.2-25 Nominal Latch Clearance at Minimum and Maximum Temperature
4.2-26 Control Rod Drive Mechanism Latch Clearance Thermal Effect
4.3-1 Fuel Loading Arrangement
4.3-2 Production and Consumption of Higher Isotopes
4.3-3 Boron Concentration vs. Cycle Burnup With Burnable Absorber Rods
4.3-4 Burnable Absorber Rod Arrangement Within an Assembly
4.3-5 Typical Integral Fuel Burnable Absorber Rod Arrangement within an Assembly 4.3-6 Burnable Absorber Loading Pattern
4.3-7 Normalized Power Density Distribution Near Beginning of Life (BOL), Unrodded Core, Hot Full Power, No Xenon DCPP UNITS 1 & 2 FSAR UPDATE Chapter 4 FIGURES (Continued) Figure Title vii Revision 21 September 2013 4.3-8 Normalized Power Density Distribution Near BOL, Unrodded Core, Hot Full Power, Equilibrium Xenon 4.3-9 Unit 1 - Normalized Power Density Distribution Near BOL, Group D at Insertion Limit, Hot Full Power, Equilibrium Xenon 4.3-10 Unit 2 - Normalized Power Density Distribution Near BOL, Group D at Insertion Limit, Hot Full Power, Equilibrium Xenon 4.3-11 Normalized Power Density Distribution Near Middle of Life (MOL), Unrodded Core, Hot Full Power, Equilibrium Xenon 4.3-12 Normalized Power Density Distribution Near End of Life (EOL), Unrodded Core, Hot Full Power, Equilibrium Xenon 4.3-13 Rodwise Power Distribution in a Typical Assembly (G-10) Near BOL, Hot Full Power, Equilibrium Xenon, Unrodded Core 4.3-14 Rodwise Power Distribution in a Typical Assembly (G-10) Near EOL, Hot Full Power, Equilibrium Xenon, Unrodded Core 4.3-15 Possible Axial Power Shapes at BOL Due to Adverse Xenon Distribution
4.3-16 Possible Axial Power Shapes at MOL Due to Adverse Xenon Distribution
4.3-17 Possible Axial Power Shapes at EOL Due to Adverse Xenon Distribution
4.3-18 Deleted in Revision 16
4.3-19 Deleted in Revision 16
4.3-20 Deleted in Revision 16
4.3-21 Peak Power Density During Control Rod Malfunction Overpower Transients 4.3-22 Peak Linear Power During Boration/Dilution Overpower Transients 4.3-23 Maximum FxQT Power vs. Axial Height During Normal Operations 4.3-24 Comparison of Expected Steady State Power Distributions with the Peaking Factor Envelope DCPP UNITS 1 & 2 FSAR UPDATE Chapter 4 FIGURES (Continued) Figure Title viii Revision 21 September 2013 4.3-25 Comparison Between Calculated and Measured Relative Fuel Assembly Power Distribution 4.3-26 Comparison of Calculated and Measured Axial Shape 4.3-27 Measured Values of FQT for Full Power Rod Configurations 4.3-28 Doppler Temperature Coefficient at BOL and EOL
4.3-29 Doppler Only Power Coefficient at BOL and EOL
4.3-30 Doppler Only Power Defect at BOL and EOL
4.3-31 Moderator Temperature Coefficient at BOL, No Rods
4.3-32 Moderator Temperature Coefficient at EOL
4.3-33 Moderator Temperature Coefficient as a Function of Boron Concentration at BOL, No Rods 4.3-34 Hot Full Power Moderator Temperature Coefficient for Critical Boron Concentration 4.3-35 Total Power Coefficient at BOL and EOL
4.3-36 Total Power Defect at BOL and EOL
4.3-37 Unit 1 - Rod Cluster Control Assembly Pattern
4.3-38 Unit 2 - Rod Cluster Control Assembly Pattern
4.3-39 Accidental Simultaneous Withdrawal of Two Control Banks EOL, HZP Banks B and D Moving in the Same Plane 4.3-40 Design - Trip Curve
4.3-41 Normalized Rod Worth vs. Percent Insertion, All Rods But One
4.3-42 Axial Offset vs. Time, PWR Core with a 12-ft Core Height and 121 Assemblies DCPP UNITS 1 & 2 FSAR UPDATE Chapter 4 FIGURES (Continued) Figure Title ix Revision 21 September 2013 4.3-43 XY Xenon Test Thermocouple Response Quadrant Tilt Difference vs. Time 4.3-44 Calculated and Measured Doppler Defect and Coefficients at BOL, for a Two-loop Plant with a 12-ft Core Height and 121 Assemblies 4.3-45 Comparison of Calculated and Measured Boron Concentration for a Two-loop Plant with a 12-ft Core Height and 121 Assemblies, 4.3-46 Comparison of Calculated and Measured Boron for a Two-loop Plant with a 12-ft Core Height and 121 Assemblies 4.3-47 Comparison of Calculated and Measured Boron in a Three-loop Plant with a 12-ft Core Height and 157 Assemblies 4.4-1 Peak Fuel Average and Surface Temperatures During Fuel Rod Lifetime vs. Linear Power Density 4.4-2 Peak Fuel Centerline Temperature During Fuel Rod Lifetime vs. Linear Power Density 4.4-3 Thermal Conductivity of UO2 (Data Corrected to 95% Theoretical Density) 4.4-4 Axial Variation of Average Clad Temperature for Rod Operating at 5.43 kW/ft 4.4-5 Probability Curves for W-3 and R Grid DNB Correlations
4.4-6 TDC vs. Reynolds Number for 26-inch Grid Spacing
4.4-7 Normalized Radial Flow and Enthalpy Distribution at 4-ft Elevation
4.4-8 Normalized Radial Flow and Enthalpy Distribution at 8-ft Elevation
4.4-9 Normalized Radial Flow and Enthalpy Distribution at 12-ft Elevation Core Exit 4.4-10 Void Fraction vs. Thermodynamic Quality H-HSAT/HG-HSAT 4.4-11 PWR Natural Circulation Test DCPP UNITS 1 & 2 FSAR UPDATE Chapter 4 FIGURES (Continued) Figure Title x Revision 21 September 2013 4.4-12 Comparison of a Representative W Two-loop Reactor Incore Thermocouple Measurements with THINC-IV Predictions 4.4-13 Comparison of a Representative W Three-loop Reactor Incore Thermocouple Measurements with THINC-IV Predictions 4.4-14 Hanford Subchannel Temperature Data Comparison With THINC-IV
4.4-15 Hanford Subcritical Temperature Data Comparison With THINC-IV
4.4-16 Unit 1 - Distribution of Incore Instrumentation
4.4-17 Unit 2 - Distribution of Incore Instrumentation
4.4-18 Improved Thermal Design Procedure Illustration
4.4-19 Measured Versus Predicted Critical Heat Flux-WRB-1 Correlation
4.4-20 Measured Versus Predicted Critical Heat Flux-WRB-2 Correlation DCPP UNITS 1 & 2 FSAR UPDATE 4.1-1 Revision 21 September 2013 Chapter 4 REACTOR This chapter describes the design for the reactors at Diablo Canyon Power Plant (DCPP) Units 1 and 2, and evaluates their capability to function safely under all operating modes expected during their lifetimes. 4.1 SUMMARY DESCRIPTION This chapter describes the following subjects: (a) the mechanical components of the reactor and reactor core, including the fuel rods and fuel assemblies, reactor internals, and the control rod drive mechanisms, (b) the nuclear design, and (c) the thermal-hydraulic design.
The reactor core of each unit typically consists of VANTAGE 5 fuel assemblies, instead of the low parasitic (LOPAR) fuel previously used. Some of the current Chapter 15 accident analyses, including the large break and small break loss of coolant accidents, assume an all Vantage 5 core. Therefore, it is not expected that LOPAR fuel will be used without further analysis. Nevertheless, this section addresses both LOPAR fuel assemblies and Vantage 5 arranged in a low leakage core-loading pattern.
The significant mechanical design features of the VANTAGE 5 design, as defined in Reference 1, relative to the LOPAR fuel design may include the following:
- Integral Fuel Burnable Absorber (IFBA)
- Intermediate Flow Mixer (IFM) Grids
- Protective Grid Assemblies (P-Grid)
- Reconstitutable Top Nozzle (RTN)
- Slightly longer fuel rods and thinner top and bottom nozzle end plates to accommodate extended burnup
- Axial Blanket (typically six inches of natural or slightly enriched UO2 at both ends of fuel stack)
- Replacement of six intermediate Inconel grids with zirconium alloy grids
- Reduction in fuel rod, guide thimble and instrumentation tube diameter
- Redesigned fuel rod bottom end plug to facilitate reconstitution capability.
- Debris filter bottom nozzle (DFBN)
DCPP UNITS 1 & 2 FSAR UPDATE 4.1-2 Revision 21 September 2013 Commencing with Unit 2 Region 20 (Cycle 18 feed) and Unit 1 Region 21 (Cycle 19 feed), the Westinghouse fuel assemblies will utilize the Standardized Debris Filter Bottom Nozzle (SDFBN). This feature is discussed in detail in Section 4.2.1.2.2. The core is cooled and moderated by light water at a nominal pressure of 2250 psia in the reactor coolant system (RCS). The moderator coolant uses boron as a neutron absorber. Boron concentration in the coolant is varied as required to control relatively slow reactivity changes, such as fuel burnup. Additional boron, in the form of Integral Fuel Burnable Absorbers (IFBA) or burnable absorber rods may be employed to limit the moderator temperature coefficient (MTC) and the local power peaking that can be achieved.
A fuel assembly consists of up to 264 mechanically joined fuel rods in a 17 x 17 square array. The fuel rods are supported at intervals along their length by grid assemblies that maintain the lateral spacing between the rods throughout the design life of the assembly. The grid assembly consists of an "egg-crate" arrangement of interlocked straps. The straps contain spring fingers and dimples for maintaining fuel rod lateral and axial support, as well as for providing coolant mixing vanes. The fuel rods consist of enriched UO2 cylindrical pellets contained in zirconium alloy tubing that is plugged and seal-welded at the ends. To increase fatigue life, all fuel rods are pressurized with helium during fabrication to reduce stress and strain.
The center position in the assembly is reserved for incore instrumentation; the remaining 24 positions in the array are equipped with guide thimbles joined to the grids and the top and bottom nozzles. Depending on assembly position in the core, the guide thimbles are used as core locations for rod cluster control assemblies (RCCAs), neutron source assemblies, and burnable absorber rods (if used). The bottom nozzle is a box-like structure that serves as a bottom structural element of the fuel assembly and directs the coolant flow to the assembly.
The top nozzle assembly functions as the upper structural element of the fuel assembly in addition to providing a partial protective housing for the RCCA or other components.
Each RCCA consists of a group of individual absorber rods fastened at the top end to a common hub or spider assembly.
The control rod drive mechanisms (CRDMs) for the RCCA are of the magnetic latch type. The latches are controlled by three magnetic coils. Upon a loss of power to the coils, the RCCA is released and falls by gravity to shut down the reactor.
Components of the reactor internals are divided into three parts: (a) the lower core support structure (including the entire core barrel, the Unit 1 thermal shield, and the Unit 2 neutron shield pad assembly), (b) the upper core support structure, and (c) the incore instrumentation support structure. Reactor internals support the core, maintain fuel alignment, limit fuel assembly movement, maintain alignment between fuel DCPP UNITS 1 & 2 FSAR UPDATE 4.1-3 Revision 21 September 2013 assemblies and CRDMs, direct coolant flow past the fuel elements to the pressure vessel head, provide gamma and neutron shielding, and provide guides for incore instrumentation.
The nuclear design analyses and evaluation establish physical locations for control rods, burnable absorber, and physical parameters such as fuel enrichments and boron concentration in the coolant. These characteristics, together with corrective actions by the reactor control and the protection and the emergency core cooling systems, provide adequate reactivity control even if the RCCA with the highest reactivity worth is stuck in the fully withdrawn position. They meet the reactor performance and safety criteria specified in Section 4.2.
The thermal-hydraulic design analyses and evaluation establish coolant flow parameters that ensure adequate heat transfer between fuel cladding and reactor coolant. The thermal design takes into account local variations in dimensions, power generation, flow distribution, mixing and the IFM grids in the VANTAGE 5 fuel assembly. The mixing vanes incorporated in the fuel assembly spacer grid design induce additional flow mixing between the various flow channels within a fuel assembly as well as between adjacent assemblies.
The fuel assembly design, starting at Cycle 9, consisted of VANTAGE 5+ assemblies with fully enriched annular fuel pellets in the axial blanket region of the fuel rods (see Section 4.2.1.2.1) in order to provide additional internal rod pressure design margin.
The Cycle 9 core design also revised the design Departure From Nucleate Boiling Ratio (DNBR) (see Section 4.4) to incorporate uncertainties and biases for reactor power, flow, temperature, and pressure. The original Improved Thermal Design Procedure (ITDP) (see Section 4.2.4, Reference 86) is updated with these new uncertainties and evaluated for each fuel reload cycle. The reload design documents for each fuel cycle contain the updated ITDP reference and the new design DNBR, if required, to be incorporated into the Technical Specification Bases.
Starting at Cycle 12, the VANTAGE 5+ design had evolved to incorporate a protective grid assembly (P-Grid) at the bottom of the fuel rods that spans the gap between the bottom nozzle and grid and the fuel rods and provides an additional debris barrier to improve fuel reliability.
Instrumentation is provided in and out of the core to monitor the nuclear, thermal-hydraulic, and mechanical performance of the reactor, and to provide input signals to control functions automatically.
Table 4.1-1 presents a comparison between the reactor design parameters for the DCPP Units 1 and 2 reactor cores fueled with LOPAR fuel assemblies and VANTAGE 5 fuel assemblies. The analysis techniques employed in the core design are tabulated in Table 4.1-2. Design loading conditions for reactor core components are tabulated in Table 4.1-3. DCPP UNITS 1 & 2 FSAR UPDATE 4.1-4 Revision 21 September 2013 4.
1.1 REFERENCES
- 1. S. L. Davidson, (Ed.), Reference Core Report - VANTAGE 5 Fuel Assembly, WCAP-10444-P-A, September 1985.
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-1 Revision 21 September 2013 4.2 MECHANICAL DESIGN For design purposes, the Diablo Canyon Power Plant (DCPP) conditions are divided into four categories, in accordance with their anticipated frequency of occurrence and risk to the public, as follows:
(1) Condition I - Normal Operation (2) Condition II - Incidents of Moderate Frequency (3) Condition III - Infrequent Faults (4) Condition IV - Limiting Faults In general, Condition I occurrences are accommodated with margin between any plant parameter and the value of that parameter which would require either automatic or manual protective action. Condition II incidents are accommodated with, at most, a shutdown of the reactor with the plant capable of returning to operation after corrective action.
The release of radioactive material due to Condition III incidents should not be sufficient to interrupt or restrict public use of areas outside the exclusion area. Furthermore, a Condition III incident shall not, by itself, generate a Condition IV fault or result in a consequential loss of function of the reactor coolant system (RCS) or reactor containment barriers. Condition IV occurrences are faults that are not expected to occur, but are defined as limiting faults that must be considered in design. Condition IV faults shall not cause a release of radioactive material that results in an undue risk to public health and safety.
The reactor is designed so that its components meet the following performance and safety criteria:
(1) The mechanical design of the reactor core components and their physical arrangement, together with corrective actions by the reactor control, protection, and emergency cooling systems (when applicable) ensure that: (a) Fuel damage(a) is not expected during Conditions I and II events, although a very small number of fuel rod failures is anticipated. This number of failures is within the capability of the plant cleanup system and is consistent with the plant design bases. (a) Fuel damage as used here is defined as penetration of the fission product barrier (i.e., the fuel rod cladding).
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-2 Revision 21 September 2013 (b) The reactor can be brought to a safe state following a Condition III event with only a small number of fuel rods damaged, although sufficient fuel damage may occur to preclude resumption of operation without considerable outage time. (c) The reactor can be brought to a safe state and the core can be kept subcritical with acceptable heat transfer geometry, following transients arising from Condition IV events. (2) The fuel assemblies are designed to accommodate conditions expected to exist as a result of handling during assembly, inspection, and refueling operations, as well as shipping loads. (3) The fuel assemblies are designed to accept control rod insertions to provide the reactivity control required for power operations and shutdown conditions. (4) All fuel assemblies have provisions for the insertion of the incore instrumentation necessary for plant operation. (5) The reactor internals, in conjunction with the fuel assemblies, direct reactor coolant through the core to achieve acceptable flow distribution and to restrict bypass flow so that the heat transfer performance requirements can be met for all modes of operation. In addition, internals provide core support and distribute coolant flow to the pressure vessel head. The distribution of flow into the vessel head minimizes axial and circumferential temperature gradients, thus precluding excessive rotation or warpage that could result in leakage past the O-ring gaskets during Conditions I and II operations. Required inservice inspections can be carried out since the internals are removable and provide access to the inside of the pressure vessel. 4.2.1 FUEL 4.2.1.1 Design Bases For both the low parasitic (LOPAR) and the VANTAGE 5 fuel assemblies, the fuel rod and fuel assembly design bases are established to satisfy the general performance and safety criteria presented in Section 4.2 and the specific criteria noted below. 4.2.1.1.1 Fuel Rods To ensure their integrity, fuel rods are designed to prevent excessive fuel temperatures, excessive internal gas pressures due to fission gas buildup, and excessive cladding stresses and strains. To this end, the following conservative design bases are adopted for Condition I and Condition II operations: DCPP UNITS 1 & 2 FSAR UPDATE 4.2-3 Revision 21 September 2013 (1) Fuel Pellet Temperatures - The center temperature of the hottest pellet is to be below the melting temperature of the UO2 (melting point of 5080°F (Reference 1)) unirradiated and reducing by 58°F per 10,000 megawatt days/metric ton of uranium (MWD/MTU). While a limited amount of center melting can be tolerated, the design conservatively precludes center melting. A calculated centerline fuel temperature of 4700°F has been selected as the overpower limit. This provides sufficient margin for uncertainties. (2) Internal Gas Pressure - The fuel rod internal gas pressure remains below the value that can cause the fuel-cladding diametral gap to increase due to outward cladding creep during steady state operation. Rod pressure is also limited so that extensive departure from nucleate boiling (DNB) propagation does not occur during normal operation and accident events (Reference 14). Also, cladding flattening (Reference 15) will not occur during the fuel rod incore life. (3) Cladding Stress - The effective cladding stresses are less than those that would cause general cladding yield. While the cladding has some capability to accommodate plastic strain, the yield strength has been accepted as a conservative design basis. (4) Cladding Tensile Strain - The cladding tangential strain is less than 1 percent. The cladding strain design basis addresses slow transient strain rate mechanisms where the cladding effective stress never reaches the yield strength due to stress relaxation. The 1 percent strain limit is based on tensile and burst test data from irradiated cladding. Irradiated cladding properties are appropriately used since irradiation effects on cladding ductility occur before strain-limiting fuel cladding interaction during a transient event can occur. (5) Strain Fatigue - The cumulative strain fatigue cycles are less than the design strain fatigue life. Radial, tangential, and axial stress components due to pressure differential and fuel cladding contact pressure are combined into an effective stress using the maximum-distortion-energy theory. The von Mises criterion (Reference 22) is used to evaluate whether or not the yield strength has been exceeded. The criterion states that an isotropic material under multiaxial stress will begin to yield plastically when the effective stress (i.e., combined stress using maximum-distortion-energy theory) becomes equal to the material yield stress in simple tension, as determined by a uniaxial tensile test. Since general yielding is prohibited, the volume average effective stress determined by integrating across the cladding thickness is increased by an allowance for local nonuniformity effects before the stress is compared to the yield strength. The yield strength correlation is that appropriate for irradiated cladding since the irradiated properties are attained at low exposure, whereas the fuel/cladding DCPP UNITS 1 & 2 FSAR UPDATE 4.2-4 Revision 21 September 2013 interaction conditions, which can lead to minimum margin to the design basis limit, always occur at much higher exposures.
The preceding fuel rod design bases and other supplementary fuel design criteria/limits are given in Section 2 of Reference 25. Reference 25 provides the methodology for peak rod burnups in excess of 50,000 MWD/MTU. The above requirements impact design parameters such as pellet size and density, cladding-pellet diametral gap, gas plenum size, and helium pre-pressure. The design also considers effects such as fuel density changes, fission gas release, cladding creep, and other physical properties that vary with burnup.
An extensive irradiation testing and fuel surveillance operational experience program has been conducted to verify the adequacy of the fuel performance and design bases. This program is discussed in Section 4.2.1.3.3. 4.2.1.1.2 Fuel Assembly Structure Structural integrity of fuel assemblies is ensured by setting limits on stresses and deformations due to various loads, and by determining that the assemblies do not interfere with other components' operability. Three types of loads are considered:
(1) Nonoperational loads, such as those due to shipping and handling (2) Normal and abnormal loads defined for Conditions I and II (3) Abnormal loads defined for Conditions III and IV These stress and deformation limits are applied to the design and evaluation of the top and bottom nozzles, the guide thimbles, the grids, and the thimble joints.
The design bases for evaluating the structural integrity of the fuel assemblies are:
(1) Nonoperational - 4g axial and 6g lateral loading with dimensional stability in both lateral and axial directions. (2) Normal Operation (Condition I) and Incidents of Moderate Frequency (Condition II). The fuel assembly component structural design criteria are classified into two material categories: austenitic steels and zirconium alloys. Although not strictly fuel assembly components, reactor core elements that are made of stainless steel and are closely related to the fuel assembly design include the top and bottom nozzle, the RCCA cladding, and some burnable absorber rod's cladding. The stress categories and strength theory presented in the ASME Boiler and Pressure Vessel Code (ASME B&PV), Section III, are used as a general guide.
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-5 Revision 21 September 2013 Zirconium alloy structural components, which consist of guide thimbles and fuel tubes, are in turn subdivided into two categories because of material differences and functional requirements. The fuel tube design criteria are covered separately in Section 4.2.1.3.1. To evaluate the guide thimble design, the maximum stress theory, which assumes that yielding due to combined stresses occurs when one of the principal stresses is equal to the simple tensile or compressive yield stress, is used. Unirradiated zirconium alloy properties are used to define the stress limits. The maximum shear stress theory (Tresca criterion (Reference 22) for combined stresses is used to determine the stress intensities for the austenitic steel components. The stress intensity is defined as the numerically largest difference between the various principal stresses in a three-dimensional field. The allowable stress intensity value for austenitic stainless steel, such as nickel-chromium-iron alloys, is given by the lowest of the following: (a) One-third of the specified minimum tensile strength, or two-thirds of the minimum yield strength, at room temperature. (b) One-third of the tensile strength or 90 percent of the yield strength, at temperature, but not to exceed two-thirds of the specified minimum yield strength at room temperature. The stress intensity limits for the austenitic steel components are: Stress Intensity Limits Categories Limit General Primary Membrane Stress Intensity 1.0 Sm Local Primary Membrane Stress Intensity 1.5 Sm Primary Membrane plus Bending Stress Intensity 1.5 Sm Total Primary plus Secondary Stress Intensity 3.0 Sm where Sm is the membrane stress. (3) Abnormal Loads During Conditions III or IV - Worst cases are represented by combined seismic and blowdown loads; however, with acceptance of the DCPP leak-before-break analysis by the NRC (Reference 30), the blowdown loads resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis analysis. Only the much smaller blowdown loads from RCS branch line breaks have to be considered (see Section 3.6.2.1.1.1.). (a) Deflections of components cannot interfere with reactor shutdown or emergency cooling of fuel rods. DCPP UNITS 1 & 2 FSAR UPDATE 4.2-6 Revision 21 September 2013 (b) The fuel assembly structural component stress under faulted conditions are evaluated using primarily the methods outlined in Appendix F of the ASME Boiler and Pressure Vessel Code, Section III. Since the current analytical methods utilize elastic analysis, the stress allowables are defined as the smaller value of 2.4 Sm or 0.70 Su (ultimate stress) for primary membrane and 3.6 Sm or 1.05 Su for primary membrane plus primary bending. For the austenitic steel fuel assembly components, the stress intensity is defined in accordance with the rules described in the previous section for normal operating conditions. For the Zircaloy components the stress intensity limits are set at two-thirds of the material yield strength, Sy, at reactor operating temperature. This results in Zircaloy stress limits being the smaller of 1.6 Sy or 0.70 Su for primary membrane and 2.4 Sy or 1.05 Su for primary membrane plus bending. For conservative purposes, the Zircaloy unirradiated properties are used to define the stress limits. The grid component strength criteria are based on experimental tests. For both Zircaloy and Inconel grids, the limit is the 95 percent confidence level on the true mean as taken from the distribution of measurements at operating temperature. 4.2.1.2 Description and Design Drawings The fuel assembly and fuel rod design data are listed in Table 4.1-1. NRC approval of the VANTAGE 5 design is given in Reference 26. Figure 4.2-1 shows a cross section of the fuel assembly array, and Figures 4.2-2 and 4.2-2a show fuel assembly full-length outlines. The fuel rods are loaded into the fuel assembly structure so that there is clearance between the fuel rod ends and the top and bottom nozzles. A slightly modified rod end plug, an improved bottom nozzle reconstitution feature, and modified grid straps to improve resistance to hangup during refueling were introduced with Region 4 of both units.
Shown in Figure 4.2-2a is a comparison of the different assembly designs noting respective overall height and grid elevation dimensions. The changes from the LOPAR design to the VANTAGE 5 design include a reduction in fuel rod, guide thimble and instrumentation tube diameters, and replacement of the six intermediate (mixing vane) Inconel grids with zirconium alloy grids. The VANTAGE 5 design also incorporates three zirconium alloy intermediate flow mixing (IFM) grids. The debris filter bottom nozzle (DFBN) has been incorporated into the VANTAGE 5 fuel assembly. The DFBN is similar to the LOPAR bottom nozzle design used in Region 5 (Cycle 3 feed) of the Diablo Canyon cores, except it is lower in height and has a new pattern of smaller flow holes. The DFBN minimizes passage of debris particles which could cause fretting damage to fuel rod cladding. Starting with Unit 2 Region 20 (Cycle 18 feed) and Unit 1 Region 21 (Cycle 19 feed), the SDFBN will be utilized. This SDFBN is discussed further in Section 4.2.1.2.2. DCPP UNITS 1 & 2 FSAR UPDATE 4.2-7 Revision 21 September 2013 The VANTAGE 5 assembly has the same cross-sectional envelope as the LOPAR assembly. The grid centerline elevations of the VANTAGE 5 are identical to those of the LOPAR assembly, except for the top and bottom grids. The grid centerline elevations of the VANTAGE 5 assemblies with P-Grids are identical to those of the VANTAGE 5, except for the bottom and first intermediate grid. However, for mixed cores, an integral grid-to-grid contact between different fuel assemblies is maintained. By matching grid elevation, any crossflow maldistribution between the fuel assemblies is minimized. The effect of any grid composition differences on the hydraulic compatibility is addressed in References 26 and 29.
Each fuel assembly is installed vertically in the reactor vessel and stands upright on the lower core plate, which is fitted with alignment pins to locate and orient the assembly. After all fuel assemblies are set in place, the upper support structure is installed. Alignment pins, built into the upper core plate, engage and locate the upper ends of the fuel assemblies. The upper core plate then bears downward against the fuel assemblies' top nozzles, via the holddown springs, to hold the fuel assemblies in place. 4.2.1.2.1 Fuel Rods The fuel rods consist of UO2 pellets encapsulated in zirconium alloy tubing that is plugged and seal-welded at the ends. Fuel rod schematics are shown in Figures 4.2-3 and 4.2-3a. The fuel pellets are right circular cylinders consisting of uranium dioxide powder that has been compacted by cold pressing and then sintered to the required density. The ends of each pellet are dished slightly to allow greater axial expansion at the center of the pellets. Beginning with Region 4, fuel pellets have chamfered ends to reduce pellet cracking during fuel manufacturing and handling. The VANTAGE 5 fuel rod has the same cladding wall thickness as the LOPAR fuel rod, but the VANTAGE 5 fuel rod diameter is reduced to optimize the water-to-uranium ratio. The VANTAGE 5 fuel rod length is larger by 0.695 inches to provide a longer plenum and bottom end plug. The bottom end plug has an internal grip feature to facilitate rod loading on both designs and is longer to provide a longer lead-in for the removable top nozzle reconstitution feature. The Diablo Canyon fuel may include axial blankets of natural or enriched uranium and Integral Fuel Burnable Absorbers (IFBA).
The VANTAGE 5 fuel uses a standardized pellet design, which is a refinement to the previous chamfered pellet design, with the objective of improving manufacturability while maintaining or improving performance (e.g., improved pellet chip resistance during manufacturing/ handling). This design (and the previous Region 5 design) incorporates a reduced pellet length (see Table 4.1-1) and modifications to the Region 4 pellet chamfer and dish size.
The axial blankets typically are a nominal 6 inches of natural or enriched fuel pellets at each end of the fuel rod pellet stack. However, the option exists to increase the top axial blanket length to a nominal 7 inches. Certain fuel assemblies utilize annular fuel pellets in the axial blanket region of the fuel rods. The use of this feature provides DCPP UNITS 1 & 2 FSAR UPDATE 4.2-8 Revision 21 September 2013 additional margin to the fuel rod internal pressure design limits. Axial blankets reduce neutron leakage and improve fuel utilization. The axial blankets utilize pellets, which are physically different from the non-axial blanket pellets to prevent accidental mixing during manufacturing.
Beginning with Cycle 9, the new fuel regions incorporated the Westinghouse VANTAGE + design, which is capable of achieving extended burnup operation. The VANTAGE + fuel system design includes many of the Westinghouse VANTAGE 5 design features and incorporates additional features necessary for extended operation/fuel cycles. One of these features incorporated is the use of fully enriched axial annular fuel pellets in the blanket region of the fuel rods.
Beginning with Cycle 12, the new fuel regions incorporated Westinghouse VANTAGE 5 with P-Grid design, which incorporates a new protective grid. This design includes many of the VANTAGE + system design features and adds a P-Grid above the bottom nozzle for an additional debris barrier for the fuel assembly, and extends the fuel rod bottom plug for interface with the P-Grid.
The IFBA coated fuel pellets are identical to the enriched uranium dioxide pellets except for the addition of a thin boride coating on the pellet cylindrical surface. Coated pellets occupy the central portion of the fuel column. The number and pattern of IFBA rods within an assembly may vary depending on specific application. The ends of the non-annular pellets are dished to allow for greater axial expansion at the pellet centerline and void volume for fission gas release. An evaluation and test program for the IFBA design features is given in Section 2.5 in Reference 26. Beginning with Cycle 11, the new fuel regions incorporate assemblies whose non-IFBA rods contain fully enriched solid fuel pellets in the blanket region. To avoid overstressing of the cladding or seal welds, void volume and clearances are provided within the rods to accommodate fission gases released from the fuel, differential thermal expansion between the cladding and the fuel, and fuel density changes during burnup. Shifting of the fuel within the cladding during handling or shipping prior to core loading is prevented by a helical spring that bears on top of the fuel. All fuel rods are internally pressurized with helium during the welding process to minimize compressive cladding stresses and creep due to coolant operating pressures. Fuel rod pressurization depends on the planned fuel burnup, as well as other fuel design parameters and fuel characteristics (particularly densification potential). 4.2.1.2.2 Fuel Assembly Structure The fuel assembly structure consists of a bottom nozzle, top nozzle, guide thimbles, and grids, as shown in Figures 4.2-2 and 4.2-2a.
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-9 Revision 21 September 2013 4.2.1.2.2.1 Bottom Nozzle The bottom nozzle is a box-like structure that serves as a bottom structural element of the fuel assembly and directs the coolant flow distribution to the assembly. The square nozzle is fabricated from Type 304 stainless steel. The legs form a plenum for the inlet coolant flow. The plate prevents a downward ejection of the fuel rods. The bottom nozzle is fastened to the fuel assembly guide tubes by locked screws that penetrate through the nozzle and mate with an inside fitting in each guide thimble tube. In Region 4 assemblies, the bottom nozzle design has a reconstitution feature that permits remote unlocking, removing, and relocking of the thimble screws. Coolant flow through the fuel assembly is directed from the plenum in the bottom nozzle upward through the penetrations in the plate to the channels between the fuel rods.
The debris filter bottom nozzle (DFBN) has been introduced into the Diablo Canyon Region 6 fuel assemblies to reduce the possibility of fuel rod damage due to debris-induced fretting. The relatively large flow holes in a conventional bottom nozzle are replaced with a new pattern of smaller flow holes for the DFBN. The holes are sized to minimize passage of debris particles large enough to cause damage while providing sufficient flow area, comparable pressure drop, and continued structural integrity of the nozzle. Tests to measure pressure drop and demonstrate structural integrity have been performed to verify that the debris filter bottom nozzle is totally compatible with the current design.
The 304 stainless steel DFBN is similar to the LOPAR design used for the Diablo Canyon Region 5 fuel assemblies. Significant changes compared to the LOPAR design involve: (a) a modified flow hole size and pattern as described above; and (b) a decreased nozzle height and thinner top plate (identical to the existing VANTAGE 5 bottom nozzle described in Reference 26) to accommodate the high burnup fuel rods. The DFBN retains the design reconstitution feature, which facilitates easy removal of the nozzle from the fuel assembly in the same manner as the bottom nozzle used for the Region 5 LOPAR fuel assemblies.
The weight and axial loads (holddown) imposed on the fuel assembly are transmitted through the bottom nozzle to the lower core plate. Indexing and positioning of the fuel assembly is controlled by alignment holes in two diagonally opposite bearing plates that mate with locating pins in the lower core plate. Any lateral loads on the fuel assembly are transmitted to the lower core plate through the locating pins.
Westinghouse has developed the Standardized Debris Filter Bottom Nozzle (SDFBN) for use on its 17x17 fuel designs, including the 17x17 VANTAGE+ fuel design. The SDFBN was specifically designed to have a loss coefficient that is the same, independent of supplier. The SDFBN has eliminated the side skirt communication flow holes as a means of improving the debris mitigation performance of the bottom nozzle. This nozzle has been evaluated and meets all of the applicable mechanical design criteria. In addition, there is no adverse effect on the thermal hydraulic performance of the SDFBN either with respect to the pressure drop or with respect to DNB. The SDFBN DCPP UNITS 1 & 2 FSAR UPDATE 4.2-10 Revision 21 September 2013 was implemented at Diablo Canyon beginning with Unit 2 Region 20 (Cycle 18 feed) and Unit 1 Region 21 (Cycle 19 feed). 4.2.1.2.2.2 Top Nozzle The top nozzle assembly functions as the upper structural element of the fuel assembly in addition to providing a partial protective housing for the RCCA. It consists of an adapter plate, enclosure, top plate, and pads. The integral welded assembly has holddown springs mounted on the assembly, as shown in Figure 4.2-2. The springs are made of Inconel 718. The bolts are made of Inconel 718 or Inconel 600. The other components are made of Type 304 stainless steel.
The reconstitutable top nozzle for the VANTAGE 5 assembly differs from the LOPAR design in two ways: (a) a groove is provided in each thimble thru-hole in the nozzle plate to facilitate attachment and removal; and (b) the nozzle plate thickness is reduced to provide additional axial space for fuel rod growth.
The square adapter plate penetrations permit the flow of coolant upward through the top nozzle. Other holes accept sleeves that are welded to the adapter plate and mechanically attached to the thimble tubes. The ligaments in the plate cover the tops of the fuel rods and prevent their upward ejection from the fuel assembly. The sheet metal shroud enclosure sets the distance between the adapter and the top plates. A large square hole in the top plate permits access for the control rods and the control rod spiders. Holddown springs are mounted on the top plate and fastened by bolts and clamps located at two diagonally opposite corners. On the other two corners, integral pads contain alignment holes to locate the upper end of the fuel assembly. The Westinghouse Integral Nozzle (WIN) top nozzle design, first introduced in Unit 1 cycle 14 and Unit 2 cycle 13, is a direct replacement for the previous RTN design. The WIN design incorporates design and manufacturing improvements to eliminate the Alloy 718 spring screw for attachment of the hold-down springs. The springs are assembled into the nozzle pad and pinned in place. The WIN design provides a wedged rather than a clamped (bolted) joint for transfer of the fuel assembly hold-down forces into the top nozzle structure. The flow plate, thermal characteristics, and method of attachment of the nozzle are all unchanged from the RTN top nozzle design. 4.2.1.2.2.3 Guide and Instrument Thimbles Guide thimbles are structural members that also provide channels for the neutron absorber rods, burnable poison rods, or neutron source assemblies. Each guide thimble is fabricated from zirconium alloy tubing having two different diameters. The larger diameter at the top permits rapid insertion of the control rods during a reactor trip and accommodates coolant flow during normal operation. Four holes are provided on the thimble tube above the dashpot to reduce the rod drop time. The lower portion of the guide thimble has a reduced diameter to produce a dashpot action near the end of the control rod travel during normal operation, and to accommodate the outflow of water DCPP UNITS 1 & 2 FSAR UPDATE 4.2-11 Revision 21 September 2013 from the dashpot during a reactor trip. The dashpot is closed at the bottom by an end plug that is provided with a small flow port to avoid fluid stagnation in the dashpot volume during normal operation. The top end of the guide thimble is fastened to a tubular sleeve by three expansion swages. The sleeve fits into, and is welded to, the top nozzle adapter plate. The lower end of the guide thimble is fitted with an end plug that is then fastened into the bottom nozzle by a weld-locked screw.
The central instrumentation thimble of each fuel assembly is not attached to either the top or bottom nozzles, but is constrained by its seating in counterbores of each nozzle. Incore neutron detectors pass through the bottom nozzle's large counterbore into the center thimble.
With the exception of a reduction in the guide thimble diameter and increased length above the dashpot, the VANTAGE 5 guide thimbles are identical to those in the LOPAR design. A 0.008 inch reduction to the guide thimble OD and ID (Table 4.1-1) is required due to the thicker zirconium alloy grid straps and reduced cell size. The VANTAGE 5 thimble tube is 0.170 inches longer due to the reconstitutable top nozzle feature.
The VANTAGE 5 guide thimble tube ID provides an adequate nominal diametral clearance of 0.061 inches for the control rods. The reduced VANTAGE 5 thimble tube ID also provides sufficient diametral clearance for burnable absorber rods, source rods, and dually compatible thimble plugs. The thimble plugs used in previous cycles are not the dually compatible type and cannot be inserted into the VANTAGE 5 guide thimbles.
The VANTAGE 5 instrumentation tube also has an 0.008 inch diametral decrease compared to the LOPAR assembly instrumentation tube. This decrease still allows sufficient diametral clearance for the flux thimble (max. OD = 0.397 inch) to traverse the tube without binding.
The top Inconel grid sleeve, insert, and thimble tube of the VANTAGE 5 design are joined together using three bulge joint mechanical attachments similar to that used in the LOPAR design. This bulge joint connection was mechanically tested and found to meet all applicable design criteria.
The intermediate and IFM zirconium alloy grids employ a single bulge connection to the sleeve and thimble as compared to a double bulge connection used in the Inconel grids. Mechanical testing of this bulge joint connection was also found to be acceptable. 4.2.1.2.2.4 Grid Assemblies The fuel rods, as shown in Figure 4.2-2, are supported laterally at eight intervals along their length by grid assemblies that maintain the lateral spacing between the rods by the combination of support dimples and springs. The grid assembly consists of individual slotted straps interlocked and brazed in an "egg-crate" arrangement to join the straps permanently at their points of intersection. The straps contain spring fingers, support dimples, and mixing vanes. DCPP UNITS 1 & 2 FSAR UPDATE 4.2-12 Revision 21 September 2013 Inconel 718 and zirconium alloys were chosen as the grid materials because of corrosion resistance, neutron economy, and high strength properties. The magnitude of the grid restraining force on the fuel rod is set high enough to minimize possible fretting, without overstressing the cladding at the points of contact. The grid assemblies also allow axial thermal expansion of the fuel rods to prevent their buckling or distortion.
A second type of grid assembly, with mixing vanes projecting from the edges of the straps into the coolant stream, is used in the high heat flux region of the fuel assemblies to promote coolant mixing. The outside straps on all grids contain mixing vanes which, in addition to their mixing function, help guide the grids and fuel assemblies past projecting surfaces during fuel handling or core loading and unloading.
A third type of grid assembly, configured with the same "egg crate" support matrix and other internal structures as the normal grid, is added to the bottom of the fuel assembly to provide an additional debris barrier thereby improving fuel reliability. This protective or "P" grid is thinner (i.e., shorter) than the normal grid to accommodate the gap between the bottom nozzle and the fuel rods. It has no mixing vanes and has shorter inner straps comprising the support matrix compared to the normal grid. The P-Grid is composed of Inconel 718 material. 4.2.1.3 Design Evaluation 4.2.1.3.1 Fuel Rods The fuel rods are designed to ensure that the design bases are satisfied for Conditions I and II events. 4.2.1.3.1.1 Materials - Fuel Cladding The zirconium alloys used as fuel rod cladding have a superior combination of neutron economy (low absorption cross section), high strength (to resist deformation due to differential pressures and mechanical interaction between fuel and cladding), high corrosion resistance (to coolant, fuel, and fission products), and high reliability. Reference 8 summarizes the extensive pressurized-water reactor (PWR) operating experience with Zircaloy as a cladding material. The differences between ZIRLO and Zircaloy are stated in Reference 29.
Metallographic examination of irradiated commercial fuel rods has shown occurrences of fuel/cladding chemical interaction. Reaction layers of 1 mil in thickness have been observed between fuel and cladding at limited points around the circumference. These data give no indication of propagation of the layer and eventual cladding penetration.
Stress corrosion cracking is another postulated phenomenon related to fuel/cladding chemical interaction. Out-of-reactor tests have shown that in the presence of high cladding tensile stresses, large concentrations of iodine can chemically attack the fuel DCPP UNITS 1 & 2 FSAR UPDATE 4.2-13 Revision 21 September 2013 cladding and lead to eventual cladding cracking. Westinghouse has no evidence that this mechanism is operative in commercial fuel. 4.2.1.3.1.2 Materials - Fuel Pellets Sintered, high-density UO2 reacts only slightly with the cladding at core operating temperatures and pressures. In the event of cladding defects, the high resistance of uranium dioxide to attack by water protects against fuel deterioration, although limited fuel erosion can occur. Operating experience and extensive experimental work reveal that the thermal design parameters conservatively account for changes in the thermal performance of the fuel elements due to pellet fracture that may occur during power operation. The consequences of defects in the cladding are greatly reduced by the ability of uranium dioxide to retain fission products, including those that are gaseous or highly volatile.
Improvements in fuel fabrication techniques, based on extensive analytical and experimental work (Reference 9), have eliminated or minimized the fuel pellet densification effect that had been observed in fuel irradiated in operating Westinghouse PWRs (References 5 and 8).
Fuel densification is considered in the nuclear and thermal-hydraulic design of the reactor, as described in Sections 4.3 and 4.4, respectively.
Some fuel pellets are fabricated with a thin boride coating on the pellet outside surface for reactivity control.
4.2.1.3.1.3 Materials - Strength Considerations One of the most important limiting factors in fuel element duty is the mechanical interaction of fuel and cladding. This fuel-cladding interaction produces cyclic stresses and strains in the cladding, and these in turn consume cladding fatigue life. To reduce fuel-cladding interaction, which is a principal goal of design, and enhance the cyclic operational capability of the fuel rod, prepressurized fuel rods are used.
Prepressurized fuel rods partially offset the effect of the coolant external pressure and reduce the rate of cladding creep toward the surface of the fuel. Fuel rod prepressurization delays the time at which substantial fuel-cladding interaction and hard contact occur and, hence, significantly reduces the number and extent of cyclic stresses and strains experienced by the cladding, both before and after fuel-cladding contact. These factors increase the fatigue life margin of the cladding and lead to greater cladding reliability. If gaps should form in the fuel stacks, cladding flattening will be prevented by the rod prepressurization so that the flattening time will be greater than the fuel core life.
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-14 Revision 21 September 2013 To minimize fuel-cladding interaction during startup, following handling of irradiated fuel assemblies during a refueling, or a cold shutdown, limitations in power increase rates are instituted. 4.2.1.3.1.4 Steady State Performance Evaluation In the calculation of the steady state performance of a nuclear fuel rod, the following interacting factors must be considered:
(1) Cladding creep and elastic deflection (2) Pellet density changes, thermal expansion, gas release, and thermal properties as a function of temperature and fuel burnup (3) Internal pressure as a function of fission gas release, rod geometry, and temperature distribution These effects are evaluated using the fuel rod design model of Reference 3, modified as described in Reference 9, to account for time-dependent fuel densification. The model determines fuel rod performance characteristics for a given rod geometry, power history, and axial power shape. In particular, internal gas pressure, fuel and cladding temperatures, and cladding deflections are calculated. The fuel rod is divided lengthwise into several sections and radially into a number of annular zones. Fuel density changes, cladding stresses, strains and deformations, and fission gas releases are calculated separately for each segment. These effects are then integrated to obtain the total internal pressure. Subject to the design criteria of Section 4.2.1.1.1, the initial rod internal pressure is selected to delay fuel-cladding mechanical interaction and to avoid the potential for flattened rod formation.
The gap conductance between the pellet surface and the cladding inner diameter is calculated as a function of the composition, temperature, and pressure of the gas mixture, and the gap size or contact pressure between cladding and pellet. After computing the fuel temperature for each pellet's annular zone, the fractional fission gas release is assessed using an empirical model derived from experimental data (Reference 3). Finally, the gas released is summed over all zones and the pressure is calculated.
The code shows good agreement in fit for a variety of published and proprietary data on fission gas release, fuel temperatures, and cladding deflection (Reference 3). Included in this spectrum are variations in power, time, fuel density, and geometry.
Typical fuel cladding inner diameter and the fuel pellet outer diameter as a function of exposure are presented in Figure 4.2-4. The cycle-to-cycle changes in the pellet outer diameter represent the effects of power changes as the fuel is moved into different DCPP UNITS 1 & 2 FSAR UPDATE 4.2-15 Revision 21 September 2013 positions during refueling. The gap size at any time is given by the difference between cladding inner radius and pellet outer radius. Total cladding-pellet surface contact occurs between 600 and 800 EFPD. Figure 4.2-4 represents hot fuel dimensions for a fuel rod operating at the power level shown in Figure 4.2-5. Figure 4.2-5 also illustrates representative fuel rod internal gas pressure and linear power for the lead burnup rod versus irradiation time. In addition, it outlines the typical operating range of internal gas pressures that is applicable to the total fuel rod population within a region. The plenum height of the fuel rod is designed to ensure that the maximum internal pressure of the fuel rod remains below the value that causes the fuel-cladding diametral gap to increase due to outward cladding creep.
Cladding stresses during steady state operation are low. Compressive stresses are created by the pressure differential between the coolant pressure and the rod internal gas pressure.
Because of helium prepressurization, the volume average effective stresses are always less than the yield stress at the pressurization level used in this fuel rod design. Stresses due to the temperature gradient are not included because their contribution to the cladding volume average stress is small and decreases with time during steady state operation due to stress relaxation. The stress due to pressure differential is highest in the minimum power rod at the beginning of life (BOL) (due to low internal gas pressure), and the thermal stress is highest in the maximum power rod (due to the steep radial temperature gradient).
Tensile stresses could be created once the cladding comes in contact with the pellet. These stresses would be induced by the fuel pellet swelling during irradiation. As shown in Figure 4.2-4, there is very limited cladding pushout after pellet-cladding contact. Reactor experiments (Reference 10) have shown that Zircaloy tubing exhibits "super-plasticity" at slow strain rates during neutron irradiation. Uniform cladding strains of 10 percent have been achieved under these conditions with no sign of plastic instability.
Reference 16 presents the NRC-approved model used for evaluation of fuel rod bowing. The effects of bowing on departure from nucleate boiling ratio (DNBR) are described in Section 4.4.2.3.5. 4.2.1.3.1.5 Transient Evaluation Method A "modified CYGRO," which retains the basic design approach of the referenced CYGRO (Reference 4), was used by Westinghouse to investigate fuel rod mechanical integrity during power transients.
Comparisons between the modified CYGRO and the fuel rod design model of Section 4.2.1.3.1.4 show that in all cases conformity is satisfactory. Power escalations or spikes early in life do not lead to hard cladding-pellet interaction because the pellet merely expands into the gap. Power increases that occur after considerable gap DCPP UNITS 1 & 2 FSAR UPDATE 4.2-16 Revision 21 September 2013 closure result in hard cladding-pellet interaction. The extent of the interaction determines the cladding stress level.
Pellet thermal expansion due to power increases in a fuel rod is considered the only mechanism by which significant stresses and strains can be imposed on the cladding. Such power increases in commercial reactors can result from fuel shuffling, reactor power escalation following extended reduced power operation, and control rod movement. In the mechanical design model, depletion of lead rods is calculated using best estimate power histories as determined from core physics calculations. During the depletion, the diametral gap closure is evaluated using the pellet expansion-cracking model, cladding creep model, and fuel swelling model. At various times during the depletion, the power is increased locally on the rod to the burnup-dependent attainable power density, as determined by core physics calculation. The radial, tangential, and axial cladding stresses resulting from the power increase are combined into a volume average effective cladding stress.
The von Mises' criterion, described in Section 4.2.1.1.1, is used to determine if the cladding yield stress has been exceeded. The yield stress correlation is that for irradiated cladding, since fuel-cladding interaction occurs at high burnup. Furthermore, the effective stress is increased by an allowance that accounts for stress concentrations in the cladding adjacent to radial cracks in the pellet, prior to the comparison with the yield stress. This allowance was evaluated using a two-dimensional (r, ) finite element model.
Since slow transient power increases can result in large cladding strains without exceeding the cladding yield stress due to cladding creep and stress relaxation, a criterion on allowable cladding positive strain is necessary. Based on high strain rate burst and tensile test data for irradiated tubing, 1 percent strain was adopted as the lower limit on irradiated cladding ductility.
In addition to the mechanical design models and design criteria, Westinghouse relies on performance data accumulated from transient power test programs in experimental and commercial reactors, and normal operation in commercial reactors.
It is recognized that a possible limitation to the satisfactory behavior of the fuel rods in a reactor that is subjected to daily load follow is the failure of the cladding by low cycle strain fatigue. During their normal residence time in a reactor, the fuel rods may be subjected to 1000 cycles with typical changes in power level from 50 to 100 percent of their steady state values. Fatigue life determination of fuel rod cladding is uncertain due to strain range evaluation difficulties that result from the cyclic interaction of fuel pellets and cladding, and from such highly unpredictable phenomena as pellet cracking,
- fragmentation, and relocation. Strain fatigue tests by Westinghouse since 1968 on irradiated and nonirradiated hydrided Zircaloy-4 cladding have permitted a definition of a conservative fatigue life limit and a methodology to treat the strain fatigue evaluation.
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-17 Revision 21 September 2013 Westinghouse-accumulated experience in load follow operation, that dates back to early 1970, shows that no significant coolant activity increase can be associated with the load follow mode of operation.
The Westinghouse analytical approach to strain fatigue results from evaluating several strain-fatigue models and the results of the Westinghouse experimental programs. In conclusion, the approach defined by Langer-O'Donnell (Reference 12) was retained, and the empirical factors of their correlation were modified to conservatively bound the results of the Westinghouse testing program.
The Langer-O'Donnell empirical correlation has the following form: eSRA100100ln4fNEaS+= (4.2-1) where: Sa = 1/2 E = pseudo-stress amplitude that causes failure in Nf cycles, lb/in2 = total strain range, in./in E = Young's Modulus, lb/in2 Nf = number of cycles to failure RA = reduction in area at fracture in a uniaxial tensile test, % Se = endurance limit, lb/in2 Both RA and Se are empirical constants that depend on the type of material, the temperature, and the irradiation.
The results of the Westinghouse test programs provided information on different cladding conditions, including the effect of irradiation, hydrogen level, and temperature. The Westinghouse design equations followed the concept for the fatigue design criterion according to Section III of the ASME B&PV Code, namely:
(1) The calculated pseudo-stress amplitude (Sa) includes a safety factor of 2. (2) The allowable cycles for a given Sa are 5 percent of Nf or a safety factor of 20 on cycles.
The lesser of the two allowable numbers of cycles is selected. The cumulative fatigue life fraction is then computed as:
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-18 Revision 21 September 2013 nNfk1k1k (4.2-2) where: nk = number of diurnal cycles of mode k 4.2.1.3.2 Fuel Assembly Structure 4.2.1.3.2.1 Stresses and Deflections Stresses in the fuel rod due to thermal expansion and fuel cladding irradiation growth are limited by the relative motion of the rod as it slips over the grid spring and dimple surfaces. Clearances between the fuel rod ends and nozzles are provided so that fuel cladding irradiation growth does not produce interferences. Stresses due to hold-down springs opposing the hydraulic lift force are limited by the deflection characteristic of the springs. Stresses in the fuel assembly caused by tripping of the RCCA have little influence on fatigue because of the small number of events during the life of an assembly. Welded joints in the fuel assembly structure are considered in the structural analysis of the assembly. Appropriate material properties of welds ensure that the design bases are met. Assembly components and prototype fuel assemblies made from production parts were subjected to structural tests to verify that the design bases requirements were met.
Precautions are taken during fuel handling operations to minimize fuel assembly grid strap damage. These precautions include proper training of operators, confirmation of proper functioning and alignment of the fuel handling and transfer equipment, implementation of appropriate handling precautions, and the Westinghouse recommendations. In addition, starting with Cycle 4, the grid straps are modified to prevent assembly hangup from grid strap interference during fuel handling.
The fuel assembly design loads for shipping have been established at 6g laterally and 4g axially. Probes, permanently placed in the shipping cask, monitor and detect fuel assembly displacements that would result from loads in excess of the criteria. Experience indicates that loads which exceed the allowable limits rarely occur. Exceeding the limits requires reinspection of the fuel assembly. Tests on various fuel assembly components such as the grid assembly, sleeves, inserts, and structure joints have been performed to ensure that the shipping design limits do not result in impairment of fuel assembly function.
The evaluation of the fuel assembly for the postulated Hosgri earthquake is discussed in Section 3.7.3.15.2.
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-19 Revision 21 September 2013 Seismic analysis of the fuel assembly is presented in Reference 11 and updated in Reference 32. 4.2.1.3.2.2 Dimensional Stability A prototype LOPAR fuel assembly has been subjected to column loads in excess of those expected in normal service and faulted conditions. The VANTAGE 5 Mechanical Test Program description and results are given in Appendix A of Reference 26. With the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 30), dynamic loading conditions resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis analyses. Only the much smaller loads from RCS branch line breaks have to be considered (see Section 3.6.2.1.1.1).
The dimensional stability of coolant flow channels is maintained by the grids and guide thimbles structure. The lateral spacing between fuel rods is controlled by the support dimples of adjacent grid cells plus the spring force and the internal moments generated between the spring and the support dimples.
Tests and analyses have been performed to evaluate the effects of small cracks in the grid strap dimples. While burr cracks up to 2 mils in length are acceptable for dimples, cracks greater than 2 mils in length may exist in installed grids despite stringent inspections. Testing and analysis results indicate that dimples with cracks exceeding the acceptance criteria will survive in-pile fatigue, and crack propagation is not expected. No interference with control rod insertion into thimble tubes will occur during a postulated loss-of-coolant accident (LOCA) transient due to fuel rod swelling, thermal expansion, or bowing. In the early phase of the event, the high axial loads, which could be potentially generated by the difference in thermal expansion between fuel cladding and thimbles, are relieved by slippage of the fuel rods through the grids. The relatively low drag force restraint on the fuel rods will induce only minor thermal bowing, not enough to close the fuel rod-to-thimble tube gap. This rod-to-grid slip mechanism occurs simultaneously with control rod drop. Subsequent to the control rod insertion, the transient temperature increase of the fuel rod cladding can result in sufficient swelling to contact the thimbles. 4.2.1.3.2.3 Vibration and Wear The effect of a flow-induced vibration on the fuel assembly and individual fuel rods is minimal. Both fretting and vibration have been experimentally investigated. The cyclic stress range associated with deflections of such small magnitude is insignificant and has no effect on the structural integrity of the fuel rod.
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-20 Revision 21 September 2013 The conclusion that the effect of flow-induced vibrations on the fuel assembly and fuel rod is minimal is based on test results and analysis documented in WCAP-8279 (Reference 13), which consider conditions normally encountered in reactor operation.
The reaction on the grid support due to vibration motions is correspondingly small and much less than the spring preload. Firm contact is therefore maintained. No significant cladding or grid support wear is expected during the life of the fuel assembly, as described in Section 4.2.1.3.3.
During the mid-1970s, unexpected degradation of guide thimble tube walls was observed during examination of irradiated fuel assemblies taken from several operating pressurized water reactors. It was later determined that coolant up-flow through the guide thimble tubes and turbulent cross-flow above the fuel assemblies were responsible for inducing vibratory motion in normally fully withdrawn ("parked") control rods. When these vibrating rods were in contact with the inner surface of the thimble wall, a fretting wear of the thimble wall occurred. The extent of the observed wear is both time and nuclear steam supply system (NSSS) design-dependent and has been observed, in some non-Westinghouse cases, to extend through the guide tube walls, resulting in the formation of holes.
Guide thimble tubes function as the main structural members of the fuel assembly and as channels to guide and decelerate tripped control rods. Significant loss of mechanical integrity due to wear or hole formation could: (a) result in the inability of the guide thimble tubes to withstand their anticipated loadings for fuel handling accidents and transients, and (b) hinder RCCA trip. The susceptibility and impact of guide thimble tube wear in Westinghouse plants of the DCPP design have been assessed in References 17 through 20. Included is a mechanistic wear model and the impact of the model's wear predictions on plant designs such as for DCPP.
Accordingly, the DCPP fuel design will experience less wear than that reported for other NSSS designs because that design uses thinner, more flexible control rods that have relatively more lateral support in the guide tube assembly of the upper core structure. Such construction provides the housing and guide path for the RCCA above the core, and thus restricts control rod vibration due to lateral exit flow. The wear model is also believed to conservatively predict guide thimble tube wear and even with the worst anticipated wear conditions (both in the degree of wear and the location of wear), the guide thimble tubes will be able to fulfill their design functions.
PG&E participated in a surveillance program to obtain data related to guide tube thimble wear (References 20 and 21). Data obtained from surveillance program examinations confirmed that guide thimble tubes used in DCPP meet design requirements.
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-21 Revision 21 September 2013 4.2.1.3.3 Operational Experience The operational experience of Westinghouse cores is presented in WCAP-8183 (Reference 8), which is revised annually. 4.2.1.4 Testing and Inspection Plan 4.2.1.4.1 Quality Assurance Program The Quality Assurance Program for Westinghouse nuclear fuel is summarized in the latest edition of the Westinghouse Nuclear Fuel Division Quality Assurance Program Plan, as listed in the PG&E Qualified Suppliers List. 4.2.1.4.2 Manufacturing The Westinghouse quality control philosophy during manufacturing is described in the Westinghouse Nuclear Fuel Division Quality Assurance Program Plan, as listed in the PG&E Qualified Suppliers List. 4.2.1.4.3 Onsite Inspection Onsite inspection of fuel assemblies, control rods, and reactor internals is performed in accordance with the inspection program requirements discussed in Chapter 17.
Surveillance of fuel and reactor performance is routinely conducted on Westinghouse reactors. Power distribution is monitored using the excore fixed and incore movable detectors. Coolant activity and chemistry are followed, which permit early detection of any fuel cladding defects.
Visual examinations are routinely conducted during refueling outages. Additional fuel inspections are dependent on results of the operational monitoring and the visual examinations. Onsite examinations, if required, could include fuel integrity or other fuel performance evaluation examinations. 4.2.1.4.4 Removable Fuel Rod Assembly As part of a continuing Westinghouse fuel performance evaluation program, one surveillance fuel assembly containing 88 removable fuel rods was included in Region 3 of the initial DCPP Unit 1 core loading. The objective of this program was to facilitate interim and end of life (EOL) fuel evaluation as a function of exposure. The rods could be removed, nondestructively examined, and reinserted at the end of intermediate fuel cycles. The rods could be removed easily and subjected to a destructive examination at EOL.
The overall dimensions, rod pitch, number of rods, and material are the same as for other Region 3 assemblies. These fuel rods were fabricated in parallel with the regular DCPP UNITS 1 & 2 FSAR UPDATE 4.2-22 Revision 21 September 2013 Region 3 rods using selected Region 3 cladding and pellets fabricated to the same manufacturing tolerance limits. Mechanically, the special assemblies differ from other Region 3 assemblies only in those features that facilitate removal and reinsertion.
Figure 4.2-6 compares the mechanical design of a removable fuel rod to a standard rod. Figure 4.2-7 shows the removable rod fuel assembly, the modified upper nozzle adapter plate, and thimble plug assembly; it should be compared to the standard assembly shown in Figure 4.2-2. The location of the removable rods within the fuel assembly is shown in Figure 4.2-8. Fuel handling with removable fuel rods has been done routinely and without difficulty in many operating plants.
The same fuel rod design limits, indicated in Section 4.2.1 for standard fuel rods and assemblies, are maintained for these removable rods. Their inclusion in the initial Unit 1 core loading introduced no additional safety considerations and in no way changed the safeguard analyses and related engineering information formerly presented in support of the license application. 4.2.2 REACTOR VESSEL INTERNALS 4.2.2.1 Design Bases The design bases for the mechanical design of the reactor vessel internals components are:
(1) The reactor internals, in conjunction with the fuel assemblies, shall direct reactor coolant through the core to achieve acceptable flow distribution and to restrict bypass flow so that the heat transfer performance requirements are met for all modes of operation. In addition, required cooling for the pressure vessel head shall be provided so that the axial and circumferential temperature gradients in the vessel and head flanges do not cause excessive rotation or warpage, which could result in leakage past the O-ring closure gaskets during reactor operation. (2) In addition to neutron shielding provided by the reactor coolant, a thermal shield in Unit 1 and a neutron pad (Reference 7) assembly on Unit 2 limit the neutron exposure of the pressure vessel. (3) Provisions shall be made to install incore instrumentation for plant operation and the vessel material test specimens required for the pressure vessel irradiation surveillance program (see Section 5.2). (4) The core internals were designed to withstand mechanical loads arising from the design earthquake (DE), double design earthquake (DDE),
Hosgri earthquake, and pipe ruptures. It has been verified that the core internals maintain their integrity during a Hosgri event. With the acceptance of the DCPP leak-before-break analysis by the NRC DCPP UNITS 1 & 2 FSAR UPDATE 4.2-23 Revision 21 September 2013 (Reference 30), dynamic loading conditions resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis analyses. Only the much smaller loads from RCS branch line breaks have to be considered (see Section 3.6.2.1.1.1). The seismic design of core internals is further discussed in Section 3.7. (5) The reactor has mechanical provisions to adequately support the core and internals and to ensure that the core is intact with acceptable heat transfer geometry following transients arising from abnormal operating conditions. (6) Following the design basis accident, the plant shall be capable of being shut down and cooled in an orderly fashion so that fuel cladding temperature is kept within 10 CFR 50.46 limits. This implies that the deformation of certain critical reactor internals must be kept sufficiently small to allow core cooling. Core structure functional limitations during the design basis accident are shown in Table 4.2-1. To ensure no column loading of rod cluster control guide tubes, the upper core plate deflection is limited to the value shown in Table 4.2-1.
Details of the dynamic analyses, input forcing functions, and response loadings are presented in Section 3.9. A dynamic analysis is performed on first-of-a-kind plants, in accordance with the requirements of the ASME B&PV Code, Section III, Subsection NG. Identical plants are qualified by this same analysis. With the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 30), dynamic loading conditions resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis analyses. Only the much smaller loads from RCS branch line breaks have to be considered (see Section 3.6.2.1.1.1).
With respect to previous plants, there is no change in the design configuration of reactor internals and the reactor internals core support structures. Moreover, since their mechanical properties (e.g., fuel assembly weight, beam stiffness) are virtually the same, the response of the reactor internals core support structure will not change.
The qualification of identical plants by the first-of-a-kind analysis is further verified by the Internals Vibration Assurance Program discussed in Section 3.9.1. 4.2.2.2 Description and Drawings The components of the reactor internals consist of the lower core support structure (including the entire core barrel, the thermal shield on Unit 1, and the neutron shield pad assembly on Unit 2), the upper core support structure, and the incore instrumentation support structure. The reactor internals support the core, maintain fuel alignment, limit fuel assembly movement, maintain alignment between fuel assemblies and control rod DCPP UNITS 1 & 2 FSAR UPDATE 4.2-24 Revision 21 September 2013 drive mechanisms (CRDMs), direct coolant flow past the fuel elements, direct coolant flow to the pressure vessel head, and provide gamma and neutron shielding and guides for incore instrumentation.
The coolant flows from the vessel inlet nozzles down the annulus between the core barrel and the vessel wall and then into a plenum at the bottom of the vessel. The coolant then reverses and flows up through the core support and lower core plate. After passing through the core, the coolant enters the upper support structure and flows radially to the core barrel outlet nozzles and directly through the vessel outlet nozzles. In DCPP Unit 1, a small portion of the coolant flows downward between the baffle plates and the core barrel to provide additional cooling of the barrel. Similarly, a small amount of the entering flow is directed into the vessel head plenum and exits through the vessel outlet nozzles. For DCPP Unit 2, modifications have been performed to change the direction of flow between the baffle plates and core barrel to an upflow configuration. The modifications consist of plugging the core barrel flow holes and drilling flow holes in the top former. In a converted upflow configuration, all the flow entering the core barrel from the inlet nozzle flows downward into the lower plenum, reverses and flows upwards through the lower core plate and into the core and the baffle barrel region. Also for Unit 2, an additional modification has been made to reduce the upper head bulk fluid temperature to approximately T-cold. In this modification, reactor upper and lower internals were modified to provide additional flow in the upper head region. These two modifications have been evaluated and documented in Reference 31.
The major material for the reactor internals is Type 304 stainless steel. Parts not fabricated from Type 304 stainless steel include bolts and dowel pins, which are fabricated from Type 316 stainless steel, and the radial support clevis insert and bolts, which are fabricated of Inconel 718. Type 403 stainless steel is used for the hold-down springs in the reactor core support structures; they have a yield stress greater than 90,000 psi. These materials are compatible with the reactor coolant and are acceptable based on the 1971 ASME B&PV Code, Case Number 1337. Undue susceptibility to intergranular stress corrosion cracking is prevented by not using sensitized stainless steel, as recommended in Regulatory Guide 1.44 (Reference 23).
All reactor internals are removable, thus permitting inspection of the vessel internal surface. 4.2.2.2.1 Lower Core Support Structure The reactor internals support member is the lower core support structure shown in Figures 4.2-9 and 4.2-10 for DCPP Units 1 and 2, respectively. This support structure assembly consists of the core barrel, the core baffle, the lower core plate and support columns, the thermal shield on Unit 1, and the neutron shield pad assembly on Unit 2 (the transition from a thermal shield to neutron shield pad assembly is explained in WCAP-7870 (Reference 7)), and the core support, which is welded to the core barrel. All the major material for this structure is Type 304 stainless steel. The lower core support structure is supported at its upper flange from a ledge in the reactor vessel and DCPP UNITS 1 & 2 FSAR UPDATE 4.2-25 Revision 21 September 2013 its lower end is restrained from transverse motion by a radial support system attached to the vessel wall. Within the core barrel are an axial baffle and a lower core plate, both of which are attached to the core barrel wall and form the enclosure periphery of the core. The lower core support structure and core barrel provide passageways and direct the coolant flow. The lower core plate is positioned at the bottom level of the core below the baffle plates and provides support and orientation for the fuel assemblies.
The lower core plate contains the necessary flow distribution holes for each fuel assembly. On Unit 2, adequate coolant distribution is obtained through the use of the lower core plate and core support. Unit 1 contains an additional intermediate flow diffuser plate.
On Unit 1, the one-piece thermal shield is fixed to the core barrel at the top with rigid bolted connections. The bottom of the thermal shield is connected to the core barrel by means of axial flexures. Rectangular specimen guides in which material samples can be inserted, held by a preloaded spring device, and irradiated during reactor operation, are welded to the thermal shield. On Unit 2, the neutron shield pad assembly, shown in Figure 4.2-11, consists of four panels, constructed of Type 304 stainless steel, that are bolted and pinned to the outside of the core barrel. Rectangular specimen guides in which material surveillance samples are inserted, held by a preloaded spring device, and irradiated during reactor operation, are bolted and pinned to the panels. Additional details of the neutron shielding pads and irradiation specimen holders are given in Reference 7.
Vertically downward loads from weight, fuel assembly preload, control rod dynamic loading, hydraulic loads, and earthquake acceleration are carried by the lower core plate into the lower core plate support flange on the core barrel shell, and through the lower support columns to the core support and then through the core barrel shell to the core barrel flange supported by the vessel flange. Transverse loads from earthquake acceleration, coolant cross flow, and vibration are carried by the core barrel shell and distributed between the lower radial support to the vessel wall and to the vessel flange. Transverse loads of the fuel assemblies are transmitted to the core barrel shell by direct connection of the lower core plate to the barrel wall, and by upper core plate alignment pins that are welded into the core barrel.
The radial support system of the core barrel is accomplished by "key" and "keyway" joints to the reactor vessel wall. At six equally spaced points around the circumference, an Inconel clevis block is welded to the vessel inner diameter. An Inconel insert block is bolted to each of these clevis blocks, and has a keyway geometry. Opposite each of these is a key that is welded to the lower core support. During assembly, as the internals are lowered into the vessel, the keys engage the keyways in the axial direction.
Radial and axial expansions of the core barrel are accommodated, but this design restricts transverse movement of the core barrel. With this system, cyclic stresses in the internal structures are within the ASME B&PV Code, Section III limits. In the event DCPP UNITS 1 & 2 FSAR UPDATE 4.2-26 Revision 21 September 2013 of an abnormal downward vertical displacement of the internals following a hypothetical failure, the load is transferred through energy absorbing devices of the lower internals to the vessel. The number and design of these absorbers are determined so as to limit the stresses imposed on all components (except the energy absorber) to less than yield stress (ASME B&PV Code, Section III values).
To prevent fuel rod damage as a result of water jetting through lower internals baffle gaps in Unit 2, edge bolts have been added along the full length of the center injection baffle plate joints and the gaps have been peened after bolting. Unit 1 has edge bolts along the entire length of all corner and center injection baffle plate joints.
In addition, if baffle jetting is detected in Unit 2, anti-baffle jetting fuel clips may be used to dampen the amplitude of the fuel rod vibrations. 4.2.2.2.2 Upper Core Support Assembly The upper core support assembly, shown in Figures 4.2-12, 4.2-13, and 4.2-14, consists of the upper support assembly and the upper core plate between which are contained support columns and guide tube assemblies. The support columns establish the spacing between the upper support assembly and the upper core plate, and transmit the mechanical loadings between the upper support and upper core plate. The guide tube assemblies shield and guide the control rod drive shafts and control rods. Flow restrictors are installed in the guide tubes that formerly housed the part length CRDM drive shafts.
The upper core support assembly, which is removed as a unit during the refueling operation, is positioned in its proper orientation with respect to the lower support structure by slots in the upper core plate. Fuel assembly locating pins protrude from the bottom of the upper core plate and engage the fuel assemblies as the upper assembly is lowered into place, thus ensuring proper alignment of the lower core support structure, the upper core support assembly, the fuel assemblies, and control rods. The upper core support assembly is restrained from any axial movements by a large circumferential spring that rests between the upper barrel flange and the upper core support assembly. The spring is compressed when the reactor vessel head is installed on the pressure vessel.
Vertical loads from weight, earthquake acceleration, hydraulic loads, and fuel assembly preload are transmitted through the upper core plate, via the support columns, to the upper support assembly and then into the reactor vessel head. Transverse loads from coolant cross flow, earthquake acceleration, and possible vibrations are distributed by the support columns to the upper support and upper core plate. The upper support plate is particularly stiff to minimize deflection. DCPP UNITS 1 & 2 FSAR UPDATE 4.2-27 Revision 21 September 2013 4.2.2.2.3 Incore Instrumentation Support Structures The incore instrumentation support structures consist of an upper system to convey and support thermocouples penetrating the vessel through the head, and a lower system to convey and support flux thimbles penetrating the vessel through the bottom (Figure 7.7-9 shows the basic flux-mapping system).
The upper system utilizes the reactor vessel head penetrations. Instrumentation port columns are slip-connected to in-line columns that are, in turn, fastened to the upper support plate. These port columns protrude through the head penetrations. The thermocouple conduits, made of Type 304 stainless steel, are supported from the columns of the upper core support system.
In addition to the upper incore instrumentation, there are reactor vessel bottom port columns that carry the retractable, cold-worked stainless steel flux thimbles that are pushed upward into the reactor core. Conduits extend from the bottom of the reactor vessel down through the concrete shield area and up to a thimble seal table. The thimbles are closed at the leading ends and serve as the pressure barrier between the reactor pressurized water and the containment atmosphere. Mechanical seals between the retractable thimbles and conduits are provided at the seal table. During normal operation, the retractable thimbles are stationary and move only during refueling or for maintenance, at which time a space of approximately 15 feet above the seal table is cleared for the retraction operation.
The incore instrumentation support structure is designed for adequate support of instrumentation during reactor operation and is sturdy enough to resist damage or distortion under the conditions imposed by handling during the refueling sequence. Reactor vessel surveillance specimen capsules are covered in Section 5.2.4. 4.2.2.3 Design Loading Conditions The design loading conditions for the reactor internals are:
(1) Fuel assembly weight (2) Fuel assembly spring forces (3) Internals weight (4) Control rod scram (equivalent static load) (5) Differential pressure (6) Spring preloads (7) Coolant flow forces (static)
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-28 Revision 21 September 2013 (8) Temperature gradients (9) Differences in thermal expansion (a) Due to temperature differences (b) Due to expansion of different materials (10) Interference between components (11) Vibration (mechanically or hydraulically induced) (12) One or more loops out of service (13) All operational transients listed in Table 5.2-4 (14) Pump overspeed (15) Seismic loads (DE, DDE and Hosgri) (16) Blowdown forces (due to RCS branch line breaks) Combined seismic and blowdown forces are included in the stress analysis by assuming the maximum amplitude of each force to act concurrently. In the original analyses, the blowdown forces were those resulting from breaks in the RCS cold and hot legs. However, with the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 30), the blowdown forces resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis analyses. Only the much smaller loads from RCS branch line breaks have to be considered (see Section 3.6.2.1.1.1).
The main objectives of the design analysis are to ensure that allowable stress limits are not exceeded, that an adequate design margin exists, and to establish deformation limits that are concerned primarily with components' operability. The stress limits are established not only to ensure that peak stresses do not reach unacceptable values, but also to limit the amplitude of the oscillatory stress component in consideration of material fatigue characteristics. Both low and high cycle fatigue stresses are considered when the allowable amplitude of oscillation is established. Dynamic analysis on the reactor internals is provided in Section 3.9.
As part of the evaluation of design loading conditions, extensive testing and inspections are performed from the initial selection of raw materials up to and including component installation and plant operation. Among these tests and inspections are those performed during component fabrication, plant construction, startup and checkout, and plant operation.
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-29 Revision 21 September 2013 4.2.2.4 Design Loading Categories The combination of design loadings fits into either the normal, upset, or faulted conditions as defined in the Summer 1968 Addenda to the ASME B&PV Code, Section III.
Loads and deflections imposed on components due to shock and vibration are determined analytically and experimentally in both scaled models and operating reactors. The cyclic stresses due to these dynamic loads and deflections are combined with the stresses imposed by loads from component weights, hydraulic forces, and thermal gradients for the determination of the total stresses of the internals.
The reactor internals are designed to withstand stresses originating from various operating conditions, as summarized in Table 5.2-4.
The scope and methodology of the stress analysis problem is discussed in Section 3.9. 4.2.2.4.1 Allowable Deflections For normal operating conditions, downward vertical deflection of the lower core support plate is negligible.
Limiting deflection values from the LOCA plus the earthquake (larger of the DDE or Hosgri), and for the deflection criteria of critical internal structures, are given in Table 4.2-1. The corresponding no-loss-of-function limits are also included in Table 4.2-1 for comparison with the allowed criteria. Note, however, that with the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 30), the LOCA loads resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis analyses. Only the much smaller LOCA loads from RCS branch line breaks have to be considered (see Section 3.6.2.1.1.1).
The criteria for the core drop accident are based on determining the total downward displacement of the internal structures following a hypothesized core drop resulting from loss of supports. The initial clearance between the secondary core support structures and the reactor vessel lower head in the hot condition is approximately 1/2 inch. An additional displacement of approximately 3/4 inch would occur due to strain of the energy absorbing devices of the secondary core support; thus the total drop distance is about 1-1/4 inches, which is insufficient to permit the grips of the RCCA to come out of the guide thimble.
Specifically, the secondary core support is a device that will never be used, except during a hypothetical accident of the core support (core barrel, barrel flange, etc.). There are four supports in each reactor. This device limits the fall of the core and absorbs the energy of the fall that otherwise would be imparted to the vessel. The energy of the fall is calculated assuming a complete and instantaneous failure of the DCPP UNITS 1 & 2 FSAR UPDATE 4.2-30 Revision 21 September 2013 primary core support and is absorbed during the plastic deformation of the controlled stainless steel volume loaded in tension. The maximum deformation of this austenitic stainless piece is limited to approximately 15 percent, after which a positive step is provided to ensure support. 4.2.2.5 Design Criteria Bases For normal operating conditions, Section III of the ASME B&PV Code is used as a basis for evaluating acceptability of calculated stresses. Both static and dynamic stress intensities are considered. Bolt material Type 316 stainless steel is covered in ASME B&PV Code, Section III, under Case Number 1618. It should be noted that the allowable stresses in Section III of the ASME B&PV Code are based on unirradiated material properties. Since irradiation increases the strength of the Type 304 stainless steel used for the internals, although decreasing its elongation, the allowable stresses in Section III are considered appropriate and conservative for irradiated internal structures.
The allowable stress limits used for analysis of the design basis accident for core support structures are based on the January 1971 draft of the ASME B&PV Code, Section III, Subsection NG, and the criteria for faulted conditions. 4.2.3 REACTIVITY CONTROL SYSTEM 4.2.3.1 Design Bases Bases for temperature, stress on structural members, and material compatibility are imposed on the design of the reactivity control components. 4.2.3.1.1 Design Stresses The reactivity control system is designed to withstand stresses originating from the operating transients summarized in Table 5.2-4.
Allowable stresses for normal operating conditions are in accordance with Section III of the ASME B&PV Code. All components are analyzed as Class I components under Article NB-3000.
The cyclic stresses due to dynamic loads and deflections are combined with the stresses imposed by loads from component weights, hydraulic forces, and thermal gradients to determine the total stresses of the reactivity control system. 4.2.3.1.2 Material Compatibility Materials are selected for compatibility in a pressurized water reactor environment, adequate mechanical properties at room and operating temperature, resistance to adverse property changes in a radioactive environment, and compatibility with interfacing components. DCPP UNITS 1 & 2 FSAR UPDATE 4.2-31 Revision 21 September 2013 4.2.3.1.3 Reactivity Control Components The reactivity control components are subdivided into two categories:
(1) Permanent devices used to control or monitor the core (2) Optional burnable absorber assemblies The permanent type components are the RCCAs, control rod drive assemblies, and neutron source assemblies, and thimble plug assemblies. Although the latter is presented as a reactivity control system component in this document, it is done only because it is needed to restrict bypass flow through those thimbles not occupied by absorber, source, or burnable poison rods.
The purpose of the optional burnable absorber assemblies is to control assembly power and ensure that the temperature coefficient of reactivity is less positive under normal operating conditions.
The design bases for each of the components mentioned are presented below. 4.2.3.1.3.1 Absorber Rods The following design conditions, based on Article NB-3000 of the ASME B&PV Code, Section III, are considered.
(1) The external pressure equal to the RCS operating pressure (2) The wear allowance equivalent to 1000 reactor trips (3) Bending of the rod due to a misalignment in the guide tube (4) Forces imposed on the rods during rod drop (5) Loads caused by accelerations imposed by the CRDM (6) Radiation exposure for maximum core life.
The absorber material temperature shall not exceed its melting temperature (1470°F for silver-indium-cadmium absorber material (Reference 2)).
The Westinghouse control rod that is cold-rolled Type 304 stainless steel is the only noncode material used in the control assembly. The stress intensity limit Sm for this material is defined as two-thirds of the 0.2 percent offset yield stress. The Framatome control rod noncode material stress intensity limit Sm is also two-thirds of the 0.2 percent offset yield stress.
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-32 Revision 21 September 2013 4.2.3.1.3.2 Burnable Absorber Rods The burnable absorber rod cladding (304SS for the borosilicate design and Zircaloy-4 for the wet annular burnable absorber (WABA) design) is designed as a Class I component under Article NB-3000 of the ASME B&PV Code, Section III, 1973, for Conditions I and II. For Conditions III and IV loads, code stresses are not considered limiting. Failures of the burnable absorber rods during these conditions must not interfere with reactor shutdown or emergency cooling of the fuel rods.
The structural elements of the burnable absorber rod are designed to maintain absorber geometry even if the borosilicate glass is fractured. The rods are designed so that the borosilicate absorber material is below its softening temperature (1492°F(a) for reference 12.5 weight percent boron rods), and the Al2O3-B4C material is below 1200°F during normal operation or overpower transients. 4.2.3.1.3.3 Neutron Source Rods The neutron source rods are designed to withstand:
(1) An external pressure equal to the RCS operating pressure (2) An internal pressure equal to the pressure generated by gases released over the neutron source rod life. 4.2.3.1.3.4 Thimble Plug Assembly The thimble plug assemblies: (1) Accommodate the differential thermal expansion between fuel assembly and core internals (2) Maintain positive contact with the fuel assembly and the core internals (3) Can be inserted into, or withdrawn from, the fuel assembly by a force not exceeding 65 pounds. 4.2.3.1.4 Control Rod Drive Mechanisms The CRDMs are Code Class I components designed to meet the stress requirements for normal operating conditions of Section III of the ASME B&PV Code. Both static and dynamic stress intensities are considered. The stresses originating from the required design transients are included in the analysis.
(a) Borosilicate glass is accepted for use in burnable absorber rods if the softening temperature is greater than 1510°F (+/-18°F). The softening temperature is defined in ASTM Standard C 338.
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-33 Revision 21 September 2013 A dynamic seismic analysis is performed on the CRDM to confirm its ability to trip under a postulated seismic disturbance while maintaining resulting stresses under ASME B&PV Code, Section III allowable values. 4.2.3.1.4.1 Control Rod Drive Mechanism Design Requirements The CRDMs were designed to meet the following basic operational requirements:
(1) 5/8-inch step (2) 150-inch travel (nominal) (3) 360 pounds-force maximum load (4) Step in or out at 45 inches per minute (72 steps per minute) maximum (5) Power interruption shall initiate release of drive rod assembly (6) Trip delay of 150 milliseconds or less - Free fall of drive rod assembly shall begin less than 150 milliseconds after power interruption, no matter what holding or stepping action is being executed, with any load and coolant temperatures between 100 and 550°F. (7) 40-year design life with normal refurbishment (8) 28,000 complete travel excursions equaling 13 million steps with normal refurbishment 4.2.3.2 Description and Drawings Reactivity control is provided by neutron absorbing rods and a soluble chemical neutron absorber (boric acid). The boric acid concentration is varied to control long-term reactivity changes such as: (1) Fuel depletion and fission product buildup (2) Cold to hot, zero power reactivity change (3) Reactivity change produced by intermediate-term fission products such as xenon and samarium (4) Burnable poison depletion The concentration of boric acid in the reactor coolant is regulated by the chemical and volume control system (CVCS), as described in Section 9.3.4.
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-34 Revision 21 September 2013 The RCCAs provide reactivity control for: (1) Shutdown (2) Reactivity changes due to coolant temperature changes in the power range (3) Reactivity changes associated with the power coefficient of reactivity (4) Reactivity changes due to void formation The neutron source assemblies provide a means of verifying that the neutron instrumentation performs its function during periods of low neutron activity. They also provide the required count rate during startup.
The most effective reactivity control component is the RCCA and its corresponding drive rod assemblies. Figure 4.2-15 identifies the rod cluster control and drive rod assembly, in addition to the interfacing fuel assembly, guide tubes, and CRDM. Guidance for the control rod cluster is provided by the guide tube, as shown in Figure 4.2-15. The guide tube provides two regimes of guidance:
(1) In the lower section, a continuous guidance system provides support immediately above the core. This system protects the rod against excessive deformation and wear due to hydraulic loading. (2) The region above the continuous section provides support and guidance at uniformly spaced intervals.
The support envelope is determined by the RCCA pattern, as shown in Figure 4.2-16. The guide tube ensures alignment and support of the control rods, spider body, and drive rod while maintaining trip times at or below required limits. 4.2.3.2.1 Reactivity Control Components 4.2.3.2.1.1 Rod Cluster Control Assembly The RCCAs are divided into two categories: control and shutdown. Two criteria have been employed for selection of the control groups. First, the total reactivity worth must be adequate to meet the nuclear requirements. Second, because some of these rods may be partially inserted at power operation, the total power peaking factor should be low enough to ensure that the power capability is met. The control and shutdown groups provide adequate shutdown margin (SDM) which is defined as: the instantaneous amount of reactivity by which the reactor is subcritical, or would be subcritical from its present condition, assuming all rod cluster assemblies (shutdown and control) are fully inserted, except for the single rod cluster assembly of highest reactivity worth that is assumed to be fully withdrawn. DCPP UNITS 1 & 2 FSAR UPDATE 4.2-35 Revision 21 September 2013 An RCCA comprises a group of individual neutron absorber rods fastened at the top end to a common spider assembly, as illustrated in Figure 4.2-16.
The absorber material used in the control rods is a silver-indium-cadmium alloy that is essentially "black" to thermal neutrons and has sufficient additional resonance absorption to significantly increase its worth. The alloy is in the form of extruded rods that are sealed in stainless steel tubes to prevent the rods from coming in direct contact with the coolant. The silver-indium-cadmium rods are inserted into cold-worked stainless steel tubing. It is sealed at the bottom and top by welded end plugs, as shown in Figure 4.2-17. Sufficient diametral and end clearance is provided to accommodate relative thermal expansions.
The bullet-nosed bottom plugs reduce the hydraulic drag during reactor trip and guide the absorber rods smoothly into the dashpot section of the fuel assembly guide thimbles. The upper plug is threaded for assembly to the spider and has a reduced end section to make the joint more flexible.
The spider assembly is in the form of a central hub with radial vanes containing cylindrical fingers from which the absorber rods are suspended. Handling detents and detents for connection to the drive rod assembly are machined into the upper end of the hub. A coil spring inside the spider body absorbs the impact energy at the end of a trip insertion. All components of the spider assembly are made from Types 304 and 308 stainless steel, except for the retainer, which is made of 17-4 PH stainless steel material, and the springs, which are made of Inconel 718 alloy or, for the Westinghouse RCCA spider only, an oil-tempered carbon steel where the springs do not contact the coolant. Other Framatome spider assembly components not made from 304 or 308 stainless steel are the spider itself, cast from Type 316L stainless steel, the cladding which is tempered and cold worked Type 316 stainless steel and the rod spring spacer which is Inconel 750. The absorber rods are fastened securely to the spider to ensure trouble-free service.
The overall length is such that when the assembly is withdrawn through its full travel, the tips of the absorber rods remain engaged in the guide thimbles so that alignment between rods and thimbles is always maintained. Because the rods are long and slender, they are relatively free to conform to any small misalignments with the guide thimble. 4.2.3.2.1.2 Burnable Absorber Assembly Each burnable absorber assembly consists of borosilicate or WABA burnable absorber rods attached to a hold down assembly. Conceptual burnable absorber assemblies (containing borosilicate absorber) are shown in Figure 4.2-18. WABA rods may be used in place of the borosilicate absorber rods.
The borosilicate absorber rods consist of borosilicate glass tubes contained within Type 304 stainless steel tubular cladding, which is plugged and seal welded at the ends DCPP UNITS 1 & 2 FSAR UPDATE 4.2-36 Revision 21 September 2013 to encapsulate the glass. The glass is also supported along the length of its inside diameter by a thin wall tubular inner liner. The top end of the liner is open to permit the diffused helium to pass into the void volume and the liner overhangs the glass. The liner has an outward flange at the bottom end to maintain the position of the liner with the glass. A typical borosilicate burnable absorber rod is shown in longitudinal and transverse cross-sections in Figure 4.2-19.
A WABA rod (Figure 4.2-18a) consists of annular pellets of alumina-boron carbide (Al2O3-B4C) burnable absorber material contained within two concentric Zircaloy tubes. These Zircaloy tubes, which form the inner and outer cladding for the WABA rod, are plugged and welded at each end to encapsulate the annular stack of absorber material. The assembled rod is then internally pressurized to 650 psig and seal welded. The absorber stack lengths are positioned axially within the WABA rods by the use of Zircaloy bottom-end spacers. An annular plenum is provided within the rod to accommodate the helium gas released from absorber material depletion during irradiation. The reactor coolant flows inside the inner tube and outside the outer tube of the annular rod. Further design details are given in Section 3.0 of Reference 28. The burnable absorber rods are statically suspended and positioned in selected guide thimbles within the fuel assemblies. The absorber rods in each assembly are attached together at the top end of the rods to a hold down assembly by a flat, perforated retaining plate which fits within the fuel assembly top nozzle and rests on the adapter plate. The absorber rod assembly is held down and restrained against vertical motion through a spring pack which is attached to the plate and is compressed by the upper core plate when the reactor upper internals assembly is lowered into the reactor. This arrangement ensures that the absorber rods cannot be ejected from the core by flow forces. Each rod is permanently attached to the base plate by a nut, which is locked into place. The borosilicated rod cladding is slightly cold worked Type 304 stainless steel, and the WABA rod cladding is Zircaloy-4. All other structural materials are Types 304 or 308 stainless steel except for the springs which are Inconel-718. The borosilicate glass tube provides sufficient boron content to meet the criteria discussed in Section 4.3.1. 4.2.3.2.1.3 Neutron Source Assembly The neutron source assembly provides a base neutron level to ensure that the detectors are operational and responding to core multiplication neutrons. Because there is very little neutron activity during core loading, refueling, hot and cold shutdown, and approach to criticality, neutron sources are placed in the reactor to help determine if source range detectors are properly responding.
During core loading, it is verified that active source assemblies provide the responding source range detectors with a sufficient count rate. For normal source range detectors (N-31 and N-32), and for alternate source range detectors (N-51 and N-52), the following count rate requirements must be met after an installed active source is neutronically coupled to a detector: DCPP UNITS 1 & 2 FSAR UPDATE 4.2-37 Revision 21 September 2013 (1) For N-31 and N-32: Count Rate Maximum (2B, B+0.5, 1.0) counts per second (2) For N-51 and N-52: Count Rate Maximum (2B, B+0.05, 0.1) counts per second Where: B = background count without fuel or sources in counts in per second The differences in required count rates are due to differences in detector sensitivity between the proportional counters (N-31 and N-32) and the fission chambers (N-51 and N-52).
The source assembly also permits detection of changes in the core multiplication factor during core loading, refueling, and approach to criticality. This can be done since the multiplication factor is related to an inverse function of the detector count rate. Therefore, a change in the multiplication factor can be detected during addition of fuel assemblies while loading the core, a change in control rod positions, and changes in boron concentration.
The primary source rod, containing californium-252, spontaneously fissions and emits neutrons. After the primary source rod decays beyond the desired neutron flux level, neutrons are then supplied by the secondary source rod. The secondary source rod contains a mixture of approximately half antimony and half beryllium by volume, which is activated by neutron bombardment during reactor operation. Activation of antimony results in the subsequent release of neutrons by the (,n) reaction in beryllium. This becomes a source of neutrons during periods of low neutron flux, such as during refueling and subsequent startups. The DCPP Units 1 and 2 reactor cores each employ two primary source assemblies and two secondary source assemblies in the first core. Each primary source assembly contains one primary source rod and between zero and twenty-three burnable absorber rods. Each secondary source assembly contains a symmetrical grouping of four secondary source rods and between zero and twenty burnable absorber rods. Source assemblies are shown in Figures 4.2-20 and 4.2-21.
Each of the two new secondary sources installed in Unit 2 starting with Cycle 10 and in Unit 1 starting with Cycle 11, have six secondary source rods and no burnable poison rods. See Figure 4.2-21A. Neutron source assemblies are located at diametrically opposite sides of the core. The assemblies are inserted into the guide thimbles at selected unrodded locations.
The primary and secondary source rods both utilize slightly cold worked 304 SS material. The secondary source rods contain about 500 grams of stacked antimony-beryllium pellets, and the rod is internally prepressurized to 650 psig. The DCPP UNITS 1 & 2 FSAR UPDATE 4.2-38 Revision 21 September 2013 primary source rods contain capsules of Californium source material and alumina spacer rods to position the source material within the cladding. The rods in each assembly are permanently fastened at the top end to a hold down assembly, which is identical to that of the burnable absorber assemblies.
The other structural members are fabricated from Type 304 and 308 stainless steel except for the springs exposed to the reactor coolant. They are wound from an age hardened nickel base alloy for corrosion resistance and high strength. 4.2.3.2.1.4 Thimble Plug Assembly Thimble plug assemblies are utilized, if desired, to further limit bypass flow through the guide thimbles in fuel assemblies that do not contain either control rods, source rods, or burnable absorber rods.
The thimble plug assemblies shown in Figure 4.2-22 consist of a flat base plate with short rods suspended from the bottom surface and a spring pack assembly. The 24 short rods, called thimble plugs, project into the upper ends of the guide thimbles to reduce the bypass flow area. Similar short rods may be also used on the source assemblies and burnable absorber assemblies to plug the ends of all vacant fuel assembly guide thimbles.
All components in the thimble plug assembly, except for the springs, are fabricated from Type 304 stainless steel. The springs are wound from an age-hardened nickel base alloy for corrosion resistance and high strength.
4.2.3.2.2 Control Rod Drive Mechanism All parts exposed to reactor coolant are made of metals that resist the corrosive action of the water. Three types of metals are used exclusively: stainless steels, nickel alloy, and cobalt-based alloys. Wherever magnetic flux is carried by parts exposed to the main coolant, 400 series stainless steel is used. Cobalt-based alloys are used for the pins and latch tips. Nickel alloy is used for the springs of both latch assemblies, and Type 304 stainless steel for all pressure-containing parts. Hard chrome plating provides wear surfaces on the sliding parts and prevents galling between mating parts.
A position indicator assembly slides over the CRDM rod travel housing. This position indicator assembly detects the drive rod assembly position by means of 42 discrete coils that magnetically sense the entry and presence of the rod drive line through its centerline over the normal length of the drive rod travel.
The CRDMs are located on the head of the reactor vessel. They are coupled to RCCAs. An actual CRDM is shown in Figure 4.2-23, and a schematic in Figure 4.2-24.
The primary function of the CRDM is to insert or withdraw RCCAs into or from the core to control average core temperature and to shut down the reactor. The CRDM is a DCPP UNITS 1 & 2 FSAR UPDATE 4.2-39 Revision 21 September 2013 magnetically operated jack. A magnetic jack is an arrangement of three electromagnets that are energized in a controlled sequence by a power cycler to insert or withdraw the RCCAs of the reactor core in discrete steps. The CRDM consists of the pressure vessel, coil stack assembly, the latch assembly, and the drive rod assembly:
(1) The pressure vessel includes a latch housing and a rod travel housing that are connected by a threaded, seal-welded maintenance joint. The latch housing is the lower portion of the vessel and contains the latch assembly. The rod travel housing is the upper portion of the vessel and provides space for the drive rod during its upward movement as the control rods are withdrawn from the core. (2) The coil stack assembly includes the coil housings, an electrical conduit and connector, and three operating coils: (a) the stationary gripper coil, (b) the movable gripper coil, and (c) the lift coil. Energizing the operation coils causes movement of the pole pieces and latches in the latch assembly. (3) The latch assembly includes the guide tube, stationary pole pieces, movable pole pieces, and two sets of latches: (a) the movable gripper latch, and (b) the stationary gripper latch. The latches engage grooves in the drive rod assembly. The movable gripper latches are moved up or down in 5/8-inch steps by the lift pole to raise or lower the drive rod. The stationary gripper latches hold the drive rod assembly while the movable gripper latches are repositioned for the next 5/8-inch step. (4) The drive rod assembly includes a flexible coupling, a drive rod, a disconnect button, a disconnect rod, and a locking button. The drive rod has 5/8-inch grooves that receive the latches during holding or moving of the drive rod.
The disconnect button, disconnect rod, and locking button provide positive locking of the coupling to the RCCA and permit remote disconnection. The CRDM has a trip design. Tripping can occur during any part of the power cycler sequencing if power to the coils is interrupted.
The CRDM is threaded and seal-welded on an adapter on top of the reactor vessel, and is coupled to the RCCA directly below. DCPP UNITS 1 & 2 FSAR UPDATE 4.2-40 Revision 21 September 2013 The mechanism can handle a 360-pound load, including the drive rod weight, at a rate of 45 inches per minute. Withdrawal of the RCCA is accomplished by magnetic forces while insertion is by gravity.
The mechanism internals are designed to operate in 650°F reactor coolant. The three operating coils are designed to operate at 392°F with forced air cooling required to maintain that temperature.
The CRDM, shown schematically in Figure 4.2-24, withdraws and inserts its control rod as electrical pulses are received by the operator coils. Position of the control rod is measured by 42 discrete coils mounted on the position indicator assembly surrounding the rod travel housing. Each coil magnetically senses the entry and presence of the top of the ferromagnetic drive rod assembly as it moves through the coil centerline.
During plant operation, the stationary gripper coil of the drive mechanism holds the control rod withdrawn from the core in a static position until the movable gripper coil is energized.
If power to the stationary gripper coil is cut off, the combined weight of the drive rod assembly and the RCCA is sufficient to move latches out of the drive rod assembly groove. The control rod falls by gravity into the core. The trip occurs as the magnetic field, holding the stationary gripper plunger half against the stationary gripper pole, collapses, and the stationary gripper plunger half is forced down by the weight acting upon the latches. After the drive rod assembly is released by the mechanism, it falls freely until the control rods enter the buffer section of their thimble tubes.
4.2.3.3 System Evaluation 4.2.3.3.1 Reactivity Control Components The components are analyzed for loads corresponding to normal, upset, emergency, and faulted conditions. The analysis performed depends on the mode of operation under consideration.
The scope of the analysis requires many different techniques and methods, both static and dynamic.
Some of the loads that are considered on each component, where applicable, are:
(1) Control rod scram (equivalent static load) (2) Differential pressure (3) Spring preloads (4) Coolant flow forces (static)
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-41 Revision 21 September 2013 (5) Temperature gradients (6) Differences in thermal expansion (a) Due to temperature differences (b) Due to expansion of different materials (7) Interference between components (8) Vibration (mechanically or hydraulically induced) (9) All operational transients listed in Table 5.2-4 (10) Pump overspeed (11) Seismic loads (DE, DDE and Hosgri earthquake) The main objective of the analysis is to ensure that allowable stress limits are not exceeded, that an adequate design margin exists, and to establish deformation limits that are concerned primarily with the components' functioning. The stress limits are established not only to ensure that peak stresses will not reach unacceptable values, but also to limit the amplitude of the oscillatory stress component in consideration of fatigue characteristics of the materials. Standard methods of strength of materials are used to establish the stresses and deflections of these components. The dynamic behavior of the reactivity control components has been studied using experimental test data and experience from operating reactors. The design of reactivity component rods provides sufficient cold void volume within the burnable absorber and source rods to limit internal pressures to a value that satisfies the criteria in Section 4.2.3.1. The void volume for the helium in the borosilicate glass burnable absorber rods is obtained through the use of glass in tubular form that provides a central void along the length of the rods. For the WABA rods, an annular void volume is provided between the two tubes at the top and along the length of each WABA rod (Figure 4.2-18a). Helium gas is not released by the neutron absorber rod material; thus the absorber rod is only exposed to an external pressure during operating conditions. The internal pressure of source rods continues to increase from ambient until EOL; the internal pressure never exceeds that allowed by the criteria in Section 4.2.3.1. Except for the WABA rods, the stress analysis of reactivity component rods assumes 100 percent gas release to the rod void volume, considers the initial pressure within the rod, and assumes that the pressure external to the component rod is zero. The stress analysis for the WABA rods assumed a maximum 30 percent gas release, consistent with Reference 28.
Based on available data on borosilicate glass properties, and on nuclear and thermal calculations for these burnable absorber rods, gross swelling or cracking of the glass DCPP UNITS 1 & 2 FSAR UPDATE 4.2-42 Revision 21 September 2013 tubing is not expected during operation. Some minor creep of the glass at the hot spot on the inner surface of the tube could occur, but would continue only until the glass came in contact with the inner liner. The wall thickness of the inner liner is sized to provide adequate support in the event of slumping and to collapse locally before rupture of the exterior cladding, should unexpected large volume changes due to swelling or cracking occur. The top of the inner liner is open to allow communication to the central void by the helium, which diffuses out of the glass.
An evaluation of the WABA rod design is given in Reference 28.
No bending or warping is induced in the rods, although the clearance offered by the guide thimble would permit a postulated warpage to occur without restraint on the rods.
The radial and axial temperature profiles have been determined by considering gap conductance, thermal expansion, and neutron and/or gamma heating of the contained material as well as gamma heating of the cladding. The maximum neutron absorber material temperature was found to be less than 850°F, which occurs axially at only the highest flux region. The maximum borosilicate glass temperature was calculated to be about 1200°F, and occurs after the initial rise to power. The glass temperature then decreases rapidly for the following reasons: (a) reduction in power generation due to B10 depletion, (b) better gap conductance as the helium produced diffuses to the gap, and (c) external gap reduction due to borosilicate glass creep. Rod, guide thimble, and dashpot flow analysis indicates that the flow is sufficient to prevent coolant boiling and maintain cladding temperatures at a value at which the cladding material has adequate strength to resist coolant operating pressures and rod internal pressures. Analysis of the RCCA spider indicates it is structurally adequate to withstand the various operating loads, including the higher loads that occur during the drive mechanism stepping action and rod drop. Verification of the spider structural capability has been experimentally demonstrated.
The material was selected on the basis of resistance to irradiation damage and compatibility with the reactor environment. No apparent degradation of construction material has occurred in operating plants with the DCPP reactivity control design.
Regarding material behavior in a radioactive environment, it should be noted that at high fluences, the austenitic material increases in strength with a corresponding decreased ductility (as measured by tensile tests) but energy absorption (as measured by impact tests) remains quite high. Corrosion of the material exposed to the coolant is quite low, and proper control of Cl- and O2 in the coolant prevents stress corrosion. All of the austenitic stainless steel base material used is processed and fabricated to preclude sensitization.
Analysis of the RCCA shows that if the drive mechanism housing ruptures, the RCCA will be ejected from the core by the pressure differential of the operating pressure and ambient pressure across the drive rod assembly. The ejection is also predicated on the DCPP UNITS 1 & 2 FSAR UPDATE 4.2-43 Revision 21 September 2013 failure of the drive mechanism to retain the drive rod/RCCA position. It should be pointed out that a drive mechanism housing rupture causes the ejection of only one RCCA with the other assemblies remaining in the core. For the Westinghouse RCCA only, analysis also showed that a pressure drop in excess of 4000 psi must occur across a two-fingered vane to break the vane/spider body joint, causing ejection of two neutron absorber rods from the core. Since the highest normal pressure of the primary system coolant is only 2250 psi, with the safety valves set to lift at 2485 psig, a pressure drop in excess of 4000 psi is not expected. Thus, ejection of the neutron absorber rods is not possible.
Ejection of a burnable absorber or thimble plug assembly is conceivable if one postulates that the hold-down bar fails and that the base plate and burnable absorber rods are severely deformed. In the unlikely event of hold-down bar failure, the upward displacement of the burnable absorber assembly only permits the base plate to contact the upper core plate. Since this displacement is small, the major portion of the absorber material remains positioned within the core. In the case of the thimble plug assembly, the thimble plugs will partially remain in the fuel assembly guide thimbles, thus maintaining a majority of the desired flow impedance. Further displacement or complete ejection would necessitate that the square base plate and burnable absorber rods be forced, thus plastically deformed, to fit up through a smaller diameter hole. As expected, this condition requires a substantially higher force or pressure drop than that of the hold-down bar failure.
Experience with control rods, burnable absorber rods, and source rods is discussed in Reference 8. The mechanical design of the reactivity control components provides for the protection of the active elements to prevent the loss of control capability and functional failure of critical components. The components have been reviewed for potential failure and consequences of a functional failure of critical parts. The results of the review are summarized below. 4.2.3.3.1.1 Rod Cluster Control Assembly (1) The basic absorbing material is sealed from contact with the primary coolant and the fuel assembly and guidance surfaces by a high quality stainless steel cladding. Potential loss of absorber mass or reduction in reactivity control material due to mechanical or chemical erosion or wear is therefore reliably minimized. (2) A breach of the cladding for any postulated reason does not result in serious consequences. The silver-indium-cadmium absorber material is relatively inert and would still remain remote from high coolant velocity regions. Rapid loss of material resulting in significant loss of reactivity control material would not occur. DCPP UNITS 1 & 2 FSAR UPDATE 4.2-44 Revision 21 September 2013 (3) The individually clad absorber rods are doubly secured to the retaining spider vane by a threaded joint and a welded lock pin. A failure of the joint would result in the insertion of the individual rod into the core. This results in reduced core reactivity which is a fail-safe condition. (4) The spider finger braze joint that fastens the individual rods to the vanes on the Westinghouse RCCA has also experienced many years of service, as described above, without failure. A failure of this joint would also result in insertion of the individual rod into the core. The Framatome RCCA spider is one-piece casting that includes vanes and fingers, a failure of which could also result in insertion of the individual rod into the core. (5) The Westinghouse RCCA radial vanes are brazed to the spider body and guidance of the rod cluster control is accomplished by the inner fingers of these vanes. They are therefore the most susceptible to mechanical damage. For the Framatome RCCA, the radial vanes are integral parts of the one-piece spider casting. Failure of the vane-to-hub joint of a single rod vane could potentially result in failure of the separated vane and rod insertion. This could occur only at withdrawal elevation where the spider is above the continuous guidance section of the guide tube (in the upper internals). A rotation of the disconnected vane could cause it to hang on one of the guide cards in the intermediate guide tube. Such an occurrence would be evident from the failure of the rod cluster control to insert below a certain elevation, but with free motion above this point. This possibility is considered extremely remote because the single rod vanes are subjected to only vertical loads and very light lateral reactions from the rods even during a seismic event. The consequences of such a failure are not considered critical since only one drive line of the reactivity control system would be involved. This condition is readily observed and can be cleared at shutdown. (6) The spider hub, being of single unit cylindrical construction, is very rugged and has extremely low potential for damage. Should some unforeseen event cause fracture of the hub above the vanes, the lower portion with the vanes and rods attached would insert by gravity into the core causing reactivity decrease, again a fail-safe condition. (7) The RCCA rods are provided a clear channel for insertion by the guide thimbles of the fuel assemblies. All fuel rod failures are protected against by providing this physical barrier between the fuel rod and the intended insertion channel. Distortion of the fuel rods by bending cannot apply sufficient force to damage or significantly distort the guide thimble. Fuel rod distortion by swelling, though precluded by design, would be DCPP UNITS 1 & 2 FSAR UPDATE 4.2-45 Revision 21 September 2013 terminated by fracture before contact with the guide thimble occurs. If such were not the case, a force reaction at the point of contact would cause a slight deflection of the guide thimble. The radius of curvature of the deflected shape of the guide thimbles would be sufficiently large to have a negligible influence on rod cluster control insertion. 4.2.3.3.1.2 Burnable Absorber Assemblies The burnable absorber assemblies are static temporary reactivity control elements. The axial position is ensured by the holddown assembly that bears against the upper core plate. Their lateral position is maintained by the guide thimbles of the fuel assemblies.
The individual rods are shouldered against the underside of the retainer plate and securely fastened at the top by a threaded nut that is then locked in place. The square dimension of the retainer plate is larger than the diameter of the flow holes through the core plate. Therefore, failure of the holddown bar or spring pack does not result in ejection of the burnable absorber rods from the core.
The only incident that could result in ejection of the burnable absorber rods is a multiple fracture of the retainer plate. This is not considered credible because of the light loads borne by this component.
The burnable absorber rods are clad with either stainless steel or Zircaloy 4. The burnable absorber is either a borosilicate glass tube which is maintained in position by a central hollow stainless steel tube or Al2O3-B4C annular pellets contained within two concentric Zircaloy tubes. Burnable absorber rods are placed in static assemblies and are not subjected to motion which might damage the rods. Further, the guide thimble tubes of the fuel assembly afford additional protection from damage.
During the accumulated thousands of years of burnable absorber rodlet operating experience, only one instance of penetration of the stainless steel burnable absorber cladding has been observed. The consequences of cladding breach are also small. It is anticipated that upon cladding breach, the B4C or borosilicate glass would be leached by the coolant water and that localized power peaking of a few percent would occur; no design criteria would be violated. Additional information on the consequences of postulated WABA rod failures is presented in Reference 28. 4.2.3.3.1.3 Drive Rod Assemblies All postulated failures of the drive rod assemblies, either by fracture or uncoupling, lead to the fail-safe condition. If the drive rod assembly fractures at any elevation, that portion remaining coupled falls with, and is guided by, the RCCA. This always results in a reactivity decrease.
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-46 Revision 21 September 2013 4.2.3.3.2 Control Rod Drive Mechanism 4.2.3.3.2.1 Material Selection Materials for all pressure-containing CRDM components comply with Section III of the ASME B&PV Code and were fabricated from either austenitic (Type 304) stainless steel or CF-8 stainless steel.
Magnetic pole pieces are fabricated from Type 410 stainless steel. All nonmagnetic parts, except pins and springs, are fabricated from Type 304 stainless steel. Cobalt alloy is used to fabricate link pins. Springs are made from nickel alloy. Latch arm tips are clad with Stellite 6 or ERCoCrA to provide improved wearability. Hard chrome plate and Stellite 6 or ERCoCrA are used selectively for bearing and wear surfaces.
The cast coil housings require a magnetic material. The choice, made on the basis of cost, was the ductile iron used in the CRDM. The finished housings are zinc-plated to provide corrosion resistance.
Coils are wound on bobbins of molded Dow Corning 302 material, with double glass-insulated copper wire. Coils are then vacuum-impregnated with silicon varnish. A wrapping of mica sheet is secured to the coil outer surface. The result is a well-insulated coil capable of sustained operation at 200°C.
The drive shaft assembly uses a Type 410 stainless steel drive rod. The coupling is machined from Type 403 stainless steel. Other parts are Type 304 stainless steel with the exception of the springs, which are Inconel-X, and the locking button, which is Haynes 25. 4.2.3.3.2.2 Radiation Damage As required by the equipment specification, the CRDMs are designed to accommodate a radiation dose rate of 10 rad/hr. The above radiation level, which amounts to 1.753 x 106 rads in 20 years, will not limit CRDM life. 4.2.3.3.2.3 Positioning Requirements The mechanism has a step length of 5/8 inch that determines the positioning capabilities of the CRDM. (Note: Positioning requirements are determined by reactor physics.) 4.2.3.3.2.4 Evaluation of Materials' Adequacy The ability of the pressure housing components to perform throughout the design lifetime as defined in the equipment specification is confirmed by the stress analysis report required by the ASME B&PV Code, Section III.
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-47 Revision 21 September 2013 The CRDM latch assembly is a wear item that may require refurbishment after a minimum of two million steps. 4.2.3.3.2.5 Results of Dimensional and Tolerance Analysis With respect to the CRDM systems as a whole, critical clearances are present in the following areas:
(1) Latch assembly (diametral clearances) (2) Latch arm-drive rod clearances (3) Coil stack assembly-thermal clearances (4) Coil fit in coil housing These clearances have been proven by life tests and actual field performance at operating plants: (1) Latch Assembly - Thermal Clearances - The magnetic jack has several clearances where parts made of Type 410 stainless steel fit over parts made from Type 304 stainless steel. Differential thermal expansion is therefore important. (2) Latch Arm - Drive Rod Clearances - The CRDM incorporates a load transfer action. The movable or stationary gripper latch is not under load during engagement due to load transfer action. Figure 4.2-25 shows latch clearance variation with the drive rod at minimum and maximum temperatures. Figure 4.2-26 shows clearance variations over the design temperature range. (3) Coil Stack Assembly - Thermal Clearances - The assembly clearance of the coil stack assembly over the latch housing was selected so that the assembly could be removed under all anticipated conditions of thermal expansion. (4) Coil Fit in Coil Housing - CRDM and coil housing clearances are selected so that coil heatup results in a close or tight fit. This facilitates thermal transfer and coil cooling in a hot CRDM.
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-48 Revision 21 September 2013 4.2.3.4 Testing and Inspection Plan 4.2.3.4.1 Reactivity Control Components Tests and inspections are performed on each reactivity control component to verify its mechanical characteristics. For the RCCA, prototype testing has been conducted and both manufacturing tests/inspections and functional testing are performed at the plant site.
During the component manufacturing phase, the following requirements apply to the reactivity control components to ensure proper functioning during reactor operation:
(1) To attain the desired standard of quality, all materials are procured to specifications. (2) For the Westinghouse RCCA only, all spiders are proof tested by an applied load to the spider body which is reacted on by the 16 peripheral, outermost fingers. This proof load subjects the spider assembly to a load greater than the acceleration loads caused by the CRDM stepping. (3) All cladding/end plug welds are checked for integrity by visual inspection, X-ray, and helium leak tests. All the seal welds in the neutron absorber rods, burnable absorber rods, and source rods are checked in this manner. (4) To ensure proper fitup with the fuel assembly, the rod cluster control, burnable absorber, and source assemblies are installed in the fuel assembly without restriction or binding in the dry condition. The RCCAs are functionally tested following initial core loading, but prior to criticality, to demonstrate reliable operation of the assemblies. Each assembly is operated (and tripped) once each at the following conditions:
no flow cold, full flow cold, no flow hot, and full flow hot. In addition, the slowest and fastest rods for each condition are tripped six more times. Rod drop tests following refueling outages will be performed in accordance with the DCPP Technical Specifications (Reference 24) requirements. 4.2.3.4.2 Control Rod Drive Mechanisms Quality assurance procedures during production of CRDMs include material selection, process control, and mechanism component tests during production and hydrotests.
After all manufacturing procedures had been developed, several prototype CRDMs and drive rod assemblies were life tested with the entire drive line under normal environmental temperature, pressure, and flow conditions. All acceptance tests were of DCPP UNITS 1 & 2 FSAR UPDATE 4.2-49 Revision 21 September 2013 a duration equal to or greater than that required for plant operation. All drive rod assemblies tested in this manner have shown minimal wear damage.
These tests include verification that the trip time achieved by the CRDMs meets the design requirements from start of RCCA motion to dashpot entry. Trip time will be confirmed for each CRDM prior to initial reactor operation, and at periodic intervals thereafter. In addition, Technical Specifications ensure that the trip time requirement is met.
It is expected that all CRDMs will meet specified operating requirements for the duration of plant life with normal refurbishment. Nevertheless, a Technical Specification pertaining to an inoperable RCCA exists. If an RCCA cannot be moved by its mechanism, adjustments in the boron concentration ensure that adequate shutdown margin is achieved following a trip. Thus, inability to move one RCCA can be tolerated. More than one inoperable RCCA could be tolerated, but would impose additional demands on the plant operator. Therefore, the number of acceptable inoperable RCCAs is limited to one.
To demonstrate continuous free movement of the RCCA and to ensure acceptable core power distributions during operation, partial-movement checks are performed in accordance with Technical Specifications. In addition, periodic drop tests of the RCCAs are performed at each refueling shutdown to demonstrate continued ability to meet trip time requirements. During these tests, the acceptable trip time of each assembly is not greater than the requirements listed in the Technical Specifications at full flow and operating temperature, from decay of the gripper coil voltage to dashpot entry. To confirm the mechanical adequacy of the fuel assembly and RCCA, functional test programs have been conducted on a full-scale control rod. The prototype assembly was tested under simulated conditions of reactor temperature, pressure, and flow for approximately 1000 hours. The prototype mechanism accumulated about 3,000,000 steps and 600 trips. At the end of the test, the control rod drive mechanism was still operating satisfactorily.
All units are production tested prior to shipment to confirm the ability of CRDMs to meet design specification-operational requirements. Periodic tests are also conducted during plant operation in accordance with the Technical Specifications. 4.2.3.5 Instrumentation Instrumentation for determining reactor coolant average temperature (Tavg) is provided to create demand signals for moving groups of RCCAs to provide load follow (determined as a function of turbine impulse pressure) during normal operation, and to counteract operational transients. The hot and cold leg resistance temperature detectors (RTDs) are described in Section 7.2. The reactor control system, which controls the reactor coolant average temperature by regulation of control rod bank position, is described in Section 7.7. DCPP UNITS 1 & 2 FSAR UPDATE 4.2-50 Revision 21 September 2013 Rod position indication instrumentation is provided to sense the actual position of each control rod so that it may be displayed to the operator. Signals are also supplied by this system as input to the rod deviation comparator. The rod position indication system is described in Chapter 7. The CVCS, one of whose functions is to permit adjustment of the reactor coolant boron concentration for reactivity control (as well as to maintain the desired operating fluid inventory in the volume control tank), consists of a group of instruments arranged to provide a manually preselected makeup composition that is borated or diluted, as required, to the charging pump suction header or the volume control tank. This system, as well as other systems, including boron sampling provisions that are part of the CVCS, is described in Section 9.3.
When the reactor is critical, the normal indication of reactivity status in the core is the position of the control bank in relation to reactor power (as indicated by the reactor coolant system loop T) and coolant average temperature. These parameters are used to calculate insertion limits for the control banks to warn the operator of excessive rod insertion. Monitoring of the neutron flux for various phases of reactor power operation, as well as of core loading, shutdown, startup, and refueling is by means of the nuclear instrumentation system. The monitoring functions and readout and indication characteristics for the following reactivity monitoring systems are included in the discussion on safety-related display instrumentation in Section 7.5:
(1) Nuclear instrumentation system (2) Temperature indicators (a) T average (measured) (b) T (measured) (c) Auctioneered T average (3) Demand position of rod cluster control assembly group (4) Actual rod position indicator. 4.
2.4 REFERENCES
- 1. J. A. Christensen, et al, Melting Point of Irradiated UO2, WCAP-6065, February 1965.
- 2. J. Cohen, Development and Properties of Silver Base Alloys as Control Rod Material for Pressurized Water Reactors, WAPD-214, December 1959.
- 3. J. V. Miller (Ed.), Improved Analytical Methods Used in Westinghouse Fuel Rod Design Computations, WCAP-8720, October 1976.
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-51 Revision 21 September 2013 4. C. M. Friedrich and W. H. Guilinger, CYGRO-2, A Fortran IV Computer Program for Stress Analysis of the Growth of Cylindrical Fuel Elements with Fission Gas Bubbles, WAPD-TM-547, November 1966. 5. C. J. Kubit (Ed.), Safety-Related Research and Development for Westinghouse Pressurized Water Reactor - Program Summaries, Winter 1976, WCAP-8768, Rev. 1, December 1976.
- 6. Deleted.
- 7. S. Kraus, Neutron Shielding Pads, WCAP-7870, May 1972.
- 8. Westinghouse Electric Corporation, Operational Experience with Westinghouse Cores, WCAP-8183, (Revised Annually).
- 9. J. M. Hellman (Ed.), Fuel Densification Experimental Results and Model For Reactor Application, WCAP-8218-P-A (Westinghouse Proprietary) and WCAP-8219-A, March 1975.
- 10. B. Watkins and D. S. Wood, "The Significance of Irradiation - Induced Creep on Reactor Performance of a Zircaloy-2 Pressure Tube," Applications - Related Phenomena for Zirconium and its Alloys, ASTM STP 458, American Society for Testing and Materials, 1969.
- 11. L. Gesinski, et al, Safety Analysis of the 17x17 Fuel Assembly for Combined Seismic and Loss-of-Coolant Accident, WCAP-8288, December 1973.
- 12. W. J. O'Donnell and B. F. Langer, "Fatigue Design Basis for Zircaloy Components," Nuclear Science and Engineering, 20, 1-12, 1964.
- 13. E. E. DeMario and S. Nakazato, Hydraulic Flow Test of the 17 x 17 Fuel Assembly, WCAP-8279, February 1974.
- 14. D. H. Risher, et al, Safety Analysis for the Revised Fuel Rod Internal Pressure Design Basis, WCAP-8963A, January 1979.
- 15. R. A. George, et al, Revised Clad Flattening Model, WCAP-8377 (Westinghouse Proprietary) and WCAP-8381, July 1974.
- 16. J. Skaritka, (Ed), Fuel Rod Bow Evaluation, WCAP-8691, Rev. 1 (Proprietary) and WCAP-8692, Rev. 1, July 1979.
- 17. Letter from T. M. Anderson (Westinghouse) to D. G. Eisenhut (NRC), Integrity of Control Rod Guide Thimble, NS-TMA-1936, September 12, 1978.
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-52 Revision 21 September 2013 18. Letter from T. M. Anderson (Westinghouse) to D. G. Eisenhut (NRC), Additional Information - Integrity of CRGT, NS-TMA-1992, December 15, 1978. 19. Letter from T. M. Anderson (Westinghouse) to D. G. Eisenhut (NRC), Guide Thimble Tube Wear, NS-TMA-2102, June 27, 1979.
- 20. Letter from P. A. Crane (PG&E) to J. F. Stolz (NRC), Response to NRC Questions on Guide Tube Wear, March 25, 1980.
- 21. H. Kunishi and G.R. Schmidt, J. Skaritka (Ed.), Salem Unit 1 17 x 17 Fuel Assembly Guide Thimble Tube Wear Examination Report, Westinghouse Report, January 1982.
- 22. R. L. Cloud, et al. (Ed.), Pressure Vessels and Piping: Design and Analysis, Volume 1, Chapter 1, The American Society of Mechanical Engineers, 1972.
- 23. Regulatory Guide 1.44, Control of the Use of Sensitized Stainless Steel, USNRC, May 1973.
- 24. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
- 25. S. L. Davidson (Ed.), et al, Extended Burnup Evaluation of Westinghouse Fuel, WCAP-10125-P-A (Proprietary), December 1985.
- 26. S. L. Davidson (Ed.), Reference Core Report - VANTAGE 5 Fuel Assembly, WCAP-10444-P-A, September 1985.
- 27. S. L. Davidson (Ed.), et al, Verification Testing and Analysis of the 17 x 17 Optimized Fuel Assembly, WCAP-9401-P-A, August 1981.
- 28. J. Skaritka, Westinghouse Wet Annular Burnable Absorber Evaluation Report, WCAP-10021-P-A, Revision 1, October 1983.
- 29. S. L. Davidson (Ed.), et al, VANTAGE+ Fuel Assembly Reference Core Report, WCAP-12610, (Proprietary), June 1990.
- 30. Letter from Sheri R. Peterson (NRC) to Gregory M. Rueger (PG&E), Leak-Before-Break Evaluation of Reactor Coolant System Piping for DCPP Units 1 and 2, (Docket Nos. 50-275 and 50-323), March 2, 1993.
- 31. WCAP-16487-P, Revision 1, Diablo Canyon Nuclear Power Plant Unit 2 Upflow Conversion and Upper Head Temperature Reduction Engineering Report, March 2006.
DCPP UNITS 1 & 2 FSAR UPDATE 4.2-53 Revision 21 September 2013 32. WCAP-16946-P, Revision 2, Diablo Canyon Reactor Vessel Closure Head and Integrated Head Assembly Project, - Impact of IHA on Reactor Vessel, Internals, Fuel and Loop Piping, September 2010. DCPP UNITS 1 & 2 FSAR UPDATE 4.3-1 Revision 21 September 2013 4.3 NUCLEAR DESIGN The nuclear design of the reactors for Units 1 and 2 at DCPP, including fuel and reactivity control systems, is described in this section; the analytical methods used in reactor design and evaluation are also discussed. 4.3.1 DESIGN BASES The design bases and functional requirements for the nuclear design of the fuel and reactivity control system, and the relationship of these design bases to the GDC of July 1971, are presented in this section. Where appropriate, supplemental criteria, such as 10 CFR 50.46, are addressed.
Before discussing the nuclear design bases, a brief review of the four major plant operation conditions, categorized in accordance with their anticipated frequency of occurrence and risk to the public, (see Section 4.2) follows:
(1) Condition I - Normal Operation (2) Condition II - Incidents of Moderate Frequency (3) Condition III - Infrequent Faults (4) Condition IV - Limiting Faults In general, Condition I occurrences are accommodated with margin between any plant parameter and the value of that parameter which would require either automatic or manual protective action. Condition II incidents are accommodated with, at most, a shutdown of the reactor with the plant capable of returning to operation after corrective action. Fuel damage(a) is not expected during Conditions I and II events. It is not possible, however, to preclude a very small number of rod failures. These are within the capability of the plant cleanup system and are consistent with the plant design bases.
Condition III incidents shall not cause more than a small fraction of the fuel elements in the reactor to be damaged, although sufficient fuel element damage might occur to preclude immediate resumption of operation. The release of radioactive material due to Condition III incidents should not be sufficient to interrupt or restrict public use of those areas beyond the exclusion radius. Furthermore, a Condition III incident shall not, by itself, generate a Condition IV fault or result in a consequential loss of function of the reactor coolant system (RCS) or reactor containment barriers. Condition IV occurrences are faults that are not expected to occur, but are defined as limiting faults that must be considered in design. Condition IV faults shall not cause a release of radioactive material that results in an undue risk to public health and safety.
(a) Fuel damage as used here is defined as penetration of the fission product barrier (i.e., the fuel rod cladding).
DCPP UNITS 1 & 2 FSAR UPDATE 4.3-2 Revision 21 September 2013 The core design power distribution limits related to fuel integrity are met for Condition I occurrences through conservative design, and maintained by the action of the control system. The requirements for Condition II occurrences are met by providing an adequate protection system that monitors reactor parameters. The control and protection systems are described in Chapter 7 and the consequences of Conditions II, III, and IV occurrences are discussed in Chapter 15. 4.3.1.1 Fuel Burnup 4.3.1.1.1 Basis Sufficient reactivity should be incorporated in the fuel to attain a desired region average discharge burnup. This, along with the design basis in Section 4.3.1.3, satisfies GDC 10. 4.3.1.1.2 Discussion Fuel burnup is a measure of fuel depletion that represents the integrated energy output of the fuel (MWD/MTU) and is a convenient means for quantifying fuel exposure.
The core design lifetime or design discharge burnup is achieved by installing sufficient initial excess reactivity in each fuel region, and by following a fuel replacement program (such as that described in Section 4.3.2) that meets all safety-related criteria in each cycle of operation.
Initial excess reactivity in the fuel, although not a design basis, must be sufficient to maintain core criticality at full power operating conditions throughout cycle life with equilibrium xenon, samarium, and other fission products present. The end of design cycle life is defined to occur when the chemical shim concentration is essentially zero, with control rods present to the degree necessary for operational requirements (e.g., the controlling bank at the "bite" position). In terms of chemical shim boron concentration, this represents approximately 10 ppm with no control rod insertion. 4.3.1.2 Negative Reactivity Feedbacks (Reactivity Coefficients) 4.3.1.2.1 Basis The fuel temperature coefficient of reactivity will be negative, and the moderator temperature coefficient (MTC) of reactivity will be nonpositive for full power operating conditions, thus providing negative reactivity feedback characteristics over the operating range. Below 70 percent power, an MTC of up to +5 pcm (percent mille)/°F is allowed. From 70 percent to 100 percent the MTC limit decreases linearly from +5 to 0 pcm/°F. The design basis meets GDC 11.
DCPP UNITS 1 & 2 FSAR UPDATE 4.3-3 Revision 21 September 2013 4.3.1.2.2 Discussion When compensation for a rapid increase in reactivity is considered, there are two major effects. These are the resonance absorption effects (Doppler) associated with changing fuel temperature, and the spectrum effect resulting from changing moderator density. These basic physics characteristics are often identified by reactivity coefficients. The use of slightly enriched uranium ensures that the Doppler coefficient of reactivity, which provides the most rapid reactivity compensation, is negative. The core is also designed to have an overall negative MTC of reactivity at full power so that average coolant temperature or void content provides another, slower, compensatory effect. A small positive MTC is allowed at low power. The negative MTC at full power can be achieved through use of fixed burnable absorbers and/or boron coated fuel pellets and/or control rods by limiting the reactivity held down by soluble boron.
Burnable absorber content (quantity and distribution) is not stated as a design basis other than as it relates to achieving a nonpositive MTC at power operating conditions, as discussed above. 4.3.1.3 Control of Power Distribution 4.3.1.3.1 Basis The nuclear design basis, with at least a 95 percent confidence level, is as follows:
(1) The fuel will not be operated at greater than 14.3 kW/ft under normal operating conditions, including an allowance of 2 percent for calorimetric error and not including the power spike factor due to densification effects (Reference 3). (2) Under abnormal conditions, including the maximum overpower condition, the fuel peak power will not cause melting as defined in Section 4.4.1.2. (3) The fuel will not operate with a power distribution that violates the departure from nucleate boiling (DNB) design basis (i.e., the departure from nucleate boiling ratio (DNBR) shall not be less than the design limit DNBR, as discussed in Section 4.4.1) under Conditions I and II events, including the maximum overpower condition. (4) Fuel management will be such as to produce fuel rod powers and burnups consistent with the assumptions in the fuel rod mechanical integrity analysis of Section 4.2.
The above basis meets GDC 10.
DCPP UNITS 1 & 2 FSAR UPDATE 4.3-4 Revision 21 September 2013 4.3.1.3.2 Discussion Calculation of the extreme power shapes that affect fuel design limits is performed with proven methods as described in Section 4.3.3 and verified frequently with results from measurements in operating reactors. The conditions under which limiting power shapes are assumed to occur are chosen conservatively with regard to any permissible operating state.
Even though there is good agreement between peak power calculations and measurements, a nuclear uncertainty margin is applied to calculated peak local power. Such a margin is provided both for the analysis of normal operating states and for anticipated transients. 4.3.1.4 Maximum Controlled Reactivity Insertion Rate 4.3.1.4.1 Basis The maximum reactivity insertion rate due to withdrawal of RCCAs, or by boron dilution, is limited. This limit, expressed as a maximum reactivity change rate (75 pcm/sec)(a), is set such that the peak heat generation rate does not exceed the maximum allowable, and DNBR is not below the minimum allowable at overpower conditions. This satisfies GDC 25.
The maximum control rod reactivity worth and the maximum rates of reactivity insertion using control rods are limited to preclude either rupture of the coolant pressure boundary or disruption of the core internals to a degree that would impair core cooling capacity in the event of a rod withdrawal or ejection accident (see Chapter 15). Following any Condition IV event (such as rod ejection and steam line break), the reactor can be brought to the shutdown condition and the core will maintain acceptable heat transfer geometry. This satisfies GDC 28. 4.3.1.4.2 Discussion Reactivity addition associated with an accidental withdrawal of a control bank (or banks) is limited by the maximum rod speed (or travel rate) and by the worth of the bank(s). For this reactor the maximum control rod speed is 45 inches per minute and the maximum rate of reactivity change considering two control banks moving is less than 75 pcm/sec.
(a) 1 pcm = 10-5 where = )kk(ln12 (see footnote, Table 4.3-1).
DCPP UNITS 1 & 2 FSAR UPDATE 4.3-5 Revision 21 September 2013 4.3.1.5 Shutdown Margins 4.3.1.5.1 Basis Minimum shutdown margin, as specified in the Core Operating Limits Reports, is required in all operational modes except refueling.
In all analyses involving reactor trip, the single, highest worth RCCA is postulated to remain untripped in its full-out position (stuck rod criterion). This satisfies GDC 26. 4.3.1.5.2 Discussion Two independent reactivity control systems are provided: control rods and soluble boron in the coolant. The control rod system can compensate for the reactivity effects of the fuel and water temperature changes accompanying power level changes over the range from full load to no load. In addition, the control rod system provides the minimum shutdown margin under Condition I events and is capable of making the core subcritical rapidly enough to prevent exceeding acceptable fuel damage limits, assuming that the highest worth control rod is stuck out upon trip.
The boron system can compensate for all xenon burnout reactivity changes and will maintain the reactor in cold shutdown. Thus, backup and emergency shutdown provisions are provided by a mechanical and a chemical shim control system that satisfies GDC 26.
When fuel assemblies are in the pressure vessel and the vessel head is not in place, keff will be maintained at or below 0.95 with control rods and soluble boron. Further, the fuel will be maintained sufficiently subcritical that removal of all RCCAs will not result in criticality. 10 CFR 50.68(b) specifies a keff not to exceed 0.95 in spent fuel storage racks flooded with borated water and a keff not to exceed 0.98 in normally dry new fuel storage racks assuming optimum moderation. No criterion is given for the refueling operation; however, a 5 percent margin, which is consistent with spent fuel storage and 3 percent below the new fuel storage margin, is adequate for the controlled and continuously monitored operations involved.
An exemption granted from the NRC from the requirements of 10 CFR 50.68(b)(1) for the loading, unloading, and handling of components of the HI-STORM 100 dual-purpose dry cask storage system at DCPP is addressed in Section 9.1.4.7.
DCPP UNITS 1 & 2 FSAR UPDATE 4.3-6 Revision 21 September 2013 4.3.1.6 Stability 4.3.1.6.1 Basis The core will be inherently stable to power oscillations of the fundamental mode. This satisfies GDC 12. 4.3.1.6.1.1 Discussion Oscillations in total core power output, from whatever cause, are readily detected by loop temperature sensors and by nuclear instrumentation. If power increased unacceptably, a reactor trip would occur, thus preserving margins to fuel design limits. The stability of the turbine/steam generator/core systems and the reactor control system ensure that core power oscillations do not normally occur. Protection circuits' redundancy ensures an extremely low probability of exceeding design power levels. 4.3.1.6.2 Basis Spatial power oscillations within the core, with a constant core power output, should they occur, can be reliably and readily detected and suppressed. 4.3.1.6.2.1 Discussion The core is designed so that diametral and azimuthal oscillations due to spatial xenon effects are self-damping, and no operator action or control action is required to suppress them. Stability against diametral oscillations is so great that this excitation is highly improbable. Convergent azimuthal oscillations can be excited by prohibited motion of individual RCCAs. Such oscillations are readily observable and alarmed, using the excore long ion chambers. Indications are also continuously available from incore thermocouples and loop temperature measurements. Movable incore detectors can be activated to provide more detailed information. In all presently proposed cores, these horizontal plane oscillations are self-damping by virtue of reactivity feedback effects designed into the core.
Axial xenon spatial power oscillations can be excited by power level changes or by control rod motion/misalignments. The oscillations are inherently convergent at the beginning of core life, but become divergent as the core ages. The time in core life when oscillations may become divergent depends on core characteristics. Xenon oscillations studies performed for plants similar to DCPP concluded that oscillations can diverge as early as 50 EFPD. The magnitude of oscillations increases with increasing core burnup, although the period is unaffected. The type of oscillation (convergence or divergence) does not depend on the amplitude of the initial oscillation but is a function of initial conditions at the start of the transient.
DCPP UNITS 1 & 2 FSAR UPDATE 4.3-7 Revision 21 September 2013 The excore detectors provide monitoring of axial power distribution. The operator actions (control rod movement or power level changes) are expected to suppress and control axial xenon transients. The limits on measured axial difference assure that the fuel design limits (Fq) are not exceeded during either normal operation or a xenon transient. The measured AFD is also used as an input to the OTT trip function so that the DNB design bases are not exceeded. 4.3.1.7 Anticipated Transients Without Scram Each unit has an ATWS mitigation system actuation circuitry (AMSAC) system. Details of this system are given in Section 7.6. 4.3.2 DESCRIPTION 4.3.2.1 Nuclear Design Description The reactor core consists of 193 fuel assemblies arranged in a pattern that approximates a right circular cylinder. Each fuel assembly contains a 17 x 17 rod array composed of 264 fuel rods, 24 RCCA guide tubes, and an incore instrumentation thimble. Each rod is held in place by spacer grids and top and bottom nozzles. The fuel rods are constructed of zirconium alloy tubing containing UO2 fuel pellets. A limited substitution of fuel rods by filler rods of zirconium alloy or stainless steel may be made for a particular design if justified by a cycle-specific reload analysis. Figure 4.2-1 shows a cross-sectional view of a fuel assembly and the related RCCA locations. The fuel assembly design is discussed in Section 4.2.1.
All the fuel rods within a given assembly generally have the same nominal uranium enrichment. The exceptions are that the top and bottom portions of the rods may contain a low enriched or natural uranium blanket and that some assemblies may contain more than one enrichment as a result of reconstitution operations. Figure 4.3-1 shows a typical equilibrium 18-month cycle core loading of fresh and burned fuel assemblies. This "typical" loading pattern is modified for fuel cycles of longer length to accommodate the needed additional cycle energy.
A typical reload pattern employs low leakage fuel management in which more highly burned fuel is placed on the core periphery. Reload cores will operate approximately 12 months to 24 months between refuelings. The feed fuel enrichment is determined by the amount of fissionable material required to provide the desired core lifetime and energy production. Reactivity losses due to U-235 depletion and the buildup of fission products are partially offset by the buildup of plutonium produced by the capture of neutrons in U-238, as shown in Figure 4.3-2. At the beginning of any cycle, an excess reactivity to compensate for these losses over the specified cycle life must be "built" into the reactor. This excess reactivity is controlled by removable neutron absorbing DCPP UNITS 1 & 2 FSAR UPDATE 4.3-8 Revision 21 September 2013 material in the form of boron dissolved in the primary coolant and burnable absorber rods or boron coated fuel pellets.
Boric acid concentration in the primary coolant is varied to control and to compensate for long-term reactivity requirements, such as those due to fuel burnup, fission product poisoning, including xenon and samarium, burnable absorber material depletion, and the cold-to-operating moderator temperature change. Using its normal makeup path, the chemical and volume control system (CVCS) is capable of inserting negative reactivity at a rate of approximately 30 pcm/min when the reactor coolant boron concentration is 1000 ppm, and approximately 35 pcm/min when the reactor coolant boron concentration is 100 ppm. In an emergency, the CVCS can insert negative reactivity at approximately 65 pcm/min when the reactor coolant concentration is 1000 ppm, and 75 pcm/min when the reactor coolant boron concentration is 100 ppm. The peak xenon burnout rate is 25 pcm/min (Section 9.3.4 discusses the capability of the CVCS to counteract xenon decay). Rapid transient reactivity requirements and safe shutdown requirements are met with control rods.
As the boron concentration increases, the MTC becomes less negative. Using soluble poison alone would result in a positive MTC at beginning of life (BOL) at full power operating conditions. Therefore, burnable absorber rods are used to reduce the soluble boron concentration sufficiently to ensure that the MTC is not positive for full power operating conditions. During operation, the absorber content in these rods is depleted, thus adding positive reactivity to offset some of the negative reactivity from fuel depletion and fission product buildup. The depletion rate of the burnable absorber material is not critical since chemical shim is always available and flexible enough to cover any possible deviations in the expected burnable absorber depletion rate. Figure 4.3-3 shows typical core depletion curves with burnable absorbers. In addition to reactivity control, the burnable absorbers are strategically located to provide a favorable radial power distribution. Figures 4.3-4 and 4.3-5 show the typical burnable absorber distribution within a fuel assembly for the several burnable absorber patterns used for both discrete and integral fuel burnable absorbers. The burnable absorber loading pattern for a typical equilibrium cycle reload core is shown in Figure 4.3-6 using the integral fuel burnable absorber.
Tables 4.1-1, and 4.3-1 through 4.3-3, summarize the reactor core design parameters for a typical reload fuel cycle, including reactivity coefficients, delayed neutron fraction, and neutron lifetimes. 4.3.2.2 Power Distribution DCPP employs two methods for performing core power distribution calculations. The Power Distribution Monitoring System (PDMS) generates a continuous measurement of the core power distribution using the methodology documented in References 32 and 33. The measured core power distribution is used to determine the DCPP UNITS 1 & 2 FSAR UPDATE 4.3-9 Revision 21 September 2013 most limiting core peaking factors, which are used to verify that the reactor is operating within the design limits.
The PDMS requires information on current plant and core conditions in order to determine the core power distribution using the core peaking factor measurement and measurement uncertainty methodology described in References 32 and 33. The core and plant condition information is used as input to the continuous core power distribution measurement software that continuously and automatically determines the current core peaking factor values. The core power distribution calculation software provides the measured peaking factor values at nominal one-minute intervals to allow operators to confirm that the core peaking factors are within design limits. In order for the PDMS to accurately determine the peaking factor values, the core power distribution measurement software requires accurate information about the current reactor power level average reactor vessel inlet temperature, control bank positions, the power range detector currents, and the core exit thermocouples.
Data obtained from the movable neutron flux detectors, described in Section 7.7.2.9.2, are used to calibrate the PDMS, and may also be used independent of the PDMS to generate a flux map of the core power distribution. The accuracy of these power distribution calculations has been confirmed through more than 1,000 flux maps during some 20 years of operation, under conditions very similar to those expected for DCPP. Details of this confirmation are given in References 1 and 3 and in Section 4.3.2.2.7. 4.3.2.2.1 Definitions Power distributions are quantified in terms of hot channel factors. These factors are a measure of the peak pellet power within the reactor core and the total energy produced in a coolant channel and are expressed in terms of quantities related to the nuclear or thermal design; namely:
Power density is the thermal power produced per unit volume of the core (kW/liter). Linear power density is the thermal power produced per unit length of active fuel (kW/ft). Since fuel assembly geometry is standardized, this is the unit of power density most commonly used. For all practical purposes, it differs from kW/liter by a constant factor that includes geometry effects and the fraction of the total thermal power which is generated in the fuel rods.
Average linear power density is the total thermal power produced in the fuel rods divided by the total active fuel length of all rods in the core.
Local heat flux is the heat flux at the surface of the cladding (Btu ft-2hr-1). For nominal fuel rod parameters, this differs from linear power density by a constant factor.
Rod power or rod integral power is the linear power density in one rod integrated over its length (kW). DCPP UNITS 1 & 2 FSAR UPDATE 4.3-10 Revision 21 September 2013 Average rod power is the total thermal power produced in the fuel rods divided by the number of fuel rods.
The hot channel factors used in the discussion of power distributions in this section are defined as follows: FTQ, heat flux hot channel factor, is defined as the maximum local heat flux on the surface of a fuel rod divided by the average fuel rod heat flux, allowing for manufacturing tolerances on fuel pellets and rods. FNQ, nuclear heat flux hot channel factor, is defined as the maximum local fuel rod linear power density divided by the average fuel rod linear power density, assuming nominal fuel pellet and rod parameters. (No densification effects included.) FEQ, engineering heat flux hot channel factor, is the allowance on heat flux required for manufacturing tolerances. The engineering factor allows for local variations in enrichment, pellet density, and diameter.
Combined statistically, the net effect is a factor of 1.03 to be applied to the calculated linear power density. FNH, nuclear enthalpy rise hot channel factor, is defined as the ratio of the integral of linear power along the rod with the highest integrated power to the average rod power. Manufacturing tolerances, hot channel power distribution, and surrounding channel power distributions are treated explicitly in the calculation of DNB ratio described in Section 4.4. For the purposes of discussion, it is convenient to define subfactors of FTQ; design limits are set, however, in terms of the total peaking factor: FTQ factor channel hotflux heat or factor peaking Total= kW/ft AveragekW/ft Maximum= (4.3-1) without densification effects. FTQ = FNQx FEQ = max [FNXY(z) x P(z)] x FNU x FEQ (4.3-2) where: DCPP UNITS 1 & 2 FSAR UPDATE 4.3-11 Revision 21 September 2013 FNQ and FEQ are defined above. FNU = the measurement uncertainty associated with a full core flux map with movable detectors or PDMS FNXY(z) = ratio of peak power density to average power density in the horizontal plane of peak local power P(z) = ratio of the power per unit core height in the horizontal plane at elevation Z to the average value of power per unit core height 4.3.2.2.2 Radial Power Distributions The power shape in horizontal sections of the core at full power is a function of the fuel and burnable absorber loading patterns, and the presence or absence of a single bank of control rods. Thus, at any time in the cycle, any horizontal section of the core can be characterized as unrodded, or with group D control rods. These two situations, combined with burnup effects, determine the radial power shapes that can exist in the core at full power. The effects on radial power shapes of power level, xenon, samarium, and moderator density effects are also considered, but these are smaller. While radial power distributions in various planes of the core are often illustrated, the core radial enthalpy rise distribution, as determined by the power integral of each channel, is of greater interest. Figures 4.3-7 through 4.3-12 show representative radial power distributions for one-eighth of the core for representative operating conditions during the initial cycle, as follows: Figure Conditions 4.3-7 Hot full power (HFP) at BOL unrodded no xenon 4.3-8 HFP at BOL unrodded equilibrium xenon 4.3-9 HFP at BOL Bank D in equilibrium xenon - Unit 1 4.3-10 HFP at BOL Bank D in equilibrium xenon - Unit 2 4.3-11 HFP at middle of life (MOL) unrodded equilibrium xenon, and 4.3-12 HFP at EOL unrodded equilibrium xenon. Since hot channel location varies from time to time, a single reference radial design power distribution is selected for DNB calculations. This reference power distribution, normalized to core average power, is chosen conservatively to concentrate power in one area of the core, minimizing the benefits of flow redistribution. 4.3.2.2.3 Assembly Power Distributions For the purpose of illustration, assembly power distributions for the BOL and EOL conditions corresponding to Figures 4.3-8 and 4.3-12 are given for the same assembly in Figures 4.3-13 and 4.3-14, respectively. DCPP UNITS 1 & 2 FSAR UPDATE 4.3-12 Revision 21 September 2013 Since the detailed power distribution surrounding the hot channel varies from time to time, a conservatively flat assembly power distribution is assumed in the DNB analysis, described in Section 4.4, with the rod of maximum integrated power artificially raised to the design value of FNH. The nuclear design considers all fuel cycles and all operating conditions to ensure that a flatter assembly power distribution does not occur with limiting values of FNH. 4.3.2.2.4 Axial Power Distributions The shape of the power profile in the axial direction is largely under the control of the operator either through the manual operation of the control rods or the automatic motion of rods responding to manual operation of the CVCS. Nuclear effects that cause variations in the axial power shape include moderator density, Doppler effect on resonance absorption, spatial xenon variations, fuel, burnable absorber material distribution, and burnup. Automatically controlled variations in total power output and control rod motion are also important in determining the axial power shape at any time. Signals are available to the operator from the excore ion chambers that run parallel to the axis of the core. Separate signals are taken from the top and bottom halves of the chambers. The difference between top and bottom signals for each of four pairs of detectors is called the flux difference, . If it deviates from the flux difference target band, an alarm is actuated.
Calculations of core average peaking factor for many plants and measurements from operating situations are associated with either or axial offset to place an upper bound on the peaking factor. For these correlations, axial offset is defined as: Axial offset = btbt+ (4.3-4) (Multiply by 100 to get percent axial offset.)
where: t and b are the top and bottom detector readings. Representative axial power shapes for BOL, MOL, and EOL conditions covering a wide range, including power shape changes achieved by skewing xenon distributions, are shown in Figures 4.3-15 through 4.3-17. 4.3.2.2.5 Local Power Peaking Fuel densification causes fuel pellets to shrink both axially and radially. Pellet shrinkage combined with random hang-up of fuel pellets results in gaps in the fuel column when the pellets below the hung-up pellet settle in the fuel rod. The gaps vary in length and location in the fuel rod. Because of decreased neutron absorption in the vicinity of the DCPP UNITS 1 & 2 FSAR UPDATE 4.3-13 Revision 21 September 2013 gap, power peaking occurs in the adjacent fuel rods resulting in an increased power peaking factor. A quantitative measure of this local power peaking is given by the power spike factor S(z) where z is the axial location in the core.
In previous analyses of power peaking factors for Diablo Canyon Units 1 and 2, it was necessary to apply a penalty on calculated overpower transient FQ values to allow for interpellet gaps caused by pellet hang-ups and pellet shrinkage due to densification. This penalty is known as the densification spike factor. However, studies have shown (Reference 31) that this penalty can be eliminated for the fuel type present in the Diablo Canyon Units 1 and 2 cores. 4.3.2.2.6 Limiting Power Distributions As discussed in Section 4.3.1, Condition I occurrences are those expected frequently or regularly in the course of power operation, maintenance, or maneuvering of the plant. Condition I occurrences are accommodated with margin between any plant parameter and the value of that parameter that would require either automatic or manual protective action. Since they occur frequently or regularly, Condition I occurrences affect the consequences of Conditions II, III, and IV events. Analysis of each fault condition is generally based on a conservative set of initial conditions corresponding to the most adverse set of conditions that can occur during Condition I operation.
The list of steady state and shutdown conditions, permissible deviations, and operational transients is given in Section 15.1. Implicit in the definition of normal operation is proper and timely action by the reactor operator. That is, the operator follows recommended operating procedures for maintaining appropriate power distributions and takes any necessary remedial actions when alerted to do so by plant instrumentation. Thus, as stated above, the worst or limiting power distribution that can occur during normal operation is considered as the starting point for analysis of Conditions II, III, and IV events.
Improper procedural actions or errors by the operator are assumed in the design as occurrences of moderate frequency (Condition II). The limiting power shapes that result from such Condition II events are, therefore, those power shapes, which deviate from the normal operating condition at the recommended axial offset band. Power shapes that fall in this category are used to determine reactor protection system setpoints and maintain margin to overpower or DNB limits.
Maintaining power distributions within the required hot channel factor limits is discussed in the Technical Specifications. A complete discussion of power distribution control in Westinghouse pressurized water reactors is included in References 2, 29, and 30. Detailed background information on the following design constraints on local power density in a Westinghouse pressurized water reactor, on the defined operating procedures, and on the measures taken to preclude exceeding design limits is presented in References 23, 29, 30.
DCPP UNITS 1 & 2 FSAR UPDATE 4.3-14 Revision 21 September 2013 The upper bound on peaking factors, FTQ and FNH, includes all of the nuclear effects that influence the radial and/or axial power distributions throughout core life for various modes of operation, including load follow, reduced power operation, and axial xenon transients.
Radial power distributions are calculated for full power, and fuel and moderator temperature feedback effects are included for the average enthalpy plane of the reactor. Steady state nuclear design calculations are done for normal flow with the same mass flow in each channel, and flow redistribution effects are neglected. The effect of flow redistribution is calculated explicitly when important to the DNB analysis of accidents. The effect of xenon on radial power distribution is small (compare Figures 4.3-7 and 4.3-8), but is included as part of the normal design process.
The core average axial profile can experience significant changes that can occur rapidly as a result of rod motion and load changes, and more slowly due to xenon distribution. To study points of closest approach to axial power distribution limits, several thousand cases are examined. Since the nuclear design properties dictate what axial shapes can occur, the limits of interest can be set in terms of parameters, which are readily observed. Specifically, the following nuclear design parameters are significant to the axial power distribution analysis:
(1) Core power level (2) Core height (3) Coolant temperature and flow (4) Coolant temperature program as a function of reactor power (5) Fuel cycle lifetimes (6) Rod bank worths (7) Rod bank overlaps Normal plant operation assumes compliance with the following conditions: (1) Control rods in a single bank move together with no individual rod insertion differing by more than 12 steps (indicated) from the bank demand position (2) Control banks are sequenced with overlapping banks (3) Control bank insertion limits are not violated (4) Axial power distribution procedures, which are given in terms of flux difference control and control bank position, are observed.
DCPP UNITS 1 & 2 FSAR UPDATE 4.3-15 Revision 21 September 2013 The above axial power distribution procedures are part of the normal plant operating procedures. Briefly, they require control of the axial offset (see Equation 4.3-4) at all power levels, within a permissible operating band. This minimizes xenon transient effects on the axial power distribution, since the procedures essentially keep the xenon distribution in phase with the power distribution.
Calculations are performed for normal reactor operation at beginning, middle, and end of cycle conditions. Different operation histories are implicitly included in the methodology. These different histories cover both base loaded operation and extensive load following.
These cases represent many possible reactor states in the life of one fuel cycle. They are considered to be necessary and sufficient to generate a local power density limit which, when increased by 5 percent for conservatism, will not be exceeded with a 95 percent confidence level. Many of the points do not approach the limiting envelope. However, they are generated as part of the process that leads to the shapes, which do define the envelope.
Thus, it is not possible to single out any transient or steady state condition that defines the most limiting case. It is not even possible to separate out a small number, which form an adequate analysis. The process of generating a myriad of shapes is essential to the philosophy that leads to the required level of confidence. A set of parameters that produces a limiting case for one reactor fuel cycle (defined as approaching the line of Figure 4.3-23) is not necessarily a limiting case for another reactor or fuel cycle with different control bank worths or insertion limits, enrichments, burnup, reactivity coefficient, etc. The shape of the axial power distribution calculated for a particular time depends on the operating history of the core up to that time, and on the manner in which the operator conditioned xenon in the days immediately before that time.
The calculated points are synthesized from axial calculations combined with the radial factors appropriate for rodded and unrodded planes. In these calculations, the effects on the radial peak of xenon redistribution that occur, following the withdrawal of a control bank (or banks) from a rodded region, are obtained from three-dimensional calculations. The factor to be applied to the radial peak is obtained from calculations in which the xenon distribution is preconditioned by the presence of control rods and then allowed to redistribute for several hours. A detailed discussion of this effect may be found in References 23 and 29. In addition to the 1.05 conservatism factor, the calculated values are increased by a factor of 1.03 for the engineering factor FEQ. The envelope drawn over the calculated [max (FTQ Power)] points, as shown in Figure 4.3-23 from a past cycle, gives an example of an upper bound envelope on local power density versus elevation in the core. Figure 4.3-24 illustrates BOL, MOL, and EOL steady state conditions from a past cycle. Cycle-specific values are calculated each cycle.
DCPP UNITS 1 & 2 FSAR UPDATE 4.3-16 Revision 21 September 2013 Finally, this upper bound envelope is based on operation within an allowed range of axial flux steady state conditions. These limits are detailed in the Core Operating Limits Reports and rely only on excore surveillance supplemented by the required normal monthly power distribution measurement. If the axial flux difference exceeds the allowable range, an alarm is actuated.
Allowing for fuel densification, the average linear power is 5.445 kW/ft for both units at 3,411 MWt. The conservative upper bound value of normalized local power density, including uncertainty allowances, is 2.58, corresponding to a peak linear power of 14.3 kW/ft at 102 percent power.
To determine reactor protection system setpoints, with respect to power distributions, three categories of events are considered: rod control equipment malfunctions, operator errors of commission, and operator errors of omission. In evaluating these three categories, the core is assumed to be operating within the four constraints described above.
The first category is uncontrolled rod withdrawal (with rods moving in the normal bank sequence). Also included are motions of the banks below their insertion limits, which could be caused, for example, by uncontrolled dilution or primary coolant cooldown. Power distributions were calculated, assuming short-term corrective action. That is, no transient xenon effects were considered to result from the malfunction. The event was assumed to occur from typical normal operating situations, which include normal xenon transients. It was also assumed that the total power level would be limited by the reactor trip to below 118 percent. Results are given in Figure 4.3-21 in units of kW/ft. The peak power density, which can occur in such events, assuming reactor trip at or below 118 percent, is less than that required for fuel centerline melt, including uncertainties.
The second category, also appearing in Figure 4.3-21, assumes that the operator mispositions the rod bank in violation of insertion limits and creates short-term conditions not included in normal operating conditions.
The third category assumes that the operator fails to take action to correct a flux difference violation. The results shown in Figure 4.3-22 are FTQ multiplied by 102 percent power, including an allowance for calorimetric error. The peak linear power does not exceed 22.0 kW/ft, provided the operator's error does not continue for a period which is long compared to the xenon time constant. It should be noted that a reactor overpower accident is not assumed to occur coincident with an independent operator error. Additional detailed discussion of these analyses is presented in Reference 23. Analyses of possible operating power shapes for the DCPP reactor show that the appropriate hot channel factors FTQ and FNH for peak local power density, and for DNB analysis at full power, are the values given in Table 4.3-1 and addressed in the Technical Specifications.
DCPP UNITS 1 & 2 FSAR UPDATE 4.3-17 Revision 21 September 2013 The maximum allowable FTQ can increase with decreasing power, as shown in the Technical Specifications. Increasing FNH with decreasing power is permitted by the DNB protection setpoints and allows radial power shape changes with rod insertion to the insertion limits, as described in Section 4.4.3.2. The allowances for increased FNH permitted is: FNH = 1.65 [1 + 0.3 (1-P)] for VANTAGE 5 fuel, and (4.3-5) FNH = 1.62 [1 + 0.3 (1-P)] for LOPAR fuel (4.3-6) This becomes a design basis criterion, which is used for establishing acceptable control rod patterns and control bank sequencing. Likewise, fuel loading patterns for each cycle are selected with consideration of this design criterion. The worst values of FNH for possible rod configurations occurring in normal operation are used in verifying that this criterion is met. Typical radial factors and radial power distributions are shown in Figures 4.3-7 through 4.3-12. The worst values generally occur when the rods are assumed to be at their insertion limits. As discussed in Reference 3, it has been determined that the Technical Specification limits are met, provided the above conditions (1) through (4) are observed. These limits are taken as input to the thermal-hydraulic design basis, as described in Section 4.4.3.2.1.
If the possibility exists during normal operation of local power densities exceeding those assumed as the precondition for a subsequent hypothetical accident, but which would not itself cause fuel failure, administrative controls and alarms are provided to return the core to a safe condition. These alarms are described in Chapter 7 and in the Technical Specifications. 4.3.2.2.7 Experimental Verification of Power Distribution Analysis This subject, which is discussed in depth in Reference 1, is summarized here. To measure the peak local power density, FTQ, with the movable detector system described in Sections 7.7.2.9.2 and 4.4.5, the following uncertainties are considered: (1) Reproducibility of the measured signal (2) Errors in the calculated relationship between detector current and local flux (3) Errors in the calculated relationship between detector flux and peak rod power some distance from the measurement thimble Allowance for (1) has been quantified by repetitive measurements made with several intercalibrated detectors using the common thimble features of the incore detector DCPP UNITS 1 & 2 FSAR UPDATE 4.3-18 Revision 21 September 2013 system. This system allows more than one detector to access any thimble. Item (2) above is quantified to the extent possible by using the fluxes measured at one thimble location to predict fluxes at another location, which is also measured. Local power distribution predictions are verified in critical experiments on arrays of rods with simulated guide thimbles, control rods, burnable poisons, etc.
Reference 1 concludes that the uncertainty associated with the peak nuclear heat flux factor, FTQ, is 4.58 percent at the 95 percent confidence level with only 5 percent of the measurements greater than the inferred value. In comparing measured power distributions (or detector currents) against the calculations for the same situations, it is not possible to subtract out the detector reproducibility. Thus, a comparison between measured and predicted power distributions must consider measurement error. Such a comparison is illustrated in Figure 4.3-25 for one of the maps of Reference 1, which is similar to hundreds of maps taken since then on various reactors, confirming the adequacy of the 5 percent uncertainty allowance on FTQ. A similar analysis for the uncertainty in FNH (rod integral power) measurements results in an allowance of 3.68 percent at the equivalent of a 2 confidence level. For historical reasons, an 8 percent uncertainty factor is allowed in the nuclear design basis; that is, the predicted rod integrals at full power must not exceed the design FNH less 8 percent. This 8 percent may be reduced in final design to 4 percent to allow a wider range of acceptable axial power distributions in the DNB analysis and still meet the design bases of Section 4.3.1.3.
A measurement in the second cycle of a 121-assembly, 12-foot core, is compared with a simplified one-dimensional core average axial calculation in Figure 4.3-26. This calculation does not give explicit representation to the fuel grids.
The accumulated data on power distributions in actual operation is basically of three types:
(1) Much of the data is obtained in steady state operation at constant power in the normal operating configuration. (2) Data with unusual values of axial offset are obtained as part of the excore detector calibration exercise which is performed monthly. (3) Special tests have been performed in load follow and other transient xenon conditions which have yielded useful information on power distributions.
DCPP UNITS 1 & 2 FSAR UPDATE 4.3-19 Revision 21 September 2013 These data are presented in detail in Reference 3. Figure 4.3-27 contains a summary of measured values of FTQ as a function of axial offset for five plants from that report. 4.3.2.2.8 Testing An extensive series of physics tests is performed on first cores. These tests and the criteria for satisfactory results are described in detail in Chapter 14. Since not all limiting situations can be created at BOL, the main purpose of the tests is to provide a check on the calculation methods used in the predictions for the conditions of the test. Physics testing is also performed at the beginning of each reload cycle to ensure that the operating characteristics of the core are consistent with design predictions. 4.3.2.2.9 Monitoring Instrumentation The adequacy of instrument numbers, spatial deployment, required correlations between readings and peaking factors, calibration, and errors is described in References 1, 2, and 3. The relevant conclusions are summarized in Sections 4.3.2.2.7 and 4.4.5.
Reference 32 describes the instrumentation requirements and calibration of the PDMS, and the uncertainties applied to the calculated peaking factors.
If the limitations given in Section 4.3.2.2.6 on rod insertion and flux difference are observed, the excore detector system provides adequate monitoring of power distributions.
Further details of specific limits on the observed rod positions and flux difference are given in the Core Operating Limits Reports, together with a discussion of their bases.
Limits for alarms, reactor trip, etc., are given in the Technical Specifications. System descriptions are provided in Section 7.7. 4.3.2.3 Reactivity Coefficients Reactor core kinetic characteristics determine the response of the core to changing plant conditions, or to operator adjustments made during normal operation, as well as the core response during abnormal or accidental transients. These kinetic characteristics are quantified in reactivity coefficients. The reactivity coefficients reflect changes in the neutron multiplication due to varying plant conditions such as power, moderator or fuel temperatures, or, less significantly, due to a change in pressure or void conditions. Since reactivity coefficients change during the life of the core, ranges of coefficients are employed in transient analysis to determine the response of the plant throughout life. The analytical methods and calculational models used in calculating the reactivity coefficients are given in Section 4.3.3. These models have been confirmed through extensive testing of more than 30 cores similar to DCPP, as discussed in Section 4.3.3. DCPP UNITS 1 & 2 FSAR UPDATE 4.3-20 Revision 21 September 2013 4.3.2.3.1 Fuel Temperature (Doppler) Coefficient The fuel temperature (Doppler) coefficient is defined as the change in reactivity per degree change in effective fuel temperature and is primarily a measure of the Doppler broadening of U-238 and Pu-240 resonance absorption peaks. Doppler broadening of other isotopes such as U-236, Np-237, etc., are also considered, but their contributions to the Doppler effect is small. An increase in fuel temperature increases the effective resonance absorption cross sections of the fuel and produces a corresponding reduction in reactivity.
The fuel temperature coefficient is calculated by two-group two or three-dimensional calculations. Moderator temperature is held constant and the power level is varied. Spatial variation of fuel temperature is taken into account by calculating the effective fuel temperature as a function of power density, as discussed in Section 4.3.3.1.
The Doppler temperature coefficient is shown in Figure 4.3-28 as a function of the effective fuel temperature (at BOL and EOL conditions). The effective fuel temperature is lower than the volume averaged fuel temperature since the neutron flux distribution is nonuniform through the pellet and gives preferential weight to the surface temperature. The Doppler-only contribution to the power coefficient (defined later) is shown in Figure 4.3-29 as a function of relative core power. The integral of the differential curve in Figure 4.3-29 is the Doppler contribution to the power defect and is shown in Figure 4.3-30 as a function of relative power. The Doppler coefficient becomes more negative as a function of life as the Pu240 content increases, thus increasing the Pu240 resonance absorption, but less negative as the fuel temperature changes with burnup, as described in Section 4.3.3.1. The upper and lower limits of Doppler coefficient used in accident analyses are given in Chapter 15. 4.3.2.3.2 Moderator Coefficients The moderator coefficient is a measure of the change in reactivity due to a change in specific coolant parameters such as density, temperature, pressure, or void. 4.3.2.3.2.1 Moderator Density and Temperature Coefficients The MTC (density) is defined as the change in reactivity per degree change in the moderator temperature. Generally, the effect of the changes in moderator density, as well as the temperature, are considered together. A decrease in moderator density means less moderation which results in a negative MTC. An increase in coolant temperature, keeping the density constant, leads to a hardened neutron spectrum resulting in greater resonance absorption in U238, Pu240, and other isotopes. The hardened spectrum also causes a decrease in the fission to capture ratio in U235 and Pu239. Both of these effects make the MTC more negative. Since water density decreases as temperature increases, the MTC (density) becomes more negative with increasing temperature.
DCPP UNITS 1 & 2 FSAR UPDATE 4.3-21 Revision 21 September 2013 The soluble boron also affects the MTC (density) since its density, like that of water, also decreases when the coolant temperature rises. Therefore, a decrease in the soluble poison concentration introduces a positive component into the moderator coefficient. Indeed, if the concentration of soluble poison is large enough, the net value of the coefficient may be positive. With the burnable poison rods present, however, the initial hot boron concentration is sufficiently low, making the MTC negative at full power operating temperatures. The effect of control rods is to make the moderator coefficient more negative by reducing the required soluble boron concentration and by increasing "leakage" from the core.
With burnup, the MTC normally becomes more negative primarily as a result of boric acid dilution, but also, to a significant extent, from the effects of plutonium and fission products buildup.
The MTC is calculated for various plant conditions by performing two-group two or three dimensional calculations, varying the moderator temperature (and density) by about +/-5°F about each of the mean temperatures. The MTC is shown in Figures 4.3-31 through 4.3-33 as a function of core temperature and boron concentration for a typical reload unrodded and rodded core. The temperature range covered is from cold (68°F) to about 600°F. The contribution due to Doppler coefficient (because of change in moderator temperature) has been subtracted from these results. Figure 4.3-34 shows the hot, full power MTC as a function of cycle lifetime for the critical boron concentration condition based on the design boron letdown condition (Figure 4.3-3) for a typical reload cycle. 4.3.2.3.2.2 Moderator Pressure Coefficient The moderator pressure coefficient relates the change in moderator density, resulting from a reactor coolant pressure change, to the corresponding effect on neutron production. This coefficient is of much less significance than the MTC. A change of 50 psi in pressure has approximately the same effect on reactivity as a half-degree change in moderator temperature. This coefficient can be determined from the MTC by relating change in pressure to the corresponding change in density. The moderator pressure coefficient is negative over a portion of the moderator temperature range at BOL (-0.004 pcm/psi, BOL) but is always positive at operating conditions and becomes more positive during life (+0.3 pcm/psi, EOL). 4.3.2.3.2.3 Moderator Void Coefficient The moderator void coefficient relates the change in neutron multiplication to the presence of voids in the moderator. In a pressurized water reactor (PWR), this coefficient is not very significant because of the low void content in the coolant. The core void content is less than one-half of 1 percent and is due to local or statistical boiling. The void coefficient at BOL varies from 50 pcm/% void at BOL and low temperatures to -250 pcm/% void at EOL and at operating temperatures. The negative void coefficient at operating temperature becomes more negative with fuel burnup. DCPP UNITS 1 & 2 FSAR UPDATE 4.3-22 Revision 21 September 2013 4.3.2.3.3 Power Coefficient The combined effect of moderator temperature and fuel temperature change as the core power level changes is called the total power coefficient, and is expressed in terms of reactivity change per percent power change. The power coefficient at BOL and EOL conditions is given in Figure 4.3-35. It becomes more negative with burnup, reflecting the combined effect on moderator and fuel temperature coefficients of burnup. The power defect (integral reactivity effect) at BOL and EOL is given in Figure 4.3-36. 4.3.2.3.4 Comparison of Calculated and Experimental Reactivity Coefficients Based on the comparison between calculated and experimental reactivity coefficients in Section 4.3.3, the accuracy of the current analytical model is:
+/- 0.2% for Doppler effect and power defect +/- 2 pcm/°F for the moderator coefficient Experimental verification of the calculated coefficients will be done during the physics startup tests described in Chapter 14.
4.3.2.3.5 Reactivity Coefficients Used in Transient Analysis Table 4.3-1 gives representative ranges for the reactivity coefficients used in the transient analysis. The exact values of the coefficient used in the analysis depend on whether the transient of interest is examined at the BOL or EOL, whether the most negative or the most positive (least negative) coefficients are appropriate, and whether spatial nonuniformity must be considered in the analysis. Conservative values of coefficients are always used in the transient analysis, as described in Chapter 15.
The values listed in Table 4.3-1, and illustrated in Figures 4.3-29 through 4.3-36, apply to the core shown in Figure 4.3-1. Appropriate coefficients for use in other cycles depend on the core's operating history, the number and enrichment of fresh fuel assemblies, the loading pattern of burned and fresh fuel, and the number and location of any burnable poison rods. The need for a reevaluation of any accident in a subsequent cycle is contingent on whether or not the coefficients for that cycle fall within the range used in the analysis presented in Chapter 15. Control rod requirements are given in Table 4.3-2 for the core described and for a hypothetical equilibrium cycle since these are markedly different. These latter numbers are provided for information only. 4.3.2.4 Control Requirements To ensure shutdown margin availability under cooldown to ambient temperature conditions, concentrated soluble boron is added to the coolant. Boron concentrations for several core conditions are listed in Table 4.3-1. They are all well below the DCPP UNITS 1 & 2 FSAR UPDATE 4.3-23 Revision 21 September 2013 solubility limit. The RCCAs are employed to bring the reactor to the hot shutdown condition. The minimum shutdown margin required is given in the Core Operating Limits Reports.
The ability to shut down from hot conditions is demonstrated in Table 4.3-2 by comparing the difference between the reactivity available in the RCCA, allowing for the rod with the highest worth being stuck, with that required for control and protection. The shutdown margin allows 10 percent for analytic uncertainties (see Section 4.3.2.4.9). The largest reactivity control requirement appears at EOL when the MTC reaches its peak negative value as reflected in the larger power defect.
Control rods are required to provide sufficient reactivity to compensate for the power defect from full power to zero power and the required shutdown margin. The reactivity addition resulting from power reduction consists of contributions from Doppler, variable average moderator temperature, flux redistribution, and reduction in void content. 4.3.2.4.1 Doppler Control requirements to compensate for the Doppler effect are listed in Tables 4.3-2 and 4.3-3, for DCPP Units 1 and 2, respectively. 4.3.2.4.2 Variable Average Moderator Temperature When the core is shut down to the hot zero power condition, the average moderator temperature changes from the equilibrium full load value, determined by the steam generator and turbine characteristics (such as steam pressure, heat transfer, and tube fouling), to the equilibrium no-load value, which is based on the steam generator shell side design pressure. The design change in temperature is conservatively increased by 4°F to account for control dead band measurement errors.
Since the moderator coefficient is negative, there is a reactivity addition with power reduction. The MTC becomes more negative as the fuel depletes because the boron concentration decreases. This effect is the major contribution to the increased requirement at EOL. 4.3.2.4.3 Redistribution During full power operation, the coolant density decreases with core height and this, together with partial insertion of control rods, results in less fuel depletion near the top of the core. Under steady state conditions, the relative power distribution will be slightly asymmetric towards the bottom of the core. On the other hand, at hot zero power conditions, the coolant density is uniform and there is no flattening due to Doppler. The result is a flux distribution that at zero power can be skewed toward the top of the core. The reactivity insertion due to the skewed distribution is calculated with an allowance for the most adverse effects of xenon distribution.
DCPP UNITS 1 & 2 FSAR UPDATE 4.3-24 Revision 21 September 2013 4.3.2.4.4 Void Content A small void content in the core is due to nucleate boiling at full power. The void collapse that results from a power reduction makes a small reactivity contribution. 4.3.2.4.5 Rod Insertion Allowance At full power, the control bank is operated within a prescribed travel band to compensate for small periodic changes in boron concentration, in temperature, and very small changes in the xenon concentration not compensated for by a change in boron concentration. When the control bank reaches either limit of this band, a change in boron concentration is required to compensate for additional reactivity changes. Since the insertion limit is set by a rod travel limit, a conservatively high calculation of the inserted worth is made which exceeds the normally inserted reactivity. 4.3.2.4.6 Burnup Excess reactivity of 10 percent to 25 percent (hot) is installed at the beginning of each cycle to provide sufficient reactivity to compensate for fuel depletion and fission products buildup throughout the cycle. This reactivity is controlled by the addition of soluble boron to the coolant and by burnable absorber. The soluble boron concentrations for several core configurations, the unit boron worth, and burnable absorber worth are given in Tables 4.1-1 and 4.3-1. Since the excess reactivity for burnup is controlled by soluble boron and/or burnable absorber, it is not included in control rod requirements. 4.3.2.4.7 Xenon and Samarium Poisoning Changes in xenon and samarium concentrations in the core occur at a sufficiently slow rate, even following rapid power level changes, so that the resulting reactivity change is controlled by changing the soluble boron concentration. 4.3.2.4.8 pH Effects Changes in reactivity due to a change in coolant pH, if any, are sufficiently small in magnitude and occur slowly enough to be controlled by the boron system. Further details are available in Reference 4. 4.3.2.4.9 Experimental Confirmation Following a normal shutdown, the total core reactivity change during cooldown with a stuck rod has been measured on a 121-fuel-assembly, 10-foot-high core, and a 121-fuel-assembly, 12-foot-high core. In each case, the core was allowed to cool down until it reached criticality, simulating the steam line break accident. For the 10-foot-core, the total reactivity change associated with the cooldown is overpredicted by about 0.3 percent with respect to the measured result. This represents an error of about DCPP UNITS 1 & 2 FSAR UPDATE 4.3-25 Revision 21 September 2013 5 percent in the total reactivity change and is about half the uncertainty allowance for this quantity. For the 12-foot-core, the difference between the measured and predicted reactivity change was an even smaller 0.2 percent . These and other measurements demonstrate the ability of the methods described in Section 4.3.3 to accurately predict the total shutdown reactivity of the core. 4.3.2.5 Control Core reactivity is controlled by means of a chemical neutron absorber (chemical shim) dissolved in the coolant, RCCAs, and burnable poison rods as described below. 4.3.2.5.1 Chemical Shim Boron in solution as boric acid is used to control relatively slow reactivity changes associated with:
(1) The moderator temperature defect in going from cold shutdown at ambient temperature to the hot operating temperature at zero power (2) Transient xenon and samarium poisoning, such as that following power changes or changes in RCCA position (3) The excess reactivity required to compensate for the effects of fissile inventory depletion and buildup of long-life fission products (4) The burnable absorber depletion The boron concentrations for various core conditions are presented in Table 4.3-1. 4.3.2.5.2 Rod Cluster Control Assemblies As shown in Table 4.1-1, 53 RCCAs are used in these reactors. The RCCAs are used for shutdown and control purposes to offset fast reactivity changes associated with: (1) The required shutdown margin in the hot zero power, stuck rods condition (2) The increase in power above hot zero power (power defect including Doppler and moderator reactivity changes) (3) Unprogrammed fluctuations in boron concentration, coolant temperature, or xenon concentration (with rods not exceeding the allowable rod insertion limits) (4) Reactivity ramp rates resulting from load changes DCPP UNITS 1 & 2 FSAR UPDATE 4.3-26 Revision 21 September 2013 Control bank reactivity insertion at full power is limited to maintain shutdown capability. As the power level is reduced, control rod reactivity requirements are reduced and more rod insertion is allowed. The control bank position is monitored and the operator is notified by an alarm if the limit is approached. The determination of the insertion limit uses conservative xenon distributions and axial power shapes. In addition, the RCCA withdrawal pattern obtained from these analyses is used in determining power distribution factors, and in determining the maximum reactivity worth during an ejection accident of an inserted RCCA. The Technical Specifications discuss rod insertion limits.
Power distribution, rod ejection, and rod misalignment analyses are based on the arrangement of the shutdown and control RCCA groups shown in Figures 4.3-37 and 4.3-38, for Units 1 and 2, respectively. All shutdown RCCAs are withdrawn before control banks withdrawal is initiated. In going from zero to 100 percent power, control banks A, B, C, and D are withdrawn sequentially. Rod position limits and the basis for rod insertion limits are provided in the Core Operating Limits Reports. 4.3.2.5.3 Burnable Absorber Rods Burnable absorber rods (either discrete or integral type) provide partial control of excess reactivity during the fuel cycle. These rods prevent the MTC from being positive at normal operating conditions. They perform this function by reducing the requirement for soluble boron in the moderator at the beginning of the fuel cycle, as described above. The burnable absorber patterns used together with a typical number of rods per assembly, are shown in Figure 4.3-6 for a cycle using integral absorber exclusively. The arrangements within an assembly for discrete and integral absorber types are displayed in Figures 4.3-4 and 4.3-5 respectively. The critical concentration of soluble boron resulting from the slow burnup of boron in the rods is such that the MTC remains negative at all times for full power operating conditions. 4.3.2.5.4 Peak Xenon Startup Peak xenon buildup is compensated by the boron control system. Startup from the peak xenon condition is accomplished with a combination of rod motion and boron dilution. Boron dilution may be made at any time, including the shutdown period, provided the shutdown margin is maintained. 4.3.2.5.5 Load Follow Control and Xenon Control The DCPP units are usually base loaded; however, it is expected that during certain times of certain years some load following may be required.
Should load following become a desired mode of operation, then, during load follow maneuvers, power changes would be accomplished using control rod motion, dilution or boration by the boron systems as required, and reductions in coolant Tavg. Control rod motion limitations are discussed in Section 4.3.2.5.2 and the Technical Specifications. DCPP UNITS 1 & 2 FSAR UPDATE 4.3-27 Revision 21 September 2013 Reactivity changes due to the changing xenon concentration can be controlled by rod motion and/or soluble boron concentration changes. 4.3.2.5.6 Burnup The excess reactivity available for burnup is controlled with soluble boron and/or burnable absorber. The boron concentration must be limited during operating conditions to ensure the MTC is negative at full power. Sufficient burnable absorber is installed at the beginning of a cycle to give the desired cycle lifetime without exceeding the boron concentration limit. The practical minimum boron concentration is 10 ppm. 4.3.2.6 Control Rod Patterns and Reactivity Worths The RCCAs are designated by function as the control groups and the shutdown groups. The terms "group" and "bank" are used synonymously throughout this chapter to describe a particular grouping of control assemblies. The RCCA patterns are displayed in Figures 4.3-37 and 4.3-38 for Units 1 and 2, respectively. These patterns are not expected to change during the life of the units. The control banks are labeled A, B, C, and D, and the shutdown banks are labeled SA, SB, SC and SD.
The two criteria used to select the control groups are: (a) the total reactivity worth must be adequate to meet the requirements specified in Tables 4.3-2 and 4.3-3, and (b) because these rods may be partially inserted at power operation, the total power peaking factor should be low enough to ensure that power capability requirements are met. Analyses indicate that the first requirement can be met by one or more banks whose total worth equals at least the required amount. Since the shape of the axial power distribution would be more peaked following movement of a single group of rods worth 3 to 4 percent , four banks, each worth approximately 1 percent , were selected.
The position of control banks for criticality under any reactor condition is determined by the boron concentration in the coolant. On an approach to criticality, boron is adjusted to ensure criticality will be achieved with control rods above the insertion limit set by shutdown and other considerations (see Technical Specifications). Early in the cycle there may also be a withdrawal limit at low power to maintain an MTC more negative than the Technical Specification limit. Usual practice is to adjust boron to ensure that the rod position lies within the so-called maneuvering band so that an escalation from zero power to full power does not require further adjustment of boron concentration.
Ejected rod worths are given in Section 15.4.6 for several different conditions. Experimental confirmation of these worths can be found by reference to startup test reports such as Reference 5.
Allowable deviations due to misaligned control rods are discussed in the Technical Specifications.
DCPP UNITS 1 & 2 FSAR UPDATE 4.3-28 Revision 21 September 2013 A representative calculation for two banks of control rods withdrawn simultaneously (rod withdrawal accident) is shown in Figure 4.3-39. Calculation of control rod reactivity worth versus time following reactor trip involves both control rod velocity and differential reactivity worth. Rod position versus time of travel after rod release is shown in Figure 4.3-40. The reactivity worth versus rod position is calculated by a series of steady state calculations at various control rod positions assuming all rods out of the core as the initial position to minimize the initial reactivity insertion rate. To be conservative, the rod of highest worth is assumed stuck out of the core and the flux distribution (and thus reactivity importance) is assumed to be skewed to the bottom of the core. The result of these calculations is shown in Figure 4.3-41.
The shutdown groups provide additional negative reactivity to ensure an adequate shutdown margin. Shutdown margin is defined as the instantaneous amount of reactivity by which the core is, or would be, subcritical from its present condition if all RCCAs (shutdown and control) are fully inserted, but assuming that the RCCA with the highest reactivity worth remains fully withdrawn (N-1). The loss of control rod worth due to material irradiation is negligible, since only bank D rods may be in the core under normal operating conditions.
Tables 4.3-2 and 4.3-3 show that the available reactivity in withdrawn RCCAs provides the design bases minimum shutdown margin allowing for the highest worth cluster to be at its fully withdrawn position in DCPP Units 1 and 2, respectively. An allowance for uncertainty in the calculated worth of N-1 rods is made before determination of the shutdown margin. 4.3.2.7 Criticality of Fuel Assemblies Criticality of fuel assemblies outside the reactor is precluded by adequate design of fuel transfer and fuel storage facilities, and by administrative control procedures.
New fuel can be stored in dry fuel storage facilities. To design storage facilities, the fuel assemblies are assumed to be in their most reactive condition, i.e., fresh or undepleted and with no control rods or removable neutron absorbers present. Assemblies cannot be closer together than the design separation provided by the storage facility, except in special cases, such as in fuel shipping containers where analyses are performed to establish design acceptability. The mechanical integrity of the fuel assembly is assumed.
Criticality analyses of the storage facilities must assume flooding with unborated water. To prevent accidental criticality, the fuel assembly spacing of the facility provides essentially full nuclear isolation and the effective multiplication factor (keff) for the array is no greater than keff for the single most reactive fuel assembly. The criterion for wet fuel storage criticality analyses is that there is a 95 percent probability, 95 percent confidence level for the keff of the fuel storage array being less than 1.0 if flooded with nborated water, per 10 CFR 50.68(b)(4). The two possible variations in the criticality DCPP UNITS 1 & 2 FSAR UPDATE 4.3-29 Revision 21 September 2013 analyses result from: (a) calculation uncertainties, and (b) fuel rack fabrication uncertainties.
Standard calculations have been compared to results of critical experiments. The results indicate the following:
(1) The average difference between the calculations and experimental results, or bias in the computations, was 0.0103 k (KENO5a) and 0.0000 (CASMO3). (2) The standard deviation of the bias between the calculations and experimental results was 0.0018 k (KENO5a) and 0.0024 (CASMO3).
Fuel rack fabrication uncertainties are as follows:
(1) The analyzed tolerance on the inner stainless steel box dimension of a rack cell is +/-0.032 inch. (2) The tolerance on the center-to-center spacing between fuel rack cells is +/-0.05.
As an example, a fuel assembly of standard design and 3.5 wt percent enriched uranium oxide, without a control rod or burnable absorber rods, fully flooded and reflected with cold clean water, has a keff of about 0.85. Two such fuel assemblies spaced 1 inch apart with parallel axes 9.5 inches apart have a keff of about 0.99. Three such fuel assemblies spaced 1 inch apart with parallel axes would be supercritical. An infinite number of dry fuel assemblies of this design would have a keff < 0.80. Verification that appropriate shutdown criteria, including uncertainties, are met during refueling is achieved using standard Westinghouse reactor design methods. Core subcriticality during refueling is continuously monitored as described in the Technical Specifications. 4.3.2.8 Stability 4.3.2.8.1 Introduction The stability of PWR cores against xenon-induced spatial oscillations, and the control of such transients, are discussed extensively in References 2, 6, 7, and 8.
Due to the negative power coefficient of reactivity, PWR cores are inherently stable to oscillations in total power. In a large reactor core, however, xenon-induced oscillations can take place with no corresponding change in total core power. The oscillation may be caused by a power shift in the core that occurs rapidly in comparison with the xenon-iodine time constants. Such a power shift occurs in the axial direction when a plant load change is made by control rod motion, and results in a change in the DCPP UNITS 1 & 2 FSAR UPDATE 4.3-30 Revision 21 September 2013 moderator density and fuel temperature distributions. Such a power shift in the diametral plane of the core could result from abnormal control action. 4.3.2.8.2 Stability Index Power distributions, either in the axial direction or in the X-Y plane, can undergo oscillations due to perturbations introduced in the equilibrium distributions without changing total core power. The xenon-induced oscillations are essentially limited to the first flux overtones in the current PWRs, and the stability of the core against xenon-induced oscillations can be determined in terms of the eigenvalues of the first flux harmonics. Writing the eigenvalue of the first flux harmonic, either in the axial direction or in the X-Y plane, as:
();1i,icb2=+= (4.3-7) b is defined as the stability index and T = 2/c as the oscillation period of the first harmonic. The time-dependence of the first harmonic in the power distribution can now be represented as: ()ctcosaeeAtbtt== (4.3-8) where A and a are constants. The stability index can also be obtained approximately by: +nA1nAlnT1 = b (4.3-9) where An, An+1 are the successive peak amplitudes of the oscillation, and T is the time period between the successive peaks. 4.3.2.8.3 Prediction of the Core Stability The stability of the DCPP cores in relation to xenon-induced spatial oscillations is expected to be equal to that of earlier designs because: (a) the overall core size is unchanged and spatial power distributions are similar, (b) the MTC is expected to be similar, and (c) the Doppler coefficient of reactivity is expected to be similar at full power.
4.3.2.8.4 Stability Measurements (1) Axial Measurements Two axial xenon transient tests conducted in a PWR with a core height of 12 feet and 121 fuel assemblies, at approximately 10 and 50 percent of cycle life, are reported in Reference 9. DCPP UNITS 1 & 2 FSAR UPDATE 4.3-31 Revision 21 September 2013 The axial offset (AO) of power was obtained as a function of time for both tests as shown in Figure 4.3-42. The total core power was maintained constant during these spatial xenon tests, and the stability index and the oscillation period were obtained from a least-square fit of the AO data to Equation 4.3-7. The conclusions of the tests are as follows: (a) The core was stable against induced axial xenon transients both at the core average burnups of 1550 MWD/MTU and 7700 MWD/MTU. (b) The reactor core becomes less stable as fuel burnup progresses, and the axial stability index was essentially zero at 12,000 MWD/MTU. (2) Measurements in the X-Y Plane Two X-Y xenon oscillation tests were performed at a PWR plant with a core height of 12 feet and 157 fuel assemblies. This plant had the highest power output of any Westinghouse PWR operating in 1972. The first test was conducted at a core average burnup of 1540 MWD/MTU and the second at a core average burnup of 12900 MWD/MTU. Both of the X-Y xenon tests show that the core was stable in the X-Y plane at both burnups. The second test shows that the core became more stable as the fuel burnup increased and all Westinghouse PWRs with 121 and 157 assemblies are expected to be stable throughout their burnup cycles. In each of the two X-Y tests, a perturbation was introduced to the equilibrium power distribution through an impulse motion of one RCC unit located along the diagonal axis. Following the perturbation, the uncontrolled oscillation was monitored using the movable detector and thermocouple system and the excore power range detectors. The quadrant tilt difference is the quantity that properly represents the diametral oscillation in the X-Y plane of the reactor core in that the difference of the quadrant average powers over two symmetrically opposite quadrants essentially eliminates the contribution to the oscillation from the azimuthal mode. The quadrant tilt difference (QTD) data were least-square fitted to the form of Equation 4.3-7. A stability index of 0.076 hr-1 with a period of 29.6 hours was obtained from the thermocouple data shown in Figure 4.3-43. In the second X-Y xenon test, the PWR core with 157 fuel assemblies became more stable due to increased fuel depletion. 4.3.2.8.5 Comparison of Calculations with Measurements Axial xenon transient tests were analyzed in an axial slab geometry using a flux synthesis technique. The PANDA code (Reference 11) was used for direct simulation DCPP UNITS 1 & 2 FSAR UPDATE 4.3-32 Revision 21 September 2013 of the AO data. X-Y xenon transient tests analyses are performed with the modified TURTLE code. Both the PANDA and TURTLE codes solve the two-group time-dependent neutron diffusion equation with time-dependent xenon and iodine concentrations. The fuel temperature and moderator density feedback is limited to a steady state model. All the X-Y calculations were performed in an average enthalpy plane.
The basic nuclear cross sections used in this study were generated from a unit cell depletion program that evolved from codes LEOPARD and CINDER (Reference 14). The detailed experimental data during the tests, including the reactor power level, enthalpy rise, and the impulse motion of the control rod assembly, as well as the plant follow burnup data, were closely simulated in the study.
The results of the stability calculation for the axial tests are compared with the experimental data in Table 4.3-4. The calculations show conservative results for both of the axial tests with a margin of approximately 0.01 hr-1 in the stability index. An analytical simulation of the first X-Y xenon oscillation test shows a calculated stability index of -0.081 hr-1, in good agreement with the measured value of -0.076 hr-1. As indicated earlier, the second X-Y xenon test showed that the core had become more stable compared to the first test. The increase in the core stability in the X-Y plane due to increased fuel burnup is due mainly to the increased magnitude of the negative MTC.
Previous studies of the physics of xenon oscillations, including three-dimensional analysis, are reported in References 6, 7, 8, 9, and Section 1 of Reference 10.
4.3.2.8.6 Stability Control and Protection The excore detector system provides indications of xenon-induced spatial oscillations. The readings from the excore detectors are available to the operator and also form part of the protection system.
(1) Axial Power Distribution To maintain proper axial power distributions, the operator is instructed to maintain an axial offset within a prescribed operating band, based on the excore detector readings. Should the axial offset move far enough outside this band, the protection limit will be reached and the power will be automatically cut back. (2) Radial Power Distribution The DCPP cores are calculated to be stable with respect to xenon-induced oscillations in the X-Y plane during the plant's lifetime.
DCPP UNITS 1 & 2 FSAR UPDATE 4.3-33 Revision 21 September 2013 The X-Y stability of large PWRs has been further verified as part of the startup physics test program at a PWR core with 193 fuel assemblies. The measured X-Y stability of the PWR core with 157 assemblies, and the good agreement between the calculated and measured stability index for this core, as discussed in Sections 4.3.2.8.4 and 4.3.2.8.5, make it very unlikely that a sustained X-Y oscillation can occur in a core with 193 assemblies. In the unlikely event that X-Y oscillations occur, backup actions are possible and would be implemented, if necessary, to increase the natural stability of the core until tests demonstrate a suitable stability, by making the MTC more negative. A more detailed discussion of the power distribution control in PWR cores is presented in Reference 2. 4.3.2.9 Vessel Irradiation Pressure vessel irradiation and the corresponding material surveillance program are discussed in Sections 5.4.1 and 5.2.4. A brief review of the methodology used to determine neutron and gamma flux attenuation between the core and pressure vessel follows.
The primary shielding material used to attenuate high energy neutron and gamma flux originating in the core consists primarily of the core baffle, core barrel, the thermal shield for Unit 1 and the neutron pads for Unit 2, and associated water annuli, all of which are within the region between the core and the pressure vessel. In general, few group neutron diffusion theory codes are used to determine flux and fission power density distributions within the active core, and the accuracy of these analyses is verified by incore measurements on operating reactors. Outside the active core, methods such as those that use multigroup space-dependent slowing down codes, as described in Section 5.2.4, are used. Region-wise power sharing information from the core calculations is often used as reference source data for multigroup codes.
The neutron flux distribution and spectrum in the various structural components varies significantly from the core to the pressure vessel. Representative values of the neutron flux distribution and spectrum are presented in Table 4.3-5. The values listed are based on equilibrium cycle reactor core parameters and power distributions and are thus suitable for long-term neutron fluence projections and for correlation with radiation damage estimates. 4.3.3 ANALYTICAL METHODS Calculations required in nuclear design consist of the following three distinct types, which are performed in sequence:
(1) Determination of effective fuel temperatures DCPP UNITS 1 & 2 FSAR UPDATE 4.3-34 Revision 21 September 2013 (2) Generation of macroscopic few-group parameters (3) Space-dependent, few-group diffusion calculations 4.3.3.1 Fuel Temperature (Doppler) Calculations Temperatures vary radially within the fuel rod, depending on heat generation rate in the pellet, the conductivity of the materials in the pellet, gap and cladding, and coolant temperature.
Fuel temperatures for use in most nuclear design Doppler calculations are obtained from a simplified version of the Westinghouse fuel rod design model described in Section 4.2.1.3.1, which considers the effect of radial variation of pellet conductivity, expansion-coefficient and heat generation rate, elastic deflection of the cladding, and a gap conductance which depends on the initial fill gas, the hot open gap dimension, and the fraction of the pellet over which the gap is closed. The fraction of the gap assumed closed represents an empirical adjustment to produce good agreement with observed reactivity data at BOL. Further gap closure occurs with burnup and accounts for the decrease in Doppler defect with burnup which has been observed in operating plants. For detailed calculations of the Doppler coefficient, such as for use in xenon stability calculations, a more sophisticated temperature model is used which accounts for the effects of fuel swelling, fission gas release, and plastic cladding deformation.
Radial power distributions in the pellet as a function of burnup are obtained from LASER (Reference 15) calculations. The effective U-238 temperature for resonance absorption is obtained from the radial temperature distribution by applying a radially dependent weighting function. The weighting function was determined from REPAD (Reference 16) Monte Carlo calculations of resonance escape probabilities in several steady state and transient temperature distributions. In each case, a flat pellet temperature was determined which produced the same resonance escape probability as the actual distribution. The weighting function was empirically determined from these results.
The effective Pu-240 temperature for resonance absorption is determined by a convolution of the radial distribution of Pu-240 number densities from LASER burnup calculations and the radial weighting function. The resulting temperature is burnup dependent, but the difference between U-238 and Pu-240 temperatures, in terms of reactivity effects, is small.
The effective pellet temperature for pellet dimensional change is that value which produces the same outer pellet radius in a virgin pellet as that obtained from the temperature model. The effective cladding temperature for dimensional change is its average value.
The temperature calculational model has been validated by plant Doppler defect data as shown in Table 4.3-6 and Doppler coefficient data as shown in Figure 4.3-44. Stability DCPP UNITS 1 & 2 FSAR UPDATE 4.3-35 Revision 21 September 2013 index measurements also provide a sensitive measure of the Doppler coefficient near full power (see Section 4.3.2.8). It can be seen that Doppler defect data are typically within 0.2 percent of prediction. 4.3.3.2 Macroscopic Group Constants There are two lattice codes used for the generation of macroscopic group constants for use in the spatial few group diffusion codes. They are a version of the LEOPARD and CINDER codes and PHOENIX-P. A detailed description of each follows. Macroscopic few-group constants and analogous microscopic cross sections (needed for feedback and microscopic depletion calculations) can be generated for fuel cells by a Westinghouse version of the LEOPARD and CINDER codes, which are linked internally and provide burnup-dependent cross sections. Normally, a simplified approximation of the main fuel chains is used; however, where needed, a complete solution for all the significant isotopes in the fuel chains from Th-232 to Cm-244 is available (Reference 17). Cross section library tapes contain microscopic cross sections from the ENDF/B (Reference 18) library, with a few exceptions, where other data provide better agreement with critical experiments, isotopic measurements, and plant critical boron values.
The effect on the unit fuel cell of nonlattice components in the fuel assembly is obtained by supplying an appropriate volume fraction of these materials in an extra region which is homogenized with the unit cell in the fast (MUFT) and thermal (SOFOCATE) flux calculations. In the thermal calculation, the fuel rod, cladding, and moderator are homogenized by energy-dependent disadvantage factors derived from an analytical fit to integral transport theory results. Group constants for burnable absorber cells, guide thimbles, instrument thimbles, and interassembly gaps are generated in a manner analogous to the fuel cell calculation. Reflector group constants are taken from infinite medium LEOPARD calculations. Baffle group constants are calculated from an average of core and radial reflector microscopic group constants for stainless steel.
Group constants for control rods are calculated in a linked version of the HAMMER (Reference 19) and AIM (Reference 20) codes to provide an improved treatment of self-shielding in the broad resonance structure of the appropriate isotopes at epithermal energies than is available using LEOPARD. The Doppler broadened cross sections of the control rod material are represented as smooth cross sections in the 54-group LEOPARD fast group structure and in 30 thermal groups. The four-group constants in the rod cell and appropriate extra region are generated in the coupled space-energy transport HAMMER calculation. A corresponding AIM calculation of the homogenized rod cell with extra region is used to adjust the absorption cross sections of the rod cell to match the reaction rates in HAMMER. These transport-equivalent group constants are reduced to two-group constants for use in space-dependent diffusion calculations. In discrete X-Y calculations only one mesh interval per cell is used, and the rod group DCPP UNITS 1 & 2 FSAR UPDATE 4.3-36 Revision 21 September 2013 constants are further adjusted for use in this standard mesh by reaction rate matching the standard mesh unit assembly to a fine-mesh unit assembly calculation.
Validation of the cross section method is based on analysis of critical experiments (Table 4.3-7), isotopic data (Table 4.3-8), plant critical boron (CB) values at hot zero power (HZP), BOL (Table 4.3-9), and at HFP as a function of burnup (Figures 4.3-45 through 4.3-47). Control rod worth measurements are shown in Table 4.3-10. Confirmatory critical experiments on burnable absorbers are described in Reference 21.
The PHOENIX-P computer code is a two-dimensional, multi-group, transport based lattice code and capable of providing all necessary data for PWR analysis. Being a dimensional lattice code, PHOENIX-P does not rely on pre-determined spatial/spectral interaction assumptions for a heterogeneous fuel lattice, hence, will provide a more accurate multi-group flux solution than versions of LEOPARD/CINDER. The PHOENIX-P computer code is approved by the USNRC as the lattice code for generating macroscopic and microscopic few group cross sections for PWR analysis (Reference 27).
The solution for the detailed spatial flux and energy distribution is divided into two major steps in PHOENIX-P (References 27 and 28). In the first step, a two-dimensional fine energy group nodal solution is obtained which couples individual subcell regions (pellet, cladding and moderator) as well as surrounding pins. PHOENIX-P uses a method based on the Carlvik's collision probability approach and heterogeneous response fluxes which preserves the heterogeneity of the pin cells and their surroundings. The nodal solution provides accurate and detailed local flux distribution, which is then used to spatially homogenize the pin cells to fewer groups. The second step in the solution process solves for the angular flux distribution using a standard S4 discrete ordinates calculation. This step is based on the group-collapsed and homogenized cross sections obtained from the first step of the solution. The S4 fluxes are then used to normalize the detailed spatial and energy nodal fluxes. The normalized nodal fluxes are used to compute reaction rates, power distribution and to deplete the fuel and burnable absorbers. A standard B1 calculation is employed to evaluate the fundamental mode critical spectrum and to provide an improved fast diffusion coefficient for the core spatial codes.
The PHOENIX-P code employs a 42 energy group library, which has been derived mainly from ENDF/B-V files. The PHOENIX-P cross sections library was designed to properly capture integral properties of the multi-group data during group collapse, and enabling proper modeling of important resonance parameters. The library contains all neutronic data necessary for modeling fuel, fission products, cladding and structural data, coolant, and control/burnable absorber materials present in Light Water Reactor cores.
DCPP UNITS 1 & 2 FSAR UPDATE 4.3-37 Revision 21 September 2013 Group constants for burnable absorber cells, guide thimbles, instrument thimbles, control rod cells and other non-fuel cells can be obtained directly from PHOENIX-P without any adjustments such as those required in the cell or 1D lattice a codes. 4.3.3.3 Spatial Few-Group Diffusion Calculations Spatial few-group diffusion calculations have primarily consisted of two group X-Y calculations using an updated version of the TURTLE code, and two-group axial calculations using an updated version of the PANDA code. However, with the advent of VANTAGE 5 and hence axial features such as axial blankets and part length burnable absorbers, there will be a greater reliance on three-dimensional nodal codes such as 3D PALADON (Reference 25) and 3D ANC (Advanced Nodal Code) (Reference 26). The three dimensional nature of the nodal codes provide both the radial and axial power distributions.
Nodal three-dimensional calculations are carried out to determine the critical boron concentrations and power distributions. The moderator coefficient is evaluated by varying the inlet temperature in the same calculations used for power distribution and reactivity predictions.
Validation of TURTLE reactivity calculations is associated with the validation of the group constants themselves, as discussed in Section 4.3.3.2. Validation of the Doppler calculations is associated with the fuel temperature validation, as discussed in Section 4.3.3.1. Validation of the moderator coefficient calculation is obtained by comparison with plant measurements at HZP conditions, as shown in Table 4.3-11. Axial calculations are used to determine differential control rod worth curves (reactivity versus rod insertion) and axial power shapes during steady state and transient xenon conditions. Group constants are obtained from three-dimensional nodal calculations homogenized by flux volume weighting.
Validation of the spatial codes for calculating power distributions involves the use of incore and excore detectors, and is discussed in Section 4.3.2.2.7.
Based on comparison with measured data, it is estimated that the accuracy of current analytical methods is:
+/-0.2% for Doppler defect +/-2 x /°F for moderator temperature coefficient +/-50 ppm for critical boron concentration with depletion +/-3% for power distributions +/-0.2% for rod bank worth DCPP UNITS 1 & 2 FSAR UPDATE 4.3-38 Revision 21 September 2013 4.
3.4 REFERENCES
- 1. F. L. Langford and R. J. Nath, Jr., Evaluation of Nuclear Hot Channel Factor Uncertainties, WCAP-7308-L, April 1969 (Westinghouse Proprietary) and WCAP-7810, December 1971.
- 2. J. S. Moore, Power Distribution Control of Westinghouse Pressurized Water Reactors, WCAP-7208, September 1968 (Westinghouse Proprietary) and WCAP-7811, December 1971.
- 3. A. F. McFarlane, Power Peaking Factors, WCAP-7912-L, March 1971 (Westinghouse Proprietary) and WCAP-7912, March 1972.
- 4. J. O. Cermak et al, Pressurized Water Reactor pH - Reactivity Effect, Final Report, WCAP-3696-8 (EURAEC-2074), October 1968.
- 5. J. E. Outzs, Plant Startup Test Report, H. B. Robinson Unit No. 2, WCAP-7844, January 1972.
- 6. C. G. Poncelet and A. M. Christie, Xenon-Induced Spatial Instabilities in Large PWRs, WCAP 3680-20, (EURAEC-1974), March 1968.
- 7. F. B. Skogen and A. F. McFarlane, Control Procedures for Xenon-Induced X-Y Instabilities in Large PWRs, WCAP 3680-21, (EURAEC-2111), February 1969.
- 8. F. B. Skogen and A. F. McFarlane, Xenon-Induced Spatial Instabilities in Three-Dimensions, WCAP-3680-22 (EURAEC-2116), September 1969.
- 9. J. C. Lee, et al, Axial Xenon Transient Tests at the Rochester Gas and Electric Reactor, WCAP-7964, June 1971.
- 10. C. J. Kubit, Safety Related Research and Development for Westinghouse Pressurized Water Reactors, Program Summaries, Spring-Fall 1973, WCAP-8204, October 1973.
- 11. R. F. Barry, et al, The PANDA Code, WCAP-7757, September 1971.
- 12. S. Altomare and R. F. Barry, The TURTLE 24.0 Diffusion Depletion Code, WCAP-7758, September 1971.
- 13. R. F. Barry, LEOPARD - A Spectrum Dependent Non-Spatial Depletion Code for the IBM-7094, WCAP-3269-26, September 1963.
- 14. T. R. England, CINDER - A One-Point Depletion and Fission Product Program. WAPD-TM-334, August 1962.
DCPP UNITS 1 & 2 FSAR UPDATE 4.3-39 Revision 21 September 2013 15. C. G. Poncelet, LASER - A Depletion Program for Lattice Calculations Based on MUFT and THERMOS, WCAP-6073, April 1966. 16. J. E. Olhoeft, The Doppler Effect for a Non-Uniform Temperature Distribution in Reactor Fuel Elements, WCAP-2048, July 1962.
- 17. R. J. Nodvik, et al, Supplementary Report on Evaluation of Mass Spectrometric and Radiochemical Analyses of Yankee Core I Spent Fuel, Including Isotopes of Elements Thorium Through Curium, WCAP-6086, August 1969.
- 18. M. K. Drake, (Ed), Data Formats and Procedure for the ENDF Neutron Cross Section Library, BNL-50274, ENDF-102, Vol. I, 1970.
- 19. J. E. Suich and H. C. Honeck, The HAMMER System, Heterogeneous Analysis by Multigroup Methods of Exponentials and Reactors, DP-1064, January 1967.
- 20. H. P. Flatt and D. C. Baller, AIM-5, A Multigroup, One Dimensional Diffusion Equation Code, NAA-SR-4694, March 1960.
- 21. J. S. Moore, Nuclear Design of Westinghouse Pressurized Water Reactors with Burnable Poison Rods, WCAP-7806, December 1971.
- 22. J. M. Hellman, (Ed), Fuel Densification Experimental Results and Model for Reactor Application, WCAP-8218-P-A (Westinghouse Proprietary) and WCAP-8219-A, March 1975. 23. T. Morita, et al., Power Distribution Control and Load Following Procedures, WCAP-8385 (Proprietary) and WCAP-8403, September 1974. 24. Deleted in Revision 12.
- 25. T. M. Camden. et al., PALADON - Westinghouse Nodal Computer Code, WCAP-9485-P-A. December 1979 and Supplement 1, September 1981.
- 26. S. L. Davidson, (Ed), et al., ANC: Westinghouse Advanced Nodal Computer Code, WCAP-10965-P-A, September 1986.
- 27. T. Q. Nguyen, et al, Qualification of the PHOENIX-P/ANC Nuclear Design System for Pressurized Water Reactor Cores, WCAP-11596-P-A, June 1988.
- 28. C. M. Mildrum, L. T. Mayhue, M. M. Baker and P. G. Issac, Qualification of the PHOENIX/POLCA Nuclear Design and Analysis Program for Boiling Water Reactors, WCAP-10841 Proprietary and WCAP-10842 (Non-Proprietary), June 1985. 29. WCAP-10216-P-A, Relaxation of Constant Axial Offset Control FQ Surveillance Technical Specification, June 1983 (Westinghouse Proprietary).
DCPP UNITS 1 & 2 FSAR UPDATE 4.3-40 Revision 21 September 2013 30. WCAP-9272-P-A, Westinghouse Reload Safety Evaluation Methodology, July 1985 (Westinghouse Proprietary).
- 31. Kersting, P. J., et al., Assessment of Clad Flattening and Densification Power Spike Factor Elimination in Westinghouse Nuclear Fuel, WCAP-13589-A (Proprietary), March 1995, and WCAP-14297-A (Non-Proprietary), March 1995.
- 32. WCAP-12472-P-A, BEACON Core Monitoring and Operations Support System, August 1994 (Westinghouse Proprietary).
- 33. WCAP-12472-P-A, Addendum 1-A, BEACON Core Monitoring and Operations Support System, January 2000 (Westinghouse Proprietary).
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-1 Revision 21 September 2013 4.4 THERMAL AND HYDRAULIC DESIGN This section discusses the thermal and hydraulic design of the DCPP reactors. 4.4.1 DESIGN BASES The objective of the thermal and hydraulic design of the reactor core is to provide adequate heat transfer that is compatible with the heat generation distribution in the core, so that heat removal by the RCS or the emergency core cooling system (ECCS) (when applicable) meets the following performance and safety criteria:
(1) Fuel damage(a) is not expected during normal operation and operational transients (Condition I) or any transient conditions arising from faults of moderate frequency (Condition II). It is not possible, however, to preclude a very small number of rod failures. These will be within the capability of the plant cleanup system and are consistent with the plant design bases. (2) The reactor can be brought to a safe state following a Condition III event with only a small fraction of fuel rods damaged(a) although sufficient fuel damage might occur to preclude resumption of operation without considerable outage time. (3) The reactor can be brought to a safe state and the core can be kept subcritical with acceptable heat transfer geometry following transients arising from Condition IV events.
Accordingly, the following design bases have been established for the thermal and hydraulic design of the reactor core. 4.4.1.1 Departure from Nucleate Boiling Design Basis 4.4.1.1.1 Basis Departure from nucleate boiling (DNB) will not occur on at least 95 percent of the limiting fuel rods during normal operation and operational transients and any transient conditions arising from faults of moderate frequency (Conditions I and II events) at a 95 percent confidence level.
This criterion has been conservatively met by adhering to the following thermal design basis: there must be at least a 95 percent probability that the minimum departure from nucleate boiling ratio (DNBR) of the limiting power rod during Condition I and II events is greater than or equal to the DNBR limit of the DNB correlation being used. The DNBR limit for the correlation is established based on the variance of the correlation such that (a) Fuel damage as used here is defined as penetration of the fission product barrier (i.e., the fuel rod cladding). DCPP UNITS 1 & 2 FSAR UPDATE 4.4-2 Revision 21 September 2013 there is a 95 percent probability with 95 percent confidence that DNB will not occur when the calculated DNBR is at the DNBR limit. 4.4.1.1.2 Discussion Historically, this DNBR limit has been 1.30 for Westinghouse applications. In this application the WRB-1 correlation (Reference 84) for LOPAR fuel and the WRB-2 correlation (Reference 85) for VANTAGE 5 fuel are employed. With the significant improvement in the accuracy of the critical heat flux prediction by using these correlations instead of previous DNB correlations, a DNBR limit of 1.17 is applicable in this application.
The design method employed to meet the DNB design basis is the "Improved Thermal Design Procedure" (Reference 86). Uncertainties in plant operating parameters, nuclear and thermal parameters, and fuel fabrication parameters are considered statistically such that there is at least a 95 percent probability that the minimum DNBR will be greater than or equal to 1.17 for the limiting power rod. Plant parameter uncertainties are used to determine the plant DNBR uncertainties. These DNBR uncertainties, combined with the DNBR limit, establish a design DNBR value, which must be met in plant safety analyses. Since the parameter uncertainties are considered in determining the design DNBR value, the plant safety analyses are performed using values of input parameters without uncertainties.
This design procedure is illustrated in Figure 4.4-18. For this application, the minimum required DNBR values for the LOPAR fuel analysis are a 1.34 for thimble cold wall cells (three fuel rods and a thimble tube) and 1.38 for typical cell (four fuel rods). The design DNBR values for the VANTAGE 5 fuel are a 1.32 and 1.34 for thimble and typical cells, respectively.
In addition to the above considerations, a plant-specific DNBR margin has been considered in the analyses. In particular, safety analysis DNBR limits of 1.44 for thimble and 1.48 for typical cells for LOPAR fuel, and 1.68 and 1.71 for thimble and typical cells respectively for the VANTAGE 5 fuel, were employed in the safety analyses. The plant allowance available between the DNBRs used in the safety analyses and the design DNBR values is not required to meet the design basis discussed earlier. This allowance will be used for the flexibility in the design, operation, and analyses of DCPP.
By preventing DNB, adequate heat transfer is ensured between the fuel cladding and the reactor coolant, thereby preventing cladding damage. Maximum fuel rod surface temperature is not a design basis because it will be within a few degrees of coolant temperature during operation in the nucleate boiling region. Limits provided by the nuclear control and protection systems are such that this design basis will be met for transients associated with Condition II events including overpower transients. The DNBR margin at rated power operation and during normal operating transients is substantially larger (see Table 4.1-1). DCPP UNITS 1 & 2 FSAR UPDATE 4.4-3 Revision 21 September 2013 4.4.1.2 Fuel Temperature Design Basis 4.4.1.2.1 Basis During Conditions I and II modes of operation, the maximum fuel temperature shall be less than the melting temperature of UO2. The UO2 melting temperature for at least 95 percent of the peak kW/ft fuel rods will not be exceeded at the 95 percent confidence level. The melting temperature of UO2 is taken as 5080°F (Reference 1) unirradiated, and decreasing 58°F per 10,000 megawatt days per metric ton of uranium (MWD/MTU). By precluding UO2 melting, the fuel geometry is preserved and possible adverse effects of molten UO2 on the cladding are eliminated. To preclude center melting and establish overpower protection system setpoints, a calculated centerline fuel temperature of 4700°F has been selected as the overpower limit, thus providing sufficient margin for uncertainties. The peak linear power value used in the design evaluation is 22.0 kW/ft. This value corresponds to a peak centerline temperature which is less than 4700°F. 4.4.1.2.2 Discussion Fuel rod thermal evaluations are performed at rated power, maximum overpower, and during transients at various burnups. These analyses ensure that this design basis, as well as the fuel integrity design bases given in Section 4.2, are met. They also provide input for the evaluation of Conditions III and IV faults given in Chapter 15. 4.4.1.3 Core Flow Design Basis 4.4.1.3.1 Basis A minimum of 92.5 percent of the thermal flowrate (see Section 5.1) will pass through the fuel rod region of the core and be effective for fuel rod cooling. Coolant flow through the thimble tubes, as well as leakage from the core barrel-baffle region into the core, is not effective for heat removal. 4.4.1.3.2 Discussion Core cooling evaluations are based on the thermal flowrate (minimum flow) entering the reactor vessel. A maximum of 7.5 percent of this value is allotted as bypass flow. This includes rod cluster control (RCC) guide thimble cooling flow, head cooling flow, baffle leakage and leakage to the vessel outlet nozzle, and flow in the gaps between the peripheral assemblies and the baffle wall. 4.4.1.4 Hydrodynamic Stability Design Bases 4.4.1.4.1 Basis Modes of operation associated with Conditions I and II events shall not lead to hydrodynamic instability. DCPP UNITS 1 & 2 FSAR UPDATE 4.4-4 Revision 21 September 2013 4.4.1.5 Other Considerations The above design bases, together with the fuel cladding and fuel assembly design bases given in Section 4.2.1.1, are sufficient. Fuel cladding integrity criteria cover possible effects of cladding temperature limitations. As noted in Section 4.2.1.3.1, the fuel rod conditions change with time. A single cladding temperature limit for Conditions I or II events is not appropriate since of necessity it would be overly conservative. A cladding temperature limit is applied to the loss-of-coolant accident (LOCA) (Section 15.4.1), control rod ejection accident (Reference 2), and locked rotor accident (Reference 67). 4.4.2 DESCRIPTION 4.4.2.1 Summary Comparison The core design parameters of the DCPP Units 1 and 2 reactors are presented in Table 4.1-1.
The reactor core is designed to a minimum DNBR greater than or equal to the design limit DNBR as well as no fuel centerline melting during normal operation, operational transients, and faults of moderate frequency. 4.4.2.2 Fuel Cladding Temperatures A discussion of fuel cladding integrity is presented in Section 4.2.1.3.1. The thermal-hydraulic design ensures that the maximum fuel pellet temperature is below the melting point of UO2 (see Section 4.4.1.2). To preclude center melting and establish overpower protection system setpoints, a calculated centerline fuel temperature of 4700°F has been selected as the overpower limit. The temperature distribution within the fuel pellet is predominantly a function of the local power density and UO2 thermal conductivity. However, the computation of radial fuel temperature distributions combines crud, oxide, cladding, gap, and pellet conductances. The factors that influence these conductances, such as gap size (or contact pressure), internal gas pressure, gas composition, pellet density, and radial power distribution within the pellet, etc., have been combined into a semiempirical thermal model (see Section 4.2.1.3.1) with modifications for time-dependent fuel densification (Reference 68). The temperature predictions have been compared to incore fuel temperature measurements (References 3 through 9) and melt radius data (References 10 and 11) with good results. 4.4.2.2.1 Effect of Fuel Densification on Fuel Rod Temperatures Fuel densification results in fuel pellet shrinkage. This affects the fuel temperatures in the following ways:
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-5 Revision 21 September 2013 (1) Pellet radial shrinkage increases the pellet diametral gap that results in increased thermal resistance of the gap and thus higher fuel temperatures (see Section 4.2.1.3.1). (2) Pellet axial shrinkage may produce pellet-to-pellet gaps that result in local power spikes, described in Section 4.3.2.2.1, and thus higher total heat flux hot channel factor, FTQ and local fuel temperatures. (3) Pellet axial shrinkage results in a fuel stack height reduction and an increase in the linear power generation rate (kW/ft) for a constant core power level. Using the methods of Reference 68, the increase in linear power for the fuel rod specifications listed in Table 4.1-1 is 0.2 percent. Fuel rod thermal parameters (fuel centerline, average, and surface temperatures) are determined throughout its lifetime considering time-dependent densification. Maximum fuel average and surface temperatures, shown in Figure 4.4-1 as a function of linear power density (kW/ft), are peak values attained during the fuel lifetime. Similarly, Figure 4.4-2 presents the peak value of fuel centerline temperature versus linear power density, attained during its lifetime.
The maximum pellet temperature at the hot spot during full power steady state and at the maximum overpower T trip point is shown in Table 4.1-1 for Units 1 and 2. The principal factors employed in fuel temperature determinations are discussed below. 4.4.2.2.2 UO2 Thermal Conductivity The thermal conductivity of UO2 was evaluated from data reported in References 12 through 24.
At the higher temperatures, thermal conductivity is best obtained by utilizing the integral conductivity to melt, which can be determined with more certainty. From an examination of the data, it has been concluded that the best estimate for the value of kdTC28000 is 93 watts/cm. This conclusion is based on the integral values reported in References 10 and 24 through 28. The design curve for the thermal conductivity is shown in Figure 4.4-3. The section of the curve at temperatures between 0 and 1300°C is in excellent agreement with the recommendation of the IAEA panel (Reference 29). The section of the curve above 1300°C is derived from an integral value of 94 watts/cm (References 10, 24 and 28).
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-6 Revision 21 September 2013 Thermal conductivity for UO2 at 95 percent theoretical density can be represented best by the following equation:
()313T108.7750.0238T11.81kx++= (4.4-1) where:
k is in watts/cm-°C, and T is in °C 4.4.2.2.3 Radial Power Distribution in UO2 Fuel Rods An accurate radial power distribution as a function of burnup is needed to determine the power level for incipient fuel melting and other important performance parameters, e.g., pellet thermal expansion, fuel swelling, and fission gas release rates.
This UO2 fuel rods radial power distribution is determined with the neutron transport theory LASER (Reference 81) code that has been validated by comparing code predictions on radial burnup and isotopic distributions with measured radial microdrill data(a) (References 30 and 31). A "radial power depression factor," f, is determined using radial power distribution predicted by LASER. The factor f enters into the determination of the pellet centerline temperature, Tc, relative to the pellet surface temperature, Ts, through the expression: 4fq'dTk(T)cTsT= (4.4-2) where: k(T) = the thermal conductivity for UO2 with a uniform density distribution q' = the linear power generation rate 4.4.2.2.4 Gap Conductance The temperature drop across the pellet-cladding gap is a function of the gap size and the thermal conductivity of the gas in the gap. The gap conductance model is selected such that when combined with the UO2 thermal conductivity model, the calculated fuel centerline temperatures reflect the inpile temperature measurements.
(a) "Microdrill data" are data obtained from the physical examination of irradiated pellets in a hot cell. Small core samples are removed from different radial positions in a pellet (using a "microdrill"). Isotopic measurements of the fuel samples determine actual UO2 burnups at the sample points.
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-7 Revision 21 September 2013 The temperature drop across the gap is calculated by assuming an annular gap conductance mode of the following form: 610x14.4/2MgasKh+= (4.4-3) or an empirical correlation derived from thermocouple and melt radius data: 120.0064.0gasK1500h++= (4.4-4) where: h = thermal gap conductance, Btu/hr-ft2-°F gasK= thermal conductivity of the gas mixture including a correction factor (Reference 32) for the accommodation coefficient for light gases (e.g., helium), Btu/hr-ft-°F = diametral gap size, ft M = gap multiplication factor (Reference 83) The larger gap conductance value from these two equations is used to calculate the temperature drop across the gap for finite gaps.
For evaluations in which the pellet-cladding gap is closed, a contact conductance is calculated. The contact conductance between UO2 and Zircaloy has been measured and found to be dependent on the contact pressure, composition of the gas at the interface, and the surface roughness (References 32 and 33). This information, together with the surface roughness found in Westinghouse fuels, leads to the following correlation: 610x14.4gasK0.6Ph+= (4.4-5) where: h = contact conductance, Btu/hr-ft2-°F P = contact pressure, psi 4.4.2.2.5 Surface Heat Transfer Coefficients The fuel rod surface heat transfer coefficients during subcooled forced convection and the outer cladding wall temperature for the onset of nucleate boiling is presented in Section 4.4.2.8.1. DCPP UNITS 1 & 2 FSAR UPDATE 4.4-8 Revision 21 September 2013 4.4.2.2.6 Fuel Cladding Temperatures The fuel rod outer surface at the hot spot operates at a temperature of approximately 660°F for steady state operation at rated power throughout core life, due to the onset of nucleate boiling. At beginning of life (BOL), this temperature is that of the cladding metal outer surface.
During operation over the life of the core, the buildup of oxides and crud on the fuel rod cladding outer surface causes the cladding surface temperature to increase. Allowance is made in the fuel center melt evaluation for this temperature rise. The thermal-hydraulic DNB limits ensure that adequate heat transfer is provided between the fuel cladding and the reactor coolant so that cladding temperature does not limit core thermal output. Figure 4.4-4 shows the axial variation of average cladding temperature for the average power rod both at beginning and end of life (EOL). 4.4.2.2.7 Treatment of Peaking Factors The total heat flux hot channel factor, FTQ, is defined by the ratio of the maximum to core average heat flux. The design value of FTQ for normal operation is 2.58 including fuel densification effects as shown in Table 4.3-1. This results in a peak local linear power density of 14.3 kW/ft at full power. The corresponding peak local power at the maximum overpower trip point (118 percent total power) is 16.6 kW/ft. Centerline temperature at this kW/ft must be below the UO2 melt temperature over the lifetime of the rod including allowances for uncertainties. From Figure 4.4-2, the centerline temperature at the maximum overpower trip point is well below that required to produce melting. Fuel centerline and average temperature at rated (100 percent) power and at the maximum overpower trip point for Units 1 and 2 are presented in Table 4.1-1. 4.4.2.3 Departure from Nucleate Boiling Ratio The minimum DNBRs for the rated power, and anticipated transient conditions are given in Table 4.1-1 for Units 1 and 2. The minimum DNBR in the limiting flow channel will occur downstream of the peak heat flux location (hot spot) due to the increased downstream enthalpy rise.
DNBRs are calculated by using the correlation and definitions described in Section 4.4.2.3.1. The THINC-IV (Reference 47) computer code (discussed in Section 4.4.3.4.1) determines the flow distribution in the core and the local conditions in the hot channel for use in the DNB correlation. The use of hot channel factors is discussed in Section 4.4.3.2.1 (nuclear hot channel factors) and in Section 4.4.2.3.4 (engineering hot channel factors). 4.4.2.3.1 Departure from Nucleate Boiling Technology The W-3 correlation, and several modifications, have been used in Westinghouse critical heat flux (CHF) calculations. The W-3 was originally developed from single tube DCPP UNITS 1 & 2 FSAR UPDATE 4.4-9 Revision 21 September 2013 data (Reference 34), but was subsequently modified to apply to the 0.422 inch, OD rod "R"-grid (Reference 35) and "L"-grid (Reference 36), as well as the 0.374 inch OD (References 37 and 38) rod bundle data. These modifications to the W-3 correlation have been demonstrated to be adequate for reactor rod bundle design.
A description of the 17 x 17 fuel assembly test program and a summary of the results are described in detail in Reference 37.
Figure 4.4-5 shows the data obtained in this test program. The test results indicate that a reactor core using this geometry may operate with a minimum DNBR of 1.28 and satisfy the design criterion.
The WRB-1 correlation (Reference 84) as developed based exclusively on the large bank of mixing vane grid rod bundle CHF data (over 1100 points) that Westinghouse has collected. The WRB-1 correlation, based on local fluid conditions, represents the rod bundle data with better accuracy over the wide range of variables than the previous correlation used in design. This correlation accounts directly for both typical and thimble cold wall cell effects, uniform and nonuniform heat flux profiles, and variations in rod heated length and in grid spacing.
Figure 4.4-19 shows measured critical heat flux plotted against predicted critical heat flux using the WRB-1 correlation.
Critical heat flux tests which model the 17x17 optimized fuel assembly have been performed with the results described in detail in Reference 87. It was concluded that the CHF characteristics of the 17x17 optimized fuel assembly design are not significantly different from those of 17x17 LOPAR design, and can be adequately described by the "R" grid form of the WRB-1 CHF correlation. Furthermore, the new data can be incorporated into the "R" grid data base such that the WRB-1 correlation can be applied to 17x17 LOPAR fuel design without changing the DNBR design criterion of 1.17.
The WRB-2 DNB correlation (Reference 85) was developed to take credit for the VANTAGE 5 fuel assembly mixing vane design. A DNBR limit of 1.17 is also applicable for the WRB-2 correlations. Figure 4.4-20 shows measured critical heat flux plotted against predicted critical heat flux using the WRB-2 correlation. 4.4.2.3.2 Definition of Departure from Nucleate Boiling Ratio The DNBR, as applied to this design for both typical and thimble cold wall cells is:
"actual"Predicted DNB,qqDNB= (4.4-6)
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-10 Revision 21 September 2013 For the W-3 (R-Grid) correlation, FFq'""S3WEU,PredictedDNB,qx= (4.4-7) when all flow cell walls are heated and q" EU, W-3 is the uniform DNB heat flux as predicted by W-3 DNB correlation and F is the flux shape factor which accounts for nonuniform axial heat flux distributions (Reference 39) with the "C" term modified as in Reference 34. F'S is the modified spacer factor described in Reference 37 using an axial grid spacing coefficient, KS = 0.046, and a thermal diffusion coefficient (TDC) of 0.038, based on the 26-inch grid spacing data. Since the actual grid spacing is approximately 20 inches, these values are conservative since the DNB performance was found to improve and TDC increase as axial grid spacing is decreased (References 35 and 40).
When a cold wall is present for the W-3 correlation,
'F"q"qSCW3,WEU,PredictedDNB,x= (4.4-8) where:
CWFF"q"qDhe,WEU,CW3,WEU,x= (4.4-8A) "Dh3,WEU,q is the uniform DNB heat flux as predicted by the W-3 cold wall correlation (Reference 34) when not all flow cell walls are heated (thimble cold wall cell). The cold wall factor (CWF) is provided in References 34 and 39. For the WRB-1 and WRB-2 correlations, Fq"1WRBPredictedDNB,"q= for WRB1 correlation (4.4-9) Fq"2WRB= for WRB2 correlation (4.4-9A) where:
F is the same flux shape factor that is used with the W-3 correlation.
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-11 Revision 21 September 2013 4.4.2.3.3 Mixing Technology The rate of heat exchange by mixing between flow channels is proportional to the difference in the local mean fluid enthalpy of the respective channels, the local fluid density, and the flow velocity. The proportionality is expressed by the dimensionless TDC, which is defined as: Vaw'TDC= (4.4-10) where: w' = flow exchange rate per unit length, lbm/ft-sec = fluid density, 1bm/ft3 V = fluid velocity, ft/sec a = lateral flow area between channels per unit length, ft2/ft The application of the TDC in the THINC analysis for determining the overall mixing effect or heat exchange rate is presented in Reference 41.
The TDC is determined by comparing the THINC code predictions with the measured subchannel exit temperatures. Data for 26-inch axial grid spacing are presented in Figure 4.4-6 where the TDC is plotted versus the Reynolds number. The TDC is found to be independent of the Reynolds number, mass velocity, pressure, and quality over the ranges tested.
The two-phase data (local and subcooled boiling) fell within the scatter of the single-phase data. The effect of two-phase flow on the value of TDC has been demonstrated by Cadek (Reference 40), Rowe and Angle (References 42 and 43), and Gonzalez-Santalo and Griffith (Reference 44). In the subcooled boiling region, the values of TDC were indistinguishable from the single-phase values. In the quality region, Rowe and Angle show that in the case with rod spacing similar to that in PWR reactor core geometry, the value of TDC increased with quality to a point and then decreased but never below the single-phase value. Gonzalez-Santalo and Griffith showed that the mixing coefficient increased as the void fraction increased.
The data from these tests on the R grid showed that a design TDC value of 0.038 (for 26 inch grid spacing) can be used in determining the effect of coolant mixing in the THINC analysis. A mixing test program similar to the one described above was conducted at Columbia University for the 17 x 17 geometry and mixing vane grids on 26-inch spacing (Reference 45). The mean value of TDC obtained from these tests was 0.059, and all data were well above the current design value of 0.038.
Because the reactor grid spacing is approximately 20 inches, additional margin is available for this design, as the value of TDC increases as grid spacing decreases (Reference 40). DCPP UNITS 1 & 2 FSAR UPDATE 4.4-12 Revision 21 September 2013 The inclusion of three intermediate flow mixer (IFM) grids in the upper span of the VANTAGE 5 fuel assembly results in a grid spacing of approximately 10 inches. Therefore, the design value of 0.038 for TDC is a conservatively low value for use in VANTAGE 5 to determine the effect of coolant mixing in the core thermal performance analysis. 4.4.2.3.4 Hot Channel Factors The total hot channel factors for heat flux and enthalpy rise are defined as the maximum-to-core average ratios of these quantities. The heat flux hot channel factor considers the local maximum linear heat generation rate at a point (the "hot spot"), and the enthalpy rise hot channel factor involves the maximum integrated value along a channel (the "hot channel").
Each of the total hot channel factors considers a nuclear hot channel factor (see Section 4.4.3.2) describing the neutron power distribution and an engineering hot channel factor, which allows for variations in flow conditions and fabrication tolerances. The engineering hot channel factors are made up of subfactors that account for the influence of the variations of fuel pellet diameter, density, enrichment and eccentricity; fuel rod diameter pitch and bowing; inlet flow distribution; flow redistribution; and flow mixing. 4.4.2.3.4.1 Heat Flux Engineering Hot Channel Factor, FEQ The heat flux engineering hot channel factor is used to evaluate the maximum heat flux. This subfactor is determined by statistically combining the tolerances for the fuel pellet diameter, density, enrichment, eccentricity, and the fuel rod diameter, and has a value of 1.03. Measured manufacturing data on Westinghouse fuel verify that this value was not exceeded for 95 percent of the limiting fuel rods at a 95 percent confidence level. As shown in Reference 99, no DNB penalty need be taken for the short, relatively low intensity heat flux spikes caused by variations in the above parameters. 4.4.2.3.4.2 Enthalpy Rise Engineering Hot Channel Factor, FEH The effect of variations in flow conditions and fabrication tolerances on the hot channel enthalpy rise is directly considered in the THINC core thermal subchannel analysis (see Section 4.4.3.4.1) under any reactor operating condition. The following items contribute to the enthalpy rise engineering hot channel factor:
(1) Pellet Diameter, Density and Enrichment, Fuel Rod Diameter, Pitch, and Bowing Design values employed in the THINC analysis are based on applicable limiting tolerances such that design values are met for 95 percent of the limiting channels at a 95 percent confidence level. The effect of variations in pellet diameter and enrichment is employed in the THINC analysis as a DCPP UNITS 1 & 2 FSAR UPDATE 4.4-13 Revision 21 September 2013 direct multiplier on the hot channel enthalpy rise, while the fuel rod diameter, pitch, and bowing variation, including incore effects, enter in the preparation of the THINC input values. (2) Inlet Flow Maldistribution Inlet flow maldistribution in the core thermal performances is discussed in Section 4.4.3.1.2. A design basis of 5 percent reduction in coolant flow to the hot assembly is used in the THINC-IV analysis. (3) Flow Redistribution The flow redistribution accounts for the flow reduction in the hot channel resulting from the high flow resistance in the channel due to the local or bulk boiling. The effect of the nonuniform power distribution is inherent to the THINC analysis. (4) Flow Mixing The subchannel mixing model incorporated in the THINC code and used in reactor design is based on experimental data (Reference 46), as discussed in Section 4.4.3.4.1. The mixing vanes incorporated in the spacer grid design induce additional flow mixing between the various flow channels in a fuel assembly, as well as between adjacent assemblies.
This mixing reduces the enthalpy rise in the hot channel resulting from local power peaking or unfavorable mechanical tolerances. 4.4.2.3.5 Effects of Rod Bow on DNBR The phenomenon of fuel rod bowing, as described in Reference 79, must be accounted for in the DNBR safety analysis of Condition I and Condition II events for each plant application. Applicable generic credits for margin resulting from retained conservatism in the evaluation of DNBR and/or margin obtained from measured plant operating parameters (such as FNH or core flow), which are less limiting than those required by the plant safety analysis, can be used to offset the effect of rod bow. The safety analysis for Diablo Canyon cores maintains sufficient margin between the safety analysis DNBR limits and the design DNBR limits and the design DNBR limits as shown below to accommodate full flow and low flow DNBR penalties identified in Reference 80, which are applicable to 17x17 LOPAR and VANTAGE 5 fuel assembly analysis utilizing the WRB-1 and WRB-2 correlations, respectively.
However, for the upper assembly span of VANTAGE 5 fuel where additional restraint is provided with the Intermediate Flow Mixer (IFM) grids, the grid-to-grid spacing in DNB limiting span is approximately 10 inches compared to approximately 20 inches in the LOPAR. Using the rod bow topical report methods (Reference 88), and scaling with the DCPP UNITS 1 & 2 FSAR UPDATE 4.4-14 Revision 21 September 2013 NRC approved factor results in predicted channel closure in the limiting spans of less than 50 percent closure; therefore, no rod bow DNBR penalty is required in the 10 inch spans in the VANTAGE 5 safety analyses.
LOPAR VANTAGE 5 Design Limit Typical Cell 1.38 1.34 Thimble Cell 1.34 1.32
Safety Limit Typical Cell 1.48 1.71 Thimble Cell 1.44 1.68
The maximum rod bow penalties accounted for in the design safety analysis are based on an assembly average burnup of 24,000 MWD/MTU based on Reference 88. At burnups greater than 24,000 MWD/MTU, credit is taken for the effect of FNH burndown. Due to the decrease in fissionable isotopes and the buildup of fission product inventory, no additional rod bow penalty is required. 4.4.2.3.6 Transition Core The Westinghouse transition core DNB methodology is given in References 89 and 90 and has been approved by the NRC via Reference 91. Using this methodology, transition cores are analyzed as if they were full cores of one assembly type (full LOPAR or full VANTAGE 5), applying the applicable transition core penalties. This penalty was included in the safety analysis limit DNBRs such that sufficient margin over the design limit DNBR existed to accommodate the transition core penalty and the appropriate rod bow DNBR penalty. However, since the transition to a full VANTAGE 5 core has been completed, various analyses, such as large break and small loss of coolant accident analysis, have assumed a full VANTAGE 5 core and no longer assume a transition core penalty.
The LOPAR and VANTAGE 5 designs have been shown to be hydraulically compatible in Reference 85. 4.4.2.4 Flux Tilt Considerations Significant quadrant power tilts are not anticipated during normal operation since this phenomenon is caused by asymmetric perturbations. A dropped or misaligned RCCA could cause changes in hot channel factors. These events are analyzed separately in Chapter 15.
Other possible causes for quadrant power tilts include X-Y xenon transients, inlet temperature mismatches, enrichment variations within tolerances, and so forth.
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-15 Revision 21 September 2013 In addition to unanticipated quadrant power tilts, other readily explainable asymmetries may be observed during calibration of the excore detector quadrant power tilt alarm. During operation, at least one power distribution measurement is taken per effective-full-power month. Each of these power distribution measurements is reviewed for deviations from the expected power distributions. The acceptability of an observed asymmetry, planned or otherwise, depends solely on meeting the required accident analyses assumptions. In practice, once acceptability has been established by review of the power distribution measurements, the quadrant power tilt alarms and related instrumentation are adjusted to indicate zero quadrant tilt, 1.00 quadrant power tilt ratio, as the final step in the calibration process. Proper functioning of the quadrant power tilt alarm is significant because no allowances are made in the design for increased hot channel factors due to unexpected developing flux tilts since all likely causes are prevented by design or procedures or specifically analyzed. Finally, in the event that unexplained flux tilts do occur, the Technical Specification (Reference 82) stipulates appropriate corrective actions to ensure continued safe operation of the reactor. 4.4.2.5 Void Fraction Distribution The calculated core average and the hot subchannel maximum and average void fractions are presented in Tables 4.4-1 and 4.4-2 for operation at full power with design hot channel factors for Units 1 and 2, respectively. The void fraction distribution in the core is presented in Reference 47. The void fraction as a function of thermodynamic quality is shown in Figure 4.4-10. The void models used in the THINC-IV computer code are described in Section 4.4.2.8.3. 4.4.2.6 Core Coolant Flow Distribution Coolant enthalpy rise and flow distributions are shown for the 4-foot elevation (1/3 of core height) in Figure 4.4-7, 8-foot elevation (2/3 of core height) in Figure 4.4-8, and at the core exit in Figure 4.4-9. These distributions correspond to a representative Westinghouse 4-loop plant. The THINC code analysis for this case utilized a uniform core inlet enthalpy and inlet flow distribution. 4.4.2.7 Core Pressure Drops and Hydraulic Loads 4.4.2.7.1 Core Pressure Drops The analytical model and experimental data used to calculate the pressure drops, for the full power conditions given in Table 4.4-1, are described in Section 4.4.2.8.2. The core pressure drop consists of the fuel assembly, lower core plate, and upper core plate pressure drops. These pressure drops are based on the best estimate flow, as described in Section 5.1.5. Section 5.1.5 also defines the thermal design flow (minimum flow), which is the basis for reactor core thermal performance, and the mechanical design flow (maximum flow), which is used in the mechanical design of the reactor vessel internals and fuel assemblies. Since the best estimate flow is that which is most likely to exist in an operating plant, the calculated core pressure drops in DCPP UNITS 1 & 2 FSAR UPDATE 4.4-16 Revision 21 September 2013 Table 4.1-1 are greater than pressure drops previously quoted using the thermal design flow. The relation between best estimate flow, thermal design flow, and mechanical design flow is illustrated in Figure 5.1-2. 4.4.2.7.2 Hydraulic Loads The fuel assembly holddown springs, Figure 4.2-2, are designed to keep the fuel assemblies resting on the lower core plate under transients associated with Conditions I and II events. Maximum flow conditions are limiting because hydraulic loads are a maximum. The most adverse flow conditions occur during a LOCA, as discussed in Section 15.4.1.
Hydraulic loads at normal operating conditions are calculated based on the best estimate flow and best estimate core bypass flow. Core hydraulic loads at cold plant startup conditions are also based on this flow, but are adjusted to account for the coolant density difference. Conservative core hydraulic loads for a pump overspeed transient, that create flowrates 18 percent greater than the best estimate flow, are evaluated to be greater than twice the fuel assembly weight.
The hydraulic verification tests are discussed in Reference 48. 4.4.2.8 Correlation and Physical Data 4.4.2.8.1 Surface Heat Transfer Coefficients Forced convection heat transfer coefficients are obtained from the familiar Dittus-Boelter correlation (Reference 49), with the properties evaluated at bulk fluid conditions: 0.4kpC0.8mGeD0.023kehD= (4.4-11) where: h = heat transfer coefficient, Btu/hr-ft2-°F De = equivalent diameter, ft k = thermal conductivity, Btu/hr-ft-°F G = mass velocity, lb/hr-ft2 µ = dynamic viscosity, lb/ft-hr Cp = heat capacity, Btu/lb-°F This correlation has been shown to be conservative (Reference 50) for rod bundle geometries with pitch-to-diameter ratios in the range used by PWRs.
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-17 Revision 21 September 2013 The onset of nucleate boiling occurs when the cladding wall temperature reaches the amount of superheat predicted by Thom's (Reference 51) correlation. After this occurrence, the outer cladding wall temperature is determined by: Tsat = [0.072 exp (-P/1260)] (q")0.5 (4.4-12) where: TSAT = wall superheat, Tw - Tsat, °F q" = wall heat flux, Btu/hr-ft2 P = pressure, psia Tw = outer cladding wall temperature, °F TSAT = saturation temperature of coolant at P, °F 4.4.2.8.2 Total Core and Vessel Pressure Drop Pressure losses occur as a result of viscous drag (friction) and/or geometry changes (form) in the fluid flowpath. The flow field is assumed to be incompressible, turbulent, single-phase water. Two-phase considerations are neglected in the vessel pressure drop evaluation because the core average void is negligible (see Section 4.4.2.5 and Tables 4.4-1 and 4.4-2).
Two-phase flow considerations in the core thermal subchannel analyses are considered and the models are discussed in Section 4.4.3.1.3. Core and vessel pressure losses are calculated by equations of the form:
(144)c2g2VeDFLKLP+= (4.4-13) where:
PL = pressure drop, lbf/in2 = fluid density, 1bm/ft3 L = length, ft De = equivalent diameter, ft V = fluid velocity, ft/sec gc = 2secf1bftm1b32.174 K = form loss coefficient, dimensionless F = friction loss coefficient, dimensionless Fluid density is assumed to be constant at an appropriate value for each component in the core and vessel. Because of the complex core and vessel flow geometry, precise DCPP UNITS 1 & 2 FSAR UPDATE 4.4-18 Revision 21 September 2013 analytical values for the form and friction loss coefficients are not available. Therefore, experimental values for these coefficients are obtained from geometrically similar models.
The results of full-scale tests of core components and fuel assemblies were utilized in developing the core pressure loss characteristics. The pressure drop for the vessel was obtained by combining the core pressure loss with correlation of 1/7th scale model hydraulic test data on a number of vessels (References 52 and 53) and form loss relationships (Reference 54). Moody (Reference 55) curves were used to obtain the single-phase friction factors.
Tests of the primary coolant loop flowrates are made (see Section 4.4.4.1) prior to initial criticality to verify that the flowrates used in the design are conservative. 4.4.2.8.3 Void Fraction Correlation Three separate void regions are considered in flow boiling in a PWR as illustrated in Figure 4.4-10. They are the wall void region (no bubble detachment), the subcooled boiling region (bubble detachment), and the bulk boiling region.
In the wall void region, local boiling begins at the point where the cladding temperature reaches the amount of superheat predicted by Thom's (Reference 51) correlation (discussed in Section 4.4.2.8.1). The void fraction in this region is calculated using Maurer's (Reference 56) relationship. The bubble detachment point, where the superheated bubbles break away from the wall, is determined by using Griffith's (Reference 57) relationship. The void fraction in the subcooled boiling region (i.e., after the detachment point) is calculated from the Bowring (Reference 58) correlation. This correlation predicts the void fraction from the detachment point to the bulk boiling region.
The void fraction in the bulk boiling region is predicted by using homogeneous flow theory and assuming no slip. The void fraction in this region is, therefore, a function of steam quality only. 4.4.2.9 Thermal Effects of Operational Transients DNB core safety limits are expressed as a function of coolant temperature, pressure, core power, and axial power imbalance. Steady state operation within these safety limits ensures that the minimum DNBR is not less than the safety limit DNBR.
Figure 15.1-1 shows lines at the safety limit DNBR and the resulting overtemperature T trip lines (which are part of the Technical Specifications), plotted as T versus T-average for various pressures. This system provides adequate protection against anticipated operational transients that are slow with respect to fluid transport delays in the primary system. In addition, for fast transients (e.g., uncontrolled rod bank DCPP UNITS 1 & 2 FSAR UPDATE 4.4-19 Revision 21 September 2013 withdrawal at power incident (Section 15.2.2), specific protection functions are provided as described in Section 7.2; their use is described in Chapter 15 (see Table 15.1-2). Fuel rod thermal response is discussed in Section 4.4.3.7. 4.4.2.10 Uncertainties in Estimates 4.4.2.10.1 Uncertainties in Fuel and Cladding Temperatures As discussed in Section 4.4.2.2, the fuel temperature is a function of crud, oxide, cladding, gap, and pellet conductances. Uncertainties in the fuel temperature calculation are essentially of two types: fabrication uncertainties, such as variations in the pellet and cladding dimensions and the pellet density; and model uncertainties, such as variations in the pellet conductivity and the gap conductance. These uncertainties have been quantified by comparison of the thermal model to the incore thermocouple measurements (References 3 through 9), by out-of-pile measurements of the fuel and cladding properties (References 12 through 23), and by measurements of the fuel and cladding dimensions during fabrication. The effect of densification on fuel temperature uncertainties is presented in Reference 68.
In addition, the measurement uncertainty in determining the local power, and the effect of density and enrichment variations on local power, are considered in establishing the heat flux hot channel factor.
Uncertainty in determining cladding temperature results from uncertainties in the crud and oxide thickness. Because of the excellent heat transfer between the surface of the rod and the coolant, the film temperature drop does not appreciably contribute to the uncertainty. Reactor trip setpoints, as specified in the Technical Specifications, include allowance for instrument and measurement uncertainties such as calorimetric error, instrument drift, and channel reproducibility. 4.4.2.10.2 Uncertainties in Pressure Drops Core and vessel pressure drops based on the best estimate flow, as described in Section 5.1, are quoted in Table 4.1-1. The uncertainties quoted are based on the uncertainties in both the test results and the analytical extension of these values to the reactor application. 4.4.2.10.3 Uncertainties Due to Inlet Flow Maldistribution Uncertainties in the inlet flow maldistribution criteria used in the core thermal analyses are discussed in Section 4.4.3.1.2.
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-20 Revision 21 September 2013 4.4.2.10.4 Uncertainty in DNB Correlation The uncertainty in the DNB correlation (Section 4.4.2.3) can be written as a statement on the probability of not being in DNB based on the DNB data statistics. This is discussed in Section 4.4.2.3.2. 4.4.2.10.5 Uncertainties in DNBR Calculations The uncertainties in the DNBRs calculated by THINC analysis (see Section 4.4.3.4.1) due to uncertainties in the nuclear peaking factors are accounted for by applying conservatively high values of the nuclear peaking factors and including measurement error allowances in the statistical evaluation of the limit DNBR (see Section 4.4.1.1.2) using the Improved Thermal Design Procedure (Reference 86). In addition, conservative values for the engineering hot channel factors are used (see Section 4.4.2.3.4). The results of a sensitivity study with THINC-IV show that the minimum DNBR in the hot channel is relatively insensitive to variations in the core-wide radial power distribution (for the same value of FNH). The ability of the THINC-IV computer code to accurately predict flow and enthalpy distributions in rod bundles is discussed in Section 4.4.3.4.1 and in Reference 59. The sensitivity of the minimum DNBR in the hot channel to the void fraction correlation (see also Section 4.4.2.8.3), the inlet velocity and exit pressure distributions, and the grid pressure loss coefficients have been studied (Reference 47). The results show that the minimum DNBR in the hot channel is relatively insensitive to variations in these parameters. 4.4.2.10.6 Uncertainties in Flowrates The uncertainties associated with loop flowrates are discussed in Section 5.1. For core thermal performance evaluations, a thermal design loop flow is used which is less than the best estimate loop flow (by approximately 4 percent). In addition, another 7.5 percent of the thermal design flow is assumed to be ineffective for core heat removal capability because it bypasses the core through the various available flowpaths described in Section 4.4.3.1.1. 4.4.2.10.7 Uncertainties in Hydraulic Loads As discussed in Section 4.4.2.7.2, hydraulic loads on the fuel assembly are evaluated for a pump overspeed transient that creates flowrates 18 percent greater than the best estimate flow. A design uncertainty of 10 percent is applied. 4.4.2.10.8 Uncertainty in Mixing Coefficients The value of the mixing coefficient, TDC, used in THINC analyses for this application is 0.038. The mean value of TDC obtained in the R grid mixing tests described in Section 4.4.2.3.1 was 0.042 (for 26-inch grid spacing). The value of 0.038 is one DCPP UNITS 1 & 2 FSAR UPDATE 4.4-21 Revision 21 September 2013 standard deviation below the mean value and 90 percent of the data gives values of TDC greater than 0.038 (Reference 41).
The results of the mixing tests discussed in Section 4.4.2.3.3, had a mean value of TDC of 0.059 and standard deviation of = 0.007. Hence, the current design value of TDC is almost three standard deviations below the mean for 26-inch grid spacing. 4.4.2.11 Plant Configuration Data Plant configuration data for the thermal-hydraulic and fluid systems external to the core are provided in Chapters 5, 6, and 9. Implementation of the ECCS is discussed in Chapters 6 and 15. Some specific areas of interest are:
(1) Total coolant flow rate for the RCS is provided in Table 5.1-1. (2) Total RCS volume is given in Table 5.1-1. (3) The flowpath length through each volume can be calculated from physical data provided in the referenced tables. (4) The height of fluid in each component of the RCS may be determined from the physical data presented in Section 5.5. The RCS components are water-filled during power operation with the pressurizer being approximately 60 percent water-filled. (5) ECCS components are located to meet the criteria for net positive suction head (NPSH) described in Section 6.3. (6) Line lengths and sizes for the safety injection system (SIS) are determined so as to guarantee a total system resistance that will provide, as a minimum, the fluid delivery rates assumed in the safety analyses described in Chapter 15. (7) The minimum flow areas for RCS components are presented in Section 5.5. (8) RCS steady state pressure and temperature distribution are presented in Table 5.1-1.
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-22 Revision 21 September 2013 4.4.3 EVALUATION 4.4.3.1 Core Hydraulics 4.4.3.1.1 Flowpaths Considered in Core Pressure Drop and Thermal Design The following flowpaths are considered:
(1) Flow through the spray nozzles into the upper head for cooling purposes (2) Flow entering the RCC guide thimbles to cool core components
(3) Leakage flow from the vessel inlet nozzle directly to the vessel outlet nozzle through the gap between vessel and barrel (4) Flow entering the core from the baffle-barrel region through the gaps between the baffle plates (5) Flow introduced between baffle and barrel to cool these components (6) Flow through the empty guide thimble tubes The above contributions are evaluated to confirm that the design basis value of 7.5 percent core bypass flow is met. 4.4.3.1.2 Inlet Flow Distribution Data from several 1/7 scale hydraulic reactor model tests (References 52, 53, and 60) have been considered in arriving at the core inlet flow maldistribution criteria to be used in the THINC analyses (see Section 4.4.3.4.1). THINC-I (Reference 41) analyses have indicated that a conservative design basis is to consider a 5 percent reduction in the flow to the hot assembly (Reference 61). The same 5 percent reduction to the hot assembly inlet is used in THINC-IV analyses.
The experimental error in the inlet velocity distribution has been estimated in Reference 47. The sensitivity of changes in inlet velocity distributions to hot channel thermal performance is shown to be small.
The effect of the total flowrate on the inlet velocity distribution was studied in the experiments of Reference 52. As expected, no significant variation could be found in inlet velocity distribution with reduced flowrate. 4.4.3.1.3 Empirical Friction Factor Correlations, FEQ Two empirical friction factor correlations are used in the THINC-IV computer code (described in Section 4.4.3.4.1). DCPP UNITS 1 & 2 FSAR UPDATE 4.4-23 Revision 21 September 2013 The friction factor in the axial direction, parallel to the fuel rod axis, uses the Novendstern-Sandberg (Reference 62) correlation. This correlation consists of the following:
(1) For isothermal conditions, this correlation uses the Moody (Reference 55) friction factor, including surface roughness effects. (2) Under single-phase heating conditions, a factor is applied based on the values of the coolant density and viscosity at the temperature of the heated surface and at the bulk coolant temperature. (3) Under two-phase flow conditions, the homogeneous flow model proposed by Owens (Reference 63) is used with a modification to account for a mass velocity and heat flux effect.
The flow in the lateral directions, normal to the fuel rod axis, views the reactor core as a large tube bank. Thus, the lateral friction factor proposed by Idel'chick (Reference 54) is applicable. This correlation is of the form: 0.2ReAFLL= (4.4-14) where: A is a function of the rod pitch and diameter as given in Reference 54 ReL is the lateral Reynolds number based on rod diameter Extensive comparisons of THINC-IV predictions using these correlations to experimental data are given in Reference 59, and verify the applicability of these correlations in PWR design. 4.4.3.2 Influence of Power Distribution The core power distribution, which at BOL is largely established by fuel enrichment, loading pattern, and core power level, is a function of variables such as control rod worth and position and fuel depletion throughout lifetime. Although radial power distributions in various planes of the core are often illustrated for general interest, the core radial enthalpy rise distribution, as determined by the integral of power over each channel, is of greater importance for DNB analyses. These radial power distributions, characterized by FNH (defined in Section 4.3.2.2.2), as well as axial heat flux profiles, are discussed in the following two sections. DCPP UNITS 1 & 2 FSAR UPDATE 4.4-24 Revision 21 September 2013 4.4.3.2.1 Nuclear Enthalpy Rise Hot Channel Factor, FNH Given the local power density q' (kW/ft) at a point x, y, z in a core with N fuel rods and height H:
()dzz)y,(x,q'Nldzz,y,xq'Maxpower rod averagepower rod hotHorodsallooHoNHF== (4.4-15) The location of minimum DNBR depends on the axial profile and its magnitude depends on the enthalpy rise up to that point. The maximum value of the rod integral is used to identify the most likely rod for minimum DNBR. An axial power profile is obtained which, when normalized to the design value of FNH, recreates the axial heat flux along the limiting rod. The surrounding rods are assumed to have the same axial profile with rod average powers that are typical of distributions found in hot assemblies. In this manner, worst case axial profiles can be combined with worst case radial distributions for reference DNB calculations.
Local heat fluxes are obtained by using hot channel and adjacent channel explicit power shapes which take into account variations in horizontal power shapes throughout the core. The sensitivity of the THINC-IV analysis to radial power shapes is discussed in Reference 47. For operation at a fraction P of full power, the design FNH is given by: FNH = 1.56 [1 + 0.3 (1-P)] (LOPAR) (4.4-16) FNH = 1.59 [1 + 0.3 (1-P)] (VANTAGE 5) The permitted relaxation of FNH is included in the DNB protection setpoints and allows radial power shape changes with rod insertion to the insertion limits (Reference 64), thus allowing greater flexibility in the nuclear design. 4.4.3.2.2 Axial Heat Flux Distributions As discussed in Section 4.3.2.2, the axial heat flux distribution can vary as a result of rod motion, power change, or due to spatial xenon transients that may occur in the axial direction. Consequently, it is necessary to measure the axial power imbalance by means of the excore nuclear detectors (as discussed in Section 4.3.2.2.7) and protect the core from excessive axial power imbalance. The reactor trip system provides automatic reduction of the trip setpoint in the overtemperature T channels on excessive axial power imbalance, i.e., when an extremely large axial offset corresponds to an axial shape that could lead to a DNBR, which is less than that calculated for the reference DNB design axial shape. DCPP UNITS 1 & 2 FSAR UPDATE 4.4-25 Revision 21 September 2013 The reference DNB design axial shape is a chopped cosine with a peak-to-average ratio of 1.55. 4.4.3.3 Core Thermal Response A general summary of the steady state thermal-hydraulic design parameters including thermal output, flowrates, etc., is provided in Table 4.1-1. As stated in Section 4.4.1, the design bases are to prevent DNB and to prevent fuel melting for Conditions I and II events. The protective systems described in Chapter 7 (Instrumentation and Controls) are designed to meet these bases. The response of the core to Condition II transients is given in Chapter 15. 4.4.3.4 Analytical Techniques 4.4.3.4.1 Core Analysis The objective of reactor core thermal analysis is to determine the maximum heat removal capability in all flow subchannels, and to show that the core safety limits, as presented in the Technical Specifications, are not exceeded. The thermal design considers local variations in dimensions, power generation, flow redistribution, and mixing. THINC-IV is a realistic three-dimensional matrix model developed to account for hydraulic and nuclear effects on the enthalpy rise in the core (References 47 and 59). The behavior of the hot assembly is determined by superimposing the power distribution among the assemblies upon the inlet flow distribution, while allowing for flow mixing and distribution between assemblies. The average flow and enthalpy in the hottest assembly is obtained from the core-wide assembly-by-assembly analysis. The local variations in power, fuel rod and pellet fabrication, and mixing within the hottest assembly are then superimposed on the average conditions of the hottest assembly to determine conditions in the hot channel.
The following sections describe the use of the THINC code in the thermal-hydraulic design evaluation. 4.4.3.4.1.1 Steady State Analysis The THINC-IV computer program determines coolant density, mass velocity, enthalpy, vapor void, static pressure, and DNBR distributions along parallel flow channels within a reactor core under all expected operating conditions. The core region being studied is made up of a number of contiguous elements in a rectangular array extending the full length of the core. An element may represent any region of the core from a single assembly to a subchannel.
The momentum and energy exchange between elements in the array are described by the conservation of energy and mass equations, the axial momentum equation, and two lateral momentum equations that couple each element with its neighbors. The momentum equations used in THINC-IV incorporate frictional loss terms that represent DCPP UNITS 1 & 2 FSAR UPDATE 4.4-26 Revision 21 September 2013 the combined effects of frictional and form drag due to the presence of the grids and fuel assembly nozzles in the core. The cross flow resistance model used in the lateral momentum equations was developed from experimental data for flow normal to tube banks (Reference 54). The energy equation for each element also contains additional terms that represent the energy gain or loss due to the cross flow between elements.
The unique feature in THINC-IV is that lateral momentum equations, which include both inertial and cross flow resistance terms, are incorporated into the calculation scheme. Another important consideration in THINC-IV is that the entire velocity field is solved, en masse, by a field equation, while in other codes, such as THINC-I and COBRA (Reference 65), the solutions are obtained by stepwise integration throughout the array. The resulting formulation of the conservation equations is more rigorous for THINC-IV and the solution is, therefore, more accurate. The solution method is complex and some simplifying techniques must be employed. Because the reactor flow is chiefly in the axial direction, the core flow field is primarily one-dimensional, and it is reasonable to assume that the lateral velocities and the parameter gradients are larger in the axial direction than the lateral direction. Thus, a perturbation technique is used to represent separately the axial and lateral parameters in the conservation equations.
Three THINC-IV computer runs constitute one design run: a core-wide analysis, a hot-assembly analysis, and a hot subchannel analysis.
The first computation is a core-wide assembly-by-assembly analysis that uses an inlet velocity distribution modeled from experimental reactor models (References 52, 53, and
- 60) (see Section 4.4.3.1.2). The core is made up of a number of contiguous fuel assemblies divided axially into increments of equal length. The system of perturbed and unperturbed equations are solved for this array giving the flow, enthalpy, pressure drop, temperature, and void fraction in each assembly. This computation determines the interassembly energy and flow exchange at each elevation for the hot assembly.
THINC-IV stores this information, then uses it for the subsequent hot assembly analysis in which each computational element represents one-fourth of the hot assembly. The inlet flow and the amount of momentum and energy interchange at each elevation are known from the previous core-wide calculation. The same solution technique is used to solve for the local parameters in the hot one-quarter assembly.
The third computation further divides the hot assembly into channels consisting of individual fuel rods to form flow channels. The local variations in power, fuel rod and pellet fabrication, fuel rod spacing and mixing (engineering hot channel factors) within the hottest assembly are imposed on the average conditions of the hottest fuel assembly to determine the conditions in the hot channel. Engineering hot channel factors are described in Section 4.4.2.3.4. 4.4.3.4.1.2 Experimental Verification An experimental verification (Reference 59) of the THINC-IV analysis for core-wide assembly-by-assembly enthalpy rises, as well as enthalpy rises in a nonuniformly DCPP UNITS 1 & 2 FSAR UPDATE 4.4-27 Revision 21 September 2013 heated rod bundle, have been obtained. In these tests, system pressure, inlet temperature, mass flowrate, and heat fluxes were typical of present PWR core designs.
During reactor operation, various incore monitoring systems obtain measured data indicating core performance. Assembly power distributions and assembly mixed mean temperature are measured and can be converted into the proper three-dimensional power input needed for the THINC programs. These data can then be used to verify the Westinghouse thermal-hydraulic design codes.
One standard startup test is the natural circulation test in which the core is held at a very low power (2 percent) and the pumps are turned off. The core will then be cooled by the natural circulation currents created by the power differences in the core and the annulus. During natural circulation, a thermal siphoning effect occurs, resulting in the hotter assemblies gaining flow, thereby creating significant interassembly cross flow. Tests with significant cross flow are of more value in code verification.
Interassembly cross flow is caused by radial variations in pressure, that are caused in turn by variations in the axial pressure drops in different assemblies. Under normal operating conditions (subcooled forced convection), the axial pressure drop is due mainly to friction losses. Because all assemblies have the same geometry, all assemblies have nearly the same axial pressure drops, and cross flow velocities are small. However, under natural circulation conditions (low flow) the axial pressure drop is due primarily to the difference in elevation head (or coolant density) between assemblies. This phenomenon can result in relatively large radial pressure gradients and, therefore, in higher cross flow velocities than at normal reactor operating conditions. Incore instrumentation was used to obtain the assembly-by-assembly core power distribution during a natural circulation test. Assembly exit temperatures during the natural circulation test on a 157-assembly three-loop plant were predicted using THINC-IV. The predicted data points were plotted as assembly temperature rise versus assembly power, and a least squares fitting program was used to generate an equation that best fits the data. The result is the straight line presented in Figure 4.4-11 and is predicted closely by THINC-IV. This agreement verifies the lateral momentum equations and the cross flow resistance model used in THINC-IV.
Data have been obtained for Westinghouse plants operating from 67 to 101 percent of full power. A representative cross section of the data obtained from a two-loop and a three-loop reactor was analyzed to verify the THINC-IV predictions that are compared with the experimental data in Figures 4.4-12 and 4.4-13.
The predicted assembly exit temperatures were compared with the measured exit temperatures for each data run. Measured and predicted assembly exit temperatures are compared for both THINC-IV and THINC-I, and are given in Table 4.4-3. THINC-IV generally fits the data somewhat more accurately than THINC-I. Both codes are conservative and predict exit temperatures higher than measured values for the DCPP UNITS 1 & 2 FSAR UPDATE 4.4-28 Revision 21 September 2013 high-powered assemblies. Experimental verification of the THINC-IV subchannel calculation has been obtained from exit temperature measurements in a nonuniformly heated rod bundle (Reference 66).
Figure 4.4-14 compares, for a typical run, the measured and predicted temperature rises as a function of the power density in the channel. The THINC-IV results correctly predict the temperature gradient across the bundle.
In Figure 4.4-15, the measured and predicted temperature rises are compared for a series of runs at different pressures, flows, and power levels. Again, the measured points represent the average of the measurements taken in the various quadrants. The THINC-IV predictions provide a good representation of the data.
Thus, the THINC-IV analysis provides a realistic evaluation of the core performance and is used in the thermal analyses as described above. 4.4.3.4.1.3 Transient Analysis The THINC-III thermal-hydraulic computer code (Reference 41) is the third section of the THINC-I program that has transient DNB analysis capability.
The conservation equations needed for the transient analysis are included in THINC-III by adding the necessary accumulation terms to the conservation equations used in the steady state (THINC-I) analysis. The input description must now include one or more of the following time arrays:
(1) Inlet flow variation (2) Heat flux distribution (3) Inlet pressure history At the beginning of the transient, the calculation procedure is carried out as in the steady state analysis. The THINC-III code is first run in the steady state mode to ensure conservatism with respect to THINC-IV and to provide the steady state initial conditions at the start of the transient. The time is incremented by an amount determined either by the user or by the program. At each new time step, the accumulation terms are evaluated using the information from the previous time step.
This procedure is continued until a preset maximum time is reached.
At various times during the transient, steady state THINC-IV is applied to show that the application of THINC-III is conservative. The THINC-III code does not have the capability for evaluating fuel rod thermal response. This is treated by the methods described in Section 15.1.9.
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-29 Revision 21 September 2013 4.4.3.4.2 Fuel Temperatures As discussed in Section 4.4.2.2, fuel rod behavior is evaluated with a semiempirical thermal model that considers, in addition to the thermal aspects, such items as cladding creep, fuel swelling, fission gas release, release of absorbed gases, cladding corrosion and elastic deflection, and helium solubility.
A detailed description of the thermal model can be found in References 67 and 83 with the modification for the time-dependent densification given in Reference 68. 4.4.3.4.3 Hydrodynamic Instability The analytical methods used to determine hydraulic instability are discussed in Section 4.4.3.5. 4.4.3.5 Hydrodynamic and Flow-Power Coupled Instability Boiling flow may be susceptible to thermohydrodynamic instabilities (Reference 69). These instabilities may cause a change in thermohydraulic conditions that may lead to a reduction in the DNB heat flux relative to that observed during a steady flow condition, or to undesired forced vibrations of core components. Thus, the thermohydraulic design criterion states that operation under Conditions I and II modes shall not lead to thermohydrodynamic instabilities.
Two specific types of flow instabilities are considered by Westinghouse for PWR operation. These are the Ledinegg, or flow excursion, type of static instability and the density wave type of dynamic instability. A Ledinegg instability involves a sudden change in flowrate from one steady state to another. This instability occurs (Reference 69) when the slope of the RCS pressure drop-flowrate curve becomes algebraically smaller than the slope of the loop supply (pump head) pressure drop-flowrate curve. The Westinghouse pump head curve has a negative slope whereas the RCS pressure drop-flow curve has a positive slope over the Conditions I and II operational ranges. Thus, Ledinegg instability will not occur.
The mechanism of density wave oscillations in a heated channel has been described by Lahey and Moody (Reference 70).
The method developed by Ishii (Reference 71) for parallel closed channel systems evaluates if a given condition is stable with respect to the density wave type of dynamic instability. This method had been used to assess the stability of typical Westinghouse reactor designs (References 72, 73, 74) under operating Conditions I and II. The results indicate that a large margin to density wave instability exists (e.g., an increase in the order of 200 percent of rated reactor power would be required) for the inception of this type of instability.
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-30 Revision 21 September 2013 Flow instabilities that have been observed have occurred almost exclusively in closed channel systems operating at low pressures relative to the Westinghouse PWR operating pressures. Kao, Morgan, and Parker (Reference 75) analyzed parallel closed channel stability experiments simulating a reactor core flow. These experiments were conducted at pressures up to 2200 psia. The results showed that for flow and power levels typical of power reactor conditions, no flow oscillations could be induced above 1200 psia. Additional evidence that flow instabilities do not adversely affect thermal margin is provided by data from rod bundle DNB tests.
In summary, it is concluded that thermohydrodynamic instabilities will not occur under Conditions I and II modes of operation for Westinghouse PWR reactor designs. A large power margin exists to predicted inception of such instabilities. Analysis has been performed and shows that minor plant-to-plant differences in Westinghouse reactor designs such as fuel assembly arrays, core power flow ratios, fuel assembly length, etc., will not result in gross deterioration of the above power margins. 4.4.3.6 Temperature Transient Effects Analysis Waterlogging damage of a fuel rod could occur as a consequence of a power increase on a rod after water has entered the fuel rod through a cladding defect and will continue until the fuel rod internal pressure equals the reactor coolant pressure. A subsequent power increase raises the temperature and, hence, could raise the pressure of the water contained within the fuel rod. Zircaloy-clad fuel rods, which have failed due to waterlogging (References 76 and 77) indicate that very rapid power transients are required for fuel failure. Release of the internal fuel rod pressure is expected to have a minimal effect on the RCS (Reference 76) and is not expected to result in failure of additional fuel rods (Reference 77). Ejection of fuel pellet fragments into the coolant stream is not expected (References 76 and 77). A cladding breach due to waterlogging is thus expected to be similar to any fuel rod failure mechanism that exposes fuel pellets to the reactor coolant stream. Waterlogging has not been identified as the mechanism for cladding distortion or perforation of any Westinghouse Zircaloy-4-clad rods.
An excessively high fuel rod internal gas pressure could cause cladding failure. During operational transients, fuel rod cladding rupture due to high internal gas pressure is precluded by adopting a design basis that the fuel rod internal gas pressure remains below the value that causes the fuel-cladding diametral gap to increase due to outward cladding creep. 4.4.3.7 Potentially Damaging Temperature Effects During Transients A fuel rod experiences many operational transients (intentional maneuvers) while in the core. Several thermal effects must be considered when designing and analyzing fuel rod performance.
The cladding can be in contact with the fuel pellet at some time in the fuel lifetime. Cladding-pellet interaction occurs if fuel pellet temperature is increased after the DCPP UNITS 1 & 2 FSAR UPDATE 4.4-31 Revision 21 September 2013 cladding is in contact with the pellet. Cladding-pellet interaction is discussed in Section 4.2.1.3.1.
Increasing fuel temperature results in an increased fuel rod internal pressure. One of the fuel rod design bases is that the fuel rod internal pressures remain below values that can cause the fuel-cladding diametral gap to increase due to outward cladding creep (Section 4.2.1.1.1).
The potential effects of operation with waterlogged fuel were discussed in Section 4.4.3.6, which concluded that waterlogging is not a concern during operational transients.
Clad flattening, as noted in Section 4.2.1.3.1, has been observed in some operating power reactors. Thermal expansion (axial) of the fuel rod stack against a flattened section of cladding could cause cladding failure. This is no longer a concern because clad flattening is precluded by prepressurization.
A differential thermal expansion between the fuel rods and the guide thimbles can occur during a transient. Excessive bowing of fuel rods can occur if the grid assemblies do not allow axial movement of the fuel rods relative to the grids. Thermal expansion of fuel rods is considered in the grid design so that axial loads imposed on the fuel rods during a thermal transient will not result in excessively bowed fuel rods (see Section 4.2.1.2.2). 4.4.3.8 Energy Release During Fuel Element Burnout As discussed in Section 4.4.3.3, the core is protected from going through DNB over the full range of possible operating conditions. At full power operation, the typical minimum DNBR was calculated for VANTAGE 5 fuel for Unit 1 and for Unit 2 and is listed in Table 4.1-1. This means that, for these conditions, the probability of a rod going through DNB is less than 0.1 percent at 95 percent confidence level based on the statistics of the WRB-2 correlations (References 84 and 85). In the extremely unlikely event that DNB should occur, cladding temperature will rise due to steam blanketing the rod surface and the consequent degradation in heat transfer. During this time a potential for a chemical reaction between the cladding and the coolant exists. Because of the relatively good film boiling heat transfer following DNB, the energy release from this reaction is insignificant compared to the power produced by the fuel. These results have been confirmed in DNB tests conducted by Westinghouse (References 66 and 78). 4.4.3.9 Energy Release During Rupture of Waterlogged Fuel Elements A full discussion of waterlogging including energy release is contained in Section 4.4.3.6.
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-32 Revision 21 September 2013 4.4.3.10 Fuel Rod Behavior Effects from Coolant Flow Blockage Coolant flow blockage can occur within the coolant channels of a fuel assembly or external to the reactor core. The effect of coolant flow blockage within the fuel assembly on fuel rod behavior is more pronounced than external blockages of the same magnitude. In both cases, the flow blockages cause local reductions in coolant flow. The amount of local flow reduction, its location in the reactor, and how far downstream does the reduction persist, are considerations that influence fuel rod behavior. Coolant flow blockage effects in terms of maintaining rated core performance are determined both by analytical and experimental methods. The experimental data are usually used to augment analytical tools such as the THINC-IV program. Inspection of the DNB correlation (Section 4.4.2.3) shows that the predicted DNBR depends on local values of quality and mass velocity.
The THINC-IV code can predict the effects of local flow blockages on DNBR within the fuel assembly on a subchannel basis, regardless of where the flow blockage occurs. THINC-IV accurately predicts the flow distribution within the fuel assembly when the inlet nozzle is completely blocked (Reference 59). For the DCPP reactors operating at nominal full power conditions as specified in Table 4.1-1, the effects of an increase in enthalpy and decrease in mass velocity in the lower portion of the fuel assembly would not result in the reactor reaching the safety limit DNBR.
The analyses, which assume fully developed flow along the full channel length, show that a reduction in local mass velocity greater than approximately 53 percent would be required to reduce the DNBRs from the DNBRs at the nominal conditions shown in Table 4.4-1 to the safety limit DNBRs. In reality, a local flow blockage is expected to promote turbulence and thus would likely not effect DNBR. Coolant flow blockages induce local cross flows as well as promoting turbulence. Fuel rod vibration could occur, caused by this cross flow component, through vortex shedding or turbulent mechanisms. If the cross flow velocity exceeds the limit established for fluid elastic stability, large amplitude whirling will result in, and can lead to, mechanical wear of the fuel rods at the grid support locations. The limits for a controlled vibration mechanism are established from studies of vortex shedding and turbulent pressure fluctuations. Fuel rod wear due to flow-induced vibration is considered in the fuel rod fretting evaluation (Section 4.2). 4.4.3.11 Pressurization Analyses for Shutdown Conditions The objective of these analyses is to evaluate, for low-to-high decay heat shutdown conditions, the thermal hydraulic response, particularly the maximum RCS pressure limits, if no operator recovery actions were taken to limit or prevent boiling in the RCS (References 97 and 98). The results of these analyses are used to determine acceptable RCS vent path configurations used during outage conditions as a contingency to mitigate RCS pressurization upon a postulated loss of residual heat removal (RHR). Typical RCS vent path openings capable of use include the reactor DCPP UNITS 1 & 2 FSAR UPDATE 4.4-33 Revision 21 September 2013 vessel head flange, one or more pressurizer safety valves, steam generator primary hot leg manways, or combinations of these openings depending on the decay heat load. 4.4.4 TESTING AND VERIFICATION 4.4.4.1 Testing Prior to Initial Criticality Reactor coolant flow tests, as noted in Tests 3.9 and 3.10 of Table 14.1-2, are performed following fuel loading, but prior to initial criticality. Coolant loop pressure drop data are obtained in this test. These data, in conjunction with coolant pump performance information, allow determination of the coolant flowrates at reactor operating conditions. This test verifies that proper coolant flowrates have been used in the core thermal and hydraulic analysis. 4.4.4.2 Initial Power Plant Operation Core power distribution measurements are made at several core power levels (see Section 4.3.2.2.7) during startup and initial power operation. These tests are used to verify that conservative peaking factors were used in the core thermal and hydraulic design and analysis. 4.4.4.3 Component and Fuel Inspections Inspections performed on the manufactured fuel are delineated in Section 4.2.1.4. Fabrication measurements critical to thermal and hydraulic analysis are obtained to verify that the engineering hot channel factors employed in the design analyses (Section 4.4.2.3.4) are met. 4.4.5 INSTRUMENTATION REQUIREMENTS 4.4.5.1 Incore Instrumentation Instrumentation is located in the core so that by correlating movable neutron detector information with fixed thermocouple information the radial core characteristics may be obtained for all core quadrants.
The incore instrumentation system is composed of thermocouples, positioned to measure fuel assembly coolant outlet temperatures at preselected positions, and movable fission chamber detectors positioned in guide thimbles that run the length of selected fuel assemblies to measure the neutron flux distribution. Figures 4.4-16 and 4.4-17 show the number and location of instrumented assemblies in the core for Units 1 and 2, respectively. In the Unit 1 reactor, four of these thermocouples have been moved to the upper head for monitoring conditions in the upper head.
The core exit thermocouples provide a backup for the flux monitoring instrumentation to monitor power distribution. The routine, systematic collection of thermocouple readings DCPP UNITS 1 & 2 FSAR UPDATE 4.4-34 Revision 21 September 2013 provides a data base. From this data base, abnormally high or abnormally low readings, quadrant temperature tilts, or systematic departures from a prior reference map can be deduced.
The movable incore neutron detector system is used for more detailed mapping should the thermocouple system indicate an abnormality. These two complementary systems are more useful when taken together than taken alone. The incore instrumentation system is described in more detail in Section 7.2.9. Incore instrumentation is provided to obtain data from which fission power density distribution in the core, coolant enthalpy distribution in the core, and fuel burnup distribution may be determined. 4.4.5.2 Overtemperature and Overpower T Instrumentation The overtemperature T trip protects the core against low DNBR. The overpower T trip protects against excessive power (fuel rod rating protection). As discussed in Section 7.2.1, factors included in establishing the overtemperature T and overpower T trip setpoints include the reactor coolant temperature in each loop. The axial distribution of core power, as determined by the two-section (upper and lower) excore neutron detectors, is also a factor in establishing the overtemperature T trip. 4.4.5.3 Instrumentation to Limit Maximum Power Output The output of the three ranges (source, intermediate, and power) of detectors, with the associated nuclear instrumentation electronics, is used to limit the maximum power output of the reactor.
Eight instrument wells are located around the reactor periphery in the primary shield, 45° apart from each other, at an equal distance from the reactor vessel. Two of the positions, on opposite flat portions of the core, directly across from the primary startup neutron source positions, each contain a BF3 proportional counter to cover the source range, and a compensated ionization chamber for the intermediate range. The source range detector is located at an elevation of approximately one-fourth of the core height; the compensated ionization chambers are positioned at an elevation corresponding to one-half of the core height. The two positions opposite the other two flat portions of the core house the post-accident neutron flux monitor detectors.
Four dual-section uncompensated ionization chamber assemblies are installed vertically in the instrumentation wells directly across from the four corners of the core. They are used as power range detectors. To minimize neutron flux pattern distortions, they are placed within 1 foot of the reactor vessel. Each dual-section uncompensated ionization chamber assembly provides two signals that correspond to the neutron flux in the upper DCPP UNITS 1 & 2 FSAR UPDATE 4.4-35 Revision 21 September 2013 and in the lower positions of a core quadrant, thus permitting the determination of relative axial power production.
Signals from the detectors in the three ranges (source, intermediate, and power) provide inputs which, when combined, monitor neutron flux from a completely shutdown condition to 120 percent of full power, with the capability of recording overpower excursions up to 200 percent of full power.
The difference in neutron flux readings between the upper and lower sections of the power range detectors is used to limit the overtemperature T and overpower T trip setpoints and to provide the operator with an indication of the core power axial offset. In addition, the output of the power range channels are used as follows:
(1) For the rod speed control function
(2) To alert the operator to an excessive power unbalance between the quadrants (3) To protect the core against rod ejection accidents (4) To protect the core against adverse power distributions resulting from dropped rods Details of the neutron detectors and nuclear instrumentation design and the control and trip logic are given in Chapter 7. The limits on neutron flux operation and trip setpoints are given in the Technical Specifications. 4.4.5.4 Loose Parts Monitoring A Westinghouse loose parts and vibration monitoring system is provided for early detection of possible loose parts in the RCS and to reduce their probability of causing damage to RCS components.
Accelerometers (piezoelectric crystals) are located in areas where loose parts are most likely to become entrapped. Redundant accelerometers are installed on the top and the bottom of the reactor vessel and on the lower head of each of the four steam generators. Signals from the accelerometers are transmitted by high-temperature leads to preamplifiers located in the containment. From the preamplifiers, the signals are sent to the data acquisition and control panel located in the control room. All components are designed to remain operational over the life of the plant in the temperature, humidity, and radiation environment in which they are installed.
When the output of an individual transducer channel exceeds an adjustable setpoint:
(1) The condition activates a local alarm at the control cabinet.
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-36 Revision 21 September 2013 (2) The output of the alarmed channel is evaluated for validity and logged before being transmitted to the main control board annunciator. The output of the transducers can be audiomonitored by the operator at the control panel. The alarm monitoring of the selected channel continues during audiomonitoring.
In the event that the output of a loose part channel exceeds the alarm value, the record of the event will be available to the operator and plant staff for analysis. The event will be compared with other previously recorded signatures of the RCS. If necessary, consultants will be contacted to further evaluate the event. This analysis, together with other plant instrumentation, will form the basis for judgment of the effects and significance of the loose parts event.
The sensitivity of the loose parts channels is such that a loose part striking the reactor vessel or steam generators with as little as one-half-foot-pound of energy produces signals of sufficient strength to be detected over the normal background signals. 4.
4.6 REFERENCES
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- 2. D. H. Risher, Jr., An Evaluation of the Rod Ejection Accident in Westinghouse Pressurized Water Reactors Using Spatial Kinetics Methods, WCAP-7588, Rev. 1, December 1971. 3. G. Kjaerheim and E. Rolstad, In Pile Determination of UO2 Thermal Conductivity, Density Effects and Gap Conductances, HPR-80, December 1967. 4. G. Kjaerheim, In-Pile Measurements of Centre Fuel Temperatures and Thermal Conductivity Determination of Oxide Fuels, paper IFA-175 presented at the European Atomic Energy Society Symposium on Performance Experience of Water-Cooled Power Reactor Fuel, Stockholm, Sweden, October 21-22, 1969.
- 5. I. Cohen, et al, Measurement of the Thermal Conductivity of Metal-Clad Uranium Oxide Rods during Irradiation, WAPD-228, 1960.
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- 7. J. P. Stora, et al, Thermal Conductivity of Sintered Uranium Oxide under In-Pile Conditions, EURAEC-1095, 1964.
- 8. I. Devold, A Study of the Temperature Distribution in UO2 Reactor Fuel Elements, AE-318, Aktiebolaget Atomenergi, Stockholm, Sweden, 1968.
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-37 Revision 21 September 2013 9. M. G. Balfour, et al, In-Pile Measurement of UO2 Thermal Conductivity, WCAP-2923, 1966.
- 10. R. N. Duncan, Rabbit Capsule Irradiation of UO2, CVTR Project, CVNA-142, June 1962.
- 11. R. C. Nelson, et al, Fission Gas Release from UO2 Fuel Rods with Gross Central Melting, GEAP-4572, July 1964.
- 12. V. C. Howard and T. G. Gulvin, Thermal Conductivity Determinations on Uranium Dioxide by a Radial Flow Method, UKAEA IG-Report 51, November 1960.
- 13. C. F. Lucks and H. W. Deem, "Thermal Conductivity and Electrical Conductivity of UO2," in Progress Reports Relating to Civilian Applications, BMI-1448 (Rev.) for June 1960, BMI-1489 (Rev.) for December 1960 and BMI-1518 (Rev.) for May 1961.
- 14. J. L. Daniel, et al, Thermal Conductivity of UO2, HW-69945, September 1962.
- 15. A. D. Feith, Thermal Conductivity of UO2 by a Radial Heat Flow Method, TID-21668, 1962.
- 16. J. Vogt, et al, Determination of the Thermal Conductivity of Unirradiated Uranium Dioxide, AB Atomenergi Report RMB-527, 1964, Quoted by IAEA Technical Report Series No. 59, "Thermal Conductivity of Uranium Dioxide." 17. T. Nishijima, et al, "Thermal Conductivity of Sintered UO2 and A12 03 at High Temperatures," J. American Ceramic Society, 48, 1965, pp. 31-34.
- 18. J. B. Ainscough and M. J. Wheeler, "The Thermal Diffusivity and Thermal Conductivity of Sintered Uranium Dioxide," in Proceedings of the Seventh Conference on Thermal Conductivity, National Bureau of Standards, Washington, D.C., 1968, p. 467.
- 19. T. G. Godfrey, et al, Thermal Conductivity of Uranium Dioxide and Armco Iron by an Improved Radial Heat Flow Technique, ORNL-3556, June 1964.
- 20. J. P. Stora, et al, Thermal Conductivity of Sintered Uranium Oxide Under In-Pile Conditions, EURAEC-1095, August 1964.
- 21. A. J. Bush, Apparatus for Measuring Thermal Conductivity to 2500°C, Westinghouse Research Laboratories Report 64-1P6-401-R3, February 1965, (Westinghouse Proprietary).
- 22. R. R. Asamoto, et al, The Effect of Density on the Thermal Conductivity of Uranium Dioxide, GEAP-5493, April 1968.
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-38 Revision 21 September 2013 23. O. L. Kruger, Heat Transfer Properties of Uranium and Plutonium Dioxide, Paper 11-N-68F presented at the fall meeting of Nuclear Division of the American Ceramic Society, September 1968, Pittsburgh.
- 24. J. A. Gyllander, In-Pile Determination of the Thermal Conductivity of UO2 in the Range 500-2500°C, AE-411, January 1971.
- 25. M. F. Lyons, et al, UO2 Powder and Pellet Thermal Conductivity During Irradiation, GEAP-5100-1, March 1966.
- 26. D. H. Coplin, et al, The Thermal Conductivity of UO2 by Direct In-reactor Measurements, GEAP-5100-6, March 1968.
- 27. A. S. Bain, "The Heat Rating Required to Produce Center Melting in Various UO2 Fuels," ASTM Special Technical Publication, No. 306, Philadelphia, 1962, pp. 30-46.
- 28. J. P. Stora, "In-Reactor Measurements of the Integrated Thermal Conductivity of UO2 - Effects of Porosity," Trans. ANS, 13, 1970, pp. 137-138.
- 29. International Atomic Energy Agency, "Thermal Conductivity of Uranium Dioxide," Report of the Panel held in Vienna, April 1965, IAEA Technical Reports Series, No. 59, Vienna, The Agency, 1966.
- 30. C. G. Poncelet, Burnup Physics of Heterogeneous Reactor Lattices, WCAP-6069, June 1965. 31. R. J. Nodvick, Saxton Core II Fuel Performance Evaluation, WCAP-3385-56, Part II, Evaluation of Mass Spectrometric and Radiochemical Analyses of Irradiated Saxton Plutonium Fuel, July 1970.
- 32. R. A. Dean, Thermal Contact Conductance Between UO2 and Zircaloy-2, CVNA-127, May 1962.
- 33. A. M. Ross and R. L. Stoute, Heat Transfer Coefficient Between UO2 and Zircacloy-2, AECL-1552, June 1962.
- 34. L. S. Tong, Boiling Crisis and Critical Heat Flux, AEC Critical Review Series, TID-25887, 1972.
- 35. F. E. Motley and F. F. Cadek, DNB Tests Results for New Mixing Vane Grids (R), WCAP-7695-A, P-A (Proprietary), and WCAP-7958-A, January 1975.
- 36. F. E. Motley, and F. F. Cadek, Application of Modified Spacer Factor to L. grid Typical and Cold Wall Cell DNB, WCAP-7988 (Westinghouse Proprietary), and WCAP-8030-A, October, 1972.
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-39 Revision 21 September 2013 37. F. E. Motley, et al, Critical Heat Flux Testing of 17 x 17 Fuel Assembly Geometry with 22-Inch Grid Spacing, WCAP-8536 (Westinghouse Proprietary), and WCAP-8537, May 1975.
- 38. F. F. Cadek, et al, Effect of 17 x 17 Fuel Assembly Geometry on DNB, WCAP-8296-PA (Proprietary) and WCAP-8297, February 1976.
- 39. L. S. Tong, "Prediction of Departure from Nucleate Boiling for an Axially Non-Uniform Heat Flux Distribution," J. Nucl. Energy, 21, 1967, pp. 241-248.
- 40. F. F. Cadek, et al, Effect of Axial Spacing on Interchannel Thermal Mixing with The R Mixing Vane Grid, WCAP-7941, PA (Proprietary), and WCAP-7959-A, January 1975.
- 41. H. Chelemer, et al, Subchannel Thermal Analysis of Rod Bundle Cores, WCAP-7015, Rev. 1, January 1969.
- 42. D. S. Rowe and C. W. Angle, Crossflow Mixing Between Parallel Flow Channels During Boiling, Part II Measurement of Flow and Enthalpy in Two Parallel Channels, BNWL-371, Part 2, December 1967.
- 43. D. S. Rowe and C. W. Angle, Crossflow Mixing Between Parallel Flow Channels During Boiling, Part III Effect of Spacers on Mixing Between Two Channels, BNWL-371, Part 3, January 1969.
- 44. J. M. Gonzalez-Santalo and P. Griffith, Two-Phase Flow Mixing in Rod Bundle Subchannels, ASME Paper 72-WA/NE-19, 1972.
- 45. F. E. Motley, et al, The Effect of 17 x 17 Fuel Assembly Geometry on Interchannel Thermal Mixing, WCAP-8299, March 1974.
- 46. F. F. Cadek, Interchannel Thermal Mixing with Mixing Vane Grids, WCAP-7667-L, May 1971 (Westinghouse Proprietary), and WCAP-7755, September 1971.
- 47. L. E. Hochreiter, Application of the THINC IV Program to PWR Design, WCAP-8054, October 1973 (Westinghouse Proprietary), and WCAP-8195, October 1973.
- 48. S. Nakazato and E. E. DeMario, Hydraulic Flow Test of the 17 x 17 Fuel Assembly, WCAP-8279, February 1974.
- 49. F. W. Dittus and L. M. K. Boelter, "Heat Transfer in Automobile Radiators of the Tubular Type," Calif. Univ. Publication in Eng., 2, No. 13, 1930, pp. 443-461.
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-40 Revision 21 September 2013 50. J. Weisman, "Heat Transfer to Water Flowing Parallel to Tube Bundles," Nucl. Sci. Eng., 6, 1959, pp. 78-79.
- 51. J. R. S. Thom, et al, "Boiling in Sub-cooled Water During Flowup Heated Tubes or Annuli," Proc. Instn. Mech. Engrs., 180, Pt. C, 1965-66, pp. 226-46.
- 52. G. Hetsroni, Hydraulic Tests of the San Onofre Reactor Model, WCAP-3269-8, June 1964.
- 53. G. Hetsroni, Studies of the Connecticut-Yankee Hydraulic Model, NYO-3250-2, June 1965.
- 54. I. E. Idel'chik, Handbook of Hydraulic Resistance, AEC-TR-6630, 1960.
- 55. L. F. Moody, "Friction Factors for Pipe Flow," Transaction of the American Society of Mechanical Engineers, 66, 1944, pp. 671-684.
- 56. G. W. Maurer, A Method of Predicting Steady State Boiling Vapor Fractions in Reactor Coolant Channels, WAPD-BT-19, June 1960, pp. 59-70.
- 57. P. Griffith, et al, Void Volumes in Subcooled Boiling Systems, ASME Paper No. 58-HT-19, 1958.
- 58. R. W. Bowring, Physical Model, Based on Bubble Detachment, and Calculation of Steam Voidage in the Subcooled Region of a Heated Channel, HPR-10, December 1962. 59. L. E. Hochreiter, et al, THINC-IV An Improved Program for Thermal-Hydraulic Analysis of Rod Bundle Cores, WCAP-7956, June 1973.
- 60. F. D. Carter, Inlet Orificing of Open PWR Cores, WCAP-9004, January 1969, (Westinghouse Proprietary), and WCAP-7836, January 1972.
- 61. J. Shefcheck, Application of the THINC Program to PWR Design, WCAP-7359-L, August 1969 (Westinghouse Proprietary), and WCAP-7838, January 1972.
- 62. E. H. Novendstern and R. O. Sandberg, Single Phase Local Boiling and Bulk Boiling Pressure Drop Correlations, WCAP-2850, April 1966 (Westinghouse Proprietary), and WCAP-7916, June 1972.
- 63. W. L. Owens, Jr., "Two-Phase Pressure Gradient," International Developments in Heat Transfer, Part II, ASME, New York, 1961, pp. 363-368.
- 64. A. F. McFarlane, Power Peaking Factors, WCAP-7912-L, March 1972 (Westinghouse Proprietary), and WCAP-7912, March 1972.
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-41 Revision 21 September 2013 65. D. S. Rowe, COBRA-III, a Digital Computer Program for Steady State and Transient Thermal-Hydraulic Analysis of Rod Bundle Nuclear Fuel Elements, BNWL-B-82, 1971.
- 66. J. Weisman, et al, "Experimental Determination of the Departure from Nucleate Boiling in Large Rod Bundles at High Pressures," Chem. Eng. Prog. Symp. Ser. 64, No. 82, 1968, pp. 114-125.
- 67. Supplemental information on fuel design transmitted from R. Salvatori, Westinghouse NES, to D. Knuth, AEC, as attachments to letters NS-SL-518 (12/22/72), NS-SL-521 (12/29/72), NS-SL-524 (12/29/72), and NS-SL-543 (1/12/73) (Westinghouse Proprietary), and supplemental information on fuel design transmitted from R. Salvatori, Westinghouse NES, to D. Knuth, AEC, as attachments to letters NS-SL-527 (1/2/73), and NS-SL-544 (1/12/73).
- 68. J. M. Hellman (ed), Fuel Densification Experimental Results and Model for Reactor Application, WCAP-8219, October 1973.
- 69. J. A. Boure, et al, Review of Two-Phase Flow Instability, ASME Paper 71-HT-42, August 1971.
- 70. R. T. Lahey and F.J. Moody, The Thermal Hydraulics of a Boiling Water Reactor, American Nuclear Society, 1977.
- 71. M. Ishii, et al, "An Experimental Investigation of the Thermally Induced Flow Oscillations in Two-Phase Systems," J. of Heat Transfer, November 1976, pp. 616-622.
- 72. Virgil C. Summer FSAR, Docket #50-395.
- 73. Byron/Braidwood FSAR, Docket #50-456.
- 74. South Texas FSAR, Docket #50-498.
- 75. H. S. Kao, et al., "Prediction of Flow Oscillation in Reactor Core Channel," Trans. ANS. Vol. 16, 1973, pp. 212-213.
- 76. L. A. Stephan, The Effects of Cladding Material and Heat Treatment on the Response of Waterlogged UO2 Fuel Rods to Power Bursts, IN-ITR-111, January 1970.
- 77. Western New York Nuclear Research Center Correspondence with the AEC on February 11 and August 27, 1971, Docket 50-57.
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-42 Revision 21 September 2013 78. L. S. Tong, et al., Critical Heat Flux (DNB) in Square and Triangular Array Rod Bundles, presented at the Japan Society of Mechanical Engineers Semi-International Symposium held at Tokyo, Japan, 1967, September 4-8, pp. 25-34.
- 79. J. Skaritka, (Ed.), Fuel Rod Bow Evaluation, WCAP-8691, Ref. 1 July 1979.
- 80. "Partial Response to Request Number 1 for Additional Information on WCAP-8691, Revision 1" Letter, E. P. Rahe, Jr., (Westinghouse) to J. R. Miller (NRC), NS-EPR-2515, dated October 9, 1981; "Remaining Response to Request Number 1 for Additional Information on WCAP-8691, Revision 1" Letter, E. P. Rahe, Jr., (Westinghouse) to R. J. Miller (NRC), NS-EPR-2572, dated March 16, 1982.
- 81. C. G. Poncelet, LASER - A Depletion Program for Lattice Calculations Based on MUFT and THERMOS, WCAP-6073, April 1966.
- 82. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
- 83. W. J. Leech, et al., Revised PAD Code Thermal Safety Model, WCAP-8720, Addendum 2 (Proprietary), October 1982.
- 84. F. E. Motley, K. W. Hill, F. F. Cadek and J. Shefcheck, New Westinghouse Correlation WRB-1 for Predicting Critical Heat Flux in Rod Bundles with Mixing Vane Grids, WCAP-8762, July, 1976 (Proprietary) and WCAP-8763, July 1976 (Non-Proprietary).
- 85. S. L. Davidson and W. R. Kramer, (Ed.), Reference Core Report VANTAGE 5 Fuel Assembly, WCAP-10444-P-A, September 1985.
- 86. H. Chelemer, L. H. Boman and D. R. Sharp, Improved Thermal Design Procedure, WCAP-8567, July 1975.
- 87. S. L. Davidson, F. E. Motley, Y. C. Lee, T. Bogard and W. J. Bryan, Verification Testing and Analyses of the 17x17 Optimized Fuel Assembly, WCAP-9401, March 1979 (Proprietary) and WCAP-9402.
- 88. J. Skaritka, Fuel Rod Bow Evaluation, WCAP-8691, Revision 1, July 1979.
- 89. S. L. Davidson, J. A. Iorii, (Ed.) Reference Core Report - 17x17 Optimized Fuel Assembly, WCAP-9500-A, May 1982.
- 90. Letter from E. P. Rahe (W) to Miller (NRC) dated March 19, 1982, NS-EPR-2573, WCAP-9500 and WCAPs 9401/9402 NRC SER Mixed Core Compatibility Items.
DCPP UNITS 1 & 2 FSAR UPDATE 4.4-43 Revision 21 September 2013 91. Letter from C. O. Thomas (NRC) to Rahe (W) - Supplemental Acceptance No. 2 for Referencing Topical Report, WCAP-9500, January 1983. 92. F. E. Motley and F. F. Cadek, DNB Test Results for R Grid Thimble Cold Wall Cells, WCAP-7695-P-A, Addendum 1, October 1972.
- 93. K. W. Hill, et al., Effect of 17x17 Fuel Assembly Geometry on DNB, WCAP-8296-P-A, February 1975.
- 94. F. E. Motley, et al., Critical Heat Flux Testing of 17x17 Fuel Assembly Geometry with 22-inch Grid Spacing, WCAP-8536, May 1975.
- 95. F. E. Motley and F. F. Cadek, Application of Modified Spacer Factor to L. Grid Typical and Cold Wall Cell DNB, WCAP-7988-P-A, January 1975.
- 96. F. E. Motley and F. F. Cadek, DNB Test Results for New Mixing Vane Grids (R), WCAP-7695-L, July 1972.
- 97. Toby Burnett, et al., Systems Evaluation for Reactor Flange Venting for the Diablo Canyon Power Plant, Westinghouse Technical Report, August 1992.
- 98. E. R. Frantz, et al., RCS Pressurization Analysis for Diablo Canyon Shutdown Scenarios, Westinghouse Technical Report, April 3, 1997.
- 99. K. W. Hill, et al., Effect of Local Heat Flux Spikes on DNB in Non-Uniform Heated Rod Bundles, WCAP-8174 (Proprietary), August 1974 and WCAP-8202 (Non-Proprietary), August 1973.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 4.1-1 Sheet 1 of 7 Revision 21 September 2013 REACTOR DESIGN COMPARISON Thermal and Hydraulic Design Parameters Unit 1 Unit 2 (Using ITDP)(a) Reactor Core Heat Output, MWt 3,411 3,411 Reactor Core Heat Output, 106 Btu/hr 11,641.7 11,641.7 Heat Generated in Fuel, % 97.4 97.4 Core Pressure, Nominal, psia(b) 2,280 2,280 Core Pressure, Min Steady State(b) psia 2,250 2,250 Fuel Type Vantage 5 Vantage 5 Minimum DNBR at nominal Conditions(c) Typical Flow Channel 2.63(n)2.63 Thimble (Cold Wall) Flow Channel 2.47(n)2.47 Limit DNBR for Design Transients
Typical Flow Channel 1.71 1.71
Thimble (Cold Wall) Flow Channel 1.68 1.68
DNB Correlation WRB-2 WRB-2
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 4.1-1 Sheet 2 of 7 Revision 21 September 2013 HFP Nominal Coolant Conditions(d) Unit 1 Unit 2 Vessel Minimum Measured Flow(e) Rate (including Bypass) 106 lbm/hr 135.4 136.6 gpm 359,200 362,500 Vessel Thermal Design Flow(e) Rate (including Bypass) 106 lbm/hr 132.2 133.4 gpm 350,800 354,000 Core Flow Rate (excluding Bypass, based on TDF) 106 lbm/hr 122.3 123.4 gpm 324,490 327,450 Effective Flow Area(f) for Heat Transfer, ft2 54.13 54.13 Average Velocity along Fuel(f,k) Rods, ft/sec (Based on TDF) 14.0 14.2
Core Inlet Mass Velocity,(f) 106 lbm/hr-ft (Based on TDF) (V-5) 2.26 2.28
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 4.1-1 Sheet 3 of 7 Revision 21 September 2013 Thermal and Hydraulic Design Parameters Unit 1 Unit 2 (Based on Thermal Design Flow) Nominal Vessel/Core Inlet Temperature, °F 544.5(g) 545.1(g) Vessel Average Temperature, °F 577.3 577.6 Core Average Temperature, °F 581.5 582.3 Vessel Outlet Temperature, °F 610.1 610.1 Average Temperature Rise in Vessel, °F 65.6 65.0 Average Temperature Rise in Core, °F 70.4 70.7 Heat Transfer Active Heat Transfer Surface Area,(f) ft2 57,505 57,505 Average Heat Flux, Btu/hr-ft2 197,180 197,180 Maximum Heat Flux for Normal(h) Operation, Btu/hr-ft2 508,720 508,720 Average Linear Power, kW/ft 5.445 5.445 Peak Linear Power for Normal Operation,(h) kW/ft 14.3 14.3 Peak Linear Power for Prevention of Centerline Melt, kW/ft 22.0(i) 22.0(i) Pressure Drop(j) Across Core, psi
- 25.5 + 2.6 27.2 + 2.7 Across Vessel,(n) including nozzle, psi
- 52.8 + 5.3 48.2 + 4.8 Thermal and Hydraulic Design Parameters Heat Flux Hot Channel Factor, FQT 2.58 2.58 Temperature at Peak Linear Power for 4,700 4,700 Prevention of Centerline Melt, °F Fuel Central Temperature, °F Peak at 100% power <3,230m <3,230 Peak at maximum thermal output for maximum overpower DT trip point <4,0801 <4,080
- Pressure drop values for mechanical design flow and low inlet temperatures of 531.7°F and 531.9°F for Units 1 and 2.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 4.1-1 Sheet 4 of 7 Revision 21 September 2013 Core Mechanical Design Parameters Unit 1 Unit 2 Fuel Assemblies Design RCC Canless RCC Canless Number of fuel assemblies 193 193 Rod array 17 X 17 17 X 17 U02 rods per assembly 264 264 Rod pitch, in 0.496 0.496 Overall dimensions, in 8.426 x 8.426 8.426 x 8.426 Fuel weight (as U02) lb 222,645/204,200* 222,645/204,200* Zirconium alloy weight, lb 46,993/52,300 46,993/52,300 Number of grids per assembly 8-12 2 non-mixing vane type 6 mixing vane type 3 IFM; 1 P-Grid 8-12 2 non-mixing vane type 6 mixing vane type 3 IFM; 1 P-Grid Composition of grids INC718/ Zircaloy-4 INC718/ Zircaloy-4 or ZIRLO or ZIRLO Weight of grids, lb 1841/2820 1841/2820 Number of guide thimbles per assembly 24 24 Composition of guide thimbles Zircaloy-4 or ZIRLO Zircaloy-4 or ZIRLO Diameter of guide thimbles (ID x OD), in. Upper part 0.450 x 0.482/ 0.450 x 0.482/ 0.442 x 0.474 0.442 x 0.474 Lower part 0.397 x 0.430 0.397 x 0.430 Diameter of instrument guide thimbles, in. 0.450 x 0.482/ 0.450 x 0.482/ 0.442 x 0.474 0.442 x 0.474
- Values following a diagonal are applicable to the VANTAGE 5 fuel assembly, including those with a P-Grid DCPP UNITS 1 & 2 FSAR UPDATE TABLE 4.1-1 Sheet 5 of 7 Revision 21 September 2013 Core Mechanical Design Parameters (Cont'd) Unit 1 Unit 2 Fuel Rods Number 50,952 50,952 Outside diameter, in 0.374/0.360* 0.374/0.360* Diametral gap, in 0.0065/0.0062 0.0065/0.0062 Cladding thickness, in 0.0225 0.0225 Cladding material Zircaloy-4 Zircaloy-4 or ZIRLO or ZIRLO Gap material Helium Helium Fuel Pellets Material UO2 sintered UO2 sintered Density, % of theoretical 95 95 Diameter, in 0.3225/0.3088 0.3225/0.3088 Length, in 0.530/0.507 0.530/0.507 Mass of UO2, lb/ft of fuel rod 0.364/0.334 0.364/0.334 Rod Cluster Control Assemblies Neutron absorber, Ag-In-Cd Ag-In-Cd Composition 80%, 15%, 5% 80%, 15%, 5%
Diameter, in 0.341 0.341** Nominal length of absorber material, in. 142 142 Density, lb/in3 0.367 0.367 Cladding material Type 304 Type 304** SS-cold worked SS-cold worked Cladding thickness, in 0.0185 0.0185 Number of RCCAs 53 53 Number of absorber rods per cluster 24 24 Core Structure Core barrel, ID/OD, in 148.0/152.5* 148.0/152.5* Thermal shield, ID/OD, in 158.5/164.0 Neutron pad Design
- Values following a diagonal are applicable to the VANTAGE 5 assembly ** Diameter reduced to 0.336 over bottom 12 inches and ion-nitrided cold-worked Type 316L-SS cladding material applicable to Framatome RCCA only DCPP UNITS 1 & 2 FSAR UPDATE TABLE 4.1-1 Sheet 6 of 7 Revision 21 September 2013 Nuclear Design Parameters Unit 1 Unit 2 Structure Characteristics Core diameter, in (equivalent) 132.7 132.7 Core average active fuel height, in. 144 144 Reflector Thickness and Composition Top - water plus steel, in. 10 10 Bottom - water plus steel, in. 10 10 Side - water plus steel, in 15 15 H2 0/U, cold molecular ratio lattice 2.41/2.74* 2.41/2.74*
Fuel Enrichment, wt% (Cycle 1)(1) Region 1 2.10 2.10 Region 2 2.60 2.60 Region 3 3.10 3.10 Burnable Poison Rods (First Core) Number 1518 1518 Material Borosilicate glass Borosilicate glass Outside diameter, in. 0.381 0.381 Inner tube, OD, in. 0.1815 0.1815 Cladding material Stainless steel Stainless steel Inner tube material Stainless steel Stainless steel Boron loading (w/o B2O3 in glass rod) 12.5 12.5 Weight of Boron-10 per ft of rod, lb/ft 0.00419 0.00419 Initial reactivity worth, % hot (cold) 7.63 (5.5) 7.63 (5.5) Excess Reactivity (First Core) Maximum fuel assembly, % (cold, clean, unborated water) 1.39 1.39 Maximum core, % (cold, zero power, beginning of cycle) 1.221 1.221 Fuel Enrichment, Wt% Maximum feed enrichment 5.0 5.0 Burnable Absorbers (VANTAGE 5 reloads) Type IFBA IFBA Number (typical range) 2000 - 15000 2000 - 15000 Material ZrB2 ZrB2 B10 Loading, mg/inch (typical) 2.25 2.25
- These values are applicable to the VANTAGE 5 fuel assembly DCPP UNITS 1 & 2 FSAR UPDATE TABLE 4.1-1 Sheet 7 of 7 Revision 21 September 2013 (a) Includes the effect of fuel densification
(b) Values used for thermal hydraulic core analysis
(c) Based on Tin = 545.1°F (Unit 1) and Tin = 545.7°F (Unit 2) corresponding to Minimum Measured Flow of each unit (d) Based on Safety Analysis Tin = 548.4°F and Pressure = 2280 psia (e) Includes 15 percent steam generator tube plugging
(f) Assumes all LOPAR or VANTAGE 5 core
(g) Safety Analysis Tin = 548.4°F for both units (h) This limit is associated with the value of FQT= 2.58 (i) See Section 4.3.2.2.6
(j) Based on best estimate reactor flow rate, Section 5.1
(k) At core average temperature
(l) Enrichments for subsequent regions can be found in the Nuclear Design Report issued each cycle (m) Assuming mechanical design flow
(n) Values need review by Westinghouse
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 4.1-2 Sheet 1 of 3 Revision 11 November 1996 ANALYTICAL TECHNIQUES IN CORE DESIGN Analysis Technique Computer Code Section Referenced Mechanical Design of Core Internals Loads, deflections, and stress analysis Static and dynamic Blowdown code, FORCE finite 3.7.2.1 modeling element structural analysis 3.9.1 code, and others 3.9.3 Fuel Rod Design Fuel performance characteristics Semiempirical thermal Westinghouse fuel rod 4.2.1.3.1 (temperature, internal pressure, model of fuel rod with design model 4.3.3.1 cladding stress, etc.) consideration of fuel 4.3.3.2 density changes, heat 4.4.3.4.2 transfer, fission gas release, etc. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 4.1-2 Sheet 2 of 3 Revision 11 November 1996 Analysis Technique Computer Code Section Referenced Nuclear Design (1) Cross sections and group Microscopic data Modified/ENDF/B library 4.3.3.2 constants Macroscopic constants for LEOPARD /CINDER type 4.3.3.2 homogenized core regions and PHOENIX Group constants for control rods with self-shielding HAMMER-AIM 4.3.3.2 (2) X-Y power distributions, fuel 2-D, 2-group diffusion TURTLE and ANC 4.3.3.3 depletion, critical boron theory concentrations, X-Y xenon distributions, reactivity coefficients and control rod worths (3) X-Y-Z power distributions, fuel 3-D, 2-group diffusion 3D PALADON 4.3.3.3 depletion, critical boron theory and ANC concentrations, X-Y-Z xenon distributions, reactivity coefficients and control rod worth (4) Axial power distributions 1-D, 2-group diffusion PANDA 4.3.3.3 and axial xenon distribution theory (5) Fuel rod power Integral transport theory LASER 4.3.3.1 (6) Effective resonance Monte Carlo weighting REPAD temperature function DCPP UNITS 1 & 2 FSAR UPDATE TABLE 4.1-2 Sheet 3 of 3 Revision 11 November 1996 Analysis Technique Computer Code Section Referenced Thermal-Hydraulic Design (1) Steady state Subchannel analysis of THINC-IV 4.4.3.4.1 local fluid conditions in rod bundles, including inertial and crossflow resistance terms, solution progresses from core-wide to hot assembly to hot channel (2) Transient DNB analysis Subchannel analysis of THINC-I (THINC-III) 4.4.3.4.1 local fluid conditions in rod bundles during transients by including accumulation terms in con-servation equations; solution progresses from core-wide to hot assembly to hot channel
DCPP UNITS 1 & 2 FSAR UPDATE Revision 12 September 1998 TABLE 4.1-3 DESIGN LOADING CONDITIONS FOR REACTOR CORE COMPONENTS (1) Fuel assembly weight (2) Fuel assembly spring forces (3) Internals weight (4) Control rod scram (equivalent static load)
(5) Differential pressure (6) Spring preloads (7) Coolant flow forces (static) (8) Temperature gradients (9) Differences in thermal expansions (a) Due to temperature differences (b) Due to expansion of different materials (10) Interference between components (11) Vibration (mechanically or hydraulically induced) (12) One or more loops out of service (13) All operational transients listed in Table 5.2-4 (14) Pump overspeed (15) Seismic loads (DE and DDE) (16) Blowdown forces (due to RCS branch line breaks)(a)
(a) In the original analysis, the blowdown forces used were those resulting from breaks in the RCS cold and hot legs. However, with the acceptance of the DCPP leak-before-break analysis by the NRC, the blowdown forces resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis structural analyses and included in the loading combinations. Only the much smaller forces from RCS branch line breaks have to be considered (see Section 3.6.2.1.1.1). DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 4.2-1 MAXIMUM DEFLECTIONS ALLOWED FOR REACTOR INTERNAL SUPPORT STRUCTURES Allowable No-loss-of-function Component Deflections, in. Deflections, in. Upper Barrel Radial inward 4.1 8.2 Radial outward 0.5 1.0 Upper Package 0.10 0.15
Rod Cluster Guide Tubes 1.00 1.75 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 4.3-1 Sheet 1 of 2 Revision 16 June 2005 NUCLEAR DESIGN PARAMETERS (Typical) Core Average Linear Power, kW/ft, including densification effects 5.445(a) Total Heat Flux Hot Channel Factor, FQT 2.58 Nuclear Enthalpy Rise Hot Channel Factor, FHN 1.65 VANTAGE 5 1.62 LOPAR Reactivity Coefficients
Doppler coefficient See Figures 4.3-28 and 4.3-29
Moderator temperature coefficient at operating conditions, pcm/°F(b) 0 to -40 Boron coefficient in primary coolant, pcm/ppm -16 to -8
Delayed Neutron Fraction and Lifetime eff BOL, (EOL) 0.0069, (0.0051) *, BOL, (EOL), sec 19.2 (18.6) Control Rod Worths
Rod requirements See Table 4.3-2
Maximum bank worth, pcm < 2000
Maximum ejected rod worth See Chapter 15 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 4.3-1 Sheet 2 of 2 Revision 16 June 2005 Boron Concentrations (ppm) Refueling 2000 keff = 0.95, cold, rod cluster control assemblies in 2000 Full power, no xenon, keff = 1.0, hot, rod cluster control assemblies out 1876(d) Full power, equilibrium xenon, keff = 1.0, hot, rod cluster control assemblies out 1536(d) Reduction with fuel burnup Typical reload cycle, ppm/GWD/MTU(c) See Figure 4.3-3 (a) Data in table based on Units 1 and 2
(b) 1 pcm = percent mille = 10-5 where is calculated from two state point values of keff by 1n (k2/k1 ) (c) Gigawatt day (GWD) = 1000 megawatt days (1000 MWD)
(d) These values are representative values used for analytical purposes only.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 4.3-2 UNIT 1 - REACTIVITY REQUIREMENTS FOR ROD CLUSTER CONTROL ASSEMBLIES Reactivity Effects, Beginning of Life End of Life End of Life % (First Cycle) (First Cycle) (Equilibrium Cycle) (Typical) 1. Control Requirements Fuel temperature (Doppler) 1.39(a) 1.12(a) 1.00 Moderator temperature(includes void) 0.16 0.89 0.80 Redistribution 0.50 0.85 0.90 Rod insertion allowance 0.50 0.50 0.50
- 2. Total Control 2.55 3.36 3.20
- 3. Estimated Rod Cluster Control Assembly Worth (53 Rods) All but one (highest worth) assemblies inserted 7.18 7.05 6.50
- 4. Estimated Rod Cluster Control Assembly- Credit with 10% adjustment to accommodate uncertainties 6.46 6.34 5.85
- 5. Shutdown Margin Available (Section 4.2) 3.91 2.98 2.65(b) (a) Includes 0.1 percent uncertainty (b) The design basis minimum shutdown is 1.6%
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 4.3-3 UNIT 2 - REACTIVITY REQUIREMENTS FOR ROD CLUSTER CONTROL ASSEMBLIES Reactivity Effects, Beginning of Life End of Life End of Life % (First Cycle) (First Cycle) (Equilibrium Cycle) (Typical) 1. Control Requirements Fuel temperature (Doppler) 1.39(a) 1.12(a) 1.00 Moderator temperature (includes void) 0.29 0.96 0.94 Redistribution 0.50 0.85 0.90 Rod insertion allowance 0.50 0.50 0.50
- 2. Total Control 2.68 3.43 3.34
- 3. Estimated Rod Cluster Control Assembly Worth (53 Rods)
All but one (highest worth) assemblies inserted 6.48 6.38 5.70
- 4. Estimated Rod Cluster Control Assembly (Credit with 10% adjustment to accommodate uncertainties 5.83 5.74 5.13
- 5. Shutdown Margin Available (Section 4.2) 3.15 2.31 1.79(b) (a) Includes 0.1% uncertainty (b) The design basis minimum shutdown is 1.6%
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 4.3-4 AXIAL STABILITY INDEX PWR CORE WITH A 12-FT HEIGHT
Burnup Stability Index, hr-1 (MWD/T) FZ CB (ppm) Exp. Calc. 1550 1.34 1065 0.041 0.032 7700 1.27 700 0.014 0.006 Difference: 0.027 0.026
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 4.3-5 TYPICAL NEUTRON FLUX LEVELS (n/cm2-sec) AT FULL POWER E 1 MeV 5.53 keV E 1 MeV 0.625 eV E 5.53 keV E 0.625 eV (nv)0 Core center 6.51 x 1013 1.12 x 1014 8.50 x 1013 3.00 x 1013 Core outer radius 3.23 x 1013 5.74 x 1013 4.63 x 1013 8.60 x 1012 at midheight
Core top, on axis 1.53 x 1013 2.42 x 1013 2.10 x 1013 1.63 x 1013 Core bottom, on axis 2.36 x 1013 3.94 x 1013 3.50 x 1013 1.46 x 1013 Pressure vessel inner wall, 2.77 x 1010 5.75 x 1010 6.03 x 1010 8.38 x 1010 azimuthal peak, core midheight
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 4.3-6 COMPARISON OF MEASURED AND CALCULATED DOPPLER DEFECTS Core Burnup Measured Calculated Plant Fuel Type (MWD/MTU) (pcm)(a) (pcm) 1 Air filled 1800 1700 1710
2 Air filled 7700 1300 1440
3 Air and 8460 1200 1210 helium filled (a) pcm = 10-5 . See footnote in Table 4.3-1
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 4.3-7 BENCHMARK CRITICAL EXPERIMENTS Description of No. of LEOPARD keff Using Experiments Experiments Experimental Bucklings UO2 Al clad 14 1.0012 SS clad 19 0.9963 Borated H2O 7 0.9989 Total 40 0.9985
U-metal Al clad 41 0.9995 Unclad 20 0.9990
Total 61 0.9993
Grand Total 101 0.9990
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 4.3-8 SAXTON CORE II ISOTOPICS ROD MY, AXIAL ZONE 6
Atom Ratio Measured 2 Precision, % LEOPARD Calculation U-234/U 4.65 x 10-5 29 4.60 x 10-5 U-235/U 5.74 x 10-3 0.9 5.73 x 10-3 U-236/U 3.55 x 10-4 5.6 3.74 x 10-4 U-238/U 0.99386 0.01 0.99385 Pu-238/Pu 1.32 x 10-3 2.3 1.222 x 10-3 Pu-239/Pu 0.73971 0.03 0.74497 Pu-240/Pu 0.19302 0.2 0.19102 Pu-241/Pu 6.014 x 10-2 0.3 5.74 x 10-2 Pu-242/Pu 5.81 x 10-3 0.9 5.38 x 10-3 Pu/U(a) 5.938 x 10-2 0.7 5.970 x 10-2 Np-237/U-238 1.14 x 10-4 15 0.86 x 10-4 Am-241/Pu-239 1.23 x 10-2 15 1.08 x 10-2 Cm-242/Pu-239 1.05 x 10-4 10 1.11 x 10-4 Cm-244/Pu-239 1.09 x 10-4 20 0.98 x 10-4 (a) Weight ratio DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 4.3-9 CRITICAL BORON CONCENTRATIONS, AT HZP, BOL
Plant Type Measured Calculated 2-loop, 121 assemblies, 10-foot core 1583 1589
2-loop, 121 assemblies, 12-foot core 1625 1624
2-loop, 121 assemblies, 12-foot core 1517 1517
3-loop, 157 assemblies, 12-foot core 1169 1161
3-loop, 157 assemblies, 12-foot core 1344 1319
4-loop, 193 assemblies, 12-foot core 1370 1355
4-loop, 193 assemblies, 12-foot core 1321 1306
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 4.3-10 COMPARISON OF MEASURED AND CALCULATED ROD WORTH
2-Loop Plant, 121 Assemblies, 10-foot core Measured, pcm Calculated, pcm Group B 1885 1893 Group A 1530 1649 Shutdown group 3050 2917
ESADA Critical, 0.69-in pitch, 2 wt.% PuO2, 8% Pu240, 9 Control Rods 6.21-in rod separation 2250 2250 2.07-in rod separation 4220 4160 1.38-in rod separation 4100 4010 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 4.3-11 COMPARISON OF MEASURED AND CALCULATED MODERATOR TEMPERATURE COEFFICIENTS AT HZP, BOL
Measured iso(a) Calculated iso Plant Type/Control Bank Configuration pcm/°F pcm/°F 3-Loop, 157 Assemblies, 12-foot core
D at 160 steps -0.50 -0.50 D in, C at 190 steps -3.01 -2.75 D in, C at 28 steps -7.67 -7.02 B, C, and D in -5.16 -4.45
2-Loop, 121 Assemblies, 12-foot core
D at 180 steps +0.85 +1.02 D in, C at 180 steps -2.40 -1.90 C and D in, B at 165 steps -4.40 -5.58 B, C, and D in, A at 174 steps -8.70 -8.12 (a) Isothermal coefficients, which include the Doppler effect in the fuel iso = 105 ln(k 2k1)/T(°F) DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 4.4-1 UNIT 1 VOID FRACTIONS AT NOMINAL REACTOR CONDITIONS WITH DESIGN HOT CHANNEL FACTORS
Average Maximum Core (LOPAR) 0.14% --
(V-5) 0.17% --
Hot subchannel (LOPAR) 0.75% 1.80%
(V-5) 0.89% 2.11%
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 4.4-2 UNIT 2 VOID FRACTIONS AT NOMINAL REACTOR CONDITIONS WITH DESIGN HOT CHANNEL FACTORS
Average Maximum Core (LOPAR) 0.16% --
(V-5) 0.19% --
Hot subchannel (LOPAR) 0.83% 1.99%
(V-5) 3.92% 14.51%
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 4.4-3 Revision 11 November 1996 COMPARISON OF THINC-IV AND THINC-I PREDICTIONS WITH DATA FROM REPRESENTATIVE WESTINGHOUSE TWO- AND THREE-LOOP REACTORS Improvement, °F Power, % Full Measured Inlet rms, F , °F for THINC-IV Reactor MWt Power Temp, °F THINC-I THINC-IV over THINC-1 Ginna 847 65.1 543.7 1.97 1.83 0.14 854 65.7 544.9 1.56 1.46 0.10 857 65.9 543.9 1.97 1.82 0.15 947 72.9 543.8 1.92 1.74 0.18 961 74.0 543.7 1.97 1.79 0.18 1091 83.9 542.5 1.73 1.54 0.19 1268 97.5 542.0 2.35 2.11 0.24 1284 98.8 240.2 2.69 2.47 0.22 1284 98.9 541.0 2.42 2.17 0.25 1287 99.0 544.4 2.26 1.97 0.29 1294 99.5 540.8 2.20 1.91 0.29 1295 99.6 542.0 2.10 1.83 0.27
Robinson 1427.0 65.1 548.0 1.85 1.88 0.03 1422.6 64.9 549.4 1.39 1.39 0.00 1929.0 88.0 550.0 2.35 2.34 0.01 2207.3 100.7 534.0 2.41 2.41 0.00 2213.9 101.0 533.8 2.52 2.44 0.08 Revision 11 November 1996FIGURE 4.2-1 FUEL ASSEMBLY CROSS SECTION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 4.2-2 FUEL ASSEMBLY OUTLINE (LOPAR) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE 159.9753.475152.258.4268.3728.4188.4262.3831.32122.31101.7681.212.251.525.8430.7251.2771.8292.37112.92133.47159.7653.670151.568.4262.738153.96133.37112.8292.2771.7251.1730.626.19017 x 17 VANTAGE 5 FUEL ASSEMBLY17 x 17 RECONSTITUTABLE LOPAR FUEL ASSEMBLYLM0000LM0000***FOR VANTAGE 5 ASSEMBLIES WITH A P-GRID(NOT SHOWN) INSTALLED. P-GRID REFERENCEDIMENSION IS 3.093". GRID 1 AND GRID 2 REFERENCEDIMENSIONS ARE 6.535" AND 30.42", RESPECTIVELY.153.60 Revision 15 September 2003FIGURE 4.2-2A 17 x 17 VANTAGE 5 / LOPAR FUEL ASSEMBLY COMPARISON UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.2-3 FUEL ROD SCHEMATIC (LOPAR) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE BOTTOMBOTTOMDIMENSION CFUEL STACK LENGTHDIMENSION BPLENUMDIMENSION AFUEL ROD LENGTHDIAMETER DDIAMETER E17 x 17 VANTAGE 5FUEL ROD17 x 17 LOPARFUEL RODTOPTOPDIMENSION17 x 17 V-517 x 17 LOPARA152.285151.56B7.5256.90C144.00144.00DIAMETER D.315.329DIAMETER E.360.374*FOR VANTAGE 5 WITH P-GRID FUELROD DIMENSION "A" IS 152.870" ANDDIMENSION "B" IS 7.730".**DIMENSIONS ARE IN INCHESNOT SHOWN IS THEEXTERNAL GRIP TYPE OFTHE LOPAR FUEL RODBOTTOM END PLUG.BOTTOM END PLUG SHOWSINTERNAL GRIP TYPE FOR V-5 FUEL RODS. FIGURE 4.2-3A 17x17 VANTAGE 5 / LOPAR FUEL ROD ASSEMBLY COMPARISON UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 15 September 2003 Revision 11 November 1996FIGURE 4.2-4 TYPICAL CLAD AND PELLET DIMENSIONS AS A FUNCTION OF EXPOSURE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.2-5 REPRESENTATIVE FUEL ROD INTERNAL PRESSURE AND LINEAR POWER DENSITY FOR THE LEAD BURNUP AS A FUNCTION OF TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 4.2-6 REMOVABLE ROD COMPARED TO STANDARD ROD UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 Revision 11 November 1996 FIGURE 4.2-7 REMOVABLE FUEL ROD ASSEMBLY OUTLINE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 Revision 11 November 1996FIGURE 4.2-8 LOCATION OF REMOVABLE RODS WITHIN AN ASSEMBLY UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 4.2-9 LOWER CORE SUPPORT ASSEMBLY UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 4.2-10 LOWER CORE SUPPORT ASSEMBLY UNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.2-11 NEUTRON SHIELD PAD LOWER CORE SUPPORT STRUCTURE UNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.2-12 UPPER CORE SUPPORT STRUCTURE UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 Revision 11 November 1996FIGURE 4.2-13 UPPER CORE SUPPORT STRUCTURE UNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.2-14 PLAN VIEW OF UPPER CORE SUPPORT STRUCTURE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 Revision 11 November 1996 FIGURE 4.2-15 ROD CLUSTER CONTROL AND DRIVE ROD ASSEMBLY WITH INTERFACING COMPONENTS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE
1.840 DIA.NOM. (1)SPRINGSPIDER BODY0.361 DIA. (3)0.381 DIA..88 TRAV.SPRING RETAINER1.25 DIA. (2)150.574161.0142.00ABSORBER LENGTHABSORBER80% SILVER, 15% INDIUM, 5% CADMIUMNOTE: DIMENSIONS SHOWN FOR ALL MODELS ANNOTATED DIMENSIONS ARE WESTINGHOUSE MODEL WITH FRAMATOME MODEL HAVING THE FOLLOWING DIMENSIONS: (1) 1.804 (2) 1.240 (3) 0.354
Revision 14 November 2001FSAR UPDATEUNITS 1 AND 2 DIABLO CANYON SITE FIGURE 4.2-16 ROD CLUSTER CONTROL ASSEMBLY OUTLINE
80% Ag, 15% In, 5% Cd151.73 (SEE NOTE)0.381 DIA. NOM.NOTE: WESTINGHOUSE DIMENSION SHOWN. FRAMATOME ROD LENGTH IS 153.658-154.468. Revision 14 November 2001FSAR UPDATEUNITS 1 AND 2 DIABLO CANYON SITE FIGURE 4.2-17 ABSORBER ROD Revision 11 November 1996 FIGURE 4.2-18 BURNABLE ABSORBER ASSEMBLY UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.2-18A WET ANNULAR BURNABLE ABSORBER ROD UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 4.2-19 BURNABLE ABSORBER ROD SECTIONS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 4.2-20 PRIMARY SOURCE ASSEMBLY UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 4.2-21 SECONDARY SOURCE ASSEMBLY UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE
0.385 MAX Revision 14 November 2001FIGURE 4.2-21A SECONDARY SOURCE ASSEMBLY UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.2-22 THIMBLE PLUG ASSEMBLY UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 4.2-23 CONTROL ROD DRIVE MECHANISMUNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 20 November 2011 FIGURE 4.2-24 CONTROL ROD DRIVE MECHANISM SCHEMATIC UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 20 November 2011 Revision 11 November 1996 FIGURE 4.2-25 NORMAL LATCH CLEARANCE AT MINIMUM AND MAXIMUM TEMPERATURE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 4.2-26 CONTROL ROD DRIVE MECHANISM LATCH CLEARANCE THERMAL EFFECT UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-1 FUEL LOADING ARRANGEMENT UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-2 PRODUCTION AND CONSUMPTION OF HIGHER ISOTOPES UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-3 BORON CONCENTRATION VS CYCLE BURNUP WITH BURNABLE ABSORBER RODS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-4 BURNABLE ABSORBER ROD ARRANGEMENT WITHIN AN ASSEMBLY UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-5 TYPICAL INTEGRAL FUEL BURNABLE ABSORBER ROD ARRANGEMENT WITHIN AN ASSEMBLY UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-6 BURNABLE ABSORBER LOADING PATTERN UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-7 NORMALIZED POWER DENSITY DISTRIBUTION NEAR BEGINNING OF LIFE (BOL), UNRODDED CORE, HOT FULL POWER, NO XENON UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-8 NORMALIZED POWER DENSITY DISTRIBUTION NEAR BOL UNRODDED CORE, HOT FULL POWER, EQUILIBRIUM XENON UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-9 NORMALIZED POWER DENSITY DISTRIBUTION NEAR BOL GROUP D AT INSERTION LIMIT, HOT FULL POWER, EQUILIBRIUM XENON UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-10 NORMALIZED POWER DENSITY DISTRIBUTION NEAR BOL GROUP D AT INSERTION LIMIT, HOT FULL POWER, EQUILIBRIUM XENON UNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-11 NORMALIZED POWER DENSITY DISTRIBUTION NEAR MIDDLE OF LIFE (MOL) UNRODDED CORE, HOT FULL POWER, EQUILIBRIUM XENON UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-12 NORMALIZED POWER DENSITY DISTRIBUTION NEAR END OF LIFE (EOL) UNRODDED CORE, HOT FULL POWER, EQUILIBRIUM XENON UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-13 RODWISE POWER DISTRIBUTION IN A TYPICAL ASSEMBLY (G-10) NEAR BOL, HOT FULL POWER, EQUILIBRIUM XENON, UNRODDED CORE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-14 RODWISE POWER DISTRIBUTION IN A TYPICAL ASSEMBLY (G-10) NEAR EOL, HOT FULL POWER, EQUILIBRIUM XENON, UNRODDED CORE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-15 POSSIBLE AXIAL POWER SHAPES AT BOL DUE TO ADVERSE XENON DISTRIBUTIONS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-16 POSSIBLE AXIAL POWER SHAPES AT MOL DUE TO ADVERSE XENON DISTRIBUTIONS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-17 POSSIBLE AXIAL POWER SHAPES AT EOL DUE TO ADVERSE XENON DISTRIBUTIONS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-21 PEAK POWER DENSITY DURING CONTROL ROD MALFUNCTION OVER POWER TRANSIENTS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-22 PEAK LINEAR POWER DURING BORATION / DILUTION OVER POWER TRANSIENTS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-23 MAXIMUM FxQT POWER vs AXIAL HEIGHT DURING NORMAL OPERATIONS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-24 COMPARISON OF EXPECTED STEADY STATE POWER DISTRIBUTIONS WITH THE PEAKING FACTOR ENVELOPE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-25 COMPARISON BETWEEN CALCULATED AND MEASURED RELATIVE FUEL ASSEMBLY POWER DISTRIBUTION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-26 COMPARISON OF CALCULATED AND MEASURED AXIAL SHAPE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-27 MEASURED VALUES OF FQT FOR FULLPOWER ROD CONFIGURATIONS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-28 DOPPLER TEMPERATURE COEFFICIENT AT BOL AND EOL UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-29 DOPPLER ONLY POWER COEFFICIENT AT BOL AND EOL UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-30 DOPPLER ONLY POWER DEFECT AT BOL AND EOL UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-31 MODERATOR TEMPERATURE COEFFICIENT AT BOL, NO RODS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-32 MODERATOR TEMPERATURE COEFFICIENT AT EOL UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-33 MODERATOR TEMPERATURE COEFFICIENT AS A FUNCTION OF BORON CONCENTRATION AT BOL, NO RODS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-34 HOT FULL POWER MODERATOR TEMPERATURE COEFFICIENT FOR CRITICAL BORON CONCENTRATION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-35 TOTAL POWER COEFFICIENT AT BOL AND EOL UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-36 TOTAL POWER DEFECT AT BOL AND EOL UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-37 ROD CLUSTER CONTROL ASSEMBLY PATTERN UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-38 ROD CLUSTER CONTROL ASSEMBLY PATTERN UNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-39 ACCIDENTAL SIMULTANEOUS WITHDRAWAL OF TWO CONTROL BANKS EOL, HZP BANKS B AND D MOVING IN THE SAME PLANE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-40 DESIGN - TRIP CURVE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-41 NORMALIZED ROD WORTH vs. PERCENT INSERTION, ALL RODS BUT ONE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-42 AXIAL OFFSET vs. TIME PWR CORE WITH A 12-FT CORE HEIGHT AND 121 ASSEMBLIES UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-43 XY XENON TEST THERMOCOUPLE RESPONSE QUADRANT TILT DIFFERENCE vs. TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-44 CALCULATED AND MEASURED DOPPLER DEFECT AND COEFFICIENTS AT BOL, FOR A TWO-LOOP PLANT WITH A 12-FT CORE HEIGHT AND 121 ASSEMBLIES UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-45 COMPARISON OF CALCULATED AND MEASURED BORON CONCENTRATION FOR A TWO-LOOP PLANT WITH A 12-FT CORE HEIGHT AND 121 ASSEMBLIES UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-46 COMPARISON OF CALCULATED AND MEASURED BORON FOR A TWO LOOP PLANT WITH A 12-FT CORE HEIGHT AND 121 ASSEMBLIES UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.3-47 COMPARISON OF CALCULATED AND MEASURED BORON IN A 3-LOOP PLANT WITH A 12-FT CORE HEIGHT AND 157 ASSEMBLIES UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.4-1 PEAK FUEL AVERAGE AND SURFACE TEMPERATURES DURING FUEL ROD LIFETIME vs. LINEAR POWER DENSITY UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.4-2 PEAK FUEL CENTERLINE TEMPERATURE DURING FUEL ROD LIFETIME vs. LINEAR POWER DENSITY UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.4-3 THERMAL CONDUCTIVITY OF UO2 (DATA CORRECTED TO 95% THEORETICAL DENSITY) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 4.4-4 AXIAL VARIATION OF AVERAGE CLAD TEMPERATURE FOR ROD OPERATING AT 5.43 KW/FT UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.4-5 PROBABILITY CURVES FOR W-3 AND R GRID DNB CORRELATIONS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.4-6 TDC vs. REYNOLDS NUMBER FOR 26-INCH GRID SPACING UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.4-7 NORMALIZED RADIAL FLOW AND ENTHALPY DISTRIBUTION AT 4-FT ELEVATION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.4-8 NORMALIZED RADIAL FLOW AND ENTHALPY DISTRIBUTION AT 8-FT ELEVATION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.4-9 NORMALIZED RADIAL FLOW AND ENTHALPY DISTRIBUTION AT 12-FT ELEVATION CORE EXIT UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.4-10 VOID FRACTION vs. THERMODYNAMIC QUALITY H-HSAT/HG-HSAT UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.4-11 PWR NATURAL CIRCULATION TEST UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.4-12 COMPARISON OF A REPRESENTATIVE W TWO-LOOP REACTOR INCORE THERMOCOUPLE MEASUREMENTS WITH THINC-IV PREDICTIONS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.4-13 COMPARISON OF A REPRESENTATIVE W THREE-LOOP REACTOR INCORE THERMOCOUPLE MEASUREMENTS WITH THINC-IV PREDICTIONS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.4-14 HANFORD SUBCHANNEL TEMPERATURE DATA COMPARISON WITH THINC-IV UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.4-15 HANFORD SUBCRITICAL TEMPERATURE DATA COMPARISON WITH THINC-IV UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.4-16 DISTRIBUTION OF INCORE INSTRUMENTATION UNIT 1 DIABLO CANYON SITE FSAR UPDATE Error! Not a valid embedded object. Revision 11 November 1996FIGURE 4.4-17 DISTRIBUTION OF INCORE INSTRUMENTATION UNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.4-18 IMPROVED THERMAL DESIGN PROCEDURE ILLUSTRATION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 4.4-19 MEASURED VERSES PREDICTED CRITICALHEAT FLUX - WRB-1 CONNECTION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 4.4-20 MEASURED VERSES PREDICTED CRITICAL HEAT FLUX - WRB-2 CONNECTION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE DCPP UNITS 1 & 2 FSAR UPDATE i Revision 21 September 2013 Chapter 5 REACTOR COOLANT SYSTEM CONTENTS Section Title Page 5.1 SUMMARY DESCRIPTION 5.1-1
5.1.1 Schematic Flow Diagram 5.1-1
5.1.2 Piping and Instrumentation Diagrams 5.1-2
5.1.3 Elevation Drawings 5.1-2
5.1.4 Reactor Coolant System Components 5.1-2 5.1.4.1 Reactor Vessel 5.1-2 5.1.4.2 Steam Generators 5.1-2 5.1.4.3 Reactor Coolant Pumps 5.1-3 5.1.4.4 Piping 5.1-3 5.1.4.5 Pressurizer 5.1-3 5.1.4.6 Pressurizer Relief Tank 5.1-3 5.1.4.7 Safety and Relief Valves 5.1-3
5.1.5 Reactor Coolant System Performance and 5.1-4 Safety Functions 5.1.5.1 Reactor Coolant Flow 5.1-4 5.1.5.2 Best Estimate Flow 5.1-4 5.1.5.3 Thermal Design Flow 5.1-4 5.1.5.4 Mechanical Design Flow 5.1-4 5.1.5.5 System and Components 5.1-5
5.1.6 System Operation 5.1-6 5.1.6.1 Plant Startup 5.1-6 5.1.6.2 Power Generation and Hot Standby 5.1-7 5.1.6.3 Plant Shutdown 5.1-7 5.1.6.4 Refueling 5.1-8 5.1.6.5 Mid-Loop Operation 5.1-8
5.1.7 References 5.1-9
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 5 CONTENTS (Continued) Section Title Page ii Revision 21 September 2013 5.2 INTEGRITY OF THE REACTOR COOLANT PRESSURE BOUNDARY 5.2-1
5.2.1 Design of Reactor Coolant Pressure Boundary Components 5.2-1 5.2.1.1 Performance Objectives 5.2-2 5.2.1.2 Design Parameters 5.2-3 5.2.1.3 Compliance with 10 CFR 50.55a 5.2-4 5.2.1.4 Applicable Code Cases 5.2-4 5.2.1.5 Design Transients 5.2-5 5.2.1.6 Identification of Active Pumps and Valves 5.2-14 5.2.1.7 Design of Active Pumps and Valves 5.2-14 5.2.1.8 Inadvertent Operation of Valves 5.2-18 5.2.1.9 Stress and Pressure Limits 5.2-18 5.2.1.10 Stress Analysis for Structural Adequacy 5.2-19 5.2.1.11 Analysis Method for Faulted Condition 5.2-23 5.2.1.12 Protection Against Environmental Factors 5.2-24 5.2.1.13 Compliance with Code Requirements 5.2-25 5.2.1.14 Stress Analysis for Faulted Condition Loadings (DDE and LOCA) 5.2-25 5.2.1.15 Stress Analysis for Faulted Condition Loadings (Hosgri) 5.2-28 5.2.1.16 Stress Levels in Category I Systems 5.2-31 5.2.1.17 Analytical Methods for Stresses in Pumps and Valves 5.2-31 5.2.1.18 Analytical Methods for Evaluation of Pump Speed and Bearing Integrity 5.2-31 5.2.1.19 Operation of Active Valves Under Transient Loadings 5.2-32
5.2.2 Overpressurization Protection 5.2-32 5.2.2.1 Location of Pressure-Relief Devices 5.2-32 5.2.2.2 Mounting of Pressure-Relief Devices 5.2-33 5.2.2.3 Report on Overpressurization Protection 5.2-34 5.2.2.4 Low Temperature Overpressure Protection 5.2-34
5.2.3 General Material Considerations 5.2-35 5.2.3.1 Material Specifications 5.2-35 5.2.3.2 Compatibility with Reactor Coolant 5.2-37 5.2.3.3 Compatibility with External Insulation and Environmental Atmosphere 5.2-37 5.2.3.4 Chemistry of Reactor Coolant 5.2-37
5.2.4 Fracture Toughness 5.2-38 5.2.4.1 Compliance with Code Requirements 5.2-38 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 5 CONTENTS (Continued) Section Title Page iii Revision 21 September 2013 5.2.4.2 Acceptable Fracture Energy Levels 5.2-39 5.2.4.3 Operating Limitations During Startup and Shutdown 5.2-40 5.2.4.4 Compliance with Reactor Vessel Material Surveillance Program Requirements 5.2-40 5.2.4.5 Reactor Vessel Annealing 5.2-51 5.2.4.6 LOCA Thermal Transient 5.2-52
5.2.5 Austenitic Stainless Steel 5.2-53 5.2.5.1 Cleaning and Contamination Protection Procedures 5.2-53 5.2.5.2 Solution Heat Treatment Requirements 5.2-54 5.2.5.3 Material Inspection Program 5.2-54 5.2.5.4 Unstabilized Austenitic Stainless Steel 5.2-54 5.2.5.5 Avoidance of Sensitization 5.2-54 5.2.5.6 Retesting Unstabilized Austenitic Stainless Steel Exposed to Sensitizing Temperatures 5.2-56 5.2.5.7 Control of Delta Ferrite 5.2-57
5.2.6 Pump Flywheels 5.2-58 5.2.6.1 Compliance with AEC Safety Guide 14 5.2-58 5.2.6.2 Additional Data and Analyses 5.2-59
5.2.7 Reactor Coolant Pressure Boundary Leakage Detection System 5.2-59 5.2.7.1 Leakage Detection Methods 5.2-60 5.2.7.2 Indication in Control Room 5.2-62 5.2.7.3 Limits for Reactor Coolant Leakage 5.2-63 5.2.7.4 Unidentified Leakage 5.2-63 5.2.7.5 Maximum Allowable Total Leakage 5.2-65 5.2.7.6 Differentiation Between Identified and Unidentified Leaks 5.2-65 5.2.7.7 Sensitivity and Operability Tests 5.2-67
5.2.8 Inservice Inspection Program 5.2-68
5.2.9 Leakage Prediction from Primary Coolant Sources Outside Containment 5.2-69
5.2.10 References 5.2-69
5.3 THERMAL HYDRAULIC SYSTEM DESIGN 5.3-1
5.3.1 Analytical Methods and Data 5.3-1
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 5 CONTENTS (Continued) Section Title Page iv Revision 21 September 2013 5.3.2 Operating Restrictions on Reactor Coolant Pumps 5.3-1 5.3.3 Temperature-Power Operating Map 5.3-1 5.3.4 Load Following Characteristics 5.3-1 5.3.5 Transient Effects 5.3-2 5.3.6 Thermal and Hydraulic Characteristics Summary Table 5.3-2 5.4 REACTOR VESSEL AND APPURTENANCES 5.4-1 5.4.1 Reactor Vessel Description 5.4-1 5.4.1.1 Design Bases 5.4-1 5.4.1.2 Design Transients 5.4-1 5.4.1.3 Codes and Standards 5.4-1 5.4.1.4 Reactor Vessel Description 5.4-2 5.4.1.5 Inspection Provisions 5.4-2 5.4.2 Features for Improved Reliability 5.4-4 5.4.3 Protection of Closure Studs 5.4-4 5.4.4 Materials and Inspections 5.4-4 5.4.5 Special Processes for Fabrication and Inspection 5.4-4 5.4.5.1 Fabrication Processes 5.4-4 5.4.5.2 Tests and Inspections 5.4-5 5.4.6 Quality Assurance Surveillance 5.4-6 5.4.7 Reactor Vessel Design Data 5.4-6 5.4.8 Reactor Vessel Evaluation 5.4-6 5.5 COMPONENT AND SUBSYSTEM DESIGN 5.5-1 5.5.1 Reactor Coolant Pumps 5.5-1 5.5.1.1 Design Bases 5.5-1 5.5.1.2 Design Description 5.5-1 5.5.1.3 Design Evaluation 5.5-3 5.5.1.4 Tests and Inspections 5.5-8 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 5 CONTENTS (Continued) Section Title Page v Revision 21 September 2013 5.5.2 Steam Generators 5.5-10 5.5.2.1 Design Bases 5.5-10 5.5.2.2 Design Description 5.5-10 5.5.2.3 Design Evaluation 5.5-12 5.5.2.4 Tests and Inspections 5.5-14 5.5.2.5 Steam Generator Tube Surveillance Program 5.4-15
5.5.3 Reactor Coolant Piping 5.5-16 5.5.3.1 Design Bases 5.5-16 5.5.3.2 Design Description 5.5-17 5.5.3.3 Design Evaluation 5.5-19 5.5.3.4 Tests and Inspections 5.5-20
5.5.4 Main Steam Line Flow Restrictors 5.5-20
5.5.5 Main Steam Line Isolation System 5.5-20
5.5.6 Residual Heat Removal System 5.5-21 5.5.6.1 Design Bases 5.5-21 5.5.6.2 System Description 5.5-21 5.5.6.3 Design Evaluation 5.5-26 5.5.6.4 Tests and Inspections 5.5-29
5.5.7 Reactor Coolant Cleanup System 5.5-29
5.5.8 Main Steam Line and Feedwater Piping 5.5-29
5.5.9 Pressurizer 5.5-30 5.5.9.1 Design Bases 5.5-30 5.5.9.2 Design Description 5.5-31 5.5.9.3 Design Evaluation 5.5-32 5.5.9.4 Tests and Inspections 5.5-35
5.5.10 Pressurizer Relief Tank 5.5-35 5.5.10.1 Design Bases 5.5-35 5.5.10.2 Design Description 5.5-35 5.5.10.3 Design Evaluation 5.5-36 5.5.11 Valves 5.5-36 5.5.11.1 Design Bases 5.5-36 5.5.11.2 Design Description 5.5-37 5.5.11.3 Design Evaluation 5.5-38 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 5 CONTENTS (Continued) Section Title Page vi Revision 21 September 2013 5.5.11.4 Tests and Inspections 5.5-38 5.5.12 Safety and Relief Valves 5.5-38 5.5.12.1 Design Bases 5.5-38 5.5.12.2 Design Description 5.5-38 5.5.12.3 Design Evaluation 5.5-39 5.5.12.4 Tests and Inspections 5.5-39
5.5.13 Component Supports 5.5-40 5.5.13.1 Design Bases 5.5-40 5.5.13.2 Design Description 5.5-40 5.5.13.3 Design Evaluation 5.5-42
5.5.14 Reactor Vessel Head Vent System 5.5-43 5.5.14.1 Design Bases 5.5-43 5.5.14.2 Design Description 5.5-43 5.5.14.3 Supports 5.5-44 5.5.15 References 5.5-45 5.5.16 Reference Drawings 5.5-45
5.6 INSTRUMENTATION REQUIREMENTS 5.6-1
5.6.1 Pressurizer and Coolant Loops 5.6-1
5.6.2 Residual Heat Removal (RHR) System 5.6-2
5.6.3 References 5.6-2
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 5 TABLES Table Title vii Revision 21 September 2013 5.1-1 System Design and Operating Parameters 5.2-1 ASME Code Cases for Westinghouse PWR Class A Components
5.2-2 Equipment Code and Classification List
5.2-3 Procurement Information - Components Within Reactor Coolant System Boundary 5.2-4 Summary of Reactor Coolant System Design Transients
5.2-5 Stress Limits for Class A Components
5.2-6 Load Combinations and Stress Criteria for Westinghouse Primary Equipment 5.2-7 Faulted Condition Stress Limits for Class A Components 5.2-8 Loading Combinations and Acceptance Criteria for Primary Equipment Supports 5.2-9 Active and Inactive Valves in the Reactor Coolant Pressure Boundary
5.2-10 Reactor Coolant System Design Pressure Setpoints (psig)
5.2-11 Reactor Vessel Materials
5.2-12 Pressurizer, Pressurizer Relief Tanks and Surge Line Materials
5.2-13 Reactor Coolant Pump Materials
5.2-14 Steam Generator Materials
5.2-15 Reactor Coolant Water Chemistry Specification
5.2-16 Reactor Coolant Boundary Leakage Detection Systems
5.2-17 Deleted in Revision 2
5.2-17A DCPP Unit 1 Reactor Vessel Toughness Data DCPP UNITS 1 & 2 FSAR UPDATE Chapter 5 TABLES (Continued) Table Title viii Revision 21 September 2013 5.2-17B DCPP Unit 2 Reactor Vessel Toughness Data 5.2-18 Deleted in Revision 2
5.2-18A Identification of Unit 1 Reactor Vessel Beltline Region Base Material
5.2-18B Identification of Unit 2 Reactor Vessel Beltline Region Base Material
5.2-19 Deleted in Revision 2
5.2-19A Fracture Toughness Properties of Unit 1 Reactor Vessel Beltline Region Base Material 5.2-19B Fracture Toughness Properties of Unit 2 Reactor Vessel Beltline Region Base Material 5.2-20 Deleted in Revision 2 5.2-20A Identification of Unit 1 Reactor Vessel Beltline Region Weld Metal 5.2-20B Identification of Unit 2 Reactor Vessel Beltline Region Weld Metal
5.2-21 Deleted in Revision 2
5.2-21A Fracture Toughness Properties of Unit 1 Reactor Vessel Beltline Region Weld Metal 5.2-21B Fracture Toughness Properties of Unit 2 Reactor Vessel Beltline Region Weld Metal 5.2-22 Reactor Vessel Material Surveillance Program Withdrawal Schedule 5.2-23 Reactor Coolant System Pressure Boundary Isolation Valves
5.4-1 Reactor Vessel Design Parameters (Both Units)
5.4-2 Reactor Vessel Quality Assurance Program
5.5-1 Reactor Coolant Pump Design Parameters (Both Units)
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 5 TABLES (Continued) Table Title ix Revision 21 September 2013 5.5-2 Reactor Coolant Pump Quality Assurance Program 5.5-3 Steam Generator Design Data
5.5-4 Deleted in Revision 4
5.5-5 Steam Generator Quality Assurance Program (Both Units)
5.5-6 Reactor Coolant Piping Design Parameters (Both Units)
5.5-7 Reactor Coolant Piping Quality Assurance Program (Both Units)
5.5-8 Design Bases for Residual Heat Removal System Operation (Both Units) 5.5-9 Residual Heat Removal System Codes and Classifications (Both Units) 5.5-10 Residual Heat Removal System Component Data (Both Units) 5.5-11 Recirculation Loop Leakage
5.5-12 Pressurizer Design Data
5.5-13 Pressurizer Quality Assurance Program (Both Units)
5.5-14 Pressurizer Relief Tank Design Data
5.5-15 Reactor Coolant System Boundary Valve Design Parameters
5.5-16 Pressurizer Valves Design Parameters
5.5-17 Reactor Vessel Head Vent System Equipment Design Parameters
DCPP UNITS 1 & 2 FSAR UPDATE x Revision 21 September 2013 Chapter 5 FIGURES Figure Title 5.1-1 Deleted in Revision 1
5.1-2 Pump Head-Flow Characteristics
5.2-1 Identification and Location of Beltline Region Material for the Reactor Vessel (Unit 1) 5.2-2 Reactor Coolant Loop Model
5.2-2A Deleted in Revision 19
5.2-3 THRUST RCL Model Showing Hydraulic Force Location
5.2-3A Deleted in Revision 19
5.2-4 Identification and Location of Beltline Region Material for the Reactor Vessel (Unit 2) 5.2-5 Deleted in Revision 2 5.2-6 Deleted in Revision 9 5.2-7 Lower Bound Fracture Toughness A533, GR.B, C1.1
5.2-8 Transition Temperature Correlation Between Kld (Dynamic) and Cv for a Series of Unirradiated Steels 5.2-9 Containment Monitor Response Time Versus Primary Leak Rate
5.2-10 Air Ejector Radiogas Monitor Response Time Versus Primary Leak Rate 5.2-11 Blowdown Liquid Monitor Response Time Versus Primary Leak Rate
5.2-12 Containment Cooling Water Liquid Monitor Response Time Versus Primary Leak Rate 5.2-13 Containment Area Monitor Response Time Versus Primary Leak Rate DCPP UNITS 1 & 2 FSAR UPDATE Chapter 5 FIGURES (Continued) Figure Title xi Revision 21 September 2013 5.2-14 Containment Radiogas Monitor Count Rate Versus Primary Leak Rate after Equilibrium 5.2-15 Containment Particulate Monitor Count Rate Versus Primary Leak Rate after Equilibrium 5.2-16 Surveillance Capsule Elevation View (Unit 1) 5.2-17 Surveillance Capsule Plan View (Unit 1)
5.2-18 Surveillance Capsule Elevation View (Unit 2)
5.2-19 Surveillance Capsule Plan View (Unit 2)
5.3-1 Hot Leg, Cold Leg, and Average Reactor Coolant Loop Temperature as a Function of Percent Full Power 5.4-1 Reactor Vessel (Unit 1)
5.4-2 Reactor Vessel (Unit 2)
5.5-1 Reactor Coolant Controlled Leakage Pump
5.5-2 Reactor Coolant Pump Estimated Performance Characteristics
5.5-3 Reactor Coolant Pump Spool Piece and Motor Support Stand
5.5-4 Westinghouse Delta 54 Steam Generator
5.5-4A Deleted in Revision 19
5.5-5 Deleted in Revision 19
5.5-6 Deleted in Revision 19
5.5-7 Deleted in Revision 1
5.5-8 Pressurizer
5.5-9 Reactor Support
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 5 FIGURES (Continued) Figure Title xii Revision 21 September 2013 5.5-10 Steam Generator and Reactor Coolant Pump Supports 5.5-11 Component Supports
5.5-12 Pressurizer Support
5.5-13(a) U1: Function Diagram, Reactor-Turbine Generator Protection 5.5-14 Schematic Flow Diagram of the Reactor Vessel Head Vent System
5.5-14A Deleted in Revision 20
5.5-15 Deleted in Revision 20
5.5-16 Deleted in Revision 8
5.5-17(a) U2: Function Diagram, Reactor-Turbine Generator Protection 5.5-18 Seven Nozzle RSG Outlet Flow Restrictor
NOTE:
(a) This figure corresponds to a controlled engineering drawing that is incorporated by reference into the FSAR Update. See Table 1.6-1 for the correlation between the FSAR Update figure number and the corresponding controlled engineering drawing number.
DCPP UNITS 1 & 2 FSAR UPDATE xiii Revision 21 September 2013 Chapter 5 APPENDICES Title Title 5.5A CAPABILITY OF MAIN STEAM ISOLATION AND CHECK VALVES TO WITHSTAND CLOSURE LOADS FOLLOWING A POSTULATED MAIN STEAM LINE BREAK
DCPP UNITS 1 & 2 FSAR UPDATE 5.1-1 Revision 19 May 2010 Chapter 5 REACTOR COOLANT SYSTEM 5.1 SUMMARY DESCRIPTION The reactor coolant system (RCS) consists of four similar heat transfer loops connected in parallel to the reactor pressure vessel, which are located inside the containment. Each loop contains a reactor coolant pump, steam generator, and associated piping and valves. The system also includes a pressurizer, a pressurizer relief tank, interconnecting piping, and instrumentation necessary for operation.
During operation, the RCS transfers heat generated in the core to the steam generators where the steam that drives the turbine-generator is produced. Borated pressurized water circulates in the RCS at a flowrate and temperature consistent with the reactor core thermal-hydraulic performance requirements. The water also acts as a neutron moderator and reflector, and as a solvent for the boric acid neutron absorber used as chemical shim control.
The RCS pressure boundary provides a barrier against the release of radioactivity generated within the reactor, and is designed to ensure a high degree of integrity throughout plant life.
RCS pressure is controlled by the pressurizer in which water and steam are maintained in equilibrium by electrical heaters or water sprays. Steam can be formed (by the heaters) or condensed (by the pressurizer spray) to minimize reactor coolant pressure variations. Spring-loaded safety valves and power-operated relief valves are mounted on the pressurizer, and discharge to the pressurizer relief tank where the steam is condensed and cooled by mixing with water. Noncondensable gases (primarily) or steam can be removed from the reactor vessel head by the reactor vessel head vent system (RVHVS). 5.1.1 SCHEMATIC FLOW DIAGRAM Figure 3.2-7 is a schematic flow diagram of the reactor coolant system. Principal pressures, temperatures, flowrates, and coolant volume under normal full power operating conditions are listed in Table 5.1-1.
The RCS pressure boundary is defined as:
(1) The reactor vessel, including control rod drive mechanism housings (2) The reactor coolant side of the steam generators (3) Reactor coolant pump casings DCPP UNITS 1 & 2 FSAR UPDATE 5.1-2 Revision 19 May 2010 (4) A pressurizer attached to one of the reactor coolant loops (5) Safety and relief valves (6) The interconnecting piping, valves, and fittings between the principal components listed above (7) The piping, fittings, and valves leading to connecting auxiliary or support systems up to and including the second isolation valve (from the high-pressure side) on each line 5.1.2 PIPING AND INSTRUMENTATION DIAGRAMS RCS piping and instrumentation are shown schematically in Figure 3.2-7.
5.1.3 ELEVATION DRAWINGS Physical layout of the RCS is shown in the following figures: Figures 1.2-4, 1.2-5, and 1.2-6 (plan views inside containment) Figures 1.2-22, 1.2-24, and 1.2-28 (section views inside containment) Figure 5.5-10 (steam generator and reactor coolant pump supports) Figure 5.5-11 (component supports) Figure 5.5-12 (pressurizer support) 5.1.4 REACTOR COOLANT SYSTEM COMPONENTS The principal RCS components are described in this section. 5.1.4.1 Reactor Vessel The reactor vessel is a cylindrical vessel with a welded hemispherical bottom head and a removable, bolted, flanged, and gasketed, hemispherical upper head. The vessel contains the core, core supporting structures, control rods, and other parts directly associated with the core. The RVHVS, consisting of four remotely operated solenoid valves in two trains, each with two valves in series, is installed on the upper head.
The vessel has inlet and outlet nozzles located in a horizontal plane just below the reactor vessel flange, but above the top of the core. Coolant enters the vessel through the inlet nozzles and most of it flows down the core barrel-vessel wall annulus, turns, and flows up through the core to the outlet nozzles (Figures 5.4-1 and 5.4-2). 5.1.4.2 Steam Generators The steam generators are vertical shell and U-tube evaporators with integral moisture separating equipment. The reactor coolant flows through inverted U-tubes, entering DCPP UNITS 1 & 2 FSAR UPDATE 5.1-3 Revision 19 May 2010 and leaving through the nozzles located in the hemispherical bottom head of the steam generator. Steam is generated on the shell side and flows upward through the moisture separators to the outlet nozzle at the top of the vessel. 5.1.4.3 Reactor Coolant Pumps The reactor coolant pumps are identical single-speed centrifugal units driven by air-cooled, three-phase induction motors. The shaft is vertical with the motor mounted above the pumps. A flywheel on the shaft above the motor provides additional rotational energy to extend pump coastdown. The inlet is at the bottom of the pump; discharge is on the side. 5.1.4.4 Piping Sizing of reactor coolant loop piping is consistent with system requirements. RCS hot leg piping is 29 inches ID and the cold leg return line to the reactor vessel is 27-1/2 inches ID. The piping between the steam generator and the pump suction is 31 inches ID to reduce pressure drop and improve flow conditions to the pump suction. To further improve pump suction conditions, a flow splitter is provided in the pipe bend upstream of the pump suction. 5.1.4.5 Pressurizer The pressurizer is a vertical, cylindrical vessel with hemispherical top and bottom heads. Electrical heaters are installed through the bottom head of the vessel while the spray nozzle and the relief and safety valve connections are located in the top head of the vessel. The heaters can be removed for maintenance or replacement. 5.1.4.6 Pressurizer Relief Tank The pressurizer relief tank (PRT) is a horizontal, cylindrical vessel with elliptical ends. Steam from the pressurizer safety and relief valves is discharged into the PRT through a sparger pipe submerged below the water level. This condenses and cools the steam by mixing it with water that is near ambient temperature. The PRT is provided with 2 rupture disks set at 100 psig. 5.1.4.7 Safety and Relief Valves The pressurizer safety valves are spring-loaded, self-activated with back-pressure compensation. The power-operated relief valves (PORVs) limit system pressure for large power mismatch and thus prevent actuation of the fixed high-pressure reactor trip. They operate automatically or by remote manual control. Remotely operated valves are provided to isolate the inlet to the PORVs if excessive seat leakage occurs in the PORVs. Acoustic monitors are provided to monitor leaking safety valves.
DCPP UNITS 1 & 2 FSAR UPDATE 5.1-4 Revision 19 May 2010 5.1.5 REACTOR COOLANT SYSTEM PERFORMANCE AND SAFETY FUNCTIONS Design and performance characteristics of the RCS are provided in Table 5.1-1. 5.1.5.1 Reactor Coolant Flow The reactor coolant flow, a major parameter in the design of the system and its components, is established using a detailed design procedure supported by operating plant performance data, by pump model tests and analysis, and by pressure drop tests and analyses of the reactor vessel and fuel assemblies. Data from all operating plants have indicated that the actual flow has been well above the flow specified for the thermal design of the plant. 5.1.5.2 Best Estimate Flow The best estimate flow is the most likely value for the actual plant operating condition. This flow is based on the best estimate of the reactor vessel, steam generator and piping flow resistance, and on the best estimate of the reactor coolant pump head-flow capacity, with no uncertainties assigned to either the system flow resistance or the pump head. Although the best estimate flow is the most likely value to be expected in operation, more conservative flowrates are applied in the thermal and mechanical designs. 5.1.5.3 Thermal Design Flow Thermal design flow is the basis for the reactor core thermal performance, the steam generator thermal performance, and the nominal plant parameters used throughout the design. To provide the required margin, the thermal design flow accounts for the uncertainties in the reactor vessel, steam generator, and piping flow resistances, reactor coolant pump head, and the methods used to measure flowrate. The combination of these uncertainties, which includes a conservative estimate of the pump discharge weir flow resistance, is equivalent to increasing the best estimate RCS flow resistance by approximately 15-20 percent. The intersection of this conservative flow resistance with the best estimate pump curve, (an example is shown in Figure 5.1-2), establishes the thermal design flow. This procedure provides a flow margin for thermal design that is confirmed when the plant is in operation. Tabulations of important design and performance characteristics of the RCS, as provided in Table 5.1-1, are based on the thermal design flow, as indicated. 5.1.5.4 Mechanical Design Flow Mechanical design flow is the flow used in the mechanical design of the reactor vessel internals and fuel assemblies. To ensure that a conservatively high flow is specified, the mechanical design flow is based on a reduced system resistance (90 percent of best estimate) and on increased pump head capability (107 percent of best estimate). DCPP UNITS 1 & 2 FSAR UPDATE 5.1-5 Revision 19 May 2010 The intersection of this flow resistance with the higher pump curve, (an example is shown in Figure 5.1-2), establishes the mechanical design flow. 5.1.5.5 System and Components The interrelated performance and safety functions of the RCS and its major components are listed below:
(1) The RCS provides sufficient heat transfer capability to transfer the heat produced during power operation and the initial phase of plant cooldown, when the reactor is subcritical, to the steam system via the steam generator. (2) The system provides sufficient heat transfer capability to transfer the heat produced during the subsequent phase of plant cooldown and cold shutdown to the residual heat removal (RHR) system. (3) The system heat removal capability under power operation and normal operational transients, including the transition from forced to natural circulation, ensures that no fuel damage occurs within the operating bounds permitted by the reactor control and protection systems. (4) The RCS contains the water used as the core neutron moderator and reflector and as a solvent for chemical shim control. (5) The system, together with the chemical and volume control system (CVCS), maintains the homogeneity of soluble neutron poison concentration and controls the rate of change of coolant temperature, preventing uncontrolled reactivity changes. (6) The reactor vessel is an integral part of the RCS pressure boundary and can accommodate the temperatures and pressures associated with operational transients. The reactor vessel supports the reactor core and control rod drive mechanisms. (7) The pressurizer maintains system pressure during operation and limits pressure transients. During plant load reduction or increase, reactor coolant volume changes are accommodated in the pressurizer via the surge line. (8) The reactor coolant pumps supply the coolant flow necessary to remove heat from the reactor core and transfer it to the steam generators. (9) The steam generators provide high quality steam to the turbine. The tube and tubesheet boundary are designed to prevent the transfer of radioactivity generated within the core to the secondary system.
DCPP UNITS 1 & 2 FSAR UPDATE 5.1-6 Revision 19 May 2010 (10) The RCS piping constitutes a boundary to contain the coolant under operating temperature and pressure conditions and limit leakage (and radioactivity release) to the containment atmosphere. It contains pressurized water that is circulated at a flowrate and temperature, which is consistent with reactor core thermal and hydraulic performance requirements. (11) The RVHVS can be used to remove noncondensable gases or steam from the reactor vessel head by remote-manual operation from the control room. 5.1.6 SYSTEM OPERATION Brief descriptions of normal plant operations covering plant startup, power generation, hot shutdown, cold shutdown, and refueling are provided below. 5.1.6.1 Plant Startup Plant startup encompasses the operations which bring the reactor plant from cold shutdown to no-load power operating temperature and pressure.
Before plant startup, the reactor coolant loops and pressurizer are filled completely with reactor coolant to eliminate noncondensable gases. If the vacuum refill method of filling the RCS is performed, the vacuum process will remove noncondensable gases and the pressurizer will not need to be filled completely. The water contains the correct concentration of boron to maintain shutdown margin. The secondary side of the steam generator is filled with water to normal startup level. The RCS is then pressurized using the low-pressure control valve and either the centrifugal charging pump (CCP3) (preferentially) or the centrifugal charging pumps (CCP1 and CCP2) to obtain the required pressure drop across the No. 1 seal of the reactor coolant pumps. The pumps may then be operated intermittently in venting operations. As an alternative, a vacuum process can be used in filling the RCS. If this method is used, operating the reactor coolant pumps intermittently to aid venting noncondensable gases may not be required. During reactor coolant pump operation, the centrifugal charging pump (CCP3) (or a charging pump (CCP1 or CCP2)) and the low-pressure letdown path from the RHR system to the CVCS maintain the necessary RCS pressure. Reactor coolant pump operation is initiated after the required pressure differential across the No. 1 seal is achieved. The brittle fracture prevention temperature limitations of the reactor vessel impose an upper pressure limit during low temperature operation. The charging pump supplies seal injection water for the reactor coolant pump shaft seals. A nitrogen atmosphere and normal operating temperature, pressure, and water level are established in the pressurizer relief tank.
DCPP UNITS 1 & 2 FSAR UPDATE 5.1-7 Revision 19 May 2010 After venting, the RCS is pressurized, all reactor coolant pumps are started, and the pressurizer heaters are energized to begin heating the reactor coolant in the pressurizer, which leads to formation of the steam bubble. If the vacuum refill method of filling the RCS is performed, a pressurizer steam bubble may be formed prior to starting the reactor coolant pumps. The pressurizer liquid level is reduced until the no-load power level volume is established. During the initial heatup phase, hydrazine is added to the reactor coolant to scavenge the oxygen in the system; the heatup is not taken beyond 180°F until the oxygen level has been reduced to the specified level. As the reactor coolant temperature increases, the pressurizer heaters are manually controlled to maintain adequate suction pressure for the reactor coolant pumps. 5.1.6.2 Power Generation and Hot Standby Power generation includes steady state operation, ramp changes not exceeding the rate of 5 percent of full power per minute, step changes of 10 percent of full power (not exceeding full power), and step load decreases with steam dump not exceeding 95 percent of full power.
During power generation, RCS pressure is maintained by the pressurizer controller at or near 2235 psig, while the pressurizer liquid level is controlled by the charging-letdown flow control of the CVCS.
When the reactor power level is less than 15 percent, the reactor power is controlled manually. At powers above 15 percent, the operator may select the automatic mode of operation. The rod motion is then controlled by the reactor control system that automatically maintains an average coolant temperature, which follows a program based on turbine load. During hot standby operations, when the reactor is subcritical, the RCS temperature is maintained by steam dump to the main condenser. This is accomplished by valves in the steam line, operating in the pressure control mode, which is set to maintain the steam generator steam pressure, or manually. Residual heat from the core or operation of a reactor coolant pump provides heat to overcome RCS heat losses. 5.1.6.3 Plant Shutdown Plant shutdown is the operation that brings the reactor plant from no-load power operating temperature and pressure to cold shutdown. During plant cooldown from hot standby to hot shutdown conditions, concentrated boric acid solution from the CVCS is added to the RCS to increase the reactor coolant boron concentration to that required for cold shutdown. If the RCS is to be opened during the shutdown, the hydrogen and fission gas in the reactor coolant is reduced by degassing the coolant in the volume control tank.
DCPP UNITS 1 & 2 FSAR UPDATE 5.1-8 Revision 19 May 2010 Plant shutdown is attained in two phases: first, by the combined use of the RCS and steam systems, and, second, by the RHR system. During the first phase of shutdown, residual core and reactor coolant heat are transferred to the main steam system via the steam generator. Steam from the steam generator is dumped to the main condenser or to the atmosphere. At least one reactor coolant pump is kept running to ensure uniform RCS cooldown. Pressurizer heaters and spray flow are manually controlled to cool the pressurizer while maintaining the required reactor coolant pump suction pressure. The plant does not permit the pressurizer to go water-solid without the RHR system and low temperature overpressure protection systems in service. As the pressurizer cools, the low-pressure control valve, pressurizer spray, pressurizer heaters, and the charging pumps maintain the required RCS pressure. When the reactor coolant temperature is below approximately 350°F and the nominal pressure is less than or equal to 390 psig, the second phase of shutdown commences with the operation of the RHR system.
Typically at least one reactor coolant pump (either of those in a loop containing a pressurizer spray line) is kept running until the coolant temperature is reduced to approximately 145°F. Pressurizer cooldown continues by initiating auxiliary spray flow from the CVCS if reactor coolant pumps are not available. Plant shutdown continues until the reactor coolant temperature is 140°F or less. 5.1.6.4 Refueling Before removing the reactor vessel head for refueling, the system temperature is reduced to 140°F or less, and hydrogen and fission product levels are reduced. Water level is monitored to indicate when the water level is below the top of the reactor vessel head. Draining continues until the water level is below the reactor vessel flange. The vessel head is then removed and the refueling cavity is flooded. Upon completion of refueling, the system is refilled for plant startup. 5.1.6.5 Mid-Loop Operation During refueling conditions, steam generator nozzle dams may be used in accordance with approved plant procedures to isolate the steam generator U-tubes from the reactor coolant system for inspection and maintenance. The steam generators are discussed in Section 5.5.2.
Use of steam generator nozzle dams requires lowering the water level in the RCS to a level below that necessary to remove the reactor head (i.e., partial drain or mid-loop operation). Mid-loop operation, when performed in accordance with approved plant procedures, is acceptable when core decay heat is less than or equal to 15.3 MWt (Reference 1). During mid-loop operation, water level is closely monitored to ensure adequate decay heat removal by the RHR system.
DCPP UNITS 1 & 2 FSAR UPDATE 5.1-9 Revision 19 May 2010 5.
1.7 REFERENCES
- 1. RCS Pressurization Analysis for Diablo Canyon Shutdown Scenarios, Westinghouse Technical Report, April 1997.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-1 Revision 21 September 2013 5.2 INTEGRITY OF THE REACTOR COOLANT PRESSURE BOUNDARY The reactor coolant system (RCS) boundary is designed to accommodate the system pressures and temperatures attained under all expected modes of plant operation, including all anticipated transients, and to maintain the resulting stresses within allowable values. The system is protected from overpressure by means of pressure relieving devices as required by applicable codes and a special system for low temperature operation. Materials of construction are specified to minimize corrosion and erosion and to provide a structure and system pressure boundary that will maintain its integrity throughout the life of the plant. Inspections in accordance with Reference 8, and provisions for surveillance of critical areas to enable periodic assessment of the boundary integrity, are made. 5.2.1 DESIGN OF REACTOR COOLANT PRESSURE BOUNDARY COMPONENTS The RCS transfers heat from the reactor to the steam generators under conditions of both forced and natural circulation flow. The heat transfer capability of the steam generators is sufficient to transfer to the steam and power conversion system the heat generated during normal operation and the initial phase of plant cooldown under natural circulation conditions.
During the second phase of plant cooldown and during cold shutdown and refueling, the heat exchangers of the residual heat removal (RHR) system are employed. Their capability is discussed in Section 5.5.
RCS pumps ensure heat transfer by forced circulation flow. They are also discussed in Section 5.5. Initial RCS tests are performed to determine the circulation capability of the reactor coolant pumps. Thus, adequate reactor coolant circulation is confirmed prior to plant operation.
To ensure a heat sink for the reactor under conditions of natural circulation flow, the steam generators are at a higher elevation than the reactor. The steam generators provide sufficient tube area to ensure an adequate residual heat removal rate with natural circulation flow. This was confirmed by post-TMI generic testing.
Whenever the RCS boron concentration is varied, good mixing is provided to ensure uniform boron concentration throughout the RCS. Although pressurizer mixing is not achieved to the same degree, the fraction of the total RCS volume, which is in the pressurizer is small. Pressurizer spray provides homogenization of boron concentration.
Also, the distribution of flow around the system is not subject to the degree of variation that would be required to produce nonhomogeneities in coolant temperature or boron concentration as a result of areas of low coolant flowrate.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-2 Revision 21 September 2013 Coolant temperature variation during normal operation is limited and the associated reactivity change is well within the capability of the rod control group movement. For design evaluation, the RCS heatup and cooldown transients are analyzed using a rate of temperature change equal to 100°F per hour. Over certain temperature ranges, fracture prevention criteria will impose a lower limit to heatup and cooldown rates.
Before plant cooldown is initiated, the boron concentration in the RCS is increased to the value required for the corresponding target temperature. Subsequent reactor coolant samples are taken to verify that the RCS boron concentration is correct. During plant cooldown, minimum shutdown margin (SDM) is maintained in accordance with requirements of the Diablo Canyon Power Plant (DCPP) Technical Specifications (Reference 19). The temperature changes imposed on the RCS during its normal modes of operation do not cause any unacceptable reactivity changes. 5.2.1.1 Performance Objectives The performance objectives of the RCS are described in Section 5.1. Equipment codes and classification of the components within the RCS boundary are listed in Table 5.2-2. Procurement information for major RCS components is provided in Table 5.2-3.
The following five operating conditions are considered in the design of the RCS:
(1) Normal Conditions Any condition in the course of startup, operation in the design power range, hot standby and system shutdown, other than upset, emergency, faulted, or testing conditions. (2) Upset Conditions Any deviations from normal conditions anticipated to occur often enough that the design should include a capability to withstand the conditions without operational impairment. The upset conditions include those transients that result from any single operator error control malfunction, transients caused by a fault in a system component requiring its isolation from the system, and transients due to loss of load or power. Upset conditions include any abnormal incidents not resulting in a forced outage and also forced outages for which the corrective action does not include any repair of mechanical damage. The estimated duration of an upset condition was included in the design specifications. (3) Emergency Conditions Emergency conditions are those deviations from normal conditions that require shutdown for correction of the conditions or repair of damage in DCPP UNITS 1 & 2 FSAR UPDATE 5.2-3 Revision 21 September 2013 the system. These conditions have a low probability of occurrence but are included to ensure that no gross loss of structural integrity results as a concomitant effect of any damage developed in the system. The total number of postulated occurrences for such events will not cause more than 25 stress cycles having an Sa value greater than that for 106 cycles from the applicable ASME Boiler and Pressure Vessel (ASME B&PV)
Code, Section III, fatigue design curves. (4) Faulted Conditions Faulted conditions are those combinations of conditions associated with extremely low probability postulated events whose consequences are such that the integrity and operability of the nuclear energy system may be impaired to the extent that considerations of public health and safety are involved. Such conditions require compliance with safety criteria as may be specified by jurisdictional authorities. (5) Testing Conditions Testing conditions are those tests, in addition to the hydrostatic or pneumatic tests, permitted by the ASME B&PV Code, Section III, including leak tests or subsequent hydrostatic tests. 5.2.1.2 Design Parameters The RCS, in conjunction with the reactor control and protection systems, maintains the reactor coolant at conditions of temperature, pressure, and flow adequate to protect the core from damage. The safety design requirements are to prevent conditions of high power, high reactor coolant temperature, or low reactor coolant pressure, or buildup of noncondensable gases which could interfere with core cooling, or combinations of these which could result in a departure from nucleate boiling ratio (DNBR) smaller than the applicable limit value (refer to Sections 4.4.1.1 and 4.4.2.3). The chemical and volume control system (CVCS) is designed to avoid uncontrolled reductions in boric acid concentration or reactor coolant temperature. The reactor coolant is the core moderator, reflector, and solvent for the chemical shim. As a result, changes in coolant temperature or boric acid concentration affect the reactivity level in the core.
The following design bases have been selected to ensure that uniform RCS boron concentration and temperature are maintained:
(1) Coolant flow is provided by either a reactor coolant pump or an RHR pump to ensure uniform mixing whenever the boron concentration is varied.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-4 Revision 21 September 2013 (2) The RCS design arrangement eliminates dead ended sections and other areas of low coolant flow in which nonhomogeneities in coolant temperature or boron concentration could develop. (3) The RCS is designed to operate within the coolant temperature change limitations. The design pressure for the RCS is 2485 psig except for the pressurizer relief line between the safety valve and the pressurizer relief tank (PRT), which is designed for 600 psig, and the PRT itself, which is designed for 100 psig. Normal RCS operating pressure is 2235 psig. RCS design temperature is 650°F, except for the pressurizer and its surge line, which are designed for 680°F, and the pressurizer relief line from the safety valve to the PRT, which is designed for 340°F. Design parameters for other system components are discussed in Section 5.5. 5.2.1.3 Compliance with 10 CFR 50.55a Codes and standards applicable to reactor coolant pressure boundary (RCPB) components are specified in 10 CFR 50.55a. They depend on when the plant was designed and constructed. Construction permits for DCPP Units 1 and 2 were issued on April 23, 1968, and December 9, 1970, respectively. Therefore, codes and standards specified in 10 CFR 50.55a for construction permits issued before January 1, 1971, are applicable to the DCPP.
The codes, standards, and component classifications used in the design and construction of the DCPP RCPB components are shown in Table 5.2-2 and are in accordance with the applicable provisions of 10 CFR 50.55a. These design codes specify applicable surveillance requirements including allowances for normal degradation. 5.2.1.4 Applicable Code Cases Although use of the normal, upset, emergency, and faulted condition terminology was introduced in codes (ASME B&PV Code, Section III, Summer 1968 Addenda) and standards after the code applicability date for the DCPP, analyses of RCS components in accordance with the more recent ASME B&PV Code conditions (normal, upset, and faulted) have been performed for the load combinations and associated stress limits identified in Tables 5.2-5, 5.2-6, and 5.2-7. Valves have been designed in accordance with USAS B16.5, in general, and ASME B&PV Code, Section VIII, for flange connections.
Most components within the RCPB which are equivalent to NRC Regulatory Guide (RG) 1.26 (Reference 20), Quality Group A, were supplied by Westinghouse Electric Corporation. Any application, by Westinghouse or its vendors, of the code cases in Table 5.2-1 is in accordance with ASME Code guidelines. Specific application of any of these code cases to both DCPP units has not been identified since, at the time of their DCPP UNITS 1 & 2 FSAR UPDATE 5.2-5 Revision 21 September 2013 fabrication, there was neither code, nor AEC requirements to maintain and update a centralized list of these code cases. 5.2.1.5 Design Transients To ensure the high degree of integrity of RCS equipment over the design life of the plant, fatigue evaluation is based on conservative estimates of the magnitude and frequency of temperature and pressure transients resulting from various operating conditions in the plant. To a large extent, the specific transient operating conditions to be considered for equipment fatigue analyses were determined by Westinghouse. The transients selected represent operating conditions that should be prudently anticipated during plant operation and are sufficiently severe or frequent to be of possible significance to component cyclic behavior.
The design cycles discussed herein are conservative estimates for equipment design purposes only and are not intended to be an accurate representation of actual transients or to reflect operating experience. As such, the number of occurrences specified in Table 5.2-4 is not an absolute limit, but reflect design bases assumptions. The design limit requires that the cumulative fatigue usage factor (as calculated per ASME code guidance) for the equipment or component is less than 1.0. Therefore, a higher number of occurrences may be allowable based upon evaluation of actual stresses.
A program has been established and will be maintained which will include tracking the number of cyclic or transient occurrences of Table 5.2-4 to ensure that components are maintained within their design limit unless the program demonstrates by other means that the design limit will not be exceeded. 5.2.1.5.1 Normal Conditions The following five transients are considered normal conditions:
(1) Heatup and Cooldown For design evaluation, the heatup and cooldown cases are represented by continuous heatup or cooldown at a rate of 100°F per hour, which corresponds conceivably to a heatup or cooldown rate that could only occur under upset or emergency conditions. Heatup brings the RCS from ambient to the no-load temperature and pressure conditions. Cooldown represents the reverse situation. Due to the practical limitations discussed below, the actual heatup rates will be lower than the limiting values, and typically will be on the order of 50°F per hour. Typical cooldown rates are approximately 80°F per hour.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-6 Revision 21 September 2013 The limitations on heatup reflect: (a) Criteria for prevention of nonductile failures that establish maximum permissible temperature change rates, as a function of plant pressure and temperature. (b) Slower initial heatup rates when using pumping energy only. (c) Interruptions in the heatup and cooldown cycles due to such factors as drawing a pressurizer steam bubble, rod withdrawal, sampling, water chemistry, and gas adjustments. Ideally, heatup and cooldown would occur only before and after refueling. In practice, additional unscheduled plant cooldowns may be necessary for plant maintenance. (2) Unit Loading and Unloading The unit loading and unloading cases under automatic reactor control are conservatively represented by a continuous and uniform ramp power change of 5 percent per minute between 15 percent load and full load. This load swing is the maximum possible consistent with operation under automatic reactor control. The reactor temperature varies with load as prescribed by the temperature control system. (3) Step Increase and Decrease of 10 percent The +/-10 percent step change in load demand is a control transient that is assumed to be a change in turbine control valve opening that might be caused by disturbances in the outside electrical network. The reactor control system is designed to restore plant equilibrium without reactor trip following a +/-10 percent step change in turbine load demand initiated from nuclear plant equilibrium conditions in the range between 15 and 100 percent of full load, the power range for automatic reactor control. During load change conditions, the reactor control system attempts to match turbine and reactor outputs in such a manner that peak reactor coolant temperature is minimized and reactor coolant temperature is restored to its programmed setpoint at a sufficiently slow rate to prevent an excessive decrease in pressurizer pressure. Following a step load decrease in turbine load, the secondary side steam pressure and temperature initially increase since the decrease in nuclear power lags behind the step decrease in turbine load. During the same time increment, the RCS average temperature and pressurizer pressure also increase initially. Because of the power mismatch between the turbine and reactor and the increase in reactor coolant temperature, the DCPP UNITS 1 & 2 FSAR UPDATE 5.2-7 Revision 21 September 2013 control system automatically inserts the control rods to reduce core power. The reactor coolant temperature is ultimately reduced from its peak value to a value below its initial equilibrium value at the beginning of the transient. Reactor coolant average temperature setpoint changes as a function of turbine-generator load, as determined by first-stage turbine pressure measurement. The pressurizer pressure also decreases from its peak pressure value and follows the reactor coolant decreasing-temperature trend. At some point during the decreasing-pressure transient, the saturated water in the pressurizer begins to flash, reducing the rate of pressure decrease. Subsequently, the pressurizer heaters come on to restore the plant pressure to its normal value. Following a step load increase in turbine load, the reverse situation occurs; i.e., the secondary side steam pressure and temperature initially decrease and the reactor coolant average temperature and pressure initially decrease. The control system automatically withdraws the control rods to increase core power. The decreasing pressure transient is reversed by actuation of the pressurizer heaters, and eventually the system pressure is restored to its normal value. The reactor coolant average temperature is raised to a value above its initial equilibrium value at the beginning of the transient. (4) Large Step Decrease in Load This transient applies to a step decrease in turbine load from full power of such magnitude that the resultant rapid increase in reactor coolant average temperature and secondary side steam pressure and temperature automatically initiates a secondary side steam dump system that prevents a reactor shutdown or lifting of steam generator safety valves. Thus, when a plant is designed to accept a step decrease of 95 percent from full power, it signifies that a steam dump system provides a heat sink to accept 85 percent of the turbine load. The remaining 10 percent of the total step change is assumed by the rod control system. If a steam dump system were not provided to cope with this transient, there would be such a large mismatch between what the turbine is demanding and what the reactor is furnishing that a reactor trip and lifting of steam generator safety valves would occur. DCPP was originally designed to accept step load reductions from 0 to 95 percent without a reactor trip (with 85 percent steam dump capability). A 95 percent step load decrease is rarely experienced in the operation of the plant, and when it does occur, there is a large duty imposed on all operating NSSS and control systems that make recovery from this transient difficult without the occurrence of a reactor trip. Therefore, the DCPP UNITS 1 & 2 FSAR UPDATE 5.2-8 Revision 21 September 2013 design basis load reduction transient for DCPP has been revised to a 50 percent step load reduction in the analyses performed for the replacement steam generators (RSGs) and Tavg range program, which is a common design basis transient for several Westinghouse plants.
The analysis for the 50 percent load reduction (References 33 and 35) shows that the DCPP control system is capable of controlling the RSG water level so that a reactor trip on steam generator low-low level or turbine trip / feedwater isolation on steam generator high-high level does not occur. Specific analysis results show that the steam generator level is maintained within +/-20 percent of the nominal setpoint and all control system responses are smooth and have no sustained oscillations or divergence. To ensure that a load reduction transient presents no hazard to the integrity of the RCS or the main steam system, the Condition II analysis presented in Section 15.2.7 continues to assume a total loss of external electrical load without an immediate reactor trip.
(5) Steady State Fluctuations The reactor coolant average temperature, for purposes of design, is assumed to increase or decrease at a maximum rate of 6°F in 1 minute.
The temperature changes are assumed to be around the programmed value of Tavg (Tavg +/-3°F). Average reactor coolant pressure varies accordingly; it is controlled by the pressurizer pressure control. 5.2.1.5.2 Upset Conditions The following six transients are considered upset conditions: (1) Loss of Load Without Immediate Turbine or Reactor Trip This transient applies to a step decrease in turbine load from full power occasioned by the loss of turbine load without immediately initiating a reactor trip and represents the most severe transient on the RCS. The reactor and turbine eventually trip as a consequence of a high pressurizer level trip initiated by the reactor trip system (RTS). Since redundant means of tripping the reactor are provided as a part of the reactor protection system (RPS), transients of this nature are not expected but are included to ensure a conservative design. (2) Loss of Power This transient involves the loss of outside electrical power to the station with a reactor and turbine trip. Under these circumstances, the reactor coolant pumps are de-energized and, following their coastdown, natural circulation builds up in the system to some equilibrium value. This DCPP UNITS 1 & 2 FSAR UPDATE 5.2-9 Revision 21 September 2013 condition permits removal of core residual heat through the steam generators that are being fed by the auxiliary feedwater system (AFWS) powered either by a diesel generator or main steam. Steam is initially removed for reactor cooldown through atmospheric relief valves provided for this purpose. (3) Loss of Flow This transient applies to a partial loss of flow accident from full power in which a reactor coolant pump is tripped as a result of a loss of power to the pump. The consequences of such an accident are a reactor and turbine trip on reactor coolant pump bus undervoltage, followed by automatic opening of the steam dump system and flow reversal in the affected loop. The flow reversal results in a reactor coolant at cold leg temperature, being passed through the steam generator and cooled still further. This cooler water then passes through the hot leg piping and enters the reactor vessel outlet nozzles. The net result of the flow reversal is a sizable reduction in the hot leg coolant temperature of the affected loop. (4) Reactor Trip from Full Power A reactor trip from full power may occur for a variety of causes resulting in RCS and steam generator secondary side temperature and pressure transients. It results from continued heat transfer from the reactor coolant to the steam generator. The transient continues until the reactor coolant and steam generator secondary side temperatures are in equilibrium at zero power conditions. A continued supply of feedwater and controlled dumping of secondary steam remove the core residual heat and prevent the steam generator safety valves from lifting. The reactor coolant temperatures and pressures undergo a rapid decrease from full power values as the RTS causes the control rods to move into the core. (5) Inadvertent Auxiliary Spray The inadvertent pressurizer auxiliary spray transient will occur if the auxiliary spray valve is opened inadvertently during normal operation. This will introduce cold water into the pressurizer causing a very sharp pressure decrease. Auxiliary spray water temperature depends on regenerative heat exchanger performance. The most conservative case occurs when the letdown stream is shut off and unheated charging fluid enters the pressurizer. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-10 Revision 21 September 2013 The design assumes a spray water temperature of 100°F and a flowrate of 200 gpm. It is also assumed that, if activated, the auxiliary spray will continue for 5 minutes until shut off.
The pressure decreases rapidly to the low-pressure reactor trip point and the pressurizer low-pressure reactor trip is assumed to be actuated. This accentuates the pressure decrease until the pressure is finally limited to the hot leg saturation pressure. After 5 minutes the spray is stopped and the pressurizer heaters return the pressure to 2250 psia. It is finally assumed that RCS temperature changes do not occur as a result of auxiliary spray initiation except in the pressurizer. (6) Design Earthquake (DE) The earthquake loads are a part of the mechanical loading conditions specified in equipment specifications. The origin of their determination is separate and distinct from those transient loads resulting from fluid pressure and temperature. Their magnitude is considered in the design analysis, however, for comparison with appropriate stress limits. 5.2.1.5.3 Emergency Conditions No transient is classified as an emergency condition. 5.2.1.5.4 Faulted Conditions The following transients are considered faulted conditions:
(1) RCS Boundary Pipe Break This accident involves the postulated rupture of a pipe belonging to the RCS boundary. It is conservatively assumed that system pressure is reduced rapidly and the emergency core cooling system (ECCS) is initiated to introduce water into the RCS. The safety injection signal will also initiate a turbine and reactor trip. The criteria for locating design basis pipe ruptures for the design of RCS supports and restraints, thus ensuring continued integrity of vital components and engineered safety features (ESF), are presented in Section 3.6. They are analyzed in Reference 7. With the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 31), the dynamic effects of breaks in the main reactor coolant loop piping no longer have to be considered in the design basis analyses. Only the dynamic effects from RCS branch line breaks have to be considered (see Section 3.6.2.1.1.1).
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-11 Revision 21 September 2013 (2) Steam Line Break For RCS component evaluation, the following conservative conditions are considered: (a) The reactor is initially in hot, zero power subcritical condition assuming all rods in, except the most reactive rod, which is assumed to be stuck in its fully withdrawn position. (b) A steam line break occurs inside the containment. (c) Subsequent to the break, there is no return to power and the reactor coolant temperature cools down to 212°F. (d) The ECCS pumps restore the reactor coolant pressure. The above conditions result in the most severe temperature and pressure variations that the component will encounter during a steam break accident. The dynamic reaction forces associated with circumferential steam line breaks are considered in the design of supports and restraints to ensure continued integrity of vital components and ESFs. Criteria for protection against dynamic effects associated with pipe breaks are covered in Section 3.6. (3) Double Design Earthquake (DDE) The mechanical stress resulting from the DDE is considered on a component basis. The design basis for the plant is the DDE. The seismic analysis is described in Section 3.7. (4) Hosgri Earthquake Studies subsequent to the original seismological survey of the site region have resulted in the development of a postulated earthquake of greater magnitude. The characteristics and consequences of this postulated Hosgri earthquake are discussed in Section 5.2.1.15. The design transients and the number of cycles of each are shown in Table 5.2-4.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-12 Revision 21 September 2013 5.2.1.5.5 Preoperational Tests Prior to plant startup the following tests were carried out:
(1) Turbine Roll Test This test was imposed upon the plant during the hot functional test period for turbine cycle checkout. Reactor coolant pump power heats the reactor coolant to operating temperature and the steam generated is used to perform a turbine roll test. Plant cooldown during the test exceeds, however, the 100°F per hour maximum rate. (2) Hydrostatic Test Conditions Each of the major NSSS components (steam generator, reactor coolant pumps, reactor vessel, control rod drive mechanisms, and pressurizer) may be subjected to a maximum of 10 hydrostatic tests without exceeding ASME B&PV Code criteria. The pressure tests are:
(a) Primary Side Hydrostatic Test Before Initial Startup Pressure tests include both shop and field hydrostatic tests that occur as a result of component or system testing. This hydrostatic test was performed prior to initial fuel loading at a water temperature of at least 168°F (calculated using the methods presented in Paragraph NB2300, Section III of the 1971 ASME B&PV Code, Summer 1972 Addenda), which is compatible with reactor vessel fracture prevention criteria requirements, and a maximum test pressure. In this test, the primary side of the steam generator is pressurized to 3107 psig coincident with no pressurization of the secondary side. The reciprocating charging pump provided the means to hydrostatically test the RCS during preoperational tests, and this pump has been replaced with a centrifugal charging pump (CCP3). Hydrostatic testing of the primary side is accomplished by a temporary hydrostatic test pump. (b) Secondary Side Hydrostatic Test Before Initial Startup The secondary side of the steam generator is pressurized to 1356 psig (1.25 times the design pressure of the secondary side) coincident with the primary side at zero psig. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-13 Revision 21 September 2013 (c) Primary Side Leak Test Each time the primary system is opened, a leak test is performed. During this test the primary system pressure is assumed, for design purposes, to be raised to 2500 psia, with the system temperature above design transition temperature, while the system is checked for leaks. In actual practice, the primary system is pressurized to less than 2500 psia to prevent the pressurizer safety valves from lifting during the leak test. The secondary side of the steam generator is pressurized by closing off the steam lines, so that the pressure differential across the tubesheet does not exceed 1600 psi. (d) Secondary Side Leak Test The secondary side is pressurized to 1085 psig (the design pressure of the secondary side of the steam generator) coincident with the primary side at 0 psig.
(e) Tube Leakage Test During the life of the plant it may be necessary to check the steam generator for tube leakage and tube-to-tube sheet leakage. This is done by visual inspection of the underside (channel head side) of the tube sheet for water leakage, with the secondary side pressurized. Tube leakage tests are performed during plant cold shutdown.
For these tests, the secondary side of the steam generators is pressurized with water, initially at a very low pressure, and the primary system remains depressurized (i.e., 0 psig). The underside of the tube sheet is examined visually for leaks. If any leaks are observed, the secondary side is depressurized and repairs made by tube plugging. The secondary side is then repressurized (to a higher pressure) and the underside of the tube sheet is again checked for leaks. The process is repeated until all the leaks are repaired. The maximum (final) secondary-side test pressure reached is 840 psig.
The total number of tube leakage tests is defined as 800 during the life of the plant. The following is a breakdown of the anticipated number of occurrences at each secondary side pressure.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-14 Revision 21 September 2013 Case Test Pressure, psig No. of Occurrences Case 1 200 400 Case 2 400 200 Case 3 600 120 Case 4 840 80
Both the primary and secondary sides of the steam generators will be at ambient temperature during these tests.
Since the tests outlined under items (a) and (b) occur prior to plant startup, the number of cycles is independent of plant life. 5.2.1.6 Identification of Active Pumps and Valves Pumps and valves are classified as either active or inactive components for faulted conditions. Active components are those whose operability is relied upon to perform a safety function such as a reactor shutdown. Inactive components are those whose operability (e.g., valve opening or closure, pump operation or trip) is not relied upon to perform a safety function. The reactor coolant pumps are the only pumps in the RCS boundary and are classified as "inactive" in the event of a reactor coolant loop pipe rupture.
Valves in sample lines are not considered to be part of the RCS boundary because the nozzles where these lines connect to the RCS are orificed to a 3/8-inch hole. This hole restricts the flow such that loss through a severance of one of these lines is sufficiently small to allow operators to execute an orderly plant shutdown. Table 5.2-9 lists the active and inactive valves between major components in the main process lines of the RCPB, along with the actuation type, valve types, and location. The listed valves are those that are within the pressure boundary. Check valves are also included in Table 5.2-9. Check valves are a credited means of pressure boundary isolation for the original design per ANS 18.2. Vents, drains, test and instrument root valves are excluded from the table as they meet the isolation requirements and are not between major components of the RCPB. Manual valves are passive components and are not considered either active or inactive, therefore they are not included on Table 5.2-9. 5.2.1.7 Design of Active Pumps and Valves The design criteria for active safety-related pumps outside the RCS boundary are discussed in Section 3.9.2. All these safety-related pumps are designated either ASME B&PV Code Class II or III.
Active pumps were qualified for operability by first being subjected to rigid tests both prior to installation in the plant and after installation in the plant. The in-shop test DCPP UNITS 1 & 2 FSAR UPDATE 5.2-15 Revision 21 September 2013 included (a) hydrostatic tests of pressure-retaining parts to 150 percent of the product of the design pressure times the ratio of material allowable stress at room temperature to the allowable stress value at the design temperature, (b) seal leakage tests, and (c) performance tests to determine total developed head, minimum and maximum head, net positive suction head (NPSH) requirements and other pump parameters. Bearing temperature and vibration levels were monitored during these operating tests. Bearing temperature limits and vibration levels were established by the manufacturer based on bearing materials, clearances, oil type and rotational speed. After a pump was installed in the plant, it underwent cold hydrostatic tests, and hot functional tests, and will undergo the required periodic inservice inspection operation. These tests demonstrated that a pump will function as required during all normal operating conditions for the design life of the plant.
In addition to these tests, the active pumps were qualified for operability by assuring that they will start, continue operating and not be damaged during the postulated Hosgri earthquake.
It was shown that the pumps will perform their design functions when subjected to loads imposed by the maximum seismic accelerations and maximum nozzle loads. It was required that test or analysis be used to show that the lowest natural frequency of each pump was greater than 33 Hz. A pump having a natural frequency above 33 Hz was considered rigid. This consideration avoids amplification between the component and structure for all seismic areas. A static shaft deflection analysis of rotors was performed with horizontal and vertical accelerations acting simultaneously. The deflections, determined from the static shaft analyses, were compared to the allowable rotor clearances. Pump and motor bearing loads were determined and shown to be below the manufacturer's specified levels. To avoid damage during the postulated earthquake, the stresses caused by the combination of normal operating loads, earthquake, and dynamic system loads were limited to the limits indicated in Section 3.9.2. Pump casing stresses caused by the maximum nozzle loads were limited to the stresses outlined in Section 3.9.2. The maximum seismic nozzle loads combined with the loads imposed by the seismic accelerations were considered in the analysis of pump supports. Furthermore, calculated misalignment was shown to be less than that which could hinder pump operation. The stresses in the supports were below those of Section 3.9.2. Therefore, support distortion is elastic and of short duration (no longer than the duration of the seismic event).
Performing these analyses with the loads and the stress limits of Section 3.9.2, assures that critical parts of pumps will not be damaged during the postulated earthquake.
If the natural frequency was found to be below 33 Hz, an analysis was performed to determine the amplified input accelerations necessary to perform the static analysis. The adjusted accelerations were determined with the same conservatisms used for rigid DCPP UNITS 1 & 2 FSAR UPDATE 5.2-16 Revision 21 September 2013 structures. The static analysis was performed using the adjusted accelerations; the stress limits stated in Section 3.9.2 were satisfied.
To complete the seismic qualifications procedures, the pump motors were qualified for operation during the maximum seismic event. Any auxiliary equipment which is vital to the operation of the pump or pump motor, and which was not qualified for operation with the pump or motor was qualified separately.
The above program gives assurance that the active pumps and motors would not be damaged and would continue operating under seismic loadings. These requirements demonstrate that the active pumps will perform their intended functions.
Since it has been demonstrated that the pumps would not be damaged during the earthquake, the functional ability of the active pumps after the earthquake is assured. Normal operating loads and steady state nozzle loads are the most probable conditions following an earthquake. The ability of the pumps to function under these loads is demonstrated during normal plant operation.
The valves were designed to function at normal operating conditions, maximum design conditions, and DDE/Hosgri conditions. Active valves that are used for accident mitigation only, and do not serve to support safe shutdown following a Hosgri earthquake, were qualified for active function for a Hosgri earthquake to provide increased conservatism in accordance with Reference 30. The design meets the requirements of the ANSI B31.1, ANSI B16.5, and MSS-SP-66 codes.
The stress limits for the valves in the RCS pressure boundary are indicated in Table 5.2-5. The design criteria and allowable stress limits for safety-related valves outside the RCS pressure boundary (i.e., valves considered to be ASME B&PV Code Class II or III components) are indicated in Section 3.9.2.
In addition, all valves 1 inch and larger within the RCPB were checked for wall thickness to ANSI B16.5, MSS-SP-66, or ASME B&PV Code, Section III (1968, some 1974) requirements, as applicable, and subjected to nondestructive tests in accordance with ASME and ASTM codes.
The valves were designed to the requirements of ANSI B16.5 or MSS-SP-66 pertaining to minimum wall thickness for pressure containing components. Analyses were performed to qualify active valves. These valves were subjected to a series of stringent tests prior to service and during the plant life. Prior to installation, the following tests were performed: shell hydrostatic tests to MSS-SP-61 requirements, backseat and main seat leakage tests. Cold hydrostatic tests, hot functional qualification tests, periodic inservice inspections and operability tests have been and are performed to verify and assure the functional ability of the valves. These tests assure reliability of the valves for the design life of the plant.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-17 Revision 21 September 2013 On all active valves, an analysis of the extended structure was performed for static equivalent seismic loads applied at the center of gravity of the extended structure. The minimum stress limits allowed in these analyses will assure that no significant permanent damage occurs in the extended structures during the earthquake.
Motor operators and other electrical appurtenances necessary for operation were qualified.
The natural frequencies of all active valves were determined by test or by analysis. If the natural frequencies of the valves were shown to be less than 33 Hz, one of the following options was employed:
(1) The valve was qualified by dynamic testing. (2) The valve was modified to increase the minimum frequency to greater than 33 Hz. (3) The valve was qualified conservatively using static accelerations that are sufficiently in excess of accelerations it might experience in the plant to take into account any effect due to both multifrequency excitation and multi-mode response (a factor of 1.5 times peak acceleration is generally accepted, although lower coefficients can be used when shown to yield conservative results). (4) A dynamic analysis of the valve was performed to determine the equivalent acceleration to be applied during the static analysis. The analysis provided the amplification of the input acceleration considering the natural frequency of the valve and the frequency content of the applicable plant floor response spectra. The adjusted accelerations were then used in the static analysis and the valve operability was assured by the methods outlined above, using the modified acceleration input.
Swing check valves are characteristically simple in design and their operation is not affected by seismic accelerations or applied nozzle loads. The check valve design is compact and there are no extended structures or masses whose motion could cause distortions which could restrict operation of the valve. The nozzle loads due to seismic excitation do not affect the functional ability of the valve since the valve disc is typically designed to be isolated from the casing wall. The clearance available around the disc prevents the disc from becoming bound or restricted due to any casing distortions caused by nozzle loads. Therefore, the design of these valves is such that once the structural integrity of the valve is assured using standard design or analysis methods, the ability of the valve to operate is assured by the design features. For the faulted condition evaluations, since piping stresses are shown to be acceptable, the check valves are qualified.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-18 Revision 21 September 2013 The valves have undergone the following tests: (a) in-shop hydrostatic test, (b) in-shop seat leakage test, and (c) periodic in-plant exercising and inspection to assure functional ability.
By the above methods, all active valves are qualified for operability for the faulted condition seismic loads. These methods simulate the seismic event and assure that the active valves will perform their safety-related functions when necessary. 5.2.1.8 Inadvertent Operation of Valves The inactive valves within the reactor coolant pressure boundary listed in Table 5.2-9 are not relied upon to function after an accident. They meet redundancy requirements and will not increase the severity of any of the transients discussed in Section 5.2.1.5, if operated inadvertently during any such transient. 5.2.1.9 Stress and Pressure Limits System hydraulic and thermal design parameters are the basis for the analysis of equipment, coolant piping, and equipment support structures for normal and upset loading conditions. The analysis uses a static model to predict deformation and stresses in the system. The analysis gives six components, three moments, and three forces. These moments and forces are resolved into pipe stresses in accordance with applicable codes. Stresses in the structural supports are determined by the material and section properties based on linear elastic small deformation theory.
In addition to the loads imposed on the system under normal and upset conditions, the design of mechanical equipment and equipment supports requires that consideration also be given to faulted loading conditions such as those experienced during seismic and pipe rupture events. With the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 31), the dynamic loading conditions resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis analyses. Only the dynamic loads resulting from RCS branch line breaks and other high energy line breaks have to be considered (see Section 3.6.2.1.1.1).
Analysis of the reactor coolant loops and support systems for seismic loads is based on a three dimensional, multi-mass elastic dynamic model. The floor response spectra are used as input to the detailed dynamic model, which includes the effects of the supports and the supported equipment. The loads developed from the dynamic model are incorporated into a detailed loop and support model to determine the support member stresses.
The dynamic analysis employs the displacement method, lumped parameter, stiffness matrix formulations, and assumptions that all components behave in a linearly elastic manner. Seismic analyses are covered in detail in Section 3.7.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-19 Revision 21 September 2013 Loading combination and allowable stresses for RCS components are provided in Tables 5.2-5, 5.2-6 and 5.2-7. 5.2.1.10 Stress Analysis for Structural Adequacy Methods and models used to determine the structural adequacy of components under the normal and upset conditions are described herewith. 5.2.1.10.1 Analysis Method for Reactor Coolant System The load combinations considered in the design of structural steel members of component supports are summarized in Table 5.2-8. The design is described in Section 5.5.
(1) Deadweight The deadweight loading imposed by piping on the supports consists of the dry weight of the coolant piping and weight of the water contained in the piping during normal operation. In addition, the total weight of the primary equipment components, including water, forms a deadweight loading on the individual component supports. (2) Thermal Expansion The free vertical thermal growth of the reactor vessel nozzle centerlines is considered to be an external anchor movement transmitted to the reactor coolant loop (RCL). The weight of the water in the steam generator and the reactor coolant pump is applied as an external force in the thermal analysis to account for equipment nozzle displacement as an external movement. For the RSGs, the RCL piping was reanalyzed for thermal expansion. The thermal expansion reanalysis was performed in a similar manner to the original analysis except water weights were included as a part of the deadweight analysis. (3) Earthquake Loads The earthquake acceleration, which produces transient vibration of the equipment mounted within the containment building, is specified in terms of the floor response spectrum curves at various elevations within the containment building.
These floor response spectrum curves for earthquake motions are described in detail in Section 3.7. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-20 Revision 21 September 2013 (4) Pressure The steady state hydraulic forces based on the system's initial pressure are applied as internal loads to the RCL model for determination of the RCL support system deflections and support forces. (5) Pipe Rupture Loads In the original RCS analysis, blowdown loads were developed in the broken and unbroken reactor coolant loops as a result of the transient flow and pressure fluctuations during a postulated loss-of-coolant accident (LOCA) in one of the reactor coolant loops. One millisecond opening time was used to simulate the instantaneous occurrence of the postulated LOCA. However, with the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 31), the dynamic blowdown loads resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis analyses. Only the much smaller blowdown loads resulting from RCS branch line breaks have to be considered (see Section 3.6.2.1.1.1). For the RSGs, the RCL piping was reanalyzed for pipe rupture events. Since pipe rupture events in the main RCL piping no longer have to be considered in the design basis analyses (see Section 3.6.2.1.1.1), pipe rupture loads for the reanalysis are defined for RCL branch line breaks. The pipe rupture load analysis considered double-ended circumferential breaks in the RHR, SI (accumulator line), and pressurizer branch line connections to the RCL piping. The analysis also considered the effects of main steamline breaks on the RCL piping and the RCS equipment supports. The feedline break was not explicitly analyzed as the main steamline break is more limiting. 5.2.1.10.2 Analytical Models The static and dynamic structural analyses assume linear elastic behavior and employ the displacement (stiffness) matrix method and the normal mode theory for lumped-parameter, multimass structural representation to formulate the solution. The complexity of the physical system to be analyzed requires the use of a computer for its solution.
(1) Reactor Coolant Loop Model The RCL model is constructed for the WESTDYN (Reference 18) computer program. This is a special purpose program designed for the static and dynamic analysis of redundant piping systems with arbitrary loads and boundary conditions.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-21 Revision 21 September 2013 (2) Support Structure Models The equipment support structure models have dual purposes since they are required: (a) To quantitatively represent, in terms of 6 x 6 stiffness matrices, the elastic restraints which the supports impose upon the loop (b) To evaluate the individual support member stresses due to the forces imposed upon the support by the loop. The loadings on the component supports are obtained from the analysis of an integrated RCL support system's dynamic structural model, as shown in Figure 5.2-2. Figure 5.2-2 shows the RCL model and component supports included in the RCL piping reanalysis performed for the RSGs. The reanalysis considered the pipe rupture restraints on the main RCL piping to be inactive. The pipe rupture restraints on the main RCL piping were made inactive by either removing shims or by removing the support. The primary equipment supports were evaluated using the STASYS (Reference 18), STRUDL (Reference 18), and NASTRAN (Reference 18), programs. (3) Hydraulic Models The hydraulic model is constructed to quantitatively represent the behavior of the coolant fluid within the RCLs in terms of the concentrated time-dependent loads imposed upon the loops. In the original analysis, in evaluating the hydraulic forcing functions during a LOCA, the pressure and the momentum flux terms are dominant. Inertia and gravitational terms were neglected although they were taken into account when evaluating the local fluid conditions. Thrust forces resulting from a LOCA were calculated in a two-step process. First, the MULTIFLEX 3.0 (Reference 6) code calculated transient pressure, flowrates, and other coolant properties as a function of time. Second, the THRUST (Reference 18) code used the results obtained from MULTIFLEX and calculated time-history of forces at locations where there is a change in either direction or area of flow within the RCL. These locations for the broken loop are shown in Figure 5.2-3. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-22 Revision 21 September 2013 With the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 31), the dynamic thrust forces and blowdown loads resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis analyses. Only the thrust forces and blowdown loads resulting from RCS branch line breaks have to be considered. (see Section 3.6.2.1.1.1) For the RCL piping reanalysis performed for the RSGs, thrust forces and blowdown loads were determined for RCS branch line and main steamline breaks identified in Section 5.2.1.10.1. 5.2.1.10.3 Analysis and Solutions (1) Static Load Solutions The static solutions for deadweight, thermal expansion, and pressure load conditions are obtained by using the WESTDYN computer program. (2) Normal Mode Response Spectral Seismic Load Solution The stiffness matrices representing various supports for dynamic behavior are incorporated into the RCL model. The response spectra for the DE are applied along the X or Z, and Y axes simultaneously. From the input data, the overall stiffness matrix of the three-dimensional RCL is generated and the natural frequencies and normal modes are obtained by the modified Jacobi method. The forces, moments, deflections, rotations, support structure reactions and stresses are then calculated for each significant mode. The total seismic response is computed by combining the contributions of the significant modes by the square root of the sum of the squares method. 5.2.1.10.4 Reactor Coolant Loop Stress Analysis Results The stress for the normal and upset conditions shows that the stresses in the piping are below the code-allowable values.
(1) Normal Conditions Stresses due to primary loading of pressure and deadweight are combined and compared with the USAS B31.1 Piping Code allowable primary stress limit. The thermal expansion stress is a secondary stress and is, therefore, not combined with stresses due to the primary loadings of pressure and deadweight. The magnitude of the thermal stress is compared with the B31.1 Piping Code allowable expansion stress limit.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-23 Revision 21 September 2013 The stress evaluation for the normal condition shows that the stresses in all RCL members are within the allowable stress values. (2) Upset Conditions The DE stresses are added to the stresses due to primary loadings of pressure and deadweight. The stress evaluation for the upset condition shows that stresses in all RCL members are within the allowable stress values. 5.2.1.10.5 Component Supports Stress Analysis Results (1) Normal Conditions Thermal, weight, and pressure forces (obtained from the RCL analysis) acting on the support structures are combined algebraically. The combined load component vector is multiplied by member influence coefficient matrices to obtain all force components at each end of each member in the support system. (2) Upset Conditions DE support forces are added algebraically to normal condition forces. The interaction and stress equations are the allowable limits specified by AISC-69. The stress evaluation for the normal and upset conditions shows that the stresses in all members are within the allowable values. 5.2.1.11 Analysis Method for Faulted Condition The analysis of the RCLs and support systems for blowdown loads resulting from a LOCA is based on the time-history response of simultaneously applied blowdown forcing functions on a broken and unbroken loop dynamic model. The forcing functions are defined at points in the system loop where changes in cross section or direction of flow occur such that differential loads are generated during the blowdown transient. Stresses and loads are checked and compared to the corresponding allowable stress.
The stresses in components resulting from normal sustained loads and the worst case blowdown analysis are combined with the DDE seismic analysis to determine the maximum stress for the combined loading case. This is considered a very conservative method since it is highly improbable that both maxima will occur at the same instant. These stresses are combined to ensure that the main reactor coolant piping loops and connected primary equipment support system will not lose their intended functions under this highly improbable situation.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-24 Revision 21 September 2013 For faulted conditions, the limits are provided in Table 5.2-7. Further details of the stress analysis for faulted conditions are presented in Section 5.2.1.14. With the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 31), the dynamic thrust forces and blowdown loads resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis analyses. Only the thrust forces and blowdown loads resulting from RCS branch line breaks have to be considered (see Section 3.6.2.1.1.1). For the RCL reanalysis performed for the RSGs, thrust forces and blowdown loads were determined for RCS branch line breaks identified in Section 5.2.1.10.1. Details of the stress analyses performed to evaluate the effects of the postulated Hosgri earthquake are presented in Section 5.2.1.15.
Protection criteria against dynamic effects associated with pipe breaks are covered in Section 3.6. With the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 31), the dynamic effects of breaks in the main reactor coolant loop piping no longer have to be considered in the design basis analyses. Only the dynamic effects from RCS branch line breaks have to be considered (see Section 3.6.2.1.1.1). 5.2.1.12 Protection Against Environmental Factors Protection provided for the RCS against environmental factors is discussed in Sections 3.3, 3.4, and 3.5. Fire protection is discussed in Section 9.5.1. 5.2.1.13 Compliance with Code Requirements In the PG&E quality group classification of DCPP fluid systems and fluid system components, the vessels, piping, valves, pumps and their supports of the RCS pressure boundary are designated Code Class I. The Code Class I classification includes the components of the RCS pressure boundary identified as ANS Safety Class 1 in ANSI N18.2, Nuclear Safety Criteria for the Design of Stationary Pressurized Water Reactor Plants, American Nuclear Society, August 1970 Draft, and Quality Group A in AEC RG 1.26. The correspondence of DCPP system quality group classifications to ANSI N18.2 Safety Classes and to AEC RG 1.26 quality groups is discussed in Section 3.2.
For conservative fatigue evaluations of the reactor vessel, steam generator, reactor coolant pump, and pressurizer in accordance with the ASME B&PV Code, maximum stress intensity ranges are derived from combining the normal and upset condition transients discussed in Section 5.2. The stress ranges and number of occurrences are then used in conjunction with the fatigue curves in the ASME B&PV Code to get the associated cumulative usage factors.
The criterion presented in the ASME B&PV Code is used for fatigue analysis. The cumulative usage factor is less than 1, hence, the fatigue design is adequate.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-25 Revision 21 September 2013 The reactor vessel vendor's stress report has been reviewed by Westinghouse Electric Corporation. The stress report includes a summary of the stress analysis for regions of discontinuity analyzed in the vessel, a discussion of the results including a comparison with the corresponding code limits, a statement of the assumptions used in the analysis, descriptions of the methods of analysis and computer programs used, a presentation of the actual hand calculations, a listing of the input and output of the computer programs used, and a tabulation of the references cited in the report. The content of the stress report is in accordance with the requirements of the ASME B&PV Code, and all information in the stress report is reviewed and approved by Westinghouse.
For the replacement RVCH, the content of the stress report is in accordance with the requirements of the ASME B&PV Code, and all information in the stress report is reviewed and approved by PG&E. 5.2.1.14 Stress Analysis for Faulted Condition Loadings (DDE and LOCA) Stress analyses of the RCS for faulted conditions employ the displacement (stiffness) matrix method and lumped-parameter, multimass representation of the system. The analyses are based on adequate and accurate representation of the system using an idealized, mathematical model. 5.2.1.14.1 Analysis Method (1) Reactor Coolant Loop (RCL) The procedure for evaluation of the piping stresses due to combined loadings of weight, pressure, DDE, and LOCA is as follows: The LOCA stress analysis yields the time-history of stresses at various cross sections in the RCL piping. Axial stress due to pressure is included.
Since the DDE results are obtained by the response spectra method, the six components of a state vector for deflection at a point or for internal member force cannot be assigned absolute and/or relative algebraic signs. Consequently, the maximum values of the DDE axial and shear stresses at a pipe cross section are calculated from the internal force state vector at that cross section by considering all possible permutations of signs of the six components of the state vector. The DDE axial and shear stresses are combined with the time-history of LOCA axial and shear stresses.
Dynamic LOCA loads resulting from pipe rupture events in the main RCL were considered in the design basis stress analyses and were included in the loading combinations. With the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 31), main RCL pipe rupture events no longer need to be considered as described in Section 3.6.2.1.1.1. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-26 Revision 21 September 2013 The resultant axial and shear stresses are combined with the hoop and radial stresses (due to pressure) to determine the principal stresses, 1, 2, and 3. The previous steps are performed for various cross sections in the RCL piping. It should be emphasized that, for a given location of the pipe cross section, the stress intensity calculation is performed at every step computed from the time-history analysis. The state of stress for stress points in the unbroken legs of a broken loop and the unbroken loop piping are within the stress intensity limit provided in Table 5.2-7.
Reanalysis for the RSGs Maximum resultant deadweight, DDE, and LOCA moments were determined at locations located along the RCL piping, elbows, and connections to equipment. At each location, the maximum resultant moment for DDE is the largest resultant moment from the various shock cases that were performed for the DDE load analysis. The largest resultant moment for LOCA is the largest moment from the pipe rupture analyses for RCL branch line breaks and the main steamline break.
B31.1 Code pipe stress equations were used with the resultant moments to determine deadweight DDE, and LOCA pipe stresses at locations along the RCL corresponding to the maximum resultant moment locations. At each location, the stresses were combined by absolute sum and were added to the pressure stress to determine the maximum stress at that location. This maximum stress was then verified to be within the stress limit provided in Table 5.2-7. It should be emphasized that the above analysis method is very conservative since the peak DDE and LOCA pipe stresses are considered to occur at the exact same instant in time and that the resultant moments for each load type are considered to be aligned such that the maximum pipe stress occurs at the same location around the pipe circumference for each load type. (2) Evaluation of Support Structures The support loads are computed by multiplying the support stiffness matrix, and the displacement vector at the support point. The support loads are used for support member evaluation. Loads acting on the supports obtained from the RCL analysis (including time-history LOCA forces), support structure member properties, and influence coefficients at each end of each member are input into the THESSE (Reference 18) program. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-27 Revision 21 September 2013 The THESSE program proceeds as follows for each support: (1) Combine the various types of support plane loads to obtain operating condition loads (normal, upset, or faulted). (2) Multiply member influence coefficients by operating condition loads to obtain all member internal forces and moments. The output gives a complete tabulation of all worst force and stress conditions in each member in the supporting system and provides maximum loads on the supporting concrete. (3) Solve appropriate stress or interaction equations for the specified operating condition. The AISC-69 specification is used with the limits specified in Table 5.2-8 for the operating conditions considered. 5.2.1.14.2 Time-history Dynamic Solution for LOCA Loading The initial displacement configuration of the mass points is defined by applying the initial steady state hydraulic forces to the unbroken RCL model. For the dynamic solution, the unbroken RCL model is modified to simulate the physical severance of the pipe due to the postulated LOCA event. The natural frequencies and normal modes for the modified RCL dynamic model are then determined. After proper coordinate transformation to the RCL global coordinate system, the hydraulic forcing functions to be applied at each lumped mass point are then stored for later use as input to the FIXFM (Reference 18) program. The initial displacement conditions, natural frequencies, normal modes, and the time-history hydraulic forcing functions form the input to the FIXFM program, which calculates the dynamic time-history displacement response for the dynamic degrees of freedom in the RCL model. The displacement response is plotted at all mass points. The displacement response at support points is reviewed to validate the use of the chosen support stiffness matrices for dynamic behavior. If the calculated support point response does not match the anticipated response, the dynamic solution is revised using a new set of support stiffness matrices for dynamic behavior. This procedure is repeated until a valid dynamic solution is obtained.
The time-history displacement response from the valid solution is saved for later use to compute the support loads and to analyze the RCL piping stresses. It is reiterated that the RCS analysis described in this section is the analysis originally performed for the RCS faulted conditions. With the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 31), dynamic LOCA loads resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis stress analyses and included in the loading combinations; only the LOCA loads resulting from RCS branch line breaks have to be considered. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-28 Revision 21 September 2013 Reanalysis for the RSGs The initial displacement configuration of the mass points is defined by applying the initial steady state hydraulic forces to the RCL model. These initial displacement conditions, natural frequencies, normal modes, the time-history hydraulic forcing functions and reactor vessel nozzle displacements are used by the WESTDYN program to calculate the time-history dynamic response for the RCL model. The time-history response is used to determine pipe moments, support forces, and pipe deflections. 5.2.1.14.3 Analysis Results All support system elements were evaluated to verify that the supported equipment and piping remain within their respective faulted condition stress limits. Stresses in the support system elements for faulted conditions are below the limits provided in Table 5.2-8. The stress evaluation for the faulted conditions shows that the stresses in the piping are below code-allowable values. 5.2.1.15 Stress Analysis for Faulted Condition Loadings (Hosgri) 5.2.1.15.1 Integrated Reactor Coolant Loop Analysis Analysis of the reactor coolant loop piping was performed using the response spectra method. The RCL model was constructed for the WESTDYN computer program.
The horizontal response spectrum at 140 feet in the inner containment structure, corresponding to the steam generator upper support elevation, and the horizontal spectrum at 114 feet in the inner containment structure, corresponding to the reactor coolant pump support and reactor vessel elevation, was used in the analysis. A vertical response spectrum envelope from elevation 114 ft to the base slab of elevation 87 ft was used in the analysis. With mode, the results due to the vertical shock were combined by direct addition with the results of the horizontal shock directions. The modal contributions were then added by the square-root-sum-of-the-squares (SRSS) method.
Two seismic cases were considered; north-south plus vertical and east-west plus vertical. Each horizontal shock was combined with the vertical shock and the worst combined response was used in the evaluation of the system.
The results of the analysis are as follows: The results of the seismic evaluation were combined with the pressure and deadweight stresses. The revised piping stresses were all under the allowable of 2.4 Sh, or, for loop piping, 3.6 Sh. 5.2.1.15.2 Steam Generator Evaluation The seismic spectra at the elevations of the steam generator upper support and vertical support were used as the seismic input. The horizontal spectra at the upper support DCPP UNITS 1 & 2 FSAR UPDATE 5.2-29 Revision 21 September 2013 and the vertical spectra at the vertical support were used as input. The model was used to evaluate the shell, tube bundles, upper and lower internals, and other pressure boundary components.
The nozzles and support feet of the steam generator were analyzed using static stress analysis methods with externally applied design loads. Loadings on the inlet and outlet nozzles of the steam generator for the Hosgri earthquake were calculated as part of the reactor coolant loop piping analysis. The loadings calculated by this analysis were compared with previous faulted condition loads. The new loads were shown to be lower than the loads that were used initially to evaluate the nozzles. Therefore, the stresses caused by the Hosgri spectra are within the design basis of these nozzles.
The loads on the steam generator support feet and upper seismic support were supplied for the Hosgri evaluation by the reactor coolant loop analysis. These loadings are below the loading originally calculated for the DDE analysis.
A long-term seismic program (LTSP) seismic margin assessment was performed by Westinghouse for the DCPP RSGs and associated supports. The assessment shows that the limiting LTSP seismic margin for the components affected by the RSGs is greater than the controlling value of 3.06 contained in the LTSP final report (Reference 34). In addition, the assessment confirms a minimum elastic seismic margin scale factor (FSE) greater than 1.65 for RSG components. A lower value of FSE (1.33) was calculated for the RSG vertical support; however, the resulting 84 percent nonexceedance high confidence, low probability of failure is greater than 3.06 (i.e., 3.22 g), when the standard ductility factor of 1.25 is applied. Details of the margin assessment are provided in Supplement 1 to Reference 33. An LTSP seismic margin assessment was also performed for the Unit 2 RSG support anchorages. An FSE of 1.31 corresponding to an LTSP seismic capacity of 2.6 g was determined for the RSG vertical support anchorages. Higher LTSP seismic capacities were calculated for the RSG upper and lower support anchorages. 5.2.1.15.3 Reactor Coolant Pump Evaluation The seismic analyses of the reactor coolant pump were performed using dynamic modal methods with a finite element computer program. The seismic response spectra corresponding to the elevation of the reactor coolant pump support structure were used.
The nozzles and support feet of the reactor coolant pump were analyzed by static stress analysis methods with externally applied design loads. For the Hosgri spectra the external loads applied to the inlet and outlet nozzles of the reactor coolant pump by the reactor coolant loop piping are all below the load for which the nozzles previously were shown acceptable. No further analysis was necessary for the nozzles.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-30 Revision 21 September 2013 The loads resulting from piping reactions for the Hosgri spectra were lower than the DDE loads for which the reactor coolant pump support feet were analyzed. No further analysis was necessary for the support feet. 5.2.1.15.4 Reactor Vessel Evaluation Several portions of the reactor vessel were evaluated using static stress analysis methods with externally applied design loads. The control rod drive mechanism head adapter, closure head flange, vessel flange, closure studs, inlet nozzle, outlet nozzle, vessel support, vessel wall transition, core barrel support pads, bottom head shell juncture and bottom head instrumentation penetrations were analyzed by this method. The design loads for all areas evaluated except the inlet and outlet nozzles and vessel supports were chosen to be more conservative than any actual load the component would ever experience. The design loads for the inlet and outlet nozzles and vessel supports were umbrellas of loads experienced by past plants. In cases where the actual plant loads exceed the design loads, separate analyses were performed to assure adequacy. All stresses and fatigue usage factors were found to be acceptable
The Hosgri loads calculated by the reactor coolant loop analysis were compared with the DDE seismic loads and are lower. Thus, the previous reactor vessel analysis ensures adequacy for the Hosgri seismic event. 5.2.1.15.5 Reactor Vessel Internals Evaluation The reactor vessel internals evaluation is presented in Section 3.7.3.15.
5.2.1.15.6 Fuel Assembly Evaluation The fuel assembly evaluation is presented in Section 3.7.3.15. 5.2.1.15.7 Control Rod Drive Mechanism and Support System Evaluation The evaluation of the control rod drive mechanism and its support system is presented in Section 3.7.3.15. 5.2.1.15.8 Primary Equipment Support Evaluation Reactor coolant system component supports were shown adequate for the Hosgri seismic event by evaluating the supports for the loads determined in the integrated reactor coolant loops seismic analysis.
The STASYS and NASTRAN computer programs were used to obtain support stiffness matrices and member influence coefficients for the equipment supports.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-31 Revision 21 September 2013 Loads acting on the supports obtained from the reactor coolant loop analysis, support structure member properties, and influence coefficients at each end of each member were input to the THESSE program.
A finite element stress analysis of the steam generator upper support structure was performed with the WECAN (Reference 18) computer program. The STRUDL program was used to analyze the pressurizer support frame.
In summary, stresses in all reactor coolant system component support members are below yield and buckling values for the Hosgri seismic event. The integrity of the supports has therefore been demonstrated for this postulated event. 5.2.1.15.9 Pressurizer Evaluation The Hosgri response spectra for 4 percent damping at the 140 ft. elevation has a peak of 5 g horizontally, well below the value used to qualify the pressurizer. Therefore, the original pressurizer analysis is conservative for the Hosgri earthquake.
A dynamic reactor coolant loop analysis, which included a surge line model and was performed with the Hosgri response spectra, produced loads (forces and moments) on the support skirt, surge nozzle, and upper seismic lug which were less than those produced by the original surge line analysis. Therefore, the loads on these components are acceptable. 5.2.1.16 Stress Levels in Category I Systems Sections 5.2.1.14 and 5.2.1.15 discuss RCS Category I components and the resulting stress levels under faulted conditions. 5.2.1.17 Analytical Methods for Stresses in Pumps and Valves The design and analysis to ensure structural integrity and operability of RCS pumps and valves used the load combinations and stress limits that reflected the AEC regulatory requirements in effect when the construction permits for DCPP were issued. As a result, the design and analysis of these components are based on the requirements of various codes and procedures that were in effect when the equipment was purchased.
These codes and procedures have been widely used by the nuclear industry and were, to a large extent, incorporated or referenced in the 1971 ASME B&PV Code, Section III (refer to Section 3.9.2). Every valve and pump is hydrostatically tested to the applicable ASME B&PV Code requirements, as listed in Table 5.2-2, to ensure the integrity of the pressure boundary parts. 5.2.1.18 Analytical Methods for Evaluation of Pump Speed and Bearing Integrity Reactor coolant pump overspeed evaluation is covered in Section 5.5.1. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-32 Revision 21 September 2013 5.2.1.19 Operation of Active Valves Under Transient Loadings Operation of active valves under transient loadings is discussed in Sections 3.9.2 and 3.10.
During plant startup testing, the preoperational piping dynamics effects test program described in Section 3.9.1 will note and correct excessive piping deflections and vibrations. Since all valves are supported as part of adjoining piping, this testing and any required corrective action, will ensure that the deflections by the pipe (and valve) supports will not impair the operability of active safety-related valves, including those in the RCS pressure boundary. 5.2.2 OVERPRESSURIZATION PROTECTION The pressurizer is designed to accommodate pressure increases (as well as decreases) caused by load transients. The spray system condenses steam to prevent the pressurizer pressure from reaching the setpoint of the power-operated relief valves (PORVs) during a step reduction in power level of 10 percent of load. Flashing of water to steam and generation of steam by automatic actuation of the heaters keeps the pressure above the low-pressure reactor trip setpoint.
The spray nozzles are located on the top of the pressurizer. Spray is initiated when the pressure controlled spray demand signal is above a given setpoint. The spray flow increases proportionally with increasing pressure and pressure error until it reaches a maximum value. Protection against overpressurization during low temperature operation is provided by the low temperature overpressure protection (LTOP) system, which is described in Section 5.2.2.4. 5.2.2.1 Location of Pressure-Relief Devices The pressurizer is equipped with three PORVs that limit system pressure for a large power mismatch and thus prevent actuation of the fixed high-pressure reactor trip. The relief valves are operated automatically or by remote-manual control. The operation of these valves also limits the undesirable opening of the spring-loaded safety valves. Remotely operated block valves are provided to isolate the PORVs if excessive leakage occurs. The relief valves are designed to limit the pressurizer pressure to a value below the high-pressure trip setpoint for all design transients, up to and including, the design percentage step load decrease with steam dump but without reactor trip.
Isolated output signals from the pressurizer pressure protection channels are used for pressure control. These are used to control pressurizer spray and heaters, and PORVs.
In the event of a complete loss of heat sink, protection of the RCS against overpressure (Reference 1) is afforded by pressurizer and steam generator safety valves along with any of the following reactor trip functions:
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-33 Revision 21 September 2013 (1) Reactor trip on turbine trip (2) Pressurizer high-pressure reactor trip (3) Overtemperature T reactor trip (4) Steam generator low-low water level reactor trip A detailed functional description of the process equipment associated with the high-pressure trip is provided in Reference 2.
The overpressure protection upper limit is based on the positive surge of the reactor coolant produced as a result of turbine trip under full load, assuming the core continues to produce full power and normal feedwater is maintained. The self-actuated safety valves are sized on the basis of steam flow from the pressurizer to accommodate this surge at a setpoint of 2500 psia and a total accumulation of 3 percent. Each of the safety valves is rated to carry 420,000 lb/hr, which is greater than one-third of the total rated capacity of the system. Note that no credit is taken for the relief capability provided by the PORVs during this surge.
The RCS design and operating pressures, together with the safety, power-relief, and pressurizer spray valve setpoints, and the protection system setpoint pressures are listed in Table 5.2-10. A schematic representation of the RCS showing the location of pressure-relieving devices is shown in Figure 3.2-7.
System components whose design pressure and temperature are less than the RCS design limits are provided with overpressure protection devices and redundant isolation means. System discharge from overpressure protection devices is collected in the pressurizer relief tank in the RCS. Isolation valves are provided at all connections to the RCS. Figures 3.2-8 through 3.2-10 show those systems that communicate directly with the RCS, and all pressure-relieving devices to prevent reactor coolant pressure from causing overpressure in auxiliary emergency systems in the event of leakage into those systems.
All pressurizer relief piping was manufactured, installed, tested, and analyzed in accordance with USAS B31.7. The piping from the pressurizer to the relief valves is designed to ANSI B31.1. The valve discharge piping to the pressurizer relief tank is designed to ANSI B31.7 - Class III piping. 5.2.2.2 Mounting of Pressure-Relief Devices The pressurizer safety and relief valve piping system has undergone extensive analysis considering combined loads due to internal pressure, pipe and valve deadweight, thermal growth of the pressurizer, seismic accelerations due to earthquakes, and hydraulic hammer forces due to operation of the valve and the volume of water in the water seal at the inlet to the valve. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-34 Revision 21 September 2013 A vertical loop in the pipe between the pressurizer and the safety valve is provided to allow for differential thermal growth between the safety valves and the pressurizer. Previously, the loop provided a water seal against the valve seat to prevent gas and steam leakage through the valve from damaging the seat. The safety valves have been modified from a water-seated to a steam-seated design and water in the loop is continuously drained. The hydraulic hammer analysis was a dynamic time-history type of analysis taking into account the water seal volume, the valve opening time, the location and number of bends in the downstream piping, and the lengths of each piece of straight pipe on the discharge of the valves. Analyses consider combinations of all three valves open or shut to determine the most highly stressed condition. The analyses have not been revised to reflect the absence of the water seal volume, resulting in a conservative design since the loads are less severe without the water seal volume. 5.2.2.3 Report on Overpressurization Protection The design bases for overpressurization protection of the RCS are discussed in Section 5.5. Additional information is also provided in Reference 10. 5.2.2.4 Low Temperature Overpressure Protection RCS overpressure protection during startup and shutdown is provided by the LTOP system, which consists of two mutually redundant and independent systems. Each system receives reactor coolant pressure and temperature signals. When a low-temperature, high-pressure transient occurs, it opens a pressurizer PORV until the pressure returns to within acceptable limits. During normal operation, the system is off. If the reactor coolant temperature is below the low temperature setpoint and the enable switch on the main control board is not in the enable position, an alarm will sound on the main annunciator. The operator can then enable the circuit before a water-solid condition is reached, and the system is then ready to operate without further operator action.
During startup, at the temperature at which the steam bubble is formed, the trip circuit is automatically defeated and the operator can disable the system later in the startup sequence.
The system is completely automatic. Whenever the system is enabled and reactor coolant temperature is below the low temperature setpoint, a high-pressure signal will trip it automatically and open the PORV until the pressure drops below the reset value.
Features of the LTOP control system include: indicating lights and annunciator alarm when the system trips, indicating lights when the system is enabled, and annunciator alarm when the isolation valve for the PORV is closed and the system is enabled.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-35 Revision 21 September 2013 The LTOP system relieves the RCS pressure transient given a single failure. Since the two LTOP systems are mutually redundant and independent, failure of either one would not affect the remaining system.
The system is testable at all times. The pressurizer PORVs are in series with motor-operated block valves, which may be closed during testing. Test signals may be injected into the appropriate control circuits and the position of the valve monitored and timed.
All LTOP components meet Seismic Category I and IEEE-279 (Reference 21) criteria. The electrical portions of the system are powered from inverters supplied by the station's battery. The air to the valves is backed by bottled nitrogen. 5.2.3 GENERAL MATERIAL CONSIDERATIONS This section discusses the materials used in the RCS. 5.2.3.1 Material Specifications The reactor vessels for Units 1 and 2 were fabricated to the 1965 through Winter 1966 Addenda and 1968 Editions, respectively, of the ASME B&PV Code, Section III.
Materials of construction for the replacement RVCHs meet the requirements of the ASME B&PV Code, Section III, 2001 Edition with Addenda through 2003.
Materials of construction for the RSGs meet the requirements of the 1998 Edition of the ASME B&PV Code, Section III, with addenda through the 2000 Addenda. Steam generator pressure boundary ferritic material is procured with RTNDT of 0°F. Materials of construction for the pressurizers for Units 1 and 2 meet the requirements of the 1965 Edition of the ASME B&PV Code, Section III, and addenda through the 1966 Addenda. Charpy tests in the major working or rolling direction were performed at 10°F to ensure that the required toughness levels were obtained. The fracture toughness of these materials is considered sufficient to ensure a margin of safe operation.
Pipe is seamless forged stainless steel conforming to ASTM A376, Type 316 with weld repair limited to 3 percent of nominal wall thickness. Fittings in the main reactor coolant loops for both Unit 1 and Unit 2 are cast stainless steel conforming to ASTM A351, Gr. CF8M. The 90-degree elbows are cast in sections and joined by electroslag welds. The cobalt content is limited to 0.20 percent.
The minimum wall thickness of the pipe and fittings is not less than that calculated using ASA B31.1, Section 1, formula of paragraph 122 with an appropriate allowable stress value provided in Nuclear ASA Code Cases N-7 (for piping) and N-10 (for fittings).
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-36 Revision 21 September 2013 The pressurizer surge line pipe conforms to ASTM A-376, Type 316, with supplementary requirements S2 (transverse tension tests) and S6 (ultrasonic test). The S2 requirements apply to each length of pipe. The S6 requirements apply to 100 percent of the piping wall volume. The pipe wall thickness for the pressurizer surge line is Schedule 140 for Unit 1 and Schedule 160 for Unit 2. There are two 90-degree elbow fittings in the pressurizer surge line for both Unit 1 and Unit 2. The Unit 1 surge line fittings are wrought stainless steel conforming to ASTM A-403, WP316. The Unit 2 surge line fittings are forged stainless steel conforming to ASTM A-182, F316. Branch nozzles conform to SA-182, Grade F316. Thermal sleeves for Unit 1 conform to SA-312 or SA-240, Type 316. The sample scoop conforms to SA-182, Type 316. The pressurizer spray scoop conforms to SA-403, Grade WP 316.
Stainless steel pipe conforms to ANSI B36.19 for sizes 1/2 through 12 inches and wall thickness schedules 40S through 80S. Stainless steel pipe outside of the scope of ANSI B36.19 conforms to ANSI B36.10, exclusive of the RCL piping of special sizes 27-1/2, 29, and 31 inches I.D. Flanges conform to ANSI B16.5. Socket weld fittings and socket joints conform to ANSI B16.11.
Radiographic or ultrasonic examination was performed throughout 100 percent of the wall volume of each pipe and fitting. Acceptance standards for ultrasonic testing are in accordance with ASME B&PV Code, Section III, except that the defect standard for acceptance is a Charpy-V notch not exceeding 1 inch in length and 3 percent of wall thickness in depth. Acceptance standards for radiographic examination are in accordance with ASTM E-186 Severity Level 2, except that defect categories D and E are not acceptable. A liquid penetrant examination was performed on both the entire outside and inside surfaces of each finished hot, cold, and crossover loop fitting and pipe in accordance with the procedure of ASME B&PV Code, Section VIII, Appendix VIII, and the acceptance standards of ASA B31.1, Code Cases N-9 or N-10.
All unacceptable defects were eliminated in accordance with the requirements of ASME B&PV Code, Section III. All butt welds and nozzle welds are of a full penetration design; welds 2 inches and smaller are socket-welded joints. The mechanical properties of representative material heats in the final heat treat condition were no less than 1.20 times the allowable stress tabulated in ASA Code Case N-7 corresponding to 650°F.
Type 308 weld filler material was used for all welding applications to avoid microfissuring. As an option, Type 308L weld filler metal analysis was substituted for consumable inserts when this technique was used for the weld root closure. All welding was performed in accordance with the ASME B&PV Code, Section IX. In all welding, except for the replacement RVCH cladding operations, the interpass temperature was limited to 350°F maximum. The methodology used for the RVCH cladding was qualified in compliance with Regulatory Guide 1.43. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-37 Revision 21 September 2013 5.2.3.2 Compatibility with Reactor Coolant The materials of construction of the RCPB were specified to minimize corrosion and erosion. To avoid the possibility of accelerated erosion, the internal coolant velocity is limited to about 50 fps.
The reactor vessel is constructed of carbon steel with a 0.125 inch minimum of stainless steel or Inconel cladding on all internal surfaces that are in contact with the reactor coolant. The pressurizer is also constructed of carbon steel with austenitic stainless steel cladding on all surfaces exposed to the reactor coolant. All parts of the reactor coolant pump in contact with the reactor coolant are austenitic stainless steel except for seals, bearings, and secondary seals (O-rings made of elastomer material). The portions of the steam generator in contact with the reactor coolant water are clad with austenitic stainless steel. The steam generator tubesheet is weld clad with Inconel and the heat transfer tubes are made of Inconel. Tables 5.2-11 through 5.2-14 summarize the materials of construction of these RCS components.
The reactor coolant piping and fittings that make up the loops are austenitic stainless steel. All smaller piping that comprises part of the RCS boundary, such as the pressurizer surge line, spray and relief line, loop drains, and connecting lines to other systems, is also made of austenitic stainless steel. All valves in the RCS that are in contact with the coolant are constructed primarily of stainless steel. Other materials in contact with the coolant, such as materials for hard surfacing and packing, are special materials. 5.2.3.3 Compatibility with External Insulation and Environmental Atmosphere The materials of construction of the RCPB were specified to ensure compatibility with the containment-operating environment. All insulation used on the RCPB, as defined by the ASME B&PV Code, Section XI, is of the reflective stainless steel type or as described in Section 6.2.3.3.8. Additional information on the compatibility of RCPB materials with the containment environment to which they are exposed is provided in Section 3.11. 5.2.3.4 Chemistry of Reactor Coolant The RCS water chemistry is selected to minimize corrosion. A periodic analysis of the coolant chemical composition is performed to verify that the reactor coolant quality meets the specifications for coolant chemistry, activity level, and boron concentration.
The CVCS provides a means for adding chemicals to the RCS that control the pH of the coolant during initial startup and subsequent operation, scavenge oxygen from the coolant during startup, and control the oxygen level of the coolant due to radiolysis during all power operations subsequent to startup. To ensure thorough mixing, at least one reactor coolant pump or RHR pump is always in service when chemicals are being added to the system or when changing the boron concentration. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-38 Revision 21 September 2013 The chemical used for pH control is lithium hydroxide. This chemical is chosen for its compatibility with the materials and water chemistry of the borated water/stainless steel/zirconium/Inconel system. In addition, lithium is present in solution from the neutron irradiation of dissolved boron in the coolant. The lithium hydroxide is introduced into the RCS via the charging flow. The solution is prepared in the plant and poured into the chemical mixing tank. Reactor makeup water is then used to flush the solution to the suction manifold of the charging pumps.
The concentration of lithium hydroxide in the RCS is maintained in the range specified for pH control. If the concentration exceeds this range, a demineralizer is valved in to remove the excess lithium. Since the amount of lithium to be removed is small and its buildup can be readily calculated and determined by analysis, the flow through the cation bed demineralizer is not required to be full letdown flow.
During reactor startup from the cold condition, hydrazine is employed as an oxygen scavenging agent. The hydrazine solution is introduced into the RCS using the same injection flow path as the pH control agent, as described above.
Dissolved hydrogen is employed to control and scavenge oxygen produced due to radiolysis of water in the core region. Sufficient partial pressure of hydrogen is maintained in the volume control tank such that the specified equilibrium concentration of hydrogen is maintained in the reactor coolant. A self-contained pressure control valve maintains a minimum pressure in the vapor space of the volume control tank. This can be adjusted to provide the correct equilibrium hydrogen concentration. The RCS water chemistry specifications are provided in Table 5.2-15.
5.2.4 FRACTURE TOUGHNESS This section addresses fracture toughness in the RCPB. The RCS component upon which operating limitations are based is the reactor vessel. 5.2.4.1 Compliance with Code Requirements Assurance of adequate fracture toughness of the reactor pressure vessel is established using methods to estimate the reference nil-ductility transition (NDT) temperatures (RTNDT) (Reference 5). The fracture toughness properties of the reactor vessel wall material surrounding the irradiated core region are the limiting properties. The stringent fracture toughness requirements of the ASME B&PV Code, Section III, 1971 Edition, and the 1972 Summer Addenda are complied with. The estimated RTNDT uses as a guide the fracture toughness requirements of NB2300 of the Summer 1972 Addenda, which meet the intent of 10 CFR 50, Appendix G. For materials not in the beltline region, RTNDT was estimated using methods identified in Section 5.3.2 of the NRC Standard Review Plan. The upper-shelf energy level of the material is established using methods (Reference 5), which are responsive to 10 CFR 50, Appendix G.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-39 Revision 21 September 2013 The DCPP Units 1 and 2 reactor vessels were fabricated to the 1966 and 1968 editions of the code, respectively. Thus, Charpy impact test orientation was parallel to the working or rolling direction of the base materials. Additional impact tests were performed, however, on the intermediate and lower shell course plates of both vessels. These plates surround the effective height of the fuel assemblies. Full Charpy test curves were obtained on these plates from specimens oriented normal to the principal rolling direction. Full Charpy curves for all the base material in the vessels have been obtained by the fabricator on impact specimens oriented parallel to the principal working or rolling direction. Reactor vessel fracture toughness data are provided in Tables 5.2-17A and 5.2-18A, and Tables 5.2-17B and 5.2-18B for Units 1 and 2, respectively.
The replacement reactor vessel closure head (RVCH) was manufactured to the requirements of the ASME B&PV Code, Section III, 2001 Edition with Addenda through 2003. Fracture toughness data is provided in Table 5.2-17B.
Reactor vessel beltline region weld test specimens were taken from weldments prepared from excess production plate, weld wire, and flux materials. After completion of welding, the weldments were subjected to heat treatment to obtain the metallurgical effects equivalent to those produced during fabrication of the reactor vessel. The significant properties (e.g., weld wire chemical composition and weld flux type) of the weld materials in the beltline region were representative of the actual beltline materials and their fracture toughness. The use of test specimens prepared from excess production plate, weld wire, and flux materials and subjected to heat treatment satisfies the intent of the specific requirement of Section III.C.2 of Appendix G to 10 CFR 50 and ensures an adequate margin of safety. Two hundred forty bolting material specimens were impact tested at 10°F. The average of all the impact energy values was 50.5 ft-lb. The lateral expansion was measured on 24 specimens, and an average value of 35 mils was recorded. Fracture energy values obtained on 90 percent of the 240 specimens tested at 10°F either met or exceeded the fracture toughness requirements of Appendix G of 10 CFR 50. The lowest value of 40 ft-lb. exceeded the special mechanical property requirements of paragraph N-330 of the 1965 Edition of the ASME B&PV Code, which states that an average of 35 ft-lb. fracture energy is considered adequate for pressure vessel materials to be pressurized at ambient temperature (70°F). 5.2.4.2 Acceptable Fracture Energy Levels The identification and location of reactor vessel beltline region materials for Units 1 and 2 are shown in Figures 5.2-1 and 5.2-4, respectively. Chemical composition, fracture toughness properties, estimates of maximum anticipated change in RTNDT, and upper-shelf energy at the end-of-license fluence at the vessel wall 1/4 thickness location for materials in the beltline region are provided in Tables 5.2-18A through 5.2-21B for Units 1 and 2.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-40 Revision 21 September 2013 The stresses due to gamma heating in the vessel walls were also calculated and combined with the other design stresses. They were compared with the code-allowable limit for mechanical plus thermal stress intensities to verify that they are acceptable. The gamma stresses are low and thus have a negligible effect on the stress intensity in the vessel. 5.2.4.3 Operating Limitations During Startup and Shutdown Allowable pressures as a function of the rate of temperature change and the actual temperature relative to the reactor vessel RTNDT are established according to the methods in the 1972 NDT Summer Addenda of the ASME B&PV Code, Section III, Appendix G. Heatup and cooldown curves are provided in the DCPP Pressure Temperature Limits Report. The heatup and cooldown curves are based on the estimated RTNDT fracture toughness properties of the reactor vessel materials. Toughness data for the reactor vessel base materials are provided in Tables 5.2-17A and 5.2-17B for Units 1 and 2, respectively. Predicted RTNDT values are derived for 1/4T and 3/4T (thickness) in the limiting material by using the method described in Reference 27 and the maximum fluence for the applicable service period. The limiting material in the Unit 1 reactor vessel is weld seam 3-442C with an initial RTNDT conservatively estimated at -56°F, a copper content of 0.203 wt percent, and a nickel content of 1.018 wt percent. The limiting materials in the Unit 2 reactor vessel is the intermediate shell plate B5454-2 with a measured initial RTNDT of 67°F, a copper content of 0.14 wt percent, and a nickel content of 0.59 wt percent.
The maximum integrated fast neutron (E > 1 MeV) exposure for the vessel at 1/4T is computed to be 7.93 x 1018 and 8.75 x 1018 n/cm2 for 40 calendar years of operation at 3411 MWt for Units 1 and 2, respectively. The estimated end of life adjusted RTNDT for Units 1 and 2 are 218°F and 180°F, respectively, at 1/4T of the above material. 5.2.4.4 Compliance with Reactor Vessel Material Surveillance Program Requirements The toughness properties of the reactor vessel beltline material will be monitored throughout the service life with a material surveillance program that meets the requirements of 10 CFR 50, Appendix H. The original surveillance test program (Reference 11) for DCPP Unit 1 complies with ASTM E 185-70, the standard in effect when the vessel was manufactured. With three exceptions, the program also complies with ASTM E 185-73. The exceptions are the number of capsules in the program containing the limiting material, the number of Charpy specimens in each capsule, and the orientation of the base metal specimens.
A supplemental surveillance program was implemented at the Unit 1 fifth refueling outage to improve the existing program by bringing the overall surveillance program in better compliance with ASTM E 185-82, provide data for the period beyond which the DCPP UNITS 1 & 2 FSAR UPDATE 5.2-41 Revision 21 September 2013 original surveillance program was designed, and to provide the necessary data to demonstrate the effectiveness of reactor vessel thermal annealing. Capsule D from Unit 1, which was meant to be annealed and reinserted into the reactor vessel, was removed during 1R12 and is stored in the spent fuel pool. There are currently no industry plans to anneal reactor vessels. The Unit 1 supplemental surveillance program is described in References 28 and 29. For Unit 2, the specimen orientation, number, selection procedure, and removal schedule conform to ASTM E 185-73. The surveillance capsule program for Unit 2 is described in Reference 26. 5.2.4.4.1 Program Description The evaluation of radiation damage is based on preirradiation testing of Charpy V-notch and tensile specimens, and postirradiation testing of Charpy V-notch, and tensile specimens; plus wedge opening loading (WOL) fracture mechanics test specimens for Unit 1 and compact tension (CT) and bend bar fracture mechanics test specimens for Unit 2. These programs are based on transition temperature and fracture mechanics approaches, and conform with ASTM E-185, Recommended Practice for Surveillance Tests for Nuclear Reactor Vessels and 10 CFR 50, Appendix H. Thermal control specimens are not required since the surveillance specimens will be exposed to the combined neutron irradiation and temperature effects, and the test results will provide the maximum transition temperature shift. The surveillance program for Unit 2 does not include correlation monitors, but the program for Unit 1 does. Neutron dosimeters included in the capsules can be used to measure exposure throughout the life of the reactor vessel. 5.2.4.4.2 Surveillance Capsules The Unit 1 original reactor vessel surveillance program included eight specimen capsules and the supplemental surveillance program consists of four additional specimen capsules. The Unit 2 surveillance program consists of six specimen capsules. The Type II capsules in Unit 1 and all of the Unit 2 capsules utilize fissionable materials (uranium-238 and neptunium-237) as neutron dosimeters. The fissionable materials, in the form of U308 and Np02 powder, are encapsulated in metal (brass or stainless steel) capsules, which are sealed in steel blocks. The capsules are located in guide baskets welded to the outside of the thermal shield and neutron shield pads for Units 1 and 2, respectively, and are positioned directly opposite the center portion of the core. Sketches showing the location and spacing of the capsules for Unit 1 relative to the core, thermal shield, vessel, and weld seams are shown in Figures 5.2-16 and 5.2-17. Sketches showing the location and spacings of the capsules for Unit 2 are shown in Figures 5.2-18 and 5.2-19. The capsules can be removed when the vessel head and upper internals are removed and can be replaced when the lower internals are removed.
The eight capsules in the Unit 1 original surveillance program contain reactor vessel steel specimens from the intermediate shell plate or plates located in the core region of the reactor. The three Type II capsules also contain weld metal and heat affected zone DCPP UNITS 1 & 2 FSAR UPDATE 5.2-42 Revision 21 September 2013 specimens. All of the base material specimens are oriented parallel to the principal rolling direction. In addition, correlation monitors made from fully documented specimens of SA-533, Grade B, Class 1 material obtained through Subcommittee II of ASTM Committee E10, Radioisotopes and Radiation Effects, are inserted in the capsules of Unit 1 only. The eight capsules contain 27 tensile specimens, 256 Charpy V-notch specimens (which include weld metal and heat affected zone material), and 42 WOL specimens.
The four supplemental surveillance capsules for Unit 1 contain Charpy impact and tensile specimens machined from intermediate shell plate 4107-1, and oriented such that the specimen longitudinal axis is normal (transverse) to the plate principal rolling direction. Shell plate 4107 is the limiting base metal at 48 EFPY. These four capsules also contain surrogate weld metal specimens obtained from ABB Combustion Engineering. These surrogate weld specimens were made with the same weld wire heat (27204) and flux type (Linde 1092) as the Unit 1 reactor vessel limiting weld metal, and are representative of the Unit 1 limiting weld. The four capsules will also contain various Charpy specimens supplied by Electric Power Research Institute (EPRI) which will be used to obtain data on the effects of a reactor vessel thermal anneal. Two of the capsules will also contain previously irradiated test material from surveillance capsule S. This material consists of heat-affected zone (HAZ) and limiting weld metal broken Charpy specimens (which can be reconstituted into testable specimens), and weld metal WOL specimens. The 4 capsules contain 266 Charpy specimens, 24 tensile specimens, 20 reconstitution blanks from surveillance capsule S tested Charpy specimens, and 2 WOL specimens.
The six capsules for Unit 2 contain reactor vessel steel specimens oriented both parallel and normal (longitudinal and transverse) to the principal rolling direction of the limiting shell plate located in the core region of the reactor and associated weld metal and heat affected zone metal. The six capsules contain 54 tensile specimens, 360 Charpy V-notch specimens (which include weld metal and heat affected zone material), 72 CT specimens, and six bend bar specimens.
Dosimeters including Ni, Co, Fe (Unit 2 only), Co-Al, Cd shielded Co-Al, Cd shielded Np-237, and Cd shielded U-238 are placed in filler blocks drilled to contain the dosimeters. The dosimeters permit evaluation of the flux seen by the specimens and the vessel walls. In addition, thermal monitors made of low melting alloys are included to monitor the temperature of the specimens. The specimens are enclosed in a tight fitting stainless steel sheath to prevent corrosion and ensure good thermal conductivity. The complete capsule is helium leak tested. Vessel base material sufficient for at least two capsules will be kept in storage should the need arise for additional replacement test capsules in the program. Sufficient weld metal and heat affected zone material from Unit 2 for two additional capsules will also be stored. No additional weld metal or heat affected zone material is available for Unit 1.
As part of the surveillance program, a report of the residual elements in weight percent to the nearest 0.01 percent will be made for surveillance material and as deposited weld DCPP UNITS 1 & 2 FSAR UPDATE 5.2-43 Revision 21 September 2013 metal. Each of five Type I (base metal only) capsules (T, U, W, X and Z) for Unit 1 contains the following specimens:
Material No. of Charpys No. of Tensiles No. of WOL Plate No. B4106-1 8 1 2 Plate No. B4106-2 8 1 2 Plate No. B4106-3 8 1 2 ASTM Reference 8 - -
The following dosimeters and thermal monitors are included in each of the five capsules: Dosimeters Copper Nickel Cobalt-aluminum (0.15% Co.) Cobalt-aluminum (cadmium shielded) Thermal Monitors 97.5% Pb, 2.5% Ag (579°F melting point) 97.5% Pb, 1.75% Ag, 0.75% Sn (590°F melting point) Each of the three Type II capsules (S, V and Y) for Unit 1 contains the following specimens: Material No. of Charpys No. of Tensiles No. of WOL Plate No. B4106-3 8 2 2 Weld Metal(a) 8 2 2 Heat Affected Zone Metal 8 - - (Plate B4106-3) ASTM Reference 8 - - The following dosimeters and thermal monitors are included in each of the three Type II capsules: Dosimeters Copper Nickel Cobalt-aluminum (0.15% Co.) Cobalt-aluminum (cadmium shielded) (a) Weld fabricated from weld wire heat number 27204 using Linde 1092 Flux Lot No. 3714. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-44 Revision 21 September 2013 U-238 (cadmium shielded) Np-237 (cadmium shielded) Thermal Monitors 97.5% Pb, 2.5% Ag (579°F melting point) 97.5% Pb, 1.75% Ag, 0.75% Sn (590°F melting point) The four supplemental capsules for Unit 1 contain the following specimens, dosimeters, and thermal monitors: CAPSULE A(Note i) CAPSULE B(Note i) CAPSULE C(Note i) CAPSULE D(Note ii) Charpy Tension Charpy Tension WOL Charpy Tension Charpy Tension Weld Metal (Surrogate 27204) 15 3 15 3 - 30 3 15 3 Base Metal (Plate 4107-1) 15 3 15 3 - 15 3 15 3 Correlation Monitor (HSST-02 Plate) 12 - 8 - - - - - - Capsule S Weld Metal (Original 27204) - - 10 (Note iii) - 2 - - 10 (Note iii) - EPRI Specimens - - 30 - - 35 - 46 - Notes:
(i) Dosimeter wires: copper, iron, nickel and aluminum-0.15% cobalt (cadmium shielded and unshielded) Fission dosimeters: neptunium-237 (cadmium oxide shielded), and uranium 238 (cadmium oxide shielded) Thermal monitors: 97.5% Pb, 2.5% Ag (579°F melt point), 97.5% Pb, 1.75% Ag, 0.75% Sn (590°F melt point) (ii) Capsule D will contain the following dosimeters: Dosimeter wires: copper, iron, nickel and aluminum-0.15% cobalt (gadolinium shielded and unshielded) Fission dosimeters: neptunium-237 (gadolinium shielded) and uranium 238 (gadolinium shielded) Thermal monitors: will not be provided because annealing temperature will exceed the melting point of thermal monitors (iii) Broken weld metal and HAZ Charpy specimens from capsule S, suitable for reconstitution DCPP UNITS 1 & 2 FSAR UPDATE 5.2-45 Revision 21 September 2013 Each of the six capsules for Unit 2 will contain the following specimens: No. of No. of No. of No. of Material Charpys Tensiles Cts Bend Bars Plate B5454-1(a) 15 3 4 Plate B5454-1(b) 15 3 4 1 Weld Metal(c) 15 3 4 Heat Affected Zone Metal (Plate B5454-1) 15
The following dosimeters and thermal monitors are included in each of the six capsules: Dosimeters Iron Copper Nickel Cobalt-aluminum (0.15% Co) Cobalt-aluminum (cadmium shielded) U-238 (cadmium shielded) NP-237 (cadmium shielded) Thermal Monitors 97.5% Pb, 2.5% Ag (579°F melting point) 97.5% Pb, 1.75% Ag, 0.75% Sn (590°F melting point) The fast neutron exposure of the specimens occurs at a faster rate than that experienced by the vessel wall with the specimens being located between the core and the vessel. Since these specimens experience accelerated exposure and are actual samples from the materials used in the vessel, the changes in material properties are representative of the vessel at a later time in life. Data from the fracture toughness specimens (WOL, CT, and bend bar) are expected to provide additional information for use in determining fracture toughness for irradiated material.
The reactor vessel surveillance capsules for Unit 1 are shown in Figure 5.2-16 and in Figure 5.2-18 for Unit 2.
Correlation between calculations and measurements on the irradiated samples in the capsules, assuming the same neutron spectrum at the samples and the vessel inner wall, is described in Section 5.2.4.4.5 and has indicated good agreement. The degree to which the specimens perturb the fast neutron flux and energy distribution is considered in the evaluation of the surveillance specimen data. The integrated flux calculations at the vessel wall are adjusted using the surveillance data to provide best-estimate fluence values. The calculated maximum fast neutron exposure at the (a) Specimens oriented parallel to the principal rolling direction (longitudinal). (b) Specimens oriented normal to the principal rolling direction (transverse). (c) Weld fabricated from weld wire heat numbers 21935 and 12008 using Linde 1092 Flux Lot No. 3869. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-46 Revision 21 September 2013 vessel wall is 1.32 x1019 n/cm2 and 1.46 x 1019 n/cm2 (E > 1 MeV) for Units 1 and 2, respectively (NUREG-1511). 5.2.4.4.3 Capsule Removal For Units 1 and 2, the removal schedule conforms to Appendix H of 10 CFR 50. The schedule for removal of the Unit 1 and Unit 2 capsules is provided in Table 5.2-22. 5.2.4.4.4 Measurement of Integrated Fast Neutron (E > 1.0 MeV) Flux at the Irradiation Samples The use of passive neutron sensors such as those included in the internal surveillance capsule dosimetry sets does not yield a direct measure of the energy-dependent neutron flux level at the measurement location. Rather, the activation or fission process is a measure of the integrated effect that the time-and energy-dependent neutron flux has on the target material over the course of the irradiation period. An accurate assessment of the average flux level and, hence, time integrated exposure (fluence) experienced by the sensors may be developed from the measurements only if the sensor characteristics and the parameters of the irradiation are well known.
In particular, the following variables are of interest:
(1) the measured specific activity of each sensor (2) the physical characteristics of each sensor (3) the operating history of the reactor (4) the energy response of each sensor (5) the neutron energy spectrum at the sensor location In this section, the procedures used to determine sensor-specific activities, to develop reaction rates for individual sensors from the measured specific activities and the operating history of the reactor, and to derive key fast neutron exposure parameters from the measured reaction rates are described.
5.2.4.4.4.1 Determination of Sensor Reaction Rates The specific activity of each of the radiometric sensors is determined using established ASTM procedures. Following sample preparation and weighing, the specific activity of each sensor is determined by means of a lithium-drifted germanium, Ge(Li), gamma spectrometer. In the case of the surveillance capsule multiple foil sensor sets, these analyses are performed by direct counting of each of the individual wires or, as in the case of U-238 and Np-237 fission monitors, by direct counting preceded by dissolution and chemical separation of cesium from the sensor. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-47 Revision 21 September 2013 The irradiation history of the reactor over its operating lifetime is obtained from NUREG-0020, "Licensed Operating Reactors Status Summary Report," or from other plant records. In particular, operating data are extracted on a monthly basis from reactor startup to the end of the capsule irradiation period. For the sensor sets utilized in the surveillance capsule irradiations, the half-lives of the product isotopes are long enough that a monthly histogram describing reactor operation has proven to be an adequate representation for use in radioactive decay corrections for the reactions of interest in the exposure evaluations.
Having the measured specific activities, the operating history of the reactor, and the physical characteristics of the sensors, reaction rates referenced to full power operation are determined from the following equation: RANFYCleojd=jjrefjPPtet (5.2-1) where: A = measured specific activity (dps/gm) R = reaction rate averaged over the irradiation period and referenced to operation at a core power level of Pref (rps/nucleus) No = number of target element atoms per gram of sensor F = weight fraction of the target isotope in the sensor material Y = number of product atoms produced per reaction Pj = average core power level during irradiation period j (MW) Pref = maximum or reference core power level of the reactor (MW) Cj = calculated ratio of (E > 1.0 MeV) during irradiation period j to the time weighted averaged (E > 1.0 MeV) over the entire irradiation period = decay constant of the product isotope (sec-1) tj = length of irradiation period j (sec) td = decay time following irradiation period j (sec) and the summation is carried out over the total number of monthly intervals comprising the total irradiation period.
In the above equation, the ratio Pj/Pref accounts for month-by-month variation of power level within a given fuel cycle. The ratio Cj is calculated for each fuel cycle and accounts for the change in sensor reaction rates caused by variations in flux level due to changes in core power spatial distributions from fuel cycle to fuel cycle. For a single cycle irradiation Cj = 1.0. However, for multiple cycle irradiations, particularly those employing low leakage fuel management, the additional Cj correction must be utilized. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-48 Revision 21 September 2013 5.2.4.4.4.2 Corrections to Reaction Rate Data Prior to using the measured reaction rates in the least squares adjustment procedure discussed in Section 5.2.4.4.4.3, additional corrections are made to the U-238 measurements to account for the presence of U-235 impurities in the sensors as well as to adjust for the build-in of plutonium isotopes over the course of the irradiation.
In addition to the corrections made for the presence of U-235 in the U-238 fission sensors, corrections are also made to both the U-238 and Np-237 sensor reaction rates to account for gamma ray induced fission reactions occurring over the course of the irradiation. 5.2.4.4.4.3 Least Squares Adjustment Procedure Values of key fast neutron exposure parameters are derived from the measured reaction rates using the FERRET least squares adjustment code (Reference 12). The FERRET approach uses the measured reaction rate data, sensor reaction cross-sections, and a calculated trial spectrum as input and proceeds to adjust the group fluxes from the trial spectrum to produce a best fit (in a least squares sense) to the measured reaction rate data. The "measured" exposure parameters along with the associated uncertainties are then obtained from the adjusted spectrum.
In the FERRET evaluations, a log-normal least squares algorithm weights both the trial values and the measured data in accordance with the assigned uncertainties and correlations. In general, the measured values f are linearly related to the flux by some response matrix A: isg(,)()f=Aig(s)g (5.2-2) where i indexes the measured values belonging to a single data set s, g designates the energy group, and delineates spectra that may be simultaneously adjusted. For example, iiggRs= (5.2-3) relates a set of measured reaction rates Ri to a single spectrum g by the multigroup reaction cross-section ig. The log-normal approach automatically accounts for the physical constraint of positive fluxes, even with large assigned uncertainties.
In the least squares adjustment, the continuous quantities (i.e., neutron spectra and cross-sections) are approximated in a multigroup format consisting of 53 energy groups. The trial input spectrum is converted to the FERRET 53 group structure using the SAND-II code (Reference 13). This procedure is carried out by first expanding the 47 group calculated spectrum into the SAND-II 620 group structure using a SPLINE DCPP UNITS 1 & 2 FSAR UPDATE 5.2-49 Revision 21 September 2013 interpolation procedure in regions where group boundaries do not coincide. The 620-point spectrum is then re-collapsed into the group structure used in FERRET.
The sensor set reaction cross-sections, obtained from the ENDF/B-VI dosimetry file (Reference 14), are also collapsed into the 53 energy group structure using the SAND-II code. In this instance, the trial spectrum, as expanded to 620 groups, is employed as a weighting function in the cross-section collapsing procedure. Reaction cross-section uncertainties in the form of a 53 x 53 covariance matrix for each sensor reaction are also constructed from the information contained on the ENDF/B-VI data files. These matrices include energy group-to-energy group uncertainty correlations for each of the individual reactions.
Due to the importance of providing a trial spectrum that exhibits a relative energy distribution close to the actual spectrum at the sensor set locations, the neutron spectrum input to the FERRET evaluation is obtained from plant-specific calculations for each dosimetry location. While the 53 x 53 group covariance matrices applicable to the sensor reaction cross-sections are developed from the cross-section data files, the covariance matrix for the input trial spectrum is constructed from the following relation: gg'n2gg'gg'MRRRP=+ (5.2-4) where Rn specifies an overall fractional normalization uncertainty (i.e., complete correlation) for the set of values. The fractional uncertainties, Rg, specify additional random uncertainties for group g that are correlated with a correlation matrix given by: gg'gg'P1e[]H=+ (5.2-5) where: H=(')gg222 The first term in the correlation matrix equation specifies purely random uncertainties, while the second term describes short-range correlations over a group range ( specifies the strength of the latter term). The value of is 1 when g = g' and 0 otherwise. 5.2.4.4.5 Calculation of Integrated Fast Neutron (E > 1.0 MeV) Flux at the Irradiation Samples Fast neutron exposure calculations for the reactor geometry are carried out using both forward and adjoint discrete ordinates transport techniques. A single forward calculation provides the relative energy distribution of neutrons for use as input to neutron dosimetry evaluations as well as for use in relating measurement results to the actual exposure at key locations in the pressure vessel wall. A series of adjoint DCPP UNITS 1 & 2 FSAR UPDATE 5.2-50 Revision 21 September 2013 calculations, on the other hand, establishes the means to compute absolute exposure rate values using fuel cycle-specific core power distributions, thus providing a direct comparison with all dosimetry results obtained over the operating history of the reactor.
In combination, the absolute cycle-specific data from the adjoint evaluations together with relative neutron energy spectra distributions from the forward calculation provided the means to:
(1) Evaluate neutron dosimetry from surveillance capsule locations. (2) Enable a direct comparison of analytical prediction with measurement. (3) Determine plant-specific bias factors to be used in the evaluation of the best estimate exposure of the reactor pressure vessel. (4) Establish a mechanism for projection of pressure vessel exposure as the design of each new fuel cycle evolves. 5.2.4.4.5.1 Reference Forward Calculation The forward transport calculation for the reactor is carried out in r, geometry using the DORT two-dimensional discrete ordinates code (Reference 15) and the BUGLE-93 cross-section library (Reference 16). The BUGLE-93 library is a 47 neutron group, ENDFB-VI based, data set produced specifically for light water reactor applications. In these analyses, anisotropic scattering is treated with a P3 expansion of the scattering cross-sections and the angular discretization is modeled with an S8 order of angular quadrature. The reference forward calculation is normalized to a core midplane power density characteristic of operation at the stretch rating for the reactor.
The spatial core power distribution utilized in the reference forward calculation is derived from statistical studies of long-term operation of Westinghouse 4-loop plants. Inherent in the development of this reference core power distribution is the use of an out-in fuel management strategy, i.e., fresh fuel on the core periphery. Furthermore, for the peripheral fuel assemblies, a 2 uncertainty derived from the statistical evaluation of plant-to-plant and cycle-to-cycle variations in peripheral power is used.
Due to the use of this bounding spatial power distribution, the results from the reference forward calculation establish conservative exposure projections for reactors of this design operating at the stretch rating. Since it is unlikely that actual reactor operation would result in the implementation of a power distribution at the nominal +2 level for a large number of fuel cycles and, further, because of the widespread implementation of low leakage fuel management strategies, the fuel cycle-specific calculations for this reactor will result in exposure rates well below these conservative predictions.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-51 Revision 21 September 2013 5.2.4.4.5.2 Cycle Specific Adjoint Calculations All adjoint analyses are also carried out using an S8 order of angular quadrature and the P3 cross-section approximation from the BUGLE-93 library. Adjoint source locations are chosen at several key azimuths on the pressure vessel inner radius. In addition, adjoint calculations were carried out for sources positioned at the geometric center of all surveillance capsules. Again, these calculations are run in r, geometry to provide neutron source distribution importance functions for the exposure parameter of interest; in this case, (E > 1.0 MeV). The importance functions generated from these individual adjoint analyses provide the basis for all absolute exposure projections and comparison with measurement. These importance functions, when combined with cycle-specific neutron source distributions, yield absolute predictions of neutron exposure at the locations of interest for each of the operating fuel cycles, and establish the means to perform similar predictions and dosimetry evaluations for all subsequent fuel cycles.
Having the importance functions and appropriate core source distributions, the response of interest can be calculated as:
(R0, 0) = r E I (r, , E) S(r, , E) r dr d dE (5.2-6) where: (R0, 0) = Neutron flux (E > 1.0 MeV) at radius R0 and azimuthal angle 0 I (r, , E) = Adjoint importance function at radius r, azimuthal angle , and neutron source energy E S (r, , E) = Neutron source strength at core location r, and energy E It is important to note that the cycle-specific neutron source distributions, S(r,,E), utilized with the adjoint importance functions, I(r,,E), permit the use not only of fuel cycle-specific spatial variations of fission rates within the reactor core, but also allow for the inclusion of the effects of the differing neutron yield per fission and the variation in fission spectrum introduced by the build-in of plutonium isotopes as the burnup of individual fuel assemblies increases.
5.2.4.5 Reactor Vessel Annealing There are no special design features that would prohibit the onsite annealing of the vessel. In the event that an annealing operation should be required to restore the properties of the vessel material opposite the reactor core because of neutron irradiation damage, a metal temperature of approximately 850°F maximum for a period of 168 hours maximum would be applied.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-52 Revision 21 September 2013 The reactor vessel materials surveillance program is adequate to accommodate the reactor vessel annealing. The remaining surveillance capsules at the time of annealing would be removed and given a thermal cycle equivalent to the annealing cycle. They would then be reinserted in their normal position between the core internals assembly and the reactor vessel wall. Subsequent testing of the fracture toughness specimens from the capsules would then reflect the radiation environment both before and after any annealing operation. 5.2.4.6 LOCA Thermal Transient In the event of a large LOCA, the RCS rapidly depressurizes and the loss of coolant may empty the reactor vessel. If the reactor is at normal operating conditions before the accident, the reactor vessel temperature is approximately 550°F, and, if the plant has been in operation for some time, part of the reactor vessel is irradiated. At an early stage in the depressurization transient, the ECCS rapidly injects cold coolant into the reactor vessel. This produces a thermal stress in the vessel wall. To evaluate the effect of the stress, three possible modes of failure are considered; ductile yielding, brittle fracture, and fatigue.
(1) Ductile Mode The failure criterion used for this evaluation is that there shall be no gross yielding across the vessel wall using the material yield stress specified in the ASME B&PV Code, Section III. The combined pressure and thermal stresses during injection through the vessel thickness as a function of time have been compared to the material yield stress during the safety injection transient. The results of the analyses showed that local yielding may occur only in approximately the inner 18 percent of the base metal and in the vessel cladding, complying with the above criterion. (2) Brittle Mode The possibility of brittle fracture of the irradiated reactor vessel core region has been considered utilizing fracture mechanics concepts. This analysis takes into account the effects of water temperature, heat transfer coefficients, and fracture toughness as a function of time, temperature, and irradiation. Both a local crack effect and a continuous crack effect have been considered, with the latter requiring the use of a rigorous finite element axisymmetric code. On the weight of this evidence, the thermal shock resulting from the LOCA will not produce instability in the vessel wall even at the end of plant life.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-53 Revision 21 September 2013 (3) Fatigue Mode The failure criterion used for fatigue analysis was based on the ASME B&PV Code, Section III. In this method the piece is assumed to fail once the combined usage factor at the most critical location for all transients applied to the vessel exceeds the code-allowable usage factor of 1. The location in the vessel below the nozzle level, which will see the emergency core cooling water and have the highest usage factor will be the incore instrumentation tube attachment welds to the vessel bottom head. As a worst case assumption, the incore instrumentation tubes and attachment penetration welds are considered to be quenched to the cooling water temperature while the vessel wall maintains its initial temperature before the start of the transient. The maximum possible pressure stress during the transient is also taken into account. This method of analysis is quite conservative and yields calculated stresses greater than would actually be experienced. The resulting usage factor for the instrument tube welds considering all operating transients and including the safety injection transient occurring at the end of the plant life is below 0.2, which compares favorably with the code-allowable usage factor of 1. It is concluded from the results of these analyses that the delivery of cold emergency core cooling water to the reactor vessel following a LOCA does not cause any loss of integrity of the vessel. 5.2.5 AUSTENITIC STAINLESS STEEL The unstabilized austenitic stainless steel materials used in the RCPB, in systems required for reactor shutdown, and for emergency core cooling, are processed and fabricated using established methods and techniques to avoid partial or local sensitization. The measures taken to avoid sensitization are in general conformance with the recommendations of RG 1.44 (Reference 22). 5.2.5.1 Cleaning and Contamination Protection Procedures All materials are cleansed and protected by procedures that guard against contaminants capable of causing stress corrosion cracking during storage, fabrication, shipment, erection, testing and operation. Contaminant concentration limits are implemented per plant approved procedures.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-54 Revision 21 September 2013 5.2.5.2 Solution Heat Treatment Requirements Whenever applicable, solution heat treatment of materials prior to fabrication or assembly into components or systems is discussed in Section 5.2.5.5 below. In such cases, solution heat treatment conformed to the requirements of RG 1.44. 5.2.5.3 Material Inspection Program Austenitic stainless steel materials are procured from raw material produced in the final heat-treated condition as required by the respective ASTM or ASME material specification for the particular type or grade of alloy.
Westinghouse-furnished wrought austenitic stainless steel alloy materials are corrosion tested in the final heat-treated condition. These tests are performed in accordance with ASTM A262. 5.2.5.4 Unstabilized Austenitic Stainless Steel Unstabilized austenitic stainless steel used in components of the RCPB are as follows: (1) Reactor Vessel (a) (Unit 1) Primary nozzle safe-ends - Type 316 stainless steel forgings. (Unit 2) Primary nozzle safe-ends - Type 316 stainless steel forgings overlaid with weld metal after final post-weld heat treatment. (2) Steam Generators Primary nozzle safe-ends - Grade F316LN forging. (3) Pressurizers Unit 1 Unit 2 (a) Surge nozzle safe-end Type 316 forging Type 316L forging (b) Spray nozzle safe-end Type 316 forging Type 316L forging (c) Relief nozzle safe-end Type 316 forging Type 316L forging (d) Safety valve (3) nozzle Type 316 forging Type 316L forging safe-end 5.2.5.5 Avoidance of Sensitization Methods and material techniques used to avoid partial or local severe sensitization are as follows:
(1) Core Structural Components DCPP UNITS 1 & 2 FSAR UPDATE 5.2-55 Revision 21 September 2013 In all cases where austenitic stainless steel must be given a stress-relieving treatment above 800°F, a high-temperature stabilizing procedure was used. This is performed in the temperature range of 1600-1900°F, with holding time sufficient to achieve chromium diffusion to the grain boundary regions. Proof that such stabilization is achieved is based on ASTM A393. (2) Stainless Welding (a) Nozzle safe-ends 1. Weld deposit with Ni-Cr-Fe Weld Metal F-Number 43 and attach austenitic stainless steel safe-end after final post-weld heat treatment. 2. Use of a stainless steel weld metal analysis A-7 containing less than 0.02 percent carbon or more than 5 percent ferrite, or both. (b) All welding is conducted using procedures that are in accordance with the ASME B&PV Code, Section IX. (c) All welding procedures and welders have been qualified to the ASME B&PV Code rules of Section IX. When these welding procedure tests are performed on test welds made from base metal and weld metal materials that are from the same lot(s) of materials used in the fabrication of components, additional testing is frequently required to determine the metallurgical, chemical, physical, corrosion, etc., characteristics of the weldment. The additional tests conducted on a technical case basis are as follows: light and electron microscopy, elevated temperature mechanical properties, chemical check analysis, fatigue tests, intergranular corrosion tests or static and dynamic corrosion tests within reactor water chemistry limitations. (d) The interpass temperature of all welding methods is limited to 350°F maximum, with the exception of the replacement RVCH cladding operations. The methodology used for the RVCH cladding weld operations was qualified in compliance with Regulatory Guide 1.43. (e) Travel speed, voltage, amperage, as well as thickness of weld metal layers, and degree of weaving (two electrode diameters or ID of gas cup maximum) are carefully controlled on all welding processes to minimize sensitization in the completed welds.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-56 Revision 21 September 2013 (f) All welds are nondestructively examined in accordance with code requirements. (g) Code-authorized inspectors are required to review and sign off on all welding done both in the shop and field. (h) For the RSGs, ferrite level is 5-18 percent, calculated by WRC sketch. (3) Hard Facing All hard facing procedures on austenitic stainless steel use low (less than 800°F) preheat temperatures to preclude sensitization of the base metal. Processes approved are limited to those proven by tests not to cause sensitization. (4) Bent Pipe Sections Bent pipe sections are solution heat-treated to produce nonsensitized conditions in the material after bending; this is done by controlling handling temperatures and water quenching time to ensure that all carbides are in solution. 5.2.5.6 Retesting Unstabilized Austenitic Stainless Steel Exposed to Sensitizing Temperatures It is not normal Westinghouse practice to expose unstabilized austenitic stainless steels to the sensitization range of 800 to 1500°F during fabrication into components except as described in Section 5.2.5.5. If, during the course of fabrication, the steel is inadvertently exposed to the sensitization temperature range, 800 to 1500°F, the material may be tested in accordance with A262 to verify that it is not susceptible to intergranular attack. Testing is not required for:
(1) Cast metal or weld metal with a ferrite content of 5 percent or more. (2) Material with a carbon content of 0.03 percent or less that is subjected to temperatures in the range of 800 to 1500°F for less than 1 hour. (3) Material exposed to special processing provided the processing is properly controlled to develop a uniform product and provided that adequate documentation exists of service experience and/or test data to demonstrate that the processing will not result in increased susceptibility to intergranular stress corrosion.
If it was verified that such material was susceptible to intergranular attack, the material would have been solution annealed again and water quenched or rejected. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-57 Revision 21 September 2013 5.2.5.7 Control of Delta Ferrite Welding of austenitic stainless steel was controlled to mitigate the occurrence of microfissuring or hot cracking in the weld. Although published data and experience have not confirmed that fissuring is detrimental to the quality of the weld, it is recognized that such fissuring is undesirable in a general sense. Also, the presence of delta ferrite is one of the mechanisms for reducing the susceptibility of stainless steel welds to hot cracking.
The scope of these controls encompassed welding processes used to join stainless steel parts in components designed, fabricated, or stamped in accordance with the ASME B&PV Code, Section III, Classes 1, 2, and core support components. Delta ferrite control was appropriate for the above welding requirements except where no filler metal was used if for other reasons such control was not applicable. These exceptions included electron beam welding, autogenous gas shielded tungsten arc welding, explosive welding, and welding using fully austenitic welding materials.
In accordance with Section III, fabrication and installation specifications required welding procedure and welder qualification and included delta ferrite determinations for the austenitic stainless steel welding materials used for welding qualification testing and for production processing. Specifically, the undiluted weld deposits of the "starting" welding materials were required to contain a minimum of 5 percent delta ferrite as determined by chemical analysis and calculation using the appropriate weld metal constitution diagrams in Section III. New welding procedure qualification tests were evaluated for these applications in accordance with the requirements of Sections III and IX. The results of all the destructive and nondestructive tests were reported in the procedure qualification record in addition to the information required by Section III.
The "starting" welding materials used for fabrication and installation welds of austenitic stainless steel materials and components meet the requirements of Section III. Welding materials were tested using the welding energy inputs to be employed in production welding.
Combinations of approved heats and lots of starting welding materials were used for all welding processes. The welding quality assurance program included identification and control of welding material by lots and heats as appropriate. All of the weld processing was monitored according to approved inspection programs, including review of starting materials, qualification records, and welding parameters. Welding systems are also subject to quality assurance audit including calibration of gauges and instruments; identification of starting and completed materials; welder and procedure qualifications; availability and use of approved welding and heat treating procedures; and documentary evidence of compliance with materials, welding parameters, and inspection requirements. Fabrication and installation welds were inspected using nondestructive examination methods according to Section III rules. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-58 Revision 21 September 2013 5.2.6 PUMP FLYWHEELS Provisions for reactor coolant pump (RCP) flywheel integrity are presented in this section. 5.2.6.1 Compliance with AEC Safety Guide 14 The flywheel consists of two thick plates bolted together. The flywheel material is produced by a process that minimizes flaws in the material and improves its fracture toughness properties; i.e., an electric furnace with vacuum degassing. Each plate is fabricated from SA-533, Grade B, Class 1 steel. Supplier certification reports are available for all plates and demonstrate the acceptability of the flywheel material on the basis of the requirements of AEC Safety Guide 14 (Reference 23). Flywheel blanks are flame cut from SA-533, Grade B, Class 1 plates with at least 1/2 inch of stock left on the outer and bore surfaces for machining to final dimensions. The finished machined flywheels, including bores, keyways, and drilled holes, are subjected to magnetic particle or liquid penetrant examinations in accordance with the requirements of Section III of the ASME B&PV Code. The finished flywheels, as well as the flywheel material (rolled plate), are subjected to 100 percent volumetric ultrasonic inspection using procedures and acceptance standards specified in Section III of the ASME B&PV Code.
The RCP motors are designed such that, by removing the cover to provide access, the flywheel is available to allow an inservice inspection program in accordance with the Technical Specifications. Determining acceptability of the flywheel material involves two steps as follows: (1) Establish a reference curve describing the lower bound fracture toughness behavior for the material in question. (2) Use Charpy (CV) impact energy values obtained in certification tests at 10°F to fix position of the heat in question on the reference curve. A lower bound Kld reference curve (see Figure 5.2-7) has been constructed from dynamic fracture toughness data generated by Westinghouse (Reference 3) on A-533, Grade B, Class 1 steel. All data points are plotted on the temperature scale relative to the RTNDT temperature. The construction of the lower-bound curve below which no single test point falls, combined with the use of dynamic data when flywheel loading is essentially static, together represent a large degree of conservatism.
The applicability of a 30 ft-lb Charpy energy reference value has been derived from sections on Special Mechanical Property Requirements and Tests in Article 3, Section III, of the ASME B&PV Code. The implication is that the low test temperature of +10°F, and the 30 ft-lb. requirement at that temperature provide assurance that RTNDT is less than +10°F. Flywheel plates exhibit an average value of 30 ft-lb or greater in the DCPP UNITS 1 & 2 FSAR UPDATE 5.2-59 Revision 21 September 2013 weak direction and, therefore, meet the specific Safety Guide 14 requirement that RTNDT must be no higher than 10°F. Making the conservative assumption that all materials in compliance with the code requirements are characterized by an RTNDT temperature of 10°F, it is possible to reassign the reference temperature position RTNDT in Figure 5.2-7 to a value of 10°F.
Flywheel operating temperature at the surface is 120°F. The lower bound toughness curve indicates a value of 116 ksi-in1/2 at the (NDT + 110) position corresponding to operating temperature. Thus, the Safety Guide 14 requirement that the operating temperature be at least 100°F above RTNDT is fulfilled. At the time the flywheels were ordered, Charpy V-notch tests were required only at 10°F. However, by assuming a minimum toughness at operating temperature in excess of 100 ksi-in1/2, it can be seen by examination of the correlation in Figure 5.2-8 that the CV upper-shelf energy must be in excess of 50 ft-lb. Therefore, the requirement "b", that the upper-shelf energy must be at least 50 ft-lb, is satisfied.
It is concluded that flywheel plate materials are suitable for use and meet the Safety Guide 14 acceptance criteria on the bases of suppliers' certification data. 5.2.6.2 Additional Data and Analyses The calculated stresses at operating speed are based on stresses due to centrifugal forces. The stress resulting from the interference fit of the flywheel on the shaft is less than 2000 psi at zero speed and becomes zero at approximately 600 rpm because of radial hub expansion. The RCPs run at approximately 1190 rpm and may operate briefly at overspeeds of up to 109 percent (at 1295 rpm). For conservatism, however, 125 percent of operating speed was selected as the design speed for the RCPs. The flywheels are given a preoperational test prior to shipment at 125 percent of the operating speed.
Precautionary measures, taken to preclude missile formation from primary coolant pump components, ensure that the pumps will not produce missiles under any anticipated accident condition. Each component of the primary pump motors has been analyzed for missile generation. Any fragments of the motor rotor would be contained by the heavy stator. The same conclusion applies to the pump impeller because the small fragments that might be ejected would be contained by the heavy casing. 5.2.7 REACTOR COOLANT PRESSURE BOUNDARY LEAKAGE DETECTION SYSTEM Means are provided to detect and, to the extent practical, identify the location of reactor coolant leakage sources. Detection systems with diverse modes of operation are used to ensure adequate surveillance with sufficient sensitivity so that increases in leakage rate can be detected before the integrated leakage rate reaches a value that could DCPP UNITS 1 & 2 FSAR UPDATE 5.2-60 Revision 21 September 2013 interfere with the safe operation of the plant. Section 5.2.9 discusses sources of reactor coolant leakage outside containment.
RG 1.45, Revision 0 (Reference 25), described acceptable methods for selection of leakage detection systems for the reactor coolant pressure boundary. The construction permits for DCPP Units 1 and 2 were issued prior to the guidance of RG 1.45. The RCPB leakage detection system meets the intent of RG 1.45, Revision 0, to detect and monitor reactor coolant system leakage such that operators have sufficient time to take corrective actions (References 31 and 37). 5.2.7.1 Leakage Detection Methods Systems using diverse methods and modes of operation are provided to continuously monitor environmental conditions within the containment, and to detect the presence of radioactive and nonradioactive leakage to the containment. Once operation begins, background levels are established, thereby providing a baseline for leakage detection. Deviations from normal conditions indicate possible changes in leakage rates and are monitored in the control room and the auxiliary building. Indications of leakage include changes in containment particulate and gaseous activity, containment sump level, containment condensation, and other volumetric measurement such as increased coolant makeup demand. A list of systems available to detect these changes is provided in Table 5.2-16. 5.2.7.1.1 Containment Radioactivity Monitors Containment radioactivity monitors continuously monitor the air particulate and gaseous activity levels in the containment during normal plant operation. Leakage to the containment from the RCPB will result in changes in airborne radioactivity levels that can be detected by this equipment. Detector sensitivity, in terms of leakage rates, depends on the radioactivity level in the reactor coolant itself.
The containment radioactivity monitors measure beta and/or gamma activity in the containment by taking continuous air samples from the containment atmosphere. This sample flow first passes through the air particulate monitor and then through the gas monitor assembly. The sample is then returned to the containment. A complete description of the containment activity monitors, including sensitivity and control, indication, and alarm, is presented in Section 11.4. 5.2.7.1.2 Containment Sump Levels and Pump Operation Leakage from the primary system would result in reactor coolant flowing into one of the containment sumps. Sump level and sump pump integrated flow is monitored to provide a measure of the overall leakage that remains in liquid state.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-61 Revision 21 September 2013 5.2.7.1.3 Containment Condensation Measurements The containment condensation measuring system provides a measure of the amount of leakage vaporized (see Section 5.2.7.4). This system collects and measures moisture condensed from the containment atmosphere by the cooling coils of the fan cooler air circulation units. Moisture from leaks up to sizes permissible for continued plant operation will partially evaporate into the containment atmosphere and will be condensed on the fan cooling coils. This system dependably and accurately measures total vaporized leakage, including leakage from the cooling coils themselves. It measures the liquid runoff flowrate from the drain pans under each containment fan cooler unit. The condensate measuring system consists of a vertical standpipe, valves, and instrumentation installed in the drain piping of the reactor containment fan cooler unit.
Depending on the number of reactor containment fan cooler units in operation, the drainage flowrate from each unit due to normal condensation can be determined. Additional or abnormal leaks will result in containment humidity and condensation runoff rate increases, and the additional leakage can then be measured. 5.2.7.1.4 Other Methods of Detection (1) Charging Pump Operation During normal operation only one charging pump is operating. If a gross loss of reactor coolant should occur which was not detected by the methods previously described, the flowrate mismatch of the charging and letdown flows would indicate RCS leakage. (2) Liquid Inventory Gross leakage can also be detected by an increase in the makeup rate to the RCS. This is inherently a low-precision indication, because makeup to the RCS is also required due to other process variables. A quantitative measurement of leakage requires a test over a reasonable period of time to establish changes in the physical inventory. (3) Coolant Radiation Monitors The component cooling liquid monitor continuously monitors the component cooling water system (CCWS) for activity indicative of a leak of reactor coolant from either the RCS or the RHR system loop in the CCWS. In addition, condenser offgas monitors and steam generator blowdown radiation detectors are available to detect steam generator tube leakage. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-62 Revision 21 September 2013 (4) Containment Atmosphere Temperature and Pressure Measurement Various air temperature and pressure sensors would supplement indications of RCS leakage. Containment temperature and pressure fluctuate slightly during plant operation, but a rise above the normally indicated range of values may indicate RCS leakage into the containment. The accuracy and relevance of temperature and pressure measurements is a function of containment free volume and detector location. Alarm signals from these instruments would be valuable in recognizing rapid and sizable energy releases to the containment. Thermoswitches are installed in the leakoff piping from RCS valves with restricted access during plant operation as a means of identifying the source of leakage (i.e., the specific valve) from a packing or bellows failure. Identified indicating lights, located in a routinely inspected area, are actuated by the thermoswitches. A control room alarm is provided for valve stem leakoff. 5.2.7.1.5 Visual and Ultrasonic Inspections Visual and ultrasonic inspections of the RCPB will be made periodically during plant shutdown periods. Limited access to the containment is possible for this purpose during normal plant operation. The design of the reactor vessel and its arrangement in the system provides accessibility during service life to the entire internal surface of the vessel (except where access is limited by control rod drive or instrument penetrations). Access is also provided to the entire primary piping system, except for the area of pipe within the concrete biological shielding. 5.2.7.1.6 Reactor Coolant System Water Inventory Balance As prescribed by the Technical Specifications, a RCS water inventory balance shall be performed at least once every 72 hours, with exceptions as noted in the Technical Specifications. Tracking the RCS inventory in a consistent manner provides an effective means of quantifying overall system leakages.
Data on other secondary methods of leak detection, such as pressurizer liquid level, volume control tank liquid level, charging pump flowrate, and pressurizer relief tank liquid level are provided in Table 5.2-16. 5.2.7.2 Indication in Control Room Positive indications in the control room of coolant leakage from the RCS to the containment are provided by equipment that permits continuous monitoring of containment air activity, containment sump level changes, and of runoff from the condensate collecting pans under the cooling coils of the containment fan cooler units. This equipment provides indication of normal background, which is indicative of a basic level of leakage from the RCS and components. An increase in observed parameters is DCPP UNITS 1 & 2 FSAR UPDATE 5.2-63 Revision 21 September 2013 an indication of leakage within the containment, and the equipment provided is capable of monitoring this change.
As indicated in Table 5.2-16, numerous other forms of RCS leakage indication are provided in the control room or auxiliary building control area. Leakage detection systems are provided and located in a manner such that for minor leakages the operator can identify the subsystem that is leaking and effectively isolate that leakage with no more than short-term interruption of the operation of the complete system. Figures 5.2-14 and 5.2-15 are examples of the correlative relationships between radioactivity leak detector indications and the corresponding volumetric leak flowrate. This information is provided to the operator for a quick and easy interpretation of leakage conditions, and forms the basis for determining operator action. 5.2.7.3 Limits for Reactor Coolant Leakage Operational leakage limiting conditions for RCS operation are presented in the Technical Specifications.
The Technical Specifications also present leakage limitations for the Reactor Coolant System Pressure Isolation Valves (PIVs) listed in Table 5.2-23.
Reactor Coolant System PIVs protect low pressure ECCS systems such as the RHR System and the Safety Injection System (SIS) from overpressurization and rupture of their low pressure piping which could result in a LOCA that bypasses the containment. Testing of these valves at least once per refueling interval during startup ensures a low probability of gross failure. Each PIV is required to be tested prior to returning the valve to service following maintenance, repair, or replacement work. 5.2.7.4 Unidentified Leakage The sensitivity and response time of RCPB leakage detection systems vary for different methods of detection. However, the diverse systems available are required to have the capability to detect continuous leakage rates as low as 1 gpm within 1 hour for unidentified leaks at the design conditions and assumptions, as recommended by RG 1.45 (Reference 25).
The containment particulate monitor is the most sensitive instrument of those available for detection of reactor coolant leakage into the containment. This instrument is capable of detecting particulate radioactivity concentrations as low as 10-11 µCi/cc. The sensitivity of the air particulate monitor to an increase in reactor coolant leakage rate is dependent on the magnitude of the normal leakage into the containment. The sensitivity is greatest where normal leakage is low, as has been demonstrated by the experience of Indian Point Unit No. 1, Yankee Rowe, and Dresden Unit 1. Based on data from these operating plants, it is expected that this unit will detect (at the 95 percent confidence level) an increase in containment air particulate activity resulting in a gross count rate equivalent to 1 x 10-9 µCi/cc during normal full power operation. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-64 Revision 21 September 2013 As shown in Figure 5.2-9, this system has adequate response to detect a 1 gpm leak within 1 hour assuming a reactor coolant particulate activity corresponding to as low as 0.1 percent fuel defects. The assumption of 0.1 percent fuel defects used in the design calculation is less than the percentage of failed fuel assumed in the Environmental Report (Reference 36) and follows the guidance of RG 1.45 (References 25 and 37).
The containment radioactive gas monitor is inherently less sensitive (threshold at 10-7 µCi/cc) than the containment air particulate monitor, and would function in the event that significant reactor coolant gaseous activity results from fuel cladding defects. The sensitivity and range are such that gross count rates equivalent to from 10-6 to 10-3 µCi/cc will be detected. This system is also adequate to detect a 1 gpm leak within 1 hour assuming a reactor coolant gaseous activity corresponding to as low as 0.1 percent fuel defects as shown in Figure 5.2-9. The assumption of 0.1 percent fuel defects used in the design calculation is less than the percentage of failed fuel assumed in the Environmental Report and follows the guidance of RG 1.45 (References 25 and 37). The containment gaseous activity will result from any fission product gases (Kr-85, Xe-135) leaking from the RCS as well as from the argon-41 produced in the air around the reactor vessel. Assuming a constant background radioactivity in the containment atmosphere due predominantly to argon-41, and reactor coolant gaseous activity of 0.03 µCi/cc (corresponding to about 0.05 percent fuel defects), a 1-gpm coolant leak would double the fission product gas background in about 2 hours. The occurrence of a leak of 2 to 4 gpm would double the background in less than 1 hour. In these circumstances, this instrument is a useful backup to the air particulate monitor.
The adequacy of the containment particulate and radioactive gas monitors to detect a change in leakage during the initial period of plant operation will be limited by low coolant activity levels. The gas detector will not be as sensitive as the other leakage detection systems during this period because the argon-41 background will mask the low level of gaseous activity from coolant leakage.
Within the containment, the average air temperature is held at 120°F or below in accordance with the Technical Specifications. The hot dry air promotes evaporation of water leakage from hot systems, and the cooling coils of the fan cooler units provide a significant surface area at or below the dewpoint temperature. Therefore, under equilibrium conditions, the quantity of condensate collected by the cooling coils of the fan cooler units should be equal to the evaporated water leakage and steam leakage from systems within the containment.
To determine abnormal leakage rate inside the containment based on condensation measurements, it will first be necessary to determine the condensation rate from the fan coolers during normal operation. With the initiation of an additional or abnormal leak, the containment atmosphere humidity will begin to increase but such an increase in humidity is reduced by additional condensation on the fan cooler tubes. (Assuming that DCPP UNITS 1 & 2 FSAR UPDATE 5.2-65 Revision 21 September 2013 there is no large heat addition to the containment that could cause the cooling water temperature to increase.)
With the increasing specific and relative humidity, the heat removal capacity needed to cool the air-vapor mixture to its dewpoint decreases. Therefore, increases in available heat removal capacity (i.e., increases in the number of fans in operation) will result in added condensate flow. Through accurate measurement of condensate flow from the fan coolers, a reliable estimate of evaporated leakage inside the containment can be made.
A preliminary estimate of the evaporated leakage can be obtained from the condensate flow increase rate during the transient; a better estimate can be determined from the steady state condensate flow when equilibrium has been reached. After equilibrium is attained, condensate flow from approximately 0.1 to 30 gpm per detector can be measured by this system.
Except for the condensate measuring system, the sensitivities of the RCPB leakage detection systems are not significantly affected during plant operation with concurrent leaks from other sources. Condensation of moisture on the containment air cooler coils will produce a scrubbing effect for particulate activity, but is not expected to appreciably reduce particulate detector sensitivity.
When the plant is shut down, personnel can enter the containment to check visually for leaks. The lack of escaping steam or water during hydrostatic tests has been widely used as a criterion for leaktightness of pressurized systems. Detection of the location of significant leaks would be aided by the presence of boric acid crystals near a leak. The boric acid crystals are transported outside the RCS in the leaking fluid and then deposited by the evaporation process. Sensitivities and response times of other methods of leak detection are provided in Table 5.2-16 and in Figures 5.2-10 through 5.2-13. 5.2.7.5 Maximum Allowable Total Leakage As discussed above, the reactor coolant leakage detection systems provide the capability for detecting extremely small leakage rates from the RCPB during normal operation. Signals from the various leak detectors are displayed in the control room and are used by the operators to determine if corrective action is required. A limited amount of leakage is expected from the RCPB and from auxiliary systems within the containment. Although it is desirable to maintain leakage at a minimum, a maximum allowable total leakage rate is established and used as a basis for action by the reactor operator to initiate corrective measures. Allowable total leakage rates for the DCPP units are presented in the Technical Specifications. RCS identified leakage is limited to 10 gpm by Technical Specification 3.4.13.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-66 Revision 21 September 2013 5.2.7.6 Differentiation Between Identified and Unidentified Leaks Generally, leakage into closed systems, or leakage into the containment atmosphere from sources that are both specifically located and known either not to interfere with the operation of the unidentified leakage monitoring systems or not to be from a flow in the RCPB, are called identified leakages. Uncontained leakage to the containment atmosphere may be the result of a variety of possible leakages that are generally classified as unidentified leakages. Unidentified leakage is eventually collected in tanks or sumps where the flowrate can be established and monitored during operation. 5.2.7.6.1 Leakage Location Capability Leakage detection systems have been designed to aid operating personnel, to the extent possible, in differentiating between possible sources of detected leakage within the containment and in identifying the physical location of the leak. Containment entry for visual inspection will, however, remain the only method of positively identifying the source and magnitude of leakage detected by remote sensing systems.
The containment monitoring system provides the primary means of remotely identifying the source and location of leakage within the containment. Increases in containment airborne activity levels detected by any of the monitor channels will indicate the RCPB as the source of leakage. Additionally, the capability of drawing monitored samples from several containment locations will allow localization of the general area of leakage since activity levels will be somewhat higher in the vicinity of the leakage source. Conversely, if the condensate measuring system detects increased containment moisture without a corresponding increase in airborne activity level, the indicated source of leakage would be judged to be a nonradioactive system, except when the reactor coolant activity may be low.
Less sensitive methods of leakage detection, such as unexplained increases in reactor plant makeup requirements to maintain pressurizer level, will also provide positive indication of the RCPB as the leakage source. Increases in the frequency of a particular containment sump pump operation will facilitate localization of the source to components whose leakage would drain to that sump. Leakage rates of the magnitude necessary to be detectable by these latter methods are expected to be noted first by the more sensitive radiation detection equipment. 5.2.7.6.2 Adequacy of Leakage Detection System The component cooling liquid monitor continuously monitors the component cooling loop of auxiliary coolant for activity indicative of a leak of reactor coolant from either the RCS or the RHR system.
If an accident involving gross leakage from the RCS occurred, it would be detected by the following methods:
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-67 Revision 21 September 2013 (1) Pump Operation During normal operation, only one charging pump is operating. If a gross loss of reactor coolant occurred which was not detected by previously described methods, the difference between charging and letdown flowrate would indicate the leakage. (2) Liquid Inventory Gross leaks might be detected by unscheduled increases in the amount of reactor coolant makeup water, which is required to maintain the normal level in the pressurizer. This is inherently a low-precision measurement, since makeup water is also required for leakage from systems outside the containment. Gross leakage would also be detected by a rise in the normal containment sump level. (3) RHR Loop The RHR loop removes residual and sensible heat from the core and reduces the temperature of the RCS during the second phase of plant shutdown. Tube leaks from the RHR heat exchangers during normal operation would be detected outside the containment by the component cooling loop radiation monitors. Leakage detection systems are provided and located in a manner such that the operator can identify the subsystem, which is leaking and effectively isolate that leakage with no more than short-term interruption of the operation of the complete system. 5.2.7.7 Sensitivity and Operability Tests Periodic testing of leakage detection systems will be conducted to verify the operability and sensitivity of detector equipment. These tests include installation calibrations and alignments, periodic channel calibrations, functional tests, and channel checks. The containment monitoring system is calibrated on installation using typical isotopes of interest. Subsequent periodic calibrations using detector check sources will consist of single-point calibration to confirm detector sensitivity based on the known correlation between the detector response and the check source standard. This procedure will adequately measure instrument sensitivity since the geometry of the sampler cannot be significantly altered after the initial calibration. Channel checks to verify acceptable channel operability during normal operation and functional testing to verify proper channel response to simulated signals will also be conducted on a regular basis. A complete description of calibration and maintenance procedures and frequencies for the containment radiation monitor system is presented in Section 11.4. The condensate measuring system will also be periodically tested to ensure proper operation and verify sensitivity.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-68 Revision 21 September 2013 The equipment used, procedures involved, and frequency of testing, inspection surveillance and examination of the structural and leaktight integrity of RCPB components are described in detail in Section 5.2.8. 5.2.8 INSERVICE INSPECTION PROGRAM The inservice inspection (ISI) program complies, except where relief is granted by the NRC, with the requirements of 10 CFR 50.55a(b)(2), in effect on January 1, 2005, and uses the ASME B&PV Code, Section XI, 2001 Edition with 2002 and 2003 Addenda, as the basis for the inservice examinations and tests conducted during the third 120-month inspection interval. Components that are designated ASME B&PV Code Class 1, 2, and 3 for inservice inspections are included in the Inservice Inspection (ISI) Program Plan (Reference 8). The ISI Program Plan also describes the pressure test program for pressure-retaining Code Class 1, 2, and 3 components; examination techniques; Code Cases; and compliance with ASME B&PV Code, Section XI.
The second interval Containment Inservice Inspection Program Plan implements the ASME Code Section XI, Subsections IWE and IWL, 2001 Edition with 2003 Addenda, within the limits and modifications of 10CFR50.55a. IWE exams of the metallic liner are performed on a 40-month frequency within the 10 year interval starting September 9th, 2008. Concrete shell exams occur on a 5-year frequency as specified by IWL 2410(a) with the initial examinations performed on November 2000 and August 2001, for Unit 1 and Unit 2 respectively. As part of the inspection effort for Unit 1, a preservice inspection (PSI) program for Class 1, 2, and 3 systems was conducted in compliance with the requirements of ASME B&PV Code, Section XI, 1974 Edition including the Summer 1975 Addenda, except where relief was granted by the NRC. For PSI piping examinations in Unit 1, the examination technique of Appendix III and the acceptance criteria of IWB-3514, both from the Winter 1975 Addenda of the ASME B&PV Code, Section XI, were used. For Unit 2, a PSI program for Class 1, 2, and 3 systems was conducted in compliance with the requirements of ASME B&PV Code, Section XI, 1977 Edition including the Summer 1978 Addenda, except where relief was granted by the NRC.
The ISI program for the first inspection interval for Units 1 and 2 met the requirements of the ASME B&PV Code, Section XI, 1977 Edition including the Summer 1978 Addenda, except where relief was granted by the NRC. The ISI program for the second inspection interval for Units 1 and 2 met the requirements of the ASMS B&PV Code, Section XI, 1989 Edition without addenda, except where relief was granted by the NRC. Where examination techniques differed due to code changes between the PSI and the ISI examinations, or between subsequent ISI examinations, the latest inservice examination data will be used as the new baseline.
Design provisions for access to the reactor vessel are described in Section 5.4.1.5. Remote access and data acquisition methods have been developed to facilitate inspection of reactor vessel areas that are not readily accessible for direct examination. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-69 Revision 21 September 2013 Areas that are inaccessible for the remote examination equipment are detailed in PG&E requests for relief that have been submitted to the NRC. 5.2.9 LEAKAGE PREDICTION FROM PRIMARY COOLANT SOURCES OUTSIDE CONTAINMENT NUREG-0737 (Reference 24) requires a program to reduce leakage from systems outside the containment that would or could contain highly radioactive fluids during a severe transient or accident. The systems, or portions of systems, that are included in the leakage reduction program required by NUREG-0737, and the reason for their inclusion, are as follows:
(1) The RHR and SIS that would circulate radioactive water from the RCS (2) The containment spray system (CSS) that would circulate radioactive water from the containment sump (3) The hydrogen purge/hydrogen recombiner systems that would purge or recirculate radioactive containment building atmosphere (4) The nuclear steam supply (NSS) sampling system because of the highly radioactive fluids to be sampled (5) The gaseous radwaste (GRW) system because it could be used to collect highly radioactive gases from the RCS (6) The liquid radwaste (LRW) system for sampling the containment sump during an accident At intervals of approximately 24 months, operating pressure leak tests will be performed on appropriate portions of the SIS, the RHR system, the NSS sampling system, the LRW system, the GRW system, the CSS and the hydrogen purge/hydrogen recombiner system. Systems that normally contain liquids will be pressurized to normal operating pressure using systems pumps or hydro pumps. Each liquid system will be visually inspected during its pressure test so that leakage from the system can be measured and corrected. Systems that normally contain gases will be pressurized with a gas, and leakage will be determined using a calibrated leakrate monitor. If gaseous systems have excessive leakage, then leaks will be located using appropriate leak detection methods such as the soap bubble. After initial criticality, leakage from the GRW system will be evaluated by monitoring the auxiliary building ventilation exhaust with radiation detectors.
5.2.10 REFERENCES 1. K. Cooper et al., Overpressure Protection for Westinghouse Pressurized Water Reactor, WCAP 7769, Rev. 1, June 1972. DCPP UNITS 1 & 2 FSAR UPDATE 5.2-70 Revision 21 September 2013 2. J. A. Nay, Topical Report, Process Instrumentation for Westinghouse Nuclear Steam Supply Systems, WCAP 7671, April 1971. 3. W. O. Shabbits, Dynamics Fracture Toughness Properties of Heavy Section A-533 Grade B Class 1 Steel Plate, WCAP-7623.
- 4. H. T. Corten, R. H. Sailors, Relationship Between Material Fracture Toughness Using Fracture Mechanics and Transition Temperature Tests, UILU-ENG 71-60010, August 1, 1972.
- 5. W. S. Hazelton et al., Basis for Heatup and Cooldown Limit Curves, WCAP-7924, July 1972.
- 6. MULTIFLEX 3.0, A Fortran IV Computer Program for Analyzing Thermal-Hydraulic-Structural System Dynamics Advanced Beam Model, WCAP-9735 Rev. 2 (Proprietary) and WCAP-9736 Rev.1 (Non-Proprietary), February 1998.
- 7. Determination of Design Pipe Breaks for the Westinghouse Reactor Coolant System, WCAP-7503, Revision 1, February 1972.
- 8. Diablo Canyon Power Plant - Inservice Inspection Program Plan - The Third 10-year Inspection Interval, Pacific Gas and Electric Company.
- 9. Structural Analysis of Reactor Coolant Loop/Support System for the Diablo Canyon Nuclear Generating Station Unit No. 1, SD-117. 10. PG&E Report on RCS Overpressurization at Low Temperatures Referenced in W Letter PGE-4049 of July 9, 1979.
- 11. PG&E Diablo Canyon Unit 1 Reactor Vessel Surveillance Program, WCAP-8465, January 1975.
- 12. Schmittroth, E. A., FERRET Data Analysis Code, HEDL-TME-79-40, Hanford Engineering Development Laboratory, Richland, Washington, September 1979.
- 13. McElroy, W. N., et al, A Computer-Automated Iterative Method of Neutron Flux Spectra Determined by Foil Activation, AFWL-TR-67-41, Volumes I-IV, Air Force Weapons Laboratory, Kirkland AFB, NM, July 1967.
- 14. RSIC Data Library Collection DLC-178, SNLRML Recommended Dosimetry Cross-Section Compendium, July 1994.
- 15. RSIC Computer Code Collection CCC-543, TORT-DORT Two- and Three-Dimensional Discrete Ordinates Transport, Version f2.8.14, January 1994.
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-71 Revision 21 September 2013 16. RSIC Data Library Collection DLC-175, BUGLE-93, Production and Testing of the VITAMIN-B6 Fine Group and the BUGLE-93 Broad Group Neutron/Photon Cross-Section Libraries Derived from ENDF/B-VI Nuclear Data, April 1994. 17. H. P. Flatt and D. C. Baller, AIM-5, A Multigroup One Dimensional Diffusion Equation Code, NAA-SR-4694, March 1960.
- 18. Documentation of Selected Westinghouse Structural Analysis Computer Codes, WCAP-8252, Rev.1, May 1977..
- 19. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
- 20. Regulatory Guide 1.26, Quality Group Classification and Standards for Water-, Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants (for Comment). March 1972.
- 21. IEEE-Std-279, Criteria for Protection Systems for Nuclear Power Generating Stations, 1971.
- 22. Regulatory Guide 1.44, Control of the Use of Sensitized Stainless Steel, May 1973.
- 23. AEC Safety Guide 14, Reactor Coolant Pump Flywheel Integrity (for Comment), October 1971. 24. NUREG-0737, Clarification of TMI Plan Requirements, U. S. Nuclear Regulatory Commission, November 1980.
- 25. Regulatory Guide 1.45, Revision 0, Reactor Coolant Pressure Boundary Leakage Detection Systems, May 1973.
- 26. PG&E Diablo Canyon Unit 2 Reactor Vessel Radiation Surveillance Program, WCAP 8783, December 1976.
- 27. Revision 2 to Regulatory Guide 1.99, Radiation Damage to Reactor Vessel Materials, May 1988.
- 28. Supplemental Reactor Vessel Radiation Surveillance Program For PG&E Diablo Canyon Unit 1 WCAP-13440, December 1992.
- 29. Diablo Canyon Unit 1 - Supplemental Reactor Vessel Radiation Surveillance Program - PG&E Letter to NRC No. DCL-92-072.
- 30. PG&E Letter to the NRC No. DCL-92-198 (LER 1-92-015).
DCPP UNITS 1 & 2 FSAR UPDATE 5.2-72 Revision 21 September 2013 31. Letter from Sheri R. Peterson (NRC) to Gregory M. Rueger (PG&E), "Leak-Before-Break Evaluation of Reactor Coolant System Piping for DCPP Units 1 and 2," March 2, 1993.
- 32. Strauch, P. L. et al, Topical Report on Reactor Coolant Pump Flywheel Inspection Examination, WCAP-14535A, November 1996
- 33. Diablo Canyon Units 1 and 2 Replacement Steam Generator Program - NSSS Licensing Report, WCAP-16638 (Proprietary), September 2007.
- 34. Final Report of the Diablo Canyon Long Term Seismic Program, PG&E, July 1988.
- 35. Diablo Canyon Units 1 and 2 Tavg and Tfeed Ranges Program NSSS Engineering Report. WCAP-16985-P.
- 36. Letter from F. T. Searls (PG&E) to Atomic Energy Commission , dated August 9, 1971 , Enclosure "Environmental Report, Units 1 and 2 Diablo Canyon Site, Atomic Energy Commission Dockets 50-275, 50-323," dated July 1971.
- 37. Letter from Alan Wang (NRC) to John T. Conway (PG&E), "Diablo Canyon Power Plant, Unit Nos. 1 and 2 - Issuance of Amendments RE: Revision to Technical Specification 3.4.15, "RCS Leakage Detection Instrumentation," dated January 24, 2011.
- 38. Diablo Canyon Power Plant - Containment Inservice Inspection Program Plan- The Second 10-year Inspection Interval, Pacific Gas and Electric Company.
DCPP UNITS 1 & 2 FSAR UPDATE 5.3-1 Revision 20 November 2011 5.3 THERMAL HYDRAULIC SYSTEM DESIGN The overall objective of the reactor core thermal and hydraulic design is to provide adequate heat transfer, compatible with the heat generation distribution in the core, such that the performance and safety criteria requirements of Chapter 4 are met under all plant operating conditions. 5.3.1 ANALYTICAL METHODS AND DATA The thermal and hydraulic design bases of the reactor coolant system (RCS) are described in Sections 4.3 and 4.4 in terms of core heat generation rates, departure from nucleate boiling ratio (DNBR), analytical models, peaking factors, and other relevant aspects of the reactor. 5.3.2 OPERATING RESTRICTIONS ON REACTOR COOLANT PUMPS To meet the net positive suction head (NPSH) requirements for operation of the reactor coolant pumps, the operating procedures state that the pressure differential across the No. 1 seal must be at least 200 psig before operating the reactor coolant pump. To achieve this pressure differential, the RCS pressure must be maintained at approximately 325 psig, with the volume control tank pressure high enough to provide an effective back pressure on the No. 1 seal of at least 15 psig. 5.3.3 TEMPERATURE-POWER OPERATING MAP The programmed relationship between RCS temperature and power for Unit 1 is shown in Figure 5.3-1. A similar relationship has been programmed for Unit 2 and the corresponding temperatures are also shown in Figure 5.3-1.
The effects of reduced core flow due to inoperative pumps are discussed in Sections 5.5.1, 15.2, and 15.3.
Natural circulation capability of the system is shown in Table 15.2-2. 5.3.4 LOAD-FOLLOWING CHARACTERISTICS The RCS is designed on the basis of steady state operation at full power heat load. The reactor coolant pumps utilize constant-speed drives as described in Section 5.5 and the average coolant temperature is controlled to have a value that is a linear function of load, as described in Section 7.7.
DCPP UNITS 1 & 2 FSAR UPDATE 5.3-2 Revision 20 November 2011 5.3.5 TRANSIENT EFFECTS Evaluation of transient effects is presented as follows:
Event FSAR Section Complete loss of forced reactor coolant flow 15.3.4 Partial loss of forced reactor coolant flow 15.2.5 Loss of external electrical load and/or turbine trip 15.2.7 Loss of normal feedwater 15.2.8 Loss of offsite power 15.2.9 Accidental depressurization of the reactor coolant system 15.2.13
Component cyclic and transient design occurrences are contained in Table 5.2-4. 5.3.6 THERMAL AND HYDRAULIC CHARACTERISTICS SUMMARY TABLE The thermal and hydraulic characteristics are provided in Tables 4.1-1 and 5.1-1.
DCPP UNITS 1 & 2 FSAR UPDATE 5.4-1 Revision 20 November 2011 5.4 REACTOR VESSEL AND APPURTENANCES Section 5.4 discusses the design, material, fabrication, inspection, and quality provisions that apply to the reactor vessel and its appurtenances. 5.4.1 REACTOR VESSEL DESCRIPTION 5.4.1.1 Design Bases The reactor vessel is designed to maintain its integrity under all anticipated modes of plant operation, including exposure to all foreseeable pressure and temperature transients and neutron flux during the life of the plant, by ensuring that all resulting stresses remain within allowable values. 5.4.1.2 Design Transients Cyclic loads are introduced by normal power changes, reactor trip, startup, and shutdown operations. These design bases cycles are selected for fatigue evaluation and constitute a conservative design envelope for the projected plant life. Vessel analysis results in a usage factor that is less than 1.
Regarding the thermal and pressure transients involved in the loss-of-coolant accident (LOCA), the reactor vessel is analyzed to confirm that the delivery of cold emergency core cooling water to the vessel following a LOCA does not cause a loss of vessel integrity. The design specifications require analysis to prove that the vessel is in compliance with the fatigue limits of Section III of ASME Boiler and Pressure Vessel Code (ASME B&PV). The loadings and transients specified for the analysis are based on the most severe conditions expected during service. The typical normal heatup and cooldown rates are less than the 100°F per hour upset or faulted condition rate used for design evaluation purposes. These rates are reflected in the vessel design specifications. (See Section 5.2.) 5.4.1.3 Codes and Standards The manufacturer of the reactor vessels for Diablo Canyon Units 1 and 2 is Combustion Engineering, Inc., Chattanooga, Tennessee. The purchase orders for the Units 1 and 2 vessels were placed on March 27, 1967, and November 20, 1968, respectively. Pursuant to 10 CFR 50.55a(c), the applicable ASME B&PV Code requirements for reactor vessel design, fabrication, and material specifications are the 1965 Edition through the Winter 1966 addenda for Unit 1 and the 1968 Edition for Unit 2.
The replacement RVCH was manufactured by AREVA and contracted on July 28, 2006. Pursuant to 10 CFR 50.55a(c), the applicable ASME B&PV Code requirements for DCPP UNITS 1 & 2 FSAR UPDATE 5.4-2 Revision 20 November 2011 design, fabrication, and material specifications are the requirements of the ASME B&PV Code, 2001 Edition with Addenda through 2003. 5.4.1.4 Reactor Vessel Description The reactor vessels are cylindrical with welded hemispherical bottom heads and removable, bolted, flanged, and gasketed hemispherical upper heads. The reactor vessel flanges and heads are each sealed by two hollow metallic O-rings. Seal leakage is detected by means of two leakoff channels: one between the inner and outer ring and one outside the outer O-ring. The vessel contains the core, core support structures, control rods, and other parts directly associated with the core.
The reactor vessel closure heads contain head adapters. These head adapters are tubular members, attached by partial penetration welds to the underside of the closure head. The upper end of the head adapters are welded to the CRDM latch housing or instrument adapters. The upper end of these items contains threads for the assembly of the rod drive housing or CET column. Inlet and outlet nozzles are spaced evenly around the vessels. Outlet nozzles are located on opposite sides of the vessel to facilitate optimum layout of the reactor coolant system (RCS) equipment. The inlet nozzles are tapered from the coolant loop vessel interfaces to the vessel inside wall to reduce loop pressure drop.
The bottom head of the vessel contains penetration nozzles for connection and entry of he nuclear incore instrumentation. Each nozzle consists of a tubular member made of an Inconel stainless steel composite tube. Each tube is attached to the inside of the bottom head by a partial penetration weld. Internal surfaces of the vessel that are in contact with primary coolant are weld overlaid with 5/32-inch minimum of stainless steel. The exterior of the reactor vessel is insulated with canned stainless steel reflective sheets. The insulation is 3 inches thick and contoured to enclose the top, sides, and bottom of the vessel.
A schematic of the reactor pressure vessel (RPV) is shown in Figure 5.4-1 for Unit 1 and Figure 5.4-2 for Unit 2. Reactor vessel principal design parameters for both units are provided in Table 5.4-1. 5.4.1.5 Inspection Provisions The internal surface of the reactor vessel can be inspected using visual nondestructive techniques over the accessible areas. If necessary, the core barrel can be removed, making the entire inside vessel surface accessible.
The closure head is examined visually during each refueling. Periodic visual inspections of accessible outer control rod drive mechanism penetration tubes and the gasket seating surface are performed. The transition area between the dome and head flange, which is the area of highest stress of the closure head, is accessible on the outer DCPP UNITS 1 & 2 FSAR UPDATE 5.4-3 Revision 20 November 2011 surface for visual inspection, surface examination, and ultrasonic testing. The closure studs, nuts, and washers can be inspected periodically using visual, magnetic particle, and/or ultrasonic techniques.
Full-penetration welds in the following irradiated areas of the installed reactor vessel are available for visual and/or nondestructive inspection:
(1) Vessel shell
(2) Primary coolant nozzles
(3) Bottom head (4) Field welds between the reactor vessel, nozzles, and the main coolant piping The design considerations that have been incorporated into the system to permit the above inspections are as follows:
(1) All reactor internals are completely removable. Appropriate tools, and the storage space required to permit these inspections, are provided.
(2) The closure head is stored dry on the reactor operating deck during refueling to facilitate direct visual inspection. (3) All reactor vessel studs, nuts, and washers are removed to dry storage during refueling. (4) Removable plugs are provided in the primary shield. The insulation covering the nozzle welds may be removed. (5) A removable plug is provided in the lower core support plate to allow remote access for inspection of the bottom head without removal of the lower internals. The reactor vessel presents access problems because of the radiation levels and remote underwater accessibility to this component. Because of these limitations, several steps have been incorporated into the design and manufacturing procedures in preparation for the periodic nondestructive tests that are required by the inservice inspection (ISI) program, and in accordance with the ASME B&PV Code, Section XI. These are:
(1) Shop ultrasonic examinations were performed on all internally clad surfaces to acceptance and repair standards that ensure an adequate cladding bond to allow later ultrasonic testing of the base metal from the DCPP UNITS 1 & 2 FSAR UPDATE 5.4-4 Revision 20 November 2011 inside surface. The size of cladding bonding defect allowed is 3/4-inch by 3/4-inch. (2) The design of the reactor vessel shell in the core area is a clean, uncluttered, cylindrical surface to permit positioning of the ISI test equipment without obstruction.
(3) After the shop hydrostatic testing, selected areas of the reactor vessel were ultrasonically tested and mapped to facilitate the ISI program. 5.4.2 FEATURES FOR IMPROVED RELIABILITY Reactor pressure vessel performance reliability is based on a conservative design, adequate protection measures, proper selection of materials, appropriate fabrication processes, quality assurance program implementation, conservative operating procedures, and an adequate ISI and material surveillance program. Section 5.2 addresses RPV design, overpressure protection, material selection, pressure and temperature operating limitations, and surveillance programs. Fabrication and quality assurance measures are discussed below. 5.4.3 PROTECTION OF CLOSURE STUDS Westinghouse refueling procedures require the studs, nuts, and washers be removed from the reactor closure and placed in storage racks during preparation for refueling. The storage racks are then removed from the refueling cavity for maintenance and inspection prior to reactor closure and refueling cavity flooding. Therefore, the reactor closure studs are never exposed to the borated refueling cavity water. The stud holes in the reactor flange are sealed with special plugs before removing the reactor closure, thus preventing leakage of the borated refueling water into the stud holes. 5.4.4 MATERIALS AND INSPECTIONS Reactor vessel materials are listed in Table 5.2-11. Construction, inspections and tests for the RPV and appurtenances are presented in Table 5.4-2. Inservice inspections meet the requirements of ASME Section XI, as referenced in 10 CFR 50.55a. 5.4.5 SPECIAL PROCESSES FOR FABRICATION AND INSPECTION 5.4.5.1 Fabrication Processes (1) Minimum preheat requirements were established for pressure boundary welds using low alloy weld material. Special preheat requirements were added for stainless steel cladding of low-stressed areas. Preheat was maintained until post-weld heat treatment, except for overlay cladding. DCPP UNITS 1 & 2 FSAR UPDATE 5.4-5 Revision 20 November 2011 Limitations on preheat requirements (a) decrease the probabilities of weld cracking by decreasing temperature gradients, (b) lower susceptibility to brittle transformation, (c) prevent hydrogen embrittlement, and (d) reduce peak hardness. (2) On Unit 2, the use of severely sensitized stainless steel as a pressure boundary material was prohibited and eliminated either by choice of material or by programming the assembly method. This restriction on the use of sensitized stainless steel provides the primary system with preferential materials suitable for: (a) Improved resistance to contaminants during shop fabrication, shipment, construction, and operation (b) Application of critical areas. (3) Galling prevention is accomplished by chrome plating of the control rod drive mechanism head adapter threads and surfaces of the guide studs. (4) Cracking prevention is accomplished by ensuring that the final joining beads are Inconel weld metal at all locations in the reactor vessel where stainless steel and Inconel are joined. (5) Core region shells fabricated of plate material have longitudinal welds and are angularly located away from the peak neutron exposure experienced in the vessel. 5.4.5.2 Tests and Inspections Tests and inspections for the RPV and appurtenances are listed in Table 5.4-2. They are discussed below. 5.4.5.2.1 Ultrasonic Examinations The following ultrasonic examinations were performed:
(1) During fabrication, angle beam inspection of 100 percent of plate material is performed to detect discontinuities that may be undetected by longitudinal wave examination, in addition to the design code straight beam ultrasonic test.
(2) The reactor vessel is examined after hydrotesting to provide a baseline map for use as a reference document in relation to later inservice inspections. DCPP UNITS 1 & 2 FSAR UPDATE 5.4-6 Revision 20 November 2011 5.4.5.2.2 Penetrant Examinations The partial penetration welds for the control rod drive mechanism head adapter are inspected by dye penetrant after the first layer of weld material, after each 1/4-inch of weld metal, and the final surface. Bottom instrumentation tubes are inspected by dye penetrant after each layer of weld metal. Core support block attachment welds are inspected by dye penetrant after the first layer of weld metal and after each 1/2-inch of weld metal. This is required to detect cracks or other defects, to lower the weld surface temperatures for cleanliness, and to prevent microfissures. All austenitic steel surfaces are 100 percent dye penetrant tested after the hydrostatic test. 5.4.5.2.3 Magnetic Particle Examination (1) All surfaces of quenched and tempered materials are inspected on the inside diameter prior to cladding and the outside diameter is 100 percent inspected after hydrotesting. This serves to detect possible defects resulting from the forming and heat treatment operations. (2) The attachment welds for the vessel supports, lifting lugs, and refueling seal ledge are inspected after the first layer of weld metal and after each 1/2-inch of weld thickness. Where welds are back chipped, the areas are inspected prior to welding. (3) All carbon steel surfaces are magnetic particle tested after the hydrostatic test. 5.4.6 QUALITY ASSURANCE SURVEILLANCE The surveillance program that calls for RPV quality assurance provisions to verify proper fabrication and to ensure that integrity is maintained throughout the plant's lifetime, is listed in Table 5.4-2. 5.4.7 REACTOR VESSEL DESIGN DATA The RPV design parameters are presented in Table 5.4-1. 5.4.8 REACTOR VESSEL EVALUATION Section 5.2 presents an assessment of the stresses induced in the RPV during normal, upset, and faulted conditions, showing that in all cases they are below the respective allowable stresses (see Tables 5.2-5, 5.2-6, and 5.2-7). DCPP UNITS 1 & 2 FSAR UPDATE 5.5-1 Revision 21 September 2013 5.5 COMPONENT AND SUBSYSTEM DESIGN This section discusses performance requirements and design features of the various components of the RCS and associated subsystems. 5.5.1 REACTOR COOLANT PUMPS Each unit has four identical reactor coolant pumps (RCPs), one in each loop. 5.5.1.1 Design Bases The RCP ensures an adequate core cooling flowrate, and hence sufficient heat transfer, to maintain a departure from nucleate boiling ratio (DNBR) greater than the applicable limit value (refer to Sections 4.4.1.1 and 4.4.2.3) for all modes of operation. The required net positive suction head (NPSH) is, by conservative pump design, always less than that available by system design and operation.
Sufficient pump rotation inertia is provided by a flywheel, in conjunction with the impeller and motor assembly, to provide adequate flow during coastdown. This flow provides the core with adequate cooling, following an assumed loss of pump power.
The RCP motor has been tested without mechanical damage, at overspeeds up to and including 125 percent of normal speed.
The RCP is shown in Figure 5.5-1; its design parameters are provided in Table 5.5-1. Code applicability and material requirements are provided in Tables 5.2-2 and 5.2-13, respectively. 5.5.1.2 Design Description The RCP is a vertical, single-stage, centrifugal, shaft seal pump designed to pump large volumes of main coolant at high temperatures and pressures.
The pump consists of, from bottom to top, the hydraulic section, the shaft seal, and the motor. Each section is described as follows:
(1) The hydraulic section consists of an impeller, diffuser, casing, thermal barrier, heat exchanger, lower radial bearing, bolting ring, motor stand, and pump shaft. (2) The shaft seal section consists of the No. 1 controlled leakage, film riding face seal, and the No. 2 and No. 3 rubbing face seals. These seals are contained within the main flange and seal housing.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-2 Revision 21 September 2013 (3) The motor section consists of a vertical solid-shaft, squirrel cage induction-type motor, and oil-lubricated double Kingsbury-type thrust bearing, two oil-lubricated radial bearings, and a flywheel. Attached to the bottom of the pump shaft is the impeller. The reactor coolant is drawn up through the impeller, discharged through passages in the diffuser, and out through the discharge nozzle in the side of the casing. A thermal barrier heat exchanger above the impeller limits heat transfer between hot system water and pump internals. A weir plate, installed in the pump discharge nozzle, prevents excessive flow of emergency core cooling system (ECCS) injection water into the casing in the event of a small loss-of-coolant accident (LOCA).
High-pressure seal injection water is introduced through the thermal barrier wall. A portion of this water flows through the seals; the remainder flows downward into the Reactor Coolant System, where it acts as a buffer to prevent system water from entering the radial bearing and seal section of the unit. The heat exchanger provides a means of cooling system water entering the pump radial bearing and seal section to an acceptable level in the event that seal injection flow is lost. The water-lubricated journal-type pump bearing, mounted above the thermal barrier heat exchanger, has a self-aligning spherical seat.
The RCP motor bearings are of conventional design. The radial bearings are the segmented- pad-type and the thrust bearings are tilting pad Kingsbury bearings. All are oil-lubricated. The lower radial bearing and the thrust bearings are submerged in oil and the upper radial bearing is fed oil from the oil flow off the outer surface of the thrust runner. The motor is an air-cooled, Class B thermalastic epoxy-insulated, squirrel cage induction motor. The rotor and stator are of standard construction and are cooled by air. Six resistance temperature detectors are located throughout the stator to sense the winding temperature. The top of the motor consists of a flywheel and an anti-reverse rotation device.
Each RCP is equipped with a system to monitor shaft vibration. The system monitors pump shaft radial vibration, motor shaft radial vibration, and motor frame velocity. The two pump shaft radial vibration probes are mounted in a horizontal plane above the seal housing with one probe parallel to the pump discharge and the other perpendicular to the pump discharge. The two motor shaft vibration probes are mounted in a horizontal plane below the lower motor bearing with one probe parallel to the pump discharge and the other perpendicular to the pump discharge. The two velocity probes are mounted in a horizontal plane on the motor stand with one probe parallel to the pump discharge and the other perpendicular to the pump discharge. A keyphasor probe is mounted below the lower motor bearing and is used for spectral analysis and to measure pump speed. In the event that the signal from a probe becomes invalid and becomes a nuisance alarm the signal may be defeated, since the probes and cables are not accessible during power operation. DCPP UNITS 1 & 2 FSAR UPDATE 5.5-3 Revision 21 September 2013 The instrumentation monitors are mounted in a common rack located on the operating deck in containment. Alarms in the control room are provided by the rack in containment. Vibration data from the instrument rack is collected and stored on a server in the control room, and analyzed at a personal computer in the administration building. The server and computer are shared by both units. The server or computer may be turned off to support maintenance or power switching, as the vibration equipment will still provide alarms and indication. If the server is off, indication requires connection of test equipment to the local rack. The RCP vibration monitoring system does not perform a safety function.
As shown in Table 5.2-13, all parts of the pump in contact with the reactor coolant are austenitic stainless steel except for seals, bearings, and special parts. Component cooling water is supplied to the two oil coolers on the pump motor and to the pump thermal barrier heat exchanger.
The pump shaft, seal housing, thermal barrier, bolting ring, and motor stand can be removed from the casing as a unit without disturbing the reactor coolant piping. The flywheel is available for inspection by removing the cover.
The performance characteristic, shown in Figure 5.5-2, is common to all of the fixed-speed mixed-flow pumps, and the "knee" at about 45 percent design flow introduces no operational restrictions since the pumps operate at full speed. 5.5.1.3 Design Evaluation This section discusses RCP design features incorporated to ensure safe and reliable operation while maintaining RCS integrity. 5.5.1.3.1 Pump Performance The RCPs are sized to equal or exceed the required flowrates. Initial RCS tests confirm the total delivery capability. Thus, assurance of adequate forced circulation coolant flow is provided prior to initial plant operation.
The reactor trip system (RTS) ensures that pump operation is within the assumptions used for loss-of-coolant flow analyses, which also ensures that adequate core cooling is provided to permit an orderly reduction in power if flow from an RCP is lost during operation.
An extensive test program was conducted for several years to develop the controlled leakage shaft seal for pressurized water reactor applications. Long-term tests were conducted on less than full-scale prototype seals as well as on full-size seals. Operating plants continue to demonstrate the satisfactory performance of the controlled leakage shaft seal pump design.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-4 Revision 21 September 2013 The support of the stationary member of the No. 1 seal (seal ring) is such as to allow large deflections, both axial and tilting, while still maintaining its controlled gap relative to the seal runner. Even if all the graphite were removed from the pump bearing, the shaft could not deflect far enough to cause opening of the controlled leakage gap. The "spring-rate" of the hydraulic forces associated with the maintenance of the gap is high enough to ensure that the ring follows the runner under very rapid shaft deflections.
Testing of pumps with the No. 1 seal entirely bypassed (full reactor pressure on the No. 2 seal) shows that relatively small leakage rates would be maintained for long periods of time. The plant operator is warned of this condition by the increase in No. 1 seal leakoff, and has time to close this line and to conduct a safe plant shutdown without significant leakage of reactor coolant to the containment. Thus, it may be concluded that gross leakage from the pump does not occur, even if seals were to suffer physical damage.
The effect of loss of offsite power on the pump itself is to cause an RCS pump trip, and temporary stoppage in the supply of injection water to the pump seals and component cooling water to the thermal barrier for seal and bearing cooling if a generator trip results. The emergency diesel generators are started automatically due to loss of offsite power, so that component cooling water flow is automatically restored to ensure cooling of the pump seals and bearings when the reactor coolant temperature is above 150°F. Seal water injection flow is subsequently restored by automatically restarting a charging pump on diesel generator electrical power. 5.5.1.3.2 Coastdown Capability It is important to reactor operation that the reactor coolant continues to flow for a short time after reactor trip. To provide this flow after a reactor trip, each reactor coolant pump is provided with a flywheel. Thus, the rotating inertia of the pump, motor, and flywheel is employed during the coastdown period to continue the reactor coolant flow.
The pump is designed for the design earthquake (DE) at the site. Bearing integrity is maintained as discussed below. It is, therefore, concluded that the coastdown capability of the pumps is maintained even under the most adverse case of a pump trip coincident with the DE. 5.5.1.3.3 Flywheel Integrity Integrity of the RCP flywheel is discussed in Section 5.2.6. 5.5.1.3.4 Bearing Integrity The design requirements for the RCP bearings are primarily aimed at ensuring a long life with negligible wear, so as to give accurate alignment and smooth operation over long periods of time. To this end, the surface-bearing stresses are held at a very low DCPP UNITS 1 & 2 FSAR UPDATE 5.5-5 Revision 21 September 2013 value, and, even under the most severe seismic transients, do not begin to approach loads, which cannot be adequately carried for short periods of time.
Because there are no established criteria for short-term, stress-related failures in such bearings, it is not possible to make a meaningful quantification of such parameters as margins to failure, safety factors, etc. A qualitative analysis of the bearing design, embodying such considerations, gives assurance of the adequacy of the bearing to operate without failure.
High/low oil level in the motor bearings signals an alarm in the control room. Each motor bearing contains embedded temperature detectors, and so initiation of failure, separate from loss of oil, is indicated and alarmed in the control room as a high bearing temperature. Even if these indications are ignored and the bearing proceeds to fail, the low melting point of Babbitt metal on the pad surfaces ensures that no sudden seizure of the bearing occurs. In this event, the motor continues to drive since it has sufficient reserve capacity to operate until it can be shut down.
The RCP shaft is designed so that its critical speed is well above the operating speed. 5.5.1.3.5 Locked Rotor The postulated case in which the pump impeller severely rubs on a stationary member and then seizes, was evaluated. The analysis showed that under such conditions, assuming instantaneous seizure of the impeller, the pump shaft fails in torsion just below the coupling to the motor, disengaging the flywheel and motor from the shaft. This constitutes a loss of coolant flow in the loop. Following such a postulated seizure, the motor continues to run without any overspeed, and the flywheel maintains its integrity since it is still supported on a shaft with two bearings.
There are no credible sources of shaft seizure other than impeller rubs. Any seizure of the pump bearing is precluded by the graphite in the bearing. Any seizure in the seals results in a shearing of the anti-rotation pin in the seal ring. The motor has adequate power to continue pump operation even after the above occurrences. Indications of pump malfunction in these conditions are first, by high-temperature signals from the bearing water temperature detector, (except for RCP 2-1, TE-155 was disabled at the input to Process Control System (PCS) rack 19 for U2 cycle 18) and second, by excessive No. 1 seal leakoff indications. Along with these signals, pump vibration levels are checked. When there are indications of a serious malfunction, the pump is shut down for investigation. 5.5.1.3.6 Critical Speed The RCPs are designed to operate below first critical speed. This results in a shaft design that, even under the most severe postulated transient, gives very low stress values.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-6 Revision 21 September 2013 Both the damped and lateral natural frequencies are determined by establishing a number of shaft sections and applying weights and moments of inertia for each section bearing spring and damping data. The torsional natural frequencies are similarly determined. The lateral and torsional natural frequencies are greater than 120 and 110 percent of the running speed, respectively. 5.5.1.3.7 Missile Generation Each pump component is analyzed for missile generation. Any fragments of the motor rotor would be contained by the heavy stator. The same conclusion applies to the pump impeller because the small fragments that might be ejected would be contained by the heavy casing. 5.5.1.3.8 Pump Cavitation The minimum NPSH required by the RCP at running speed is approximately 170 feet (approximately 74 psi). For the controlled leakage seal to operate correctly, a differential pressure of approximately 200 psi across the seal is necessary. This results in a requirement for a minimum of 325 psi pressure in the primary loop before the RCP may be operated. This 325 psi requirement is for initial fill and vent only. In normal operation, a p greater than 200 psi at the Number 1 seal is required for reactor coolant pump operation. This requirement is reflected in the operating instructions. At this pressure, the NPSH requirement is exceeded and no limitation on pump operation occurs from this source. 5.5.1.3.9 Pump Overspeed Considerations The generator and the RCP remain electrically connected for 30 seconds following turbine trip actuated by either the RTS or the turbine protection system (TPS), except for certain trips caused by electrical or mechanical faults which require immediate tripping of the generator. A complete load disconnect with turbine overspeed would result in an overspeed potential for the RCP. The turbine control system and the turbine intercept valves limit the overspeed to less than 120 percent. As additional backup, the TPS has a mechanical overspeed protection trip usually set at about 110 percent.
The details of the turbine trip interface logic are shown in Figures 5.5-13 and 5.5-17. The sequence of events following a generator trip, which transfers the engineered safety features onto the emergency power system (EPS) is discussed in Section 8.3. 5.5.1.3.10 Anti-reverse Rotation Device Each RCP is provided with an anti-reverse rotation device in the motor. This anti-reverse mechanism consists of five pawls mounted on the outside diameter of the flywheel, a serrated ratchet plate mounted on the motor frame, a spring return for the ratchet plate, and three shock absorbers.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-7 Revision 21 September 2013 After the motor comes to a stop, a minimum of one pawl engages the ratchet plate and, as the motor tends to rotate in the opposite direction, the ratchet plate also rotates until stopped by the shock absorbers. The rotor remains in this position until the motor is energized again. After the motor comes up to speed, the ratchet plate is returned to its original position by the spring return.
When the motor is started, the pawls initially drag over the ratchet plate. Once the motor reaches sufficient speed, centrifugal forces acting on the pawls produce enough friction to prevent the pawls from rotating, and thus hold the pawls in the elevated position until the motor is stopped. 5.5.1.3.11 Shaft Seal Leakage Leakage along the RCP shaft is controlled by three shaft seals arranged in series so that reactor coolant leakage to the containment is essentially zero. Charging flow is directed to each RCP via a 5-micron seal (maximum) water injection filter. It enters the pumps through the thermal barrier and is directed down to a point between the pump shaft bearing and the thermal barrier cooling coils. Here the flow splits and a portion flows down past the thermal barrier cooling cavity and labyrinth seals. The remainder flows up the pump shaft, cooling the lower bearing, and leaves the pump via the No. 1 seal bypass line or the No. 1 seal leakoff line. There is also a minor flow through the No. 2 seal.
Leakoff flow through the No. 1 seal from each pump is piped to a common manifold, and then, via a seal water return filter, through a seal water heat exchanger, to the volume control tank. The volume control tank provides a back pressure of at least 15 psig on the No. 1 seal. A small amount of No. 1 seal leakoff passes through the No. 2 seal. No. 2 seal leakoff flows to the reactor coolant drain tank.
The No. 3 seal is a double dam seal that divides seal flow into two paths. Part of the flow is directed radially outward to join the No. 2 seal leakoff line and the second part flows radially inward to the No. 3 seal leakoff line to the containment structure sump. A standpipe is provided to ensure a back pressure of at least 7 feet of water on the No. 3 seal. 5.5.1.3.12 Spacer Couplers The installation of a removable spool piece, shown in Figure 5.5-3, in the reactor coolant pump shaft facilitates the inspection and maintenance of the pump seal system without breaking any of the fluid, electrical, or instrumentation connections to the motor, without removal of the motor.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-8 Revision 21 September 2013 5.5.1.4 Tests and Inspections Support feet are cast integral with the casing to eliminate a weld region. The design enables disassembly and removal of the pump internals for normal access to the internal surface of the pump casing.
Inservice inspection is discussed in Section 5.2.8. The RCP quality assurance program is given in Table 5.5-2. 5.5.1.4.1 Electroslag Welding Reactor coolant pump casings fabricated by electroslag welding were qualified as follows:
(1) The electroslag welding procedure employing 2- and 3-wire technique was qualified in accordance with the requirements of the ASME Boiler and Pressure Vessel (B&PV) Code, Section IX, and Code Case 1355 (see Table 5.2-1) plus supplementary evaluations specified by Westinghouse. (2) A separate weld test was made using the 2-wire electroslag technique to evaluate the effects of a stop and restart of welding by this process. This evaluation was performed to establish proper procedures and techniques as such an occurrence was anticipated during production applications due to equipment malfunction, power outages, etc. (3) All of the weld test blocks in (1) and (2) above were radiographed using a 24 MeV betatron. The radiographic quality level obtained was between 0.5 and 1 percent, as defined by ASTM E-94. There were no discontinuities evident in any of the electroslag welds.
The casting segments were surface conditioned for 100 percent radiographic and penetrant inspections. The radiographic acceptance standards were ASTM E-186 Severity Level 2 except no Category D or E defectives were permitted for section thicknesses up to 4-1/2 inches and ASTM E-280, Severity Level 2, for section thicknesses greater than 4-1/2 inches. The edges of the electroslag weld preparations were machined. These surfaces were also penetrant inspected prior to welding. The penetrant acceptance standards were those of the ASME B&PV Code, Section III, Paragraph N-627.
The completed electroslag weld surfaces were ground flush with the casting surface. The electroslag weld and adjacent base material were then 100 percent radiographed in accordance with ASME B&PV Code Case 1355. Also, the electroslag weld surfaces and adjacent base material were penetrant inspected in accordance with ASME B&PV Code, Section III, Paragraph N-627. Weld metal and base metal chemical and physical properties were determined and certified. Heat treatment furnace charts were recorded DCPP UNITS 1 & 2 FSAR UPDATE 5.5-9 Revision 21 September 2013 and certified, and are available at the nuclear steam supply system (NSSS) vendor's facilities. 5.5.1.4.2 In-process Control of Variables Many variables must be controlled to maintain desired quality welds. These variables and their relative importance are as follows:
(1) Heat Input vs. Output The heat input is determined by the product of volts and current and measured by voltmeters and ammeters, which are considered accurate and are calibrated every 30 days. During any specific weld these meters are constantly monitored by the operators. (2) Weld Gap Configuration The weld gap configuration is controlled by 1-1/4-inch spacer blocks. As these blocks are removed, there is the possibility of gap variation. It has been found that a variation from 1 to 1-3/4 inches is not detrimental to weld quality as long as the current is adjusted accordingly. (3) Flux Chemistry The flux used for welding is Arcos BV-I Vertomax. This is a neutral flux, the chemistry of which is specified by Arcos Corporation. The molten slag is kept at a nominal depth of 1-3/4 inches and may vary in depth by plus or minus 3/8 inch without affecting the weld. This is measured with a stainless steel dipstick. (4) Weld Cross Section Configuration The higher the current or heat input and the lower the heat output, the greater the dilution of weld metal with base metal. This causes a rounder barrel-shaped configuration compared to welding with lower heat input and higher heat output, which reduces the amount of dilution and provides a more narrow barrel-shaped configuration. Configuration is also a function of section thickness; the thinner the section, the rounder the pattern produced. 5.5.1.4.3 Welder Qualification Welder qualification is in accordance with ASME B&PV Code, Section IX rules.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-10 Revision 21 September 2013 5.5.2 STEAM GENERATORS Each RCS loop contains a vertical U-tube steam generator. 5.5.2.1 Design Bases Steam generator design data are provided in Table 5.5-3. The design can sustain the transient conditions identified in Table 5.2-4. Estimates of radioactivity levels anticipated in the secondary side of the steam generators during normal operation and their bases for the estimates are discussed in Section 11.1. The transient analysis of a steam generator tube rupture is discussed in Section 15.4.
When operating at 100 percent power, integral moisture separating equipment reduces moisture content of the steam at the exit of the steam generators to 0.05 percent. Under the following transient conditions, the moisture content at the exit of the steam generators is <0.25 percent:
- loading or unloading at a rate of 5 percent of full power steam flow per minute in the range from 15 to 100 percent of full load steam flow
- a step load change of 10 percent of full power in the range from 15 to 100 percent of full load steam flow The steam generator tubesheet complex meets the stress limitations and fatigue criteria specified in the ASME B&PV Code, Section III, as well as emergency condition limitations specified in Section 5.1 of this document. Codes and materials requirements of the steam generator are listed in Tables 5.2-2 and 5.2-14, respectively. The steam generator design maximizes integrity against hydrodynamic excitation and vibration failure of the tubes for plant life.
The water chemistry in the reactor side is selected to provide the necessary boron content for reactivity control and to minimize corrosion of RCS surfaces. Water chemistry for the primary coolant side is presented in Table 5.2-15. 5.5.2.1.1 Design Basis for the Steam Outlet Nozzle Flow Restrictor The design criterion for the steam nozzle flow restrictors is to limit steam flow in the event of a steam line break during normal operating conditions, in order to reduce pressure drop loadings on the steam generator internal components, as well as to limit the mass and energy release rate into the containment. 5.5.2.2 Design Description The steam generator, shown in Figure 5.5-4, is a vertical shell and U-tube design with evaporators having integral moisture separating equipment. The reactor coolant flows through the inverted U-tubes, entering and leaving through the nozzles located in the DCPP UNITS 1 & 2 FSAR UPDATE 5.5-11 Revision 21 September 2013 hemispherical bottom head of the steam generator. Steam is generated on the shell side and flows upward through the moisture separators to the outlet nozzle at the top of the vessel. The head is divided into inlet and outlet chambers by a vertical partition plate extending from the head to the tubesheet. Manways are provided for access to both sides of the divided head.
The steam generator unit is primarily carbon steel. The heat transfer tubes and the divider plate are Inconel and the interior surfaces of the reactor coolant channel heads and nozzles are clad with austenitic stainless steel. The primary side of the tubesheet is weld clad with Inconel.
The feedwater enters the upper shell through an elevated feedwater ring consisting of an alloy steel header with a welded feedwater nozzle thermal liner. Water discharges from the header through debris-filtering spray nozzles located in the top of the header. This configuration reduces the potential for water hammer and thermal stratification. Feedwater then flows into the downcomer formed by the shell and the tube bundle wrapper before entering the boiler section of the steam generator.
Subsequently, the water-steam mixture flows upward through the tube bundle and into the steam drum section. A set of centrifugal moisture separators, located above the tube bundle, removes most of the entrained water from the steam. Steam dryers are employed to increase the steam quality to a minimum of 99.95 percent, which corresponds to a steam outlet moisture content of 0.05 percent. The moisture separators recirculate flow that mixes with feedwater as it enters the downcomer formed by the shell and tube bundle wrapper. The steam generator shell has two bolted and gasketed access openings for inspection and maintenance of the dryers that can be disassembled and removed through the opening. 5.5.2.2.1 Design Description of the Steam Outlet Nozzle Flow Restrictor An integral flow restrictor is provided in each steam nozzle to limit flow in the event of a steam line break accident downstream of the steam nozzle. The flow restrictor consists of seven holes in the steam outlet nozzle forging, with Venturi type flow limiting inserts installed in each of these holes. The total minimum flow area is 1.4 ft2 for the seven inserts. The Alloy 690 flow limiting inserts are welded to the Alloy 690 cladding at the steam nozzle bottom. Materials, welding, and inspection requirements applied in fabrication of the steam nozzle flow restrictor assemblies conform to ASME Code Section III (1998 Edition, with addenda through 2000 Addenda) requirements.
The steam outlet nozzle flow restrictor assembly is shown in Figure 5.5-18.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-12 Revision 21 September 2013 5.5.2.3 Design Evaluation 5.5.2.3.1 Forced Convection The limiting case for heat transfer capability is the nominal 100 percent design thermal duty. To ensure that this thermal duty will be met, the RSGs are designed to operate with an effective fouling factor, or heat transfer resistance, that is greater than that experienced for comparable units in service. Adequate tubing area is selected to ensure that the full design heat removal rate is achieved for these conditions.
The historical best estimate fouling factor applied to Alloy 690-TT tubing is 0.00006 hr-ft2-°F/Btu. The design fouling factor for the Diablo Canyon RSGs is 0.00018 hr-ft2-°F/Btu. When added to the conduction resistance of the tubing, this additional resistance accounts for approximately 17 percent margin for heat transfer, i.e., a 17 percent higher heat transfer coefficient is expected compared to the design value. This margin ensures that the RSGs will provide sufficient heat transfer capability through the design life. 5.5.2.3.2 Natural Circulation Flow The driving head created by the change in coolant density as it is heated in the core and rises to the outlet nozzle initiates convection circulation. This circulation is enhanced by the fact that the steam generators, which provide a heat sink, are at a higher elevation than the reactor core, which is the heat source. Thus, natural circulation is ensured for the removal of decay heat during hot shutdown in the unlikely event of loss of forced circulation. 5.5.2.3.3 Secondary System Fluid Flow Instability Prevention Undesirable perturbations in secondary side flow are postulated to result from events such as water hammer and circulation loop instability. Such events can compromise the functional capability and mechanical integrity of the secondary system. The RSGs include design features intended to preclude these occurrences.
The potential for water hammer is mitigated by the inclusion of an upward-sloping section of the feedwater ring header. This reduces the volume within the feedwater ring assembly that could potentially be filled with steam, and also reduces the possibility of thermal stratification in the feed flow. The steam generators include top-discharge spray nozzles, which further reduce the possibility of steam pockets being trapped in the feedwater ring, and also serve as a means to prevent loose parts from entering the steam generator through the feedwater system.
Instability in the circulation loop for the secondary fluid can result from a distribution of pressure drops that favors two-phase flow, which is de-stabilizing and is found in the upper tube bundle and moisture separators, as opposed to single-phase flow, which is stabilizing and is found in the downcomer and lower tube bundle areas. A stability DCPP UNITS 1 & 2 FSAR UPDATE 5.5-13 Revision 21 September 2013 damping factor is determined in which a negative value indicates damped, stable circulation flow. The RSGs are designed to provide damped, stable circulation over the full range of operating conditions, with sufficient margin to prevent increased two-phase pressure drop, caused by conditions such as partially blocked tube support plate flow holes, from causing instability. 5.5.2.3.4 Tube and Tubesheet Stress Analyses Tube and tubesheet stress analyses for the RSGs confirm that the steam generator tubesheet will withstand the loading (quasi-static rather than shock loading) caused by loss of reactor coolant. With the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 10), dynamic loading conditions resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis analyses; only the much smaller dynamic loads resulting from RCS branch line breaks have to be considered (see Section 3.6.2.1.1.1). 5.5.2.3.5 Corrosion The RSGs include a number of key design features that enhance operation, performance, and maintenance. The design features and materials have been developed and selected to minimize the potential for tube degradation. The design features enhance steam and water flow by the tubes, which minimizes the potential for concentration of chemical species that can be detrimental to tubing material.
For the RSGs, the U-tubes are fabricated of nickel-chromium-iron (Ni-Cr-Fe) Alloy 690. The tubes undergo thermal treatment following tube-forming and annealing operations. The thermal treatment subjects the tubes to elevated temperatures for a prescribed period of time to improve the microstructure of the material. Thermally treated Alloy 690 has been shown in laboratory tests and operating nuclear power plants to be very resistant to PWSCC and ODSCC. The use of Alloy 690 does not require changes to DCPP primary or secondary water chemistry requirements or procedures. 5.5.2.3.6 Design Evaluation for the Steam Outlet Nozzle Flow Restrictor In the event of a main steam line break, steam flow rate from the steam generators is restricted by the outlet nozzle Venturi inserts, which limit the steam blowdown rate from the steam generators. 5.5.2.3.7 Flow-induced Vibration In the design of the steam generators, the possibility of degradation of tubes due to either mechanical- or flow-induced excitation is thoroughly evaluated. This evaluation includes detailed analysis of the tube support systems as well as an extensive research program with tube vibration model tests.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-14 Revision 21 September 2013 In evaluating degradation due to vibration, consideration is given to sources of excitation such as those generated by primary fluid flowing within the tubes, mechanically induced vibration, and secondary fluid flow on the outside of the tubes. During normal operation, the effects of primary fluid flow within the tubes and mechanically induced vibration are considered to be negligible and should cause little concern. Thus, the primary source of tube vibrations is the hydrodynamic excitation by the secondary fluid on the outside of the tubes. In general, three vibration mechanisms have been identified:
(1) Vortex shedding (2) Fluidelastic excitation (3) Turbulence Vortex shedding does not provide detectable tube bundle vibration for the following reasons: (1) Flow turbulence in the downcomer and tube bundle inlet region inhibits the formation of Von Karman's vortex train. (2) The spatial variations of cross flow velocities along the tube preclude vortex shedding at a single frequency. (3) Both axial and cross flow velocity components exist on the tubes. The axial flow component disrupts the Von Karman vortices. The steam generator design is qualified by analyses (relying on theoretical calculations based on laboratory test data and operating steam generator experience), which demonstrate that no tubes will experience unacceptable degradation or wear due to vibration over the steam generator design life.
5.5.2.4 Tests and Inspections The steam generator quality assurance program is given in Table 5.5-5. Radiographic inspection and acceptance standards are in accordance with the requirements of the ASME B&PV Code, Section III, 1998 Edition through the 2000 Addenda.
Liquid penetrant inspection was performed on weld deposited tubesheet cladding, channel head cladding, tube-to-tubesheet weldments, and weld deposit cladding. Liquid penetrant inspection and acceptance standards are in accordance with the requirements of the ASME B&PV Code, Section III, 1998 Edition through the 2000 Addenda.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-15 Revision 21 September 2013 Magnetic particle inspection was performed on all pressure boundary forgings (tubesheet, shell barrels, channel head, transition cone, elliptical head, and secondary-side nozzles), and the following weldments:
- Nozzle to shell
- Upper lateral support lugs
- Instrument connections
- Temporary attachments after removal
- All accessible pressure-retaining welds after hydrostatic testing. Magnetic particle inspection and acceptance standards were in accordance with the requirements of the ASME B&PV Code, Section III, 1998 Edition through the 2000 Addenda.
Ultrasonic examination was performed on all pressure boundary forgings (tubesheet, shell barrels, channel head, transition cone, elliptical head, primary nozzle safe ends, and secondary-side nozzles.
Manways provide access to both the primary and secondary sides of the steam generators. Primary side inspection and maintenance is described in Section 5.5.2.5 and is typically performed with nozzle dams in place to isolate the steam generator bowl from the reactor coolant system. 5.5.2.4.1 Tests and Inspections for the Steam Outlet Nozzle Flow Restrictor The flow restrictor Venturi inserts at the steam outlet are located inside the steam outlet nozzle and welded to the cladding. Therefore, the flow restrictor inserts are not a pressure boundary component. However, component integrity is ensured by compliance with ASME Code requirements. 5.5.2.5 Steam Generator Tube Surveillance Program 5.5.2.5.1 Inservice Inspection Steam generator tube inspection is performed in accordance with the Technical Specifications (Reference 6) and the DCPP surveillance test procedure. Eddy current non-destructive testing is used to perform tube inspections. The steam generator tube surveillance program ensures that the structural and leakage integrity of this portion of the RCS will be maintained. The program for inservice inspection of steam generator tubes is based on NEI 97-06 (Reference 5). Inservice inspection of SG tubing is essential in order to maintain surveillance of the conditions of the tubes in the event there is evidence of mechanical damage or progressive degradation due to design, manufacturing errors, or inservice conditions that lead to corrosion. Inservice inspection of SG tubing also provides a means of characterizing the nature and cause of any tube degradation so that corrective measures can be taken.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-16 Revision 21 September 2013 Tube degradation will be detected during scheduled inservice SG tube examinations. Steam generator tube inspections of operating plants have demonstrated the capability to reliably detect degradation that has penetrated 20 percent of the original tube wall thickness. Plugging is required for all tubes with imperfections exceeding the plugging limit defined in the Technical Specifications. Degradation may be left in service if qualified non-destructive examination sizing techniques verify that the imperfection is less than the plugging limit (reference PG&E response to NRC Generic Letter 97-05). 5.5.2.5.2 Primary-to-Secondary Leakage The plant is expected to be operated in a manner such that the secondary coolant will be maintained within those chemistry limits found to result in negligible corrosion of the SG tubes. The extent of cracking during plant operation is limited by the limitation on SG tube leakage between the Reactor Coolant System and the Secondary Coolant System (primary-to-secondary leakage = 150 gallons per day per SG). Cracks having a primary-to-secondary leakage less than this limit during operation will have an adequate margin of safety to withstand the loads imposed during normal operation and by postulated accidents. DCPP has demonstrated that primary-to-secondary leakage of 150 gallons per day per SG can readily be detected during power operation. Leakage in excess of this limit will require plant shutdown and an unscheduled inspection, during which the leaking tubes will be located and plugged.
Section 15.5.18.1 provides the radiological assessment for accident-induced leakage up to 10.5 gpm at room temperature conditions in any one SG following an SLB. 5.5.3 REACTOR COOLANT PIPING Reactor coolant piping provides a flowpath connecting the major components of each RCS loop. 5.5.3.1 Design Bases The RCS piping was designed and fabricated to accommodate the stresses due to the pressures and temperatures attained under all expected modes of plant operation or system interactions. Code and material requirements are provided in Table 5.2-2 and Section 5.2.3.
Materials of construction are specified to minimize corrosion/erosion and ensure compatibility with the operating environment.
The reactor coolant loop and pressurizer surge line piping for both units are designed and fabricated in accordance with ASA Standard B31.1. It was installed in accordance with ASME B&PV Code, Section III, 1971.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-17 Revision 21 September 2013 5.5.3.2 Design Description Principal design data for the reactor coolant system (RCS) piping for both units are provided in Table 5.5-6. The RCS piping was specified in the smallest sizes consistent with system requirements. In general, high fluid velocities are used to reduce piping sizes. This design philosophy results in the reactor inlet and outlet piping diameters listed in Table 5.5-6. The line between the steam generator and the pump suction is larger to reduce pressure drop and improve flow conditions to the pump suction.
The reactor coolant piping is seamless forged, and fittings are cast. Cast sections of large 90° elbows are joined by electroslag welds. All materials are austenitic stainless steel. All smaller piping that is part of the RCS boundary, such as the pressurizer surge line, spray and relief line, loop drains, and connecting lines to other systems are also austenitic stainless steel. The nitrogen supply line for the pressurizer relief tank is carbon steel. All joints and connections are welded, except for the pressurizer relief and the pressurizer safety valves, where flanged joints are used. Thermal sleeves are installed at points in the system where high thermal stresses could develop due to rapid changes in fluid temperature during normal operational transients. These points include:
(1) Charging connections at the primary loop from the chemical and volume control system (CVCS) (2) Both ends of the pressurizer surge line (3) Pressurizer spray line connection at the pressurizer Thermal sleeves were not provided for the remaining injection connections of the ECCS since these connections are not in normal use.
All piping connections from auxiliary systems were made above the horizontal centerline of the reactor coolant piping, with the exception of:
(1) Residual heat removal (RHR) pump suction, which is 45° down from the horizontal centerline. This enables the water level in the RCS to be lowered in the reactor coolant pipe while continuing to operate the RHR system, should this be required for maintenance. (2) Loop drain lines and the connection for temporary level measurement of water in the RCS during refueling and maintenance operation. (3) The differential pressure taps for flow measurement are downstream of the steam generators on the first 90° elbow. There are three flow transmitters at each elbow. The transmitters at each elbow are arranged so that they use a common high-pressure tap (on the outside of the elbow)
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-18 Revision 21 September 2013 and separate low pressure taps (on the inside of the elbow). Additional discussion is included in Section 7.2.1. Penetrations into the coolant flowpath were limited to the following:
(1) The spray line inlet connections extend into the cold leg piping in the form of a scoop so that the velocity head of the reactor coolant loop flow adds to the spray driving force. (2) The reactor coolant sample system taps protrude into the main stream to obtain a representative sample of the reactor coolant. (3) The narrow range RCS temperature sensors (RTDs) are mounted in thermowells that extend into the hot and cold legs. The RTD bypass scoops and nozzles have been capped. (4) The wide range RCS temperature sensors (RTDs) are mounted in thermowells that protrude into the hot legs and cold legs. Signals from these instruments are used to compute the reactor coolant T (temperature of the hot leg, Thot, minus the temperature of the cold leg, Tcold) and an average reactor coolant temperature (Tavg). The Tavg and T for each loop are indicated on the main control board. Section 7 further describes the temperature sensor arrangement.
The RCS pressure boundary piping includes those sections of piping interconnecting the reactor vessel, steam generator, and RCP. It also includes the following:
(1) Charging line and alternate charging line from the isolation valve up to the branch connections on the reactor coolant loop (2) Letdown line and excess letdown line from the branch connections on the reactor coolant loop to the isolation valve (3) Pressurizer spray lines from the reactor coolant cold legs to the spray nozzle on the pressurizer vessel (4) RHR lines to or from the reactor coolant loops up to the designated isolation or check valve (5) Safety injection lines from the designated isolation or check valve to the reactor coolant loops (6) Accumulator lines from the designated isolation or check valve to the reactor coolant loops DCPP UNITS 1 & 2 FSAR UPDATE 5.5-19 Revision 21 September 2013 (7) Loop fill, loop drain, sample, and instrument lines to or from the designated isolation valve to or from the reactor coolant loops (8) Pressurizer surge line from one reactor coolant loop hot leg to the pressurizer vessel inlet nozzle (9) Abandoned resistance temperature detector scoop element, pressurizer spray scoop, sample connection with scoop, reactor coolant temperature element installation boss, and the temperature element thermowell itself (10) All branch connection nozzles attached to reactor coolant loops (11) Pressure relief lines from nozzles on top of the pressurizer vessel up to and through the power-operated pressurizer relief valves and pressurizer safety valves (12) Seal injection water and labyrinth differential pressure lines to or from the RCP inside reactor containment (13) Auxiliary spray line from the isolation valve to the pressurizer spray line header (14) Sample lines from pressurizer to the isolation valve (15) Pressurizer loop seal drain lines to the pressurizer.
Details of the materials of construction and codes used in the fabrication of reactor coolant piping and fittings are discussed in Section 5.2. 5.5.3.3 Design Evaluation 5.5.3.3.1 Piping Load and Stress Evaluation Piping loads and stress evaluation methodology for normal, upset, and faulted conditions are described in Section 5.2.1. 5.5.3.3.2 Material Corrosion/Erosion Evaluation The water chemistry is selected to minimize corrosion. A periodic analysis of the coolant chemical composition is performed to verify that the reactor coolant quality meets the specifications. The RCS water chemistry is presented in Section 5.2.3.4 and Table 5.2-15.
An upper limit of about 50 feet per second is specified for internal coolant velocity to avoid the possibility of accelerated erosion. All pressure-containing welds within the reactor coolant pressure boundary are available for examination and have removable insulation.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-20 Revision 21 September 2013 5.5.3.4 Tests and Inspections 5.5.3.4.1 Inservice Inspection Inservice inspection is discussed in Section 5.2.8. 5.5.3.4.2 Piping Quality Assurance The RCS piping quality assurance program is given in Table 5.5-7. 5.5.3.4.3 Electroslag Weld Quality Assurance The 90° elbows used in the reactor coolant loop piping were electroslag welded. A description of this procedure is contained in Section 5.5.1.
The following quality assurance actions for RCS piping were undertaken:
(1) The electroslag welding procedure employing 1-wire technique was qualified in accordance with the requirements of ASME B&PV Code, Section IX, and Code Case 1355 plus supplementary evaluation. (2) The casting segments were surface conditioned for 100 percent radiographic and penetrant inspections. The acceptance standards were USAS Code Case N-10, and ASTM E-186, Severity Level 2, except no Category D or E defectives were permitted. 5.5.4 MAIN STEAM LINE FLOW RESTRICTORS As described in Section 5.5.2.2.1, each steam generator has a flow restrictor located in the steam outlet nozzle to limit the steam blowdown from the steam generators in the event of a main steam line rupture. The flow restrictor consists of seven 6.03-inch ID venturi nozzles. In addition, a 16-inch flow restrictor is installed in each main steam line outlet to measure steam flow.
The main steam line flow restrictors are welded into the inside of a length of main steam pipe. Therefore, the 16-inch flow restrictors are not a pressure boundary component. However, component integrity is ensured by compliance with ASME Code requirements. 5.5.5 MAIN STEAM LINE ISOLATION SYSTEM Each main steam line has one isolation valve and one check valve, both of the swing check type, located outside the containment. The isolation valves are held open by a pneumatic actuator until a trip signal is received, as discussed in Section 6.2.4. For analysis of the ability of these valves to close under pipe break conditions, refer to Appendix 5.5A to this Chapter.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-21 Revision 21 September 2013 5.5.6 RESIDUAL HEAT REMOVAL SYSTEM A separate RHR system is provided for each unit. This section describes one system with the second being identical unless otherwise noted.
The RHR system transfers heat from the RCS to the component cooling water system (CCWS) to reduce reactor coolant temperature to the cold shutdown temperature at a controlled rate during the latter part of normal plant cooldown, and maintains this temperature until the plant is started up again.
As a secondary function, the RHR system also serves as part of the ECCS during the injection and recirculation phases of a LOCA.
The RHR system can also be used to transfer refueling water between the refueling water storage tank and the refueling cavity before and after the refueling operations. 5.5.6.1 Design Bases RHR system design parameters are listed in Table 5.5-8. A schematic diagram of the RHR system is shown in Figure 3.2-10. The RHR system is designed to remove heat from the core and reduce the temperature of the RCS during the second phase of plant cooldown. During the first phase of cooldown, the temperature of the RCS is reduced by transferring heat from the RCS to the steam and power conversion system (SPCS) via the steam generators.
The RHR system is placed in operation when the nominal temperature and pressure of the RCS are 350°F and 390 psig, respectively. The cooldown calculation of Reference 12 assumes the RHR is placed in service no sooner than 4 hours after reactor shutdown. Assuming that two RHR heat exchangers and two RHR pumps are in service and that each heat exchanger is supplied with component cooling water at design flow and temperature, the analysis shows that the RHR system design is capable of reducing the temperature of the reactor coolant to 140°F in less than 20 hours after reactor shutdown. The heat load handled by the RHR system during the cooldown transient includes sensible and decay heat from the core and RCP heat. 5.5.6.2 System Description The RHR system consists of two RHR heat exchangers, two RHR pumps, and the associated piping, valves, and instrumentation necessary for operational control. The inlet line to the RHR system is connected to the hot leg of reactor coolant loop 4, while the return lines are connected to the cold legs of each of the reactor coolant loops. These normal return lines are also the ECCS low-head injection lines (see Figure 6.3-4).
The RHR system suction line is isolated from the RCS by two motor-operated valves in series while the discharge lines are isolated by two check valves in each line. These DCPP UNITS 1 & 2 FSAR UPDATE 5.5-22 Revision 21 September 2013 check valves are not a part of the RHR system; they are shown as part of the ECCS. The isolation valves inlet line pressure-relief valve and associated piping are located inside the containment. The remainder of the system is located outside the containment.
During system operation, reactor coolant flows from the RCS to the RHR pumps, through the tube side of the RHR exchangers, and back to the RCS. The heat is transferred in the RHR heat exchangers to the component cooling water circulating through the shell side of the heat exchangers.
Coincident with RHR operations, a portion of the reactor coolant flow may be diverted from downstream of the RHR heat exchangers to the CVCS low-pressure letdown line for cleanup and/or pressure control. By regulating the diverted flowrate and the charging flow, the RCS pressure can be controlled. Pressure regulation is necessary to maintain the pressure range dictated by the fracture prevention criteria requirements of the reactor vessel and by the No. 1 seal differential pressure and NPSH requirements of the RCPs.
The RCS cooldown rate is manually controlled by regulating the reactor coolant flow through the tube side of the RHR heat exchangers. A line containing a flow control valve bypasses the RHR heat exchangers and is used to maintain a constant return flow to the RCS. Instrumentation is provided to monitor system pressure, temperature, and total flow, and to activate an alarm on system low flow.
The RHR system is also used for filling the refueling cavity before refueling. After refueling operations, water is pumped back to the refueling water storage tank until the water level is brought down to the desired level below the flange of the reactor vessel. The remainder is removed via a drain connection at the bottom of the refueling canal.
When the RHR system is in operation, the water chemistry is the same as that of the reactor coolant. Provision is made for the sampling system to extract samples from the flow of reactor coolant downstream of the RHR heat exchangers. A local sampling point is also provided on each RHR train between the pump and heat exchanger.
The RHR system functions in conjunction with the high-head and intermediate portions of the ECCS to provide injection of borated water from the refueling water storage tank into the RCS cold legs during the injection phase following a LOCA. During normal operation, the RHR system is lined up to perform this emergency function.
In its capacity as the low-head portion of the ECCS, the RHR system provides long-term recirculation capability for core cooling following the injection phase of the LOCA. This function is accomplished by aligning the RHR system to take suction from the containment sump.
For a more complete discussion of the use of the RHR system as part of the ECCS, see Section 6.3. DCPP UNITS 1 & 2 FSAR UPDATE 5.5-23 Revision 21 September 2013 5.5.6.2.1 Component Description The materials used to fabricate RHR system components are in accordance with applicable code requirements. All parts of components in contact with borated water are fabricated or clad with austenitic stainless steel or equivalent corrosion resistant material.
RHR component applicable codes and classification are provided in Table 5.5-9. Component parameters are listed in Table 5.5-10. 5.5.6.2.1.1 Residual Heat Removal Pumps Two pumps are installed in the RHR system. The pumps are sized to deliver sufficient reactor coolant flow through the RHR heat exchangers to meet the plant cooldown requirements. The use of two pumps ensures that cooling capacity is only partially lost should one pump become inoperative.
The RHR pumps are protected from overheating and loss of suction flow by miniflow bypass lines that provide flow to the pump suction at all times. A control valve located in each miniflow line is regulated by a signal from the flow transmitters located in each pump discharge header. The control valves open on low RHR pump discharge flow and close when RHR flow has been established. To prevent pump to pump interaction as a result of differences between pump flow characteristics, check valves were installed downstream of the RHR heat exchangers. During minimum flow operation the check valve will prevent the stronger pump from dead heading or reversing flow into the weaker pump, thereby maintaining minimum required recirculation flow. A pressure sensor in each pump discharge header provides a signal for an indicator in the control room. A high pressure alarm is also actuated by the pressure sensor.
The two pumps are vertical, centrifugal units with mechanical shaft seals. All pump surfaces in contact with reactor coolant are austenitic stainless steel or equivalent corrosion resistant material. 5.5.6.2.1.2 Residual Heat Removal Heat Exchangers Two RHR heat exchangers are installed in the system. The heat exchanger design is based on heat load and temperature differences between reactor coolant and component cooling water existing 20 hours after reactor shutdown when the temperature difference between the two systems is small. The decay heat removal used in the cooldown analysis is given in Table 5.5-8. The RHR heat exchangers are part of the emergency core cooling supporting the recirculation mode in which long-term core cooling is provided during the accident recovery period. During the emergency core cooling recirculation phase, water from the containment sump flows through the tube side of the RHR heat exchangers, transferring DCPP UNITS 1 & 2 FSAR UPDATE 5.5-24 Revision 21 September 2013 heat from containment to the CCW system. Further discussion of the RHR heat exchangers in this mode is found in Section 6.3.2. The most limiting RHR system heat exchanger design requirement is to remove decay heat, sensible heat and reactor coolant pump heat at the design flow rates starting four hours following reactor shutdown. Less limiting, the initial heat removal provided by the RHR heat exchangers after a design basis loss-of-coolant accident (LOCA) occurs after the refueling water storage tank (RWST) inventory has been injected into the reactor. Under these conditions, the RHR heat exchangers are in service with a containment sump temperature well below the limiting condition. In addition to RHR heat exchangers, heat removal from containment following a LOCA is shared with the containment fan cooler units (CFCUs). The installation of two heat exchangers ensures that the heat removal capacity of the system is only partially lost if one heat exchanger becomes inoperative.
The RHR heat exchangers are of the shell and U-tube type. Reactor coolant circulates through the tubes, while component cooling water circulates through the shell. The tubes and other surfaces in contact with reactor coolant are austenitic stainless steel or equivalent corrosion resistant material. The shell is carbon steel. The tubes are welded to the tubesheet to prevent leakage of reactor coolant. 5.5.6.2.1.3 Residual Heat Removal System Valves Valves that perform a modulating function are equipped with two sets of packings and an intermediate leakoff connection that discharges to the drain header. Some manual and motor-operated valves have backseats to facilitate repacking and to limit stem leakage when the valves are open. Leakoff connections are provided where required by valve size and fluid conditions. 5.5.6.2.2 System Operation A discussion of RHR system operation during various reactor operating modes follows. 5.5.6.2.2.1 Reactor Startup Generally, during cold shutdown, residual heat from the reactor core is being removed by the RHR system. The number of pumps and heat exchangers in service depends on the RHR load at the time.
At initiation of plant startup, the RCS is completely filled, and the pressurizer heaters are energized. The RHR pumps are operating, but a portion of the discharge is directed to the CVCS via a line that is connected to the common header downstream of the RHR heat exchanger. After the RCPs are running and the pressurizer steam bubble has formed, the RHR pumps are stopped. Indication of steam bubble formation is provided DCPP UNITS 1 & 2 FSAR UPDATE 5.5-25 Revision 21 September 2013 in the control room by the damping out of the RCS pressure fluctuations and by pressurizer level indication. The RHR system is then isolated from the RCS and the system pressure is controlled by normal letdown and the pressurizer spray and pressurizer heaters. An alternative to this startup process is a vacuum refill method of filling the RCS, described in Section 5.1.6.1. This may result in starting the RCPs after the pressurizer steam bubble is formed. 5.5.6.2.2.2 Power Generation and Hot Standby Operation During power generation and hot standby operation, the RHR system is not in service but is aligned for operation as part of the ECCS. 5.5.6.2.2.3 Reactor Shutdown The initial phase of reactor cooldown is accomplished by transferring heat from the RCS to the SPCS through the use of the steam generators. When the reactor coolant nominal temperature and pressure are reduced to 350°F and 390 psig, respectively, the second phase of cooldown starts with the RHR system being placed in operation. Data and procedure reviews indicate it will require more than 4 hours after reactor shutdown to initiate RHR cooldown (Reference 12).
Startup of the RHR system includes a warmup period during which time reactor coolant flow through the heat exchangers is limited to minimize thermal shock. The rate of heat removal from the reactor coolant is manually controlled by regulating the coolant flow through the RHR heat exchangers. By adjusting the control valves downstream of the RHR heat exchangers, the mixed mean temperature of the return flows is controlled. Coincident with the manual adjustment, the heat exchanger bypass valve contained in the common bypass line is regulated to give the required total flow. The reactor cooldown rate is limited by RCS equipment cooling rates based on allowable stress limits, as well as the operating temperature limits of the CCWS. As the reactor coolant temperature decreases, the reactor coolant flow through the RHR heat exchangers is increased.
As cooldown continues, the pressurizer is filled with water and the RCS is operated in the water-solid condition.
At this stage, pressure is controlled by regulating the charging flow rate and the alternate letdown rate to the CVCS from the RHR system.
After the reactor coolant pressure is reduced and the temperature is 140°F or lower, the RCS may be opened for refueling or maintenance.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-26 Revision 21 September 2013 5.5.6.2.2.4 Refueling Several systems may be used during refueling to provide borated water from the refueling water storage tank to the refueling cavity. These include the RHR system, containment spray system, safety injection system, refueling water purification system, and the charging system (which includes the LHUTs). During this operation, the isolation valves to the refueling water storage tank are opened.
The reactor vessel head is removed. The refueling water is then pumped into the reactor vessel and into the refueling cavity through the open reactor vessel.
After the water level reaches the desired level, the refueling water storage tank supply valves are closed, and RHR operation continues.
During refueling, the RHR system is maintained in service with the number of pumps and heat exchangers in operation as required by the heat load.
Following refueling, the RHR pumps are used to drain the refueling cavity to the desired level below the top of the reactor vessel flange by pumping water from the RCS to the refueling water storage tank. 5.5.6.3 Design Evaluation Design features of the RHR system ensure safe and reliable system performance as discussed below.
5.5.6.3.1 System Availability and Reliability The system is provided with two RHR pumps and two RHR heat exchangers arranged in separate flowpaths. If one of the two pumps or one of the two heat exchangers is not operable, safe cooldown of the plant is not compromised, although the time required for cooldown is extended.
The two separate heat exchanger and pump flowpaths provide redundant capability of meeting the engineered safety function of the RHR system. The loss of one of these RHR system flowpaths would not negate the capability of the ECCS since the two flowpaths provide full redundancy for engineered safety requirements. The injection flow paths to loops one and two and to loops three and four are not redundant. Both of these flowpaths must be available with the heat exchanger discharge cross tie open to meet the engineered safety function of the RHR system.
To ensure reliability, the two RHR pumps are connected to two separate electrical buses so that each pump receives power from a different source. If a total loss of offsite power occurs while the system is in service, each bus is automatically transferred to a separate emergency diesel power supply.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-27 Revision 21 September 2013 5.5.6.3.2 Leakage Provisions and Flooding Protection In the event of a LOCA, fission products may be recirculated via the RHR system exterior to the containment. If an RHR pump seal should fail, water would spill onto the floor of the pump compartment. Each RHR pump is in a separate, shielded compartment that drains to a sump containing two pumps that can pump the spillage to the waste disposal system. Each sump pump is capable of removing the spillage that would result from the failure of one RHR pump seal.
If flooding occurred, overflow from one pump compartment would drain through a 14 inch line to the pipe trench rather than flood the adjacent compartment. Added sump pump reliability is achieved by elevating the drive motors above the compartment overflow drain so that the pump motors would not be flooded. Gross leakage from the RHR system can be accommodated in the pump compartments, each of which has a capacity of 9450 gallons.
The RHR heat exchangers and pumps can also be isolated, in the event of gross leakage, through appropriate isolation valves. The isolation valves are operated manually by means of remote valve reach-rod operators located in a shielded valve gallery. Radiation levels in the vicinity of the recirculation loop are discussed in Chapter 12.
Recirculation loop component leakage is detected by means of a radiation monitor that samples the air in the ventilation exhaust ducts from each compartment. Supplemental radiation monitoring is provided by the plant vent gas monitoring system. Alarms in the control room alert the operator when the activity exceeds a preset level, and the capability exists to detect small leaks within a short period of time. Operation of the sump pumps is a less sensitive indication of leakage. Recirculation loop components that are potential sources of leaks are described in Table 5.5-11. The table lists conservative estimates of the maximum leakage expected from each leak source during normal operation. However, the design basis for sizing auxiliary building sump pumps that will be required to dispose of this leakage employs a conservative value of 35 gpm, as described above.
The consequences of a leak through an RHR heat exchanger to the CCWS are discussed in Section 9.2. 5.5.6.3.3 Overpressurization Protection The inlet line to the RHR system is equipped with a pressure relief valve sized to relieve the combined flow of both charging pumps into the RCS and thus prevents exceeding the RHR system design pressure.
Each discharge line to the RCS is equipped with a pressure relief valve located in the ECCS (see Figure 3.2-9, Sheet 3). They relieve the maximum possible back-leakage through the valves separating the RHR system from the RCS. DCPP UNITS 1 & 2 FSAR UPDATE 5.5-28 Revision 21 September 2013 The design of the RHR system includes the following features for valves on the inlet line between the high-pressure RCS and the lower pressure RHR system:
(1) To prevent both RHR suction line isolation valves from opening as a result of fire damage to electrical cables, ac power is removed from the operators of the indicated motor-operated valves for plant conditions during which the RHR system is isolated. (2) The isolation valve adjoining the RCS is interlocked with a pressure signal to prevent its being opened whenever the RCS pressure is greater than a set value. (3) The second isolation valve, the one adjoining the RHR system, is similarly interlocked with a pressure signal to prevent opening if RCS pressure is above a set value, and a pressurizer temperature signal to prevent opening if it exceeds a set value. (4) The RHR suction valves interlock relays are powered from the SSPS output cabinets. To maintain the ability to open the RHR suction valve(s) when the SSPS output cabinet(s) are de-energized in Mode 6 or defueled, a jumper(s) is used to lock-in the RHR suction valve(s) open permissive.
This defeats the applicable RHR system overpressurization/temperature protection. Jumper installation is limited to Mode 6 and defueled only. See Section 7.6 for a more complete discussion of the permissive interlocks on these isolation valves. 5.5.6.3.4 Shared Function The safety function performed by the RHR system is not compromised by its normal function during plant cooldown. The valves associated with the RHR system are normally aligned to allow immediate use of this system in its engineered safety feature mode of operation. The system has been designed in such a manner that two redundant flow circuits are available, ensuring the availability of at least one train for safety purposes.
The normal plant cooldown function of the RHR system is accomplished through a suction line arrangement that is independent of any safety function. The normal cooldown return lines are arranged in parallel redundant circuits and are utilized also as the low-head safety injection lines to the RCS. Utilization of the same return circuits for the safety function as well as for normal cooldown, lends assurance to the proper functioning of these lines for safety purposes.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-29 Revision 21 September 2013 5.5.6.3.5 Radiological Considerations The highest radiation levels experienced by the RHR system are those that would result from a LOCA. Following a LOCA, the RHR system is used as part of the ECCS. During the recirculation phase of emergency core cooling, the RHR system is designed to operate for up to a year pumping water from the containment sump, cooling it, and returning it to the containment to cool the core.
Since the RHR system is located outside the containment, except for some valves and piping, most of the system is not subjected to the high levels of radioactivity in the containment postaccident environment. To ensure continued operation of the RHR system components, the valve motor operators, the RHR pump motors, and the RHR pump seals have been evaluated for operation in postaccident environments. See Section 3.11 for details of the evaluation.
The operation of the RHR system does not involve a radiation hazard for the operators since the system is controlled remotely from the control room. If maintenance of the system is necessary, the portion of the system requiring maintenance is isolated by remotely operated valves and/or manual valves with stem extensions, which allow operation of the valves from a shielded location. The isolated piping is drained and flushed before maintenance is performed. 5.5.6.4 Tests and Inspections Periodic visual inspections and preventive maintenance are conducted during plant operation according to normal industrial practice. The instrumentation channels for the RHR pump flow instrumentation devices are calibrated on a nominal 36-month frequency.
The RHR pumps are tested by starting them periodically. 5.5.7 REACTOR COOLANT CLEANUP SYSTEM The CVCS provides reactor coolant cleanup and is discussed in Section 9.3. The radiological considerations are discussed in Chapter 11. 5.5.8 MAIN STEAM LINE AND FEEDWATER PIPING Main steam line piping is covered in Section 10.3. Feedwater piping is covered in Section 10.4.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-30 Revision 21 September 2013 5.5.9 PRESSURIZER The pressurizer provides a point in the RCS where liquid and vapor are maintained at equilibrium temperature and pressure under saturated conditions for pressure control purposes.
During an insurge, the spray system, fed from two cold legs, condenses steam in the vessel to prevent the pressurizer pressure from reaching the setpoint of the power-operated relief valves. During an outsurge, flashing of water to steam and generation of steam by automatic actuation of the heaters helps keep the pressure above the low-pressure reactor trip setpoint. Heaters are also energized, on high water level during insurges, to heat the subcooled surge water entering the pressurizer from the reactor coolant loop. 5.5.9.1 Design Bases The general configuration of the pressurizer is shown in Figure 5.5-8. The design data of the pressurizer are provided in Table 5.5-12. Codes and material requirements are provided in Section 5.2. 5.5.9.1.1 Pressurizer Surge Line The surge line is sized to limit the pressure drop between the RCS and the safety valves with maximum allowable discharge flow from the safety valves. Overpressure of the RCS does not exceed 110 percent of the design pressure. The surge line and the thermal sleeves at each end are designed to withstand the thermal stresses resulting from volume surges, which occur during operation. 5.5.9.1.2 Pressurizer The pressurizer volume (see Table 5.5-12) satisfies the following requirements:
(1) The combined saturated water volume and steam expansion volume is sufficient to provide the desired pressure response to system volume changes. (2) The water volume is sufficient to prevent the heaters from being uncovered during a step load increase of 10 percent of full power. (3) The steam volume is large enough to accommodate the surge resulting from the design step load reduction from full load with reactor control and steam dump without the water level reaching the high level reactor trip point.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-31 Revision 21 September 2013 (4) The steam volume is large enough to prevent water relief through the safety valves following a loss of load with the high water level initiating a reactor trip. (5) The pressurizer does not empty following reactor and turbine trip. (6) The emergency core cooling signal is not activated during reactor trip and turbine trip. 5.5.9.2 Design Description The pressurizer is designed to accommodate positive and negative reactor coolant surges caused by RCS transients. 5.5.9.2.1 Pressurizer Surge Line The pressurizer surge line connects the pressurizer to one reactor hot leg. The line enables continuous coolant volume/pressure adjustments between the RCS and the pressurizer. 5.5.9.2.2 Pressurizer The pressurizer is a vertical, cylindrical vessel with essentially hemispherical top and bottom heads constructed of carbon steel, with austenitic stainless steel cladding on all surfaces exposed to the reactor coolant. The surge line nozzle and removable electric heaters are installed in the bottom head. The heaters are removable for maintenance or replacement. A thermal sleeve is provided to minimize stresses in the surge line nozzle. A screen at the surge line nozzle and baffles in the lower section of the pressurizer prevent a cold insurge of water from flowing directly to the steam/water interface and assist mixing.
Spray line nozzles and relief and safety valve connections are located in the top head of the vessel. Spray flow is modulated by automatically controlled air-operated valves. The spray valves can also be operated manually by a switch in the control room.
A small continuous spray flow is provided through a manual bypass valve around the power-operated spray valves to ensure that the pressurizer liquid is homogeneous with the coolant and to prevent excessive cooling of the spray piping. During an outsurge from the pressurizer, flashing of water to steam and generating of steam by automatic actuation of the heaters keep the pressure above the minimum allowable limit. During an insurge from the RCS, the spray system, which is fed from two cold legs, condenses steam in the vessel to prevent the pressurizer pressure from reaching the setpoint of the power-operated relief valves for normal design transients. Heaters are energized on high water level during insurge to heat the subcooled surge water that enters the DCPP UNITS 1 & 2 FSAR UPDATE 5.5-32 Revision 21 September 2013 pressurizer from the reactor coolant loop. The heaters are further discussed in Section 8.3. 5.5.9.2.2.1 Pressurizer Support The skirt-type support, shown in Figure 5.5-12, is attached to the lower head and extends for a full 360° around the vessel. The lower part of the skirt terminates in a bolting flange with bolt holes to secure the vessel to its structural steel framework. The skirt-type support is provided with ventilation holes around its upper perimeter to ensure free convection of ambient air past the heater plus connector ends for cooling. 5.5.9.2.2.2 Pressurizer Instrumentation Refer to Chapter 7 for details of the instrumentation associated with pressurizer pressure, level, and temperature. 5.5.9.2.2.3 Spray Line Temperatures Temperatures in the spray lines from two loops are measured and indicated. Alarms from these signals are actuated by low spray water temperature. Low temperature conditions indicate insufficient flow in the spray lines. 5.5.9.2.2.4 Safety and Relief Valve Discharge Temperatures Temperatures in the pressurizer safety and relief valve discharge lines are measured and indicated. An increase in a discharge line temperature is an indication of leakage through the associated valve.
5.5.9.3 Design Evaluation The pressurizer is designed to provide safe and reliable reactor coolant system pressure control. 5.5.9.3.1 System Pressure RCS pressure is maintained by the steam bubble in the pressurizer. During normal operation, the pressurizer maintains RCS pressure by automatic operation of pressurizer heaters and spray. When the pressurizer is filled with water (i.e., near the end of the second phase of plant cooldown and during initial system heatup, if the vacuum refill method of filling the RCS is not used as described in section 5.1.6.1), RCS pressure is maintained by the RHR, CVCS, and LTOP systems. Safety limits are established to control the rate of temperature change in the pressurizer. These safety limits are administratively controlled to ensure that RCS pressure and temperature do not exceed the maximum transient value allowed under ASME B&PV Code, Section III, and thereby ensure continued integrity of the RCS boundary. DCPP UNITS 1 & 2 FSAR UPDATE 5.5-33 Revision 21 September 2013 5.5.9.3.2 Pressurizer Performance The pressurizer has a minimum free internal volume. The normal operating water volume at full load conditions is 60 percent of the minimum free internal vessel volume. Under part load conditions, the water volume in the vessel is reduced for proportional reductions in plant load to 22 percent of free vessel volume at zero power level. During shutdown modes 3, 4, and 5, the pressurizer water volume is controlled between 22 percent and 90 percent of the indicated level. Whenever the LTOP system is enabled as described in Section 5.2.2.4, the administrative controls and requirements of the Pressure and Temperature Limits Report (PTLR) take precedence. Pressurizer performance has been analyzed for the various plant operating transients discussed in Section 5.2.1. The design pressure was not exceeded with the pressurizer design parameters listed in Table 5.5-12. 5.5.9.3.3 Pressure Setpoints The RCS design and operating pressure together with the safety, power relief, and pressurizer spray valves setpoints, and the protection system setpoint pressures are listed in Section 5.2.2. The design pressure allows for operating transient pressure changes. The selected design margin considers core thermal lag, coolant transport times and pressure drops, instrumentation and control response characteristics, and system relief valve characteristics. 5.5.9.3.4 Pressurizer Spray Two separate, automatically controlled spray valves with remote-manual overrides are used to initiate pressurizer spray. In parallel with each spray valve is a manual throttle valve that permits a small, continuous flow through both spray lines to reduce thermal stresses and thermal shock when the spray valves open, and to help maintain uniform water chemistry and temperature in the pressurizer. Spray flow is not normally initiated if the temperature difference between the pressurizer and spray fluid exceeds 320°F. Temperature sensors with low alarms are provided in each spray line to alert the operator to insufficient bypass flow. The layout of the common spray line piping to the pressurizer forms a water seal that prevents the steam buildup back to the control valves. The spray rate is selected to prevent the pressurizer pressure from reaching the operating setpoint of the power relief valves during a step reduction in power level of 10 percent of full load.
The pressurizer spray lines and valves are large enough to provide adequate spray using as the driving force the differential pressure between the surge line connection in the hot leg and the spray line connection in the cold leg. The spray line inlet connections extend into the cold leg piping in the form of a scoop so that the velocity head of the reactor coolant loop flow adds to the spray driving force. The spray valves and spray line connections are arranged so that the spray will operate when one RCP is not operating. The line may also be used to assist in equalizing the boron concentration between the reactor coolant loops and the pressurizer. DCPP UNITS 1 & 2 FSAR UPDATE 5.5-34 Revision 21 September 2013 A flowpath from the CVCS to the pressurizer spray line is also provided. This additional facility provides auxiliary spray to the vapor space of the pressurizer during cooldown if the RCPs are not operating. The thermal sleeves on the pressurizer spray connection and the spray piping are designed to withstand the thermal stresses resulting from the introduction of cold spray water. 5.5.9.3.5 Pressurizer Design Analysis The occurrences for pressurizer design cycle analysis are defined as follows:
(1) For design purposes, the temperature in the pressurizer vessel is always assumed to equal saturation temperature for the existing RCS pressure, except in the pressurizer steam space subsequent to a pressure increase.
In this case, the temperature of the steam space will exceed the saturation temperature since an isentropic compression of the steam is assumed. (2) The temperature shock on the spray nozzle is assumed to equal the temperature of the nozzle minus the cold leg temperature, and the temperature shock on the surge nozzle is assumed to equal the pressurizer water space temperature minus the hot leg temperature. (3) Pressurizer spray is assumed to be initiated instantaneously reaching its design value as soon as the RCS pressure increases 40 psi above the nominal operating pressure. Spray is assumed to be terminated as soon as the RCS pressure falls below the normal operating pressure-plus 40 psi-level. (4) Unless otherwise noted, pressurizer spray is assumed to be initiated once during each transient condition. The pressurizer surge nozzle is also assumed to be subject to one temperature transient per transient condition, unless otherwise noted. (5) At the end of each transient, except the faulted conditions, the RCS is assumed to return to a load condition consistent with the plant heatup transient. (6) Temperature changes occurring as a result of pressurizer spray are assumed to be instantaneous. Temperature changes occurring on the surge nozzle are also assumed to be instantaneous. (7) Whenever spray is initiated in the pressurizer, the pressurizer water level is assumed to be at the no-load level.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-35 Revision 21 September 2013 5.5.9.4 Tests and Inspections The pressurizer is designed and constructed in accordance with ASME B&PV Code, Section III, 1965 Edition with addenda through the summer of 1966. Peripheral support rings are furnished for the insulation modules. The pressurizer quality assurance program is given in Table 5.5-13. 5.5.10 PRESSURIZER RELIEF TANK The pressurizer relief tank (PRT) accommodates the pressurizer and other relief valve discharges. 5.5.10.1 Design Bases Design data for the PRT are provided in Table 5.5-14. Codes and materials applicable to the tank are discussed in Section 5.2. The tank design is based on the requirement to condense and cool a discharge of pressurizer steam equal to 110 percent of the volume above the full power pressurizer water level setpoint. The tank is not designed to accept a continuous discharge from the pressurizer. The volume of water in the tank (see Table 5.1-1) is capable of absorbing the heat from the assumed discharge, with an initial temperature of 120°F and increasing to a final temperature of 200°F. The tank is cooled, when necessary, by manual spraying of cool water into the tank and draining the warm mixture to the waste disposal system (WDS). 5.5.10.2 Design Description The PRT condenses and cools the discharge from the pressurizer safety and relief valves. Discharge from smaller relief valves located inside and outside the containment is also piped to the relief tank. The tank normally contains water and a predominantly nitrogen atmosphere. Provision is made, however, to permit the gas in the tank to be periodically monitored for hydrogen and/or oxygen concentrations. Through its connection to the WDS, the PRT provides a means for removing any noncondensable gases from the RCS that might collect in the pressurizer vessel.
Steam is discharged through a sparger pipe under the water level. This condenses and cools the steam by mixing it with water that is near ambient temperature. The tank is equipped with an internal spray and a drain that are used to cool the tank following a discharge. A flanged nozzle is provided on the tank for the pressurizer discharge line connection. The tank is protected against a discharge exceeding its design pressure by two rupture disks that discharge into the reactor containment.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-36 Revision 21 September 2013 5.5.10.2.1 Pressurizer Relief Tank Pressure The PRT pressure transmitter supplies a signal for an indicator with a high-pressure alarm. Also, the PRT pressure transmitter provides a signal to close the air-operated valve to the WDS vent header on high pressure. 5.5.10.2.2 Pressurizer Relief Tank Level The PRT level transmitter supplies a signal for an indicator with high and low level alarms. 5.5.10.2.3 Pressurizer Relief Tank Water Temperature The temperature of the water in the PRT is indicated in the control room. An alarm actuated by high temperature informs the operator that cooling of the tank contents is required. 5.5.10.3 Design Evaluation The volume of water in the tank is capable of absorbing heat from the pressurizer discharge during a step load decrease of 10 percent. Water temperature in the tank is maintained at the nominal containment temperature.
The rupture disks on the relief tank have a relief capacity equal to the combined capacity of the pressurizer safety valves. The tank design pressure is twice the calculated pressure resulting from the maximum design safety valve discharge described above. The tank and rupture disks holders are also designed for full vacuum to prevent tank collapse if the contents cool following a discharge without nitrogen being added. The discharge piping from the safety and relief valves to the PRT is sufficiently large to prevent back pressure at the safety valves from exceeding 20 percent of the setpoint pressure at full flow. 5.5.11 VALVES The safety-related function of the valves within the reactor coolant pressure boundary listed on Table 5.2-9 is to act as pressure-retaining components and leaktight barriers during normal plant operation and accidents. 5.5.11.1 Design Bases As noted in Section 5.2, all RCS valves including those in connected systems, out to and including the second isolation valve, are normally closed or capable of automatic or remote manual closure. Valve closure time must be such that for any postulated component failure outside the system boundary, the loss of reactor coolant event would not prevent orderly reactor shutdown and cooldown assuming makeup is provided by normal makeup systems. Normal makeup systems are those systems normally used to DCPP UNITS 1 & 2 FSAR UPDATE 5.5-37 Revision 21 September 2013 maintain reactor coolant inventory under startup, hot standby, operation, or cooldown conditions. If the second of two normally open check valves is considered as the pressure boundary, means are provided to periodically assess back-flow leakage of the first valve when closed. For a check valve to qualify as the system pressure boundary, it must be located inside the containment.
Reactor coolant pressure boundary valves are listed in Table 5.2-9. Materials of construction are specified to minimize corrosion/erosion and to ensure compatibility with the environment. Design parameters are provided in Table 5.5-15.
Valves are designed and fabricated in accordance with ASA B16.5, MSS-SP-66, and ASME B&PV Code, Section III, 1968 Edition. To the extent practicable, valve leakage is minimized by design. 5.5.11.2 Design Description All valves in the RCS that are in contact with the coolant are constructed primarily of stainless steel. Other materials in contact with the coolant, such as for hard surfacing and packing, are special materials.
All RCS pressure boundary manual and motor-operated valves that are 3 inches and larger are provided with double-packed stuffing boxes and stem intermediate lantern gland leakoff connections. Some of the throttling control valves, regardless of size, are provided with double-packed stuffing boxes and with stem leakoff connections. All leakoff connections are piped to a closed collection system. Leakage to the atmosphere is essentially zero for these valves. Gate valves are either wedge design or parallel disk and are essentially straight through. The wedge may be either split or solid. All gate valves have a backseat, outside screw and yoke. Globe valves, "T" and "Y" style, are full-ported with outside screw and yoke construction. Ball valves are V-notch design for equal percentage flow characteristics. Check valves are spring-loaded lift piston types for sizes 2 inches and smaller, and swing type for sizes 2-1/2 inches and larger. All check valves containing radioactive fluid are stainless steel and do not have body penetrations other than the inlet, outlet, and bonnet. The check hinge is serviced through the bonnet. The RHR heat exchanger outlet check valves have hinge pin covers.
Each accumulator check valve is designed with a low-pressure drop configuration with all operating parts contained within the body. The disk has unlimited rotation to provide a change of seating surface and alignment after each valve opening.
Valves at the RHR system interface are provided with interlocks that meet the intent of IEEE-Std-279 (Reference 1). These interlocks are discussed in detail in Section 5.5.6 above and Section 7.6.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-38 Revision 21 September 2013 5.5.11.3 Design Evaluation Stress analysis of the reactor coolant loop/support system, discussed in Sections 3.7 and 5.2, ensure acceptable stresses for all valves in the reactor coolant pressure boundary under every condition expected. Reactor coolant chemistry parameters are specified to minimize corrosion. Periodic analyses of coolant chemical composition, discussed in the DCPP Equipment Control Guidelines, ensure that the reactor coolant meets these specifications. The upper-limit coolant velocity of about 50 feet per second minimizes erosion. Valve leakage is minimized by design features as discussed above. 5.5.11.4 Tests and Inspections Hydrostatic, seat leakage, and operation tests are performed on RCS boundary valves in accordance with ASME B&PV Code, Section XI, Subsection IWV, as required by the Technical Specifications and 10 CFR 50.55a. No further test program is considered necessary. Inservice inspection is discussed in Section 5.2.8.
There are no full-penetration welds within valve body walls. Valves are accessible for disassembly and internal visual inspection. 5.5.12 SAFETY AND RELIEF VALVES The pressurizer is equipped with safety and relief valves for overpressure protection and control. Their use is described in Section 5.2.2. 5.5.12.1 Design Bases The combined capacity of the pressurizer safety valves is designed to accommodate the maximum surge resulting from complete loss of load. This objective is met without reactor trip or any operator action, provided the steam safety valves open as designed when steam pressure reaches the steam-side safety valve setting. The power-operated pressurizer relief valves are designed to limit pressurizer pressure to a value below the fixed high-pressure reactor trip setpoint. 5.5.12.2 Design Description The pressurizer safety valves are totally enclosed pop type. The valves are spring loaded, self-actuated, and have back pressure compensation features.
The pressurizer is equipped with three power-operated relief valves (PORVs), each with a corresponding PORV block valve. The PORVs are air-operated and actuated by 125 Vdc solenoid valves that are energized-to-open, spring-to-close. The circuits to the solenoid valves are supplied with redundant interlocks that prevent energization below normal operating pressure. Control power is vital 125 Vdc from the station batteries (see Section 8.3.2). Indication is powered from 120 V instrument ac. The PORV block DCPP UNITS 1 & 2 FSAR UPDATE 5.5-39 Revision 21 September 2013 valves are shown schematically in Figure 3.2-7. Each of the three valves is powered from a separate 480 V vital bus.
Positive indication of PORV position is obtained by a direct, stem-mounted indicator, which mechanically actuates limit switches at the full-open and full-closed valve stem positions. Acoustic monitors located in the downstream piping provide indication of safety valve positions. The acoustic position indication is both seismically and environmentally qualified. Sections 3.10 and 3.11 discuss equipment qualification. An alarm is provided in the control room to signal if a PORV is not fully closed.
The 6-inch pipes connecting the pressurizer nozzles to their respective safety valves are shaped in the form of a loop seal. This arrangement is necessary to accommodate thermal movement and the collection of condensate for the water loop seal. However, the pressurizer safety valves have been converted from water-seated to steam-seated, and the water loop seal was eliminated by continuously draining the condensate back to the pressurizer liquid space. With the elimination of the water loop seal, hydraulic loading due to the presence of water in the loop seal is no longer a concern.
The relief valves are quick-opening, operated automatically or by remote control. Remotely operated stop valves are provided to isolate the PORVs if excessive leakage develops.
Temperatures in the pressurizer safety and relief valve discharge lines are measured and indicated. An increase in a discharge line temperature is an indication of leakage through the associated valve. Design parameters for the pressurizer spray control, safety, and power relief valves are provided in Table 5.5-16. 5.5.12.3 Design Evaluation The pressurizer safety valves prevent RCS pressure from exceeding 110 percent of system pressure. The pressurizer power relief valves prevent actuation of the fixed high-pressure trip for all design transients up to and including the design step load decrease, with steam dump but without reactor trip. The relief valves also limit undesirable opening of the spring-loaded safety valves.
The mounting of these valves is designed to accommodate the magnitude and direction of thrust of the safety valve discharges. In addition, the physical layout is such as to limit the piping reaction loads on these valves. The adequacy of the design has been checked by Westinghouse. 5.5.12.4 Tests and Inspections Safety and relief valves, as well as the corresponding block valves, were tested on a prototypical basis to demonstrate their ability to open and close under expected operating conditions for design basis transients and accidents. Qualification criteria DCPP UNITS 1 & 2 FSAR UPDATE 5.5-40 Revision 21 September 2013 include provisions for the associated circuitry, piping, and supports as well as the valves themselves.
In addition to the requirements of the Technical Specifications, each pressurizer power operated relief valve will be demonstrated operable at least once per 24 months by performing a channel calibration of the actuation instrumentation. This frequency interval is subject to SR 3.0.2 of the Technical Specifications.
The only other testing performed on safety and relief valves, other than operational tests and inspections, is the required hydrostatic, seat leakage, and operation tests. These tests ensure that the valves will operate as designed. No further test program is considered necessary.
There are no full-penetration welds within the valve body walls. Valves are accessible for disassembly and internal visual inspection. 5.5.13 COMPONENT SUPPORTS RCS component supports are designed to maintain safe and reliable component and system operation. 5.5.13.1 Design Bases Component supports allow virtually unrestrained lateral thermal movement of the loop during plant operation and provide restraint to the loops and components during accident conditions. The loading combinations and stress limits are discussed in Section 5.2 and listed in Table 5.2-8. The design maintains the integrity of the RCS boundary for normal and accident conditions and satisfies the requirements of the piping code. Results of piping and supports stress evaluation are presented in Sections 5.2.1.10.4 and 5.2.1.10.5, respectively. 5.5.13.2 Design Description The support structures for the steam generator lower supports and the RCP supports are welded structural steel sections. The steam generator upper supports consist of a steel ring with lateral bumpers and four snubbers per steam generator. Linear-type structures (tension and compression struts, columns, and beams) are used in all cases except for the reactor vessel supports, which consist of a closed, steel box ring-type structure.
Attachments to the supported equipment are the nonintegral type that are bolted to or bear against the components. The supports-to-concrete attachments are either embedded anchor bolts or fabricated assemblies. The supports permit virtually unrestrained thermal growth of the supported systems but restrain vertical, lateral, and rotational movement resulting from seismic and pipe break loadings. This is DCPP UNITS 1 & 2 FSAR UPDATE 5.5-41 Revision 21 September 2013 accomplished using spherical bushings in the columns for vertical support and structural frames, hydraulic snubbers, and struts for lateral support.
The principal support material is welded and bolted structural steel that is subjected to Charpy V-notch impact tests in accordance with ASTM Standard Method A370. Material properties are discussed in Section 5.2.3. The supports for the various components are described in the following paragraphs. 5.5.13.2.1 Reactor Support The reactor is supported on a massive concrete structure that also serves as a biological shield. Forces are transmitted from the reactor to the concrete support structure by an octagonal closed steel box that provides support at four of the eight reactor nozzles as shown in Figure 5.5-9. The bearing plates below the reactor nozzle support shoes contain cooling water passages to control the temperature of the supporting concrete. The reactor support resists seismic loads and coolant loop (hot and cold leg) piping reactions. The reactor support system allows the reactor to expand radially over the supports but resists translational and torsional movement by the combined tangential restraining action of each nozzle support. 5.5.13.2.2 Steam Generator Supports The steam generators are supported by two independent upper and lower structural systems as shown in Figures 5.5-10 and 5.5-11 and described below:
(1) Vertical Supports Four vertical pipe columns for each steam generator provide full vertical restraint while allowing free movement radially with respect to the reactor.
These are bolted at the top to the steam generator and at the bottom to the concrete structure. Spherical ball bushings at the top and bottom of each of column allow unrestrained lateral movement of the steam generator during heatup and cooldown. (2) Horizontal Supports Horizontal supports restrain the steam generators at two levels: (a) At elevation 140 feet, where the reinforced concrete slab acts as a rigid diaphragm supporting horizontal forces (predominantly seismic) generated at this level. (b) At elevation 111 feet (the channel head), where support pads are provided on the vessel. DCPP UNITS 1 & 2 FSAR UPDATE 5.5-42 Revision 21 September 2013 The horizontal supports permit slow radial movement due to thermal expansion while maintaining a positive restraint against sudden loads such as an earthquake or pipe rupture. This is accomplished through the use of four 1300 kip rated hydraulic snubbers at elevation 140 feet attached to a ring shimmed to the steam generator at 20 locations around the circumference. Each hydraulic snubber was tested to 1-1/3 times the rated load and is capable of supporting twice the rated load at yield.
The support pads at elevation 111 feet are keyed and shimmed to a sliding frame that is sandwiched between two rigid stationary frames anchored to massive concrete walls. The sliding frame is provided with a bumper system to transfer load to the stationary frames. The frame system for each of two sets of steam generators is interconnected so that pipe rupture loads in one loop are distributed between two frame systems. 5.5.13.2.3 Reactor Coolant Pump Supports The RCPs are supported on structural steel frames restrained horizontally at elevation 106 feet 5-1/2 inches by a system of steel struts anchored to rigid concrete walls as shown in Figures 5.5-10 and 5.5-11. Thermal expansion is permitted by low friction support pads and oversized mounting holes. The support pads are keyed and shimmed to the frame. This support system resists vertical and lateral loads due to all plant operating conditions. 5.5.13.2.4 Pressurizer Support The pressurizer is bolted to a structural steel frame, providing vertical and lateral support at its base at elevation 113 feet 2 inches as shown in Figure 5.5-12. Additional lateral support is provided by rigid guides embedded in the concrete slab near the center of gravity of the vessel at elevation 139 feet, in conjunction with lugs projecting from the vessel shell. The upper support allows the pressurizer to expand radially and vertically, but resists torsional and translational horizontal movements. 5.5.13.2.5 Crossover Pipe Restraint The crossover leg is restrained at elevation 96 feet by a system of two sets of steel bumpers located at the elbows of the pipe as shown in Figure 5.5-10. Each set consists of a bumper strapped to the pipe, which bears on a rigid bumper anchored to a concrete pad at elevation 94 feet. The restraint resists blowdown loads from a rupture of the crossover pipe. The crossover pipe restraints were deactivated by removing shims. The bumpers strapped to the pipe and the rigid bumpers were left intact and are abandoned in place. 5.5.13.3 Design Evaluation Detailed evaluation ensures the design adequacy and structural integrity of the reactor coolant loop and the primary equipment supports system. The detailed evaluation is made by comparing the analytical results with established criteria for acceptability. DCPP UNITS 1 & 2 FSAR UPDATE 5.5-43 Revision 21 September 2013 Structural analyses are performed to demonstrate design adequacy for safety and reliability of the plant in case of a large or small seismic disturbance and/or LOCA conditions. However, with the acceptance of the DCPP leak-before-break analysis by the NRC (Reference 10), dynamic LOCA loads resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis structural analyses and included in the loading combinations; only the LOCA loads resulting from RCS branch line breaks have to be considered (see Section 3.6.2.1.1.1). Since the breaks postulated for the original analyses are more severe than the breaks now required to be considered, the original analyses are conservative. Loads (thermal, weight and pressure) that the system is expected to encounter often during its lifetime are applied and stresses are compared to allowable values, as described in Section 5.2. The stress limits for component supports are provided in Table 5.2-8.
For the RCL piping reanalysis performed for the RSGs in Unit 2, thrust forces and blowdown loads were determined for RCS branch line breaks identified in Section 5.2.1.10.1. 5.5.14 REACTOR VESSEL HEAD VENT SYSTEM 5.5.14.1 Design Bases The basic function of the reactor vessel head vent system (RVHVS) is to remove noncondensable gases from the reactor vessel head. This system is designed to mitigate a possible condition of inadequate core cooling or impaired natural circulation resulting from the accumulation of noncondensable gases in the RCS. The design of the RVHVS is in accordance with the requirements of NUREG-0578 (Reference 7) and the subsequent definitions and clarifications in NUREG-0737 (Reference 8). 5.5.14.2 Design Description The RVHVS removes noncondensable gases or steam from the RCS via remote-manual operations from the control room. The system discharges at the reactor vessel head, into a well-ventilated area of the containment, to ensure optimum dilution of combustible gases. The RVHVS is designed to vent a volume of hydrogen at system design pressure and temperature approximately equivalent to one-half of the RCS volume in 1 hour.
The flow diagram of the RVHVS is shown in Figure 5.5-14. The RVHVS consists of two parallel flowpaths with redundant isolation valves in each flowpath. The venting operation uses only one of these flowpaths at any time. Equipment design parameters are listed in Table 5.5-17. Isolation valve limit switch position indication is provided in the control room.
The active portion of the system consists of four 1 inch open/close solenoid operated isolation valves connected to a dedicated RVCH penetration, located near the center of the reactor vessel head. The use of two valves in series in each flowpath minimizes the DCPP UNITS 1 & 2 FSAR UPDATE 5.5-44 Revision 21 September 2013 possibility of reactor coolant pressure boundary leakage. The isolation valves in one flowpath are powered by one vital power supply, and the valves in the second flowpath are powered by a second vital power supply. The isolation valves are fail closed, normally closed, active valves. Device qualification is described in Sections 3.10 and 3.11.
If one single active failure prevents a venting operation through one flowpath, the redundant path is available for venting. Similarly, the two isolation valves in each flowpath provide a single failure method of isolating the venting system. With two valves in series, the failure of any one valve or power supply will not inadvertently open a vent path. These valves are energized-to-open, spring-to-close. Thus, the combination of safety-grade train assignments and valve failure modes will not prevent vessel head venting or venting isolation with any single active failure.
The RVHVS has two normally deenergized valves in series in each flowpath. This arrangement eliminates the possibility of a spuriously opened flowpath due to the spurious movement of one valve. As such, power lockout to any valve is not considered necessary.
The RVHCS is connected to a reactor vessel closure head vent nozzle penetration. The reactor vent piping utilizes a 3/8-inch orifice prior to branching into two redundant flowpaths. The system is designed to limit the blowdown from a break downstream of the orifices such that loss through a severance of one of these lines is sufficiently small to allow operators to execute an orderly plant shutdown.
A break of the RVHVS line upstream of the orifices would result in a small LOCA of not greater than 1 inch diameter. Such a break is similar to those analyzed in WCAP-9600 (Reference 2). Since a break in the head vent line would behave similarly to the hot leg break case presented in WCAP-9600, the results presented therein are applicable to a RVHVS line break. This postulated vent line break results, therefore, in no calculated core uncovery.
All piping and equipment from the housing to second isolation valve are designed and fabricated in accordance with ASME B&PV Code, Section III, Class 1 requirements. The remainder of the piping is nonsafety related. 5.5.14.3 Supports The vent system piping is supported to ensure that the resulting loads and stresses on the piping and on the vent connection to the housing are acceptable. All supports and support structures comply with the requirements of the ASME B&PV Code, Section III, Subsection NF.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5-45 Revision 21 September 2013 5.5.15 REFERENCES 1. IEEE-Std-279, Criteria for Protection Systems for Nuclear Power Generating Station, 1971.
- 2. Report on Small Break Accidents for Westinghouse NSSS System, WCAP-9600, June 1979.
- 3. Deleted in Revision 18.
- 4. Deleted in Revision 19.
- 5. NEI 97-06, Steam Generator Program Guidelines, latest revision.
- 6. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
- 7. Nuclear Regulatory Commission, TMI Short-Term Lessons Learned Requirements, NUREG-0578, 1979.
- 8. Nuclear Regulatory Commission, Clarification of TMI Plan Requirements, NUREG-0737, November 1980.
- 9. Deleted in Revision 19.
- 10. Letter from Sheri R. Peterson (NRC) to Gregory M. Rueger (PG&E), "Leak-Before-Break Evaluation of Reactor Coolant System Piping for DCPP Units 1 and 2," March 2, 1993,
- 11. Deleted in Revision 19.
- 12. Westinghouse Calculation SE/FSE-C-PGE-0013, "RHRS Cooldown Performance at Uprated Conditions," Rev. 0, June 5, 1996. 5.5.16 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures.
DCPP UNITS 1 & 2 FSAR UPDATE 5.6-1 Revision 21 September 2013 5.6 INSTRUMENTATION REQUIREMENTS 5.6.1 PRESSURIZER AND COOLANT LOOPS The pressurizer and each of the reactor coolant loops are monitored by process control instrumentation. This instrumentation provides the input signals to the following control and protection functions that are described in Chapter 7:
(1) Reactor trip (Section 7.2) (2) Engineered safety features actuation (Sections 7.3 and 7.6) (3) Nonsafety related systems (Section 7.7)
The reactor coolant system (RCS) design and operating pressure together with the safety, power relief and pressurizer spray valves nominal setpoints, and the protection system nominal setpoint pressures are listed in Table 5.2-10. The design pressure allows for operating transient pressure changes. The selected design margin considers core thermal lag, coolant transport times and pressure drops, instrumentation and control response characteristics, and system relief valve characteristics.
To meet the requirements of NUREG-0578(1) for supplementing existing instrumentation to unambiguously indicate inadequate core cooling, a subcooling meter and a reactor vessel water level measurement are provided. Inadequate core cooling detection instrumentation is discussed in more detail in Section 7.5.2.2. The subcooling meters are a subset of RVLIS and provide the operator with on-line indication of the core coolant temperature and pressure margins to saturation conditions. The reactor vessel water level is determined by the reactor vessel head level system by measuring the pressure drop between the upper and lower plena in the vessel.
Each subcooling meter (train A or B) has wide range temperature inputs from two each of the RCS hot legs and the hottest incore thermocouple associated with that train. Two pressure measurements (one per train) are input from the hot legs. The subcooling meter displays consist of a digital meter on the main control board (train B), a recorder to provide a redundant display (train A/PAM1), and the indication on each RVLIS display (PAM3 and PAM4). All the indications provide the temperature margin to saturation of the RCS. In addition to temperature margin, the RVLIS displays also provide the pressure margin.
The reactor vessel level measurement is used in combination with the existing core exit thermocouples and the subcooling meter. Differential pressure between the top of the reactor vessel and the bottom of the reactor vessel on two narrow-range and two wide-range instruments is measured. The system functions as follows: with the reactor coolant pumps off, the pressure drop between the top and the bottom of the vessel indicates the collapsed liquid level (the equivalent liquid level without voids in the two-phase region) in the vessel. This is read on the narrow-range instrument in terms DCPP UNITS 1 & 2 FSAR UPDATE 5.6-2 Revision 21 September 2013 of feet of liquid. With the reactor coolant pumps running, the pressure drop (in feet of liquid) from the top to the bottom of the vessel when compared to the measurement with the same combination of running pumps during normal, single phase RCS condition, provides an approximate indication of the void fraction in the vessel. This is read on the wide-range instrument as percent of full flow differential pressure with the vessel filled with water. 5.6.2 RESIDUAL HEAT REMOVAL (RHR) SYSTEM Process control instrumentation for the RHR system is provided for the following purposes:
(1) Furnish input signals for monitoring and/or alarming purposes for: (a) Temperature indications (b) Pressure indications (c) Flow indications (2) Furnish input signals for control purposes of such processes as follows: (a) Control valve in the RHR pump bypass line so that it opens at flows below a preset limit and closes at flows above a preset limit (b) RHR isolation valves control circuitry (See Section 7.6 for the description of the interlocks) (c) Control valve in the RHR heat exchanger bypass line to control temperature of reactor coolant returning to reactor loops during plant cooldown (d) RHR pump circuitry for starting RHR pumps on "S" signal (e) RHR pump trip on low reactor water storage tank level 5.
6.3 REFERENCES
- 1. NUREG-0578, TMI Short-Term Lessons Learned Requirements, USNRC, 1979.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.1-1 Sheet 1 of 2 Revision 20 November 2011 SYSTEM DESIGN AND OPERATING PARAMETERS(c) Unit 1 Unit 2 Plant design life, years(a) 50 50 Nominal operating pressure, psig 2,235 2,235 Total system volume, including pressurizer and surge line, ft3 12,064 +/- 100 12,169 +/- 100 System liquid volume, including 11,082 - 11,337(f) 11,187 - 11,448(d) pressurizer water, ft3 (nominal) Total heat output , Btu/hr 11,687 x106 11,687x 106 Total coolant flowrate, lb/hr 132.9 x 106 - 135.1 x 106 (f) 134.0 x 106 - 136.3 x 106 (d) System thermal and hydraulic data (f) Reactor vessel Inlet temp, °F 531.7 - 544.5(f) 531.9 - 545.1(d) Outlet temp, °F 598.3 - 610.1(f) 598.1 - 610.1(d) P, psi 48.4(e) 42.6(e) Steam generator Inlet temp, °F 598.3 - 610.1(f) 598.1 - 610.1(d) Outlet temp, °F 531.4 - 544.2(f) 531.6 - 544.8(d) P, psi 38.8(e) 39.3(e) Design Fouling Factor 0.00018 0.00018 Piping P, psi 7.1(e) 7.2(e) Reactor coolant pump Inlet temp, °F 531.4 - 544.2(f) 531.6 - 544.8(d) Outlet temp, °F 531.7 - 544.5(f) 531.9 - 545.1(d) Developed head, ft 284(e) 268.4(e) Flow (each), gpm 94,500(e) 95,200(e) Steam pressure, psia 730 - 821(f) 731 - 825(d) Steam flow, lb/hr (total) 14.64 x 106 - 14.89 x 106 (f) 14.64 x 106 - 14.90 x 106 (d) Feedwater inlet temp, °F 425.0 - 435.0 425.0 - 435.0 Pressurizer spray rate, maximum, gpm 800 800
Pressurizer heater capacity, kW(b) 1800 1800 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.1-1 Sheet 2 of 2 Revision 20 November 2011 Pressurizer relief tank volume, ft3 1800 1800 (a) Although DCPP useful life is expected to be 40 years, the RCS design conservatively assumes that integrity must be maintained during 50 years. (b) See Table 5.5-12. (c) 0% SGTP, NSSS rated power (d) Design value corresponding to full power, 565.0 - 577.6ºF vessel average temperature. (e) Best Estimate value corresponding to full power. (f) Design value corresponding to full power, 565.0 - 577.3ºF vessel average temperature.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.2-1 Sheet 1 of 2 Revision 19 May 2010 ASME CODE CASES FOR WESTINGHOUSE PWR CLASS A COMPONENTS Code Case(b) Title 1141 Foreign Produced Steel 1332 Requirements for Steel Forgings 1334 Requirements for Corrosion Resistant Steel Bars 1335 Requirements for Bolting Material 1337 Requirements for Special Type 403 Modified Forgings or Bars (Section III) 1344 Requirements for Nickel-Chromium Age-Hardenable Alloys 1345 Requirements for Nickel-Molybdenum-Chromium-Iron Alloys 1355 Electroslag Welding 1358(a) High Yield Strength Steel for Section III Construction 1360(a) Explosive Welding 1361 Socket Welds 1364 Ultrasonic Transducers SA-435 (Section II) 1384 Requirements for Precipitation Hardening Alloy Bars & Forgings 1388 Requirements for Stainless Steel - Precipitation Hardening 1390 Requirements for Nickel-Chromium Age-Hardenable Alloys for Bolting 1395 SA-508, Class 2 Forgings - Modified Manganese Content 1401 Welding Repair to Cladding 1407 Time of Examination 1412(a) Modified High Yield Strength Steel 1414(a) High Yield Strength Cr-Mo 1423 Plate: Wrought Type 304 with Nitrogen Added 1433 Forgings: SA-387 1434 Class BN Steel Casting (Postweld Heat Treatment for SA-487) 1448 Use of Case Interpretations of ANSI B31 Code for Pressure Piping 1456 Substitution of Ultrasonic Examination 1459 Welding Repairs to Base Metal 1461 Electron Beam Welding 1470 External Pressure Charts for Low Alloy Steel 1471 Vacuum Electron Beam Welding of Tube Sheet Joints 1474 Integrally Finned Tubes (Section III) 1477 B-31.7, ANSI 1970 Addenda N-20-4 SB-163 Nickel-Chromium-Iron Tubing at a Specified Minimum Yield Strength of 40,000 psi 1487 Evaluation of Nuclear Piping for Faulted Conditions 1492 Postweld Heat Treatment 1493 Postweld Heat Treatment 1494 Weld Procedure Qualification Test 1498 SA-508, Class 2, Minimum Tempering Temperature 1501 Use of SA-453 Bolts in Service Below 800 degrees F without Stress Rupture Tests 1504 Electrical and Mechanical Penetration Assemblies 1505(a) Use of 26 Cr, 1 Mo Steel 1508 Allowable Stresses, Design Stress Intensity and/or Yield Strength Values 1514 Fracture Toughness Requirements 1515 Ultrasonic Examination of Ring Forgings for Shell Section of Section III - Class I Vessels 1516 Welding of Non-Integral Seats in Valves for Section III Application 1517 Material Used in Pipe Fittings 1519 Use of A-105-71 in lieu of SA-105 1521 Use of H. Grades SA-240, SA-479, SA-336, and SA-358 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.2-1 Sheet 2 of 2 Revision 19 May 2010 Code Case(b) Title 1522 ASTM Material Specifications 1523 Plate Steel Refined by Electroslag Remelting 1524 Piping 2" NPS and Smaller 1525 Pipe Descaled by Other Than Pickling 1526 Elimination of Surface Defects 1527 Integrally Finned Tubes 1528 High Strength SA-508 Class 2 and SA-541 Class 2 Forgings for Section III Construction of Class I Components 1529 Material for Instrument Line Fittings 1531 Electrical Penetrations, Special Alloys for Electrical Penetrations Seals 1534 Overpressurization of Valves 1535 Hydrostatic Test of Class I Nuclear Valves 1539 Metal Bellows and Metal Diaphragm Steam Sealed Valves, Class 1, 2, and 3 1542 Requirements for Type 403 Modified Forgings of Bars for Bolting Material 1544 Radiographic Acceptance Standards for Repair Welds 1545 Test Specimens from Separate Forgings for Class 1, 2, 3, and MC. 1546 Fracture Toughness Test for Weld Metal Section 1547 Weld Procedure Qualification Tests; Impact Testing Requirements, Class I 1522 Design by Analysis of Section III Class I Valves 1556(a) Penetrameters for Film Side Radiographs in Table T-320 of Section V 1567 Test Lots for Low Alloy Steel Electrodes 1568 Test Lots for Low Alloy Steel Electrodes 1571 Materials for Instrument Line Fittings; For SA-234 Carbon Steel Fittings 1573 Vacuum Relief Valves 1574 Hydrostatic Test Pressure for Safety Relief Valves
(a) Westinghouse has performed a review of these specific code cases and knows of no specific application made to components for Diablo Canyon Units 1 and 2. (b) Code cases adopted for use at DCPP are specified in the introduction to the Inservice Inspection Program Plan.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.2-2 Sheet 1 of 2 Revision 20 November 2011 EQUIPMENT CODE AND CLASSIFICATION LIST
Code Unit 1 Unit 2 Component Class(d) Code Addenda Code Addenda Reactor Coolant System Reactor vessel A ASME III 65 thru winter 66 ASME III 68 none Reactor vessel closure head A ASME III 2001 thru 2003 ASME III 2001 thru 2003 Control rod drive mechanism housing A ASME III 2001 thru 2003 ASME III 2001 thru 2003 Steam generator (tube side) A ASME III 98 thru 2000 ASME III 98 thru 2000 shell side) C(a) ASME III 65 thru winter 65 ASME III 65 thru summer 66Pressurizer A ASME III 65 thru summer 66 ASME III 65 thru summer 66Reactor coolant piping(b)(c), fittings N/A ASA B31.1 none ASA B31.1.0 1971 Surge pipe, fittings N/A ASA B31.1 none ASA B31.1.0 1971 Reactor coolant thermowells N/A ASA B31.1 none ASA B31.1 none Safety valves N/A ASME III 65 Article 9 ASME III 65 Article 9 Relief valves N/A USAS B16.5 none USAS B16.5 none Valves to reactor coolant system boundary USAS B16.5 or None USAS B16.5 or None MSS-SP-66 or MSS-SP-66 or N/A ASME III 68 ASME III 68 or 74(e) or 74(e) Piping to reactor coolant system boundary A ANSI B31.7 69 1971 Addenda ANSI B31.7 69 1971 Pressurizer relief tank C ASME III 68 thru summer 68 ASME III 68 thru summer 68 Reactor coolant pump standpipe orifice N/A No Code No Code Reactor coolant pump standpipe N/A ASME VIII 68 None ASME VIII 68 None Reactor coolant pump Casing A ASME III 65 thru summer 66 ASME III 65 thru summer 66 Main flange A ASME III 65 thru summer 66 ASME III 65 thru summer 66Thermal barrier A ASME III 65 thru summer 66 ASME III 65 thru summer 66
- 1 seal housing A ASME III 65 thru summer 66 ASME III 65 thru summer 66
- 2 seal housing A ASME III 65 thru summer 66 ASME III 65 thru summer 66 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.2-2 Sheet 2 of 2 Revision 20 November 2011 Code Unit 1 Unit 2 Component Class(d) Code Addenda Code Addenda Pressure retaining bolting A ASME III 65 thru summer 66 ASME III 65 thru summer 66 Remaining parts N/A ASME III 65 thru summer 66 ASME III 65 thru summer 66Reactor coolant pump motor oil coolers B ASME III 65 thru summer 66 ASME III 65 thru summer 66 (a) Code design requirements are in excess of the requirement dictated by the applicable Safety Class. (b) Reactor Coolant System piping subassemblies inspected to ASME I as required by California law. (c) Classification for other piping and associated valves in the Reactor Coolant System boundary shall be as defined by the Systems Engineering Flow Diagrams for the appropriate Safety Class.
(d) See Section 3.2. (e) A small number of valves were purchased to ASME Section III, 1974 requirements.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 20 November 2011 TABLE 5.2-3 PROCUREMENT INFORMATION COMPONENTS WITHIN REACTOR COOLANT SYSTEM BOUNDARY Component Purchase Order Dates Unit 1 Unit 2 Reactor vessel 3/27/67 12/27/68 Replacement RVCH 7/28/06 7/28/06 CRDM housing 7/28/06 7/28/06 Original steam generator 11/22/66 4/6/67 Replacement steam generator 8/12/04 8/12/04 Pressurizer 4/24/67 4/24/67 Reactor coolant pump 3/29/67 3/29/67 Reactor coolant pipe, fittings, and fabrication 5/2/67(a) 10/7/68(a) 1/16/68(b) 11/20/69(b) Surge pipe, fittings, and fabrication 5/2/67(a) 10/7/68(a) Piping to reactor coolant system boundary fabrication and installation 5/25/70 5/25/70
(a) Purchase of pipe. (b) Fabrication of pipe.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.2-4 Sheet 1 of 2 Revision 19 May 2010 SUMMARY OF REACTOR COOLANT SYSTEM DESIGN TRANSIENTS Normal Conditions Occurrences 1. RCS heatup and cooldown at 100F/hr 250 (each)(e)2. Pressurizer heatup at 100F/hr and cooldown at 200F/hr 250 (each)(e)3. Unit loading and unloading at 5% of full power/min 18,300 (each)4. Step load increase and decrease of 10% of full power 2,500 (each)
- 5. Hot standby operation/feedwater cycling (f) 18,300 6. Large step load decrease 250
- 7. Steady state fluctuations infinite
- 8. Tavg/power coastdown from nominal to reduced temperature Note (c) Upset Conditions 1. Loss of load (above 15% full power), without immediate turbine or reactor trip 100(e) 2. Loss of all offsite power 50(e) 3. Partial loss of flow 100(e) 4. Reactor trip from full power 500(e) 5. Inadvertent auxiliary spray (differential temperature > 320F 12(e) 6. Design earthquake 20 Faulted Conditions(a) 1. Main reactor coolant pipe break(d) 1 2. Steam pipe break 1
- 3. Double design earthquake 1
- 4. 7.5M Hosgri earthquake(b) 1 Test Conditions 1. Turbine roll test 10(e) 2. Hydrostatic test conditions a. Primary side 10(e) b. Secondary side 10(e) 3. Leak tests (for closures) a. Primary side 60(e) b. Secondary side 10 4. Tube leak tests (secondary side pressurized as follows) 200 psig 400 400 psig 200 600 psig 120 840 psig 80 (a) In accordance with the ASME Boiler and Pressure Vessel Code, faulted conditions are not included in fatigue evaluations. (b) See Section 3.7.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.2-4 Sheet 2 of 2 Revision 19 May 2010 (c) The Tavg operating range conditions bound the Tavg/power coastdown conditions of 565F and steam pressure of 750 psia. No special or separate Tavg/power coastdown transients are required. (d) With the acceptance of the DCPP leak-before-break analysis by the NRC, dynamic loading conditions resulting from pipe rupture events in the main reactor coolant loop piping no longer have to be considered in the design basis analyses; only the loads resulting from RCS branch line breaks have to be considered. (e) These limits were contained in Technical Specifications (Table 5.7-1) prior to License Amendment 135 (Improved Technical Specifications) (f) Applies to steam generator only.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 5.2-5 STRESS LIMITS FOR CLASS A COMPONENTS Loading Combinations Piping(a) Valves
- 1. Normal P Sh See Section 3.9.2 2. Upset P 1.2 Sh See Section 3.9.2 (Normal + DE loads)
- 3. Faulted P 1.8 Sh See Section 3.9.2 (Normal + DDE loads)
- 4. Faulted P 2.4 Sh See Section 3.9.2 (Normal + Hosgri)
(a) Sh = allowable stress from USAS B31.1 Code for power piping P = piping stress calculated per USAS B31.1 Code requirements.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.2-6 Revision 19 May 2010 LOAD COMBINATIONS AND STRESS CRITERIA FOR WESTINGHOUSE PRIMARY EQUIPMENT (a) CONDITION LOAD COMBINATION STRESS CRITERIA(e) Design Deadweight + Pressure DE Pm Sm PL + Pb 1.5 Sm Normal Deadweight + Pressure + Thermal PL + Pb + Pe + Q 3 Sm(b) Upset - 1 Deadweight + Pressure + Thermal DE UT 1.0(b) PL + Pb + Pe + Q 3 Sm Deadweight + Pressure + Thermal UT 1.0(b) PL + Pb + Pe + Q 3 Sm Faulted - 1 Deadweight + Pressure DDE Table 5.2-7 Faulted - 2 Deadweight + Pressure DDE + LPR(c, d, g) Table 5.2-7 Faulted - 3 Deadweight + Pressure Hosgri Table 5.2-7 Faulted - 4 Deadweight + Pressure + Other Pipe Rupture(f) Table 5.2-7 (a) Steam generators, reactor coolant pumps, pressurizer. (b) Based on elastic analysis. For simplified elastic-plastic analysis, the stress limits of the 1971 ASME Code Section III, NB-3228.3 apply. (c) LPR = reactor coolant loop pipe rupture (d) DDE and LPR combined by SRSS method (e) For definition of stress criteria terms, see Additional Notes. (f) Pipe rupture other than LPR. (g) While the original stress analysis considered this load combination, with the acceptance of the DCPP leak-before-break analysis by the NRC, loads resulting from ruptures in the main reactor coolant loop no longer have to be considered in the design basis structural analyses and included in the loading combinations, only the loads resulting from RCS branch line breaks have to be considered. . Pm = General membrane; average primary stress across solid section. Excludes discontinuities and concentrations. Produced only by mechanical loads. PL = Local membrane; average stress across any solid section. Considers discontinuities, but not concentrations. Produced only by mechanical loads. Pb = Bending; component of primary stress proportional to distance from centroid of solid section. Excludes discontinuities and concentrations. Produced only by mechanical loads. Pe = Expansions; stresses which result from the constraint of "free end displacement" and the effect of anchor point motions resulting from earthquakes. Considers effects of discontinuities, but not local stress concentration. (Not applicable to vessels). Q = Membrane Plus Bending; self-equilibrating stress necessary to satisfy continuity of structure. Occurs at structural discontinuities. Can be caused by mechanical loads or by differential thermal expansion. Excludes local stress concentrations. UT = Cumulative usage factor. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.2-7 Revision 19 May 2010 FAULTED CONDITION STRESS LIMITS FOR CLASS A COMPONENTS System (or Subsystem) Component Stress Limits for Stress Limits for Analysis Analysis Vessels and Pumps (f) Loop Piping Test Pm Pm + Pb P Elastic Smaller of Smaller of 3.6Sh 0.8 LT(c)(d) 2.4 Sm and 0.70 Su(e) 3.6 Sm and 1.05 Su(b) Elastic Plastic Larger of 0.70 Su or Larger of 0.70 Sut or Larger of 0.70 Sut or 0.8 LT(c)(d) Sy + 1/3 (Su - Sy)(c) Sy + 1/3 (Sut - Sy)(c) Sy + 1/3 (Sut - Sy)(c) Limit Analysis 0.9L1(a)(c) 0.9L1(a)(c) 0.9L1(a)(c) 0.8 LT(c)(d) Plastic Larger of 0.70 Su Larger of 0.70 Sut Larger of 0.70 Sut Plastic or or or 0.8 LT(c)(d) Elastic Sy + 1/3 (Su - Sy) Sy + 1/3 (Sut - Sy) Sy + 1/3 (Sut - Sy) (a) L1 = Lower bound limit load with an assumed yield point equal to 2.3 Sm or 1.5 Sy, as applicable. (b) These limits are based on a bending shape factor of 1.5 for simple bending cases with different shape factors; the limits will be changed proportionally. (c) When elastic system analysis is performed, the effect of component deformation on the dynamic system response should be checked. (d) LT = The limits established for the analysis need not be satisfied if it can be shown from the test of a prototype or model that the specified loads (dynamic or static equivalent) do not exceed 80% of LT, where LT is the ultimate load or load combination used in the test. In using this method, account shall be taken of the size effect and dimensional tolerances (similitude relationships) that may exist between the actual component and the tested models to ensure that the loads obtained from the test are a conservative representation of the load carrying capability of the actual component under postulated loading for faulted conditions. (e) Sy = Yield stress at temperature Sut = ultimate stress from true stress-strain curve at temperature Su = Ultimate stress from engineering stress strain curve at temperature Sm = stress intensity from ASME Section III at temperature Sh = Allowable stress from USAS B31.1 Code (f) For steam generators, stress limits are taken from Appendix F of ASME Section III. DCPP UNITS 1 & 2 FSAR UPDATE Revision 12 September 1998 TABLE 5.2-8 LOADING COMBINATIONS AND ACCEPTANCE CRITERIA FOR PRIMARY EQUIPMENT SUPPORTS CONDITION LOADING COMBINATIONS STRESS LIMITS Normal Deadweight + Temperature + Pressure 1969 AISC Specification, Part 1
Upset Deadweight + Temperature + Pressure +/- DE 1969 AISC Specification, Part 1
Faulted - 1 Deadweight + Pressure DDE + LPR(a, b, f) 1969 AISC Specification, Part 2(c) or Sy after load redistribution, whichever is higher Faulted - 2 Deadweight + Pressure HOSGRI 1969 AISC Specification, Part 2(c) or Sy(e) after load redistribution, whichever is higher Faulted - 3 Deadweight + Pressure + Other Pipe 1969 AISC Specification, Part 2(c) Rupture(d) or Sy after load redistribution, whichever is higher (a) LPR = Reactor coolant loop pipe rupture. (b) DDE and LPR combined by SRSS method (or more conservative method). (c) For supports qualified by load test, allowable loads = 0.8 times Lt per Table 5.2-7. (d) Pipe rupture other than LPR. (e) For the pressurizer upper lateral supports and the reactor vessel supports, the allowable Sy is based on average value of actual yield stress of the material. (f) While the original stress analysis considered this load combination, with the acceptance of the DCPP leak-before-break analysis by the NRC, loads resulting from ruptures in the main reactor coolant loop no longer have to be considered in the design basis structural analyses and included in the loading combinations, only the loads resulting from RCS branch line breaks have to be considered. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.2-9 Sheet 1 of 3 Revision 20 November 2011 ACTIVE AND INACTIVE VALVES IN THE REACTOR COOLANT PRESSURE BOUNDARY(a) Type Valve Valve A-Active System Valves I.D. Number Location and Figure Number Type Size, in. Actuation I-Inactive RCS 8000 A, B, C Pressurizer Gate 3 Motor A Figure 3.2-7, Sheets 3 & 4
RCS 8010 A, B, C Pressurizer Relief 6 P A Figure 3.2-7, Sheets 3 & 4 RCS 8078 A,B,C,D Reactor vessel head vent Globe 1 Solenoid A Figure 5.5-14
RCS PCV-455 A,B Pressurizer spray Ball 4 Air I Figure 3.2-7, Sheets 3 & 4
RCS PCV-455 C Pressurizer Globe 3 Air A PCV-456 Figure 3.2-7, Sheets 3 & 4
RCS PCV-474 Pressurizer Globe 3 Air I Figure 3.2-7, Sheets 3 & 4
CVCS LCV-459 RCS cold leg loop 2 Globe 3 Air A Figure 3.2-8, Sheets 5 & 6
CVCS LCV-460 RCS cold leg loop 2 Globe 3 Air A Figure 3.2-8, Sheets 5 & 6
CVCS 8145 CVCS pressurizer auxiliary spray Globe 2 Air A 8148 Figure 3.2-8, Sheets 5 & 6
CVCS 8166 RCS excess letdown Globe 1 Air I 8167 Figure 3.2-8, Sheets 1 & 2
CVCS 8367 A, B, C, D CVCS seal water injection Check 2 P I Figure 3.2-8, Sheets 1 & 2 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.2-9 Sheet 2 of 3 Revision 20 November 2011 Type Valve Valve A-Active System Valves I.D. Number Location and Figure Number Type Size, in. Actuation I-Inactive
CVCS 8372 A, B, C, D CVCS seal water injection Check 2 P I Figure 3.2-8, Sheets 1 & 2 CVCS 8377 CVCS pressurizer auxiliary spray Check 2 P I Figure 3.2-8, Sheets 5 & 6 CVCS 8378 A CVCS charging line to loop 3 Check 3 P I 8379 A Figure 3.2-8, Sheets 5 & 6 CVCS 8378 B CVCS charging line to loop 4 Check 3 P I 8379 B Figure 3.2-8, Sheet 5 & 6 RHR 8701 RHR isol. hot leg loop 4 Gate 14 Motor I(b) Figure 3.2-10, Sheets 1 & 2
RHR 8702 RHR isol. hot leg loop 4 Gate 14 Motor I(b) Figure 3.2-10, Sheets 1 & 2
RHR 8740 A, B RCS hot leg Check 8 P I Figure 3.2-10, Sheets 1 & 2 SIS 8818 A, B, C, D SIS cold leg Check 6 P I Figure 3.2-9, Sheets 5 & 6 SIS 8819 A, B, C, D SIS cold legs Check 2 P I Figure 3.2-9, Sheets 5 & 6 SIS 8820 SIS boron injection containment Check 3 P I isolation, Figure 3.2-9, Sheets 3 & 4
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.2-9 Sheet 3 of 3 Revision 20 November 2011 Type Valve Valve A-Active System Valves I.D. Number Location and Figure Number Type Size, in. Actuation I-Inactive
SIS 8900 A, B, C, D SIS cold leg Check 1 1/2 P I Figure 3.2-9, Sheets 3 & 4 SIS 8905 A, B, C, D RCS hot legs Check 2 P I Figure 3.2-9, Sheets 5 & 6 SIS 8948 A, B, C, D RCS cold leg Check 10 P I Figure 3.2-9, Sheets 1 & 2 SIS 8949 A, B, C, D RCS hot legs Check 6 P I Figure 3.2-9, Sheets 5 & 6 SIS 8956 A, B, C, D RCS cold leg Check 10 P I Figure 3.2-9, Sheets 1 & 2 (a) As defined in 10 CFR 50.2, valves are listed first by system (RCS, CVCS, RHR, and SIS) and then by valve I.D. number. (b) For the postulated Hosgri earthquake this valve is considered active.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11A April 1997 TABLE 5.2-10 REACTOR COOLANT SYSTEM NOMINAL PRESSURE SETPOINTS (PSIG) Design pressure 2485 Operating pressure 2235 Safety valves 2485 Power relief valves 2335 Pressurizer spray valves (begin to open) 2260 Pressurizer spray valves (full open) 2310 High-pressure reactor trip 2385 High-pressure alarm 2310 Low-pressure reactor trip (typical, but variable) 1950 Low-pressure alarm 2210 Hydrostatic test pressure 3107 Backup heaters on (pressurizer) 2210 Proportional heaters (begin to operate) 2250 Proportional heaters (full operation) pressurizer 2220 Pressurizer power relief valve interlock 2185
DCPP UNITS 1 & 2 FSAR UPDATE Revision 21 September 2013 TABLE 5.2-11 REACTOR VESSEL MATERIALS Section Materials Pressure plate Unit 1: A-533 Grade B Class 1 Unit 2: SA-533 Grade B Class 1 Pressure forgings Unit 1: A-508 Class 2 Unit 2: SA-508 Class 2 Replacement RVCH Forging SA-508 Grade 3 Class 1
Primary nozzle safe ends Stainless steel Type 316 Forging
Cladding, stainless Type 304 or equivalent (Combination of Types 308, 308L, 309, 309L, and 312) Stainless weld rod Types 308L, 308, and 309
O-ring head seals Inconel 718
CRDM housings Inconel 690 and stainless Type 304
Lower tube SB-167
Studs SA-540 Grade B-23 and B-24
Instrumentation nozzles Inconel 600
Thermal insulation Stainless steel
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.2-12 Sheet 1 of 2 Revision 21 September 2013 PRESSURIZER, PRESSURIZER RELIEF TANKS, AND SURGE LINE MATERIALS Pressurizer Unit 1 Unit 2 Shell SA-533, Grade A SA-533, Grade A (Class 1) (Class 2) Heads SA-216, Grade WCC SA-533, Grade A (Class 2) Support skirt SA-516, Grade 70 SA-516, Grade 70 Nozzle weld ends SA-182, F316 SA-182, F316L Inst. tube coupling SA-182, F316 SA-182, F316 Cladding, stainless Type 304 or Type 304 or equivalent equivalent Nozzle forgings SA-508, Class 2 Mn-Mo
Nozzle Weld Overlay N/A First pass 309L, ERNiCr-3 over dissimilar metal weld Remainder of overlay ERNiCrFe-7 (Automatic GTAW) ERNiCrFe-7A (Manual GTAW) Internal plate SA-240, Type 304 SA-240, Type 304 Inst. tubing SA-213, Type 304 316 SA-213, Type 304 316 Heater well tubing SA-213, Type 316 seamless SA-213, Type 316 seamless Heater well adaptor SA-182, F316 SA-182, F316 Pressurizer Relief Tank Shell ASTM A-285, Grade C ASTM A-285, Grade C Heads ASTM A-285, Grade C ASTM A-285, Grade C Internal coating Amercoat 55 Amercoat 55 Surge Line Pipes ASTM A-376, Type 316 ASTM A-376, Type 316 Fittings ASTM A-403, WP316 ASTM A-182, F316 Nozzles ASTM A-182, Grade F316 ASTM A-182, Grade F316 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.2-12 Sheet 2 of 2 Revision 21 September 2013 Valves Unit 1 Unit 2 Pressure-containing parts ASTM A-351, Grade CF8M ASTM A-351, Grade CF8M ASTM A-182, Grade F ASTM A-182, Grade F and ASME SA-351, Grade CF3 (for RCS-8029) and ASME SA-351, Grade CF3 (for RCS-8029) DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 5.2-13 REACTOR COOLANT PUMP MATERIALS Shaft ASTM A-182, Grade F347 Impeller ASTM A-351, Grade CF8 Casing ASTM A-351, Grade CF8 Flywheel ASTM A-533, Grade B, Class I
DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 5.2-14 STEAM GENERATOR MATERIALS Pressure forgings ASME SA 508, Grade 3, Class 2 Cladding Stainless steel Types 309L, 308L Tubesheet cladding Alloy 690 weld material Tubes Alloy 690 TT
DCPP UNITS 1 & 2 FSAR UPDATE Revision 12 September 1998 TABLE 5.2-15 REACTOR COOLANT WATER CHEMISTRY SPECIFICATION Parameter Steady State Transient Limit Conductivity, Mho/cm @ 25C (a)(c) ---- pH @ 25C (a)(c) ---- Oxygen, ppm(b) 0.10 1.0 Chloride, ppm 0.15 1.5 Fluoride, ppm 0.15 1.5 Hydrogen, cc(STP)/kg power > 1 MWt (c) ---- normal target band (c) ---- Total suspended solids, ppm (c) ---- Li-7, ppm as Li (c) ---- Boric acid, ppm as B (c) ---- Silica, ppm (c) ---- Aluminum, ppm (c) ---- Calcium, ppm (c) ---- Magnesium, ppm (c) ---- Sulfur compounds, ppm (c) ---- (a) Varies with boric acid and lithium hydroxide concentration.
(b) Limit is not applicable with Tavg 250F. During startup, hydrazine may be used to achieve RCS concentrations of up to 10 ppm when the coolant temperature is between 150 and 180F and the oxygen exceeds 0.1 ppm.
(c) Chemical Control Limits and Actions Guidelines for the Primary Systems are listed in plant procedures. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.2-16 Sheet 1 of 4 Revision 12 September 1998 REACTOR COOLANT BOUNDARY LEAKAGE DETECTION SYSTEMS Radioactivity Detection Systems Detector Location or Process Medium Type Range Approximate Time to Detect 1-gpm Leak Identified(c) Leak Detection Seismic(a) Category Indicator in Control Room Containment Air G-M 10-1 to 104 mR/hr Less responsive than other detection systems No II Yes Incore inst area Air G-M 10-1 to 104 mR/hr Less responsive than other detection systems No II Yes Containment air particulate Air NaI Scintillator 10 to 106 cpm See Fig. 5.2-9 No II(b) Yes Containment radiogas Air G-M 10 to 106 cpm See Fig. 5.2-9 No II(b) Yes Plant vent radiogas Air Beta Scintillator 10 to 5E6 cpm Less responsive than other detection systems No II Yes Condenser air ejector Air Beta Scintillator 10 to 5E6 cpm See Fig. 5.2-10 Yes II Yes Component cooling liquid Liquid NaI Scintillator 10 to 106 cpm See Fig. 5.2-12 No IC Yes Steam generator blowdown Liquid NaI Scintillator 10 to 106 cpm See Fig. 5.2-11 Yes II Yes DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.2-16 Sheet 2 of 4 Revision 12 September 1998 Other Detection Systems Detector Location or Process Medium Type Range and Repeatability(e) Approximate Time to Detect 1-gpm Leak (q) Identified(c) Leak Detection Seismic(a) Category Indicator in Control Room Containment(d) condensation Liquid Change in time required to accumulate fixed volume see note (m) 1 hr (g)(h)(l) No II Yes Containment sumps Liquid Liquid level and quantity of liquid 1 to 48 in. W.C. (n) 1 to 35 in. W.C. (p) +/-1 in. 1 hr (h) No II Yes Reactor vessel flange leakoff Liquid Temperature 50 to 300 F +/-5 F <30 sec (f) Yes II Yes Reactor coolant drain tank Liquid Liquid level and quantity of liquid 0-100% +/-2%
<20 min (h) Yes II No Pressurizer relief valve discharge Liquid Temperature 50 to 400 F +/-7 F <30 sec (f) Yes II Yes Pressurizer relief tank Liquid Yes II Yes Liquid level 0 to 100 % +/-2% <12 hrs (h)
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.2-16 Sheet 3 of 4 Revision 12 September 1998 Systems Used to Quantify Leakage (i) Detector System Medium Type Range/Sensitivity Seismic Category Indicated in Control Room Pressurizer level Liquid Liquid level 0 to 100% (g)(j) 125 gal/% level I Yes Volume control tank level Liquid Liquid level 0 to 100% (g)(j) 19 gal/% level II Yes Charging pump flow Liquid Flow 0 to 200 gpm (k) +/- 10% span when flow 60 gpm (channel uncertainty value) II Yes Pressurizer relief tank level Liquid Liquid level 0 to 100% (h) min. 127, max. 154 gal/% level (20 % level 80) II Yes (a) Seismic Category I systems are designed to perform required safety functions following a DDE. Category II instrument systems were designed to function under conditions up to DE. Class IC instrument systems refer to maintenance of pressure boundary integrity of Category I fluid systems. Also refer to Section 3.2. (b) These units were not constructed to withstand DDE accelerations; however, they will be housed in a Seismic Category I structure and protected from external damage associated with a seismic event. Therefore, it is considered that these units can be returned to operational status within 36 hours of a DDE. (c) Leakage is defined as identified or unidentified in accordance with Regulatory Guide 1.45.
(d) Containment condensation measures moisture condensed by the fan cooler drip collection system.
(e) Repeatability, including the operators ability to read the same value at another time, is included in this column; this is a true measure of ability to detect a change in system conditions over a period of time. (f) Automatically alarmed. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.2-16 Sheet 4 of 4 Revision 12 September 1998 (g) Requires operator action - (i.e., close valve, start-stop pump, etc., and operator monitoring and logging). (h) Requires operator monitoring and logging to note changes in rate, level, flow, etc.
(i) Systems listed here would be used to quantify true leakage rate in the event systems listed on Sheets 1 & 2 above detected an unidentified leak. These systems also provide additional capability for detecting leak rates of 1-gpm within short periods of time. (j) Normal variations in process variable or automatic control systems will mask this change. Operator must take action as in (g) above to detect leakage. (k) Insufficient accuracy/repeatability to ever detect a 1-gpm change in flowrate.
(l) Dependent on initial conditions. May take longer for fan cooler drip level if humidity is initially low.
(m) Level switches (HI and HI-HI) are provided in each CFCU drain line. The level switches have a fixed location in each drain line providing a repeatable alarm. The time intervals between the receipt of the HI level and HI-HI level alarms are monitored and logged by the operator. Alarm intervals less than a conservative pre-defined value directs the operator to perform an RCS water inventory balance to quantify the RCS leakage rate. (n) This range refers to the containment structure sumps.
(o) Not used.
(p) This range refers to the reactor cavity sump.
(q) This column refers to the capability of the detection system to sense a leak.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 21 September 2013 TABLE 5.2-17A DCPP UNIT 1 REACTOR VESSEL TOUGHNESS DATA Minimum Average 50 Ft-lb/35 Mil Upper Shelf Plate Material Cu Ni P NDTT Tempt °F RTNDT Ft-lb Component No. Type (Wt%) (Wt%) (Wt%) °F Long Trans °F Long Trans Repl. Cl. Hd. 06W255-1 SA508,CL1 0.05 0.82 0.005 20 211 Ves. Sh. Flg. B4101 A508,CL2 -- 0.75 0.010 35(a) -5 15(a) 35 99(a) Inlet Noz. B4103-1 A508,CL2 -- 0.66 0.013 60(a) 17 37(a) 60 77(a) Inlet Noz. B4103-2 A508,CL2 -- 0.67 0.013 60(a) 27 47(a) 60 75(a) Inlet Noz. B4103-3 A508,CL2 -- 0.68 0.010 43(a) 10 30(a) 43 108(a) Inlet Noz. B4103-4 A508,CL2 -- 0.66 0.010 48(a) 2 22(a) 48 106(a) Outlet Noz. B4104-1 A508,CL2 -- 0.74 0.011 60(a) -13 7(a) 60 77(a) Outlet Noz. B4104-2 A508,CL2 -- 0.76 0.006 43(a) -3 17(a) 43 74(a) Outlet Noz. B4104-3 A508,CL2 -- 0.71 0.012 54(a) -12 8(a) 54 86(a) Outlet Noz. B4104-4 A508,CL2 -- 0.68 0.008 60(a) 30 50(a) 60 84(a) Upper Shl. B4105-1 A533B,CL1 0.12 0.56 0.010 10 68 88(a) 28 80(a) Upper Shl. B4105-2 A533B,CL1 0.12 0.57 0.008 0 49 69(a) 9 74(a) Upper Shl. B4105-3 A533B,CL1 0.14 0.56 0.010 0 54 74(a) 14 81(a) Inter. Shl. B4106-1 A533B,CL1 0.125 0.53 0.013 -10 57 40 -10 134 116 Inter. Shl. B4106-2 A533B,CL1 0.120 0.50 0.013 -10 36 57 -3 132 114 Inter.Shl. B4106-3 A533B,CL1 0.086 0.476 0.011 10 70 90(a) 30 119 77(a) Lower Shl. B4107-1 A533B,CL1 0.13 0.56 0.011 -10 59 75 15 127 110 Lower Shl. B4107-2 A533B,CL1 0.12 0.56 0.010 -10 64 80 20 127 103 Lower Shl. B4107-3 A533B,CL1 0.12 0.52 0.010 -50 52 38 -22 135 116 Bot. Hd. Seg. B4111-1 A533B,CL1 0.15 0.51 0.014 -20 33 53(a) -7 82(a) Bot. Hd. Seg. B4111-2 A533B,CL1 0.12 0.63 0.009 -40 16 36(a) -24 90(a) Bot. Hd. Seg. B4111-3 A533B,CL1 0.13 0.50 0.009 -40 21 41(a) -19 85(a) Bot. Hd. Seg. B4110 A553B,CL1 0.06 0.44 0.010 -10 60 80(a) 20 75(a) (a) Estimated per NRC Standard Review Plan Section 5.3.2. DCPP UNITS 1 & 2 FSAR UPDATE Revision 21 September 2013 TABLE 5.2-17B DCPP UNIT 2 REACTOR VESSEL TOUGHNESS DATA Minimum Average 50 Ft-lb/35 Mil Upper Shelf Plate Material Cu Ni P NDTT Tempt °F RTNDT Ft-lb Component No. Type (Wt%) (Wt%) (Wt%) °F Long Trans °F Long Trans Repl. Cl. Hd. 06W255-1 SA508,CL1 0.05 0.82 0.005 - 20 - 211 Inlet Noz. B5461-1 SA508,CL2 0.09 0.70 0.012 -20 23 43(a) -17 116 75 Inlet Noz. B5461-2 SA508,CL2 0.09 0.70 0.012 2 18(a) -20 119 77(a) Inlet Noz. B5461-3 SA508,CL2 0.10 0.82 0.013 45 -25(a) -40 127 83(a) Inlet Noz. B5461-4 SA508,CL2 0.10 0.81 0.013 48 -28(a) -40 129 84(a) Outlet Noz. B5462-1 SA508,CL2 0.11 0.67 0.010 4 16(a) -44 145 94 Outlet Noz. B5462-4 SA508,CL2 0.11 0.67 0.009 10 10(a) -40 137.5 89(a) Outlet Noz. B5462-2 SA508,CL2 0.11 0.67 0.009 -40 14 34(a) -26 135.5 88(a) Outlet Noz. B5462-3 SA508,CL2 0.11 0.67 0.009 -50 17 37(a) -23 131.5 85(a) Upper Shl. B5453-1 SA533B,CL1 0.11 0.60 0.014 0 85 88 28 92 82 Upper Shl. B5453-3 SA533B,CL1 0.11 0.60 0.012 10 45 65(a) 5 136.5 86.5(ab) Upper Shl. B5011-1R SA533B,CL1 0.11 0.65 0.015 10 40 60(a) 0 110 72(a) Inter. Shl. B5454-1 SA533B,CL1 0.14 0.65 0.010 -40 14 112 52 128 91 Inter. Shl. B5454-2 SA533B,CL1 0.14 0.59 0.012 0 60 127 67 113 99 Inter. Shl. B5454-3 SA533B,CL1 0.15 0.62 0.013 -40 30 93 33 129 90 Lower Shl. B5455-1 SA533B,CL1 0.14 0.56 0.010 -20 42 45 -15 134 112 Lower Shl. B5455-2 SA5338,CL1 0.14 0.56 0.011 0 25 45 0 137 122 Lower Shl. B5455-3 SA533B,CL1 0.10 0.62 0.010 0 55 75 15 128 100 Bot. Hd. Seg. B5009-2 SA533B,CL1 0.13 0.57 0.011 -10 110 130(a) 70 85 55(a) Bot. Hd. Seg. B5009-3 SA533B,CL1 0.13 0.60 0.009 12 8(a) -20 131 84 Bot. Hd. Seg. B5009-1 SA533B,CL1 0.13 0.58 0.010 0 88 108(a) 48 95 62(a) Bot. Hd. Seg. B5010 SA533B,CL1 0.14 0.63 0.011 -30 20 40(a) -20 114 74 (a) Estimated per NRC Standard Review Plan Section 5.3.2. (b) Westinghouse Letter LTR-PCAM-09-26, Revision 1, "Diablo Canyon Units 1 and 2 Reactor Vessel Extended Beltline Material Properties Search," June 3, 2009 DCPP UNITS 1 & 2 FSAR UPDATE Revision 21 September 2013 TABLE 5.2-18A IDENTIFICATION OF UNIT 1 REACTOR VESSEL BELTLINE REGION BASE MATERIAL Material Composition, Wt.% Component Plate No. Heat No. Spec. No. C Mn P S Si Ni Mo Cu Inter shell B4106-1 C2884-1 A533B,CL1 0.25 1.34 0.013 0.015 0.21 0.53 0.45 0.125 Inter shell B4106-2 C2854-2 A533B,CL1 0.18 1.32 0.013 0.015 0.23 0.50 0.46 0.120 Inter shell B4106-3 C2793-1 A533B,CL1 0.20 1.33 0.011 0.012 0.25 0.476 0.46 0.086 Lower shell B4107-1 C3121-1 A533B,CL1 0.25 1.36 0.011 0.014 0.24 0.56 0.48 0.13 Lower shell B4107-2 C3131-2 A533B,CL1 0.24 1.32 0.010 0.013 0.23 0.56 0.46 0.12 Lower shell B4107-3 C3131-1 A533B,CL1 0.19 1.38 0.010 0.013 0.26 0.52 0.46 0.12
DCPP UNITS 1 & 2 FSAR UPDATE Revision 21 September 2013 TABLE 5.2-18B IDENTIFICATION OF UNIT 2 REACTOR VESSEL BELTLINE REGION BASE MATERIAL Material Composition, Wt.% Component Plate No. Heat No. Spec. No. C Mn P S Si Ni Mo Cu Inter shell B5454-1 C5161-1 SA533B,CL1 0.21 1.30 0.010 0.015 0.19 0.65 0.46 0.14 Inter shell B5454-2 C5168-2 SA533B,CL1 0.25 1.38 0.012 0.016 0.21 0.59 0.55 0.14 Inter shell B5454-3 C5161-2 SA533B,CL1 0.23 1.32 0.013 0.015 0.20 0.62 0.45 0.15 Lower shell B5455-1 C5175-1 SA533B,CL1 0.21 1.38 0.010 0.018 0.19 0.56 0.56 0.14 Lower shell B5455-2 C5175-2 SA533B,CL1 0.22 1.40 0.011 0.018 0.19 0.56 0.56 0.14 Lower shell B5455-3 C5176-1 SA533B,CL1 0.23 1.34 0.010 0.014 0.20 0.62 0.56 0.10
DCPP UNITS 1 & 2 FSAR UPDATE Revision 15 September 2003 TABLE 5.2-19A FRACTURE TOUGHNESS PROPERTIES OF UNIT 1 REACTOR VESSEL BELTLINE REGION BASE MATERIAL Initial EOL(a) Material TNDT (F) RTNDT (F) USE(b) (ft-lb) Fluence(c) (N/cm2) RTNDT(d) (F) USE(d) (ft-lb) Upper Shell Plate B4105-1 10 28(e) 80(e) 1.64E+17 89 74 B4105-2 0 9(e) 74(e) 1.64E+17 70 68 B4105-3 0 14(e) 81(e) 1.64E+17 77 74 Inter Shell Plate B4106-1 10 116 7.93E+18 115 90 B4106-2 3 114 7.93E+18 113 90 B4106-3 10 30(e) 77(e) 7.93E+18 139 63 Lower Shell Plate B4107-1 -10 15 110 7.93E+18 133 87 B4107-2 -10 20 103 7.93E+18 131 82 B4107-3 22 116 7.93E+18 88 93 _______________________
(a) End of license for 40 operating years, September 2021. (b) Upper shelf energy. (c) Fluence at vessel wall 1/4 thickness location. (d) Per Regulatory Guide 1.99, Revision 2. (e) Estimated from data in the longitudinal direction per NRC Standard Review Plan Section 5.3.2.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 20 November 2011 TABLE 5.2-19B FRACTURE TOUGHNESS PROPERTIES OF UNIT 2 REACTOR VESSEL BELTLINE REGION BASE MATERIAL Initial EOL(a) Material TNDT (°F) RTNDT (°F) USE(b) (ft-lb) Fluence(c) (N/cm2) RTNDT(d) (°F) USE(d) (ft-lb) Upper Shell Plate B5453-1 0 28 82 1.81E+17 74 75 B5453-3 -10 5(e) 86.5(f) 1.81E+17 65 82 B5011-1R 10 0(e) 72(e) 1.81E+17 60 66 Inter Shell Plate B5454-1 -40 52 91 8.75E+18 166 69 B5454-2 0 67 99 8.75E+18 180 76 B5454-3 40 33 90 8.75E+18 173 68
Lower Shell Plate B5455-1 15 112 8.75E+18 114 86 B5455-2 0 0 122 8.75E+18 129 94 B5455-3 0 15 100 8.75E+18 112 81
(a) End of license for 40 operating years, April 2025. (b) Upper shelf energy. (c) Fluence at vessel wall 1/4 thickness location. (d) Per Regulatory Guide 1.99, Revision 2. (e) Estimated from data in the longitudinal direction per NRC Standard Review Plan Section 5.3.2. (f) Westinghouse Letter LTR-PCAM-09-26, Revision 1, "Diablo Canyon Units 1 and 2 Reactor Vessel Extended Beltline Material Properties Search," June 3, 2009 DCPP UNITS 1 & 2 FSAR UPDATE Revision 15 September 2003 TABLE 5.2-20A IDENTIFICATION OF UNIT 1 REACTOR VESSEL BELTLINE REGION WELD METAL Weld Weld Wire Flux Average Deposit Composition, Wt.% Weld Location Process Type Heat No. Type Lot No. C Mn P S Si Mo Ni CR Cu Upper shell Sub-Arc B-4 Mod. 13253 Linde 1092 37740.18 1.30 0.020 0.013 0.24 0.45 0.73 0.19 0.25 to inter shell circle seam 8-442
Inter shell Sub-Arc B-4 Mod. 27204 Linde 1092 37240.14 1.36 0.016 0.025 0.45 0.48 1.018 0.06 0.203 long seams 2-442 A, B, & C
Inter shell Sub-Arc B-4 Mod. 21935 Linde1092 38690.14 1.38 0.015 0.010 0.15 0.54 0.704 -- 0.183 to lower shell circle seam 9-442
Lower shell Sub-Arc B-4 Mod. 27204 Linde 1092 37740.14 1.36 0.016 0.025 0.45 0.48 1.018 0.06 0.203 long seams 3-442 A, B, & C
DCPP UNITS 1 & 2 FSAR UPDATE Revision 15 September 2003 TABLE 5.2-20B IDENTIFICATION OF UNIT 2 REACTOR VESSEL BELTLINE REGION WELD METAL Weld Weld Wire Flux Average Deposit Composition, Wt.% Weld Location Process Type Heat No. Type Lot No. C Mn P S Si Mo Ni CR Cu Nozzle shell Sub-Arc B-4 Mod. 21935 Linde 1092 3889 0.14 1.38 0.015 0.010 0.15 0.540.704 - 0.183 to inter shell circle seam 8-201
Inter shell Sub-Arc B-4 Mod. 21935 Linde 1092 3869 0.13 1.41 0.018 0.010 0.16 0.550.87 0.03 0.22 long seams (Tandem) B-4 Mod. 12008 2-201 A, B, & C
Inter shell Sub-Arc B-4 10120 Linde 0091 3458 0.14 1.12 0.011 0.008 0.18 0.480.082 - 0.046 to lower shell circle seam 9-201
Lower shell Sub-Arc B-4 33A277 Linde 124 3878 0.11 1.17 0.015 0.011 0.26 0.500.165 0.06 0.258 long seams 3-201 A, B, & C
DCPP UNITS 1 & 2 FSAR UPDATE Revision 20 November 2011 TABLE 5.2-21A FRACTURE TOUGHNESS PROPERTIES OF UNIT 1 REACTOR VESSEL BELTLINE REGION WELD METAL Initial EOL(a) Material RTNDT (°F) USE(b) (ft-lb) Fluence(c) (N/cm2) RTNDT(d) (°F) USE(d) (ft-lb) Upper Shell Long. Welds 1-442 A,B,C -20 86(f) <1.64+17 69 74 Upper Shell to Inter. Shell Weld 8-442 -56(e) 111(g) <1.64E+17 40 93 Inter. Shell Long. Welds 2-442 A,B -56(e) 91(h) 5.35E+18 194 66 2-442 C -56(e) 91(h) 2.87E+18 157 69 Inter. Shell to Lower Shell Weld 9-442 -56(e) 109(I) 7.93E+18 166 75 Lower Shell Long. Welds 3-442 A,B -56(e) 91(h) 4.46E+18 182 67 3-442 C -56(e) 91(h) 7.93E+18 218 63 (a) End of license for 40 operating years, September 2021. (b) Upper shelf energy. (c) Fluence at vessel wall 1/4 thickness location. (d) Per Regulatory Guide 1.99, Revision 2. (e) Generic value per 10 CFR 50.61. (f) CE Vessel Weld Test Report, April 9, 1968. (g) WCAP 10492, Analysis of Capsule T, Salem 2 Surveillance Program, March 1984. (h) WCAP 15958, Rev. 0, "Analysis of Capsule V from PG&E Diablo Canyon Unit 1 Reactor Vessel Radiation Surveillance Program," January 2003. (i) PG&E Letter DCL-95-176, August 16, 1995, and PG&E Letter DCL-98-094, July 6, 1998. DCPP UNITS 1 & 2 FSAR UPDATE Revision 20 November 2011 TABLE 5.2-21B FRACTURE TOUGHNESS PROPERTIES OF UNIT 2 REACTOR VESSEL BELTLINE REGION WELD METAL Initial EOL(a) Material RTNDT (°F) USE(b) (ft-lb) Fluence(c) (N/cm2) RTNDT(d) (°F) USE(d) (ft-lb) Upper Shell Long. Welds 1-201 A,B,C -50 118(f) <1.81E+17 14 97 Upper Shell to Inter. Shell Weld 8-201 -56(e) 109(g) <1.81E+17 37 95 Inter. Shell Long. Welds 2-201 A,B -50 118(f) 5.61E+18 165 78 2-201 C -50 118(f) 6.08E+18 170 76 Inter. Shell to Lower Shell Weld 9-201 -56(e) 125(h) 8.75E+18 35 102 Lower Shell Long. Welds 3-201 A,B -56(e) 88(h) 6.08E+18 121 56 3-201 B -56(e) 88(h) 5.61E+18 118 57 (a) End of license for 40 operating years, April 2025. (b) Upper shelf energy. (c) Fluence at vessel wall 1/4 thickness location. (d) Per Regulatory Guide 1.99, Revision 2. (e) Generic value per 10 CFR 50.61. (f) WCAP 15423, "Analysis of Capsule V from PG&E Diablo Canyon Unit 2 Reactor Vessel Radiation Surveillance Program," September 2000. (g) PG&E Letter DCL-95-176, August 16, 1995. (h) Average of three Charpy tests at +10°F, CD weld wire/flux qualification test. DCPP UNITS 1 & 2 FSAR UPDATE Revision 21 September 2013 TABLE 5.2-22 REACTOR VESSEL MATERIAL SURVEILLANCE PROGRAM WITHDRAWAL SCHEDULE UNIT 1 Lead Fluence at Capsule Removal Capsule(f)(g) Location Factor(d) Center (n/cm2)(d) Time (Plant EFPY)(a) S 320° 3.48 2.83E+18 1.25 (Tested,1R1) Y 40° 3.45 1.05E+19 5.86 (Tested, 1R5) T 140° 3.45 1.05E+19 5.86 (Removed, 1R5) Z 220° 3.45 1.05E+19 5.86 (Removed, 1R5) V 320° 2.26 1.36E+19 14.3 (Tested 1R11) C(b) 140° 3.47 1.22E+19 15.9 (Removed 1R12) D(b) 220° 3.47 1.22E+19 15.9 (Removed 1R12) B(b) 40° 3.47 3.44E+19 (projected) 33.0 (Planned 1R23) A(b) 184° 1.32 Standby Standby U 356° 1.24 Standby Standby X 176° 1.24 Standby Standby W 4° 1.24 Standby Standby UNIT 2 Lead Fluence at Capsule Removal Capsule Location Factor(d) Center (n/cm2)(d) Time (EFPY)(a) U 56° 5.20 3.30E+18 1.02 (Tested, 2R1) X 236° 5.39 9.06E+18 3.16 (Tested, 2R3) Y 238.5° 4.56 1.53E+19 7.08 (Tested, 2R6) W(e) 124° 5.35 2.78E+19 11.49 (Removed, 2R9) V(e) 58.5° 4.57 2.38E+19 11.49 (Tested, 2R9) Z(e) 304° 5.35 2.78E+19 11.49 (Removed, 2R9) (a) Approximate full power years from plant startup. (b) Four supplemental capsules installed at 5.86 EFPY (EOC5). (c) Deleted in Revision 16. (d) Approximate values taken from WCAP-17299-NP (Rev. 0) for Units 1 and 2. (e) Capsule EFPY for Unit 2 capsules removed in 2R9; W = 61.5, V = 52.5, and Z = 61.5 (f) Unit 1 capsules T, U, W, X, and Z are Type 1 (base metal only) (g) Unit 1 capsules S, V, and Y are Type 2 (base metal and weld) DCPP UNITS 1 & 2 FSAR UPDATE Revision 16 June 2005 TABLE 5.2-23 REACTOR COOLANT SYSTEM PRESSURE BOUNDARY ISOLATION VALVES VALVE NUMBER FUNCTION 1. 8948 A, B, C, and D Accumulator, RHR, and SIS first off check valves from RCS cold legs 2. 8819 A, B, C, and D SIS second off check valves from RCS cold legs 3. 8818 A, B, C, and D RHR second off check valves from RCS cold legs 4. 8956 A, B, C, and D Accumulator second off check valves from RCS cold legs 5. 8701 and 8702 RHR suction isolation valves
- 6. 8949 A, B, C, and D RHR and SIS first off check valves from RCS hot legs 7. 8905 A, B, C, and D SIS second off check valves from RCS hot legs 8. 8740(a) A and B RHR second off check valves from RCS hot legs ____________________
(a) 8703 may be used to satisfy Technical Specification 3.4.14 Required Actions A.1 or A.2.1 when in Condition A for valves 8740A and 8740B.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 5.4-1 REACTOR VESSEL DESIGN PARAMETERS (BOTH UNITS) Design/operating pressure, psig 2485/2235 Design temperature, F 650 Overall height of vessel and closure head, ft-in. (bottom head OD to top of control rod mechanism adapter) 43-10 Thickness of insulation, min, in. 3 Number of reactor closure head studs 54 Diameter of reactor closure head/studs, in. 7 ID of flange, in. 167 OD of flange, in. 205 ID at shell, in. 173 Inlet nozzle ID, in. 27-1/2 Outlet nozzle ID, in. 29 Cladding thickness, min, in. 5/32 Lower head thickness, min, in. 5-1/4 Vessel beltline thickness, min, in. 8-1/2 Closure head thickness, in. 7 DCPP UNITS 1 & 2 FSAR UPDATE Revision 20 November 2011 TABLE 5.4-2 REACTOR VESSEL CONSTRUCTION QUALITY ASSURANCE PROGRAM Forgings RT(a) UT(a) PT(a) MT(a) 1. Flanges - Yes - Yes 2. Studs - Yes - Yes
- 3. Instrumentation tubes - Yes Yes - 4. Main nozzles - Yes - Yes 5. Nozzles safe ends - Yes Yes - 6. CRDM and Thermocouple Nozzles - Yes Yes - 7. RVHVS and RVLIS Nozzles Yes - Yes - Plates - Yes - Yes Weldments 1. Main seam Yes Yes(c) - Yes 2. Instrumentation tube connection - - Yes - 3. Main nozzles Yes Yes(c) - Yes 4. Cladding - Yes(b) Yes - 5. Nozzle to safe ends weld Yes - - Yes 6. Nozzle to safe ends weld overlay (Unit 2) Yes Yes(c) Yes - 7. All ferritic welds accessible after hydrotest - - - Yes 8. All nonferritic welds accessible after hydrotest - - Yes - 9. Seal ledge - - - Yes 10. Head lift lugs - - - Yes 11. Core pads welds - Yes Yes Yes 12. CRDM and Thermocouple Nozzle Connections - - Yes - 13. RVHVS and RVLIS Nozzle Connections - - Yes - 14. CRDM Nozzle to Integrated Latch Housing Weld Yes - Yes - (a) RT - Radiographic; UT - Ultrasonic; PT - Dye penetrant; MT - Magnetic particle (b) UT of cladding bond-to-base metal (c) UT after hydrotest DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 5.5-1 REACTOR COOLANT PUMP DESIGN PARAMETERS (BOTH UNITS) Design pressure, psig 2,485 Design temperature, F 650 Capacity per pump, gpm 88,500 Developed head, ft 277 NPSH required, ft 170 Suction temperature, F 545 RPM nameplate rating 1,180 Discharge nozzle, ID, in. 27-1/2 Suction nozzle, ID, in. 31 Overall unit height, ft-in. 28-6.7 Water volume, ft3 56 Moment of inertia, ft-lb 82,000 Weight, dry, lb 188,200 Motor Type AC induction single-speed, air-cooled Power, HP 6,000 Voltage, volts 11,500 Insulation class B or H Thermalastic Epoxy Phase 3 Starting Current, amps 1,700 Input (hot reactor coolant), kW 4,371 Input (cold reactor coolant), kW 5,790 Seal water injection, gpm 8 Seal water return, gpm 3
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 5.5-2 REACTOR COOLANT PUMP QUALITY ASSURANCE PROGRAM RT(a) UT(a) PT(a) MT(a) Castings Yes - Yes - Forgings
- 1. Main shaft - Yes Yes -
- 2. Main studs - Yes Yes -
- 3. Flywheel (rolled plate) - Yes Yes (for the bore)
Weldments
- 1. Circumferential Yes - Yes -
- 2. Instrument connections - - Yes -
(a) RT - Radiographic UT - Ultrasonic PT - Dye penetrant MT - Magnetic particle
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.5-3 Sheet 1 of 2 Revision 19 May 2010 STEAM GENERATOR DESIGN DATA(a) Unit 1 Unit 2 Number of steam generators 4 4 Design pressure, reactor coolant/steam, psig 2,485/1085 2,485/1085
Reactor coolant hydrostatic test pressure (tube side-cold), psig 3,106 3,106
Design temperature, reactor coolant/steam, F 650/600 650/600 Reactor coolant flow, (per SG) lb/hr 33.2 x 106 33.5 x 106 Total heat transfer surface area, ft2 54,240 54,240 Heat transferred, Btu/hr 2,920 x 106 2,920 x 106 Steam conditions at full load Outlet nozzle: Steam flow, lb/hr 3.64 x 106 3.7 x 106 Steam temperature, F 519 519 Steam pressure, psia 805(c) 805(c) Maximum moisture carryover, wt % 0.05 0.05 Feedwater, temperature, F 435 435 Overall height, ft-in. 68-2 68-2 Shell OD, upper/lower, in. 175-3/8 /135-3/8 175-3/8/135-3/8 Number of U-tubes(b) 4,444 4,444 U-tube outer diameter, in. 0.75 0.75 Tube wall thickness, (minimum), in. 0.043 0.043 Number of manways/ID, in. 4/18 4/18 Number of handholes/ID, in. 4/6 4/6 Number of inspection ports/ID, in. 8/2.5 8/2.5 Number of tube upper bundle inspection ports/ID, in. 2/4 2/4 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.5-3 Sheet 2 of 2 Revision 19 May 2010 Rated Load Unit 1 Unit 2 Reactor coolant water volume, ft3 1016 1016 Primary side fluid heat content, Btu 26.0 x 107 26.0 x 107 Secondary side water volume, ft3 2100 2100 Secondary side steam volume, ft3 3700 3700 Secondary side fluid heat content, Btu 6.0 x 107 6.0 x 107 (a) Quantities are for each steam generator. (b) The actual number of "active" tubes (i.e., those contributing to the heat transfer surface area) may be less than the number given due to the plugging and/or removal of some tubes. (c) Warranted exit pressure at SG end-of-life (e.g., 10% SGTP and design fouling conditions). DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.5-5 Sheet 1 of 2 Revision 19 May 2010 STEAM GENERATOR QUALITY ASSURANCE PROGRAM (BOTH UNITS) RT(a) UT(a) PT(a) MT(a) ET(a) Tubesheet
- 1. Forging - Yes - Yes -
- 2. Cladding - Yes(b) Yes - - Channel Head
- 1. Forging Yes - Yes -
- 2. Cladding - Yes Yes - -
Secondary Shell and Head
- 1. Forgings - Yes - Yes -
Tubes - Yes - - Yes Nozzles (Forging) - Yes - Yes - Weldments 1. Shell, circumferential Yes Yes (d) - Yes - 2. Cladding, (channel head- tubesheet joint cladding restoration) - Yes Yes - - 3. Feedwater nozzle to shell Yes - - Yes -
- 4. Support brackets - - - Yes -
- 5. Tube to tubesheet - - Yes - -
- 6. Instrument connections (primary and secondary) - - - Yes - 7. Temporary attachments after removal - - - Yes -
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.5-5 Sheet 2 of 2 Revision 19 May 2010 RT(a) UT(a) PT(a) MT(a) ET(a) Weldments (Cont'd)
- 8. After hydrostatic test (all welds where accessible) - - - Yes - 9. Primary nozzle safe ends Yes Yes Yes - - 10. Steam nozzle safe ends Yes - - -
- 11. Feedwater nozzle safe ends Yes Yes Yes - - (a) RT - Radiographic UT - Ultrasonic PT - Dyepenetrant MT - Magnetic particle ET - Eddy current
(b) Flat surfaces only
(c) Weld deposit areas only (d) Welds subject to ASME Section XI ISI
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.5-6 Revision 16 June 2005 REACTOR COOLANT PIPING DESIGN PARAMETERS (BOTH UNITS) Reactor inlet piping, ID, in. 27.5
Reactor inlet piping, nominal/min wall thickness, in. 2.38/2.22
Reactor outlet piping, ID, in. 29
Reactor outlet piping, nominal/min wall thickness, in. 2.50/2.33
Coolant pump suction piping, ID, in. 31
Coolant pump suction piping, nominal/min wall thickness, in. 2.66/2.50
Pressurizer surge line piping, Unit 1/Unit 2 ID, in. 11.50/11.19
Pressurizer surge line piping, Unit 1/Unit 2 nominal wall thickness, in. 1.25/1.41
Water volume, all loops and surge line, ft3 1500 Design/operating pressure, psig 2485/2235 Design temperature, F 650 Design temperature (pressurizer surge line) F 680 Design pressure, pressurizer relief line From pressurizer to safety valve, 2485 psig, 650 F Design temperature, pressurizer relief lines From safety valve to pressurizer relief tank, 600 psig, 600F
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.5-7 Revision 11 November 1996 REACTOR COOLANT PIPING QUALITY ASSURANCE PROGRAM (BOTH UNITS) RT(a) UT(a) PT(a) Fittings and Pipe (Castings) Yes - Yes Fittings and Pipe (Forgings) - Yes Yes Weldments 1. Circumferential Yes - Yes
- 2. Nozzle to piperun (except no RT for nozzles less than 4 inches) Yes - Yes
- 3. Instrument connections - - Yes (a) RT - Radiographic UT - Ultrasonic PT - Dye penetrant
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.5-8 Revision 14 November 2001 DESIGN BASES FOR RESIDUAL HEAT REMOVAL SYSTEM OPERATION (BOTH UNITS) Residual heat removal system startup No sooner than 4 hours after reactor shutdown Number of Trains in Operation 2
Reactor coolant system initial pressure, psig 390 Reactor coolant system initial temperature, F 350 Component cooling water design temperature, F 95 Cooldown time, hours after reactor shutdown <20 Reactor coolant system temperature at end of cooldown, F 140 Decay heat generation used in cooldown analysis, Btu/hr 75.5 x 106
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.5-9 Revision 11 November 1996 RESIDUAL HEAT REMOVAL SYSTEM CODES AND CLASSIFICATIONS (BOTH UNITS) Components Code Residual heat removal pump ASME P&V(a), Class II Residual heat exchanger (tube side) ASME III(b), Class C (shell side) ASME VIII(c) Piping(d) ANSI B31.7 ANSI B31.1
Valves ANSI B16.5(e)
(a) Draft ASME Code for Pumps and Valves for Nuclear Power, November 1968 Edition.
(b) ASME III - American Society of Mechanical Engineers, Boiler and Pressure Vessel Code, Section VIII, Pressure Vessels, 1968 Edition. (c) ASME VIII - American Society of Mechanical Engineers, Boiler and Pressure Vessel Code, Section VIII, Pressure Vessels, 1968 Edition. (d) American National Standards Institute, B31.7 Class II - 1969 with 1970 Addendum for safety-related portions. American National Standards Institute, B31.1-1967 with 1970 Addendum for nonsafety- related portions. (e) American National Standards Institute, B16.5, Steel Pipe Flanges and Flanged Fittings, 1968 Edition. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.5-10 Sheet 1 of 2 Revision 12 September 1998 RESIDUAL HEAT REMOVAL SYSTEM COMPONENT DATA (BOTH UNITS) Residual Heat Removal Pump Number 2 (per unit)
Design pressure, psig 700 Design temperature, F 400 Design flow, gpm 3000
Design head, ft 350
Net positive suction head, ft Available 36.3 Required 11.0
Residual Heat Exchanger
Number 2 (per unit)
Design heat removal capacity, Btu/hr 34.15 x 106 Tube-side Shell-side Design pressure, psig 630 150 Design temperature, F 400 250 Design flow, lb/hr 1.48 x 106 2.48 x 106 Inlet temperature, F 137 95 Outlet temperature, F 114 108.8 Material Austenitic stainless steel Carbon steel
Fluid Reactor coolant Component cooling water DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.5-10 Sheet 2 of 2 Revision 12 September 1998 Piping and Valves Design pressure, psig 2485(a) Design temperature, F 650(a) Design pressure, psig 700 Design temperature, F 400 Suction side relief valve
Relief pressure, psig 450 Relief capacity, gpm 900
Discharge side relief valve
Relief pressure, psig 600 Relief capacity, gpm 20
Material Austenitic stainless steel
(a) Valves and piping that are part of the reactor coolant pressure boundary.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.5-11 Revision 18 October 2008 RECIRCULATION LOOP LEAKAGE Type of Leakage Control and Unit Leakage to Leakage to No. of Leakage Rate Atmosphere, Drain Tank, Items Units Used in the Analysis cc/hr cc/hr Residual heat removal 2 Mechanical seal 20 0 pumps (low-head safety with leakoff of injection) one drop/min
Centrifugal charging pump 2 Same as residual 40 0 (CCP1 and CCP2) heat removal pump
Safety injection 2 Same as residual 40 0 heat removal pump Flanges:
- a. Pump 12 Gasket-adjusted to 0 0 zero leakage following any test
- b. Valves bonnet body 40 10 drops/min/flange 1200 0 (larger than 2 in.) used in analysis (30 cc/hr)
- c. Control valves 6 180 0
- d. Heat exchangers 2 240 0
Valves - stem leakoffs 40 Backseated, double 0 40 packing with leak-off of 1 cc/hr/in. stem diameter
Miscellaneous small 50 Flanged body packed 50 0 valves stems - 1 drop/min used
Miscellaneous large Double-packing 40 0 valves (larger than 2 in.) 1 cc/hr/in. stem diameter
TOTALS 1910 40
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.5-12 Revision 12 September 1998 PRESSURIZER DESIGN DATA Design/operating pressure, psig 2485/2235 Hydrostatic test pressure (cold), psig 3107 Design/operating temperature, F 680/653 Water volume, full power, ft3 1080 Steam volume, full power, ft3 720 Surge line nozzle diameter, in. 14 Shell ID, in. 84 Electric heaters capacity, kW(a) 1800 Heatup rate of pressurizer using heaters only, F/hr 55 Maximum spray rate, gpm 800 (a) Initial heater capacity limit; 150 kW is the minimum required capacity for each backup group that can be supplied by emergency vital power (2 groups). DCPP UNITS 1 & 2 FSAR UPDATE TABLE 5.5-13 Revision 11 November 1996 PRESSURIZER QUALITY ASSURANCE PROGRAM (BOTH UNITS) Heads RT(a) UT(a) PT(a) MT(a) ET(a)
- 1. Plates Yes - - Yes -
- 2. Cladding - - Yes - -
Shell
- 1. Plates - Yes - Yes -
- 2. Cladding - - Yes - -
Heaters
- 1. Tubing(b) - Yes Yes - -
- 2. Center of element - - - - Yes
Nozzle - Yes Yes - - Weldments
- 1. Shell, longitudinal Yes - - Yes -
- 2. Shell, circumferential Yes - - Yes -
- 3. Cladding - - Yes - -
- 4. Nozzle safe end (forging) Yes - Yes - -
- 5. Instrument connections - - Yes - -
- 6. Support skirt - - - Yes -
- 7. Temporary attachments after removal - - - Yes -
- 8. All welds and plate heads after - - - Yes - hydrostatic test
Final Assembly
- 1. All accessible exterior surfaces - - - Yes -
after hydrostatic test (a) RT - Radiographic; UT - Ultrasonic; PT - Dye penetrant; MT - Magnetic particle; ET - Eddy current (b) Or a UT and ET DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 5.5-14 PRESSURIZER RELIEF TANK DESIGN DATA Design pressure, psig 100 Rupture disk release pressure, psig 100 5% Design temperature, F 340 Total rupture disk relief capacity 1.6 x 106 lb/hr at 100 psig
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 5.5-15 REACTOR COOLANT SYSTEM BOUNDARY VALVE DESIGN PARAMETERS Design pressure, psig 2485
Nominal operating pressure, psig 2235
Preoperational plant hydrotest, psig 3107 Design temperature, F 650 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 5.5-16 PRESSURIZER VALVES DESIGN PARAMETERS Pressurizer Spray Control Valves Number 2
Design pressure 2485 Design temperature, F 650 Design flow for valves full open, each, gpm 400
Pressurizer Safety Valves Number 3
Maximum relieving capacity, ASME rated flow, lb/hr 420,000 (per valve)
Set pressure, psig 2485
Fluid Saturated steam
Backpressure: Normal, psig 3 to 5 Expected during discharge, psig 350
Pressurizer Power Relief Valves Number 3
Design pressure, psig 2485 Design temperature, F 650 Relieving capacity at 2,350 psig, lb/hr (per valve) 210,000
Fluid Saturated steam DCPP UNITS 1 & 2 FSAR UPDATE Revision 20 November 2011 TABLE 5.5-17 REACTOR VESSEL HEAD VENT SYSTEM EQUIPMENT DESIGN PARAMETERS Valves Number (includes six manual valves) 10 Design pressure, psig 2485 Design temperature, °F 650 Piping Vent line, nominal diameter, in. 1
Design pressure, psig 2485 Design temperature, °F 620 Revision 11 November 1996FIGURE 5.1-2 PUMP HEAD - FLOW CHARACTERISTICS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 5.2-1 IDENTIFICATION AND LOCATION OF BELTLINE REGION MATERIALS FOR THE REACTOR VESSEL UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 5.2-2 REACTOR COOLANT LOOP MODEL FIGURE 5.2-3 THRUST RCL MODEL SHOWING HYDRAULIC FORCE LOCATIONS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010 Revision 11 November 1996FIGURE 5.2-4 IDENTIFICATION AND LOCATION OF BELTLINE REGION MATERIAL FOR THE REACTOR VESSEL UNIT 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 5.2-7 LOWER BOUND FRACTURE TOUGHNESS A533 GRADE B CLASS 1 (REF WCAP-7623) UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 21 September 2013 Revision 11 November 1996 FIGURE 5.2-8 TRANSITION TEMPERATURE CORRELATION BETWEEN Kld (DYNAMIC) AND Cv FOR A SERIES OF UNIRRADIAYED STEELS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 5.2-9 CONTAINMENT MONITOR RESPONSE TIMEVERSUS PRIMARY LEAKRATE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 5.2-10 AIR EJECTOR RADIOGAS MONITOR RESPONSE TIME VERSUS PRIMARY LEAKRATE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 5.2-11 BLOWDOWN LIQUID MONITOR RESPONSETIME VERSUS PRIMARY LEAKRATE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 5.2-12 CONTAINMENT COOLING WATER LIQUID MONITOR RESPONSE TIME VERSUS PRIMARY LEAKRATE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 5.2-13 CONTAINMENT AREA MONITOR RESPONSETIME VERSUS PRIMARY LEAKRATE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE 0.0010.010.11101000001101001,00010,000100,000COUNTS/(MINUTE)2PRIMARY LEAKRATE (GPM)2510-310-110-2 0.1% Fuel Defect 0.2% Fuel Defects 1% Fuel Defects Revision 19 May 2010FIGURE 5.2-14 CONTAINMENT RADIOGAS MONITOR COUNT RATE VERSES PRIMARY LEAKRATE AFTER EQUILIBRIUM UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 5.2-15 CONTAINMENT PARTICULATE MONITOR COUNT RATE VERSUS PRIMARY LEAKRATE AFTER EQUILIBRIUM UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 5.2-16 SURVEILLANCE CAPSULE ELEVATION VIEW UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 5.2-17 SURVEILLANCE CAPSULE PLAN VIEW UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 5.2-18 SURVEILLANCE CAPSULE ELEVATION VIEWUNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 5.2-19 SURVEILLANCE CAPSULE PLAN VIEW UNIT 2 DIABLO CANYON SITE FSAR UPDATE 5305405505605705805906006106200102030405060708090100% POWERTEMPERATURE OFTHOT LEGTAVERAGETCOLD LEG NOTE 1: UNIT 1 AND UNIT 2 DESIGN VALUE RANGES FOR FULL POWER. NOTE 2: THE PLOTS SHOWN ARE FOR THE MAXIMUM THOT LEG, TAVERAGE, AND TCOLD LEG TEMPERATURES AT FULL POWER.
Revision 21 September 2013FIGURE 5.3-1 HOT LEG, COLD LEG, AND AVERAGE REACTOR COOLANT LOOP TEMPERATURE AS A FUNCTION OF PERCENT FULL POWERUNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE UNIT 1 NOTE 1 598.3ºF to 610.1ºF UNIT 2 598.1ºF to 610.1ºF UNIT 1 565.0ºF to 577.3ºF UNIT 2 565.0ºF to 577.6ºF UNIT 1 531.7ºF to 544.5ºF UNIT 2 531.9ºF to 545.1ºF NOTE 2 Revision 20 November 2011FIGURE 5.4-1 REACTOR VESSEL UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 20 November 2011FIGURE 5.4-2 REACTOR VESSEL UNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 5.5-1 REACTOR COOLANT CONTROLLED LEAKAGE PUMP UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 5.5-2 REACTOR COOLANT PUMP ESTIMATED PERFORMANCE CHARACTERISTICS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 5.5-3 REACTOR COOLANT PUMP SPOOL PIECE AND MOTOR SUPPORT STAND UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008 FIGURE 5.5-4 WESTINGHOUSE DELTA 54 REPLACEMENT STEAM GENERATOR UNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 5.5-8 PRESSURIZER UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 5.5-9 REACTOR SUPPORT UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 5.5-10 STEAM GENERATOR AND REACTOR COOLANT PUMP SUPPORTS
- Crossover pipe restraints Inactive.
FIGURE 5.5-11 COMPONENT SUPPORTS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008 Revision 11 November 1996 FIGURE 5.5-12 PRESSURIZER SUPPORT UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE
FIGURE 5.5-14 SCHEMATIC FLOW DIAGRAM OF THE REACTOR VESSEL HEAD VENT SYSTEM UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 20 November 2011 UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 5.5-18 SEVEN NOZZLE RSG OUTLET FLOW RESTRICTOR Revision 19 May 2010 DCPP UNITS 1 & 2 FSAR UPDATE
APPENDIX 5.5A CAPABILITY OF MAIN STEAM ISOLATION AND CHECK VALVES TO WITHSTAND CLOSURE LOADS FOLLOWING A POSTULATED MAIN STEAM LINE BREAK
Prepared by Westinghouse Electric Corporation DCPP UNITS 1 & 2 FSAR UPDATE 5.5A-1 Revision 15 September 2003 Appendix 5.5A CAPABILITY OF MAIN STEAM ISOLATION AND CHECK VALVES TO WITHSTAND CLOSURE LOADS FOLLOWING A POSTULATED MAIN STEAM LINE BREAK 5.5A.1 SUMMARY During the postulated event of a pipe rupture in the main steam system, the check and isolation valves close under loading conditions that are much more severe than those encountered during normal plant operation. The analyses presented here demonstrate that both the main steam line check and isolation valves are capable of successfully performing their functions during this event. 5.5A.2 RESULTS Impact energy levels for the most severe pipe rupture conditions are given in Table 5.5A-1. The highest level is 0.888 x 106 in-lb for the isolation valve disc. The disc is capable of absorbing energy levels exceeding twice this predicted value without developing excessive deflections. The check valve disc, which has the same capability, is subjected to lower energy levels.
The bearing stress at the valve seat is determined to be 62.2 ksi resulting from the disc-to-seat reaction. A typical allowable stress for this type of application ranges from 150 to 250 ksi. For the most part, the tail link is not stressed beyond the elastic limit; where the elastic limit is exceeded, the incursion into the plastic range is slight. The maximum tail link deflection is determined to be 0.0425 in. This deflection will not prevent proper valve closure.
The maximum shearing stress developed in the rockshaft is 21.5 ksi, well within the elastic range of the material. The deflection in the rockshaft will be insignificant. 5.5A.3 BASIC CRITERIA AND ASSUMPTIONS The following criteria and assumptions were used in the analysis:
(1) The initial angle of the isolation and check valve discs are 80 and 70° from the closed position, respectively. (2) The postulated break locations that were selected will result in the most severe disc impact energy for each valve. Postulated break locations are established and defined in Reference 1, page 3.6A-41.
DCPP UNITS 1 & 2 FSAR UPDATE 5.5A-2 Revision 15 September 2003 (3) The postulated break type that will result in the most severe disc impact energy is used. Types of breaks considered include circumferential, longitudinal, and crack as defined in Reference 2. The circumferential break is used in this analysis. (4) The ruptured pipe is assumed to separate to full flow area instantaneously. A discharge coefficient of 1 is conservatively assumed for flow through the break area. (5) It is conservatively assumed that there is no obstruction to discharging flow from the break that would prevent maximum blowdown flow from being developed. (6) Isolation valve trip is conservatively assumed to occur 0.5 seconds (minimum) after a pipe rupture. Evaluation of larger time delays between pipe rupture and disc release shows that the shorter time is a more severe condition on the valve; and therefore, the shortest possible release time is used in the analysis. (7) It is assumed that there is no frictional resistance to the valve rockshaft rotation; and that the pneumatic actuators offer no resistance to closure after a trip signal. (8) Initial steam conditions used in the analysis are as follows: Hot Standby: Line pressure = 1020 psia Line flow = 0 lb/sec Full Load: Line pressure = 800 psia Line flow = 1010 lb/sec
Under a postulated pipe rupture, the maximum flow through the isolation valve occurs under a plant hot standby condition. This results in a maximum acceleration of the valve disc. For the check valve, the plant operating condition that will result in the maximum disc impact energy is full load. 5.5A.4 ANALYSIS 5.5A.4.1 Maximum Disc Impact Energy The check valve computer program used to solve the equations of motion for the valve disc to determine angular velocity and energy at impact is a modification of RELAP 3(3), the AEC's presently accepted loss-of-coolant accident (LOCA) analysis program. The modification consists of incorporating the equations of motion for the valve disc.
The equations incorporated into the program to mathematically describe the valve disc motion include the equations of motion, valve pressure drop as a function of flow rate, DCPP UNITS 1 & 2 FSAR UPDATE 5.5A-3 Revision 15 September 2003 actuator return spring forces, and valve flow area as a function of disc position. Because of the similarity in construction, these equations are the same (except for spring forces) for both the isolation and check valves. The isolation valve calculations are initiated following a trip signal. For the check valve, initiation is when the flow reverses in the pipe creating forces to close the disc.
The disc angular acceleration and velocity and the maximum disc impact energy are calculated as a function of the torque acting on the disc. This torque is comprised of gravitational, fluid flow, actuator, frictional, and viscous components. In this analysis, the frictional and viscous torque components act to delay the closure and thus are conservatively neglected. The gravity torque is a function of disc position and the actuator torque is a function of spring displacement. The fluid flow torque is caused by pressure differential across the disc. The pressure differential across the disc, in the non-choking flow region, is the frictional pressure drop across the disc calculated from the valve loss coefficients established by the valve manufacturer (Schutte and Koerting Company). To determine the pressure drop across the disc in the choking flow region, a static pressure difference in volumes upstream and downstream of the disc is used. 5.5A.5 COMPONENT ANALYSIS 5.5A.5.1 Load Generation The loads acting on the valve components are generated by the disc angular velocity, disc angular acceleration, and the kinetic energy developed in the disc at instant of impact. These quantities are given in Table 5.5A-1. The maximum of these values for the isolation of check valves were used in the analysis. 5.5A.5.2 Disc Analysis Analysis of disc closure is accomplished by an equivalent static method whereby the disc is loaded with a pseudoloading which approximates the inertia forces acting on the disc. The magnitude of this loading is varied and a relationship between the strain energy developed in the disc and the pseudoloading is established. The maximum displacements experienced by the disc are taken to correspond to the point at which the strain energy developed under the pseudoloading equals the kinetic energy at instant of impact. 5.5A.5.3 Valve Body Seat Area Analysis The valve body seat area is analyzed by determining the reaction of the valve seat due to the impact of the disc. This reaction is found from the load-energy relationship derived in the analysis for the valve disc as described above. The load corresponding
to the initial kinetic energy in the disc is determined from this load-energy relationship. The reaction at the valve disc is determined by dividing this load by the circumferential area of the valve seat. DCPP UNITS 1 & 2 FSAR UPDATE 5.5A-4 Revision 15 September 2003 5.5A.5.4 Tail Link Analysis The critical loading conditions on the tail link occur during travel when the tail link is acted upon by centrifugal forces. In this mode the tail link structure may be considered statically determinate with the centrifugal force resultant applied at the rock shaft and reacted at the disc connection. The maximum loads in the travel mode occur just prior to disc impact, and since the tail link structure is taken as statically determinate, the moment and force resultants throughout for this condition are determined from equilibrium considerations. With the axial and moment resultants known throughout the tail link, deflections are determined by dividing the structure into an appropriate number of sections, then determining and summing the deflections of these individual sections. 5.5A.5.5 Rockshaft Analysis The design loading condition occurs just prior to valve closure when the rockshaft sees the peak centrifugal forces developed in the tail link. These centrifugal forces are applied as shearing forces to the rockshaft. No coupling between this loading condition and the torque carried by the rockshaft in the open position is considered, since this torque diminishes as the valves close and is zero at instant of valve closure. 5.5A.6 REFERENCES 1. Nuclear Services Corporation, Evaluation for Effects of Postulated Pipe Break Outside Containment for Diablo Canyon Unit 1, Revision 2, June 26, 1974.
- 2. Letter (Docket Nos. 50-275 and 50-323) from A. Giambusso of the U.S. Atomic Energy Commission to F.T. Searls of the Pacific Gas and Electric Company, dated December 18, 1972, including the attachment "General Information Required for Consideration of the Effects of Piping System Break Outside Containment."
- 3. W.H. Rettig, et al, "RELAP 3 - A Computer Program for Reactor Blowdown Analysis," IN-1321, June 1970. Also Supplement of June 1971.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 15 September 2003 TABLE 5.5A-1 SUMMARY OF RESULTS UNDER PIPE RUPTURE CONDITIONS Check Valve Isolation Valve Velocity at disk impact, rad/sec 74.7 77.6
Acceleration at disk impact, rad/sec2 6373 5474
Energy at disk impact, 106 in-lb 0.817 0.888 Maximum flowrate through valve, lb/sec 2767 3220
DCPP UNITS 1 & 2 FSAR UPDATE i Revision 21 September 2013 Chapter 6 ENGINEERED SAFETY FEATURES CONTENTS Section Title Page 6.1 GENERAL 6.1-1
6.1.1 Introduction 6.1-1
6.1.2 Summary Description 6.1-2
6.1.3 References 6.1-5
6.2 CONTAINMENT SYSTEMS 6.2-1
6.2.1 Containment Functional Design 6.2-1 6.2.1.1 Design Bases 6.2-1 6.2.1.2 Testing and Inspection 6.2-6 6.2.1.3 Instrumentation Requirements 6.2-7 6.2.1.4 Materials 6.2-7
6.2.2 Containment Heat Removal Systems 6.2-8 6.2.2.1 Design Bases 6.2-8 6.2.2.2 System Design 6.2-9 6.2.2.3 Design Evaluation 6.2-16 6.2.2.4 Tests and Inspections 6.2-23 6.2.2.5 Instrumentation Requirements 6.2-24 6.2.2.6 Materials 6.2-24
6.2.3 Containment Air Purification and Cleanup Systems 6.2-25 6.2.3.1 Design Bases 6.2-25 6.2.3.2 System Design 6.2-26 6.2.3.3 Design Evaluation 6.2-29 6.2.3.4 Tests and Inspections 6.2-43 6.2.3.5 Instrumentation Application 6.2-45 6.2.3.6 Materials 6.2-45
6.2.4 Containment Isolation System 6.2-45 6.2.4.1 Design Bases 6.2-46 6.2.4.2 System Design 6.2-51 6.2.4.3 Design Evaluation 6.2-54 6.2.4.4 Tests and Inspections 6.2-54 6.2.4.5 Materials 6.2-55 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 6 CONTENTS (Continued) Section Title Page ii Revision 21 September 2013 6.2.5 Combustible Gas Control in Containment 6.2-56 6.2.5.1 Design Bases 6.2-57 6.2.5.2 System Design 6.2-58 6.2.5.3 Design Evaluation 6.2-61 6.2.5.4 Testing and Inspections 6.2-67 6.2.5.5 Instrumentation Requirements 6.2-67 6.2.5.6 Materials 6.2-68
6.2.6 References 6.2-68
6.2.7 Reference Drawings 6.2-71
6.3 EMERGENCY CORE COOLING SYSTEM 6.3-1
6.3.1 Design Bases 6.3-1 6.3.1.1 Range of Coolant Ruptures and Leaks 6.3-1 6.3.1.2 Fission Product Decay Heat 6.3-1 6.3.1.3 Reactivity Required for Cold Shutdown 6.3-1 6.3.1.4 Capability to Meet Functional Requirements 6.3-2 6.3.2 System Design 6.3-6 6.3.2.1 Schematic Piping and Instrumentation Diagram 6.3-6 6.3.2.2 Equipment and Component Descriptions 6.3-6 6.3.2.3 Applicable Codes and Classifications 6.3-13 6.3.2.4 Material Specifications and Compatibility 6.3-13 6.3.2.5 Design Pressures and Temperatures 6.3-13 6.3.2.6 Coolant Quantity 6.3-14 6.3.2.7 Pump Characteristics 6.3-14 6.3.2.8 Heat Exchanger Characteristics 6.3-14 6.3.2.9 ECCS Flow Diagrams 6.3-14 6.3.2.10 Relief Valves and Vents 6.3-15 6.3.2.11 System Reliability 6.3-15 6.3.2.12 Protection Provisions 6.3-15 6.3.2.13 Provisions for Performance Testing 6.3-15 6.3.2.14 Net Positive Suction Head 6.3-16 6.3.2.15 Control of Accumulator Motor-Operated Isolation Valves 6.3-17 6.3.2.16 Motor-operated Valves and Controls 6.3-18 6.3.2.17 Manual Actions 6.3-18 6.3.2.18 Process Instrumentation 6.3-18 6.3.2.19 Materials 6.3-18
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 6 CONTENTS (Continued) Section Title Page iii Revision 21 September 2013 6.3.3 Performance Evaluation 6.3-18 6.3.3.1 Evaluation Model 6.3-18 6.3.3.2 ECCS Performance 6.3-18 6.3.3.3 Alternate Analysis Methods 6.3-25 6.3.3.4 Fuel Rod Perforations 6.3-25 6.3.3.5 Effects of ECCS Operation on the Core 6.3-25 6.3.3.6 Use of Dual Function Components 6.3-25 6.3.3.7 Lag Times 6.3-27 6.3.3.8 Limits on System Parameters 6.3-28
6.3.4 Tests and Inspections 6.3-28 6.3.4.1 Quality Control 6.3-29 6.3.4.2 Preoperational System Tests 6.3-29 6.3.4.3 Periodic Component Testing 6.3-32 6.3.4.4 Testing Following Completion of Modifications 6.3-32
6.3.5 Instrumentation Requirements 6.3-33 6.3.5.1 Temperature Indication 6.3-33 6.3.5.2 Pressure Indication 6.3-34 6.3.5.3 Flow Indication 6.3-34 6.3.5.4 Level Indication 6.3-35 6.3.5.5 Valve Position Indication 6.3-35 6.3.5.6 Subcooling Meter 6.3-36
6.3.6 References 6.3-36
6.4 HABITABILITY SYSTEMS 6.4-1
6.4.1 Control Room 6.4-1 6.4.1.1 Habitability Systems Functional Design 6.4-1 6.4.1.2 Design Bases 6.4-1 6.4.1.3 System Design 6.4-3 6.4.1.4 Design Evaluation 6.4-3 6.4.1.5 Testing and Inspection 6.4-4 6.4.1.6 Instrumentation Requirements 6.4-4
6.4.2 Technical Support Center 6.4-5 6.4.2.1 Habitability Systems Functional Design 6.4-5 6.4.2.2 Design Bases 6.4-5 6.4.2.3 System Design 6.4-6 6.4.2.4 Design Evaluation 6-4-7 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 6 CONTENTS (Continued) Section Title Page iv Revision 21 September 2013 6.4.2.5 Testing and Inspection 6-4-7 6.4.2.6 Instrumentation Requirements 6.4-7
6.4.3 References 6.4-7
6.5 AUXILIARY FEEDWATER SYSTEM 6.5-1
6.5.1 Design Bases 6.5-1 6.5.1.1 Design Conditions 6.5-1 6.5.1.2 Design Bases Summary 6.5-4
6.5.2 System Design 6.5-5 6.5.2.1 Equipment and Component Descriptions 6.5-5 6.5.2.2 Applicable Codes and Classifications 6.5-7
6.5.3 Design Evaluation 6.5-8 6.5.3.1 Loss of Main Feedwater 6.5-8 6.5.3.2 Rupture of Main Feedwater Pipe 6.5-9 6.5.3.3 Rupture of Main Steam Pipe 6.5-10 6.5.3.4 Rupture of a Steam Supply Line to the Turbine Driven Aux Feedwater Pump 6.5-10 6.5.3.5 Plant Cooldown 6.5-10
6.5.4 Tests and Inspections 6.5-12
6.5.5 Instrumentation Requirements 6.5-12
6.5.6 References 6.5-13
6.5.7 Reference Drawings 6.5-14
DCPP UNITS 1 & 2 FSAR UPDATE v Revision 21 September 2013 Chapter 6 TABLES Table Title 6.2-1 Deleted in Revision 18.
6.2-2 Deleted in Revision 18.
6.2-3 Deleted in Revision 18.
6.2-4 Deleted in Revision 18.
6.2-5 Deleted in Revision 11
6.2-6 Deleted in Revision 18.
6.2-7 Deleted in Revision 18.
6.2-8 Deleted in Revision 11
6.2-9 Deleted in Revision 11
6.2-10 Deleted in Revision 11 6.2-11 Deleted in Revision 18. 6.2-12 Deleted in Revision 18.
6.2-13 Deleted in Revision 18.
6.2-14 Containment Pressure Differential - Elements for Loop Compartment and Pressurizer Enclosure Analysis Model 6.2-15 Containment Pressure Differential - Flowpaths for Loop Compartment and Pressurizer Enclosure Analysis Model 6.2-16 Containment Pressure Differential - Loop Compartment Analysis - Mass and Energy Release Rates. Double-ended Severance of a Reactor Coolant Hot Leg 6.2-17 Containment Pressure Differential - Pressurizer Enclosure Analysis - Mass and Energy Release Rates. Pressurizer Spray Line Rupture DCPP UNITS 1 & 2 FSAR UPDATE Chapter 6 TABLES (Continued) Table Title vi Revision 21 September 2013 6.2-18 Containment Pressure Differential - Elements for Reactor Cavity Analysis Model 6.2-19 Containment Pressure Differential - Flowpath Data for Reactor Cavity Analysis Model 6.2-20 Containment Pressure Differential - Reactor Cavity Analysis - Total Mass and Energy Release Rates 6.2-21 Containment Pressure Differential - Reactor Cavity Analysis - Calculated Peak Pressures 6.2-22 Containment Pressure Differential - Elements for Pipe Annulus Analysis Model 6.2-23 Containment Pressure Differential - Pipe Annulus Analysis - Mass and Energy Release Rates. Cold Leg Break Inside Pipe Annulus 6.2-24 Containment Pressure Differential - Compartment Pressures 6.2-25 Containment Heat Removal Systems Design Code Requirements
6.2-26 Containment Heat Removal Systems Design Parameters
6.2-27 Single Failure Analysis - Containment Heat Removal Systems
6.2-28 Deleted in Revision 18.
6.2-29 Spray Additive System Design Parameters
6.2-30 Spray Additive System - Codes Used in System Design
6.2-31 Deleted in Revision 11
6.2-32 Deleted in Revision 11
6.2-33 Deleted in Revision 11
6.2-34 Deleted in Revision 11
6.2-35 Deleted in Revision 11 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 6 TABLES (Continued) Table Title vii Revision 21 September 2013 6.2-36 Parameters and Results for Spray Iodine Removal Analysis During Injection Phase Operation 6.2-37 Spray Fall Heights in the Containment
6.2-38 Spray Additive System Single Failure Analysis
6.2-39 Containment Piping Penetrations and Valving
6.2-40 Operating Conditions for Containment Isolation
6.2-41 Post-LOCA Temperature Transient Used for Aluminum and Zinc Corrosion
6.2-42 Parameters Used to Determine Hydrogen Generation
6.2-43 Core Fission Product Energy After Operation with Extended Fuel Cycles
6.2-44 Fission Product Decay Deposition in Sump Solution 6.2-45 Summary of Hydrogen Accumulation Data
6.2-46 Deleted in Revision 2
6.2-47 Containment Reflective Insulation
6.2-48 Containment Conventional Insulation
6.2-49 Deleted in Revision 11
6.2-50 Deleted in Revision 11
6.2-51 Deleted in Revision 8
6.2-52 Deleted in Revision 8
6.2-53 Deleted in Revision 11
6.2-54 Deleted in Revision 11
6.2-55 Maximum Pressure Differential Across Steam Generator
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 6 TABLES (Continued) Table Title viii Revision 21 September 2013 6.3-1 Emergency Core Cooling System - Component Parameters 6.3-2 Emergency Core Cooling System - Design Code Requirements
6.3-3 Materials of Construction - Emergency Core Cooling System Components
6.3-4 Deleted in Revision 11A
6.3-5 Safety Injection to Recirculation Mode; Sequence and Timing of Manual Changeover 6.3-6 Normal Operating Status of Emergency Core Cooling System Components for Core Cooling 6.3-7 Sequence and Delay Times for Startup of ECCS
6.3-8 Emergency Core Cooling System Shared Functions Evaluation 6.3-9 Maximum Potential Recirculation Loop Leakage External to Containment 6.3-10 ECCS Relief Valve Data
6.3-11 Net Positive Suction Heads for Post-DBA Operational Pumps
6.3-12 ECCS Motor-operated Valves with Electric Power Removed During Normal Operation 6.5-1 Criteria for Auxiliary Feedwater System Design Basis Conditions
6.5-2 Summary of Assumptions - AFWS Design Verification
6.5-3 Summary of Sensible Heat Sources (For Plant Cooldown by AFWS)
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 6 FIGURES Figure Title ix Revision 21 September 2013 6.2-1 Deleted in Revision 18. 6.2-2 Deleted in Revision 18.
6.2-3 Deleted in Revision 18.
6.2-4 Deleted in Revision 18.
6.2-5 Deleted in Revision 11
6.2-6 Deleted in Revision 11
6.2-7 Deleted in Revision 11
6.2-8 Deleted in Revision 11
6.2-9 Deleted in Revision 11 6.2-10 Containment Spray Pump Performance Curve 6.2-11(a) Arrangement of Recirculation Sump Screen (Unit 1) 6.2-11A(a) Arrangement of Recirculation Sump Screen (Unit 2) 6.2-12 Containment Spray Nozzle Cutaway
6.2-13 Containment Spray Headers Plan View
6.2-14 Comparison of Spray Removal Model and CSE Results (Run A6)
6.2-15 Containment Recirculation Sump pH vs. Time After LOCA Begins
6.2-16 Containment Equilibrium Elemental Iodine Partition Coefficient vs. Time for Minimum Sump pH Case 6.2-17 Containment Isolation System
6.2-18 Penetration Diagram Legend (2 Sheets)
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 6 FIGURES (Continued) Figure Title x Revision 21 September 2013 6.2-19 Penetration Diagram (29 Sheets) 6.2-20 Containment Hydrogen Purge System Purge Stream
6.2-21 Containment Hydrogen Purge System Supply Stream
6.2-22 Containment Hydrogen Purge System, Hydrogen Analyzer Stream
6.2-23 Model B Electric Hydrogen Recombiner - Cutaway
6.2-24 Aluminum and Zinc Corrosion Rate Design Curve
6.2-25 Results of Westinghouse Capsule Irradiation Tests
6.2-26 Post-LOCA Containment Hydrogen Concentration
6.2-27 Post-LOCA Hydrogen Accumulation 6.2-28 Post-LOCA Hydrogen Production 6.2-29 Post-LOCA Hydrogen Accumulation from Corrosion of Material Inside Containment with No Recombiner 6.2-30 Deleted in Revision 9
6.2-31 Deleted in Revision 2
6.2-32 Deleted in Revision 18.
6.2-33 Containment Pressure Differential Elements and Flow Paths for Loop Containment Analysis Model 6.2-34 Containment Pressure Differential - Loop Compartment Analysis - Absolute and Differential Pressures in Loop Compartment 1 6.2-35 Containment Pressure Differential - Loop Compartment Analysis - Absolute and Differential Pressures in Loop Compartment 2 6.2-36 Containment Pressure Differential - Pressurizer Enclosure Analysis - Absolute and Differential Pressure in Pressurizer Enclosure DCPP UNITS 1 & 2 FSAR UPDATE Chapter 6 FIGURES (Continued) Figure Title xi Revision 21 September 2013 6.2-37 Containment Pressure Differential Elements and Flow Paths for Reactor Cavity Analysis Model 6.2-38 Containment Pressure Differential Location of Elements for Reactor Cavity Analysis Model 6.2-39 Containment Pressure Differential Location of Elements for Reactor Cavity Analysis Model 6.2-40 Maximum Displacement for Hot Leg Break at Reactor Nozzle
6.2-41 Maximum Displacement for Cold Leg Break at Reactor Nozzle
6.2-42 Containment Pressure Differential Reactor Cavity Analysis - Pressure in Reactor Vessel Annulus (Element 3) 6.2-43 Containment Pressure Differential Reactor Cavity Analysis - Pressure in Loop Compartment (Element 21) Adjacent to Reactor Cavity (Element 3) 6.2-44 Containment Pressure Differential Reactor Cavity Analysis - Pressure in Lower Reactor Cavity (Element 2) 6.2-45 Containment Pressure Differential Reactor Cavity Analysis - Pressure in Upper Portion of Containment (Element 32) 6.2-46 Containment Pressure Differential Reactor Cavity Analysis - Pressure in Hot Leg Pipe Annulus (Element 1) 6.2-47 Deleted in Revision 11
6.2-47A Deleted in Revision 11
6.2-48 Deleted in Revision 11
6.2-49 Deleted in Revision 8
6.2-50 Deleted in Revision 8
6.2-51 Compartment Locations Used in Calculations of Differential Pressure Across Steam Generators from DEHL Break DCPP UNITS 1 & 2 FSAR UPDATE Chapter 6 FIGURES (Continued) Figure Title xii Revision 21 September 2013 6.2-52 Differential Pressure Across Steam Generator (Between Compartment 3 and 2) Resulting From a DEHL Break in Compartment 3 6.3-1 Residual Heat Removal Pump Performance Curves (Typical)
6.3-2 Centrifugal Charging Pumps 1 & 2 Performance Curves (Typical)
6.3-3 Safety Injection Pump Performance Curves (Typical)
6.3-4 Alignment of ECCS-related Components During Injection Phase of Emergency Core Cooling 6.3-5 Alignment of ECCS-related Components During Recirculation Phase of Emergency Core Cooling 6.5-1(a) Auxiliary Feedwater System 6.5-2(a) Long Term Cooling Water System 6.5-3 Auxiliary Feedwater Flow for Plant Shutdown (2 Sheets)
NOTE:
(a) This figure corresponds to a controlled engineering drawing that is incorporated by reference into the FSAR Update. See Table 1.6-1 for the correlation between the FSAR Update figure number and the corresponding controlled engineering drawing number.
DCPP UNITS 1 & 2 FSAR UPDATE xiii Revision 21 September 2013 Chapter 6 APPENDICES Appendix Title 6.2A Deleted in Revision 18. 6.2B Deleted in Revision 11
6.2C Deleted in Revision 19.
6.2D REANALYSIS OF LONG-TERM LOSS-OF-COOLANT ACCIDENTS AND MAIN STEAMLINE BREAK EVENTS 6.3A SINGLE FAILURE CAPABILITY
DCPP UNITS 1 & 2 FSAR UPDATE 6.1-1 Revision 21 September 2013 Chapter 6 ENGINEERED SAFETY FEATURES 6.1 GENERAL 6.
1.1 INTRODUCTION
Engineered safety features (ESF) systems are provided to reduce the safety and environmental consequences of possible Diablo Canyon Power Plant (DCPP) accidents. These systems cool the reactor core during loss of primary coolant, absorb energy released during accidents, contain solids, liquids, or gases released during accidents, and/or absorb radioactive materials that could otherwise be released from the plant buildings. These systems are standby systems, in that they are called upon to perform their main functions only in the event of unexpected severe plant accidents. They provide protection beyond the systems and plant design features that are primarily intended for the prevention of accidents.
The principles and guidelines used in the design, construction, and operation of the ESF are specified in the following documents:
(1) General Design Criteria (10 CFR 50, Appendix A) (2) NRC Reactor Site Criteria (10 CFR 100) (3) ANSI Standard N18.2, Nuclear Safety Criteria for the Design of Pressurized Water Reactor Plants (4) AEC Safety Guides and NRC Regulatory Guides (5) DCPP Technical Specifications(1) (6) Industry Codes and Standards The methods used to evaluate ESF performance are primarily contained in this chapter and Chapter 15.
The DCPP Technical Specifications establish limiting conditions for maintenance of ESF components. Maintenance of a particular component is permitted if the remaining components meet the minimum requirements for operation and the following conditions are also met:
(1) The remaining equipment has been demonstrated to be in operable condition.
DCPP UNITS 1 & 2 FSAR UPDATE 6.1-2 Revision 21 September 2013 (2) A suitable limit is placed on the total time required to complete maintenance to return the component to an operable condition. ESF systems meet redundancy requirements, thus maintenance of active components is possible during operation without impairment of the safety function. Routine servicing and maintenance of equipment of this type that is not required more frequently than on an outage basis would generally be scheduled for periods of refueling and maintenance outages. Any continued reactor operation during outages of individual ESF components will conform to reasonable, experienced judgment and industry practices, thus ensuring safe operation.
This chapter provides detailed descriptions of the DCPP ESFs and evaluates their performance under postulated accident conditions. Specifically, information is provided which shows that:
(1) The concept upon which the operation of each system is predicted has been proven sufficiently by experience, and/or by tests under simulated accident conditions, and/or by conservative extrapolations from present knowledge. (2) The system will function during the period required and will accomplish its intended purpose. (3) The system has been designed with adequate consideration of component and system reliability, component and system redundancy, and separation of components and portions of systems. (4) Provisions have been made for periodic tests, inspections, and surveillance to ensure that the systems will be dependable and effective when called upon to function. 6.1.2 SUMMARY DESCRIPTION The ESFs provided at DCPP are the following: (1) Containment Systems The steel-lined, reinforced concrete containment structure, including the concrete cylindrical wall, base, and dome, is designed to prevent significant release to the environs of radioactive materials that could be released into the containment as a result of accidents inside the containment (Sections 6.2.1 and 6.2.4).
DCPP UNITS 1 & 2 FSAR UPDATE 6.1-3 Revision 21 September 2013 (2) The Emergency Core Cooling System (ECCS) This system provides water to cool the core in the event of an accidental loss of primary reactor coolant water. The ECCS also supplies dissolved boron into the cooling water to provide shutdown margin (Section 6.3). (3) The Containment Spray System (CSS) The primary function of this system is to help limit the peak pressure in the containment in the event of a major accidental release of pressurized water from the primary coolant system (Section 6.2.2). (4) The Containment Fan Cooler System (CFCS) The CFCS also functions to limit the pressure in the containment structure in the event of an accidental release of primary coolant water (Section 6.2.2). (5) The Containment Spray Additive System (CSAS) This system functions by adding sodium hydroxide, an effective iodine scrubbing solution, to the CSS water, thus reducing the content of iodine and other fission products in the containment atmosphere (Section 6.2.3). (6) The Containment Hydrogen Control System (CHCS) The long-term buildup of gaseous hydrogen in the containment following a loss-of-coolant accident (LOCA) is primarily controlled by internal hydrogen recombiners. The internal recombiners are supplemented by the containment hydrogen purge system (CHPS) and a provision to add external recombiners, if necessary (Section 6.2.5). (7) The Fuel Handling Area Heating and Ventilating System This system, consisting of fans, high-efficiency particulate air (HEPA) filters, and charcoal filters, provides a significant reduction in the amounts of volatile radioactive materials that could be released to the atmosphere in the event of a major fuel handling accident (Section 9.4.3). (8) The Auxiliary Building Ventilation System The auxiliary building ventilating system provides the capability for significant reductions in the amounts of volatile radioactive materials that could be released to the atmosphere in the event of leakage from the residual heat removal (RHR) circulation loop following a LOCA (see Section 9.4.2). DCPP UNITS 1 & 2 FSAR UPDATE 6.1-4 Revision 21 September 2013 (9) The Control Room Heating and Ventilation System The control room heating and ventilating system provides the capability to control the volatile radioactive material that could enter the control room atmosphere in the event of a LOCA to acceptable levels (Sections 9.4.1 and 6.4). (10) The Auxiliary Feedwater System (AFWS) This system supplies water to the secondary side of the steam generators for reactor decay heat removal, when the normal feedwater system is unavailable (Section 6.5). Instrument control air is used in most of the ESF systems. In some cases nitrogen is used. When required, bottled air or nitrogen is provided. ESF devices are designed to maintain a safe position or move to a safe position on loss of air or nitrogen pressure. Thus, the air and nitrogen systems are not needed to ensure device safe operation and are Design Class II. A detailed analysis of the air and backup air / nitrogen systems and their relation to safety-related devices, including a listing of such devices, are found in Section 9.3.1. All ESF remotely operated valves have position indication on the control board in two places. Red and green indicator lights are located next to the manual control station, showing open and closed valve positions. The ESF positions of these valves are displayed on the monitor light panels (four panels), which consist of an array of white lights. Three of the light panels are dark during normal operation; these are only energized concurrent with a Phase A containment isolation, a Phase B containment isolation, safety injection signal, containment ventilation isolation, and feedwater isolation. The remaining panel is always energized. The design of these arrays is such that the white lights will be dark when the valves are in their normal or required positions for power operation, or their correct position after automatic actuation. These light panels can be tested during normal operation with switches on the control panel. These monitor lights thus enable the operator to quickly assess the status of the ESF systems. These indications are derived from contacts integral to the valve operators. In the case of the accumulator isolation valves, redundancy of position indication is provided by valve stem-mounted limit switches (the stem-mounted switches are independent of the limit switches in the motor operators), which actuate an annunciator on the control board when the valves are not correctly positioned. Refer to Section 7.6 for additional information. Pump motor power feed breakers indicate that they have closed by energizing indicating lights on the control board in order to enable additional monitoring of in-containment conditions in the post-LOCA recovery period. DCPP UNITS 1 & 2 FSAR UPDATE 6.1-5 Revision 21 September 2013 6.
1.3 REFERENCES
- 1. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-1 Revision 21 September 2013 6.2 CONTAINMENT SYSTEMS Containment systems enclose the reactor and most plant systems and equipment that operate at high temperatures and pressures and may contain radioactive materials. This section describes and evaluates the design of the containment systems and confirms their capability to fulfill their intended objectives. 6.2.1 CONTAINMENT FUNCTIONAL DESIGN 6.2.1.1 Design Bases 6.2.1.1.1 Accident Conditions The containment system is designed so that for all pipe breaks, up to and including the double-ended severance of a reactor coolant pipe, the containment peak pressure is below the design pressure with adequate margin. In addition, containment pressure is reduced to an acceptable value within 1 day following any LOCA.
This capability is maintained by the containment system even if one assumes a loss of offsite power and the worst single failure of an active component during the injection phase and the worst single failure of an active or passive component during the recirculation phase. The post-LOCA and post-main steam line break operating phases are discussed further in Appendix 6.2D for Model Delta 54 steam generators, termed replacement steam generators (RSGs). 6.2.1.1.2 Containment Pressure Differential In the original design, the containment subcompartment dynamic pressure differential analysis described below and in Sections 6.2.1.1.2.1, 6.2.1.1.2.2, 6.2.1.1.2.3, and 6.2.1.1.2.4, and in Tables 6.2-14 through 6.2-24 and Figures 6.2-33 through 6.2-52 was performed to determine the ability of the containment subcompartment structural elements to accommodate the resulting differential pressures. However, as discussed in Section 3.6.2.1.1.1, due to the acceptance of the DCPP leak-before-break evaluation by the NRC, the effects of dynamic subcompartment pressurization due to breaks in the main reactor coolant loop piping no longer have to be considered in the design basis analyses; only the effects resulting from RCS branch line breaks have to be considered. Hence, the pressurizer enclosure analysis is appropriate as presented below since it results from a branch line break, but the analyses for the other compartments are conservative since the breaks postulated in those analyses are more severe than the breaks now required to be considered. These analyses remain bounding for the largest branch line breaks that could occur with the RSGs installed in each unit.
During the early stages of a large area LOCA, pressure differentials may be briefly established in the containment. While the geometry of the containment, except for the net free volume, has no direct effect upon the containment peak pressure, indirect considerations such as the design of structural supports of ESF equipment and the DCPP UNITS 1 & 2 FSAR UPDATE 6.2-2 Revision 21 September 2013 prevention of missile generation make it desirable to calculate the differential pressure transients caused by different breaks.
Four cases are of interest: (a) a rupture of an RCS hot leg at the biological shield that results in the maximum differential pressure across the loop compartment walls, (b) a rupture of an RCS hot leg at the reactor vessel nozzle weld that results in the maximum reactor cavity differential pressure, (c) a pressurizer spray line rupture that results in the maximum pressurizer enclosure differential pressure, and (d) a hot leg break in one of the steam generator loop compartments that yields the maximum pressure differential across the steam generator.
These four cases were analyzed using the TMD (Reference 45) computer code with an unaugmented homogeneous critical mass flowrate correlation. As a result of comparisons at low pressures between measured critical mass flowrates and predictions using the homogeneous critical flow model, an equation has been developed that conservatively bounds experimental critical mass flowrates by applying an augmentation factor of (1.2-0.2X) to the homogeneous model flowrates, where X is steam quality in the upstream compartment. Since critical mass flowrates obtained using the augmentation factor are conservative with respect to experimental data (calculated flowrates are lower than observed), peak compartment pressures calculated using the augmentation factor would be expected to be conservative (higher than expected values). The use of the unaugmented homogeneous critical mass flowrate calculation introduces additional conservatism in the analysis.
The TMD mathematical model used to calculate the flows and pressures throughout the containment is based upon time-dependent equations of conservation of mass, conservation of energy, conservation of momentum, and state. Flow inertia effects between the volumes are also calculated. The model calculates critical flow conditions for application under high-pressure differentials. A 100 percent entrainment of the water emerging from the break is assumed. Subcompartment vent discharge flows are considered as unrecoverable pressure losses and, consequently, vent discharge coefficients are not used. A break flow discharge coefficient of unity is assumed.
Calculated values of peak differential pressure and peak absolute pressure at the time of peak differential pressure are tabulated in Table 6.2-24 for compartments within the containment. Table 6.2-24 also shows design differential pressure for these compartments. In general, considerations other than peak differential pressure determined the design of structural elements within the containment. Consequently, these structural elements can accommodate differential pressures that are significantly higher than the design values shown in Table 6.2-24. The design has been reviewed to determine the as-built capability of these structural elements to accommodate differential pressure. This review shows that differential pressures that are significantly higher than the design values can be accommodated with resulting stress levels within the applicable acceptance criteria as described in Section 3.8.2. The capability of those structural elements affected by differential pressure between the reactor vessel annulus and surrounding containment spaces was specially investigated, since the calculated DCPP UNITS 1 & 2 FSAR UPDATE 6.2-3 Revision 21 September 2013 peak differential pressure exceeds the design value for those elements of the calculational model that are in the vicinity of the postulated break. The results of this investigation, which considered both overall loading and the possibility of local failure in the vicinity of the postulated break, show that no failure would occur and that resisting structural members are not stressed beyond 73 percent of yield capacity. 6.2.1.1.2.1 Loop Compartment Analysis If a LOCA is postulated to occur in a loop compartment region, the steam mass that enters this space must be vented to the rest of the containment. The flowpaths potentially available for such venting are through the operating deck and through the crane wall as well as to the adjacent loop compartments. The first of these routes permits steam, air, and water to enter the dome and the second grants access to the annular spaces between the crane wall and the containment shell.
The analysis assumed a double-ended rupture of an RCS hot leg at the biological shield, since this would result in the maximum differential pressure across the loop compartment walls. Compartments in the containment were represented by an 18-element model and pressures in each element were updated at one millisecond intervals until the rapidly changing portion of the blowdown was completed. The description and volume of each of the compartments represented by an element in the model are given in Table 6.2-14. Table 6.2-15 gives the minimum area of the flowpaths connecting these elements. The elements in the model and the flowpaths connecting them are shown diagramatically in Figure 6.2-33. The mass and energy release rates used in the analysis are given, as a function of time after the postulated break, in Table 6.2-16. Figures 6.2-34 and 6.2-35 show the transient differential and absolute pressures in the two loop compartments for elements of the model with the highest calculated differential pressure. As shown, the highest differential pressures occur during the first fraction of a second following the postulated break. As shown in Table 6.2-24, the peak differential pressure calculated for a loop compartment is less than the design value.
The containment loop compartments were reanalyzed for assumed double-ended RCS cold and hot leg pipe breaks within the loop compartments. For this analysis, the TMD code was used, with the compressibility factor and without the augmented critical flow correlation, to determine the subcompartments' response. The model used was reviewed by the Nuclear Regulatory Commission (NRC). They found that the subcompartment nodalization and input parameters are conservative and, therefore, acceptable for the purpose of evaluating the adequacy of the steam generator supports for postulated RCS pipe ruptures within the loop compartment. 6.2.1.1.2.2 Pressurizer Enclosure Analysis The analysis assumed a double-ended rupture of the pressurizer spray line, since this would result in the maximum differential pressure across the pressurizer enclosure DCPP UNITS 1 & 2 FSAR UPDATE 6.2-4 Revision 21 September 2013 walls. In the event of such a rupture, fluid from the break would be vented to both the containment dome and the loop compartments. Table 6.2-14 gives a description and the volumes of elements of the model while Table 6.2-15 shows the minimum area of the flowpaths connecting the elements. The mass and energy release rates used in the analysis are given, as a function of time after the postulated break, in Table 6.2-17.
Figure 6.2-36 shows the transient differential and absolute pressures in the pressurizer enclosure for that element of the model with the highest calculated differential pressure. As shown in Table 6.2-24, the peak differential pressure calculated with the TMD code for the pressurizer enclosure is less than the design value. 6.2.1.1.2.3 Reactor Cavity Analysis The analysis assumes a double-ended rupture of an RCS pipe at the reactor vessel nozzle weld, since this would result in the maximum reactor cavity differential pressure. The break areas are calculated from the lateral and axial deflections of the ruptured pipe ends. As shown in Figures 6.2-40 and 6.2-41, the geometry of the piping in relation to the penetration liner and the steel shims located within the annulus act to limit the lateral deflection of the hot leg to 7.44 inches, while the cold leg is limited to 4.57 inches. Axial deflections of the ruptured pipe ends are limited by equipment supports to 1.53 inches for the hot leg and 3.10 inches for the cold leg. The maximum break areas corresponding to these deflections are 426 square inches for the hot leg rupture and 369 square inches for the cold leg rupture. Because of the larger break size, the hot leg rupture results in the maximum reactor cavity differential pressure and the analysis described here assumes only a hot leg break. The volumes of elements of the model are given in Table 6.2-18, and data for flowpaths connecting the elements are given in Table 6.2-19. Figure 6.2-37 shows a diagram of the elements of the model and the flowpaths between them. Figures 6.2-38 and 6.2-39 illustrate the location of some of the elements in the model. The mass and energy release used in the analysis are given, as a function of time after the postulated break, in Table 6.2-20.
Subsequent analyses with the TMD code, with the compressibility factor and without the augmented critical flow correlation, were performed to determine the response of the reactor cavity to postulated ruptures of the RCS hot and cold leg pipes. The maximum credible break size and locations were identified to be a 115-square inch cold leg break and a 76-square inch hot leg break at the pipe-to-reactor vessel inlet and outlet nozzle welds, respectively. Pipe displacement restraints have been provided to limit the break sizes to those values. Reactor Vessel Annulus Figure 6.2-42 shows the transient pressure calculated for that element of the model with the highest peak calculated pressure (element 3). This element represents a portion of the reactor vessel annulus in the immediate vicinity of the postulated break. DCPP UNITS 1 & 2 FSAR UPDATE 6.2-5 Revision 21 September 2013 Figure 6.2-43 shows the transient pressure calculated for element 21 of the model, which represents the loop compartment adjacent to the portion of the reactor vessel annulus represented by element 3. By comparing Figures 6.2-42 and 6.2-43, the peak differential pressure between the reactor vessel annulus and the adjacent loop compartment is approximately 325 psi. This peak value occurs at the time when element 3 reaches peak pressure, approximately 0.065 second after the postulated break. Table 6.2-24 shows this peak differential pressure for the reactor vessel annulus. From Table 6.2-21, it can be seen that peak pressures calculated for those elements of the model that represent the portion of the reactor vessel annulus in the vicinity of the postulated break are significantly higher than for the remainder of the reactor vessel annulus. Although peak differential pressures for some elements of the model exceed the design differential pressure for the reactor vessel annulus, structural elements have sufficient margin to accommodate these peak differential pressures without failure. Lower Reactor Cavity Figures 6.2-44 and 6.2-45 show the transient pressure calculated for element 2, which represents the lower reactor cavity, and for element 32, which represents the upper portion of the containment. The transient pressures calculated for these elements do not reach a peak value during the time period covered by the reactor cavity analysis since this pressure response is a longer term phenomenon. However, the differential pressure between the lower reactor cavity and the upper containment does reach a peak value of approximately 6.3 psi for the break postulated for the reactor cavity analysis. Since the peak pressure calculated for the upper containment by the long-term mass and energy release model is 43.8 psig and no other compartments surround the lower reactor cavity, a conservative estimate of the peak differential pressure across the walls of the lower reactor cavity is obtained from the sum of these two pressures. This value (rounded off to 51 psi) is shown in Table 6.2-24, which also shows that the peak calculated differential pressure for the lower reactor cavity is less than the design value. Pipe Annulus Figure 6.2-46 shows the transient pressure calculated for the reactor coolant system hot leg pipe annulus (element 1). The calculated peak pressure in psig is conservatively assumed to equal the peak differential pressure. Although for the reactor cavity analysis described here the peak differential pressure calculated is approximately 283 psi, an earlier analysis, which assumed a cold leg break inside the cold leg pipe annulus, resulted in a peak calculated differential pressure of 1018 psi. This latter value is shown in Table 6.2-24, since it assumes a break that results in a higher pressure in a pipe annulus. A geometrically simplified model of the containment used the elements with the volumes and vent areas shown in Table 6.2-22. The pressure in the pipe annulus was established through a steady state analysis of the peak mass and energy release in the region. Table 6.2-23 lists the mass and energy release rates used in this analysis. DCPP UNITS 1 & 2 FSAR UPDATE 6.2-6 Revision 21 September 2013 Although the earlier analysis did not make use of the TMD mathematical model, the peak differential pressure calculated is believed to conservatively predict the maximum value, which would occur from a postulated pipe break. As shown in Table 6.2-24, the calculated peak differential pressure for the pipe annulus is significantly lower than the design differential pressure. In addition, structural elements can accommodate pressure within a pipe annulus that are much greater than the design value. Consequently, a reanalysis of this break using the TMD mathematical model is not necessary. 6.2.1.1.2.4 Steam Generator Analysis The containment structure immediately surrounding the DCPP steam generators is open and therefore not conducive to the development of asymmetric pressurization loads on the steam generator from a steam line or primary piping rupture. The steam line exits the steam generator area at an elevation above the steam generator, goes behind a secondary shield wall, and does not pass along the side of an enclosed steam generator. Consequently, a rupture in the vertical run parallel to the steam generator would be on the opposite side of the secondary shield wall and would cause no steam generator asymmetric pressurization. A rupture in the steam line at the steam nozzle on the steam generator would cause steam to flow into the upper containment. Because this containment volume is large, the rupture would not necessarily cause any asymmetric pressures on the steam generator.
A TMD analysis of asymmetric pressurization resulting from double-ended breaks in the primary loops, similar to that for the other subcompartments was performed to evaluate the pressure differentials across the steam generator for an RCS loop break. The effect of compressibility was evaluated and found to be insignificant (less than 1 percent effect). Calculations for several DEHL and DECL breaks were performed, with the maximum differential pressure of 6.04 psi occurring for a DEHL break. The mass and energy release rates used for the DEHL are shown in Table 6.2-16. Table 6.2-55 shows the maximum calculated pressure differential across the steam generator for the nine cases analyzed. The compartment locations are illustrated in Figure 6.2-51. The pressure history for the worst case DEHL break is shown in Figure 6.2-52. The maximum calculated differential pressure of 6.04 psi is, when combined with other postulated loads, within the design capability of the upper and lower steam generator supports (see Section 5.5.13). 6.2.1.2 Testing and Inspection 6.2.1.2.1 Preoperational Testing Following completion of each containment structure, a structural integrity test was performed by pressurizing the containment with air to 115 percent of design pressure, or 54 psig. These tests were performed as described in Section 3.8.1.7.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-7 Revision 21 September 2013 During the depressurization phase of the structural integrity tests, overall integrated leakage rate tests were performed in accordance with the requirements of Appendix J to 10 CFR 50 (see Section 3.8.1.7). 6.2.1.2.2 Inservice Surveillance Periodic leakage rate testing will be performed over the life of the units in accordance with the requirements of Appendix J to 10 CFR 50, Option B, as modified by approved exemptions. Applicable surveillance requirements for such testing are included in the Technical Specifications. A leakage detection system has been installed to measure leakrate for the air lock door seals to ensure compliance with the Technical Specifications (Reference 46). Periodic testing of the containment isolation valves is discussed in Section 6.2.4.4. 6.2.1.3 Instrumentation Requirements Pressure inside the containment is continuously monitored by independent pressure transmitters located at widely separated points outside the containment. Instruments with range of -5 to 55 psig and 0 to 200 psig are available. Section 7.3 describes containment pressure as an input to the ESFs actuation system and Section 7.5 describes containment pressure display instrumentation.
Other instrumentation available for monitoring conditions within the containment include:
(1) Containment water level monitors (described in Section 7.5) (2) Containment hydrogen monitors (described in Section 6.2.5.5) (3) Temperature detectors positioned at various locations within the containment air volume (4) Containment radiation and plant vent monitors (described in Section 11.4.2) 6.2.1.4 Materials Containment structural heat sink materials used for containment integrity analyses following a LOCA or main steam line break are listed in Table 6.2D-19; corresponding material properties are listed in Table 6.2D-20. A current record of paint used on containment heat sink structures and equipment is maintained in engineering files.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-8 Revision 21 September 2013 6.2.2 CONTAINMENT HEAT REMOVAL SYSTEMS The functional performance objectives of the CHRS are:
(1) To limit the containment ambient temperature during normal plant operating conditions (2) To reduce the containment ambient temperature and pressure following a LOCA or steam line break The CFCS performs the function of limiting containment ambient temperature during normal plant operation. In addition, during the injection phase following a LOCA, the CFCS and the CSS operate to reduce the containment ambient temperature and pressure. While performing this cooling function, the CHRS also helps limit offsite radiation levels by reducing the pressure differential between containment and outside atmosphere, thus reducing the driving force for leakage of fission products from the containment atmosphere.
The CSS, in conjunction with the spray additive system (SAS), also helps to limit the offsite radiation levels following the postulated LOCA by removing airborne iodine from the containment atmosphere during the injection phase. The SAS and its iodine removal effectiveness are discussed in Section 6.2.3. 6.2.2.1 Design Bases The CHRS is designed to provide sufficient heat removal capability to maintain the postaccident containment atmospheric pressure below the design value of 47 psig. Heat energy sources considered are described in Section 6.2.1. Adequate heat removal capability for the containment atmosphere is provided by two diverse and separate, full capacity ESFs, the CSS and the CFCS. These two systems are designed to work in conjunction with one another to meet the single failure criteria discussed in Section 3.1. Any single failure will still leave sufficient CSS and CFCS capability functional to together mitigate design basis accidents. Used in conjunction with one another during the injection phase, one containment spray pump and two containment fan cooler units will provide the heat removal capability to maintain the postaccident containment pressure below the design value of 47 psig. CHRS design parameters are listed in Table 6.2-26.
The CFCS also functions during normal operating conditions to limit the containment ambient temperature to 120°F and is described in Section 9.4.5.
The CFCS fan coolers are designed to Seismic Category I criteria.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-9 Revision 21 September 2013 6.2.2.2 System Design The CFCS, shown schematically in Figure 9.4-4, consists of five identical fan coolers, each including cooling coils, fan and drive motor, locked-open air flow dampers and pressure relief dampers, duct distribution system, instrumentation, and control. The CFCS was modified to delete the moisture separators and HEPA filters. During operation of the units, air is drawn into the cooling coils, cooled, and discharged back through the ductwork to the containment atmosphere. All of the fan coolers, the distribution ductwork, and cooling water piping are located outside the missile shield wall. This arrangement provides protection from missiles for all system components.
The design parameters for the CHRS components and materials used are listed in Table 6.2-26. Codes and standards used as a basis for the design of the components are given in Table 6.2-25.
Ductwork distributes the cooled air to the various containment compartments and areas. During normal and postaccident operations, the flow sequence through each air fan cooler is as follows: locked-open normal and accident air flow dampers, cooling coils, fan, and distribution ductwork.
Airflow through the exhaust ducting, towards the fan, can occur when the fan is idle. Incorporated into the fan/motor coupling is an anti-reverse rotation device that precludes the fan motor from rotating backwards. This device replaces backdraft dampers previously installed in the fan discharge duct.
Design provisions have been made, to the extent practicable, to facilitate access for periodic visual inspection of all important components of the CFCS. Testing of any components, after maintenance or as a part of a periodic inspection program, may be performed at any time, since the CFCS units are in operation on an essentially continuous schedule during normal plant operation.
The CSS, shown schematically in Figure 3.2-12, consists of two pumps, spray ring headers and nozzles, valves, and connecting piping. Following a LOCA, water from the RWST is initially used for containment spray. Later, water recirculated from the containment sump can be supplied by the RHR pumps for recirculation spray. If no component failures affect the RHR train capability, the emergency procedures direct the initiation of recirculation sprays. However, single failures that result in the loss of one RHR train cause the decision of how to divide the recirculation flow between spray and core injection to be made by the Technical Support Center in charge of accident mitigation.
The component design pressure and temperature conditions in Table 6.2-26 are specified as the most severe conditions to which each component is exposed during either normal or post-LOCA operation. DCPP UNITS 1 & 2 FSAR UPDATE 6.2-10 Revision 21 September 2013 6.2.2.2.1 Component Descriptions 6.2.2.2.1.1 Containment Spray System Refueling Water Storage Tank This tank serves as a source of emergency borated cooling water for the injection phase. It will normally be used to fill the refueling canal for refueling operations. During all other plant operating modes, it will be aligned to the suction of the emergency core cooling pumps and the containment spray pumps. The tank has an assumed accident analysis volume of 350,000 gallons at the beginning of the injection phase. The tank is constructed of stainless steel and is protected by a concrete shield. Containment Spray Pumps The containment spray pumps are of the horizontal centrifugal type and are driven by electric motors. The motors are powered from separate vital buses. The pumps are designed to perform at rated capacity against a total head composed of containment design pressure, nozzle elevation head, and the line and nozzle pressure losses. Adequate net positive suction head (NPSH) is available during the injection phase for a minimum level in the RWST. A performance curve for the containment spray pumps is shown in Figure 6.2-10. Spray Nozzles The spray nozzles, of the hollow cone design having an open throat and 3/8 inch spray orifice, are not subject to clogging by particles less than 1/4 inch in size. The nozzles produce a mean drop diameter of 700 microns at rated system conditions (40 psi p and 15.2 gpm per nozzle). The spray solution is stable and soluble at all temperatures of interest in the containment and will not precipitate or otherwise interfere with nozzle performance. If containment spray is used in the recirculation phase, the containment recirculation sump screens (Figure 6.2-11) limit particle size to preclude the possibility of clogging. Periodic testing of the nozzles, as required by Technical Specification, will ensure that nozzles are unobstructed. Nozzle design and performance characteristics are listed in Table 6.2-26 and in Figure 6.2-12. A plan view of the containment spray headers showing the location of the spray nozzles is given in Figure 6.2-13. Containment Spray System Piping and Valves The piping and valves for the CSS are designed for 240 psig and 200°F.
The Hosgri and double design earthquake (DDE) piping analyses for the piping located inside containment downstream of sealed-open isolation valves 9006 A and B take credit for the empty piping configuration that exists during normal plant operation.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-11 Revision 21 September 2013 6.2.2.2.1.2 Containment Fan Cooler System The design data of the containment fan cooler system are presented in Table 6.2-26. Cooling Coils The coils are fabricated with copper plate fins on copper tubes. The heat removal capability of the cooling coils is 81 x 106 Btu/hr per fan cooler unit at saturation conditions (271°F, 47 psig), with 2000 gpm cooling water supply at 125°F. The design internal pressure of each coil is 200 psig and the coils can withstand an external pressure of 47 psig at a temperature of 271°F without damage.
Each fan cooler consists of 12 individual coils mounted in two banks, 6 coils high. These banks are located one behind the other for horizontal series air flow, and the tubes of the coil are horizontal with vertical fins.
The cooling coil assembly consists of one bank of WC-36114-4H (1/2 water velocity circuiting) coils four rows deep and one bank of WC-36114-6T (1/3 water velocity circuiting) coils six rows deep. Each coil is provided with a drain pan and drain piping to prevent flooding of the coil face area during accident conditions. This condensate is drained to the containment sump. Each cooling coil assembly has a top and bottom horizontal coil casing made of galvanized steel. The safety function of the cooling coil casings is to fill the air gap between each stacked cooling coil assembly and direct airflow through the cooling fins to ensure that adequate heat transfer occurs within the containment fan cooler units.
The cooling water supply to the containment fan coolers is discussed in Section 9.2.2. Fans The five containment cooling fans are of the centrifugal, nonoverloading direct-drive type. The fan bearings have a specially designed seal, are heavy duty, and are selected for the proper thrust and axial loads. Special lubricant is used to ensure protection during accident operation.
Each fan can provide a minimum flowrate of 47,000 cfm when operating against the system resistance of approximately 3-3/4 inches of water existing during the accident condition. Enclosure Each of the five fan cooler enclosure assemblies consists of four prefabricated modular units. Modules 1, 2, and 3 are located on the inlet side of the cooling coils. Module 4 is located on the outlet side of the cooling coils and serves as a plenum for the fan inlet. DCPP UNITS 1 & 2 FSAR UPDATE 6.2-12 Revision 21 September 2013 As a result of the modifications made to the fan cooler enclosure assemblies, only Module 3 serves to direct the airflow into the coils for normal and post-LOCA operations. Modules 1 and 2 are no longer required for service.
Module 1 contains the locked-open accident flow inlet dampers. Locking the accident inlet damper open prevents module overpressurization during LOCA. Module 2 contains the locked-closed accident flow outlet dampers. Module 3 contains the locked-open normal flow inlet dampers and the pressure-relief damper. Anti-Reverse Rotation Device (ARRD) An anti-reverse rotation device is incorporated into the fan/motor coupling that prevents the fan motor from rotating backwards. This device protects the fan motor from airflow that could cause an over-current trip condition when the idle fan starts.
The anti-reverse rotation device is designed to withstand the dynamic loads associated with a 7 psi pressure differential. Pressure Relief Damper Each fan cooler unit is equipped with a pressure relief damper. These dampers are normally closed counterweighted devices that open progressively as the pressure differential across them exceeds 0.25 psi. In the event of a LOCA, the pressure relief dampers limit the pressure differential across the enclosure walls, and thus maintain the structural integrity of the fan cooler units during the pressure transient. Ductwork Except for the short section of branch duct between the containment purge exhaust isolation valve and its debris screen, the ducting is Design Class II and supported to Seismic Category I design requirements. The duct branch bounded by the containment purge isolation valve and its debris screen, including the flexible connection, is classified as Design Class I. Vacuum relief dampers and pressure relief dampers are provided along the ductwork to limit the differential pressure acting on the duct to 0.2 psi during accident conditions. The vacuum relief dampers are classified as Design Class I. The debris screen, flexible connection, duct branch, and vacuum relief dampers are required to function from the beginning of an accident to full closure of the containment purge isolation valves (assuming the valve is open for containment purge when the accident occurs). This is to ensure that debris generated during an accident will not lodge in the seat of the containment isolation valve to prevent its full closure.
Ducts are constructed of galvanized sheet steel. Bolted flanges are provided with gaskets suitable for 300°F service. All longitudinal seams are tack welded or riveted and sealed. DCPP UNITS 1 & 2 FSAR UPDATE 6.2-13 Revision 21 September 2013 Air Flow Dampers Dampers are locked in their normal operating position. The air flow dampers are an integral part of the fan coolers. Each damper is constructed of steel painted with corrosion-inhibiting paint, with multiple blades and edge seals to minimize leakage. Motors for Fan Coolers A two-speed, single-winding motor is used to drive each fan cooler. The motor operates at the high speed during normal operation and at the low speed during postaccident operation.
The motor unit is provided with an integral air-to-water heat exchanger. The motor insulation is Class F (National Electrical Manufacturers Association rated hot spot temperature of 155°C). At incident ambient and load conditions, the motor insulation hot spot temperature is not expected to exceed 118°C. The motors have 2300V insulation for 460V service that provides additional insulation margin. The motor ball bearings are lubricated with high-temperature grease.
The motor heat exchanger housings enclose the major functional element of the motor and limit exposure to the environment that would exist in the containment under postaccident conditions.
The motor heat exchanger consists of the cooling coil, the housing, and two pressure equalization dampers (relief valves to vent containment pressure into the heat exchanger). The motor heat exchanger circulates component cooling water. The joints of the motor heat exchanger cooling coil are brazed with a high-temperature alloy.
The motor heat exchanger cooling coil is mounted within the motor heat exchanger housing and is generally of the same type construction as the main coils. The plenum after the coil has a condensate drain connection. The cooling coil is designed to be easily removed for inspection and maintenance. The cooler is designed to maintain the environment of the fan cooler motor within an acceptable range during normal and postaccident operation. The motor heat exchanger has sufficient capacity to remove all motor assembly heat losses and external heat loads under all operating conditions, while limiting the maximum thermal environment consistent with motor design.
The fan cooler motor heat exchanger housing is equipped with two pressure equalization dampers to relieve pressure differentials resulting from a postaccident pressure transient. The valves begin to open at 5 inches water gauge. The valve is designed for a maximum pressure differential of 30 inches of water. Each valve has a maximum flow area of 7.07 square inches. The valve and body flapper plate are electrolytically nickel-coated carbon steel. The valve bracket, link, shaft, springs, and fasteners are Type 316 stainless steel. The seat seal is a silicone rubber O-ring. Each DCPP UNITS 1 & 2 FSAR UPDATE 6.2-14 Revision 21 September 2013 valve is subjected to a certification test before shipment to ensure proper opening pressure and leaktightness.
The motor, motor heat exchanger, and fan are mounted on a common base for extra rigidity. Electrical Supply Details of the vital bus power sources are discussed in Chapter 8. 6.2.2.2.2 System Operation 6.2.2.2.2.1 Containment Spray System The CSS may operate over an extended period and under the environmental conditions existing following a LOCA or a main steam line break. The system operation can be divided into the following two distinct phases: Injection Phase The spray system will be actuated by a "P" signal, either manually from the control room, or on coincidence of two-out-of-four containment high-high pressure signals. Coincidence of "S" and "P" signals starts the containment spray pumps and opens the discharge valves to the spray headers. The "P" signal alone will open the valves associated with the spray additive tank. During the injection phase, the pumps are drawing borated water from the RWST and mixing it with NaOH solution from the spray additive tank. Spray injection will continue until the RWST low-low level is reached, at which time the CSS pumps are manually tripped and isolated. Recirculation Phase If containment spray is used in the recirculation phase, recirculation spray is provided by the RHR pumps, which draw suction from the containment sump. Recirculation phase operation of the RHR pumps is discussed in Section 6.3.2 and Section 5.5.6. 6.2.2.2.2.2 Containment Fan Cooler System During normal operation, the number of units running will depend on the amount of cooling required in the containment. The operator uses the containment temperature and pressure readings to determine how many fan cooler units should be operating. At full power operation, four or fewer units are usually required, while at cold shutdown only one unit may be needed. Limiting conditions for operation are included in the Technical Specifications.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-15 Revision 21 September 2013 In the event of a LOCA, two of the five fan coolers are required to operate. The units are placed in postaccident mode of operation either by a safety injection signal or manually from the control room.
As shown in Table 6.2-26, in the accident mode each fan cooler motor will reduce speed from 1200 to 600 rpm and provide a heat removal capacity of 81 x 106 Btu/hr at containment design conditions. The cooler heat removal capacity is based on 125°F cooling water and other parameters as specified in Table 6.2-26.
A high degree of mechanical reliability is incorporated in the containment ventilation system. The fan cooler system regularly demonstrates its availability because it is used during normal plant operation to control temperature inside the containment. The capacity of two of the five fan coolers is adequate to prevent containment overpressurization and to bring about temperature reduction following a LOCA or steam line break (SLB). In the event of a failure of offsite electric power concurrent with a LOCA or SLB, the fan cooler units and the pumps supplying cooling water to these coolers are started automatically and supplied with power from the emergency diesel generators.
Immediately following a LOCA, the peak steam-air mixture entering the cooling coils is at approximately 271°F with a density of 0.175 pounds per cubic foot. Part of the water vapor condenses on the cooling coils. The air-side pressure drop is not appreciably affected by the condensate on the cooling coils. The air leaving the coils is saturated at a temperature somewhat below 271°F.
The steam-air mixture remains in this condition as it flows into the fan. At this point it picks up some sensible heat from the fan and fan motor before entering the distribution header and the dry-bulb temperature rises slightly above 271°F and the relative humidity drops to slightly below 100 percent. Flow Distribution and Flow Characteristics The location of the distribution ductwork outlets, together with the location of the fan cooler unit inlets, ensures that the air will be directed to all areas requiring ventilation before returning to the units.
In addition to ventilating areas inside the periphery of the polar crane wall, the distribution system also includes branch ducts for ventilating the upper portion of the containment. These ducts extend upward along the containment wall and discharge in the dome area.
The air discharged inside the periphery of the polar crane wall will circulate and rise above the operating floor though openings around the steam generators where it will mix with air displaced from the dome area. This mixture will return to the fan cooler inlets located on the operating floor. The temperature of this air will essentially be the design ambient for the containment (120°F maximum). DCPP UNITS 1 & 2 FSAR UPDATE 6.2-16 Revision 21 September 2013 The temperature of the postaccident steam-air mixture initially entering the cooling coils will be at approximately 271°F with a density of 0.175 pounds per cubic foot.
In the accident mode of operation, the recirculation rate with five coolers operating is approximately 5.4 containment volumes per hour. Cooling Water for the Fan Cooler Units The cooling water requirements for all five fan cooler units during a LOCA and recovery are supplied by the CCWS, which is described in Section 9.2.2. 6.2.2.3 Design Evaluation 6.2.2.3.1 Heat Removal Capability The CSS and CFCS limit the effects of post blowdown energy additions to the containment during the injection phase following a LOCA.
The minimum fall path for CSS water droplets is conservatively assumed to be the distance from the lowest spray ring to the operating deck. The heat transfer calculations presented in Section 6.2.1 show that essentially all spray droplets reach thermal equilibrium at containment design temperature and pressure in a distance considerably less than the minimum fall path. For a detailed description of the analytical methods and models used to assess the performance capability of the CHRS, refer to the containment integrity analysis presented in Section 6.2.1. The CFCS removes sufficient heat from the containment, following the initial LOCA containment pressure transient, to keep the containment pressure from exceeding the design pressure. The fans and cooling coils continue to remove heat after the LOCA and reduce the containment pressure close to atmospheric within the first 24 hours. In addition, the following objectives are met to provide the ESF functions:
(1) Each of the five fan cooler units is capable of transferring heat from the containment atmosphere, at the design basis rate for postaccident design conditions (see Table 6.2-26). (2) In removing heat at the design basis rate, the coils are capable of discharging the resulting condensate without impairing their flow capacity and without raising the cooling water exit temperature to the boiling point.
Since condensation of water from the air-steam mixture is the principal mechanism for removal of heat from the postaccident containment atmosphere by the cooling coils, the coil fins will operate as wetted surfaces under these conditions. Entrained water droplets added to the air-steam mixture will therefore have essentially no effect on the heat removal capability of the coils. DCPP UNITS 1 & 2 FSAR UPDATE 6.2-17 Revision 21 September 2013 The postaccident heat removal capability of the fan coolers is demonstrated by the Westinghouse computer program HECO (Reference 36). 6.2.2.3.2 Single Failure Analysis A single failure analysis on all active components of the containment heat removal systems was made to show that the failure of any single component will not prevent performance of the design function. This analysis is summarized in Table 6.2-27. 6.2.2.3.3 Reliability 6.2.2.3.3.1 Containment Spray System The CSS, including required auxiliary systems, is designed to tolerate a single active failure during the injection phase following a LOCA or SLB without loss of protective function. 6.2.2.3.3.2 Containment Fan Cooler System The design of the motor and heat exchanger housing seals out the postaccident environment to minimize the amount of moisture entering the motor windings. In addition, any moisture entering the motor housing will condense on the motor heat exchanger. The chief attribute of this design approach is that it ensures that the internal motor parts are maintained in a "usual service condition" despite the hostile environment outside the motor. The motors are designed for Class F temperature in normal operation, which is consistent with the 40-year plant life requirement. During postaccident operation, the motor heat exchanger keeps winding temperatures below the 155°C insulation hot spot temperature rating.
Qualification of the fan cooler motors is described in PG&E Environmental Qualification (EQ) File IH-05 (Reference 39). Since issuance of this report, a revised heat transfer analysis has been performed by Westinghouse to verify the performance of the motor heat exchanger. The bases for motor temperature rise calculations are complete engineering tests of typical motors, which provide winding temperatures rises and heat losses. These data are used to validate equations that predict temperature rises and heat losses for various design parameters and service conditions. A number of machines are tested to permit computer interpolation of each loss curve. Revised analysis results for prediction of motor winding hot spot temperatures are as follows:
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-18 Revision 21 September 2013 Ambient Air at Motor Inlet Previously Reported (WCAP-7829) Rise Total Revised Analysis Rise Total Normal 57°C Max 48°C 105°C 45°C 102°C DBA 75°C Max 47°C 122°C 36°C 111°C Post-DBA 58°C Avg 34°C 92°C 34°C 92°C These results confirm the ability of the motor heat exchanger to maintain winding hot-spot temperatures below the qualification level temperatures established in WCAP-7829 (Reference 4 of EQ File IH-05).
The motor insulation system is Class F (National Electrical Manufacturers Association rated hot-spot temperature at 155°C) thermalastic epoxy. The basic mica structure has high-voltage (2300V) insulation impregnated and coated to give a homogeneous insulation system that is highly moisture resistant. Internal leads and terminal box-motor interconnections are given special design consideration to ensure that the level of insulation exceeds that of the service voltage for the motor.
Tests indicate that the insulation system will survive direct exposure to the postulated postaccident environment. Hence, the heat exchanger system used to cool the windings provides an additional margin of safety. In addition, it should be noted that at the time of the postulated incident, the fan motor would be started if not already running, and its internal temperature, being higher than the ambient, would tend to drive any moisture present out of the windings. The heat exchanger was designed using a very conservative fouling factor. However, if surface fouling reduces the capability of the heat exchanger by one-half, the motor would still have a normal life expectancy, even under postulated accident conditions.
To prove the effectiveness of the heat exchanger in inhibiting large quantities of the steam-air mixture from impinging on the winding and bearings, several full-scale motor tests were performed at representative accident conditions. The tests exposed the motors to a steam-air mixture as well as boric acid and alkaline spray at 80 psig and saturated temperature conditions. Insulation resistance, winding and bearing temperatures, relative humidity, voltage and current, as well as heat exchanger water temperature and flow, were recorded periodically during the test. Following the test, the motors were disassembled and inspected and tested to further ensure that the units had performed as designed. In all tests, the motor unit performed satisfactorily.
The bearings are designed to perform in the ambient temperature conditions resulting from the postulated incident. It should be noted, however, that the interior bearing housing details are cooled by the heat exchanger, thus providing an extra margin of assurance. In addition, separate tests were performed on bearings mounted within a test rig. These bearings were directly exposed to the immediate accident environment including temperature, pressure, steam-air mixture, and chemical sprays. The bearing DCPP UNITS 1 & 2 FSAR UPDATE 6.2-19 Revision 21 September 2013 ran continuously for 22 months without failure. In all tests, bearings were lubricated with fully irradiated grease prior to testing.
To further ensure motor insulation effectiveness (thermalastic epoxy), a separate motor test was conducted by Westinghouse in accordance with IEEE-334 (Reference 47) without the heat exchanger attached to the motor. The test was completed satisfactorily. 6.2.2.3.3.3 Anti-Reverse Rotation Device Tests The air is discharged through the ducting to the annular ring where the air is distributed to various compartments and areas. The return air to the fan coolers is taken at elevation 140 feet where the containment fan coolers are located. After a LOCA, the pressure rise at the upper elevation is relatively slow and, as a result, the pressure difference that is expected between the inlet and outlet of the containment fan cooler unit is extremely small. A value of 7 psi pressure difference was chosen as a conservative design limit.
To demonstrate the adequacy of the anti-reverse rotation device design, dynamic tests were performed to demonstrate that the device will withstand the dynamic loads associated with a 7 psi pressure differential. Static tests were performed to show that the subsequent transient differential pressure can react on the anti-reverse rotation device without failure. The results of these tests and subsequent stress analyses are summarized below:
(1) The anti-reverse rotation device was statically loaded to 3828 ft-Ib driven torque and 2400 ft-Ib reverse rotation torque with no failure. Spin testing was performed to validate retraction of the pawls. The anti-reverse rotation device showed no permanent deformation. (2) The anti-reverse rotation device was tested to validate its ability to react to reverse rotation of the fan shaft under dynamic loading conditions. The dynamic load test conditions include the following: 317 ft-lb of torque, 3 degrees total rotation, 0.391 radians/second angular velocity at end of rotation.
From these results, it was concluded that the anti-reverse rotation device will withstand the load imposed by a 7 psi pressure differential and the design of the anti-reverse rotation device is adequate for the intended use. 6.2.2.3.3.4 Containment Fan Cooler Cooling Coil Test Summary Plate-finned cooling coils are an integral part of the CFCS. These heat exchangers remove sensible heat during normal operation, but become condensers in the postaccident environment. Because of limited experimental information concerning the DCPP UNITS 1 & 2 FSAR UPDATE 6.2-20 Revision 21 September 2013 performance of plate-finned cooling coils operating in a condensing environment in the presence of a noncondensible (air), a demonstration test was undertaken.
The test method was to subject a scaled coil to a parametric test. These parameters were (a) containment pressure (with corresponding steam density and temperature), (b) air flowrate, (c) cooling water flowrate, (d) cooling water temperature, and (e) entrained water content. Each parametric test condition was then used as input to the HECO computer program used in coil selections. The results of the test and the computer program predictions were compared.
In all cases, the measured heat transfer rate was greater than that predicted by the HECO code. The range of parameter variations was selected to be consistent with the design points of the containment fan cooling coils contained in actual plants. It is apparent that for this specific type of heat exchanger, functioning in the range of environments tested, no moisture separator is needed to protect the coils from excessive waterlogging due to entrained spray droplets.
The extension of the test to full-size units is merely an increase in component size and total flow quantities, but not a change in controlling parameters. It is concluded that the test demonstrates that the computer code used to select cooling coil design is valid in defining the heat removal rates of plate-finned tube cooling coil assemblies of the CFCS. Therefore, these tests demonstrate that fan cooler designs, which are selected by this computer program, will perform as required in the postaccident containment environment. 6.2.2.3.3.5 Motor Unit Testing Tests were conducted (Reference 39) to demonstrate the effectiveness of a heat exchanger assembly in isolating motor windings from the steam and chemistry of the post-LOCA environment. Additional tests were conducted in 1971 to comply with provisions of IEEE Standard 334. These tests also qualified design features not included in the original motor. Steam exposure tests per IEEE Standard 334 were performed on the same motor with and without the heat exchanger to qualify it for both types of application.
Objectives given particular attention in the current tests to meet proposals of IEEE 334 included:
(1) Aging of all samples to full service life prior to exposure to simulated design basis accident (DBA) conditions (2) Vibration of thermally aged models prior to steam exposure (3) Change of facilities to provide fast pressure transients to simulate accident conditions during the initial transient DCPP UNITS 1 & 2 FSAR UPDATE 6.2-21 Revision 21 September 2013 (4) Performance of five pressure transients and exposure to a saturated steam environment for 7 days on the prototype in accordance with the DBA simulation model (5) Comparisons between insulation samples subjected to combined environment and irradiation and those exposed sequentially to thermal aging, irradiation, moisture, and voltage (6) Irradiation of all lubricants to 2 x 108 rads before use (7) Destructive tests of statistically selected insulation samples to measure degradation caused by environments including irradiation, with various combinations and durations The tests in this series qualified all motor materials and design features for the conditions and duration of the test.
6.2.2.3.3.6 Containment Fan Cooler Motor Insulation Irradiation Testing The testing program on the effects of radiation on the WF-SAC "Thermalastic" Epoxy insulation system used in the fan cooler motors has been completed. In these tests, irradiation of form-wound motor coil sections was accomplished up to exposure levels exceeding that calculated for the design basis LOCA. Three coil samples received the following treatment sequence: irradiation, vibration test, high-potential test, and vibration test. Six of the nine coil samples received high-potential and breakdown voltage tests. All coil samples passed the high-potential tests. The breakdown voltage levels of all coils were well in excess of those required by the design and clearly indicate that the fan cooler motor insulation system will perform satisfactorily following exposure to the radiation levels calculated for the DBA. 6.2.2.3.3.7 Containment Fan Cooler Motor Lubricant Irradiation Testing This section summarizes the results of tests performed on samples of unirradiated and irradiated Westinghouse Style No. 773A773G05 (Chevron SRI) lubricant, which is used in the fan cooler fan bearing as well as in the motor bearing. The results of these tests indicate that the shear stability or consistency of the grease is increased by irradiation levels anticipated in the containment following a DBA. The consistency of the grease following irradiation remained within the most commonly recommended consistency for ball bearing application (NLGI No. 2).
The purpose of this test program was to establish the effect of irradiation on the bearing lubrication used on both the fan cooler motor and fan bearings. The maximum calculated 1-year integrated dose for the bearing lubricant, using the DBA with no credit for fission product removal from the containment atmosphere other than by natural decay, is 1.5 x 108 rads. The fan and motor bearings would receive a lesser exposure DCPP UNITS 1 & 2 FSAR UPDATE 6.2-22 Revision 21 September 2013 due to self-shielding effects of the motor housing bearing seals and bearing pillow blocks.
Samples of the lubricant were placed in a vented 1.5- x 12 inch aluminum tube. The tube was then placed adjacent to a 34 kilo-curie Cobalt 60 source and irradiated for 79 hours. Dosimetry measurements were made at various locations in the tube using Dupont light blue calibration paper 300 MS-C, No. CB-91639. Following exposures to average levels of 1.2 x 108, 1.5 x 108, and 1.8 x 108 rads, the irradiated grease along with unirradiated grease taken from the same supply were subjected to the Micro-Cone Penetration Test using standard apparatus conforming to ASTM D1403-56T.
The results of the penetration test indicate that as exposure increased, the grease underwent a change in thickness function to the point that, at 1.8 x 108 rads, sufficient change had taken place to cause the grease to increase in consistency to an NLGI No. 2 rating, as the grease was "worked" or sheared rather than decreased as in the unirradiated grease. The most commonly used greases, for ball bearing applications such as those in the fan cooler, have consistencies ranging between NLGI No. 1 and No. 3.
Based on the tests results from irradiation and ASTM Micro-Cone penetration measurements, the containment fan cooler bearing lubricant, Westinghouse Style No. 773A773G05 (Chevron SRI) undergoes no significant change in properties, as measured in terms of consistency. 6.2.2.3.3.8 Ductwork Flow Distribution Performance The fan cooler discharge ductwork and supports, up to and including the backdraft dampers' frame, are Design Class I to maintain the integrity and the design heat removal capability of the operating fan coolers. The section of duct between the containment purge exhaust isolation valve and its debris screen, including the flexible connection, is also classified as Design Class I. This duct section must maintain its integrity during an accident up to the time full closure of the containment purge isolation valve has been attained to ensure that debris generated during an accident will not lodge in the seat of the containment isolation valve to prevent its full closure. The remaining ductwork, equipped with vacuum relief dampers and pressure relief dampers, is Design Class II, but is supported with Seismic Category I supports. This greatly minimizes the collapsing/damage to the distribution ductwork from pressure transients during an accident condition.
During a LOCA, the primary objective is heat removal for containment pressure reduction. The exact distribution of the recirculation flow through the ductwork is not critical. In the event of breakage/damage to Design Class II ductwork branches, no significant reduction in CFCS performance is anticipated because ductwork damage will not reduce the total heat removal capability of the operating fan coolers. DCPP UNITS 1 & 2 FSAR UPDATE 6.2-23 Revision 21 September 2013 6.2.2.4 Tests and Inspections The CSS is designed so that component surveillance can be performed periodically to demonstrate system readiness. The pressure-containing portions of the system are tested periodically to check for leakage. This testing includes the portions of the system that would circulate radioactive water from the containment sump, if recirculation spray was required.
Access is available for visual inspection of the fan cooler components, including fans, cooling coils, enclosure dampers, and ductwork. Since these units are in use during power operation, continuous checks of their status are available. 6.2.2.4.1 Preoperational Testing The aim of preoperational CSS testing was to:
(1) Demonstrate that the system is adequate to meet the design pressure conditions. Outside containment piping welds were subjected to radiographic inspection and/or partial hydrotesting; inside the containment the spray header welds were subjected to 100 percent radiographic inspection. (2) Demonstrate that the spray nozzles in the containment spray header are clear of obstructions by passing air through the test connections. (3) Verify that the proper sequencing of valves and pumps occurs on initiation of the containment spray signal and demonstrate the proper operation of remotely operated valves. (4) Verify the operation of the spray pumps; each pump is run at minimum flow and the flow directed through the normal path back to the RWST.
During this time, the minimum flow is adjusted to that required for routine testing. Each fan cooler unit was tested after installation for proper flow and distribution through the duct distribution system. 6.2.2.4.2 Periodic Testing The aim of the periodic CSS testing is to:
(1) Verify the proper sequencing of valves and pumps on initiation of the containment spray signal and demonstrate the proper operation of remotely operated valves. A spray test interlock prevents accidental actuation of containment spray during testing.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-24 Revision 21 September 2013 (2) Verify the operation of the spray pumps; each pump will be run at minimum flow and the flow directed through the normal path back to the RWST. The fan cooling units are used during normal operation. The fans not in use can be started from the control room to verify readiness. A test signal is used to demonstrate proper fan starting.
The periodic testing of the ECCS discussed in Section 6.3 demonstrates proper transfer to the emergency diesel generator power source in the event of a loss of power. 6.2.2.5 Instrumentation Requirements In addition to responding to containment-related instrumentation (see Section 6.2.1.5), CHRS instrumentation requirements include the capability for measurement of discharge pressure and NPSH in the containment spray pumps and containment spray pump flow to containment. To ensure that water flows to the safety injection system (SIS) after a LOCA and determine when to shift from the injection to the recirculation mode, RWST level indication and alarm are provided. The containment fan cooler bearings are monitored for vibration. Similarly, the containment fan cooler motor assembly bearings and windings are monitored to ensure that vibration and temperature limits are not exceeded. The following instrumentation associated with the containment fan coolers enables additional monitoring of in-containment conditions in the post-LOCA recovery period: (1) The cooling water discharge flow for the containment fan coolers is indicated in the control room and alarmed if the flow is low. (2) The cooling water exit temperatures are indicated locally outside the reactor compartment. (3) Bearing temperatures are indicated and alarmed on the plant process computer. 6.2.2.6 Materials Design parameters and materials used in the construction of CHRS components are listed in Table 6.2-26. Those parts of the system that may come in contact with borated water or sodium hydroxide solution are made of stainless steel or a similarly corrosion-resistant material.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-25 Revision 21 September 2013 6.2.3 CONTAINMENT AIR PURIFICATION AND CLEANUP SYSTEMS The functional performance requirement for the spray additive system (SAS) is to ensure that offsite radiological exposures resulting from a LOCA are within the limits of 10 CFR 100. The SAS provides a chemical additive to the containment spray to reduce airborne iodine activity levels and retain the iodine in the core cooling solution. The two small charcoal filter units in the containment air purification system are not classified as ESFs and are described in Section 9.4.5. These units are not necessary for cleanup during accident conditions. 6.2.3.1 Design Bases 6.2.3.1.1 Air Cleanup The SAS is designed to add sodium hydroxide to the containment spray water to enhance the absorption of elemental iodine from the containment atmosphere and to retain the iodine in the containment sump water in nonvolatile forms.
According to the known behavior of elemental iodine in highly dilute solutions, the hydrolysis reaction, described by the relationships:
++IHIOOHI2 (6.2-8) proceeds nearly to completion (Reference 4) at pH values between 8 and 9.5. The iodine form is highly soluble, and HIO readily undergoes additional reactions to form iodate.
The overall iodate reaction is: ++++3H5IIO3OH3I32 (6.2-9) Values of the spray removal half-life of the molecular iodine in a typical containment are on the order of minutes, or less. This makes the spray system a very efficient fission product removal system in comparison to such alternatives as charcoal filtration systems.
The design basis of the system is two-fold:
(1) Sufficient sodium hydroxide must be added to the containment spray water to ensure rapid absorption by the spray of elemental iodine present in the containment atmosphere following a LOCA. (2) During the injection phase operation of the spray pumps, a sufficient amount of sodium hydroxide must be carried to the containment sump water via the containment spray to ensure retention of the iodine in the sump solution.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-26 Revision 21 September 2013 6.2.3.1.2 Seismic Criteria The SAS is designed to accommodate the design earthquake (DE) within applicable code stress limits and to withstand the DDE or Hosgri earthquake without rupture or loss of function. Seismic design criteria are described in greater detail in Section 3.7. 6.2.3.2 System Design 6.2.3.2.1 General Description The SAS, as shown schematically in Figure 3.2-12, consists of the spray additive tank, eductors, valves, and connecting piping. The design parameters are presented in Table 6.2-29. Applicable codes and standard are given in Table 6.2-30.
Parts of the system in contact with borated water, the sodium hydroxide spray additive, or mixture of the two are stainless steel or an equivalent corrosion-resistant material.
Pressure containing portions of spray and ECCS systems are inspected in accordance with ASME Boiler and Pressure Vessel (ASME B&PV) Code, Section XI, as required by the Technical Specifications and the Inservice Inspection Program Plan (Reference 38).
The SAS will be actuated by a "P" signal initiated either manually from the control room or on coincidence of two sets of two-out-of-four high-high containment pressure signals. Coincidence of "S" and "P" signals will start the containment spray pumps and open the discharge valves to the spray headers. The "P" signal alone will open the valves associated with the spray additive tank. On actuation, approximately 4 percent of each spray pump discharge flow will be diverted through each spray additive eductor to draw sodium hydroxide from the tank. This sodium hydroxide solution will then mix with the liquid entering the suction line of the pumps to give a solution suitable for removal of iodine from the containment atmosphere.
During the injection phase, the emergency core cooling pumps will inject borated water drawn from the RWST into the reactor and containment. Since these flowpaths will not inject sodium hydroxide, the ratio of the total volume injected by all pumps to the volume injected by the spray pumps will determine the change in sodium hydroxide concentration during the injection phase. The total volume of water in the sump includes the total amount contained in the primary coolant and accumulators that could be released to the containment recirculation sump at the start of the LOCA.
During the recirculation phase following a postulated LOCA, containment spray water may be provided by recirculation of water from the containment sump through the RHR pumps and piping that connects the RHR pump discharge to the containment spray header. The changeover from injection to recirculation is performed by operator action on low level in the RWST, which results in an alarm and an automatic trip of the RHR DCPP UNITS 1 & 2 FSAR UPDATE 6.2-27 Revision 21 September 2013 pumps. The remainder of the changeover sequence is accomplished manually by the operator from the control room as shown in Table 6.3-5. One RWST level instrumentation channel actuates an alarm on low-low RWST level to alert the operator to terminate spray injection from the RWST and initiate recirculation spray, if used, from the containment recirculation sump. 6.2.3.2.2 Component Descriptions 6.2.3.2.2.1 Containment Recirculation Sump and Strainer The containment recirculation sump and strainer is a large collecting reservoir designed to provide an adequate supply of water with a minimum amount of particulate matter to the SIS, the centrifugal charging pump (CCP1 and CCP2) system, the RHR system, and the CSS, if recirculation spray is used, during the recirculation mode of ECCS operation following a postulated LOCA.
The sump is located in the annulus area of the containment between the crane wall and the containment liner at the 91 foot elevation. It is approximately 50 feet from RCS piping and components that could become sources of debris. The two 14-inch suction pipes are located on opposite sides of the sump for ECCS train separation. In the sump, there is a strainer system, which includes a trash rack with integral debris curb and two screen assemblies (front and rear assemblies). Each screen assembly is designed with 3/32-inch nominal diameter openings, which are sized for the smallest credible restriction in the ECCS flowpath. Each screen assembly has a plenum. These plenums come together above the two 14-inch RHR pump suction lines and both plenums feed both RHR lines. The lower or rear plenum assembly is water tight to allow collection of any potential back leakage from the RHR system. The strainer assemblies are designed to minimize blockage. The design provides enough screen area to ensure, with maximum accident debris loads and RHR flowrates, the RHR system has sufficient NPSH margin. Since both plenums feed both RHR trains, without complete blockage of both strainer assemblies, there is no condition that would cause both RHR trains to fail.
The physical arrangement of the screen assemblies for Unit 1 is shown in Figure 6.2-11 and the Unit 2 arrangement is shown in Figure 6.2-11A.
Any debris or other matter that passes into the sump through the 3/32-inch maximum hole size allowed for the screen assemblies will pass through the SIS, the centrifugal charging pump system (CCP1 and CCP2), the RHR system, and the CSS, if recirculation spray is used, without restriction and eventually will be pumped back into the containment. This is based on the maximum nominal-sized debris (i.e., 1/8 inch diameter) that could potentially pass through the sump screen assemblies and pass through the ECCS throttle valves.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-28 Revision 21 September 2013 Safety Injection System Fluid from the containment recirculation strainer passes into the 14 inch RHR pump suction piping. The flow passes through the RHR pumps and heat exchangers. The flowpath continues from the exit of the RHR heat exchanger to the suction of the SIS pumps. The SIS pumps discharge to either the cold or hot legs of the RCS loops. The flowpath continues through the RCS cold or hot legs into the core, through the reactor vessel, into the ruptured RCS loop, through the rupture into the containment and, finally, ends in the containment recirculation sump. Centrifugal Charging Pump System (CCP1 and CCP2) The first section of the flowpath, from the containment recirculation sump to the exit of the RHR heat exchangers, is identical to the first section of the SIS flowpath, as discussed above. The flowpath continues from the exit of the RHR heat exchangers to the suction of the centrifugal charging pumps (CCP1 and CCP2). From these centrifugal charging pumps, it goes through the charging injection to the cold legs of the RCS loops. The flowpath continues through the 27-1/2 inch piping of the RCS cold legs, into the core, through the reactor vessel, into the ruptured RCS loop, through the rupture into the containment and, finally, into the containment recirculation sump. Centrifugal charging pump CCP3, which replaced the positive displacement pump, is not credited as part of the centrifugal charging pump system (CCP1 and CCP2) described in Chapters 6 and 15. . Residual Heat Removal System The first section of the flowpath, from the containment recirculation sump to the exit of the RHR heat exchangers, is identical to the first section of the SIS flowpath, as discussed above. The flowpath continues from the exit of the RHR heat exchangers to either the cold or hot legs of the RCS loops. The flowpath continues through the cold legs or hot legs of the RCS loop piping, into the core, through the reactor vessel, into the ruptured RCS loop, through the rupture into the containment and, finally, into the containment recirculation sump. Containment Spray System The first section of the flowpath, from the containment recirculation sump to the exit of the RHR heat exchangers, is identical to the first section of the SIS flowpath, as discussed above. The flowpath continues from the exit of the RHR heat exchangers to the spray headers and out of the 3/8 inch spray nozzles into the containment. Finally, fluid in the containment drains into the containment recirculation sump. DCPP UNITS 1 & 2 FSAR UPDATE 6.2-29 Revision 21 September 2013 6.2.3.2.2.2 Spray Additive Tank The stainless steel tank will contain sufficient 30 weight percent sodium hydroxide solution to bring the containment sump fluid to a minimum pH of 8.0 on mixing with the borated water from the RWST, the accumulators, and reactor coolant following a large break LOCA. This will ensure continued iodine removal and retention effectiveness of the containment sump water during the recirculation phase. 6.2.3.2.2.3 Spray Additive Eductors Sodium hydroxide will be added to the spray liquid by a liquid jet eductor, a device which uses kinetic energy of a pressurized liquid to entrain another liquid. The pressurized liquid in this case is the spray pump discharge used to entrain the sodium hydroxide solution, which is then discharged back into the suction of the spray pumps. On actuation, approximately 4 percent of each spray pump discharge flow is diverted through each spray additive eductor to draw sodium hydroxide solution from the spray additive tank. An eductor motive flowrate of 104 gpm and an eductor suction flowrate of 35 gpm results in a spray solution pH of at least 9.5. (See design case in Table 6.2-36.) 6.2.3.2.2.4 Spray Nozzles A description of the containment spray nozzles is provided in Section 6.2.2. 6.2.3.2.2.5 Piping and Valves The piping and valves for the SAS are designed for 240 psig at 200 degrees F. 6.2.3.2.2.6 Electrical Supply Details of the vital bus power sources are discussed in Chapter 8. 6.2.3.2.2.7 Containment Paints The calculation to document the total painted surface area, and the paint volume, which could fall off in a post-LOCA environment was performed using conservatively high paint contents inside containment. However, this calculation indicated insignificant impact on long term decay heat removal capability of the ECCS due to paint accumulation in the containment sump.
A containment paint log is maintained by engineering and provides a current record of actual containment paint condition. 6.2.3.3 Design Evaluation The spray system, by virtue of the large contact surface area provided between the droplets and the containment atmosphere, affords an excellent means of absorbing DCPP UNITS 1 & 2 FSAR UPDATE 6.2-30 Revision 21 September 2013 radioactive iodine released as a consequence of a LOCA. Sodium hydroxide is added to the spray fluid to increase the absorption of iodine in the spray to the point where the rate of absorption is largely limited by the transfer rate through the gas film surrounding the drops. Reference 5 describes in detail the analytical and experimental basis for the above containment atmosphere iodine removal mechanism. The approach used is summarized below. 6.2.3.3.1 Drop Size Distribution The drop size distribution used in the analytical model is based on data obtained from measurements of the actual size distribution from the Spraco 1713 nozzle for the range of pressure drops encountered during operation of the spray system. A complete analysis of the expected drop size distributions, including a statistical analysis is contained in References 5, 6, and 33. The parameters used in applying these distributions to the calculation of the iodine removal coefficient for the DCPP units are given in Tables 6.2-29, 6.2-36, and 6.2-37. 6.2.3.3.2 Condensation As the spray solution enters the high-temperature containment atmosphere, steam will condense on the spray drops. The amount of condensation is calculated by an enthalpy balance on the drop:
mh + mchg= m'hf (6.2-10) where: m and m' = mass of the drop before and after condensation mc = mass of condensate, lb h = initial enthalpy of the drop, Btu/lb hg and hf = saturation enthalpy of water vapor and liquid, respectively, Btu/lb The increase in each drop diameter in the distribution is, therefore, given by:
)hhh()vv()dd(fggf'3= (6.2-11) where:
vf = specific volume of liquid at saturation, ft3/lb v = specific volume of the drop before condensation, ft3/lb hfg = latent heat of evaporation, Btu/lb hg = enthalpy of steam at saturation, Btu/lb d = drop diameter before condensation, cm d' = drop diameter after condensation, cm DCPP UNITS 1 & 2 FSAR UPDATE 6.2-31 Revision 21 September 2013 The increase in drop size due to condensation is expected to be complete in a few feet of fall for the majority of drop sizes in the distribution. More detailed calculations by Parsly show that even for the largest drops in the distribution, thermal equilibrium is reached in less than half the available drop fall height. 6.2.3.3.3 Mass Transfer Model The basic equation for the iodine concentration in the containment atmosphere is derived from a material balance of the elemental iodine in the containment. The iodine removal by the spray system may be expressed by:
)C(HCEFdtdCVL1ggc= (6.2-12) where:
Vc = containment free volume, cc Cg = iodine concentration in the containment atmosphere, gm/cc H = iodine partition coefficient, (gm/liter of liquid)/(gm/liter of gas) F = spray flowrate, cc/sec
The resulting change in the drop size distribution is taken into consideration in the mass transfer calculations described below. The variable E is the absorption efficiency, which may also be described as the fractional approach to saturation: L1LL1L2CCCCE*= (6.2-13) where: CL1 = iodine concentration in the liquid entering the dispersed phase, gm/cc CL2 = iodine concentration in the liquid leaving the dispersed phase, gm/cc CL*= equilibrium iodine concentration in the liquid, gm/cc This absorption efficiency is calculated from the time-dependent mass transfer model suggested by L. F. Parsly (Reference 7).
The absorption efficiency calculated is a function of drop size, and the removal constant s, in reciprocal hours, for the entire spray is, therefore, obtained by an appropriate summation over all drop size groups: ciin1isVHFE== (6.2-14) DCPP UNITS 1 & 2 FSAR UPDATE 6.2-32 Revision 21 September 2013 A further discussion of drop size distribution, drop trajectories, drop coalescence and mass transfer modeling is presented in References 5, 6, and 33. 6.2.3.3.4 Experimental Verification of Models The ability of the model described to give conservative estimates of actual spray performance was demonstrated in test runs made at Oak Ridge National Laboratory (ORNL) and Battelle Pacific Northwest Laboratory. The results of these tests (Reference 5), shown in Figure 6.2-14 for Run A6, verified that the spray removal model used is conservative in all cases. 6.2.3.3.5 System Performance Evaluation The CSS can function with one spray train operating (abnormal operating mode) or with both spray trains operating (normal operating mode). In addition, the operation of one or both ECCS trains affects the rate of withdrawal of water from the RWST, the duration of the spray injection phase, and thus the amount of sodium hydroxide added to the containment.
Spray iodine removal performance has been evaluated for the design case, a double-ended LOCA, assuming that:
(1) Only one-out-of-two spray pumps operate (one spray train operating) (2) The ECCS operates at its maximum capacity (two ECCS trains operating) (3) Borated water is retained in the RWST for the exclusive use of the spray during the first part of the ECCS recirculation phase The second assumption maximizes ECCS flow from the RWST. Overall, the first two assumptions give the most conservative prediction of sodium hydroxide introduction into the containment (minimum containment recirculation sump pH). The third assumption ensures that sufficient sodium hydroxide solution is added to provide for a sump pH of 8.0 or greater when spray injection terminates. Figure 6.2-15 presents various resulting sump pH versus time curves.
Performance of the spray system is conservatively evaluated at the containment design temperature and pressure. Since this peak pressure condition is expected to exist for a few minutes at most, and mass transfer parameters and spray flowrate improve with decreasing pressure, an appreciable margin is added to the evaluation. The design case removal constant for the spray system (s) provided in Table 6.2-36 was calculated by applying the model derived in Section 6.2.3.3 at this back pressure condition to the sprayed portion of the containment volume.
During the spray injection phase, a single containment spray pump delivers approximately 2466 gpm to the spray header, at containment design pressure (47 psig). DCPP UNITS 1 & 2 FSAR UPDATE 6.2-33 Revision 21 September 2013 If both of the two spray pumps are available in this phase, approximately 4932 gpm is delivered to the containment spray headers from the RWST. This flowrate is not ECCS-dependent.
The variation of sump pH with time after the accident is shown for various cases in Figure 6.2-15 (Reference 51). At the time spray injection terminates, the sump water has reached an equilibrium pH of at least 8.0. The sump pH will remain at the same pH after the spray injection phase because no additional water is added to the system.
Any reevolution of dissolved iodine from the sump to the containment atmosphere depends upon the concentration gradient between the liquid and vapor phases. The equilibrium between these iodine concentrations is given by the partition coefficient, H, and is a function of concentration, pH, and temperature. The partition coefficient at pH 8.0 exceeds the value of approximately 4 x 103 required to maintain a decontamination factor of 100 in the containment atmosphere for sump temperature above 120° F, and thus a containment atmosphere decontamination factor of 100 or greater can be expected. Figure 6.2-16 presents equilibrium elemental iodine partition coefficients in the containment at various temperatures for the minimum sump pH case. The equations given by Eggleton (Reference 8) were used to determine the partition coefficients. Although the iodate reaction is expected to contribute significantly to the iodine partition at high sump pH values, it has been neglected in these calculations in the interest of conservatism.
Approximately 17 percent of the containment free air volume is not reached by the spray. The values listed below were used to estimate the total unsprayed volume in the containment. (1) Containment radius 70 ft Height between operating deck and spring line 91 ft Approximate deck area covered only by grating 2,990 ft2 Height between elevation 91 feet and deck 49 ft Average fall height below deck through grating 12 ft (2) These data result in the following volumes: Volume in dome 717,000 ft3 Volume in cylinder above deck 1,400,000 ft3 Occupied volume above deck -95,000 ft3 Sprayed volume below deck 36,000 ft3 Sprayed refueling cavity volume 45,000 ft3 Total sprayed volume 2,103,000 ft3 Total free volume 2,550,000 ft3 Total unsprayed volume 447,000 ft3 Percent unsprayed volume 17.5 % DCPP UNITS 1 & 2 FSAR UPDATE 6.2-34 Revision 21 September 2013 The use of the spray removal constant in the radiological release calculations for the LOCA is described in Section 15.5. The calculations of thyroid exposures in Section 15.5 were based on the assumption of uniform mixing in the full free volume of the containment. As a result of the circulation of air from the unsprayed portions of the containment free volume to the sprayed areas by the fan cooler system, good mixing is provided. As shown in Table 6.2-26, the fan cooler unit capacity is 47,000 cfm. If a simplified two-volume model were used, in combination with assumptions that some iodine was available for leakage from the lower containment section (unsprayed), some reduction in the effective calculated spray removal coefficient would result. In order to evaluate these and other possible combinations of degraded performance of the spray system, a sensitivity study was performed to determine the effect of a reduced removal coefficient on thyroid exposures. The results of this study are presented in Figures 15.5-6, 15.5-7, and 15.5-8. As shown in these figures, both the short-term and the long-term thyroid exposures are very insensitive to reduced spray removal coefficient down to values as low as 10 hr-1. 6.2.3.3.6 Single Failure Analysis A failure analysis was conducted on all active components of the system to show that failure of any single active component will not prevent the design function from being fulfilled. This analysis is summarized in Table 6.2-38.
The purpose of the motor-operated double-disk gate valve in the spray additive line, shown in Figure 3.2-12 and listed in Table 3.9-3 (Sheet 11), is to permit periodic testing of the two parallel motor-operated valves downstream from that valve. This valve, which is required only in the short term, is not included in the single failure analysis of Table 6.2-38 because it is not an active component. It performs no active function, is normally open, receives a "P" signal to ensure positive opening, and is designed to fail as is, i.e., in the open position.
As discussed in Section 6.3.3, the probability of any spurious valve movement is estimated to be about 2.5 x 10-8/valve-hour. Thus, the probability of the inadvertent closure of this valve, coincident with a LOCA, is not considered likely. The single failure analysis for the remainder of the spray system is given in Section 6.2.2. 6.2.3.3.7 Reliability The SAS is designed to tolerate a single active failure without loss of protective function. The SAS is in use only during the injection period following a LOCA.
In the sump, there is a screen system, which includes a trash rack with integral debris curb and two screen assemblies (front and rear assemblies). Each screen assembly is designed with 3/32-inch nominal diameter openings, which are sized for the smallest credible restriction in the ECCS flowpath. Each screen assembly has a plenum. These plenums come together above the two 14-inch RHR pump suction lines and both DCPP UNITS 1 & 2 FSAR UPDATE 6.2-35 Revision 21 September 2013 plenums feed both RHR lines. The lower or rear plenum assembly is water tight to allow collection of any potential back leakage from the RHR system.
The strainer assemblies are designed to minimize blockage. The design provides enough screen area to ensure, with maximum accident debris levels and RHR flowrates, the RHR system will not lose suction. Since both plenums feed both RHR trains, without complete blockage of both strainer assemblies, there is no condition that would cause both SAS trains to fail.
The refueling cavity is provided with an 8 inch drain line (see Figure 3.2-19, grid 37-C) with a sealed open valve (HCV-111) and blind flange that is removed when the refueling canal is not in use. The drain is closed only when the refueling cavity is in use. 6.2.3.3.8 Evaluation of Insulation and Other Debris Affecting Recirculation Sump/Strainer Availability Following a LOCA The evaluation of insulation and other debris affecting recirculation sump availability following a LOCA was completed based on the requirements and guidance of Generic Letter (GL) 2004-02, which was issued by the NRC to address the potential impact of debris blockage on emergency recirculation during design basis accidents at pressurized water reactors. To meet the intent of GL 2004-02, the evaluation is based on the guidance provided in NEI 04-07, Revision 0, Pressurized Water Reactor Sump Performance Evaluation Methodology, and the subsequently issued safety evaluation of that guidance by the NRC.
- NEI 04-07, along with the NRC safety evaluation, provides an acceptable methodology to evaluate and resolve the potential impact of debris blockage on the emergency recirculation strainer. This methodology, along with subsequent industry guidance, provides a conservative approach to evaluate the following main topics associated with post-accident strainer performance:
- Upstream Effects
- Debris Generation
- Debris Transport
- Heat Loss
- Downstream Effects DCPP UNITS 1 & 2 FSAR UPDATE 6.2-36 Revision 21 September 2013 Upstream Effects The objective of the upstream effects assessment is to evaluate the flowpaths upstream of the containment strainer for holdup of inventory which could reduce flow to and possibly starve the strainer.
This evaluation was performed in accordance with the recommendations contained within NEI 04-07 to identify those flowpaths that could result in the holdup of water not previously considered. These flowpaths included those areas into which CS and RCS break flow would enter.
After holdup from the refueling cavity drain, ductwork, the portion of the reactor cavity below the 91 foot elevation, and holdup curbs had been conservatively estimated and the basis for no other significant sources of liquid holdup had been established, it was determined that all other water return flowpaths have sufficiently large openings to prevent the holdup of significant quantities of water that could challenge the containment minimum water level analysis. Therefore, the remaining water level is still sufficient to provide the containment minimum water level.
The required flowpaths for return of water to the containment sump pool include the refueling canal drains, the stairwells connecting the various elevations of containment, the reactor coolant drain tank hatch cover, and the openings (doorways) within the crane wall.
The refueling canal drain for both Units 1 and 2 is a single 8-inch drain pipe that is protected by a basket approximately 8 inches tall with openings of approximately 4 inches x 4 inches which are sufficiently large to prevent any credible debris that may be generated as a result of the break from blocking this flowpath. Therefore, there is no expected blockage of the refueling canal drain. The upper internals laydown area is within the refueling canal and this area is slightly recessed below the nominal refueling canal floor. This is an area of potential holdup of water and it has been estimated that this area could holdup approximately 244 ft3. This volume is not credited in the minimum containment water level.
The reactor coolant drain tank hatch cover is designed to provide a flow path for injected ECCS water, and spilled RCS fluid, to the recirculation sump from a break inside the biological shield wall. The break will flow through the reactor annulus space, fill the portion of the reactor cavity below the 91 foot elevation, and start to fill the floor at the 91 foot elevation through this hatch cover. The fluid will then flow out of the openings in the crane wall and to the recirculation sump. For breaks other than inside the biological shield wall, the reactor coolant drain tank hatch cover is not required to function and is not credited.
As a result of the evaluations performed and physical changes completed it was determined that the upstream effects analysis provides the necessary level of assurance that the required volume of water will be available to the recirculation sump DCPP UNITS 1 & 2 FSAR UPDATE 6.2-37 Revision 21 September 2013 for the function to meet the applicable requirements as set forth in NEI 04-07 and GL 2004-02.
Debris Generation Debris generation analysis has two primary inputs. The plant accident analysis identifies the postulated accidents that require RHR strainer operation by the Emergency Core Cooling System (ECCS) in the recirculation mode from the containment sump. An accurate inventory of debris source materials addressing type, quantity, location, and characteristics of the materials is also required.
The purpose of the debris generation evaluation is to determine which breaks have the potential to challenge the sump operation in a post-accident scenario. Break locations are postulated based upon which location gives both the most fibrous debris (e.g., insulation) and the worst combination of debris with regard to expected debris transport and head loss behavior given the respective Zone of Influence (ZOI) of the debris. The ZOI represents the zone where a given high-energy line break will generate debris that will be transported to the strainer. The locations will be used to determine total debris generated. The debris generated is then assigned size distributions and defined by material characteristics. The methodology as provided in NEI 04-07 was generally followed along with the recommendations from the SER as applicable.
For break selection, the only exception taken to NEI 04-07 and SER was the use of the criterion specifying "every five feet" as described in the SER. Due to the volume and configuration of DCPP's containment, the overlapping ZOIs essentially covered the same locations. The approach used was to determine the limiting debris generation locations (based on ZOIs) and then determine the quantity and types of debris within the ZOI. This simplification of the process did not reduce the debris generation potential for the worst case conditions as described in NEI 04-07 and the SER.
Through a review of the breaks evaluated it was determined that all breaks generate similar quantities of debris from erosion of unjacketed fibrous materials, latent dirt/dust, miscellaneous debris (stickers, tags, labels, tape), coatings in the ZOI (particulate), and unqualified coating chips. Therefore, breaks that present the greatest challenge to post-accident sump performance are breaks that generate limiting amounts of cal-sil and fibrous debris. All areas with a significant potential to generate fibrous debris (Loop 2 crossover leg, pressurizer surge line, and pressurizer loop seal lines) have been analyzed. All areas with a significant potential to generate cal-sil debris (hot-leg, cold-leg, and crossover legs on all four loops) have been analyzed. Debris quantities have been calculated for any location which generates substantial quantities of fibrous insulation or cal-sil insulation.
Debris Transport The purpose of the debris transport evaluation is to estimate the fraction of debris that would be transported from debris sources within containment to the sump strainers. DCPP UNITS 1 & 2 FSAR UPDATE 6.2-38 Revision 21 September 2013 The methodology used in the transport analysis is based on the NEI 04-07, Volume 1, guidance for refined analyses as modified by the refined methodologies suggested in Appendices III, IV, and VI of NEI 04-07, Volume 2. The specific effect of each of four modes of transport was analyzed for each type of debris generated. These modes of transport are:
- Blowdown transport - the vertical and horizontal transport of debris to all areas of containment by the break jet;
- Washdown transport - the vertical (downward) transport of debris by the CS and break flows;
- Pool fill-up transport - the transport of debris by break and CS flows from the RWST to regions that may be active or inactive during recirculation; and
- Recirculation transport - the horizontal transport of debris from the active portions of the recirculation pool to the sump screens by the flow through the ECCS.
The logic tree approach was then applied for each type of debris determined from the debris generation calculation. The logic tree used by DCPP is somewhat different than the baseline logic tree provided in NEI 04-07, Volume 1. This departure was made to account for certain nonconservative assumptions identified in NEI 04-07, Volume 2, including the transport of large pieces, the potential for washdown debris to enter the pool after inactive areas have been filled, and the direct transport of debris to the sump screens during pool fill-up. Also, the generic logic tree was expanded to account for a more refined debris size distribution.
As part of DCPP's debris reduction modifications, debris interceptors were installed in all three crane wall doors. These debris interceptors are vertically mounted perforated stainless steel plates (18-inches tall, 11 gauge, with 1/8-inch diameter holes) with a horizontal lip (10 inches, also perforated stainless steel plate) that projects into the flow.
Prototypical debris interceptors were tested at critical parameters (expected fluid velocity, flood height and turbulent kinetic energy) to determine the performance of the debris interceptors. As was shown in testing, debris which transports to the debris interceptor by tumbling along the floor will be stopped by the interceptor. Debris which is suspended near the debris interceptor is assumed to transport over the interceptor, with the exception of paint chips.
This testing replicated an accurate RMI debris bed in front of the interceptor, and suspended 9-mil unqualified coatings chips and 2-mil high heat aluminum chips (in separate tests) uniformly throughout the flow stream. The test showed that the debris interceptor is effective in capturing a portion of the 9-mil coatings chips and 2-mil coatings chips, even with sufficient TKE to suspend them at the interceptor. DCPP UNITS 1 & 2 FSAR UPDATE 6.2-39 Revision 21 September 2013 Head Loss As there are no acceptable analytical methods available for the selection and sizing of a suitable strainer, the resolution of GL 2004-02 for DCPP was an evolution of iterations of head loss testing, fiber bypass testing, and debris mitigation. A base debris loading was obtained from the existing debris within containment. As the replacement screen size was limited due to the space constraints and fiber bypass limitations, various debris mitigation options were considered. The resulting debris loads were determined and subsequent head loss and bypass tests were performed to verify strainer performance. This iteration process was repeated, as required to obtain successful results. The ultimate resolution was the screen head loss and fuel bottom nozzle head loss testing which confirmed the ability to maintain a coolable core on recirculation with debris-laden fluid.
Sump strainer head losses were determined though a combination of testing and analysis. The testing performed was designed to assure that a conservative design basis head loss would be determined for DCPP. The head losses associated with the portion of the strainers downstream of the perforated plate screens (the strainer plenums and RHR piping entrance) were established using analytical methods.
The testing performed included use of debris loadings representative of the design basis debris loads and included fiber, particulate, coating chips, and chemical precipitate debris. This testing program provides the basis for all strainer head losses and covers both clean-screen and debris-laden conditions.
In addition to strainer head loss testing, DCPP has performed fiber bypass testing to determine the quantity of fibrous debris which could potentially bypass the strainer and be capable of forming a debris bed on the fuel bottom nozzle.
Downstream Effects The purpose of the downstream effects evaluation is to evaluate the effects of debris carried downstream of the containment strainers on the function of the ECCS and CSS in terms of potential wear of components and blockage of flow streams.
The following specific downstream effects evaluations have been completed:
- Debris ingestion evaluation
- Blockage of equipment in the ECCS/CSS flow paths
- Erosive wear of ECCS/CSS valves
- Wear and abrasion on auxiliary equipment
- Fuel and vessel evaluation DCPP UNITS 1 & 2 FSAR UPDATE 6.2-40 Revision 21 September 2013 The debris ingestion evaluation determined the quantity and size of debris which may bypass the containment screens, and the concentration of this debris in the sump pool following a high energy line break. The output of this evaluation is used in the subsequent downstream evaluations.
The blockage evaluation determined that there are no blockage/plugging issues for existing piping, valves, instrumentation lines, orifices, eductors, heat exchanger tubes, and containment spray nozzles. As part of the resolution for GL 2004-02, new ECCS screens were installed in DCPP Unit 1 and Unit 2. The new screens were specified to be fabricated from stainless steel plates with holes of 3/32-inch perforations. Although the blockage evaluation was performed on the previous screen configuration with 1/8-inch round openings, the blockage evaluation was reviewed and determined to be conservative for the new replacement screen with nominal 3/32-inch round openings. A post installation inspection was performed on the replacement screens to verify that there were no gaps between the joints of any two adjacent surfaces greater than the nominal hole or gap size. The potential for blockage of the reactor vessel level instrumentation system (RVLIS) is not included in this evaluation. DCPP has a Westinghouse designed RVLIS for which WCAP-16406-P states there is no blockage concern due to the debris ingested through the sump screen during recirculation.
The erosive wear evaluation determines the downstream effects of sump debris with respect to erosive wear on the valves in the ECCS and CSS at DCPP Units 1 and 2 using the WCAP-16406-P methodology.
As required by the WCAP methodology, a detailed erosive wear evaluation was required for 12 ECCS throttle valves, Valves 8822A-D, 8904A-D, and 8810A-D. Erosion of valves, calculated as a change in flow area divided by the original flow area (A/A), must remain less than 3 percent A/A. This criterion was established in WCAP-16406-P to prevent erosive wear from significantly impacting the flow rate through the valves. The results of this evaluation show that all valves pass the erosion evaluation using the depleting debris concentration evaluation.
Wear and abrasion of auxiliary equipment evaluation addresses wear and abrasion from debris ingestion on the DCPP auxiliary equipment. This includes the effects of abrasive and erosive wear on ECCS and CSS pumps, heat exchangers, orifices, and spray nozzles following the methodology in WCAP-16406-P.
Erosion is defined as the gradual wearing away of material on an object due to particles impinging on the surface of the object. Abrasion is defined as the gradual wearing away of material on an object due to friction of particles rubbing the surface of the object.
For heat exchangers, orifices, and spray nozzles, the two concerns raised by debris ingestion are plugging (previously addressed) and failure due to erosive wear. Failure of the heat exchangers, orifices, and spray nozzles to maintain system performance could occur as a result of loss of wall material caused by erosive wear.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-41 Revision 21 September 2013 The DCPP heat exchangers, orifices, and spray nozzles were evaluated for the effects of erosive wear for a constant debris concentration as determined in the debris ingestion evaluation. The erosive wear on these components was determined to be insufficient to affect the system performance.
For pumps, the concern raised by debris ingestion through the sump screen during recirculation is failure due to abrasive and erosive wear. Three aspects of pump operability are potentially affected by debris ingestion including hydraulic performance, mechanical shaft seal assembly performance, and mechanical performance (vibration) of the pump.
For the DCPP ECCS pumps, the effect of debris ingestion through the sump screen on three aspects of operability, including hydraulic performance, mechanical shaft seal assembly performance, and mechanical performance (vibration) of the pumps, were evaluated. The hydraulic and mechanical performances of the pumps were determined to not be affected by the recirculating sump debris for the 30-day mission time of the pumps.
There has been no demonstration that the ECCS pump primary seals would fail during a postulated LOCA. The 40-hour testing referenced in Section 8.1.3 of WCAP-16406-P showed that the seals did not fail when tested. Mechanical pump seals at DCPP were not considered to fail as a result of the downstream debris after a postulated LOCA. Such seals would still be subject to a postulated single passive failure of the pressure boundary. Section 6.3.3.2.7 describes the detection and isolation capabilities to minimize the effects of a post-LOCA recirculation loop leakage. Fuel and Vessel The objective of the fuel and vessel downstream evaluation is to determine the effects that debris carried downstream of the containment screen and into the reactor vessel has on core cooling.
The following specific fuel and vessel downstream effects evaluation have been performed:
- Vessel blockage
- Fuel blockage, bottom nozzle tests
- LOCADM analysis The vessel blockage evaluation determined the potential for reactor vessel blockage from debris carried downstream of the containment sump screen. In addition to locations at the core inlet and exit, other possible locations for blockage within the reactor vessel internals which might affect core cooling were assessed. The smallest clearance in the reactor vessel exclusive of the core was found to be 0.52 inches and DCPP UNITS 1 & 2 FSAR UPDATE 6.2-42 Revision 21 September 2013 0.46 inches for DCPP Units 1 and 2, respectively. These dimensions are approximately five times greater than the dimension of the strainer holes in the containment sump screen.
Therefore, any debris that could make it through the 3/32-inch holes in the strainer would not challenge the limiting (smallest) clearances in the vessel.
DCPP performed fuel bottom nozzle head loss test to determine the effects of debris carried downstream of the containment screen onto the fuel assembly. The test and evaluation is an alternate assessment of fuel blockage performed for DCPP. DCPP is taking exception to the WCAP-16406-P, Revision 1, screening evaluation method. A series of fuel assembly bottom nozzle head loss tests were performed.
The test article for the fuel bottom nozzle head loss tests consisted of a simulated core support plate, a bottom nozzle, a P-grid, an intermediate support grid, simulated fuel rods and simulated control rods. Fuel bottom nozzle head loss tests were conducted using the actual fibrous debris which bypassed the test sector during the fiber bypass tests with maximum particulate debris (it was conservatively assumed that 100 percent of the particulate debris which arrives at the strainer also arrives at the fuel bottom nozzle). Unqualified inorganic zinc and unqualified high heat aluminum coatings were conservatively assumed to fail as particulate debris when conducting the fuel bottom nozzle head loss tests, and were conservatively assumed to fail as chips when conducting strainer head loss tests. Fuel bottom nozzle head loss tests conservatively included all chemical precipitate debris.
The fuel bottom nozzle head loss effects were evaluated by Westinghouse through a comparison between the measured head loss of the test data and available driving head for the various DCPP LOCA scenarios.
The Westinghouse comparisons showed that sufficient driving head is available to match the head loss due to debris buildup, therefore, adequate flow will enter the core to match boil-off, and the core will remain covered. Because the core remains covered, Westinghouse concluded that no late heatup occurs, and the maximum local oxidation, the corewide oxidation, and the peak cladding temperature calculations for the traditional LOCA analyses are still considered applicable.
The LOCADM evaluation used the LOCADM code from WCAP-16793-NP, Revision 0, to predict the growth of fuel cladding deposits and to determine the clad/oxide interface temperature that results from coolant impurities entering the core following a LOCA.
The stated acceptance criterion is that the maximum cladding temperature maintained during periods when the core is covered will not exceed a core average clad temperature of 800°F. This acceptance basis is applied after the initial quench of the core and is consistent with the long-term core cooling requirements stated in 10 CFR 50.46 (b)(4) and 10 CFR 50.46 (b)(5).
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-43 Revision 21 September 2013 An additional acceptance criterion is to demonstrate that the total debris deposition on the fuel rods (oxide plus crud plus precipitate) is less than 50 mils. This is based on the maximum acceptable deposition thickness before bridging of adjacent fuel rods by debris is predicted to occur. Debris accumulation in the fuel was observed at the lower grid locations during testing. The testing showed that the bridging that occurred at the grids was acceptable, and that flow through the accumulated debris bed was sufficient to ensure cooling of the fuel.
The evaluation was performed with the LOCADM code using DCPP specific data. The results of this evaluation show that the calculated fuel cladding deposits and clad/oxide interface temperature do not challenge the acceptance criteria.
For the minimum sump water volume cases, LOCADM was also run with increased quantities of debris - in accordance with the bump-up factor methodology. The bump-up factor had a negligible effect on both the total thickness and fuel cladding temperature.
The results of these evaluations show that DCPP can maintain adequate long-term core cooling post-LOCA. 6.2.3.4 Tests and Inspections 6.2.3.4.1 Preoperational Testing The containment spray system was tested functionally in accordance with written procedures, as outlined in Chapter 14. Spray pump delivered flow and head data were recorded to verify that the containment spray pumps meet design criteria.
Spray additive eductor performance data were provided by the manufacturer based on actual tests of a similar eductor. These tests were conducted using a 1.3 specific gravity solution to verify eductor design performance. Additional manufacturer's tests were run using water so that comparative performance data were available for the two different additive solutions at eductor design conditions. Eductor performance was checked subsequent to installation into the system. Spray additive flowrates were measured, with resulting rates in the range 31.5 to 38.5 gpm (35 gpm +/- 10 percent) considered acceptable.
Each containment spray header was tested individually by connecting a source of air to the normally capped flange connection on the spray pump discharge header, shutting the manual spray header isolation valve and opening the air test line isolation valve and the motor-operated spray header isolation valve. Individual nozzles were checked for proper performance by streamers, which indicated unobstructed air flow.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-44 Revision 21 September 2013 The containment sump recirculation mode was tested initially as part of a preoperational flow test under ambient conditions of the SIS. The purpose of the test was to demonstrate the capability of appropriate subsystems to deliver fluid from the containment sump into the RCS in the required time. 6.2.3.4.2 Periodic Testing 6.2.3.4.2.1 Component Testing Routine periodic testing of the SAS components and all necessary support systems at power, under the conditions defined in the Technical Specifications, is performed.
During periodic tests, the equipment is inspected visually for leaks. Leaking seals, packing, or flanges are corrected to eliminate the leak. Valves and pumps are operated and inspected after every maintenance to ensure proper operation.
No periodic testing is performed for the containment sump. However, the sump and screens are inspected during each regularly scheduled refueling outage, and after any maintenance that could result in sufficient debris to block the sump screens. Work area inspections are performed at the conclusion of maintenance activities anywhere in the containment to ensure that debris that could block the sump screens is removed.
The containment spray pumps are tested individually by manually shutting the spray header isolation valves, manually opening the RWST test return line isolation valves, and manually starting the pumps. Pump differential pressure can be used to verify pump performance. Each containment spray header can be tested individually by connecting an air source to the normally capped flange connection on the spray pump discharge header, shutting the manual spray header isolation valve, and opening the air test line isolation valve and the motor-operated spray header isolation valve. Individual nozzles can then be checked for proper performance by streamers, which indicate unobstructed air flow.
Each of the system's motor-operated valves can be operated individually by switches in the control room. Valve position indication on the same control room panel is used to verify valve operability. These valves are tested while the pumps are shut down. During eductor suction valve operation, the normally open spray additive tank valve is closed. Relief valves and vacuum breakers on the sodium hydroxide tank are set and tested prior to installation and periodically thereafter.
The concentration of the sodium hydroxide additive solution is established at the time of initial tank fill, and then periodically checked by titration of tank samples taken from the local sample connection.
Provision is made in the circuitry of the various system alarms to test the proper operations of the alarm circuitry with a test signal input. These circuits include the DCPP UNITS 1 & 2 FSAR UPDATE 6.2-45 Revision 21 September 2013 sodium hydroxide tank low-level alarms, the RWST low-level alarms, and the containment high-pressure alarms. 6.2.3.4.2.2 System Testing The periodic testing of the emergency diesel generators discussed in Chapter 8 demonstrates proper transfer to the emergency diesel generator power sources in the event of a loss of power. 6.2.3.5 Instrumentation Application Analog and logic channels employed for initiation of SAS operation are discussed in Chapter 7. All alarms will be annunciated in the control room. 6.2.3.5.1 Spray Additive Tank Pressure A locally mounted indicator on the nitrogen line monitors the spray additive tank pressure while adding nitrogen and during periodic inspections. 6.2.3.5.2 Spray Additive Flow A flow element is located in the discharge line from the spray additive tank. Flow indication is provided in the control room. 6.2.3.5.3 Spray Additive Tank Level Two separate instruments are provided: one to supply readout in the control room and the other to provide local indication. Two alarms are provided to announce when the solution in the tank has dropped below a level approaching the Technical Specification minimum requirements. 6.2.3.6 Materials The SAS design parameters and materials of construction are listed in Table 6.2-29. Code compliance is shown in Table 6.2-30. Paints on component surfaces within containment are listed in Table 6.2-28. 6.2.4 CONTAINMENT ISOLATION SYSTEM The containment isolation system (CIS) prevents excessive radioactivity from passing through the containment to the atmosphere in the event of a LOCA. This is accomplished by automatically sealing the various pipes through the containment walls.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-46 Revision 21 September 2013 6.2.4.1 Design Bases The CIS is designed to meet the requirements of the 1971 General Design Criteria (GDC) except where specifically indicated. When deviations are noted, these cases do not meet the 1971 GDC because of commitment to design and construction prior to issuance of these criteria. Such cases do comply with the 1967 GDC, however. The design uses the following premises:
(1) An automatic containment isolation barrier is provided by a closed system, a trip valve, or a check valve. (2) A closed system meets the following requirements: (a) Inside the containment: 1. No mass transfer with either the RCS or the reactor containment interior 2. Has the same safety classification as ESFs (Design Class I) 3. Must withstand an external pressure and temperature that is greater than containment design pressure and temperature 4. Must withstand accident transient and environmental parameters 5. Must be protected against missiles and high-energy jets (b) Outside the containment: 1. Does not communicate with the atmosphere outside the containment 2. Has the same safety classification as ESFs (Design Class I, Code Class II) 3. Internal design pressure and temperature must be greater than containment design pressure and temperature 4. Must be protected against missiles and high-energy jets (3) A trip valve is a motor-, air-operated, or solenoid valve that moves to a preferred position upon a containment isolation signal. It can also be opened or closed manually from a remote location.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-47 Revision 21 September 2013 (4) Lines that must remain in service subsequent to certain accidents have, as a minimum, one manual isolation valve. (5) Lines 1 inch nominal pipe size and larger that penetrate the containment and are connected to the RCS have at least two valves inside the containment. The valves are normally closed or have automatic closure. For incoming lines, check valves are permitted and are considered as an automatic barrier inside containment. (6) All isolation valves (automatic and manual) and associated equipment are Design Class I. The isolation section piping is Design Class I, Code Class II. 6.2.4.1.1 Containment Penetration Piping Isolation Grouping The definitions used in the design bases and the physical configuration of various systems that penetrate the containment divide themselves naturally into five groups. These groups were used to determine the necessary valves on lines penetrating the containment. The lines and valves are shown graphically in Figure 6.2-17. PG&E has named and defined each group as shown below. The groupings, A through E, do not correspond to the piping code classes described in Section 3.2.1. 6.2.4.1.1.1 Group A Piping Group A piping complies with the requirements of either GDC 55 or 56. Outside the containment this piping either connects directly to the atmosphere or is considered open, even though it may be physically closed. Inside the containment, it is either part of the reactor coolant pressure boundary (RCPB), opens directly to the containment atmosphere, or is considered open, even though it may be physically closed. In this group, the following minimum requirements apply:
(1) Incoming Lines: One trip valve inside the containment and one trip valve outside the containment, or one check valve inside the containment and one trip valve outside the containment (2) Outgoing Lines: One trip valve inside the containment and one trip valve outside the containment 6.2.4.1.1.2 Group B Piping Group B piping complies with the requirements of either GDC 55 or 56. Outside the containment, this piping operates in a closed system (physically closed and Design Class I), and inside the containment it is either part of the RCPB or connects directly to the containment atmosphere. For this group the following minimum requirements apply:
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-48 Revision 21 September 2013 (1) Incoming Lines: One check valve inside the containment and a closed system outside the containment (2) Outgoing Lines: One trip valve inside the containment and a closed system outside the containment 6.2.4.1.1.3 Group C Piping Group C piping complies with the requirements of GDC 57, which states that isolation valves in closed systems must be outside the containment and no simple check valve may be used. Outside the containment, this piping connects with systems that are either opened or closed. Inside the containment, both types of systems are separated from the RCPB and from the containment atmosphere by a membrane barrier. For this group, the following minimum requirements apply:
(1) Incoming Lines: One trip valve outside containment (2) Outgoing Lines: One trip valve outside containment 6.2.4.1.1.4 Group D Piping Group D piping complies with the intent of the applicable GDC to the extent that valves are provided in the proper locations. These lines must, however, remain in service following an accident and, therefore, the valves do not isolate automatically, but trip to the required position. Piping for the ESFs is in this class. For this group, the following minimum requirements apply: (1) Incoming Lines: One local or remote-manual valve outside the containment (2) Outgoing Lines: One local or remote-manual valve outside the containment 6.2.4.1.1.5 Group E Piping Group E piping complies with the requirements of either GDC 55, 56, or 57. This piping is characterized by sealed closed valves and used for intermittent service not related to system functions. For this group, the following minimum requirements apply: (1) Incoming Lines: Sealed closed manual valve outside the containment and a sealed closed manual valve or a check valve inside the containment (2) Outgoing Lines: Sealed closed manual valve outside the containment and a sealed closed manual valve inside the containment DCPP UNITS 1 & 2 FSAR UPDATE 6.2-49 Revision 21 September 2013 (3) No-flow Lines: Diaphragm or sealed closed valve outside containment and diaphragm inside containment 6.2.4.1.2 Piping Systems With some exceptions such as those noted in Table 6.2-39 and Appendix 3.1A, piping systems penetrating the containment conform to GDC 54, 55, 56, and 57. The number and location of isolation valves are shown graphically in Figure 6.2-19; the legend for the diagrams is given in Figure 6.2-18. The criteria to which each penetration complies and a description of the isolation valves are given in Table 6.2-39. To the extent indicated in Table 6.2-39 and Figure 6.2-19, piping penetrations are designed with the capability of leak detection and periodic testing of the isolation valve operability.
6.2.4.1.3 Instrument Lines Instrument lines penetrating containment meet the intent of AEC Safety Guide 11 (Reference 48).
The containment pressure instrumentation penetration lines (see Sheet 15 of Figure 6.2-19) consist of a sealed, fluid-filled system consisting of a sealed bellows sensor connected to the diaphragm of the pressure transmitter by a sealed fluid-filled tube. This arrangement provides a double barrier (one inside and one outside) between containment and outside atmosphere. It provides an automatic double barrier isolation without operator action and without sacrificing any reliability with regard to its engineered safety functions. The bellows and tubing inside containment and transmitter diaphragm and tubing outside containment are protected from postulated missile and HELB pipe whip/jet impingement effects by their location, which provides separation and shielding from these hazards. Isolation valving is not essential to meet the intent of Safety Guide 11.
The deadweight pressure calibrator penetration line (see Sheet 22 of Figure 6.2-19) is provided with one valve located close to the outside containment wall on Unit 1 and an instrument cap on Unit 2. The deadweight calibrator that was common to both Units and the Unit-specific calibration pressure indicators (PT-458B) have been removed. The tubing from the GE area on each Unit to Area H is abandoned in place. The valves are opened only for calibration purposes. For Unit 1, the tubing between valves outside containment is removed and a cap installed on the inboard valve. The calibrator and tube are filled with distilled water that is separated from the reactor coolant by the diaphragm in the pressure sensor. This diaphragm is designed to withstand full RCS pressure from either side. The intent of AEC Safety Guide 11 is met by the use of a diaphragm on both Units plus one sealed-closed valve on Unit 1 and instrument cap on Unit 2. 1-PT-458A and 2-PT-458A have been abandoned-in-place, resulting in the isolation valves being closed, hence, the inboard seal is a closed valve with the PT-458A diaphragm as a back-up.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-50 Revision 21 September 2013 The containment penetration used for the integrated leakrate test meets the intent of Safety Guide 11 by having one sealed closed valve inside and one outside containment (see Sheet 11 of Figure 6.2-19).
Reactor vessel level instrumentation penetration lines (see sheet 25 of Figure 6.2-19) consist of a sealed fluid-filled system, consisting of a sealed bellows sensor inside containment connected to one side of a differential pressure unit (DPU) outside of containment by a sealed fluid-filled system. The sensor and the DPU are capable of withstanding full RCS pressure. Isolation valving is not essential to meet the intent of Safety Guide 11. 6.2.4.1.4 Testing and Reliability The CIS design provides such functional reliability and ready testing facilities as are necessary to avoid undue risk to the health and safety of the public. The pneumatic-operated isolation valves close on loss of control power or compressed gas. The instrumentation and control circuits are redundant in the sense that a single failure cannot prevent containment isolation. Isolation valves will be periodically tested for operability. Automatic Phase A and Phase B valves and sealed closed valves are periodically tested for leak-tightness. 6.2.4.1.5 System Protection Adequate protection for containment isolation, including piping, valves, and vessels is provided against dynamic effects and missiles that might result from plant equipment failures, including a LOCA. Isolation valves inside the containment are located between the crane wall or some other missile shield and the outside containment wall. Isolation valves and piping or vessels that provide one of the isolation barriers outside the containment, are similarly protected. 6.2.4.1.6 System Operation Immediate isolation of the containment is accomplished automatically. No manual operation is required. Automatic trip valves are provided in those lines that must be isolated immediately following an accident. Lines that must remain in service subsequent to certain accidents are provided with at least one remotely operated manual valve. Table 6.2-40 shows operating conditions that make containment isolation mandatory. Setpoints are specified in the plant Technical Specifications.
Each automatic isolation valve is provided with a manual switch for operation. The position of each automatic isolation valve and remote-manual valve is displayed in the control room. Governing conditions regarding closure of isolation valves and the instrumentation and controls for the system are described in Section 6.2.4.2 and in Chapter 7.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-51 Revision 21 September 2013 6.2.4.2 System Design All piping, valves, and connected equipment necessary to maintain the containment isolation boundary are designed to withstand postaccident conditions with respect to pressure, temperature, and atmospheric conditions for which they are required to maintain that boundary.
Analyses were made to ensure the integrity of the isolation valve system and connecting lines due to the forces resulting from inadvertent closure of isolation valves under operating conditions. Possible maximum forces and moments have been calculated, and valves, piping systems, and piping configurations have been designed to withstand these forces. Flued heads have also been designed to withstand these forces. Where required, snubbers and pipe restraints have been installed to absorb forces and eliminate line whipping caused by the inadvertent closure of an isolation valve. 6.2.4.2.1 Valve Positioning The automatically tripped isolation valves are actuated to the closed position by one of two separate containment isolation signals.
There are two automatic phases of containment isolation at DCPP. Phase A isolates all nonessential process lines but does not affect safety injection, containment spray, component cooling water supplied to the reactor coolant pumps and containment fan coolers, and steam and auxiliary feedwater lines. Phase B isolates all process lines except safety injection, containment spray, auxiliary feedwater, and the containment fan coolers component cooling water system. Valves which close automatically upon receipt of a Phase A isolation signal are designated by the letter "T" in the penetration diagrams (Figure 6.2-19). The letter "P" is used to designate those valves that close automatically upon receipt of a Phase B isolation signal.
Phase A isolation is initiated by high containment pressure, low pressurizer pressure, low steamline pressure, or manual initiation. Phase B isolation is initiated by high-high containment pressure or manual initiation.
Three levels of containment process penetrations have been defined for the DCPP:
(1) "Nonessential" process lines are defined as those that do not increase the potential for damage for in-containment equipment when isolated. These are isolated on Phase A isolation. (2) "Essential" process lines are those providing cooling water and seal water flow through the reactor coolant pumps. These services should not be interrupted while the reactor coolant pumps are operating unless absolutely necessary. These are isolated on Phase B isolation.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-52 Revision 21 September 2013 (3) Safety system process lines are those required to perform the function of the ESF system. Table 6.2-39 identifies nonessential, essential, and safety systems penetrating containment.
All nonessential systems use either manually sealed closed valves or else the valves are automatically isolated on a Phase A containment isolation signal. Additionally, all essential systems (defined in (2) above) are automatically isolated on a Phase B containment isolation signal.
Valves that operate as part of the SIS are designated by the letter "S" in the penetration diagrams. All automatic isolation valves are operable from the control room. All remote-manual containment isolation valves are opened and closed normally from the control room or from local control panels (e.g., sampling system valves are operated from a panel in the sampling room). Position indicators are provided for each valve near its manual control switch.
Specific administrative procedures govern the positioning of all isolation valves (except check valves) as well as any flanged closures during normal operation, shutdown, and accident conditions. Check valves in incoming lines open only when the fluid pressure in the line coming from the outside is higher than the pressure on the containment side. Gravity or a spring holds the valve closed in the balanced pressure condition.
The main steam lines each have a check valve in series with the isolation valve to prevent reverse flow of steam in the event of the rupture of a steam pipe inside the containment. Instrumentation and logic circuits are provided to detect a ruptured steam pipe and to close the automatic trip isolation valves on the steam lines. 6.2.4.2.2 Systems Data Table 6.2-39 lists the lines penetrating the containment and the valves and closed systems employed for containment isolation. This table lists the number and types of isolation valves, valve positions during normal operation, shutdown, accident conditions, and primary and secondary modes of actuation, as well as their functional classification in accordance with the definitions in Section 6.2.4.2.1 above. Supplementary information regarding the listing in the table is discussed in the following paragraphs:
(1) Leakage Characteristics at Accident Pressures All valves for containment isolation were specified, constructed, and tested to the maximum allowable leakage rates as shown in the following (inservice testing limits are specified in the Containment Leakage Rate Testing Program):
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-53 Revision 21 September 2013 Valve Type Seat Leakage(a) Ball <0.3 Globe and gate 3 Check(b) 3 Diaphragm (Saunders Patent) Negligible Butterfly (rubber-seated) Negligible Maximum allowable stem leakage for open backseated valves was specified as one cubic centimeter of water per hour per inch of stem diameter at design conditions. (2) Control System Type Containment isolation valves are provided with actuation and control features appropriate to the valve type. For example, air-operated globe and diaphragm ("Saunders Patent") valves are generally equipped with air diaphragm operators, spring loaded to fail-closed on loss of air or electrical signal. Motor-operated gate valves can be supplied from vital onsite emergency power as well as their normal power source. Manual and check valves do not require actuation or control systems. Valve and operator types are listed in Table 6.2-39. (3) Signal to Operate the Valve All remote-manual containment isolation valves are opened and closed normally from the control room or from local control panels (e.g., sampling system valves are operated from a panel in the sampling room). (4) Power Source Required to Actuate or Operate the Valve Remote-manual containment isolation valves are actuated by compressed gas or electrical power. (5) Time Necessary to Close the Valve Standard closing times normally available are adequate for the sizes of containment isolation valves used. Valves equipped with air diaphragm operators generally close in approximately 2 seconds; 10 seconds is typical of the closing time available in large motor-operated gate valves. (a) Leakage is expressed in units of cubic centimeters of water per hour per inch of nominal pipe size at valve design conditions. (b) The main steam isolation valve is a Schutte-Koerting reverse check which does not meet this seat leakage criterion. DCPP UNITS 1 & 2 FSAR UPDATE 6.2-54 Revision 21 September 2013 (6) Normal and Failed Positions of the Valves Normal and failed positions of the valves are indicated in Table 6.2-39. Diagrams for each penetration, showing all valves, barriers, missile shielding, and leakage test connections are attached as Figure 6.2-19. The parts of the piping systems that are Design Class I are also indicated in this figure. The conditions requiring containment isolation are listed in Table 6.2-40. 6.2.4.2.3 Missile Protection No valve is considered to be an isolation valve if it is not missile-protected. Isolation valves, actuators, and control devices required inside the containment are located between the missile barrier and the containment wall. Isolation valves, actuators, and control devices outside the containment are located outside the path of potential missiles or are provided with missile protection. The missile barrier for each isolation valve is shown schematically on the penetration diagrams (Figure 6.2-19). See Section 3.5 for additional information on missile protection. 6.2.4.3 Design Evaluation The CIS provides a minimum of two barriers to prevent leakage of radioactivity to the outside environment. Either barrier is sufficient to keep leakage within the allowable limits.
No manual operation is required for Phase A and Phase B containment isolation although isolation can be accomplished manually. Each remote-manual and automatic isolation valve is designed to close or go to a preferred position on a loss of power or air or nitrogen supply, except for motor-operated valves, which fail as-is. Resetting the isolation signals will not result in the automatic reopening of containment isolation valves. Reopening of containment isolation valves requires deliberate action and ganged reopening will not result from a single operator action after the signal has been reset.
Control circuits are designed to close the isolation valves on a de-energized state. No power is therefore required to isolate the containment. The exception to this is steam line isolation, which requires the energization of one of two mutually redundant circuits.
All valves, piping, and equipment that are considered to be isolation barriers are designed to Design Class I requirements and are protected against potential missiles and water jets. 6.2.4.4 Tests and Inspections CIS periodic tests and inspections are provided to ensure a continuous state of readiness to perform its safety function. Testing is performed in accordance with the DCPP UNITS 1 & 2 FSAR UPDATE 6.2-55 Revision 21 September 2013 Technical Specifications 5.5.16.a Containment Leakage Rate Testing Program, as required by 10 CFR 50.54(o), and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. As a general requirement, all containment isolation valves will be tested periodically with a gas to determine leaktightness.
Exceptions to this requirement are those valves not required to be testable by Appendix J to 10 CFR 50, and certain valves that cannot be isolated for air testing. These include the first of double check valves to the RCS and valves for which such testing would require draining significant portions of the RHR system or the SIS. Even if these systems were drained, the presence of other valves associated with the systems would make it impractical to determine the source of any measured leakage. Where a quantitative leakage test is necessary, provisions are made for each valve to measure the inflow of the pressurizing medium, collect and measure leakage, or calculate the leakage from the rate of pressure drop. The test pressure on the valve will be at a differential pressure of not less than the peak calculated containment internal pressure related to the design basis LOCA (Pa). Pa is specified as 43.5 psig in Technical Specification 5.5.16.b and this value bounds the calculated LOCA containment integrity results in Appendix 6.2D.4.1.5.
Check valves and single-disk gate valves will have the test pressure applied to the inboard side of the valve(a). Diaphragm valves may be tested on either side since their leakage characteristics are the same in either direction. Double-disk gate valves may be tested by applying the test pressure between the disks. Globe valves may be tested by pressurizing either the inboard side or under the seat.
Locations of test connections (TC) and test vents (TV) are shown on the penetration diagram (Figure 6.2-19). In most cases, equipment vents or drains can be used as TC or TV.
Containment isolation signal actuation channels are designed with sufficient redundancy to provide the capability for channel testing and calibration during power operation without tripping the system (see Chapter 7 for more details). Also, a single failure in the instrumentation and control circuits will not prevent isolation.
For additional details regarding periodic testing and inspection of valves, refer to the Technical Specifications. 6.2.4.5 Materials Materials selection for the penetration lines and isolation valves of the CIS depends on the particular application and function of the systems involved. Further information is provided in the FSAR Update section describing the individual systems of interest, and in Section 3.8 where details of penetration designs are presented.
(a) Exceptions are the three RHR injection lines. The valves in these lines will be tested from the outboard side, as there is no way to test from the inboard side.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-56 Revision 21 September 2013 6.2.5 COMBUSTIBLE GAS CONTROL IN CONTAINMENT Because of the possibility of hydrogen release to the containment atmosphere following a LOCA, means to monitor and control the postaccident concentration of hydrogen in the containment are necessary. This section contains the analysis of the potential hydrogen production rates and the description of the monitoring and control system.
In the Preliminary Safety Analysis Report (PSAR) (Reference 9) for DCPP Unit 2, an analysis of the expected hydrogen production concluded that any hydrogen accumulation could be controlled by containment venting, with radiological exposures below the annual limits specified in 10 CFR 20. Using more conservative parameters, the AEC regulatory staff calculated that the lower flammability limit would be attained in less than 40 days (Reference 10). The staff concluded that the purging operation could result in offsite activity concentration levels that exceed 10 CFR 20 limits. Additional capability for filtering of containment effluent, including charcoal beds, would, however, reduce the I-131 concentration level. Assuming 90 percent filter efficiency for iodine removal, the staff estimated (Reference 11) that doses at the site boundary would be about 0.8 rem whole body and about 8.5 rem to the thyroid if the entire contents of the containment were vented over a 30-day period. Estimated exposures were, therefore, less than 10 percent of the guideline levels established in 10 CFR 100.
Since then, the research and development work discussed in more detail in Section 6.2.5.3 substantially reduced the uncertainties in both the expected rates of hydrogen accumulation and the potential exposures that would result from hydrogen control by venting as follows:
(1) Research on the corrosion of aluminum and associated hydrogen production rates by Westinghouse (Reference 12 - 15 and 42) has reduced uncertainties on corrosion rates in the expected postaccident environment and allowed a reduction in the expected corrosion rate from the 42 mg/dm2/hr used in the Unit 2 PSAR to the value shown in Figure 6.2-24. (2) The amounts of aluminum used in the as-built plant have been minimized through materials design specifications. Zinc is another significant contributor. The uncertainties in the amounts of hydrogen produced from both have been reduced by itemized accounting (Table 6.2-42).
(3) The amounts of hydrogen expected to be produced by the zirconium-water reaction have been reduced by the more stringent limits established on ECCS performance. (4) Research by the AEC and its contractors (a partial compilation is included in Reference 16) in the context of ECCS studies has substantially reduced uncertainties in the extent of zirconium-water reactions following a LOCA. DCPP UNITS 1 & 2 FSAR UPDATE 6.2-57 Revision 21 September 2013 (5) Reevaluation of energy generation rates has allowed reduction of hydrogen generation rate from sump radiolysis. (6) Research on hydrogen yield in the core and sumps by Westinghouse (References 13-15) has reduced uncertainties in these constants.
(7) Refined analysis of the distribution of fission product decay energy (Reference 17) has resulted in more precise values for the fractions of beta and gamma energies absorbed by water. (8) Additional meteorological data and analysis (References 18-20) conducted by PG&E as a part of the 2-year site program has established high probabilities of conditions favorable for controlled venting. (9) Development of the general purpose EMERALD (Reference 21) computer program for the calculation of doses following accidents has resulted in more accurate estimates of potential exposures, and permitted additional sensitivity studies of the influence of various parameters on potential exposures.
Subsequently, redundant thermal recombiners were installed inside containment. Thermal recombiners are now the primary means of postaccident combustible gas control. The original hydrogen purge system has been retained as a backup system.
In addition, blind flanges are provided on purge system piping and outside containment to allow postaccident installation of portable recombiners and their control packages should they ever be needed. Also, previously unused containment penetrations are now dedicated to the exclusive use of the hydrogen purge system. 6.2.5.1 Design Bases The general design criteria are as follows:
(1) The basic data and analytical models and assumptions used for hydrogen production and accumulation are based on Regulatory Guide (RG) 1.7 (Reference 22). (2) To ensure that the lower flammability limit (4 percent) will not be exceeded, the internal electric hydrogen recombiners will be started at or below 3.5 percent by volume. (3) The use of corrodable materials that yield hydrogen has been controlled in the containment to minimize hydrogen production. (4) The internal electric hydrogen recombiners control containment hydrogen concentration following a LOCA to at or below 4.0 percent by volume.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-58 Revision 21 September 2013 Each of the two redundant recombiners is capable of providing the required removal capacity. The containment hydrogen purge system serves as a backup system only. (5) The recombiner and purge systems meet Design Class I design and construction standards. (6) The containment purge system is provided with charcoal filters to minimize the release of radioactive iodine. The filters are sized in accordance with activity loading specifications associated with ESFs. (7) The purge system is designed for constant or intermittent operation, and will be operated under strict administrative controls. (8) Instrumentation is provided to monitor the flowrate and the amount of activity released by the purging operation. (9) The estimated incremental exposures resulting from containment venting are a negligible addition to those estimated for containment leakage. (10) The operators are provided with current data on containment hydrogen concentration, containment activity levels, wind direction, and wind speed to determine optimum purge schedules. 6.2.5.2. System Design The designs of the internal hydrogen recombiners and the hydrogen purge system are described in this section. 6.2.5.2.1 Thermal Recombiners Internal electric hydrogen recombiner systems (EHRS) were installed in both units of the DCPP as the primary means of controlling containment atmosphere hydrogen concentration following a LOCA. The EHRS are Design Class I because in the event of a LOCA their operation to mitigate the effects of the accident must be ensured.
The EHRS is a natural convection, flameless, thermal reactor-type hydrogen-oxygen recombiner. In its basic operation, it heats a continuous stream of air-hydrogen mixture to a temperature sufficient for spontaneous recombination of the hydrogen with the oxygen in the air to form water vapor.
The system consists of two independent recombination units, each of which contains the electric heater banks, a power supply panel that contains the equipment for powering the heaters, and a power control panel to the heaters. The recombination units are located inside the reactor containment building; the power supply and control panels are located outside this building. DCPP UNITS 1 & 2 FSAR UPDATE 6.2-59 Revision 21 September 2013 This system provides 100 percent redundancy since each recombiner and its associated power supply and control panel are capable of providing the required hydrogen removal capacity. The second unit, including its associated power supply and control panels, is normally on standby following a postulated LOCA.
The EHRS design characteristics are as follows: Normal Operating Conditions Post-LOCA Operating Conditions Temperature, °F 120 288 (max) Pressure, psia 15 77 (max) Pressure transient, psia N/A 77 (max in 10 sec) Relative humidity, % 0-100 100 Radiation, rads/hr 5 3.3 x 105 Radiation-total dose, rads NA 2 x 108 (max) Spray solution, ppm B/pH NA/NA 2550/9-10.5 Design life, yr 40 NA Recombiner capacity, scfm of containment gas at 1 atm NA 100 (min) The recombination unit consists of an inlet preheater section, a heater-recombination section, and a mixing chamber (see Figure 6.2-23). Air and the hydrogen are drawn into the unit by natural convection via the inlet louvers and pass through the preheater section, which consists of a shroud placed around the central heaters to take advantage of heat conduction through the walls. In this area, the temperature of the inlet air is raised. This rise in temperature accomplishes the dual function of increasing system efficiency and evaporating any moisture droplets that may be entrained in the air. The warmed air then passes through the flow orifice that has been specifically sized to regulate air flow through the unit. After passing through the orifice plate, the air flows vertically upward through the heater section, where its temperature is raised to the range of 1150°F to 1400°F, causing recombination of H2 and O2 to occur. The recombination temperature is approximately 1135°F.
Next, the air rises from the top of the heater section and flows into the mixing chamber, which is at the top of the unit. Here, the hot air is mixed with the cooler containment air and then discharged back into the containment at a lower temperature. The cooler containment air enters the mixing chamber through the lower part of the upper louvers located on three sides of the unit.
The unit is completely enclosed and the internals are protected against impingement from containment spray. The major structural components are manufactured from stainless steel and Incoloy-800. The heater sheathing is also Incoloy-800.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-60 Revision 21 September 2013 Each bank is constructed of Incoloy-800 sheathed tubular elements mounted in a heavy-gauge steel flange with holes for mounting into the recombination unit heater frame.
There are four banks of heaters in each recombination unit. Each bank contains 60 individual, U-type heating elements connected in series-parallel arrangements as required to obtain the power rating for each bank. The internal connections are wired to special terminal blocks located outside the heater flange. Each bank is sized for a specific power rating.
The power supply panel contains all the necessary electrical equipment to provide the power required by the heaters in the recombination unit.
The panel consists of an isolation transformer, silicon-controlled rectifier module, an auxiliary control power transformer, and a main line contactor. The control panel contains all the control and monitoring equipment required for operating the recombination unit and is easily accessible to the plant operators.
The EHRS does not require any instrumentation inside the containment for proper operation after a LOCA. Thermocouples are provided for convenience in testing and periodic checkout; they are not considered necessary, however, to ensure proper operation of the recombiner.
Basically, proper recombiner operation after an accident is ensured by measuring the amount of electric power to the recombination unit from the control panel. The temperature readout device is a monitoring unit, not a control unit.
6.2.5.2.2 Hydrogen Purge System The CHPS is a Design Class I system consisting of two diverse purge routes and two redundant supply routes. The system is a backup to the thermal recombiners for control of hydrogen and includes provisions for postaccident installation of portable recombiners. The basic features of the CHPS are shown in Figures 6.2-20, 6.2-21, and 6.2-22.
Each purge stream leaves the containment through a motor-operated isolation valve, which opens remotely during venting. Dedicated penetrations are used for the purge system. One purge stream is routed through a gate valve, roughing filter, HEPA filter, charcoal, HEPA after-filter, a blower, a hand control valve, a flow measuring device, plant vent radiation monitor, and the associated plant vent radiation monitoring systems. The second purge stream is routed through a gate valve, a flow measuring device, a hand-controlled valve, and the containment excess pressure relief line to the auxiliary building ventilation system carbon filter plenum. This purge stream then follows the auxiliary building ventilation exhaust flowpath through the roughing filter, HEPA filter, carbon adsorber, exhaust fan, plant vent and the associated plant vent radiation DCPP UNITS 1 & 2 FSAR UPDATE 6.2-61 Revision 21 September 2013 monitoring system. The purge stream can be operated independently of the supply stream.
The supply stream is drawn through a roughing filter and a blower and routed through a hand control valve, a flow measuring device, a gate valve, and isolation check valves. The supply stream can be operated independently of the purge stream.
The supply stream entrance and the purge stream exit are widely separated to prevent short circuiting. The containment fan cooler units ensure complete mixing of the postaccident containment atmosphere.
All motor-operated valves inside containment are supplied with Class 1E power.
Two hydrogen monitors per unit monitor postaccident hydrogen concentration (see Figure 6.2-22). Their characteristics are described in Section 6.2.5.5.
Prior to initiation of hydrogen purge, the containment radiation monitoring system is used to monitor, either continuously or intermittently, the radioactivity in containment. The plant vent radiation monitors measure the radioactivity in the purge stream.
The CHPS is designed for either intermittent or continuous flow operation. While the hydrogen recombiner system is the design basis system for post-LOCA containment hydrogen control, in the event that hydrogen concentration were to reach the control limit of 3.5 percent, the hydrogen purge system may be placed into operation under strict administrative controls. The supply stream isolation valves and blower are operated manually. The supply stream provides for immediate dilution, and the hydrogen concentration decreases. The purge stream is initiated after the supply stream begins diluting hydrogen. The supply and the purge streams may be adjusted to regulate the flowrates to values required to maintain hydrogen level in the containment at or below the 4.0 percent limit. Instrumentation is provided to monitor flowrate, hydrogen concentration, and radiation levels.
While it is intended to serve only as a backup to the recombiners, and may not be acceptable for operation following a LOCA, the hydrogen purge system otherwise satisfies the design requirements for an ESF system. Two redundant systems complete with separate lines, blowers, and filters have been provided. These lines, valves, instrumentation, and blowers are Design Class I. Each blower and its associated controls are powered by independent electrical power supplies. 6.2.5.3 Design Evaluation 6.2.5.3.1 Hydrogen Productions and Accumulation Following a LOCA, hydrogen will be produced inside the reactor containment by radiolysis of the core and sump solutions, by corrosion of aluminum and zinc, by DCPP UNITS 1 & 2 FSAR UPDATE 6.2-62 Revision 21 September 2013 reaction of the zirconium in fuel cladding with water, and by release of the hydrogen contained in the reactor coolant system. 6.2.5.3.1.1 Method of Analysis The quantity of zirconium, which reacts with the core cooling solution, depends on the performance of the ECCS.
The criteria for ECCS evaluation (10 CFR 50.46) requires that the zirconium-water reaction be limited to 1 percent by weight of the total quantity of zirconium in the core. ECCS calculations have shown the zirconium-water reaction to be less than 1 percent.
Aluminum inside the containment is not used in safety-related components that are in contact with the recirculating core cooling fluid. It is more reactive with the containment spray alkaline borate solution than other plant materials such as galvanized steel, copper, and copper nickel alloys.
The zirconium-water reaction and aluminum and zinc corrosion with containment spray are chemical reactions, which are essentially independent of the radiation field inside the containment following a LOCA. Radiolytic decomposition of water is dependent on the radiation field intensity. The radiation field inside the containment is calculated for the maximum credible accident for which the fission product activities are given in TID-14844 (Reference 24).
The hydrogen generation is calculated using the NRC model discussed in RG 1.7 (Reference 22), Standard Review Plan 6.2.5 (Reference 40) and Branch Technical Position CSB 6-2 (Reference 41). 6.2.5.3.1.2 Assumptions The following assumptions are made: Zirconium-Water Reaction The zirconium-water reaction is described by the chemical equation: Zr + 2H2O Zr O2 + 2H2 + Heat Hydrogen generation due to this reaction will be completed during the first day following the LOCA. The NRC model assumes a 5 percent (5 times the maximum allowable value defined by 10 CFR 50, Appendix K (ECCS)) zirconium-water reaction. The hydrogen generated is assumed to be released immediately to the containment atmosphere. Approximately 7.9 standard cubic feet (SCF) of hydrogen gas are produced for each pound of zirconium metal reacted.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-63 Revision 21 September 2013 Hydrogen from the Reactor Coolant System The quantity of hydrogen in the RCS during normal operation includes hydrogen from the pressurizer gas space and hydrogen dissolved in the reactor coolant. The pressurizer gas space hydrogen is based on:
(1) A maximum allowable coolant hydrogen concentration of 60 cc(stp)/kg(a) of coolant (2) Control banks of pressurizer heaters will modulate to control pressurizer heat losses to maintain constant pressurizer temperature and pressure (3) Minimum bypass spray rate of 2.0 gpm (4) Normal liquid level of the pressurizer (60 percent) (5) Pressurizer power-operated relief valves closed The hydrogen from the reactor coolant and the pressurizer vapor space is available for release to the containment immediately following a LOCA. Corrosion of Plant Materials Oxidation of metals in aqueous solution generates hydrogen gas as one of the corrosion products. Extensive corrosion testing has been conducted to determine the behavior of the various metals used within the containment. Metals tested include zirconium alloys, Inconel, aluminum alloys, cupronickel alloys, carbon steel, galvanized carbon steel, and copper.
Tests conducted at ORNL (References 25 and 26) and Westinghouse (Reference 42) have verified the compatibility of the various materials with alkaline borate solution and have shown that aluminum and zinc will corrode at a rate that will significantly add to the hydrogen accumulation in the containment atmosphere.
The corrosion of aluminum may be described by the overall reaction: 2 Al + 3 H2O Al2O3 + 3 H2 Three moles of hydrogen are produced for every two moles of aluminum oxidized. Approximately 20 scf of hydrogen are produced for each pound of aluminum corroded.
The corrosion of zinc may be described in the overall reaction: Zn + 2H2O Zn(OH)2 + H2 (a) stp = standard temperature and pressure DCPP UNITS 1 & 2 FSAR UPDATE 6.2-64 Revision 21 September 2013 One mole of hydrogen is produced for each mole of zinc oxidized. Approximately 5.5 scf of hydrogen gas are produced for each pound of zinc corroded.
The time-temperature cycle (Table 6.2-41) considered in the calculation of aluminum and zinc corrosion is a step-wise representation of the postulated postaccident containment temperature transient. The corrosion rates at the various steps were determined from the aluminum and zinc corrosion rate design curves (References 42 and 55) shown in Figure 6.2-24, which include the effects of temperature and spray solution conditions. For conservative estimation, no credit was taken for protective shielding effects of insulation or enclosures from the spray, and complete and continuous immersion was assumed.
The calculations were performed by Westinghouse using the methodology of RG 1.7 but using the corrosion rates given in Figure 6.2-24 and the containment time-temperature values given in Table 6.2-41.
For this hydrogen generation reanalysis the aluminum and zinc inventories inside containment are as shown in Table 6.2-42. Radiolysis of Core and Sump Water Water radiolysis is a complex process involving reactions of numerous intermediates. However, the overall radiolytic process may be described by the reaction: 2222/1OHOH+ Table 6.2-43 presents the total decay energy ( + ) of a reactor core. It assumes full power operation with extended fuel cycles prior to the accident. For the maximum credible accident case, the contained decay energy in the core accounts for the assumed TID-14844 release of 50 percent halogens and 1 percent other fission products. In the TID-14844 model, the noble gases are assumed to escape to the containment vapor space.
The yield of hydrogen from radiolytically decomposed solution has been studied extensively by Westinghouse and ORNL. The results of static capsule tests conducted by Westinghouse indicate hydrogen yields much lower than 0.44 molecules per 100 eV for core radiolysis.
There are, however, differences between the static capsule tests and the dynamic condition in core, where the cooling fluid is continuously flowing. The flow is assumed to disturb the steady state conditions that are observed in static capsule tests, and while the occurrence of back reactions is still significant, the overall net yield of hydrogen is somewhat higher in the flowing system.
Westinghouse studies of radiolysis in dynamic systems (Reference 15) show 0.44 molecules per 100 eV to be a maximum yield for high solution flowrates through a DCPP UNITS 1 & 2 FSAR UPDATE 6.2-65 Revision 21 September 2013 gamma radiation field. Work by ORNL (References 25 and 26), Zittel (Reference 28), and Allen (Reference 29) confirm this value.
This analysis, based on RG 1.7, is conservative because it assumes a hydrogen yield value of 0.5 molecules per 100 eV. It also assumes that 10 percent of the gamma energy, produced from fission products in the fuel rods, is absorbed by the solution in the region of the core, and the noble gases escape to the containment vapor space.
Another potential source of hydrogen assumed for the postaccident period arises from water in the reactor containment sump being subjected to radiolytic decomposition by fission products. An assessment must therefore be made of the decay energy deposited in the solution and the radiolytic hydrogen yield, much in the same manner as for core radiolysis.
The energy deposited in solution is computed using the following basis:
(1) For the maximum credible accident, a TID-14844 release model (Reference 24) is assumed where 50 percent of the total core halogens and 1 percent of all other fission products, excluding noble gases, are released from the core to the sump solution.
(2) The quantity of fission product release considers a reactor operating with extended fuel cycles prior to the accident. (3) The total decay energy from the released fission products, both beta and gamma, is assumed to be fully absorbed in the solution. The calculation of the fission product decay energy deposited in the sump solution considers the decay of halogens and the decay of the remaining 1 percent of fission products. The energy release rates and integrated energy release for various times after a LOCA are listed in Table 6.2-44.
The yield of hydrogen from sump solution radiolysis is most nearly represented by the static capsule tests performed by Westinghouse and ORNL with an alkaline sodium borate solution. The differences between these tests and the actual conditions for the sump solution, however, are important and render the capsule tests conservative in their predictions of radiolytic hydrogen yields.
In this assessment, the sump solution will have considerable depth, which inhibits the ready diffusion of hydrogen from solution, as compared to the case with shallow-depth capsule tests. This retention of hydrogen in solution will have a significant effect in reducing the hydrogen yields to the containment atmosphere. The buildup of hydrogen in solution will enhance the back reaction to form water and lower the net hydrogen yields, in the same manner as a reduction in the gas to liquid volume ratio will reduce the yield. This is illustrated by the data presented in Figure 6.2-25 for capsule tests with various gas to liquid volume ratios. The data show a significant reduction in the net DCPP UNITS 1 & 2 FSAR UPDATE 6.2-66 Revision 21 September 2013 hydrogen yield from the primary maximum yield of 0.44 molecules per 100 eV. Even at the very highest ratios, where capsule solution depths are very low, the yield is less than 0.30, with the highest scatter data point at 0.39 molecules per 100 eV.
Taking these data into account, a reduced hydrogen yield is a reasonable assumption for the case of sump radiolysis. The expected yield is on the order of 0.1 molecules per 100 eV or less. RG 1.7 does not, however, allow credit for the reduced hydrogen yields and a yield value of 0.5 molecules per 100 eV is used in the analyses.
All containment volumes are connected by large vent areas to promote good air circulation. Hydrogen will diffuse very rapidly giving an even distribution under the conditions existing in the containment structure. In addition, thermal mixing effects, heating of air above the hot sump water, and possible steam released from the RCS will move the hydrogen-laden air from the points of generation toward the cool external walls. Although hydrogen is lighter than air, it will not concentrate significantly in high areas because of the high diffusion rate, the open design of the containment, and the fan cooler air mixing.
The ability of hydrogen to diffuse rapidly into all volumes is inferred from a CSE experiment (Reference 23). These tests showed very good mixing in the main chamber and a rapid interchange by diffusion and mixing with the atmosphere of other chambers that had limited communication. The diffusivity of hydrogen is approximately 10 times that of iodine, so a more uniform mixture is expected for hydrogen. Also, higher concentration provides greater concentration gradients for better diffusion than indicated by the CSE tests. Table 6.2-45 summarizes the calculated hydrogen production and accumulation data. 6.2.5.3.1.3 Results of Analyses The results of the hydrogen analyses are presented in Figures 6.2-26 through 6.2-29. 6.2.5.3.1.4 Conclusion From the results shown in Figures 6.2-26 through 6.2-29, a 100 scfm hydrogen recombiner, started when the bulk containment hydrogen concentration reaches 3.5 percent by volume (after 3 days), or earlier, will ensure that the bulk containment hydrogen concentration will not reach the lower flammability limit of 4 percent by volume. The licensing limit of 4.0 percent by volume is assured by operating procedures that direct operators to initiate recombiner operation at hydrogen concentrations as low as 0.5 percent by volume. Thus, neither hydrogen burning nor detonation will occur.
The analysis of potential radiation exposures that could result from venting for hydrogen control is contained in the loss-of-coolant section of Chapter 15.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-67 Revision 21 September 2013 6.2.5.4 Testing and Inspections All Design Class I components of the systems were designed, fabricated, installed, and tested under quality assurance requirements in accordance with 10 CFR 50, Appendix B, as described in Chapter 17.
Nondestructive examination is performed on the components of the systems in accordance with the requirements of the applicable codes as described in Section 3.2. The systems will be tested in accordance with the procedures outlined in Chapter 14. Periodic inservice testings of all fans, valves, and instrumentation in the system will be performed. The valves associated with containment isolation will be tested as described in Section 6.2.4.4. Tests and inspections of filters and fans are described in Section 9.4.
During preoperational startup testing of the plant, a functional test using predetermined sample hydrogen gas mixtures will be performed to verify hydrogen analyzer operation. 6.2.5.5 Instrumentation Requirements Two redundant hydrogen monitors are installed in each unit to provide continuous indication and recording in the control room of containment hydrogen concentration. The monitors are Instrument Class II, Type C, Regulatory Guide 1.97 Category 3 and each has its own dedicated containment penetration and isolation valves to meet single failure criteria (see Figure 6.2-22 for system layout). The monitoring system is capable of sampling and measuring the hydrogen concentration inside the containment to diagnose the course of beyond-design-basis accidents. The system has a range of 0-10 percent by volume. The normal system configuration is with the hydrogen monitors off-line and their respective containment isolation valves closed.
The containment radiation monitoring system and the plant vent radiation monitors are used to monitor the radioactivity in containment and the hydrogen purge line. Spare monitors are available on site. A manual sample point is provided on each exhaust line to obtain a grab sample for laboratory analysis.
Flow indicators and recorders are provided for each exhaust line. The indicators are Design Class I. The range is 0 to 5000 feet per minute (corresponding to flowrates of 0 to 400 cfm).
Isolation valves status is shown on the main control board as indicated in Table 6.2-39. Annunciation is provided to alarm on high radioactivity, high flowrate, and fan failure. 6.2.5.6 Materials Materials of construction of components of the EHRS and the CHPS are indicated in the sections above when appropriate to the discussion. DCPP UNITS 1 & 2 FSAR UPDATE 6.2-68 Revision 21 September 2013 6.
2.6 REFERENCES
- 1. Deleted in Revision 18.
- 2. Deleted in Revision 18.
- 3. Deleted in Revision 18. 4. M. A. Styrikovich, et al, Atomnoya Energya, Vol. 17, No. 1, July 1964, pp. 45-49, (Translation in UD 621.039.562.5). 5. R. M. Kemper, Iodine Removal by Spray in the Diablo Canyon Station Containment, WCAP-7977, September 1973. 6. W. F. Pasedag and J. L. Gallagher, "Drop Size Distribution and Spray Effectiveness," Nuclear Technology, 10, 1971, p. 412. 7. L. F. Parsly, Design Considerations of Reactor Containment Spray Systems, ORNL-TM-2412, Part VII, 1970. 8. A.E.J. Eggleton, A Theoretical Examination of Iodine-Water Partition Coefficient, AERE, (R) - 4887, 1967. 9. Preliminary Safety Analysis Report, Nuclear Unit Number 2, Diablo Canyon Site, Pacific Gas and Electric Company. Supplements Number 3 and 5. 10. Safety Evaluation by the Division of Reactor Licensing (USAEC) in the Matter of Pacific Gas and Electric Company Diablo Canyon Nuclear Power Plant Unit 2 Docket No. 50-323, November 18, 1969. 11. Report on Pacific Gas and Electric Company Nuclear Unit 2 - Diablo Canyon Site, Advisory Committee on Reactor Safeguard, USAEC, October 16, 1969. 12. M. J. Bell, et al, Investigation of Chemical Additives for Reactor Containment Sprays, Westinghouse Electric Corporation, WCAP-7826, December 1971. 13. W. K. Brunot, et al, Control of the Hydrogen Concentration Following a Loss-of-Coolant Accident by Containment Venting for the H. B. Robinson Plant, WCAP-7372, November 1969.
- 14. W. D. Fletcher, et al, "Post-LOCA Hydrogen Generation in PWR Containments," Journal of the American Nuclear Society, June 1970. 15. W. D. Fletcher, et al, "Post-LOCA Hydrogen Generation in PWR Containments", Nuclear Technology 10, 1971, pp. 420-427.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-69 Revision 21 September 2013 16. Draft Environmental Statement Concerning Proposed Rule-Making Action-Acceptance Criteria for Emergency Core Cooling Systems for Light-Water-Cooled Nuclear Power Reactor, USAEC Regulatory Staff, December 1972. 17. J. Sejvar, Distribution of Fission Product Decay Energy in PWR Cores, Westinghouse Electric Corporation, WCAP-7816, December 1971. 18. M. L. Mooney and H. E. Cramer, Meteorological Study of the Diablo Canyon Nuclear Power Plant Site, Pacific Gas and Electric Company, May 1970. 19. M. L. Mooney, Supplement No. 1 to Meteorology Report for Diablo Canyon Site, May 1971. 20. M. L. Mooney, Supplement No. 2 to Meteorology Report for Diablo Canyon Site, June 1972. 21. W. K. Brunot, EMERALD - A Program for the Calculation of Activity Releases and Potential Doses from a Pressurized Water Reactor Plant, Pacific Gas and Electric Company, October 1971. 22. Regulatory Guide 1.7, Rev. 2, Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident, USNRC, November 1978. 23. H. E. Zittel, Radiation and Thermal Stability of Spray Solutions, ORNL-NSRD Program Bi-Monthly Report for May-June, 1969. ORNL-TM-2663, September, 1969. 24. J. J. DiNunno, et al, Calculation of Distance Factors for Power and Test Reactor Sites, AEC Report Number TID-14844, March 23, 1962. 25. W. B. Cottrell, ORNL Nuclear Safety Research and Development Program Bi-Monthly Report for July - August 1968, ORNL-TM-2368, November 1968. 26. W. B. Cottrell, ORNL Nuclear Safety Research and Development Program Bi-Monthly Report for September - October, 1968, ORNL-TM-2425, January 1969, p. 53. 27. Deleted in Revision 18. 28. H. E. Zittel and T. H. Row, "Radiation and Thermal Stability of Spray Solutions," Nuclear Technology, 10, 1971, pp. 436-443. 29. A. O. Allen, The Radiation Chemistry of Water and Aqueous Solutions, Princeton, N. J., Van Nostrand, 1961. 30. Deleted in Revision 18. 31. Deleted in Revision 18. DCPP UNITS 1 & 2 FSAR UPDATE 6.2-70 Revision 21 September 2013 32. Deleted in Revision 18. 33. R. M. Kemper, Iodine Removal by Spray in the Salem Station Containment, WCAP-7952, August 1972. 34. Deleted in Revision 18. 35. Deleted in Revision 18. 36. G. A. Israelson, J. R. van Searen, W. C. Boettinger, Reactor Containment Fan Cooler Cooling Test Coil, WCAP-7336-L, 1969. 37. Deleted in Revision 18. 38. Diablo Canyon Power Plant - Inservice Inspection Program Plan - The Third 10-Year Inspection Interval, Pacific Gas and Electric Company. 39. EQ File IH-05, Containment Fan Cooler Motor, Pacific Gas and Electric Company. 40. Standard Review Plan 6.2.5, Combustible Gas Control. 41. Branch Technical Position CSB 6-2, Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident. 42. D. D Whyte., R. C. Burchell, Corrosion Study for Determining Hydrogen Generating From Aluminum and Zinc During Postaccident Conditions, WCAP-8776, April 1976. 43. Deleted in Revision 18. 44. Deleted in Revision 18.
- 45. F. M. Bordelon, Analysis of the Transient Flow Distribution During Blowdown (TMD Code) WCAP-7548, 1970. 46. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended. 47. IEEE-Std-334, Guide for Type Tests of Class I Motors Installed Inside the Containment of Nuclear Power Generating Stations, 1971.
- 48. AEC Safety Guide 11, Instrument Lines Penetrating Primary Reactor Containment, March 10, 1971.
- 49. Deleted in Revision 18.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2-71 Revision 21 September 2013 50. Westinghouse Letter PGE-91-533, Safety Evaluation for Containment Spray Flow Reduction, February 7, 1991. 51. Westinghouse Letter PGE-89-673, RWST Setpoint Evaluation, July 24, 1989. 52. Deleted in Revision 18. 53. Deleted in Revision 18. 54. Deleted in Revision 18.
- 55. J. C. Griess, A. L. Bacarella, Design Considerations of Reactor Containment Spray Systems - Part III. The Corrosion of Materials in Spray Solutions, ORNL-TM-2412, Part III, December 1969. 56. Deleted in Revision 18. 57. Deleted in Revision 18. 58. Deleted in Revision 18.
6.2.7 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures. DCPP UNITS 1 & 2 FSAR UPDATE 6.3-1 Revision 21 September 2013 6.3 EMERGENCY CORE COOLING SYSTEM 6.3.1 DESIGN BASES The ECCS is designed to cool the reactor core as well as to provide additional shutdown capability following initiation of the following accident conditions:
(1) A pipe break or spurious valve lifting in the RCS that causes a discharge larger than that which can be made up by the normal makeup system, up to and including the circumferential rupture of the largest pipe in the RCS (see Sections 15.3.1 and 15.4.1 for a discussion of these accidents.) (2) Rupture of a control rod drive mechanism (CRDM) causing a rod cluster control assembly (RCCA) ejection accident (see Section 15.4.6) (3) A pipe break or spurious valve lifting in the steam system, up to and including the instantaneous circumferential rupture of the largest pipe in the steam system (see Sections 15.2.14, 15.3.2, and 15.4.2) (4) A steam generator tube rupture (see Section 15.4.3) 6.3.1.1 Range of Coolant Ruptures and Leaks The LOCA analysis for DCPP considered a spectrum of three guillotine breaks. This analysis was supplemented by Westinghouse generic sensitivity studies (References 1 and 2), which demonstrated that the guillotine breaks are the worst case for this type of plant. The large break analysis is discussed in Section 15.4.
The small break analysis included a spectrum of three break sizes. Again, this was supplemented with the generic sensitivity study of Reference 2. The limiting small break was identified as a 4 inch pipe break, but the analysis demonstrated that a small break LOCA is not limiting. The small break analysis is discussed in Section 15.3. 6.3.1.2 Fission Product Decay Heat The primary function of the ECCS following a LOCA is to remove the stored and fission product decay heat from the reactor core to prevent fuel rod damage to the extent that such damage may impair effective core cooling. The acceptance criteria for the accidents, as well as their analyses, are provided in Chapter 15. 6.3.1.3 Reactivity Required for Cold Shutdown The ECCS provides shutdown capability for the accidents listed above by means of shutdown chemical (boron) injection. The most critical accident for shutdown capability is the steam line break and for this accident the ECCS meets the criteria defined in Sections 15.3 and 15.4. DCPP UNITS 1 & 2 FSAR UPDATE 6.3-2 Revision 21 September 2013 6.3.1.4 Capability to Meet Functional Requirements 6.3.1.4.1 Single Failure Capability To ensure that the ECCS will perform its intended function if any of the accidents listed above occurs, it is designed to tolerate a single active failure during the short term immediately following an accident, or to tolerate a single active or passive failure during the long-term following an accident. This subject is detailed in Section 3.1 and Appendix 6.3A. 6.3.1.4.2 Loss of Offsite Power The ECCS is designed to meet its minimum required level of functional performance with onsite electrical power system operation (assuming offsite power is not available) or with offsite electrical power system operation for any of the above abnormal occurrences assuming a single failure as discussed in Section 3.1 and Appendix 6.3A. 6.3.1.4.3 Seismic Requirements The ECCS is designed to perform its function of ensuring core cooling and providing shutdown capability following an accident under simultaneous DDE loading. ECCS operability during and following a Hosgri event has been verified. The seismic requirements are defined in Sections 3.7 and 3.10. 6.3.1.4.4 Systems Operation The operation of the ECCS following a LOCA can be divided into two distinct modes: (1) The injection mode in which any reactivity increase following the postulated accident is terminated, initial cooling of the core is accomplished, and coolant lost from the primary system is replenished (2) The recirculation mode in which long-term core cooling is provided during the accident recovery period A discussion of these modes follows: 6.3.1.4.4.1 Injection Mode After Loss of Primary Coolant As shown in Figure 6.3-4, the principal mechanical components of the ECCS that provide core cooling immediately following a LOCA are the accumulators (one for each loop), the safety injection pumps, the centrifugal charging pumps (CCP1 and CCP2), the residual heat removal (RHR) pumps, and the associated valves, tanks, and piping.
For large pipe ruptures, (0.5 square feet equivalent and larger), the RCS would be depressurized and voided of coolant rapidly. A high flowrate of emergency coolant is DCPP UNITS 1 & 2 FSAR UPDATE 6.3-3 Revision 21 September 2013 required to quickly cover the exposed fuel rods and limit possible core damage. This high flow is provided by the passive accumulators, followed by CCP1 and CCP2, safety injection pumps, and the RHR pumps discharging into the cold legs of the RCS.
During the injection mode, the RHR and safety injection pumps deliver into the accumulator injection lines between the two check valves. The CCP1 and CCP2 deliver through the charging injection line directly into the cold legs.
Emergency cooling is provided for small ruptures primarily by high-head injection(a). Small ruptures are those, with an equivalent diameter of 6 inches or less, that do not immediately depressurize the RCS below the accumulator discharge pressure. CCP1 and CCP2 deliver borated water at the prevailing RCS pressure to the cold legs of the RCS, from the RWST during the injection mode.
The safety injection pumps also take suction from the RWST and deliver borated water to the cold legs of the RCS. The safety injection pumps begin to deliver water to the RCS after the pressure has fallen below the pump shutoff head.
The RHR pumps take suction from the RWST and deliver borated water to the RCS. These pumps begin to deliver water to the RCS only after the pressure has fallen below the pump shutoff head.
The injection mode of emergency core cooling is initiated by the safety injection signal ("S" signal). This signal is actuated by any of the following:
(1) Pressurizer low pressure (2) Containment high pressure (3) Low steamline pressure (4) Manual actuation Operation of the ECCS during the injection mode is completely automatic. The safety injection signal automatically initiates the following actions: (1) Starts the diesel generators and, if all other sources of power are lost, aligns them to the vital buses (2) Starts CCP1 and CCP2, the safety injection pumps, and the RHR pumps (3) Aligns CCP1 and CCP2 for injection by: (a) The charging pumps and safety injection pumps are commonly referred to as "high-head pumps" and the RHR pumps as "low-head pumps." Likewise, the term "high-head injection" is used to denote charging and safety injection pump injection and "low-head injection" refers to RHR pump injection.
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-4 Revision 21 September 2013 (a) Closing the valves in the charging pump discharge line to the normal charging line (b) Opening the valves in the charging pumps suction line from the RWST (c) Closing the valves in the charging pump normal suction line from the volume control tank (d) Opening the charging injection inlet and outlet line isolation valves The injection mode continues until the low level is reached in the RWST, at which time the RHR pumps are automatically tripped. The operator then manually changes system alignment to the recirculation mode. The remaining water in the RWST provides a reserve to be used by the containment spray pumps to ensure that enough sodium hydroxide has been added to the containment, utilizing the spray additive system (SAS), to maintain the pH of the recirculation fluid greater than 8.0. Three channels of RWST instrumentation are used, providing three independent and redundant RWST level indications that are displayed in the control room, to inform the operator of the water level in the tank at all times. Any two of these three channels will actuate the low-level alarm and will automatically trip the RHR pumps on low RWST level. After the changeover is begun, the rate of possible demand on the tank is reduced, providing increasing periods of operation for the pumps still drawing water from the tank, and giving further assurance that water will remain in the tank after the completion of the changeover.
6.3.1.4.4.2 Changeover from Injection Mode to Recirculation After Loss of Primary Coolant Water level indication and alarms on the RWST and level indication in the containment sump provide ample warning to terminate the injection mode while the operating pumps still have adequate NPSH. Since the injection mode of operation following a LOCA is terminated before the RWST is completely emptied, all pipes are kept filled with water before recirculation is initiated. For some small break loss of coolant accidents, the RCS pressure may remain above the shut off head of the RHR pumps which would only be providing recirculation flow. For these scenarios, the operators will trip the RHR pumps or initiate CCW flow to an RHR heat exchanger within 30 minutes. This ensures that pump recirculation does not result in heating and pressurizing the RHR suction piping. Following receipt of the RWST low-level alarm and automatic tripping of the RHR pumps, the remainder of the changeover sequence from injection mode to recirculation mode is accomplished manually by the operator from the control room (except for restoring power to the RWST supply valves to the RHR and the safety injection pumps). The same sequence (as delineated in Table 6.3-5) is followed regardless of which power supply is available (offsite or emergency onsite). Controls for ECCS components DCPP UNITS 1 & 2 FSAR UPDATE 6.3-5 Revision 21 September 2013 are grouped together on the main control board. The component position lights verify when the function of a given switch has been completed. The total required switchover time for the changeover from injection to recirculation is approximately 10 minutes, as shown in Table 6.3-5. The postulated single failure during the changeover sequence is the failure of an RHR pump to trip on low RWST level. The operator action requires approximately 5 minutes to locally open the breaker for an RHR pump motor. The operator action is performed concurrently with the changeover sequence and there is no increase in the total time for the changeover. The changeover sequence can be completed, with the single failure, and the remaining useable RWST volume exceeds the licensing basis of 32,500 gallons. 6.3.1.4.4.3 Recirculation Mode After Loss of Primary Coolant After the injection operation, water collected in the containment sump is cooled and returned to the RCS by the low-head/high-head recirculation flowpath. The RCS can be supplied simultaneously from the RHR pumps and from a portion of the discharge from the residual heat exchanger that is directed to CCP1 and CCP2 and safety injection pumps that return the water to the RCS. The latter mode of operation ensures flow in the event of a small rupture where the depressurization proceeds more slowly, so that the RCS pressure is still in excess of the shutoff head of the RHR pumps at the onset of recirculation. Approximately 7.0 hours after LOCA inception, the operators will manually initiate hot leg recirculation and complete the switchover process within 15 minutes to ensure termination of boiling and prevent boric acid crystallization. Some cold leg recirculation would be maintained after hot leg recirculation is initiated.
The RWST is protected from back flow of reactor coolant from the RCS. All connections to the RWST except those that are designed to return flow to the RWST are provided with check valves to prevent back flow. During normal plant operation, when the RCS is hot and pressurized, there is no direct connection between the RWST and the RCS. Also during normal plant shutdown, when the RCS is being cooled down and the RHR system begins to operate, the RHR system is isolated from the RWST by a motor-operated valve in addition to a check valve.
Redundancy in the external recirculation loop is provided by duplicate centrifugal charging (CCP1 and CCP2), safety injection, and RHR pumps and heat exchangers. Inside the containment, the high-pressure injection system is divided into two separate flow trains. For cold leg recirculation, CCP1 and CCP2 deliver to all four cold legs and the safety injection and RHR pumps deliver also to all four cold legs by separate flowpaths. For hot leg recirculation, each safety injection pump delivers through separate paths to two hot legs, while the RHR pumps deliver to two of the four hot legs.
The sump isolation valves are located in small steel-lined pressure-tight compartments. This arrangement contains any leakage from an isolation valve stem or bonnet.
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-6 Revision 21 September 2013 6.3.1.4.4.4 Operation After Steam Line Rupture Following a steam line rupture, the ECCS is automatically actuated to deliver borated water from the RWST to the RCS. The response of the ECCS following a steam line break is identical to its response during the injection mode of operation following a LOCA. The safety injection signal initiates identical actions as described for the injection mode of the LOCA, even though not all of these actions are required following a steam line rupture; e.g., the RHR pumps are not required since the RCS pressure will remain above the pump shutoff head.
The delivery of the concentrated boric acid from the RWST provides negative reactivity to counteract the increase in reactivity caused by the system cooldown. The CCP1 and CCP2 continue to deliver borated water from the RWST until enough water has been added to the RCS to make up for the shrinkage due to cooldown. The safety injection pumps also deliver borated water from the RWST for the interval when the RCS pressure is less than the shutoff head of the safety injection pumps. After pressurizer water level has been restored, the injection is manually terminated.
The sequence of events following a postulated steam line break is described in Section 15.4.2. 6.3.2 SYSTEM DESIGN 6.3.2.1 Schematic Piping and Instrumentation Diagram Piping schematic diagrams of the ECCS are shown in Figures 3.2-8, 3.2-9, and 3.2-10. 6.3.2.2 Equipment and Component Descriptions The major components of the ECCS are described in the following sections. Pertinent design and operating parameters for ECCS components are given in Table 6.3-1. 6.3.2.2.1 Accumulators The accumulators are pressure vessels partially filled with borated water and pressurized with nitrogen gas. During normal operation each accumulator is isolated from the RCS by two check valves in series. Should the RCS pressure fall below the accumulator pressure (see Table 6.3-1), the check valves open and borated water is forced into the RCS. One accumulator is attached to each of the cold legs of the RCS. Mechanical operation of the swing-disk check valves is the only action required to open the injection path from the accumulators to the core via the cold leg. Sections 6.3.2.15 and 6.3.5.5.1 describe the accumulator motor-operated valve and its position indicator.
Connections are provided to remotely adjust the level and boron concentration of the borated water in each accumulator during normal plant operation, as required. Accumulator water level may be adjusted either by draining to the reactor coolant drain DCPP UNITS 1 & 2 FSAR UPDATE 6.3-7 Revision 21 September 2013 tank and then to the chemical and volume control system (CVCS) holdup tank, or by pumping borated water from the RWST to the accumulator. Samples of the solution in the accumulators are taken periodically to check boron concentration.
Accumulator pressure is provided by a supply of nitrogen gas and can be adjusted as required during normal plant operation. The accumulators are, however, normally isolated from this nitrogen supply. Gas relief valves on the accumulators protect them from pressures in excess of design pressure.
The accumulators are located within the containment but outside of the secondary shield wall, which protects them from missiles. Since the accumulators are located within the containment, a release of the nitrogen gas from the accumulators would cause an increase in normal containment pressure. Containment pressure increase following release of the gas from all accumulators has been calculated and is well below the containment pressure setpoint for ECCS actuation.
Release of accumulator gas is detected by the accumulator pressure indicators and alarms. Thus, the operator can take action promptly as required to maintain plant operation within the requirements of the Technical Specification (Reference 10) covering accumulator operability. 6.3.2.2.2 Refueling Water Storage Tank The content of the RWST is normally used to supply borated water to the refueling canal for refueling operations. In addition to its usual service, this tank provides borated water to the ECCS pumps and the containment spray pumps following a LOCA or MSLB. During normal operation, the RWST is aligned to the suction of the safety injection pumps, RHR pumps, and containment spray pumps. The suction of CCP1 and CCP2 is automatically aligned to the tank by the safety injection signal.
The water in this tank is borated to a minimum concentration of 2300 ppm boron that ensures reactor shutdown by approximately 10 percent k/k when all rod cluster control assemblies (RCCAs) are inserted, and when the reactor is cooled down for refueling. 6.3.2.2.3 Pumps 6.3.2.2.3.1 Residual Heat Removal Pumps The RHR pumps are provided to deliver water from the RWST to the RCS should the RCS pressure fall below their shutoff head. Each RHR pump is a single-stage, vertical, centrifugal pump. It has an integral motor-pump shaft, driven by an induction motor. The unit has a self-contained mechanical seal, which is cooled by component cooling water (CCW).
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-8 Revision 21 September 2013 During the injection mode of ECCS operation, the RHR pumps draw water from the RWST; during the recirculation mode, they draw water from the containment sump. The changeover from the injection mode to recirculation mode (described in Section 6.3.1.4.4.2 and in Table 6.3-5) is initiated by low level in the RWST, which results in an automatic trip of the RHR pumps. The changeover is thus automatically initiated after water is available in the containment sump and before water is exhausted from the RWST. Adequate NPSH is always available to the RHR pumps in both the injection phase and the recirculation phase. Table 6.3-11 lists available and required NPSH. Phase I of the preoperational system test (see Section 6.3.4.2.2.1) verified that the RHR pump performance was satisfactory for all required alignments.
A minimum flow recirculation line is provided for the pumps to recirculate fluid through the residual heat exchangers and return the cooled fluid to the pump suction should these pumps be started with their normal flowpaths blocked. Once flow to the RCS is established, the recirculation line is automatically closed. This line prevents deadheading the pumps and permits pump testing during normal operation. To prevent pump to pump interaction as a result of differences between pump flow characteristics, check valves were installed downstream of the RHR heat exchangers. During minimum flow operation the check valve will prevent the stronger pump from deadheading/reversing flow into the weaker pump, thereby maintaining minimum required recirculation flow. The RHR pumps are also discussed in Section 5.5.6. 6.3.2.2.3.2 Centrifugal Charging Pumps (CCP1 and CCP2) When aligned for safety injection operation, CCP1 and CCP2 deliver water from the RWST to the RCS at the prevailing RCS pressure. CCP1 and CCP2 are multistage, diffuser design, barrel-type casing with vertical suction and discharge nozzles. The pump is driven by an induction motor. The unit has a self-contained lubrication system cooled by CCW and a mechanical seal system that requires no external cooling.
A minimum flow bypass line is provided on each pump discharge to recirculate flow to the pump suction after cooling in the seal water heat exchanger during normal operation. Valves in minimum flow bypass lines are closed by the operator when the ECCS is transferred to the recirculation mode of operation following a LOCA. During normal plant operation, CCP1 or CCP2 may be in use. CCP1 and CCP2 may be tested during normal operation through the use of the minimum flow bypass line. 6.3.2.2.3.3 Safety Injection Pumps Safety injection pumps deliver water from the RWST to the RCS after the RCS pressure is reduced below the shutoff head of the pumps. Each safety injection pump is a multistage, centrifugal pump. The pump is driven directly by an induction motor. The unit has a self-contained lubrication system and a mechanical seal system that are cooled by CCW.
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-9 Revision 21 September 2013 A minimum flow bypass line is provided on each pump discharge to recirculate flow to the RWST in the event the pumps are started with the normal flowpaths blocked. This line also permits pump testing during normal operation. Two motor-operated valves in series are provided in this line. These valves are closed by operator action during the switchover to the ECCS recirculation mode. 6.3.2.2.4 Residual Heat Exchangers The RHR heat exchangers are conventional shell- and U-tube-type units. During normal cooldown of the primary system, reactor coolant flows through the tube side while CCW flows through the shell side. During the emergency core cooling recirculation phase, water, from the containment sump, flows through the tube side. Further discussion of the RHR heat exchangers is found in Section 5.5.6. 6.3.2.2.5 Valves Stroke times for motor-operated valves used in the ECCS are given in Table 6.3-1. This table also lists the leakage specification for the various type of valves used in the ECCS. Setpoints and capacities for relief valves are given in Table 6.3-10.
Design features employed to minimize valve leakage include the following:
(1) Globe valves, which during postaccident recirculation are normally closed, are installed with the recirculated fluid pressure under the seat to prevent stem leakage of recirculated (radioactive) water. (2) Relief valves are enclosed; i.e., they are provided with a closed bonnet and discharge to a closed system. (3) Control and motor-operated valves (2-1/2 inches and above) in the RHR portion of the ECCS recirculation loop outside containment have double-packed stuffing boxes and stem leakoff connections to the equipment drain system. Valves in the other portions of the ECCS recirculation loop outside containment have their leakoff connections capped. 6.3.2.2.5.1 Motor-Operated Gate Valves The seating design of all motor-operated gate valves is of either the parallel-disk design or the flexible wedge design. These designs release the mechanical holding force during the first increment of travel so that the motor operator works only against the frictional component of the hydraulic imbalance on the disk and the packing box friction.
The disks are guided throughout the full disk travel to prevent chattering and provide ease of gate movement. The seating surfaces are hard-faced to prevent galling and reduce wear.
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-10 Revision 21 September 2013 Where a gasket is employed for the body-to-bonnet joint, it is either a fully trapped, controlled compression, spiral-wound gasket with provisions for seal welding, or of the pressure-seal design. The valve stuffing boxes are designed with a lantern ring leakoff connection with a minimum of a full set of packing below the lantern ring and a minimum of one-half of a set of packing above the lantern ring for valves that have leakoff connections piped to an equipment drain system.
The motor operator incorporates a "hammer blow" feature that allows the motor to attain its full speed prior to being placed under load. Valves are designed to function with a pressure differential across the valve disk determined in accordance with NRC Generic Letter 89-10, "Safety-Related Motor-Operated Valve Testing and Surveillance." 6.3.2.2.5.2 Manual Globe, Gate, and Check Valves Gate valves are either wedge design or parallel-disk and are straight through. The wedge is either split or solid. All gate valves have a backseat, outside screw, and yoke.
Globe valves, "T" and "Y" style, are full-ported with outside screw and yoke construction.
Check valves are spring-loaded lift-piston-types for sizes 2 inches and smaller, swing-type for size 2-1/2 to 4 inches and either tilting or swing-disk-type for size 4 inches and larger. Stainless steel check valves have no penetration welds other than the inlet, outlet, and bonnet. The check hinge is serviced through the bonnet.
The stem packing and gasket of the stainless steel manual globe and gate valves are similar to those described above for motor-operated valves. Carbon steel manual valves are employed to pass nonradioactive fluids only and therefore do not contain the double packing and seal weld provisions. 6.3.2.2.5.3 Diaphragm Valves The diaphragm valves are of the Saunders patent type, which uses the diaphragm member for shutoff with even weir bodies. These valves are used in systems not exceeding a design temperature and pressure of 200°F and 200 psig, respectively. 6.3.2.2.5.4 Accumulator Check Valves (Swing-Disk) The accumulator check valves are designed with a low pressure drop configuration with all operating parts contained within the body.
Design considerations and analyses that ensure that leakage across the check valves located in each accumulator injection line will not impair accumulator availability are as follows:
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-11 Revision 21 September 2013 (1) During normal operation the check valves are in the closed position with a nominal differential pressure across the disk of approximately 1650 psi. Since the valves remain in this position except for testing or when called upon to function, and are therefore not subject to abuse of flowing operation or impact loads caused by sudden flow reversal and seating, they do not experience significant wear of the moving parts and are expected to function with minimal leakage. (2) When the RCS is being pressurized during the normal plant heatup operation, the check valves are tested for leakage as soon as there is a stable differential pressure of about 100 psi or more across the valve. This test confirms the seating of the disk and whether or not there has been an increase in the leakage since the last test. When this test is completed, the discharge line motor-operated isolation valves are opened and the RCS pressure increase is continued. There should be no increase in leakage from this point on since increasing reactor coolant pressure increases the seating force and decreases the probability of leakage. (3) The experience derived from the check valves employed in the emergency injection systems indicates that the system is reliable and workable. This is substantiated by the satisfactory experience obtained from operation of the Ginna and subsequent plants where the usage of check valves is identical to this application. (4) The accumulators can accept some inleakage from the RCS without affecting availability. Inleakage would require, however, that the accumulator water volume be adjusted in accordance with Technical Specification requirements. 6.3.2.2.5.5 Relief Valves Relief valves are installed in various sections of the ECCS to protect the system from overpressure. Valves that normally see liquid service have their stem and spring adjustment assemblies isolated from the system fluid by a bellows seal between the valve disk and spindle. The closed bonnet provides an additional barrier for enclosure of the relief valves. Table 6.3-10 lists the system relief valves with their capacities and setpoints. The accumulator relief valves are sized to pass nitrogen gas at a rate in excess of the accumulator gas fill line delivery rate. The relief valves will also pass water in excess of the maximum water fill rate, but this is not considered important, because the time required to fill the gas space gives the operator ample opportunity to correct the situation.
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-12 Revision 21 September 2013 6.3.2.2.5.6 Ball Valves Each main RHR line has an air-operated ball valve, which is normally open and is designed to fail in the open position, thus maximizing flow from this system to the RCS during ECCS operation. These ball valves at the discharge of each RHR system heat exchanger along with the ball valve in the RHR system heat exchanger bypass line are adjusted during RHR system operation to meet the design plant cooldown requirements. 6.3.2.2.6 Piping All piping joints are either welded, flanged, or threaded connections.
Weld connections for pipes sized 2-1/2 inches and larger are butt-welded. Minimum piping and fitting wall thickness as determined by ANSI B31.7 Code formula are increased to account for the material specifications permissible tolerance on the nominal wall and an appropriate allowance for wall thinning on the external radius during any pipe bending operations in the shop fabrication of the subassemblies. 6.3.2.2.7 Heat Tracing Heat tracing is installed on piping, valves, flanges, and instrumentation lines normally containing concentrated boric acid solution. The heat tracing is designed to prevent boric acid precipitation due to cooling, by compensating for heat loss. The heat tracing is arranged in parallel circuits in a bifilar configuration. The parallel circuits are supplied from different power sources to provide power supply redundancy. One circuit is used for normal operation and the second, using slightly lower setpoints, serves as a backup. Each circuit is controlled independently by a thermostat at a location having a temperature representative of the circuit. Thermocouples to detect pipe temperature are installed under the thermal insulation near the thermostats. Selected thermocouples are monitored, and both low and high temperatures are alarmed in the control room. The thermocouple monitor has local indication and stored data memory that may be downloaded to commercial spreadsheet software and printed. Because the precipitation temperature of 4 percent boric acid is below normal room temperature, the boric acid line heat tracing functions as a precautionary measure, and is not safety-related.
Therefore, with the lowering of the normal boric acid solution from 12 to 4 percent, for Cycle 5 and later, the safety-related boric acid heat tracing on piping, valves, flanges, and instrumentation lines carrying boric acid solution were downgraded from safety-related to non-safety related. Two trains of boric acid heat tracing are provided to ensure the boric acid solution temperature does not fall below the precipitation temperature of approximately 65°F. DCPP UNITS 1 & 2 FSAR UPDATE 6.3-13 Revision 21 September 2013 6.3.2.3 Applicable Codes and Classifications The codes and standards to which the individual ECCS components are designed are listed in Table 6.3-2. 6.3.2.4 Material Specifications and Compatibility Materials employed for ECCS components are given in Table 6.3-3. Materials are selected to meet the applicable material code requirements of Table 6.3-2 and the following additional requirements:
(1) All parts of components in contact with borated water are fabricated of or clad with austenitic stainless steel or similar corrosion-resistant material. (2) All parts of components in contact (internal) with sump solution during recirculation are fabricated of austenitic stainless steel or similar corrosion resistant material. (3) Valve seating surfaces are hard-faced with Stellite No. 6 or similar to prevent galling and to reduce wear. (4) Valve stem materials were selected for their corrosion resistance, high tensile properties, and resistance to surface scoring by the packing.
The elevated temperature of the sump solution during recirculation is well within the design temperature of all ECCS components. In addition, consideration has been given to the potential for corrosion of various types of metals exposed to the fluid conditions prevalent immediately after the accident or during long-term recirculation operations.
Environmental testing of ECCS equipment inside the containment, which is required to operate following a LOCA, is discussed in Reference 6 and Section 3.11. The results of the test program indicate that the equipment will operate satisfactorily during and following exposure to the combined containment postaccident environmental temperature, pressure, chemistry, and radiation. 6.3.2.5 Design Pressures and Temperatures The component design pressure and temperature conditions as given in Table 6.3-1 are specified as the most severe conditions to which each component is exposed to during either normal plant operation or during ECCS operation. ECCS components are designed to withstand the appropriate seismic loadings in accordance with their Design Class.
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-14 Revision 21 September 2013 6.3.2.6 Coolant Quantity The quantities and minimum boron concentration of coolant available to the ECCS are summarized in Table 6.3-1.
The minimum volume that will be maintained in the RWST is 455,300 gallons (this includes the usable and unusable volume). In the event of a LOCA, this volume also provides a sufficient amount of borated water to meet the following requirements: (1) Provide adequate coolant during the injection phase to meet ECCS design objectives. (Refer to Sections 15.3 and 15.4.) (2) Increase the boron concentration of reactor coolant and recirculation water to a point that ensures no return to criticality with the reactor at cold shutdown and all control rods, except the most reactive RCCA, inserted into the core. (Refer to Sections 15.3.1 and 15.4.1.) (3) Fill the containment sump to support continued operation of the ECCS System pumps at the time of transfer from the injection mode to the recirculation mode of cooling. The sump screens are required to be fully submerged to prevent vortexing and air ingestion, during changeover from the injection mode to the recirculation mode, for a large-break LOCA (LBLOCA) (Reference 16). (4) Fulfill spray requirements. 6.3.2.7 Pump Characteristics Typical performance curves for RHR pumps, CCP1 and CCP2, and safety injection pumps are shown in Figures 6.3-1, 6.3-2, and 6.3-3, respectively. The upper curves represent the typical performance characteristics of the pump. The lower curves illustrate that margins for the potential pump degradation have been considered in the analyses described in Chapter 15. 6.3.2.8 Heat Exchanger Characteristics The RHR heat exchangers are described in Sections 6.3.2.2.5 and 5.5.6. Design characteristics are included in Table 5.5-10. 6.3.2.9 ECCS Flow Diagrams Alignment of the major ECCS components during the injection and recirculation phases is shown in Figures 6.3-4 and 6.3-5, respectively. Tables 15.3-2 and 15.3-3 summarize the calculated times at which the major components perform their safety-related functions for various accident conditions (tabulated in Table 15.1-2) that require ECCS operations.
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-15 Revision 21 September 2013 6.3.2.10 Relief Valves and Vents Relief valves installed in the ECCS are described in Section 6.3.2.2.6.5. Table 6.3-10 lists the system relief valves, along with their capacities and setpoints. 6.3.2.11 System Reliability ECCS reliability was considered in all aspects of system evolution, from initial design to periodic testing of the components during plant operation. The ECCS is a two-train, fully redundant, standby ESF. The system was designed to withstand any single credible active failure during injection or active or passive failure during recirculation and maintain the performance objectives outlined in Section 6.3.1. Two trains of pumps, heat exchangers, and flowpaths are provided for redundancy; only one train is required to satisfy performance requirements. Initiating signals for the ECCS are derived from independent sources as measured from process (e.g., low pressurizer pressure) or environmental variables (e.g., containment pressure).
Each train is physically separated and protected so that a single event cannot initiate a common mode failure. Each ECCS train is supplied from separate vital power sources. The vital power sources are discussed in Chapter 8.
The preoperational testing program ensures that the systems, as designed and constructed, meet functional requirements.
The ECCS is designed with the ability for on-line testing of most components so that availability and operational status can be readily confirmed. The integrity of the ECCS is ensured through examination of critical components during routine inservice inspection. 6.3.2.12 Protection Provisions The provisions taken to protect the ECCS from damage that might result from dynamic effects associated with a postulated rupture of piping are discussed in Section 3.6. The provisions taken to protect the system from missiles are discussed in Section 3.5. The provisions to protect the system from seismic damage are discussed in Sections 3.7, 3.9, and 3.10. Thermal stresses on the RCS are discussed in Section 5.2. 6.3.2.13 Provisions for Performance Testing Design features have been incorporated to ensure that the following testing can be performed:
(1) Active components may be tested periodically for operability (e.g., pumps on miniflow, certain valves, etc.).
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-16 Revision 21 September 2013 (2) An integrated system actuation test(a) can be performed when the plant is cooled down and the RHR system is in operation. The ECCS will be arranged so that no flow will be introduced into the RCS for this test. (3) An initial flow test of the full operational sequence can be performed. Specific design features that ensure this test capability are the following:
(1) Power sources are provided to permit actuation of individual ECCS active components. (2) The safety injection pumps can be tested periodically during plant operation using the minimum flow recirculation lines provided. (3) The RHR pumps are used every time the RHR system is put into operation. They can also be tested periodically when the plant is at power using the miniflow recirculation lines. (4) The CCP1 and CCP2 are either normally in use for charging service or can be tested periodically on miniflow. (5) Remotely operated valves can be exercised during routine plant maintenance. (6) For each accumulator tank, level and pressure instrumentation is provided for continuous monitoring during plant operation. (7) Pressure instrumentation and a flow indicator are provided in the safety injection pump header and in the RHR pump headers. (8) An integrated system test can be performed when the plant is cooled down and the RHR system is in operation. This test does not introduce flow into the RCS but does demonstrate the operation of the valves, pump circuit breakers, and automatic circuitry including diesel starting and the automatic loading of ECCS components off the diesels (by simultaneously simulating a loss of offsite power to the vital electrical buses). 6.3.2.14 Net Positive Suction Head The ECCS is designed so that adequate NPSH is provided to system pumps. In addition to considering the static head and suction line pressure drop, the calculation of available NPSH in the recirculation mode for the RHR pumps assumes that the vapor pressure of the liquid in the sump equals containment pressure. This assumption ensures that the actual available NPSH is always greater than the calculated NPSH. (a) Details of the testing of the sensors and logic circuits associated with the generation of a safety injection signal, together with the application of this signal to the operation of each active component, are given in Section 7.3.
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-17 Revision 21 September 2013 The calculation of available NPSH during recirculation is as follows: NPSHactual = (h)containment pressure - (h)water vapor, partial pressure + (h)static head - (h)loss NPSHcalculated = (h)static head - (h)loss Adequate NPSH is shown to be available for all pumps as follows: (1) RHR Pumps The NPSH of the RHR pumps was evaluated for normal plant shutdown operation, and for both the injection and recirculation modes of operation for the DBA. Recirculation operation gives the limiting NPSH requirement. The NPSH evaluation was based on all pumps (i.e., both RHR, CCP1 and CCP2, both safety injection, and both containment spray pumps) operating at the maximum design (runout) flowrates. The minimum available and required NPSH values for this pump are given in Table 6.3-11. (2) Safety Injection and Centrifugal Charging Pumps 1 and 2 The NPSH for the safety injection pumps and CCP1 and CCP2 was evaluated for both the injection and recirculation modes of operation for the DBA. The end of the injection mode of operation gives the limiting NPSH available. The limiting NPSH was determined from the elevation head and vapor pressure of the water in the RWST, which is at atmospheric pressure, and the pressure drop in the suction piping from the tank to the pumps. The NPSH evaluation is based on all pumps operating at the maximum design flowrates. Following switchover to the recirculation mode, adequate NPSH is supplied from the containment sump by the booster action of the RHR pumps. The minimum available and required NPSH for these pumps are given in Table 6.3-11. 6.3.2.15 Control of Accumulator Motor-Operated Isolation Valves During power operation, electrical power is removed from the valves by opening the 480V breaker, thereby preventing inadvertent closure due to an electrical short. As the valve is provided with an automatic opening signal whenever RCS pressure exceeds the unblocking pressure, P11, a manual override permits closing of the valves at pressures exceeding P11. (See Figure 7.3-33 for controls.) Additionally, it will open automatically upon receipt of the safety injection signal should the valve be closed and the breaker is racked in. This safety injection signal overrides any bypass feature. Position indicators for these valves are discussed in Section 6.3.5.5.1.
The accumulator power operated isolation valves are considered to be "operating bypasses" in the context of IEEE 279-1971, which requires that bypasses of a protective DCPP UNITS 1 & 2 FSAR UPDATE 6.3-18 Revision 21 September 2013 function be removed automatically whenever permissive conditions are not met. In addition, as these accumulator isolation valves fail to meet single failure criteria, removal of power to the valves is required. 6.3.2.16 Motor-operated Valves and Controls Each containment sump isolation valve is interlocked with its respective pump suction/RWST isolation valve to the RHR system. The interlock is provided with redundant signals from each isolation valve. This interlock prevents opening the sump isolation valve when the RWST isolation valves are open and thus prevents dumping the RWST contents into the containment sump.
To preclude spurious movement of specific motor-operated valves that could result in a loss of ECCS function, electric power is removed from certain valves during normal operation. These valves are listed in Table 6.3-12 and further discussion is provided in Section 6.3.3.2.12. 6.3.2.17 Manual Actions No manual actions are required from the operator during the injection phase of ECCS operation. Those manual actions required for changeover from the injection phase to the recirculation phase are described in Section 6.3.1.4.4.2 and in Table 6.3-5. 6.3.2.18 Process Instrumentation Varied instrumentation is available to assist the operator in assessing postaccident conditions. This instrumentation is listed in Section 6.3.5. 6.3.2.19 Materials Table 6.3-3 lists the materials used in ECCS components. 6.3.3 PERFORMANCE EVALUATION 6.3.3.1 Evaluation Model The evolution of the Westinghouse ECCS performance analysis methodology is discussed in References 1 through 5 and 13 through 15. Its application to the DCPP, which is summarized in this section, has been discussed with and approved by the NRC. 6.3.3.2 ECCS Performance The following events were analyzed to ensure that the limits on core behavior following an RCS pipe rupture are not exceeded when the ECCS operates with minimum design equipment: DCPP UNITS 1 & 2 FSAR UPDATE 6.3-19 Revision 21 September 2013 (1) Large pipe break analysis (2) Small line break analysis (3) ECCS recirculation mode cooling The adequacy of flow delivered to the RCS by the ECCS with the operation of minimum design equipment is demonstrated in Chapter 15.
The design basis performance characteristic is derived from the specified performance characteristic for each pump with a conservative estimate of system piping resistance, based on the final piping layout. The performance characteristic utilized in the accident analyses includes a decrease in the design head for margin. When the initiating incident is assumed to be the severance of an injection line, the injection curve utilized in the analyses accounts for the loss of injection water through the broken line. 6.3.3.2.1 Large Pipe Break Analysis The large pipe break analysis is used to evaluate the initial core thermal transient for a spectrum of pipe ruptures from a break size greater than 1.0 square foot up to the double-ended rupture of the largest pipe in the RCS.
The injection flow from active components is required to control the cladding temperature subsequent to accumulator injection, complete reactor vessel refill, and eventually return the core to a subcooled state. The results indicate that the maximum cladding temperature attained at any point in the core is such that the limits on core behavior as specified in Section 15.4.1 are met. 6.3.3.2.2 Small Pipe Break Analysis The small pipe break analysis is used to evaluate the initial core thermal transient for a spectrum of pipe ruptures, which bounds breaks corresponding to the smallest break size, typically a 3/8 inch diameter opening (0.11 square inch), up to and including a break size of 1.0 square foot. For a break opening 3/8 inch or smaller, the makeup flow rate from either CCP1 or CCP2 is adequate to allow time for an orderly plant shutdown without automatic ECCS actuation.
The results of the small pipe break analysis indicate that the limits on core behavior are adequately met, as shown in Section 15.3.1. 6.3.3.2.3 Recirculation Cooling Core cooling during recirculation can be maintained by the flow from one RHR pump if RCS pressure is low. If RCS pressure remains high, either CCP1 or CCP2 and one safety injection pump operating in series with one RHR pump provide the added head and flow needed to maintain adequate cooling. DCPP UNITS 1 & 2 FSAR UPDATE 6.3-20 Revision 21 September 2013 Heat removal from the recirculated sump water is accomplished via operation of one or both of the residual heat exchangers. 6.3.3.2.4 Required Operating Status of ECCS Components Normal operating status of ECCS components is given in Table 6.3-6.
ECCS components are available whenever the coolant energy is high and the reactor is critical. During low temperature physics tests, there is a negligible amount of stored energy and low decay heat in the coolant; therefore, an accident comparable in severity to accidents occurring at operating conditions is not possible in low temperature physics tests, and ECCS components are not required. 6.3.3.2.5 Range of Core Protection Core protection is afforded with the minimum ESF equipment, defined by consideration of the single failure criteria as discussed in Sections 3.1, 6.3.1 and Appendix 6.3A. The minimum design case will ensure that the entire break spectrum is accounted for and the core cooling design bases of Section 6.3.1 are met. The analyses for this case are presented in Sections 15.3 and 15.4.
For large RCS ruptures, the accumulators and the active high-head and low-head pumping components serve to complete the core refill. One RHR pump is required for long-term recirculation.
If the break is small (1.0 square foot or less), the accumulators, CCP1 or CCP2, and one safety injection pump ensure adequate cooling during the injection mode. Long-term recirculation requires operation of one RHR pump in conjunction with CCP1 or CCP2 and one safety injection pump and components of the auxiliary heat removal systems that are required to transfer heat from the ECCS (e.g., CCW system and ASW system). The LOCA analyses, presented in Sections 15.3 and 15.4, indicate that certain modifications (i.e., reduced component availability) to the normal operating status of the ECCS, as given in Table 6.3-6, are permissible without impairing the ability of the ECCS, to provide adequate core cooling capacity. 6.3.3.2.6 ECCS Piping Failures The rupture of the portion of an injection line from the last check valve to the connection of the line to the RCS can cause not only a loss of coolant but impair the injection as well. To reduce the probability of an emergency core cooling line rupture causing a LOCA, the check valves that isolate the ECCS from the RCS are installed adjacent to the reactor coolant piping.
For a small break, the reactor pressure maintains a relatively uniform back pressure in all injection lines so that a significant flow imbalance does not occur. Also, system resistances are balanced by adjustment of throttling valves in the injection lines prior to DCPP UNITS 1 & 2 FSAR UPDATE 6.3-21 Revision 21 September 2013 plant operation. A rupture in an accumulator injection line is accounted for in the analyses by assuming that for cold leg breaks the entire contents of the associated accumulator are discharged through the break. 6.3.3.2.7 External Recirculation Loop Major ECCS components are shielded, as required, from their associated redundant train to facilitate maintenance. During recirculation, following a LOCA, access to these components is not credited.
Pressure relieving devices with setpoints below the shutoff head of the high pressure ECCS pumps, from portions of the ECCS located outside of containment that might contain radioactivity, discharge to the pressurizer relief tank. An analysis has been performed to evaluate the radiological effects of recirculation loop leakage (see Section 15.1). A loop is assumed to include CCP1 or CCP2, a safety injection pump, an RHR pump, an RHR heat exchanger, and the associated piping. Thus two loops are provided, each of which is adequate for core cooling. In the analysis, maximum leakage was assumed as discussed in Appendix 6.3A. Analyses indicate that the offsite dose resulting from such leakage is much less than the guidelines of 10 CFR 100.
Since redundant flowpaths are provided during recirculation, a leaking component in one of the flowpaths may be isolated. This action curtails any further leakage. Maximum potential leakage from components during normal operation is given in Table 6.3-9. Each pump compartment and heat exchanger compartment are provided with sufficient drains to the RHR room sump to prevent compartment overflow due to the design leakage rate. Containment isolation valves can be remote manually closed before the pump compartment can overflow.
This layout permits the detection of a leaking recirculation loop component by means of a radiation monitor that samples the air exiting the heat exchanger compartment. Alarms in the control room will alert the operator when the activity exceeds a preset level. Sump level alarms and operation of sump pumps will be indicated in the control room as a backup for detection of water leaks.
Should a tube-to-shell leak develop in a RHR heat exchanger, the operator will be warned by a CCW high radiation alarm. For large leaks, the operator will also be warned by a CCW surge tank high-level alarm. In the event that the leak cannot be isolated before the CCW surge tank fills, the tank relief valve will lift and direct the excess water to the auxiliary building sump.
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-22 Revision 21 September 2013 6.3.3.2.8 Evaluation of Shutdown Reactivity Capability Following an Abnormal Release of Steam from the Main Steam System Analyses are performed to ensure that the core limitations defined in Sections 15.2, 15.3, and 15.4 are met following a steam line rupture or a single active failure in the main steam system. 6.3.3.2.8.1 Main Steam System Single Active Failure Analyses of reactor behavior following any single active failure in the main steam system that results in an uncontrolled release of steam are included in Section 15.2. The analyses assume that a single valve (largest of the safety, relief, or bypass valves) opens and fails to close, resulting in an uncontrolled cooldown of the RCS.
Results indicate that if the incident is initiated at the hot shutdown condition, which results in the worst reactivity transient, the limit DNBR values will be met. Thus, the ECCS provides adequate protection for this incident. 6.3.3.2.8.2 Steam Line Rupture This accident is discussed in detail in Section 15.4. The limiting steam line rupture is a complete line severance.
The results of the analysis indicate that the design basis criteria are met. Thus, the ECCS adequately fulfills its shutdown reactivity addition function. Following a secondary side high-energy (steam or feedwater) line rupture, CCW is supplied to the seal-water heat exchanger to provide cooling for CCP1 and CCP2 under miniflow conditions. This action prevents damage to the CCPs before safety injection termination criteria are reached and CCP operation is terminated. 6.3.3.2.9 Evaluation of Loss of Offsite Power Diesel generators supply power to ECCS components in the event that all sources of offsite power become unavailable.
The supply of emergency power to the ECCS components is arranged so that, as a minimum, CCP1 or CCP2, one safety injection pump, and one RHR pump together with the associated valves will automatically receive adequate power in the event that a loss of offsite power occurs simultaneously with any of the DBAs described in Section 6.3.1. Adequate power is provided even if the single failure is the failure of an emergency diesel generator to start.
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-23 Revision 21 September 2013 6.3.3.2.10 Evaluation of the Capability to Withstand Postaccident Environment A comprehensive testing program has been undertaken to demonstrate that ECCS components and associated instrumentation and electrical equipment that are located inside the containment will operate for the required time period, under the combined post-LOCA conditions of temperature, pressure, humidity, radiation, chemistry, and seismic phenomena (Reference 6).
Components such as remote motor-operated valves and flow and pressure transmitters have been shown capable of operating for the required postaccident periods, when exposed to post-LOCA environmental conditions. All other ECCS components are located outside of the containment. 6.3.3.2.11 Accumulator Availability Accumulator availability requirements during power operation, hot standby, and startup conditions are detailed in the Technical Specifications. 6.3.3.2.12 Single Failures in Electrical and Control Circuitry ESF systems, including the ECCS, are designed to tolerate single failures in the electrical and control circuitry as defined below. In addition, provisions are made in construction, layout, and installation that minimize the occurrence of electrical faults.
Single failures of switching components that are considered in the design include (a) a single instance of contact failure, (b) a loss of control power, or (c) mechanical failure resulting in the sticking of a component in any position. Faults that require a particular time sequence of abnormal connections or that involve selective combinations of multiple contact closures are considered to involve more than one failure, and hence to be incredible. Examples of a single wiring failure considered in design include the single short and open circuit faults. Single short circuits considered are (a) a single conductor shorted to ground or to a structure such as a cable tray, or (b) two conductors in the same cable shorted together. Faults that require several particular wires to be connected, or which require sustained application of power through a short circuit, are not considered to be credible. Open circuit faults considered include (a) a single conductor breaking, (b) a single connector being disconnected, or (c) a single field-run cable severed.
The random shorting to the manual closing switch contacts or a hot short in the cable run to the closing coil have been identified as control system failure modes that could lead to spurious movement of a passive motor-operated valve. The estimated probabilities of these faults, based on MIL-HDBK-217A (Reference 8) with credit for periodic tests are 2.5 x 10-8/valve-hour and 3.0 x 10-10/valve-hour, respectively. The probability of any spurious valve closure is therefore 2.53 x 10-8/valve-hour. In the case of ECCS valves, the maximum mission time occurs for those valves that are required for the switchover from cold leg recirculation to hot leg recirculation, i.e., approximately DCPP UNITS 1 & 2 FSAR UPDATE 6.3-24 Revision 21 September 2013 7.0 hours. For this maximum mission time, the probability of a spurious motor-operated valve movement is computed as 2.7x 10-7/valve-mission at any given time. Thus, the probability of the failure of any one of these valves coincident with an event requiring the actuation of the ECCS is considered sufficiently low so as to be considered incredible.
During the safety review of the operating license application for the DCPP, the AEC (now NRC) regulatory staff adopted the position that failures of the type discussed above that could lead to spurious movement of passive motor-operated valves must be considered in relation to satisfying the single failure criterion. The regulatory staff's position, as stated in Branch Technical Position EICSB 18, considers removal of electric power an acceptable means, under certain conditions, of satisfying the single failure criterion. As a consequence of the regulatory staff's requirements, electric power will be removed from certain ECCS and RHR valves during normal operation. These valves are listed in Table 6.3-12. When electric power is removed from the valve operators, power is still supplied to position indication circuitry so that there is continuous, redundant position indication on the control board. Redundant position indication is provided by two sets of lights: (a) red and green position lights that indicate open or closed, and (b) white monitor lights that indicate that the valves are in their proper locked-out position. 6.3.3.2.13 SIS Pump Missile Proneness The capability of safety injection pump-motor combination to generate an external missile has been evaluated in Section 3.5. The results of this evaluation showed that neither the safety injection pump nor the motor are capable of generating external missiles. However, the flexible coupling between the pump and motor could conceivably become a missile in the unlikely event that it should fail to maintain its mechanical integrity, due to a maximum overspeed condition caused by a large pressure head driving the pump in reverse. Such failure would require the failure of two check valves in the open position in conjunction with a rupture of the pipe on the suction side of the pump.
Despite the low probability of such a combination of failures, a shroud has been installed around the flexible coupling to eliminate all possibility of missiles being generated in the unlikely event of gross coupling failure. 6.3.3.2.14 Effect of Grid Deformation on ECCS Performance The effects of grid distortion caused by a combination of LOCA and seismic loads have been evaluated for DCPP. The combined LOCA and seismic structural analysis has shown that some peripheral VANTAGE 5 fuel assemblies will undergo loads capable of deforming the zirconium alloy structural grids when 17x17 standard fuel is present with VANTAGE 5 assemblies. The details of the coolable geometry analysis appear in DCPP UNITS 1 & 2 FSAR UPDATE 6.3-25 Revision 21 September 2013 Section 15.4.1 and the results demonstrate that the core remains amenable to cooling with the deformed grid geometry. 6.3.3.3 Alternate Analysis Methods The method of break analysis and the spectrum of breaks analyzed are described in Section 6.3.1.1. 6.3.3.4 Fuel Rod Perforations Results of the small pipe break and large pipe break analyses are presented in Sections 15.3 and 15.4, respectively. 6.3.3.5 Effects of ECCS Operation on the Core When water in the RWST at its minimum boron concentration is mixed with the contents of the RCS, the resulting boron concentration ensures that the reactor will remain subcritical in the cold condition with all control rods, except the most reactive RCCA, inserted into the core. The boron concentration of the accumulator and the RWST is below the solubility limit of boric acid at the respective temperatures. 6.3.3.6 Use of Dual Function Components The ECCS contains components that have no other operating function as well as components that are shared with other systems. Components in each category are as follows: (1) Components of the ECCS that perform no other function are: (a) One accumulator for each reactor coolant loop that discharges borated water into its respective cold leg of the reactor coolant loop piping (b) Associated piping, valves, and instrumentation (2) Components of the ECCS that also have a normal operating function are as follows: (a) The RHR pumps and heat exchangers: These components are normally used during the latter stages of normal reactor cooldown and when the reactor is held at cold shutdown for core decay heat removal. However, during all other plant operating periods, they are aligned to perform the low-head injection function. DCPP UNITS 1 & 2 FSAR UPDATE 6.3-26 Revision 21 September 2013 (b) Two safety injection pumps that supply borated water for core cooling to the RCS (Note that the SI pumps are also used for SI accumulator fill and makeup, but this is not a significant function.) During refueling, the pumps may be used for the boration flow path with all reactor head bolts fully detensioned. (c) CCP1 and CCP2: These pumps are normally aligned for charging service. The normal operation of the pumps as part of the CVCS is discussed in Section 9.3. (d) The RWST: This tank is used to fill the refueling canal for refueling operations (see Section 9.1). During all other plant operating periods, it is aligned to the suction of the safety injection pumps and the RHR pumps. CCP1 and CCP2 are automatically aligned to the suction of the RWST upon receipt of the safety injection signal. An evaluation of all components required for operation of the ECCS demonstrates that either:
(1) The component is not shared with other systems. (2) If the component is shared with other systems, it is aligned during normal plant operation to perform its accident function, or, if not aligned to its accident function, two valves in parallel are provided to align the system for injection, and two valves in series are provided to isolate portions of the system not utilized for injection. These valves are automatically actuated by the safety injection signal.
Table 6.3-8 indicates the alignment of components during normal operation, and the realignment required to perform the accident function. 6.3.3.6.1 Dependence on Other Systems Other systems that operate in conjunction with the ECCS are as follows:
(1) The CCW system (Section 9.2.2) cools the RHR heat exchangers during the recirculation mode of operation. It also supplies cooling water to CCP1 and CCP2, the safety injection pumps, and the RHR pumps during the injection and recirculation modes of operation. (2) The ASW system (Section 9.2.1) provides cooling water to the CCW heat exchangers. (3) The electrical systems (Section 8.3) provide normal and emergency power sources for the ECCSs.
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-27 Revision 21 September 2013 (4) The ESF actuation system (ESFAS) (Section 7.3) generates the initiation signal for emergency core cooling. (5) The AFW system (Section 6.5) supplies feedwater to the steam generators. (6) The auxiliary building ventilation system (Section 9.4) removes heat from the pump compartments and provides for radioactivity contamination control should some leakage occur in a compartment. 6.3.3.7 Lag Times The sequence and time-delays for actuation of ECCS components for the injection and recirculation phases of emergency core cooling are given in Table 6.3-7. Alignment of the major ECCS components during the injection and recirculation phases is shown in Figures 6.3-4 and 6.3-5, respectively. Tables 15.3-2 and 15.3-3 summarize the calculated times at which the major components perform the safety-related functions for those various accident conditions (tabulated in Table 15.1-2) that require the ECCS.
The minimum active components will be capable of delivering full rated flow within a specified time interval after process parameters reach the setpoints for the safety injection signal. Response of the system is automatic with appropriate allowances for delays in actuation of circuitry and active components. The active portions of the system are actuated by the safety injection signal. In analyses of system performance, delays in reaching the programmed trip points and in actuation of components are established on the basis that only emergency onsite power is available. The starting sequence following a loss of offsite power is discussed in detail in Chapter 8. The ECCS is operational after an elapsed time not greater than 25 seconds, including the time to bring the RHR pumps up to full speed.
The starting times for components of the ECCS are consistent with the delay times used in the LOCA analyses for large and small breaks.
In the LOCA analysis presented in Sections 15.3 and 15.4, no credit is assumed for partial flow prior to the establishment of full flow and no credit is assumed for the availability of normal 230-kV and 500-kV offsite power sources.
For smaller LOCAs, there is some additional delay before the process variables reach their respective programmed trip setpoints since this is a function of the severity of the transient imposed by the accident. This is allowed for in the analyses of the range of LOCAs.
Accumulator injection occurs immediately when RCS pressure has decreased below the operating pressure of the accumulator.
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-28 Revision 21 September 2013 6.3.3.8 Limits on System Parameters The specification of individual parameters as indicated in Table 6.3-1 includes due consideration of allowances for margin over and above the required performance value (e.g., pump flow and NPSH), and the most severe conditions to which the component could be subjected (e.g., pressure, temperature, and flow). This consideration ensures that the ECCS is capable of meeting its minimum required level of functional performance. 6.3.3.8.1 Coolant Storage Reserves A minimum RWST volume is provided to ensure that, after an RCS break, sufficient water is injected and available within containment to permit recirculation cooling flow to the core, to meet the NPSH requirement of the RHR pumps. This volume is less than that required to fill the refueling canal (to permit normal refueling operation). Thus, adequate emergency coolant storage volume for ECCS operation is provided. 6.3.3.8.2 Limiting Conditions for Maintenance During Operation Maintenance on an active component will be permitted if the remaining components meet the minimum conditions for operation as well as the following conditions:
(1) The remaining equipment has been verified to be in operable condition, ready to function just before the initiation of the maintenance. (2) A suitable time limit is placed on the total time span of successful maintenance that returns the components to an operable condition, ready to function.
The design philosophy with respect to active components in the high-head/low-head injection system is to provide backup equipment so that maintenance is possible during operation without impairment of the system safety function (Appendix 6.3A). Routine servicing and maintenance of equipment of this type that is not required more frequently than on an outage basis would generally be scheduled for periods of refueling and maintenance outages. The Technical Specifications discuss in detail the applicable limiting conditions for maintenance during operations. 6.3.4 TESTS AND INSPECTIONS To demonstrate the readiness and operability of the ECCS, all of the components are subjected to periodic tests and inspections. Preoperational performance tests of ECCS components were conducted in the manufacturer's shop. An initial system flow test was performed to demonstrate proper components functioning.
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-29 Revision 21 September 2013 6.3.4.1 Quality Control Tests and inspections were carried out during fabrication of each of the ECCS components. These tests were conducted and documented in accordance with the quality assurance program discussed in Chapter 17. 6.3.4.2 Preoperational System Tests These tests evaluated the hydraulic and mechanical performance of the passive and active components involved in the injection mode by demonstrating that they have been installed and adjusted so they will operate in accordance with the intent of the design. The tests were divided into two categories: component tests and integrated system test. The components tests were divided into the following five sub-categories: (a) valve and pump actuation, (b) accumulator injection, (c) RHR pump, (d) safety injection pump, and (e) CCP1 and CCP2 performance tests. The integrated system test for the ECCS was formulated using RG 1.79 (Reference 11) as a basis. The integrated system test was divided into the three phases and was performed after the five component tests had been completed. 6.3.4.2.1 Component Tests The actuation tests verified: the operability of all ECCS valves initiated by the safety injection signal ("S"), the phase A containment isolation signal ("T"), and the Phase B containment isolation signal ("P"), the operability of all safety feature pump circuitry down through the pump breaker control circuits, and the proper operation of all valve interlocks. Sequencing and timing tests were conducted to verify that the ECCS components will be aligned properly to perform their intended functions. The objective of the accumulator injection test was to verify that the injection lines were free from obstruction and that the accumulator check valves operate correctly. The test objectives were met by a low-pressure blowdown of each accumulator. The test was performed with the reactor head and internals removed. The acceptance criteria for the accumulator blowdown test were based on equaling or exceeding a calculated curve; the curve simulated the system line resistances (L/D). The primary intent of the accumulator blowdown tests was to verify these calculated discharge line resistances.
The purpose of the three pump performances tests (RHR pumps, safety injection pumps, and CCP1 and CCP2) was to evaluate the hydraulic and mechanical performance of the pumps delivering through the flowpath required for emergency core cooling. These tests were divided into two parts: pump operation under miniflow conditions and pump operation at full flow conditions.
The predicted system resistances were verified by measuring the flow in each piping branch, as each pump delivered from the RWST to the open reactor vessel, and adjustments were made where necessary to ensure that flow was distributed properly among branches. DCPP UNITS 1 & 2 FSAR UPDATE 6.3-30 Revision 21 September 2013 During flow tests, each system was checked to ensure that there is sufficient minimum total line resistance to preclude runout from overloading the motor of any pump. At the completion of the flow tests, the total pump flow and relative flow between the branch lines were compared with the system acceptable flows.
Each system was accepted only after demonstration of proper actuation of all components and after demonstration of flow delivery of all components within design requirements. 6.3.4.2.2 Integrated System Tests 6.3.4.2.2.1 System Test - Phase I The Phase I test was conducted prior to hot functional tests and involves testing the ECCS at ambient conditions with the reactor vessel open.
A loss of offsite power was simulated prior to test initiation. The emergency diesel generators supplied power to the ESF equipment through Phase I of the test.
The ECCS was tested functionally by manually initiating safety injection and monitoring components for correct system alignment, autostarts, and pump delivery rates. Response time data were obtained for components being tested to demonstrate that they meet or exceed acceptance criteria as established in the test.
At the conclusion of the test, the RHR, safety injection pump, and CCP1 and CCP2 were realigned to the recirculation mode to demonstrate the capability of the RHR pumps to deliver water from the containment recirculation sump to the safety injection pump and CCP1 and CCP2 suctions, and to the containment spray system (CSS) headers. The time required for changeover to recirculation was evaluated to demonstrate that it can be completed during the time allowed. 6.3.4.2.2.2 System Test - Phase II The Phase II test was conducted during hot functional testing with the RCS at hot operating conditions.
High-pressure safety injection (CCP1 and CCP2) was tested by manually initiating safety injection and monitoring components for correct alignment, autostarts of pumps, and delivery of water from the RWST to the reactor vessel through the high-pressure safety injection branch lines.
Response time data were obtained for components being tested to demonstrate that they met or exceeded acceptance criteria.
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-31 Revision 21 September 2013 6.3.4.2.2.3 System Test - Phase III During Phase III tests, the safety injection pumps and accumulator check valves were tested. The test was conducted during the cooldown phase of hot functional testing as the required RCS pressures were reached.
Safety injection pumps were tested by manually initiating safety injection with the RCS pressure at a value below the shutoff head of the pumps. Safety injection pump autostart and delivery of water from the RWST to the reactor vessel via safety injection pump injection flowpaths were checked.
Response time data were obtained for components being tested to demonstrate that they meet or exceed acceptance criteria.
Accumulator check valve operation was verified as RCS pressure decreased to a value below the accumulator pressure setpoint. The accumulator discharge isolation valves were closed as soon as flow through the check valves had been verified to minimize the thermal transient to the RCS. 6.3.4.2.3 Conformance with Regulatory Guide 1.79 The ECCS tests described above meet the requirements of RG 1.79, except in the following instances:
During the hot flow test (System Test - Phase III above/Paragraph C.3.2(a) of RG 1.79), feedwater flow from the AFW pumps is blocked in order to avoid a temperature and pressure transient from this cause in the RCS. The pumps are started on the safety injection signal but will be run on recirculation. Flow from the AFW pumps to the steam generators is verified as part of the feedwater system tests. The quantity of water injected into the RCS by CCP1 and CCP2 during this test is limited by pressurizer water level, rather than limiting the quantity to avoid reducing the number of design stress cycles. Calculations indicate that the injection nozzles are subjected to essentially the full thermal shock by the time any meaningful data can be obtained from this test.
During the recirculation phase of the safety injection pumps low-pressure test at ambient conditions with the reactor vessel open (System Test - Phase I above/Paragraph C.3.b(2) of RG 1.79), temporary piping is installed from the refueling canal into the containment sump. This temporary piping bypasses the coarse but not the fine sump screen. The pressure drop across the coarse and fine screens are less than one thousandth of a foot of water head, which is impractical to measure and which will not compromise the pump NPSH.
During the testing of the accumulators under ambient conditions to verify flowrates (Component Tests above/Paragraph 3.c(1) of RG 1.79), the accumulator discharge is initiated by opening the accumulator isolation valves, not by rapidly reducing RCS pressure. The discharge flowrate is calculated from the change of accumulator DCPP UNITS 1 & 2 FSAR UPDATE 6.3-32 Revision 21 September 2013 pressure with time, not from the change of accumulator level with time. Accumulator discharge tests are not repeated for normal and emergency power supplies; operation of the accumulator isolation valves with both normal and emergency power supplies is demonstrated as a part of other tests. 6.3.4.3 Periodic Component Testing Routine periodic testing of the ECCS components and all necessary support systems is specified in the Technical Specifications. If such testing indicates a need for corrective maintenance, the redundancy of equipment in these systems permits such maintenance without shutting down or reducing load under the conditions established in the Technical Specifications.
Test connections are provided for periodic checks of the leakage of reactor coolant back through the accumulator discharge line check valves and to ascertain that these valves seat properly whenever the RCS pressure is raised. This test will be performed following valve actuation due to automatic or manual action, or flow through the valve in accordance with Technical Specifications. The SI test lines (and associated reactor coolant pressure boundary (RCPB) test valves) that are used for ECCS check valve surveillance testing are designed for testing in Modes 4 and 5 only. Per Section 6.3.3.2.2, maximum flow rate through each RCPB test valve is limited such that, in the event of a downstream pipe break during testing in Modes 4 or 5, the makeup flow rate from either CCP1 or CCP2 is adequate to allow time for an orderly plant shutdown/cooldown without ECCS actuation.
Periodic visual inspection of portions of the system for leakage is specified in the Technical Specifications. Pressure-containing portions of spray and ECCS systems are inspected in accordance with ASME Section XI, as stated in the DCPP Inservice Inspection Program Plan (Reference 9). 6.3.4.4 Testing Following Completion of Modifications In addition to the Technical Specification requirements, an ECCS subsystem is demonstrated operable during shutdown, following completion of modifications to the ECCS subsystem that alter the subsystem flow characteristics by performing a flow balance test to verify: For CCP1 and CCP2, with a single pump running that: (1) The sum of injection line flow rates, excluding the highest flow rate, is greater than or equal to 299 gpm, and (2) The total flow rate through all four injection lines is less than or equal to 461 gpm, and DCPP UNITS 1 & 2 FSAR UPDATE 6.3-33 Revision 21 September 2013 (3) The difference between the maximum and minimum injection line flow rates is less than or equal to 15.5 gpm, and (4) The total pump flow rate is less than or equal to 560 gpm. For safety injection pumps, with a single pump running that: (1) The sum of injection line flow rates, excluding the highest flow rate, is greater than or equal to 427 gpm, and (2) The total flow rate through all four injection lines is less than or equal to 650 gpm, and (3) The difference between the maximum and minimum injection line flow rates is less than or equal to 20.0 gpm, and (4) The total pump flow rate is less than or equal to 675 gpm. The RHR subsystem is demonstrated operable during shutdown, following completion of modifications to the RHR subsystem that alter the subsystem flow characteristics, by performing a flow test and verifying a total flow rate greater than or equal to 3976 gpm with a single pump RHR running and delivering flow to all four cold legs. 6.3.5 INSTRUMENTATION REQUIREMENTS Instrumentation and associated analog and logic channels used to initiate ECCS operation are discussed in Section 7.3. This section describes the instrumentation employed to monitor ECCS components during normal plant operation and ECCS postaccident operation. All alarms are annunciated in the control room. 6.3.5.1 Temperature Indication 6.3.5.1.1 Residual Heat Exchanger Outlet Temperature The fluid temperature at the outlet of each RHR heat exchanger is recorded in the control room. 6.3.5.1.2 ECCS Pump-motor Temperatures Temperature indicators are provided to monitor RHR, CCP1 and CCP2, and SI motor/motor bearing temperatures. High temperatures activate alarms in the control room. DCPP UNITS 1 & 2 FSAR UPDATE 6.3-34 Revision 21 September 2013 6.3.5.2 Pressure Indication 6.3.5.2.1 Charging Injection Line Pressure The charging injection line pressure (PT-947 between valves 8801A & 8801B and 8803A & 8803B) shows that the charging pumps are operating. The transmitters are outside the containment, with indicators on the control board. 6.3.5.2.2 Safety Injection Header Pressure Safety injection pump discharge pressure for each pump shows that the safety injection pumps are operating. The transmitters are outside the containment, with indicators on the control board. 6.3.5.2.3 Accumulator Pressure Duplicate pressure channels are installed on each accumulator. Pressure indication in the control room and high- and low-pressure alarms are provided by each channel. 6.3.5.2.4 Residual Heat Removal Pump Discharge Pressure RHR pump discharge pressure for each pump is indicated in the control room. A high-pressure alarm is actuated by each channel. 6.3.5.3 Flow Indication 6.3.5.3.1 CCP1 and CCP2 Injection Flow Injection flow through the common header to the reactor cold legs is indicated in the control room. 6.3.5.3.2 Safety Injection Pump Header Flow Flow through the safety injection headers is indicated in the control room. 6.3.5.3.3 Residual Heat Removal Pump Injection Flow Flow through each RHR injection and recirculation header leading to the reactor cold or hot legs is indicated in the control room. 6.3.5.3.4 Test Line Flow Local indication of the leakage test line flow is provided to check for proper seating of the accumulator check valves between the injection lines and the RCS.
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-35 Revision 21 September 2013 6.3.5.3.5 Safety Injection Pump Minimum Flow A local flow indicator is installed in the safety injection pump minimum flow line. 6.3.5.3.6 Residual Heat Removal Pump Minimum Flow A flowmeter installed in each RHR pump discharge header provides control for the valve located in the pump minimum flow line. 6.3.5.4 Level Indication 6.3.5.4.1 Refueling Water Storage Tank Level Three water level instrumentation channels are provided for the RWST. Each channel provides independent indication on the main control board, thus satisfying the requirements of paragraph 4.20 of IEEE 279-1971 (Reference 12). Two-out-of-three logic is provided for RHR pump trip and low-level alarm initiation. One channel provides low-low water level alarm initiation. One channel also provides a high water level alarm. 6.3.5.4.2 Accumulator Water Level Duplicate water level channels are provided for each accumulator. Both channels provide indication in the control room and actuate high- and low-water level alarms. 6.3.5.4.3 Containment Sump Water Level Two redundant wide-range reactor cavity water level channels are provided to measure level from the bottom of the reactor cavity. Wide-range recorders are located on the postaccident monitoring panel.
Two redundant narrow-range instruments measure level from the bottom of the containment recirculation sump. The containment recirculation sump level instrumentation consists of two level transmitters (DP) designed to operate in a postaccident environment. The transmitter housings are located above any possible flooding level. Narrow-range indicators are located on the main control board. The containment sump level instrumentation is described in more detail in Section 7.5. 6.3.5.5 Valve Position Indication Valve positions that are indicated on the control board are done so by a "normal off" system; i.e., should the valve not be in its proper position, a bright white light will give a highly visible indication to the operator. This indication is active only during ECCS operation.
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-36 Revision 21 September 2013 6.3.5.5.1 Accumulator Isolation Valve Position Indication The accumulator motor-operated valves are provided with red (open) and green (closed) position indicating lights located at the control switch for each valve. These lights are energized from instrument power (120 Vac) and actuated by the associated valve motor operator limit switches.
A monitor light that is on when the valve is not fully open is provided in an array of monitor lights that are all off when their respective valves are in proper position enabling safety features operation. This light is energized from a separate instrument ac circuit and actuated by a valve motor-operated limit switch.
An alarm annunciator point is activated by a valve motor operator limit switch or a stem travel limit switch whenever an accumulator valve is not fully open with the system at pressure (the pressure at which the safety injection block is unblocked). The alarm is reinstated once an hour. A separate annunciator point is used for each accumulator valve. 6.3.5.6 Subcooling Meter Each subcooling meter provides continuous digital-type display of either the temperature or pressure subcooling margin. The displays are a subset of RVLIS and are located on PAM3 and PAM4, with low and low-low alarms being provided. A digital display of the temperature margin is fed from train B and is available on the main control board. A recorder fed from train A is located on the postaccident monitoring panel. The subcooling meter displays, calculators, and inputs are described in Sections 5.6 and 7.5. 6.
3.6 REFERENCES
- 1. Westinghouse ECCS - Four Loop Plant (17 x 17) Sensitivity Studies, WCAP-8565 (Proprietary) and WCAP-8566, July 1975.
- 2. Westinghouse ECCS - Plant Sensitivity Studies, WCAP-8340 (Proprietary) and WCAP-8356, July 1974.
- 3. Westinghouse ECCS Evaluation Model-Summary, WCAP-8339, July 1974.
- 4. Westinghouse ECCS Evaluation Model - Supplementary Information, WCAP-8471 (Proprietary) and WCAP-8472, January 1975.
- 5. Westinghouse ECCS Evaluation Model - October 1975 Version, WCAP-8622 (Proprietary) and WCAP-8623, November 1975.
- 6. Environmental Testing of Engineered Safety Features Related Equipment (NSSS-Standard Scope), WCAP-7744, Volume I, August 1971.
DCPP UNITS 1 & 2 FSAR UPDATE 6.3-37 Revision 21 September 2013 7. Westinghouse ECCS Evaluation Model - February 1978 Version, WCAP-9220 (Proprietary) and WCAP-9221, February 1978.
- 8. "Reliability, Stress and Failure Rate Data for Electronic Equipment," Military Standardization Handbook, MIL-HDBK-217A, December 1965, Department of Defense, Washington, D.C.
- 9. Diablo Canyon Power Plant - Inservice Inspection Program Plan - The Third 10 Year Inspection Interval.
- 10. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
- 11. Regulatory Guide 1.79, Preoperational Testing of Emergency Core Cooling System for Pressurized Water Reactors, USNRC, June 1974.
- 12. IEEE-Std-279, Criteria for Protection Systems for Nuclear Power Generating Stations, 1971.
- 13. Westinghouse ECCS Evaluation Model, 1981 Version, WCAP-9220-P-A, Rev. 7 (proprietary), WCPA-9221-A, Rev. 1 (nonproprietary), February 1982.
- 14. Young, M. Y., et al., BART-A1: A Computer Code for the Best Estimate Analysis of REFLOOD Transients, WCAP-9561-P, Addendum 3, June 1986.
- 15. Chiou, J. S., et al., Models for PWR Reflood Calculations Using the BART Code, WCAP-10062.
- 16. License Amendment Nos. 199 (DPR-80) and 200 (DPR-82), "Technical Specification 3.5.4, Refueling Water Storage Tank (RWST)," USNRC, March 26, 2008.
DCPP UNITS 1 & 2 FSAR UPDATE 6.4-1 Revision 21 September 2013 6.4 HABITABILITY SYSTEMS The DCPP control room and the onsite technical support center (TSC) are common to Units 1 and 2. The control room is located at elevation 140 feet of the auxiliary building. The TSC is located on the upper levels of the buttresses on the west side of the Unit 2 turbine building. Access to the control room is via the east door of the TSC, across the Unit 2 turbine building at elevation 104 feet, and then to the control room at elevation 140 feet via the elevator or stairway on the east side of the turbine building. The TSC is large enough to house 25 persons and necessary data and information displays.
Both facilities are designed to be habitable throughout the course of a DBA and the resulting radiological condition, except that the TSC system is manually activated. In addition, the control room is designed to be habitable throughout the course of a hazardous chemical release. 6.4.1 CONTROL ROOM 6.4.1.1 Habitability Systems Functional Design Habitability systems provide for access and occupancy of the control room during normal operating conditions, radiological emergencies, hazardous chemical emergencies, and fire emergencies as specified by AEC General Design Criterion (GDC) 19 (1971). To this end, administrative procedures, shielding, the ventilation and air conditioning system, the fire protection system, kitchen facilities, and sanitary facilities are used. Control room design features are consistent with AEC GDC19. 6.4.1.2 Design Bases The design bases for the functional design of control room habitability systems for both normal and emergency radiological hazards were:
(1) 10 CFR 20.1 through 20.601, Standards for Protection Against Radiation (pre-1995; compliance with current requirements of Part 20 is addressed in Chapter 12): "...no licensee shall possess, use, or transfer licensed material in such a manner as to cause any individual in a restricted area to receive in any period of one calendar quarter from radioactive material and other sources of radiation in the licensee's possession a dose in excess of the standards specified in the following table:
DCPP UNITS 1 & 2 FSAR UPDATE 6.4-2 Revision 21 September 2013 Rems per calendar quarter Whole body; head and trunk, active blood-forming organs; lens of eyes, or gonads 1-1/4 Hands and forearms; feet and ankles 18-3/4 Skin of whole body 7-1/2" (2) 10 CFR 50, Licensing of Production and Utilization Facilities, Appendix A, Criterion 19 (1971): "Adequate radiation protection shall be provided to permit access and occupancy of the control room under accident conditions without personnel receiving radiation exposures in excess of 5 rem whole body, or its equivalent to any part of the body, for the duration of the accident." (3) NCRP Report No. 39 (1971), Basic Radiation Protection Criteria: "It is compatible with the risk concept to accept exposures leading to doses considerably in excess of those appropriate for lifetime use when recovery from an accident or major operational difficulty is necessary. Saving of life, measures to circumvent substantial exposures to population groups or even preservation of valuable installations may all be sufficient cause for accepting above-normal exposures. Dose limits cannot be specified. They should be commensurate with the significance of the objective, and held to the lowest practicable level that the emergency permits." The functional design of control room habitability systems for fire and hazardous chemical emergencies is based on:
(1) 10 CFR 50, Licensing of Production and Utilization Facilities, Appendix A, Criterion 3: "Structures, systems, and components important to safety shall be designed and located to minimize, consistent with other safety requirements, the probability and effect of fires and explosions.
Noncombustible and heat resistant materials shall be used wherever practical throughout the unit, particularly in locations such as the containment and control room. Fire detection and fighting systems of appropriate capacity and capability shall be provided and designed to minimize the adverse effects of fires on structures, systems, and components important to safety. Fire fighting systems shall be designed to ensure that their rupture or inadvertent operation does not significantly impair the safety capability of these structures, systems and components." (2) National Fire Protection Association Standards DCPP UNITS 1 & 2 FSAR UPDATE 6.4-3 Revision 21 September 2013 The habitability systems functional design was evaluated for each of the following conditions:
(1) Normal operating conditions (2) Radiological conditions resulting from a DBA (3) Hazardous chemical release (4) Control room fire accident 6.4.1.3 System Design As described in Section 12.1.2, control room shielding consists of concrete walls, floor, and roof. Control room shielding design radiation exposure limits are consistent with GDC 19.
The control room ventilation and pressurization (CRVP) system is a redundant, Design Class I system. The isolation dampers are bubble-tight-type and are designed to Seismic Category I criteria. The ductwork, ventilation fans, and filter units are designed to Seismic Category I criteria. Sections 12.2 and 9.4 describe the control room ventilation and air conditioning systems. A minimum of ten self-contained breathing apparatuses (five for each unit) are provided in the control room.
The fire protection system is shared by Units 1 and 2 and is designed considering the standards of the National Fire Protection Association. The control room fire protection system is described in Section 9.5.1. Control room communications are described in Section 9.5.2.
Kitchen and sanitary facilities are shared by Units 1 and 2 and are designed to support operating personnel during normal operating conditions and for the duration of an accident. 6.4.1.4 Design Evaluation Normal operating and postaccident control room operating, emergency, and administrative procedures are contained in the DCPP Plant Manual. The several volumes of the Plant Manual are listed in Section 13.5.
The adequacy of control room shielding is evaluated for normal operating conditions in Chapter 11 and Section 12.1, and for postaccident conditions in Section 15.5.
The adequacy of the control room ventilation systems is evaluated for normal operating conditions in Chapter 11 and Section 12.1, for radiological emergencies in Section 15.5, DCPP UNITS 1 & 2 FSAR UPDATE 6.4-4 Revision 21 September 2013 for hazardous chemical emergencies in Section 9.4.1, and for fire emergencies in Sections 9.4.1 and 9.5.1.
The adequacy of the control room fire protection system is evaluated in Sections 9.5.1 and 7.7.2.10.1.2. Kitchen and sanitary facilities are adequate to support operating personnel during normal operating conditions and for the duration of an accident.
These evaluations indicate the capability of the control room habitability systems to perform their functions reliably and accurately during normal operating periods and under emergency conditions or operating interruptions. 6.4.1.5 Testing and Inspection Testing of control room habitability systems is discussed in the following sections:
(1) Ventilation and air conditioning system Section 9.4.1 (2) Fire protection system Section 9.5.1 (3) Communication system Section 9.5.2 Surveillance requirements for inspection and testing of plant equipment are contained in the Technical Specifications(3) and the Plant Manual. These requirements ensure that performance capability is maintained throughout the lifetime of the plant. 6.4.1.6 Instrumentation Requirements Smoke detector and radiation detector instrumentation employed for monitoring and actuation of the control room habitability systems are discussed in the following sections: (1) Ventilation and air conditioning system Section 9.4.1 (2) Fire protection system Section 9.5.1 (3) Communication systems Section 9.5.2 Design details and logic of the instrumentation are discussed in Chapter 7.
DCPP UNITS 1 & 2 FSAR UPDATE 6.4-5 Revision 21 September 2013 6.4.2 TECHNICAL SUPPORT CENTER 6.4.2.1 Habitability Systems Functional Design Habitability systems provide for access and occupancy of the TSC during normal plant operating conditions, throughout the course of a DBA, and during radiological and fire emergencies. To this end, administrative procedures and shielding, as well as the ventilation and air conditioning, and the fire protection systems, are used.
The TSC is sized to accommodate a minimum of 20 PG&E and 5 NRC personnel. It serves as the onsite NRC emergency headquarters. 6.4.2.2 Design Bases In addition to the design bases specified for the control room in Section 6.4.1.2, the TSC habitability systems must meet 10 CFR 50.47, NUREG-0578(1), and NUREG-0696(2) requirements. Accordingly, the TSC will provide: (1) A capability for transmitting technical information between the control room and the TSC by telephone and process computer printout (2) Instrumentation in the TSC capable of providing displays of vital plant parameters throughout the course of a DBA (3) A capability for monitoring direct radiation and airborne radioactive contaminants. The monitors will provide warning if the radiation levels in the TSC reach potentially dangerous levels (4) Accessibility to the records of the as-built plant conditions and layout of structures, systems, and components (5) Access to the control room for key TSC personnel In addition, habitability will be ensured during:
(1) Normal operating conditions (2) Design basis accident (3) Radiological and fire emergencies, including those that may occur during (1) or (2) above DCPP UNITS 1 & 2 FSAR UPDATE 6.4-6 Revision 21 September 2013 6.4.2.3 System Design The TSC is designated to be habitable throughout the course of a DBA. The outside walls, with steel bulkhead doors, form an airtight perimeter boundary. The TSC structure is designed to Seismic Category I criteria.
The TSC shielding is designed to limit the integrated doses under postaccident conditions to 2.5 rem to the whole body consistent with the criteria for the control room. TSC shielding design radiation dose rate limits were 10 mRem/hr for direct radiation and 5 mRem/hr for airborne particulate and gaseous releases (internal to TSC). The total dose rate to any individual in the TSC is thus limited to 15 mRem/hr, from a time period beginning 1 hour after start of the DBA to 30 days later. A minimum of ten self-contained breathing apparatuses (five for each unit) are provided in the TSC. Postaccident doses inside the TSC will not exceed those specified by GDC 19 and the Standard Review Plan (SRP) 6.4.
The TSC has the manual capability to isolate the area from the outside and to recirculate air by the air conditioning system. The hazardous chemical release warning/annunciation will have to be received from the control room, however, to enable those in the TSC to manually isolate the area from the outside.
The TSC is provided with its own ventilation system with a self-contained air conditioning unit. It is not seismically qualified and is fed from a normal power source, although it has the capability to obtain power from a vital bus. The Design Class I CRVP system provides a redundant supply of pressurization air to the TSC ventilation system. The connecting ductwork, ventilation fans, and filter units are designed to Seismic Category I criteria. Sections 12.2 and 9.4 describe the TSC ventilation and air conditioning system.
The TSC fire protection system is designed considering the standards of the National Fire Protection Association. It is described in Section 9.5.1.
The TSC includes provisions to monitor important plant parameters. The TSC computers provide all necessary plant and health physics data to offsite facilities.
The TSC is tied to the radiological monitoring network such that a laboratory, located adjacent to the TSC, is set aside for analytical work. The principal purpose of this facility is to provide minimum onsite analytical capability in the event that the normal facilities are unavailable.
The TSC communications are described in Section 9.5.2.
DCPP UNITS 1 & 2 FSAR UPDATE 6.4-7 Revision 21 September 2013 6.4.2.4 Design Evaluation Normal operating and postaccident TSC administrative procedures are discussed and evaluated in the DCPP Manual, in FSAR Update Chapters 12 and 13, and in the Emergency Plan.
The adequacy of TSC shielding is evaluated for both normal operating and postaccident conditions in Section 12.1, and for postaccident conditions in Section 15.5.
The adequacy of the TSC ventilation system is evaluated for normal and postaccident operating conditions in Sections 9.4.11 and 12.2, for postaccident conditions in Section 15.5, for toxic gas emergencies in Section 9.4.1, and for fire emergencies in Sections 9.4.1 and 9.5.1.
The adequacy of the TSC fire protection system is evaluated in Section 9.5.1. 6.4.2.5 Testing and Inspection Preoperational testing of TSC habitability systems is discussed in the following sections:
(1) Ventilation and air conditioning system Section 9.4.11 (2) Fire protection system Section 9.5.1 (3) Communication systems Section 9.5.2 6.4.2.6 Instrumentation Requirements Instrumentation and habitability support equipment associated with the TSC are addressed in the Emergency Plan.
6.
4.3 REFERENCES
- 1. NUREG-0578, TMI Short-term Lessons Learned Requirements, U. S. Nuclear Regulatory Commission, 1979.
- 2. NUREG-0696, Functional Criteria for Emergency Response Facilities, U. S. Nuclear Regulatory Commission, 1981.
- 3. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
DCPP UNITS 1 & 2 FSAR UPDATE 6.5-1 Revision 21 September 2013 6.5 AUXILIARY FEEDWATER SYSTEM 6.5.1 DESIGN BASES The AFWS serves as a backup supply of feedwater to the secondary side of the steam generators when the main feedwater system is not available, thereby maintaining the heat sink capabilities of the steam generators. As an ESF system, the AFWS is directly relied upon to prevent core damage and RCS system overpressurization in the event of transients such as a loss of normal feedwater or a secondary system pipe rupture, and to provide a means for plant cooldown following any plant transient.
Auxiliary feed pumps are provided and designed to ensure complete reactor decay heat removal under all conditions including loss of power and loss of the normal heat sink (the condenser circulating water), while maintaining minimum water levels within the steam generator.
Following a reactor trip, decay heat is dissipated by evaporating water in the steam generators and venting the generated steam either to the condensers through the steam dump valves or to the atmosphere through the steam generator safety valves or the power-operated relief valves. Steam generator water inventory must be sufficient to ensure adequate heat transfer and decay heat removal. The AFWS must be capable of functioning for extended periods, allowing time either to restore normal feedwater flow or to proceed with an orderly cooldown of the reactor coolant to 350°F where the RHR system can assume the burden of decay heat removal.
AFWS flow and emergency water supply capacity must be sufficient to remove core decay heat, reactor coolant pump heat, and sensible heat during the plant cooldown. The AFWS can also be used to maintain the steam generator water level above the tubes following a LOCA. The water head in the steam generators prevents leakage of fission products from the reactor coolant system (RCS) into the secondary side once the RCS is depressurized. 6.5.1.1 Design Conditions The reactor plant conditions that impose safety-related performance requirements on the AFWS are as follows:
(1) Loss of main feedwater transient (a) Loss of main feedwater with offsite power available (b) Loss of main feedwater without offsite power available DCPP UNITS 1 & 2 FSAR UPDATE 6.5-2 Revision 21 September 2013 (2) Secondary system pipe ruptures (a) Feedline rupture (b) Steam line rupture (3) Loss of all ac power (4) Loss-of-coolant accident (LOCA) (5) Cooldown Each of these conditions is discussed in more detail in the following sections.
6.5.1.1.1 Loss of Main Feedwater Transients Design basis loss of main feedwater transients are caused by:
(1) Interruptions of the main feedwater system flow due to a malfunction in the feedwater or condensate system (2) Loss of offsite power with the consequential shutdown of the system pumps, auxiliaries, and controls Loss of main feedwater transients are characterized by a reduction in steam generator water level that results in a reactor trip, a turbine trip, and auxiliary feedwater actuation by the protection system logic. Following reactor trip from a high initial power level, the power quickly falls to decay heat levels. The water levels continue to decrease, progressively uncovering the steam generator tubes as decay heat is transferred and discharged in the form of steam either through the steam dump valves to the condenser or through the steam generator safety or power-operated relief valves to the atmosphere. The reactor coolant temperature increases since the residual heat exceeds that dissipated through the steam generators. With increased temperature, reactor coolant volume expands and begins to fill the pressurizer. Without the addition of sufficient AFW, further expansion will result in liquid being discharged through the pressurizer safety and/or relief valves.
If the temperature rise and the resulting volumetric expansion of the primary coolant are permitted to continue, then: (a) pressurizer safety valve capacities may be exceeded causing overpressurization of the RCS, and/or (b) the continuing loss of fluid from the primary coolant system may result in bulk boiling in the RCS system and eventually in core uncovering, loss of natural circulation, and core damage. If such a situation were ever to occur, the ECCS would not be effective because the primary coolant system pressure exceeds the shutoff head of the safety injection pumps, the nitrogen overpressure in the accumulator tanks, and the design pressure of the RHR loop.
DCPP UNITS 1 & 2 FSAR UPDATE 6.5-3 Revision 21 September 2013 The loss of offsite power transient differs from a simple loss of main feedwater in that emergency power sources must be relied upon to operate vital equipment. The loss of power to the motor- driven circulating water pumps results in a loss of condenser vacuum and, therefore, of use of the condenser dump valves. Hence, steam generated by decay heat is relieved through the steam generator safety valves or the power-operated relief valves. The calculated transient is similar for both the loss of main feedwater and the loss of offsite power, except that reactor coolant pump heat input is not a consideration in the loss of offsite power transient following loss of power to the reactor coolant pump bus.
The loss of normal feedwater transient is the basis for the minimum flow required for the smallest capacity single AFWS pump. Each pump is sized so that any single pump will provide sufficient flow against a conservative steam generator safety valve set pressure with 3 percent tolerance and 5 psi accumulation to prevent liquid relief from the pressurizer. 6.5.1.1.2 Secondary System Pipe Ruptures A feedwater line rupture results in the loss of feedwater flow to the steam generators and the complete blowdown of one steam generator within a short time if the rupture occurs downstream of the last nonreturn valve in the main or AFWS piping to an individual steam generator. A feedwater line rupture may also cause spilling of AFW through the break as a consequence of the fact that the AFWS branch line may be connected to the main feedwater line in the region of the postulated break. Such situations can result in the injection of a disproportionately large fraction of the total AFWS flow (the system preferentially pumps water to the lowest pressure region) to the faulted loop rather than to the effective steam generators, which are at relatively high pressure. System design provides for terminating, limiting, or minimizing that fraction of AFW flow, which is delivered to a faulted loop or spilled through a break to ensure that sufficient flow is delivered to the remaining effective steam generator(s).
Main steam line rupture accident conditions are characterized initially by a plant cooldown and, for breaks inside containment, by increasing containment pressure and temperature. Auxiliary feedwater is not needed during the early phase of the transient, but flow to the faulted loop contributes to an excessive release of mass and energy to containment. Thus, steam line rupture conditions establish the upper limit on AFW flow delivered to a faulted loop. Eventually, however, the RCS heats up again and AFWS water flow is required for the non-faulted loops, but at somewhat lower rates than for the loss of feedwater transients described previously. Provisions in the design of the AFWS limit, control, or terminate AFWS water flow to the faulted loop as necessary to prevent containment overpressurization following a steam line break inside containment, or, for steam leads 3 and 4, to maintain the temperature profile in the GE/GW area within analyzed limits, and to ensure minimum flow to the remaining unfaulted loops.
DCPP UNITS 1 & 2 FSAR UPDATE 6.5-4 Revision 21 September 2013 6.5.1.1.3 Loss of All AC Power The loss of all ac power is postulated as resulting from accident conditions wherein not only onsite and offsite ac power is lost, but also emergency ac power is lost as an assumed common mode failure. Battery power for operation of protection circuits is assumed available. The impact on the AFWS is the necessity for providing both AFW pump power and a control source that are not dependent on ac power and which are capable of maintaining the plant at hot shutdown until ac power is restored. As discussed in Section 6.5.2, in the event of a complete station blackout with dc power available, decay heat removal would continue to be ensured through the availability of one double capacity steam-driven AFW pump. 6.5.1.1.4 Loss-of-Coolant Accident The LOCAs do not impose any flow requirements on the AFWS that are in excess of those required by the other accidents addressed in this section.
Small LOCAs cause relatively slow rates of decrease in RCS pressure and liquid volume. The principal contribution from the AFWS following a small LOCA is basically the same as the system's function during hot shutdown or following a spurious safety injection signal which trips the reactor. Maintaining a water level inventory in the secondary side of the steam generators provides a heat sink for removing decay heat and establishes the capability for providing a buoyancy head for natural circulation. The AFWS may be used to assist in system cooldown and depressurization following a small LOCA while bringing the reactor to a cold shutdown condition.
6.5.1.1.5 Cooldown The cooldown function performed by the AFWS is a partial one since the RCS is reduced from normal zero load temperature to a hot leg temperature of approximately 350°F. The latter is the maximum temperature recommended for placing the RHR system into service. The RHR system completes the cooldown to cold shutdown conditions. Cooldown may be required following expected transients, following an accident such as a main feedline break, or prior to refueling or plant maintenance. If the reactor trips following extended operation at rated power level, the AFWS delivers sufficient feedwater to remove decay heat and reactor coolant pump heat following reactor trip while maintaining steam generator water level. Following transients or accidents, the recommended cooldown rate is consistent with expected needs and at the same time does not impose additional requirements on the capacities of the auxiliary feedwater pumps, considering a single failure. 6.5.1.2 Design Bases Summary Table 6.5-1 summarizes the criteria used for the AFWS general design bases for various plant conditions.
DCPP UNITS 1 & 2 FSAR UPDATE 6.5-5 Revision 21 September 2013 6.5.2 SYSTEM DESIGN In the unlikely event of a complete loss of offsite and main generator electrical power to the station, decay heat removal would continue to be ensured by the availability of one double capacity steam-driven, and two full capacity motor-driven auxiliary feed pumps, and steam discharged to atmosphere through the steam generator power-operated relief valves and/or the spring-loaded safety valves. The system is shown in simplified form in Figure 6.5-1. For the detailed piping schematic, see Figure 3.2-3, Sheets 3 and 4. 6.5.2.1 Equipment and Component Descriptions 6.5.2.1.1 Water Sources The minimum condensate storage tank (CST) volume alone is sufficient to perform the plant cooldown described in Section 6.5.3.5 and to address a NRC Generic Letter 81-21 postulated worst case natural circulation cooldown. For a worst case natural circulation cooldown, 196,881 gallons for Unit 1 and 163,058 gallons for Unit 2 are required to cooldown to 350°F. An additional volume of 3,119 gallons for Unit 1 and 2,942 gallons for Unit 2 are reserved for allowed leakage through internal plenums at CST connections and for margin. The inventory of the CST at the minimum Technical Specification usable volumes of 200,000 gallons for Unit 1 and 166,000 gallons for Unit 2 envelopes this total required amount. The usable reserved inventory in both CSTs was increased from 164,678 gallons to 224,860 gallons (Reference 3).
A supplemental source of water is available from the 5.0 million gallon raw water storage reservoir. In the event the CST becomes exhausted, additional cooling water supplies are available to maintain hot standby conditions or to bring the plant to cold shutdown. These additional long-term cooling water sources use both existing piping systems and pumps, along with temporary portable pump driver units and hoses. Two million gallons of water will be available from the raw water reservoir for both units following exhaustion of preferential water sources (Reference 4). The additional sources, listed in order of preference according to water quality, are as follows:
(1) Unit 1 and 2 CST (supply from nonaffected unit if water inventory is not required for that unit) (2) Main condenser hotwells (using condensate pumps) (3) Fire water transfer tank (4) Fire water tank DCPP UNITS 1 & 2 FSAR UPDATE 6.5-6 Revision 21 September 2013 (5) Main condenser hotwells (using portable fire pumps)
(6) Raw water storage reservoirs (7) Pacific Ocean (via auxiliary saltwater system) The above order of preference, although desirable relative to control of steam generator secondary side water chemistry, is not necessarily the preferred order in response to a plant transient requiring rapid operator response. The operating procedures identify an order of preference that is based on ensuring rapid alignment of the long term cooling water supply.
The various long-term cooling water sources and their connections to the AFWS are shown schematically in Figure 6.5-2. Water systems are discussed in Section 9.2.
Connections and valving arrangements are provided to interconnect permanent plant systems by means of special-use hoses as follows:
(1) ASW system at the inlet water box of the CCW heat exchanger to the turbine building fire system (2) Raw water storage reservoir to the plant raw water supply line (3) Condenser hotwells to the turbine building fire system (4) Fire water system crosstie (through piping) to the AFWS. This piping was originally Design Class II but was seismically upgraded to Design Class I criteria The available hoses and portable pumps (not permanently connected to existing systems) are stored in structures that have been verified to survive the postulated Hosgri seismic event.
6.5.2.1.2 Auxiliary Feedwater Pumps and Controls The turbine-driven AFW pump takes water from the CST, which is the preferred source of AFW. The turbine-driven AFW pump has a net flow of 780 gpm available to supply the steam generators. Driving steam for the turbine-driven AFW pump is taken from two of the four main steam lines upstream of the main steam isolation valves and is exhausted to the atmosphere. Only one steam supply is required for turbine operation. However, steam must always be available from both steam lines during plant operation to preclude a loss of all steam supplies due to any single failure incident.
Each of the two steam supply lines to the turbine-driven AFW pump is provided with a separate, normally open, motor-operated isolation valve and a non-return valve. The non-return valves provide protection against potential cross-connection between the DCPP UNITS 1 & 2 FSAR UPDATE 6.5-7 Revision 21 September 2013 steam lines. A normally closed, motor-operated stop valve is located in the steam supply line to the turbine inlet. During normal operation, the steam supply line is pressurized up to this stop valve, with steam available to operate the turbine-driven AFW pump when a control signal is received to open the stop valve.
The motor-driven AFW pumps are powered from the vital buses. They are available for standby service when there is insufficient steam to operate the turbine-driven AFW pump, or when the turbine-driven AFW pump is unavailable. Each motor-driven AFW pump can deliver a net flow of 390 gpm to two steam generators. Note that the flow rates of 780 and 390 gpm represent the minimum required flow rates of the turbine- and motor-driven AFW pumps at a steam generator back-pressure corresponding to the lowest steam generator safety valve set pressure, plus 3 percent for setpoint tolerance and 5 psi for accumulation.
Controls for the AFWS are described in Chapter 7. In addition to the manual actuation of the AFW pumps, the following signals provide for automatic actuation of motor-driven AFW pumps:
(1) Two-out-of-three low-low level signals in any one steam generator (2) Trip of both main feedwater pumps (3) Safety injection signal (4) Transfer to diesel without safety injection signal (5) Anticipated Transients Without Scram (ATWS) Mitigation System Actuation Circuitry (AMSAC)
The turbine-driven AFW pump automatic actuation signals are:
(1) Two-out-of-three low-low level signals in any two steam generators (2) Undervoltage on both RCP buses (loss of offsite power) (3) AMSAC The steam generator blowdown isolation valves and the blowdown sample isolation valves are tripped shut whenever an AFW pump is started automatically.
As with all ESF equipment, the ac motor-driven pumps and all valves in the system are automatically and sequentially loaded on the emergency buses on loss of offsite power.
DCPP UNITS 1 & 2 FSAR UPDATE 6.5-8 Revision 21 September 2013 6.5.2.2 Applicable Codes and Classifications All auxiliary feed pumps and the appropriate piping and valves are Design Class I. The system fittings and piping are designed to ANSI Code for Pressure Piping B31.1 and B31.7, as appropriate. The system valves were originally designed to the requirements of the ASME Pump and Valve Code, 1968 Draft. Later additions were designed to ASME B&PV Code, Section III.
The system level control valves are normally open and require no actions for system operation. The AFW initiation circuitry is part of the ESF, and as such, is installed in accordance with IEEE Standard 279 (Reference 1).
All automatic initiating signals and circuits are installed in accordance with regulatory requirements and are safety-grade and redundant. No single failure in the automatic portion of the system will result in loss of the capability to manually initiate the AFWS from the control room. 6.5.3 DESIGN EVALUATION Analyses have been performed for the limiting transients that define the AFWS performance requirements. Specifically, they include:
(1) Loss of main feedwater (2) Loss of offsite power (loss of main feedwater without offsite power available) (3) Rupture of a main feedwater pipe (4) Rupture of a main steam pipe inside containment (5) Rupture of a steam supply line to the turbine driven Aux Feedwater Pump In addition, specific calculations for DCPP Units 1 and 2 were performed to determine plant cooldown flow (storage capacity) requirements.
The loss of all ac power was evaluated by comparison with the transient results of a loss of offsite power, assuming an available auxiliary feedwater pump having a diverse (non-ac) power supply. The LOCA analysis incorporates system flow requirements defined by other transients and is, therefore, not performed to determine AFWS flow requirements. Each of the above analyses is explained further in the following sections. 6.5.3.1 Loss of Main Feedwater A loss of feedwater was analyzed in Section 15.2.8 to show that two motor-driven AFWS pumps delivering flow to four steam generators does not result in pressurizer DCPP UNITS 1 & 2 FSAR UPDATE 6.5-9 Revision 21 September 2013 filling. Furthermore, the peak RCS pressure remains below the criterion for Condition II transients and no fuel failures occur.
Table 6.5-2 summarizes the assumptions used in the Chapter 15 analysis. All main feedwater flow to the steam generators is terminated at event initiation. Reactor trip is assumed to occur when the water level in any steam generator reaches the low-low level trip setpoint. Auxiliary feedwater flow from both motor-driven pumps initiates 60 seconds after receiving a low-low level signal in any steam generator. The analysis assumes that the plant is initially operating at 102 percent (calorimetric error) of the NSSS design rating shown in the table, a conservative assumption in defining decay heat and stored energy in the RCS.
The loss of offsite power to the station auxiliaries' transient is discussed in Section 15.2.9. The same assumptions discussed above for the loss of main feedwater transient apply to this analysis, except that power is assumed to be lost to the reactor coolant pumps following reactor trip.
Both the loss of main feedwater and loss of offsite power analyses demonstrate that there is considerable margin with respect to pressurizer filling.
A better-estimate analysis is performed to address the reliability of the AFWS. This analysis is similar to that described above for the Chapter 15 analysis, but assuming that only a single motor-driven AFS pump supplies a minimum of 390 gpm to two of the four steam generators. The cases considered in this additional analysis assume better-estimate conditions for several key parameters, including initial power level, decay heat, RCS temperature, pressurizer pressure, and the low-low steam generator water level reactor trip setpoint. The results of this better-estimate analysis demonstrate that there is margin to pressurizer filling. 6.5.3.2 Rupture of Main Feedwater Pipe The double-ended rupture of a main feedwater pipe downstream of the main feedwater line check valve was analyzed (see Section 15.4.2.2). Table 6.5-2 summarizes the assumptions used in this analysis. Reactor trip is assumed to occur when the ruptured steam generator reaches the low-low level trip setpoint (adjusted for errors). The initial power rating assumed in the feedline break analysis is 102 percent of the NSSS design rating.
Although the AFWS at DCPP Units 1 and 2 would allow delivery of AFW to two intact loops automatically in 1 minute, no AFW flow is assumed until 10 minutes after the break. At this time it is assumed that the operator has isolated the AFWS from the break and flow from one motor-driven AFW pump of 390 gpm (total) commences. The AFW flow is asymmetrically split between two of the three unaffected steam generators. The analysis demonstrates that the reactor coolant remains subcooled, assuring that the core remains covered with water and no bulk boiling occurs in the hot leg. DCPP UNITS 1 & 2 FSAR UPDATE 6.5-10 Revision 21 September 2013 6.5.3.3 Rupture of a Main Steam Pipe Because the result of the steam line break transient is an initial RCS cooldown, the AFWS is not needed to remove heat in the short term. Furthermore, addition of excessive AFW to the faulted steam generator will affect the peak containment pressure following a steam line break inside containment. This transient is performed at four power levels for several break sizes. AFW is assumed to be initiated at the time of the break, independent of system actuation signals. The maximum flow is used for this analysis, considering a case where runout protection for the largest pump fails. Table 6.5-2 summarizes the assumptions used in this analysis. At 10 minutes after the break, it is assumed that the operator has isolated the AFWS from the faulted steam generator, which subsequently blows down to ambient pressure. This assumption for operator action is also used for temperature profile development for main steam line breaks outside containment. 6.5.3.4 Rupture of a Steam Supply Line to the Turbine Driven Aux Feedwater Pump An unisolated double-ended rupture of a turbine driven auxiliary feedwater pump steam supply line (downstream of the non-return valves associated with steam supply isolation valves, FCV-37/38, and upstream of steam supply stop valve, FCV-95, and in the GE/GW area) could result in loss of all auxiliary feedwater (AFW) and main feedwater. A break in this location will result in a reactor trip (automatic or manual), which also trips the Main Feedwater Pumps causing loss of main feedwater. The postulated break will render the turbine driven AFW pump No. 1 inoperable due to loss of steam supply. The resulting increased temperature in the GE/GW area would cause the E/H actuated LCVs associated with motor driven AFW pump No. 3 to fail due to a harsh environment. AFW pump No. 3 is assumed to be lost due to either pump runout/trip on overcurrent due to excessive flow/insufficient back pressure through the affected AFW flow control valve due to the line break; or by the requirement to isolate AFW feedwater flow to the ruptured S/G within 10 minutes. If S/G 3 is faulted by the break, the single failure of motor driven AFW pump No. 2 would then leave the plant with no AFW.
To ensure that the plant is maintained within analyzed conditions, the steam line break must be isolated. 6.5.3.5 Plant Cooldown Maximum and minimum flow requirements from the previously discussed transients meet the flow requirements of plant cooldown. This operation, however, defines the basis for tank size, based on the required cooldown duration, maximum decay heat input, and maximum stored heat in the system. The AFWS partially cools the system to the point where the RHR system may complete the cooldown of the RCS. Table 6.5-2 shows the assumptions used to determine the cooldown heat capacity of the AFWS.
DCPP UNITS 1 & 2 FSAR UPDATE 6.5-11 Revision 21 September 2013 The cooldown is assumed to commence at maximum rated power, and maximum trip delays and decay heat source terms are assumed when the reactor is tripped. Primary system metal, primary water, secondary system metal, and secondary system water are all included in the stored heat to be removed by the AFWS. Table 6.5-3 lists the items constituting the sensible heat stored in the NSSS.
The AFWS flow required for shutdown and cooldown of the unit is plotted as a function of time in Figure 6.5-3. Figure 6.5-3, Sheet 1, shows flow requirements for a plant shutdown from the maximum calculated NSSS output of 3568 MWt, assuming both of the 440 gpm motor-driven pumps and the 880 gpm turbine-driven pump function. The reduction in flowrate occurs at about 52 seconds, when normal water level is restored in the steam generators. The subsequent feedwater addition rate is based on a 50°F per hour RCS cooldown rate.
Figure 6.5-3, Sheet 2, shows AFW flow requirements for a plant shutdown from the maximum calculated Unit 2 NSSS output of 3568 MWt assuming only one 440 gpm motor-driven pump functions. In this case, normal steam generator water level is restored in approximately 3.2 hours. The 440 gpm net flowrate is sufficient to prevent the water in the steam generators from reaching less than the minimum level required and to prevent heatup of RCS to the point where water relief would occur.
Feedwater flow can be stopped when the RHR system has been placed in operation. This occurs when the RCS has been cooled to 350°F and its pressure reduced to less than or equal to 390 psig. The Technical Specification 3.7.6 required 200,000 gallons for Unit 1 and 166,000 gallons for Unit 2 (usable) in the CST for the auxiliary feed pumps is adequate for decay heat removal and for makeup to the steam generators during a controlled cooldown from full power to 350°F. Refer to Section 6.5.2.1.1 for additional information in usable inventory.
In case of an incident, such as a small break in the reactor coolant loop concurrent with a loss of offsite and main generator power, the plant can remain at the hot shutdown condition for a period of time that depends on the amount of water available in the CST. Cooldown delay guidance is found in the plant operating procedures, which, under certain conditions (e.g., control room inaccessibility), allow a delay in beginning cooldown. Backup sources of AFW are available as described in Section 6.5.2.1.1.
The Technical Specifications do not permit the RCS to be heated above 350°F without at least 200,000 gallons for Unit 1 and 166,000 gallons for Unit 2 of usable water in the CST.
The AFWS is protected by barriers and restraints from the dynamic effects of a ruptured pipe outside the containment.
As discussed above, only one motor-driven auxiliary feed pump is required to prevent RCS overpressurization. The single failure of any active component in the AFWS will not prevent the system from performing its safety-related function. DCPP UNITS 1 & 2 FSAR UPDATE 6.5-12 Revision 21 September 2013 Manual and remotely actuated control valves are provided for isolation of a broken pipe. The AFWS is protected from missiles, pipe whip, or jet impingement from the rupture of any nearby high-energy line. Flooding of safety-related equipment due to an AFW line rupture would not occur because of the relatively low flowrates and the location of the system. The consequences of postulated pipe rupture outside the containment, including the postulated rupture of AFWS lines, are discussed in Section 3.6.
An analysis, using the methodology presented in Reference 1, shows that cooldown using the AFWS will not be prevented by any postulated auxiliary steam line break within an AFWS compartment.
A fire protection review of the AFWS electrical cable and control wiring has shown that no single postulated fire can prevent the AFWS from taking the plant to cold shutdown. This is due to physical separation of redundant electrical buses, combined with the ability to control the AFWS from either the main control board, the hot shutdown panel, 4-kV switchgear, or at the valves. 6.5.4 TESTS AND INSPECTIONS The AFWS initiation signals and circuitry are testable. Such testability is included in the surveillance test procedures for the plant as delineated in the Technical Specifications.
The AFWS piping also has a periodic inservice inspection (ISI) program in accordance with the ASME B&PV Code, Section XI. 6.5.5 INSTRUMENTATION REQUIREMENTS As shown in Figures 7.3-8 and 7.3-17 the motor-driven AFW pumps are started by closure of the solid-state protection system (SSPS) output relay and one of the timers. The relay is actuated by safety injection initiation or low-low level in any steam generator. The timers provide automatic starting sequences after bus transfer either with or without safety injection. Each pump is started by a separate relay or timer from redundant SSPS trains A or B. The motor-driven pumps are also automatically started by trip of both main feedwater pumps, or an AMSAC signal.
The turbine-driven AFWS pump is started by opening a steam supply valve. As shown in Figure 7.3-18, this valve is opened by one of the SSPS output relays. One of these relays starts on loss of offsite power and the other on low-low level in any two steam generators. The turbine-driven pump is also started by an AMSAC signal.
The initiating sensors are powered from separate and redundant nuclear instrumentation and control panels, each of which is supplied by either onsite emergency generators or station emergency batteries. Each of the two redundant SSPS trains is supplied by a separate safety-grade power source.
DCPP UNITS 1 & 2 FSAR UPDATE 6.5-13 Revision 21 September 2013 Instrumentation is provided in the motor-driven pump discharge to sense low pump discharge pressure indicative of a depressurized steam generator. In a low pump discharge situation, control valves are automatically throttled to prevent pump runout. This automatic action limits flow to any depressurized steam generator.
No such instrumentation is provided for the turbine-driven AFW pump. Manual action by the plant operator is required to terminate flow to a depressurized steam generator.
Manual initiation for each train exists in the control room. The manual initiation system is installed in the same manner as the automatic initiation system. No single failure in the manual initiation portion of the circuit can result in the loss of AFWS function (see Figures 7.3-17 and 7.3-18 for the circuitry).
One AFW flow indicator is provided for each of four steam generators. The indicators are safety-grade. Indication is provided at the main control board and the hot shutdown panel.
Two separate critical instrument power buses are used for the four flow indicators, with two flow indicators on each bus. The flow from the turbine-driven auxiliary feedwater pump is monitored by the same indicators that monitor the motor-driven AFW pump flow.
Additional indication of AFW flow is provided by the safety-grade steam generator wide-range level indication. This provides recording on the main control board and indication on the hot shutdown panel. It is powered from the same bus that powers two of the flow indicators. 6.
5.6 REFERENCES
- 1. IEEE 279, Criteria for Protection Systems for Nuclear Power Generating Stations, 1971.
- 2. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
- 3. DCPs C-50829 and C-049829, Condensate Storage Tank Modification to Add Plenums
- 4. PG&E Letter to the NRC, "Review of Systems and Equipment Necessary to Accomplish a Safe Shutdown Following a Major Earthquake," dated January 26, 1978.
DCPP UNITS 1 & 2 FSAR UPDATE 6.5-14 Revision 21 September 2013 6.5.7 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures. DCPP UNIT 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 6.2-14 CONTAINMENT PRESSURE DIFFERENTIAL ELEMENTS FOR LOOP COMPARTMENT AND PRESSURIZER ENCLOSURE ANALYSIS MODEL Element Volume, ft3 Description 1 2.860 x 104 Loop compartment 2 2.550 x 104 Loop compartment 3 2.660 x 104 Loop compartment 4 2.660 x 104 Loop compartment 5 2.550 x 104 Loop compartment 6 2.860 x 104 Loop compartment 7 2.270 x 104 Dome 8 3.525 x 104 9 4.015 x 104 Compartments 8-12 below 10 1.251 x 104 Elevation 140 ft and above elevation 11 1.415 x 104 117 ft outside the crane wall 12 1.732 x 104 13 2.098 x 104 14 3.706 x 104 15 1.650 x 104 Compartments 13-18 below elevation 16 2.497 x 104 117 ft outside the crane wall 17 1.337 x 104 18 2.042 x 104 19 2.312 x 103 20 2.004 x 103 Pressurizer enclosure 21 9.69 x 102 DCPP UNIT 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 6.2-15 CONTAINMENT PRESSURE DIFFERENTIAL FLOW PATHS FOR LOOP COMPARTMENT AND PRESSURIZER ENCLOSURE ANALYSIS MODEL Flowpath Connecting Elements Minimum Flow Area, ft2 Flowpath Connecting Elements Minimum Flow Area, ft2 1-2 790.00 10-9 212.00 1-7 130.00 11-12 212.00 2-3 790.00 12-8 212.00 2-7 34.00 12-13 40.00 3-4 110.00 13-14 270.00 3-12 20.00 13-4 20.00 4-5 790.00 14-15 270.00 4-8 20.00 14-5 20.00 5-6 790.00 15-1 20.00 5-7 34.00 15-9 40.00 6-1 300.00 16-15 270.00 6-7 130.00 16-2 20.00 7-3 130.00 17-18 270.00 7-4 130.00 17-16 254.00 8-9 212.00 18-13 48.00 8-7 40.00 7-19(a) 32.80 9-6 40.00 19-20(a) 146.00 9-7 40.00 20-21(a) 125.00 10-11 212.00 2-21(a) 4.50 7-21(a) 25.30
a) Used only for pressurizer enclosure analysis.
DCPP UNIT 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 6.2-16 CONTAINMENT PRESSURE DIFFERENTIAL LOOP COMPARTMENT ANALYSIS - MASS AND ENERGY RELEASE RATES DOUBLE-ENDED SEVERANCE OF A REACTOR COOLANT HOT LEG Time, sec Mass Release Rate, lb/sec Energy Release Rate, Btu/sec 0. 2.4704E+05 1.3834E+08 2.5100E-03 7.3494E+04 4.0804E+07 5.0300E-03 7.2355E+04 4.0173E+07 1.0040E-02 7.0343E+04 3.9080E+07 1.7530E-02 6.8460E+04 3.8082E+07 2.5040E-02 6.7699E+04 3.7715E+07 2.7520E-02 8.8473E+04 4.9400E+07 3.5010E-02 9.3921E+04 5.2531E+07 4.2540E-02 9.7912E+04 5.4828E+07 5.0070E-02 1.0044E+05 5.6284E+07 5.7580E-02 1.0147E+05 5.6886E+07 6.5080E-02 1.0154E+05 5.6946E+07 7.5120E-02 1.0044E+05 5.6349E+07 8.2570E-02 9.8810E+04 5.5451E+07 9.2510E-02 9.5936E+04 5.3861E+07 1.0001E-01 9.3090E+04 5.2281E+07 1.1759E-01 8.5296E+04 4.6953E+07 1.2751E-01 8.2263E+04 4.6293E+07 1.6002E-01 7.4507E+04 4.2074E+07 1.7507E-01 7.1563E+04 4.0472E+07 1.7755E-01 7.2357E+04 4.0943E+07 1.9512E-01 7.2090E+04 4.0899E+07 2.0253E-01 7.1718E+04 4.0734E+07 2.1751E-01 7.0525E+04 4.0151E+07 2.6007E-01 6.5426E+04 3.7447E+07 2.7512E-01 6.3890E+04 3.6590E+07 2.8508E-01 6.3182E+04 3.6185E+07 2.9760E-01 6.2740E+04 3.5916E+07 3.1011E-01 6.2704E+04 3.5876E+07 3.4008E-01 6.2969E+04 3.6010E+07 3.5251E-01 6.2882E+04 3.5980E+07 3.6752E-01 6.2621E+04 3.5848E+07 4.0501E-01 6.2062E+04 3.5553E+07 5.0013E-01 6.1329E+04 3.5205E+07 6.0028E-01 6.0879E+04 3.6029E+07 1.1003E+00 5.6031E+04 3.3016E+07 1.4003E+00 5.2485E+04 3.1512E+07 2.0002E+00 4.4871E+04 2.7839E+07 2.2002E+00 4.2601E+04 2.6645E+07 2.5000E+00 4.0314E+04 2.5338E+07 2.6000E+00 4.0156E+04 2.4941E+07 3.0000E+00 3.9109E+04 2.4386E+07 DCPP UNIT 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 6.2-17 CONTAINMENT PRESSURE DIFFERENTIAL PRESSURIZER ENCLOSURE ANALYSIS - MASS AND ENERGY RELEASE RATES PRESSURIZER SPRAY LINE RUPTURE Time, sec Mass Release Rate, lb/sec Energy Release Rate, Btu/sec 0. 1 6.510x102 0.00101 1,843 1.201x106 0.00201 2,077 1.331x106 0.00302 2,095 1.341x106 0.01505 2,124 1.351x106 0.01605 2,143 1.362x106 0.02501 2,148 1.362x106 0.02707 2,168 1.372x106 0.02804 2,177 1.377x106 0.02907 2,182 1.380x106 0.03411 2,190 1.383x106 0.03504 2,190 1.383x106 0.03703 2,179 1.376x106 0.03906 2,165 1.368x106 0.04705 2,137 1.352x106 0.05404 2,143 1.353x106 0.07412 2,176 1.379x106 0.09005 2,151 1.357x106 0.09712 2,167 1.364x106 0.09910 2,174 1.369x106 0.10505 2,200 1.383x106 0.11017 2,218 1.387x106 0.11511 2,198 1.382x106 0.12010 2,176 1.369x106 0.13001 2,135 1.346x106 0.15015 2,161 1.368x106 0.15500 2,160 1.360x106 0.17509 2,126 1.340x106 0.23010 2,161 1.360x106 0.27005 2,141 1.349x106 0.30028 2,113 1.333x106 0.35002 2,125 1.340x106 0.40003 2,124 1.340x106 0.41001 2,116 1.335x106 0.52014 2,110 1.332x106 0.80008 2,116 1.328x106 1.0900 2,106 1.328x106 1.2701 2,100 1.323x106 1.7700 2,075 1.307x106 2.7300 2,033 1.280x106 3.0002 2,028 1.276x106 DCPP UNIT 1 & 2 FSAR UPDATE TABLE 6.2-18 Sheet 1 of 2 Revision 11 November 1996 CONTAINMENT PRESSURE DIFFERENTIAL ELEMENTS FOR REACTOR CAVITY ANALYSIS MODEL Volume, ft3
- 1. Pipe annulus 11.80
- 2. Lower reactor cavity 13,115.00
- 3. Break location 147.33
- 4. Reactor vessel annulus 26.14
- 5. Reactor vessel annulus 25.80
- 6. Reactor vessel annulus 24.84
- 7. Reactor vessel annulus 182.58
- 8. Reactor vessel annulus 25.16
- 9. Reactor vessel annulus 147.33
- 10. Reactor vessel annulus 24.84
- 11. Reactor vessel annulus 129.94
- 12. Reactor vessel annulus 24.51
- 13. Reactor vessel annulus 147.33
- 14. Reactor vessel annulus 24.84
- 15. Reactor vessel annulus 193.58
- 16. Reactor vessel annulus 25.16
- 17. Reactor vessel annulus 147.33
- 18. Reactor vessel annulus 24.84
- 19. Break location 129.94
- 20. Reactor vessel annulus 24.51
- 21. Lower containment 46,305.00
- 22. Lower containment 45,065.00
- 23. Lower containment 45,065.00
- 24. Lower containment 46,305.00
- 25. Pipe annulus 9.00
- 26. Pipe annulus 9.00
- 27. Pipe annulus 11.80
- 28. Pipe annulus 11.80
- 29. Pipe annulus 9.00
- 30. Pipe annulus 9.00
- 31. Pipe annulus 11.80 DCPP UNIT 1 & 2 FSAR UPDATE TABLE 6.2-18 Sheet 2 of 2 Revision 11 November 1996 Volume, ft3
- 32. Upper containment 2,105,510.00
- 33. Reactor vessel annulus 25.80
- 34. Reactor vessel annulus 25.46
- 36. Reactor vessel annulus 25.80
- 35. Reactor vessel annulus 26.14
- 37. Reactor vessel annulus 25.80
- 38. Reactor vessel annulus 25.46
- 39. Reactor vessel annulus 9.92
- 40. Reactor vessel annulus 10.14
- 41. Reactor vessel annulus 9.92
- 42. Reactor vessel annulus 9.70
- 43. Reactor vessel annulus 9.92
- 44. Reactor vessel annulus 10.14
- 45. Reactor vessel annulus 9.92
- 46. Reactor vessel annulus 9.70
- 47. Inspection port 14.10
- 48. Inspection port 14.10
- 49. Inspection port 14.10
- 50. Inspection port 14.10
- 51. Inspection port 14.10
- 52. Inspection port 14.10
- 53. Inspection port 14.10
- 54. Inspection port 14.10
DCPP UNIT 1 & 2 FSAR UPDATE TABLE 6.2-19 Sheet 1 of 5 Revision 11 November 1996 CONTAINMENT PRESSURE DIFFERENTIAL FLOWPATH DATA FOR REACTOR CAVITY ANALYSIS MODEL Between Elements Initial Element Secondary Element K f x103 Inertia Length, ft Hydraulic Diameter of Smaller Element ft Minimum Flow Area, ft2 Equivalent Length of Smaller Element, for fl/D, ft 1 3 0.88 25 2.50 0.44 1.28 2.29 1 19 0.88 25 2.50 0.44 1.28 2.29 1 21 1.00 25 2.30 0.44 2.56 2.30 2 23 1.00 13 15.00 7.83 20.60 15.36 2 24 1.00 13 22.12 7.83 32.70 15.36 3 5 0.45 24 4.69 0.50 1.74 4.44 3 7 0.00 18 8.70 1.59 9.72 8.70 3 19 0.00 18 8.10 1.43 7.10 8.10 3 47 0.44 17 2.69 2.00 3.14 2.28 3 39 0.45 25 2.45 0.41 1.42 2.25 3 25 0.45 24 1.96 0.46 1.28 1.75 4 8 0.00 24 8.70 0.50 1.77 8.70 4 33 0.00 24 6.75 0.51 2.31 6.76 5 4 0.00 24 6.75 0.51 2.31 6.76 5 6 0.00 24 8.70 0.50 1.74 8.70 5 38 0.00 24 6.60 0.51 2.31 6.60 6 2 1.00 24 4.25 0.50 1.74 4.25 6 8 0.00 24 6.75 0.50 2.21 6.76 6 20 0.00 24 6.60 0.50 2.21 6.60 7 4 0.45 24 4.62 0.50 1.77 4.44 7 9 0.00 18 8.70 1.59 9.72 8.70 7 25 0.45 24 1.96 0.46 1.28 1.75 7 26 0.45 24 1.96 0.46 1.28 1.75 7 40 0.45 25 2.40 0.42 1.46 2.25 7 48 0.44 17 2.56 2.00 3.14 2.26 DCPP UNIT 1 & 2 FSAR UPDATE TABLE 6.2-19 Sheet 2 of 5 Revision 11 November 1996 Between Elements Initial Element Secondary Element K f x103 Inertia Length, ft Hydraulic Diameter of Smaller Element ft Minimum Flow Area, ft2 Equivalent Length of Smaller Element, for fl/D, ft 8 2 1.00 24 4.25 0.50 1.77 4.25 8 10 0.00 24 6.75 0.50 2.21 6.76 9 11 0.00 18 8.10 1.43 7.10 8.10 9 26 0.45 24 1.96 0.46 1.28 1.75 9 27 0.45 25 2.50 0.44 1.28 2.29 9 33 0.45 24 4.69 0.50 1.74 4.44 9 41 0.45 25 2.45 0.41 1.42 2.25 9 49 0.44 17 2.69 2.00 3.14 2.28 10 2 1.00 24 4.25 0.50 1.74 4.25 10 12 0.00 24 6.60 0.50 2.21 6.60 11 13 0.00 18 8.10 1.43 7.10 8.10 11 27 0.45 25 2.50 0.44 1.28 2.29 11 28 0.45 25 2.50 0.44 1.28 2.29 11 34 0.45 24 4.69 0.50 1.70 4.44 11 42 0.45 25 2.46 0.41 1.39 2.25 11 50 0.44 17 2.71 2.00 3.14 2.28 12 2 1.00 24 4.25 0.50 1.70 4.25 12 14 0.00 24 6.60 0.50 2.21 6.60 13 28 0.45 25 2.50 0.44 1.28 2.29 13 29 0.45 24 1.96 0.46 1.28 1.75 13 35 0.45 24 4.69 0.50 1.74 4.44 13 43 0.45 25 2.45 0.41 1.42 2.25 13 51 0.44 17 2.69 2.00 3.14 2.28 14 2 1.00 24 4.25 0.50 1.74 4.25 DCPP UNIT 1 & 2 FSAR UPDATE TABLE 6.2-19 Sheet 3 of 5 Revision 11 November 1996 Between Elements Initial Element Secondary Element K f x103 Inertia Length, ft Hydraulic Diameter of Smaller Element, ft Minimum Flow Area, ft2 Equivalent Length of Smaller Element for fl/D, ft 15 13 0.00 18 8.70 1.59 9.72 8.70 15 29 0.45 24 1.96 0.46 1.28 1.75 15 30 0.45 24 1.96 0.46 1.28 1.75 15 36 0.45 24 4.62 0.50 1.77 4.44 15 44 0.45 25 2.40 0.42 1.46 2.25 15 52 0.44 17 2.56 2.00 3.14 2.26 16 2 1.00 24 4.25 0.50 1.77 4.25 16 14 0.00 24 6.75 0.50 2.21 6.76 17 15 0.00 18 8.70 1.59 9.72 8.70 17 30 0.45 24 1.96 0.46 1.28 1.75 17 31 0.45 25 2.50 0.44 1.28 2.29 17 37 0.45 24 4.69 0.50 1.74 4.44 17 45 0.45 25 2.45 0.41 1.42 2.25 17 53 0.44 17 2.69 2.00 3.14 2.28 18 2 1.00 24 4.25 0.50 1.74 4.25 18 16 0.00 24 6.75 0.50 2.21 6.76 19 17 0.00 18 8.10 1.43 7.10 8.10 19 31 0.45 25 2.50 0.44 1.28 2.29 19 38 0.45 24 4.69 0.50 1.70 4.44 19 46 0.45 25 2.46 0.41 1.39 2.25 19 54 0.44 17 2.71 2.00 3.14 2.28 20 2 1.00 24 4.25 0.50 1.70 4.25 20 18 0.00 24 6.60 0.50 2.21 6.60 21 22 0.00 11 50.00 15.81 802.30 50.00 21 32 1.00 11 24.50 17.24 952.00 24.50 DCPP UNIT 1 & 2 FSAR UPDATE TABLE 6.2-19 Sheet 4 of 5 Revision 11 November 1996 Between Elements Initial Element Secondary Element K f x103 Inertia Length, ft Hydraulic Diameter of Smaller Element ft Minimum Flow Area, ft2 Equivalent Length of Smaller Element, for fl/D, ft 22 32 1.00 11 24.50 17.24 952.00 24.50 23 22 0.00 11 50.00 15.81 802.30 50.00 23 32 1.00 11 24.50 17.24 952.00 24.50 24 21 0.00 11 50.00 15.81 802.30 50.00 24 23 0.00 11 50.00 15.81 802.30 50.0 24 32 1.00 11 24.50 17.24 952.00 24.50 25 22 1.00 24 1.75 0.46 2.56 1.75 26 22 1.00 24 1.75 0.46 2.56 1.75 27 23 1.00 25 2.30 0.44 2.56 2.30 28 23 1.00 25 2.30 0.44 2.56 2.30 29 24 1.00 24 1.75 0.46 2.56 1.75 30 24 1.00 24 1.75 0.46 2.56 1.75 31 21 1.00 25 2.30 0.44 2.56 2.30 33 10 0.00 24 8.70 0.50 1.74 8.70 33 34 0.00 24 6.60 0.51 2.31 6.60 34 12 0.00 24 8.70 0.50 1.70 8.70 34 35 0.00 24 6.60 0.51 2.31 6.60 35 14 0.00 24 8.70 0.50 1.74 8.70 36 16 0.00 24 8.70 0.50 1.77 8.70 36 35 0.00 24 6.75 0.51 2.31 6.67 37 18 0.00 24 8.70 0.50 1.74 8.70 37 36 0.00 24 6.75 0.51 2.31 6.67 38 20 0.00 24 8.70 0.50 1.70 8.70 38 37 0.00 24 6.60 0.51 2.31 6.60 DCPP UNIT 1 & 2 FSAR UPDATE TABLE 6.2-19 Sheet 5 of 5 Revision 11 November 1996 Between Elements Initial Element Secondary Element K f x103 Inertia Length, ft Hydraulic Diameter of Smaller Element, ft Minimum Flow Area, ft2 Equivalent Length of Smaller Element for fl/D, ft 39 32 1.00 25 2.25 0.41 1.42 2.25 39 40 0.00 24 7.07 0.53 1.44 7.08 39 46 0.00 24 6.91 0.53 1.44 6.92 40 32 1.00 25 2.25 0.42 1.46 2.25 40 41 0.00 24 7.07 0.53 1.44 7.08 41 32 1.00 25 2.25 0.41 1.42 2.25 41 42 0.00 24 6.91 0.53 1.44 6.92 42 32 1.00 25 2.25 0.41 1.39 2.25 42 43 0.00 24 6.91 0.53 1.44 6.92 43 32 1.00 25 2.25 0.41 1.42 2.25 44 32 1.00 25 2.25 0.42 1.46 2.25 44 43 0.00 24 7.07 0.53 1.44 7.08 45 32 1.00 25 2.25 0.41 1.42 2.25 45 44 0.00 24 7.07 0.53 1.44 7.08 46 32 1.00 25 2.25 0.41 1.39 2.25 46 45 0.00 24 6.91 0.53 1.44 6.92 47 32 1.00 17 2.25 2.00 3.14 2.25 48 32 1.00 17 2.25 2.00 3.14 2.25 49 32 1.00 17 2.25 2.00 3.14 2.25 50 32 1.00 17 2.25 2.00 3.14 2.25 51 32 1.00 17 2.25 2.00 3.14 2.25 52 32 1.00 17 2.25 2.00 3.14 2.25 53 32 1.00 17 2.25 2.00 3.14 2.25 54 32 1.00 17 2.25 2.00 3.14 2.25
DCPP UNIT 1 & 2 FSAR UPDATE TABLE 6.2-20 Sheet 1 of 6 Revision 11 November 1996 CONTAINMENT PRESSURE DIFFERENTIAL REACTOR CAVITY ANALYSIS - TOTAL MASS AND ENERGY RELEASE RATES 426 in2 Hot Leg Break Time, sec (X10-3) Mass Flow, lbm/sec (X104) Energy Flow, Btu/sec (X107) 0 0 0 1 2.77 1.78 2 2.88 1.85 3 2.80 1.80 4 2.73 1.75 5 2.68 1.71 6 2.65 1.69 7 2.66 1.69 8 2.68 1.70 9 2.71 1.72 10 2.75 1.75 11 2.80 1.78 12 2.84 1.80 13 2.88 1.83 14 2.92 1.85 15 3.42 2.17 16 3.56 2.26 17 3.44 2.18 18 3.61 2.29 19 4.00 2.54 20 3.98 2.53 21 4.45 2.82 22 4.06 2.58 23 4.27 2.71 24 4.30 2.72 25 4.40 2.79 26 4.61 2.92 27 4.62 2.93 28 4.61 2.93 29 4.59 2.91 30 4.56 2.89 31 4.54 2.88 32 4.48 2.84 33 4.31 2.73 34 4.19 2.65 35 4.17 2.64 36 4.17 2.64 37 4.18 2.65 38 4.16 2.63 39 4.13 2.61 DCPP UNIT 1 & 2 FSAR UPDATE TABLE 6.2-20 Sheet 2 of 6 Revision 11 November 1996 426 in2 Hot Leg Break Time, sec (X10-3) Mass Flow, lbm/sec (X104) Energy Flow, Btu/sec (X107) 41 4.31 2.73 42 4.34 2.75 43 4.34 2.75 44 4.32 2.74 45 4.29 2.72 46 4.22 2.67 47 4.09 2.59 48 4.02 2.54 49 4.01 2.54 50 4.02 2.55 51 4.03 2.55 52 4.03 2.55 53 4.05 2.56 54 4.09 2.59 55 4.11 2.60 56 4.11 2.60 54 4.09 2.59 55 4.11 2.60 56 4.11 2.60 57 4.08 2.58 58 4.05 2.56 59 4.00 2.53 60 3.94 2.49 61 3.89 2.46 62 3.88 2.45 63 3.88 2.46 64 3.89 2.46 65 3.90 2.47 66 3.91 2.47 67 3.91 2.48 68 3.91 2.48 69 3.90 2.47 70 3.87 2.45 71 3.83 2.42 72 3.79 2.39 73 3.74 2.37 74 3.70 2.34 75 3.68 2.33 76 3.68 2.33 77 3.67 2.32 78 3.66 2.32 79 3.65 2.31 DCPP UNIT 1 & 2 FSAR UPDATE TABLE 6.2-20 Sheet 3 of 6 Revision 11 November 1996 426 in2 Hot Leg Break Time, sec (X10-3) Mass Flow, lbm/sec (X104) Energy Flow, Btu/sec (X107) 80 3.64 2.30 81 3.63 2.29 82 3.61 2.28 83 3.60 2.27 84 3.58 2.26 85 3.56 2.25 86 3.54 2.24 87 3.51 2.22 88 3.47 2.19 89 3.41 2.16 90 3.38 2.14 92 3.34 2.12 93 3.12 2.09 94 3.28 2.08 95 3.26 2.06 96 3.23 2.04 97 3.21 2.03 98 3.18 2.01 99 3.16 1.99 100 3.13 1.98 105 3.03 1.92 110 2.97 1.88 115 2.92 1.85 120 2.91 1.84 125 2.90 1.83 130 2.89 1.83 135 2.88 1.82 140 2.88 1.82 145 2.87 1.81 150 2.87 1.81 155 2.86 1.81 160 2.86 1.80 165 2.85 1.80 170 2.85 1.80 175 2.84 1.80 180 2.84 1.80 185 2.84 1.80 190 2.84 1.80 195 2.85 1.80 200 2.85 1.80 210 2.86 1.80 220 2.86 1.81 DCPP UNIT 1 & 2 FSAR UPDATE TABLE 6.2-20 Sheet 4 of 6 Revision 11 November 1996 426 in2 Hot Leg Break Time, sec (X10-3) Mass Flow, lbm/sec (X104) Energy Flow, Btu/sec (X107) 230 2.86 1.80 240 2.85 1.80 250 2.85 1.80 260 2.85 1.80 270 2.86 1.81 280 2.87 1.81 290 2.87 1.81 300 2.86 1.80 310 2.86 1.80 320 2.85 1.80 330 2.83 1.79 340 2.82 1.78 350 2.81 1.78 360 2.81 1.77 370 2.81 1.77 380 2.81 1.78 390 2.82 1.78 400 2.82 1.78 410 2.81 1.78 430 2.81 1.78 440 2.81 1.78 450 2.81 1.77 460 2.81 1.77 470 2.80 1.77 480 2.80 1.77 490 2.80 1.77 500 2.79 1.76 510 2.79 1.76 520 2.78 1.76 530 2.78 1.75 540 2.78 1.75 550 2.78 1.75 560 2.78 1.76 570 2.78 1.76 580 2.79 1.76 590 2.79 1.76 600 2.79 1.76 610 2.79 1.76 620 2.78 1.76 630 2.78 1.75 640 2.78 1.75 DCPP UNIT 1 & 2 FSAR UPDATE TABLE 6.2-20 Sheet 5 of 6 Revision 11 November 1996 426 in2 Hot Leg Break Time, sec (X10-3) Mass Flow, lbm/sec (X104) Energy Flow, Btu/sec (X107) 650 2.77 1.75 660 2.77 1.75 670 2.77 1.75 680 2.77 1.75 690 2.78 1.75 700 2.78 1.75 710 2.78 1.75 720 2.78 1.75 730 2.78 1.75 740 2.78 1.75 750 2.78 1.75 760 2.78 1.75 770 2.78 1.75 780 2.78 1.75 790 2.78 1.75 800 2.78 1.75 810 2.78 1.75 820 2.77 1.75 830 2.77 1.75 840 2.77 1.75 850 2.77 1.75 860 2.77 1.75 870 2.77 1.75 880 2.77 1.75 890 2.77 1.75 900 2.77 1.75 910 2.76 1.75 920 2.76 1.75 940 2.76 1.74 950 2.76 1.74 960 2.75 1.74 970 2.75 1.74 980 2.75 1.74 990 2.75 1.74 1000 2.75 1.74 1100 2.72 1.72 1200 2.70 1.71 13 2.68 1.70 1400 2.67 1.69 1500 2.65 1.69 1600 2.64 1.68 DCPP UNIT 1 & 2 FSAR UPDATE TABLE 6.2-20 Sheet 6 of 6 Revision 11 November 1996 426 in2 Hot Leg Break Time, sec (X10-3) Mass Flow, lbm/sec (X104) Energy Flow, Btu/sec (X107) 1700 2.62 1.67 1800 2.59 1.65 1900 2.57 1.64 2000 2.55 1.63 2100 2.53 1.62 2200 2.51 1.61 2300 2.49 1.60 2400 2.47 1.58 2500 2.45 1.57 2600 2.43 1.56 2700 2.41 1.55 2800 2.39 1.54 2900 2.37 1.53 3000 2.35 1.52
DCPP UNIT 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 6.2-21 CONTAINMENT PRESSURE DIFFERENTIAL REACTOR CAVITY ANALYSIS - CALCULATED PEAK PRESSURES Element Peak Pressure, psig Element Peak Pressure, psig 1 280 31 135 2 (a) 32 (a) 3 325 33 113 4 134 34 112 5 138 35 108 6 100 36 105 7 170 37 122 8 100 38 137 9 125 39 149 10 100 40 148 11 117 41 116 12 102 42 112 13 112 43 109 14 100 44 109 15 113 45 130 16 99 46 146 17 135 47 303 18 100 48 157 19 325 49 115 20 100 50 107 21 (a) 51 103 22 (a) 52 105 23 (a) 53 124 24 (a) 54 301 25 169 26 116 27 109 28 100 29 100 30 103 (a) Pressure still increasing 1.0 second after break. The long-term pressure transient is described by analysis in Appendix 6.2D.
DCPP UNIT 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 6.2-22 CONTAINMENT PRESSURE DIFFERENTIAL ELEMENTS FOR PIPE ANNULUS ANALYSIS MODEL Element Volume, ft3 Vent Area, ft2 Loop compartment 1 80,700.00 764.00
Loop compartment 2 80,700.00 804.00
Reactor coolant pipe annulus 30.00 10.25
Reactor vessel annulus 620.00 49.84
Lower reactor cavity 6,750.00 48.00
DCPP UNIT 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 6.2-23 CONTAINMENT PRESSURE DIFFERENTIAL PIPE ANNULUS ANALYSIS - MASS AND ENERGY RELEASE RATES COLD LEG BREAK INSIDE PIPE ANNULUS Time, Mass Release Rate, Energy Release Rate, sec lb/sec Btu/sec 0. 1.1282E+05 6.3328E+07 7.5300E-03 3.3118E+04 1.8430E+07 2.5100E-02 5.8777E+04 3.2805E+07 5.5080E-02 7.6822E+04 4.2973E+07 9.7550E-02 7.3730E+04 4.1204E+07 1.0521E-01 7.3931E+04 4.1316E+07 1.2273E-01 7.3538E+04 4.1100E+07 1.3518E-01 7.3781E+04 4.1239E+07 2.0001E-01 7.2990E+04 4.0790E+07 4.5013E-01 7.2189E+04 4.0342E+07 6.8507E-01 7.0839E+04 3.9583E+07 1.5003E+00 6.1318E+04 3.4228E+07 DCPP UNIT 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 6.2-24 CONTAINMENT PRESSURE DIFFERENTIAL COMPARTMENT PRESSURES
Compartment Design Differential Pressure, psi Calculated Peak Differential Pressure, psi Calculated Absolute Pressure At Time of Peak Differential, psia Loop compartment 15.0 14.5 29.4
Reactor coolant pipe annulus 1,200 1,018 1,033
Reactor vessel annulus 120(a) 325(b) 341 Lower reactor cavity 60 51 66
Pressurizer enclosure 4 2.6 (c) 17.6 (a) See discussion in Section 6.2.1.3.6. (b) The peak break compartment pressure is 175 psig for a 115-square-inch cold leg break. (c) Value includes 0.1 psi penalty from Tavg coastdown effects from replacing the steam generators. See Appendix 6.2D.2.2.4.
DCPP UNIT 1 & 2 FSAR UPDATE Revision 12 September 1998 TABLE 6.2-25 CONTAINMENT HEAT REMOVAL SYSTEMS DESIGN CODE REQUIREMENTS Component Code
Valves ANSI B16.5
Piping (including headers and spray nozzles)
- Design Class I portions ANSI B31.1 - Design Class II portions ANSI B31.1
Containment Spray Pump ASME BP&V III(a) Refueling Water Storage Tank AWWA D100(b)
(a) November 1968 draft code (b) ASME B&PV Code, Section VIII, Allowable Stresses Used for Design
DCPP UNIT 1 & 2 FSAR UPDATE TABLE 6.2-26 Sheet 1 of 3 Revision 18 October 2008 CONTAINMENT HEAT REMOVAL SYSTEMS DESIGN PARAMETERS Containment Spray Pump Type Horizontal Centrifugal Number (per unit) 2 Design pressure, psig 275(c) Design temperature, °F 275(c) Design flowrate, gpm 2600 Design head, ft 450 Material Type 316 stainless steel
Containment Spray Nozzle Number (per unit) 343 Type Spraco 1713A Flow per nozzle at 40 psi p, gpm 15.2 Material Type 304 stainless steel Refueling Water Storage Tank Number (per unit) 1 Total available tank volume (includes only usable volume)(a), gal 450,000 Minimum Technical Specifications required volume (includes usable and unusable volume), gal 455,300 Accident analysis volume (assumed), gal 350,000 Boron concentration, ppm 2300-2500 Design temperature, °F 100 Design pressure, psig Atmospheric Operating pressure, psig Atmospheric Material Austenitic stainless steel with reinforced concrete shroud Containment Fan Coolers Number (per unit) 5 Fan type Centrifugal Bearing monitors Vibration
DCPP UNIT 1 & 2 FSAR UPDATE TABLE 6.2-26 Sheet 2 of 3 Revision 18 October 2008 Containment Fan Coolers (Continued) Normal Mode Operation(b) Accident Mode Operation(b) Speed, rpm 1,200 600 Capacity, cfm 110,000 47,000 Static pressure at 0.075 lb/ft3, in. water 7.3 3.75 Containment atmosphere pressure, psig 0 47 Containment atmosphere temperature, °F 120 271 Containment atmosphere density, lb/ft3 0.0685 0.175 Brake horsepower 275 103 Name plate horsepower 300 100 Component cooling water flow to motor heat exchanger, gpm 50 30 (min) Motor Assembly Number (per unit) 5 Type 460 V, 3 phase, 60 Hz, two speed, single winding Bearing monitor Vibration and temperature Winding monitor RTDs Service factor 1 Heat exchange cooling media Component cooling water
Cooling Coil Assembly Number (per unit) 5 Type Plate-finned Tube material Copper Fin material Copper Fins per inch 8.5 Tube thickness, in. 0.035 Fin thickness, in. 0.008 Tube normal OD, in. 0.625 Tube length, in. 114 Vertical drain pan spacing, ft 3.25 Pan drain diameter, in. 2 Assembly drain diameter, in. 8 Drain pipe, Sch 10 Assembly frame material Steel Drain pan material Steel
DCPP UNIT 1 & 2 FSAR UPDATE TABLE 6.2-26 Sheet 3 of 3 Revision 18 October 2008 Containment Fan Coolers (Continued) Normal Accident Mode Operation(b) Operation(b) Heat removal minimum, Btu/hr 3.14 x 106 81 x 106 Steam-air flow, cfm 110,000 47,000 Steam-air inlet temperature, °F 120 271 Steam-air outlet temperature, °F 92.5 269 Total pressure, psig 0 47 Air density, lb/ft3 0.0685 0.0677 Steam density, lb/ft3 - 0.1073 Condensation rate, gpm 0 41.8 Air face velocity, fpm 645 275 Static pressure drop (0.075 lb/ft3), in. water 2.0 0.3 clean, 0.74 dirty Cooling water flow, gpm 2000 2000 Cooling water inlet temperature, °F 90 125 Cooling water outlet temperature, °F 94 212 Pressure drop, ft water 8.8 8.8 Coil tube side foul factor 0.0005 0.0005 Water velocity, fps 3.43 3.43 The moisture separator and HEPA filter were deleted in Revision 9.
(a) Usable volume includes the water above the outlet pipe. Unusable water includes the water below the outlet.
(b) CFCU data are shown for an illustration of performance at typical operating points. Design minimum CCW flow to the CFCU cooling coils is nominally 1600 gpm for both normal and limiting accident modes. Design maximum CCW flow to the CFCU cooling coils is 2500 gpm for accident modes. Temperatures, heat removal rates, and other parameters will vary dynamically according to the accident conditions. (c) Specified values for containment spray pump design pressure and temperature are maximum values and do not designate concurrent design conditions for the pump.
DCPP UNIT 1 & 2 FSAR UPDATE TABLE 6.2-27 Revision 12 September 1998 SINGLE FAILURE ANALYSIS - CONTAINMENT HEAT REMOVAL SYSTEMS Component Malfunction Comments and Consequences A. Spray Nozzles Clogged Large number of nozzles precludes clogging of a significant number. B. Pumps
Containment spray pump Fails to start Two pumps provided. Operation of one required. C. Automatically Operated Valves: (Open on coincidence of two out of four high-high containment pressure signals) Containment spray pump discharge isolation valve Fails to open Two complete systems provided. Operation of one required. D. Valves Operated From Control Room for Spray Recirculation, if Used Containment spray header isolation valve from residual heat exchanger discharge Fails to open Two complete systems provided. Operation of spray recirculation not required. E. Containment Fan Coolers Fails to start Five fan coolers provided. Two required for minimum safety feature operation.
DCPP UNIT 1 & 2 FSAR UPDATE Revision 12 September 1998 TABLE 6.2-29 SPRAY ADDITIVE SYSTEM DESIGN PARAMETERS Eductors Quantity 2 Eductor Inlet (motive) Operating fluid Borated Water Operating temperature Ambient Eductor Suction fluid NaOH concentration, wt% 30 Specific gravity ~ 1.3 Viscosity (design), cp ~ 10 Operating temperature Ambient
Spray Additive Tank Number 1 Total Volume (empty), gal. 4000 NaOH Concentration, wt% 30 Design Temperature, °F 300 Internal Design Pressure, psig 14 Operating Temperature, °F 100 Operating Pressure, psig ~ 3(a) Material Stainless Steel
(a) During normal operating and test conditions, the tank is pressurized with nitrogen at 3 psig. During preoperational testing or following a postulated accident, the nitrogen supply system will supply sufficient nitrogen to maintain this pressure as the tank empties. In the postulated event that the nitrogen supply system is inoperative, the tank pressure would fall below atmospheric pressure as the tank empties. Vacuum breakers are provided for this occurrence. DCPP UNIT 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 6.2-30 SPRAY ADDITIVE SYSTEM - CODES USED IN SYSTEM DESIGN Spray Additive Tank ASME B&PV, Section VIII Code Class 3 Valves ANSI B16.5
Piping (including headers and spray nozzles)
Design Class I portions ANSI B31.7 Design Class II portions ANSI B31.1
Eductors ASME B&PV, Section III
DCPP UNIT 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 6.2-36 PARAMETERS AND RESULTS FOR SPRAY IODINE REMOVAL ANALYSIS DURING INJECTION PHASE OPERATION(a) Best Minimum Design Parameter Estimate Expected Case Power, MWt 3568 3568 3568 Containment free vol, ft3 2.6 x 106 2.6 x 106 2.6 x 106 Unsprayed volume, % 17 17 17 No. pumps operating 2 1 1 Spray pump flowrate, gpm 5300 2650 2600 Containment pressure, psig 25 25 47 Containment temperature, °F 233 233 271 Spray fall height, ft 132.75 128 128 Spray solution pH 9.85(b) 9.85(b) 9.5 Results Exponential removal constant for the spray system (hr-1) 92 36 31(c) (a) Data provided in this table are for spray iodine removal analysis only. A different set of data used in the containment integrity analysis are provided in Appendix 6.2D. (b) Based on 2000 ppm boron concentration in the RWST. Only the Design Case has been updated for the change to a minimum 2300 ppm boron concentration in the RWST. (c) Although a subsequent safety evaluation showed that the Design Case coefficient of 31 hr-1 (for 2600 gpm spray header flow) should be reduced to approximately 29 hr-1 (for 2466 gpm spray header flow), the potential offsite dose increase due to this change is extremely small and can be considered insignificant (Reference 50).
DCPP UNIT 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 6.2-37 SPRAY FALL HEIGHTS IN THE CONTAINMENT Area(a), ft2 Drop Fall Height(b), ft 1,075 58 1,400 93 100 105 225 122 9,900 128 150 145 2,550 177 (a) Area represents portion of operating deck covered by spray nozzles located at a particular elevation above the operating deck. (b) Measured from 268 ft minimum average nozzle elevation. Average spray fall height: 128 ft. DCPP UNIT 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 6.2-38 SPRAY ADDITIVE SYSTEM SINGLE FAILURE ANALYSIS
Component Malfunction Comments and Consequences Automatically Operated Valves: (Open on coincidence of two-out-four high-high signals) Spray additive tank outlet isolation valve Fails to open Two parallel provided. Operation of one required.
DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 1 of 20 CONTAINMENT PIPING PENETRATIONS AND VALVING Revision 20 November 2011 Pentr. Nos. System (Safety Priority) (33) Figure 6.2-19 Sheet No. Vlv Ltr Valve ID Number (* = Credited CIV) (51) Valve Type (30) Oper-ator Type(31) Cntmt Locat. (32) Appli- cable GDC GDC Confor-mance PG&E Group (43) Control Room Indication Normal Position(35) Power Fail. Position Trip On (25) Used After LOCA (36) Post- LOCA Position (37) Fluid (23) Temp (24) Notes 1 Feedwater 1 (II) A FW-FCV-438* Gte Mtr O 57 Yes C Yes O As is (1) N C W Hot 1,26 (NE/SA) B FW-140* Gte Man O 57 (7) D No O As is - Y O W Hot 7,26,8 - FW-109(U2),536,108 Glb Man O 57 Yes No C - - N C W Hot 26,39 - FW-590(U2),596(U1) Gte Man O 57 Yes No C - - N C W Hot 26,39 - FW-377 Chk - O 57 Yes No C - - Y O W Hot 26,39
- S/G Tubes* Cls - I 57 Yes D - - - - Y - W Hot 2,44 2 Feedwater 1 (II) A FW-FCV-439* Gte Mtr O 57 Yes C Yes O As is (1) N C W Hot 1,26 (NE/SA) B FW-147* Gte Man O 57 (7) D No O As is - Y O W Hot 7,26,8 - FW-389(U2),535,103(U1) Glb Man O 57 Yes No C - - N C W Hot 26,39 FW-103(U2),141(U1),591(U2), Gte Man O 57 Yes No C - - N C W Hot 26,39 595(U1) Gte Man O 57 Yes No C - - N C W Hot 26,39 - FW-378 Chk - O 57 Yes No C - - Y O W Hot 26,39 - -S/G Tubes* Cls - I 57 Yes D - - - - Y - W Hot 2,44 3 Feedwater 1 (II) A FW-FCV-440* Gte Mtr O 57 Yes C Yes O As is (1) N C W Hot 1,26 (NE/SA) B FW-153* Gte Man O 57 (7) D No O As is - Y O W Hot 7,26,8 - FW-97(U2),102(U1),533 Glb Man O 57 Yes No C - - N C W Hot 26.39 - FW-97(U1), 592(U2) Gte Man O 57 Yes No C - - N C W Hot 26.39 - FW-379 Chk - O 57 Yes No C - - Y O W Hot 26.39 - S/G Tubes* Cls - I 57 Yes D - - - - Y - W Hot 2,44 4 Feedwater 1 (II) A FW-FCV-441* Gte Mtr O 57 Yes C Yes O As is (1) N C W Hot 1,26 (NE/SA) B FW-157* Gte Man O 57 (7) D No O As is - Y O W Hot 7,26,8 - FW-99,534 Glb Man O 57 Yes No C - - N C W Hot 26.39 - ,107(U1),593(U2) Gte Man O 57 Yes No C - - N C W Hot 26.39 - FW-380 Chk - O 57 Yes No C - - Y O W Hot 26,39 - S/G Tubes* Cls - I 57 Yes D - - - - Y - W Hot 2,44 - Flanged Connection Blf - O 55 - - No - - - N - W Hot 26 5 Main steam 1 (I) E MS-FCV-41* (3) Air O 57 Yes C Yes O As is (4) N C G Hot 3,4,26 (NE/SA) F MS-FCV-25* Glb Air O 57 Yes C Yes C Closed (4) N C G Hot 4,26 G MS-PCV-19* Glb Air O 57 (5) D Yes C Closed (5) N C G Hot 5,26 H MS-RV-3, 4, 5, 6, 222 Rlf Spr O 57 (39) No C Closed - N C G Hot 26,39 - MS-5399 Gte Man O 57 Yes No C - - N C G Hot 26,39 - MS-5407 Glb Man O 57 Yes No C - - N C G Hot 26,39 - MS-1014(U1),1016(U2),1017(U2),1018(U2) Glb Man O 57 Yes No C - - N C G Hot 26,39 - MS-1014(U2),1015,1016(U1) Gte Man O 57 Yes No C - - N C G Hot 26,39 - 1017(U1),1018(U1),1019 Gte Man O 57 Yes No C - - N C G Hot 26,39 - MS-1001,1002,1003, Gte Man I 57 Yes No - - - N C G Hot 26,39 - 1004(U1),1005,1006(U1),1007, Gte Man I 57 Yes No - - - N C G Hot 26,39 - 1008(U1),1009,1011,1012(U1) Gte Man I 57 Yes No - - - N C G Hot 26,39 - MS-1004(U2),1006(U2),1008(U2), Glb Man I 57 Yes No - - - N C G Hot 26,39 - 1012(U2),1013 Glb Man I 57 Yes No - - - N C G Hot 26,39 - 1(2)-04F-42A,42B,42C,42D,42E, Glb Man I 57 Yes - - - - N - G Hot 26,39 - 42F,42G,42H(U2),42I(U2), Glb Man I 57 Yes - - - - N - G Hot 26,39 DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 2 of 20 Revision 20 November 2011 Pentr. Nos. System (Safety Priority) (33) Figure 6.2-19 Sheet No. Vlv Ltr Valve ID Number (* = Credited CIV) (51) ValveType (30) Oper-ator Type(31) Cntmt Locat.(32) Appli-cable GDC GDC Confor-mance PG&E Group(43) Control Room Indication Normal Position(35) Power Fail. Position Trip On (25) Used After LOCA (36) Post- LOCA Position(37) Fluid(23) Temp (24)
Notes - Vent Plugs (U1), Glb Man I 57 Yes - - - - N - G Hot 26,39 - 46A, 46B, 46C,46D,46E,46F,46G, Glb Man I 57 Yes - - - - N - G Hot 26,39
- 46H, 46I, 46J Glb Man I 57 Yes - - - - N - G Hot 26,39 - 1(2)-04L-131A,131B,131C,131D, Glb Man I 57 Yes - - - - N - G Hot 26,39 - 131E,131F,131G,131H,131I, Glb Man I 57 Yes - - - - N - G Hot 26,39 - 131J,132A,132B,132C,132D, Glb Man I 57 Yes - - - - N - G Hot 26,39 - 132E,132F,132G,132H,132I,132J, Glb Man I 57 Yes - - - - N - G Hot 26,39 - 149,150A,150B,150C,150D, Glb Man I 57 Yes - - - - N - G Hot 26,39 - 150E,150F,150G,150H,151A, Glb Man I 57 Yes - - - N - G Hot 26,39 - 151B,151C,151D,151E,151F Glb Man I 57 Yes - - - - N - G Hot 26,39 - 151G,151H,152,159A,159B, Glb Man I 57 Yes - - - - N - G Hot 26,39 - 159C,159D,159E,159F,159G, Glb Man I 57 Yes - - - - N - G Hot 26,39 - 159H,159I,159J Glb Man I 57 Yes - - - - N - G Hot 26,39 - 1(2)-04P-12A,12B,12C,12D(U1), Glb Man O 57 Yes - - - - N - G Hot 26,39 - 12E(U1),13A,13B,13C,14A,14B, Glb Man O 57 Yes - - - - N - G Hot 26,39 - 14C,14D(U2),17A,17B,17C,98A,98B Glb Man O 57 Yes - - - - N - G Hot 26,39 - 98C(U2), Cap @ PI-518(U2), Glb Man O 57 Yes - - - - N - G Hot 26,39 - 108A,117(U2) Glb Man O 57 Yes - - - - N - G Hot 26,39 - 1(2)-04P-106 Glb Man I 57 Yes - - - - N - G Hot 26,39 - S/G Tubes* Cls - I - - D - - - - Y - G Hot 2,44 6 Main steam 2 (I) A MS-FCV-42* (3) Air O 57 Yes C Yes O As is (4) N C G Hot 3,4,26 (NE/SA) B MS-FCV-24* Glb Air O 57 Yes C Yes C Closed (4) N C G Hot 4,26 C MS-PCV-20* Glb Air O 57 (5) D Yes C Closed (5) N C G Hot 5,26 D MS-RV-7, 8, 9, 10, 223 Rlf Spr O 57 (39) No C Closed - N C G Hot 26,39 E MS-FCV-37* Gte Mtr O 57 Yes D Yes O As is R-M Y O G Hot 26 - MS-5398,2014(U2),2015, Gte Man O 57 Yes No C - - N C G Hot 26,39 - 2019 Gte Man O 57 Yes No C - - N C G Hot 26,39 H MS-5445 Glb Man O 57 Yes No C - - N C G Hot 26,39 - MS-5408,2014(U1), Glb Man O 57 Yes No C - - N C G Hot 26,39 - 2016,2017,2018 Glb Man O 57 Yes No C - - N C G Hot 26,39 - MS-2006(U2), 2007(U2), Glb Man I 57 Yes No C - - N C G Hot 26,39 - 2008(U2),2009(U2), 2013 Glb Man I 57 Yes No C - - N C G Hot 26,39 - MS-2001,2002,2003,2004,2005, Gte Man I 57 Yes No C - - N C G Hot 26,39 - 2006(U1),2007(U1),2008(U1), Gte Man I 57 Yes No C - - N C G Hot 26,39 - 2009(U1),2011,2012 Gte Man I 57 Yes No C - - N C G Hot 26,39 - 1(2)-04F-43A,43B,43C,43D,43E, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 43F,43G,43H(U2),43I(U2), Glb Man I 57 Yes No C - - N C G Hot 26,39 - 43J(U2),Vent Plugs(U1), , Glb Man I 57 Yes No C - - N C G Hot 26,39 - 47A,47B,47C,47D,47E,47F,47G, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 47H,47I(U2),47J(U2),Vent Plugs(U1) Glb Man I 57 Yes No C - - N C G Hot 26,39 - 1(2)-04L-135A,135B,135C,135D, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 135E,135F,135G,135H,136A, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 136B,136C,136D,136E,136F, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 136G,136H,136I,136J,137A,137B, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 137C,137D,137E,137F,137G, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 137H,137I,137J,153,154A,154B, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 154C,154D,154E,154F,154G, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 154H,154I,160A,160B,160C, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 160D,160E,160F,160G,160H, Glb Man I 57 Yes No C - - N C G Hot 26,39 DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 3 of 20 Revision 20 November 2011 Pentr. Nos. System (Safety Priority) (33) Figure 6.2-19 Sheet No. Vlv Ltr Valve ID Number (* = Credited CIV) (51) ValveType (30) Oper-ator Type(31) Cntmt Locat.(32) Appli-cable GDC GDC Confor-mance PG&E Group(43) Control Room Indication Normal Position(35) Power Fail. Position Trip On (25) Used After LOCA (36) Post- LOCA Position(37) Fluid(23) Temp (24)
Notes - 160I,160J, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 1(2)-04P-11A,11B,11C,11D(U1), Glb Man O 57 Yes No C - - N C G Hot 26,39
- 15A,15B,15C,16A,16B,16C,18A, Glb Man O 57 Yes No C - - N C G Hot 26,39 - 18B,18C,18D(U2),96A,96B, Glb Man O 67 Yes No C - - N C G Hot 26,39 - 96C(U2),Cap @ PI-528(U2), Glb Man O 57 Yes No C - - N C G Hot 26,39 - 100,109A Glb Man O 57 Yes No C - - N C G Hot 26,39 - 1(2)-04P-103 Glb Man I 57 Yes No C - - N C G Hot 26,39 - S/G Tubes* Cls - I 57 Yes D - - - - Y - G Hot 2,44 7 Main steam 2 (I) A MS-FCV-43* (3) Air O 57 Yes C Yes O As is (4) N C G Hot 3,4,26 (NE/SA) B MS-FCV-23* Glb Air O 57 Yes C Yes C Closed (4) N C G Hot 4,26 C MS-PCV-21* Glb Air O 57 (5) D Yes C Closed (5) N C G Hot 5,26 D MS-RV-11, 12, 13, 14, 224 Rlf Spr O 57 (39) No C Closed - N C G Hot 26,39 E MS-FCV-38* Gte Mtr O 57 Yes D Yes O As is R-M Y O G Hot 26 - MS-909(U2),3014(U2),3015,3019, Gte Man O 57 Yes No C - - N C G Hot 26,39 - 5397 Gte Man O 57 Yes No C - - N C G Hot 26,39 H MS-5444 Glb Man O 57 Yes No C - - N C G Hot 26,39 - MS-909(U1), 910, 3014(U1),5409, Glb Man O 57 Yes No C - - N C G Hot 26,39 - 3016, 3017, 3018 Glb Man O 57 Yes No C - - N C G Hot 26,39 - MS-3004(U2),3005(U1),3006, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 3007(U2),3013, Glb Man I 57 Yes No C - - N C G Hot 26,39 - MS-3001,3002,3003,3004(U1), Gte Man I 57 Yes No C - - N - G Hot 26,39 - 3005(U2),3007(U1),3008,3009, Gte Man I 57 Yes No C - - N - G Hot 26,39 - 3011,3012 Gte Man I 57 Yes No C - - N - G Hot 26,39 - 1(2)-04F-44A,44B,44C,44D,44E, Glb Man I 57 Yes No C - - N - G Hot 26,39 - 44F,44G,44H,44I,48A,48B,48C, Glb Man I 57 Yes No C - - N - G Hot 26,39 - 48D,48E,48F,48G,48H,48I(U2), Glb Man I 57 Yes No C - - N - G Hot 26,39 - 48J(U2),Vent Plugs(U1) Glb Man I 57 Yes No C - - N - G Hot 26,39 - 1(2)-04L-140A,140B,140C,140D, Glb Man I 57 Yes No C - - N - G Hot 26,39 - 140E,140F,140G,140H,141A, Glb Man I 57 Yes No C - - N - G Hot 26,39 - 141B,141C,141D,141E,141F, Glb Man I 57 Yes No C - - N - G Hot 26,39 - 141G,141H,141I,141J,142A, Glb Man I 57 Yes No C - - N - G Hot 26,39 - 142B,142C,142D,142E,142F, Glb Man I 57 Yes No C - - N - G Hot 26,39 - 142G,142H,142I,142J,155,156A, Glb Man I 57 Yes No C - - N - G Hot 26,39 - 156B,156C,156D,156E,156F, Glb Man I 57 Yes No C - - N - G Hot 26,39 - 156G,156H,156I,161A,161B, Glb Man I 57 Yes No C - - N - G Hot 26,39 - 161C,161D,161E,161F,161G, Glb Man I 57 Yes No C - - N - G Hot 26,39 - 161H,161I,161J Glb Man I 57 Yes No C - - N - G Hot 26,39 - 1(2)-04P-1A,1B,1C,5A,5B,Cap @PT-536A(U1) Glb Man O 57 Yes No C - - N - G Hot 26,39 - 6A,6B,6C,10A,10B,10C Glb Man O 57 Yes No C - - N - G Hot 26,39 - 97A,97B,97C(U2),Cap @ PI-538(U1) Glb Man O 57 Yes No C - - N - G Hot 26,39 - 110A Glb Man O 57 Yes No C - - N - G Hot 26,39 - 1(2)-04P-104 Glb Man I 57 Yes No C - - N - G Hot 26,39 - S/G Tubes* Cls - I 57 Yes D - - - - Y - G Hot 2,44 8 Main steam 1 (I) E MS-FCV-44* (3) Air O 57 Yes C Yes O As is (4) N C G Hot 3,4,26 (NE/SA) F MS-FCV-22* Glb Air O 57 Yes C Yes C Closed (4) N C G Hot 4,26 G MS-PCV-22* Glb Air O 57 (5) D Yes C Closed (5) N C G Hot 5,26 H MS-RV-58,59,60,61,225 Rlf Spr O 57 (39) No C Closed - N C G Hot 2639 DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 4 of 20 Revision 20 November 2011 Pentr. Nos. System (Safety Priority) (33) Figure 6.2-19 Sheet No. Vlv Ltr Valve ID Number (* = Credited CIV) (51) ValveType (30) Oper-ator Type(31) Cntmt Locat.(32) Appli-cable GDC GDC Confor-mance PG&E Group(43) Control Room Indication Normal Position(35) Power Fail. Position Trip On (25) Used After LOCA (36) Post- LOCA Position(37) Fluid(23) Temp (24)
Notes - MS-4015,4016(U1),4019,5396 Gte Man O 57 Yes No C - - N C G Hot 26,39 - MS-908,4014,4016(U2),4017 Glb Man O 57 Yes No C - - N C G Hot 26,39
- 4018,5410 Glb Man O 57 Yes No C - - N C G Hot 26,39 - MS-4001(U1),4002,4003,4004, Gte Man I 57 Yes No C - - N C G Hot 26,39 - 4006(U1),4007,4009,4011(U2), Gte Man I 57 Yes No C - - N C G Hot 26,39 - 4012 Gte Man I 57 Yes No C - - N C G Hot 26,39 - MS-4001(U2),4005,4013, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 4006(U2),4008,4011(U1), Glb Man I 57 Yes No C - - N C G Hot 26,39 - 1(2)-04F-45A,45B,45C,45D,45E, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 45F,45G,45H(U2),45I(U2), Glb Man I 57 Yes No C - - N C G Hot 26,39 - Vent Plugs(U1),49A Glb Man I 57 Yes No C - - N C G Hot 26,39 - 49B,49C,49D,49E,49F,49G,49H, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 49I(U1),49J(U1),Vent Plugs(U2) Glb Man I 57 Yes No C - - N C G Hot 26,39 - 1(2)-04L-145A,145B,145C,145D, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 145E,145F,145G,145H,146A, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 146B,146C,146D,146E,146F, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 146G,146H,146I,146J,147A, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 147B,147C,147D,147E,147F, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 147G,147H,147I,147J,157,158A, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 158B,158C,158D,158E,158F, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 158G,158H,158I,162A,162B, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 162C,162D,162E,162F,162G, Glb Man I 57 Yes No C - - N C G Hot 26,39 - 162H,162I,162J Glb Man I 57 Yes No C - - N C G Hot 26,39 - 1(2)-04P-2A,2B,2C,7A,7B,Cap@PT-546A(U1),8A,8B, Glb Man O 57 Yes No C - - N C G Hot 26,39 - 8C,9A,9B,9C,95A,95B,95C(U2),Cap@PI-548 Glb Man O 57 Yes No C - - N C G Hot 26,39 - 111A,133(U2) Glb Man O 57 Yes No C - - N C G Hot 26,39 - 1(2)-04P-105 Glb Man I 57 Yes No C - - N C G Hot 26,39 - S/G Tubes* Cls - I 57 Yes D - - - - N - G Hot 2,44 9 Component 3 (V) H CCW-169* But Man O 57 (7) D No O As is (7) Y O W Cold 7,26,8 Cooling Water to - CCW-170 Gte Man O 57 Yes No O As is (7) Y O W Cold 7,26,8,39 Fan Coolers (SA) - CCW-171 Glb Man I 57 Yes No C As is - Y C W Cold 26,39 - CCW-172 Gte Man I 57 Yes No C - - Y C W Cold 26,39 - Closed CFCU* Cls - I 57 Yes D - - - - Y - W Cold 47 10 Component 3 (V) H CCW-177* But Man O 57 (7) D No O As is (7) Y O W Cold 7,26,8 Cooling Water to - CCW-178 Gte Man O 57 Yes No O As is (7) Y O W Cold 7,26,8,39 Fan Coolers (SA) - CCW-179 Glb Man I 57 Yes No C As is - Y C W Cold 26,39 - CCW-180 Gte Man I 57 Yes No C - - Y C W Cold 26,39 - Closed CFCU* Cls - I 57 Yes D - - - - Y - W Cold 47 11 Component 3 (V) H CCW-469* But Man O 57 (7) D No O As is (7) Y O W Cold 7,26,8 Cooling Water to - CCW-470 Gte Man O 57 Yes No O As is (7) Y O W Cold 7,26,8,39 Fan Coolers (SA) - CCW-471 Glb Man I 57 Yes No C As is - Y C W Cold 26,39 - CCW-473 Gte Man I 57 Yes No C - - Y C W Cold 26,39 DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 5 of 20 Revision 20 November 2011 Pentr. Nos. System (Safety Priority) (33) Figure 6.2-19 Sheet No. Vlv Ltr Valve ID Number (* = Credited CIV) (51) ValveType (30) Oper-ator Type(31) Cntmt Locat.(32) Appli-cable GDC GDC Confor-mance PG&E Group(43) Control Room Indication Normal Position(35) Power Fail. Position Trip On (25) Used After LOCA (36) Post- LOCA Position(37) Fluid(23) Temp (24)
Notes - Closed CFCU* Cls - I 57 Yes D - - - - Y - W Cold 47 12 Component 3 (V) H CCW-477* But Man O 57 (7) D No O As is (7) Y O W Cold 7,26,8 Cooling Water to - CCW-478 Gte Man O 57 Yes No O As is (7) Y O W Cold 7,26,8,39 Fan Coolers (SA) - CCW-479 Glb Man I 57 Yes No C As is - Y C W Cold 26,39 - CCW-481 Gte Man I 57 Yes No C - - Y C W Cold 26,39 - Closed CFCU* Cls - I 57 Yes D - - - - Y - W Cold 47 13 Component 3 (V) H CCW-185* But Man O 57 (7) D No O As is (7) Y O W Cold 7,26,8 Cooling Water to - CCW-186(U1) Gte Man O 57 Yes No O As is (7) Y O W Cold 7,26,8,39 Fan Coolers (SA) - CCW-186(U2) Glb Man O 57 Yes No O As is (7) Y O W Cold 7,26,8,39 - CCW-187 Glb Man I 57 Yes No C As is - Y C W Cold 26,39 - CCW-188 Gte Man I 57 Yes No C - - Y C W Cold 26,39 - Closed CFCU* Cls - I 57 Yes D - - - - Y - W Cold 47 14 Component 3 (VI) I CCW-176* But Man O 57 (7) D No O As is (7) Y O W Cold 7,26,8 Cooling Water - CCW-175 Gte Man O 57 Yes No O As is (7) Y O W Cold 7,26,8,39 from Fan Coolers - 1(2)-14F-4A,4B,4C,4D,4E,4F,4G, Glb Man O 57 Yes No O - - Y C W Cold 26,39 (SA) - 4H,4I,4J,4K Glb Man O 57 Yes No O - - Y C W Cold 26,39 - CCW-173,174,704(U1), Glb Man I 57 Yes No C As is - Y C W Cold 26,39 - 704(U2) Gte Man I 57 Yes No C As is - Y C W Cold 26,39 - Closed CFCU* Cls - I 57 Yes D - - - - Y - W Cold 47 15 Component 3 (VI) I CCW-184* But Man O 57 (7) D No O As is (7) Y O W Cold 7,26,8 Cooling Water - CCW-183 Gte Man O 57 Yes No O As is (7) Y O W Cold 7,26,8,39 from Fan Coolers - 1(2)-14F-5A,5B,5C,5D,5E,5F,5G, Glb Man O 57 Yes No O - - Y C W Cold 26,39 (SA) - 5H,5I,5J,5K Glb Man O 57 Yes No O - - Y C W Cold 26,39 - CCW-181,182,705 Glb Man I 57 Yes No C As is - Y C W Cold 26,39
- Closed CFCU* Cls - I 57 Yes D - - - - Y - W Cold 47 16 Component 3 (VI) I CCW-476* But Man O 57 (7) D No O As is (7) Y O W Cold 7,26,8 Cooling Water - CCW-475 Gte Man O 57 Yes No O As is (7) Y O W Cold 7,26,8,39 from Fan Coolers - 1(2)-14F-13A,13B,13C,13D,13E, Glb Man O 57 Yes No O - - Y C W Cold 26,39 (SA) - 13F,13G,13H,13I,13J,13K Glb Man O 57 Yes No O - - Y C W Cold 26,39 - CCW-472,474,706 Glb Man I 57 Yes No C As is - Y - W Cold 26,39 - Closed CFCU* Cls - I 57 Yes D - - - - Y - W Cold 47 17 Component 3 (VI) I CCW-484* But Man O 57 (7) D No O As is (7) Y O W Cold 7,26,8 Cooling Water - CCW-483 Gte Man O 57 Yes No O As is (7) Y O W Cold 7,26,8,39 from Fan Coolers - 1(2)-14F-14A,14B,14C,14D,14E, Glb Man O 57 Yes No O - - Y C W Cold 26,39, (SA) - 14F,14G,14H,14I,14J(U2), Glb Man O 57 Yes No O - - Y C W Cold 26,39 - 14K(U2) Glb Man O 57 Yes No O - - Y C W Cold 26,39 - CCW-480,482,707 Glb - I 57 Yes No C As is - Y - W Cold 26,39 DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 6 of 20 Revision 20 November 2011 Pentr. Nos. System (Safety Priority) (33) Figure 6.2-19 Sheet No. Vlv Ltr Valve ID Number (* = Credited CIV) (51) ValveType (30) Oper-ator Type(31) Cntmt Locat.(32) Appli-cable GDC GDC Confor-mance PG&E Group(43) Control Room Indication Normal Position(35) Power Fail. Position Trip On (25) Used After LOCA (36) Post- LOCA Position(37) Fluid(23) Temp (24)
Notes - Closed CFCU* Cls - I 57 Yes D - - - - Y - W Cold 47 18 Component 3 (VI) I CCW-192* But Man O 57 (7) D No O As is (7) Y O W Cold 7,26,8 Cooling Water - CCW-191 Gte Man O 57 Yes No O As is (7) Y O W Cold 7,26,8,39 from Fan Coolers - 1(2)-14F-6A, Glb Man O 57 Yes No O - - Y C W Cold 26,39 (SA) - 6B,6C,6D,6E,6F,6G,6H,6I,6J,6K Glb Man O 57 Yes No O - - Y C W Cold 26,39 - CCW-189,190,708 Glb Man I 57 Yes No C As is - Y - W Cold 26,39 - Closed CFCU* Cls - I 57 Yes D - - - - Y - W Cold 47 19 Component 4 (I) A CCW-FCV-356* But Mtr O 55 Yes A Yes O As is P N C W Cold - Cooling Water to - CCW-297 Gte Man O 55 Yes No C As is P N C W Cold 26,39 Reactor Coolant B CCW-585* Chk - I 55 Yes A No O - - N O W Cold - Pumps (ES) 20 Component 4 (III) F CCW-FCV-363* But Mtr O 55 Yes A Yes O As is P N C W Cold - Cooling Water E CCW-FCV-749* But Mtr I 55 Yes A Yes O As is P N C W Cold - from Reactor H CCW-581* Chk - I 55 Yes A No O - - N O W Cold - Coolant Pumps (ES) 21 Component 4 (II) C CCW-FCV-750* Glb Mtr I 55 Yes A Yes O As is P N C W Hot - Cooling Water D CCW-FCV-357* Glb Mtr O 55 Yes A Yes O As is P N C W Hot - from Reactor G CCW-670* Chk - I 55 Yes A No O - - N O W Hot - Coolant Pumps (ES) 22 CCW to Excess 4 (IV) I CCW-695* Chk - O 57 (8) C No O - - N O W Cold 8 Letdown Heat - CCW-436 Gte Man I 57 Yes No - - - N - W Cold 26,39 Exchanger (NE) - CCW-428 Glb Man I 57 Yes No - - - N - W Cold 26,39
- - Cls - I 57 Yes C - - - - N - W Cold - 23 CCW from 4 (V) J CCW-FCV-361* But Air O 57 Yes C Yes O Closed T N C W Cold -
Excess - CCW-429,517 Gte Man I 57 Yes - - - - N - W Cold 26,39 Letdown Heat - CCW-RV-52 Rlf - I 57 Yes - - - - N - W Cold 39 Exchanger (NE) - - Cls - I 57 Yes C - - - - N - W Cold - 24 Residual Heat 5 (I) A SI-8818A* Chk - I 55 Yes B No O - - Y O W Hot 26,40 Removal No. 1 B SI-8818B* Chk - I 55 Yes B No O - - Y O W Hot 26,40 Cold Leg C SI-8809A Gte Mtr O 55 (9) Yes O As is R-M Y C W Hot 7,9,26,39,40 Injection (SA) M SI-8885A (U1) Glb Air I 55 Yes (22) C Closed - N C W Hot 22,26,39,41 - SI-73,94,95(U1),257, Glb Man I 55 Yes No C - - N C W Hot 22,26,39,42
- 258 Glb Man I 55 Yes No C - - N C W Hot 22,26,39,42 - Closed SI System* Cls - O 55 Yes B - - - - Y - W Hot 10 5A (I) M SI-317A (U2) Glb Man I 55 Yes No C - - N C W Hot 26, 39, 41 25 Residual Heat 5 (III) I SI-8818C* Chk - I 55 Yes B No O - - Y O W Hot 26,40 Removal No. 2 J SI-8818D* Chk - I 55 Yes B No O - - Y O W Hot 26,40 Cold Leg K SI-8885B (U1) Glb Air I 55 Yes (22) C Closed - N C W Hot 22,26,39,41 Injection (SA) - SI-259,260 Glb Man I 55 Yes No C - - N C W Hot 26,39,42 DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 7 of 21 Revision 20 November 2011 Pentr. Nos. System (Safety Priority) (33) Figure 6.2-19 Sheet No. Vlv Ltr Valve ID Number (* = Credited CIV) (51) ValveType (30) Oper-ator Type(31) Cntmt Locat.(32) Appli-cable GDC GDC Confor-mance PG&E Group(43) Control Room Indication Normal Position(35) Power Fail. Position Trip On (25) Used After LOCA (36) Post- LOCA Position(37) Fluid(23) Temp (24)
Notes L SI-8809B Gte Mtr O 55 (9) Yes O As is R-M Y C W Hot 7,9,26,39,40 5A (III) K SI-317B (U2) Glb Man I 55 Yes No C - - N C W Hot 26,39,41 - Closed SI System* Cls - O 55 Yes B - - - - Y - W Hot 10 26 Residual Heat 5 (II) D RHR-8716A Gte Mtr O 55 (9) Yes O As is R-M Y C W Hot 7,9,26,39,40 Removal Hot E RHR-HCV-670 Bal Air O 55 Yes Yes O O - N O W Hot 26,39,41 Leg Injection F RHR-8741 Gte Man O 55 Yes No C - - N C W Hot 26,39,41 (SA) - RHR-944(U2) Glb Man O 55 Yes No C - - N C W Hot 26,39,42 - 1(2)-10F-1A,1B,1C,1D, Glb Man O 55 Yes No C - - N C W Hot 26,39,41 - 1E,1F,1G,1H,1J,1K,1I,1L Glb Man O 55 Yes No C - - N C W Hot 26,39,41 G RHR-8716B Gte Mtr O 55 (9) Yes O As is R-M Y O W Hot 7,9,26,39,40 H RHR-8703* Gte Mtr I 55 (11) B Yes C As is R-M Y O W Hot 7,11,26,40 N RHR-RV-8708 Rlf - I 55 Yes No C As is - N C W Hot 26,39,41
- RHR-932,947,985 Glb Man I 55 Yes No C As is - N C W Hot 26,39,42 - Closed RHR System* Cls - O 55 Yes B - - - - Y - W Hot 10 27 Reactor Coolant 6 (I) A RHR-8701* Gte Mtr I 55 (11) D Yes O As is R-M N C W Hot 7,26,45 System Loop 4 G RHR-RV-8707 Rlf - I 55 (11) No C As is - N C W Hot 26,39 Recirculation (SA) - RHR-927 Glb Man I 55 - No C - - N C W Hot 26,39 H RHR-1012* Glb Man O 55 (11) D No C - - N C W Hot 26,45 I RHR-1014* Glb Man O 55 (11) D No C - - N C W Hot 26,45 B SI-8980* Gte Mtr O 55 (11) D Yes O As is R-M Y C W Hot 7,26,45 C RHR-8700A* Gte Mtr O 55 (11) D Yes O As is R-M Y C W Hot 7,26,45 D RHR-8700B* Gte Mtr O 55 (11) D Yes O As is R-M Y C W Hot 7,26,45 - RHR-937(U1),939(U1), Glb Man O 55 - No C - - N C W Hot 26,39 8706A,8706B Glb Man O 55 - No C - - N C W Hot 26,39 - RHR-1022 (U2), RHR-1024 (U2) Gte Man O 55 - - No C - - N C W Hot 26,39 RHR-1025, RHR-1027 Gte Man O 55 - - No C - - N C W Hot 26,39 - SFS Increased cooling Blf - O 55 - No - - - N - W Hot 26 Emergency connection (U1) 28 Containment 6 (II) E SI-8982A* Gte Mtr O 56 (12) D Yes C As is (12) Y O W Hot 12,26,53 Sump - SI-69 Glb Man O 56 - No C As is - N C W Hot 26,39,42 Recirculation (SA) - SI-8863A Glb Man O 56 - No C As is N C W Hot 26,39,41 - Closed SI System* Cls - O 56 (50) D - - - - Y - W Hot 10 29 Containment 6 (III) F SI-8982B* Gte Mtr O 56 (12) D Yes C As is (12) Y O W Hot 12,26,53 Sump - SI-66 Glb Man O 56 - No C As is - N C W Hot 26,39,42 Recirculation (SA) - SI-8863B Glb Man O 56 Yes - No C As is - N C W Hot 26,39,41 - Closed SI System* Cls - O 56 (50) D - - - - Y - W Hot 10 30 Containment 7 (I) A CS-9011B* Chk - I 56 Yes D No O - - Y C W Cold - Spray System B CS-9001B* Gte Mtr O 56 (11) D Yes C As is (13) Y C W Cold 11,13 (SA) C CS-30 Glb Man O 56 Yes No C - - N C W Cold 26,39 - CS-32 Glb Man O 56 Yes No C - - N C W Cold 39 - CS-36 Glb Man O 56 Yes No C - - N C W Cold 26,39 D CS-9003B* Gte Mtr O 56 (11) D Yes C As is (7) Y C W Cold 11,26,49,40 DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 8 of 20 Revision 20 November 2011 Pentr. Nos. System (Safety Priority) (33) Figure 6.2-19 Sheet No. Vlv Ltr Valve ID Number (* = Credited CIV) (51) ValveType (30) Oper-ator Type(31) Cntmt Locat.(32) Appli-cable GDC GDC Confor-mance PG&E Group(43) Control Room Indication Normal Position(35) Power Fail. Position Trip On (25) Used After LOCA (36) Post- LOCA Position(37) Fluid(23) Temp (24)
Notes - CS-9002B Chk - O 56 N/A No C - - Y C W Cold 26,39 - CS-RV-9007B Rlf - O 56 (11) No C - - N C W Cold 39 31 Containment 7 (II) E CS-9011A* Chk - I 56 Yes D No O - - Y O W Cold - Spray System F CS-9003A* Gte Mtr O 56 (11) D Yes C As is (7) Y C W Cold 11,26,49,40 (SA) G CS-9001A* Gte Mtr O 56 (11) D Yes C As is (13) Y C W Cold 11,13 H CS-31 Glb Man O 56 Yes No C - - N C W Cold 39
- CS-29,35 Glb Man O 56 Yes No C - - N C W Cold 26,39 - CS-9002A Chk - O 56 N/A No C - - Y C W Cold 26,39 - CS-RV-9007A Rlf - O 56 Yes No C - - N C W Cold 39 32 Spare -- - - - - - - - - - - - - - - - - 26 33 Safety Injection 8 (I) B SI-8835* Gte Mtr O 55 (11) D Yes O As is (7) Y C W Cold 7,11,26,40 System (SA) A SI-8819A,8819B,8819C, Chk - I 55 Yes No O - - Y O W Cold 26,39,40 8819D Chk - I 55 Yes No O - - Y O W Cold 26,39,40 G SI-8823 (U1) Glb Air I 55 Yes (22) C Closed - N C W Cold 22,26,39,41 - SI-96,97,165,167,168(U1); 294 (U2) Glb Man I 55 Yes - C - - N C W Cold 26,39,42 - SI-296(U1), 297(U1), 298(U1), 299(U1) Glb Man I 55 Yes - C - - N C W Cold 26,39,42 - SI-166,168(U2) Gte Man I 55 Yes - C - - N C W Cold 26,39,42 - 8822A,8822B,8822C,8822D, Glb Man I 55 Yes - C - - Y C W Cold 26,39,40 - 8826A,8826B,8827A,8827B Glb Man I 55 Yes - C - - N C W Cold 26,39,41 - 8828A,8828B,8829A,8829B Glb Man I 55 Yes - C - - N C W Cold 26,39,41 - SI-119 Glb Man O 55 Yes - C - - N C W Cold 26,39,42 - Closed SI System* Cls - O 55 (50) D - - - - Y - W Cold 46 8A (I) G SI-318 (U2) Glb Man I 55 Yes No C - - N C W Cold 26,39,41 34 Safety Injection 8 (II) C SI-8820 Chk - I 55 Yes No O - - Y O W Cold 26,39,40 System (SA) D SI-8801A*, 8801B* Gte Mtr O 55 (11) D Yes C As is R-M Y O W Cold 11,14,26,40 I SI-8969* Glb Man O 55 Yes No C - - N C W Cold 26,42 I SI-8874A, 8874B Glb Man O 55 Yes No C - - N C W Cold 26,39,41 - SI-179(U1),181(U1) Glb Man O 55 Yes No C - - N C W Cold 26,39,42 - Closed SI System* Cls - O 55 (50) D - - - - Y - W Cold 46 35 Regenerative 9 (I) A CVCS-8149A* Glb Air I 55 Yes A Yes O Closed T N C W Hot -
Heat Exchanger B CVCS-8149B* Glb Air I 55 Yes A Yes O Closed T N C W Hot - to Letdown Heat C CVCS-8149C* Glb Air I 55 Yes A Yes O Closed T N C W Hot - Exchanger (NE) G CVCS-RV-8117 Rlf Spr I 55 Yes No C Closed - N C W Hot 39 - CVCS-8,553,751(U2),752(U2) Glb Man I 55 Yes No C - - N C W Hot 26,39 D CVCS-8152* Glb Air O 55 Yes A Yes O Closed T N C W Hot - 36 Normal Charging 9 (II) E CVCS-8378C* Chk - I 55 Yes A No O - - N O W Cold 26,54 to Regenerative - CVCS-88,565 Glb Man I 55 Yes No C - - N C W Cold 26,39,42 Heat Exchanger F CVCS-8107* Gte Mtr O 55 Yes A Yes O As is S N O W Cold 26,54 (SA) (34) 37 Steam Generator 1 (III) J MS-FCV-151* Glb Air O 57 Yes C Yes O Closed T - C W Hot 26 Blowdown (NE) - MS-1055(U1),1056 Gte Man O 57 Yes No C - - N C W Hot 26,39 - MS-1055(U2) Glb Man O 57 Yes No C - - N C W Hot 26,39 I MS-FCV-760* Glb Air I 57 48 C Yes O Closed (4) N C W Hot 4,26,48 DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 9 of 20 Revision 20 November 2011 Pentr. Nos. System (Safety Priority) (33) Figure 6.2-19 Sheet No. Vlv Ltr Valve ID Number (* = Credited CIV) (51) ValveType (30) Oper-ator Type(31) Cntmt Locat.(32) Appli-cable GDC GDC Confor-mance PG&E Group(43) Control Room Indication Normal Position(35) Power Fail. Position Trip On (25) Used After LOCA (36) Post- LOCA Position(37) Fluid(23) Temp (24) Notes - MS-1054(U1) Gte Man I 57 Yes No C - - N C W Hot 26,39 - MS-1054(U2) Glb Man I 57 Yes No C - - N C W Hot 26,39
- SG Tubes* Cls - I 57 Yes C - - - - - - W Hot 2,44 38 Steam Generator 1 (III) J MS-FCV-154* Glb Air O 57 Yes C Yes O Closed T - C W Hot 26 Blowdown (NE) - MS-2055(U1), 2056 Gte Man O 57 Yes No C - - N C W Hot 26,39 - MS-2055(U2) Glb Man O 57 Yes No C - - N C W Hot 26,39 I MS-FCV-761* Glb Air I 57 48 C Yes O Closed (4) N C W Hot 4,26,48 - MS-2054(U1) Gte Man I 57 Yes No C - - N C W Hot 26,39 - SG Tubes* Cls - I 57 Yes C - - - - - - W Hot 2,44 39 Steam Generator 1 (III) J MS-FCV-157* Glb Air O 57 Yes C Yes O Closed T - C W Hot 26 Blowdown (NE) - MS-3055,3056 Gte Man O 57 Yes No C - - N C W Hot 26,39 I MS-FCV-762* Glb Air I 57 48 C Yes O Closed (4) N C W Hot 4,26,48 - MS-3054(U1) Gte Man I 57 Yes No C - - N C W Hot 26,39 - MS-3054(U2) Glb Man I 57 Yes No C - - N C W Hot 26,39 - SG Tubes* Cls - I 57 Yes C - - - - - - W Hot 2,44 40 Steam Generator 1 (III) J MS-FCV-160* Glb Air O 57 Yes C Yes O Closed T - C W Hot 26 Blowdown (NE) - MS-4055,4056 Gte Man O 57 Yes No C - - N C W Hot 26,39 I MS-FCV-763* Glb Air I 57 48 C Yes O Closed (4) N C W Hot 4,26,48 - MS-4054(U1) Gte Man I 57 Yes No C - - N C W Hot 26,39 - MS-4054(U2) Glb Man I 57 Yes No C - - N C W Hot 26,39 - SG Tubes* Cls - I 57 Yes C - - - - - - W Hot 2,44 41 Reactor Coolant 10 (I) A CVCS-8368A* Chk - I 55 Yes B No O - - Y O W Cold - Pump Seal Water - CVCS-277 Glb Man I 55 Yes No C - - N C W Cold 26,39 Supply (ES) - - Cls - O 55 Yes B - - - - Y - W Cold 10 42 Reactor Coolant 10 (I) A CVCS-8368B* Chk - I 55 Yes B No O - - Y O W Cold - Pump Seal Water - CVCS-607(U1),290 Glb Man I 55 Yes No C - - N C W Cold 26,39 Supply (ES) - - Cls - O 55 Yes B - - - - Y - W Cold 10 43 Reactor Coolant 10 (I) A CVCS-8368C* Chk - I 55 Yes B No O - - Y O W Cold - Pump Seal Water - CVCS-609(U1),301 Glb Man I 55 Yes No C - - N C W Cold 26,39 Supply (ES) - - Cls - O 55 Yes B - - - - Y - W Cold 10 44 Reactor Coolant 10 (I) A CVCS-8368D* Chk - I 55 Yes B No O - - Y O W Cold - Pump Seal Water - CVCS-306 Glb Man I 55 Yes No C - - N C W Cold 26,39 Supply (ES) - - Cls - O 55 Yes B - - - - Y - W Cold 10 45 Reactor Coolant 10 (II) B CVCS-8112* Gte Mtr I 55 Yes A Yes O As is T N C W Cold - Pump Seal Water C CVCS-8109* Chk - I 55 Yes A No O - - Y O W Cold -
Return (NE) CVCS-946 (Unit 2) Glb Man I 55 Yes A No C - - N C W Cold 39 D CVCS-8100* Gte Mtr O 55 Yes A Yes O As is T N C W Cold - - CVCS-315 Dia Man O 55 Yes No C - - N C W Cold 26,39 DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 10 of 20 Revision 20 November 2011 Pentr. Nos. System (Safety Priority) (33) Figure 6.2-19 Sheet No. Vlv Ltr Valve ID Number (* = Credited CIV) (51) ValveType (30) Oper-ator Type(31) Cntmt Locat.(32) Appli-cable GDC GDC Confor-mance PG&E Group(43) Control Room Indication Normal Position(35) Power Fail. Position Trip On (25) Used After LOCA (36) Post- LOCA Position(37) Fluid(23) Temp (24) Notes 46 Refueling Canal 3 (II) C LWS-8796* Dia Man I 56 Yes E No C - - N C W Cold - Recirculation - LWS-88 Dia Man I 56 Yes No C - - N C W Cold 26,39 (NE) D LWS-8787* Dia Man O 56 Yes E No C - - N C W Cold - 47 Refueling Canal 3 (IV) F LWS-8795* Dia Man I 56 Yes E No C - - N C W Cold - Return (NE) - LWS-90 Dia Man I 56 Yes No C - - N C W Cold 26,39 G LWS-8767* Dia Man O 56 Yes E No C - - N C W Cold - 48 Spare - - - - - - - - - - - - - - - - - 26 49 Containment 3 (I) A LWS-FCV-500* Bal Air I 56 Yes A Yes O Closed T N C W Cold - Sump Discharge B LWS-FCV-501* Bal Air O 56 Yes A Yes O Closed T N C W Cold -
(NE) 50 Reactor Coolant 12 (IV) G LWS-FCV-254* Bal Air O 56 Yes A Yes O Closed - N C W Hot -
Drain Tank H LWS-FCV-253* Bal Air I 56 Yes A Yes O Closed T N C W Hot - Discharge (NE) 51A Nitrogen Supply 8 (III) E SI-8880* Glb Air O 56 Yes A Yes O Closed T N C G Cold - Header to F SI-8916* Chk - I 56 Yes A No O - - N O G Cold - Accumulators - SI-153 Glb Man I 56 Yes No C - - N C G Cold 26,39 (NE) 51B Safety Injection 13 (I) A SI-8871* Glb Air I 55 Yes A Yes C Closed T N C W Cold - System B SI-8883* Glb Air O 55 Yes A Yes C Closed T N C W Cold - Test Line (NE) C SI-8961* Glb Air O 55 Yes A Yes C Closed T N C W Cold - D SI-161* Glb Man O 55 Yes E No C - - N C W Cold 49 E SI-8964 Glb Man O 55 Yes No C - - N C W Cold 26,39 13 (I) F SI-319 (U1) Glb Man O 55 Yes No O - - N O W Cold 13A (I) F SI-319 (U2) Glb Man O 55 Yes No O - - N O W Cold 51C Reactor Coolant 12 (II) C LWS-FCV-256* Bal Air O 56 Yes A Yes O Closed T N C G Cold - Drain Tank D LWS-FCV-255* Bal Air I 56 Yes A Yes O Closed T N C G Cold - Vent (NE) 51D Reactor Coolant 12 (III) E LWS-FCV-257* Bal Air O 56 Yes A Yes O Closed T N C W Cold - Drain Tank to Gas F LWS-FCV-258* Bal Air I 56 Yes A Yes O Closed T N C W Cold - Analyzer (NE) 52A Pressurizer Relief 14 (III) E RCS-8029* Bal Air O 55 Yes A Yes O Closed T N C W Cold - Tank Makeup - RCS-664(U1),680(U2) Dia Man O 55 Yes No C - - N C W Cold 26,39 (NE) F RCS-8046* Chk - I 55 Yes A No O - - N O W Cold - - RCS-528 Dia Man I 55 Yes No C - - N C W Cold 26,39 52B Pressurizer Relief 14 (II) C RCS-8047* Chk - I 55 Yes A No O - - N O G Cold - Tank Nitrogen - RCS-532 Dia Man I 55 Yes No C - - N C G Cold 26,39 DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 11 of 20 Revision 20 November 2011 Pentr. Nos. System (Safety Priority) (33) Figure 6.2-19 Sheet No. Vlv Ltr Valve ID Number (* = Credited CIV) (51) ValveType (30) Oper-ator Type(31) Cntmt Locat.(32) Appli-cable GDC GDC Confor-mance PG&E Group(43) Control Room Indication Normal Position(35) Power Fail. Position Trip On (25) Used After LOCA (36) Post- LOCA Position(37) Fluid(23) Temp (24) Notes Supply (NE) D RCS-8045* Dia Air O 55 Yes A Yes O Closed T N C G Cold - 52C Steam Generator 2 (II) F MS-902* Gte Man O 56 Yes E No C - - N C G Cold 26 Nitrogen Supply - MS-903 Gte Man O 56 Yes No C - - N C G Cold 26,39 (NE) G MS-5200* Chk - I 56 Yes E No O - - N O G Cold 26 52D Reactor Coolant 12 (I) A LWS-FCV-260* Bal Air O 56 Yes A Yes O Closed T N C G Cold - Drain Tank B LWS-60* Chk - I 56 Yes A No O - - N O G Cold - Nitrogen Supply - LWS-61 Dia Man I 56 Yes No C - - N C G Cold 26,39 (NE) 52E Containment H2 24 (I) A VAC-FCV-235* Glb Sol I 56 (28) E Yes C Closed (28) Y O G Cold 28,29 Monitor Supply B VAC-FCV-236* Glb Sol O 56 (28) E Yes C Closed (28) Y O G Cold 28 (NE) 52F Containment H2 24 (II) C VAC-FCV-237* Glb Sol O 56 (28) E Yes C Closed (28) Y O G Cold 28,29 Monitor Return D VAC-252* Chk - I 56 Yes E No O - - Y O G Cold - (NE) - VAC-109 Glb Man I 56 Yes No C - - N C G Cold 26,39 52G Containment 15 (I) A Sealed Bellows Sbl - I 56 Yes - - - - Y - G Cold 16 Pressure PT-937 - Capillary Fill Valve* Glb Man I 56 Yes E No C - - Y C G Cold 16,26 (SA) B Sealed Instrument Sin - O 56 Yes - - - - Y - G Cold 16 - Capillary Fill Valve* Glb Man O 56 Yes E No C - - Y C G Cold 16,26 52H Containment 15 (I) A Sealed Bellows Sbl - I 56 Yes - - - - Y - W Cold 16 Pressure PT-932 - Capillary Fill Valve* Glb Man I 56 Yes E No C - - Y C W Cold 16,26 (SA) B Sealed Instrument Sin - O 56 Yes - - - - Y - W Cold 16 (abandon in place) - Capillary Fill Valve* Glb Man O 56 Yes E No C - - Y C W Cold 16,26 53A Steam Generator 1 1 (IV) K MS-FCV-250* Glb Air O 57 Yes C Yes O Closed T N C W Hot 26 Blowdown - MS-1050 Glb Man O 57 Yes No O - - N O W Hot 26,39 Sample I MS-FCV-760 Glb Air I 57 Yes Yes - Closed (4) N C W Hot 2,26,39 (NE) - MS-1048(U2),1049 Glb Man I 57 Yes No O - - N O W Hot 26,39
- MS-1048(U1) Gte Man I 57 Yes No O - - N O W Hot 26,39 - SG Tubes* Cls - I 57 Yes C - - - - - - W Hot 2,44 53B Steam Generator 2 1 (IV) K MS-FCV-248* Glb Air O 57 Yes C Yes O Closed T N C W Hot 26 Blowdown - MS-2050 Glb Man O 57 Yes Yes O - - N O W Hot 26,39 Sample I MS-FCV-761 Glb Air I 57 Yes Yes O Closed (4) N C W Hot 2,26,39 (NE) - MS-2048(U2),2049 Glb Man I 57 Yes Yes O - - N O W Hot 26,39 - MS-2048(U1) Gte Man I 57 Yes Yes O - - N O W Hot 26,39 - SG Tubes* Cls - I 57 Yes C - - - - - - W Hot 2,44 53C Steam Generator 3 1 (IV) K MS-FCV-246* Glb Air O 57 Yes C Yes O Closed T N C W Hot 26 Blowdown - MS-3050 Glb Man O 57 Yes Yes O - - N O W Hot 26,39 Sample I MS-FCV-762 Glb Air I 57 Yes Yes O Closed (4) N C W Hot 2,26,39 (NE) - MS-3048(U2),3049 Glb Man I 57 Yes Yes O - - N O W Hot 26,39 - MS-3048(U1) Gte Man I 57 Yes Yes O - - N O W Hot 26,39 - SG Tubes* Cls - I 57 Yes C - - - - - - W Hot 2,44 DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 12 of 20 Revision 20 November 2011 Pentr. Nos. System (Safety Priority) (33) Figure 6.2-19 Sheet No. Vlv Ltr Valve ID Number (* = Credited CIV) (51) ValveType (30) Oper-ator Type(31) Cntmt Locat.(32) Appli-cable GDC GDC Confor-mance PG&E Group(43) Control Room Indication Normal Position(35) Power Fail. Position Trip On (25) Used After LOCA (36) Post- LOCA Position(37) Fluid(23) Temp (24)
Notes 53D Steam Generator 4 1 (IV) K MS-FCV-244* Glb Air O 57 Yes C Yes O Closed T N C W Hot 26 Blowdown - MS-4050 Glb Man O 57 Yes Yes O - - N O W Hot 26,39 Sample I MS-FCV-763 Glb Air I 57 Yes Yes O Closed (4) N C W Hot 2, 26,39 (NE) - MS-4048(U2),4049 Glb Man I 57 Yes Yes O - - N O W Hot 26,39 - MS-4048(U1) Gte Man I 57 Yes Yes O - - N O W Hot 26,39 - SG Tubes* Cls - I 57 Yes C - - - - - - W Hot 2,44 54 Instrument Air 16 (I) A AIR-I-587* Chk - I 56 Yes A No O - - N O G Cold - Header (NE) B FCV-584* Bal Air O 56 Yes A Yes O Closed T N C G Cold - E AIR-I-235 Dia Man O 56 Yes No C - - N C G Cold 26,39 E AIR-I-585* Dia Man O 56 Yes E No C - - N C G Cold 49 55 Spare - - - - - - - - - - - - - - - - - 26 56 Service Air 16 (II) C AIR-S-114* Chk - I 56 Yes E No O - - N O G Cold - Header (NE) D AIR-S-200* Bal Man O 56 Yes E No C - - N C G Cold - - AIR-S-111 (inline) Chk Man O 56 Yes No O - - N O G Cold 26,39 - AIR-S-112 Glb Man O 56 Yes No C - - N C G Cold 26,39 - AIR-S-113 Gte Man O 56 Yes No C - - N C G Cold 26,39 57 Containment 24 (III) E VAC-FCV-669* Gte Mtr O 56 (28) E Yes C As is (28) Y(38) C G Cold 28 External H2 F VAC-FCV-659* Gte Mtr I 56 (28) E Yes C As is (28) Y(38) C G Cold 28 Recombiners (SA) 58 Mini-Equipment Not a piping penetration Hatch (NE) 59A Pressurizer Liquid 17 (II) C NSS-9355A* Glb Air I 55 Yes A Yes O Closed T N C W Hot - Sample (NE) - NSS-259(U2),261(U1) Glb Man I 55 Yes No C - - N C W Hot 26,39 D NSS-9355B* Glb Air O 55 Yes A Yes O Closed T N C W Hot -
- NSS-260(U2),268(U1) Glb Man O 55 Yes No C - - N C W Hot 26,39 59B Hot Leg Sample 17 (III) E NSS-9356A* Glb N2 I 55 Yes A Yes O Closed T Y C W Hot - (NE) - NSS-261(U2),267(U1) Glb Man I 55 Yes No C - - N C W Hot 26,39 F NSS-9356B* Glb N2 O 55 Yes A Yes O Closed T Y C W Hot - - NSS-262 Glb Man O 55 Yes No C - - N C W Hot 26,39 59C Accumulator 17 (IV) G NSS-9357A* Glb Air I 55 Yes A Yes O Closed T N C W Cold - Sample (NE) - NSS-263 Glb Man I 55 Yes No C - - N C W Cold 26,39 H NSS-9357B* Glb Air O 55 Yes A Yes O Closed T N C W Cold - - NSS-264 Glb Man O 55 Yes No C - - N C W Cold 26,39 59D Containment 15 (I) A Sealed Instrument Sin - I 56 Yes - - - - Y - W Cold 16 Pressure - Capillary Fill Valve* Glb Man I 56 Yes E - - - - Y - W Cold 16,26 Transmitter PT-938 B Sealed Bellows Sbl - O 56 Yes - - - - Y - W Cold 16 (SA) - Capillary Fill Valve* Glb Man O 56 Yes E - - - - Y - W Cold 16,26 DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 13 of 20 Revision 20 November 2011 Pentr. Nos. System (Safety Priority) (33) Figure 6.2-19 Sheet No. Vlv Ltr Valve ID Number (* = Credited CIV) (51) ValveType (30) Oper-ator Type(31) Cntmt Locat.(32) Appli-cable GDC GDC Confor-mance PG&E Group(43) Control Room Indication Normal Position(35) Power Fail. Position Trip On (25) Used After LOCA (36) Post- LOCA Position(37) Fluid(23) Temp (24)
Notes 59E RV Level 25 (I) A Sealed Bellows Sbl - I 55 Yes - - - - Y - W Cold 16 Instrumentation - Capillary Fill Valve* Glb Man I 55 Yes E - - - - Y - W Cold 16,26 Transmitter B Hydraulic Isolators Hys - O 55 Yes - - - - Y - W Cold 16 LIS-1310 (SA) - Capillary Fill Valve* Glb Man O 55 Yes E - - - - Y - W Cold 16,26 59F RV Level 25 (I) A Sealed Bellows Sbl - I 55 Yes - - - - Y - W Cold 16 Instrumentation - Capillary Fill Valve* Glb Man I 55 Yes E - - - - Y - W Cold 16,26 Transmitter B Hydraulic Isolators Hys - O 55 Yes - - - - Y - W Cold 16 LIS-1311 (SA) - Capillary Fill Valve* Glb Man O 55 Yes E - - - - Y - W Cold 16,26 59G RV Level 25 (I) A Sealed Bellows Sbl - I 55 Yes - - - - Y - W Cold 16 Instrumentation - Capillary Fill Valve* Glb Man I 55 Yes E - - - - Y - W Cold 16,26 Transmitter B Hydraulic Isolators Hys - O 55 Yes - - - - Y - W Cold 16 LIS-1312 (SA) - Capillary Fill Valve* Glb Man O 55 Yes E - - - - Y - W Cold 16,26 59H Containment 15 (I) A Sealed Instrument Sin - I 56 Yes - - - - Y - W Cold 16 Pressure - Capillary Fill Valve* Glb Man I 56 Yes E - - - - Y - W Cold 16,26 Transmitters B Sealed Bellows Sbl - O 56 Yes - - - - Y - W Cold 16 PT-933 & PT-935 - PT-933 Cap Fill Valve* Glb Man O 56 Yes E - - - - Y - W Cold 16,26 (SA) - PT-935 Cap Fill Valve* Glb Man O 56 Yes E - - - - Y - W Cold 16,26 60 Mini-Equipment Not a piping penetration Hatch (NE) 61 Containment 18 (II) D VAC-FCV-660* But Air I 56 Yes A Yes O Closed (18) N C G Cold 18 Purge Supply E VAC-FCV-661* But Air O 56 Yes A Yes O Closed (18) N C G Cold 18 (NE) - VAC-80 Gte Man O 56 Yes No C - - N C G Cold 26,39 62 Containment 18 (III) F VAC-RCV-11* But Air I 56 Yes A Yes O Closed (18) N C G Cold 18 Purge Exhaust G VAC-RCV-12* But Air O 56 Yes A Yes O Closed (18) N C G Cold 18 (NE) - VAC-81 Gte Man O 56 Yes No C - - N C G Cold 26,39 63 Containment 18 (I) A VAC-FCV-662* But Air I 56 Yes A Yes O Closed (18) N C G Cold 18 Pressure and B VAC-FCV-663* But Air O 56 Yes A Yes O Closed (18) N C G Cold 18 Vacuum Relief C VAC-FCV-664* But Air O 56 Yes A Yes O Closed (18) N C G Cold 18 (NE) J Spectacle Flange Spf - O 56 Yes - N/A - - N/A N/A G Cold 26 - VAC-79(U1) Gte Man O 56 Yes No C - - N C G Cold 26,39 - VAC-79(U2) Glb Man O 56 Yes No C - - N C G Cold 26,39 64 Fuel Transfer 3 (III) E Blind Flange Blf - I - (19) - N/A - - N/A N/A - - 19,26 Tube (NE) Instrument Plug - - I - (19) - N/A - - N/A N/A - - 19,26 Not a piping penetration 65 Personnel Hatch (NE) Not a piping penetration 66 Emergency Not a piping penetration Personnel Hatch (NE) DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 14 of 20 Revision 20 November 2011 Pentr. Nos. System (Safety Priority) (33) Figure 6.2-19 Sheet No. Vlv Ltr Valve ID Number (* = Credited CIV) (51) ValveType (30) Oper-ator Type(31) Cntmt Locat.(32) Appli-cable GDC GDC Confor-mance PG&E Group(43) Control Room Indication Normal Position(35) Power Fail. Position Trip On (25) Used After LOCA (36) Post- LOCA Position(37) Fluid(23) Temp (24) Notes 67 Equipment Hatch Not a piping penetration (NE) 68 Containment Air 19 (II) C VAC-FCV-679* Bal Air O 56 Yes A Yes O Closed (18) N C G Cold 18 Sample (NE) - VAC-25 Dia Man O 56 Yes No C - - N C G Cold 26,39 D VAC-FCV-678* Bal Air I 56 Yes A Yes O Closed (18) N C G Cold 18 69 Containment Air 19 (I) A VAC-FCV-681* Bal Air O 56 Yes A Yes O Closed (18) Y C G Cold 18 Sample (NE) - VAC-26 Dia Man O 56 Yes No C - - N C G Cold 26,39 B VAC-21* Chk - I 56 Yes A No O - - Y O G Cold - 70 Auxiliary Steam 20 (I) A AXS-26* Gte Man O 56 Yes E No C - - N C G Hot - Supply (NE) B AXS-208* Chk - I 56 Yes E No O - - N O G Hot - - AXS-207 Gte Man I 56 Yes No C - - N C G Hot 26,39 71 Relief Valve 14 (IV) G RCS-8028* Chk - I 56 Yes E No O - - N O G Hot - (NE) Header - RCS-510,511 Glb Man I 56 No No C Closed - N C G Hot 26,39 H CVCS-RV-8125, Rlf - O 56 Yes No C Closed - N C G Hot 39 H SI-RV-8851,8853A,8853B, Rlf - O 56 Yes No C Closed - N C G Hot 39 H 8856A,8856B,8858 Rlf - O 56 Yes No C Closed - N C G Hot 39 H CS-RV-9007A,9007B Rlf - O 56 Yes No C Closed - N C G Hot 39 I RCS-512
- Glb Man O 56 No E No C - - N C G Hot - - CVCS-225(U1) Dia Man O 56 No No C Closed - N C G Hot 26,39 - CVCS-226(U1) Glb Man O 56 No No C Closed - N C G Hot 26,39 - CVCS-226(U2) Dia Man O 56 No No C Closed - N C G Hot 26,39 72 Spare - - - - - - - - - - - - - - - - - 26 73 Spare - - - - - - - - - - - - - - - - - 26 74 Spare - - - - - - - - - - - - - - - - - 26 75 Safety Injection 21 (I) A SI-8802B* Gte Mtr O 55 (11) D Yes C As is (7) Y O W Cold 7,11,26,40 Pump 2 - SI-35 Glb Man O 55 Yes No C - - N C W Cold 26,39,42 SI-115, 8890B Glb Man O 55 Yes - No C - - N C W Cold 26,39,41 Discharge B SI-8824 (U1) Glb Air I 55 Yes (22) C Closed - N C W Cold 22,26,39,41 (SA) C SI-8905C Chk - I 55 Yes No O - - Y O W Cold 26,39,40 D SI-8905D Chk - I 55 Yes No O - - Y O W Cold 26,39,40 - SI-8833A,8833B,8834A, 8834B Glb Man I 55 Yes No C - - N C W Cold 26,39,42 - 8904C,8904D Glb Man I 55 Yes No C - - Y C W Cold 26,39,40 - Closed SI System* Cls - O 55 50 D - - - - Y - W Cold 46 21A(1) B SI-315B (U2) Glb Man I 55 Yes No C - - N C W Cold 26,39,41 76A Pressurizer 17 (I) A NSS-9354A* Glb Air I 55 Yes A Yes O Closed T Y C G Hot - Steam - NSS-257(U2),270(U1) Glb Man I 55 Yes No C - - N C G Hot 26,39 Sample B NSS-9354B* Glb Air O 55 Yes A Yes O Closed T Y C G Hot -
(NE) - NSS-258(U2),269(U1) Glb Man O 55 Yes No C - - N C G Hot 26,39 76B Pressurizer 14 (I) A RCS-8034B* Glb Air O 55 Yes A Yes O Closed T N C G Cold -
DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 15 of 20 Revision 20 November 2011 Pentr. Nos. System (Safety Priority) (33) Figure 6.2-19 Sheet No. Vlv Ltr Valve ID Number (* = Credited CIV) (51) ValveType (30) Oper-ator Type(31) Cntmt Locat.(32) Appli-cable GDC GDC Confor-mance PG&E Group(43) Control Room Indication Normal Position(35) Power Fail. Position Trip On (25) Used After LOCA (36) Post- LOCA Position(37) Fluid(23) Temp (24) Notes Relief Tank Gas Analyzer B RCS-8034A* Glb Air I 55 Yes A Yes O Closed T N C G Cold - (NE) 76C Deadweight Tester 22 (I) A Sealed Bellows Sbl - I 55 Yes - - - - - - W Cold 16 (Abandoned in - 1(2)-07P-7E Glb Man I 55 Yes No C - - N C W Cold 16,26,39 place. Tester 1-07P-7F*,7G* Glb Man I 55 Yes E No C - - N C W Cold 16,26 removed.) (NE) B 1-07P-8085B* Glb Man O 55 Yes E No C - - N C W Cold 26 U2: 1/4" Instrument cap - - O 55 Yes - - - - - - - - - 16 76D Containment 15 (I) A Sealed Bellows Sbl - I 56 Yes - - - - Y - W Cold 16 Pressure - Capillary Fill Valve* Glb Man I 56 Yes E - - - - Y - W Cold 16,26 Transmitter B Sealed Instrument Sin - O 56 Yes - - - - Y - W Cold 16 PT-934 (SA) - Capillary Fill Valve* Glb Man O 56 Yes E - - - - Y - W Cold 16,26 76E Spare Connection 11 (III) - Unit-1: 3/8" Inst Cap - - I 56 Yes - - - - - - - - 26 - U1: 3/8" Inst Cap - - O 56 Yes - - - - - - - - 26 - U2: 1" Welded Pipe Cap - - - - - - - - - - - - - - 26 77 Safety Injection 21 (II) E SI-8802A* Gte Mtr O 55 (11) D Yes C As is (7) Y O W Cold 7,11,26,40 Pump 1 - SI-38 Glb Man O 55 Yes No C - - N C W Cold 26,39,42 SI-114, 8890A Glb Man O 55 Yes - No C - - N C W Cold 26,39,41 Discharge F SI-8905A Chk - I 55 Yes No O - - Y O W Cold 26,39,40 (SA) G SI-8905B Chk - I 55 Yes No O - - Y O W Cold 26,39,40
- SI-8831A,8831B,8832A, 8832B Glb Man I 55 Yes No C - - N C W Cold 26,39,42 - ,8904A,8904B Glb Man I 55 Yes No C - - Y C W Cold 26,39,40 - Closed SI System* Cls - O 55 50 D - - - - Y - W Cold 46 78A Containment H2 24 (I) A VAC-FCV-238* Glb Sol I 56 (28) E Yes C Closed (28) Y O G Cold 28,29 Monitor Supply (SA) B VAC-FCV-239* Glb Sol O 56 (28) E Yes C Closed (28) Y O G Cold - 78B Containment H2 24 (II) C VAC-FCV-240* Glb Sol O 56 (28) E Yes C Closed (28) Y O G Cold 28,29 Monitor Return D VAC-253* Chk - I 56 Yes E No O - - Y O G Cold - (SA) - VAC-108 Glb Man I 56 Yes No C - - N C G Cold 26,39 78C Containment 15 (I) A Sealed Bellows Sbl - I 56 Yes - - - - - - W Cold 16 Pressure - Capillary Fill Valve* Glb Man I 56 Yes E - - - - - - W Cold 16,26 Transmitter B Sealed Instrument Sin - O 56 Yes - - - - - - W Cold 16 PT-936 (SA) - Capillary Fill Valve* Glb Man O 56 Yes E - - - - - - W Cold 16,26 78D Spare 11 (III) - Unit-1: 3/8" Inst Plug - - I 56 Yes - - - - - - - - - 26 Connection 11 (III) - U1: 3/8" Inst Plug - - O 56 Yes - - - - - - - - - 26 - U2: 1" Welded Pipe Cap - - - - - - - - - - - - - - 26 78E Spare Connection - - 1" Welded Pipe Cap - - - - - - - - - - - - - - 26 DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 16 of 20 Revision 20 November 2011 Pentr. Nos. System (Safety Priority) (33) Figure 6.2-19 Sheet No. Vlv Ltr Valve ID Number (* = Credited CIV) (51) ValveType (30) Oper-ator Type(31) Cntmt Locat.(32) Appli-cable GDC GDC Confor-mance PG&E Group(43) Control Room Indication Normal Position(35) Power Fail. Position Trip On (25) Used After LOCA (36) Post- LOCA Position(37) Fluid(23) Temp (24)
Notes 78F Spare Connection - - 1" Welded Pipe Cap - - - - - - - - - - - - - - 26 78G Spare Connection - - 1" Welded Pipe Cap - - - - - - - - - - - - - - 26 78H Spare Connection - - 1" Welded Pipe Cap - - - - - - - - - - - - - - 26 79 Fire Water (NE) 23 (I) A FP-FCV-633* Glb Air O 56 Yes A Yes O Closed T N C W Cold - - FP-179(U1),866(U2) Gte Man O 56 Yes No C - - N C W Cold 26,39 B FP-180(U1)*,FP-867(U2)* Chk - I 56 Yes A No O - - N O W Cold - - FP-308(U1),868(U2) Gte Man I 56 Yes No C - - N C W Cold 26,39 80A Spare Instrument 11 (II) - Instrument Plug* - - I 56 Yes E No - - - N - G Cold 26 (U1) Test Line (Unit-1) - VAC-301* Glb Man O 56 Yes E No C - - N C G Cold 26 80A Spare Instrument 11 (IV) - VAC-303* Glb Man I 56 Yes E No C - - N C G Cold 26 (U2) Test Line (Unit-2) - VAC-301* Glb Man O 56 Yes E No C - - N C G Cold 26 80B Spare Instrument 11 (II) - Instrument Plug* - - I 56 Yes E No - - - N - G Cold 26 (U1) Test Line (Unit-1) - VAC-302* Glb Man O 56 Yes E No C - - N C G Cold 26 80B Spare Instrument 11 (IV) - VAC-304* Glb Man I 56 Yes E No C - - N - G Cold 26 (U2) Test Line (Unit-2) - VAC-302* Glb Man O 56 Yes E No C - - N C G Cold 26 80C Spare Instrument 11 (III) - Instrument Plug* - - I 56 Yes E No - - - N C G - 26 Test Line - Instrument Plug* - - O 56 Yes E No - - - N C G - 26 80D Containment 15 (I) A Sealed Bellows Sbl - I 56 Yes - - - - - - W Cold 16 Pressure - Capillary Fill Valve* Glb Man I 56 Yes E - - - - - - W Cold 16,26 Transmitter B Sealed Instrument Sin - O 56 Yes - - - - - - W Cold 16 PT-939 (SA) - Capillary Fill Valve* Glb Man O 56 Yes E - - - - - - W Cold 16,26 80E RV Level 25 (I) A Sealed Bellows Sbl - I 55 Yes - - - - Y - W Cold 16 Instrumentation - Capillary Fill Valve* Glb Man I 55 Yes E - - - - Y - W Cold 16,26 Transmitter B Hydraulic Isolators Hys - O 55 Yes - - - - Y - W Cold 16 LIS-1320 (SA) - Capillary Fill Valve* Glb Man O 55 Yes E - - - - Y - W Cold 16,26 80F RV Level 25 (I) A Sealed Bellows Sbl - I 55 Yes - - - - Y - W Cold 16 Instrumentation - Capillary Fill Valve* Glb Man I 55 Yes E - - - - Y - W Cold 16,26 Transmitter B Hydraulic Isolators Hys - O 55 Yes - - - - Y - W Cold 16 LIS-1321 (SA) - Capillary Fill Valve* Glb Man O 55 Yes E - - - - Y - W Cold 16,26 80G RV Level 25 (I) A Sealed Bellows Sbl - I 55 Yes - - - - Y - W Cold 16 DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 17 of 20 Revision 20 November 2011 Pentr. Nos. System (Safety Priority) (33) Figure 6.2-19 Sheet No. Vlv Ltr Valve ID Number (* = Credited CIV) (51) ValveType (30) Oper-ator Type(31) Cntmt Locat.(32) Appli-cable GDC GDC Confor-mance PG&E Group(43) Control Room Indication Normal Position(35) Power Fail. Position Trip On (25) Used After LOCA (36) Post- LOCA Position(37) Fluid(23) Temp (24) Notes Instrumentation - Capillary Fill Valve* Glb Man I 55 Yes E - - - - Y - W Cold 16,26 Transmitter B Hydraulic Isolators Hys - O 55 Yes - - - - Y - W Cold 16 LIS-1322 (SA) - Capillary Fill Valve* Glb Man O 55 Yes E - - - - Y - W Cold 16,26 81 Containment 24 (III) E VAC-FCV-668* Gte Mtr O 56 (28) E Yes C As is (28) Y(38) C G Cold 28 External H2 F VAC-FCV-658* Gte Mtr I 56 (28) E Yes C As is (28) Y(38) C G Cold 28 Recombiners (SA) 82A Post-LOCA 25 (IV) G LWS-FCV-697* Glb Sol O 56 (28) A Yes C Closed (28) Y C W Cold 28,29 Sampling System H LWS-FCV-696* Glb Sol I 56 (28) A Yes C Closed (28) Y C W Cold - Reactor Cavity Sump (NE) 82B Post-LOCA 25 (II) C VAC-FCV-698* Glb Sol I 56 (28) A Yes C Closed (28) Y C G Cold 28,29 Sampling System - VAC-118 Glb Man I 56 - No C - - N C G Cold 26,39 Containment Air D VAC-FCV-699* Glb Sol O 56 (28) A Yes C Closed (28) Y C G Cold 28,29 Supply (NE) 82C Post-LOCA 25 (III) E VAC-FCV-700* Glb Sol O 56 (28) A Yes C Closed (28) Y C G Cold 28,29 Sampling System F VAC-116* Chk - I 56 Yes A No O - - Y O G Cold 29 Containment Air - VAC-115 Glb Man I 56 Yes No C - - N C G Cold 26,39 Return (NE) 82D Spare Piping 11 (II) Blind Flange* - I 56 Yes A No C - - N C G Cold 26 (U1) Connection - Blind Flange - - O 56 Yes No C - - N C G Cold 26 VAC-1-680* Gte O 56 Yes A No C - - N C G Cold 26 82D Chilled Water 7 (III) 52 (U2) Supply (NE) 52 82E Spare Instrument 11 (III) - Instrument Plug* - - I 56 Yes E No - - - - - G Cold 26 Test Line - Instrument Plug* - - O 56 Yes E No - - - - - G Cold 26 83A Spare Piping 11 (II) Blind Flange* - - I 56 Yes A No C - - N C G Cold 26 (U1) Connection - Blind Flange - - O 56 Yes No C - - N C G Cold 26 VAC-1-681* Gte Man O 56 Yes A No C - - N C G Cold 26 83A Chilled Water 7 (IV) 52 (U2) Return (NE) 52 83B Hydrogen Purge 11 (I) A VAC-200*,201* Chk - I 56 Yes E No O - - Y(38) O G Cold - Supply (NE) B VAC-1*,2* Gte Man O 56 Yes E No C - - Y(38) C G Cold - - VAC-195 Glb Man O 56 Yes No C - - N C G Cold 26,39 84 Spare - - - - - - - - - - - - - - - - - 26 DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 18 of 20 Revision 20 November 2011 Pentr. Nos. System (Safety Priority) (33) Figure 6.2-19 Sheet No. Vlv Ltr Valve ID Number (* = Credited CIV) (51) ValveType (30) Oper-ator Type(31) Cntmt Locat.(32) Appli-cable GDC GDC Confor-mance PG&E Group(43) Control Room Indication Normal Position(35) Power Fail. Position Trip On (25) Used After LOCA (36) Post- LOCA Position(37) Fluid(23) Temp (24) Notes (a) Arabic numbers in parentheses indicate notes at the end of the table. Notes: 1. Trip on feedwater isolation. (See Table 6.2-40, Item 4.) 2. Steam generator secondary side is missile-protected closed system. 3. Reverse check (main steam isolation). 4. Trip on steam line isolation. (See Table 6.2-40, Item 3.) 5. Safety-related function. Valve trip is related to systems safety function. 6. Deleted in Revision 17 7. Safety-related function demands that this valve not automatically isolate.
- 8. Valve does not meet 1971 GDC but does meet the 1968 GDC which was applicable at time of construction commitment. 9. This valve is not considered as the automatic isolation barrier. The barrier is provided by the closed system. The valve does have provision for remote manual isolation should the situation require it. 10. PG&E considers the closed system outside containment as an automatic isolation barrier. This is allowed per ANS 56.2 1984 paragraph 3.6.7 11. Provision for remote manual isolation exists should the situation require it. Safety-related function demands that this valve not isolate. It conforms with the intent of the GDC as it affects maintenance of the containment boundary. 12. The protective chamber is considered outside containment. The motor-operated valves are the isolation valves outside containment. 13. Valve opens on containment spray signal. 14. Valve opens on SIS signal.
- 15. Deleted in Revision 17
- 16. Containment isolation effected by completely sealed instrument system. This penetration is not leak tested. 17. Multiple penetration number usage results from several small pipes routed through single penetrations (no longer used in this table). 18. Containment vent isolation trip. (See Table 6.2-40.)
- 19. The fuel transfer tube is not considered to be a piping penetration, but rather a Type B test penetration. The quick-opening hatch is double gasketed with a test connection allowing pressurization between the gaskets for Type B testing. The portion of the transfer tube inside the containment is considered to be part of the containment liner; the portion of the transfer tube outside the containment is not considered to be part of the containment boundary. 20. Deleted in Revision 17 21. Deleted. 22. Administratively controlled valve which is treated in the same manner as a sealed closed valve. Control room indication is only active when the valve is not administratively cleared.
DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 19 of 20 Revision 20 November 2011 23. W = Water; G = Gas 24. Hot - over 200ºF; Cold - 200ºF or less 25. R-M = Remote Manual; S = Safety Injection; T = Containment Isolation Signal, Phase A; P = Containment Isolation Signal, Phase B. 26. Testability not required by Appendix J to 10 CFR 50. 27. Deleted in Revision 17. 28. This device is used for post accident monitoring or control and must not be isolated by a containment isolation signal. 29. This penetration has multiple tubes running though the guard pipe (see Note 17). 30. The following abbreviations are used: Gte = Gate Cls = Closed system Sbl = Sealed bellows Spf = Spectacle flange Glb = Globe Chk = Check Blf = Blind flange Rlf = Relief Dia = Diaphragm Sin = Sealed instruments But = Butterfly Bal = Ball Hys = Hydraulic isolators 31. The following abbreviations are used: Man = Manual Mtr = Motor Air = Air E/H = Electrohydraulic Spr = Spring Sol = Solenoid 32. "I" is used for inside and "O" for outside. 33. Safety-related priority designation for each penetration per Section 6.2.4.2.1 is as follows: ES = Essential SA = Safety NE = Nonessential 34. Penetration 36 is not used by a safety system for accident mitigation. However, flow through this Penetration may be required to achieve safe shutdown following a Hosgri earthquake or an Appendix R fire. 35. "Normal Position" column: (A) C = Closed, O = Open (B) For check valves, position is always stated as open. (C) "Normal" configuration applies to the following plant conditions:
(a) Modes 1-4, applicable T.S. 3/4.6.1 and 3/4.6.3. (b) Mode 6, applicable T.S. 3/4.9.4. (D) If valve is normally open or periodically opened for fulfillment of its function during the "Normal" plant configurations, then an "Open" designator is used. (E) If valve is normally closed and opened only in support of testing, under administrative control per T.S. 3.6.3, or for stroke testing of the valve itself, then a "Closed" designator is used. (F) Relief valves are assigned a "Closed" designator. 36. "Used After LOCA" column: (A) N = No, Y = Yes (B) For check valves, if valve passes flow at any point following the accident, then a "Yes" designator is used. (C) For valves that change position on a safeguards signal, this change is not considered a use, that is, the time the safeguards signal is received is not considered after the accident. (D) Use is principally an indicator of a valve passing flow at any point after the accident. 37. "Post-LOCA Position" column: (A) C = Closed, O = Open (B) The column pertains to a post accident condition, long term core cooling. (C) The assumed accident is a primary system LOCA with Containment isolation Phase A and B signals generated, system depressurization below 150 PSIG, corresponding to a RHR pump injection flow of greater than 200 GPM. The accident is assumed to progress through injection, cold leg recirculation, and to hot leg recirculation for the long term. (D) The hot leg injection flowpath is injection to RHR hot legs 1 & 2, SI pump hot legs 1,2,3, & 4, and Charging cold legs 1,2,3, & 4; the condition established by EOP E-1.4, (no RNOs entered). (E) Containment temperature has been reduced to near ambient conditions. (F) Containment pressure has been reduced to near atmospheric conditions.
DCPP Units 1 & 2 FSAR UPDATE TABLE 6.2-39 Sheet 20 of 20 Revision 20 November 2011 (G) Primary system/containment recirculation sump temperature has been reduced to below 200°F. (H) Although used periodically, PASS valves are considered to be normally closed. 38. Valve may be used following a LOCA only in the event of a failure of both internal hydrogen recombiners. 39. Valve is not an Appendix J tested containment isolation valve. Valve is listed because it defines the containment penetration boundary. Valve does not affect containment isolation function. It is relied upon only to maintain system pressure boundary integrity. 40. Valve is not subject to Type C leakage tests because it is required to be in service post accident and the line pressure upstream of the CIV is greater than the post-accident pressure inside containment. The closed system outside containment is the credited containment isolation barrier as allowed per ANS 56.2 1984 paragraph 3.6.7. 41. Valve is not tested because this valve is a containment boundary valve and the line pressure upstream of the CIV is greater than the post-accident pressure inside containment. The closed system outside containment is the credited isolation barrier as allowed per ANS 56.2 1984 paragraph 3.6.7. 42. Valve is not tested because it is exempt per ANS 56.8 section 3.3.1. The closed system outside containment is credited as the outside isolation barrier as allowed per ANS 56.2 1984 paragraph 3.6.7. 43. PG&E group is included for credited CIVs only.
- 44. This penetration is on the secondary side. The steam generator tubes provide passive containment isolation. Secondary side leakage is tracked separately and evaluated for impact on the SGTR analysis in accordance with 10CFR100. 45. This penetration does not require testing per Appendix J section II.H because the penetration does not provide a direct connection to the atmosphere during normal operation, is not required to close automatically, and is not required to operate intermittently. This penetration is filled with water from the submerged sump preventing gas escape to the outside and meets the test exception per Appendix J section II.c.3 as described in ANS 56.2-1984 appendix B3.1. 46. This system meets the requirements of a closed system outside of containment, outboard of the designated CIVs. The piping located between the CIVs and the containment structure is qualified per SRP 6.2.4 to serve as the barrier. The closed system is the second barrier for containment isolation. This is allowed per ANS 56.2 1984 paragraph 3.6.7. 47. The Containment Fan Coolers are a closed system inside containment. CCW does not communicate directly with the containment atmosphere. 48. Valve is included as a credited CIV because it was included on the original Tech Specs for the plant license. However, PG&E piping group C does not require that there be an inside CIV because there is an additional barrier to the RCS or containment atmosphere. The barrier on this penetration is the steam generator tubes. 49. Although PG&E Groups D & E do not require this valve to be a CIV, it is included as a credited CIV because it was included in the original Tech Specs for the plant license. The inside barrier is a valve. 50. This penetration meets GDC 55/56 on other defined basis with a single valve and a closed system. This is allowed by Reg. Guide 1.141 and ANSI N271-1976.
- 51. For valves not marked with an asterisk (*), these are Containment Boundary Valves. They are relied upon to maintain containment penetration pressure boundary integrity and are controlled per TS 3.6.3. 52. This penetration is abandoned in place through the installation of welded plugs in the penetration. Reference DCP M-50715. 53. This penetration does not require testing per Appendix J section II.H because the penetration does not provide a direct connection to the atmosphere during normal operation, is not required to close automatically, and is not required to operate intermittently. This penetration is filled with water from the submerged sump preventing gas escape to the outside and meets the test exception per Appendix J section II.c.3 as described in ANS 56.2-1984 appendix B3.2. 54. Valve is not subject to Type C leakage tests because the line pressure upstream of the CIV is greater than the post-accident pressure inside containment. The CVCS system is a closed system outside containment which prevents potential primary containment atmospheric pathways during and following a design basis accident as allowed by ANS 56.8 section 3.3.1.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2-40 Sheet 1 of 2 Revision 15 September 2003 OPERATING CONDITIONS FOR CONTAINMENT ISOLATION Item No. Functional Unit Operating Conditions 1 Containment isolation Phase A a. High containment pressure
- b. Pressurizer low pressure
- c. Low steamline pressure
- d. Manual
2 Containment isolation Phase B a. High-high containment pressure
- b. Manual
3 Steam line isolation a. Low steamline pressure
- b. High steamline pressure rate
- c. High-high containment pressure
- d. No manual MSI and manual Ph. B does not give MSI. 4 Feedwater line isolation a. High containment pressure
- b. Low steamline pressure
- c. Pressurizer low pressure
- d. Steam generator high-high level
- e. Manual SIS
- f. Reactor trip with low Tavg.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2-40 Sheet 2 of 2 Revision 15 September 2003 Item No. Functional Unit Operating Conditions 5 Containment ventilation isolation a. Containment exhaust high radioactivity
- b. Safety injection activation
- c. Manual Phase A or Manual Phase B
DCPP UNITS 1 & 2 FSAR UPDATE Revision 14 November 2001 TABLE 6.2-41 POST-LOCA TEMPERATURE TRANSIENT USED FOR ALUMINUM AND ZINC CORROSION Time Interval, sec Temperature, °F 0 - 10 240 10 - 30 265 30 - 750 258 750 - 2000 253 2000 - 10,000 250 10,000 - 20,000 245 20,000 - 50,000 240 50,000 - 75,000 230 75,000 - 100,000 220 100,000 - 200,000 210 200,000 - 400,000 198 400,000 - 600,000 185 600,000 - 800,000 175 800,000 - 1,200,000 160 1,200,000 - 2,000,000 153 2,000,000 - 3,000,000 145 3,000,000 - 5,000,000 138 5,000,000 - 8,640,000 129
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2-42 Sheet 1 of 2 Revision 14 November 2001 PARAMETERS USED TO DETERMINE HYDROGEN GENERATION Plant Thermal Power Rating 3,425 MWt Containment Temperature Prior to Accident 120°F Containment Free Volume 2,550,000 ft3 Weight Zirconium Cladding 43,300 lb
Hydrogen Recombiner Flowrate 100 scfm Corrodible Metals Aluminum and zinc
Core Cooling Solution Radiolysis Sources Percent of total halogens retained in the core 50.00 Percent of total noble gases retained in the core 0.00 Percent of other fission products retained in the core 99.00 Energy Distribution Percent of total decay energy - gamma 50.00 Percent of total decay energy - beta 50.00 Energy Absorption by Core Cooling Solution Percent of gamma energy absorbed by solution 10.00 Percent of beta energy absorbed by solution 0.00 Hydrogen Production Molecules H2 produced per 100 eV energy absorbed by solution 0.50 Sump Solution Radiolysis Sources Percent of total halogens released to sump solution 50.00 Percent of noble gases released to sump solution 0.00 Percent of other fission products released to sump solution 1.00
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2-42 Sheet 2 of 2 Revision 14 November 2001 Energy Absorption by Sump Solution Percent of total energy (beta and gamma) which is absorbed by the sump solution 100.00 Hydrogen Production Molecules of hydrogen produced per 1000 eV of energy absorbed by the sump solution 0.50 Long-term Aluminum Corrosion Rate 200 mils/year
Aluminum Inventory in Containment 3585 lb (amount used in analyses) 15,988 ft2 Zinc Inventory in Containment (amount used in analysis) 58,449 lb 397,000 ft2
DCPP UNITS 1 & 2 FSAR UPDATE Revision 14 November 2001 TABLE 6.2-43 CORE FISSION PRODUCT ENERGY AFTER OPERATION WITH EXTENDED FUEL CYCLES Core Fission Product Energy(a) Time After Reactor Trip, days Energy Release Rate, watts/MWt x 10-3 Integrated Energy Release,watts days/MWt x 10-4 1 5.11 0.696 5 3.41 2.28 10 2.72 3.80 20 2.00 6.11 30 1.66 7.92 40 1.47 9.48 50 1.33 10.9 60 1.21 12.2 70 1.12 13.3 80 1.02 14.4 90 0.943 15.4 100 0.868 16.2
(a) Assumes 50% core halogens +99% other fission products and no noble gases. Values are for total ( and ) energy. DCPP UNITS 1 & 2 FSAR UPDATE Revision 14 November 2001 TABLE 6.2-44 FISSION PRODUCT DECAY DEPOSITION IN SUMP SOLUTION Sump Fission Product Energy(a) Energy Integrated Time After Release Energy Reactor Trip, Rate, Release, days watts/MWt x 10-1 watt-days/MWt x 10-3 1 25.6 0.535 5 8.17 1.02 10 5.35 1.35 15 3.81 1.57 20 2.91 1.75 30 2.06 1.99 40 1.69 2.18 60 1.30 2.47 80 1.04 2.70 100 0.837 2.88 (a) Considers release of 50 percent of core halogens, no noble gases, and 1 percent of other fission products to the sump solution.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 14 November 2001 TABLE 6.2-45 SUMMARY OF HYDROGEN ACCUMULATION DATA (with no recombination) Time of Total Production Volume Percent Occurrence, Rate, Hydrogen days scfm 2.09 1 10.9 2.65 2 8.18 3.09 3 6.45 3.48 4 6.23 3.83 5 5.03 4.13 6 4.90 5.10 10 3.19 5.96 15 2.62 6.67 20 2.42 9.76 50 1.66 11.54 75 1.22 12.95 100 1.11
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2-47 Page 1 of 2 Revision 11 November 1996 CONTAINMENT REFLECTIVE INSULATION(a) Line No. Size, in. Length, ft. Line Designation 1 29 19 Reactor Coolant Out Loop 1 2 29 19 Reactor Coolant Out Loop 2 3 29 19 Reactor Coolant Out Loop 3 4 29 19 Reactor Coolant Out Loop 4 5 31 22 Reactor Coolant PP Suction Loop 1 6 31 22 Reactor Coolant PP Suction Loop 2 7 31 13 Reactor Coolant PP Suction Loop 3 8 1 3 Reactor Coolant PP Suction Loop 4 9 27-1/2 21 Reactor Coolant PP Discharge Loop 1 10 27-1/2 4 Reactor Coolant PP Discharge Loop 2 11 27-1/2 23 Reactor Coolant PP Discharge Loop 3 12 27-1/2 23 Reactor Coolant PP Discharge Loop 4 13 4 111 Loop 1 spray line 14 4 84 Loop 2 spray line 15 4 96 Pressurizer spray line 16 14 65 Pressurizer surge line 24 3 38 Letdown Line Loop 2 50 3 9 Charging Line Loop 3 109 14 45 Hot Leg Recirc. Before V-8702 235 6 13 Safety Injection Loop 1 Hot Leg 236 6 10 Safety Injection Loop 2 Hot Leg 237 6 8 Safety Injection Loop 3 Hot Leg 238 6 11 Safety Injection Loop 4 Hot Leg 246 3 6 Charging Line Loop 4 253 10 41 Accumulator Injection Loop 1 254 10 35 Accumulator Injection Loop 2 255 10 14 Accumulator Injection Loop 3 256 10 30 Accumulator Injection Loop 4 958 2 4 Loop 1 cold leg drain RCDT 959 2 6 Loop 2 cold leg drain RCDT 960 2 2 Loop 3 cold leg drain RCDT 961 2 3 Loop 4 cold leg drain RCDT 1665 14 21 Loop 4 hot leg before V 8701 1992 1-1/2 3 Boron Inj Tk. Out Loop 2 cold 1993 1-1/2 3 Boron Inj Tk. Out Loop 3 cold DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2-47 Page 2 of 2 Revision 11 November 1996 Line No. Size, in. Length, ft. Line Designation 3844 6 35 RHR PP 1-1 Inj Cold Leg 1 3845 6 48 RHR PP 1-1 Inj Cold Leg 2 3846 6 48 RHR PP 1-1 Inj Cold Leg 3 3847 6 48 RHR PP 1-1 Inj Cold Leg 4 3855 2 4 SI PPS Cold Leg Loop 1 recirc.
(a) The information contained in this table is "representative" of Units 1 and 2. Data reflecting actual conditions for any individual line may be somewhat different than that presented, or may change with plant modifications. This table will not be revised to reflect these individual conditions or changes.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2-48 Sheet 1 of 2 Revision 19 May 2010 CONTAINMENT CONVENTIONAL INSULATION Line No. Insul. Size, in. Length, ft. Line Designation 23 IV 12 45 Pressurizer relief header 50 IV 3 64 Charging Line Loop 3 51 IV 2 77 Charging line auxiliary spray 63 V 1 218 Excess Letdown Loop 2 214 V 3/4 3 Loop 1 hot leg sample 215 V 3/4 1 Loop 4 hot leg sample 225 V 28 94 Steam Gen. 1-4 steam outlet 226 V 28 96 Steam Gen. 1-3 steam outlet 227 V 28 96 Steam Gen. 1-2 steam outlet 228 V 28 94 Steam Gen. 1-1 steam outlet 246 IV 3 115 Charging Line Loop 4 508 III 8 226 RHR PP 1-1 Inj Cold Leg 1 + 2 509 III 8 77 RHR PP 1-1 Inj Cold Leg 3 + 4 528 III 2-1/2 123 Reactor coolant drain tk. PP disch. 554 IV 16 54 Steam Gen. 1 feedwater supply 555 IV 16 57 Steam Gen. 2 feedwater supply 556 IV 16 53 Steam Gen. 4 feedwater supply 557 IV 16 54 Steam Gen. 3 feedwater supply 692 III 3/4 4 Cold Leg Loop 3 + 4 test line 927 III 14 33 Loop 4 hot leg to RHR PPS 1012 V 2 3 Steam Gen. 1 blowdown out N/S 1017 2 3 Steam Gen. 2 blowdown out N/S 1020 V 2 14 Steam Gen. 3 blowdown out N/S 1038 V 2 8 Steam Gen. 4 blowdown out N/S 1040 V 2-1/2 235 Steam Gen. 1-1 blowdown tank hdr. 1041 V 2-1/2 189 Steam Gen. 1-2 blowdown tank hdr. 1042 V 2-1/2 85 Steam Gen. 1-3 blowdown tank hdr. 1043 V 2-1/2 116 Steam Gen. 1-4 blowdown tank hdr. 1059 V 2 32 Steam Gen. 1 blowdown out S/N 1060 V 2 17 Steam Gen. 2 blowdown out S/N 1061 IV 2 3 Steam Gen. 3 blowdown out S/N 1062 V 2 15 Steam Gen. 4 blowdown out S/N 1167 III 4 51 RHR hot leg RV outlet 1169 V 3/4 7 Loop 1 spray line bypass 1170 V 3/4 7 Loop 2 spray line bypass 1675 V 3/8 51 Loop 1 hot leg sample 1676 V 3/8 6 Loop 4 hot leg sample
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2-48 Sheet 2 of 2 Revision 19 May 2010 Line No. Insul. Size, in. Length, ft. Line Designation 1901 III 1 8 Loop 2 V8076 + V8074B Lkoff. H 1999 III 3/4 10 SIS Accum. 1 test 2000 III 3/4 13 SIS Accum. 2 test 2001 III 3/4 60 SIS Accum. 3 test 2002 III 3/4 28 SIS Accum. 4 test 2158 IV 3/4 12 Regen. hx. channel temp. relief 2176 III 1 35 Leakoff header line to PRT 2385 III 4 202 SIS RV outlet header to PRT 2523 III 1/2 4 RHR Suction Vlv. 2 Loop 4 leakoff 2524 III 1/2 18 RHR Suction Vlv. 1 Loop 4 leakoff 2638 III 1 57 Cont. aux. steam supply to el. 91 2766 III 1/2 2 PCV-455 A leakoff line 2773 III 1/2 4 PCV-455 B leakoff line 2998 III 4 4 SIS RV outlet header to PRT 2999 III 4 5 SIS RV outlet header to PRT 3094 V 3/4 5 RHR Loop 4 V-8702 8702 therm 3095 III 3/4 5 RHR Loop 4 V-8701 8702 therm 3214 I 2 73 Incore chiller chill wtr. sup. 3215 I 2 73 Incore chiller chill wtr. ret. 3407 III 1/2 6 Loop 2 Letdown V-8076 leakoff 3729 III 2-1/2 14 REAC Clnt. Dr. PPS Disch. Header 3844 II 6 70 RHR PP 1-1 inj cold leg 1 3845 II 6 59 RHR PP 1-1 inj cold leg 2 3900 III 1 174 Reactor head aux. steam 3936 I 2 2 Incore chiller chill wtr. ret. 4399 III 1/2 1 4400 III 1/2 7 4402 III 1/2 5 4406 III 1 4 4407 III 1 2 (a) This line is contained completely within the hot leg insulation. (b) The information contained in this table is "representative" of Units 1 and 2. Data reflecting actual conditions for any individual line may be somewhat different than that presented, or may change with plant modifications. This table will not be revised to reflect these individual conditions or changes. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 6.2-55 MAXIMUM PRESSURE DIFFERENTIAL ACROSS STEAM GENERATOR Break Maximum Pressure Between Type Location Differential, psi Compartments Compressibility DEHL 1 5.50 @ .0185 sec 1-2 yes DEHL 2 5.26 @ .0144 sec 2-1 yes DEHL 3 6.04 @ .0184 sec 3-2 yes DEHL 4 5.98 @ .0184 sec 4-5 yes DEHL 5 5.26 @ .0144 sec 5-6 yes DEHL 6 5.45 @ .0185 sec 6-5 yes DEHL 3 6.00 @ .0184 sec 3-2 no DEHL 3 4.46 @ .0215 sec 3-2 no (worst case) DECL 3 4.48 @ .0215 sec 3-2 yes (worst case)
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-1 Sheet 1 of 3 Revision 18 October 2008 EMERGENCY CORE COOLING SYSTEM COMPONENT PARAMETERS Accumulators Number (per unit) 4 Design Pressure, psig 700 Design Temperature, °F 300 Operating Temperature, °F 50-150 Normal Operating Pressure, psig 621.5 Minimum Operating Pressure, psig (c) 579 Total Volume, ft3 1,350 each Nominal Water Volume, ft 850 Boric Acid Concentration Nominal, ppm 2,350 Minimum, ppm 2,200 Relief Valve Setpoint, psig 700 Centrifugal Charging Pumps (CCP1 and 2) (Design parameters for these pumps are given in Section 9.3.4.) Safety Injection Pumps Number (per unit) 2 Design Pressure, psig 1,700 Design Temperature, °F 300 Design Flowrate, gpm 425 Design Head, ft 2,500 Max Flowrate, gpm 675 Head at Max Flowrate, ft 1,500 Discharge Pressure at Shutoff Head, psig 1,520 Motor Rating, hp(a) 400 Residual Heat Removal Pumps (Design parameters for these pumps are given in Section 5.5.6) DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-1 Sheet 2 of 3 Revision 18 October 2008 Residual Heat Exchangers (Design parameters for these heat exchangers are given in Section 5.5.6) Refueling Water Storage Tank Number (per unit) 1 Total available tank volume (includes only usable volume)(b), gal 450,000 Minimum Technical Specifications required volume (includes usable and unusable volume), gal 455,300 Accident analysis volume (assumed) 350,000 Boron Concentration, ppm 2300-2500 Design Pressure, psig Atmospheric Operating Pressure, psig Atmospheric Design Temperature, ºF 100 Material Austenitic stainless steel with reinforced concrete shroud Valves (1) All Motor-Operated Valves That Must Function on Safety Injection ("S") Signal (a) Up to and including 8 inches (excluding SI-8805 A&B, CVCS-8107 and CVCS-8108) Maximum opening or closing time, sec 10 (b) CVCS-8107 and CVCS 8108 Maximum opening and closing time, sec 14 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-1 Sheet 3 of 3 Revision 18 October 2008 (c) SI-8805 A&B Maximum opening or closing time, sec 11 (d) Over 8 inches Minimum opening or closing rate, in./min 60 (2) All Other Motor-Operated Gate Valves Up to and Including 8 Inches Minimum opening or closing rate, in./min 12 (3) Original purchase specification leakage criteria. Inservice leakage requirements are specified in the valve Inservice Testing Program. (a) Conventional globe valves Disk leakage, cc/hr/in. of nominal pipe size 3 Backseat leakage (when open), cc/hr/in. of stem diameter 1 (b) Gate valves Disk leakage, cc/hr/in. of nominal pipe size 3 Backseat leakage (when open), cc/hr/in. of stem diameter 1 (c) Check valves Disk leakage, cc/hr/in. of nominal pipe size 3 (d) Diaphragm valves Disk leakage None (e) Pressure relief Disk leakage, cc/hr/in. of nominal pipe size 3 (f) Accumulator check valves Disk leakage, cc/hr/in. of nominal pipe size 3 (a) 1.15 service factor not included. (b) Usable volume includes the water above the outlet pipe. Unusable water includes the water below the outlet. (c) This minimum SI accumulator pressure is the value that is used in the accident analysis in Chapter 15. (Note that more conservative values may appear in other documents such as Technical Specifications, operating procedures, etc.) DCPP UNITS 1 & 2 FSAR UPDATE Revision 12 September 1998 TABLE 6.3-2 EMERGENCY CORE COOLING SYSTEM DESIGN CODE REQUIREMENTS Component Code Accumulators ASME B&PV, Section III(a) Class C Refueling Water Storage Tank Valves AWWA D100(c) USAS B16.5, MSS-SP-66 and ASME B&PV, Section III(a) Piping(b) - Design Class I portions (excluding Code Class A and @) ANSI B31.7 - Design Class I, Code Classes A and @ portions and Design Class II portions ANSI B31.1 Pumps Charging ASME B&PV, Section III(a) Residual heat removal ASME B&PV, Section III(a) Safety injection ASME B&PV, Section III(a)
(a) Draft Code November 1968 Edition.
(b) See Q-List (Reference 8 of Section 3.2) for piping classification.
(c) ASME B&PV Code, Section VIII, allowable stresses used for design.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-3 Sheet 1 of 2 Revision 12 September 1998 MATERIALS OF CONSTRUCTION EMERGENCY CORE COOLING SYSTEM COMPONENTS COMPONENT MATERIAL
Accumulators Carbon steel, clad with austenitic stainless steel Refueling Water Storage Tank Austenitic stainless steel with reinforced concrete shroud Pumps (parts in contact with coolants) Centrifugal charging Austenitic stainless steel Safety injection Martensitic stainless steel Residual heat removal Austenitic stainless steel or equivalent corrosion-resistant material Residual Heat Exchangers Shell Carbon steel Shell end cap Carbon steel Tubes Austenitic stainless steel Channel Austenitic stainless steel Channel cover Austenitic stainless steel Tube sheet Forged carbon steel with austenitic stainless steel weld overlay Valves Motor-operated valves containing radioactive fluids and pressure-containing parts Austenitic stainless steel or equivalent Body-to-bonnet bolting and nuts Low-alloy steel, austenitic stainless steel, or 17-4PH stainless Seating surfaces Stellite No. 6 or equivalent
Stems Austenitic stainless steel or 17-4PH stainless DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-3 Sheet 2 of 2 Revision 12 September 1998 COMPONENT MATERIAL
Motor-operated Valves Containing Non-radioactive, Boron-free Fluids Body, bonnet, and flange Carbon steel
Stems Corrosion resistant steel
Diaphragm Austenitic stainless steel
Accumulator Check Valves Parts contacting borated water Austenitic stainless steel
Clapper arm shaft Corrosion resistant steel
Relief Valves Stainless steel bodies Stainless steel
Carbon steel bodies Carbon steel
All nozzles, disks, spindles, and guides Austenitic stainless steel Bonnets for stainless steel valves without a balancing bellows Stainless steel All other bonnets Carbon steel
Piping All piping in contact with borated water Austenitic stainless steel
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-5 Sheet 1 of 6 SAFETY INJECTION TO RECIRCULATION MODE; SEQUENCE AND TIMING OF MANUAL CHANGEOVER Revision 20 November 2011 Actuation Time for Total Time Operation Elapsed Time Action Status Item sec sec min LOCA 0:00
Safety injection signal-all RHR, SI and charging pumps (CCP1 and CCP2) in operation 0:20 Spray initiation 0:40
RWST low level alarm and RHR pumps trip; initiate recirculation changeover 17:56 IMPLEMENT - Appendix EE 0 10 18:06 CUT IN - Series Contactors ** 8974A, 8809A, 8982A, 8982B, 8974B, 8809B 0 10 18:16 VERIFY - Safety injection signal reset ** 5 10 18:26 VERIFY - Containment isolation Phase A and Phase B reset ** 5 10 18:36 CHECK - Both ASW pumps running 0 5 18:41 VERIFY - CCW heat exchanger saltwater inlet valves open ** FCV-602(603) (Note 3) 5 10 18:51 VERIFY - CCW heat exchanger CCW outlet valves open ** FCV-430(431) (Note 3) 5 10 19:01 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-5 Sheet 2 of 6 Revision 20 November 2011 OPEN - Component cooling water to RHR heat exchanger 2 ** FCV-364 10 15 19:16 OPEN - Component cooling water to RHR heat exchanger 1 ** FCV-365 10 15 19:31 STOP - Centrifugal charging pump CCP3 ** 5 10 19:41 PA Announcement ** 0 10 19:51 Dispatch Operators to locally close breakers for 8976 and 8980 ** 52-1H/2H-20 52-1F/2F-31 0 20 20:11 VERIFY - RHR Pump 2 stopped 0 5 18:11 CLOSE - RHR pump suction valve from RWST 8700B 120 125 20:16
VERIFY - RHR Pump 1 stopped 0 5 20:21 CLOSE - RHR pump suction valve from RWST 8700A 120 125 22:26 CLOSE - RHR crosstie isolation valves 8716A 8716B 20 20 30 22:56 CHECK - RCS Pressure less than 1500 PSIG 0 5 23:01 CLOSE - SI pump miniflow block valves 8974A 8974B 10 10 20 23:21 CLOSE - CCP recirculation valves 8105 8106 10 10 20 23:41 CHECK - recirculation sump level > 92.0' LI-940 LI-941 5 5 10 23:51 CHECK - RHR pump 2 stopped 0 5 23:56 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-5 Sheet 3 of 6 Revision 20 November 2011 CHECK - RHR P2 suction from RWST closed 8700B 0 5 24:01 OPEN - RHR P2 suction from sump 8982B 30 35 24:36 VERIFY - RHR HX 1-2 in Service per App. EE 5 5 24:41 START - RHR-P2 RHR-P2 1 15 24:56 OPEN - SI pumps suction from RHR HX2 8804B 20 25 25:21 CHECK - RCS Pressure less than 1500 PSIG 0 5 25:26 VERIFY - SI pumps running 0 5 25:31 CHECK - RHR Pump 2 motor current less than 57 amps AND stable 0 5 25:36 OPEN - Cross-connect line from SI pump 1 to charging pumps (CCP1 and CCP2) 8807A 8807B 20 20 30 26:06 VERIFY - CCP1 and CCP2 running Changeover of a single train complete at 26:11 0 5 26:11 CHECK - RHR pump 1 stopped 0 5 26:16 CHECK - RHR P1 suction from RWST closed 8700A 0 5 26:21 OPEN - RHR P1 suction from sump 8982A 30 35 26:56 VERIFY - RHR HX 1 in Service per App. EE 5 5 27:01 START - RHR P1 RHR-P1 1 15 27:16 OPEN - SI pump suction from RHR HX1 Changeover of both trains complete at 27:41 8804A 20 25 27:41 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-5 Sheet 4 of 6 Revision 20 November 2011 CHECK- RCS Pressure less than 1500 PSIG 0 5 27:46 VERIFY - SI pumps running 0 5 27:51 CHECK - RHR Pump 1 motor current less than 57 amps AND stable 0 5 27:56 CHECK - at least one RHR pump running RHR Pump 0 5 28:01 CLOSE - Charging pump suction RWST isolation 8805A 8805B 11 11 21 28:22 CLOSE - SI pump suction RWST isolation 8976 20 25 28:47 CLOSE - RHR pump suction from RWST 8980 25 30 29:17 Receive RWST low-low level alarm 33:25 CHECK - both RHR pumps running 0 5 33:30 CHECK - PK01-18, Containment Spray Actuated On OR Cont. Pressure greater than 22 PSIG 0 10 33:40 CHECK - RWST level less than 4% LI-920 LI-921 LI-922 5 5 5 15 33:55 RESET - Containment spray 5 10 34:05 STOP - Containment Spray (CS) pumps1 & 2 CS-P1 CS-P2 1 1 5 34:10 CLOSE - CS pump discharge to spray header valves System in recirculation mode 9001A 9001B 10 10 20 34:30 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-5 Sheet 5 of 6 Revision 20 November 2011 CHECK - Cont. Pressure greater than 22 PSIG 0 5 34:35 VERIFY - Both RHR trains in service 0 5 34:40 CLOSE - RCS from RHR-P1 Cold leg injection terminated 8809A 20 25 35:05 OPEN - RHR-P1 to spray header Recirculation sump to spray header 9003A 15 20 35:25 Notes to Table 6.3-5 1. Actuation Time: The estimated actuation time for a component to complete its function. For valves, this is the maximum expected stroke time. In some cases, where the component is already expected to be in the desired position, no actuation time is added.
- 2. Time for Operation: The actuation time plus the estimated operator action, if applicable.
- 3. If the valves are not already in the desired position the analysis assumes they are stroked concurrently while the crew continues in the procedure, since subsequent checks of ASW/CCW alignment are made at decision points further on in the procedure.
- All these steps from Appendix EE of Procedure EOP E-1.3 can be performed in parallel with the steps that follow since they add up to 125 seconds, which is less than the 295 seconds (from 18:06 to 23:01) needed before we close 8974A/B (this is the first step that depends on a step from Appendix EE).
The following assumptions are used for Table 6.3-5: 1. Double-ended reactor coolant pump suction LOCA.
- 2. Maximum safety features implemented:
- a. Pumps at flow limited by pipe friction 2 RHR pumps: 7300 gpm total during injection 1 RHR pump: 4600 gpm for 5 minutes during changeover, when assuming a single failure of one RHR pump to trip on low RWST level 2 SI pumps: 900 gpm total 2 Charging pumps (CCP1 and CCP2): 900 gpm total
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-5 Sheet 6 of 6 Revision 20 November 2011 b. 2 Containment spray pumps: 6550 gpm total during injection, assuming 20 psig in containment 6800 gpm total during changeover, assuming 0 psig in containment
- c. Allowable 100 gpm leakage penalty from RWST
- 3. Refueling water storage tank.
- a. Maximum outflow: 15,750 gpm based on 2a and 2b during injection 8,700 gpm based on 2a and 2b during changeover, no single failure
- b. Volume available: 404,511 gal. c. Low-level alarm volume: 116,812 gal. d. Low-low level alarm volume: 0 gal.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 12 September 1998 TABLE 6.3-6 NORMAL OPERATING STATUS OF EMERGENCY CORE COOLING SYSTEM COMPONENTS FOR CORE COOLING Number of Safety Injection Pumps Operable 2 Number of Charging Pumps Operable 2 Number of Residual Heat Removal Pumps Operable 2 Number of Residual Heat Exchangers Operable 2 Refueling Water Storage Tank Available Volume, gal 350,000 Boron Concentration in Refueling Water Storage Tank, Maximum, ppm 2,500 Minimum, ppm 2,300 Boron Concentration in Accumulators, Maximum, ppm 2,500 Minimum, ppm 2,200 Number of Accumulators 4 Minimum Accumulator Pressure, psig (a) 579 Nominal Accumulator Water Volume, ft3 850 System Valves, Interlocks, and Piping Required for the Above Components which are Operable All
(a) This minimum SI accumulator pressure is the value that is used in the accident analysis in Chapter 15. (Note that more conservative values may appear in other documents such as Technical Specifications, operating procedures, etc.)
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-7 Sheet 1 of 4 Revision 12 September 1998 SEQUENCE AND DELAY TIMES FOR STARTUP OF ECCS Delay, sec References
Accident Actuation Signal(s) Action Sequence (Subsystem or Component) (h) (i) (j) Design Performance Minimum ECCS Performance Assumed in Analysis Section FSAR Figures Tables
- 1. Major Reactor 15.4.1 Coolant System Rupture (LOCA)
- a. Injection phase (g) Accumulator tank (g) (g) (g) 4 tanks, each with 850 ft3 of borated water @ 600 psig Three tanks injecting into RCS; one injecting into broken loop 6.3 8.3-4 (a) Containment isolation valves 1 1 10 Double barrier; fast automatic valve closure upon receipt of CIS A single active failure is allowable 6.2.4 6.2-12, 6.2-13 &
6.2-14 8.3-4 (b) (d) ECCS required valves (k) (k) See Table 6.3-1 Rapid reliable system alignment or isolation A single active failure is allowable 6.3.2 7.3-22, 7.3-33 8.3-4 (b) (d) Centrifugal charging pumps -5 15 4-1/2 Two centrifugal charging pumps supply borated water into a single injection flowpath splitting into 4 cold leg injection lines One pump required at design flow 6.3.2, 9.3.4 7.3-4 8.3-4 (b) (d) Safety injection pumps Two pumps inject via a single path splitting into 4 cold leg injection lines One pump delivering at design flow 6.3.2 3.2-9 (b) (d) Residual heat removal pumps Two pumps inject into 4 cold legs, via 2 lines that each split into 2 cold leg injection lines One pump delivering at design flow 6.3.2, 5.5.6 3.2-9 (b) (d) Component cooling water pumps 25/25/30 35/35/40 4-1/2 Two flowpaths; each 11,500 gpm @ 130 ft One flowpath required at design flow 9.2.2 7.3-7 8.3-4 (e) Auxiliary feed- water pumps 30/35 40/45 5 Two flowpaths; each 800 gpm @ 2350 ft One flowpath required at design flow 6.5.2 7.3-8 8.3-4 (b) (d) Auxiliary salt- water pumps 30/35 40/45 5 Two flowpaths; each 11,000 gpm @ 115 ft One flowpath required at design flow 9.2.7 7.3-5 8.3-4 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-7 Sheet 2 of 4 Revision 12 September 1998 Delay, sec References
Accident Actuation Signal(s) Action Sequence (Subsystem or Component)
(h) (i) (j)
Design Performance Minimum ECCS Performance Assumed in Analysis Section FSAR Figures Tables (c) Containment spray pumps
Pump 1
Pump 2 26 22 26 22 1.7 1.7 Two flowpaths; each 2600 gpm @ 450 ft One flowpath required at design flow 7.3-11 8.3-4 b. Recirculation phase (f) Operating personnel shift system alignment from injection phase (Total switchover time is approximately 10 min. See 6.3.2) (Design performance for ECCSA and related equipment as described in 1a above) A single failure is allowable 6.3.2 2. Major Seccondary System Rupture (b) Action sequence similar to 1a above. Operation of ESF required. Valves isolate feedwater & steam Same as 1a above Same as 1a above Same as 1a above with these further notes: Accumulator and low head injection required only in the severe cases. Since no RCS rupture has occurred, all four accumu-ators are functional 15.4.2 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-7 Sheet 3 of 4 Revision 12 September 1998 Accident Actuation Signal(s) Action Sequence (Subsystem or Component)
(h) (i) (j) Design Performance Minimum ECCS Performance Assumed in Analysis Section FSAR Figures Tables
- 3. Steam Generator Tube Rupture Low pressurizer pressure Same as 1a above although no containment spray.
Additionally, automatic isolation of individual steam generator blowdown valve occurs due to SGBD liquid radiation monitor. Injection and charging flow regulated to maintain visible pressurizer water level. Auxiliary feedwater to affected SG manually isolated. Pressurizer reliefs operated to reduce RCS pressure under 1000 psia Same as 1a above with additional isolation done within 30 minutes Same as 1a above Same as 1a above (but all four accumulators assumed functional). Conservative estimate of 125,000 lb of reactor coolant transferred to the secondary side of the affected steam generator 15.4.3 4. Minor RCS Rupture which Actuates ECCS Low pressurizer
- pressure, or level, or high containmen t pressure 15.3.1 a. Injection phase Same as 1a above Same as 1a above Same as 1a above Same as 1a above Same as 1a above b. Recirculation Same as 1a above Same as 1a above Same as 1a above Same as 1a above Same as 1a above DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-7 Sheet 4 of 4 Revision 12 September 1998 (a) Initiated by means of containment isolation signal, which occurs on containment high pressure (2 of 3) or on safety injection signal (SIS).
(b) Safety injection signal actuates on any of the following: Low pressurizer pressure, high containment pressure, low steamline pressure, or manual actuation. (c) Containment spray actuation signal, which occurs on containment high-high pressure (2 of 4), or manual actuation.
(d) Emergency diesel loading sequencer loads the diesel in accordance with the sequence shown in Tables 8.3-2 and 8.3-4. Also see Figures 8.3-9, 8.3-10, 8.3-11, and 8.3-16. (e) Auxiliary feedwater autostart signal, which occurs with a SIS. SG low-low level or tripping of both main feedwater pumps.
(f) Water level indication and alarms on the refueling water storage tank and in the containment sump provide ample warning to terminate the injection mode and begin the recirculation mode while the operating pumps still have adequate net positive suction head. Manual switchover by operating personnel changes the ECCS from injection to recirculation mode. (g) All valves between the accumulators and the RCS are required to be open in Modes 1, 2, and 3; consequently, the accumulators inject as soon as the RCS pressure drops below the pressure (600 psia) of the accumulators. (h) Electrical and instrumentation delay time after "S" signal with main generator power or offsite power available. For containment spray pumps, delay time is after "P" signal. (i) Electrical and instrumentation delay time after "S" signal using diesel generator. For containment spray pumps, delay time is after "P" signal. (j) Equipment startup time after receipt of signal.
(k) These delay times vary.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 12 September 1998 TABLE 6.3-8 EMERGENCY CORE COOLING SYSTEM SHARED FUNCTIONS EVALUATION Component Normal Operating Arrangement Accident Arrangement Refueling water storage tank Lined up to suction of safety injection and residual heat removal pumps Lined up to suction of centrifugal charging, safety injection, and residual heat removal pumps. Valves for realignment meet single failure criteria. Centrifugal charging pumps Lined up for charging service Lined up to charging injection header. Valves for realignment meet single failure criteria. Residual heat removal pumps Lined up to cold legs of reactor coolant piping Lined up to cold legs of reactor coolant piping. Residual heat exchangers Lined up for residual heat removal pump operation Lined up for residual heat removal pump operation. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 6.3-9 MAXIMUM POTENTIAL RECIRCULATION LOOP LEAKAGE EXTERNAL TO CONTAINMENT
Items Type of Leakage Control and Unit Leakage Rate Used in the Analysis Leakage to Atmosphere, cc/hr Leakage to Drain Tank, cc/hr
- 1. Residual Heat Removal Pumps Mechanical seal with leakoff - 10 cc/hr seal(a) 20 0
- 2. Safety Injection Pumps Same as residual heat removal pump 40 0
- 3. Charging Pumps Same as residual heat removal pump 40 0
- 4. Flanges:
- a. Pumps Gasket - adjusted to zero leakage following any test; 10 drops/min/flange used(30 cc/hr). Due to leak tight flanges on pumps, no leakage to atmosphere is assumed 0 0 b. Valves bonnet to body (larger than 2 in.) 1200 0 c. Control valves 180 0 d. Heat exchangers 240 0
- 5. Valves - Stem Leakoffs Backseated double-packing with leakoff - 1 cc/hr in. stem diameter used (see Table 6.3-1) 0 40 6. Misc. Small Valves Flanged body-packed stems -1 drop/min used (3 cc/hr). 150 0
- 7. Misc. Large Valves (larger than 2 in.) Double-packing 1 cc/hr/in. stem diameter used 40 0 TOTALS 1910 40
(a) Seals are acceptance tested to essentially zero leakage.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 6.3-10 ECCS RELIEF VALVE DATA
Description Fluid Discharged Fluid Inlet Temp Normal, °F Set Pressure, psig Back Pressure Constant Psig Build-up Capacity N2 supply to accumulators N2 120 700 0 0 1500 scfm SIS pump discharge Water 100 1750 3 50 20 gpm
RHR pumps SI line Water 120 600 3 50 400 gpm
SI pumps suction header Water 120 220 3 50 20 gpm
Accumulator to containment Water or N2 gas 120 700 0 0 1500 scfm
DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 6.3-11 NET POSITIVE SUCTION HEADS FOR POST-DBA OPERATIONAL PUMP(a)
Pump Flow and Condition Suction Source Minimum Available NPSH, ft Required NPSH, ft Water Temp, °F Safety injection 675 gpm runout flow Refueling water storage tank 31 29 100 max Centrifugal charging 560 gpm runout flow Refueling water storage tank 44 24 100 max Residual heat removal 4500 gpm Refueling water storage tank 27 20 100 max Residual heat removal 4900 gpm runout flow Containment sump 25 24 Saturated liquid Containment spray 3500 gpm runout flow Refueling water storage tank 40 19 100 max (a) NPSH conservatively calculated without considering additional static suction head of water in the RWST.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-12 Sheet 1 of 2 Revision 16 June 2005 ECCS MOTOR-OPERATED VALVES WITH ELECTRIC POWER REMOVED DURING NORMAL POWER PLANT OPERATION Position Valve Identification Service Description Normal Operation Injection Phase Cold Leg Recirc Phase Hot Leg Recirc Phase Power Restorable From Control Room 8703 RHR pump discharge to RCS hot leg loops Closed Closed Closed Open No 8802 A, B SIS pump discharge to RCS hot leg loops Closed Closed Closed Open No 8808 A, B, C, D Accumulator isolation Open Open Open Open No
8809 A 8809 B RHR pump discharge to RCS cold leg loops Open Open Closed(b) Closed Yes Open Open Open Closed Yes 8835 SIS pump discharge to RCS cold leg loops Open Open Open Closed No 8974 A, B SIS pump miniflow Open Open Closed Closed Yes
8976 RWST supply to SIS pumps Open Open Closed Closed No
8980 RWST supply to RHR pumps Open Open Closed Closed No
8982 A, B Containment recirc. sump supply to RHR pumps Closed Closed Open Open Yes DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3-12 Sheet 2 of 2 Revision 16 June 2005 Position Valve Identification Service Description Normal Operation Injection Phase Cold Leg Recirc Phase Hot Leg Recirc Phase Power Restorable From Control Room 8992 NaOH spray additive supply Open Open Open Open No
8701(a) Loop 4 hot leg RHR suction valve 2 Closed Closed Closed Closed No 8702(a) Loop 4 hot leg RHR suction valve 1 Closed Closed Closed Closed No (a) Valve required to function for a normal RHR cooldown not for ECCS. (b) Closed if containment spray is required.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 6.5-1 CRITERIA FOR AUXILIARY FEEDWATER SYSTEM DESIGN BASIS CONDITIONS Condition or Transient Classification(a) Criteria(a) Additional Design Criteria Loss of main feedwater Condition II Peak RCS pressure not to exceed design pressure. No consequential fuel failures Pressurizer does not fill with both motor-driven aux feed pumps feeding 4 SGs.(b) Loss of offsite power Condition II (same as LMFW) (same as LMFW)
Steamline rupture Condition IV 10 CFR 100 dose limits containment design pressure not exceeded None Feedline rupture Condition IV 10 CFR 100 dose limits. RCS design pressure not exceeded. Core does not uncover Loss of all ac power (Station Blackout) N/A Same as loss of offsite power assuming turbine-driven pump Loss of coolant Condition III 10 CFR 100 dose limits 10 CFR 50 PCT limits Condition IV 10 CFR 100 dose limits 10 CFR 50 PCT limits Cooldown N/A 100°F/hr 557°F to 350°F (a) Ref: ANSI N18.2 (This information provided for those transients analyzed in Chapter 15.) (b) A better-estimate analysis has also been performed to demonstrate that the pressurizer does not fill with a single motor-driven auxiliary feedwater pump feeding 2 SGs a total of 390 gpm.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.5-2 Sheet 1 of 2 Revision 19 May 2010 SUMMARY OF ASSUMPTIONS AFWS DESIGN VERIFICATION Transient Loss of Feedwater (Loss of Offsite Power) Cooldown Main Feedline Break Major Steam Line Break (Containment) a. Max NSSS power 102% of 3425 MWe 3470 (Unit 1) 3496 (Unit 2) 102% of 3425 MWe 102% of 3425 MWe b. Time delay from event to Rx trip (see Table 15.2-1) 2 sec (See Table 15.4-8) Variable c. AFWS actuation signal/time delay for AFWS flow Low-low SG level 1 minute N/A Low-low SG level 10 minutes Assumed immediately 0 sec (no delay) d. SG water level at time of reactor trip. Low-low SG level 8 % narrow range span (NRS) N/A Low-low SG level 0% NRS N/A e. Initial SG inventory Nominal + uncertainty (75% NRS) 106,000 lbm/SG at 519° F 75% NRS faulted SG Consistent with power Rate of change before
& after AFWS actuation See Figure 15.2.8-1 N/A See Figure 15.4.2-10 N/A Decay heat Figure 15.1-7 Figure 15.1-7 Figure 15.1-7 Figure 15.1-7
- f. AFW pump design pressure 1102 psig 1112 psia 1102 psig N/A g. Min. No. of SGs that must receive AFW flow 4 of 4 N/A 2 of 4 N/A h. RC pump status All operating (LOOP - Tripped at reactor trip) Tripped All operating (offsite power available/
Tripped at reactor trip (offsite power unavailable) All operating DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.5-2 Sheet 2 of 2 Revision 19 May 2010 Transient Loss of Feedwater (Loss of Offsite Power) Cooldown Main Feedline Break Major Steam Line Break (Containment)
- i. Maximum AFW temperature 100° F 100° F 100° F 100 j. Operator action None N/A 10 minutes 10 minutes
- k. AFW purge volume/
temperature 113 ft3per loop/435° F 450 ft3plant total/430° F 113 ft3per loop/435° F 0.0ft3/ based on power l. Normal blowdown None assumed None assumed None assumed None assumed
- m. Sensible heat See cooldown Table 6.5-3 See cooldown N/A
- n. Time at standby/time to cooldown to RHR 2 hr/4 hr 2 hr/4 hr 2 hr/4 hr N/A o. AFW flowrate 600 gpm (total) constant (minimum requirement Variable 390 gpm (total) constant (after 10 minutes)*
(minimum requirement) Variable as a function of the faulted steam generator pressure (maximum requirement for release to containment)
- Minimum flow of 175.5 / 214.5 gpm to each of the two steam generators receiving AFW flow.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 6.5-3 SUMMARY OF SENSIBLE HEAT SOURCES (For Plant Cooldown by AFWS) Primary Water Sources (initially at emergency safeguards design (ESD) power temperature and inventory)
- RCS fluid - Pressurizer fluid (liquid and vapor)
Primary Metal Sources (initially at ESD power temperature)
- Reactor coolant piping, pumps and reactor vessel - Pressurizer - Steam generator tube metal and tubesheet - Reactor vessel internals
Secondary Water Sources (initially at ESD power temperature and inventory)
- Steam generator fluid (liquid and vapor) - Main feedwater purge fluid between steam generator and AFWS piping
Secondary Metal Sources (initially at ESD power temperature)
- All steam generator metal above tubesheet, excluding tubes
Revision 11 November 1996FIGURE 6.2-10 CONTAINMENT SPRAY PUMP PERFORMANCE CURVE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.2-12 CONTAINMENT SPRAY NOZZLE CUTAWAY UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 6.2-13 CONTAINMENT SPRAY HEADERS PLAN VIEW UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 6.2-14 GENERIC METHODOLOGY COMPARISON OF SPRAY REMOVAL MODELAND CSE RESULTS (RUN A6) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 12 September 1998 Revision 11 November 1996 FIGURE 6.2-15 CONTAINMENT RECIRCULATION SUMP pH VERSUS TIME AFTER LOCA BEGINS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 6.2-16 CONTAINMENT EQUILIBRIUM ELEMENTAL IODINE PARTITION COEFFICIENT VERSUS TIME FOR MINIMUM SUMP pH CASE (2 ECCS TRAINS AND 1 SPRAY TRAIN) FOR THREE TEMPERATURES UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 12 September 1998 Revision 11 November 1996FIGURE 6.2-17 CONTAINMENT ISOLATION SYSTEM UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.2-18 (Sheet 1 of 2) PENETRATION DIAGRAM LEGEND UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.2-18 (Sheet 2 of 2) PENETRATION DIAGRAM LEGEND UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 1 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 2 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 3 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 Revision 11 November 1996FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 4 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE
Revision 21 September 2013FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 5 OF 25) UNIT 1 DIABLO CANYON SITE FSAR UPDATE
Revision 21 September 2013FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 5A OF 25) UNIT 2 DIABLO CANYON SITE FSAR UPDATE TCD*V*D*V* - UNIT-2 ONLY*H**IRHR SYSTEM (CLOSED SYSTEM)(I ) RCS LOOP 4 RECIRC. (27)(II ) CONT. SUMP RECIRC. (28)(III) CONT. SUMP RECIRC. (29)# - UNIT-1 ONLYINSIDECONT.OUTSIDECONT.MMTVTCMIIIFMTVTCEIICONTAINMENTRECIRC. SUMPPROTECTIVECHAMBERPROTECTIVECHAMBERMCMMBRWST#CONCENTRICGUARD PIPEID#TV#MTVAMTV1MB0MBRCDTLOOP 4 RCSTO PRT(RCS)G Revision 20 November 2011FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 6 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE IMB OMB D INSIDECONT.OUTSIDECONT.MISC. EQUIP.DRAIN TK.TVTV,TCRHR HT.EX.PRHR HT.EX.CONTAINMENTSPRAY PUMPS,VALVES ANDRELATEDEQUIPMENTFROMRWSTTHIS SYSTEM IS DESIGN CLASS IRCSANDPRTCLOSEDSYSTEMTCAITVCTCBMMDMTV,TCFHGMTVPTCMISC. EQUIP.DRAIN TK.TCEIIIVIIICOOLINGCOILWATERCHILLERTCTCTCTVS-1TJS-1TLS-1S-1TITK0MB1MBTV(I ) CONTAINMENT SPRAY (30)(II ) CONTAINMENT SPRAY (31)(III) CHILLED WATER SUPPLY (82D)(IV ) CHILLED WATER RETURN (83A)TC **-UNIT-2 ONLY* Revision 21 September 2013FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 7 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE OMB IMB 22TCCOLD LEGS (RCS)GSIS TESTIMTVBTCOMBIMBINSIDECONT.OUTSIDECONT.SIS INJECTIONPUMPSATYP. OF 4IITVISCCHARGINGPUMPSMDTCTYP. OF 2MTCTVCHARGINGPUMPSSTVCCOLD LEGS (RCS)IIITCTCVVFTOACCUM.TES-1TVN(I ) SIS COLD INJECTION (33)(II ) SIS COLD INJECTION (34)(III) N SUPPLY TO ACCUM. (51A)S Revision 20 November 2011FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 8 OF 25) UNIT 1 DIABLO CANYON SITE FSAR UPDATE 22TCCOLD LEGS (RCS)GTO SIS TESTSTATION #2IMTVBTCOMBIMBINSIDECONT.OUTSIDECONT.SIS INJECTIONPUMPSATYP. OF 4IITVISCCHARGINGPUMPSMDTCTYP. OF 2MTCTVCHARGINGPUMPSSTVCCOLD LEGS (RCS)IIITCTCVVFTOACCUM.TES-1TVN(I ) SIS COLD INJECTION (33)(II ) SIS COLD INJECTION (34)(III) N SUPPLY TO ACCUM. (51A)S Revision 20 November 2011FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 8A OF 25) UNIT 2 DIABLO CANYON SITE FSAR UPDATE S.O.TATBTCDPRTGTCFROMRCSREGENERATIVEHEATEXCHANGERITDVDTVLETDOWNHEATEXCHANGERFROM RESID.HT REMOVALHT. EXCH.OUTLETCVCS(CLOSED SYSTEM)REGEN.HEATEXCH.0MBTO RCSCOLD LEG 3(ALTERNATE)0MB0MBTO RCSCOLD LEG 4(NORMAL)TO RCSPRESSAUX. SPRAYTCTCEIIMSMSFTVFROMCHARGING PUMPS(II ) REGEN. HEAT EXCHR. CHARGING/AUX. SPRAY (36)(I ) LETDOWN LINE REGEN. HEAT EXCHR. TO LETDOWN HEAT EXCHR. (35)V0MB1MBINSIDECONT.OUTSIDECONT. Revision 21 September 2013FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 9 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE OMBOMB OMB OMB IMB FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 10 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 21 September 2013 IMBOMB Revision 11 November 1996FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 11 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE 2S-1ATVNITROGENSUPPLYS-1CTVTO VENTHEADERS-1ETVS-1GTVTO GASANALYZERTO LIQUIDHOLD-UPTTTTTO REFUELINGWATERSTORAGETO EQUIP.DRAINRECEIVERIIIIVIIIHTCTFTCTDTCTBTCTCREACTOR COOLANTDRAIN TANKFROM PRESSURIZERRELIEF TANKFROMCONTAINMENTCLOSEDDRAINSTO REACTORCAVITY SUMPINSIDECONT.OUTSIDECONT. (I ) REACTOR COOLANT DRAIN TANK N SUPPLY (52D)(II ) REACTOR COOLANT DRAIN TANK VENT HEADER (51C)(III) REACTOR COOLANT DRAIN TANK GAS ANALYZER (51D)(IV ) REACTOR COOLANT DRAIN TANK DISCHARGE (50) Revision 15 September 2003FSAR UPDATE UNITS 1 AND 2 DIABLO CANYON SITE FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 12 OF 25) FROMACCUMULATORTANK(TYP. 4 LOOPS)FROM SISTEST CONN.FROM RCSCOLD LOOP(TYP. 4 LOOPS)SIS TEST LINETCATIEPRESSUREINDICATORTVTEST CONN. FROMSI PUMP DISCH. HDR.TBSCDTVTESTLINETCTVLIQUID HOLDUP TANKINSIDECONT.OUTSIDECONT.( I ) TEST LINE FROM SAFETY INJECTION SYSTEM (51B) Revision 20 November 2011FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 13 OF 25) UNIT 1DIABLO CANYON SITE FSAR UPDATE F TO SISTEST STATION#1FROMACCUMULATORTANK(TYP. 4 LOOPS)FROM SISTEST CONN.FROM RCSCOLD LOOP(TYP. 4 LOOPS)SIS TEST LINETCATIEPRESSUREINDICATORTVTEST CONN. FROMSI PUMP DISCH. HDR.TBSCDTVTESTLINETCTVLIQUID HOLDUP TANKINSIDECONT.OUTSIDECONT.(I ) TEST LINE FROM SAFETY INJECTION SYSTEM (51B) Revision 20 November 2011FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 13A OF 25) UNIT 2 DIABLO CANYON SITE FSAR UPDATE F Revision 21 September 2013FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 14 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE PRESSURIZER RELIEF TANK OMB IMB IMBOMB Revision 11 November 1996FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 15 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE 0MB1MBTCAITVS-1TBETCINSTRUMENTAIR SUPPLY(>100 PSIG)TO VALVESANDINSTRUMENTSTO VALVESANDINSTRUMENTSINSIDECONT.OUTSIDECONT.0MB1MBTCCIIS-1DTCINSIDECONT.OUTSIDECONT.AIR OUTLETSSCVTC & TVCOMPRESSEDAIR SUPPLY(I ) INSTRUMENT AIR HEADER (54)(II ) SERVICE AIR HEADER (56) FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 16 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 21 September 2013 IMBOMB OMB IMB ~~~SVITCTCTABSAMPLINGSYSTEMTTCTCPRESSURIZERSTEAM (RCS)OUTSIDECONT.INSIDECONT.SYSTEM IS DISIGN CLASS IPOST LOCAIITCTCTCDSAMPLINGSYSTEMTTVTCPRESSURIZERLIQUID (RCS)S-1POST LOCA*IIITCTCTEFSAMPLINGSYSTEMTTVTCS-1FROMRESIDUALHEATREMOVALDELAYCOILHOT LEGLOOP NO. 1(RCS)HOT LEGLOOP NO. 4(RCS)POST LOCAACCUMULATORNO. 1 (TYP.)(I)TCTCTGHSAMPLINGSYSTEMTTVTCS-1PRESSURIZER STEAM SAMPLE (76A)(II)PRESSURIZER LIQUID SAMPLE (59A)(III)HOT LEG SAMPLE (59B)(IV)ACCUMULATOR SAMPLE (59C)IV*- UNIT -2 ONLY FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 17 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 15 September 2003 Revision 11 November 1996FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 18 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 19 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 20 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE CDHOT LEG3HOT LEG4MTVATCBISISTEST LINETCSISPUMP 2INSIDECONT.OUTSIDECONT.FGHOT LEG1HOT LEG2MTVETCIITCSISPUMP 1(I ) SIS PUMP 2 DISCHARGE (75)(II ) SIS PUMP 1 DISCHARGE (77) Revision 19 May 2010FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 21 OF 25) UNIT 1 DIABLO CANYON SITE FSAR UPDATE CDHOT LEG3HOT LEG4MTVATCBITO SISTEST STATION#2TCSISPUMP 2INSIDECONT.OUTSIDECONT.FGHOT LEG1HOT LEG2MTVETCIITCSISPUMP 1(I ) SIS PUMP 2 DISCHARGE (75)(II ) SIS PUMP 1 DISCHARGE (77) Revision 19 May 2010FSAR UPDATE UNIT 2 DIABLO CANYON SITE FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 21A OF 25) FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 22 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008 TCTCTCIBATTVINSIDECONT.OUTSIDECONT.1MB0MBS-1S-1FIRE WATERSUPPLY HDR.(I ) FIRE WATER SUPPLY (79)
FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 23 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 21 September 2013 IMB OMB H22 2DESIGN CLASS IIDESIGN CLASS IIMFSVATCDISVBTVIISVCTV2MONITORIIIMERECOMBINERPROVISIONCHPEXHAUSTSYSTEMINSIDECONT.OUTSIDECONT.(I ) CONTAINMENT H MONITOR SUPPLY (52E, 78A)(II ) CONTAINMENT H MONITOR RETURN (52C, 78B) (III) CONTAINMENT H EXTERNAL RECOMBINER (57, 81)ALL SYSTEMS ARE DESIGN CLASS I, EXCEPT AS NOTED. FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 24 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 16 June 2005 AIINSIDECONT.OUTSIDECONT.RCSHIGH VOLUMEBELLOWS SENSORBHYDROLICISOLATORINSTRUMENTATION1MB0MBSCIIS-1SDS-1SEIIIFS-1SGIVS-1SHPOSTLOCASAMPLINGSYSTEMREACTORCAVITYSUMPD(I ) REACTOR VESSEL LEVEL INSTRUMENTATION (59E,59F,59G,80E,80F,80G)(II ) POST-LOCA SAMPLING SYSTEM CONT. AIR SUPPLY (82B)(III) POST-LOCA SAMPLING SYSTEM CONT. AIR RETURN (82C)(IV) POST-LOCA SAMPLING SYSTEM REACTOR CAVITY SUMP (82A) FIGURE 6.2-19 PENETRATION DIAGRAM (SHEET 25 OF 25) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 21 September 2013 IMB OMB Revision 11 November 1996 FIGURE 6.2-20 CONTAINMENT HYDROGEN PURGE SYSTEM PURGE STREAM UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 6.2-21 CONTAINMENT HYDROGEN PURGE SYSTEM SUPPLY STREAM UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE CONTAINMENTAIRSCEL-82SCONTAINMENTAIRRETURNSTVTVTCCONTAINMENTAIRSCEL-83SCONTAINMENTAIRRETURNSTVTV52E52F78A78BOUTSIDEINSIDECONTAINMENTNOTES:1. VALVES SHOWN FOR NORMAL PLANT OPERATION.2. ALL PIPING AND VALVES ARE DESIGN CLASS I, EXCEPT AS NOTED.3. HYDROGEN MONITORS ARE CLASS II.TCDESIGN CLASS IIDESIGN CLASS II FIGURE 6.2-22 CONTAINMENT HYDROGEN PURGE SYSTEM HYDROGEN ANALYZER STREAM UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 16 June 2005 Revision 11 November 1996FIGURE 6.2-23 MODEL B ELECTRIC HYDROGEN RECOMBINER CUTAWAY UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.2-24 ALUMINUM AND ZINC CORROSION RATE DESIGN CURVE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE 0.0010.010.110.1110100GAS/LIQUID VOLUME RATIOAPPARENT G(H2), MOLECULES/100 eV2.5E+6 Rads/hr, pH = 8.62.5E+5 Rads/hr, pH = 9.46.1E+5 Rads/hr, pH = 9.4Alkaline Sodium Borate Solution3000 ppm Boron - 72 deg FRevision 14 November 2001FIGURE 6.2-25 RESULTS OF WESTINGHOUSE CAPSULE IRRADIATION TESTS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE 01234 5678910051015202530Time After LOCA (days)Hydrogen Concentration (volume %)No RecombinerRecombiner Started at 3.5 v/oRecombiner Started at 24 Hours4.0 v/o3.5 v/oFIGURE 6.2-26 POST-LOCA CONTAINMENT HYDROGEN CONCENTRATION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 14 November 2001 050000100000 1500002000002500003000003500000102030405060708090100Time after LOCA (days)Hydrogen Accumulation (scf)No RecombinerRecombination Started at 3.5 v/oRecombination Started at 24 HoursFIGURE 6.2-27 POST-LOCA HYDROGEN ACCUMULATION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 14 November 2001 01234567891011120102030405060708090100Time After LOCA (days)Hydrogen Production Rate (SCFM)TotalCorrosionCore RadiolysisSump RadiolysisFIGURE 6.2-28 POST-LOCA HYDROGEN PRODUCTION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 14 November 2001 02550 75100125 1501752000102030405060708090100Time After LOCA (days)Hydrogen Accumulation (thousands of SCF)Aluminum CorrosionZinc CorrosionTotal CorrosionFSAR UPDATEUNITS 1 AND 2 DIABLO CANYON SITE FIGURE 6.2-29 POST-LOCA HYDROGEN ACCUMULATION FROM CORROSION OF MATERIAL INSIDE CONTAINMENT WITH NO RECOMBINER Revision 14 November 2001 Revision 11 November 1996FIGURE 6.2-33 CONTAINMENT PRESSURE DIFFERENTIAL ELEMENTS AND FLOW PATHS FOR LOOP CONTAINMENT ANALYSIS MODEL UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 6.2-34 CONTAINMENT PRESSURE DIFFERENTIAL LOOP COMPARTMENT ANALYSIS ABSOLUTE AND DIFFERENTIAL PRESSURES IN LOOP COMPARTMENT 1 UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 6.2-35 CONTAINMENT PRESSURE DIFFERENTIAL LOOP COMPARTMENT ANALYSIS ABSOLUTE AND DIFFERENTIAL PRESSURES IN LOOP COMPARTMENT 2 UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 6.2-36 CONTAINMENT PRESSURE DIFFERENTIAL PRESSURIZER ENCLOSURE ANALYSIS ABSOLUTE AND DIFFERENTIAL PRESSURES IN PRESSURIZER ENCLOSURE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 6.2-37 CONTAINMENT PRESSURE DIFFERENTIAL ELEMENTS AND FLOW PATHS FOR REACTOR CAVITY ANALYSIS MODEL UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.2-38 CONTAINMENT PRESSURE DIFFERENTIALLOCATION OF ELEMENTS FOR REACTOR CAVITY ANALYSIS MODEL UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 6.2-39 CONTAINMENT PRESSURE DIFFERENTIAL LOCATION OF ELEMENTS FOR REACTOR CAVITY ANALYSIS MODEL UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.2-40 MAXIMUM DISPLACEMENTS FOR HOT LEGBREAK AT REACTOR NOZZLE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.2-41 MAXIMUM DISPLACEMENTS FOR COLD LEG BREAK AT REACTOR NOZZLE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.2-42 CONTAINMENT PRESSURE DIFFERENTIAL REACTOR CAVITY ANALYSIS PRESSURE IN REACTOR VESSEL ANNULUS(ELEMENT 3) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.2-43 CONTAINMENT PRESSURE DIFFERENTIAL REACTOR CAVITY ANALYSIS PRESSURE IN LOOP COMPARTMENT (ELEMENT 21) ADJACENT TO REACTOR CAVITY (ELEMENT 3) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.2-44 CONTAINMENT PRESSURE DIFFERENTIAL REACTOR CAVITY ANALYSIS PRESSURE IN LOWER REACTOR CAVITY (ELEMENT 2) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.2-45 CONTAINMENT PRESSURE DIFFERENTIAL REACTOR CAVITY ANALYSIS PRESSURE IN UPPER PORTION OF CONTAINMENT (ELEMENT 32) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.2-46 CONTAINMENT PRESSURE DIFFERENTIAL REACTOR CAVITY ANALYSIS PRESSURE IN HOT LEG PIPE ANNULUS (ELEMENT 1) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.2-51 CONTAINMENT LOCATIONS USED IN CALCULATION OF DIFFERENTIAL PRESSURE ACROSS STEAM GENERATORS FROM DEHL BREAK UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.2-52 DIFFERENTIAL PRESSURE ACROSS STEAM GENERATOR (BETWEEN COMPARTMENTS 3 AND 2) RESULTING FROM A DEHL BREAK IN COMPARTMENT 3. UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.3-1 RESIDUAL HEAT REMOVAL PUMP PERFORMANCE CURVES (TYPICAL) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008FIGURE 6.3-2 CENTRIFUGAL CHARGING PUMPS 1 & 2 PERFORMANCE CURVES (TYPICAL) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 6.3-3 SAFETY INJECTION PUMP PERFORMANCE CURVES (TYPICAL) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 6.3-4 ALIGNMENT OF ECCS-RELATED COMPONENTS DURING INJECTION PHASE OF EMERGENCY CORE COOLINGUNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 20 November 2011 FIGURE 6.3-5 ALIGNMENT OF ECCS-RELATED COMPONENTS DURING RECIRCULATIONPHASE OF EMERGENCY CORE COOLINGUNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 20 November 2011 AUXILIARY FEEDWATER FLOW FOR PLANT SHUTDOWN FROM 3568 MWT WITH ALL THREE AFW PUMPS IN OPERATION (FOR INFORMATION ONLY Revision 12 September 1998FIGURE 6.5-3 (Sheet 1) AUXILIARY FEEDWATER FLOW FOR PLANT SHUTDOWN UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE AUXILIARY FEEDWATER FLOW FOR PLANT SHUTDOWN FROM 3568 MWT WITH ONLY ONE 440 GPM MOTOR-DRIVEN AFW PUMP IN OPERATION (FOR INFORMATION ONLY) FIGURE 6.5-3 (Sheet 2) AUXILIARY FEEDWATER FLOW FOR PLANT SHUTDOWN UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 20 November 2011 DCPP UNITS 1 & 2 FSAR UPDATE
APPENDIX 6.2D REANALYSIS OF LONG-TERM LOSS-OF-COOLANT ACCIDENTS AND MAIN STEAMLINE BREAK EVENTS
DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-1 Revision 20 November 2011 6.2D.1 INTRODUCTION The containment system is designed such that for all break sizes, up to and including the double-ended severance of a reactor coolant pipe or secondary system pipe, the containment peak calculated pressure is less than the containment design pressure. This appendix details the methodology for calculating the mass and energy releases and the resulting containment response subsequent to a hypothetical loss-of-coolant accident (LOCA) or a main steamline break (MSLB) with the replacement steam generators installed in DCPP Units 1 & 2.
In order to determine the impact of replacing the original Westinghouse Model 51 steam generators with Westinghouse Model Delta 54 steam generators, the LOCA and MSLB releases and the containment response were performed. The LOCA analysis resulted in showing that DCPP Unit 2 bounds both units with a peak containment pressure of 41.4 psig for the double-ended hot leg (DEHL) break. The peak pressure for the double-ended pump suction (DEPS) break was 39.8 psig. The MSLB analysis results showed that DCPP Unit 2 bounds both units with a peak containment pressure of 42.8 psig for the 1.4 ft2 double-ended rupture (DER) of the main steamline at 70 percent power and a failure of the feedwater regulator valve (FRV). The details of the analyses are presented in the following sections. 6.2D.2 MASS AND ENERGY RELEASE ANALYSIS FOR POSTULATED LOSS-OF-COOLANT ACCIDENTS The uncontrolled release of pressurized high-temperature reactor coolant, termed a LOCA, would result in release of steam and water into the containment. This, in turn, would result in increases in the local subcompartment pressures, and an increase in the global containment pressure and temperature. Therefore, there are both long- and short-term issues relative to a postulated LOCA that must be considered at the conditions for the DCPP Units 1 and 2 steam generator replacement project at the core power of 3411 MWt.
The long-term LOCA mass and energy releases are analyzed to approximately 107 seconds and are utilized as input to the containment integrity analysis. The containment integrity analysis demonstrates the acceptability of the containment safeguards systems to mitigate the consequences of a hypothetical large-break LOCA. The containment safeguards systems must be capable of limiting the peak containment pressure to less than the design pressure and to limit the temperature excursion to less than the acceptance limits. For this program, Westinghouse generated the mass and energy releases using the March 1979 model, described in WCAP-10325-P-A (Reference 1). The Nuclear Regulatory Commission (NRC) review and approval letter is included with WCAP-10325-P-A (Reference 1). Section 6.2D.2.1 discusses the long-term LOCA mass and energy releases generated for this program. The results of this analysis were provided for use in the containment integrity analysis.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-2 Revision 20 November 2011 The short-term LOCA-related mass and energy releases are used as input to the subcompartment analyses. These analyses are performed to ensure that the walls of a subcompartment can maintain their structural integrity during the short pressure pulse (generally less than 3 seconds) accompanying a high-energy line pipe rupture within that subcompartment. The subcompartments that are typically evaluated include the steam generator compartment, the reactor cavity region, and the pressurizer compartment. DCPP Units 1 and 2 are approved for leak-before-break. Any changes associated with the replacement steam generators are typically offset by the leak-before-break benefit of using the smaller reactor coolant system (RCS) nozzle breaks. This demonstrates that the current licensing bases for the subcompartments would remain bounding. The critical mass flux correlation utilized in the SATAN computer program (Reference 5) was used to conservatively estimate the impact of the changes in RCS temperatures on the short-term releases. The evaluation showed that the design basis releases would remain bounding due to leak-before-break. Section 6.2D.2.2 discusses the short-term evaluation conducted for the replacement steam generator program. 6.2D.2.1 Long-Term LOCA Mass and Energy Releases The mass and energy release rates described in this section form the basis of further computations to evaluate the containment following the postulated accident. Discussed in this section are the long-term LOCA mass and energy releases for the hypothetical double-ended pump suction (DEPS) rupture with minimum safeguards and maximum safeguards and double-ended hot-leg (DEHL) rupture break cases. These LOCA cases are used for the long-term containment integrity analyses in Section 6.2D.4.1.
6.2D.2.1.1 Input Parameters and Assumptions The mass and energy release analysis is sensitive to the assumed characteristics of various plant systems, in addition to other key modeling assumptions. Where appropriate, bounding inputs are utilized and instrumentation uncertainties are included. For example, the RCS operating temperatures are chosen to bound the highest average coolant temperature range of all operating cases and a temperature uncertainty allowance of +5.0°F is then added. Nominal parameters are used in certain instances. For example, the RCS pressure in this analysis is based on a nominal value of 2,250 psia plus an uncertainty allowance +42.0 psi. All input parameters are chosen consistent with accepted analysis methodology.
Some of the most critical items are the RCS initial conditions, core decay heat, safety injection flow, and primary and secondary metal mass and steam generator heat release modeling. Specific assumptions concerning each of these items are discussed in the following paragraphs. Tables 6.2D-1 and 6.2D-2 present key data assumed in the analysis.
The core rated power of 3479 MWt adjusted for calorimetric error (that is, 102 percent of 3411 MWt) was used in the analysis. As previously noted, RCS operating temperatures DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-3 Revision 20 November 2011 to bound the highest average coolant temperature range were used as bounding analysis conditions. The use of higher temperatures is conservative because the initial fluid energy is based on coolant temperatures that are at the maximum levels attained in steady-state operation. Additionally, an allowance to account for instrument error and dead-band is reflected in the initial RCS temperatures. The selection of 2,250 psia as the limiting pressure is considered to affect the blowdown phase results only, since this represents the initial pressure of the RCS. The RCS rapidly depressurizes from this value until the point at which it equilibrates with containment pressure.
The rate at which the RCS blows down is initially more severe at the higher RCS pressure. Additionally, the RCS has a higher fluid density at the higher pressure (assuming a constant temperature) and subsequently has a higher RCS mass available for releases. Thus, 2,250 psia plus uncertainty was selected for the initial pressure as the limiting case for the long-term mass and energy release calculations.
The selection of the fuel design features for the long-term mass and energy release calculation is based on the need to conservatively maximize the energy stored in the fuel at the beginning of the postulated accident (that is, to maximize the core stored energy). The core stored energy, that was selected to bound the 17x17 fuel product to be used at DCPP Units 1 and 2, was 3.50 full-power seconds (FPS). The margins in the core stored energy include a statistical uncertainty in order to address the thermal fuel model and associated manufacturing uncertainties and the time in the fuel cycle for maximum fuel densification. Thus, the analysis very conservatively accounts for the stored energy in the core.
A margin in the RCS volume of 3 percent (which is composed of a 1.6-percent allowance for thermal expansion and a1.4-percent allowance for uncertainty) was modeled.
A uniform steam generator tube plugging level of 0 percent was modeled. This assumption maximizes the reactor coolant volume and fluid release by virtue of consideration of the RCS fluid in all steam generator tubes. During the post-blowdown period, the steam generators are active heat sources since significant energy remains in the secondary metal and secondary mass that has the potential to be transferred to the primary side. The 0-percent tube plugging assumption maximizes the heat transfer area and, therefore, the transfer of secondary heat across the steam generator tubes. Additionally, this assumption reduces the reactor coolant loop resistance, which reduces the P upstream of the break for the pump suction breaks and increases break flow. Thus, the analysis conservatively accounts for the level of steam generator tube plugging.
The secondary-to-primary heat transfer is maximized by assuming conservative heat transfer coefficients. This conservative energy transfer is ensured by maximizing the initial internal energy of the inventory in the steam generator secondary side. This internal energy is based on full-power operation plus uncertainties.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-4 Revision 20 November 2011 Regarding safety injection flow, the mass and energy release calculation considered configurations/failures to conservatively bound respective alignments. The limiting case is the failure of a train of the solid state protection system (SSPS). This configuration/failure would credit minimum flow from one centrifugal charging pump (CCP1 or CCP2), one safety injection (SI) pump, and one residual heat removal (RHR) pump (see Table 6.2D-2). In addition, the containment backpressure is assumed to be equal to the containment design pressure. This assumption was shown in WCAP-10325-P-A (Reference 1) to be conservative for the generation of mass and energy releases.
In summary, the following assumptions were employed to ensure that the mass and energy releases are conservatively calculated, thereby maximizing energy release to containment:
- Maximum expected operating temperature of the RCS (100-percent full-power conditions)
- Allowance for RCS temperature uncertainty (+5.0°F )
- Margin in RCS volume of 3 percent (which is composed of 1.6-percent allowance for thermal expansion and 1.4-percent allowance for uncertainty)
- Core rated power of 3411 MWt
- Allowance for calorimetric error (+2.0 percent of power)
- Conservative heat transfer coefficients (that is, steam generator primary/secondary heat transfer, and RCS metal heat transfer)
- Allowance in core stored energy for effect of fuel densification
- A margin in core stored energy (statistical uncertainty to account for manufacturing tolerances)
- An allowance for RCS initial pressure uncertainty (+42.0 psi)
- A maximum containment backpressure equal to design pressure (47.0 psig)
- Steam generator tube plugging level (0-percent uniform) - Maximizes reactor coolant volume and fluid release - Maximizes heat transfer area across the steam generator tubes - Reduces coolant loop resistance, which reduces the P upstream of the break for the pump suction breaks and increases break flow DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-5 Revision 20 November 2011 Thus, based on the previously discussed conditions and assumptions, an analysis of DCPP Units 1 and 2 with replacement steam generators was made for the release of mass and energy from the RCS in the event of a LOCA at 3479 MWt.
6.2D.2.1.2 Description of Analyses The evaluation model used for the long-term LOCA mass and energy release calculations is the March 1979 model described in WCAP-10325-P-A (Reference 1).
This report section presents the long-term LOCA mass and energy releases generated in support of the DCPP Units 1 and 2 steam generator replacement project. These mass and energy releases are then subsequently used in the containment integrity analysis. LOCA Mass and Energy Release Phases The containment system receives mass and energy releases following a postulated rupture in the RCS. These releases continue over a time period, which, for the LOCA mass and energy analysis, is typically divided into four phases.
Blowdown - the period of time from accident initiation (when the reactor is at steady-state operation) to the time that the RCS and containment reach an equilibrium state.
Refill - the period of time when the lower plenum is being filled by accumulator and emergency core cooling system (ECCS) water. At the end of blowdown, a large amount of water remains in the cold legs, downcomer, and lower plenum. To conservatively consider the refill period for the purpose of containment mass and energy releases, it is assumed that this water is instantaneously transferred to the lower plenum along with sufficient accumulator water to completely fill the lower plenum. This allows an uninterrupted release of mass and energy to containment. Thus, the refill period is conservatively neglected in the mass and energy release calculation.
Reflood - begins when the water from the lower plenum enters the core and ends when the core is completely quenched.
Post-reflood (FROTH) - describes the period following the reflood phase. For the pump suction break, a two-phase mixture exits the core, passes through the hot legs, and is superheated in the steam generators prior to exiting the break as steam. After the broken loop steam generator cools, the break flow becomes two phase. 6.2D.2.1.3 Computer Codes The WCAP-10325-P-A (Reference 1) mass and energy release evaluation model is comprised of mass and energy release versions of the following codes: SATAN VI, WREFLOOD, FROTH, and EPITOME. These codes were used to calculate the DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-6 Revision 20 November 2011 long-term LOCA mass and energy releases for the DCPP Units 1 and 2 steam generator replacement project.
SATAN VI calculates blowdown, the first portion of the thermal-hydraulic transient following break initiation, including pressure, enthalpy, density, mass and energy flow rates, and energy transfer between primary and secondary systems as a function of time.
The WREFLOOD code addresses the portion of the LOCA transient where the core reflooding phase occurs after the primary coolant system has depressurized (blowdown) due to the loss of water through the break and when water supplied by the ECCS refills the reactor vessel and provides cooling to the core. The most important feature of WREFLOOD is the steam/water mixing model (see Section 6.2D.2.1.8).
FROTH models the post-reflood portion of the transient. The FROTH code is used for the steam generator heat addition calculation from the broken and intact loop steam generators.
EPITOME continues the FROTH post-reflood portion of the transient from the time at which the secondary equilibrates to containment design pressure to the end of the transient. It also compiles a summary of data on the entire transient, including formal instantaneous mass and energy release tables and mass and energy balance tables with data at critical times. 6.2D.2.1.4 Break Size and Location Generic studies have been performed with respect to the effect of postulated break size on the LOCA mass and energy releases. The double-ended guillotine break has been found to be limiting due to larger mass flow rates during the blowdown phase of the transient. During the reflood and FROTH phases, the break size has little effect on the releases.
Three distinct locations in the RCS loop can be postulated for a pipe rupture for mass and energy release purposes:
- Hot leg (between vessel and steam generator)
- Cold leg (between pump and vessel)
- Pump suction (between steam generator and pump)
The break locations analyzed for this program are the double-ended pump suction (DEPS) rupture with a total break area of (10.46 ft2) and the double-ended hot leg (DEHL) rupture with a total break area of (9.17 ft2). Break mass and energy releases have been calculated for the blowdown, reflood, and post-reflood phases of the LOCA for the DEPS cases. For the DEHL case, the releases were calculated only for the blowdown. The following information provides a discussion on each break location. DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-7 Revision 20 November 2011 The DEHL rupture has been shown in previous studies to result in the highest blowdown mass and energy release rates. Although the core flooding rate would be the highest for this break location, the amount of energy released from the steam generator secondary is minimal because the majority of the fluid that exits the core vents directly to containment bypassing the steam generators. As a result, the reflood mass and energy releases are reduced significantly as compared to either the pump suction or cold-leg break locations where the core exit mixture must pass through the steam generators before venting through the break. For the hot-leg break, generic studies have confirmed that there is no reflood peak (that is, from the end of the blowdown period the containment pressure would continually decrease). Therefore, only the mass and energy releases for the hot-leg break blowdown phase are calculated and presented in this section of the report.
The cold-leg break location has also been found in previous studies to be much less limiting in terms of the overall containment energy releases. The cold-leg blowdown is faster than that of the pump suction break, and more mass is released into the containment. However, the core heat transfer is greatly reduced, and this results in a considerably lower energy release into containment. Studies have determined that the blowdown transient for the cold leg is, in general, less limiting than that for the pump suction break. During reflood, the flooding rate is greatly reduced and the energy release rate into the containment is reduced. Therefore, the cold-leg break is bounded by other breaks and no further evaluation is necessary.
The pump suction break combines the effects of the relatively high-core flooding rate, as in the hot-leg break, and the addition of the stored energy in the steam generators. As a result, the pump suction break yields the highest energy flow rates during the post-blowdown period by including all of the available energy of the RCS in calculating the releases to containment. Thus, only the DEHL and DEPS cases are used to analyze long-term LOCA containment integrity. 6.2D.2.1.5 Application of Single-Failure Criterion An analysis of the effects of the single-failure criterion has been performed on the mass and energy release rates for each break analyzed. An inherent assumption in the generation of the mass and energy release is that offsite power is lost. This results in the actuation of the emergency diesel generators, required to power the safety injection system. This is not an issue for the blowdown period, which is limited by the DEHL break.
Two cases have been analyzed to assess the effects of a single failure. The first case assumes minimum safeguards safety injection (SI) flow based on the postulated single failure of a train of the solid state protection system. This results in the loss of one train of safeguards equipment. The other case assumes maximum safeguards SI flow based on no postulated failures that would impact the amount of ECCS flow. The analysis of the cases described provides confidence that the effect of credible single failures is bounded. DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-8 Revision 20 November 2011 6.2D.2.1.6 Acceptance Criteria for Analyses A large-break LOCA accident is classified as an American Nuclear Society (ANS) Condition IV event, an infrequent fault. To satisfy the NRC acceptance criteria presented in the Standard Review Plan, Section 6.2.1.3 (Reference 2), the relevant requirements are the following:
- 10 CFR 50, Appendix A
- 10 CFR 50, Appendix K, paragraph I.A To meet these requirements, the following must be addressed:
- Sources of energy
- Break size and location
- Calculation of each phase of the accident
- Mass and energy release data The mass and energy releases for the DCPP Unit 2 cases are shown in Tables 6.2D-3 through 6.2D-9. 6.2D.2.1.7 Blowdown Mass and Energy Release Data The SATAN-VI code is used for computing the blowdown transient. The code utilizes the control volume (element) approach with the capability for modeling a large variety of thermal fluid system configurations. The fluid properties are considered uniform and thermo-dynamic equilibrium is assumed in each element. A point kinetics model is used with weighted feedback effects. The major feedback effects include moderator density, moderator temperature, and Doppler broadening. A critical flow calculation for subcooled (modified Zaloudek), two-phase (Moody), or superheated break flow is incorporated into the analysis. The methodology for the use of this model is described in WCAP-10325-P-A (Reference 1).
Table 6.2D-3 presents the calculated mass and energy release for the blowdown phase of the DEHL break without any pumped safety injection for DCPP Unit 2. For the hot leg break mass and energy release tables, break path 1 refers to the mass and energy exiting from the reactor-vessel side of the break; break path 2 refers to the mass and energy exiting from the steam-generator side of the break. Tables 6.2D-4 and 6.2D-5 present the mass and energy balance data for the Unit 2 DEHL case.
Table 6.2D-6 presents the calculated mass and energy releases for the blowdown phase of the DEPS break. For the pump suction breaks, break path 1 in the mass and energy release tables refers to the mass and energy exiting from the steam-generator side of the break. Break path 2 refers to the mass and energy exiting from the pump-side of the break.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-9 Revision 20 November 2011 6.2D.2.1.8 Reflood Mass and Energy Release Data The WREFLOOD code is used for computing the reflood transient. The WREFLOOD code consists of two basic hydraulic models: one for the contents of the reactor vessel and one for the coolant loops. The two models are coupled through the interchange of the boundary conditions applied at the vessel outlet nozzles and at the top of the downcomer. Additional transient phenomena such as pumped SI and accumulators, reactor coolant pump performance, and steam generator release are included as auxiliary equations that interact with the basic models as required. The WREFLOOD code permits the capability to calculate variations during the core reflooding transient of basic parameters such as core flooding rate, core and downcomer water levels, fluid thermo-dynamic conditions (pressure, enthalpy, density) throughout the primary system, and mass flow rates through the primary system. The code permits hydraulic modeling of the two flow paths available for discharging steam and entrained water from the core to the break, that is, the path through the broken loop and the path through the unbroken loops.
A complete thermal equilibrium mixing condition for the steam and ECCS injection water during the reflood phase has been assumed for each loop receiving ECCS water. This is consistent with the usage and application of the WCAP-10325-P-A (Reference 1) mass and energy release evaluation model in recent analyses, for example, D. C. Cook Docket 50-315 (Reference 3). Even though the WCAP-10325-P-A (Reference 1) model credits steam/water mixing only in the intact loop and not in the broken loop, the justification, applicability, and NRC approval for using the mixing model in the broken loop has been documented (Reference 3). Moreover, this assumption is supported by test data and is further discussed below. The model assumes a complete mixing condition (that is, thermal equilibrium) for the steam/water interaction. The complete mixing process, however, is made up of two distinct physical processes. The first is a two-phase interaction with condensation of steam by cold ECCS water. The second is a single-phase mixing of condensate and ECCS water. Since the steam release is the most important influence to the containment pressure transient, the steam condensation part of the mixing process is the only part that need be considered. (Any spillage directly heats only the sump.)
The most applicable steam/water mixing test data have been reviewed for validation of the containment integrity reflood steam/water mixing model. This data was generated in 1/3-scale tests (Reference 4), which are the largest scale data available and thus most clearly simulates the flow regimes and gravitational effects that would occur in a pressurized water reactor (PWR). These tests were designed specifically to study the steam/water interaction for PWR reflood conditions.
A group of 1/3-scale tests corresponds directly to containment integrity reflood conditions. The injection flow rates for this group cover all phases and mixing conditions calculated during the reflood transient. The data from these tests were reviewed and discussed in detail in WCAP-10325-P-A (Reference 1). For all of these DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-10 Revision 20 November 2011 tests, the data clearly indicate the occurrence of very effective mixing with rapid steam condensation. The mixing model used in the containment integrity reflood calculation is, therefore, wholly supported by the 1/3-scale steam/water mixing data.
Additionally, the following justification is also noted. The post-blowdown limiting break for the containment integrity peak pressure analysis is the pump suction double-ended rupture break. For this break, there are two flow paths available in the RCS by which mass and energy may be released to containment. One is through the outlet of the steam generator, the other via reverse flow through the reactor coolant pump. Steam that is not condensed by ECCS injection in the intact RCS loops passes around the downcomer and through the broken loop cold leg and pump in venting to containment. This steam also encounters ECCS injection water as it passes through the broken loop cold leg, complete mixing occurs and a portion of it is condensed. It is this portion of steam that is condensed that is taken credit for in this analysis. This assumption is justified based upon the postulated break location, and the actual physical presence of the ECCS injection nozzle. A description of the test and test results are contained in WCAP-10325-P-A (Reference 1) and operating license Amendment No. 126 for D.C. Cook (Reference 3).
Table 6.2D-7 presents the calculated mass and energy releases for the reflood phase of the pump suction double-ended rupture with a single failure of a train of the solid state protection system (SSPS) for DCPP Unit 2. The principal parameters during reflood are given in Table 6.2D-8 for the bounding DEPS case. 6.2D.2.1.9 Post-Reflood Mass and Energy Release Data The FROTH code (Reference 5) is used for computing the post-reflood transient. The FROTH code calculates the heat release rates resulting from a two-phase mixture present in the steam generator tubes. The mass and energy releases that occur during this phase are typically superheated due to the depressurization and equilibration of the broken loop and intact loop steam generators. During this phase of the transient, the RCS has equilibrated with the containment pressure. However, the steam generators contain a secondary inventory at an enthalpy that is much higher than the primary side. Therefore, there is a significant amount of reverse heat transfer that occurs. Steam is produced in the core due to core decay heat. For a pump suction break, a two-phase fluid exits the core, flows through the hot legs, and becomes superheated as it passes through the steam generator (Reference 6). Once the broken loop cools, the break flow becomes two phase. During the FROTH calculation, ECCS injection is addressed for both the injection phase and the recirculation phase. The FROTH code calculation stops when the secondary side equilibrates to the saturation temperature (Tsat) at the containment design pressure; after this point the EPITOME code completes the steam generator depressurization (see Sections 6.2D.2.1.8 and 6.2D.2.1.11 for additional information).
The methodology for the use of this model is described in WCAP-10325-P-A (Reference 1). The mass and energy release rates are calculated by FROTH and DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-11 Revision 20 November 2011 EPITOME until the time of containment depressurization. After containment depressurization (14.7 psia), the mass and energy release available to containment is generated directly from core boil-off/decay heat.
Table 6.2D-9 presents the two-phase post-reflood mass and energy release data for the pump suction double-ended break case with a single failure of a train of the SSPS. 6.2D.2.1.10 Decay Heat Model ANS Standard 5.1 (Reference 7) was used in the LOCA mass and energy release model for DCPP Units 1 and 2 for the determination of decay heat energy. This standard was balloted by the Nuclear Power Plant Standards Committee in October 1978 and subsequently approved. The official standard (Reference 7) was issued in August 1979. Table 6.2D-10 lists the decay heat generation rate used in the DCPP steam generator replacement project mass and energy release analysis.
Significant assumptions in the decay heat generation rate for use in the LOCA mass and energy releases analysis include the following:
- The decay heat sources considered are fission product decay and heavy element decay of U-239 and Np-239.
- The decay heat power from fissioning isotopes other than U-235 is assumed to be identical to that of U-235.
- The fission rate is constant over the operating history of maximum power level.
- The factor accounting for neutron capture in fission products has been taken from Equation 11 of Reference 7 up to 10,000 seconds and from Table 10 of Reference 7 beyond 10,000 seconds.
- The fuel has been assumed to be at full power for 108 seconds.
- The number of atoms of U-239 produced per second has been assumed to be equal to 70 percent of the fission rate.
- The total recoverable energy associated with one fission has been assumed to be 200 MeV/fission.
- An uncertainty of two sigma (two times the standard deviation) has been applied to the fission product decay.
Based upon NRC staff review, (Safety Evaluation Report [SER] of the March 1979 evaluation model [Reference 1]), use of the ANS Standard-5.1, November 1979 decay DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-12 Revision 20 November 2011 heat model was approved for the calculation of mass and energy releases to the containment following a LOCA. 6.2D.2.1.11 Steam Generator Equilibration and Depressurization Steam generator equilibration and depressurization is the process by which secondary-side energy is removed from the steam generators in stages. The FROTH computer code calculates the heat removal from the secondary mass until the secondary temperature is the Tsat at the containment design pressure. After the FROTH calculations, the EPITOME code continues the FROTH calculation for steam generator cooldown removing steam generator secondary energy at different rates (that is, first-and second-stage rates). The first-stage rate is applied until the steam generator reaches Tsat at the user-specified intermediate equilibration pressure, when the secondary pressure is assumed to reach the actual containment pressure. Then the second-stage rate is used until the final depressurization, when the secondary reaches the reference temperature of Tsat at 14.7 psia, or 212°F. The heat removal of the broken loop and intact loop steam generators are calculated separately.
During the FROTH calculations, steam generator heat removal rates are calculated using the secondary side temperature, primary side temperature, and a secondary side heat transfer coefficient determined using a modified McAdam's correlation. Steam generator energy is removed during the FROTH transient until the secondary side temperature reaches Tsat at the containment design pressure. The constant heat removal rate used during the first heat removal stage is based on the final heat removal rate calculated by FROTH. The steam generator energy available to be released during the first stage interval is determined by calculating the difference in secondary energy available at the containment design pressure and that at the (lower) user-specified intermediate equilibration pressure, assuming saturated conditions. This energy is then divided by the first-stage energy removal rate, resulting in an intermediate equilibration time. At this time, the rate of energy release drops substantially to the second-stage rate. The second-stage rate is determined as the fraction of the difference in secondary energy available between the intermediate equilibration and final depressurization at 212°F, and the time difference from the time of the intermediate equilibration to the user-specified time of the final depressurization at 212°F. With current methodology, all of the secondary energy remaining after the intermediate equilibration is conservatively assumed to be released by imposing a mandatory cooldown and subsequent depressurization down to atmospheric pressure at 3,600 seconds, that is, 14.7 psia and 212°F (the mass and energy balance tables have this point labeled as "Available Energy"). 6.2D.1.12 Sources of Mass and Energy The sources of mass considered in the LOCA mass and energy release analysis are given in Table 6.2D-4 for the DEHL breaks for Diablo Canyon Unit 2. The sources of mass for the DEPS break case with the SSPS failure for Diablo Canyon Unit 2 are given in Table 6.2D-11. These sources are the RCS, accumulators, and pumped SI. DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-13 Revision 20 November 2011 The energy inventory considered in the DEHL breaks for DCPP Unit 2 is given in Table 6.2D-5. The energy inventory for the DEPS break mass and energy release analysis for Diablo Canyon Unit 2 is given in Table 6.2D-12. The energy sources are as follows:
- RCS water
- Accumulator water (all inject)
- Pumped SI water
- Decay heat
- Core-stored energy
- RCS metal (includes steam generator tubes)
- Steam generator metal (includes transition cone, shell, wrapper, and other internals)
- Steam generator secondary energy (includes fluid mass and steam mass)
- Secondary transfer of energy (feedwater into and steam out of the steam generator secondary)
The analysis used the following energy reference points: Available energy: 212°F; 14.7 psia (energy available that could be released) Total energy content: 32°F; 14.7 psia (total internal energy of the RCS)
The mass and energy inventories are presented at the following times, as appropriate:
- Time zero (initial conditions)
- End of blowdown time
- End of refill time
- End of reflood time
- Time of broken loop steam generator equilibration to pressure setpoint
- Time of intact loop steam generator equilibration to pressure setpoint
- Time of full depressurization (3,600 seconds) The energy release from the metal-water reaction rate is considered as part of the WCAP-10325-P-A (Reference 1) methodology. Based on the way that the energy in the fuel is conservatively released to the vessel fluid, the fuel cladding temperature does not increase to the point where the metal-water reaction is significant. This is in contrast to the 10 CFR 50.46 analyses, which are biased to calculate high fuel rod cladding temperatures and, therefore, a significant metal-water reaction. For the LOCA mass and energy release calculation, the energy created by the metal-water reaction value is small and is not explicitly provided in the energy balance tables. The energy that is determined is part of the mass and energy releases and is therefore already included in the overall mass and energy releases for the Diablo Canyon units.
The sequence of events for the LOCA transients is shown in Tables 6.2D-13 through 6.2D-15.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-14 Revision 20 November 2011 6.2D.2.1.13 Conclusions The consideration of the various energy sources in the long-term mass and energy release analysis provides assurance that all available sources of energy have been included in this analysis. Thus, the review guidelines presented in SRP Section 6.2.1.3 have been satisfied. The results of this analysis were provided for use in the containment integrity analysis in Section 6.2D.4. 6.2D.2.2 Short-Term LOCA Mass and Energy Releases The uncontrolled release of pressurized high-temperature reactor coolant, termed a LOCA, would result in release of steam and water into the containment. This, in turn, would result in increases in the local subcompartment pressures, and an increase in the global containment pressure and temperature. Therefore, there are both long- and short-term issues relative to a postulated LOCA that must be considered for the DCPP Units 1 and 2 steam generator replacement project at a core power of 3411 MWt. 6.2D.2.2.1 Accident Description The short-term LOCA-related mass and energy releases are used as input to the subcompartment analyses. These analyses are performed to ensure that the walls of a subcompartment can maintain their structural integrity during the short pressure pulse (generally less than 3 seconds) accompanying a high-energy line pipe rupture within that subcompartment. The subcompartments that are typically evaluated include the steam generator compartment, the reactor cavity region, and the pressurizer compartment. The magnitude of the pressure differential across the walls is a function of several parameters, which include the blowdown mass and energy release rates, the subcompartment volume, vent areas, and vent flow behavior. The blowdown mass and energy release rates are affected by the initial RCS temperature conditions.
DCPP Units 1 and 2 are approved for leak-before-break. Any changes associated with the replacement steam generators are typically offset by the leak-before-break benefit of using the smaller RCS nozzle breaks. This demonstrates that the current licensing bases for the subcompartments would remain bounding for breaks postulated in the large, primary loop piping. Leak-before-break does not cover the double-ended pressurizer spray line break so that specific break must be evaluated for the replacement steam generator conditions.
The critical mass flux correlation utilized in the SATAN computer program (Reference 5) was used to conservatively estimate the impact of the changes in RCS temperatures on the short-term releases. The evaluation showed that the replacement steam generator program would result in a more conservative set of initial conditions for the short-term pressurizer spray line break. The following sections discuss the short-term evaluation conducted for this program. DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-15 Revision 20 November 2011 6.2D.2.2.2 Input Parameters and Assumptions The short-term releases are linked directly to the critical mass flux, which increases with decreasing temperatures. The increase in mass flux is created by an increase in the differential pressure between the reservoir pressure and the saturation pressure at the RCS operating conditions. The critical mass flux is the maximum break flow per cross-sectional flow area based on a reservoir pressure and saturation temperature. The short-term LOCA releases would be expected to increase due to any reductions in RCS coolant temperature conditions.
It is noted that any changes in initial RCS volume and steam generator liquid/steam mass and volume from the proposed parameters for the DCPP Units 1 and 2 replacement steam generator program have no effect on the releases because of the short duration of the postulated accident. The only change that needs to be addressed for this short term LOCA mass and energy release evaluation is the impact of the DCPP Units 1 and 2 replacement steam generator program on the RCS coolant temperatures.
The comparison of the RCS operating conditions for the lower portion of the RCS average temperature (Tavg) coastdown prior to a shutdown and the current licensed parameters showed that the cold leg temperature for the replacement steam generator program is lower than the current design basis analysis conditions. Short term releases are controlled by density effects, so the lower temperatures from the DCPP Unit 1 replacement steam generator program operating conditions are more limiting. The comparison of the cold leg temperature for the replacement steam generator program and the current design basis parameters is shown in Table 6.2D-16.
6.2D.2.2.3 Description of Model Short term blowdown transients are characterized by a peak mass and energy release rate that occurs during a subcooled condition, thus the Zaloudek correlation (Reference 5), which models this condition, is currently used in the short term LOCA mass and energy release analyses with the SATAN computer program. This correlation appears in the critical flow routine of SATAN (Reference 5) and it can be used to conservatively evaluate the impact of the changes in RCS temperature conditions due to the steam generator replacement project on the short term releases from the current design basis conditions for DCPP Units 1 and 2. This is accomplished by maximizing the reservoir pressure and minimizing the RCS inlet and outlet temperatures (which maximizes Gcrit). Using a lower temperature results in a lower Psat and a higher Gcrit. Since this maximizes the change in short-term LOCA mass and energy releases, data representative of the lowest inlet temperature with uncertainty subtracted is used for the evaluation for the spray line break.
The result of the comparison of the critical mass flux shows that the short-term spray line releases for the DCPP Unit 1 would increase by 4.6 percent for the replacement steam generator program when a temperature coastdown is also considered. The investigation of the current design basis double-ended spray line break mass and DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-16 Revision 20 November 2011 energy releases also revealed that the as-built pressurizer spray line is a 4 inch, schedule 120 pipe and the analysis modeled a 4 inch, schedule 160 pipe. This is a non-conservative break flow area of 11 percent. The total increase in the releases would be 15.6 percent. This increase can be partially offset for the temperature coastdown scenario by modeling the resistance of the spray line piping. When the spray line piping is included, the mass releases decrease by 13.8 percent. The overall effect of a temperature coastdown would result in a 1.8 percent increase in the mass releases for the pressurizer spray line break. The results in FSAR Update Table 6.2-24 show that the pressurizer enclosure walls have a design pressure of 4.0 psi and the current peak differential pressure is 2.5 psi. This is 37.5 percent margin to the design value for the walls. An increase of 1.8 percent in the releases would result in an increase in the peak differential pressure of 0.10 psid for a total peak differential pressure of 2.6 psid. 6.2D.2.2.4 Results The short-term LOCA-related analyses that are discussed in FSAR Update Section 6.2.1.3.6 have been reviewed to assess the effects associated with the steam generator replacement project. Based on the application of leak-before-break methods, the current design basis analysis results remain bounding for the double-ended primary loop piping breaks. The current design basis results for the double-ended rupture of the pressurizer spray line would increase by 1.8 percent in the peak differential pressure of the pressurizer compartment walls from 2.5 psid to 2.6 psid which remains less than the design pressure difference of 4.0 psid. 6.2D.3 STEAMLINE BREAK MASS AND ENERGY RELEASE INSIDE CONTAINMENT 6.2D.3.1 Introduction and Background Steamline ruptures occurring inside a reactor containment structure may result in significant releases of high-energy fluid to the containment environment that could produce high pressure conditions for extended periods of time. The magnitude of the releases following a steamline rupture is dependent upon the plant initial operating conditions and the size of the rupture as well as the configuration of the plant steam system and the containment design. There are competing effects and credible single failures in the postulated accident scenario used to determine the worst cases for containment pressure and the associated containment temperature following a steamline break.
The DCPP steamline break and containment response analysis for the replacement steam generator program considers a spectrum of cases that vary the initial power condition, break size, and the postulated single failure. DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-17 Revision 20 November 2011 6.2D.3.2 Input Parameters and Assumptions Major assumptions affecting the mass and energy releases to containment are summarized below:
Initial Steam Generator Inventory A high initial steam generator mass is assumed. The initial level corresponds to 75 percent narrow range span (NRS) at all power levels. This consists of a nominal level of 65 percent NRS plus a steam generator water level control uncertainty of 10 percent NRS.
Main Feedwater System The rapid depressurization that occurs following a steamline break typically results in large amounts of water being added to the steam generators through the main feedwater system. A rapid-closing main feedwater regulating valve (FRV) near each steam generator limits this effect. The feedwater addition to the faulted steam generator is maximized to be conservative since it increases the water mass inventory that will be converted to steam and released from the break.
Following the initiation of the steamline break, main feedwater flow is conservatively modeled by assuming that sufficient feedwater flow is provided to match or exceed the steam flow prior to reactor trip. The initial increase in feedwater flow is in response to the FRV opening in response to the steam flow/feedwater flow mismatch and the lower backpressure on the feedwater pump as a result of the depressurizing steam generator. This maximizes the total mass addition prior to feedwater isolation. The feedwater isolation response time, following the SI signal, is assumed to be a total of 9 seconds, accounting for delays associated with signal processing plus the valve stroke time.
The feedwater in the unisolable feedline between the FRV and faulted steam generator is also considered in the analysis. The hot main feedwater reaches saturated conditions as the steam generator and feedline depressurize. The decrease in density as flashing occurs causes most of the unisolable feedwater to enter the faulted steam generator. This unisolable feedwater line volume of 208 ft3 is an additional source of fluid that can increase the mass discharged out of the break.
Some cases postulate the FRV on the faulted loop failing open. See Section 6.2D.3.3 for information on the effects of this single failure.
Auxiliary Feedwater Within the first minute following a steamline break, an SI signal is generated. Immediately upon receipt of the SI signal, auxiliary feedwater (AFW) is initiated. Addition of AFW to the faulted steam generator will increase the secondary mass available for release to the containment. The AFW flowrate to the faulted steam DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-18 Revision 20 November 2011 generator is maximized based on flow from both motor-driven AFW pumps and the turbine-driven AFW pump. The AFW flowrate is modeled as a function of steam generator pressure, varying from 569 gpm to 1588 gpm to the faulted steam generator.
Operator action is credited to terminate the AFW flow to the faulted steam generator after 10 minutes.
Unisolable Steamline The initial steam in the steamline between the break and the main steamline isolation valve (MSIV) and check valve (CV) is included in the mass and energy released from the break. The MSIV/CV is considered a single plant component and is credited to prevent reverse flow from the steamline header and intact steam generators for most cases. Cases that postulate the failure of the MSIV/CV are discussed in Section 6.2D.3.3.
Quality of the Break Effluent The quality of the break effluent is assumed to be 1.0, corresponding to saturated steam that is all vapor with no liquid. Although it is expected that there would be a significant quantity of liquid in the break effluent for a full double-ended rupture, the all-vapor assumption conservatively maximizes the energy addition to the containment atmosphere.
Reactor Coolant System Assumptions While the mass and energy released from the break is determined from assumptions that have been discussed above, the rate at which the release occurs is largely controlled by the conditions in the RCS. The major features of the primary side analysis model are summarized below:
- Continued operation of the reactor coolant pumps maintains a high heat transfer rate to the steam generators.
- The model includes consideration of the heat that is stored in the RCS metal.
- Reverse heat transfer from the intact steam generators to the RCS is modeled as the temperature in the RCS falls below the intact steam generator fluid temperature.
- Minimum flowrates are modeled from ECCS injection to conservatively minimize the amount of boron that provides negative reactivity feedback. Both the high-head and intermediate-head SI systems are considered available, with unborated purge volumes of 75.9 ft3 and 19.4 ft3, DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-19 Revision 20 November 2011 respectively. A failure of one train of ECCS is included for cases that also model a failure on a containment safeguards train (see Section 6.2D.3.3).
- The assumed NSSS power is 3425 MWt, which includes a maximum pump heat of 20 MWt.
- RCS average temperature is the full-power nominal value of 577.3°F (Unit 1) or 577.6°F (Unit 2) plus an uncertainty of +5.0°F.
- Core residual heat generation is assumed based on the 1979 ANS decay heat plus 2 model (Reference 7).
- Conservative core reactivity coefficients (e.g. moderator temperature) corresponding to end-of-cycle conditions with the most reactive rod stuck out of the core are assumed. This maximizes the reactivity feedback effects as the RCS cools down as a result of the steamline break.
- All cases have credited a minimum shutdown margin of 1.6 percent k.
6.2D.3.3 Description of Analyses The Westinghouse steamline break mass and energy release methodology was approved by the NRC (Reference 8) and is documented in WCAP-8822, "Mass and Energy Releases Following a Steam Line Rupture" (Reference 9). WCAP-8822 forms the basis for the assumptions used in the calculation of the mass and energy releases resulting from a steamline rupture. WCAP-8822 used MARVEL as the mass/energy release system code. This was subsequently replaced by LOFTRAN (References 10 and 11), which was used in the previous DCPP licensing-basis analysis. However, the analysis documented herein uses the RETRAN code, which is documented in WCAP-14882-P-A, "RETRAN-02 Modeling and Qualification for Westinghouse Pressurized Water Reactor Non-LOCA Safety Analyses" (Reference 12).
The following limitations in the NRC SER for WCAP-14882-P-A have been adhered to in the use of RETRAN to analyze this event.
- The break flow model is the Moody model.
- Only steam (dry vapor) will exit the break, since perfect steam separation in the steam generators is assumed.
- The superheat in the steam released to the containment is not evaluated. Any superheated conditions will be reset to be equal to the saturation temperature.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-20 Revision 20 November 2011 Case Definitions and Single Failures There are many factors that influence the quantity and rate of the mass and energy release from the steamline. To encompass these factors, a spectrum of cases varies the initial power level, break size and the single failure. This section summarizes the basis of the cases that have been defined for DCPP.
The power level at which the plant is operating when the steamline break is postulated can cause different competing effects that make it difficult to pre-determine a single limiting case. For example, at higher power levels there is less initial water/steam in the steam generator, which is a benefit. However, at a higher power level there is a higher initial feedwater flowrate, higher feedwater temperature, higher decay heat, and there is a higher rate of heat transfer from the primary side, which are all penalties. Therefore, cases consider initial power levels varying from full power to zero power. The specific initial power levels that are analyzed are 100, 70, 30 and 0 percent, as presented in WCAP-8822. A calorimetric uncertainty of 2 percent is applied to the initial condition for the full power case.
Most cases consider the largest possible break, a double-ended rupture immediately downstream of the flow restrictor at the outlet of the steam generator. This break conservatively bounds the plant response to a smaller break size. The effective forward break area is limited by the 1.4 ft2 cross-sectional area of the flow restrictor that is integral to the replacement steam generator. The actual break area is the cross-sectional area of the pipe, which is 3.67 ft2. A few cases also consider the effects of a smaller, split break which allows contributing steam from the steamline header and the intact steam generators until the intact loop MSIVs close. This break size is defined to be the largest break that does not generate a low steamline pressure signal. Instead, split breaks have to rely on high containment pressure signals to actuate SI (and reactor trip, feedline isolation, etc.) and steamline isolation. The split break is only considered when the faulted loop MSIV/CV is postulated as the single failure. The split breaks have the penalty of a higher integrated mass and energy released to the containment, but the smaller break size provides a beneficial reduction in the rate that the mass and energy is released.
Several single failures can be postulated that would impair the performance of various steamline break protection systems. The single failures either reduce the heat removal capacity of the containment safeguards systems or increase the energy release from the steamline break. The single failures that have been postulated for DCPP are summarized below. The analysis cases separately consider each single failure at each initial power level.
(1) Containment Safeguards Failure This is a failure of one safeguards train. The main impact is on the containment response analysis, where the active heat removal is reduced by the loss of one DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-21 Revision 20 November 2011 train of fan coolers and one containment spray pump. This failure also causes the loss of one train of ECCS in the steamline break mass and energy release analysis. (2) FRV Failure The FRV is a fast-closing (7 second stroke time) valve in the feedwater system that is the preferred (fastest) method for terminating feedwater addition to the faulted steam generator during a steamline break. If the FRV on the faulted loop fails open, the back-up main feedwater isolation valve (MFIV) is credited to close 64 seconds after an SI setpoint is reached. The slower closure time creates the possibility of additional pumped feedwater entering the faulted steam generator. Although the main feedwater pumps trip on an SI signal, the condensate pumps do not trip and can continue to provide pumped flow when the faulted steam generator depressurizes below approximately 625 psia. (3) MSIV/CV Failure The MSIV/CV is considered a single plant component that is credited to function when another single failure is postulated. When the MSIV/CV is postulated as the single failure, this means the failure of both the forward flow isolating function (MSIV) and the reverse flow isolation function (CV) on the faulted loop. Therefore the steamline blowdown initially includes steam mass from the steamline header and intact steam generators. Isolation of the break occurs due to the closure of the MSIVs on the intact steam generators. Protection Logic and Setpoints The pertinent signals and setpoints that are actuated in these analyses are summarized below.
The first SI signal is generated by a low steamline pressure signal in all double-ended rupture cases. The assumed setpoint is 458.7 psia (DCPP low steamline pressure setpoint is 600 psig), with a lead/lag of 50/5. For split rupture cases, the first SI signal that is credited comes from the hi-1 containment pressure setpoint (5.0 psig) (DCPP containment High pressure setpoint is 3 psig). The SI signal is credited to cause:
- Start of SI pumps
- Reactor trip
- Start of auxiliary feedwater pumps
- Closure of FRVs and MFIVs
- Trip of main feedwater pumps (only credited for FRV failure cases).
DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-22 Revision 20 November 2011 Most cases isolate the steamline break to blowdown of a single steam generator by fast closure of the passive CV, which prevents reverse flow from the intact steamline. For cases that model the MSIV/CV failure on the faulted loop, the closure of the intact MSIVs are credited due to the low steamline pressure signal (for double-ended ruptures) or the hi-2 containment pressure signal (for split breaks)(DCPP containment isolation High-High pressure setpoint is 22 psig). 6.2D.3.4 Acceptance Criteria The main steamline break is classified as an American Nuclear Society (ANS) Condition IV event, an infrequent fault. The acceptance criteria associated with the steamline break event resulting in a mass and energy release inside containment is based on an analysis that provides sufficient conservatism to assure that the containment design margin is maintained. The specific criteria applicable to this analysis are related to the assumptions regarding power level, stored energy, the break flow model, main and auxiliary feedwater flow, steamline and feedwater isolation, and single failure such that containment peak pressure is maximized. The specific acceptance criteria for the containment response are discussed in Section 6.2D.4.2.4. 6.2D.3.5 Results Sixteen steamline break cases were analyzed varying the initial power level, break size and the assumed single failure. The mass and energy release from the break was calculated using the RETRAN code, while the containment pressure response was determined with the GOTHIC code (see Section 6.2D.4). The limiting containment pressure case is double-ended rupture steamline break initiated from 70 percent power with the faulted loop FRV failed open. The break flowrate is shown in Figure 6.2D-1 and the break enthalpy is shown in Figure 6.2D-2. (See Section 6.2D.4.2 for the basis of this case being the limiting transient.) Section 6.2D.4.2 also contains the sequence of events for this case, including primary, secondary, and containment system actuations.
A sensitivity analysis was performed to consider the effects of the plant response for Unit 1 versus Unit 2. It was determined that the plant response to this event is essentially the same for either unit. The steamline break analysis results bound the plant response for either Unit 1 or Unit 2. 6.2D.3.6 Conclusions The steamline break inside containment event has been analyzed with conservative assumptions to maximize the mass and energy release from the break. The mass and energy releases from this analysis are used as input to the containment integrity analysis documented in Section 6.2D.4.2. DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-23 Revision 20 November 2011 6.2D.4 CONTAINMENT INTEGRITY ANALYSIS 6.2D.4.1 Loss-of-Coolant Accident The purpose of the LOCA containment integrity analysis performed to support the DCPP replacement steam generator program is to evaluate the bounding peak pressure and temperature of a design basis LOCA event inside containment and to demonstrate the ability of the containment heat removal systems to mitigate the accident. The impact of LOCA mass and energy releases on the containment pressure and temperature are assessed to ensure that the containment pressure and temperature remain below their respective design limits. The containment heat removal systems must also be capable of maintaining the environmental qualification (EQ) parameters to within acceptable limits.
The DCPP LOCA containment response analysis considers a spectrum of cases that address differences between the individual DCPP Units, LOCA break locations, and postulated single failures (minimum and maximum safeguards). The limiting cases that address the containment peak pressure case and limiting long-term EQ temperature are presented in this section.
Calculation of the containment response following a postulated LOCA was analyzed by use of the digital computer code GOTHIC version 7.2. The GOTHIC Technical Manual (Reference 13) provides a description of the governing equations, constitutive models, and solution methods in the solver. The GOTHIC Qualifications Report (Reference 14) provides a comparison of the solver results with both analytical solutions and experimental data. The GOTHIC containment modeling for Diablo Canyon is consistent with the NRC approved Kewaunee evaluation model (Reference 15). Kewaunee and Diablo Canyon both have large dry containment designs with similar active heat removal capabilities. The latest code version is used to take advantage of the diffusion layer model heat transfer option. This heat transfer option was approved by the NRC (Reference 15) for use in Kewaunee containment analyses with the condition that the effect of mist be excluded from what was earlier termed as the mist diffusion layer model. The GOTHIC containment modeling for Diablo Canyon has followed the conditions of acceptance placed on Kewaunee. The differences in GOTHIC code versions are documented in Appendix A of the GOTHIC User Manual Release Notes (Reference 16). Version 7.2 is used consistently with the restrictions identified in Reference 15; none of the user-controlled enhancements added to version 7.2 were implemented in the Diablo Canyon containment model. A description of the Diablo Canyon GOTHIC model is provided later in this section. 6.2D.4.1.1 Input Parameters and Assumptions The major modeling input parameters and assumptions used in the DCPP LOCA containment evaluation model are identified in this section. The assumed initial DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-24 Revision 20 November 2011 conditions and input assumptions associated with the fan coolers and containment sprays are listed in Table 6.2D-17. The containment spray flow data used in the analysis are presented in Table 6.2D-18. The primary function of the residual heat removal system (RHR) is to remove heat from the core by way of the ECCS. The recirculation system and CCW system parameters are outlined in Table 6.2D-17. The containment structural heat sink input is provided in Table 6.2D-19, and the corresponding material properties are listed in Table 6.2D-20.
The LOCA containment analysis described here uses revised input and assumptions in support the DCPP replacement steam generator program, while addressing analytical conservatisms. The following summarized assumptions are areas where known differences exist between the current licensing analysis and the replacement steam generator program containment integrity analysis.
The mass and energy releases are calculated specifically for the DCPP plant conditions with replacement steam generators.
Decay heat steaming mass and energy release rates, after the end of the sensible heat release from the RCS and steam generators, are calculated each time step by GOTHIC using the transient containment pressure and recirculation safety injection water temperature.
Non-condensable accumulator gas addition is modeled in the GOTHIC model; no accumulator gas addition is considered in the FSAR Update current licensing analysis.
A recirculation system model that couples the RHR, CCW, CFCUs and auxiliary service water systems was developed for the replacement steam generator program. More detailed accounting of CCW flow rates through the containment heat removal systems was used for the CFCUs, RHR heat exchangers, and miscellaneous CCW heat loads.
The DCPP LOCA containment response analysis considered a spectrum of cases for the replacement steam generator program. The cases address break locations, and postulated single failures (minimum and maximum safeguards) for each DCPP unit. Only the limiting cases, which address the containment peak pressure and limiting long-term EQ temperature, are presented in this section. The LOCA pressure and temperature response analyses were performed assuming a loss of offsite power and a worst single failure (loss of one solid state protection system [SSPS] train, i.e., loss of one containment cooling train). The active heat removal available in the long term cooling case is:
- One containment spray pump during injection-phase only
- Two containment fan cooler units
- One RHR pump and one RHR heat exchanger DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-25 Revision 20 November 2011
- Two CCW pumps and one CCW heat exchanger
- One auxiliary service water pump.
The double-ended hot leg break produces the peak pressure at the end of the blowdown. The calculation for the DEPS case was performed for a 116 day (1x107 second) transient in support of long term EQ temperatures. The sequence of events for the DEHL containment peak pressure case is shown in Table 6.2D-13 and the DEPS long term EQ temperature case for Units 1 and 2 is shown in Tables 6.2D-14 and 6.2D-15, respectively. 6.2D.4.1.2 Acceptance Criteria The containment response for design basis LOCA containment integrity is an ANS Condition IV event, an infrequent fault. The relevant requirements to satisfy NRC acceptance criteria are as follows:
- GDC-16 and -50: In order to satisfy the requirement of GDC-16 and -50, the peak calculated containment pressure should be less than the containment design pressure of 47 psig.
- GDC-38: In order to satisfy the requirement of GDC-38, the calculated pressure at 24 hours should be less than 50 percent of the peak calculated value. (This is related to the criteria for containment leakage assumptions as affecting doses at 24 hours.) 6.2D.4.1.3 Description of Analyses and Evaluations Noding Structure The Diablo Canyon GOTHIC containment model is comprised of one control volume with separate vapor and liquid regions. Mass and energy releases, containment spray injection, and sump water recirculation are modeled using boundary conditions. A cooler component is used to model containment fan cooler units (CFCUs) heat removal.
Injection of accumulator nitrogen during the event is modeled with a boundary condition.
The component cooling water system model is comprised of three control volumes (CFCU cooling water, the hot side of the CCW system, and the cold side of the CCW system) and uses GOTHIC component models for the RHR and CCW heat exchangers. A heater component models the CFCU heat transfer to the CCW water. Boundary conditions model the CCW flow through the CFCUs, RHR heat exchangers, and miscellaneous CCW heat loads.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-26 Revision 20 November 2011 Volume Input Values for the volume, height, hydraulic diameter, and elevation are input for each node. The containment is modeled as a single control volume. The lower bound free volume is 2,550,000 ft3. The hydraulic diameter, height, and floor elevation input values are 24.1 ft, 166 ft, and 91 ft, respectively.
A conservatively calculated pool surface area is used to model interfacial heat and mass transfer to liquid pools on the various floor surfaces in the containment volume. The conductor representing the floor is essentially insulated from the vapor region after the sump pool develops; however, there can still be condensation or evaporation from the surface of the liquid pools. Using this method to model the interfacial heat and mass transfer between the pools and the atmosphere was previously approved by the NRC for the Kewaunee containment DBA and equipment qualification analyses (Reference 15).
Initial Conditions The containment initial conditions for containment integrity cases are:
- Pressure: 16.0 psia
- Relative Humidity: 18 percent
- Temperature: 120°F The LOCA containment response model contains volumes representing the CCW system. The system volumes are water solid and assumed to be initially at 50 psia and 90°F.
Flow Paths Flow boundary conditions linked to functions that define the mass and energy release model the LOCA break flow to the containment. The boundary conditions are connected to the containment control volume via flow paths. The containment spray is modeled as a boundary condition connected to the containment control volume via a flow path.
The flow rates through the flow paths are specified by the boundary conditions, so the purpose of the flow path is to direct the flow to the proper control volume. The flow path input is mostly arbitrary. Standard values are used for the area, hydraulic diameter, friction length, and inertia length of the flow path. Since this is a single volume lumped parameter model, the elevation of the break flow paths is arbitrarily set to 100 ft and the elevation of the spray flow paths is arbitrarily set to 70 ft above the containment floor.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-27 Revision 20 November 2011 Heat Sinks The structural heat sinks in the containment are modeled as GOTHIC thermal conductors. The heat sink geometry data is based on conservatively low surface areas and is summarized in Table 6.2D-19. A thin air gap is assumed to exist between the steel and concrete for steel-jacketed heat sinks. A gap conductance of 10 Btu/hr/ft2/°F is conservatively assumed between steel and concrete. The volumetric heat capacity and thermal conductivity for the heat sink materials are summarized in Table 6.2D-20.
Heat and Mass Transfer Correlation GOTHIC has several heat transfer coefficient options that can be used for containment analyses. For the Diablo Canyon GOTHIC model, the direct heat transfer coefficient set is used with the diffusion layer model mass transfer correlation for the heat sinks inside containment. This heat transfer methodology was reviewed by the NRC and approved for use in containment DBA analyses in the Kewaunee analysis (Reference 15). The diffusion layer model correlation does not require the user to specify a revaporization input value, as was done in previous analyses using the Uchida correlation.
Split heat transfer coefficients are used for the heat sinks representing walls and floors. The split coefficient allows one thermal conductor to model heat transfer to both the water and vapor regions. The submerged portions of conductors are essentially insulated from the vapor after the pool develops. The fraction of the wall that is not submerged uses the vapor heat transfer coefficient as described above. GOTHIC calculates the fraction of the walls that are submerged in the sump water. The floors are submerged quickly. Sump Recirculation The calculated containment peak pressure and temperature occur before the transfer to cold leg recirculation. However, a sump recirculation model comprised of simplified RHR and CCW system models was added to the Diablo Canyon containment model for the long-term LOCA containment pressure and temperature response calculation.
The recirculation system is actuated after a low RWST level signal and the ECCS takes suction from the containment sump. The RHR heat exchanger cools the water before it is injected back into the reactor vessel. The RHR heat exchanger is cooled by CCW water and service water provides the ultimate heat sink, cooling the CCW heat exchangers.
Switchover to hot leg recirculation is assumed to occur at 7 hours.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-28 Revision 20 November 2011 6.2D.4.1.4 Boundary Conditions Mass and Energy Release Section 6.2D.2.1 describes the long term LOCA long-term mass and energy release. The LOCA mass and energy release rates are generated using the Westinghouse methodology (Reference 1). Mass and energy releases are calculated for both sides of the double-ended break in the coolant loop: the vessel side of the break and the steam generator side of the break. The mass and energy releases are input to the GOTHIC containment model as mass flow rates and enthalpies via boundary conditions connected to the containment volume with flow paths.
During blowdown, the liquid portion of the break flow is released as drops with an assumed diameter of 100 microns (0.00394 inches). This is consistent with the methodology approved for Kewaunee (Reference 15) and is based on data presented in Reference 17. After blowdown, the liquid release is assumed to be a continuous pour into the sump.
GOTHIC uses the mass and energy release tables from the time of accident initiation to 3,600 seconds, the time at which all energy in the primary heat structures and steam generator secondary system is assumed to be released/depressurized to atmospheric pressure, (i.e., 14.7 psia and 212°F). After primary system and secondary system energy have been released, the mass and energy releases to the containment are due to long-term steaming of decay heat. GOTHIC calculates the decay heat steaming mass and energy releases within user defined control variables. The steaming calculations incorporate the transient containment pressure and RHR recirculated ECCS enthalpy to calculate the mass and energy release. The calculations are essentially the same as the Westinghouse methodology previously approved by the NRC, except the calculations are performed within the GOTHIC code. The ANS Standard 5.1 decay heat model (+2 uncertainty) is used to calculate the long-term boil-off from the core. All the decay heat is assumed to produce steam from the recirculated ECCS water. The remainder of the ECCS water is returned to the sump region of the containment control volume. These assumptions are consistent with the long-term mass and energy release methodology documented in Reference 1.
Containment Fan Coolers The CFCUs are modeled with a GOTHIC cooler component. There are a total of five CFCUs in three trains. In all cases, two CFCUs are assumed to be out of service for maintenance. An inherent assumption in the LOCA containment analysis is that offsite power is lost with the pipe rupture. This results in the actuation of three emergency diesel generators (EDGs), powering the two trains of safeguards equipment. Startup of the EDGs delays the operation of the safeguards equipment that is required to mitigate the transient. There are two trains of the SSPS that actuate the two trains of emergency safeguards. The failure of one train of SSPS will fail one train of safeguards. DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-29 Revision 20 November 2011 A minimum of two CFCUs are available and a maximum of three CFCUs are assumed to be available based on the single failure assumptions.
Three long term cases are analyzed to assess the effects of single failures. The first case assumes minimum safeguards based on the postulated single failure of an SSPS train. This assumption results in the loss-of-one train of safeguards equipment. The operating equipment is conservatively modeled as: two CFCUs, one containment spray pump, one train of RHR, and one CCW heat exchanger. The other two cases assume maximum safeguards, in which both trains of SSPS are available. With the maximum safeguards cases, the single failure assumptions are the failure of one containment spray pump or the failure of one CFCU. The analysis of these three cases provides confidence that the effect of credible single failures is bounded.
The fan coolers in the containment evaluation model are modeled to actuate on the containment high pressure setpoint with uncertainty biased high, (5 psig), and begin removing heat from containment after a 48-second delay.
The CFCUs are cooled by CCW. The heat removal rate per containment fan cooler is calculated as a function of containment steam saturation temperature, the CCW inlet temperature and flow rate, and input to the GOTHIC cooler model. The heat removal rate is multiplied by the number of CFCUs available. The heat removed from the containment control volume is transferred to the CCW control volume receiving the flow through the CFCUs using a coupled heater model.
Containment Spray System The containment spray is modeled with a boundary condition. DCPP has two trains of containment safeguards available, with one spray pump per train. An inherent assumption in the LOCA containment analysis is that offsite power is lost with the pipe rupture. This results in the actuation of the three EDGs powering the two trains of safeguards equipment. Startup of the EDGs delays the operation of the safeguards equipment that is required to mitigate the transient.
Relative to the single failure criterion with respect to a LOCA event, one spray pump is considered inoperable due to the SSPS failure (minimum safeguards case) or as a single failure in a maximum safeguards case. In the maximum safeguards case, in which the single failure is assumed to be one CFCU, two spray pumps are available.
The containment spray actuation is modeled on the containment high-high pressure setpoint with uncertainty biased high (24.7 psig). The sprays begin injecting 90°F water after a specified 80 second delay. The spray flow rate is a function of containment pressure and is presented in Table 6.2D-18. The containment spray is credited only during the injection phase of the transient and is terminated on a refueling water storage tank empty alarm after switchover to cold leg recirculation at a time based on the number of SI and spray pumps operating. The timing of recirculation and spray DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-30 Revision 20 November 2011 termination assumed in the LOCA containment analysis are presented in Table 6.2D-17.
Accumulator Nitrogen Gas Modeling The accumulator nitrogen gas release is modeled with a flow boundary condition in the LOCA containment model. The nitrogen release rate was conservatively calculated by maximizing the mass available to be injected. The nitrogen gas release rate was used as input for the GOTHIC function, as a specified rate over a fixed time period. Nitrogen gas was released to the containment at a rate of 327.4 lbm/s. The release begins at 51.9 seconds, the minimum accumulator tank water depletion time. 6.2D.4.1.5 LOCA Containment Integrity Results Plant input assumptions (identified in Section 6.2D.4.1.2) are the same as, or slightly more restrictive, than in the licensing-basis analyses performed with the COCO code (Reference 18). Benchmarking between the Diablo Canyon COCO and GOTHIC models was performed to confirm consistency in the implementation of the plant input values.
The containment pressure, steam temperature, and water (sump) temperature profiles of the DEHL peak pressure case are shown in Figures 6.2D-3 through 6.2D-5. Table 6.2D-13 provides the transient sequence of events for the DEHL transient.
The containment pressure, steam temperature, and water (sump) temperature profiles of the DEPS long-term EQ temperature transient are shown in Figures 6.2D-6 through 6.2D-81. Tables 6.2D-14 and 6.2-15 presents the sequence of events for the Unit 1 and Unit 2 DEPS transients, respectively. The peak pressure (Figure 6.2D-6) for the DEPS case occurs at 24.1 seconds after the end of the blowdown. The fans begin to cool the containment at 48.7 seconds. Containment sprays begin injecting at 88.01 seconds. The pressure comes down as the steam generators reach equilibrium with the containment environment, but spikes up again at recirculation when the CCW temperature increases and the CCW flow rate to the CFCUs decreases. The sensible heat release from the steam generator secondary system and RCS metal is completed at 3600 seconds, but at 3798 seconds, the RWST reaches a low level alarm and spray flow is terminated. The containment pressure increases for a time and then begins to decrease over the long term as the RHR heat exchangers and CFCUs remove the heat from the containment.
Table 6.2D-21 summarizes the containment peak pressure and temperature results and pressure and temperature at 24 hours for EQ support and the acceptance limits for these parameters.
A review of the results presented in Table 6.2D-21 shows that the analysis margin (analysis margin is the difference between the calculated peak pressure and 1 The peak DEPS values are from Unit 2. DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-31 Revision 20 November 2011 temperature and the acceptance limits) is maintained for Diablo Canyon with replacement steam generators. From the GOTHIC analysis performed in support of the Diablo Canyon replacement steam generator program the containment peak pressure is 41.4 psig. At 24 hours, the maximum containment pressure is 8.9 psig and the maximum temperature is 167.54°F. 6.2D.4.1.6 Conclusion The DCPP containment can adequately account for the mass and energy releases that would result from the replacement steam generator program. The DCPP containment systems will continue to provide sufficient pressure and temperature mitigation capability to ensure that containment integrity is maintained. The containment systems and instrumentation will continue to be adequate for monitoring containment parameters and release of radioactivity during normal and accident conditions and will continue to meet the DCPP licensing basis requirements with respect to GDC -13, -16, -38, -50, and -64 following installation of the replacement steam generators 6.2D.4.2 Steamline Break Containment Response 6.2D.4.2.1 Introduction and Background Containment integrity analyses are performed to ensure that pressure inside containment will remain below the containment building design pressure for a postulated secondary system pipe rupture. The mass and energy release analysis discussed in Section 6.2D.3 is input to this analysis. 6.2D.4.2.2 Input Parameters and Assumptions This section identifies the major input values that are used in the steamline break containment response analysis. The assumed initial conditions and the input assumptions associated with the fan coolers and containment sprays are listed in Table 6.2D-22. The containment thermal conductor input is provided in Table 6.D-19, and the corresponding material properties are listed in Table 6.2D-20. 6.2D.4.2.3 Description of Analyses The containment response analysis uses the GOTHIC computer code. The GOTHIC program is rapidly becoming the industry standard for performing containment pressure and temperature design-basis analyses. The GOTHIC Technical Manual (Reference
- 13) provides a description of the governing equations, constitutive models, and solution methods in the solver. The GOTHIC Qualifications Report (Reference 14) provides a comparison of the solver results with both analytical solutions and experimental data.
The Diablo Canyon GOTHIC containment evaluation model consists of a single lumped-parameter node; the diffusion layer model is used for heat transfer to all structures in the containment. Plant input assumptions (identified in Section 6.2D.4.2.2) are the DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-32 Revision 20 November 2011 same as, or slightly more restrictive, than in the licensing-basis analyses performed with the COCO code (Reference 18). Benchmarking between the Diablo Canyon COCO and GOTHIC models was performed to confirm consistency in the implementation of the plant input values. The benchmarking results show that the GOTHIC model predicted similar transient results.
This steamline break containment response analysis uses GOTHIC version 7.2. This code version is used to take advantage of the diffusion layer model heat transfer option. This heat transfer option was approved by the NRC (Reference 19) for use in Kewaunee containment analyses with the condition that mist be excluded from what was earlier termed as the mist diffusion layer model. The GOTHIC containment modeling for DCPP has followed the conditions of acceptance placed on Kewaunee. Kewaunee and DCPP both have large, dry containments. Changes in the GOTHIC code versions are detailed in Appendix A of the GOTHIC User Manual Release Notes (Reference 16). Version 7.2 is used consistent with the restrictions identified in Reference 19; none of the user-controlled enhancements added to version 7.2 were implemented in the DCPP containment model. 6.2D.4.2.4 Acceptance Criteria The containment response to a steamline break is analyzed to ensure that the containment pressure remains below the containment design pressure of 47.0 psig. There is no explicit design temperature limit to be met for the steamline break containment response. 6.2D.4.2.5 Results Sixteen steamline break cases were analyzed varying the initial power level and the assumed single failure. The mass and energy release from the break was calculated using the RETRAN code (see Section 6.2D.3.3), while the containment pressure response was determined with the GOTHIC code. The analysis included the effects of the replacement steam generators.
The peak pressures and peak temperatures from the spectrum of cases are listed in Table 6.2D-23. The limiting peak pressure case is a main FRV failure at 70 percent power assuming a full double-ended rupture. The sequence of events for this limiting case is listed in Table 6.2D-24. The containment pressure and temperature transient for the limiting case is shown in Figures 6.2D-9 and 6.2D-10, respectively. The peak containment pressure is 42.8 psig, which is below the containment design pressure of 47.0 psig. 6.2D.4.2.6 Conclusions The analysis performed for the replacement steam generators demonstrates that the containment pressure remains below the containment design pressure throughout the transient for a postulated secondary system pipe rupture. Thus the containment DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-33 Revision 20 November 2011 integrity has been demonstrated and all applicable acceptance criteria are therefore met. 6.2D.5 REFERENCES 1. Westinghouse LOCA Mass and Energy Release Model for Containment Design - March 1979 Version, WCAP-10325-P-A (Proprietary), WCAP-10326-A (Nonproprietary), May 1983.
- 2. Standard Review Plan, NUREG-0800, USNRC, Rev. 2, July 1981.
- 3. License Amendment No.126 for D. C. Cook Nuclear Plant Unit 1, Operating License No. DPR-58 (TAC No. 71062), June 9, 1989.
- 4. Mixing of Emergency Core Cooling Water with Steam; 1/3-Scale Test and Summary, WCAP-8423, EPRI 294-2, Final Report, June 1975.
- 5. Westinghouse Mass and Energy Release Data for Containment Design, WCAP-8264-P-A, Rev. 1, (Proprietary), WCAP-8312-A, August 1975.
- 6. Letter from Herbert N. Berkow, Director (NRC) to James A. Gresham (Westinghouse), "Acceptance of Clarifications of Topical Report WCAP-10325-P-A, 'Westinghouse LOCA Mass and Energy Release Model for Containment Design - March 1979 Version', (TAC No. MC7980)".
- 7. ANSI/ANS-5.1 1979, "American National Standard for Decay Heat Power in Light Water Reactors", August 29, 1979.
- 8. Letter from Cecil O. Thomas (NRC), "Acceptance for Referencing of Licensing Topical Report WCAP-8821(P)/8859(NP), TRANFLO Steam Generator Code Description", and "WCAP-8822(P)/8860(NP), "Mass and Energy Release Following a Steam Line Rupture," August 1983.
- 9. R. E. Land, Mass and Energy Releases Following a Steam Line Rupture, WCAP-8822 (Proprietary), WCAP-8860 (Non-Proprietary), September 1976.
- 10. T. W. T. Burnett, et al. LOFTRAN Code Description, WCAP-7907-P-A (Proprietary) and WCAP-7907-A (Non-Proprietary), April 1984.
- 11. M. P. Osborne and D. S. Love, Mass and Energy Releases Following a Steam Line Rupture, Supplement 1 - Calculations of Steam Superheat in Mass/Energy Releases Following a Steamline Rupture, WCAP-8822-S1-P-A (Proprietary), September 1986.
DCPP UNITS 1 & 2 FSAR UPDATE 6.2D-34 Revision 20 November 2011 12. D. S. Huegel, et al. RETRAN-02 Modeling and Qualification for Westinghouse Pressurized Water Reactor Non-LOCA Safety Analyses, WCAP-14882-P-A (Proprietary), April 1999.
- 13. GOTHIC Containment Analysis Package Technical Manual, Version 7.2, NAI-8907-06, Rev. 15, September 2004.
- 14. GOTHIC Containment Analysis Package Qualification Report, Version 7.2, NAI-8907-09, Rev. 8, September 2004.
- 15. License Amendment No. 169 for Kewaunee Nuclear Power Plant, Operating License No. DPR-43 (TAC No. MB6408), September 29, 2003.
- 16. GOTHIC Containment Analysis Package User Manual, Version 7.2, NAI-8907-02, Rev. 16, September 2004.
- 17. Brown and York, "Sprays formed by Flashing Liquid Jets", AICHE Journal, Volume 8, #2, May 1962.
- 18. F. M. Bordelon and E. T. Murphy, Containment Pressure Analysis Code (COCO), WCAP-8327 (Proprietary), WCAP-8326 (Non-Proprietary), July 1974.
- 19. Letter from Anthony C. McMurtray (NRC) to Thomas Coutu (NMC), "Enclosure 2, Safety Evaluation," September 29, 2003.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 6.2D-1 SYSTEM PARAMETERS INITIAL CONDITIONS Parameters Unit 1 Value Unit 2 Value Core Thermal Power (MWt) 3479.0 Same RCS Total Flow Rate (lbm/sec) 36888.88 37222.22 Vessel Outlet Temperature (°F) 615.1 Same Core Inlet Temperature (°F) 549.5 550.1 Vessel Barrel-Baffle Configuration Downflow Upflow Initial Steam Generator Steam Pressure (psia) 881.0 885.0 Steam Generator Design 54 Same Steam Generator Tube Plugging (%) 0 0 Initial Steam Generator Secondary Side Mass (lbm) 132953.7 Same Assumed Maximum Containment Backpressure (psia) 61.7 Same Accumulator Water volume (ft3) per accumulator 850.0 Same N2 cover gas pressure (psia) 577.2 Same Temperature (°F) 120.0 Same SI Start Time, (sec) [total time from beginning of event which includes the maximum delay from reaching the setpoint] 31.1 31.3 Note: Core thermal power, RCS total flow rate, RCS coolant temperatures, and steam generator secondary side mass include appropriate uncertainty and/or allowance. DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 6.2D-2 SI FLOW MINIMUM SAFEGUARDS - BOTH UNITS RCS Pressure (psig) Total Flow (gpm) Injection Mode (reflood phase) 0 4805.0 20 4558.8 40 4298.6 60 4017.4 80 3710.2 100 3363.0 120 2950.4 140 2403.8 160 1386.2 180 780.6 200 775.0 Cold-Leg Recirculation Flow 3252.3 Hot-Leg Recirculation Flow 3071.7 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-3 Sheet 1 of 6 DCPP UNIT 2 DEHL BREAK NO SAFETY INJECTION MASS AND ENERGY RELEASES DURING BLOWDOWN Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 0.00000 0.0 0.0 0.0 0.0 .00107 44,541.3 28,166.1 44,538.8 28,163.1 .00200 45,195.9 28,579.8 44,946.2 28,415.5 .00302 44,781.3 28,318.3 44,242.0 27,964.6 .00418 44,360.3 28,054.3 43,495.1 27,486.1 .101 45,600.3 29,180.2 26,321.8 16,611.8 .201 33,267.6 21,549.3 23,417.0 14,699.5 .301 33,305.3 21,529.4 20,822.6 12,924.1 .401 32,349.1 20,884.4 19,472.1 11,904.9 .501 31,804.9 20,519.1 18,650.5 11,227.7 .602 31,757.0 20,476.9 18,089.9 10,735.9 .702 31,718.8 20,458.2 17,658.8 10,352.6 .801 31,455.0 20,318.4 17,306.7 10,039.4 .901 31,016.0 20,083.4 17,042.1 9,796.6 1.00 30,566.3 19,853.9 16,829.2 9,599.1 1.10 30,194.1 19,683.7 16,682.1 9,451.1 1.20 30,012.3 19,646.5 16,563.2 9,328.8 1.30 29,787.6 19,586.1 16,532.9 9,262.9 1.40 29,464.4 19,457.8 16,556.7 9,232.0 1.50 29,049.3 19,264.7 16,602.4 9,217.8 1.60 28,611.9 19,048.4 16,669.3 9,219.3 1.70 28,244.6 18,870.7 16,750.0 9,232.1 1.80 27,948.9 18,737.3 16,837.1 9,251.8 1.90 27,615.3 18,573.6 16,922.4 9,274.5 2.00 27,190.2 18,341.3 16,996.3 9,294.7 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-3 Sheet 2 of 6 Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 2.10 26,704.6 18,060.0 17,058.9 9,312.3 2.20 26,248.5 17,795.4 17,110.8 9,327.0 2.30 25,856.3 17,573.9 17,152.8 9,339.0 2.40 25,474.8 17,357.3 17,183.4 9,347.1 2.50 25,053.4 17,106.9 17,198.6 9,348.9 2.60 24,613.6 16,836.3 17,199.5 9,344.8 2.70 24,173.4 16,560.2 17,188.2 9,335.3 2.80 23,762.0 16,302.1 17,166.7 9,321.5 2.90 23,395.3 16,073.1 17,137.0 9,304.3 3.00 23,030.8 15,842.8 17,099.2 9,283.3 3.10 22,655.9 15,597.7 17,053.6 9,258.9 3.20 22,292.5 15,355.4 16,999.6 9,230.3 3.30 21,967.1 15,138.0 16,941.5 9,200.0 3.40 21,653.4 14,924.6 16,878.8 9,167.5 3.50 21,350.8 14,714.2 16,810.6 9,132.3 3.60 21,080.5 14,523.9 16,738.5 9,095.2 3.70 20,822.7 14,338.3 16,663.4 9,056.7 3.80 20,571.6 14,151.8 16,583.8 9,015.9 3.90 20,351.7 13,984.8 16,500.0 8,973.0 4.00 20,153.7 13,830.5 16,414.2 8,929.1 4.20 19,801.1 13,541.5 16,233.0 8,836.8 4.40 19,519.2 13,292.3 16,033.2 8,735.2 4.60 19,303.2 13,081.5 15,810.9 8,622.3 4.80 19,162.2 12,916.1 15,558.8 8,494.2 5.00 19,122.7 12,817.9 15,224.4 8,321.8 5.20 19,126.1 12,749.9 14,778.4 8,089.6 5.40 19,183.3 12,715.2 14,482.9 7,943.1 5.60 19,316.8 12,709.4 14,186.0 7,795.0 5.80 19,474.5 12,712.1 13,737.5 7,561.1 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-3 Sheet 3 of 6 Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 6.00 19,682.3 12,746.5 13,338.0 7,354.5 6.20 19,940.9 12,802.3 12,987.3 7,174.8 6.40 20,353.0 12,926.6 12,623.2 6,986.7 6.60 15,413.8 10,752.9 12,297.6 6,819.0 6.80 15,236.0 10,624.6 11,933.0 6,628.2 7.00 15,366.6 10,592.9 11,574.0 6,440.0 7.20 15,549.9 10,645.6 11,272.2 6,283.6 7.40 15,660.1 10,597.4 10,978.5 6,130.4 7.60 15,835.3 10,627.2 10,688.2 5,978.1 7.80 15,997.0 10,640.0 10,404.4 5,828.7 8.00 16,185.1 10,713.2 10,136.6 5,687.6 8.20 16,233.3 10,663.1 9,888.1 5,556.5 8.40 16,136.2 10,576.9 9,648.3 5,429.6 8.60 16,204.4 10,541.3 9,419.9 5,308.6 8.80 16,402.5 10,584.6 9,198.7 5,191.3 9.00 16,589.7 10,625.8 8,984.6 5,077.8 9.20 16,775.4 10,670.0 8,780.3 4,969.7 9.40 16,967.2 10,719.0 8,577.6 4,862.4 9.60 17,173.4 10,778.1 8,379.4 4,757.7 9.80 17,433.2 10,867.7 8,183.1 4,654.3 10.0 17,813.1 11,020.7 7,988.2 4,551.9 10.2 18,281.7 11,239.0 7,795.5 4,451.1 10.2 18,278.9 11,236.9 7,792.7 4,449.6 10.4 18,141.9 11,119.8 7,602.8 4,350.6 10.6 17,891.2 10,932.2 7,410.7 4,250.7 10.8 16,616.9 10,228.6 7,217.2 4,150.6 11.0 14,856.4 9,279.7 7,028.4 4,053.5 11.2 14,805.8 9,211.3 6,844.7 3,959.8 11.4 14,894.8 9,221.9 6,670.8 3,872.0 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-3 Sheet 4 of 6 Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 11.6 15,011.3 9,254.7 6,508.6 3,790.7 11.8 15,151.7 9,305.3 6,352.9 3,712.3 12.0 15,257.5 9,338.6 6,206.3 3,638.4 12.2 15,283.8 9,332.3 6,063.8 3,566.4 12.4 15,192.4 9,266.5 5,926.0 3,496.8 12.6 14,757.1 9,024.1 5,789.2 3,427.7 12.8 13,959.1 8,596.3 5,656.8 3,361.2 13.0 13,455.7 8,317.8 5,523.9 3,294.8 13.2 13,252.4 8,192.2 5,396.1 3,231.8 13.4 13,121.4 8,106.7 5,272.7 3,171.3 13.6 12,981.4 8,020.4 5,154.8 3,114.0 13.8 12,793.3 7,912.3 5,038.8 3,057.4 14.0 12,553.5 7,780.8 4,928.6 3,003.8 14.2 12,261.1 7,624.2 4,820.7 2,951.3 14.4 11,945.6 7,457.6 4,715.3 2,900.2 14.6 11,639.3 7,297.6 4,612.4 2,850.4 14.8 11,352.9 7,150.1 4,513.9 2,803.1 15.0 11,077.4 7,010.9 4,416.2 2,756.3 15.2 10,807.5 6,886.4 4,320.6 2,710.6 15.4 10,210.4 6,711.1 4,230.6 2,668.0 15.6 9,769.8 6,599.5 4,140.3 2,625.1 15.8 9,490.9 6,539.3 4,052.4 2,583.4 16.0 9,155.4 6,429.6 3,962.8 2,540.5 16.2 8,692.4 6,230.4 3,865.8 2,494.1 16.4 7,934.8 5,863.4 3,755.1 2,441.7 16.6 7,268.8 5,557.7 3,621.9 2,381.9 16.8 6,820.5 5,382.5 3,467.5 2,316.6 17.0 6,387.0 5,228.3 3,289.7 2,245.2 17.2 5,926.6 5,068.9 3,095.5 2,169.9 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-3 Sheet 5 of 6 Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 17.4 5,426.2 4,819.1 2,894.0 2,092.0 17.6 4,998.7 4,529.1 2,694.5 2,011.4 17.8 4,606.2 4,282.6 2,515.6 1,935.3 18.0 4,277.5 4,080.7 2,353.4 1,861.1 18.2 3,992.8 3,904.4 2,215.5 1,796.0 18.4 3,755.7 3,736.3 2,095.1 1,738.0 18.6 3,530.4 3,573.1 1,989.3 1,686.3 18.8 3,304.6 3,398.0 1,894.0 1,639.4 19.0 3,067.7 3,219.6 1,806.3 1,598.2 19.2 2,812.8 3,037.2 1,723.1 1,560.7 19.4 2,545.3 2,842.0 1,645.9 1,525.1 19.6 2,295.3 2,643.4 1,573.2 1,491.5 19.8 2,081.2 2,445.3 1,491.9 1,459.4 20.0 1,903.0 2,267.3 1,409.8 1,432.3 20.2 1,784.9 2,158.5 1,315.3 1,401.7 20.4 1,693.8 2,068.8 1,233.2 1,369.0 20.6 1,606.7 1,966.1 1,161.9 1,328.4 20.8 1,514.8 1,860.1 1,108.9 1,289.5 21.0 1,412.8 1,741.8 1,066.0 1,253.8 21.2 1,326.1 1,642.4 1,038.9 1,230.3 21.4 1,251.3 1,553.6 1,020.0 1,211.5 21.6 1,159.5 1,444.2 997.1 1,185.2 21.8 1,075.7 1,347.6 965.6 1,153.5 22.0 1,005.6 1,260.1 923.1 1,114.2 22.2 941.1 1,183.5 848.3 1,035.1 22.4 870.9 1,094.7 762.7 935.4 22.6 805.0 1,013.1 709.1 871.9 22.8 738.8 929.4 613.2 754.7 23.0 684.6 860.9 499.5 616.6 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-3 Sheet 6 of 6 Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 23.2 638.5 801.5 395.6 489.6 23.4 599.6 749.4 306.5 380.7 23.6 584.4 727.4 250.3 311.9 23.8 560.9 699.3 232.4 290.3 24.0 529.0 659.3 112.5 140.9 24.0 529.0 659.2 112.2 140.5 24.2 259.5 330.9 .0 .0 24.4 .0 .0 .0 .0 Notes: 1. Mass and energy exiting from the reactor-vessel side of the break. 2. Mass and energy exiting from the steam-generator side of the break.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 6.2D-4 DCPP UNIT 2 DEHL BREAK NO SAFETY INJECTION MASS BALANCE Time (Seconds) 0.00 24.40 24.40 Mass (thousand lbm) Initial In RCS and ACC 745.68 745.68 745.68 Added Mass Pumped Injection 0.0 0.0 0.0 Total Added 0.0 0.0 0.0 ***Total Available*** 745.68 745.68 745.68 Distribution Reactor Coolant 527.43 69.55 97.56 Accumulator 218.25 165.65 137.64 Total Contents 745.68 235.20 235.20 Effluent Break Flow 0.0 510.46 510.46 ECCS Spill 0.0 0.0 0.0 Total Effluent 0.0 510.46 510.46 ***Total Accountable*** 745.68 745.66 745.66 DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 6.2D-5 DCPP UNIT 2 DEHL BREAK NO SAFETY INJECTION ENERGY BALANCE Time (s) .00 24.40 24.40 Energy (Million Btu) Initial Energy In RCS, Accumulator, SG 905.10 905.10 905.10 Added Energy Pumped Injection Decay Heat Heat from Secondary Total Added .00 .00 .00 .00 .00 8.44 14.68 23.11 .00 8.44 14.68 23.11 *** Total Available *** 905.10 928.21 928.21 Distribution Reactor Coolant Accumulator Core Stored Primary Metal Secondary Metal SG Total Contents 307.86 19.52 22.37 152.45 110.78 292.13 905.10 16.73 14.82 8.68 143.33 108.33 308.16 600.03 19.23 12.31 8.68 143.33 108.33 308.16 600.03 Effluent Break Flow ECCS Spill Total Effluent .00 .00 .00 327.58 .00 327.58 327.58 .00 327.58 *** Total Accountable *** 905.10 927.61 927.61 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-6 Sheet 1 of 6 DCPP UNIT 2 DEPS BREAK MASS AND ENERGY RELEASES DURING BLOWDOWN Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 0.0000 0.0 0.0 0.0 0.0 .00101 92,521.0 50,304.2 38,824.7 21,047.2 .00208 40,817.3 22,127.8 40,485.8 21,946.4 .101 40,420.4 21,973.6 21,118.6 11,441.9 .202 41,042.2 22,449.9 23,061.7 12,502.3 .301 41,804.0 23,053.4 23,229.8 12,602.7 .401 42,627.5 23,741.7 22,801.1 12,382.0 .501 43,380.7 24,427.7 21,953.7 11,929.5 .602 43,781.4 24,928.0 21,129.7 11,487.2 .702 43,657.5 25,113.9 20,481.4 11,138.0 .801 42,828.8 24,861.3 19,928.9 10,839.7 .902 41,675.6 24,398.6 19,483.7 10,599.5 1.00 40,579.4 23,952.7 19,187.2 10,440.0 1.10 39,511.3 23,520.0 19,028.5 10,355.8 1.20 38,402.3 23,065.4 18,959.7 10,319.7 1.30 37,249.5 22,584.3 18,947.5 10,314.2 1.40 36,108.9 22,098.2 18,964.3 10,324.1 1.50 35,071.0 21,648.3 18,995.3 10,341.3 1.60 34,208.0 21,281.0 19,025.0 10,357.6 1.70 33,463.9 20,972.1 19,059.7 10,376.7 1.80 32,776.6 20,693.9 19,096.3 10,396.8 1.90 32,102.6 20,421.0 19,124.8 10,412.7 2.00 31,397.6 20,128.0 19,120.1 10,410.4 2.10 30,611.5 19,775.1 19,082.7 10,390.3 2.20 29,873.7 19,448.4 19,019.5 10,356.3 2.30 29,105.8 19,092.8 18,929.6 10,307.7 2.40 28,311.7 18,711.9 18,608.0 10,132.0 2.50 27,476.0 18,296.6 18,386.7 10,012.6 2.60 26,393.3 17,705.5 18,230.6 9,928.7 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-6 Sheet 2 of 6 Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 2.70 24,922.5 16,832.9 18,070.0 9,842.2 2.80 22,800.1 15,489.7 17,885.8 9,742.8 2.90 20,616.3 14,089.6 17,671.8 9,627.2 3.00 20,161.2 13,878.1 17,460.5 9,513.2 3.10 20,196.4 13,958.6 17,257.3 9,403.8 3.20 19,378.6 13,416.2 17,052.9 9,293.7 3.30 18,805.8 13,055.5 16,834.1 9,175.7 3.40 18,342.4 12,765.1 16,617.5 9,059.0 3.50 17,710.2 12,348.0 16,417.2 8,951.2 3.60 17,087.6 11,936.3 16,224.1 8,847.4 3.70 16,454.6 11,515.2 16,039.6 8,748.3 3.80 15,819.4 11,091.9 15,869.2 8,657.0 3.90 15,206.0 10,683.7 15,705.2 8,569.2 4.00 14,640.1 10,307.2 15,547.3 8,484.8 4.20 13,733.4 9,708.9 15,272.4 8,338.2 4.40 13,051.6 9,255.2 15,011.2 8,199.0 4.60 12,515.4 8,894.0 14,781.2 8,076.7 4.80 12,096.1 8,603.7 14,564.4 7,961.4 5.00 11,751.9 8,356.7 14,365.1 7,855.9 5.20 11,487.0 8,156.9 14,157.9 7,745.7 5.40 11,269.7 7,982.5 13,971.9 7,647.4 5.60 11,113.2 7,843.4 13,784.2 7,547.9 5.80 10,990.7 7,722.9 13,749.7 7,536.8 6.00 10,940.3 7,646.0 15,193.0 8,329.3 6.20 10,963.9 7,614.1 14,940.2 8,192.3 6.40 11,042.5 7,615.7 14,714.6 8,072.6 6.60 11,148.5 7,634.1 14,611.4 8,018.7 6.80 11,303.9 7,684.4 14,421.8 7,918.3 7.00 11,888.5 8,015.7 14,284.5 7,847.2 7.20 11,672.0 7,866.2 14,288.9 7,854.1 7.40 10,724.4 7,593.7 14,105.8 7,755.4 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-6 Sheet 3 of 6 Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 7.60 9,379.3 7,097.2 13,887.0 7,636.4 7.80 8,896.0 6,868.3 13,719.0 7,545.6 8.00 8,893.8 6,824.3 13,627.9 7,497.5 8.20 8,962.6 6,802.8 13,510.9 7,433.6 8.40 9,023.1 6,783.7 13,356.3 7,347.3 8.60 9,101.7 6,776.5 13,202.6 7,261.4 8.80 9,211.0 6,779.6 13,064.6 7,184.5 9.00 9,333.4 6,785.3 12,918.7 7,103.5 9.20 9,480.3 6,806.0 12,767.6 7,019.6 9.40 9,640.6 6,834.0 12,616.2 6,935.4 9.60 9,778.3 6,846.9 12,467.2 6,852.5 9.80 9,868.8 6,835.7 12,324.5 6,773.2 10.0 9,896.2 6,792.3 12,186.0 6,696.0 10.2 9,829.7 6,699.2 12,053.3 6,621.8 10.4 9,687.6 6,571.8 11,933.4 6,554.7 10.6 9,527.5 6,446.8 11,819.5 6,490.8 10.8 9,364.7 6,328.9 11,702.0 6,424.7 11.0 9,196.2 6,214.5 11,590.7 6,362.3 11.2 9,033.9 6,109.0 11,483.5 6,302.3 11.4 8,872.0 6,005.4 11,371.8 6,239.7 11.6 8,702.8 5,898.5 11,264.5 6,179.6 11.8 8,537.3 5,796.3 11,161.0 6,121.7 12.0 8,369.4 5,694.7 11,054.3 6,061.9 12.2 8,200.7 5,595.0 10,952.4 6,004.9 12.4 8,034.9 5,499.8 10,852.6 5,948.9 12.6 7,865.5 5,403.7 10,750.3 5,891.6 12.8 7,702.3 5,314.2 10,655.7 5,838.6 13.0 7,551.6 5,233.9 10,550.3 5,779.5 13.2 7,401.3 5,152.3 10,453.9 5,725.6 13.4 7,259.5 5,074.6 10,354.3 5,670.0 13.6 7,123.1 4,999.2 10,256.0 5,615.0 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-6 Sheet 4 of 6 Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 13.8 6,991.0 4,926.4 10,159.5 5,561.2 14.0 6,863.0 4,856.3 10,062.4 5,507.0 14.2 6,738.6 4,788.5 9,967.0 5,453.8 14.4 6,618.4 4,722.8 9,871.9 5,401.0 14.6 6,501.7 4,658.4 9,777.2 5,348.5 14.8 6,389.5 4,596.0 9,683.6 5,296.7 15.0 6,281.6 4,535.1 9,590.3 5,245.3 15.2 6,171.6 4,472.0 9,483.3 5,186.6 15.4 6,059.9 4,407.1 9,373.4 5,126.9 15.6 5,933.8 4,330.0 9,250.0 5,060.3 15.8 5,807.6 4,251.0 9,133.7 4,998.1 16.0 5,686.8 4,172.1 9,019.7 4,937.0 16.2 5,577.9 4,096.3 8,915.3 4,881.1 16.4 5,485.7 4,026.9 8,816.4 4,828.3 16.6 5,406.5 3,963.7 8,722.4 4,778.6 16.8 5,336.4 3,906.6 8,632.6 4,731.9 17.0 5,271.2 3,854.5 8,545.6 4,687.7 17.2 5,207.5 3,806.1 8,460.9 4,645.8 17.4 5,143.9 3,761.4 8,377.4 4,605.8 17.6 5,079.6 3,719.8 8,285.9 4,562.7 17.8 5,014.2 3,681.7 8,140.2 4,490.9 18.0 4,955.8 3,652.2 8,057.0 4,457.0 18.2 4,904.4 3,630.5 7,806.7 4,348.9 18.4 4,872.1 3,641.0 7,669.6 4,296.1 18.6 4,808.6 3,669.9 7,529.6 4,210.6 18.8 4,680.8 3,696.6 7,359.4 4,084.6 19.0 4,511.3 3,716.3 7,263.6 3,984.4 19.2 4,318.7 3,730.5 7,129.8 3,851.8 19.4 4,108.5 3,737.0 7,014.4 3,723.0 19.6 3,845.2 3,697.3 6,745.6 3,510.6 19.8 3,519.3 3,593.4 6,360.4 3,244.2 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-6 Sheet 5 of 6 Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 20.0 3,194.5 3,459.0 5,982.6 3,008.7 20.2 2,897.8 3,305.1 5,627.1 2,801.6 20.4 2,631.1 3,126.0 5,288.0 2,612.5 20.6 2,389.2 2,910.7 4,972.1 2,445.3 20.8 2,164.0 2,663.0 4,675.4 2,299.6 21.0 1,987.2 2,457.6 4,393.2 2,171.1 21.2 1,849.2 2,294.1 3,859.6 1,896.8 21.4 1,720.3 2,139.3 3,457.0 1,561.0 21.6 1,610.9 2,007.2 3,529.5 1,460.3 21.8 1,490.8 1,860.9 3,728.9 1,475.2 22.0 1,378.9 1,724.3 3,561.7 1,376.2 22.2 1,271.1 1,592.1 3,703.9 1,400.4 22.4 1,173.7 1,472.6 3,088.2 1,147.5 22.6 1,090.6 1,370.2 2,670.6 986.0 22.8 1,006.2 1,265.5 2,448.0 896.1 23.0 915.2 1,153.1 2,153.7 769.6 23.2 825.6 1,041.2 2,106.1 721.4 23.4 737.3 930.7 2,412.3 787.3 23.6 656.8 829.9 2,880.0 903.1 23.8 567.9 718.1 3,225.9 980.8 24.0 486.0 615.0 2,899.2 862.5 24.2 413.5 523.7 2,569.5 752.8 24.4 359.2 455.3 2,203.3 637.6 24.6 326.3 413.8 1,836.2 525.5 24.8 302.6 384.0 1,447.8 410.3 25.0 272.7 346.2 1,028.5 289.2 25.2 232.5 295.3 573.0 160.4 25.4 188.4 239.5 139.9 39.2 25.6 140.5 178.8 .0 .0 25.8 88.5 112.8 .0 .0 26.0 30.4 38.9 .0 .0 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-6 Sheet 6 of 6 Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 26.2 .0 .0 .0 .0 Notes: 1. Mass and energy exiting from the steam-generator side of the break (path 1). 2. Mass and energy exiting from the pump-side of the break (path 2). DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-7 Sheet 1 of 6 Revision 18 October 2008 DCPP UNIT 2 DEPS BREAK MASS AND ENERGY RELEASES DURING REFLOOD MINIMUM SAFEGUARDS (SSPS FAILURE) Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 26.2 .0 .0 .0 .0 26.8 .0 .0 .0 .0 26.9 .0 .0 .0 .0 27.0 .0 .0 .0 .0 27.1 .0 .0 .0 .0 27.2 .0 .0 .0 .0 27.3 81.0 95.4 .0 .0 27.4 32.8 38.7 .0 .0 27.5 23.8 28.1 .0 .0 27.6 26.2 30.9 .0 .0 27.7 33.1 39.0 .0 .0 27.8 40.4 47.6 .0 .0 27.9 45.1 53.2 .0 .0 28.0 49.8 58.7 .0 .0 28.1 54.2 63.8 .0 .0 28.2 58.3 68.7 .0 .0 28.3 62.2 73.3 .0 .0 28.4 66.0 77.7 .0 .0 28.5 68.7 80.9 .0 .0 28.5 69.6 82.0 .0 .0 28.6 73.0 86.0 .0 .0 28.7 76.4 90.0 .0 .0 28.8 79.6 93.8 .0 .0 28.9 82.7 97.5 0 0 29.0 85.8 101.1 .0 .0 29.1 88.7 104.6 .0 .0 29.2 91.6 107.9 .0 .0 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-7 Sheet 2 of 6 Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 30.2 117.1 138.0 .0 .0 31.2 138.4 163.2 .0 .0 32.2 294.2 347.7 2,812.4 360.3 32.8 478.1 567.0 4,779.8 667.3 33.2 492.7 584.7 4,891.9 698.9 34.2 489.7 581.1 4,863.6 700.0 35.2 482.5 572.4 4,799.1 693.0 36.2 474.8 563.2 4,728.8 685.0 37.0 468.6 555.8 4,671.3 678.3 37.2 467.0 553.9 4,656.9 676.6 38.2 459.4 544.7 4,585.3 668.1 39.2 451.9 535.8 4,514.7 659.7 40.2 444.6 527.1 4,445.7 651.4 41.2 437.6 518.8 4,378.5 643.3 42.2 430.9 510.7 4,313.1 635.4 42.4 429.5 509.1 4,300.2 633.8 43.2 424.3 502.9 4,249.6 627.7 44.2 418.0 495.3 4,187.9 620.2 45.2 412.0 488.1 4,128.1 612.9 46.2 406.1 481.1 4,069.9 605.9 47.2 400.4 474.3 4,013.5 599.0 48.2 395.0 467.8 3,958.7 592.3 48.6 392.8 465.3 3,937.2 589.7 49.2 389.7 461.5 3,905.4 585.8 50.2 384.6 455.4 3,853.6 579.5 51.2 379.6 449.5 3,803.2 573.4 52.2 374.8 443.8 3,754.1 567.4 53.3 308.1 364.3 3,015.2 484.8 54.3 399.1 472.5 308.7 213.8 55.3 431.5 511.5 322.6 233.6 55.5 429.8 509.5 321.9 232.6 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-7 Sheet 3 of 6 Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 56.3 420.8 498.7 317.8 227.2 57.3 409.1 484.6 312.6 220.1 58.3 397.3 470.6 307.4 213.2 59.3 386.8 458.1 302.7 206.9 60.3 376.9 446.3 298.3 201.1 61.3 367.4 434.9 294.1 195.5 62.3 358.3 424.1 290.1 190.2 63.3 349.5 413.6 286.2 185.1 64.3 341.1 403.6 282.5 180.2 65.3 333.0 394.0 279.0 175.6 66.3 325.2 384.7 275.6 171.1 67.3 317.8 375.8 272.3 166.8 68.3 310.6 367.3 269.2 162.8 69.3 303.7 359.1 266.3 158.9 70.3 297.1 351.3 263.4 155.2 70.5 295.9 349.7 262.9 154.4 71.3 290.8 343.7 260.7 151.6 72.3 284.7 336.5 258.0 148.2 73.3 278.9 329.6 255.5 145.0 74.3 273.3 323.0 253.1 141.9 75.3 268.0 316.6 250.8 139.0 76.3 262.9 310.5 248.7 136.1 77.3 257.9 304.7 246.6 133.5 78.3 253.2 299.1 244.5 130.9 79.3 248.6 293.7 242.6 128.4 80.3 244.3 288.5 240.8 126.1 81.3 240.1 283.6 239.0 123.8 82.3 236.1 278.8 237.4 121.7 83.3 232.3 274.3 235.7 119.6 84.3 228.6 269.9 234.2 117.7 85.3 225.1 265.7 232.8 115.8 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-7 Sheet 4 of 6 Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 86.3 221.7 261.7 231.4 114.0 87.3 218.5 257.9 230.0 112.4 89.3 212.4 250.8 227.6 109.2 90.6 208.8 246.5 226.1 107.3 91.3 206.9 244.3 225.3 106.4 93.3 201.9 238.3 223.3 103.8 95.3 197.4 232.9 221.4 101.4 97.3 193.3 228.1 219.8 99.3 99.3 189.5 223.6 218.3 97.4 101.3 186.1 219.6 216.9 95.7 103.3 183.1 216.0 215.7 94.2 105.3 180.3 212.8 214.6 92.8 107.3 177.9 209.9 213.6 91.6 109.3 175.7 207.3 212.8 90.5 111.3 173.7 205.0 212.0 89.5 113.3 172.0 202.9 211.3 88.6 115.3 170.5 201.1 210.7 87.9 115.6 170.2 200.8 210.6 87.8 117.3 169.1 199.5 210.1 87.2 119.3 167.9 198.1 209.7 86.6 121.3 166.9 196.9 209.3 86.1 123.3 166.0 195.8 208.9 85.6 125.3 165.3 194.9 208.6 85.3 127.3 164.6 194.2 208.3 84.9 129.3 164.1 193.5 208.1 84.6 131.3 163.6 193.0 207.9 84.4 133.3 163.2 192.5 207.7 84.2 135.3 162.9 192.2 207.6 84.0 137.3 162.7 191.9 207.5 83.9 139.3 162.5 191.7 207.4 83.7 141.3 162.4 191.6 207.3 83.7 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-7 Sheet 5 of 6 Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 143.3 162.4 191.5 207.3 83.6 143.5 162.4 191.5 207.3 83.6 145.3 162.4 191.5 207.3 83.6 147.3 162.4 191.6 207.3 83.6 149.3 162.5 191.7 207.3 83.6 151.3 162.6 191.8 207.3 83.6 153.3 162.7 192.0 207.3 83.6 155.3 162.9 192.1 207.3 83.7 157.3 163.1 192.4 207.4 83.7 159.3 163.3 192.6 207.4 83.8 161.3 163.5 192.9 207.5 83.9 163.3 163.7 193.1 207.6 84.0 165.3 164.0 193.4 207.7 84.1 167.3 164.3 193.8 207.7 84.2 169.3 164.6 194.1 207.8 84.3 171.3 164.8 194.5 207.9 84.4 173.0 165.1 194.8 208.0 84.5 173.3 165.2 194.8 208.0 84.5 175.3 165.5 195.2 208.1 84.6 177.3 165.8 195.6 208.2 84.7 179.3 166.1 196.0 208.3 84.9 181.3 166.5 196.4 208.4 85.0 183.3 166.8 196.8 208.5 85.1 185.3 167.1 197.2 208.6 85.3 187.3 167.5 197.6 208.7 85.4 189.3 167.8 198.0 208.8 85.6 191.3 168.2 198.4 209.0 85.7 193.3 168.6 198.8 209.1 85.9 195.3 169.8 200.3 209.9 86.4 197.3 170.8 201.5 211.3 87.0 199.3 171.9 202.7 213.3 87.7 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-7 Sheet 6 of 6 Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 201.3 173.0 204.0 215.8 88.5 203.3 174.0 205.3 218.6 89.3 203.5 174.1 205.4 218.9 89.4 Notes: 1. Mass and energy exiting from the steam-generator side of the break (path 1). 2. Mass and energy exiting from the pump-side of the break (path 2). DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-8 Sheet 1 of 2 Revision 18 October 2008 DCPP UNIT 2 DEPS SSPS CASE PRINCIPAL PARAMETERS DURING REFLOOD Flooding Total Injection Accumulator Spill Time (s) Temp (°F) Rate (in/s) Carryover Fraction Core Height (ft) Downcomer Height (ft) Flow Fraction (lbm/s) Enthalpy (Btu/lbm) 26.2 175.3 .000 .000 .00 .00 .250 .0 .0 .0 .00 27.0 173.1 21.725 .000 .63 1.50 .000 7,491.0 7,491.0 .0 89.44 27.2 172.0 24.019 .000 1.01 1.41 .000 7,442.6 7,442.6 .0 89.44 28.5 171.4 2.536 .300 1.50 4.89 .333 7,109.7 7,109.7 .0 89.44 29.2 171.6 2.465 .393 1.60 7.08 .349 6,959.9 6,959.9 .0 89.44 32.8 172.5 4.749 .623 2.00 16.11 .602 6,184.5 5,667.9 .0 86.82 34.2 172.9 4.514 .666 2.19 16.12 .599 5,914.4 5,402.7 .0 86.72 37.0 174.0 4.132 .702 2.50 16.12 .596 5,596.9 5,079.5 .0 86.54 42.4 176.7 3.734 .725 3.00 16.12 .585 5,110.3 4,582.8 .0 86.20 48.6 180.5 3.444 .733 3.50 16.12 .574 4,669.1 4,132.5 .0 85.83 53.3 183.5 2.922 .734 3.85 16.12 .530 3,606.1 3,050.1 .0 84.60 54.3 184.2 3.468 .738 3.91 16.03 .591 537.6 .0 .0 58.05 55.3 185.0 3.614 .739 3.99 15.78 .596 525.9 .0 .0 58.05 55.5 185.1 3.600 .739 4.01 15.72 .596 526.2 .0 .0 58.05 63.3 192.0 3.000 .738 4.56 14.08 .582 544.4 .0 .0 58.05 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-8 Sheet 2 of 2 Revision 18 October 2008 Flooding Total Injection Accumulator Spill Time (s) Temp (°F) Rate (in/s) Carryover Fraction Core Height (ft) Downcomer Height (ft) Flow Fraction (lbm/s) Enthalpy (Btu/lbm) 70.5 199.2 2.606 .736 5.00 13.09 .568 555.0 .0 .0 58.05 80.3 209.4 2.231 .735 5.52 12.31 .550 563.2 .0 .0 58.05 90.6 219.5 1.975 .733 6.00 11.98 .532 568.0 .0 .0 58.05 103.3 229.6 1.788 .734 6.53 11.98 .515 571.2 .0 .0 58.05 115.6 237.7 1.692 .735 7.00 12.23 .506 572.7 .0 .0 58.05 129.3 245.4 1.640 .738 7.50 12.66 .500 573.4 .0 .0 58.05 143.5 252.3 1.618 .743 8.00 13.18 .499 573.6 .0 .0 58.05 159.3 259.0 1.612 .748 8.54 13.79 .500 573.5 .0 .0 58.05 161.3 259.7 1.612 .749 8.61 13.87 .501 573.5 .0 .0 58.05 173.0 264.0 1.614 .753 9.00 14.33 .502 573.4 .0 .0 58.05 189.3 269.3 1.620 .758 9.54 14.97 .505 573.2 .0 .0 58.05 203.5 273.4 1.645 .764 10.00 15.49 .512 572.5 .0 .0 58.05 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-9 Sheet 1 of 4 Revision 18 October 2008 DCPP UNIT 2 DEPS BREAK MASS AND ENERGY RELEASES DURING POST-REFLOOD SSPS FAILURE Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 203.5 208.3 260.1 372.5 127.9 208.5 207.4 259.1 373.3 127.9 213.5 207.5 259.2 373.2 127.6 218.5 206.7 258.2 374.1 127.7 223.5 205.9 257.2 374.9 127.7 228.5 206.0 257.2 374.8 127.4 233.5 205.1 256.2 375.7 127.5 238.5 205.2 256.2 375.6 127.2 243.5 204.3 255.2 376.5 127.3 248.5 204.3 255.2 376.5 127.0 253.5 203.4 254.1 377.3 127.1 258.5 203.4 254.1 377.3 126.9 263.5 202.5 253.0 378.2 126.9 268.5 202.5 252.9 378.3 126.7 273.5 201.6 251.8 379.2 126.7 278.5 201.5 251.7 379.3 126.5 283.5 200.6 250.5 380.2 126.5 288.5 200.5 250.4 380.3 126.4 293.5 199.6 249.2 381.2 126.4 298.5 199.4 249.1 381.3 126.2 303.5 199.3 248.9 381.5 126.0 308.5 198.3 247.7 382.5 126.1 313.5 198.1 247.5 382.6 125.9 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-9 Sheet 2 of 4 Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 318.5 197.1 246.2 383.7 126.0 323.5 196.9 246.0 383.9 125.8 328.5 196.7 245.7 384.1 125.7 333.5 195.6 244.4 385.1 125.7 338.5 195.4 244.0 385.4 125.6 343.5 195.1 243.7 385.7 125.4 348.5 194.8 243.3 386.0 125.3 353.5 193.7 241.9 387.1 125.4 358.5 193.3 241.5 387.5 125.2 363.5 192.9 241.0 387.8 125.1 368.5 192.5 240.5 388.2 125.0 373.5 192.1 240.0 388.7 124.9 378.5 191.7 239.4 389.1 124.8 383.5 191.2 238.8 389.6 124.7 388.5 190.6 238.1 390.1 124.6 393.5 190.1 237.4 390.7 124.6 398.5 189.5 236.7 391.3 124.5 403.5 189.0 236.1 391.8 124.4 408.5 188.5 235.4 392.3 124.3 413.5 188.0 234.8 392.8 124.2 418.5 187.4 234.1 393.4 124.2 423.5 186.8 233.3 394.0 124.1 428.5 186.1 232.5 394.7 124.1 433.5 185.4 231.6 395.3 124.0 438.5 184.7 230.7 396.1 124.0 443.5 184.6 230.5 396.2 123.8 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-9 Sheet 3 of 4 Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 448.5 183.7 229.5 397.0 123.8 453.5 183.5 229.2 397.3 123.7 458.5 183.1 228.8 397.6 123.6 463.5 182.1 227.5 398.7 123.6 468.5 181.6 226.9 399.1 123.5 473.5 181.1 226.2 399.7 123.4 478.5 180.4 225.3 400.4 123.4 483.5 180.2 225.1 400.6 123.2 488.5 179.3 224.0 401.5 123.2 493.5 178.9 223.4 401.9 123.1 498.5 178.3 222.7 402.5 123.1 503.5 177.5 221.7 403.3 123.1 508.5 177.0 221.1 403.7 123.0 513.5 176.3 220.3 404.4 122.9 518.5 175.9 219.7 404.9 122.8 523.5 185.6 231.9 395.1 124.5 528.5 185.4 231.6 395.4 124.3 533.5 184.5 230.4 396.3 124.3 538.5 184.2 230.1 396.6 124.2 543.5 183.4 229.0 397.4 124.1 548.5 182.7 228.2 398.1 124.1 553.5 182.0 227.4 398.7 124.0 558.5 181.4 226.5 399.4 123.9 563.5 180.7 225.7 400.1 123.9 568.5 86.7 108.3 494.1 148.4 829.2 86.7 108.3 494.1 148.4 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-9 Sheet 4 of 4 Revision 18 October 2008 Break Path No. 1 Flow(1) Break Path No. 2 Flow(2) Time (s) (lbm/s) Thousand (Btu/s) (lbm/s) Thousand (Btu/s) 829.3 87.3 108.3 493.4 143.1 833.5 87.3 108.2 493.5 142.9 1,677.9 87.3 108.2 493.5 142.9 1,678.0 75.7 93.8 340.8 165.3 1,717.8 75.7 93.8 340.8 165.3 1,717.9 73.1 84.1 343.4 75.0 2,000.0 70.0 80.5 346.5 75.6 2,000.1 70.0 80.5 346.5 75.2 2,500.0 67.0 77.1 349.5 75.7 2,500.1 67.0 77.1 349.5 75.3 3,000.0 64.0 73.6 352.5 75.8 3,000.1 64.0 73.6 352.5 74.9 3,500.0 61.0 70.1 355.5 75.5 3,500.1 61.0 70.1 355.5 74.4 3,600.0 60.4 69.5 356.1 74.5 Notes: 1. Mass and energy exiting from the steam-generator side of the break (path 1). 2. Mass and energy exiting from the pump-side of the break (path 2). DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 6.2D-10 LOCA MASS AND ENERGY RELEASE ANALYSIS CORE DECAY HEAT FRACTION Time (sec) Decay Heat Generation Rate (Btu/Btu) 10 0.053876 15 0.050401 20 0.048018 40 0.042401 60 0.039244 80 0.037065 100 0.035466 150 0.032724 200 0.030936 400 0.027078 600 0.024931 800 0.023389 1000 0.022156 1500 0.019921 2000 0.018315 4000 0.014781 6000 0.013040 8000 0.012000 10000 0.011262 15000 0.010097 20000 0.009350 40000 0.007778 60000 0.006958 80000 0.006424 100000 0.006021 150000 0.005323 200000 0.004847 400000 0.003770 600000 0.003201 800000 0.002834 1000000 0.002580 DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 6.2D-11 DCPP UNIT 2 DEPS SSPS CASE - MASS BALANCE Time (s) .00 26.20 26.20 203.49 829.34 1,717.82 3,600.00 Mass (thousand lbm) Initial In RCS and ACC 745.68 745.68 745.68 745.68 745.68 745.68 745.68 Added Mass Pumped Injection .00 .00 .00 96.92 460.40 946.60 1,753.68 Total Added .00 .00 .00 96.92 460.40 946.60 1,753.68 *** Total Available *** 745.68 745.68 745.68 842.61 1,206.09 1,692.29 2,499.37 Distribution Reactor Coolant 527.43 46.67 76.70 138.09 138.09 138.09 138.09 Accumulator 218.25 169.81 139.77 .00 .00 .00 .00 Total Contents 745.68 216.48 216.48 138.09 138.09 138.09 138.09 Effluent Break Flow .00 529.19 529.19 693.62 1,057.10 1,566.55 2,350.37 ECCS Spill .00 .00 .00 .00 .00 .00 .00 Total Effluent .00 529.19 529.19 693.62 1,057.10 1,566.55 2,350.37 *** Total Accountable *** 745.68 745.67 745.67 831.72 1,195.19 1,704.65 2,488.46 DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 6.2D-12 DCPP UNIT 2 DEPS SSPS FAILURE ENERGY BALANCE Time (s) .00 26.20 26.20 203.49 829.34 1,717.82 3,600.00 Energy (million Btu) Initial Energy In RCS, ACC, SG 905.10 905.10 905.10 905.10 905.10 905.10 905.10 Added Energy Pumped Injection .00 .00 .00 5.63 26.73 62.65 181.64 Decay Heat .00 8.47 8.47 29.33 83.58 145.18 250.96 Heat from Secondary .00 15.91 15.91 15.91 15.91 15.91 15.91 Total Added .00 24.38 24.38 50.87 126.21 223.74 448.52 *** Total Available *** 905.10 929.48 929.48 955.97 1,031.31 1,128.84 1,353.62 Distribution Reactor Coolant 307.86 10.53 13.22 36.37 36.37 36.37 36.37 Accumulator 19.52 15.19 12.50 .00 .00 .00 .00 Core Stored 22.37 11.66 11.66 4.85 4.37 4.03 3.33 Primary Metal 152.45 145.03 145.03 120.11 80.86 60.54 48.23 Secondary Metal 110.78 110.04 110.04 101.22 74.90 51.21 40.06 Steam Generator 292.13 314.16 314.16 285.60 204.80 135.89 105.39 Total Contents 905.10 606.60 606.60 548.15 401.30 288.04 233.39 Effluent Break Flow .00 322.30 322.30 398.33 620.52 821.40 1,106.39 ECCS Spill .00 .00 .00 .00 .00 .00 .00 Total Effluent .00 322.30 322.30 398.33 620.52 821.40 1,106.39 *** Total Accountable *** 905.10 928.90 928.90 946.48 1,021.83 1,109.45 1,339.77 DCPP UNITS 1 & 2 FSAR UPDATE Revision 20 November 2011 TABLE 6.2D-13 DOUBLE-ENDED HOT-LEG BREAK SEQUENCE OF EVENTS Time (sec) Event Description 0.0 Break Occurs 1.1 Reactor Trip Occurs on Compensated Pressurizer Pressure Setpoint of 1859.7 psia and SG Throttle Valves Closed 4.0 Low Pressurizer Pressure SI Setpoint = 1694.7 psia Reached (Safety Injection begins after a 27 second delay and feedwater control valve starts to close) 13.0 Main Feedwater Control Valve Fully Closed 15.5 Broken Loop Accumulator Begins Injecting Water 15.6 Intact Loop Accumulator Begins Injecting Water 24.4 End of Blowdown Phase - Transient Modeling Terminated DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 6.2D-14 DIABLO CANYON UNIT 1 DOUBLE-ENDED PUMP SUCTION BREAK SEQUENCE OF EVENTS (MINIMUM SAFEGUARDS) Time (s) Event Description 0.0 Break Occurs and Loss-of-Offsite Power is Assumed 1.0 Reactor Trip Occurs on Compensated Pressurizer Pressure Setpoint of 1,859.7 psia and SG Throttle Valves Closed 4.0 Low Pressurizer Pressure SI Setpoint = 1,694.7 psia Reached (SI begins after a 27-second delay and feedwater control valve starts to close) 13.0 Main Feedwater Control Valve Closed 16.4 Broken-Loop Accumulator Begins Injecting Water 16.8 Intact-Loop Accumulator Begins Injecting Water 25.6 End of Blowdown Phase 31.1 Pumped Safety Injection Begins 48.7 CFCUs On 51.9 Broken Loop Accumulator Water Injection Ends 53.2 Intact Loop Accumulator Water Injection Ends 87.6 Containment Sprays Begin Injecting 193.7 End of Reflood for Minimum Safeguards Case 508.8 Mass and Energy Release Assumption: Broken-Loop SG Equilibration to 61.7 psia 889.2 Mass and Energy Release Assumption: Broken-Loop SG Equilibration to 40.7 psia 1,495.2 Mass and Energy Release Assumption: Intact-Loop SG Equilibration to 61.7 psia 1,678.0 Cold-Leg Recirculation Begins 1,695.6 Mass and Energy Release Assumption: Intact-Loop SG Equilibration to 39.7 psia 3,600.0 End of Sensible Heat Release from RCS and SGs 3,798.0 Containment Sprays Terminated 25,200.0 Switchover to Hot-Leg Recirculation DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 6.2D-15 DIABLO CANYON UNIT 2 DOUBLE-ENDED PUMP SUCTION BREAK SEQUENCE OF EVENTS (MINIMUM SAFEGUARDS) Time (sec) Event Description 0.0 Break Occurs and Loss-of-offsite Power is assumed 1.2 Reactor Trip Occurs on Compensated Pressurizer Pressure Setpoint of 1859.7 psia and SG Throttle Valves Closed 4.2 Low Pressurizer Pressure SI Setpoint = 1694.7 psia Reached (Safety Injection begins after a 27 second delay and feedwater control valve starts to close) 13.2 Main Feedwater Control Valve Closed 18.1 Broken Loop Accumulator Begins Injecting Water 18.6 Intact Loop Accumulator Begins Injecting Water 26.2 End of Blowdown Phase 31.3 Pumped Safety Injection Begins 48.7 CFCUs On 52.7 Broken Loop Accumulator Water Injection Ends 53.7 Intact Loop Accumulator Water Injection Ends 88.0 Containment Sprays Begin Injecting 203.5 End of Reflood for Minimum Safeguards Case 568.5 Mass and Energy Release Assumption: Broken Loop SG Equilibration to 61.7 psia 829.3 Mass and Energy Release Assumption: Broken Loop SG Equilibration to 40.7 psia 1,536.5 Mass and Energy Release Assumption: Intact Loop SG Equilibration to 61.7 psia 1,678.0 Cold-Leg Recirculation Begins 1,717.8 Mass and Energy Release Assumption: Intact Loop SG Equilibration to 39.7 psia 3,600.0 End of Sensible Heat Release from Reactor Coolant System and Steam Generators 3,798.0 Containment Sprays Terminated 25,200.0 Switchover to Hot-Leg Recirculation DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 6.2D-16 COMPARISON OF RCS CONDITIONS FOR SHORT-TERM SPRAY LINE BREAK MASS AND ENERGY RELEASES RCS Temperature (F) Original Design Basis RSG Analysis(1) Cold Leg 545.16 526.8 RCS Pressure (psia) (1) Cold Leg 2332.4 2344.2 (1) A 4.8°F temperature uncertainty has been subtracted from the Diablo Canyon Unit 1 replacement steam generator project nominal temperature conditions and 42.0 psi has been added to the cold-leg pressure of 2302.4 psia Note that Unit 1 bounds Unit 2 for short-term LOCA mass and energy applications.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-17 Sheet 1 of 2 Revision 18 October 2008 DIABLO CANYON CONTAINMENT LOCA INTEGRITY ANALYSIS PARAMETERS Parameter Value Auxiliary Service Water Temperature (°F) 64 RWST Water Temperature (°F) 90 Initial Containment Temperature (°F) 120 Initial Containment Pressure (psia) 16.0 Initial Relative Humidity (%) 18 Net Free Volume (ft3) 2,550,000 Reactor Containment Fan Coolers Total CFCUs 5 Analysis Maximum 3 Analysis Minimum 2 Containment High Setpoint (psig) 5.0 Delay Time (sec) Without Offsite Power 48.0 CCW Flow to the CFCUs (gpm) During Injection During Recirculation 8,000 7,450 Containment Spray Pumps Total CSPs 2 Analysis Maximum 2 Analysis Minimum 1 Flowrate (gpm) During Injection During Recirculation Table 6.2.D-18 0 Containment High High Setpoint (psig) 24.7 Spray Delay Time (sec) Without Offsite Power 80 Containment Spray Termination Time, (sec) Minimum Safeguards Maximum Safeguards (1 CSP) Maximum Safeguards (2 CSPs) 3,798 3,018 1,824 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.2D-17 Sheet 2 of 2 Revision 18 October 2008 Parameter Value ECCS Recirculation ECCS Cold-Leg Recirculation Switchover, sec Minimum Safeguards Maximum Safeguards (1 CSP) Maximum Safeguards (2 CSPs) 1,678 1,033 829 Containment ECCS Cold-Leg Recirculation Flow, (gpm) Minimum Safeguards (1 RHR train) Maximum Safeguards (2 RHR trains) 3,252.3 8,082.4 ECCS Hot-Leg Recirculation Switchover, sec 25,200 Containment ECCS Hot-Leg Recirculation Flow, (gpm) Minimum Safeguards (1 RHR train) Maximum Safeguards (2 RHR trains) 3,071.7 4,576.8 Component Cooling Water System Total CCW Heat Exchangers 2 Analysis Maximum 2 Analysis Minimum 1 CCW Flow Rate to RHR Heat Exchanger (gpm per available HX) 4,800 ASW Flow Rate to CCW Heat Exchanger (gpm per available HX) 10,300 CCW Misc. Heat Loads (MBTU/hr) During Injection During Recirculation 1.0 2.0 CCW Flow Rate to Misc. Heat Loads (gpm) During Injection During Recirculation 2,500 500 DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 6.2D-18 CONTAINMENT SPRAY FLOW RATES AS A FUNCTION OF CONTAINMENT PRESSURE Containment Pressure (psig) 1 CSP Spray Flow Rate (gpm) 2 CSPs Spray Flow Rate (gpm) 0 3036 6142 10 2926 5922 20 2806 5692 30 2686 5442 40 2546 5182 47 2456 4992 DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 6.2D-19 GOTHIC THERMAL CONDUCTOR MODELING No. Description Materials Surface Area (ft2) Thickness (in) Initial Temp (°F) 1 Concrete Interior Walls Paint Concrete 79965 0.0075 12 120 2 Concrete Floor Paint Concrete 13012 0.0075 24 120 3 SS Fuel Transfer Tube Stainless Steel 8852 0.144 120 4 SS Structures Stainless Steel 857 0.654 120 5 CS Structures Paint Carbon Steel 48024 0.0075 0.0815 120 6 CS Structures Paint Carbon Steel 60941 0.0075 0.133 120 7 CS Lined Containment Concrete Shell Paint Carbon Steel HGap = 10 Concrete 90560 0.0075 0.375 0.0168 35.6007 120 8 CS Structures Paint Carbon Steel 42517 0.0075 0.567 120 9 CS Structures Paint Carbon Steel 56494 0.0075 0.738 120 10 CS Structures Paint Carbon Steel 31902 0.0075 1.355 120 11 CS SG Snubbers Paint Carbon Steel 522 0.0075 3.0 120 12 CS RCP Motors Paint Carbon Steel 1610 0.0075 6.99 200
DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 6.2D-20 MATERIAL PROPERTIES FROM REFERENCE 15 GOTHIC MODEL Material Thermal Conductivity (BTU/hr-ft-°F) Vol. Heat Capacity (BTU/ft3-°F) Paint 0.2083 35.91 Carbon Steel 28 58.8 Air Gap 0.0148 0.018 Concrete 1.04 23.4 Stainless Steel 8.6 58.8
DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 6.2D-21 SUMMARY OF LOCA PEAK CONTAINMENT PRESSURE AND TEMPERATURES Break Location Peak Pressure (psig) Time (sec) Peak Gas Temp (F) Time (sec) Press @ 24 hours (psig) Temp @ 24 hours (°F) DEHL 41.4 23.8 261.8 23.4 - - DEPS min SI 39.8 24.1 259.3 24.1 8.9 167.5 Acceptance Criteria <47 - - - <50 - DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 6.2D-22 INITIAL CONTAINMENT CONDITIONS, FAN COOLER AND CONTAINMENT SPRAY PUMP ASSUMPTIONS Parameter ValueContainment net free volume (ft3) 2,550,000Initial containment temperature (°F) 120.0Initial containment pressure (psia) 16.0Initial relative humidity (%) 18Number of fan coolers - All - Analysis maximum - Containment safeguards failure 532Hi containment pressure setpoint (psig) 5.0Delay (sec) from high containment pressure setpoint to start of fan coolers 38.0Flow Heat Removal 1000 59.121500 73.182000 82.472500 89.033000 93.933250 95.90Containment fan cooler heat removal (MBTU/hr) vs. Component Cooling Water (CCW) Flow rate (gpm) assuming Tsat = 271°F and TCCW = 125°F 3500 97.73Containment fan cooler air flowrate (ft3/min per fan cooler) 47,000Number of spray pumps - All - Containment safeguards failure 21Hi-hi containment pressure setpoint (psig) 24.7Delay (sec) from high-high containment pressure setpoint to start of containment sprays 74.5Press Flow 1 Pump Flow 2 Pumps 0 3036 614210 2926 592220 2806 569230 2686 544240 2546 5182Containment spray flowrate (gpm) vs. containment pressure (psig) 47 2456 4992RWST/containment spray water temperature (°F) 90.0
DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 6.2D-23 PEAK PRESSURES AND TEMPERATURES FOR CONTAINMENT RESPONSE TO STEAMLINE BREAKS Description Case Break Initial Power Failure Peak Pressure (psig @ sec) Peak Temperature (°F @ sec) 1a 1.4 ft2 DER 102% containment safeguards 29.7 @ 234 281.8 @ 225 2a 1.4 ft2 DER 70% containment safeguards 30.5 @ 615 281.8 @ 239 3a 1.4 ft2 DER 30% containment safeguards 32.7 @ 614 278.8 @ 252 4a 1.4 ft2 DER 0% containment safeguards 32.9 @ 611 277.9 @ 260 1b 1.4 ft2 DER 102% FRV 37.3 @ 466 280.7 @ 226 2b 1.4 ft2 DER 70% FRV 42.8 @ 608 280.6 @ 239 3b 1.4 ft2 DER 30% FRV 40.5 @ 693 277.4 @ 263 4b 1.4 ft2 DER 0% FRV 31.8 @ 415 275.6 @ 265 1c 1.4 ft2 DER 102% MSIV/CV 31.4 @ 253 309.9 @ 26 2c 1.4 ft2 DER 70% MSIV/CV 32.8 @ 296 310.4 @ 26 3c 1.4 ft2 DER 30% MSIV/CV 33.4 @ 403 311.2 @ 25 4c 1.4 ft2 DER 0% MSIV/CV 34.5 @ 419 312.1 @ 24 5c 0.73 ft2 Split Break 102% MSIV/CV 34.0 @ 631 295.2 @ 118 6c 0.87 ft2 Split Break 70% MSIV/CV 34.4 @ 667 301.1 @ 104 7c 0.94 ft2 Split Break 30% MSIV/CV 33.4 @ 724 302.2 @ 98 8c 0.90 ft2 Split Break 0% MSIV/CV 31.3 @ 726 296.6 @ 109 DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 6.2D-24 SEQUENCE OF EVENTS STEAMLINE BREAK, FRV FAILURE, 70% POWER Event Time (sec) SI Low Steamline Pressure Setpoint Reached 0.051 AFW Initiation 0.051 Closure of Steamline CV on Faulted Loop 0.1 Reactor Trip - Start of Rod Motion 2.1 Faulted Loop FRV Fully Closed Failed Open Hi-1 Containment Pressure Setpoint Reached 5.7 SI Flow Starts 27.1 Fan Coolers Start 43.7 Faulted Loop Backup FIV Fully Closed 64.1 SI Boron Reaches Core 148 Hi-2 Containment Pressure Setpoint Reached 164.2 Containment Sprays Start 239.2 Accumulator Injection n/a AFW Re-aligned from Faulted SG 600 Peak Containment Pressure Occurs 608 Mass Release Terminated 630
DCPP UNITS 1 & 2 FSAR UPDATE FIGURE 6.2D-1 STEAMLINE BREAK MASS RELEASE TO CONTAINMENT 1.4 ft2 DER. 70% POWER, FRV FAILURE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008 DCPP UNITS 1 & 2 FSAR UPDATE FIGURE 6.2D-2 STEAMLINE BREAK ENTHALPY OF BREAK EFFLUENT 1.4 ft2 DER. 70% POWER, FRV FAILURE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008 DCPP UNITS 1 & 2 FSAR UPDATE Diablo Canyon Unit 2 LOCA Containment AnalysisDouble Ended Hot Leg BreaksContainment Pressure051015202530354045110100Time (seconds)Pressure (psig) FIGURE 6.2D-3 CONTAINMENT PRESSURE DOUBLE-ENDED HOT LEG BREAK UNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008 DCPP UNITS 1 & 2 FSAR UPDATE Diablo Canyon Unit 2 LOCA Containment AnalysisDouble Ended Hot Leg BreakContainment Gas Temperature120140160180200220240260280110100Time (seconds)Temperature (°F) FIGURE 6.2D-4 CONTAINMENT STEAM TEMPERATURE DOUBLE-ENDED HOT LEG BREAK UNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008 DCPP UNITS 1 & 2 FSAR UPDATE Diablo Canyon Unit 2 LOCA Containment AnalysisDouble Ended Hot Leg BreakContainment Sump Temperature120140160180200220240260280110100Time (seconds)Temperature (°F) FIGURE 6.2D-5 CONTAINMENT SUMP TEMPERATURE DOUBLE-ENDED HOT LEG BREAK UNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008 DCPP UNITS 1 & 2 FSAR UPDATE Diablo Canyon LOCA Containment AnalysisDEPS Break with Minimum SafeguardsContainment Pressure0.05.010.0 15.0 20.025.030.0 35.0 40.0 45.011010010001000010000010000001E+07Time (seconds)Pressure (psig)Unit 1Unit 2 FIGURE 6.2D-6 CONTAINMENT PRESSURE DOUBLE-ENDED PUMP SUCTION BREAK UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008 DCPP UNITS 1 & 2 FSAR UPDATE Diablo Canyon LOCA Containment AnalysisDEPS Break with Minimum SafeguardsContainment Gas Temperature10012014016018020022024026028011010010001000010000010000001E+07Time (seconds)Temperature (°F)Unit 1Unit 2 FIGURE 6.2D-7 CONTAINMENT TEMPERATURE DOUBLE-ENDED PUMP SUCTION BREAK UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008 DCPP UNITS 1 & 2 FSAR UPDATE Diablo Canyon LOCA Containment AnalysisDEPS Break with Minimum SafeguardsContainment Sump Temperature10012014016018020022024026028011010010001000010000010000001E+07Time (seconds)Temperature (°F)Unit 1Unit 2 FIGURE 6.2D-8 CONTAINMENT SUMP TEMPERATURE DOUBLE-ENDED PUMP SUCTION BREAK UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008 DCPP UNITS 1 & 2 FSAR UPDATE FIGURE 6.2D-9 CONTAINMENT PRESSURE RESPONSE TO A STEAMLINE BREAK 1.4 ft2 DER, 70% POWER, FRV FAILURE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008 DCPP UNITS 1 & 2 FSAR UPDATE FIGURE 6.2D-10 CONTAINMENT TEMPERATURE RESPONSE TO A STEAMLINE BREAK 1.4 ft2 DER, 70% POWER, FRV FAILURE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008 DCPP UNITS 1 & 2 FSAR UPDATE
APPENDIX 6.3A SINGLE FAILURE CAPABILITY
Prepared by Westinghouse Electric Corporation DCPP UNITS 1 & 2 FSAR UPDATE 6.3A-1 Revision 15 September 2003 Appendix 6.3A SINGLE FAILURE CAPABILITY 6.3A.1 Definition of Terms Definitions of terms used in this appendix are located in Section 3.1.1. 6.3A.2 Active Failure Criteria The emergency core cooling system (ECCS) is designed to accept a single failure following the incident without loss of its protective function. The system design will tolerate the failure of any single active component in the ECCS itself or in the necessary associated service systems at any time during the period of required system operations following the incident.
A single active failure analysis is presented in Table 6.3A-1, and demonstrates that the ECCS can sustain the failure of any single active component in either the short- or long-term and still meet the level of performance for core cooling.
Since the operation of the active components of the ECCS following a steam line rupture is identical to that following a loss-of-coolant accident (LOCA), the same analysis is applicable and the ECCS can sustain the failure of any single active component and still meet the level of performance for the addition of shutdown reactivity. 6.3A.3 Passive Failure Criteria The following philosophy provides for necessary redundancy in component and system arrangement to meet the intent of the AEC Design Criteria on single failure as it specifically applies to failure of passive components in the ECCS. Thus, for the long-term, the system design is based on accepting either a passive or an active failure. 6.3A.3.1 Redundancy of Flow Paths and Components for Long-Term Emergency Core Cooling In the design of the ECCS, Westinghouse utilizes the following criteria:
(1) During the long-term cooling period following a loss of coolant, the emergency core cooling flow paths are separable into two subsystems, either of which can provide minimum core cooling functions and return spilled water from the floor of the containment back to the reactor coolant system (RCS).
DCPP UNITS 1 & 2 FSAR UPDATE 6.3A-2 Revision 15 September 2003 (2) Either of the two subsystems can be isolated and removed for service in the event of a leak outside the containment. (3) Adequate redundancy of check valves is provided to tolerate failure of a check valve during the long term as a passive component. (4) Should one of these two subsystems be isolated in this long-term period, the other subsystem remains operable. (5) Provisions are also made in the design to detect leakage from components outside the containment and collect this leakage. Thus, for the long-term emergency core cooling function, adequate core cooling capacity exists with one flow path removed from service whether isolated due to a leak, because of blocking of one flow path, or because failure in the containment results in a spill of the delivery of one subsystem. 6.3A.3.2 Subsequent Leakage From Components in Engineered Safety Systems With respect to piping and mechanical equipment outside the containment, considering the provisions for visual inspection and leak detection, leaks will be detected before they propagate to major proportions. A review of the equipment in the system indicates that the largest sudden leak potential would be the sudden failure of a pump shaft seal. Evaluation of leak rate assuming only the presence of a seal retention ring around the pump shaft showed flows less than 50 gpm would result. Piping leaks, valve packing leaks, or flange gasket leaks have been of a nature to build up slowly with time and are considered less severe than the pump seal failure. Larger leaks in the ECCS are prevented by the following:
(1) The system piping is located within a controlled area on the plant site. (2) The piping system receives periodic pressure tests and is accessible for periodic visual inspection. (3) The piping is austenitic stainless steel that, due to its ductility, can withstand severe distortion without failure.
Based on this review, the design of the auxiliary building and related equipment is based on handling of leaks up to a maximum of 50 gpm. Means are also provided to detect and isolate such leaks in the emergency core cooling flow path within 30 minutes.
With these design ground rules, continued function of the ECCS will meet minimum core cooling requirements, and offsite doses resulting from the leak will be within 10 CFR 100 limits. DCPP UNITS 1 & 2 FSAR UPDATE 6.3A-3 Revision 15 September 2003 A single passive failure analysis is presented in Table 6.3A-2. It demonstrates that the ECCS can sustain a single passive failure during the long-term phase and still retain an intact flow path to the core to supply sufficient flow to maintain the core covered and effect the removal of decay heat. The procedure followed to establish the alternate flow path also isolates the component that failed.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3A-1 Sheet 1 of 3 Revision 18 October 2008 SINGLE ACTIVE FAILURE ANALYSIS FOR EMERGENCY CORE COOLING SYSTEM COMPONENTS SHORT-TERM PHASE Component Malfunction Comments A. Accumulator Deliver to broken Totally passive system with one accumulator per loop. loop Evaluation based on one spilling accumulator. B. Pump 1. Centrifugal charging Fails to start Two provided; evaluation based on operation of one.
- 2. Safety injection Fails to start Two provided; evaluation based on operation of one. 3. Residual heat removal Fails to start Two provided; evaluation based on operation of one.
- 4. Residual heat removal Fails to trip on Operator trips pump locally at the breaker. RWST Low Level C. Automatically Operated Valves 1. Charging injection isolation
- a. Inlet Fails to open Two parallel lines; one valve in either line required to open
- b. Outlet Fails to open Two parallel lines; one valve in either line required to open. 2. Centrifugal Charging Pumps
- a. Suction line from refueling Fails to open Two parallel lines; only one valve in either line is water storage tank required to open.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3A-1 Sheet 2 of 3 Revision 18 October 2008 SHORT-TERM PHASE (Continued) Component Malfunction Comments b. Discharge line to the Fails to close Two valves in series; only one valve required to close. normal charging path c. Minimum flow line Fails to close Two valves in series; only one valve required to close.
- d. Suction line from Fails to close Two valves in series; only one valve required to close. volume control tank LONG-TERM PHASE A. Valves operated from Control Room for Recirculation
- 1. Containment sump recirculation Fails to open Two parallel lines; only one valve in either line is isolation required to open.
- 2. Residual heat removal pump Fails to close Check valve in series with gate valve, operation of suction line from refueling only one valve required. water storage tank
- 3. Safety injection pump suction Fails to close Check valve in series with gate valve, operation of line from refueling water only one valve required. storage tank
- 4. Centrifugal charging pump Fails to close Check valve in series with two parallel gate valves. (CCP1 and 2) suction line from Operation of either the check valve or the gate valve refueling water storage tank required.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 6.3A-1 Sheet 3 of 3 Revision 18 October 2008 LONG-TERM PHASE (Continued) Component Malfunction Comments 5. Safety injection pump suction Fails to open Separate and independent high head injection path taking line at discharge of residual suction from discharge of residual heat exchanger No. 1. A heat exchanger No. 2 crossover line allows flow from one heat exchanger to reach both safety injection and charging pumps, if necessary. 6. Centrifugal charging pump Fails to open Separate and independent high head injection path taking (CCP1 and CCP2) suction line at suction from dischange of residual heat exchanger No. 2. A discharge of residual heat exchanger No. 1 crossover line allows flow from one heat exchanger to reach both safety injection and charging pumps, if necessary. 7. Centifugal charging pump (CCP1 Fails to open Two parallel lines; only one valve in either line And CCP2) crossover line to safety is required to open. injection pump suction B. Pumps 1. Residual heat removal pump Fails to start Two provided. Evaluation based on operation of one. 2. Charging pump Fails to operate Same as short-term phase 3. Safety injection pumps Fails to operate Same as short-term phase DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 6.3A-2 EMERGENCY CORE COOLING SYSTEM RECIRCULATION PIPING PASSIVE FAILURE ANALYSIS LONG-TERM PHASE Flow Path Indication of Loss of Flow Path Alternate Flow Path Low Head Recirculation From containment sump to low head injection header via the residual heat removal pumps and the residual heat exchangers Reduced flow in the discharge line from one of the residual heat exchangers (one flow monitor in each discharge line). Accumulation of water in a residual heat removal pump compartment or auxiliary building sump. Via the independent identical low head flow path utilizing the second residual heat exchanger. High Head Recirculation From containment sump to the high head injection header via residual heat removal pump residual heat exchanger, and the high head injection pumps 1) Increasing activity of the air exhausted from the RHR heat exchanger rooms or in the plant vent. 2) Accumulation of water in a residual heat removal pump compartment or the auxiliary building sump 3) Increasing ESF pump room temperature 4) Reduced ECCS flow rates From containment sump to the high head injection headers via alternate residual heat removal pump, residual heat exchanger, and the alternate high head charging pump DCPP UNITS 1 & 2 FSAR UPDATE Chapter 7 INSTRUMENTATION AND CONTROLS CONTENTS Section Title Page i Revision 21 September 2013
7.1 INTRODUCTION
7.1-1 7.1.1 Identification of Safety-Related Systems 7.1-5
7.1.2 Identification of Safety Criteria 7.1-7 7.1.2.1 Design Bases 7.1-7 7.1.2.2 Independence of Redundant Safety-Related Systems 7.1-11 7.1.2.3 Physical Identification of Safety-Related Equipment 7.1-12 7.1.2.4 Conformance with IEEE Standards 7.1-13 7.1.2.5 Conformance with Other Applicable Documents 7.1-14
7.1.3 References 7.1-15
7.2 REACTOR TRIP SYSTEM 7.2-1
7.2.1 Description 7.2-1 7.2.1.1 System Description 7.2-1 7.2.1.2 Design Basis Information 7.2-18 7.2.1.3 Current System Drawings 7.2-21
7.2.2 Analysis 7.2-21 7.2.2.1 Evaluation of Design 7.2-21 7.2.2.2 Evaluation of Compliance with Applicable Codes and Standards 7.2-23 7.2.2.3 Specific Control and Protection Interactions 7.2-37
7.2.3 Tests and Inspections 7.2-41 7.2.3.1 In-Service Tests and Inspections 7.2-41 7.2.3.2 Compliance with Safety Guide 22 7.2-42
7.2.4 References 7.2-43
7.2.5 Reference Drawings 7.2-46
7.3 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM 7.3-1
7.3.1 Design Bases 7.3-1 7.3.1.1 General Design Criteria 2, 1967 - Performance Standards 7.3-1
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 7 CONTENTS (Continued) Section Title Page ii Revision 21 September 2013 7.3.1.2 General Design Criterion 11, 1967 - Control Room 7.3-1 7.3.1.3 General Design Criterion 15, 1967 - Engineered Safety Features Protection Systems 7.3-1 7.3.1.4 General Design Criterion 19, 1967 - Protection Systems Reliability 7.3-1 7.3.1.5 General Design Criterion 20, 1967 - Protection Systems Redundancy and Independence 7.3-1 7.3.1.6 General Design Criterion 21, 1967 - Single Failure Criterion 7.3-2 7.3.1.7 General Design Criterion 22, 1967 - Separation of Protection and Control Instrumentation Systems 7.3-2 7.3.1.8 General Design Criterion 23, 1967 - Protection Against Multiple Disability for Protection Systems 7.3-2 7.3.1.9 General Design Criterion 24, 1967 - Emergency Power for Protection Systems 7.3-2 7.3.1.10 General Design Criterion 25, 1967 - Demonstration of Functional Operability of Protection Systems 7.3-2 7.3.1.11 General Design Criterion 26, 1967 - Protection Systems Fail-Safe Design 7.3-2 7.3.1.12 General Design Criterion 37, 1967 - Engineered Safety Features Basis for Design 7.3-2 7.3.1.13 General Design Criterion 38, 1967 - Reliability and Testability of Engineered Safety Features 7.3-3 7.3.1.14 General Design Criterion 40, 1967 - Missile Protection 7.3-3 7.3.1.15 General Design Criterion 48, 1967 - Testing of Operational Sequence of Emergency Core Cooling Systems 7.3-3 7.3.1.16 General Design Criterion 49, 1967 - Containment Design Basis 7.3-3 7.3.1.17 10 CFR 50.49 - Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants 7.3-3 7.3.1.18 Safety Guide 22, February 1972 - Periodic Testing of Protection System Actuation Functions 7.3-3
7.3.2 System Description 7.3-3 7.3.2.1 Functional Design 7.3-3 7.3.2.2 Signal Computation 7.3-5 7.3.2.3 Devices Requiring Actuation 7.3-5 7.3.2.4 Implementation of Functional Design 7.3-6 7.3.2.5 Additional Design Information 7.3-9 7.3.2.6 Current System Drawings 7.3-10 7.3.3 Safety Evaluation 7.3-10 7.3.3.1 General Design Criteria 2, 1967 - Performance Standards 7.3-10 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 7 CONTENTS (Continued) Section Title Page iii Revision 21 September 2013 7.3.3.2 General Design Criterion 11, 1967 - Control Room 7.3-10 7.3.3.3 General Design Criterion 15, 1967 - Engineered Safety Features Protection Systems 7.3-11 7.3.3.4 General Design Criterion 19, 1967 - Protection Systems Reliability 7.3-12 7.3.3.5 General Design Criterion 20, 1967 - Protection Systems Redundancy and Independence 7.3-13 7.3.3.6 General Design Criterion 21, 1967 - Single Failure Criterion 7.3-13 7.3.3.7 General Design Criterion 22, 1967 - Separation of Protection and Control Instrumentation Systems 7.3-14 7.3.3.8 General Design Criterion 23, 1967 - Protection Against Multiple Disability for Protection Systems 7.3-14 7.3.3.9 General Design Criterion 24, 1967 - Emergency Power for Protection Systems 7.3-15 7.3.3.10 General Design Criterion 25, 1967 - Demonstration of Functional Operability of Protection Systems 7.3-15 7.3.3.11 General Design Criterion 26, 1967 - Protection Systems Fail-Safe Design 7.3-15 7.3.3.12 General Design Criterion 37, 1967 - Engineered Safety Features Basis for Design 7.3-16 7.3.3.13 General Design Criterion 38, 1967 - Reliability and Testability of Engineered Safety Features 7.3-16 7.3.3.14 General Design Criterion 40, 1967 - Missile Protection 7.3-16 7.3.3.15 General Design Criterion 48, 1967 - Testing of Operational Sequence of Emergency Core Cooling Systems 7.3-16 7.3.3.16 General Design Criterion 49, 1967 - Containment Design Basis 7.3-17 7.3.3.17 10 CFR 50.49 - Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants 7.3-17 7.3.3.18 Safety Guide 22, February 1972 - Periodic Testing of Protection System Actuation Functions 7.3-17
7.3.4 Compliance with IEEE Standards 7.3-18 7.3.4.1 Evaluation of Compliance with IEEE-279, 1971 - Criteria For Protection Systems for Nuclear Power Generating Stations 7.3-18 7.3.4.2 Evaluation of Compliance with IEEE-308-1971, Criteria for Class 1E Electric Systems for Nuclear Power Generating Stations 7.3-25 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 7 CONTENTS (Continued) Section Title Page iv Revision 21 September 2013 7.3.4.3 Evaluation of Compliance with IEEE-323-1971, Trial-Use Standard: General Guide for Qualifying Class I Electric Equipment for Nuclear Power Generating Stations 7.3-26 7.3.4.4 Evaluation of Compliance with IEEE-338-1971, Trial-Use Criteria for the Periodic Testing of Nuclear Power Generating Station Protection Systems 7.3-26 7.3.4.5 Evaluation of Compliance with IEEE-344-1971, Trial-Use Guide for Seismic Qualifications of Class I Electric Equipment for Nuclear Power Generating Stations 7.3-26 7.3.4.6 Evaluation of Compliance with IEEE-317-1971, Electric Penetration Assemblies in Containment Structures for Nuclear Fueled Power Generating Stations 7.3-26 7.3.4.7 Evaluation of Compliance with IEEE-336-1971, Installation, Inspection and Testing Requirements for Instrumentation and Electric Equipment During the Construction of Nuclear Power Generating Stations 7.3-27 7.3.4.8 Eagle 21 and Process Control System Design, Verification and Validation 7.3-27 7.3.5 References 7.3-27
7.3.6 Reference Drawings 7.3-32
7.4 SYSTEMS REQUIRED FOR SAFE SHUTDOWN 7.4-1
7.4.1 Design Bases 7.4-1 7.4.1.1 General Design Criterion 3, 1971 - Fire Protection 7.4-1 7.4.1.2 General Design Criterion 11, 1967 - Control Room 7.4-1 7.4.1.3 General Design Criterion 12, 1967 - Instrumentation and Control Systems 7.4-1
7.4.2 Description 7.4-2 7.4.2.1 Safe Shutdown Equipment 7.4-2 7.4.2.2 Equipment, Services, and Approximate Time Required After Incident that Requires Hot Shutdown (MODE 4) 7.4-10 7.4.2.3 Equipment and Systems Available for Cold Shutdown (MODE 5) 7.4-10 7.4.3 Safety Evaluation 7.4-11 7.4.3.1 General Design Criterion 3, 1971 - Fire Protection 7.4-11 7.4.3.2 General Design Criterion 11, 1967 - Control Room 7.4-11 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 7 CONTENTS (Continued) Section Title Page v Revision 21 September 2013 7.4.3.3 General Design Criterion 12, 1967 - Instrumentation and Control Systems 7.4-12
7.4.4 References 7.4-13
7.4.5 Reference Drawings 7.4-16
7.5 SAFETY-RELATED DISPLAY INSTRUMENTATION 7.5-1
7.5.1 Design Bases 7.5-1 7.5.1.1 General Design Criterion 2, 1967 - Performance Standards 7.5-1 7.5.1.2 General Design Criterion 11, 1967 - Control Room 7.5-1 7.5.1.3 General Design Criterion 12, 1967 - Instrumentation and Control Systems 7.5-1 7.5.1.4 General Design Criterion 17, 1967 - Monitoring Radioactivity Releases 7.5-1 7.5.1.5 10 CFR 50.49 - Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants 7.5-1 7.5.1.6 Regulatory Guide 1.97, Revision 3, May 1983 - Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident 7.5-1 7.5.1.7 NUREG-0737 (Items I.D.2, II.D.3, II.E.1.2, II.F.1, II.F.2, and III.A.1.2), November 1980 - Clarification of TMI Action Plan Requirements 7.5-2
7.5.2 Description 7.5-2 7.5.2.1 Post-Accident Reactor Coolant Pressure and Containment Monitors 7.5-3 7.5.2.2 Instrumentation for Detection of Inadequate Core Cooling 7.5-4 7.5.2.3 Plant Vent Post-Accident Radiation Monitors 7.5-7 7.5.2.4 ALARA Monitors for Post-Accident Monitor Access 7.5-8 7.5.2.5 Radioactive Gas Decay Tank Pressure 7.5-8 7.5.2.6 Auxiliary Feedwater Flow Indication 7.5-8 7.5.2.7 Dedicated Shutdown Panel 7.5-8 7.5.2.8 Pressurizer Safety Relief Valve Position Indication System 7.5-9 7.5.2.9 Emergency Response Facility Data System 7.5-9 7.5.2.10 Safety Parameter Display System 7.5-12
7.5.3 Safety Evaluation 7.5-13 7.5.3.1 General Design Criterion 2, 1967 - Performance Standards 7.5-13 7.5.3.2 General Design Criterion 11, 1967 - Control Room 7.5-13 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 7 CONTENTS (Continued) Section Title Page vi Revision 21 September 2013 7.5.3.3 General Design Criterion 12, 1967 - Instrumentation and Control Systems 7.5-15 7.5.3.4 General Design Criterion 17, 1967 - Monitoring Radioactivity Releases 7.5-15 7.5.3.5 10 CFR 50.49 - Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants 7.5-16 7.5.3.6 Regulatory Guide 1.97, Revision 3, May 1983 - Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident 7.5-16 7.5.3.7 NUREG-0737 (Items I.D.2, II.D.3, II.E.1.2, II.F.1, II.F.2, and III.A.1.2), November 1980 - Clarification of TMI Action Plan Requirements 7.5-18
7.5.4 References 7.5-21
7.5.5 Reference Drawings 7.5-25
7.6 ALL OTHER INSTRUMENTATION SYSTEMS REQUIRED FOR SAFETY 7.6-1 7.6.1 Design Bases 7.6-1 7.6.1.1 General Design Criterion 2, 1967 - Performance Standards 7.6-1 7.6.1.2 General Design Criterion 11, 1967 - Control Room 7.6-1 7.6.1.3 General Design Criterion 12, 1967 - Instrumentation and Control Systems 7.6-1 7.6.1.4 10 CFR 50.49 - Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants 7.6-1 7.6.1.5 10 CFR 50.62 - Requirements for Reduction of Risk from Anticipated Transients Without Scrams (ATWS) Events for Light-Water-Cooled Nuclear Power Plants 7.6-1
7.6.2 Description 7.6-2 7.6.2.1 Residual Heat Removal Isolation Valves 7.6-2 7.6.2.2 Pipe Break Isolation System 7.6-3 7.6.2.3 ATWS Mitigation System Actuation Circuitry (AMSAC) 7.6-3
7.6.3 Safety Evaluation 7.6-4 7.6.3.1 General Design Criterion 2, 1967 - Performance Standards 7.6-4 7.6.3.2 General Design Criterion 11, 1967 - Control Room 7.6-4 7.6.3.3 General Design Criterion 12, 1967 - Instrumentation and Control Systems 7.6-5 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 7 CONTENTS (Continued) Section Title Page vii Revision 21 September 2013 7.6.3.4 10 CFR 50.49 - Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants 7.6-6 7.6.3.5 10 CFR 50.62 - Requirements for Reduction of Risk from Anticipated Transients Without Scrams (ATWS) Events for Light-Water-Cooled Nuclear Power Plants 7.6-6
7.6.4 References 7.6-7
7.6.5 Reference Drawings 7.6-11
7.7 CONTROL SYSTEMS NOT REQUIRED FOR SAFETY 7.7-1
7.7.1 Design Bases 7.7-1 7.7.1.1 General Design Criterion 11, 1967 - Control Room 7.7-1 7.7.1.2 General Design Criterion 12, 1967 - Instrumentation and Control Systems 7.7-1 7.7.1.3 General Design Criterion 13, 1967 - Fission Process Monitors and Controls 7.7-1 7.7.1.4 General Design Criterion 22, 1967 - Separation of Protection and Control Instrumentation Systems 7.7-1 7.7.1.5 General Design Criterion 27, 1967 - Redundancy of Reactivity Control 7.7-2 7.7.1.6 General Design Criterion 31, 1967 - Reactivity Control Systems Malfunction 7.7-2
7.7.2 System Description 7.7-2 7.7.2.1 Reactor Control System 7.7-4 7.7.2.2 Rod Control System 7.7-5 7.7.2.3 Plant Control Signals for Monitoring and Indicating 7.7-6 7.7.2.4 Plant Control System Interlocks 7.7-11 7.7.2.5 Pressurizer Pressure Control 7.7-13 7.7.2.6 Pressurizer Water Level Control 7.7-13 7.7.2.7 Steam Generator Water Level Control 7.7-14 7.7.2.8 Steam Dump Control 7.7-15 7.7.2.9 Incore Instrumentation 7.7-16 7.7.2.10 Control Locations 7.7-19
7.7.3 Safety Evaluation 7.7-25 7.7.3.1 General Design Criterion 11, 1967 - Control Room 7.7-25 7.7.3.2 General Design Criterion 12, 1967 - Instrumentation and Control Systems 7.7-26 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 7 CONTENTS (Continued) Section Title Page viii Revision 21 September 2013 7.7.3.3 General Design Criterion 13, 1967 - Fission Process Monitors and Controls 7.7-29 7.7.3.4 General Design Criterion 22, 1967 - Separation of Protection and Control Instrumentation Systems 7.7-29 7.7.3.5 General Design Criterion 27, 1967 - Redundancy of Reactivity Control 7.7-30 7.7.3.6 General Design Criterion 31, 1967 - Reactivity Control Systems Malfunction 7.7-32
7.7.4 References 7.7-32
7.7.5 Reference Drawings 7.7-33
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 7 TABLES Table Title ix Revision 21 September 2013 7.2-1 List of Reactor Trips 7.2-2 Protection System Interlocks
7.2-3 Trip Correlation
7.3-1 Instrumentation Operating Condition for Engineered Safety Features
7.3-2 Engineered Safety Features Actuation System Instrumentation Operating Conditions for Isolation Functions 7.3-3 Interlocks for Engineered Safety Features Actuation System
7.5-1 Main Control Board Indicators and/or Recorders Available to the Operator (Conditions II and III Events) 7.5-2 Main Control Board Indicators and/or Recorders Available to the Operator (Condition IV Events) 7.5-3 Control Room Indicators and/or Recorders Available to the Operator to Monitor Significant Plant Parameters During Normal Operation 7.5-4 Postaccident Monitoring Panel Indicators and/or Recorders Available to the Operator 7.5-5 Information Required on the Subcooled Margin Monitors
7.5-6 Summary of Compliance with Regulatory Guide 1.97, Rev. 3
7.7-1 Plant Control System Interlocks
7.7-2 Deleted in Revision 14
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 7 FIGURES Figure Title x Revision 21 September 2013 7.2-1(a) Instrumentation and Control System Logic Diagrams 7.2-2 Setpoint Reduction Function for Overpower and Overtemperature T Trips 7.2-3 Illustration of Overpower and Overtemperature T Trip Setpoints T Versus Tavg 7.2-4 Pressurizer Sealed Reference Leg Level System
7.2-5 Design to Achieve Isolation Between Channels
7.2-6 Seismic Sensor Locations (2 Sheets)
7.2-7 Deleted in Revision 8 (Reassigned as Figure 7.2-1, Sheet 18)
7.3-1(a) Logic Diagram Symbols 7.3-2(a) Logic Diagram - Reactor Coolant Pump 7.3-3(a) Logic Diagram - Reciprocating Charging Pump 7.3-4(a) Logic Diagram - Centrifugal Charging Pumps 7.3-5(a) Logic Diagram - Auxiliary Saltwater Pumps 7.3-6(a) Logic Diagram - Containment Fan Coolers 7.3-7(a) Logic Diagram - Component Cooling Water Pumps 7.3-8(a) Logic Diagram - Auxiliary Feedwater Pumps 7.3-9(a) Logic Diagram - Residual Heat Removal Pumps 7.3-10(a) Logic Diagram - Safety Injection Pumps 7.3-11(a) Logic Diagram - Containment Spray Pumps 7.3-12(a) Logic Diagram - Primary Makeup Water Pumps 7.3-13(a) Logic Diagram - Boric Acid Transfer Pumps DCPP UNITS 1 & 2 FSAR UPDATE Chapter 7 FIGURES (Continued) Figure Title xi Revision 21 September 2013 7.3-14(a) Schematic Diagram - Auxiliary Feedwater Motor-Operated Valves 7.3-15(a) Schematic Diagram - Turbine Control 7.3-16(a) Schematic Diagram - Feedwater Pump Turbine Control 7.3-17(a) Schematic Diagram - Motor-Driven Auxiliary Feedwater Pumps 7.3-18(a) Schematic Diagram - Auxiliary Feedwater Pumps Turbine Control 7.3-19(a) Schematic Diagram - Feedwater Motor-Operated Isolation Valves 7.3-20(a) Schematic Diagram - Reactor Coolant Pump 7.3-21(a) Schematic Diagram - Reactor Coolant Motor-Operated Valves and Reactor Coolant System Solenoid Valves 7.3-22(a) Schematic Diagram - Safety Injection System Solenoid Valves 7.3-23(a) Schematic Diagram - Safety Injection Pumps 7.3-24(a) Schematic Diagram - Containment Spray Pumps 7.3-25(a) Schematic Diagram - Residual Heat Removal Pumps 7.3-26(a) Schematic Diagram - Residual Heat Removal Flow Control Valves 7.3-27(a) Schematic Diagram - Component Cooling Water Pumps 7.3-28(a) Schematic Diagram - Auxiliary Saltwater Pumps 7.3-29(a) Schematic Diagram - Charging Pumps 7.3-30(a) Schematic Diagram - Chemical and Volume Control System 7.3-31(a) Schematic Diagram - Containment Fan Coolers 7.3-32(a) Schematic Diagram - Containment Spray System Motor-Operated Valves 7.3-33(a) Schematic Diagram - Safety Injection System Motor-Operated Valves DCPP UNITS 1 & 2 FSAR UPDATE Chapter 7 FIGURES (Continued) Figure Title xii Revision 21 September 2013 7.3-34(a) Schematic Diagram - Chemical and Volume Control System Motor-Operated Valves 7.3-35(a) Schematic Diagram - Component Cooling Water System Motor-Operated Valves 7.3-36(a) Schematic Diagram - Reactor Trip Breakers 7.3-37(a) Schematic Diagram - Fire Pumps 7.3-38(a) Schematic Diagram - Containment Purge System 7.3-39(a) Schematic Diagram - Plant Air Compressors 7.3-40(a) Schematic Diagram - Control Rod Drive Motor Generator Set 7.3-41(a) Schematic Diagram - Diesel Fuel Transfer Pumps 7.3-42(a) Schematic Diagram - Main Steam Isolation Valves 7.3-43(a) Schematic Diagram - Sampling System Solenoid Valves 7.3-44(a) Schematic Diagram - Component Cooling Water Solenoid Valves 7.3-45(a) Schematic Diagram - Chemical and Volume Control System Solenoid Valves 7.3-46(a) Schematic Diagram - Liquid Radwaste Solenoid Valves 7.3-47(a) Schematic Diagram - Steam Generator Blowdown Solenoid Valves 7.3-48(a) Schematic Diagram - Generator Control 7.3-49(a) Schematic Diagram - Permissive and Bypass Lights 7.3-50(a) Separation and Color Code Instrumentation and Control - Engineered Safety Features 7.3-51 Deleted in Revision 11
7.3-52(a) Containment Electrical Penetrations, Cable Trays, and Supports DCPP UNITS 1 & 2 FSAR UPDATE Chapter 7 FIGURES (Continued) Figure Title xiii Revision 21 September 2013 7.5-1 Containment Water Level Indication 7.5-1A Deleted in Revision 8
7.5-1B Unit 2 Containment Water Level Indication (Wide Range)
7.5-2 Reactor Vessel Level Instrumentation Process Connection Schematic (Train A) 7.6-1(a) Instrumentation and Control Power Supply 7.6-2 Deleted in Revision 8 (Reassigned as Figure 7.2-1, Sheet 17)
7.7-1 Simplified Block Diagram of Reactor Control System
7.7-2 Control Bank Rod Insertion Monitor
7.7-3 Rod Deviation Comparator 7.7-4 Block Diagram of Pressurizer Pressure Control System
7.7-5 Block Diagram of Pressurizer Level Control System
7.7-6(a) Functional Logic Diagram, Digital Feedwater Control System, FW Flow Controller & Cv Demand 7.7-7(a) Functional Logic Diagram, Digital Feedwater Control System, Feedwater Control & Isolation 7.7-8 Block Diagram of Steam Dump Control System
7.7-9 Basic Flux Mapping System
7.7-10 Deleted in Revision 14
7.7-11 Deleted in Revision 14 7.7-12 Deleted in Revision 14
7.7-13 Deleted in Revision 14 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 7 FIGURES (Continued) Figure Title xiv Revision 21 September 2013 7.7-14 Deleted in Revision 15 7.7-15 Deleted in Revision 15 7.7-16(a) Arrangement of Control Room 7.7-17(a) Location of Control Console and Main Control Board 7.7-18(a) Arrangement of Control Console Nuclear Instrumentation System (CC1), Primary Plant Control (CC2), and Secondary Plant Control (CC3) - Unit 1 7.7-19(a) Arrangement of Control Console Nuclear Instrumentation System (CC1), Primary Plant Control (CC2), and Secondary Plant Control (CC3) - Unit 2 7.7-20(a) Arrangement of Main Control Board - Engineered Safety Systems (VB1) - Unit 1 7.7-21(a) Arrangement of Main Control Board - Engineered Safety Systems (VB1) - Unit 2 7.7.22(a) Arrangement of Main Control Board - Primary Plant Systems (VB2) - Unit 1 7.7.23(a) Arrangement of Main Control Board - Primary Plant Systems (VB2) - Unit 2 7.7.24(a) Arrangement of Main Control Board - Steam and Turbine (VB3) - Unit 1 7.7.25(a) Arrangement of Main Control Board - Steam and Turbine (VB3) - Unit 2 7.7.26(a) Arrangement of Main Control Board - Auxiliary Equipment and Diesel (VB4) - Unit 1 7.7.27(a) Arrangement of Main Control Board - Auxiliary Equipment and Diesel (VB4) - Unit 2
7.7.28(a) Arrangement of Main Control Board - Station Electric (VB5) - Unit 1 7.7.29(a) Arrangement of Main Control Board - Station Electric (VB5) - Unit 2 7.7-30(a) Arrangement of Hot Shutdown Remote Control Panel DCPP UNITS 1 & 2 FSAR UPDATE Chapter 7 FIGURES (Continued) Figure Title xv Revision 21 September 2013 7.7-31(a) Arrangement of Auxiliary Building Control Panel NOTE:
(a) This figure corresponds to a controlled engineering drawing that is incorporated by reference into the FSAR Update. See Table 1.6-1 for the correlation between the FSAR Update figure number and the corresponding controlled engineering drawing number.
DCPP UNITS 1 & 2 FSAR UPDATE 7.1-1 Revision 21 September 2013 Chapter 7 INSTRUMENTATION AND CONTROLS
7.1 INTRODUCTION
This chapter presents the various plant instrumentation and control systems by relating the functional performance requirements, design bases, system descriptions, design evaluations, and tests and inspections for each. The information provided in this chapter emphasizes those instruments and associated equipment that constitute the protection system as defined in IEEE 279-1971.(1) The primary purpose of the instrumentation and control systems is to provide automatic protection against unsafe and improper reactor operation during steady state and transient power operations (Conditions I, II, and III) and to provide initiating signals to mitigate the consequences of faulted conditions (Condition IV). For a discussion of the four conditions, see Chapter 15. The information presented in this chapter emphasizes those instrumentation and control systems necessary to ensure that the reactor can be operated to produce power in a manner that ensures no undue risk to the health and safety of the public.
It is shown that the applicable criteria and codes, such as the Atomic Energy Commission's General Design Criteria (GDC) and IEEE standards, concerned with the safe generation of nuclear power are met by these systems. Classification of Instrumentation Systems Instrumentation is classified Instrument Class IA, IB, IC, ID, and II depending upon the function performed. Instrument Class IA, IB, IC and ID devices have safety-related functions or other special requirements. Instrument Class II devices have nonsafety-related functions. Instrument classes are defined as follows:
(1) Instrument Class IA - Class IA instruments and controls are those that initiate and maintain safe shutdown of the reactor, mitigate the consequences of an accident, or prevent exceeding 10 CFR 100 off-site dose limits. Class IA instruments and controls enable the safety-related systems to automatically accomplish their appropriate safety functions, or they enable operating personnel to manually accomplish appropriate safety actions when a monitored condition reaches a preset level. (2) Instrument Class IB - Class IB instruments and controls are those that are required for postaccident monitoring (PAM) of Category 1 and 2 variables in accordance with Regulatory Guide (RG) 1.97, Revision 3. RG 1.97 Category 3 instruments required for PAM are Instrument Class II. PAM instrumentation enables operating personnel to:
DCPP UNITS 1 & 2 FSAR UPDATE 7.1-2 Revision 21 September 2013 (a) Determine when a condition monitored by safety-related instruments and controls reaches a level requiring manual action (b) Assess the accomplishment of plant safety functions (c) Assess fission product barrier integrity (d) Provide information to indicate the operability of individual systems important to safety (e) Assess the magnitude of radioactive materials releases from the plant PAM instruments are further divided into five variable types (A through E) as detailed in RG 1.97. These are further detailed in Section 7.5. (3) Instrument Class IC - Instrument Class IC instruments and controls have the passive function of maintaining the pressure boundary integrity (PBI) of PG&E Design Class I piping systems. Passive valve operators that are within Design Class I piping systems are Instrument Class IC and are seismically analyzed to assure structural and pressure boundary integrity of the valve operator assembly. This classification also includes instruments installed in Design Class I HVAC ducting that are required to maintain pressure boundary integrity. In addition, this classification is used for instruments that are part of seismically qualified, nonsafety-related systems and denotes that the instruments are required to maintain their pressure boundary integrity. (4) Instrument Class ID - Instrument Class ID instruments and controls are components that have certain Design Class I attributes, but do not require conformance with all Instrument Class IA, IB or IC requirements. The Instrument Class ID designation signifies that only certain design requirements are imposed for a component. The specific requirements for the Instrument Class ID instruments are provided on a case-by-case basis in the respective system Design Criteria Memorandum (DCM). Instrument Class ID components are defined as: Active components that have certain Instrument Class I attributes and are relied upon to satisfy licensing commitments or safety analyses, but do not require conformance with all Instrument Class IA and IB requirements, or Components that are electrically, mechanically or pneumatically coupled with, and whose failure may have an adverse impact on the operation of equipment with an active safety function, but do not themselves have an active safety function. These components have certain Instrument Class I requirements imposed on them to preclude their failure. DCPP UNITS 1 & 2 FSAR UPDATE 7.1-3 Revision 21 September 2013 (5) Instrument Class II - Instrument Class II instruments and controls have nonsafety-related functions. However, certain instrument Class II components are subjected to some graded quality assurance requirements. This classification also includes instruments fulfilling RG 1.97 Category 3 PAM functions. Instrument Classifications IA, IB and IC are not mutually exclusive. More than one classification may apply to a single instrument device. Where such multiple choices exist, the highest classification is assigned to the device. Definitions The definitions below establish the meaning of certain terms in the context of their use in Chapter 7.
(1) Channel - An arrangement of components, modules and software as required to generate a single protective action signal when required by a generating station condition. A channel loses its identity where single action signals are combined. (2) Module - Any assembly of interconnected components that constitutes an identifiable device, instrument, or piece of equipment. A module can be disconnected, removed as a unit, and replaced with a spare. It has definable performance characteristics that permit it to be tested as a unit.
A module can be a card or other subassembly of a larger device, provided it meets the requirements of this definition. (3) Components - Items from which the system is assembled (such as resistors, capacitors, wires, connectors, transistors, tubes, switches, and springs). (4) Single Failure - Any single event that results in a loss of function of a component or components of a system. Multiple failures resulting from a single event shall be treated as a single failure. (5) Protective Action - A protective action can be at the channel or the system level. A protective action at the channel level is the initiation of a signal by a single channel when the variable sensed exceeds a limit. A protective action at the system level is the initiation of the operation of a sufficient number of actuators to effect a protective function. (6) Protective Function - A protective function is the sensing of one or more variables associated with a particular generating station condition, signal processing, and the initiation and completion of the protective action at values of the variable established in the design bases. DCPP UNITS 1 & 2 FSAR UPDATE 7.1-4 Revision 21 September 2013 (7) Type Tests - Tests made on one or more units to verify adequacy of design of that type of unit. (8) Degree of Redundancy - The difference between the number of channels monitoring a variable and the number of channels that, when tripped, will cause an automatic system trip. (9) Minimum Degree of Redundancy - The degree of redundancy below which operation is prohibited or otherwise restricted by the Technical Specifications. (10) Cold Shutdown Condition - When the reactor is subcritical by an amount greater than the margin specified in the applicable Technical Specification and Tavg is less than or equal to the temperature specified in the applicable Technical Specification. Section 15.1 defines this as MODE 5. (11) Hot Standby Condition - When the reactor is subcritical by an amount greater than the margin specified in the Technical Specification and the Tavg is greater than or equal to the temperature specified in the applicable Technical Specification. Section 15.1 defines this as MODE 3. (12) Hot Shutdown Condition - When the reactor is subcritical by an amount greater than the margin specified in the applicable Technical Specification and Tavg is within the temperature range specified in the applicable Technical Specification. Section 15.1 defines this as MODE 4. (13) Phase A containment isolation - Closure of all nonessential process lines that penetrate containment. Initiated by high containment pressure, pressurizer low pressure, low steamline pressure, or manual actuation. (14) Phase B Containment Isolation - Closure of remaining process lines. Initiated by containment high-high pressure signal (process lines do not include engineered safety features lines) or manual actuation. (15) Trip Accuracy - The tolerance band containing the highest expected value of the difference between (a) the desired trip point value of a process variable, and (b) the actual value at which a comparator trips (and thus actuates some desired result). This is the tolerance band within which a comparator must trip. It includes comparator accuracy, channel accuracy for each input, and environmental effects on the rack-mounted electronics. It comprises all instrumentation errors; however, it does not include any process effects such as fluid stratification. (16) Channel Accuracy (an element of trip accuracy) - Includes accuracy of the primary element, transmitter, and rack-mounted electronics, but does not include indication accuracy. DCPP UNITS 1 & 2 FSAR UPDATE 7.1-5 Revision 21 September 2013 (17) Actuation Accuracy - Synonymous with trip accuracy, but used where the word "trip" may cause ambiguity. (18) Indication Accuracy - The tolerance band containing the highest expected value of the difference between: (a) the value of a process variable read on an indicator or recorder, and (b) the actual value of that process variable. An indication must fall within this tolerance band. It includes channel accuracy, accuracy of readout devices, and rack environmental effects but not process effects such as fluid stratification. (19) Reproducibility - This term may be substituted for "accuracy" in the above definitions for those cases where a trip value or indicated value need not be referenced to an actual process variable value, but rather to a previously established trip or indication value; this value is determined by test. (20) Safe Shutdown - This term is defined as hot standby (MODE 3). 7.1.1 IDENTIFICATION OF SAFETY-RELATED SYSTEMS The instrumentation and control systems and supporting systems discussed in Chapter 7 that are required to function to achieve the system responses assumed in the safety evaluations, and those needed to shut down the plant safely are:
(1) Reactor trip system (RTS) (2) Engineered safety features actuation system (ESFAS) (3) Instrumentation and control power supply system (4) Remote shutdown panel controls and instrumentation The RTS and the ESFAS are functionally defined systems. The functional descriptions of these systems are provided in Sections 7.2 and 7.3. The trip functions identified in Section 7.2, Reactor Trip System, are provided by the following: (1) Process instrumentation and control system(3, 9) (2) Nuclear instrumentation system(4) (3) Solid-state logic protection system(5) (4) Reactor trip switchgear(5) (5) Manual actuation circuitry DCPP UNITS 1 & 2 FSAR UPDATE 7.1-6 Revision 21 September 2013 The actuation functions identified in Section 7.3 are provided by the following: (1) Process instrumentation and control system(3,9) (2) Solid-state logic protection system(5) (3) Engineered safety features (ESF) test cabinet(6) (4) Manual actuation circuitry WCAP-7671 (Reference 3) describes the instrumentation and instruments systems that are safety-related as defined in the scope of IEEE-279 (Reference 1).
The original Hagan/Westinghouse PCS was replaced with a programmable logic controller (PLC) based system (DDP 1000000237 and 1000000501). The PCS converts physical plant parameters such as temperature, pressure, level, and flow into electrical signals during normal operation. These signals are used for plant control, remote process indication, and computer monitoring. The PCS also provides signals to components located in the Hot Shutdown Panel. The PCS comprises Control Racks 17-32, panels PIA, PIB, PIC, and the Instrument Rack (RI Rack). The sixteen Control Racks are divided into four Control Sets. Control Set I comprises Racks 17-20. Control Set II comprises Racks 21-24. Control Set III comprises Racks 25-27. Control Set IV comprises Racks 28-32. The Control Sets and the associated vital 120 VAC power sources are physically separated. Each Control Set contains two sub-systems based on a PLC platform. One PLC sub-system contains safety related components and functions. The other PLC sub-system contains non-safety related components and functions. The two PLC sub-systems are separated within the Control Racks. The safety related sub-system in each Control Set receives vital 120 VAC power from an independent vital 120 VAC power source. The non safety related sub-system in each Control Set receives non-vital 120 VAC power from two separate sources; one of which is inverter backed. Circuit separation and isolation is maintained for Class IE power sources to the Control Racks. Instrument Panels PIA, PIB, and PIC are physically separated from each other and contain Class IE power sources. These instrument panels receive 120 VAC power from vital 120 VAC power supplies. The RI Rack contains non-safety related components and functions that are processed by a PLC. The RI Rack receives 120 VAC power from two non-vital sources.
DCPP UNITS 1 & 2 FSAR UPDATE 7.1-7 Revision 21 September 2013 7.1.2 IDENTIFICATION OF SAFETY CRITERIA 7.1.2.1 Design Bases The design bases and functional performance for the safety-related systems described in this chapter are provided in Sections 7.1.2.1.1 (RTS), 7.1.2.1.2 (ESFAS), and 7.1.2.1.3 (Instrumentation and Control Power Supply System). 7.1.2.1.1 Reactor Trip System The RTS acts to limit the consequences of Condition II events (faults of moderate frequency such as loss of feedwater flow) by, at most, a shutdown of the reactor and turbine, with the plant capable of returning to operation after corrective action. The RTS features impose a limiting boundary region to plant operation that ensures that the reactor safety limits are not exceeded during Condition II events and that these events can be accommodated without developing into more severe conditions. 7.1.2.1.1.1 Functional Performance Requirements (1) Reactor Trips - The RTS automatically initiates reactor trip: (a) Whenever necessary to prevent fuel damage for an anticipated malfunction (Condition II) (b) To limit core damage for infrequent faults (Condition III) (c) So that the energy generated in the core is compatible with the design provisions to protect the reactor coolant pressure boundary for limiting faults (Condition IV) (2) Turbine Trips - The RTS initiates a turbine trip signal whenever reactor trip is initiated, to prevent the reactivity insertion that would otherwise result from excessive reactor system cooldown, and to avoid unnecessary actuation of the ESFAS. (3) Manual Trip - The RTS provides for manual initiation of reactor trip by operator action. 7.1.2.1.1.2 Design Bases The design requirements for the RTS are derived by analyses of plant operating and fault conditions where automatic rapid control rod insertion is necessary to prevent or limit core or reactor coolant boundary damage. The design limits for this system are:
DCPP UNITS 1 & 2 FSAR UPDATE 7.1-8 Revision 21 September 2013 (1) Minimum departure from nucleate boiling ratio (DNBR) shall not be less than the applicable limit value (see Section 4.4.1.1 and Section 4.4.2.3) as a result of any anticipated transient or malfunction (Condition II faults). (2) Power density shall not exceed the rated linear power density for Condition II faults. See Sections 4.2.1, 4.3.1, and 4.4.1 for fuel design limits. (3) The stress limit of the reactor coolant system for the various conditions shall be as specified in Sections 5.2 and 5.5. (4) Release of radioactive material shall not be sufficient to interrupt or restrict public use of those areas beyond the exclusion radius as a result of any Condition III fault. (5) For any Condition IV fault, release of radioactive material shall not result in an undue risk to public health and safety. 7.1.2.1.1.3 Seismic and Environmental Requirements The seismic and environmental design bases are discussed in Sections 3.10 and 3.11. 7.1.2.1.2 Engineered Safety Features Actuation System The ESFAS acts to limit the consequences of Condition III events (infrequent faults, such as primary coolant spillage from a small rupture, that exceed normal charging system makeup and require actuation of the safety injection system). The ESFAS also acts to mitigate Condition IV events (limiting faults that include the potential for significant release of radioactive material). 7.1.2.1.2.1 Functional Performance Requirements (1) General Performance Requirements - Signals additional to those developed by the RTS shall be generated by the ESFAS to protect against the effects (and reduce the consequences) of more serious types of accidents, designated as Conditions III and IV events. These are serious abnormal conditions in the reactor coolant system (RCS) or main steam system. The functional performance requirements for the ESF systems are discussed in detail in Chapter 6. (2) Automatic Actuation Requirements - The primary functional requirement of the ESFAS is to receive input signals (information) from the various ongoing processes within the reactor plant and containment, and automatically provide as output timely and effective signals to actuate the DCPP UNITS 1 & 2 FSAR UPDATE 7.1-9 Revision 21 September 2013 various components and subsystems comprising the ESF system. These output signals, in conjunction with actuators, ensure that the ESF systems meet their performance objectives as outlined in Chapter 6. The functional diagram presented in Figure 7.2-1, Sheet 8, provides a graphic outline of the ESFAS. (3) Manual Actuation Requirements - The ESFAS has provisions for manually initiating all of the functions of the ESF systems from the control room. Manual actuation serves as backup to the automatic initiation and provides selective control of ESF. 7.1.2.1.2.2 Design Bases The design bases for the ESF are discussed in Chapter 6; specifically, Section 6.2 for containment systems and Section 6.3 for emergency core cooling system (ECCS).
The following is a discussion of the requirements imposed on the ESFAS design by the design bases:
In addition to the requirements for a reactor trip for anticipated abnormal transients, the facility shall be provided with adequate instrumentation and controls to sense accident situations and initiate the operation of necessary ESFs. The occurrence of a limiting fault, such as a loss-of-coolant accident (LOCA) or a steam break, requires a reactor trip plus actuation of one or more of the ESFs in order to prevent or mitigate damage to the core and RCS elements and to ensure containment integrity. To accomplish these design objectives, the ESF systems shall have proper and timely initiating signals that are supplied by the sensors, transmitters, and logic components making up the various instrumentation channels of the ESFAS. The specific functions that the ESFAS initiates are:
(1) A reactor trip, provided that one has not already been generated by the RTS (2) ESF sequence that actuates the following items and ensures the proper sequencing of ESF power demands on the ESF buses (supplied by either preferred or standby power supply): (a) Cold leg charging injection valves that are opened for injection of refueling water storage tank (RWST) (borated) water by charging pumps into the cold legs of the RCS (b) Charging pumps, residual heat removal pumps, and associated valving that provide emergency makeup water to the cold leg of the DCPP UNITS 1 & 2 FSAR UPDATE 7.1-10 Revision 21 September 2013 RCS following a LOCA; and safety injection pumps for cold leg injection (c) Containment air recirculation fans and filtration system that serve to cool the containment and limit the potential for release of fission products from the containment by reducing the pressure following an accident (d) Auxiliary saltwater pumps that provide cooling water to the component cooling water system (CCWS) heat exchangers thus providing the heat sink for containment cooling (e) Motor-driven auxiliary feedwater pumps (f) Component cooling water pumps (3) Phase A containment isolation, whose function is to prevent fission product release (4) Steam line isolation to prevent the continuous, uncontrolled blowdown of more than one steam generator and thereby uncontrolled RCS cooldown (5) Main feedwater line isolation to limit the energy release in the case of a steam line break and to limit the magnitude of the RCS cooldown (6) Emergency diesel generators start to ensure a backup supply of power to emergency systems and their supporting systems (7) Containment spray actuation, which performs the following functions: (a) Initiates containment spray that serves to reduce containment pressure and temperature following a loss of coolant or steam break accident, and also to reduce airborne radioactivity by use of sodium hydroxide in the spray water (b) Initiates phase B containment isolation that isolates the containment following a loss of reactor coolant accident, or a steam or feedwater line break within containment 7.1.2.1.2.3 Environmental Requirements Applicable environmental qualification requirements are discussed in Section 3.11.
DCPP UNITS 1 & 2 FSAR UPDATE 7.1-11 Revision 21 September 2013 7.1.2.1.3 Instrumentation and Control Power Supply System 7.1.2.1.3.1 Functional Performance Requirements The functional performance requirements for the instrumentation and control power supply system are:
(1) To supply regulated single-phase ac power to all instrumentation and control equipment required for plant safety. (2) To supply reliable and continuous power to all instrumentation and control equipment required for plant safety. 7.1.2.1.3.2 Design Bases The design bases for the instrumentation and control power supply system are: (1) The uninterruptible power supply (UPS) shall have the capacity and regulation required for the ac output for proper operation of the equipment supplied. (2) Redundant loads shall be assigned to different distribution buses that are supplied from different UPSs. (3) Auxiliary devices that are required to operate dependent equipment shall be supplied from the same distribution bus to prevent the loss of electric power in one protection set from causing the loss of equipment in another protection set. No single failure shall cause a loss of power supply to more than one distribution bus. (4) Each of the distribution buses shall have access to its respective UPS supply and a standby power supply.
The instrumentation and control power supply system meets IEEE criteria, Section 5.4 of IEEE-308-1971(7). 7.1.2.1.3.3 Quality Assurance Requirements A description of the quality assurance program applied to safety-related instrumentation and control system equipment is in Chapter 17. 7.1.2.2 Independence of Redundant Safety-Related Systems Separation and independence for individual channels of the RTS and ESFAS are discussed in Sections 7.2 and 7.3, respectively. Separation of protection and control systems is discussed in Section 7.7. See Section 8.3 for a discussion of separation and independence of safety-related electrical systems. DCPP UNITS 1 & 2 FSAR UPDATE 7.1-12 Revision 21 September 2013 For separation requirements for control board wiring, see Section 7.7. Separation criteria for circuits entering the containment structure are met by providing separate electrical penetrations as follows: (1) Reactor Protection Instrumentation - Each of the Eagle 21 protection sets (I, II, III, and IV) utilizes one or more penetrations dedicated to that protection set. (2) Isolation Valves (solenoid-operated) - Each isolation valve inside the containment structure is connected to its respective ESF dc bus, and circuits are run through associated 480 V bus penetrations. All isolation valves inside the containment structure receive train A signals. Redundant isolation valves outside the containment receive train B signals. (3) Isolation Valves (motor-operated) - Each isolation valve utilizes a penetration dedicated to the 480 V ESF bus that provides power to the valve. (4) Fan Coolers - One penetration for each fan cooler motor. (5) Nuclear Instrumentation (out-of-core) - Four separate penetrations are provided for out-of-core nuclear instrumentation. The installation of other cable complies with the criteria presented in Chapter 8. 7.1.2.3 Physical Identification of Safety-Related Equipment There are four separate process protection system rack sets. Separation of redundant process channels begins at the process sensors and is maintained in the field wiring, containment penetrations, and process protection racks to the redundant trains in the protection logic racks. Redundant process channels are separated by locating the electronics in different rack sets. A color-coded nameplate on each rack is used to differentiate between different protective sets. The color coding of the nameplates is: Protection Set Color Coding I Red with white lettering II White with black lettering III Blue with white lettering IV Yellow with black lettering Each field wire termination point is tagged to assist identification. However, these tags are not color-coded.
DCPP UNITS 1 & 2 FSAR UPDATE 7.1-13 Revision 21 September 2013 All nonrack-mounted protective equipment and components are provided with an identification tag or nameplate. Small electrical components such as relays have nameplates on the enclosure that houses them.
Postaccident monitoring instruments and controls are identified "PAMS" as required by RG 1.97.
For further details of the process protection system, see Sections 7.2, 7.3, and 7.7.
There are identification nameplates on the input panels of the logic system. For details of the logic system, see Sections 7.2 and 7.3. 7.1.2.4 Conformance with IEEE Standards The safety-related control and instrumentation systems comply with the following IEEE standards, only as discussed in the appropriate sections. However, because the IEEE standards were issued after much of the design and testing had been completed, the equipment documentation may not meet the format requirements of the standards.
(1) IEEE Standard 279-1971, "Criteria for Protection Systems for Nuclear Power Generating Stations." (2) IEEE Standard 308-1971, "Criteria for Class 1E Electric Systems for Nuclear Power Generating Stations." (3) IEEE Standard 317, April 1971, "IEEE Standard for Electrical Penetration Assemblies in Containment Structures for Nuclear Fueled Power Generating Stations." (4) IEEE Standard 323, April 1971, "IEEE Trial-Use Standard: General Guide for Qualifying Class I Electric Equipment for Nuclear Power Generating Stations." (5) IEEE Standard 323-1974, "IEEE Standard for Qualifying Class 1E Equipment for Nuclear Power Generating Stations." (6) IEEE Standard 334-1971, "Trial-Use Guide for Type Tests of Continuous-Duty Class I Motors Installed Inside the Containment of Nuclear Power Generating Stations." (7) IEEE Standard 336-1971, "Installation, Inspection, and Testing Requirements for Instrumentation and Electrical Equipment During the Construction of Nuclear Power Generating Stations." (8) IEEE Standard 338-1971, "IEEE Trial-Use Criteria for the Periodic Testing of Nuclear Power Generating Station Protection Systems."
DCPP UNITS 1 & 2 FSAR UPDATE 7.1-14 Revision 21 September 2013 (9) IEEE Standard 344-1971, "Trial-Use Guide for Seismic Qualification of Class I Electric Equipment for Nuclear Power Generating Stations." (10) IEEE Standard 344-1975, "Recommended Practices for Seismic Qualification of Class 1E Equipment for Nuclear Power Generating Stations." (11) IEEE Standard 603-1980, "IEEE Standard Criteria for Safety Systems for Nuclear Power Generating Stations." 7.1.2.5 Conformance with Other Applicable Documents In addition to the conformance indicated in the preceding section, the safety-related systems in Chapter 7 comply with the following documents only as discussed in the appropriate sections.
(1) "Proposed General Design Criteria for Nuclear Power Plant Construction Permits," Federal Register, July 11, 1967. (2) Safety Guide 6, "Independence Between Redundant Standby (Onsite) Power Sources and Between Their Distribution Systems," USAEC, March 1971. (3) Safety Guide 22, "Periodic Testing of Protection System Actuation Functions," USAEC, February 1972. (4) RG 1.47, "Bypassed and Inoperable Status Indication for Nuclear Power Plant Safety Systems," USAEC, May 1973. (5) RG 1.97, Rev. 3, "Instrumentation For Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident," USNRC, May 1983. (6) RG 1.152, "Criteria for Programmable Digital Computer System Software in Safety Related Systems in Nuclear Plants," November 1985 (Regulatory Guide 1.152 endorses the guidance of ANSI/IEEE-ANS 4.3.2). (7) RG 1.153, "Criteria for Power, Instrumentation and Control Portions of Safety Systems," December 1985 (RG 1.153 endorses the guidance of IEEE Standard 603-1980). (8) ANSI/IEEE-ANS-7-4.3.2, "Application Criteria for Programmable Digital Computer Systems in Safety Systems of Nuclear Power Generating Stations," 1982 (ANSI/IEEE-ANS-7-4.3.2, 1982 expands and amplifies the requirements of IEEE Standard 603-1980).
DCPP UNITS 1 & 2 FSAR UPDATE 7.1-15 Revision 21 September 2013 7.
1.3 REFERENCES
- 1. IEEE Standard, 279-1971, Criteria for Protection Systems for Nuclear Power Generating Stations, The Institute of Electrical and Electronics Engineers, Inc.
- 2. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
- 3. J. A. Nay, Process Instrumentation for Westinghouse Nuclear Steam Supply Systems, WCAP-07671, April 1971.
- 4. J. B. Lipchak and R. A. Stokes, Nuclear Instrumentation System, WCAP-7669, April 1971.
- 5. D. N. Katz, Solid State Logic Protection System Description, WCAP-7672, June 1971.
- 6. J. T. Haller, Engineered Safeguards Final Device or Activator Testing, WCAP-7705, February 1973.
- 7. IEEE Standard 308-1971, Criteria for Class 1E Electrical Systems for Nuclear Power Generating Stations, The Institute of Electrical and Electronics Engineers, Inc.
- 8. T. W. T. Burnett, Reactor Protection System Diversity in Westinghouse Pressurized Water Reactors, WCAP-7306, April 1969.
- 9. L. E. Erin, Topical Report Eagle 21 Microprocessor-Based Process Protection System, WCAP-12374, September 1989 (W Proprietary Class 2).
DCPP UNITS 1 & 2 FSAR UPDATE 7.2-1 Revision 21 September 2013 7.2 REACTOR TRIP SYSTEM 7.2.1 DESCRIPTION This section provides a system description and the design bases for the reactor trip system (RTS). 7.2.1.1 System Description The RTS uses sensors that feed the process circuitry consisting of two to four redundant channels, which monitor various plant parameters. The RTS also contains the logic circuitry necessary to automatically open the reactor trip breakers. The logic circuitry consists of two redundant logic trains that receive input from the protection channels.
Each of the two trains, A and B, is capable of opening a separate and independent reactor trip breaker (52/RTA and 52/RTB). The two trip breakers in series connect three-phase ac power from the rod drive motor generator sets to the rod drive power bus, as shown in Figure 7.2-1, Sheet 2. For reactor trip, a loss of dc voltage to the undervoltage coil releases the trip plunger and trips open the breaker. Additionally, an undervoltage trip auxiliary relay provides a trip signal to the shunt trip coil that trips open the breaker in the unlikely event of an undervoltage coil malfunction. When either of the trip breakers opens, power is interrupted to the rod drive power supply, and the control rods fall by gravity into the core. The rods cannot be withdrawn until an operator resets the trip breakers. The trip breakers cannot be reset until the bistable, which initiated the trip, reenergizes. Bypass breakers BYA and BYB are provided to permit testing of the trip breakers, as discussed below. 7.2.1.1.1 Reactor Trips The various reactor trip circuits automatically open the reactor trip breakers whenever a condition monitored by the RTS reaches a preset level. In addition to redundant channels and trains, the design approach provides an RTS that monitors numerous system variables, thereby providing RTS functional diversity. The extent of this diversity has been evaluated for a wide variety of postulated accidents and is detailed in Reference 1.
Table 7.2-1 provides a list of reactor trips that are described below. 7.2.1.1.1.1 Nuclear Overpower Trips The specific trip functions generated are:
(1) Power Range High Nuclear Power Trip - The power range high nuclear power trip circuit trips the reactor when two of the four power range channels exceed the trip setpoint.
DCPP UNITS 1 & 2 FSAR UPDATE 7.2-2 Revision 21 September 2013 There are two independent bistables each with its own trip setting (a high and a low setting). The high trip setting provides protection during normal power operation and is always active. The low trip setting, which provides protection during startup, can be manually blocked when two of the four power range channels read above approximately 10 percent power (P-10). Three of the four channels sensing below 10 percent power automatically reinstate the trip function. Refer to Table 7.2-2 for a listing of all protection system interlocks. (2) Intermediate Range High Neutron Flux Trip - The intermediate range high neutron flux trip circuit trips the reactor when one of the two intermediate range channels exceeds the trip setpoint. This trip, which provides protection during reactor startup, can be manually blocked if two of the four power range channels are above approximately 10 percent power (P-10). Three of the four power range channels below this value automatically reinstate the intermediate range high neutron flux trip. The intermediate range channels (including detectors) are separate from the power range channels. The intermediate range channels can be individually bypassed at the nuclear instrumentation racks to permit channel testing during plant shutdown or prior to startup. This bypass action is annunciated on the control board. (3) Source Range High Neutron Flux Trip - The source range high neutron flux trip circuit trips the reactor when one of the two source range channels exceeds the trip setpoint. This trip, which provides protection during reactor startup and plant shutdown, can be manually blocked when one of the two intermediate range channels reads above the P-6 setpoint value and is automatically reinstated when both intermediate range channels decrease below the P-6 value. This trip is also automatically bypassed by two-out-of-four logic from the power range interlock (P-10). This trip function can also be reinstated below P-10 by an administrative action requiring manual actuation of two control board-mounted switches. Each switch will reinstate the trip function in one of the two protection logic trains. The source range trip point is set between the P-6 setpoint (source range cutoff flux level) and the maximum source range flux level. The channels can be individually bypassed at the nuclear instrumentation racks to permit channel testing during plant shutdown or prior to startup. This bypass action is annunciated on the control board. (4) Power Range High Positive Nuclear Power Rate Trip - This circuit trips the reactor when an abnormal rate of increase in nuclear power occurs in two of the four power range channels. This trip provides protection against rod ejection and rod withdrawal accidents of low worth from middle to low power conditions and is always active. DCPP UNITS 1 & 2 FSAR UPDATE 7.2-3 Revision 21 September 2013 Figure 7.2-1, Sheet 3, shows the logic for all of the nuclear overpower and rate trips. A detailed functional description of the equipment associated with this function is provided in Reference 2. 7.2.1.1.1.2 Core Thermal Overpower Trips The specific trip functions generated are:
(1) Overtemperature T Trip - This trip protects the core against DNB and trips the reactor on coincidence, as listed in Table 7.2-1, with one set of temperature measurements per loop. The setpoint for this trip is continuously calculated by process protection circuitry for each loop by solving the following equation: ()
°+++++If)PP(KTavgTavg)s1()s1(KKTi)s1()s1(Ti13ii212154 (7.2-1) where: °iT = indicated T at rated thermal power from loop i °iTavg = Indicated Tavg at rated thermal power from loop i °P = 2235 psig (indicated RCS nominal operating pressure) ijTh = jth narrow range Thot input signal from loop i ijfhT = ijTh (1/(1+)s6) s116+ = Lag compensator on measured Thot iThave = 3/)hT(ijf for j = 1 - 3 for each loop, i = 1 - 4 Note: A 3-input redundant sensor algorithm (RSA) eliminates ijfhT values that result from known bad inputs or that fail a consistency check. The RSA also determines a quality code for Thavei, depending on the quality and consistency of the individual ijfhT values. (Reference Section 7.2.1.1.3.) ijTc = jth narrow-range Tcold input signal from loop i ijfcT = Tcij (1/(1+7s)) DCPP UNITS 1 & 2 FSAR UPDATE 7.2-4 Revision 21 September 2013 s117+ = Lag compensator on measured Tcold 76;= Time constants utilized in the lag compensator for Thot and Tcold: 6 = 0 secs; 7 = 0 secs Tcavei = 2/)cT(ijf for j = 1 - 2 for each loop, i = 1 - 4 Note: A 2-input RSA determines a quality code and a value for Tcavei, depending on the quality and consistency of the individual ijfcT values. (Reference Section 7.2.1.1.3.) i = ()iiTcaveThave for each loop, i = 1 - 4 iTavg = ()2/TcaveThaveii for each loop, i = 1 - 4 s1s154++ = The function generated by the lead-lag controller for T dynamic compensation 4; 5 = Time constants utilized in the lead-lag controller for T: 4 = 0 sec; 5 = 0 sec P = pressurizer pressure signal, psig s1s121++ = the function generated by the lead-lag controller for Tavgi dynamic compensation 1 ; 2 = time constants utilized in the lead-lag controller for Tavg: 1 = 30 sec; 2 = 4 sec s = Laplace transform operator, sec -1 K1 = (*) K2 = (*) K3 = (*) and f1 (I) is a function of the indicated difference between top and bottom detectors of the power range nuclear ion chambers, with grains to be selected based on measured instrument response during plant startup tests such that: DCPP UNITS 1 & 2 FSAR UPDATE 7.2-5 Revision 21 September 2013 (a) for qt - qb between (*) and (*), f1 (I) = 0 (where qt and qb are percent rated thermal power in the to and bottom halves of the core respectively, and qt + qb is total thermal power in percent of rated thermal power) (b) for each percent that the magnitude of (qt - qb) exceeds (*), the T trip setpoint shall be automatically reduced by (*) of its value at rated thermal power (c) for each percent that the magnitude of (qt - qb) exceeds (*), the T trip setpoint shall be automatically reduced by (*) of its value at rated thermal power Note: The channel's maximum trip point shall not exceed its computed trip point by more than (*).
(*) Refer to Technical Specifications for current values to be used. One power range channel separately feeds each overtemperature T trip channel. Changes in f1 (I) can only lead to a decrease in the trip setpoint; refer to Figure 7.2-2. The single pressurizer pressure parameter required per loop is obtained from separate sensors that are connected to three pressure taps at the top of the pressurizer. The four pressurizer pressure signals are obtained from the three taps by connecting one of the taps to two pressure transmitters. Refer to Section 7.2.2.3.3 for analysis of this arrangement. Figure 7.2-1, Sheet 5, shows the logic for the overtemperature T trip function. (2) Overpower T Trip - This trip protects against excessive power (fuel rod rating protection) and trips the reactor on coincidence as listed in Table 7.2-1, with one set of temperature measurements per loop. The setpoint for each channel is continuously calculated using the following equation: ()
+++IfTavgTavgKTavgs1sKKTi)s1()s1(Ti2ii6i335454 (7.2-2) where: Tavgi = As defined for overtemperature T trip Ti = As defined for overtemperature T trip Tavgio = As defined for overtemperature T trip DCPP UNITS 1 & 2 FSAR UPDATE 7.2-6 Revision 21 September 2013 s1s154++ = The function generated by the lead-lag controller for measured 4; 5 = Time constants used in the lead-lag controller for measured T: 4 = 0 sec; 5 = 0 sec K4 = (*) K5 = (*)/°F for increasing average temperature; 0 for decreasing average temperature K6 = (*) for Tavgi > Tavgio; K6 = 0 for Tavgi Tavgio s1s33+ = the function generated by the rate-lag controller for Tavgi dynamic compensation 3 = time constants utilized in the rate-lag controller for Tavg 3 = 10 sec s = Laplace transform operator, sec-1 f2 (I) = 0 for all I Note: The channel's maximum trip point shall not exceed its computed trip point by more than (*).
(*) Refer to Technical Specifications for current values.
The source of temperature and flux information is identical to that of the overtemperature T trip and the resultant T setpoint is compared to the same T. Figure 7.2-1, Sheet 5, shows the logic for this trip function. 7.2.1.1.1.3 Reactor Coolant System Pressurizer Pressure and Water Level Trips The specific trip functions generated are:
(1) Pressurizer Low-Pressure Trip - The purpose of this trip is to protect against low pressure that could lead to departure from nucleate boiling (DNB), and to limit the necessary range of protection afforded by the overtemperature T trip. The parameter being sensed is reactor coolant pressure as measured in the pressurizer. Above P-7, the reactor is tripped when the dynamically compensated pressurizer pressure measurements fall below preset limits. This trip is blocked below P-7 to permit startup. The trip logic and interlocks are provided in Table 7.2-1.
DCPP UNITS 1 & 2 FSAR UPDATE 7.2-7 Revision 21 September 2013 The trip logic is shown in Figure 7.2-1, Sheet 6. (2) Pressurizer High-Pressure Trip - The purpose of this trip is to protect the reactor coolant system (RCS) against system overpressure. The same sensors and transmitters used for the pressurizer low-pressure trip are used for the high-pressure trip except that separate comparators are used for the trip. These comparators trip when nondynamically compensated pressurizer pressure signals exceed preset limits on coincidence, as listed in Table 7.2-1. There are no interlocks or permissives associated with this trip function. The logic for this trip is shown in Figure 7.2-1, Sheet 6.
(3) Pressurizer High Water Level Trip - This trip is provided as a backup to the pressurizer high-pressure trip and prevents the pressurizer from becoming water solid during low worth and low power rod withdrawal accidents. This trip is blocked below P-7 to permit startup. The coincidence logic and interlocks of the pressurizer high water level signals are provided in Table 7.2-1. The trip logic for this function is shown in Figure 7.2-1, Sheet 6. 7.2.1.1.1.4 Reactor Coolant System Low-Flow Trips These trips protect the core from DNB in the event of a loss of coolant flow situation. The means of sensing the loss of coolant are: (1) Reactor Coolant Low-Flow Trip - The parameter sensed is reactor coolant flow. Three elbow taps in each coolant loop are used as flow devices that indicate the status of reactor coolant flow. The basic function of these devices is to provide information as to whether or not a reduction in flow has occurred. An output signal from two out of the three comparators in a loop would indicate a low flow in that loop. The trip logic for this function is shown in Figure 7.2-1, Sheet 5. The coincidence logic and interlocks are shown in Table 7.2-1. (2) Reactor Coolant Pump Breakers Open Trip - Opening of two reactor coolant pump breakers or redundant overcurrent protection breakers above the P-7 interlock setpoint, which is indicative of an imminent loss of coolant flow, also causes a reactor trip. One set of auxiliary contacts on each pump breaker serves as the input signal to the trip logic. The trip logic for this function is shown in Figure 7.2-1, Sheet 5. The coincident logic and interlocks are shown in Table 7.2-1.
DCPP UNITS 1 & 2 FSAR UPDATE 7.2-8 Revision 21 September 2013 (3) Reactor Coolant Pump Bus Undervoltage Trip - This trip is required to protect against low flow that can result from loss of voltage to the reactor coolant pumps. Time delays are incorporated in the undervoltage trip relays to prevent spurious reactor trip from momentary electrical power transients. The maximum external time delay is determined to be 0.6 seconds. This allows the total time delay for reactor UV trip to stay within the limits specified in Equipment Control Guidelines and also within the limit established in the accident analysis, Section 15.1.5. (The nominal time delay will be 0.5 seconds, with a tolerance of +/- 0.05 seconds.) There are two undervoltage sensors on each of the two buses. A one-out-of-two undervoltage signal on both buses trips the reactor if above the P-7 setpoint and starts the turbine-driven auxiliary feedwater pump at any reactor power level. The trip logic for this function is shown in Figure 7.2-1, Sheet 5.
(4) Reactor Coolant Pump Bus Underfrequency Trip - This trip is required to protect against low flow resulting from bus underfrequency, which might result from a major power grid frequency disturbance. There are three underfrequency sensors on each of two buses. A two-out-of-three underfrequency signal on either bus trips the reactor if above the P-7 setpoint. The logic scheme is arranged so that a two-out-of-three underfrequency signal on bus 1 trips the breakers to reactor coolant pumps 1 and 2 only, and a two-out-of-three underfrequency signal on bus 2 will trip the breakers to reactor coolant pumps 3 and 4 only. The trip logic for this function is shown in Figure 7.2-1, Sheet 5. The PPS channels are designed so that upon loss of electrical power to any channel, the output of that channel is a trip signal The RCP bus underfrequency trip channels are an exception to the fail-safe design requirement. The RCP bus underfrequency trip function, in conjunction with the RCP bus undervoltage function, provides a fail-safe protective function. 7.2.1.1.1.5 Low-Low Steam Generator Water Level Trip (Including Trip Time Delay) This trip protects the reactor from loss of heat sink in the event of a loss of feedwater to one or more steam generators or a major feedwater line rupture. This trip is actuated on two out of three low-low water level signals occurring in any steam generator. If a low-low water level condition is detected in one steam generator, signals shall be generated to trip the reactor and start the motor-driven auxiliary feedwater pumps. If a low-low water level condition is detected in two or more steam generators, a signal is generated to start the turbine-driven auxiliary feedwater pump as well.
DCPP UNITS 1 & 2 FSAR UPDATE 7.2-9 Revision 21 September 2013 The signals to actuate reactor trip and start auxiliary feedwater pumps are delayed through the use of a Trip Time Delay (TTD) system for reactor power levels below 50 percent of RTP. Low-low water level in any protection set in any steam generator will generate a signal that starts an elapsed time trip delay timer. The allowable trip time delay is based upon the prevailing power level at the time the low-low level trip setpoint is reached. If power level rises after the trip time delay setpoints have been determined, the trip time delay is redetermined (i.e., decreased) according to the increase in power level. However, the trip time delay is not changed if the power level decreases after the delay has been determined. The use of this delay allows added time for natural steam generator level stabilization or operator intervention to avoid an inadvertent protection system actuation.
The logic is shown in Figure 7.2-1, Sheet 7. Steam generator water level low-low trip time delay:
TD = B1(P)3 + B2(P)2 + B3(P) + B4 (7.2-3) where: P = RCS loop T equivalent to power (% rated thermal power (RTP)); P 50% RTP TD = time delay for steam generator water level low-low reactor trip (in seconds)
B1, B2, B3, and B4 are constants:
B1 = -0.007128 B2 = +0.8099 B3 = -31.40 B4 = +464.1 7.2.1.1.1.6 Turbine Trip-Reactor Trip The turbine trip-reactor trip is actuated by two-out-of-three logic from low autostop oil pressure signals or by all closed signals from the turbine steam stop valves. A turbine trip causes a direct reactor trip above P-9. High-high steam generator water level signals in two-out-of-three channels for any steam generator actuate a turbine trip, trip the main feedwater pumps, and close the main feedwater control valves and feedwater bypass valves. The purpose is to protect the turbine and steam piping from excessive moisture carryover caused by high-high steam generator water level. Other turbine trips are discussed in Chapter 10. The logic for this trip is shown in Figure 7.2-1, Sheets 2, 4, 10 and 16. DCPP UNITS 1 & 2 FSAR UPDATE 7.2-10 Revision 21 September 2013 The analog portion of the trip shown in Figure 7.2-1, Sheet 16, is represented by dashed lines. When the turbine is tripped, turbine autostop oil pressure drops, and the pressure is sensed by three pressure sensors. A logic output is provided from each sensor when the oil pressure drops below a preset value. These three outputs are transmitted to two redundant two-out-of-three logic matrices, either of which trips the reactor if above P-9. The autostop oil pressure signal also dumps the emergency trip fluid, closing all of the turbine steam stop valves. When all stop valves are closed, a reactor trip signal is initiated if the reactor is above P-9. This trip signal is generated by redundant (two each) limit switches on the stop valves. 7.2.1.1.1.7 Safety Injection Signal Actuation Trip A reactor trip occurs when the safety injection system (SIS) is actuated. The means of actuating the SIS are described in Section 7.3. Figure 7.2-1, Sheet 8, shows the logic for this trip. 7.2.1.1.1.8 Manual Trip The manual trip consists of two switches with four outputs on each switch. Each switch provides a trip signal for both trip breakers and both bypass breakers. (Operating a manual trip switch also removes the voltage from the undervoltage trip coil.) There are no interlocks that can block this trip. Figure 7.2-1, Sheet 3, shows the manual trip logic. 7.2.1.1.1.9 Seismic Trip The seismic trip system operates to shut down reactor operations should ground accelerations exceed a preset level in any two of the three orthogonal directions monitored (one vertical, two horizontal). The preset level is indicated in the Technical Specifications (Reference 4). Three triaxial sensors (accelerometers) are anchored to the containment base in three separate locations 120 degrees apart (Figure 7.2-6). Each senses acceleration in three mutually orthogonal directions. Output signals are generated when ground accelerations exceed the preset level. These signals, lasting from 6 to 20 seconds (adjustable), are transmitted to the Trains A and B solid state protection system (SSPS). If two of the three sensors in any direction produce simultaneous outputs, the logic produces trains A and B reactor trip signals. The PPS channels are designed so that upon loss of electrical power to any channel, the output of that channel is a trip signal. The seismic trip channels are an exception to the fail-safe design. Since no credit is taken in accident analyses for the seismic trip, the seismic trip channels are designed energize-to-actuate to eliminate the possibility of spurious trips. DCPP UNITS 1 & 2 FSAR UPDATE 7.2-11 Revision 21 September 2013 7.2.1.1.1.10 Automatic Trip Logic The general alarm system, described in Reference 5, maintains a check on each train of the solid-state logic protection system for the existence of certain undesirable conditions. Both trains are tripped if an abnormal condition occurs simultaneously in both trains. Reference 5 states that SSPS printed circuit boards (PCBs) use Motorola High Threshold Logic (MHTL). MHTL based PCBs are obsolete and are being replaced with PCBs which are not based on MHTL (reference 33). The replacement universal logic, safeguards driver, or under voltage driver PCBs have diagnostic features that can activate a general warning alarm when there is a critical board problem. 7.2.1.1.1.11 Reactor Trip Breakers The reactor trip breakers are equipped for automatic actuation of both the undervoltage trip device and the shunt trip device. The reactor trip breakers are also equipped to permit manual trip of the breakers at the switchgear cabinet. 7.2.1.1.2 Reactor Trip System Interlocks 7.2.1.1.2.1 Power Escalation Permissives The overpower protection provided by the out-of-core nuclear instrumentation consists of three discrete, but overlapping, levels. Continuation of startup operation or power increase requires a permissive signal from the higher range instrumentation channels before the lower range level trips can be manually blocked by the operator. A one-out-of-two intermediate range permissive signal (P-6) is required prior to source range level trip blocking and detector high voltage cutoff. Source range level trips are automatically reactivated and high voltage restored when both intermediate range channels are below the permissive (P-6) levels. There is a manual reset switch for administratively reactivating the source range level trip and detector high voltage when between the permissive P-6 and P-10 level, if required. Source range level trip block and high voltage cutoff are always maintained when above the permissive P-10 level.
The intermediate range level trip and power range (low setpoint) trip can be blocked only after satisfactory operation and permissive information are obtained from two-out-of-four power range channels. Individual blocking switches are provided so that the low range power range trip and intermediate range trip can be independently blocked. These trips are automatically reactivated when any three of the four power range channels are below the permissive (P-10) level, thus ensuring automatic activation to more restrictive trip protection.
The development of permissives P-6 and P-10 is shown in Figure 7.2-1, Sheet 4. All of the permissives are digital; they are derived from analog signals in the nuclear power range and intermediate range channels.
See Table 7.2-2 for the list of protection system interlocks. DCPP UNITS 1 & 2 FSAR UPDATE 7.2-12 Revision 21 September 2013 7.2.1.1.2.2 Blocks of Reactor Trips at Low Power Interlock P-7 blocks a reactor trip at low power (below approximately 10 percent of full power) on a low reactor coolant flow or reactor coolant pump open breaker signal in more than one loop, reactor coolant pump undervoltage, reactor coolant pump underfrequency, pressurizer low pressure, and pressurizer high water level on both units. See Figure 7.2-1, Sheets 5 and 6 for permissive applications. The low power signal is derived from three-out-of-four power range neutron flux signals below the setpoint in coincidence with one-out-of-two turbine impulse chamber pressure signals below the setpoint (low plant load). The P-8 interlock blocks a reactor trip when the plant is below a preset level specified in the Technical Specifications on a low reactor coolant flow in any one loop. The block action (absence of the P-8 interlock signal) occurs when three-out-of-four neutron flux power range signals are below the setpoint. Thus, below the P-8 setpoint, the reactor is allowed to operate with one inactive loop, and trip will not occur until two loops are indicating low flow. See Figure 7.2-1, Sheet 4, for derivation of P-8, and Sheet 5 for the applicable logic.
The P-9 interlock blocks a reactor trip below the maximum value of 50 percent of full power on a turbine trip signal. See Figure 7.2-1, Sheets 2, 4, and 16 for the application logic. The reactor trip on turbine trip is actuated by two-out-of-three logic from emergency trip fluid pressure signals or by all closed signals from the turbine steam stop valves.
See Table 7.2-2 for the list of protection system blocks. 7.2.1.1.3 Coolant Temperature Sensor Arrangement and Calculational Methodology The individual narrow range cold and hot leg temperature signals required for input to the reactor trip circuits and interlocks are obtained using resistance temperature detectors (RTDs) installed in each reactor coolant loop.
The cold leg temperature measurement on each loop is accomplished with a dual element narrow-range RTD mounted in a thermowell. The cold leg sensors are inherently redundant in that either sensor can adequately represent the cold leg temperature measurement. Temperature streaming in the cold leg is not a concern due to the mixing action of the reactor coolant pump.
The hot leg temperature measurement on each loop is accomplished with three dual element narrow-range RTDs mounted in thermowells spaced 120 degrees apart around the circumference of the reactor coolant pipe for spatial variations. One of the elements in each thermowell is an installed spare.
These cold and hot leg narrow-range RTD signals are input to the protection system digital electronics and processed as follows:
DCPP UNITS 1 & 2 FSAR UPDATE 7.2-13 Revision 21 September 2013 The two filtered cold leg temperature input signals Tfcj for each loop i are processed to determine a group average value Tfcavei. The 2-input redundant sensor algorithm (RSA) calculates the group average value based on the number of good input signals.
If both input signals are BAD, the group value is set equal to the average of the two bad sensor values. If one signal is BAD and the other is DISABLED, the group value is set equal to the value of the bad sensor. The group quality is set to BAD in either case.
If one of the input signals is BAD and the other is GOOD, the group value is set equal to the GOOD value. A consistency check is not performed. The group quality is set to POOR.
If neither of the input signals is BAD, a consistency check is performed. If the deviation of these two signals is within an acceptance tolerance (+/-DELTAC), the group quality is set to GOOD and the group value is set equal to the average of the two inputs. If the difference exceeds +/-DELTAC, the group quality is set to BAD, and the individual signal qualities are set to POOR. The group value is set equal to the average of the two inputs.
DELTAC is a fixed input parameter based on operating experience. One DELTAC value is required for each protection set.
Estimates of hot leg temperature are derived from each Thot input signal as follows: oijiSBfhijhestijPTT= (7.2-4) where: ijfhTis the filtered Thot signal for the jth RTD (j = 1 to 3) in the ith loop (i = 1 to 4) iBP = power fraction being used to correct the bias value being used for any power level ()°=ifcavefhaveBiiiTT/P (7.2-5) where: oiT is the full power T in the ith loop oijS = manually input bias that corrects the individual Thot RTD value to the loop average. DCPP UNITS 1 & 2 FSAR UPDATE 7.2-14 Revision 21 September 2013 The three hot leg temperature estimates Thestj for each loop i are processed to determine a group average value Tfhavei. The 3-input RSA calculates the group value Tfhavei based on the available number of good input values. If all three inputs are BAD, the group value is set to the average of the three input sensor values. The group value quality is set to BAD. If only one input is GOOD, the group value is set equal to the value of the good sensor. The group quality is set to BAD.
If two inputs are good, the difference between the two sensors is compared to DELTAH. If the inputs do not agree within +/-DELTAH, the group quality is set to BAD and the quality of both inputs is set to POOR. If the inputs agree, the group quality is set to GOOD. The group value is set equal to the average of the two inputs in either case.
If all three inputs are good, an average of the three estimated hot leg temperatures is computed and the individual signals are checked to determine if they agree within +/- DELTAH of the average value. If all of the signals agree within +/- DELTAH of the average value, the group quality is set to GOOD. The group value (Tfhavei ) is set to the average of the three estimated average hot leg temperatures. If the signal values do not all agree within +/- DELTAH of the average, the RSA will delete the signal value that is furthest from the average. The quality of this signal will be set to POOR and a consistency check will then be performed on the remaining GOOD signals. If these signals pass the consistency check, the group value will be taken as the average of these GOOD signals and the group quality will be set to POOR. However, if these signals again fail the consistency check (within +/- DELTAH), then the group value will be set to the average of these two signals; but the group quality will be set to BAD. All of the individual signals will have their quality set to POOR.
DELTAH is a fixed input parameter based upon temperature fluctuation within the hot leg. One DELTAH value is required for each protection set.
DELTA T and T Average are calculated as follows: fcavefhaveiiiTTT= (7.2-6) 0.2/)TT(Tfcavefhaveavgiii+= (7.2-7) The calculated values for DELTA T and Tavg are then utilized for both the remainder of the Overtemperature and Overpower DELTA T protection channel and channel outputs for control purposes. A similar calculation of DELTA T is performed for and used by the steam generator low-low level trip time delay (TTD) function. DCPP UNITS 1 & 2 FSAR UPDATE 7.2-15 Revision 21 September 2013 Alarms are generated from a group status that is based on the quality of fhaveiT and fcaveiT out of the RSA. If the quality of either group is BAD and all of the inputs for that group are not offscale low, then the group status is set to TROUBLE and RTD FAILURE. If either quality is POOR and all of its inputs are not offscale low, then the group status is set to TROUBLE. Otherwise, the group status is set to GOOD. 7.2.1.1.4 Pressurizer Water Level Reference Leg Arrangement The design of the pressurizer water level instrumentation includes a slight modification of the usual tank level arrangement using differential pressure between an upper and a lower tap. The modification shown in Figure 7.2-4 consists of the use of a sealed reference leg instead of the conventional open column of water. Refer to Section 7.2.2.3.4 for an analysis of this arrangement. 7.2.1.1.5 Process Protection System The process protection system is described in Reference 3. 7.2.1.1.6 Solid State (Digital) Logic Protection The solid-state logic protection system takes binary inputs, (voltage/no voltage) from the process and nuclear instrument channels and direct inputs corresponding to conditions (normal/abnormal) of plant parameters. The system combines these signals in the required logic combination and generates a trip signal (no voltage) to the undervoltage coils of the reactor trip circuit breakers and an undervoltage auxiliary relay when the necessary combination of signals occurs. The undervoltage auxiliary relay sends a trip signal (125 Vdc) to the shunt trip coils of the reactor trip breakers. The system also provides annunciator, status light, and computer input signals that indicate the condition of bistable input signals, partial- and full-trip functions, and the status of the various blocking, permissive, and actuation functions. In addition, the system includes means for semiautomatic testing of the logic circuits. A detailed description of this system is provided in Reference 6. Reference 6 is based on SSPS printed circuit boards (PCBs) that use Motorola High Threshold Logic (MHTL). MHTL based PCBs are obsolete and are being replaced with PCBs which are not based on MHTL (reference 33). 7.2.1.1.7 Isolation Devices In certain applications, it is advantageous to employ control signals derived from individual protection channels through isolation devices contained in the protection channel, as permitted by IEEE-279 (Reference 7).
In all of these cases, signals derived from protection channels for nonprotective functions are obtained through isolation devices located in the process protection racks. By definition, nonprotective functions include those signals used for control, remote process indication, and computer monitoring.
Isolation devices qualification type tests are described in References 8, 9, and 32. DCPP UNITS 1 & 2 FSAR UPDATE 7.2-16 Revision 21 September 2013 7.2.1.1.8 Energy Supply and Environmental Qualification Requirements The energy supply for the reactor trip system, including the voltage and frequency variations, is described in Section 7.6. The environmental qualification requirements are identified in Section 3.11. 7.2.1.1.9 Reactor Trip System Instrumentation Trip Setpoints The functions that require trip action are identified in the Technical Specifications. 7.2.1.1.10 Seismic Design The seismic design considerations for the RTS are discussed in Section 3.10. The design meets the requirements of Criterion 2 of the General Design Criteria (GDC) (Reference 10). A discussion of the seismic testing of the RTS equipment is presented in Section 3.10.
The monitoring circuitry, sensors and signal electronics, for several variables that provide inputs to the reactor trip system are not seismically qualified, and in some cases, are not seismically mounted or classified as Design Class I. Those circuits are:
(1) Source range (SR) nuclear instrumentation - sensors and electronics (Design Class I) (2) Intermediate range (IR) nuclear instrumentation - sensors and electronics (Design Class I) (3) Main turbine stop valve closed limit switches (Design Class II) (4) Main turbine auto-stop oil pressure switches (Design Class II) (5) 12 kV bus underfrequency relays, potential transformers and test switches (Design Class II) (6) 12 kV bus undervoltage relays, potential transformers and test switches (Design Class II) (7) 12 kV reactor coolant pump circuit breaker open position switches (Design Class II)
Analyses have been performed to assure that the lack of seismic qualification and seismic installation of these inputs will not degrade the function of the RTS. The electrical circuits that provide the inputs to the RTS from these monitoring channels all are classified as Design Class I, Class 1E circuits. These analyses are based upon the following:
DCPP UNITS 1 & 2 FSAR UPDATE 7.2-17 Revision 21 September 2013 (1) SR and IR Nuclear Instrumentation - The DCPP safety analysis does not take credit for the SR or IR nuclear instrumentation as a primary reactor trip function. The safety analysis is bounded by credit taken for the seismically qualified power range nuclear instrumentation. Although the SR and IR nuclear instrumentation sensors and electronics are not seismically qualified, the SR and IR electronics drawers that provide the inputs to the RTS are seismically mounted in a seismically qualified cabinet. Therefore, no seismically induced common mode failures of the SR or IR nuclear instrumentation drawers exist that could degrade the RTS safety function. (2) Main Turbine Stop Valve Closed Limit Switches - The main turbine stop valve closed limit switches provide inputs to the RTS to signal a turbine tripped (loss of heat sink) condition. These inputs are secondary (backup) reactor trip signals. The stop valve limit switches and field termination cabinets have been seismically analyzed to confirm that the structural integrity of the limit switches and field termination cabinets are such that no seismically induced common mode failures of the main turbine stop valve closed limit switches or field termination cabinets exist that could degrade a primary RTS safety function. (3) Main Turbine Auto-Stop Oil Pressure Switches - The main turbine auto-stop oil pressure switches provide inputs to the RTS to signal a turbine tripped (loss of heat sink) condition. These inputs are secondary (backup) reactor trip signals. The auto-stop oil pressure switches and the cabinet have been seismically analyzed to confirm that the structural integrity of the pressure switches and cabinet to which they are mounted is such that no seismically induced common mode failures of the pressure switches or cabinet exist that could degrade a primary RTS safety function. (4) 12 kV System RTS Input Signals - The 12 kV undervoltage (UV) circuits, underfrequency (UF) circuits and breaker open position switches provide inputs from the 12 kV system to the RTS to signal a loss of rector coolant flow condition. The UV and UF inputs are primary reactor trip signals. The breaker open position inputs are secondary (backup) reactor trip signals. These circuits individually do not meet the RTS seismic qualification or mounting requirements. The UF circuits do not meet the fail-safe criterion. However, when analyzed as a "system," the 12 kV inputs to the RTS fail in such a manner as to assure a reactor trip should the equipment be subjected to an RTS design basis seismic event. In addition, the UV, UF and breaker position switch monitoring circuits and the equipment in which they are mounted have been seismically analyzed to confirm that their structural integrity is such that no seismically induced common mode failures of the monitoring circuits or the equipment in which they are mounted exist that could degrade a primary RTS safety function. DCPP UNITS 1 & 2 FSAR UPDATE 7.2-18 Revision 21 September 2013 7.2.1.2 Design Basis Information The RTS meets IEEE criteria as set forth in IEEE-279.
The following are the generating station conditions requiring reactor trip (see Section 7.1.2):
(1) DNBR approaching the applicable limit value (see Section 4.4.1.1 and Section 4.4.2.3) (2) Power density (kilowatts per foot) approaching rated value for Condition II faults (see Sections 4.2.1, 4.3.1, and 4.4.1 for fuel design limits) (3) RCS overpressure creating stressing approaching the limits specified in Sections 5.2 and 5.5 The following are the variables required to be monitored in order to provide reactor trips (see Figure 7.2-1 and Table 7.2-1): (1) Neutron flux (2) Reactor coolant temperature (3) RCS pressure (pressurizer pressure) (4) Pressurizer water level (5) Reactor coolant flow (6) Reactor coolant pump operational status (bus voltage and frequency, and breaker position) (7) Steam generator water level (8) Turbine operational status (autostop oil pressure and stop valve position)
Reactor coolant temperature is a spatially dependent variable. The effect on the measurement is negated by taking multiple samples from the reactor coolant hot leg and electronically averaging these samples in the process protection system. The parameter values that will require reactor trip are identified in the Technical Specifications. In Chapter 15 (Accident Analyses), the applicable safety analysis proves that the setpoints used are conservative.
The setpoints for the various functions in the RTS have been analytically determined such that the operational limits so prescribed prevent fuel rod cladding damage and loss DCPP UNITS 1 & 2 FSAR UPDATE 7.2-19 Revision 21 September 2013 of integrity of the RCS as a result of any Condition II incident (anticipated malfunction). As such, the RTS limits the following parameters to: (1) Minimum DNBR = The applicable limit value (see Section 4.4.1.1 and Section 4.4.2.3) (2) Maximum system pressure = 2,750 psia (3) Total core power less than or equal to 118 percent of nominal (limits the fuel rod maximum linear power to a kW/ft less than the value that could cause fuel centerline melt) The accident analyses described in Section 15.2 demonstrate that the functional requirements as specified for the RTS are adequate to meet the above considerations, even assuming, for conservatism, adverse combinations of instrument errors (refer to Table 15.1-2). A discussion of the safety limits associated with the reactor core and RCS, plus the limiting safety system setpoints, is presented in the Technical Specifications. For a discussion of energy supply and environmental variations, see Sections 7.6 and 3.11.
The following is a list of the malfunctions, accidents, or other unusual events that could physically damage RTS components or cause environmental changes. The FSAR Update sections noted with each item present discussions on the provisions made to retain the necessary protective action.
(1) Loss-of-coolant accident (see Sections 15.3.1, 15.3.4, and 15.4.1) (2) Steam breaks (see Section 15.3.2 and 15.4.2) (3) Earthquake (see Sections 2.5, 3.2, 3.7, and 3.8) (4) Fire (see Section 9.5) (5) Explosion (hydrogen buildup inside containment; see Section 6.2) (6) Missiles (see Section 3.5) (7) Flood (see Sections 2.4 and 3.4) (8) Wind (see Section 3.3)
The performance requirements are:
(1) System Response Times DCPP UNITS 1 & 2 FSAR UPDATE 7.2-20 Revision 21 September 2013 The RTS response time shall be the time interval from when the monitored parameter exceeds its trip setpoint at the channel sensor until loss of stationary gripper coil voltage. The RTS response times shall be demonstrated as required by the Technical Specifications. Maximum allowable time delays in generating the reactor trip signal are identified in the Equipment Control Guidelines. (2) Reactor trip setpoint allowable values are provided in the Technical Specifications. (3) RTS ranges: RTS Range (a) Power range nuclear power 1 to 120% rated thermal power (RTP) (b) Neutron flux rates +5 to +30% of full power (c) Overtemperature T Thot leg 530 to 650°F Tcold leg 510 to 630°F Tavg 530 to 630°F Pressurizer pressure 1250 to 2500 psig I -60 to +60% f1 (I) 1 to 3%/%I T setpoint 0 to 150% power (d) Overpower T Thot leg 530 to 650°F Tcold leg 510 to 630°F Tavg 510 to 630°F I -60 to +60% f2 (I) 1 to 3%/%I T setpoint 0 to 150 % power (e) Pressurizer pressure 1250 to 2500 psig (f) Pressurizer water level Entire cylindrical portion of pressurizer (0 - 100 %) (g) Reactor coolant flow 0 to 120% of rated flow DCPP UNITS 1 & 2 FSAR UPDATE 7.2-21 Revision 21 September 2013 RTS Range (h) Reactor coolant pump bus 50 to 70 Hz underfrequency (i) Reactor coolant pump 0 to 150 Vac bus voltage (j) Low-low steam generator water level 0 to 45% of narrow-range span 7.2.1.3 Current System Drawings The current system drawings for the RTS and supporting systems are presented at the end of this chapter (see Figures 7.2-1 through 7.2-6, and 7.3-1 through 7.3-52).
7.2.2 ANALYSIS 7.2.2.1 Evaluation of Design 7.2.2.1.1 General Discussion The RTS automatically keeps the reactor operating within a safe region by tripping the reactor whenever the limits of the region are approached. The safe operating region is defined by several considerations such as mechanical and hydraulic limitations on equipment, and heat transfer phenomena. Therefore, the RTS keeps surveillance on process variables that are directly related to equipment mechanical limitations such as pressure, pressurizer water level (to prevent water discharge through safety valves and uncovering heaters), and also on variables that directly affect the heat transfer capability of the reactor (e.g., flow and reactor coolant temperatures). Other parameters utilized in the RTS are calculated from various process variables. In any event, whenever a direct process or a calculated variable exceeds a setpoint, the reactor will be shut down to protect against either gross damage to fuel cladding or loss of system integrity that could lead to release of radioactive fission products into the containment.
While most setpoints used in the RTS are fixed, there are variable setpoints, most notably the overtemperature T and overpower T setpoints. All setpoints in the RTS have been selected either on the basis of applicable engineering code requirements or engineering design studies. Methodologies for determining RTS setpoint and allowable values are presented in WCAP 11082 or in plant procedures. The capability of the RTS to prevent loss of integrity of the fuel cladding and/or RCS pressure boundary during Conditions II and III transients is demonstrated in Chapter 15, Accident Analyses. These accident analyses are carried out using those setpoints determined from results of the engineering design studies. Setpoint limits are presented in the Technical Specifications. A discussion of the intent for each of the various reactor trips and the accident analysis (where appropriate) that utilize the trip is presented below. It should be noted that the selected trip setpoints all provide for margin before protection action is DCPP UNITS 1 & 2 FSAR UPDATE 7.2-22 Revision 21 September 2013 actually required to allow for uncertainties and instrument errors. The design meets the requirements of Criteria 6, 12, 14, and 19 of the GDC. 7.2.2.1.2 Trip Setpoint Discussion It has been pointed out previously that below the applicable DNBR limit value there may be significant local fuel cladding failure. The DNBR existing at any point in the core for a given core design can be determined as a function of the core inlet temperature, power output, operating pressure, and flow. Consequently, core safety limits in terms of a DNBR equal to the safety analysis limit value for the hot channel can be developed as a function of core T, Tavg and pressure for a specified flow as illustrated by the solid lines in Figure 7.2-3. Also shown as solid lines in Figure 7.2-3 are the loci of conditions equivalent to 118 percent power as a function of T and Tavg representing the overpower (kW/ft) limit on the fuel. The dashed lines indicate the maximum permissible setpoint (T) as a function of Tavg and pressure for the overtemperature and overpower reactor trip. Actual setpoint constants in the equation representing the dashed lines are as provided in the Technical Specifications. These values are conservative to allow for instrument errors. The design meets the requirements of Criteria 6, 12, 14, and 19 of the GDC. DNBR is not a directly measurable quantity; however, the process variables that are statistically related to DNBR are sensed and evaluated. Small isolated changes in various process variables may not individually result in violation of a core safety limit, whereas the combined variation over sufficient time may cause the overpower or overtemperature safety limit to be exceeded. The design concept of the RTS takes cognizance of this situation by providing reactor trips associated with individual process variables in addition to the overpower and overtemperature safety limit trips. The process variable trips prevent reactor operation whenever a change in the monitored value is such that a core or system safety limit is in danger of being exceeded should operation continue. Basically, the high-pressure, low-pressure, and overpower and overtemperature T trips provide sufficient protection for slow transients, as opposed to such trips as low flow or high flux, which trip the reactor for rapid changes in flow or flux, respectively, that could result in fuel damage before actuation of the slower responding T channels. Therefore, the RTS has been designed to provide protection for fuel cladding and RCS pressure boundary integrity where: (a) a rapid change in a single variable or factor that will quickly result in exceeding a core or a system safety limit, and (b) a slow change in one or more variables has an integrated effect that causes safety limits to be exceeded. Overall, the RTS offers diverse and comprehensive protection against fuel cladding failure and/or loss of RCS integrity for Conditions II and III accidents. This is demonstrated in Table 7.2-3, which lists the various trips of the RTS, the corresponding Technical Specifications on safety limits and safety system settings, and the appropriate accidents discussed in the safety analyses in which the trip could be utilized.
DCPP UNITS 1 & 2 FSAR UPDATE 7.2-23 Revision 21 September 2013 The RTS design was evaluated in detail with respect to common mode failure and is presented in References 1 and 11. The design meets the requirements of GDC 19, 22, and 23. Preoperational testing was performed on RTS components and systems to determine equipment readiness for startup. This testing served as a further evaluation of the system design.
Analyses of the results of Conditions I, II, III, and IV events, including considerations of instrumentation installed to mitigate their consequences, are presented in Chapter 15. The instrumentation installed to mitigate the consequences of load reduction and turbine trip is identified in Section 7.4.
With the installation of the RTD bypass elimination functional upgrade as part of the Eagle 21 process protection system upgrade, the following plant operating concerns are addressed:
(1) The possibility of loss of flow or reduced flow through the common return line of the hot and cold RTD bypass manifold, as a result of transport time of the temperature measurements for the RTD loop, affecting the design basis for the overtemperature, overpower and control channels monitoring associated with the affected RTD bypass loop is eliminated. (2) Operator indication of the loop Tavg, Tavg, and Delta-T deviation alarms is maintained, providing the operator the same detecting signals as with the bypass loops. (3) The potential for a failed Thot RTD affecting the loop Tavg, Tavg, and T measurements is reduced due to the algorithms provided in the Eagle 21 process protection system software that automatically detect a failed RTD and eliminate the failed RTDs measurement from affecting these plant parameters.
The seismic trip is provided to automatically shut down the reactor in the event of a seismic occurrence that causes the ground acceleration to exceed a preset level. No credit was taken for operation of the seismic trip in the safety analysis; however, its functional capability at the specified trip settings is required to enhance the overall reliability of the reactor protection system.
Checks and tests of these functional units will be made as required by the Technical Specifications. 7.2.2.2 Evaluation of Compliance with Applicable Codes and Standards 7.2.2.2.1 Evaluation of Compliance with IEEE-279 The reactor trip system meets the requirements of IEEE-279 as indicated below.
DCPP UNITS 1 & 2 FSAR UPDATE 7.2-24 Revision 21 September 2013 7.2.2.2.1.1 Single Failure Criterion The protection system is designed to provide two, three, or four instrumentation channels for each protective function and redundant (two) logic trains. These redundant channels and trains are electrically isolated and physically separated. Thus, any single failure within a channel or train will not prevent protective action at the system level when required. This meets the requirements of Criterion 20 of the GDC. The PPS channels are designed so that upon loss of electrical power to any channel, the output of that channel is a trip signal (see Sections 7.2.1.1.1.4 and 7.2.1.1.1.9 for exceptions). This meets the requirements of GDC 26.
To prevent the occurrence of common mode failures, such additional measures as functional diversity, physical separation, testing, as well as administrative control during design, production, installation, and operation are employed, as discussed in Reference 11, for protection logic. Standard reliability engineering techniques were used to assess the likelihood of trip failure due to random component failures. Common mode failures were also qualitatively investigated. It was concluded from the evaluation that the likelihood of no trip following initiation of Condition II events is extremely small (2 x 10-7 derived for random component failures). The solid-state protection system design has been evaluated by the same methods as used for the relay system and the same order of magnitude of reliability is provided. 7.2.2.2.1.2 Quality of Components and Modules For a discussion on the quality assurance program for the components and modules used in the RTS, refer to Chapter 17. The quality used meets the requirements of Criterion 1 of the GDC. 7.2.2.2.1.3 Equipment Qualification For a discussion of the tests made to verify the performance requirements, refer to Section 3.11. The test results demonstrate that the design meets the requirements of GDC 23. 7.2.2.2.1.4 Independence Each individual channel is assigned to one of four channel designations, e.g., Channel I, II, III, or IV. See Figure 7.2-5. Channel independence is carried throughout the system, extending from the sensor through to the devices actuating the protective function. Physical separation is used to achieve separation of redundant transmitters. Separation of wiring is achieved using separate wireways, cable trays, conduit runs, and containment penetrations for each redundant channel. Redundant process equipment is separated by locating electronics in different protection rack sets. Each redundant channel is energized from a separate ac power feed. This meets the requirements of GDC 20.
DCPP UNITS 1 & 2 FSAR UPDATE 7.2-25 Revision 21 September 2013 Position Regarding Separation of Isolated Signal Outputs within Process Protection Racks It is PG&E's position that specific physical separation is not required within the process protection racks between the protection circuits and isolated nonprotection circuits, and that the degree of electrical separation plus the physical separation associated with the insulation on the wires is sufficient to meet the requirements of IEEE-279.
The justification for this position is that IEEE-279 covers this situation in three paragraphs quoted below:
4.2 Single Failure Criterion. Any single failure within the protection system shall not prevent proper protective action at the system level when required. 4.6 Channel Independence. Channels that provide signals for the same protective function shall be independent and physically separated to accomplish decoupling of the effects of unsafe environmental factors, electric transients, and physical accident consequences documented in the design basis, and to reduce the likelihood of interactions between channels during maintenance operations or in the event of channel malfunction. 4.7.2 Isolated Devices. The transmission of signals from protection system equipment for control system use shall be through isolation devices, which shall be classified as part of the protection system and shall meet all the requirements of this document. No credible failure at the output of an isolation device shall prevent the associated protection system channel from meeting the minimum performance requirements specified in the design base. Examples of credible failures include short circuits, open circuits, grounds, and the application of the maximum credible ac and dc potential. A failure in an isolation device is evaluated in the same manner as a failure of other equipment in the protection system. The intent of 4.2 and 4.6 with regard to protection signals is handled through a combination of electrical and physical separation. The electrical separation is handled by supplying each protection rack set with separate independent sources of power. Physical separation is provided by locating redundant channels in separate racks sets. Thus separation, both electrical and physical, outside the rack is ensured. The intent of 4.7.2 is met within the process protection racks by the provision of qualified isolators that have been tested and verified to perform properly under the credible failures listed in 4.7.2. The isolator is designed to be an electrical barrier between protection and nonprotection and, as such, the degree of physical separation provided within the modules is that which is consistent with the voltages involved.
DCPP UNITS 1 & 2 FSAR UPDATE 7.2-26 Revision 21 September 2013 The question of whether or not specific physical separation is required is best addressed by reviewing the potential hazards involved. There are three general categories of hazards that must be protected against. These are missiles, electrical faults, and fire. Missiles external to the rack can be ruled out on the basis that the racks are located in general plant areas where it is not credible to assume missiles capable of penetrating the steel rack. Missiles within the rack can be ruled out on the basis that there is no mechanism within the racks for the generation of missiles with sufficient energy to cause damage to the hardware or wiring.
Electrical faults within a rack constitute a single failure. Since there is no internal mechanism capable of simultaneously causing such a failure in more than one protection set, the result is acceptable. The plant remains safe with three out of the four protection sets remaining in operation. A few very specific electrical faults external to the protection racks on the signals derived from protection channels may have access to the outputs of all protection set simultaneously. However, the isolators have been shown to prevent these disturbances from entering the protection circuits; thus the results are acceptable.
Fire external to the racks is a potential hazard; however, fire retardant paint and wiring, fire barriers at the rack entrances, and adequate separation external to the racks provide a satisfactory defense against the hazard. For further discussions on fire protection, see Sections 8.3.1 and 9.5.1. A potential cause of fire within more than one protection set is an electrical fault involving the nonprotection outputs from these sets; however, it has been verified during the isolator tests that the fault current is terminated by the failure of certain components with no damage occurring in the wiring leading to the module. Thus, a fire within a rack set due to high current igniting or otherwise damaging the wiring is not possible. The remaining source of fire within the racks - a short circuit within the protection wiring-effects only one protection set and thus is acceptable since three of the four protection sets remain.
It is thus established that no credible failure associated with the isolator output wiring violates the single failure criterion; therefore, the present method of rack wiring is entirely adequate. 7.2.2.2.1.5 Separation of Multiplexed, Isolated Solid-State Protection System Signals Information from both logic trains is transmitted to the plant control boards and computer using a multiplex system. To ensure separation of the signals from each train, each signal is passed through an optically-coupled isolator. Verification tests on these isolators using voltages of 118 Vac and 250 Vdc are described in Reference 12.
To provide physical separation between input and output circuits in the solid-state protection system racks, physical barriers have been provided to separate input and output wire bundles. This meets the requirements of GDC 22 and 24. DCPP UNITS 1 & 2 FSAR UPDATE 7.2-27 Revision 21 September 2013 Independence of the logic trains is discussed in Reference 6. Two reactor trip breakers are actuated by two separate logic matrices that interrupt power to the control rod drive mechanisms. The breaker main contacts are connected in series with the power supply so that opening either breaker interrupts power to all control rod drive mechanisms, permitting the rods to free-fall into the core. The design philosophy is to make maximum use of a wide variety of measurements. The protection system continuously monitors numerous diverse system variables. The extent of this diversity has been evaluated for a wide variety of postulated accidents and is discussed in Reference 1. Generally, two or more diverse protection functions would terminate the accident conditions before intolerable consequences could occur. This meets the requirements of Criteria 21 and 23 of the GDC. 7.2.2.2.1.6 Control and Protection System Interaction The protection system is designed to be independent of the control system. In certain applications, the control signals and other nonprotective functions are derived from individual protective channels through isolation devices. The isolation devices are classified as part of the protection system and are located in the process protection racks. Nonprotective functions include those signals used for control, remote process indication, and computer monitoring. The isolation devices are designed so that a short circuit, open circuit, or the application of 118 Vac or 140 Vdc on the isolated output portion of the circuit (i.e., the nonprotective side of the circuit) will not affect the input (protective) side of the circuit. The signals obtained through the isolation devices are never returned to the protective racks. This meets the requirements of Criterion 22 of the GDC. A detailed discussion of the design and testing of the isolation devices is provided in References 8, 9, and 32. These reports include the results of applying various malfunction conditions on the output portion of the isolation devices. The results show that no significant disturbance to the isolation devices input signal occurred. This meets the requirements of Criterion 31 of the GDC.
To provide additional assurance that the electrical wiring to and from the isolators, as installed, would not permit control-side faults to enter the protection system through input-output electrical coupling, tests were conducted at Diablo Canyon using voltages of 118 Vac, 250 Vdc, 460 Vac, 580 Vac and electrical noise. A description of these tests is provided in References 8, 12, and 32.
Where failure of a protection system component can cause a process excursion that requires protective action, the protection system can withstand another independent failure without loss of protective action. This is normally achieved by means of two-out-of-four (2/4) trip logic for each of the protective functions except steam generator protection. The steam generator low-low water level protective function relies upon two-out-of-three (2/3) trip logic and a control system median signal selector (MSS). The use of a control system MSS prevents any protection system failure from causing a DCPP UNITS 1 & 2 FSAR UPDATE 7.2-28 Revision 21 September 2013 control system reaction resulting in a need for subsequent protective action. For details refer to Reference 27. 7.2.2.2.1.7 Capability for Testing The RTS is capable of being tested during power operation. Where only parts of the system are tested at any one time, the testing sequence provides the necessary overlap between the parts to ensure complete system operation. The process protection equipment is designed to permit any channel to be maintained in a bypassed condition and, when required, tested during power operation without initiating a protective action at the system level. This is accomplished without lifting electrical leads or installing temporary jumpers.
If a protection channel has been bypassed for any purpose, a signal is provided to allow this condition to be continuously indicated in the control room.
The operability of the process sensors is ascertained by comparison with redundant channels monitoring the same process variables or those with a fixed known relationship to the parameter being checked. The in-containment process sensors can be calibrated during plant shutdown, if required.
Surveillance testing of the process protection system is performed with the use of a Man Machine Interface (MMI) test system. The MMI is used to enter instructions to the installed test processor in the process protection rack being tested which then generates the appropriate test signals to verify proper channel operation. The capability is provided to test in either partial trip mode or bypass mode where the channel comparators are maintained in the not-tripped state during the testing. Testing in bypass is allowed by the plant Technical Specifications. The bypass condition is continuously indicated in the control room via an annunciator.
The power range channels of the nuclear instrumentation system are tested by superimposing a test signal on the actual detector signal being received by the channel at the time of testing. The output of the bistable is not placed in a tripped condition prior to testing. Also, because the power range channel logic is two-out-of-four, bypass of this reactor trip function is not required. Note, however, that the source and intermediate-range high neutron flux trips must be bypassed during testing.
To test a power range channel, a TEST-OPERATE switch is provided to require deliberate operator action. Operation of the switch initiates the CHANNEL TEST annunciator in the control room. Bistable operation is tested by increasing the test signal level up to its trip setpoint and verifying bistable relay operation by control board annunciator and trip status lights.
It should be noted that a valid trip signal would cause the channel under test to trip at a lower actual reactor power level. A reactor trip would occur when a second bistable trips. No provision has been made in the channel test circuit for reducing the channel DCPP UNITS 1 & 2 FSAR UPDATE 7.2-29 Revision 21 September 2013 signal level below that signal being received from the nuclear instrumentation system detector. A nuclear instrumentation system channel that causes a reactor trip through one-out-of-two protection logic (source or intermediate range) is provided with a bypass function, which prevents the initiation of a reactor trip from that particular channel during the short period that it is undergoing testing. These bypasses initiate an alarm in the control room.
For a detailed description of the nuclear instrumentation system, see Reference 2.
The logic trains of the RTS are designed to be capable of complete testing at power, except for those trips listed in Section 7.2.3.2. Annunciation is provided in the control room to indicate when a train is in test, when a reactor trip is bypassed, and when a reactor trip breaker is bypassed. Details of the logic system testing are provided in Reference 6.
The reactor coolant pump breakers cannot be tripped at power without causing a plant upset by loss of power to a coolant pump. However, the reactor coolant pump breaker trip logic and continuity through the shunt trip coil can be tested at power. Manual trip cannot be tested at power without causing a reactor trip, because operation of either manual trip switch actuates both trains A and B. Note, however, that manual trip could also be initiated from outside the control room by manually tripping one of the reactor trip breakers. Initiating safety injection cannot be done at power without upsetting normal plant operation. However, the logic for these trips is testable at power.
Testing of the logic trains of the RTS includes a check of the input relays and a logic matrix check. The following sequence is used to test the system: (1) Check of Input Relays - During testing of the process instrumentation system and nuclear instrumentation system comparators, each channel comparator is placed in a trip mode causing one input relay in train A and one in train B to de-energize. A contact of each relay is connected to a universal logic printed circuit card. This card performs both the reactor trip and monitoring functions. The contact that creates the reactor trip also causes a status lamp and an annunciator on the control board to operate. Either train A or B input relay operation lights the status lamp and sounds the annunciator. Each train contains a multiplexing test switch. This switch is normally configured such that train A is in the A+B position, while train B is in the Normal position. Administrative controls are used to control this configuration and may be changed to other configurations as necessary to meet plant conditions. The A+B position alternately allows information to be transmitted from the two trains to the control board. A steady-status lamp and annunciator indicates that input relays in both trains have been deenergized. A flashing lamp means that both input relays in the two trains did not deenergize. Contact inputs to the logic protection system, such as DCPP UNITS 1 & 2 FSAR UPDATE 7.2-30 Revision 21 September 2013 reactor coolant pump bus underfrequency relays, operate input relays that are tested by operating the remote contacts as previously described and using the same indications as those provided for bistable input relays. Actuation of the input relays provides the overlap between the testing of the logic protection system and the testing of those systems supplying the inputs to the logic protection system. Test indications are status lamps and annunciators on the control board. Inputs to the logic protection system are checked one channel at a time, leaving the other channels in service. For example, a function that trips the reactor when two-out-of-four channels trip becomes a one-out-of-three trip when one channel is placed in the trip mode. Both trains of the logic protection system remain in service during this portion of the test. (2) Check of Logic Matrices - Logic matrices are checked one train at a time. Input relays are not operated during this portion of the test. Reactor trips from the train being tested are inhibited with the use of the input error inhibit switch on the semiautomatic test panel in the train. Details of semiautomatic tester operation are provided in Reference 6. At the completion of the logic matrix tests, one bistable in each channel of process instrumentation or nuclear instrumentation is tripped or is verified in the tripped state to check closure of the input error inhibit switch contacts. With the exception of the P-8 blocking function, the logic test scheme uses pulse techniques to check the coincidence logic. All possible trip and nontrip combinations are checked. Pulses from the tester are applied to the inputs of the universal logic card at the same points electrically that connect to the input relay contacts. Thus, there is an overlap between the input relay check and the logic matrix check. Pulses are fed back from the reactor trip breaker undervoltage coil to the tester. The pulses are of such short duration that the reactor trip breaker undervoltage coil armature should not respond mechanically. Because the P-8 block of the one of four RCS low flow trip is not connected to the semiautomatic tester, it is tested using the manual input function pushbuttons. The P-8 block function is verified using only one loop of RCS low flow on a staggered monthly frequency and all loops on a refueling frequency. Test indications that are provided are an annunciator in the control room indicating that reactor trips from the train have been blocked and that the train is being tested, and green and red lamps on the semiautomatic tester to indicate a good or bad logic matrix test. Protection capability provided during this portion of the test is from the train not being tested. DCPP UNITS 1 & 2 FSAR UPDATE 7.2-31 Revision 21 September 2013 The general design features and details of the testability of the logic system are described in Reference 6. The testing capability meets the requirements of Criteria 19 and 25 of the GDC. (3) Testing of Reactor Trip Breakers - Normally, reactor trip breakers 52/RTA and 52/RTB are in service, and bypass breakers 52/BYA and 52/BYB are withdrawn (out of service). In testing the protection logic, pulse techniques are used to avoid tripping the reactor trip breakers, thereby eliminating the need to bypass them during the testing, although the associated bypass breaker is closed to preclude an inadvertent reactor trip and to allow reactor trip breaker testing. The following procedure describes the method used for testing the trip breakers: (a) Bypass breaker 52/BYB is racked to test position and closed (b) With bypass breaker 52/BYA racked out (test position), manually close and trip it to verify its operation (c) Rack in and close 52/BYA (bypasses 52/RTA) (d) While blocking 52/RTA shunt trip, manually trip 52/RTA and 52/BYB through a protection system logic matrix (e) Reset 52/RTA (f) Manually trip 52/RTA using the shunt trip coil only with the shunt trip test push button (g) Reset 52/RTA (h) Rack out 52/BYB (i) Trip and rack out 52/BYA (j) Repeat above steps to test trip breaker 52/RTB and bypass breaker 52/BYA using bypass breaker 52/BYB to bypass 52/RTB Auxiliary contacts of the bypass breakers are connected so that if either train is placed in test while the bypass breaker of the other train is fully racked in and closed, both reactor trip breakers and the bypass breaker automatically trip. Auxiliary contacts of the bypass breakers are also connected in such a way that if an attempt is made to fully rack in and close the bypass breaker in one train while the bypass breaker of the other train is already fully racked in and closed, both bypass breakers automatically trip. Additionally, trip DCPP UNITS 1 & 2 FSAR UPDATE 7.2-32 Revision 21 September 2013 signals will be sent to both reactor trip and bypass breakers through the protection system logic. The train A and train B alarm systems operate an annunciator in the control room. The two bypass breakers also operate an annunciator in the control room. Bypassing of a protection train with either the bypass or the test switches results in audible and visual indications. The complete RTS is normally required to be in service. However, to permit on-line testing of the various protection channels or to permit continued operation in the event of a subsystem instrumentation channel failure, a Technical Specification defining the minimum number of operable channels and the minimum degree of channel redundancy has been formulated. This Technical Specification also defines the required restriction to operation in the event that the channel operability and degree of redundancy requirements cannot be met. The RTS is designed in such a way that some components' response time tests can only be performed during shutdown. However, the safety analyses utilize conservative numbers for trip channel response times. The measured channel response times are compared with those used in the safety evaluations. On the basis of startup tests conducted on several plants, the actual response times measured are less than the times used in the safety analyses. (4) Bypasses - The Eagle 21 process protection system is designed to permit an inoperable channel to be placed in a bypass condition for the purpose of troubleshooting or periodic test of a redundant channel. Use of the bypass mode disables the individual channel comparator trip circuitry that forces the associated logic input relays to remain in the non-tripped state until the "bypass" is removed. If the process protection channel has been bypassed for any purpose, a signal is provided to allow this condition to be continuously indicated in the control room. During such operation, the process protection system continues to satisfy the single failure criterion. This is acceptable since there are 4 channels and the two-out-of-four trip logic reduces to two-out-of-three during the test. For functions that use two-out-of-three logic, it is implicitly accepted that the single failure criterion is met because of the results of the system reliability study. From the results of this it was concluded that the Eagle 21 digital system availability is equivalent to the respective analog process protection system availability even without the incorporation of the redundancy, automatic surveillance testing, self calibration and self diagnostic features of the Eagle 21 process protection system. DCPP UNITS 1 & 2 FSAR UPDATE 7.2-33 Revision 21 September 2013 EXCEPTIONS: (a) "One-out-of-two" functions are permitted to violate the single failure criterion during channel bypass provided that acceptable reliability of operation can be otherwise demonstrated and bypass time interval is short. (b) Containment spray actuation channels are tested by bypassing or negating the channel under test. This is acceptable since there are 4 channels and the two-out-of-four trip logic reduces to two-out-of-three during the test. INTERLOCK CIRCUITS A listing of the operating bypasses is included in Table 7.2-2. These bypasses meet the intent of the requirements of Paragraph 4.12 of IEEE-279. Where operating requirements necessitate automatic or manual bypass* of a protective function, the design is such that the bypass is removed automatically whenever permissive conditions are not met. Devices used to achieve automatic removal of the bypass of a protective function are considered part of the protective system and are designed in accordance with the criteria of this section. Indication is provided in the control room if some part of the system has been administratively bypassed or taken out of service. *Note: The term "bypass" is defined as the meeting of the coincident permissive (interlock) logic to permit the protective logic to become enabled/disabled as required. The term "bypass," in this section is not intended to be defined as the disabling of the individual channel comparator trip circuitry during routine test or surveillance that forces the associated logic input relays to remain in the non-tripped state until the "bypass" is removed. (5) Multiple Setpoints - For monitoring neutron flux, multiple setpoints are used. When a more restrictive trip setting becomes necessary to provide adequate protection for a particular mode of operation or set of operating conditions, the protective system circuits are designed to provide positive means or administrative control to ensure that the more restrictive trip setpoint is used. The devices used to prevent improper use of less restrictive trip settings are considered part of the protective system and are designed in accordance with the criteria of this section. DCPP UNITS 1 & 2 FSAR UPDATE 7.2-34 Revision 21 September 2013 (6) Completion of Protective Action - The RTS is so designed that, once initiated, a protective action goes to completion. Return to normal operation requires action by the operator. (7) Manual Initiation - Switches are provided on the control board for manual initiation of protective action. Failure in the automatic system does not prevent the manual actuation of the protective functions. Manual actuation relies on the operation of a minimum of equipment. Additionally, the reactor trip and bypass breakers can be operated locally. (8) Access - The design provides for administrative control of access to all setpoint adjustments, module calibration adjustments, test points, and the means for bypassing channels or protective functions. For details refer to Reference 23. (9) Information Readout - The RTS provides the operator with complete information pertinent to system status and safety. All transmitted signals (flow, pressure, temperature, etc.) that cause a reactor trip are either indicated or recorded for every channel including all neutron flux power range currents (top detector, bottom detector, algebraic difference, and average of bottom and top detector currents). Any reactor trip actuates an annunciator. Annunciators are also used to alert the operator of deviations from normal operating conditions so that he may take appropriate corrective action to avoid a reactor trip. Actuation of any rod stop or trip of any reactor trip channel actuates an annunciator. (10) Identification - The identification described in Section 7.1.2.3 provides immediate and unambiguous identification of the protection equipment. 7.2.2.2.2 Evaluation of Compliance with IEEE-308 (Reference 13) See Section 7.6 and Chapter 8 for a discussion on the power supply for the RTS and compliance with IEEE-308 (Reference 13). 7.2.2.2.3 Evaluation of Compliance with IEEE-323 Refer to Section 3.11 for a discussion on Class I electrical equipment environmental qualification and compliance to IEEE-323 (Reference 14). Documentation of the Environmental and Seismic qualification of the process protection system is provided in References 23, 24, 25, and 26. DCPP UNITS 1 & 2 FSAR UPDATE 7.2-35 Revision 21 September 2013 7.2.2.2.4 Evaluation of Compliance with IEEE-334 There are no Class I motors in the RTS; therefore, IEEE-334 (Reference 15) does not apply. 7.2.2.2.5 Evaluation of Compliance with IEEE-338 The periodic testing of the RTS conforms to the requirements of IEEE-338 (Reference 16), with the following comments:
(1) The periodic test frequency specified in the Technical Specifications was conservatively selected, using the considerations discussed in paragraph 4.3 of Reference 16, to ensure that equipment associated with protection functions has not drifted beyond its minimum performance requirements. (2) The test interval discussed in Paragraph 5.2 of Reference 16 is developed primarily on past operating experience and modified, if necessary, to ensure that system and subsystem protection is reliably provided. Analytic methods for determining reliability are not used to determine test interval. 7.2.2.2.6 Evaluation of Compliance with IEEE-344 The seismic testing, as discussed in Section 3.10, conforms to IEEE-344 (Reference 17) except the format of the documentation may not meet the requirements because testing was completed prior to issuance of the standard. Documentation of the Environmental and Seismic qualification of the process protection system is provided in References 23, 24, 25, and 26. 7.2.2.2.7 Evaluation of Compliance with IEEE-317 The electrical penetrations are designed and built in accordance with IEEE-317 (Reference 18) with the following exceptions: (1) Prototype tests were not made with all of the physical conditions of the accident environment applied simultaneously with the electrical tests, although they were successfully made separately. For example, the momentary current tests on power penetrations are not run under simulated accident conditions. It is felt that such tests need not be made simultaneously because the construction of the penetration assemblies is such that the outer seal is located about 4-1/2 feet away from the inner seal and the containment liner and, therefore, will not be exposed to accident environmental conditions. The integrity of the containment is, therefore, maintained at the penetration assemblies during a loss-of-coolant accident (LOCA).
DCPP UNITS 1 & 2 FSAR UPDATE 7.2-36 Revision 21 September 2013 (2) Dielectric strength tests were conducted in accordance with the National Electrical Manufacturers Association (NEMA) standard that permits testing of this type of equipment at 20 percent higher than twice-rated voltage plus 1000 V for 1 second. (3) Wire and cable splice samples used at the containment penetrations were tested under conditions simulating a LOCA environment. Refer to Section 3.11 for a discussion on Class I electrical equipment environmental qualification. 7.2.2.2.8 Evaluation of Compliance with IEEE-336 Diablo Canyon is in conformance with IEEE-336 (Reference 19), with the following exceptions:
(1) Paragraph 2.4 - "Data sheets shall contain an evaluation of acceptability." The evaluation of acceptability is indicated on the results and data sheets by the approval signature. (2) Paragraph 3(4) - "Visual examination of contact corrosion." No visual examination for contact corrosion is made on breaker and starter contacts unless there is evidence of water damage or condensation. Contact resistance tests are made on breakers rated at 4 kV and above. No contact resistance test is made of lower voltage breakers or starters. (3) Paragraph 6.2.2 - "Demonstrate freedom from unwanted noise." No system test incorporates a noise measurement. If the system under test meets the test criteria, then noise is not a problem. 7.2.2.2.9 Eagle 21 Design, Verification and Validation Plan The standards that are applicable to the Eagle 21 Design, Verification, and Validation Plan are IEEE Standard 603-1980 (Reference 28), Regulatory Guide 1.152 (Reference 29), Regulatory Guide 1.153 (Reference 30), and ANSI/IEEE-ANS-7-4.3.2 (Reference 31). 7.2.2.2.10 Evaluation of Compliance with AEC General Design Criteria The RTS meets the requirements of the GDC wherever appropriate. Specific cases are noted in this chapter.
DCPP UNITS 1 & 2 FSAR UPDATE 7.2-37 Revision 21 September 2013 7.2.2.3 Specific Control and Protection Interactions 7.2.2.3.1 Nuclear Power Four power range nuclear power channels are provided for overpower protection. An additional control input signal is derived by auctioneering of the four channels for automatic rod control. If any channel fails producing a low output, that channel is incapable of proper overpower protection but does not cause control rod movement because of the auctioneer. Two-out-of-four overpower trip logic ensures an overpower trip, if needed, even with an independent failure in another channel.
In addition, a deviation signal gives an alarm if any nuclear power channel deviates significantly from any of the other channels. Also, the control system responds only to rapid changes in nuclear power; slow changes or drifts are compensated by the temperature control signals. Finally, an overpower signal from any nuclear power range channel will block manual and automatic rod withdrawal. The setpoint for this rod stop is below the reactor trip setpoint. 7.2.2.3.2 Coolant Temperature The accuracy of the RTD temperature measurements is demonstrated during plant startup tests by comparing temperature measurements from all RTDs with one another. The comparisons are done with the RCS in an isothermal condition. The linearity of the T measurements obtained from the hot leg and cold leg RTDs as a function of plant power is also checked during plant startup tests. The absolute value of T versus plant power is not important as far as reactor protection is concerned. Reactor trip system setpoints are based on percentages of the indicated T at nominal full power, rather than on absolute values of T. For this reason, the linearity of the T signals as a function of power is of importance rather than the absolute values of the T. As part of the plant startup tests, the loop RTDs signals are compared with the core exit thermocouple signals. Note also that reactor control is based on signals derived from protection system channels after isolation by isolation devices so that no feedback effect can perturb the protection channels.
Because control is based on the average temperature of the loop having the highest average temperature, the control rods are always moved based on the most conservative temperature measurement with respect to margins to DNB. A spurious low average temperature measurement from any loop temperature control channel causes no control action. A spurious high average temperature measurement causes rod insertion (safe direction).
In addition, channel deviation signals in the control system give an alarm if any temperature channel deviates significantly from the auctioneered (highest) value. Automatic rod withdrawal blocks also occur if any two of the temperature channels indicate an overtemperature or overpower condition. DCPP UNITS 1 & 2 FSAR UPDATE 7.2-38 Revision 21 September 2013 7.2.2.3.3 Pressurizer Pressure The pressurizer pressure protection channel signals are used for high- and low-pressure protection and as inputs to the overtemperature T trip protection function. Isolated output signals from these channels are used for pressure control. These are used to control pressurizer spray and heaters, and power-operated relief valves. Pressurizer pressure is sensed by fast-response pressure transmitters.
A spurious high-pressure signal from one channel can cause decreasing pressure by actuation of either spray or relief valves. Additional redundancy is provided in the low pressurizer pressure reactor trip logic and in the logic for safety injection to ensure low-pressure protection.
The pressurizer heaters are incapable of overpressurizing the RCS. Overpressure protection is based on the positive volume surge of the reactor coolant produced as a result of turbine trip under full load, assuming the core continues to produce full power. The self-actuated safety valves are sized on the basis of steam flow from the pressurizer to accommodate this surge at a setpoint of 2500 psia and an accumulation of 3 percent. Note that no credit is taken for the relief capability provided by the power-operated relief valves during this surge.
In addition, operation of any one of the power-operated relief valves can maintain pressure below the high-pressure trip point for most transients. The rate of pressure rise achievable with heaters is slow, and ample time and pressure alarms are available to alert the operator to the need for appropriate action.
Two of the pressure sensors share a common tap. The other two sensors use separate taps. Redundancy is not impaired by having a shared tap because the logic for this trip is two-out-of-four. If the shared tap is plugged, the reading of the affected channels will remain static. If the impulse line bursts, the indicated pressure will drop to zero. In either case, the fault is easily detectable, and the protective function remains operable. 7.2.2.3.4 Pressurizer Water Level Three pressurizer water level channels are used for reactor trip (two-out-of-three high level). Isolated signals from these channels are used for pressurizer water level control. A failure in the water level control system could fill or empty the pressurizer at a slow rate (on the order of 1/2 hour or more). Experience has shown that hydrogen gas can accumulate in the upper part of the condensate pot on conventional open reference leg systems in pressurizer water level service. At RCS operating pressures, high concentrations of dissolved hydrogen in the reference leg water are possible. On sudden depressurization accidents, it has been hypothesized that rapid effervescence of the dissolved hydrogen could blow water out of the reference leg and cause a large level error, measuring higher than actual level. Accurate calculations of this effect have been difficult to obtain. To eliminate the possibility of such effects in this application, a bellows is used in a pot at the top of the DCPP UNITS 1 & 2 FSAR UPDATE 7.2-39 Revision 21 September 2013 reference leg to provide an interface seal and prevent dissolving the hydrogen gas into the reference leg water. Supplier tests confirmed a time response of less than 1 second for the channel. The reference leg is uninsulated and remains at local ambient temperature. This temperature varies somewhat over the length of the reference leg piping under normal operating conditions, but does not exceed 140°F. During the extreme temperature conditions caused by a blowdown accident, any reference leg water flashing to steam is confined to the condensate steam interface in the weir at the top of the temperature barrier leg and has only a small (about 12 inches between the top of weir and bellows) effect on the measured level. Some additional error may be expected due to effervescence of hydrogen in the temperature barrier water. However, even if complete loss of this water is assumed, the error will be less than 1 foot and will not violate a safety limit. The sealed reference leg design has been installed in various plants since early 1970, and operational accuracy was verified by use of the sealed reference leg system in parallel with an open reference leg channel. No effects of operating pressure variations on either the accuracy or integrity of the channel have been observed. Calibration of the sealed reference leg system is done in place, after installation, by application of known pressure to the high pressure side of the transmitter with the pressure of the height of the reference column, corrected for density, applied to the transmitter lowside. The effects of static pressure variations are predictable. The largest effect is due to the density change in the saturated fluid in the pressurizer itself. The effect is typical of level measurements in all tanks with two-phase fluid and is not peculiar to the sealed reference leg technique.
In the sealed reference leg, there is a slight compression of the fill water with increasing pressure, but this is taken up by the flexible bellows. A leak of the fill water in the sealed reference leg is detectable by comparison of redundant channel readings while the plant is on-line, and by physical inspection of the reference leg while the plant is off-line. Leaks of the reference leg to atmosphere are immediately detectable by off-scale indications and alarms on the control board. A closed pressurizer level instrument shutoff valve would be detected by comparing the level indications from the redundant level channels (three channels). In addition, there are alarms on one of the three channels to indicate an error between the measured pressurizer water level and the programmed pressurizer water level. The instrument sensing lines for these level sensing instruments are designed so that no single instrument valve can affect more than one of the three level channels.
The high water level trip setpoint provides sufficient margin so that the undesirable condition of discharging liquid coolant through the safety valves is avoided. Even at full power conditions, which would produce the worst thermal expansion rates, a failure of the water level control would not lead to any liquid discharge through the safety valves. This is due to the automatic high pressurizer pressure reactor trip actuating at a pressure sufficiently below the safety valve setpoint. DCPP UNITS 1 & 2 FSAR UPDATE 7.2-40 Revision 21 September 2013 For control failures that tend to empty the pressurizer, two-out-of-four logic for safety injection action low pressurizer pressure ensures that the protection system can withstand an independent failure in another channel. In addition, ample time and alarms exist to alert the operator of the need for appropriate action. 7.2.2.3.5 Signal Validation Functions The basic function of the reactor protection circuits associated with low steam generator water level is to preserve the steam generator heat sink for removal of long-term residual heat.
Should a complete loss of feedwater occur, the reactor would be tripped on low-low steam generator water level. In addition, redundant auxiliary feedwater pumps are provided to supply feedwater in order to maintain residual heat removal after trip, preventing eventual thermal expansion and discharge of the reactor coolant through the pressurizer relief valves into the relief tank even when main feedwater pumps are incapacitated. This reactor trip acts before the steam generators are dry to reduce the required capacity and starting time requirements of these auxiliary feedwater pumps, and to minimize the thermal transient on the RCS and steam generators. Therefore, a low-low steam generator water level reactor trip is provided for each steam generator to ensure that sufficient initial thermal capacity is available in the steam generator at the start of the transient. It is desirable to minimize thermal transients on a steam generator for a credible loss of feedwater accident. Hence, it should be noted that a protection system failure causing control system reaction is eliminated by implementation of control system signal validation; that is, steam generator water level (SGWL) median signal selector (MSS) and steam flow arbitrator (SFA) functions in the Class II digital feedwater control system. The prime objective of the signal validation functions is to prevent a single failed protection system instrument channel from causing a disturbance in the feedwater control system requiring subsequent protective action, as required by IEEE Std 279-1971. All three isolated narrow range water level channels for each steam generator are input to the SGWL MSS. The device selects the median value of its inputs for use by the feedwater control system, and control system action is then based on this validated signal. By rejecting the high and low signals, the control system is prevented from acting on any single, failed protection system instrument channel.
The SFA function is provided to validate the steam flow inputs. The SFA uses logic to determine an appropriate control signal output based on the two steam flow channels for each steam generator. If the two input signals agree within a specified limit, the arbitrator output is the average of the inputs. If the deviation between the input signals exceeds the specified limit, the input signal closest to the arbitration signal is selected as the output. If neither of the inputs is within a specified limit, the arbitration signal itself is selected as the output of the arbitrator. The arbitration signal is based on turbine first stage pressure.
DCPP UNITS 1 & 2 FSAR UPDATE 7.2-41 Revision 21 September 2013 These algorithms prevent a single input channel failure from causing a control system transient requiring protective action. This includes failure of the instrument tap that is shared between one narrow-range level channel and one steam flow channel on each steam generator. The MSS function for steam generator narrow range level and the SFA function for steam flow satisfy the control and protection interaction requirement of IEEE Std 279-1971.
Since no adverse control system action may result from a single, failed protection instrument channel, a second random protection system failure (as would otherwise be required by IEEE 279-1971) need not be considered. A more detailed discussion of the SFA and MSS and their compliance with control and protection system interaction criteria is provided in Reference 27. 7.2.2.3.6 Seismic Trip The outputs of the seismic trip sensors are wired directly to the solid-state protection system. See Figure 7.2-1, Sheet 18.
The seismic reactor trip system was designed in compliance with IEEE-279 (Reference 7) and IEEE-344 (Reference 21), but will not be required to function during or following a LOCA or fire. Cables and raceways are separated in accordance with Section 8.3.1.4.1. 7.2.3 TESTS AND INSPECTIONS The RTS meets the testing requirements of Reference 16 with the exceptions identified in Section 7.2.2. The testability of the system is discussed in Section 7.2.2. Written test procedures and documentation, conforming to the requirements of Reference 16, are available for audit by authorized personnel.
The minimum frequencies for checks, calibration, and testing at each of the plant's operating modes are defined in the Technical Specifications. Based on experience in operation of both conventional and nuclear plant systems, when the plant is in operation, the minimum checking frequencies set forth therein are considered adequate. 7.2.3.1 In-Service Tests and Inspections Periodic surveillance of the RTS is performed to ensure proper protective action. This surveillance consists of checks, calibrations, and functional testing that are summarized in the following sections. 7.2.3.1.1 Channel Checks A channel check consists of a qualitative assessment of channel behavior during operation by observation. This determination shall include, where possible, comparison of the channel indication and/or status with other indications and/or status derived from independent instrument channels measuring the same parameters. DCPP UNITS 1 & 2 FSAR UPDATE 7.2-42 Revision 21 September 2013 7.2.3.1.2 Channel Calibration A channel calibration shall be the adjustment, as necessary, of the channel such that it responds within the required range and accuracy to known values of input. The channel calibration shall encompass the entire channel including the sensors and alarm, interlock and/or trip functions, and may be performed by any series of sequential, overlapping, or total channel steps such that the entire channel is calibrated. 7.2.3.1.3 Actuation Logic Test An actuation logic test shall be the application of various simulated input combinations in conjunction with each possible interlock logic state and verification of the required logic output. The actuation logic test shall include a continuity check, as a minimum, of output devices. 7.2.3.1.4 Process Protection Channel Operational Test A channel operational test shall be the injection of a simulated signal into the channel as close to the sensor as practicable to verify operability of alarm, interlock, and/or trip functions. The channel operational test shall include adjustments, as necessary, of the alarm, interlock, and/or trip setpoints such that the setpoints are within the required range and accuracy. 7.2.3.1.5 Trip Actuating Device Operational Test A trip actuating device operational test shall consist of operating the trip actuating device and verifying operability of alarm, interlock, and/or trip functions. The trip actuating device operational test shall include adjustment, as necessary, of the trip actuating device such that it actuates at the required setpoint within the required accuracy. 7.2.3.1.6 Reactor Trip System Response Time The RTS response time shall be the time interval from when the monitored parameter exceeds its trip setpoint at the channel sensor until loss of stationary gripper coil voltage. 7.2.3.2 Compliance with Safety Guide 22 Periodic testing of the RTS actuation functions, as described, complies with AEC Safety Guide 22 (Reference 22). Under the present design, there are protection functions that are not tested at power. These are:
(1) Generation of a reactor trip by tripping the reactor coolant pump breakers (2) Generation of a reactor trip by tripping the turbine
(3) Generation of a reactor trip by use of the manual trip switch DCPP UNITS 1 & 2 FSAR UPDATE 7.2-43 Revision 21 September 2013 (4) Generation of a reactor trip by actuating the safety injection system (5) Generation of a reactor trip by general warning circuitry (both redundant trains) (6) Generation of a reactor trip by closing both reactor trip bypass breakers The actuation logic for the functions listed is tested as described in Section 7.2.2. As required by Safety Guide 22, where equipment is not tested during reactor operation, it has been determined that:
(1) There is no practicable system design that would permit operation of the equipment without adversely affecting the safety or operability of the plant. (2) The probability that the protection system will fail to initiate the operation of the equipment is, and can be maintained, acceptably low without testing the equipment during reactor operation. (3) The equipment can be routinely tested when the reactor is shut down.
Where the ability of a system to respond to a bona fide accident signal is intentionally bypassed for the purpose of performing a test during reactor operation, each bypass condition is automatically indicated to the reactor operator in the main control room by a separate annunciator for the train in test. Test circuitry does not allow two trains to be tested at the same time so that extension of the bypass condition to redundant systems is prevented. 7.
2.4 REFERENCES
- 1. T. W. T. Burnett, Reactor Protection System Diversity in Westinghouse Pressurized Water Reactors, WCAP-7306, April 1969.
- 2. J. B. Lipchak, and R.A. Stokes, Nuclear Instrumentation System, WCAP-7669, April 1971.
- 3. J. A. Nay, Process Instrumentation for Westinghouse Nuclear Steam Supply Systems, WCAP-7671, April 1971.
- 4. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
- 5. D. N. Katz, Solid State Logic Protection System Description, WCAP-7488L, January 1971.
- 6. D. N. Katz, Solid State Logic Protection System Description, WCAP-7672, June 1971.
DCPP UNITS 1 & 2 FSAR UPDATE 7.2-44 Revision 21 September 2013 7. IEEE Standard 279-1971, Criteria for Protection Systems for Nuclear Power Generating Stations, The Institute of Electrical and Electronics Engineers. 8. J. P. Doyle, Noise, Fault, Surge, and Radio Frequency Interference Test Report for Westinghouse Eagle-21 Process Protection Upgrade System, WCAP-11733, June 1988 (W Proprietary Class 2).
- 9. R. Bartholomew and J. Lipchak, Test Report, Nuclear Instrumentation System Isolation Amplifier, WCAP-7819, Rev. 1, January 1972.
- 10. Proposed General Design Criteria for Nuclear Power Plant Construction Permits, Federal Register, July 11, 1967.
- 11. W. C. Gangloff, An Evaluation of Anticipated Operational Transients in Westinghouse Pressurized Water Reactors, WCAP-7486, May 1971.
- 12. D. N. Katz, et al., Westinghouse Protection Systems Noise Tests, WCAP-12358, Revision 2, October 1975 (W Proprietary Class 3).
- 13. IEEE Standard 308-1971, Criteria for Class 1E Electric Systems for Nuclear Power Generating Stations, The Institute of Electrical and Electronics Engineers, Inc.
- 14. IEEE Standard 323-1971, Trial-Use Standard: General Guide for Qualifying Class I Electric Equipment for Nuclear Power Generating Stations, The Institute of Electrical and Electronics Engineers, Inc. 15. IEEE Standard 334-1971, Trial-Use Guide for Type Tests of Continuous-Duty Class I Motors Installed Inside the Containment of Nuclear Power Generating Stations, The Institute of Electrical and Electronics Engineers, Inc.
- 16. IEEE Standard 338-1971, Trial-Use Criteria for the Periodic Testing of Nuclear Power Generating Station Protection Systems, The Institute of Electrical and Electronics Engineers Inc.
- 17. IEEE Standard 344-1971, Trial-Use Guide for Seismic Qualification of Class I Electric Equipment for Nuclear Power Generating Stations, The Institute of Electrical and Electronics Engineers, Inc.
- 18. IEEE Standard 317-1971, Electric Penetration Assemblies in Containment Structures for Nuclear Fueled Power Generating Stations, The Institute of Electrical and Electronics Engineers, Inc.
- 19. IEEE Standard 336-1971, Installation, Inspection and Testing Requirements for Instrumentation and Electrical Equipment during the Construction of Nuclear DCPP UNITS 1 & 2 FSAR UPDATE 7.2-45 Revision 21 September 2013 Power Generating Stations, The Institute of Electrical and Electronics Engineers, Inc.
- 20. Deleted in Revision 15.
- 21. IEEE Standard 344-1975, Recommended Practices for Seismic Qualification of Class 1E Equipment for Nuclear Power Generating Stations, The Institute of Electrical and Electronics Engineers, Inc.
- 22. Safety Guide 22, Periodic Testing of Protection System Actuation Functions, USAEC, February, 1972.
- 23. L. E. Erin, Topical Report Eagle 21 Microprocessor Based Process Protection System, WCAP-12374, September 1989.
- 24. R. B. Miller, Methodology for Qualifying Westinghouse WRD Supplied NSSS Safety-Related Electrical Equipment, WCAP-8587, W Proprietary Class 3.
- 25. Equipment Qualification Data Package, WCAP-8587, Supplement 1, EQDP-SE-9A and 69B, W Proprietary Class 3.
- 26. Equipment Qualification Test Report, WCAP-8687, Supplement 2-E69A and 69B, W Proprietary Class 2.
- 27. Advanced Digital Feedwater Control System Input Signal Validation for Pacific Gas and Electric Company Diablo Canyon Units 1 and 2, WCAP-12221 W Proprietary Class 3, April 1997 (PGE-97-540) and WCAP-12222 W Proprietary Class 3, March 1989.
- 28. IEEE Standard 603-1980, IEEE Standard Criteria for Safety Systems for Nuclear Power Generating Stations.
- 29. Regulatory Guide 1.152, Criteria for Programmable Digital Computer System Software in Safety-Related Systems in Nuclear Plants, November 1985.
- 30. Regulatory Guide 1.153, Criteria for Power, Instrumentation and Control Portions of Safety Systems, December 1985.
- 31. ANSI/IEEE-ANS 7-4.3.2, Application Criteria for Programmable Digital Computer Systems in Safety Systems of Nuclear Power Generating Stations, 1982.
- 32. C. N. Nasrallah, Noise, Fault, Surge, and Radio Frequency Interference Test Report - Westinghouse Eagle-21 Digital Family as Used in QDPS, PSMS, RVLIS, and ICCM, WCAP-11340, November 1986. 33. DCP 1000000354, Allow Replacement of SSPS Printed Circuit Boards, June 2010.
DCPP UNITS 1 & 2 FSAR UPDATE 7.2-46 Revision 21 September 2013 7.2.5 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures.
DCPP UNITS 1 & 2 FSAR UPDATE 7.3-1 Revision 21 September 2013 7.3 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM The engineered safety features actuation system (ESFAS) senses selected plant parameters and initiates necessary safety systems to protect against violating core design limits and the Reactor Coolant System (RCS) pressure boundary and to mitigate accidents. If the measured value of a sensed parameter exceeds a predetermined setpoint, a signal is sent into logic matrices sensitive to combinations indicative of faults described in Chapter 15. Once the required logic combination is completed, the system sends actuation signals to those engineered safety features (ESF) components whose aggregate function best serves the requirements of the accident. Included in this Section are the electrical schematic diagrams for all ESF systems circuits and supporting systems. Figure 7.3-52 shows containment electrical penetrations, cable trays, and supports. 7.3.1 DESIGN BASES 7.3.1.1 General Design Criterion 2, 1967 - Performance Standards ESFAS is designed to withstand the effects of or is protected against natural phenomena, such as earthquakes, flooding, tornadoes, winds, and other local site effects. 7.3.1.2 General Design Criterion 11, 1967 - Control Room ESFAS includes the controls and instrumentation in the control room necessary to support the safe operational status of the plant. 7.3.1.3 General Design Criterion 15, 1967 - Engineered Safety Features Protection Systems ESFAS provides for sensing accident situations and initiating the operation of necessary engineered safety features. 7.3.1.4 General Design Criterion 19, 1967 - Protection Systems Reliability ESFAS is designed for high functional reliability and in-service testability commensurate with the safety functions to be performed. 7.3.1.5 General Design Criterion 20, 1967 - Protection Systems Redundancy and Independence Redundancy and independence are designed into the ESFAS sufficient to assure that no single failure or removal from service of any component or channel of a system will result in loss of the protection function. The redundancy provided includes, as a minimum, two channels of protection for each protection function served. DCPP UNITS 1 & 2 FSAR UPDATE 7.3-2 Revision 21 September 2013 7.3.1.6 General Design Criterion 21, 1967 - Single Failure Definition ESFAS is designed to perform its function after sustaining a single failure. Multiple failures resulting from a single event shall be treated as a single failure. 7.3.1.7 General Design Criterion 22, 1967 - Separation of Protection and Control Instrumentation Systems ESFAS is designed such that protection functions are separated from control instrumentation functions to the extent that failure or removal from service of any control instrumentation system component or channel, or of those common to control instrumentation and protection circuitry, leaves intact a system satisfying all requirements for the protection channels. 7.3.1.8 General Design Criterion 23, 1967 - Protection Against Multiple Disability for Protection Systems ESFAS is designed such that the effects of adverse conditions to which redundant channels or protection systems might be exposed in common, either under normal conditions or those of an accident, does not result in loss of the protection function. 7.3.1.9 General Design Criterion 24, 1967 - Emergency Power for Protection Systems ESFAS is designed such that in the event of loss of all offsite power, sufficient alternate sources of power are provided to permit the required functioning of the protection systems. 7.3.1.10 General Design Criterion 25, 1967 - Demonstration of Functional Operability of Protection Systems ESFAS includes means for testing protection systems while the reactor is in operation to demonstrate that no failure or loss of redundancy has occurred. 7.3.1.11 General Design Criterion 26, 1967 - Protection Systems Fail-Safe Design The ESFAS is designed to fail into a safe state or into a state defined as tolerable on a defined basis if conditions such as disconnection of the system, loss of electric power, or adverse environments are experienced. 7.3.1.12 General Design Criterion 37, 1967 - Engineered Safety Features Basis for Design ESFAS is designed to actuate the ESFs provided to back up the safety provided by the core design, the reactor coolant pressure boundary, and their protection systems. DCPP UNITS 1 & 2 FSAR UPDATE 7.3-3 Revision 21 September 2013 7.3.1.13 General Design Criterion 38, 1967 - Reliability and Testability of Engineered Safety Features ESFAS is designed to provide high functional reliability and ready testability. 7.3.1.14 General Design Criterion 40, 1967 - Missile Protection ESFAS is protected against dynamic effects and missiles that might result from plant equipment failures. 7.3.1.15 General Design Criterion 48, 1967 - Testing of Operational Sequence of Emergency Core Cooling Systems ESFAS is designed with the capability to test under conditions as close to design as practical the full operational sequence that brings the emergency core cooling system into action, including the transfer to alternate power sources. 7.3.1.16 General Design Criterion 49, 1967 - Containment Design Basis ESFAS circuits routed through containment electrical penetrations are designed to support the containment design basis so that the containment structure can accommodate without exceeding the design leakage rate, the pressures and temperatures following a loss-of-coolant accident (LOCA). 7.3.1.17 10 CFR 50.49 - Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants The ESFAS electric components that require environmental qualification are qualified to the requirements of 10 CFR 50.49. 7.3.1.18 Safety Guide 22, February 1972 - Periodic Testing of Protection System Actuation Functions The ESFAS are periodically tested to provide assurance that the systems will operate as designed and will be available to function properly in the unlikely event of an accident. The testing program conforms to Safety Guide 22, February 1972. 7.3.2 System Description 7.3.2.1 Functional Design The following summarizes those generating station conditions requiring protective action:
(1) Primary system DCPP UNITS 1 & 2 FSAR UPDATE 7.3-4 Revision 21 September 2013 (a) Rupture in small pipes or crack in large pipes (refer to Section 15.3.1) (b) Rupture of a reactor coolant pipe - loss-of-coolant accident (LOCA) (refer to Section 15.4.1) (c) Steam generator tube rupture (refer to Section 15.4.3) (2) Secondary system (a) Minor secondary system pipe break resulting in steam release rates equivalent to the actuation of a single dump, relief, or safety valve (refer to Section 15.2.14) (b) Rupture of a major secondary system pipe (refer to Section 15.4.2)
The following summarizes the generating station variables required to be monitored for the initiation of the ESF for each accident in the preceding list: (1) Rupture in small pipes or crack in large primary system pipes (a) Pressurizer pressure (b) Containment pressure (2) Rupture of a reactor coolant pipe LOCA (a) Pressurizer pressure (b) Containment pressure (3) Steam generator tube rupture (a) Pressurizer pressure (4) Minor or major secondary system pipe rupture (a) Pressurizer pressure (b) Steam line pressures (c) Steam line pressure rate (d) Containment pressure
DCPP UNITS 1 & 2 FSAR UPDATE 7.3-5 Revision 21 September 2013 7.3.2.2 Signal Computation The ESFAS consists of two discrete portions of circuitry: (a) a process protection portion consisting of three to four redundant channels that monitor various plant parameters and containment pressures, and (b) a logic portion consisting of two redundant logic trains that receive inputs from the process protection channels and perform the needed logic to actuate the ESF. Each logic train is capable of actuating the ESF equipment required. The intent is that any single failure within the ESFAS shall not prevent system action when required. The redundancy concept is applied to the process protection and logic portions of the system. Separation of redundant process protection channels begins at the process sensors and is maintained in the field wiring, containment penetrations, and process protection racks, terminating at the redundant groups of ESF logic racks as shown in Figure 7.3-50. This conforms to GDC 20, 1967 (refer to Section 7.3.3.5). Section 7.2 provides further details on protection instrumentation. The same design philosophy applies to both systems and conforms to GDC 19, 1967, GDC 20, 1967, GDC 22, 1967 and GDC 23, 1967 (refer to Sections 7.3.3.4, 7.3.3.5, 7.3.3.7, and 7.3.3.8). The variables are sensed by the process protection circuitry, as discussed in Reference 2 and in Section 7.2. The outputs from the process protection channels are combined into actuation logic as shown on Sheets 5, 6, 7, and 8 of Figure 7.2-1. Tables 7.3-1 and 7.3-2 provide additional information pertaining to logic and function.
The interlocks associated with the ESFAS are outlined in Table 7.3-3. These interlocks satisfy the functional requirements discussed in Section 7.1.2.1.2. 7.3.2.3 Devices Requiring Actuation The following are the actions that the ESFAS initiates when performing its function:
(1) Safety injection (safety injection pumps, residual heat removal pumps, charging pumps) (2) Reactor trip (3) Feedwater line isolation by closing all main control valves, feedwater bypass valves, main feedwater isolation valves and tripping the feedwater pumps. (4) Auxiliary feedwater system actuation (5) Auxiliary saltwater pump start (6) Automatic containment spray (spray pumps, sodium hydroxide tank)
DCPP UNITS 1 & 2 FSAR UPDATE 7.3-6 Revision 21 September 2013 (7) Containment isolation (8) Containment fan coolers start (9) Emergency diesel generator startup (10) Main steam line isolation (11) Turbine and generator trips (12) Control room isolation
(13) Component cooling water pump start (14) Trip RHR pumps on low refueling water storage tank (RWST) level Refer to Figure 7.3-50 for a complete list of actuated components. 7.3.2.4 Implementation of Functional Design 7.3.2.4.1 Process Protection Circuitry The process protection sensors and racks for the ESFAS are covered in References 2, 17, 72 and 73. Discussed in these reports are the parameters to be measured including pressures, tank and vessel water levels, as well as the measurement and signal transmission considerations. These latter considerations include the basic current signal transmission system, transmitters, resistance temperature detectors (RTDs), and pneumatics. Other considerations covered are automatic calculations, signal conditioning, and location and mounting of the devices.
The sensors monitoring the primary system are located as shown on the piping schematic diagram, Figure 3.2-7, Reactor Coolant System. The secondary system sensor locations are shown on the piping schematic diagram, Figure 3.2-4, Turbine Steam Supply System.
Containment pressure is sensed by four physically separated differential pressure transmitters mounted outside of the containment structure. The transmitters are connected to containment atmosphere by filled and sealed hydraulic transmission systems similar to the sealed pressurizer water level reference leg described in Section 7.2.2.3.4. Refer to Section 6.2.4.1.3 for additional information on instrument lines penetrating containment.
Three water level instrumentation channels are provided for the RWST. Each channel provides independent indication on the main control board, thus meeting the requirements of Paragraph 4.20 of IEEE-279 1971 (Reference 4). Two-out-of-three logic is provided for residual heat removal (RHR) pump trip and low-level alarm DCPP UNITS 1 & 2 FSAR UPDATE 7.3-7 Revision 21 September 2013 initiation. One channel provides low-low-level alarm initiation; another channel provides a high-level alarm to alert the operator of overfill and potential spillage of radioactive material. Refer to Sections 3.10.2.5 and 6.3.5.4.1 for additional information on the RWST level circuits and logic relays. 7.3.2.4.2 Logic Circuitry The ESF logic racks are discussed in detail in Reference 5. The description includes the considerations and provisions for physical and electrical separation as well as details of the circuitry. Reference 5 also covers certain aspects of on-line test provisions, provisions for test points, considerations for the instrument power source, considerations for accomplishing physical separation, and provisions for ensuring instrument qualification. The outputs from the process protection channels are combined into ESF actuation logic, as shown on Sheets 5 (RCP bus undervoltage), 6 (pressurizer pressure), 7 (steam pressure rate, steamline pressure, and steam generator level), and 8 (ESF actuation and containment pressure) of Figure 7.2-1. To facilitate ESF actuation testing, two cabinets (one per train) are provided that enable operation, to the maximum practical extent, of safety features loads on a group-by-group basis until actuation of all devices has been checked. Final actuation testing is discussed in detail in Section 7.3.4.1.5.8. 7.3.2.4.3 Final Actuation Circuitry The outputs of the solid-state logic protection system (the slave relays) are energized to actuate, as are most final actuators and actuated devices. These devices are: (1) Safety Injection (SI) System Pumps and Valve Actuators - Refer to Section 6.3 for flow diagrams and additional information. (2) Containment Isolation - Phase A - T signal isolates all nonessential (to reactor operation) process lines on receipt of SI signal; Phase B - P signal isolates remaining process lines (which do not include SI lines) on receipt of a two-out-of-four high-high containment pressure signal. For further information, refer to Section 6.2.4. (3) Containment Fan Coolers - Refer to Section 6.2.2.2.2.2 (4) Component Cooling Pumps and Valves - Refer to Section 9.2.2. (5) Auxiliary Saltwater Pumps - Refer to Section 9.2.7. (6) Auxiliary Feedwater Pumps Start - Refer to Section 6.5.5. (7) Diesel Generators Start - Refer to Section 8.3.1.1.3.3.5.2. DCPP UNITS 1 & 2 FSAR UPDATE 7.3-8 Revision 21 September 2013 (8) Feedwater Isolation - Refer to Section 10.4.7. (9) Ventilation Isolation Valve and Damper Actuators - Refer to Section 6.2.4. (10) Steam Line Isolation Valve Actuators - Refer to Section 10.3.2. (11) Containment Spray Pumps and Valve Actuators - Refer to Section 6.2.2.2.2.1. When the ESF loads are to be powered by diesel generators, they must be sequenced to prevent overloading. This sequencing is discussed in Section 8.3.1.1.3.3.5.2. The following systems are required for support of the engineered safety features:
(1) Auxiliary Saltwater System - Heat removal, refer to Section 9.2.7. (2) Component Cooling Water System - Heat removal, refer to Section 9.2.2. (3) Electrical Power Distribution Systems - Refer to Chapter 8. 7.3.2.4.4 Safety System Status Display The following provisions have been made to automatically display the status of safety systems. (1) Monitor light display panels are provided to verify correct system alignment for: (a) Safety feature valves (b) Phase A isolation system equipment (c) SI, charging (CCP1 and CCP2), component cooling water, auxiliary feedwater, auxiliary saltwater, and RHR pumps (d) Phase B isolation system equipment and containment spray pumps (e) Containment fan coolers (2) A partial list of annunciator displays is included in Section 7.7.1.10.1.1: In addition to the status lights and annunciator displays described, system control switches on the control board are provided with indicating lights to display valve position DCPP UNITS 1 & 2 FSAR UPDATE 7.3-9 Revision 21 September 2013 and motor status with power potential indicating lights provided where equipment power is 480 V or higher.
The features described above, supplemented with administrative procedures, provide the operator with safety system status information, by means of which the status of bypassed or inoperable systems is available to the operator, in accordance with the intent of RG 1.47 (Reference 6). 7.3.2.5 Additional Design Information The generating station conditions that require protective action are discussed in Section 7.3.2.1. The generating station variables that are required to be monitored in order to provide protective actions are also summarized in Section 7.3.2.1. The ESFAS functional units and trip setpoints are provided in the Technical Specifications (Reference 7). The methodology for determining ESFAS setpoints and allowable values is presented in WCAP 11082 or in plant procedures. The following is a list of the malfunctions, accidents, or other unusual events that could physically damage protection system components or could cause environmental changes. The sections noted with each item present discussions on the provisions made to retain the necessary protective action. (1) LOCA (refer to Sections 15.3.1 and 15.4.1) (2) Secondary System breaks (refer to Sections 15.3.2 and 15.4.2) (3) Earthquakes (refer to Sections 2.5, 3.2, 3.7, and 3.8) (4) Fire (refer to Section 9.5.1) (5) Explosion (hydrogen buildup inside containment; refer to Sections 6.2 and 15.4) (6) Missiles (refer to Section 3.5) (7) Flood (refer to Sections 2.4 and 3.4) (8) Wind (refer to Section 3.3) Minimum performance requirements are: (1) System response times The actuation system response time is included in the overall ESF response time. DCPP UNITS 1 & 2 FSAR UPDATE 7.3-10 Revision 21 September 2013 The Technical Specifications define ESF response time. Acceptance criteria for ESF response time testing is located in ECG 38.2, "Engineered Safety Features (ESF) Response Times." (2) System accuracies The system actuation setpoints together with their allowable values are provided in the Technical Specifications. (3) Ranges of sensed variables to be accommodated until conclusion of protective action is ensured Information readouts and the ranges required in generating the required actuation signals for loss-of-coolant and secondary system pipe break protection are discussed in Section 7.5.1 and presented in Tables 7.5-1 and 7.5-2. 7.3.2.6 Current System Drawings The schematic diagrams and logic diagrams for ESF circuits and supporting systems are presented at the end of Section 7 (refer to Figures 7.3-1 through 7.3-49). 7.3.3 SAFETY EVALUATION 7.3.3.1 General Design Criterion 2, 1967 - Performance Standards The ESFAS structures, systems and components (SSCs) are contained in the auxiliary buildings that are PG&E Design Class I (refer to Section 3.8). These buildings are designed to withstand the effects of winds and tornadoes (Refer to Section 3.3), floods and tsunamis (refer to Section 3.4), external missiles (refer to Section 3.5), earthquakes (refer to Section 3.7), and other natural phenomena to protect ESFAS SSCs to ensure their safety-related functions and designs will perform. Refer to Section 7.3.2.5 for additional information. 7.3.3.2 General Design Criterion 11, 1967 - Control Room Controls and instrumentation related to ESFAS include control room status lights, annunciator displays and system control switches on the control board with indicating lights to display valve position and motor status with power potential indicating lights provided where equipment power is 480-V or higher. Refer to Section 7.3.2.4.4 for additional information. DCPP UNITS 1 & 2 FSAR UPDATE 7.3-11 Revision 21 September 2013 7.3.3.3 General Design Criterion 15, 1967 - Engineered Safety Features Protection Systems The ESFAS is designed to monitor plant variables and respond to the accident conditions identified in Section 7.3.2.1. If necessary, ESFAS will initiate the operation of the engineered safety features as described in Section 7.3.2.3. The effectiveness of the ESFAS is evaluated in Chapter 15 based on the ability of the system to contain the effects of Conditions III and IV faults including loss of coolant and secondary system pipe rupture accidents. The ESFAS parameters are based on the component performance specifications that are provided by the manufacturer, or verified by test for each component. Appropriate factors to account for uncertainties in the data are factored into the constants characterizing the system.
The ESFAS must detect Conditions III and IV faults and generate signals that actuate the ESF. The system must sense the accident condition and generate the signal actuating the protection function reliably, and within a time determined by, and consistent with, the accident analyses in Sections 15.3 and 15.4. The ESFAS will mitigate other faults as discussed in Section 15.2. The time required for the generation of the actuation signal of ESFAS is relatively short. The remainder of the time is associated with the actuation of the mechanical and fluid system equipment associated with ESF. This includes the time required for switching, bringing pumps and other equipment to speed, and the time required for them to take load.
7.3.3.3.1 Loss-of-Coolant Protection By analysis of LOCA and in-system tests, it has been verified that except for very small coolant system breaks, which can be protected against by the charging pumps (CCP1 and CCP2) followed by an orderly shutdown, the effects of various LOCAs are reliably detected by the low pressurizer pressure. The emergency core cooling system (ECCS) is actuated in time to prevent or limit core damage.
For large coolant system breaks, the passive accumulators inject first because of the rapid pressure drop. This protects the reactor during the unavoidable delay associated with actuating the active ECCS phase.
High containment pressure also actuates the ECCS, providing additional protection as a backup to actuation on low pressurizer pressure. Emergency core cooling actuation can be brought about upon sensing this other direct consequence of a primary system break; that is, the protection system detects the leakage of the coolant into the containment.
DCPP UNITS 1 & 2 FSAR UPDATE 7.3-12 Revision 21 September 2013 Containment spray provides containment pressure reduction and also limits fission product release, upon sensing elevated containment pressure (high-high), to mitigate the effects of a LOCA.
The delay time between detection of the accident condition and the generation of the actuation signal for these systems is well within the capability of the protection system equipment. However, this time is short compared to that required for startup of the fluid systems.
The analyses in Chapter 15 show that the diverse methods of detecting the accident condition and the time for generation of the signals by the protection systems are adequate to provide reliable and timely protection against the effects of loss of coolant. 7.3.3.3.2 Secondary System Pipe Rupture Protection The ECCS is also actuated to protect against a secondary system line break. Analysis of secondary system pipe rupture accidents shows that the ECCS is actuated for a secondary system pipe rupture in time to limit or prevent further damage. There is a reactor trip, but the core reactivity is further reduced by the highly borated water injected by the ECCS.
Additional protection against the effects of secondary system pipe rupture is provided by feedwater isolation that occurs upon actuation of the ECCS. Feedwater line isolation is initiated to prevent excessive cooldown of the reactor. Additional protection against a secondary system pipe rupture accident is provided by closure of all steam line isolation valves to prevent uncontrolled blowdown of all steam generators. Generation of the protection system signal is again short compared to the time to trip the fast acting steam line isolation valves that are designed to close in less than 5 seconds. The analyses in Chapter 15 of the secondary system pipe rupture accidents and an evaluation of the protection system instrumentation and channel design show that the EFSAS are effective in preventing or mitigating the effects of a secondary system pipe rupture accident. 7.3.3.4 General Design Criterion 19, 1967 - Protection Systems Reliability The ESFAS is designed for high functional reliability and in-service testability. The design employs redundant logic trains and measurement and equipment diversity. Sufficient redundancy is provided to enable individual end-to-end channel tests with each reactor at power without compromise of the protective function. Built-in semiautomatic testers provide means to test the majority of system components very rapidly. DCPP UNITS 1 & 2 FSAR UPDATE 7.3-13 Revision 21 September 2013 Refer to Section 7.3.4.1.5.1 and Section 7.2.2.2.1.7 for additional information. 7.3.3.5 General Design Criterion 20, 1967 - Protection Systems Redundancy and Independence Sufficient redundancy and independence is designed into the protection systems to ensure that no single failure, or removal from service of any component or channel of a system will result in loss of the protection function. The minimum redundancy is exceeded in each protection function that is active with the reactor at power. Functional diversity and consequential location diversity are designed into the systems. The ESF outputs from the solid-state logic protection cabinets are redundant, and the actuations associated with each train are energized to actuate, up to and including the final actuators, by the separate ac power supplies that power the respective logic trains. Mutually redundant ESF circuits utilize separate relays in separate racks. The protection system is designed to provide two, three, or four instrumentation channels for each protective function and redundant (two) logic trains. These redundant channels and trains are electrically isolated and physically separated. Thus, any single failure within a channel or train will not prevent protective action at the system level when required. Each individual channel is assigned to one of four channel designations, e.g., Channel I, II, III, or IV. Channel independence is carried throughout the system, extending from the sensor through to the devices actuating the protective function. Physical separation is used to achieve separation of redundant transmitters. Separation of wiring is achieved using separate wireways, cable trays, conduit runs, and containment penetrations for each redundant channel. Redundant process equipment is separated by locating electronics in different protection rack sets. Each redundant channel is energized from a separate ac power feed. Refer to Sections 7.3.4.1.1 and 7.3.4.1.3 for additional information. 7.3.3.6 General Design Criterion 21, 1967 - Single Failure Definition The protection system is designed to provide two, three, or four instrumentation channels for each protective function and redundant (two) logic trains. These redundant channels and trains are electrically isolated and physically separated. Thus, any single failure within a channel or train will not prevent protective action at the system level when required. Refer to Section 7.3.4.1.1 for additional information. DCPP UNITS 1 & 2 FSAR UPDATE 7.3-14 Revision 21 September 2013 7.3.3.7 General Design Criterion 22, 1967 - Separation of Protection and Control Instrumentation Systems The protection systems comply with the requirements of IEEE-279, 1971, Criteria for Protection Systems for Nuclear Power Generating Stations (Reference 4), although construction permits for the DCPP units were issued prior to issuance of the 1971 version of the standard (refer to Section 7.3.4.1). Each protection system is separate and distinct from the respective control systems. The control system is dependent on the protection system in that control signals are derived from protection system measurements, where applicable. These signals are transferred to the control system by isolation amplifiers that are classified as protection system components. The adequacy of system isolation has been verified by testing or analysis under conditions of all postulated credible faults. Isolation devices that serve to protect Instrument Class IA instrument loops have all been tested. For certain applications where the isolator is protecting an Instrument Class IB instrument loop, and the isolation device is a simple linear device with no complex failure modes, the analysis was used to verify the adequacy of the isolation device. The failure or removal of any single control instrumentation system component or channel, or of those common to the control instrumentation system component or channel and protection circuitry, leaves intact a system that satisfies the requirements of the protection system. To provide physical separation between input and output circuits in the solid-state protection system racks, physical barriers have been provided to separate input and output wire bundles. The protection system is designed to be independent of the control system. In certain applications, the control signals and other non-protective functions are derived from individual protective channels through isolation devices. The isolation devices are classified as part of the protection system and are located in the process protection racks. Non-protective functions include those signals used for control, remote process indication, and computer monitoring. The isolation devices are designed so that a short circuit, open circuit, or the application of 118-Vac or 140-Vdc on the isolated output portion of the circuit (i.e., the non-protective side of the circuit) will not affect the input (protective) side of the circuit. The signals obtained through the isolation devices are never returned to the protective racks. 7.3.3.8 General Design Criterion 23, 1967 - Protection Against Multiple Disability for Protection Systems Physical separation and electrical isolation of redundant channels and subsystems, functional diversity of subsystems, and safe failure modes are employed in the design of the reactor's defenses against functional failure through exposure to common causative factors. The redundant logic trains, reactor trip breakers, and ESF actuation devices are physically separated and electrically isolated. Physically separate channel trays, conduits, and penetrations are maintained upstream from the logic elements of each train. DCPP UNITS 1 & 2 FSAR UPDATE 7.3-15 Revision 21 September 2013 The protection system components have been qualified by testing under extremes of the normal environment. In addition, components are tested and qualified according to individual requirements for the adverse environment specific to their location that might result from postulated accident conditions. Refer to Sections 7.3.4.1.2 and 7.3.4.3 for additional information. 7.3.3.9 General Design Criterion 24, 1967 - Emergency Power for Protection Systems Emergency power for the instrumentation and control portions of the protection systems is provided initially from the station batteries, supplying dedicated 120-Vac inverters for each protection channel, and subsequently from the emergency diesel generators. A single failure of any one component will not prevent the required functioning of protection systems. Refer to Section 8.3 for additional information. 7.3.3.10 General Design Criterion 25, 1967 - Demonstration of Functional Operability of Protection Systems The ESFAS includes means for testing protection systems while the reactor is in operation to demonstrate that no failure or loss of redundancy has occurred. Operating procedures normally require that the complete ESF actuation system be operable. However, redundancy of system components is such that the system operability assumed for the safety analyses can still be met with certain instrumentation channels out of service. Channels that are out of service are to be placed in the bypass/tripped mode.
Refer to Section 7.3.4.1.5.1 for additional information. 7.3.3.11 General Design Criterion 26, 1967 - Protection Systems Fail-Safe Design In the ESF, a loss of instrument power to a specific channel/rack/or protection set will call for actuation of ESF equipment controlled by the specific channel that lost power (exceptions to the fail-safe design requirement are the containment spray and the radiation monitoring channels that initiate containment ventilation isolation). The actuated equipment in some cases must have power to comply. The power supply for the protection systems is discussed in Chapter 8. The containment spray function is energized to trip in order to avoid spurious actuation. In addition, manual containment spray requires simultaneous actuation of both manual controls. This is considered acceptable because spray actuation on high-high containment pressure signal provides automatic initiation of the system via protection channels, meeting the criteria in Reference 4. When the construction permits for the Diablo Canyon units were issued in April 1968 and December 1970, manual initiation at the system level was in compliance DCPP UNITS 1 & 2 FSAR UPDATE 7.3-16 Revision 21 September 2013 with paragraph 4.17 of IEEE-279, 1968 (Reference 8). No single random failure in the manual initiation circuits can prevent automatic initiation. Failure of manual initiation at the system level is not considered a significant safety problem because the operator can initiate operation manually at the component level. Refer to section 7.3.4.1.1 for additional information. 7.3.3.12 General Design Criterion 37, 1967 - Engineered Safety Features Basis for Design ESFAS actuates the engineered safety features required to cope with any size reactor coolant pipe break up to and including the circumferential rupture of any pipe in that boundary assuming unobstructed discharge from both ends, and to cope with any steam or feedwater line break up to and including the main steam or feedwater headers. Limiting the release of fission products from the reactor fuel is accomplished by the ECCS, which, by cooling the core, keeps the fuel in place and substantially intact and limits the metal-water reaction to an acceptable amount. 7.3.3.13 General Design Criterion 38, 1967 - Reliability and Testability of Engineered Safety Features A comprehensive program of testing has been formulated for all equipment and instrumentation vital to the functioning of the ESF. The program consists of startup tests of system components and integrated tests of the system. Periodic tests of the activation circuitry and system components, throughout the station lifetime, with maintenance performed as necessary, ensure that high reliability will be maintained and that the system will perform on demand. Details of the test program are provided in the Technical Specifications. Refer to section 7.3.4.1.5.1 for additional information. 7.3.3.14 General Design Criterion 40, 1967 - Missile Protection The various sources of missiles that might affect the ESF have been identified, and protective measures have been implemented to minimize these effects (refer to Sections 3.5 and 8.3). Electrical raceways containing circuits for the ESF have not been installed in zones where provision against dynamic effects must be made, with a few exceptions. When routing through such zones was necessary, metallic conduits only were used, and conduits containing redundant circuits were separated physically as far as practical. 7.3.3.15 General Design Criterion 48, 1967 - Testing of Operational Sequence of Emergency Core Cooling Systems The design provides for capability to test, to the extent practical, the full operational sequence up to design conditions, including transfer to alternative power sources for the DCPP UNITS 1 & 2 FSAR UPDATE 7.3-17 Revision 21 September 2013 ECCS, to demonstrate the state of readiness and capability of the system. This functional test is performed with the RCS initially cold and at low pressure. The ECCS valve alignment is set to initially simulate the system alignment for plant power operation. Details of the ECCS are found in Section 6.3. Refer to Section 7.3.4.1.5.5 for a description of the initiation circuitry. Refer to section 7.3.4.1.5.1 for additional information. 7.3.3.16 General Design Criterion 49, 1967 - Containment Design Basis ESFAS circuits routed through containment are analyzed for redundant overcurrent protection and available fault energy. ESFAS circuits routed through containment penetrations are installed without direct in-line protection. The available fault current is not of sufficient magnitude to damage the penetration conductor. These circuits will not adversely heat the penetrations as presently designed. Refer to Section 8.3 for additional information. 7.3.3.17 10 CFR 50.49 - Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants The Class 1E ESFAS SSCs required to function in harsh environments under accidents conditions are qualified to the applicable environmental conditions to ensure that they will continue to perform their safety functions. Section 3.11 describes the DCPP EQ program and the requirements for the environmental design of the electrical and related mechanical equipment. The affected components are listed on the EQ Master List. 7.3.3.18 Safety Guide 22, February 1972 - Periodic Testing of Protection System Actuation Functions Periodic testing of the ESF actuation functions, as described, complies with Safety Guide 22, February 1972 (Reference 9). Under the present design, those protection functions that are not tested at power are discussed in Section 7.3.4.1.5.9 . As described by Safety Guide 22, February 1972, where actuated equipment is not tested during reactor operation, it has been determined that:
(1) There is no practicable system design that would permit operation of the actuated equipment without adversely affecting the safety or operability of the plant. (2) The probability that the protection system will fail to initiate the operation of the actuated equipment is, and can be maintained, acceptably low without testing the actuated equipment during reactor operation.
DCPP UNITS 1 & 2 FSAR UPDATE 7.3-18 Revision 21 September 2013 (3) The actuated equipment can be routinely tested when the reactor is shut down. Where the ability of a system to respond to a bona fide accident signal is intentionally bypassed, for the purpose of performing a test during reactor operation, each bypass condition is automatically indicated to the reactor operator in the control room by a common "ESF testing" annunciator for the train in test. Test circuitry does not allow two ESF trains to be tested at the same time so that extension of the bypass condition to redundant systems is prevented.
The discussion on "bypass" in Section 7.2.2.2.1.7 is applicable.
Refer to Section 7.3.4.1.5.1 for additional information. 7.3.4 COMPLIANCE WITH IEEE STANDARDS 7.3.4.1 Evaluation of Compliance with IEEE-279, 1971 - Criteria for Protection Systems for Nuclear Power Generating Stations The ESFAS meets the criteria as set forth in IEEE-279, 1971 (Reference 4), as follows: 7.3.4.1.1 Single Failure Criterion The discussion presented in Section 7.2.2 is applicable to the ESFAS, with the following exception: In the ESF, a loss of instrument power to a specific channel/rack/or protection set will call for actuation of ESF equipment controlled by the specific channel that lost power (exceptions to the fail-safe design requirement are the containment spray and the radiation monitoring channels that initiate containment ventilation isolation). The actuated equipment in some cases must have power to comply. The power supply for the protection systems is discussed in Section 8. The containment spray function is energized to trip in order to avoid spurious actuation. In addition, manual containment spray requires simultaneous actuation of both manual controls. This is considered acceptable because spray actuation on high-high containment pressure signal provides automatic initiation of the system via protection channels, meeting the criteria in Reference 4. When the construction permits for the Diablo Canyon units were issued in April 1968 and December 1970, manual initiation at the system level was in compliance with paragraph 4.17 of IEEE-279, 1968 (Reference 8). No single random failure in the manual initiation circuits can prevent automatic initiation. Failure of manual initiation at the system level is not considered a significant safety problem because the operator can initiate operation manually at the component level.
The design conforms to GDC 21, 1967 and GDC 26, 1967. DCPP UNITS 1 & 2 FSAR UPDATE 7.3-19 Revision 21 September 2013 7.3.4.1.2 Equipment Qualification The ability of the equipment inside the containment required to function for post-LOCA operation in the adverse environment associated with the LOCA or in-containment steam break, has been evaluated in Section 3.11.
Sensors for measurement of pressurizer pressure, are located inside the containment and will be exposed to the post-LOCA environment. 7.3.4.1.3 Channel Independence The discussion presented in Section 7.2.2 is applicable. The ESFAS outputs from the solid-state logic protection cabinets are redundant, and the actuations associated with each train are energized to actuate, up to and including the final actuators, by the separate ac power supplies that power the respective logic trains. Mutually redundant ESFAS circuits utilize separate relays in separate racks. 7.3.4.1.4 Control and Protection System Interaction The discussions presented in Section 7.3.3.7 are applicable. 7.3.4.1.5 Capability for Sensor Checks and Equipment Test and Calibration The discussions of system testability in Section 7.2.2 are applicable to the sensors, analog circuitry and logic trains of the ESFAS. The following sections cover those areas in which the testing provisions differ from those for the RTS. 7.3.4.1.5.1 Testing of Engineered Safety Features Actuation System The ESFAS is tested to ensure that the systems operate as designed and function properly in the unlikely event of an accident. The testing program, which conforms with GDC 19, 1967; Criteria GDC 25 1967, GDC 38 1967, GDC 48 1967, and GDC 57 1967, and to Safety Guide 22, February 1972 (Reference 9), is as follows: (1) Prior to initial plant operations, ESFAS tests will be conducted. (2) Subsequent to initial startup, ESFAS tests will be conducted as required in the Technical Specifications. (3) During on-line operation of the reactor, the ESFAS process and logic circuitry are fully tested. In addition, essentially all of the ESF final actuators can be fully tested. The few final actuators whose operation is not compatible with continued on-line plant operation are checked during DCPP UNITS 1 & 2 FSAR UPDATE 7.3-20 Revision 21 September 2013 refueling outages. Slave relays are tested on an interval defined in the Technical Specifications. (4) During normal operation, the operability of testable final actuation devices of the ESFAS are tested by manual initiation from the test control panel. The discussions on capability for testing, as presented in Section 7.2.2.2.1.7, are applicable. 7.3.4.1.5.2 Performance Test Acceptability Standard for the "S" (Safety Injection Signal) and the "P" (Automatic Demand Signal for Containment Spray Actuation) Actuation Signals Generation During reactor operation, the acceptability of the ESFAS is based on the successful completion of the overlapping tests performed on the initiating system and the ESFAS. Checks of process indications verify operability of the sensors. Process checks and tests verify the operability of the process circuitry from the input of these circuits through the logic input relays and the inputs to the logic matrices. Solid-state logic testing checks the signal path through the logic matrices and master relays and performs continuity tests on the coils of the output slave relays. Final actuator testing can be performed by operating the output slave relays and verifying the required ESF actuation. Actuators whose testing is not compatible with on-line operation are tested during refueling outages, except those actuators normally in their required positions, which will not be tested. Operation of the final devices is confirmed by control board indication and visual observation that the appropriate pump breakers close and automatic valves have completed their travel. The basis for acceptability for the ESFAS interlocks is receipt of proper indication upon introducing a trip. Maintenance checks (performed during regularly scheduled refueling outages), such as resistance to ground of signal cables in radiation environments, are based on qualification test data that identify what constitutes acceptable degradation, e.g., radiation and thermal. 7.3.4.1.5.3 Frequency of Performance of Engineered Safety Features Actuation Tests During reactor operation, complete system testing (excluding sensors or those devices whose operation would cause plant upset) is performed as required by the Technical Specifications. Testing, including the sensors, is also performed during scheduled plant shutdown for refueling. DCPP UNITS 1 & 2 FSAR UPDATE 7.3-21 Revision 21 September 2013 7.3.4.1.5.4 Engineered Safety Features Actuation Test Description The following sections describe the testing circuitry and procedures for the on-line portion of the testing program. The guidelines used in developing the circuitry and procedures are:
(1) The test procedures must not involve the potential for damage to any plant equipment. (2) The test procedures must minimize the potential for accidental tripping. (3) The provisions for on-line testing must minimize complication of ESF actuation circuits so that their reliability is not degraded. 7.3.4.1.5.5 Description of Initiation Circuitry Several systems comprise the total ESFAS, the majority of which may be initiated by different process conditions and reset independently of each other. The remaining functions (listed in Section 7.3.2) are initiated by a common signal (safety injection), which in turn may be generated by different process conditions. In addition, operation of all other vital auxiliary support systems, such as auxiliary feedwater, component cooling water, and auxiliary saltwater, is initiated via the ESF starting sequence actuated by the safety injection signal. Each function is actuated by a logic circuit that is duplicated for each of the two redundant trains of ESF initiation circuits. The output of each of the initiation circuits consists of a master relay, which drives slave relays for contact multiplication as required. The logic, master, and slave relays are mounted in the solid-state logic protection cabinets designated trains A and B, respectively, for the redundant counterparts. The master and slave relay circuits operate various pump and fan circuit breakers or starters, motor-operated valve contactors, solenoid-operated valves, start the emergency diesel generator, etc. 7.3.4.1.5.6 Process Protection Testing Process protection testing is identical to that used for reactor trip circuitry and is described in Section 7.2.3. Briefly, in the process protection racks, a man machine interface (MMI) unit is used together with a rack mounted test panel to facilitate testing.
Section 7.2.2.2.1.7 discusses testing in bypass which is the normal method. Alternatively, administrative controls allow, during channel testing, that the channel output be put in a trip condition that de-energizes (operates) the input relays in train A and train B cabinets. Of necessity this is done on one channel at a time. Status lights and single channel trip alarms in the main control room verify that the logic input relays have been deenergized and the channel outputs are in the trip mode. An exception to DCPP UNITS 1 & 2 FSAR UPDATE 7.3-22 Revision 21 September 2013 this is containment spray, which is energized to actuate two-out-of-four logic and reverts to two-out-of-three logic when one channel is in test. 7.3.4.1.5.7 Solid-State Logic Testing After the individual process channel testing is complete, the logic matrices are tested from the trains A and B logic rack test panels. This step provides overlap between the process protection and logic portions of the test program. During this test, each of the logic inputs is actuated automatically in all combinations of trip and nontrip logic. Trip logic is not maintained long enough to permit master relay actuation - master relays are "pulsed" to check continuity. Following the logic testing, the individual master relays are actuated electrically to test their mechanical operation. Actuation of the master relays during this test applies low voltage to the slave relay coil circuits to allow continuity checking, but not slave relay actuation. During logic testing of one train, the other train can initiate the required ESF function. For additional details, refer to Reference 5. 7.3.4.1.5.8 Actuator Testing At this point, testing of the initiation circuits through operation of the master relay and its contacts to the coils of the slave relays has been accomplished. Slave relays do not operate because of reduced voltage.
In the next step, operation of the slave relays and the devices controlled by their contacts are checked. For this procedure, control switches mounted in the safeguards test cabinet (STC) near the logic rack area are provided for most slave relays. These controls require two deliberate actions on the part of the operator to actuate a slave relay. By operation of these relays one at a time through the control switches, all devices that can be operated on-line without risk to the plant are tested. Devices are assigned to the slave relays to minimize undesired effects on plant operation. This procedure minimizes the possibility of upset to the plant and again ensures that overlap in the testing is continuous, since the normal power supply for the slave relays is utilized.
During this last procedure, close communication between the main control room operator and the person at the test panel is required. Before energizing a slave relay, the operator in the control room ensures that plant conditions will permit operation of the equipment that will be actuated by the relay. After the tester has energized the slave relay, the control room operator observes that all equipment has operated as indicated by appropriate indicating lamps, monitor lamps, and annunciators on the control board. The test director, using a prepared check list, records all operations. The operator then resets all devices and prepares for operation of the next slave relay-actuated equipment. By means of the procedure outlined above, all devices actuated by ESFAS initiation circuits can be operated by the test circuitry during on-line operation, with the following exceptions: DCPP UNITS 1 & 2 FSAR UPDATE 7.3-23 Revision 21 September 2013 (1) Main steam isolation - During cold shutdowns, these valves are full stroke tested. (2) Feedwater isolation - Air-operated, spring-closed regulating control valves and feedwater bypass valves are provided for each main feedwater line. Operation of these valves is continually monitored by normal operation. During cold shutdown, these valves are tested for closure times. Motor-operated feedwater isolation valves are also provided for each feedwater isolation line. (3) Reactor coolant pump essential service isolation (a) Component cooling water supply and return. These valves cannot be fully tested during normal operation. (b) Seal water return header. These valves cannot be fully testing during normal operation. (4) Normal charging and normal letdown isolation. These valves cannot be fully tested during normal operation due to thermal and hydraulic transients induced on the lines. (5) Sequential transfer of centrifugal charging pump (CCP1 and CCP2) suction from the volume control tank (VCT) to the RWST for charging injection. These valves cannot be fully tested during normal operation due to reactivity transients associated with the swap. Additionally, restoration of normal charging and letdown following testing causes thermal and hydraulic transients. (6) Autotransfer vital buses to startup power or emergency diesel generator. (7) Containment spray additive tank outlet valves. These valves cannot be tested during normal operation without isolating the spray additive tank. (8) Accumulator outlet valves. These valves are required by Technical Specifications to be open with power removed from their operators during normal operation to prevent their inadvertent closure by a spurious signal, and therefore are not tested (see Section 7.3.4.1.5.2). (9) Main turbine trip. (10) Main feedwater pump trip. (11) Blocking of the non-ESF starts of ESF pumps during an SI signal to assure bus loading will be controlled by the ESF load sequencing timers. DCPP UNITS 1 & 2 FSAR UPDATE 7.3-24 Revision 21 September 2013 This circuitry cannot be fully tested during normal operation since slave relay contact position cannot be verified. (12) Containment spray initiation circuit interlock from an SI signal. This circuit cannot be fully tested during normal operation since slave relay contact position cannot be verified. (13) Other circuitry not associated with the ESF; for example, main generator trip, reactor coolant pump trip, and source range block. 7.3.4.1.5.9 Actuator Blocking and Continuity Test Circuits The limited number of components that cannot be operated on-line are assigned to slave relays separate from those assigned to components that can be operated on-line. For some of these components, additional blocking relays are provided that allow operation of the slave relays without actuation of the associated ESF devices. Interlocking prevents blocking the output of more than one slave relay at a time. The circuits provide for monitoring of the slave relay contacts, the devices control circuit cabling, control voltage, and the devices actuating solenoids. These slave relays and actuators may be tested using the blocking and continuity test circuits while the unit is on line; however, use of these circuits can increase the risk associated with testing, since failure of the blocking circuits may result in a reactor trip. 7.3.4.1.5.10 Time Required for Testing The system design includes provisions for timely testing of both the process protection and logic sections of the system. Testing of actuated components (including those that can only be partially tested) is a function of control room operator availability. It is expected to require several shifts to accomplish these tests. During this procedure, automatic actuation circuitry will override testing, except for those few devices associated with a single slave relay whose outputs must be blocked and then only while blocked. It is anticipated that continuity testing associated with a blocked slave relay could take several minutes. During this time, the redundant devices in the other trains would be functional. 7.3.4.1.5.11 Summary The testing program and procedures described provide capability for checking completely from the process signal to the logic cabinets and from these to the individual pump and fan circuit breakers or starters, valve contactors, pilot solenoid valves, etc., including all field cabling actually used in the circuitry called upon to operate for an accident condition. For those devices whose operation could affect plant or equipment operation, the same procedure provides for checking from the process signal to the logic rack. To check the final actuation device, the device itself is tested during shutdown conditions. All testing is performed as required by the Technical Specifications. DCPP UNITS 1 & 2 FSAR UPDATE 7.3-25 Revision 21 September 2013 The procedures require testing at various locations: (1) Process channel testing and verification of setpoints are accomplished at the process protection racks. Verification of logic input relay operation is done at the control room status lights. (2) Logic testing through operation of the master relays and low voltage application to slave relays is done at the logic rack test panel. (3) Testing of pumps, fans, and valves is done at a test panel located in the vicinity of the logic racks, in combination with the control room operator. (4) Continuity testing for the circuits that cannot be operated is done at the same test panel mentioned in (3) above. 7.3.4.1.6 Testing During Shutdown ECCS components and the system, including emergency power supplies, will be tested in accordance with the Technical Specifications. Containment spray system tests are performed at each major fuel reloading. The tests are performed with the isolation valves in the spray supply lines at the containment and spray additive tank blocked closed, and are initiated manually or by using an actual or simulated actuation signal.
All final actuators can be tested during a refueling outage. The final actuators that cannot be tested during on-line operation are tested during each major fuel reloading. All testing is performed as required by the Technical Specifications. 7.3.4.1.7 Periodic Maintenance Inspections Periodic maintenance on the system equipment is accomplished and documented according to the maintenance procedures contained in the Plant Manual. Refer to Section 13.5.1. The balance of the requirements listed in Reference 4 (Paragraphs 4.11 through 4.22) is discussed in Sections 7.2.2 and 7.2.3. Paragraph 4.20 receives special attention in Section 7.5. 7.3.4.2 Evaluation of Compliance with IEEE-308-1971, Criteria for Class 1E Electric Systems for Nuclear Power Generating Stations The power supplies for the ESF equipment conform to IEEE 308-1971 (Reference 10). Refer to Section 7.6 and 8, which discuss the power supply for the protection systems, for additional discussions on compliance with this criteria. DCPP UNITS 1 & 2 FSAR UPDATE 7.3-26 Revision 21 September 2013 7.3.4.3 Evaluation of Compliance with IEEE-323-1971, Trial-Use Standard: General Guide for Qualifying Class I Electric Equipment for Nuclear Power Generating Stations Refer to Section 3.11 for a discussion on ESF electrical equipment environmental qualification and compliance to IEEE-323-1971 (Reference 11). Documentation of the environmental and seismic qualification of the process protection system is provided in References 18, 19, 20, and 21. 7.3.4.4 Evaluation of Compliance with IEEE-338-1971, Trial-Use Criteria for the Periodic Testing of Nuclear Power Generating Station Protection Systems The periodic testing of the ESF actuation system conforms to the requirements of IEEE-338-1971 (Reference 13), with the following comments: (1) The periodic test frequency specified in the Technical Specifications was conservatively selected, using considerations in paragraph 4.3 of Reference 13, to ensure that equipment associated with protection functions has not drifted beyond its minimum performance requirements. (2) The test interval discussed in Paragraph 5.2 of Reference 13 is primarily developed on past operating experience, and modified, as necessary, to ensure that system and subsystem protection is reliably provided. Analytic methods for determining reliability are not used to determine test interval. 7.3.4.5 Evaluation of Compliance with IEEE-344-1971, Trial-Use Guide for Seismic Qualifications of Class I Electric Equipment for Nuclear Power Generating Stations The seismic testing, as set forth in Section 3.10, conforms to the testing requirements of IEEE-344-1971 (Reference 14); however, because the IEEE standards were issued after much of the design and testing had been completed the equipment documentation may not meet the format requirements of the standards. Documentation of the environmental and seismic qualification of the process protection system is provided in References 18, 19, 20, and 21. 7.3.4.6 Evaluation of Compliance with IEEE-317-1971, Electric Penetration Assemblies in Containment Structures for Nuclear Fueled Power Generating Stations Refer to Section 7.2.2 for a discussion of conformance with IEEE-317-1971 (Reference 15). The same applies to penetrations for systems described in Section 7.3. DCPP UNITS 1 & 2 FSAR UPDATE 7.3-27 Revision 21 September 2013 7.3.4.7 Evaluation of Compliance with IEEE-336-1971, Installation, Inspection, and Testing Requirements for Instrumentation and Electric Equipment During the Construction of Nuclear Power Generating Stations Refer to Section 7.2.2 for a discussion of conformance with IEEE-336-1971 (Reference 16). 7.3.4.8 Eagle 21 and Process Control System Design, Verification, and Validation The standards that are applicable to the Eagle 21 Design, Verification and Validation Plan (refer to reference 17) are IEEE-Standard 603-1980 (Reference 21), which was endorsed by Regulatory Guide 1.153-December 1985 (Reference 23), and ANSI/IEEE-ANS-7-4.3.2-1982 (Reference 24) which was endorsed by Regulatory Guide 1.152-November 1985 (Reference 22). The following ESFAS related instrument signals are processed by the PCS: (1) RHR Pump Trip on Low RWST Level (see Sections 6.3.5.4.1 and 7.3.2.4.1). References 4, 10, 13, 16, and 27 through 71 were used for design, verification, validation, and qualification of all or portions of the safety related PCS hardware and software (encompassing Triconex components, manual/auto hand stations, signal converters/isolators and loop power supplies). 7.
3.5 REFERENCES
- 1. Deleted in Revision 21.
- 2. J. A. Nay, Process Instrumentation for Westinghouse Nuclear Steam Supply Systems, WCAP-7671, April 1971.
- 3. Safety Guide 11, Instrument Lines Penetrating Primary Reactor Containment, USAEC, March 1971.
- 4. IEEE Standard 279-1971, Criteria for Protection Systems for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 5. D. N. Katz, Solid State Logic Protection System Description, WCAP-7672, June 1971.
- 6. Regulatory Guide 1.47, Bypassed and Inoperable Status Indication for Nuclear Power Plant Safety Systems, USAEC, May 1973.
- 7. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
DCPP UNITS 1 & 2 FSAR UPDATE 7.3-28 Revision 21 September 2013 8. IEEE Standard 279-1968, Criteria for Protection Systems for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc. 9. Safety Guide 22, Periodic Testing of Protection System Actuation Functions, USAEC, February 1972.
- 10. IEEE 308-1971, Criteria for Class 1E Electric Systems for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 11. IEEE Standard 323-1971, Trial-Use Standard: General Guide for Qualifying Class I Electric Equipment for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 12. Deleted in Revision 21. 13. IEEE Standard 338-1971, Trial-Use Criteria for the Periodic Testing of Nuclear Power Generating Station Protection Systems, Institute of Electrical and Electronics Engineers, Inc.
- 14. IEEE Standard 344-1971, Trial-Use Guide for Seismic Qualifications of Class I Electric Equipment for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 15. IEEE Standard 317-1971, Electric Penetration Assemblies in Containment Structures for Nuclear Fueled Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc. 16. IEEE Standard, 336-1971, Installation, Inspection, and Testing Requirements for Instrumentation and Electric Equipment During the Construction of Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 17. L. E. Erin, Topical Report Eagle 21 Microprocessor Based Process Protection System, WCAP-12374, September 1989.
- 18. R. B. Miller, Methodology for Qualifying Westinghouse WRD Supplied NSSS Safety Related Electrical Equipment, WCAP-8587, Westinghouse Proprietary Class 3.
- 19. Equipment Qualification Data Package, WCAP-8587, Supplement 1, EQDP-ESE-69A and 69B, Westinghouse Proprietary Class 3.
- 20. Equipment Qualification Test Report, WCAP-8687, Supplement 2-E69A and 69B, Westinghouse Proprietary Class 2.
- 21. IEEE Standard 603-1980, IEEE Standard Criteria for Safety Systems for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
DCPP UNITS 1 & 2 FSAR UPDATE 7.3-29 Revision 21 September 2013 22. Regulatory Guide 1.152, Criteria for Programmable Digital Computer System Software in Safety Related Systems in Nuclear Plants, November 1985. 23. Regulatory Guide 1.153, Criteria for Power, Instrumentation and Control Portions of Safety Systems, December 1985.
- 24. ANSI/IEEE-ANS-7-4.3.2, Application Criteria for Programmable Digital Computer Systems in Safety Systems of Nuclear Power Generating Stations, 1982.
- 25. Reliability Assessment of Potter & Brumfield MDR Relays, WCAP-13878, Rev. 0, Westinghouse Proprietary Class 2C, June 1994.
- 26. Extension of Slave Relay Surveillance Test Intervals, WCAP-13900, Rev. 0, Westinghouse Proprietary Class 3, April 1994.
- 27. IEEE Standard 323-2003, Qualifying Class 1E Equipment for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 28. IEEE Standard 344-1987, Recommended Practice for Seismic Qualification of Class 1E Equipment for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 29. IEEE Standard 384-1974, Criteria for Independence of Class 1E Equipment and Circuits, Institute of Electrical and Electronics Engineers, Inc.
- 30. IEEE Standard 730-1998, Software Quality Assurance Plans, Institute of Electrical and Electronics Engineers, Inc.
- 31. IEEE Standard 828-1990, Software Configuration Management Plans, Institute of Electrical and Electronics Engineers, Inc.
- 32. IEEE Standard 829-1983, Software Test Documentation, Institute of Electrical and Electronics Engineers, Inc.
- 33. IEEE Standard 830-1993, Recommended Practice for Software Requirements Specifications, Institute of Electrical and Electronics Engineers, Inc.
- 34. IEEE Standard 1008-1987, Software Unit Testing, Institute of Electrical and Electronics Engineers, Inc.
- 35. IEEE Standard 1012-1998, Software Verification and Validation, Institute of Electrical and Electronics Engineers, Inc.
- 36. IEEE Standard 1016-1987, Recommended Practice for Software Design Descriptions, Institute of Electrical and Electronics Engineers, Inc.
DCPP UNITS 1 & 2 FSAR UPDATE 7.3-30 Revision 21 September 2013 37. IEEE Standard 1016.1-1993, Guide to Software Design Descriptions, Institute of Electrical and Electronics Engineers, Inc. 38. IEEE Standard 1059-1993, Guide for Software Verification and Validation Plans, Institute of Electrical and Electronics Engineers, Inc.
- 39. IEEE Standard 1074-1995, Developing Software Life Cycle Processes, Institute of Electrical and Electronics Engineers, Inc.
- 40. IEEE Standard 1233-1998, Guide for Developing System Requirements Specifications, Institute of Electrical and Electronics Engineers, Inc.
- 41. IEEE Standard C62.41-1991, Recommended Practice for Surge Voltages in Low Voltage AC Power Circuits, Institute of Electrical and Electronics Engineers, Inc.
- 42. IEEE Standard C62.45-1992, Recommended Practice on Surge Testing for Equipment Connected to Low-Voltage (1000V and less) AC Power Circuits, Institute of Electrical and Electronics Engineers, Inc.
- 43. IEEE Standard 7-4.3.2-2003, Digital Computers in Safety Systems of Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 44. EPRI TR-106439, Guideline on Evaluation and Acceptance of Commercial-Grade Digital Equipment for Nuclear Safety Applications, Electric Power Research Institute, October, 1996. 45. EPRI TR-102323 Rev. 3, Guidelines for Electromagnetic Interference Testing in Power Plants, Electric Power Research Institute, November 2004. 46. EPRI TR-107330, Generic Requirements Specification for Qualifying a Commercially Available PLC for Safety-Related Applications in Nuclear Power Plants, Electric Power Research Institute, December 1996.
- 47. EPRI TR-102348 Rev. 1, Guideline on Licensing Digital Upgrades, Electric Power Research Institute, March 2002.
- 48. Regulatory Guide 1.100 Rev. 2, Seismic Qualification of Electrical and Mechanical Equipment for Nuclear Power Plants, USNRC, June 1988.
- 49. Regulatory Guide 1.105, Rev. 3, Setpoints for Safety-Related Instrumentation, USNRC, December 1999.
- 50. Regulatory Guide 1.152, Rev, 1, Criteria for Digital Computers in Safety Systems of Nuclear Power Plants, USNRC, January 1996.
DCPP UNITS 1 & 2 FSAR UPDATE 7.3-31 Revision 21 September 2013 51. Regulatory Guide 1.168, Verification, Validation, Reviews and Audits for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, February 2004. 52. Regulatory Guide 1.169, Configuration Management Plans for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997.
- 53. Regulatory Guide 1.170, Software Test Documentation for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997.
- 54. Regulatory Guide 1.171, Software Unit Testing for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997.
- 55. Regulatory Guide 1.172, Software Requirements Specifications for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997.
- 56. Regulatory Guide 1.173, Developing Software Life Cycle Processes For Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997
- 57. Regulatory Guide 1.180, Rev. 1, Guidelines for Evaluating Electromagnetic and Radio-Frequency Interference in Safety-Related Instrumentation and Control Systems, USNRC, October 2003.
- 58. Regulatory Guide 1.22, Periodic Testing of Protection System Actuation Functions, USNRC, February 1972.
- 59. Regulatory Guide 1.29, Rev. 3, Seismic Design Classification, USNRC, September 1978.
- 60. Regulatory Guide 1.30, Quality Assurance Requirements for the Installation, Inspection, and Testing of Instrumentation and Electric Equipment, USNRC, August 1972. 61. Regulatory Guide 1.89, Environmental Qualification of Certain Electric Equipment Important to Safety for Nuclear Power Plants, USNRC, November 1974.
- 62. Regulatory Guide 1.97, Rev 3, Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident, USNRC, May 1983.
- 63. NUREG-0800, Appendix 7.0-A, Rev. 5, Review Process for Digital Instrumentation and Control Systems, USNRC, March 2007.
DCPP UNITS 1 & 2 FSAR UPDATE 7.3-32 Revision 21 September 2013 64. BTP 7-14 Rev. 5 Guidance on Software Reviews for Digital Computer-Based Instrumentation and Control Systems, USNRC, March 2007. 65. BTP 7-18 Rev. 5, Guidance on the use of Programmable Logic Controllers in Digital Computer-Based Instrumentation and Control Systems, USNRC, March 2007.
- 66. MIL-STD-461E, Requirements for the Control of Electromagnetic Interference Emissions and Susceptibility, USDOD, August 1999
- 67. ANSI/ANS-4.5-1980, Criteria for Accident Monitoring Functions in Light-Water-Cooled Reactors, American Nuclear Society, January 1980
- 68. NEMA ICS 1-2000, Industrial Control and Systems: General Requirements, National Electrical Manufacturers Association, December 2008
- 69. NFPA 70 (NEC) 2002 National Electric Code, National Fire Protection Association, January 2002
- 70. IEC 61131-3 1993, Programming Industrial Automations Systems, International Electrotechnical Commission, December 1993
- 71. ISA-S67.04-1994, Setpoints for Nuclear Safety-Related Instrumentation, International Society of Automation, January 1994
- 72. S.V. Andre, et. al, Summary Report Eagle 21 Process Protection System Upgrade for Diablo Canyon Power Plant Units 1 and 2, WCAP-12813-R3 (P) / WCAP-13615-R2 (NP), June 1993
- 73. L.E. Erin, Topical Report Diablo Canyon Units 1 and 2 Eagle 21 Microprocessor-Based Process Protection System, WCAP-13423, October 1992 7.3.6 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures.
DCPP UNITS 1 & 2 FSAR UPDATE 7.4-1 Revision 21 September 2013 7.4 SYSTEMS REQUIRED FOR SAFE SHUTDOWN The functions necessary safe shutdown, defined as hot standby (MODE 3), are available from instrumentation channels that are associated with the major systems in both the primary and secondary sides of the plant. These channels are normally aligned to serve a variety of operational functions, including startup and shutdown, as well as protective functions. Prescribed procedures for securing and maintaining the plant in a safe shutdown condition can be instituted by appropriate alignment of selected systems. The discussion of these systems, together with the applicable codes, criteria, and guidelines, is included in other sections. In addition, the alignment of shutdown functions associated with the engineered safety features that are invoked under postulated limiting fault situations is discussed in Chapter 6 and Section 7.3. The instrumentation and control functions that are required to be aligned for maintaining safe shutdown (MODE 3) of the reactor, which are discussed in this section, are the minimum number under nonaccident conditions. These functions permit the necessary operations to:
(1) Prevent the reactor from achieving criticality in violation of the Technical Specifications (Reference 2) (2) Provide an adequate heat sink so that design and safety limits are not exceeded Refer to Appendix 9.5G for an identification of the instrumentation and controls required for safe shutdown in the event of fire. 7.4.1 DESIGN BASES 7.4.1.1 General Design Criterion 3, 1971 - Fire Protection The instrumentation and control systems required for safe shutdown are designed and located to minimize, consistent with other safety requirements, the probability and effect of fires and explosions. 7.4.1.2 General Design Criterion 11, 1967 - Control Room The instrumentation and control systems required for safe shutdown are designed to support actions to maintain and control the safe operational status of the plant from the control room or from an alternate location if control room access is lost due to fire or other causes. 7.4.1.3 General Design Criterion 12, 1967 - Instrumentation and Control Systems The instrumentation and control systems required for safe shutdown are designed to monitor and maintain variables within prescribed operating ranges.
DCPP UNITS 1 & 2 FSAR UPDATE 7.4-2 Revision 21 September 2013 7.4.2 DESCRIPTION The designation of systems used for safe shutdown depends on identifying those systems that provide the following capabilities for maintaining a safe shutdown (MODE 3): (1) Boration (2) Adequate supply of auxiliary feedwater (3) Decay heat removal These systems are identified in the following sections, together with the associated instrumentation and controls provisions. The design basis information for these systems, as required by IEEE-279-1971 (Reference 3), is provided in other sections herein. For convenience, cross-referencing to these other sections is provided. In the event that safe shutdown from outside of the control room is required, remote instrumentation, controls, and transfer switches are required for the following functions to maintain safe shutdown (MODE 3): (1) Reactor trip indication (2) Reactor coolant system (RCS) pressure control (3) Decay heat removal via the auxiliary feedwater system and the steam generator safety valves (4) RCS inventory control via charging flow (5) Safety support systems for the above functions, including auxiliary saltwater (ASW), component cooling water (CCW), and emergency diesel generators (EDGs) Instrumentation and controls required to fulfill these functions are described in the following sections. Other instrumentation and controls provided for cold shutdown (MODE 5) and operator convenience are also identified but are not required for safe shutdown (MODE 3). 7.4.2.1 Safe Shutdown Equipment 7.4.2.1.1 Monitoring Indicators The characteristics of the monitoring indicators that are provided inside and outside, the control room are described in Section 7.5. The necessary safe shutdown (MODE 3) indications are: DCPP UNITS 1 & 2 FSAR UPDATE 7.4-3 Revision 21 September 2013 (1) Water level indications for each steam generator (2) Pressure indication for each steam generator (3) Pressurizer water level indication (4) Pressurizer pressure indication (5) Condensate storage tank level indication (6) RCS temperature indication for loop 1 hot leg and cold leg (7) AFW flow indication (8) Charging flow indication (9) Reactor trip breaker indication All indications external to the control room are provided at the hot shutdown panel except for the RCS temperature indication (which is provided at the dedicated shutdown panel) and the reactor trip breaker indication (which is provided at the trip breaker switchgear). The dedicated shutdown panel is described in Section 7.5.2.7. In addition, other remote shutdown indications are provided for operator convenience at the hot shutdown panel (see Figure 7.7-30) but not required for safe shutdown (MODE 3). 7.4.2.1.2 Controls Controls utilized for obtaining and maintaining safe shutdown (MODE 3) are addressed below. 7.4.2.1.2.1 General Considerations (1) The turbine is tripped from the control room (note that this can also be accomplished at the turbine). (2) The reactor is tripped from the control room (note that this can also be accomplished at the reactor trip switchgear). (3) All automatic systems continue functioning (discussed in Sections 7.2 and 7.7). Safe shutdown (MODE 3) is a stable plant condition automatically reached following a plant shutdown. The safe shutdown condition can be safely maintained for an extended time. DCPP UNITS 1 & 2 FSAR UPDATE 7.4-4 Revision 21 September 2013 In addition, the safety injection signal trip circuit must be defeated and the accumulator isolation valves closed. (4) For motor-driven equipment that must be operated from outside the control room due to control room evacuation, controls are provided at the hot shutdown panel. A control transfer switch is provided at the 4.16-kV switchgear to directly transfer control to the hot shutdown panel for some equipment. For other equipment, a control transfer switch is provided at the hot shutdown panel to transfer control to that panel. Transfer of control is interlocked with a permissive switch that is located at the motor control center. This interlock is provided to permit isolation of the hot shutdown panel to prevent spurious actions in the event of a fire in or at the hot shutdown panel. Three methods of transfer control are employed: (a) For one set of redundant equipment, the permissive switch is normally closed, permitting transfer of control to the hot shutdown panel when the control transfer switch is operated. Abnormal permissive switch alignment or transfer of control is annunciated in the control room. (b) For the second set of redundant equipment, the permissive switch is normally open, permitting transfer of control by operating the transfer switch only after closing the permissive switch. Abnormal permissive switch alignment is annunciated in the control room. (c) For the third set of redundant equipment, the transfer switch on the 4.16-kV switchgear permits the transfer of control to the hot shutdown panel. Transfer of control is annunciated in the control room. 7.4.2.1.2.2 Pumps, Fan Coolers, and Ventilation Systems To maintain safe shutdown (MODE 3) conditions from inside or outside of the control room, controls and transfer switches are required for the AFW pumps, centrifugal charging pumps (CCP1 and CCP2), ASW pumps and the CCW pumps. Other controls are available for "operational convenience" but are not required for safe shutdown. The controls for the required pumps and other equipment are described below.
(1) AFW Pumps - In the event of a main feedwater pump stoppage due to a loss of electric power, the motor-driven and turbine-driven AFW pumps start automatically (these pumps can also be started manually). Motor-driven AFW pump start and stop motor controls are located on the hot shutdown panel, in the 4.16-kV switchgear rooms, and in the control room (refer to Figures 7.3-8 and 7.3-17). Controls for the steam supply valve to DCPP UNITS 1 & 2 FSAR UPDATE 7.4-5 Revision 21 September 2013 the turbine-driven AFW pump are located on the hot shutdown panel and in the control room (refer to Figure 7.3-18). (2) Centrifugal Charging and Boric Acid Transfer Pumps - Start and stop motor controls are provided for these pumps. The controls for the centrifugal charging pumps (CCP1 and CCP2) and the boric acid transfer pumps are located on the hot shutdown panel, as well as in the control room. Additionally, the charging pumps can be started and stopped in the 4.16-kV switchgear rooms. (For charging pumps, refer to Figures 7.3-3, 7.3-4, and 7.3-29. For boric acid transfer pumps, refer to Figures 7.3-13 and 7.3-30, Sheet 2.) (3) ASW Pumps - These pumps restart automatically following a loss of normal electric power. Start and stop motor controls are located on the hot shutdown panel, in the 4.16-kV switchgear rooms, as well as in the control room (refer to Figures 7.3-5 and 7.3-28). (4) CCW Pumps - These pumps restart automatically following a loss of normal electric power. Start and stop motor controls are located on the hot shutdown panel, in the 4.16-kV switchgear rooms, as well as in the control room (refer to Figures 7.3-7 and 7.3-27). (5) Reactor Containment Fan Cooler Units - These units restart automatically following a loss of normal electric power. Start and stop motor controls with a selector switch are provided for the fan motors. The controls are located on the hot shutdown panel, as well as in the control room (refer to Figures 7.3-6 and 7.3-31). (6) Control Room HVAC System (includes fans and dampers) - A start and stop switch is located in the control room for the fan(s). Also, a control to open or close the inlet air damper(s) is located near the dampers. When placed in automatic control, the inlet air dampers are designed to position automatically to meet the requirements of the mode of operation of the system. (7) Auxiliary Building Ventilation System - Operation of the system can be initiated from the ventilation control board in the control room. The system is designed to automatically shift to meet the requirements of the mode of operation of the system. (8) Fuel Handling Area Heating and Ventilation System (Provides ventilation for the auxiliary feedwater pumps) - Operation of the system can be initiated from the control room. Normally, the system operates with one set of supply and exhaust fans. In the event of failure of an operating fan, the redundant fan is designed to start automatically.
DCPP UNITS 1 & 2 FSAR UPDATE 7.4-6 Revision 21 September 2013 (9) 4.16-kV Switchgear Room Ventilation System - Operation of the system can be initiated from the locally mounted control switches. The system is automatically started by a thermostat located in the associated safety-related room. (10) 125-Vdc and 480-V Switchgear Room Ventilation System - Operation of the system can be initiated from the locally mounted control switches. 7.4.2.1.2.3 Valves To maintain safe shutdown (MODE 3) conditions from inside or outside of the control room, control of AFW system level control valves is required. Other controls are available for "operational convenience" but are not required for safe shutdown. The controls for the AFW valves and other remotely operated valves with controls external to the control room are described below.
(1) Letdown Orifice Isolation Valves - Open and close controls for these valves are located on the hot shutdown panel. These controls duplicate functions that are inside the control room (refer to Figure 7.3-45, Sheet 1). (2) AFW Control Valves - Manual control is provided on the hot shutdown panel that duplicates functions inside the control room (refer to Figure 7.3-14). (3) Condenser Steam Dump and Atmospheric Steam Relief Valves - The condenser steam dump and atmospheric relief valves are automatically controlled. In addition to local and control room control, the 10 percent steam dump valves can be manually controlled at the hot shutdown panel. Manual control is provided locally as well as inside the control room for the atmospheric relief valves. Steam dump to the condenser is blocked on high condenser pressure. (4) Charging Flow Control Valves - Controls for the emergency borate valve (refer to Figure 7.3-34) and charging pump discharge header flow control valves are located on the hot shutdown panel in addition to the control room. Controls for a pressurizer auxiliary spray valve are located at the dedicated shutdown panel in addition to the control room (refer to Figure 7.3-45, Sheet 1). (5) Pressurizer Power Operated Relief Valves - Emergency close controls for these valves are provided on the hot shutdown panel in addition to control from the control room (refer to Figure 7.3-21).
DCPP UNITS 1 & 2 FSAR UPDATE 7.4-7 Revision 21 September 2013 7.4.2.1.2.4 Pressurizer Heater Control The pressurizer heaters are normally controlled from the control room. On-off control is provided on the hot shutdown panel for two backup heater groups. The control is grouped with the charging flow controls and duplicates functions available in the control room. These controls are for "operational convenience" but are not required for safe shutdown (MODE 3). 7.4.2.1.2.5 Diesel Generators These units are started automatically on a safety injection, loss of voltage on either the offsite source or the vital buses, or on degraded bus voltage on the vital buses. Manual controls for diesel starting and control are provided at the main control room and also locally at the diesel generators. Additional description is provided in Section 8.3. 7.4.2.1.3 Maintenance of Safe Shutdown (MODE 3) Conditions Using Remote Shutdown Instrumentation and Controls The normal and preferred location to operate the plant from is the control room. However, in the event that the control room becomes inaccessible, the operators can establish remote control and place the unit in safe shutdown (MODE 3). Remote Shutdown System Technical Specifications (Reference 2) have been established to ensure the operability of the remote shutdown instrumentation and controls. To establish and maintain safe shutdown (MODE 3) conditions from outside of the control room, the reactor must be tripped, decay heat must be removed, and the RCS temperature, pressure, and inventory must be controlled. Additionally, systems required to support equipment performing these functions must be operable. The following provides a discussion of the minimum functions required to establish and maintain safe shutdown (MODE 3) conditions from outside of the control room until a cooldown is initiated or control is transferred back to the control room. (1) Reactor Trip - Core subcriticality is achieved by tripping the reactor. The reactor can be tripped from outside the control room by opening the reactor trip breakers at the reactor trip switchgear. Reactor trip indication is provided from outside the control room by the reactor trip breaker position. The insertion of the control rods during a reactor trip provides the negative reactivity needed to establish and maintain safe shutdown (MODE 3) conditions until such time that either control is returned to the control room or a cooldown is initiated. (2) Decay Heat Removal via the AFW System and the Steam Generator Safety Valves - Heat removal from the reactor coolant system is accomplished by transferring heat to the secondary plant through the steam generators. The decay heat is then removed from the steam DCPP UNITS 1 & 2 FSAR UPDATE 7.4-8 Revision 21 September 2013 generators via boiling and steam release through the steam generator code safety valves. Indication of secondary heat sink is provided by steam generator pressure indication, steam generator wide range level indication, and AFW flow indication at the hot shutdown panel. The hot shutdown panel also provides indication of condensate storage tank level to allow monitoring of water available to supply the suction of the AFW pumps for extended operation at safe shutdown (MODE 3). To ensure that steam generator level remains within its expected range, the AFW pump and level control valves are controllable from the hot shutdown panel. Upon initiation of a reactor trip, steam generator level will decrease due to shrink and the trip of the main feedwater pumps. The AFW pumps supply feedwater to the steam generators to compensate for the loss of main feedwater. After the level in the steam generators recovers, the feedwater supply to the steam generators must be controlled to prevent the steam generators from overfilling and overcooling the reactor coolant system, which could result in a safety injection. The feedwater flow can be controlled from the hot shutdown panel by using the AFW level control valves or by starting and stopping the AFW pumps. AFW flow indication is provided to aid in flow control. To monitor the rate of heat removal from the core during all plant conditions, including a loss of offsite power, indications of RCS hot and cold leg temperature indication are required. Loop 1 RCS hot and cold leg temperature indication is available at the dedicated shutdown panel. (3) RCS Pressure Control - Indication of RCS pressure is provided by the pressurizer pressure indication located at the hot shutdown panel. RCS overpressure protection is provided by the pressurizer code safety valves. Although pressurizer heaters would assist in controlling RCS pressure, they are not required to maintain RCS pressure control. (4) Reactor Coolant System Inventory Control via Charging Flow - Indication of RCS inventory is provided by the pressurizer level indication located at the hot shutdown panel. Level control is necessary to prevent the loss of level in the pressurizer and the subsequent loss of RCS pressure control, to prevent the RCS from achieving a solid water condition where pressure would no longer be readily controllable, and to prevent the core from being uncovered due to low level. The hot shutdown panel contains controls to start and stop each centrifugal charging pump (CCP1 and CCP2). The charging pumps not only supply water to the RCS for pressurizer level control, but also provide water to the reactor coolant pump (RCP) seals. By starting and stopping DCPP UNITS 1 & 2 FSAR UPDATE 7.4-9 Revision 21 September 2013 the charging pumps, pressurizer level can be controlled. During any time when the charging pumps are shut off, RCP seal degradation would be prevented by reactor coolant flowing past the thermal barrier heat exchanger, which is cooled by CCW flow, and out of the RCP seals. This would also remove water injected into the RCS that may have caused an increase in pressurizer level. (5) Safety Support Systems - In order for the above equipment to perform its intended safety function, it must have power and be cooled. Heat removal can be accomplished via the CCW and ASW systems. The CCW system removes heat from the lube oil and seals of the engineered safety feature (ESF) pumps. The ASW removes heat from the CCW system and rejects it to the ultimate heat sink. Both the CCW pumps and the ASW pumps can be started from the hot shutdown panel. Although the CCW and ASW pumps are normally in operation and are designed to auto-start, pump controls at the hot shutdown panel ensure that the pumps are available in the event that they do not start automatically. To ensure that power is available to ESF equipment, emergency diesel generators (EDGs) are available to supply power in the event that offsite power is unavailable. Although the EDGs should auto-start during a loss of offsite power, local manual controls for diesel starting and control provide additional assurance that power will be available to the ESF equipment required to establish and maintain hot safe shutdown (MODE 3) conditions. (6) Additional Controls Provided for Operational Convenience - Controls are also provided at the hot shutdown panel to manipulate charging flow, the 10 percent steam dump valves, the containment fan cooler units, the pressurizer heaters, the pressurizer power operated relief valves, and the letdown orifice isolation valves. Controls are provided at the dedicated shutdown panel for pressurizer auxiliary spray. These controls are provided as an operational convenience. The above evaluation demonstrates that the reactor can be maintained in a safe condition. 7.4.2.1.4 Process Control System The PCS performs the same design functions as the original PCS. Some of the instrumentation and control functions described in this chapter are processed by the PCS. References 3 through 52 were used for design, verification, validation, and qualification of all or portions of the safety related PCS hardware and software (encompassing Triconex components, manual/auto hand stations, signal converters/isolators and loop power supplies). DCPP UNITS 1 & 2 FSAR UPDATE 7.4-10 Revision 21 September 2013 7.4.2.2 Equipment, Services, and Approximate Time Required After Incident that Requires Hot Shutdown (MODE 4) (1) AFW pumps - required if main feedwater pumps are not operating. For loss of plant ac power, the turbine-driven AFW pump starts automatically within 1 minute (refer to Section 6.5). (2) Reactor containment fan cooler units - within 15 minutes (refer to Section 6) (3) EDGs - loaded within 1 minute (refer to Section 8.3). (4) Lighting in the areas of plant required during this condition - immediately (refer to Section 8.3). (5) Pressurizer heaters - within 8 hours (refer to Section 5.5.9). (6) Communication network - to be available for prompt use between the hot shutdown panel area and the following areas: (a) Outside telephone exchange (b) Boric acid transfer pump (c) EDGs (d) Switchgear room (e) Steam relief valves (f) Dedicated shutdown panel 7.4.2.3 Equipment and Systems Available for Cold Shutdown (MODE 5) (1) Reactor coolant pump (not available after loss of offsite power; refer to Section 5.5.1) (2) Auxiliary feedwater pumps (refer to Section 6.5.3.5) (3) Boric acid transfer pump (refer to Section 9.3.4) (4) Charging pumps (refer to Section 9.3.4) (5) Containment fan coolers (refer to Section 9.4.5) (6) Control room ventilation (refer to Section 9.4.1) DCPP UNITS 1 & 2 FSAR UPDATE 7.4-11 Revision 21 September 2013 (7) Component cooling pumps (refer to Section 9.2.2) (8) Residual heat removal pumps (refer to Section 5.5.6)(a) (9) Vital MCC and switchgear sections (refer to Section 8.3) (10) Controlled steam release and feedwater supply (refer to Section 7.7 and Section 10.4) (11) Boration capability (refer to Section 9.3.4) (12) Nuclear instrumentation system (source range and intermediate range; refer to Sections 7.2 and 7.7)(a) (13) Reactor coolant inventory (charging and letdown; refer to Section 9.3.4) (14) Pressurizer pressure control including control for pressurizer power-operated relief valves, heaters, and spray (refer to Sections 5.5.9 and 5.5.12)(a) (15) 10 percent atmospheric dump valves (refer to Section 10.4.4) 7.4.3 SAFETY EVALUATION 7.4.3.1 General Design Criterion 3, 1971 - Fire Protection The instrumentation and control systems required for safe shutdown (MODE 3) are designed to the fire protection guidelines of Appendix A to Branch Technical Position APCSB 9.5-1. The instrumentation and control systems required for safe shutdown are located physically in multiple areas of the plant. Appendix 9.5B, Table B-1 provides a summary of the evaluation of PG&E's compliance with Appendix A to BTP APCSB 9.5-1 and is organized by commitment. Appendix 9.5A provides the fire hazards analysis and is organized by fire zone. 7.4.3.2 General Design Criterion 11, 1967 - Control Room The instrumentation and control functions required for safe shutdown (MODE 3) are located in the control room. Redundant instrumentation and controls are located on the hot shutdown panel, switchgear, and on the dedicated shutdown panel for the purpose (a) Instrumentation and controls for these systems would require some modifications so that their functions may be performed from outside the control room. Note that the reactor plant design does not preclude attaining the cold shutdown condition from outside the control room. An assessment of plant conditions could be made on a long-term basis (a week or more) to establish procedures for making the necessary physical modifications to instrumentation and control equipment in order to attain cold shutdown. During such time, the plant could be safely maintained in the hot shutdown condition. DCPP UNITS 1 & 2 FSAR UPDATE 7.4-12 Revision 21 September 2013 of achieving and maintaining a safe shutdown in the event an evacuation of the control room is required. These controls and the instrumentation channels, together with the equipment and services that are available for both hot and cold shutdown, identify the potential capability for cold shutdown of the reactor, subsequent to a control room evacuation, through the use of suitable procedures. In the unlikely event that access to the control room is restricted, the plant can be safely maintained at safe shutdown (MODE 3), and until the control room can be reentered, by the use of the monitoring indicators and the controls listed in Section 7.4.2. These indicators and controls are provided on the hot shutdown panel, the dedicated shutdown panel, or local area panel as well as inside the control room. 7.4.3.3 General Design Criterion 12, 1967 - Instrumentation and Control Systems The safety evaluation of the maintenance of a shutdown with the systems described in Section 7.4.2 and associated instrumentation and controls has included consideration of the accident consequences that might jeopardize safe shutdown (MODE 3) conditions. The germane accident consequences are those that would tend to degrade the capabilities for boration, adequate supply of auxiliary feedwater, and decay heat removal.
The results of the accident analyses are presented in Chapter 15. Of these, the following produce the most severe consequences that are pertinent:
(1) Uncontrolled boron dilution (2) Loss of normal feedwater (3) Loss of external electrical load and/or turbine trip (4) Loss of all ac power to the station auxiliaries It is shown by these analyses that safety is not adversely affected by the incidents with the associated assumptions being that the instrumentation and controls indicated in Section 7.4.2 are available to control and/or monitor shutdown. These available systems allow the maintenance of safe shutdown (MODE 3) even under the accident conditions listed above that would tend toward a return to criticality or a loss of heat sink.
A plant design evaluation was performed by PG&E to identify the safe shutdown equipment that could be susceptible to loss of function due to the environmental conditions resulting from moderate-energy line breaks. Equipment modification such as spray barriers, terminal box cover gasket, and piping enclosures were designed and DCPP UNITS 1 & 2 FSAR UPDATE 7.4-13 Revision 21 September 2013 installed as required to preclude any loss of function in the event of a moderate-energy line break.
Additional information concerning protection of equipment from the effects of postulated piping ruptures is presented in Section 3.6. 7.
4.4 REFERENCES
- 1. Deleted in Revision 21.
- 2. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
- 3. IEEE Standard 279-1971, Criteria for Protection Systems for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 4. IEEE Standard 308-1971, Criteria for Class 1E Power Systems for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 5. IEEE Standard 323-2003, Qualifying Class 1E Equipment for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 6. IEEE Standard 336-1971, Installation, Inspection, and Testing Requirements for Power, Instrumentation, and Control Equipment at Nuclear Facilities, Institute of Electrical and Electronics Engineers, Inc. 7. IEEE Standard 338-1971, Criteria for the Periodic Surveillance Testing of Nuclear Power Generating Station Safety Systems, Institute of Electrical and Electronics Engineers, Inc. 8. IEEE Standard 344-1987, Recommended Practice for Seismic Qualification of Class 1E Equipment for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 9. IEEE Standard 384-1974, Criteria for Independence of Class 1E Equipment and Circuits, Institute of Electrical and Electronics Engineers, Inc.
- 10. IEEE Standard 730-1998, Software Quality Assurance Plans, Institute of Electrical and Electronics Engineers, Inc.
- 11. IEEE Standard 828-1990, Software Configuration Management Plans, Institute of Electrical and Electronics Engineers, Inc. 12. IEEE Standard 829-1983, Software Test Documentation, Institute of Electrical and Electronics Engineers, Inc.
DCPP UNITS 1 & 2 FSAR UPDATE 7.4-14 Revision 21 September 2013 13. IEEE Standard 830-1993, Recommended Practice for Software Requirements Specifications, Institute of Electrical and Electronics Engineers, Inc. 14. IEEE Standard 1008-1987, Software Unit Testing, Institute of Electrical and Electronics Engineers, Inc.
- 15. IEEE Standard 1012-1998, Software Verification and Validation, Institute of Electrical and Electronics Engineers, Inc.
- 16. IEEE Standard 1016-1987, Recommended Practice for Software Design Descriptions, Institute of Electrical and Electronics Engineers, Inc.
- 17. IEEE Standard 1016.1-1993, Guide to Software Design Descriptions, Institute of Electrical and Electronics Engineers, Inc.
- 18. IEEE Standard 1059-1993, Guide for Software Verification and Validation Plans, Institute of Electrical and Electronics Engineers, Inc.
- 19. IEEE Standard 1074-1995, Developing Software Life Cycle Processes, Institute of Electrical and Electronics Engineers, Inc.
- 20. IEEE Standard 1233-1998, Guide for Developing System Requirements Specifications, Institute of Electrical and Electronics Engineers, Inc.
- 21. IEEE Standard C62.41-1991, Recommended Practice for Surge Voltages in Low Voltage AC Power Circuits, Institute of Electrical and Electronics Engineers, Inc.
- 22. IEEE Standard C62.45-1992, Recommended Practice on Surge Testing for Equipment Connected to Low-Voltage (1000V and less) AC Power Circuits, Institute of Electrical and Electronics Engineers, Inc.
- 23. IEEE Standard 7-4.3.2-2003, Digital Computers in Safety Systems of Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 24. EPRI TR-106439, Guideline on Evaluation and Acceptance of Commercial-Grade Digital Equipment for Nuclear Safety Applications, Electric Power Research Institute, October, 1996.
- 25. EPRI TR-102323 Rev. 3, Guidelines for Electromagnetic Interference Testing in Power Plants, Electric Power Research Institute, November 2004.
- 26. EPRI TR-107330, Generic Requirements Specification for Qualifying a Commercially Available PLC for Safety-Related Applications in Nuclear Power Plants, Electric Power Research Institute, December 1996.
DCPP UNITS 1 & 2 FSAR UPDATE 7.4-15 Revision 21 September 2013 27. EPRI TR-102348 Rev. 1, Guideline on Licensing Digital Upgrades, Electric Power Research Institute, March 2002. 28. Regulatory Guide 1.100 Rev. 2, Seismic Qualification of Electrical and Mechanical Equipment for Nuclear Power Plants, USNRC, June 1988.
- 29. Regulatory Guide 1.105, Rev. 3, Setpoints for Safety-Related Instrumentation, USNRC, December 1999.
- 30. Regulatory Guide 1.152, Rev, 1, Criteria for Digital Computers in Safety Systems of Nuclear Power Plants, USNRC, January 1996.
- 31. Regulatory Guide 1.168, Verification, Validation, Reviews and Audits for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, February 2004.
- 32. Regulatory Guide 1.169, Configuration Management Plans for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997.
- 33. Regulatory Guide 1.170, Software Test Documentation for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997.
- 34. Regulatory Guide 1.171, Software Unit Testing for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997.
- 35. Regulatory Guide 1.172, Software Requirements Specifications for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997.
- 36. Regulatory Guide 1.173, Developing Software Life Cycle Processes For Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997
- 37. Regulatory Guide 1.180, Rev. 1, Guidelines for Evaluating Electromagnetic and Radio-Frequency Interference in Safety-Related Instrumentation and Control Systems, USNRC, October 2003.
- 38. Regulatory Guide 1.22, Periodic Testing of Protection System Actuation Functions, USNRC, February 1972.
- 39. Regulatory Guide 1.29, Rev. 3, Seismic Design Classification, USNRC, September 1978.
DCPP UNITS 1 & 2 FSAR UPDATE 7.4-16 Revision 21 September 2013 40. Regulatory Guide 1.30, Quality Assurance Requirements for the Installation, Inspection, and Testing of Instrumentation and Electric Equipment, USNRC, August 1972. 41. RG 1.47, Bypassed and Inoperable Status Indication for Nuclear Power Plant Safety Systems, USNRC, May 1973.
- 42. Regulatory Guide 1.89, Environmental Qualification of Certain Electric Equipment Important to Safety for Nuclear Power Plants, USNRC, November 1974.
- 43. Regulatory Guide 1.97, Rev 3, Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident, USNRC, May 1983.
- 44. NUREG-0800, Appendix 7.0-A, Rev. 5, Review Process for Digital Instrumentation and Control Systems, USNRC, March 2007.
- 45. BTP 7-14 Rev. 5 Guidance on Software Reviews for Digital Computer-Based Instrumentation and Control Systems, USNRC, March 2007.
- 46. BTP 7-18 Rev. 5, Guidance on the use of Programmable Logic Controllers in Digital Computer-Based Instrumentation and Control Systems, USNRC, March 2007.
- 47. MIL-STD-461E Requirements for the Control of Electromagnetic Interference Characteristics of Subsystems and Equipment, USDOD, August 1999
- 48. ANSI/ANS-4.5-1980, Criteria for Accident Monitoring Functions in Light-Water-Cooled Reactors, American Nuclear Society, January 1980
- 49. NEMA ICS 1-2000, Industrial Control and Systems: General Requirements, National Electrical Manufacturers Association, December 2008
- 50. NFPA 70 (NEC) 2002 National Electric Code, National Fire Protection Association, January 2002
- 51. IEC 61131-3 1993, Programming Industrial Automations Systems, International Electrotechnical Commission, December 1993 52. ISA-S67.04-1994, Setpoints for Nuclear Safety-Related Instrumentation, International Society of Automation, January 1994 7.4.5 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures.
DCPP UNITS 1 & 2 FSAR UPDATE 7.5-1 Revision 21 September 2013 7.5 SAFETY-RELATED DISPLAY INSTRUMENTATION This section provides a description of the instrumentation display systems that provide information to enable the operator to perform required safety functions and post-accident monitoring. 7.5.1 DESIGN BASES 7.5.1.1 General Design Criterion 2, 1967 - Performance Standards The safety-related display instrumentation is designed to withstand the effects of or is protected against natural phenomena, such as earthquakes, flooding, tornadoes, winds, and other local site effects. 7.5.1.2 General Design Criterion 11, 1967 - Control Room The safety-related display instrumentation is designed to support actions to maintain and control the safe operational status of the plant from the control room or from an alternate location if control room access is lost due to fire or other causes. 7.5.1.3 General Design Criterion 12, 1967 - Instrumentation and Control Systems The safety-related display instrumentation is designed to monitor and maintain variables within prescribed operating ranges. 7.5.1.4 General Design Criterion 17, 1967 - Monitoring Radioactivity Releases The safety-related display instrumentation is designed to monitor the containment atmosphere, the facility effluent discharge paths, and the facility environs for radioactivity that could be released from normal operations, from anticipated transients and from accident conditions. 7.5.1.5 10 CFR 50.49 - Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants The safety-related display instrumentation that requires environmental qualification are qualified to the requirements of 10 CFR 50.49. 7.5.1.6 Regulatory Guide 1.97, Revision 3, May 1983 - Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident The safety-related display instrumentation is designed to provide instrumentation to monitor plant variables and systems during and following an accident. DCPP UNITS 1 & 2 FSAR UPDATE 7.5-2 Revision 21 September 2013 7.5.1.7 NUREG-0737 (Items I.D.2, II.D.3, II.E.1.2, II.F.1, II.F.2, and III.A.1.2), November 1980 - Clarification of TMI Action Plan Requirements Item I.D.2 - Plant Safety Parameter Display Console: The safety parameter display system (SPDS) is designed to display to operating personnel a minimum set of parameters which define the safety status of the plant in accordance with the guidance of NUREG-0737, Supplement 1. Item II.D.3 - Direct indication of relief and safety valve position: The pressurizer safety relief valve position indication system provides positive indication in the control room to determine valve position using acoustic monitoring in the discharge pipe. Item II.E.1.2 - Auxiliary Feedwater System Automatic Initiation and Flow Indication: The Auxiliary Feedwater (AFW) System is designed to automatically initiate and is designed to the requirements of IEEE 279-1971. The AFW System is designed to provide a reliable indication of auxiliary feedwater system performance. Item II.F.1 - Additional Accident Monitoring Instrumentation: The safety-related display instrumentation is designed to include the following subparts:
- Noble gas effluent radiological monitor;
- Provisions for continuous sampling of plant effluents for post-accident releases of radioactive iodines and particulates and onsite laboratory capabilities;
- Containment high-range radiation monitor;
- Containment pressure monitor;
- Containment water level monitor; and
- Containment hydrogen concentration monitor Item II.F.2 - Instrumentation for Detection of Inadequate Core Cooling: The safety-related display instrumentation is designed to provide an unambiguous, easy-to-interpret indication of inadequate core cooling.
Item III.A.1.2 - Upgrade Emergency Support Facilities: The safety-related display instrumentation is designed to support the Technical Support Center (TSC), the Operations Support Center (OSC) and the Emergency Operations Facility (EOF) in accordance with the guidance of NUREG-0737, Supplement 1. 7.5.2 DESCRIPTION Tables 7.5-1 and 7.5-2 list the information readouts provided to enable the operator to perform required manual safety functions and to determine the effect of manual actions taken following a reactor trip due to a Condition II, III, or IV event, as defined in Sections 15.2, 15.3, and 15.4, respectively. The tables list the information readouts required to maintain the plant in a hot standby condition or to proceed to cold shutdown within the limits of the Technical Specifications (Reference 1). Adequate shutdown margin following Condition II and III events is verified by sampling of the reactor coolant for DCPP UNITS 1 & 2 FSAR UPDATE 7.5-3 Revision 21 September 2013 boron to ensure that the concentration is sufficient to maintain the reactor subcritical, as directed by emergency procedures.
Table 7.5-3 lists the information available to the operator for monitoring conditions in the reactor, the reactor coolant system (RCS), and in the containment and process systems throughout all normal operating conditions of the plant, including anticipated operational occurrences.
Table 7.5-4 lists the information available to the operator on the post-accident monitoring panels located in the control room. This information is designed to complement the information available on the control boards during post-accident conditions.
The following sections describe the monitoring systems available to the operator for assessing post-accident conditions in the RCS and the containment. Variables monitored include containment water level, hydrogen concentration and ambient pressure in the containment; RCS pressure; subcooling margin; and water level in the reactor vessel. 7.5.2.1 Post-Accident Reactor Coolant Pressure and Containment Monitors The systems described in this section meet the following requirements:
(1) All devices must be environmentally qualified in accordance with IEEE-323-1974 (Reference 2). (2) All devices must be seismically qualified in accordance with IEEE-344-1975 (Reference 3). (3) Cables and raceways shall be separated in accordance with Section 8.3.1.4.1. 7.5.2.1.1 Reactor Coolant Pressure Monitors The RCS pressure monitors consist of two mutually redundant monitors. The transmitters are mounted outside of containment and are tied to the RCS by means of sealed systems. Each sealed system consists of a bellows seal inside containment to separate the transmitter from the RCS, tubing through the penetration with a special fill fluid, and the transmitters outside of containment. The indicators for both monitors and the recorder for one of the monitors are provided in the control room.
7.5.2.1.2 Containment Pressure Monitors The DCPPcontainment is a steel-lined, reinforced concrete structure designed for pressure loads and load combinations described in Section 3.8.1.3.2. Containment pressure transmitters with a range of -5 to 200 psig are connected to control room DCPP UNITS 1 & 2 FSAR UPDATE 7.5-4 Revision 21 September 2013 recorders. This instrumentation complements the reactor protection system containment pressure indicators that have a range of -5 to 55 psig. 7.5.2.1.3 Containment Water Level Monitors The containment water level indication system consists of wide- and narrow-range monitors. Each monitor consists of two mutually redundant and separated channels that are post-accident- qualified in accordance with Class 1E requirements and Regulatory Guide 1.97, Revision 3 as noted in Table 7.5-6. In addition, because of their locations, each of the wide-range monitor differential pressure transmitters has been qualified for submerged post-accident operation.
Each of the wide-range monitors is provided with a recorder that is mounted on the post-accident monitor panel in the control room.
The residual heat removal (RHR) recirculation sump water level instrumentation (the narrow-range monitor) has a level indicator mounted on the main control board. These indicators are located above the respective recirculation control switches as these indicators are used by the operator when operating pumps for recirculation.
Figure 7.5-1 represents the level indication system described above.
Figure 7.5-1B shows the Unit 2 wide-range level monitors with an installed spare transmitter in service. 7.5.2.1.4 Containment Hydrogen Monitors The hydrogen monitoring system is described in Section 6.2.5.5. 7.5.2.1.5 High-Range Containment Radiation Monitor Two mutually redundant high-range area radiation monitors are provided for containment monitoring. Both indication and recording of the readouts for these monitors are provided in the control room.
A detailed discussion of these monitors is presented in Section 11.4.2.3. 7.5.2.2 Instrumentation for Detection of Inadequate Core Cooling The function of core cooling monitoring in a redundant and diverse manner is provided by the subcooling margin monitors described in Section 7.5.2.2.1 and the core exit thermocouples described in Section 7.5.2.2.2. A supplemental source of information for use in the detection of inadequate core cooling is provided by the reactor vessel level instrumentation system described in Section 7.5.2.2.3. DCPP UNITS 1 & 2 FSAR UPDATE 7.5-5 Revision 21 September 2013 7.5.2.2.1 Subcooling Meter DCPP uses the reactor vessel level instrumentation system (RVLIS) processors to calculate RCS subcooling. Information required on the subcooled margin monitors (SCMMs) is provided in Table 7.5-5. Details of the display, calculator, and inputs are as follows: 7.5.2.2.1.1 Display Each display (one in post-accident monitoring panel PAM3 (train A) and one in PAM4 (train B)) indicates either the temperature or pressure margin to saturation continuously on each RVLIS monitor. A one-hour trend of the temperature margin is also displayed. Train A of the SCMM provides a temperature margin output to an analog recorder. A remote digital display of the temperature margin from SCMM B is located on the main control board in the control room. The recorder is on the post-accident monitoring panel (PAM1) with other recorders to assess core cooling conditions. Each train of the SCMM provides a temperature margin analog signal to emergency response facility display system (ERFDS) for logging purposes. Refer to Section 3.10 for a discussion of the seismic qualification of the displays. 7.5.2.2.1.2 Calculator The redundant RVLIS processors calculate the subcooled margin. The SCMM subset of RVLIS is a software program that uses RCS pressure and temperature inputs in addition to look-up steam tables to determine subcooling. The selection logic uses the highest temperature and the input pressure. Refer to Section 3.10 for a discussion of the seismic qualification of the RVLIS processor. 7.5.2.2.1.3 Inputs (1) Temperature - Each SCMM has three temperature inputs. Four temperature signals come from each of the four hot leg wide-range resistance temperature detectors (RTDs). Hot legs 1 and 2 input to SCMM train B, and hot legs 3 and 4 input to SCMM train A. The other temperature signal into each SCMM is the hottest temperature taken from each train of core exit thermocouples. The hottest core exit thermocouple as monitored by train A inputs to SCMM A and the hottest core exit thermocouple as monitored by train B inputs to SCMM B. The temperature inputs meet Class 1E requirements and Regulatory Guide 1.97, Revision 3 as noted in Table 7.5-6. (2) Pressure - Pressure is sensed by the wide-range reactor coolant loop pressure transmitters as described in Section 7.5.2.1.1. Each SCMM receives a pressure input from a different wide range pressure transmitter. DCPP UNITS 1 & 2 FSAR UPDATE 7.5-6 Revision 21 September 2013 7.5.2.2.2 Incore Thermocouple System Chromel-Alumel thermocouples are inserted into guide tubes that penetrate the reactor vessel head through seal assemblies and terminate at the exit flow end of the fuel assemblies. The thermocouples are provided with two primary seals, a conoseal, and a compression-type seal from conduit to head. The thermocouples are supported in guide tubes in the upper core assembly. The incore thermocouple system incorporates all 65 incore thermocouples so that a complete temperature distribution can be provided.
The system consists of two redundant trains, one covering 32 thermocouples and one covering 33 thermocouples. The thermocouples are chosen so that all areas of the core are covered by each display. The number of operable thermocouples required per core quadrant is governed by the requirements provided in the Technical Specifications.
The display unit for each of the redundant trains can read out all thermocouple temperatures assigned to the train or can indicate selective incore thermocouple temperatures continuously on demand. The highest thermocouple reading in each train is recorded on the post-accident panel. The range and accuracy of these thermocouple readings are provided in Table 7.5-4.
The incore thermocouple signals are also provided as inputs to the plant computer as described in Section 7.7.2.9.1.. The incore thermocouple system is seismically and environmentally qualified. Each of the display units is powered from an independent Class 1E power source. 7.5.2.2.3 Reactor Vessel Level Instrumentation System The reactor vessel level instrumentation system (RVLIS) uses differential pressure (DP) measuring devices to measure vessel level or relative void content of the circulating primary coolant system fluid. The system is redundant and includes automatic compensation for potential temperature variations of the impulse lines. Essential information is displayed in the main control room on the post-accident monitoring panel in a form directly usable by the operator.
The RVLIS is a microprocessor-based system. The system inputs to the microprocessor include the DP cell inputs, compensating inputs from the temperature measurements of the DP cell impulse lines, compensating temperature and pressure measurements from the RCS, and status inputs from the reactor coolant pumps. The system consists of two independent channels. Each channel utilizes three DP cells.
This DP measuring system utilizes cells of differing ranges to cover different flow behaviors with and without pump operation, as discussed below.
DCPP UNITS 1 & 2 FSAR UPDATE 7.5-7 Revision 21 September 2013 (1) Reactor Vessel - Upper-Range -- This DP cell provides a measurement of reactor vessel level above the hot leg pipe when the reactor coolant pump in the loop with the hot leg connection is not operating. (2) Reactor Vessel - Narrow-Range -- This DP measurement provides a measurement of reactor vessel level from the bottom of the reactor vessel to the top of the reactor core during natural circulation conditions. (3) Reactor Vessel - Wide-Range -- This DP cell provides an indication of reactor core and internals pressure drop for any combination of operating reactor coolant pumps. The comparison of the measured pressure drop with the normal single-phase pressure drop will provide an approximate indication of the relative void content or density of the circulating fluid. This instrument will monitor coolant conditions on a continuing basis during forced flow conditions. To provide the required accuracy for the level measurement, the temperature measurements of the impulse lines to the DP cells, together with the temperature measurement of the reactor coolant and the reactor coolant system pressure, are employed to compensate the DP cell outputs for differences in system density and reference leg density. This process occurs particularly during the change in the environment inside the containment structure following an accident.
The DP cells are located outside of the containment to eliminate the potential reduction of accuracy that may result from various accident conditions. The location of the cells outside of containment makes the system operation, including calibration and maintenance, easier (Refer to Figure 7.5-2). 7.5.2.3 Plant Vent Post-Accident Radiation Monitors The plant vent post-accident monitoring is provided by dual-path iodine and particulate grab samplers and an extended range noble gas monitoring channel. The grab sample paths can be changed remotely. The extended range noble gas detector is a beta scintillation detector operated in the current mode. The only two potential release paths not using the plant vent are the atmospheric steam dumps/reliefs and the steam generator blowdown tank vent. The steam generator blowdown sample header and the steam generator blowdown tank overflow line to the discharge tunnel are continuously monitored using in-line radiation detectors. The blowdown tank is automatically isolated on a high-radiation signal from either of these monitors, and the discharge is rerouted to the equipment drain tank receiver for further processing so that the vent of the blowdown tank is not a discharge path.
The steam lines are monitored using Geiger-Mueller (GM) detectors shielded from background activity. The control room readout has direct indication, recorder output, high alarm, failure alarm, and is powered from Class 1E power supplies. DCPP UNITS 1 & 2 FSAR UPDATE 7.5-8 Revision 21 September 2013 These monitors meet the requirements of Regulatory Guide 1.97, Revision 3 (Reference 6). A detailed discussion of these monitors is provided in Section 11.4.2.2. 7.5.2.4 ALARA Monitors for Post-Accident Monitor Access The as low as is reasonably achievable (ALARA) monitors for post-accident monitors access are provided to monitor the area where the plant vent radiation monitoring post-accident systems are located. Remote indication in a low dose area is provided. Indication in the control room for RE-34 is provided by RR-34. 7.5.2.5 Radioactive Gas Decay Tank Pressure Post-accident monitoring of the pressures in the three radioactive gas decay tanks is provided in the control room. Each pressure measurement circuit consists of a field-mounted transmitter and an indicator located on the post-accident monitoring panel. The range and accuracy of these measurements are provided in Table 7.5-4. 7.5.2.6 Auxiliary Feedwater Flow Indication The auxiliary feedwater (AFW) flow indication is provided by a single flow indication channel for the individual AFW feed lines to each of the four steam generators. These flow channels are Class 1E and powered from the instrument and control power supply system.
An alternative means of AFW flow indication is provided by a Class 1E steam generator water level indication for each steam generator. 7.5.2.7 Dedicated Shutdown Panel The instrumentation on the dedicated shutdown panel provides the indication required to bring the reactor to cold shutdown from hot standby (MODE 3) in the event that all equipment in the cable spreading room, including all protection racks, are destroyed by fire. In addition to indication, control of the pressurizer auxiliary spray valve (control remote from the control room) is located in this panel. Control of vital equipment is maintained at electrical switchgear and the hot shutdown panel. Equipment is powered from the Class 1E ac instrumentation panels. None of the instrumentation and control or electrical components in this panel are required to complete any active functions for any seismic events, or events that produce harsh environmental conditions; however, the panel and certain components within the panel are seismically and environmentally qualified for integrity of safety-related circuits.
DCPP UNITS 1 & 2 FSAR UPDATE 7.5-9 Revision 21 September 2013 The following parameters are provided on the panel: Reactor coolant system pressure Pressurizer level Reactor coolant system temperature Steam generator level Steam generator pressure is available from local indicators adjacent to the dedicated shutdown panel.
Alarms and recorders are not required for this system.
Additional information concerning the use of the dedicated shutdown panel to support remote operations is provided in Section 7.4. 7.5.2.8 Pressurizer Safety Relief Valve Position Indication System The pressurizer safety relief valve (PSRV) position indication system provides the necessary information in the control room to determine the position (open/close) of each of the three PSRVs. One acoustic monitor (piezoelectric accelerometer) per PSRV is mounted inside containment on the discharge pipe in close proximity to its associated PSRV. In the event of a PSRV opening, the discharge from the pressurizer will induce pipe vibrations that will be sensed by the acoustic monitor associated with the opened PSRV. The electric signal originating from the acoustic monitors is first amplified by charge-mode amplifiers (located inside containment) and then electronically processed (on a per channel basis) in the control room to show, in the form of a bar graph (LED lights on panel RCRM) and a digital readout (on VB2), the percent flow (0 to 100 percent) of each of the three PSRVs. Additionally, a ganged annunciator will light in the event that one or more PSRVs have opened. 7.5.2.9 Emergency Response Facility Data System The emergency response facility data system (ERFDS) is used to monitor and display plant parameters used for post-accident monitoring. The safety parameter display system (SPDS) is part of this system and is described in Section 7.5.2.10. The total ERFDS is not Class 1E nor does it meet the single failure criterion; however, it is designed to be a highly reliable system. The ERFDS is server-based with distributed desktop PCs for data displays. The ERFDS meets the criteria set forth in NUREG-0737, Supplement 1 (Reference 8). NUREG-0696, 1981 (Reference 9) is used for guidance as identified in NUREG-0737, Supplement 1. The data storage and data retrieval functions associated with post-accident monitoring are performed by the Transient Recording System (TRS).
Each power plant unit has its own system to acquire and process data. However, Unit 1 and Unit 2 will share Technical Support Center (TSC) data display equipment. DCPP UNITS 1 & 2 FSAR UPDATE 7.5-10 Revision 21 September 2013 Similarly, the emergency operations facility (EOF) equipment will be shared by Unit 1 and Unit 2. The system is divided into three subsystems as discussed in the following subsections. 7.5.2.9.1 High-Speed Data Acquisition Subsystem The data acquisition subsystem is a high-speed, remote multiplexing system that interfaces with the plant instrumentation, converts the data to a digital form, and then transmits the data to other parts of the ERFDS.
The data acquisition subsystem provides Class 1E isolation in the remote multiplexers between the different Class 1E instrument loops, and also between the Class 1E instrument loops and the rest of the system. Remote multiplexers are located so as to minimize additional wire runs. Each remote multiplexer has a 12-bit analog to digital (A/D) converter for high accuracy. The remote multiplexers can also interface with bilevel signals. The digital information from the remote multiplexers for Unit 1 and Unit 2 is transmitted to both the Unit 1 and Unit 2 Transient Recording System (TRS) servers which host the SPDS application. 7.5.2.9.2 SPDS Server Subsystem The TRS Server Subsystem for each unit is a dedicated server that controls data transfer between the data acquisition subsystem and the different desktop PCs making up the data display subsystem. Display data is updated at 1-second intervals. The TRS server provides the data recall and storage for ERFDS and hosts the SPDS application. Each unit's TRS acquires ERFDS data for both units. The TRS servers transmit the data via the Plant Data Network (PDN) to the PPC, display PCs in the control room, and the DMZ servers in the TSC. TSC and EOF displays receive data from the DMZ servers via the Plant Information Network (PIN) and the DCPP LAN using remote applications (Remote Desktop Services). ERDS data to the NRC is sent via a secure internet connection on the PG&E LAN. 7.5.2.9.3 Display System The display subsystem provides the system interface for the operators and emergency personnel. The ERFDS has two categories of display devices: the ERFDS displays and the SPDS displays. The subsystem has independent functional stations in the TSC, EOF, and control room, as described below.
The TSC and EOF display equipment includes two ERFDS Human System Interfaces (HSIs) and two SPDS-HSIs. The HSIs are connected to the DCPP LAN. A color printer connected to the DCPP LAN may be used for printouts of ERFDS, SPDS, EARS, radiation data processor, and PPC displays. The control room display equipment DCPP UNITS 1 & 2 FSAR UPDATE 7.5-11 Revision 21 September 2013 includes two SPDS HSIs. Additionally, SPDS screens may be displayed on a TV monitor. The displays are human-engineered with functional groupings of variables. With the exception of an additional display monitor, the EOF portion of the display subsystem is identical to the TSC display subsystem. 7.5.2.9.4 Equipment Location 7.5.2.9.4.1 Control Room (1) Ten remote multiplexers for each unit are located in the control room. The multiplexer location and instrument channel are specified as follows: Multiplexer Number Instrument Channel Location 1 I Main Control Board, VB1 2 II Main Control Board, VB1 3 III Main Control Board, VB1 4 Nonvital Main Control Board, VB1 5 I Main Control Board, VB4 Unit 1, (VB5, Unit 2) 6 II Main Control Board, VB4 Unit 1, (VB5, Unit 2) 7 III Main Control Board, VB4 Unit 1, (VB5, Unit 2) 8 IV Main Control Board, VB4 Unit 1, (VB5, Unit 2) 9 II Post-accident monitoring panel, PAM3 10 III Post-accident monitoring panel, PAM4 11 Nonvital Rack remote multiplexer, RM (Reference 1) (2) Two submultiplexers are located in the main control board, VB1 of each unit. (3) The SPDS desks are located in the control room. Each unit has an SPDS desk. The desks each house two SPDS monitors and personal computer and a TV monitor that is available to display SPDS screens.
DCPP UNITS 1 & 2 FSAR UPDATE 7.5-12 Revision 21 September 2013 7.5.2.9.4.2 Technical Support Center The following equipment is located in the TSC:
(1) A color printer connected to the DCPP LAN may be used to print ERFDS, SPDS, PPC, EARS, and radiation data processor displays (2) Two SPDS HSIs (3) Two ERFDS HSIs (4) PDN and PIN network infrastructure, domain servers, and data/application servers. 7.5.2.9.4.3 Emergency Operations Facility The following equipment is located in the EOF: (1) Two SPDS HSIs (2) Two ERFDS HSIs (3) Network infrastructure (4) A color printer connected to the DCPP LAN may be used to print ERFDS, SPDS, PPC, EARS, and radiation data processor displays. 7.5.2.10 Safety Parameter Display System The SPDS is the display subsystem of the ERFDS. The ERFDS is described in Section 7.5.2.9. The SPDS provides a display of plant parameters from which the safety status of operation may be assessed in the control room. The primary function of the SPDS is to help operating personnel in the control room make quick assessments of plant safety status.
The SPDS equipment includes HSIs with color displays. HSIs with color displays are located in the control room, TSC, and EOF. Each control room HSI receives data from the Unit 1 or Unit 2 TRS via the PDN. TSC and EOF HSIs receive Unit 1 and Unit 2 data from the DCPP LAN. The SPDS has one primary display and a number of secondary displays. The primary display addresses the following important plant functions:
(1) Reactivity control DCPP UNITS 1 & 2 FSAR UPDATE 7.5-13 Revision 21 September 2013 (2) Reactor core cooling and heat removal from primary system (3) Reactor coolant system integrity (4) Radioactivity control (5) Containment integrity All displays are redundant (available to both SPDS display monitors in each location). All the displays are integrated with the plant operating procedures. Magnitudes and trends can be displayed.
The SPDS displays are available in the control room, TSC, and EOF. 7.5.3 SAFETY EVALUATION 7.5.3.1 General Design Criterion 2, 1967 - Performance Standards The post-accident reactor coolant pressure and containment monitors described in Section 7.5.2.1 are seismically qualified in accordance with IEEE-344-1975 (Reference 3). The seismic qualification of instrumentation used for detection of inadequate core cooling is described in Sections 3.10.2.21, 3.10.2.22, and 3.10.2.32. None of the instrumentation and control or electrical components in the dedicated shutdown panel are required to complete any active functions for any seismic events, or events that produce harsh environmental conditions; however, the panel and certain components within the panel are seismically and environmentally qualified for integrity of safety-related circuits. The post-accident reactor coolant pressure and containment monitors, the instrumentation used for detection of inadequate core cooling and the dedicated shutdown panel are housed in seismically qualified buildings (containment structure and auxiliary building). These buildings are PG&E Design Class I (refer to Section 3.8) and designed to withstand the effects of winds and tornadoes (refer to Section 3.3), floods and tsunamis (refer to Section 3.4), external missiles (refer to Section 3.5), earthquakes (refer to Section 3.7), and other natural phenomena to protect the PG&E Design Class I portion of the safety-related display instrumentation to ensure their safety-related functions and designs will be performed. 7.5.3.2 General Design Criterion 11, 1967 - Control Room Tables 7.5-1 and 7.5-2 list the information readouts provided to enable the operator to perform required manual safety functions and to determine the effect of manual actions taken following a reactor trip due to a Condition II, III, or IV event, as defined in Sections DCPP UNITS 1 & 2 FSAR UPDATE 7.5-14 Revision 21 September 2013 15.2, 15.3, and 15.4, respectively. The tables list the information readouts required to maintain the plant in a hot standby condition or to proceed to cold shutdown within the limits of the Technical Specifications (Reference 1). Adequate shutdown margin following Condition II and III events is verified by sampling of the reactor coolant for boron to ensure that the concentration is sufficient to maintain the reactor subcritical, as directed by emergency procedures. Table 7.5-3 lists the information available to the operator for monitoring conditions in the reactor, the reactor coolant system (RCS), and in the containment and process systems throughout all normal operating conditions of the plant, including anticipated operational occurrences. Table 7.5-4 lists the information available to the operator on the post-accident monitoring panels located in the control room. This information is designed to complement the information available on the control boards during post-accident conditions. For Conditions II, III, and IV events (Refer to Tables 7.5-1 and 7.5-2), sufficient duplication of information is provided to ensure that the minimum information required will be available. The information is part of the operational monitoring of the plant that is under surveillance by the operator during normal plant operation. This is functionally arranged on the control board to provide the operator with ready understanding and interpretation of plant conditions. Comparisons between duplicate information channels or between functionally related channels enable the operator to readily identify a malfunction in a particular channel. Refueling water storage tank level is indicated and alarmed by three independent single channel systems. Similarly, two channels of the RCS pressure (wide-range) are available for maintaining proper pressure-temperature relationships following a postulated Condition II or III event. One channel of steam generator water level (wide-range) is provided for each steam generator; this duplicates level information from steam generator water level (narrow-range) and ensures availability of level information to the operator.
The remaining safety-related display instrumentation necessary for Conditions II, III, or IV events is obtained through isolation devices from the protection system. These protection channels are described in Section 7.2.1.1.7. The readouts identified in the tables were selected on the basis of sufficiency and availability during, and subsequent to, an accident for which they are necessary. Thus, the occurrence of an accident does not render this information unavailable, and the status and reliability of the necessary information is known to the operator before, during, and after an accident. No special separation is required to ensure availability of necessary and sufficient information. In fact, such separation could reduce the operator's ease of interpretation of data.
DCPP UNITS 1 & 2 FSAR UPDATE 7.5-15 Revision 21 September 2013 The design criteria used in the display system are listed below: (1) Range and accuracies listed in Tables 7.5-1 and 7.5-2 are validated through the analysis of operator actions during Condition II, III, or IV events as described in Chapter 15. The display system meets the following requirements: (a) The range of the readouts extends over the maximum expected range of the variable being measured, as listed in column 4 of Tables 7.5-1 and 7.5-2. (b) The combined indicated accuracies are shown in column 5 of Tables 7.5-1 and 7.5-2. (2) Power for the display instruments is obtained from the Class 1E 120-Vac Instrument Power Supply System as described in Section 8.3.1.1.5.2.1 and the non-Class 1E 120-Vac Instrument Power Supply System as described in Section 8.3.1.1.5.2.2. (3) Those channels determined to provide useful information in charting the course of events are recorded as shown in column 6 of Tables 7.5-1 and 7.5-2. The dedicated shutdown panel described in Section 7.5.2.7 provides information concerning indications to support remote operations if control room access is lost due to fire or other causes. 7.5.3.3 General Design Criterion 12, 1967 - Instrumentation and Control Systems Section 7.5.2 provides a description of the instrumentation display systems that provide information to enable the operator to perform required safety functions and post-accident monitoring. They are designed to monitor and maintain variables within prescribed operating ranges. 7.5.3.4 General Design Criterion 17, 1967 - Monitoring Radioactivity Releases The monitors for the plant vent and containment radiation are described in Section 11.4.2.2.1. The post-accident monitors used for monitoring radioactivity releases are described in Section 7.5.2.3.
DCPP UNITS 1 & 2 FSAR UPDATE 7.5-16 Revision 21 September 2013 7.5.3.5 10 CFR 50.49 - Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants Environmental qualification of safety-related display information is identified in Table 7.5-6. The post-accident reactor coolant pressure and containment monitors described in Section 7.5.2.1 are environmentally qualified in accordance with IEEE-323-1974 (Reference 2). 7.5.3.6 Regulatory Guide 1.97, Revision 3, May 1983 - Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident Table 7.5-6 summarizes the compliance of Diablo Canyon Power Plant with Regulatory Guide 1.97, Rev. 3. The format and content of the table are consistent with both the recommendations in Table 3 of the Regulatory Guide and the guidance provided at the March 1, 1983, NRC Regional meeting. Post-Accident Monitoring Instruments and Controls Post-accident monitoring instruments and controls are divided into variable Types A through E and Categories 1 through 3 as outlined in Regulatory Guide 1.97, Rev. 3. The variable types indicate whether the variable is considered to be a key variable needed for: (a) plant operation, (b) system status indication, or (c) backup or diagnosis. The three categories provide a graded approach to design, qualification, and quality requirements depending on the importance to safety of the measurement of a specific variable. The variable types and categories are as follows: Variable Types Type A - This variable is for components that provide primary information required to permit the control room (operating personnel) to take the specific manually controlled actions for which no automatic control is provided and that are required for safety systems to accomplish their safety functions for design basis accident events. Type A variables must meet the Category 1 qualification requirements. Type B - This variable is for components that provide information to indicate whether plant safety functions are being accomplished. Plant safety functions are (a) reactivity control, (b) core cooling, (c) maintaining reactor core coolant system integrity, and (d) maintaining containment integrity. Type C - This variable is for components that provide information to indicate the potential for being breached or the actual breach of the barriers to fission product release. The barriers are (a) fuel cladding, (b) primary coolant pressure boundary, and (c) containment. DCPP UNITS 1 & 2 FSAR UPDATE 7.5-17 Revision 21 September 2013 Type D - This variable is for components that provide information to indicate the operation of individual safety systems and other systems important to safety. Type E - This variable is for components that are monitored as required for use in determining the magnitude of the release of radioactive materials and for continually assessing such releases. Categories 1 through 3: Category 1 - Provides the most stringent design and qualification criteria and is intended for key variables. Category 2 - Provides less stringent design, qualification, and quality criteria and generally applies to instruments and controls designated for indicating system operating status. Category 3 - Provides design and qualification criteria that will ensure that high-quality, off-the-shelf instrumentation is obtained. Category 3 applies to backup and diagnostic instrumentation and is also used when the design requires state-of-the-art equipment, but equipment qualified to a higher category is not available. Category 3 instrumentation is non-safety related Process Control System The PCS processes the following post-accident monitoring channels: (1) Auxiliary Feedwater Flow (Type A, Cat. 1) (2) Charging Injection Header Flow (Type D, Cat. 2) (3) Letdown Outlet Flow (Type D, Cat. 2) (4) Makeup Flow-in (Type D, Cat. 2) (5) RHR Flow to RCS Cold Legs Temperature (Type D, Cat. 2) (6) RHR HX Outlet Flow (Type D, cat. 2) (7) RHR HX Outlet to Hot Legs 1 & 2 Flow (Type D, Cat. 2) (8) Safety Injection Pump Discharge Flow (Type D, Cat. 2) (9) Steam Generator Wide Range Level (Type A, Cat. 1) (10) Volume Control Tank Level Control (Type D, Cat. 2) DCPP UNITS 1 & 2 FSAR UPDATE 7.5-18 Revision 21 September 2013 (11) CCW Heat Exchanger Outlet Temperature (Type D, Cat. 2) (12) CCW Supply Headers A and B Flow (Type D, Cat. 2) (13) Condensate Storage Tank Level (Type A, Cat. 1) (14) Refueling Water Storage Tank Level (Type A, Cat. 1) (15) Accumulator Tank Pressure (Type D, Cat. 3) (16) Quench Tank (PRT) Level (Type D, Cat. 3) (17) Quench Tank (PRT) Temperature (Type D, Cat. 3) (18) Quench Tank (PRT) Pressure (Type D, Cat. 3) References 6 and 10 through 58 were used for design, verification, validation, and qualification of all or portions of the safety related PCS hardware and software (encompassing Triconex components, manual/auto hand stations, signal converters/isolators and loop power supplies). 7.5.3.7 NUREG-0737 (Items I.D.2, II.D.3, II.E.1.2, II.F.1, II.F.2, and III.A.1.2), November 1980 - Clarification of TMI Action Plan Requirements 7.5.3.7.1 Item I.D.2 - Plant Safety Parameter Display Console SPDS Display The primary SPDS display was designed to provide the control room operators with a concise format of critical plant variables to aid in determining the safety status of the plant. Parameter selection was made to address the five functions as listed in Section 7.5.2.10. The major types of possible accidents were evaluated to develop the minimum number of plant variables necessary to alert the operator of an abnormal condition. The parameters selected for each function were:
(1) Reactivity Control (a) Three ranges of flux indication from 120 percent full power to 1 count/second using all three ranges of nuclear instrumentation:
monitors neutron flux during all modes of operation. (b) Startup rate indication.
(c) "Control Rods In" alert, which warns the operator of a reactor trip without insertion of all control rods. DCPP UNITS 1 & 2 FSAR UPDATE 7.5-19 Revision 21 September 2013 (2) Reactor Core Cooling and Heat Removal (a) Subcooled margin, which is a derived variable based on RCS pressure and temperature inputs, indicates the degree of subcooling or superheat present. (b) Highest core exit thermocouple temperature monitors core exit temperature conditions. (c) Reactor vessel level, wide- or narrow-range depending on reactor coolant pump status, indicates lack of adequate core cooling. (d) Narrow-range steam generator level can be used to determine heat removal capability of the secondary system. (3) RCS Integrity (a) Reactor coolant system pressure can be used to monitor high-pressure conditions against design limits and can be used with cold leg temperature to monitor plant conditions against system nil ductility transition (NDT) limits. (b) Pressurizer level is actually used as an indication of inventory if RCS has been, or is, subcooled. However, it is an important parameter with RCS pressure for rapid determination of normal or expected plant status. (c) Cold leg temperature can be used with RCS pressure to monitor plant status with respect to system NDT limits. (4) Radioactivity Control (a) Containment radiation monitor indicates the release of radiation from the primary system to containment. (b) Vent gas and vent iodine monitors monitor radioactivity releases from the plant vent to the environment. (c) Main steam monitors indicate radioactivity released to the secondary system and/or atmosphere via steam generator tube leaks or tube failures. DCPP UNITS 1 & 2 FSAR UPDATE 7.5-20 Revision 21 September 2013 (5) Containment Integrity (a) Containment pressure monitors monitor actual pressure against design limit. (b) Containment Isolation Phase A and/or B alert informs the operator that a Phase A and/or B isolation signal has occurred and whether alignment of the isolation valves is complete. SPDS Display Groupings The parameters for the SPDS display were grouped in each of the five areas. Alarm setpoints were selected to duplicate the trip and alarm settings of the plant instrumentation, plant Technical Specification requirements, or limits specified in the plant manuals. Distinctive color coding is used on the display to alert control room personnel to an abnormal condition. If a parameter is within its normal range, the bar for that parameter on the display is green; it is displayed red if outside the specified limits.
SPDS Operation The basis for the location of the SPDS monitors in the control room was to ensure adequate visibility by the senior control room operator and not to impede movement in the control room. Console location is indicated in Figure 7.7-16. The color coding of the SPDS display readily enables the user to determine if a parameter on the display is within normal limits. In the case of an abnormal condition, the Emergency Evaluation Coordinator will typically be the prime user of the SPDS. SPDS Monitors There are two (2) SPDS displays in the control room, EOF, and TSC. Each screen has the critical safety function status shown at the top. 7.5.3.7.2 Item II.D.3 - Direct indication of relief and safety valve position The PSRV position indication system provides the necessary information in the control room to determine the position (open/close) of each of the three PSRVs as described in Section 7.5.2.8. 7.5.3.7.3 Item II.E.1.2 - Auxiliary Feedwater System Automatic Initiation and Flow Indication AFW flow indication is provided in the control room as described in Section 7.5.2.6. AFW automatic initiation is provided as described in Section 6.5. DCPP UNITS 1 & 2 FSAR UPDATE 7.5-21 Revision 21 September 2013 7.5.3.7.4 Item II.F.1 - Additional Accident Monitoring Instrumentation The safety-related display instrumentation includes the following subparts:
- Noble gas effluent radiological monitor - refer to Section 7.5.2.3;
- Provisions for continuous sampling of plant effluents for post-accident releases of radioactive iodines and particulates - refer to Section 7.5.2.3
- Onsite laboratory capabilities - refer to Sections 12.3.2 and 6.4.2.3;
- Containment high-range radiation monitor - refer to Section 7.5.2.1.5;
- Containment pressure monitor - refer to Section 7.5.2.1.2;
- Containment water level monitor - refer to Section 7.5.2.1.3; and
- Containment hydrogen concentration monitor - refer to Section 7.5.2.1.4 A discussion of each subpart is described in the indicated section. 7.5.3.7.5 Item II.F.2 - Instrumentation for Detection of Inadequate Core Cooling The instrumentation used for detection of inadequate core cooling is described in Section 7.5.2.2. 7.5.3.7.6 Item III.A.1.2 - Upgrade Emergency Support Facilities ERFDS is described in Section 7.5.2.9. All input parameters are routed from the Validyne data acquisition system to the Transient Recording System (TRS), which provides the data recall and storage for ERFDS. Each Unit's TRS acquires ERFDS data for both Units. The TRS servers provide data to PDN connected HSIs and DMZ servers. DMZ servers provide ERFDS data to DCPP LAN connected HSIs. PDN-connected HSIs with recall capability can display ERFDS data for either Unit. There are two dedicated ERFDS HSIs connected to the DCPP LAN in both the TSC and EOF. In addition, other selected DCPP LAN connected HSIs in the TSC and EOF may also view ERFDS and SPDS data. All data available on the ERFDS HSIs in the TSC and EOF is also available on the Plant Process Computer (PPC). The PPC HSIs in the TSC and EOF receive data from DMZ servers via PIN and the DCPP LAN. Additional parameters available for display by the PPC are specified in Table 7.5-6. Other parameters are also available to allow post-accident monitoring and analysis via the PPC. 7.
5.4 REFERENCES
- 1. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
- 2. IEEE Standard 323-1974, Qualifying Class 1E Equipment for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
DCPP UNITS 1 & 2 FSAR UPDATE 7.5-22 Revision 21 September 2013 3. IEEE Standard 344-1975, Recommended Practices for Seismic Qualification of Class 1E Equipment for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 4. Deleted in Revision 15.
- 5. Deleted in Revision 15.
- 6. Regulatory Guide 1.97, Rev. 3 Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant Conditions During and Following an Accident, USNRC, May 1983.
- 7. Deleted in Revision 21.
- 8. NUREG-0737, Supplement 1, Safety Parameter Display System Requirements for Nuclear Power Plants, USNRC, December 17, 1982.
- 9. NUREG-0696, Functional Criteria for Emergency Response Facilities, USNRC, February 1981.
- 10. IEEE Standard 279-1971, Criteria for Protection Systems for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 11. IEEE Standard 308-1971, Criteria for Class 1E Power Systems for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc. 12. IEEE Standard 323-2003, Qualifying Class 1E Equipment for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc. 13. IEEE Standard 336-1971, Installation, Inspection, and Testing Requirements for Power, Instrumentation, and Control Equipment at Nuclear Facilities, Institute of Electrical and Electronics Engineers, Inc.
- 14. IEEE Standard 338-1971, Criteria for the Periodic Surveillance Testing of Nuclear Power Generating Station Safety Systems, Institute of Electrical and Electronics Engineers, Inc.
- 15. IEEE Standard 344-1987, Recommended Practice for Seismic Qualification of Class 1E Equipment for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 16. IEEE Standard 384-1974, Criteria for Independence of Class 1E Equipment and Circuits, Institute of Electrical and Electronics Engineers, Inc.
- 17. IEEE Standard 730-1998, Software Quality Assurance Plans, Institute of Electrical and Electronics Engineers, Inc.
DCPP UNITS 1 & 2 FSAR UPDATE 7.5-23 Revision 21 September 2013 18. IEEE Standard 828-1990, Software Configuration Management Plans, Institute of Electrical and Electronics Engineers, Inc. 19. IEEE Standard 829-1983, Software Test Documentation, Institute of Electrical and Electronics Engineers, Inc.
- 20. IEEE Standard 830-1993, Recommended Practice for Software Requirements Specifications, Institute of Electrical and Electronics Engineers, Inc.
- 21. IEEE Standard 1008-1987, Software Unit Testing, Institute of Electrical and Electronics Engineers, Inc.
- 22. IEEE Standard 1012-1998, Software Verification and Validation, Institute of Electrical and Electronics Engineers, Inc.
- 23. IEEE Standard 1016-1987, Recommended Practice for Software Design Descriptions, Institute of Electrical and Electronics Engineers, Inc.
- 24. IEEE Standard 1016.1-1993, Guide to Software Design Descriptions, Institute of Electrical and Electronics Engineers, Inc.
- 25. IEEE Standard 1059-1993, Guide for Software Verification and Validation Plans, Institute of Electrical and Electronics Engineers, Inc.
- 26. IEEE Standard 1074-1995, Developing Software Life Cycle Processes, Institute of Electrical and Electronics Engineers, Inc.
- 27. IEEE Standard 1233-1998, Guide for Developing System Requirements Specifications, Institute of Electrical and Electronics Engineers, Inc.
- 28. IEEE Standard C62.41-1991, Recommended Practice for Surge Voltages in Low Voltage AC Power Circuits, Institute of Electrical and Electronics Engineers, Inc.
- 29. IEEE Standard C62.45-1992, Recommended Practice on Surge Testing for Equipment Connected to Low-Voltage (1000V and less) AC Power Circuits, Institute of Electrical and Electronics Engineers, Inc.
- 30. IEEE Standard 7-4.3.2-2003, Digital Computers in Safety Systems of Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 31. EPRI TR-106439, Guideline on Evaluation and Acceptance of Commercial-Grade Digital Equipment for Nuclear Safety Applications, Electric Power Research Institute, October, 1996.
- 32. EPRI TR-102323 Rev. 3, Guidelines for Electromagnetic Interference Testing in Power Plants, Electric Power Research Institute, November 2004.
DCPP UNITS 1 & 2 FSAR UPDATE 7.5-24 Revision 21 September 2013 33. EPRI TR-107330, Generic Requirements Specification for Qualifying a Commercially Available PLC for Safety-Related Applications in Nuclear Power Plants, Electric Power Research Institute, December 1996. 34. EPRI TR-102348 Rev. 1, Guideline on Licensing Digital Upgrades, Electric Power Research Institute, March 2002.
- 35. Regulatory Guide 1.100 Rev. 2, Seismic Qualification of Electrical and Mechanical Equipment for Nuclear Power Plants, USNRC, June 1988.
- 36. Regulatory Guide 1.105, Rev. 3, Setpoints for Safety-Related Instrumentation, USNRC, December 1999.
- 37. Regulatory Guide 1.152, Rev, 1, Criteria for Digital Computers in Safety Systems of Nuclear Power Plants, USNRC, January 1996.
- 38. Regulatory Guide 1.168, Verification, Validation, Reviews and Audits for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, February 2004.
- 39. Regulatory Guide 1.169, Configuration Management Plans for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997.
- 40. Regulatory Guide 1.170, Software Test Documentation for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997.
- 41. Regulatory Guide 1.171, Software Unit Testing for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997.
- 42. Regulatory Guide 1.172, Software Requirements Specifications for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997.
- 43. Regulatory Guide 1.173, Developing Software Life Cycle Processes For Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997
- 44. Regulatory Guide 1.180, Rev. 1, Guidelines for Evaluating Electromagnetic and Radio-Frequency Interference in Safety-Related Instrumentation and Control Systems, USNRC, October 2003.
- 45. Regulatory Guide 1.22, Periodic Testing of Protection System Actuation Functions, USNRC, February 1972.
DCPP UNITS 1 & 2 FSAR UPDATE 7.5-25 Revision 21 September 2013 46. Regulatory Guide 1.29, Rev. 3, Seismic Design Classification, USNRC, September 1978. 47. Regulatory Guide 1.30, Quality Assurance Requirements for the Installation, Inspection, and Testing of Instrumentation and Electric Equipment, USNRC, August 1972.
- 48. Regulatory Guide 1.47, Bypassed and Inoperable Status Indication for Nuclear Power Plant Safety Systems, USNRC, May 1973.
- 49. Regulatory Guide 1.89, Environmental Qualification of Certain Electric Equipment Important to Safety for Nuclear Power Plants, USNRC, November 1974.
- 50. NUREG-0800, Appendix 7.0-A, Rev. 5, Review Process for Digital Instrumentation and Control Systems, USNRC, March 2007.
- 51. BTP 7-14 Rev. 5, Guidance on Software Reviews for Digital Computer-Based Instrumentation and Control Systems, USNRC, March 2007.
- 52. BTP 7-18 Rev. 5, Guidance on the use of Programmable Logic Controllers in Digital Computer-Based Instrumentation and Control Systems, USNRC, March 2007.
- 53. MIL-STD-461E, Requirements for the Control of Electromagnetic Interference Emissions and Susceptibility, USDOD, August 1999 54. ANSI/ANS-4.5-1980, Criteria for Accident Monitoring Functions in Light-Water-Cooled Reactors, American Nuclear Society, January 1980 55. NEMA ICS 1-2000, Industrial Control and Systems: General Requirements, National Electrical Manufacturers Association, December 2008
- 56. NFPA 70 (NEC) 2002 National Electric Code, National Fire Protection Association, January 2002
- 57. IEC 61131-3 1993, Programming Industrial Automations Systems, International Electrotechnical Commission, December 1993
- 58. ISA-S67.04-1994, Setpoints for Nuclear Safety-Related Instrumentation, International Society of Automation, January 1994 7.5.5 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures.
DCPP UNITS 1 & 2 FSAR UPDATE 7.6-1 Revision 21 September 2013 7.6 ALL OTHER INSTRUMENTATION SYSTEMS REQUIRED FOR SAFETY This section provides a description and an analysis of: (a) residual heat removal (RHR) isolation valves, (b) the pipe break isolation system (PBIS), and (c) the anticipated transients without scram (ATWS) mitigation system actuation circuitry (AMSAC). The instrumentation and control power supply system is described and analyzed in Section 8.3.1.1.5. A discussion of the refueling interlocks is provided in Section 9.1. The fire detection and protection system is described in Section 9.5.1. 7.6.1 DESIGN BASES 7.6.1.1 General Design Criterion 2, 1967 - Performance Standards The RHR isolation valves and the PBIS are designed to withstand the effects of or are protected against natural phenomena, such as earthquakes, flooding, tornadoes, winds, and other local site effects. 7.6.1.2 General Design Criterion 11, 1967 - Control Room The RHR isolation valves, the PBIS, and the AMSAC system are designed to support actions to maintain and control the safe operational status of the plant from the control room. 7.6.1.3 General Design Criterion 12, 1967 - Instrumentation and Control Systems The RHR isolation valves and the PBIS have instrumentation and controls to monitor and maintain system variables within prescribed operating ranges. 7.6.1.4 10 CFR 50.49 - Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants The RHR isolation valves and associated components and PBIS components that require environmental qualification are qualified to the requirements of 10 CFR 50.49. 7.6.1.5 10 CFR 50.62 - Requirements for Reduction of Risk from Anticipated Transients Without Scrams (ATWS) Events for Light-Water-Cooled Nuclear Power Plants AMSAC meets the requirement of providing a system independent of the reactor trip system to initiate auxiliary feedwater flow and turbine trip under ATWS conditions. DCPP UNITS 1 & 2 FSAR UPDATE 7.6-2 Revision 21 September 2013 7.6.2 DESCRIPTION 7.6.2.1 Residual Heat Removal Isolation Valves There are two motor-operated gate valves in series in the inlet line from the reactor coolant system (RCS) to the RHR system. They are normally closed and can only be opened for RHR after RCS pressure is reduced below approximately 390 psig. In addition, one valve cannot open until the pressurizer vapor space temperature has been reduced to approximately 475°F (refer to Sections 5.6.2 and 5.5.6 for details of the RHR system.) RHR isolation valve control and indications are as follows: (1) One isolation valve, that nearest the RCS, is interlocked with a pressure signal to prevent its being opened whenever the RCS pressure is greater than the setpoint pressure (approximately 390 psig). This interlock is derived from one process control channel. (2) The other valve is similarly interlocked. Control signals are derived from a second process control channel. In order to both comply with IEEE 279-1971 (Reference 1) and to provide diversity, the permissive interlock to open this valve is satisfied when the pressurizer vapor space temperature is reduced to approximately 475°F and the RCS pressure is reduced below approximately 390 psig. This temperature control signal is derived from one process instrumentation protection channel. (3) Each isolation valve is provided with an independent alarm circuit from independent process protection channels that will actuate a common annunciator in the control room whenever the isolation valve is not 100 percent closed and RCS pressure is greater than approximately 435 psig. Procedures instruct the operators to stop RCS pressurization and close the isolation valves should this alarm condition occur during RCS pressurization with the RHR system removed from service. (4) The RHR suction valves interlock relays are powered from the solid state protection system (SSPS) output cabinets. To maintain the ability to open the RHR suction valves when the SSPS output cabinets are de-energized in Mode 6 or defueled, jumpers are used to lock-in the RHR suction valves open permissive. This defeats the applicable RHR system overpressurization/temperature protection. Jumper installation is limited to Mode 6 and defueled only. In the fire protection review, it was postulated that fire damage to electrical cables could cause both RHR suction line isolation valves to open. To prevent this, the power will be removed from each valve's motor operator by opening manual circuit breakers after the valves have been correctly positioned whenever RCS pressure is greater than 390 psig. Continuous indication that the RHR suction line isolation valves are in the correct position is provided for each valve. The control room valve position indicators are not DCPP UNITS 1 & 2 FSAR UPDATE 7.6-3 Revision 21 September 2013 disabled by opening the circuit breakers and removing power from the valves' motor operators. RHR isolation valve control, valve position indication, and annunciation are provided in the control room. 7.6.2.2 Pipe Break Isolation System The PBIS provides a means to detect and isolate breaks in high-energy lines in the auxiliary building. This system limits the postulated mass/energy release in affected compartments. This reduces the environmental effect on a number of PG&E Design Class I and Class 1E components in the area. There are two postulated pipe breaks that could affect Area K of the auxiliary building: (a) chemical and volume control system (CVCS) letdown line, and (b) auxiliary steam line. The PBIS provides an alarm and automatic isolation (redundant) of a break in the letdown line after the letdown isolation valves. An alarm and a switch for manual isolation are provided for the auxiliary steam line. A break in a high-energy line is detected by redundant temperature sensors monitoring ambient air temperature. Alarms are provided at predetermined setpoints, based on an analysis of the postulated breaks. Annunciation is provided in the control room. The Process Control System (PCS) processes the CVCS letdown line break temperature detector inputs and provides an output to the pipe break isolation logic. The PCS also processes the Auxiliary steam line area temperature detector inputs and provides control room indication and alarm. References 1, 2, 3 and 9 through 55 were used for design, verification, validation, and qualification of all or portions of the safety related PCS hardware and software (encompassing Triconex components, manual/auto hand stations, signal converters/isolators and loop power supplies). 7.6.2.3 ATWS Mitigation System Actuation Circuitry (AMSAC) DCPP has installed an AMSAC system in both Units. The system uses the standard Westinghouse design with the steam generator water level option. References 5 and 6 describe the generic AMSAC design. A functional logic diagram is shown in Figure 7.2-1, Sheet 17.
The AMSAC system trips the turbine, starts auxiliary feedwater, and isolates steam generator blowdown on coincidence of low-low steam generator water level in three out of four steam generators. The AMSAC system performs an important safety function if the plant's primary reactor protection system fails. Accordingly, to ensure the reliability of the system, all activities DCPP UNITS 1 & 2 FSAR UPDATE 7.6-4 Revision 21 September 2013 that could affect the quality of non-Class 1E AMSAC equipment shall be controlled as if the equipment were Class 1E. ATWS Mitigation System Actuation Circuitry indication is provided in the control room with annunciation windows. 7.6.3 SAFETY EVALUATION 7.6.3.1 General Design Criterion 2, 1967 - Performance Standards The PG&E Design Class I portion of the RHR isolation valves and pipe break isolation system are seismically designed and housed in seismically qualified buildings (containment structure and auxiliary building). These buildings are Design Class I (refer to Section 3.8) and designed to withstand the effects of winds and tornadoes (refer to Section 3.3), floods and tsunamis (refer to Section 3.4), external missiles (refer to Section 3.5), earthquakes (refer to Section 3.7), and other natural phenomena to protect the PG&E Design Class I portion of the RHR isolation valves and pipe break isolation system to ensure their safety-related functions and designs will be performed. 7.6.3.2 General Design Criterion 11, 1967 - Control Room Controls and instrumentation related to (a) RHR Isolation Valves, (b) PBIS and (c) anticipated transients without scram (ATWS) mitigation system actuation circuitry (AMSAC) which are designed to support actions to maintain and control the safe operational status of the plant from the control room are as follows: RHR Isolation Valves Each RHR isolation valve is provided with an independent alarm circuit from independent process protection channels that will actuate a common annunciator in the control room whenever the isolation valve is not 100 percent closed and RCS pressure is greater than approximately 435 psig. Continuous indication that the RHR suction line isolation valves are in the correct position is provided for each valve by control room valve position indicators that are not disabled by opening the circuit breakers and removing power from the valves' motor operators. Pipe Break Isolation System The PBIS provides an alarm and automatic isolation (redundant) of a break in the letdown line after the letdown isolation valves. An alarm and a switch for manual isolation are provided for the auxiliary steam line. DCPP UNITS 1 & 2 FSAR UPDATE 7.6-5 Revision 21 September 2013 A break in a high-energy line is detected by redundant temperature sensors monitoring ambient air temperature. Alarms are provided at predetermined setpoints, based on an analysis of the postulated breaks. The auxiliary steam line break isolation system provides an alarm based on any one of several high-temperature detectors. A switch is provided on the main control board to close the valves on lines that supply auxiliary steam to the auxiliary building. Since the auxiliary steam line is tied to both the Unit 1 and Unit 2 main steam lines, the crosstie through the auxiliary building to both main steam lines can be closed from either board on detection of high area temperature. Indication of area temperature is provided on the main control board to verify that isolation has occurred. Temperature indication is the only PG&E Design Class I function of the auxiliary steam line isolation system. ATWS Mitigation System Actuation Circuitry ATWS Mitigation System Actuation Circuitry indication is provided in the control room with annunciation windows. 7.6.3.3 General Design Criterion 12, 1967 - Instrumentation and Control Systems The RHR isolation valves and the PBIS have instrumentation and controls to monitor and maintain system variables within prescribed operating ranges as follows: Residual Heat Removal Isolation Valves Based on the scope definitions presented in IEEE-279-1971 (Reference 1) and IEEE 338-1971 (Reference 3), these criteria do not apply to the RHR isolation valve interlocks; however, in order to meet NRC requirements, and because of the possible severity of the consequences of loss of function, the requirements of IEEE-279-1971 are applied with the following comments.
(1) For the purpose of applying IEEE-279-71 (Reference 1) to this circuit, the following definitions are used: (a) Protection System - The two valves in series in each line and all components of their interlocking and closure circuits. (b) Protective Action - The automatic interlock of the RHR system isolation from the RCS pressure above RHR design pressure. (2) IEEE-279-71, Paragraph 4.10: The requirement for on-line test and calibration capability is applicable only to the actuation signal and not to the isolation valves, which are required to remain closed during power operation.
DCPP UNITS 1 & 2 FSAR UPDATE 7.6-6 Revision 21 September 2013 (3) IEEE-279-71, Paragraph 4.15: This requirement does not apply as the setpoints are independent of mode of operation and are not changed. Pipe Break Isolation System The CVCS letdown line break isolation system fully complies with IEEE-279-71 (Reference 1). Three high temperature detectors are provided. Each is powered from a separate Class 1E power source. A two-out-of-three logic is used with redundant logic trains so that a single failure will not prevent system operation, while at the same time the chance of spurious operation is limited. Redundancy is carried through to the final actuation devices.
The auxiliary steam line break isolation system provides an alarm based on any one of several high-temperature detectors. A switch is provided on the main control board to close the valves on lines that supply auxiliary steam to the auxiliary building. Since the auxiliary steam line is tied to both the Unit 1 and Unit 2 main steam lines, the crosstie through the auxiliary building to both main steam lines can be closed from either board on detection of high area temperature. Indication of area temperature is provided on the main control board to verify that isolation has occurred. Temperature indication is the only PG&E Design Class I function of the auxiliary steam line isolation system. A PG&E Design Class I backup is provided by use of the main steam line isolation system. Manual action is acceptable because of the relatively slow temperature transient that occurs due to this accident. There is sufficient time for the operator to verify that the break has been isolated before backup action is required. 7.6.3.4 10 CFR 50.49 - Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants The RHR isolation valves and associated components and PBIS components listed in the DCPP EQ Master List are qualified to the requirements of 10 CFR 50.49. Environmental qualification of the valves and wiring is discussed in Section 3.11. 7.6.3.5 10 CFR 50.62 - Requirements for Reduction of Risk from Anticipated Transients Without Scrams (ATWS) Events for Light-Water-Cooled Nuclear Power Plants The AMSAC system is independent and diverse from the reactor protection system. (Refer to Section 7.2 for a description of the reactor protection system). The AMSAC system trips the turbine, starts auxiliary feedwater, and isolates steam generator blowdown on coincidence of low-low steam generator water level in three out of four steam generators. This meets the requirements of 10 CFR 50.62. The Westinghouse AMSAC System has been analyzed by the Westinghouse owners group, and has been shown to maintain the reactor coolant system pressure boundary within the ASME Boiler and Pressure Vessel Code (Reference 7). Level C stress limits DCPP UNITS 1 & 2 FSAR UPDATE 7.6-7 Revision 21 September 2013 in the event of a Condition II event as described in Section 4.2. This is documented in Westinghouse Report NS-TMA-2182 (Reference 8). 7.
6.4 REFERENCES
- 1. IEEE Standard 279-1971, Criteria for Protection Systems for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 2. IEEE Standard 308-1971, Criteria for Class IE Electric Systems for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 3. IEEE Standard 338-1971, Trial-Use Criteria for the Periodic Testing of Nuclear Power Generating Station Protection Systems, Institute of Electrical and Electronics Engineers, Inc.
- 4. Deleted in Revision 21.
- 5. AMSAC Generic Design Change Package, WCAP-10858P-A, July 1987.
- 6. AMSAC Generic Design Package, Prescriptive Version, WCAP-11436, February 1987.
- 7. ASME Boiler and Pressure Vessel Code, Section III, Division I, Subsection NB-3224.
- 8. NS-TMA-2182, Westinghouse Letter (T. M. Anderson) to USNRC (S. H. Hanauer), ATWS Submittal, December 30, 1979.
- 9. IEEE Standard 323-2003, Qualifying Class 1E Equipment for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc. 10. IEEE Standard 336-1971, Installation, Inspection, and Testing Requirements for Power, Instrumentation, and Control Equipment at Nuclear Facilities, Institute of Electrical and Electronics Engineers, Inc. 11. IEEE Standard 344-1987, Recommended Practice for Seismic Qualification of Class 1E Equipment for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc. 12. IEEE Standard 384-1974, Criteria for Independence of Class 1E Equipment and Circuits, Institute of Electrical and Electronics Engineers, Inc. 13. IEEE Standard 730-1998, Software Quality Assurance Plans, Institute of Electrical and Electronics Engineers, Inc.
DCPP UNITS 1 & 2 FSAR UPDATE 7.6-8 Revision 21 September 2013 14. IEEE Standard 828-1990, Software Configuration Management Plans, Institute of Electrical and Electronics Engineers, Inc. 15. IEEE Standard 829-1983, Software Test Documentation, Institute of Electrical and Electronics Engineers, Inc. 16. IEEE Standard 830-1993, Recommended Practice for Software Requirements Specifications, Institute of Electrical and Electronics Engineers, Inc. 17. IEEE Standard 1008-1987, Software Unit Testing, Institute of Electrical and Electronics Engineers, Inc. 18. IEEE Standard 1012-1998, Software Verification and Validation, Institute of Electrical and Electronics Engineers, Inc. 19. IEEE Standard 1016-1987, Recommended Practice for Software Design Descriptions, Institute of Electrical and Electronics Engineers, Inc. 20. IEEE Standard 1016.1-1993, Guide to Software Design Descriptions, Institute of Electrical and Electronics Engineers, Inc. 21. IEEE Standard 1059-1993, Guide for Software Verification and Validation Plans, Institute of Electrical and Electronics Engineers, Inc. 22. IEEE Standard 1074-1995, Developing Software Life Cycle Processes, Institute of Electrical and Electronics Engineers, Inc. 23. IEEE Standard 1233-1998, Guide for Developing System Requirements Specifications, Institute of Electrical and Electronics Engineers, Inc. 24. IEEE Standard C62.41-1991, Recommended Practice for Surge Voltages in Low Voltage AC Power Circuits, Institute of Electrical and Electronics Engineers, Inc. 25. IEEE Standard C62.45-1992, Recommended Practice on Surge Testing for Equipment Connected to Low-Voltage (1000V and less) AC Power Circuits, Institute of Electrical and Electronics Engineers, Inc. 26. IEEE Standard 7-4.3.2-2003, Digital Computers in Safety Systems of Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc. 27. EPRI TR-106439, Guideline on Evaluation and Acceptance of Commercial-Grade Digital Equipment for Nuclear Safety Applications, Electric Power Research Institute, October, 1996. 28. EPRI TR-102323 Rev. 3, Guidelines for Electromagnetic Interference Testing in Power Plants, Electric Power Research Institute, November 2004. DCPP UNITS 1 & 2 FSAR UPDATE 7.6-9 Revision 21 September 2013 29. EPRI TR-107330, Generic Requirements Specification for Qualifying a Commercially Available PLC for Safety-Related Applications in Nuclear Power Plants, Electric Power Research Institute, December 1996. 30. EPRI TR-102348 Rev. 1, Guideline on Licensing Digital Upgrades, Electric Power Research Institute, March 2002. 31. Regulatory Guide 1.100 Rev. 2, Seismic Qualification of Electrical and Mechanical Equipment for Nuclear Power Plants, USNRC, June 1988. 32. Regulatory Guide 1.105, Rev. 3, Setpoints for Safety-Related Instrumentation, USNRC, December 1999. 33. Regulatory Guide 1.152, Rev, 1, Criteria for Digital Computers in Safety Systems of Nuclear Power Plants, USNRC, January 1996. 34. Regulatory Guide 1.168, Verification, Validation, Reviews and Audits for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, February 2004. 35. Regulatory Guide 1.169, Configuration Management Plans for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997. 36. Regulatory Guide 1.170, Software Test Documentation for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997. 37. Regulatory Guide 1.171, Software Unit Testing for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997. 38. Regulatory Guide 1.172, Software Requirements Specifications for Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997. 39. Regulatory Guide 1.173, Developing Software Life Cycle Processes For Digital Computer Software Used in Safety Systems of Nuclear Power Plants, USNRC, September 1997 40. Regulatory Guide 1.180, Rev. 1, Guidelines for Evaluating Electromagnetic and Radio-Frequency Interference in Safety-Related Instrumentation and Control Systems, USNRC, October 2003. 41. Regulatory Guide 1.22, Periodic Testing of Protection System Actuation Functions, USNRC, February 1972. DCPP UNITS 1 & 2 FSAR UPDATE 7.6-10 Revision 21 September 2013 42. Regulatory Guide 1.29, Rev. 3, Seismic Design Classification, USNRC, September 1978. 43. Regulatory Guide 1.30, Quality Assurance Requirements for the Installation, Inspection, and Testing of Instrumentation and Electric Equipment, USNRC, August 1972. 44. Regulatory Guide 1.47, Bypassed and Inoperable Status Indication for Nuclear Power Plant Safety Systems, USNRC, May 1973. 45. Regulatory Guide 1.89, Environmental Qualification of Certain Electric Equipment Important to Safety for Nuclear Power Plants, USNRC, November 1974. 46. Regulatory Guide 1.97, Rev. 3, Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident, USNRC, May 1983. 47. NUREG-0800, Appendix 7.0-A, Rev. 5, Review Process for Digital Instrumentation and Control Systems, USNRC, March 2007. 48. BTP 7-14 Rev. 5, Guidance on Software Reviews for Digital Computer-Based Instrumentation and Control Systems, USNRC, March 2007. 49. BTP 7-18 Rev. 5, Guidance on the use of Programmable Logic Controllers in Digital Computer-Based Instrumentation and Control Systems, USNRC, March 2007. 50. MIL-STD-461E, Requirements for the Control of Electromagnetic Interference Characteristics of Sub-systems and Equipment, USDOD, August 1999 51. ANSI/ANS-4.5-1980, Criteria for Accident Monitoring Functions in Light-Water-Cooled Reactors, American Nuclear Society, January 1980 52. NEMA ICS 1-2000, Industrial Control and Systems: General Requirements, National Electrical Manufacturers Association, December 2008 53. NFPA 70 (NEC) 2002 National Electric Code, National Fire Protection Association, January 2002 54. IEC 61131-3 1993, Programming Industrial Automations Systems, International Electrotechnical Commission, December 1993 55. ISA-S67.04-1994, Setpoints for Nuclear Safety-Related Instrumentation, International Society of Automation, January 1994 DCPP UNITS 1 & 2 FSAR UPDATE 7.6-11 Revision 21 September 2013 7.6.5 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures. DCPP UNITS 1 & 2 FSAR UPDATE 7.7-1 Revision 21 September 2013 7.7 CONTROL SYSTEMS NOT REQUIRED FOR SAFETY The general design objectives of the plant control systems are:
(1) To establish and maintain power equilibrium between primary and secondary systems during steady state unit operation (2) To constrain operational transients so as to preclude unit trip and reestablish steady state unit operation (3) To provide the reactor operator with monitoring instrumentation that indicates required input and output control parameters of the systems, and provides the operator with the capability of assuming manual control of the system 7.7.1 DESIGN BASES 7.7.1.1 General Design Criterion 11, 1967 - Control Room The plant control systems are designed to support actions to maintain and control the safe operational status of the plant from the control room or from an alternate location if control room access is lost due to fire or other causes. 7.7.1.2 General Design Criterion 12, 1967 - Instrumentation and Control Systems The plant control systems have instrumentation and controls to monitor and maintain variables within prescribed operating ranges. 7.7.1.3 General Design Criterion 13, 1967 - Fission Process Monitors and Controls The plant control systems are designed to monitor and maintain control over the fission process throughout core life and for all conditions that can reasonably be anticipated to cause variations in reactivity of the core, such as indication of position of control rods and concentration of soluble reactivity control poisons. 7.7.1.4 General Design Criterion 22, 1967 - Separation of Protection and Control Instrumentation Systems The plant control systems are designed such that protection functions are separated from control instrumentation functions to the extent that failure or removal from service of any control instrumentation system component or channel, or of those common to control instrumentation and protection circuitry, leaves intact a system satisfying all requirements for the protection channels.
DCPP UNITS 1 & 2 FSAR UPDATE 7.7-2 Revision 21 September 2013 7.7.1.5 General Design Criterion 27, 1967 - Redundancy of Reactivity Control The plant control systems are designed such that at least two independent reactivity control systems, preferably of different principles, are provided. 7.7.1.6 General Design Criterion 31, 1967 - Reactivity Control Systems Malfunction The rod control system is designed such that it is capable of sustaining any single malfunction, such as, unplanned continuous withdrawal (not ejection) of a control rod, without causing a reactivity transient which could result in exceeding acceptable fuel damage limits. 7.7.2 SYSTEM DESCRIPTION The plant control systems described in Sections 7.7.2.1 through 7.7.2.10 perform the following functions: (1) Reactor Control System (a) Enables the nuclear plant to accept a step load increase or decrease of 10 percent, and a ramp increase or decrease of 5 percent per minute, within the load range of 15 to 100 percent without reactor trip, steam dump, or pressurizer relief actuation, subject to possible xenon limitations. (b) Maintains reactor coolant average temperature Tavg within prescribed limits by creating the bank demand signals for moving groups of rod cluster control assemblies (RCCAs) during normal operation and operational transients. The Tavg auctioneer unit supplies signals to pressurizer water level control and steam dump control. (2) Rod Control System (a) Provides for reactor power modulation by manual or automatic control of control rod banks in a preselected sequence, and for manual operation of individual banks (b) Provides manual control of control banks to control the power balance between the top and bottom halves of the core (c) Provides systems for monitoring and indicating: 1. Provide alarms to alert the operator if the required core reactivity shutdown margin is not available due to excessive control rod insertion DCPP UNITS 1 & 2 FSAR UPDATE 7.7-3 Revision 21 September 2013 2. Display control rod position 3. Provide alarms to alert the operator in the event of control rod deviation exceeding a preset limit (3) Plant Control Signals for Monitoring and Indicating (a) Provide for measurement of reactor power level, axial power imbalance, and radial power imbalance (b) Sense and display control rod position (c) Provide warning to the operator of excessive rod insertion (d) Provide an alarm whenever an individual rod position signal deviates from the other rods in the bank by a preset limit (e) Provide rod bottom alarm for individual dropped rods (4) Plant Control System Interlocks (refer to Table 7.7-1) (a) Prevent further withdrawal of the control banks when signal limits are approached that predict the approach of a departure from nucleate boiling ratio (DNBR) limit or kW/ft limit (b) Initiate automatic turbine load runback on overpower or overtemperature (5) Pressurizer Pressure Control - Maintains or restores the pressurizer pressure to the nominal operating pressure +/-60 psi (which is well within reactor trip and relief and safety valve action setpoint limits) following normal operation transients that induce pressure changes by control (manual or automatic) of heaters and spray in the pressurizer. It also provides steam relief by controlling the power-operated relief valves (6) Pressurizer Water Level Control - Establishes, maintains, and restores pressurizer water level within specified limits as a function of the average coolant temperature. Changes in level are caused by coolant density changes induced by loading, operational, and unloading transients. Level changes required to maintain the level within prescribed limits are produced by charging flow control (manual or automatic), as well as by manual selection of letdown orifices DCPP UNITS 1 & 2 FSAR UPDATE 7.7-4 Revision 21 September 2013 (7) Steam Generator Water Level Control (a) Establishes and maintains the steam generator water level to within predetermined physical limits during normal operating transients (b) Restores the steam generator water level to within predetermined limits at unit trip conditions. Regulates the feedwater flow under operational transients to maintain the proper heat sink for the reactor coolant system (RCS). Steam generator water inventory control is manual or automatic through use of the digital feedwater control system (Reference 7). (8) Steam Dump Control (a) Permits the nuclear plant to accept a sudden loss of load without incurring reactor trip. Steam is dumped to the condenser and/or the atmosphere as necessary to accommodate excess power generation in the reactor during turbine load reduction transients (b) Ensures that stored energy and residual heat are removed following a reactor trip to bring the plant to equilibrium no-load conditions without actuation of the steam generator safety valves (c) Maintains the plant at no-load conditions and permits a manually controlled cooldown of the plant (9) Incore Instrumentation - Provides information on the neutron flux distribution and on the core outlet temperatures at selected core locations (10) Control Locations - Provide central control and monitoring locations to perform plant operations both inside and outside the control room 7.7.2.1 Reactor Control System The reactor control system enables the nuclear plant to follow load changes automatically, including the acceptance of step load increases or decreases of 10 percent, and ramp increases or decreases of 5 percent per minute within the load range of 15 to 100 percent without reactor trip, steam dump, or pressure relief, subject to possible xenon limitations. The system is also capable of restoring coolant average temperature to within the programmed temperature deadband following a change in load. Manual control rod operation may be performed at any time. The reactor control system controls the reactor coolant average temperature by regulation of control rod bank position. The reactor coolant loop average temperatures are determined from hot leg and cold leg measurements in each reactor coolant loop. There is an average coolant temperature (Tavg) computed for each loop, where: DCPP UNITS 1 & 2 FSAR UPDATE 7.7-5 Revision 21 September 2013 2icaveTihaveTiavgT41numbersloopi+== (7.7-1) The error between the programmed reference temperature (based on turbine impulse chamber pressure), and the highest of the average loop measured temperatures (which is then processed through a lead-lag compensation unit) from each of the reactor coolant loops, constitutes the primary control signal as shown in general in Figure 7.7-1, and in more detail on the functional diagrams shown in Figure 7.2-1, Sheet 9. The system is capable of restoring coolant average temperature to the programmed value following a change in load. The programmed coolant temperature increases linearly with turbine load from zero power to the full power condition. The Tavg auctioneer unit also supplies a signal to pressurizer level control and steam dump control, and rod insertion limit monitoring. An additional control input signal is derived from the reactor power versus turbine load mismatch signal. This additional control input signal improves system performance by enhancing response. The Tavg and Tref signals are also supplied to the plant computer for a Tavg vs Tref deviation alarm. 7.7.2.2 Rod Control System 7.7.2.2.1 Control Rod System The control rod system receives rod speed and direction signals from the reactor control system. The rod speed demand signal varies over the corresponding range from 5 to 45 inches per minute (8 to 72 steps/minute), depending on the magnitude of the error signal. The rod direction demand signal is determined by the positive or negative value of the error signal. Manual control is provided to move a control bank in or out at a prescribed fixed speed. When the turbine load reaches approximately 15 percent of rated load, the operator may select the AUTOMATIC mode, and rod motion is then controlled by the reactor control system. A permissive interlock C-5 (refer to Table 7.7-1), derived from measurements of turbine impulse chamber pressure, prevents automatic withdrawal when the turbine load is below 15 percent. In the AUTOMATIC mode, the rods are again withdrawn (or inserted) in a predetermined programmed sequence by the automatic programming equipment. The manual and automatic controls are further interlocked with the control interlocks (refer to Table 7.7-1). The shutdown banks are always in the fully withdrawn position during normal operation (except as required by surveillance testing) and are moved to this position prior to criticality. A reactor trip signal causes them to fall by gravity into the core. There are four shutdown banks. DCPP UNITS 1 & 2 FSAR UPDATE 7.7-6 Revision 21 September 2013 The control banks are the only rods that can be manipulated under automatic control. Each control bank is divided into two groups to obtain smaller incremental reactivity changes per step. All rod cluster control assemblies (RCCAs) in a group are electrically paralleled to move simultaneously. There is individual position indication for each RCCA. Power to rod drive mechanisms is supplied by two motor generator sets operating from two separate 480-V, three-phase buses. Each generator is the synchronous type and is driven by a 150 hp induction motor. The ac power is distributed to the rod control power cabinets through the two series-connected reactor trip breakers.
The variable speed rod control system rod drive programmer affords the ability to insert small amounts of reactivity at low speed to accomplish fine control of reactor coolant average temperature about a small temperature deadband, as well as furnishing control at high speed.
A summary of the RCCA sequencing characteristics is provided below:
(1) Two groups within the same bank are stepped so that the relative position of the groups will not differ by more than one step. (2) The control banks are programmed so that withdrawal of the banks is sequenced in the following order: control bank A, control bank B, control bank C, and control bank D. The programmed insertion sequence is the opposite of the withdrawal sequence; i.e., the last control bank withdrawn (bank D) is the first control bank inserted. (3) The control bank withdrawals are programmed so that when the first bank reaches a preset position, the second bank begins to move out simultaneously with the first bank. When the first bank reaches the top of the core, it stops, while the second bank continues to move toward its fully withdrawn position. When the second bank reaches a preset position, the third bank begins to move out, and so on. This withdrawal sequence continues until the unit reaches the desired power. The control bank insertion sequence is the opposite. (4) Overlap between successive control banks is adjustable between 0 to 50 percent (zero and 115 steps), with an accuracy of +/-1 step. (5) Rod speeds for either shutdown banks or control banks are capable of being controlled between a minimum of 8 steps per minute and a maximum of 72 steps per minute. 7.7.2.3 Plant Control Signals for Monitoring and Indicating The following sections describe the monitoring and/or indicating functions provided by:
DCPP UNITS 1 & 2 FSAR UPDATE 7.7-7 Revision 21 September 2013 (1) Nuclear instrumentation system (7.7.2.3.1) (2) Rod position (7.7.2.3.2) (3) Control bank rod insertion monitoring (7.7.2.3.3) (4) Rod deviation alarm (7.7.2.3.4) (5) Rod bottom alarm (7.7.2.3.5) 7.7.2.3.1 Monitoring Functions Provided by the Nuclear Instrumentation System The nuclear instrumentation system (NIS) is described below and in detail in Reference 1. However, the Reference 1, Section 3.7 Item e, Ion-Chamber-Current Recorders (NR-41 through NR-44) description does not apply.
The power range channels are important because of their use in monitoring power distribution in the core within specified safe limits. They are used to measure reactor power level, axial power imbalance, and radial power imbalance. These channels are capable of recording power excursions up to 200 percent of full power. Suitable alarms are derived from these signals as described below.
Basic power range signals are:
(1) Total current from a power range detector (four such signals from separate detectors). These detectors are vertical and have a neutron sensitive length of 10 feet (2) Current from the upper half of each power range detector (four such signals) (3) Current from the lower half of each power range detector (four such signals)
Derived from these basic signals are the following (including standard signal processing for calibration):
(1) Indicated nuclear power (four such) (2) Indicated axial flux imbalance, derived from upper half flux minus lower half flux (four such)
Alarm functions derived are as follows:
(1) Deviation (maximum minus minimum of four) in indicated nuclear power DCPP UNITS 1 & 2 FSAR UPDATE 7.7-8 Revision 21 September 2013 (2) Upper radial tilt (maximum to average of four) on upper half currents (3) Lower radial tilt (maximum to average of four) on lower half currents Axial Flux Difference (AFD) limits are found in the cycle specific COLR (Core Operating Limits Report) for each unit. Technical Specifications provide the limiting values for the QPTR (Quadrant Power Tilt Ratio) limit.
Nuclear power and axial flux imbalance are selectable for recording. Indicators are provided on the control board for nuclear power and for axial flux imbalance. 7.7.2.3.2 Rod Position Monitoring Two separate systems are provided to sense and display control rod position as described below: (1) Digital Rod Position Indication System (DRPI) - The digital rod position indication system measures the actual position of each rod using a detector that consists of 42 discrete coils mounted concentric with the rod drive pressure housing. The coils are located axially along the pressure housing on 3.75 inch spacing. They magnetically sense the entry and presence of the rod drive shaft through its centerline. The coils are interlaced into two data channels and are connected to the containment electronics (Data A and B) by separate multiconductor cables. Multiplexing is used to transmit the digital position signals from the containment electronics to the control board display unit. The digital position signal is displayed on the main control board by light emitting diodes (LEDs) for each control rod. The one LED illuminated in the column shows the position for that particular rod. By employing two separate channels of information, the digital rod position indication system can continue to function (at reduced accuracy) when one channel fails. Included in the system is a rod-at-bottom signal that operates a local alarm and a control room annunciator. (2) Demand Position Indication System - The demand position indication system counts pulses generated in the rod drive control system to provide a digital readout of the demanded bank position. The demand position indication and digital rod position indication systems are separate systems; each serves as a backup for the other. Operating procedures require the reactor operator to compare the demand and digital (actual) readings upon recognition of any apparent malfunction. Therefore, a single failure in rod position indication does not in itself lead the operator to take erroneous action in the operation of the reactor. DCPP UNITS 1 & 2 FSAR UPDATE 7.7-9 Revision 21 September 2013 The demand position indication system is described in detail in Reference 2. 7.7.2.3.3 Control Bank Rod Insertion Monitoring When the reactor is critical, the normal indication of reactivity status in the core is the position of the control bank in relation to reactor power (as indicated by RCS loop T) and coolant average temperature. These parameters are used to calculate insertion limits for the control banks. Two alarms are provided for each control bank:
(1) The low alarm alerts the operator of an approach to the rod insertion limits requiring boron addition by following normal procedures with the chemical and volume control system (CVCS). (2) The low-low alarm alerts the operator to take immediate action to add boron to the RCS by any one of several alternate methods.
The purpose of the control bank rod insertion monitor is to give warning to the operator of excessive rod insertion. The insertion limit maintains sufficient core reactivity shutdown margin following reactor trip, provides a limit on the maximum inserted rod worth in the unlikely event of a hypothetical rod ejection, and limits rod insertion so that acceptable nuclear peaking factors are maintained. Since the amount of shutdown reactivity required for the design shutdown margin following a reactor trip increases with increasing power, the allowable rod insertion limits must be decreased (the rods must be withdrawn further) with increasing power. Two parameters that are proportional to power are used as inputs to the insertion monitor. These are the T between the hot leg and the cold leg, which is a direct function of reactor power, and Tavg, which is programmed as a function of power.
The rod insertion monitor uses parameters for each control rod bank as follows: ZLLi = K1i Tauct + K2i (Tavg auct - Tno-load) + K3i (7.7-2) where:
ZLLi = maximum permissible insertion limit for affected control bank i = A, B, C, and D respectively (T)auct = highest T of all loops (Tavg)auct = highest Tavg of all loops K1i = constants chosen to maintain ZLLi actual limit based on physics K2i calculations K3i DCPP UNITS 1 & 2 FSAR UPDATE 7.7-10 Revision 21 September 2013 The control rod bank demand position Z is compared to ZLLi as follows: If Z - ZLLi D, a low alarm is actuated If Z - ZLLi E, a low-low alarm is actuated where:
D, E = constants as described below Since the highest values of Tavg and T are chosen by auctioneering, a conservatively high representation of power is used in the insertion limit calculation.
Actuation of the low alarm alerts the operator of an approach to a reduced shutdown reactivity situation. Plant procedures require the operator to add boron through the CVCS. Actuation of the low-low alarm requires the operator to initiate emergency boration procedures. The value for E is chosen so that the low-low alarm would normally be actuated before the insertion limit is reached. The value for D is chosen to allow the operator to follow normal boration procedures. Figure 7.7-2 shows a block diagram of the control rod bank insertion monitor. The monitor is shown in more detail in the functional diagrams in Figure 7.2-1, Sheet 9. In addition to the rod insertion monitor for the control banks, an alarm system is provided to warn the operator if any shutdown RCCA leaves the fully withdrawn position. Rod insertion limits are found in the cycle specific COLR for each unit and are established by: (1) Establishing the allowed rod reactivity insertion at full power, consistent with the purposes discussed above (2) Establishing the differential reactivity worth of the control rods when moved in normal sequence (3) Establishing the change in reactivity with power level by relating power level to rod position (4) Linearizing the resultant limit curve. All key nuclear parameters in this procedure are measured as part of the initial and periodic physics testing program. Any unexpected change in the position of the control bank under automatic control, or a change in coolant temperature under manual control, provides a direct and immediate indication of a change in the reactivity status of the reactor. In addition, samples are taken periodically of coolant boron concentration. Variations in concentration during core life provide an additional check on the reactivity status of the reactor including core depletion.
DCPP UNITS 1 & 2 FSAR UPDATE 7.7-11 Revision 21 September 2013 7.7.2.3.4 Rod Deviation Alarm The demanded and measured rod position signals are displayed on the control board. They are also monitored by the plant computer that provides an indication and an alarm whenever an individual rod position signal deviates from the other rods in the bank by a preset limit. The alarm can be set with appropriate allowance for instrument error and within sufficiently narrow limits to preclude exceeding core design hot channel factors. Rod alignment requirements are provided in the Technical Specifications. Figure 7.7-3 is a block diagram of the rod deviation comparator and alarm system. 7.7.2.3.5 Rod Bottom Alarm A rod bottom signal for each rod in the digital rod position system is used to operate a control relay, which generates the ROD BOTTOM ROD DROP alarm. 7.7.2.4 Plant Control System Interlocks The listing of the plant control system interlocks, along with the description of their derivations and functions, is presented in Table 7.7-1. It is noted that the designation numbers for these interlocks are preceded by C. The development of these logic functions is shown in the functional diagrams (Figure 7.2-1, Sheets 9 to 16). 7.7.2.4.1 Rod Stops Rod stops are provided to prevent abnormal power conditions that could result from excessive control rod withdrawal initiated by either a control system malfunction or operator violation of administrative procedures.
Rod stops are the C1, C2, C3, C4, and C5 control interlocks identified in Table 7.7-1. The C3 rod stop derived from overtemperature T, and the C4 rod stop derived from overpower T, are also used for turbine runback, which is discussed below. 7.7.2.4.2 Automatic Turbine Load Runback Automatic turbine load runback is initiated by an approach to an overpower or overtemperature condition. This prevents high power operation that might lead to an undesirable condition, which, if reached, would be protected by reactor trip. Turbine load reference reduction is initiated by either an overtemperature or overpower T signal. Two-out-of-four coincidence logic is used. A rod stop and turbine runback are initiated when: T > Trod stop DCPP UNITS 1 & 2 FSAR UPDATE 7.7-12 Revision 21 September 2013 For the overtemperature condition, an overtemperature T (OTT) turbine runback (TR) occurs when: i i54isetpointOTTRsetpointOTTs1s1T>++ Ti = Thavei - Tfci Thavei, Tfci, 4, and 5 are defined in Section 7.2.1.1.1.2 OTT isetpoint= -20 to +20% (usually zero)(a) OTTR setpointi= -20 to +20% (usually negative)(a) For the overpower condition, an overpower T (OPT), turbine runback occurs when: ii54isetpointOPTRsetpointTOPs1s1T>++ Ti = Thavei - Tfci Thavei, Tfci, 4, and 5 are defined in Section 7.2.1.1.1.2 OPT setpointi= -20 to +20% (usually zero)(a) OPTR setpointi= -20 to +20% (usually negative)(a) T setpoint refers to the overtemperature T reactor trip value and the overpower T reactor trip value for the two conditions. The turbine runback is continued until T is equal to or less than Trod stop. This function serves to maintain an essentially constant margin to trip.
(a) The measured T and T setpoints should be in percent of full power T. During initial plant operation, the T channels were calibrated to indicate 100 percent at 100 percent power such that the channels do not reflect minor flow variations between loops or minor variations from design flow. Provisions to allow this calibration must be available in each channel before the T signal is used for any alarm or protection function.
DCPP UNITS 1 & 2 FSAR UPDATE 7.7-13 Revision 21 September 2013 7.7.2.5 Pressurizer Pressure Control The RCS pressure is controlled by using either the heaters (in the water region) or the spray (in the steam region) of the pressurizer plus steam relief for large transients. The electrical immersion heaters are located near the bottom of the pressurizer. A portion of the heater group is proportional plus integral controlled to correct small pressure variations. These variations are due to heat losses, including heat losses due to a small continuous spray. The remaining (backup) heaters are turned on when the pressurizer pressure-controlled signal demands approximately 100 percent proportional plus integral heater power.
The spray nozzles are located on the top of the pressurizer. Spray is initiated when the pressure controller spray demand signal is above a given setpoint. The spray rate increases proportionally with increasing spray demand signal until it reaches a maximum value.
Steam condensed by the spray reduces the pressurizer pressure. A small continuous spray is normally maintained to reduce thermal stresses and thermal shock and to help maintain uniform water chemistry and temperature in the pressurizer.
Three power operated relief valves limit system pressure for large positive pressure transients. In the event of a large load reduction, not exceeding the design plant load reduction capability, the pressurizer power-operated relief valves might be actuated for the most adverse conditions; e.g., the most negative Doppler coefficient and the minimum incremental rod worth. The relief capacity of the power-operated relief valves is sized large enough to limit the system pressure to prevent actuation of high-pressure reactor trip for the above condition. A block diagram of the pressurizer pressure control system is shown in Figure 7.7-4. 7.7.2.6 Pressurizer Water Level Control The pressurizer operates by maintaining a steam cushion over the reactor coolant. As the density of the reactor coolant adjusts to the various temperatures, the steam-water interface moves to absorb the variations with relatively small pressure disturbances.
The water inventory in the RCS is maintained by the CVCS. During normal plant operation, charging flow varies to produce the flow demanded by the pressurizer water level controller. The pressurizer water level is programmed as a function of coolant average temperature, with the highest average temperature (auctioneered) being used. The pressurizer water level decreases as the load is reduced from full load. This is a result of coolant contraction following programmed coolant temperature reduction from full power to low power. The programmed level is designed to match as nearly as possible the level changes resulting from the coolant temperature changes. To control pressurizer water level during startup and shutdown operations, the charging flow is either automatically regulated with the controller setpoint adjusted to the desired level or DCPP UNITS 1 & 2 FSAR UPDATE 7.7-14 Revision 21 September 2013 manually regulated from the main control room. The pressurizer water level is programmed so that the water level is above the setpoint for heater cutout (refer to Section 7.7.3.2.2). A block diagram of the pressurizer water level control system is shown in Figure 7.7-5. 7.7.2.7 Steam Generator Water Level Control Each steam generator is equipped with a digital feedwater flow control system that maintains a constant steam generator (SG) water level over all power ranges. The feedwater controller regulates the main feedwater valve and the bypass feedwater valve by continuously comparing the feedwater flow signal, the water level signal, the programmed level, and the pressure-compensated steam flow signal. The digital feedwater control system has high and low power modes, determined by the feedwater flow measurement. The mode switch will automatically occur for a given loop when the feedwater flow in the subject loop reaches a predetermined valid value. In the low power mode, wide-range steam generator level provides a feedforward index to a single element feedwater control algorithm to anticipate nuclear steam supply system (NSSS) load changes. High power mode control is three element.
In both modes, feedwater temperature adjusts the level controller gain to account for variations in steam generator level dynamics with feedwater temperature. Narrow-range level is validated in both modes as the median value of the three isolated protection system level channels on each steam generator. As explained in WCAP-12221, this median signal selection (MSS) validation scheme meets the requirements of IEEE Std 279-1971 regarding separation of control and protection functions and control/protection interaction. The MSS was implemented to reduce the frequency of unscheduled trips resulting from equipment failure or human error during surveillance testing.
The feedwater pump speed is varied to maintain a programmed pressure differential between the average of the four steam generator steam line pressures and the feed pump discharge header. The speed demand controller continuously compares the actual differential pressure (DP) with a programmed DPref that is a linear function of steam flow. The speed demand controller then provides the feedpump speed demand to the feedpump speed control system. This system opens or closes the high pressure (HP) and low pressure (LP) governor valves for each pump to match the actual pump speed to the speed demand. The system also has a feature to back down or limit pump speed if pump discharge pressure is going high, to avoid feedpump trips on high discharge pressure due to feedwater system transients.
Continued delivery of feedwater to the steam generators is required as a sink for the heat stored and generated in the reactor following a reactor trip and turbine trip. An override signal closes the feedwater valves when the average coolant temperature is below a given temperature and the reactor has tripped. Manual override of the DCPP UNITS 1 & 2 FSAR UPDATE 7.7-15 Revision 21 September 2013 feedwater control system is available at all times in the absence of a main feedwater isolation signal. Refer to Reference 7 for additional details. A block diagram of the steam generator water level control system is shown in Figures 7.7-6 and 7.7-7. 7.7.2.8 Steam Dump Control The steam dump system was originally designed to accept a 100 percent net load loss exclusive of the station auxiliaries without reactor or turbine trip. However, as described in Section 5.2.1.5.1, the design basis load reduction transient has been revised to a 50 percent step load reduction.
The automatic steam dump system is able to accommodate this abnormal load reduction and to reduce the effects of the transient imposed upon the RCS. By bypassing main steam directly to the condenser, an artificial load is thereby maintained on the primary system. The rod control system can then reduce the reactor temperature to a new equilibrium value without causing overtemperature and/or overpressure conditions.
If the difference between the Tref based on turbine impulse chamber pressure and the lead/lag compensated auctioneered Tavg exceeds a predetermined amount, and the interlock mentioned below is satisfied, a demand signal will actuate the steam dump to maintain the RCS temperature within control range until a new equilibrium condition is reached.
To prevent actuation of steam dump on small load perturbations, an independent load reduction sensing circuit is provided. This circuit senses the rate of decrease in the turbine load as detected by the turbine impulse chamber pressure. The circuit is provided to unblock the dump valves when the rate of load reduction exceeds a preset value corresponding to a 10 percent step load decrease or a sustained ramp load decrease of 5 percent per minute.
A block diagram of the steam dump control system is shown in Figure 7.7-8. 7.7.2.8.1 Load Rejection Steam Dump Controller This circuit prevents a large increase in reactor coolant temperature following a large, sudden load decrease. The error signal is a difference between the lead-lag compensated auctioneered Tavg and the Tref, which is based on turbine impulse chamber pressure.
The Tavg signal is the same as that used in the reactor control system. The lead-lag compensation for the Tavg signal is to compensate for lags in the plant thermal response and in valve positioning. Following a sudden load decrease, Tref is immediately decreased and Tavg tends to increase, thus generating an immediate demand signal for DCPP UNITS 1 & 2 FSAR UPDATE 7.7-16 Revision 21 September 2013 steam dump. Since control rods are available in this situation, steam dump terminates as the error comes within the maneuvering capability of the control rods. 7.7.2.8.2 Reactor Trip Steam Dump Controller Following a reactor trip above 15 percent power, the load rejection steam dump controller is defeated and the reactor trip steam dump controller becomes active. Since control rods are not available in this situation, the demand signal is the error signal between the lead-lag compensated auctioneered Tavg and the no-load reference Tavg. When the error signal exceeds a predetermined setpoint, the dump valves are tripped open in a prescribed sequence. As the error signal reduces in magnitude, indicating that the RCS Tavg is being reduced toward the reference no-load value, the dump valves are modulated by the reactor trip controller to regulate the rate of removal of decay heat and thus gradually establish the equilibrium hot shutdown condition.
The error signal determines whether a group of valves is to be tripped open or modulated open. In either case, they are modulated when the error is below the trip-open setpoints. Some documentation may refer to the "reactor trip steam dump controller" as the "plant trip steam dump controller." 7.7.2.8.3 Steam Header Pressure Controller The removal of residual heat from the system is maintained by the steam header pressure controller (manually selected) that controls the amount of steam flow to the condensers. This controller operates a portion of the same steam dump valves to the condensers that are used during the initial transient following turbine/reactor trip or load reduction. This mode of operation is used during startup and cooldown (turbine not paralleled), and when operating the turbine below approximately 15 percent load. 7.7.2.9 Incore Instrumentation The incore instrumentation system consists of Chromel-Alumel thermocouples at fixed core outlet positions, and movable miniature neutron detectors that can be positioned at the center of selected fuel assemblies anywhere along the length of the fuel assembly vertical axis. The basic system for inserting these detectors is shown in Figure 7.7-9. Sections 1 and 2 of Reference 3 outline the incore instrumentation system in more detail. 7.7.2.9.1 Thermocouples The incore thermocouple system has been upgraded to safety-grade to qualify the system for postaccident monitoring. The upgraded system is discussed in Section 7.5.2.2.2. DCPP UNITS 1 & 2 FSAR UPDATE 7.7-17 Revision 21 September 2013 The plant computer is also used to monitor and display the incore thermocouple temperatures through Class 1E isolation devices provided in the upgraded thermocouple system. 7.7.2.9.2 Movable Neutron Flux Detector Drive System Miniature fission chamber detectors can be remotely positioned in retractable guide thimbles to provide flux mapping of the core. Flux mapping is described in Section 7.7.2.9.3 and the use of the data is described in Section 4.3.2.2. Refer to Reference 3 for neutron flux detector parameters. The stainless steel detector shell is welded to the leading end of helical wrap drive cable and to stainless steel sheathed coaxial cable. The retractable thimbles, into which the miniature detectors are driven, are pushed into the reactor core through conduits that extend from the bottom of the reactor vessel, down through the concrete shield area, and then up to a thimble seal table.
The thimbles are closed at the leading ends, are dry inside, and serve as the pressure barrier between the reactor water pressure and the atmosphere.
Mechanical seals between the retractable thimbles and the conduits are provided at the seal line. During reactor operation, the retractable thimbles are stationary. They are extracted downward from the core during refueling to avoid interference within the core. A space above the seal line is provided for the retraction operation.
The drive system for inserting the miniature detectors consists basically of drive assemblies, five-path rotary transfer operation selector assemblies, ten-path rotary transfer selector assemblies, and stop valves, as shown in Figure 7.7-9. These assemblies are described in Reference 3. The drive system pushes hollow helical wrap drive cables into the core with the miniature detectors attached to the leading ends of the cables and small-diameter sheathed coaxial cables threaded through the hollow centers back to the ends of the drive cables. Each drive assembly consists of a gear motor that pushes a helical, wrap-drive cable and a detector through a selective thimble path by means of a special drive box and includes a storage device that accommodates the total drive cable length.
The leakage detection and gas purge provisions are discussed in Reference 3.
Manual isolation valves (one for each thimble) are provided for closing the thimbles. When closed, the valve forms a 2500 psig barrier. The manual isolation valves are not designed to isolate a thimble while a detector/drive cable is inserted into the thimble. The detector/drive cable must be retracted to a position above the isolation valve prior to closing the valve.
A small leak would probably not prevent access to the isolation valves and, thus, a leaking thimble could be isolated during a hot shutdown. A large leak might require cold shutdown for access to the isolation valve. Access to the lower reactor cavity is provided through a small access room located below the incore instrumentation seal DCPP UNITS 1 & 2 FSAR UPDATE 7.7-18 Revision 21 September 2013 area. During normal operations and hot or cold shutdown, the access room will be pressurized as cooling air from the containment heating, ventilating, and air conditioning (HVAC) system is forced through the lower reactor cavity. A normally closed PG&E Design Class I pressure relief shutter damper in the access room may be opened manually to relieve the pressure through the damper opening into the larger containment volume, thus reducing the pressure against the entry door and facilitating personnel access to the room. This damper contains counterweight devices that permit it to be automatically forced open if the pressure in the access room rises above the maximum normal operating pressure. In the event of a loss-of-coolant accident (LOCA), this damper will open and act as one of several reactor cavity subcompartment pressure-relief flowpaths. 7.7.2.9.2.1 Flux Thimble Tube Acceptance Criteria The acceptance criteria to address nonlinear wear include capping or replacing flux thimble tubes that:
(1) showed greater than 25 percent wear per year; or
(2) had to be repositioned more than once; or
(3) had multiple wear scars with any two that measured greater than 40 percent; or (4) had to be repositioned more than a total of 6 inches; or (5) can not be inspected. For wear above 40 percent, an additional predictability allowance of 5 percent is adequate to ensure that actual nonlinear wear does not exceed projected wear.
Based on Reference 11, 80 percent acceptance criterion, including 5 percent predictability uncertainty and 10 percent for eddy current testing instrument and wear scar uncertainty, PG&E will use a net acceptance criterion of 65 percent (References 9 and 10). 7.7.2.9.3 Control and Readout Description The control and readout system provides means for inserting the miniature neutron detectors into the reactor core and withdrawing the detectors while plotting neutron flux versus detector position. The thimbles are distributed nearly uniformly over the core with about the same number of thimbles in each quadrant. The control system consists of two sections, one physically mounted with the drive units, and the other contained in the control room. Limit switches in each transfer device provide feedback of path selection operation. Each gear box drives an encoder for position feedback. One five-path operation selector is provided for each drive unit to insert the detector in one of DCPP UNITS 1 & 2 FSAR UPDATE 7.7-19 Revision 21 September 2013 five functional modes of operation. A ten-path rotary transfer assembly is a transfer device that is used to route a detector into any one of up to ten selectable paths. A common path is provided to permit cross-calibration of the detectors.
The control room contains the necessary equipment for control, position indication, and flux recording for each detector. Panels are provided to indicate the position of the detectors and to plot the flux level. Additional panels are provided for such features as drive motor controls, core path selector switches, plotting, and gain controls.
A flux mapping consists, briefly, of selecting (by panel switches) flux thimbles in given fuel assemblies at various core locations. The detectors are driven to the top of the core and stopped automatically. An x-y plot (position versus flux level) is initiated with the slow withdrawal of the detectors through the core from the top to a point below the bottom. Other core locations are selected and plotted in a similar manner. Each detector provides axial flux distribution data along the center of a fuel assembly. Various radial positions of detectors may then be compared to obtain a flux map for a region of the core.
Operating plant experience has demonstrated the adequacy of the incore instrumentation system in meeting the design bases stated. 7.7.2.10 Control Locations 7.7.2.10.1 Control Room A common control room for Unit 1 and Unit 2 contains the controls and instrumentation necessary for operating each unit's reactor and turbine-generator during normal and accident conditions. The control boards for Unit 2 are physically separated from the Unit 1 control boards. The control room is continuously occupied by licensed operating personnel during all operating conditions. It is also expected to be continuously occupied during all accident conditions. In the remote case where it is not possible to occupy the control room, alternative control locations are provided. The control room for each unit is designed to normally accommodate three to five people.
Sufficient shielding, distance, and containment integrity are provided to ensure that control room personnel are not subjected to doses under postulated accident conditions that would exceed 2.5 rem to the whole body or 30 rem to the thyroid, including doses received during both entry and exit. Control room ventilation is provided by a system capable of having a large percentage of recirculated air. The fresh air intake can be closed to limit the intake of airborne activity if monitors indicate that such action is appropriate. (A complete discussion of control room ventilation and air conditioning is presented in Chapter 9.)
Provisions are made so that plant operators can readily shut down and maintain the plant at hot standby by means of controls located outside the control room at central alternative locations, one for each unit, in the auxiliary building. DCPP UNITS 1 & 2 FSAR UPDATE 7.7-20 Revision 21 September 2013 Control room arrangement is shown in Figure 7.7-16. 7.7.2.10.1.1 Main Control Boards The control board design and layout presents all the controls, indicators, recorders, and alarms required for the safe startup, operation, and shutdown of the plant.
The control board layout is based on operator ease in relating the control board devices to the physical plant and determining, at a glance, the status of related equipment. This is referred to as providing a functional layout. Within the boundaries of a functional layout, modules are arranged in columns of control functions associated with separation trains defined for the reactor protection and Engineered Safety Features (ESF) systems. Teflon-coated wire is used within the module and between the module and the first termination point.
Modular train column wiring is formed into wire bundles and carried to metal wireways (gutters). Gutters are run into metal vertical wireways (risers). The risers are the interface between field wiring and control board wiring. Risers are arranged to maintain the separated routing of the field wire trays.
Alarms and annunciators on the control board provide warning of abnormal plant conditions that might lead to possible unsafe conditions. An annunciator terminal display and logger printer are also available in the main control room. Indicators and recorders are provided for observation of instantaneous and trend values of plant operating conditions. The charts are also used for record-keeping purposes. The bench-vertical control boards and control console are arranged to afford the operator instant access to the continuing controllers, recorders, and indicators, while allowing easy access to all the other controls. Refer to Figure 7.7-17. The control console houses the reactor controls, plant process computer terminals, turbine controls, and generator controls. These are arranged from left to right of an operator sitting at the console. Various trip switches and safety system indicators are also located on the console. Refer to Figures 7.7-18 and 7.7-19. The bench-vertical board houses the indicators, recorders, and controllers for ESF, primary plant, steam generator, turbine-generator, ventilation, diesel generator, and station electrical systems. These instruments, however, do not require the immediate attention of the operator as do those located on the control console. Refer to Figures 7.7-20 through 7.7-29.
Indication provided in the control room is discussed under the description of each individual system.
DCPP UNITS 1 & 2 FSAR UPDATE 7.7-21 Revision 21 September 2013 A process computer is used to provide supplementary information to the operator and to effectively assist in the operation of the NSSS. However, the analog indication provides the operator with ample information for safe operation without the computer system. The plant operator's computer panel is located on the control console for easy access to information. A plant process computer terminal display is also at this location. 7.7.1.10.1.1.1 Main Annunciator System The function of the main annunciator system is to monitor the status of selected plant equipment, systems and components, and to alert the Plant Operations Staff when an abnormal (alarm) condition is detected. The design of the main annunciator system is described in Section 3.10.2.9. A partial list of annunciator displays includes: (1) Loss of power supplies (2) SSPS trouble (3) SSPS in test (4) NIS detector loss (5) NIS channel test (6) NIS trip bypass (7) Hot shutdown panel open (8) Hot shutdown panel in control (9) Heat tracing fault (boric acid systems) (10) Radiation monitoring system failure (11) Radiation monitoring system in test (12) Diesel generator system (13) NIS reactor trip bypass (14) NIS rod stop bypass (15) Containment high-high pressure in test DCPP UNITS 1 & 2 FSAR UPDATE 7.7-22 Revision 21 September 2013 (16) Process protection system (PPS) channel in bypass (17) PPS channel set failure (18) PPS trouble (19) PPS RTD failure (20) Steam generator trip time delay timer actuated 7.7.2.10.1.2 Occupancy Requirements The control room area that is located in the auxiliary building at elevation 140 feet is designed for safe occupancy during abnormal conditions. Adequate shielding is used to maintain acceptable radiation levels in these areas under all normal operating and accident conditions. Radiation detectors and smoke detectors are provided to monitor the air intake and to initiate appropriate alarms and modes of operation. Air conditioning is included with provisions for the air to be recirculated through charcoal filters. Emergency lighting is provided in the control room area.
Fire hazards in the control room area are limited by the following:
(1) Noncombustible materials are used in construction where possible. Structural and finish materials (including furniture) for the control room and interconnecting areas have been selected on the basis of fire-retardant characteristics. Structural floors and exterior and interior walls are of reinforced concrete. Interior partitions within the control room areas incorporate concrete blocks, metal, and gypsum drywalls on metal studs.
The control room door frames and doors are metallic. Personnel doors are tight fitting and gasketed. Wood trim is not used. (2) Control cables are provided with an individual flame-retardant insulation over each single conductor and overall flame-retardant jacket over multiconductor cables. Cables throughout the installation have an exterior jacket that meets the Insulated Power Cable Engineers Association (IPCEA) requirements. Shielded instrumentation cables are provided with fire-resistant insulation and covered with a jacket of the same material. For a more detailed discussion on insulated cable construction, refer to Appendix 8.3B and Sections 8.3.1.2 and 8.3.1.4.3. (3) All pressure information is transmitted to the control room by electrical signals. No high-pressure fluids are piped into the control room. (4) Combustible materials are administratively controlled in the control room area. DCPP UNITS 1 & 2 FSAR UPDATE 7.7-23 Revision 21 September 2013 (5) Combustible supplies, such as logs, records, procedures, and manuals, are limited to the amounts required for current operation. (6) Detectors, sensitive to smoke and combustibles, are located in the vicinity of equipment cabinets and in the air conditioning system ducts. Fire detection alarms are provided in the control room with indication of which detector has been actuated. (7) All areas of the control room are readily accessible for fire extinguishing. (8) Adequate fire extinguishers and breathing apparatus that are easily accessible are provided and are to be used in accordance with National Fire Code (NFC) and National Fire Protection Association (NFPA) requirements. This equipment is provided to control any fire that could occur. (9) The control room is occupied at all times by an operator who has been trained in fire extinguishing techniques. Therefore, as a result of these provisions, any fires in the control room area are expected to be of such small magnitude that they could be extinguished by the operator using a hand fire extinguisher. The resulting smoke and vapors would be removed by the air conditioning system. The control room area is protected from infiltration of fire, smoke, or airborne radioactivity from outdoors and other areas of the auxiliary building by minimum leakage penetrations, weather-stripped doors, absence of outside windows, and the positive air pressure maintained in the area during normal and accident operation. A smoke detection device provides warning so that the operator can take steps to minimize any hazard (refer to Section 9.4). An area radiation detector monitors the control room for radiation content and will alert the operator to a high radioactivity level.
There are additional area radiation monitors in the auxiliary building and containment structures that provide the plant operator with a warning of unexpected high levels of radioactivity. Process monitors located in the residual heat removal exhaust ducts, component cooling water system, and liquid and gaseous radwaste systems also warn the operator of higher than expected concentrations of radioactivity. A plant vent gas process monitor is backed up by an air particulate monitor that can also sample the containment air and detect primary plant piping leaks within containment. For a complete discussion of the radiation monitoring system, refer to Section 11.4. Should the operator be forced to leave the control room, operating procedures require that the operator first trip the reactor and turbine-generator through manual trip switches located on the console. The operator would then verify the reactor trip and the turbine DCPP UNITS 1 & 2 FSAR UPDATE 7.7-24 Revision 21 September 2013 trip using approved plant procedures. After the reactor and turbine have tripped, plant controls automatically bring the plant to no-load condition after which it is necessary only to control the removal of decay heat and to maintain the water level in the pressurizer to maintain the plant in a safe condition. The operator would monitor and control these operations from the hot shutdown panel. 7.7.2.10.2 Hot Shutdown Panel The hot shutdown panel, which is located in the auxiliary building at elevation 100 feet (refer to Figure 7.7-30), contains control stations, switches, and indicators to: (1) Enable the operator to control water level in the steam generators with the auxiliary feedwater system (pumps and valves) (2) Display auxiliary feedwater pump discharge pressure, auxiliary feedwater flow, auxiliary feedwater source levels, steam generator pressure and level, pressurizer pressure and level, emergency borate flow, charging flow, source range neutron flux, and vital 4.16-kV bus voltages (3) Enable the operator to manipulate the steam dump system (10 percent) (4) Start and stop: (a) Component cooling water pumps (3) (b) Auxiliary saltwater pumps (2) (c) Charging pumps CCP1 and CCP2 (2) (d) Boric acid transfer pumps (2) (5) Control: (a) Emergency boric acid valve (1) (b) Charging flow control valves (2)
(c) Power-operated relief valves (PORVs) for the pressurizer (close only) (3) (d) RCP seal injection back-pressure (e) RCP seal injection pressure Boric acid concentration can be verified by reading the boron analyzer local indication or by sampling and analysis. DCPP UNITS 1 & 2 FSAR UPDATE 7.7-25 Revision 21 September 2013 Transfer switches are located on this panel to allow the operator to activate these controls individually. Except for motor-driven equipment, any transfer switch operation will cause annunciation in the control room. For motor-driven equipment, refer to Section 7.4.1.2.1(4).
The hot shutdown panel for plant shutdown and decay heat removal would be used only under abnormal conditions when access to the control room has been lost, and not during normal plant operation. The controls and indicators are located behind doors to reduce the possibility of misoperation during normal operation. An alarm is initiated when a panel door is opened.
The indications and controls listed above are required for remote shutdown and/or Title 10, U.S. Code of Federal Regulations, Part 50, Appendix R purposes. Other indications and controls located on the hot shutdown panel are for operator convenience (additional indications and controls required for remote shutdown and Appendix R are located elsewhere throughout the plant. 7.7.2.10.3 Auxiliary Building Control Board The auxiliary building control board, which is located in the auxiliary building at elevation 85 feet (refer to Figure 7.7-31), contains the controls, indicators, and alarm functions for: (1) CVCS (Unit 1) (2) Common panel for radioactive waste handling (3) CVCS (Unit 2) The control system provides a mimic for the radioactive waste handling system to aid the operator in setting up these systems. 7.7.2.10.4 Auxiliary Control Stations Local control panels are provided for systems and components that do not require full-time operator attendance or are not used on a continuous basis. Examples of such systems are the waste disposal system and the turbine-generator hydrogen cooling system. In these cases, however, appropriate alarms are activated in the control room to alert the operator to an equipment malfunction or approach to unsafe conditions. 7.7.3 SAFETY EVALUATION 7.7.3.1 General Design Criterion 11, 1967 - Control Room The plant is provided with a centralized control room common to both Unit 1 and Unit 2 that contains the controls and instrumentation necessary for operation of both units DCPP UNITS 1 & 2 FSAR UPDATE 7.7-26 Revision 21 September 2013 under normal and accident conditions. Should the operator be forced to leave the control room, operating procedures require that the operator first trip the reactor and turbine-generator through manual trip switches located on the console. Provisions are made so that plant operators can readily shut down and maintain the plant at hot standby by means of controls located outside of the control room. Refer to Section 7.7.2.10. Proper positioning of the control rods is monitored in the control room by bank arrangements of the individual column meters for each RCCA. A rod deviation alarm alerts the operator of a deviation of one RCCA from the other rack in that bank position. There are also insertion limit monitors with visual and audible annunciation. A rod bottom alarm signal is provided to the control room for each RCCA. Four out-of-core long ion chambers also detect asymmetrical flux distribution indicative of rod misalignment. 7.7.3.2 General Design Criterion 12, 1967 - Instrumentation and Control Systems The plant control systems are designed to ensure high reliability in any anticipated operational occurrences. Equipment used in these systems is designed and constructed to maintain a high level of reliability. 7.7.3.2.1 Step Load Changes without Steam Dump The plant control systems restore equilibrium conditions, without a trip, following a +/- 10 percent step change in load demand, over the 15 to 100 percent power range for automatic control. Steam dump is blocked for load decrease less than or equal to 10 percent. A load demand greater than full power is prohibited by the turbine control load limit devices. The plant control systems minimize the reactor coolant average temperature deviation during the transient within a given value, and restore average temperature to the programmed setpoint. Excessive pressurizer pressure variations are prevented by using spray and heaters and power operated relief valves in the pressurizer. The control systems limit nuclear power overshoot to acceptable values following a 10 percent increase in load to 100 percent. 7.7.3.2.2 Loading and Unloading Ramp loading and unloading of 5 percent per minute can be accepted over the 15 to 100 percent power range under automatic control without tripping the plant. The function of the control systems is to maintain the coolant average temperature as a function of turbine-generator load.
The coolant average temperature increases during loading and causes a continuous insurge to the pressurizer as a result of coolant expansion. The sprays limit the DCPP UNITS 1 & 2 FSAR UPDATE 7.7-27 Revision 21 September 2013 resulting pressure increase. Conversely, as the coolant average temperature is decreasing during unloading, there is a continuous outsurge from the pressurizer resulting from coolant contraction. The pressurizer heaters limit the resulting system pressure decrease. The pressurizer water level is programmed so that the water level is above the setpoint for heater cutout during the loading and unloading transients. The primary concern during loading is to limit the overshoot in nuclear power and to provide sufficient margin in the overtemperature T setpoint. 7.7.3.2.3 Load Reduction Furnished by Steam Dump System When a load reduction occurs, if the difference between the required temperature setpoint of the RCS and the actual average temperature exceeds a predetermined amount, a signal will actuate the steam dump to maintain the RCS temperature within control range until a new equilibrium condition is reached.
The reactor power is reduced at a rate consistent with the capability of the rod control system. Reduction of the reactor power is automatic. The steam dump flow reduction is as fast as RCCAs are capable of inserting negative reactivity.
The rod control system can then reduce the reactor temperature to a new equilibrium value without causing overtemperature and/or overpressure conditions. The steam dump steam flow capacity is nominally 40 percent of full load steam flow at full load steam pressure.
The steam dump flow reduces proportionally as the control rods act to reduce the average coolant temperature. The artificial load is therefore removed as the coolant average temperature is restored to its programmed equilibrium value. The dump valves are modulated by the reactor coolant average temperature signal. The required number of steam dump valves can be tripped quickly to stroke full open or modulate, depending on the magnitude of the temperature error signal resulting from loss of load. 7.7.3.2.4 Turbine-Generator Trip with Reactor Trip Whenever the turbine-generator unit trips at an operating power level above the protection system interlock P-9 setting, the reactor also trips. The unit is operated with a programmed average temperature as a function of load, with the full load average temperature significantly greater than the equivalent saturation pressure of the safety valve setpoint. The thermal capacity of the RCS is greater than that of the secondary system, and because the full load average temperature is greater than the no-load temperature, a heat sink is required to remove heat stored in the reactor coolant to prevent actuation of steam generator safety valves for a trip from full power. This heat sink is provided by the combination of controlled release of steam to the condenser and by makeup of cold feedwater to the steam generators.
DCPP UNITS 1 & 2 FSAR UPDATE 7.7-28 Revision 21 September 2013 The steam dump system is controlled from the reactor coolant average temperature signal whose setpoint values are programmed as a function of turbine load. Actuation of the steam dump is rapid to prevent actuation of the steam generator safety valves. With the dump valves open, the average coolant temperature starts to reduce quickly to the no-load setpoint. A direct feedback of temperature acts to close the valves proportionally to minimize the total amount of steam that is bypassed.
Following the turbine trip, the feedwater flow is cut off when the average coolant temperature decreases below a given temperature, or when the steam generator water level reaches a given high level.
Additional feedwater makeup is then controlled manually to restore and maintain steam generator water level, while ensuring that the reactor coolant temperature is at the desired value. Residual heat removal is maintained by the steam header pressure controller (manually selected) that controls the amount of steam flow to the condensers. This controller operates a portion of the same steam dump valves to the condensers that are used during the initial transient following turbine and reactor trip.
The pressurizer pressure and water level fall rapidly during the transient because of coolant contraction. Following the turbine and reactor trip, the pressurizer level control follows RCS Tavg to its no load value. If heaters become uncovered following the trip, they are deenergized and the CVCS will provide full charging flow to restore water level in the pressurizer. Heaters are then turned on to restore pressure to normal.
The steam dump feedwater control systems are designed to prevent the average coolant temperature from falling below the programmed no-load temperature following the trip to ensure adequate reactivity shutdown margin. 7.7.3.2.5 General Considerations The plant control systems prevent an undesirable condition in the operation of the plant that, if reached, would be protected by reactor trip. The description and analysis of this protection is covered in Section 7.2. Worst-case failure modes of the plant control systems are postulated in the analysis of off-design operational transients and accidents covered in Chapter 15, such as the following:
(1) Uncontrolled RCCA withdrawal from a subcritical condition (2) Uncontrolled RCCA withdrawal at power (3) RCCA misalignment (4) Loss of external electric load and/or turbine trip (5) Loss of all ac power to the station auxiliaries DCPP UNITS 1 & 2 FSAR UPDATE 7.7-29 Revision 21 September 2013 (6) Excessive heat removal due to feedwater system malfunctions (7) Excessive load increase (8) Accidental depressurization of the RCS These analyses show that a reactor trip setpoint is reached in time to protect the health and safety of the public under these postulated incidents, and that the resulting coolant temperatures produce a DNBR well above the applicable limit value (refer to Sections 4.4.1.1 and 4.4.2.3). Thus, there will be no cladding damage and no release of fission products to the RCS under the assumption of these postulated worst case failure modes of the plant control systems.
7.7.3.3 General Design Criterion 13, 1967 - Fission Process Monitors and Controls Overall reactivity control is achieved by the combination of soluble boron and RCCAs. Long-term regulation of core reactivity is accomplished by adjusting the concentration of boric acid in the reactor coolant. Short-term reactivity control for power changes is accomplished by the plant control systems that automatically move RCCAs. This system uses input signals including neutron flux, coolant temperature, and turbine load. 7.7.3.4 General Design Criterion 22, 1967 - Separation of Protection and Control Instrumentation Systems In some cases, it is advantageous to employ control signals derived from individual protection channels through isolation devices contained in the protection channel. As such, a failure in the control circuitry does not adversely affect the protection channel. Accordingly, this postulated failure mode meets the requirements of GDC 22, 1967. Test results have proved that failure of any single control system component or channel did not perceptibly disturb the protection side (input) of the devices.
Where a single random failure can cause a control system action that results in a generating station condition requiring protective action, and can also prevent proper action of a protection system channel designed to protect against the condition, the remaining redundant protection channels are capable of providing the protective action even when degraded by a second random failure. This meets the applicable requirements of Paragraph 4.7 of IEEE-279-1971 (Reference 5). Channels of the nuclear instrumentation that are used in the protective system are combined to provide nonprotective functions, such as signals, to indicating or recording devices; the required signals are derived through isolation devices.
These isolation devices are designed so that open or short circuit conditions, as well as the application of 120-Vac or 140-Vdc to the isolation side of the circuit, will have no DCPP UNITS 1 & 2 FSAR UPDATE 7.7-30 Revision 21 September 2013 effect on the input, or protection, side of the circuit. As such, failures on the nonprotective side of the system will not affect the individual protection channels. 7.7.3.5 General Design Criterion 27, 1967 - Redundancy of Reactivity Control Two independent reactivity control systems are provided for each reactor. These are RCCAs and chemical shim (boration). Overall reactivity control is achieved by the combination of soluble boron and RCCAs. Long-term regulation of core reactivity is accomplished by adjusting the concentration of boric acid in the reactor coolant. Short-term reactivity control for power changes is accomplished by the plant control systems that automatically move RCCAs. This system uses input signals including neutron flux, coolant temperature, and turbine load.
No single electrical or mechanical failure in the rod control system could cause the accidental withdrawal of a single RCCA from the partially inserted bank at full power operation. The operator could deliberately withdraw a single RCCA in the control bank; this feature is necessary in order to retrieve a rod, should one be accidentally dropped. In the extremely unlikely event of simultaneous electrical failures that could result in single withdrawal, rod deviation would be displayed on the plant annunciator, and the rod position indicators would indicate the relative positions of the rods in the bank. Withdrawal of a single RCCA by operator action, whether deliberate or by a combination of errors, would result in activation of the same alarm and the same visual indications.
The control and shutdown rods are arranged as follows: Control Shutdown Bank A Group 1 Bank A Group 1 Bank A Group 2 Bank A Group 2 Bank B Group 1 Bank B Group 1 Bank B Group 2 Bank B Group 2 Bank C Group 1 Bank C One Group Bank C Group 2 Bank D One Group Bank D Group 1 Bank D Group 2
The rods in a group operate in parallel through multiplexing thyristors. The two groups in a bank move sequentially so that the first group is always within one step of the second group in the bank. A definite schedule of actuation or deactuation of the stationary gripper, movable gripper, and lift coils of a mechanism is required to withdraw the RCCA attached to the mechanism. Since the four stationary grippers, movable grippers, and lift coils associated with the RCCAs of a rod group are driven in parallel, any single failure that could cause rod withdrawal would affect a minimum of one group of RCCAs. Mechanical failures are in the direction of insertion, or immobility.
DCPP UNITS 1 & 2 FSAR UPDATE 7.7-31 Revision 21 September 2013 The identified multiple failure involving the least number of components consists of open circuit failure of the proper two out of sixteen wires connected to the gate of the lift coil thyristors. The probability of open wire (or terminal) failure is 0.016 x 10-6 per hour by MIL HDBK-217A (Reference 6). These wire failures would have to be accompanied by failure, or disregard, of the indications mentioned above. The probability of this occurrence is therefore too low to have any significance.
Concerning the human element, to erroneously withdraw a single RCCA, the operator would have to improperly set the bank selector switch, the lift coil disconnect switches, and the in-hold-out switch. In addition, the three indications would have to be disregarded or ineffective. Such a series of errors would require a complete lack of understanding and administrative control. A probability number cannot be assigned to a series of errors such as these. Such a number would be highly subjective.
The rod position indication provides direct visual displays of each control rod assembly position. The plant computer alarms for deviation of rods from their banks. In addition, a rod insertion limit monitor provides an audible and visual alarm to warn the operator of an approach to an abnormal condition due to dilution. The low-low insertion limit alarm alerts the operator to follow emergency boration procedures. The facility reactivity control systems are such that acceptable fuel damage limits will not be exceeded in the event of a single malfunction of either system.
An important feature of the control rod system is that insertion is provided by gravity fall of the rods.
In all analyses involving reactor trip, the single, highest worth RCCA is postulated to remain untripped in its full out position. One means of detecting a stuck control rod assembly is available from the actual rod position information displayed on the control board. The control board position readouts for each rod give the plant operator the actual position of the rod in steps. The indications are grouped by banks (e.g., control bank A, control bank B, etc.) to indicate to the operator the deviation of one rod with respect to other rods in a bank. This serves as a means to identify rod deviation.
The plant computer monitors the actual position of all rods. Should a rod be misaligned from the other rods in that bank by more than 12 steps, the rod deviation alarm is actuated.
Misaligned RCCAs are also detected and alarmed in the control room via the flux tilt (QPTR) monitoring system that is independent of the plant computer. Isolated signals derived from the NIS are compared with one another to determine if a preset amount of deviation of average power has occurred. Should such a deviation occur, the comparator output will operate a bistable unit to actuate a control board annunciator. This alarm will alert the operator to a power imbalance caused by a DCPP UNITS 1 & 2 FSAR UPDATE 7.7-32 Revision 21 September 2013 misaligned rod. By use of individual rod position readouts, the operator can determine the deviating control rod and take corrective action. Thus, the design of the plant control systems meets the applicable requirements of GDC 12, 1967 and GDC 31, 1967. The boron system can compensate for all xenon burnout reactivity transients without exception. The rod system can compensate for xenon burnout reactivity transients over the allowed range of rod travel. Xenon burnout transients of larger magnitude must be accommodated by boration or by reactor trip (which eliminates the burnout).
The boron system is not used to compensate for the reactivity effects of fuel/water temperature changes accompanying power level changes.
The rod system can compensate for the reactivity effects of fuel/water temperature changes accompanying power level changes over the full range from full-load to no-load at the design maximum load uprate.
Automatic control of the rods is, however, limited to the range of approximately 15 to 100 percent of rating for reasons unrelated to reactivity or reactor safety.
The boron system (by the use of administrative measures) will maintain the reactor in the cold shutdown state, irrespective of the disposition of the control rods.
The overall reactivity control achieved by the combination of soluble boron and RCCAs meets the applicable requirements of GDC 27, 1967. 7.7.3.6 General Design Criterion 31, 1967 - Reactivity Control Systems Malfunction Reactor shutdown with control rods is completely independent of the control functions since the trip breakers interrupt power to the rod drive mechanisms regardless of existing control signals. The design is such that the system can withstand accidental withdrawal of control groups or unplanned dilution of soluble boron without exceeding acceptable fuel design limits. Thus, the design meets the applicable requirements of GDC 31, 1967. 7.
7.4 REFERENCES
- 1. J. B. Lipchak and R. A. Stokes, Nuclear Instrumentation System, WCAP-7669, April 1971.
- 2. A. E. Blanchard, Rod Position Monitoring, WCAP-7571, March 1971.
- 3. J. J. Loving, In-Core Instrumentation (Flux-Mapping System and Thermocouples), WCAP-7607, July 1971.
DCPP UNITS 1 & 2 FSAR UPDATE 7.7-33 Revision 21 September 2013 4. Deleted in Revision 21.
- 5. IEEE Standard 279-1971, Criteria for Protection Systems for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers, Inc.
- 6. MIL-HDBK-217A, Reliability Prediction of Electronic Equipment, December 1965.
- 7. Advanced Digital Feedwater Control System Input Signal Validation For Pacific Gas and Electric Co., Diablo Canyon Units 1 and 2, WCAP - 12221, April 1997 (W Proprietary Class 3) (PGE-97-540) and WCAP - 12222, March 1989 (W Proprietary Class 3).
- 8. Westinghouse Protection System Noise Tests, WCAP - 12358, Revision 2, October 1975 (W Proprietary Class 3).
- 9. PG&E Letter DCL-11-037, Response to Telephone Conference Calls Held on February 2 and 4, 2011, Between the U.S. Nuclear Regulatory Commission and Pacific Gas and Electric Company Concerning Responses to Requests for Additional Information Related to the Diablo Canyon Nuclear Power Plant, Units 1 and 2, License Renewal Application, dated March 25, 2011.
- 10. NRC Letter to PG&E, Safety Evaluation Report Related to the License Renewal of Diablo Canyon Nuclear Power Plant, Units 1 and 2, dated June 2, 2011 (Section 3.0.3.1.2). 11. Westinghouse Commercial Atomic Power (WCAP) - 12866, Bottom Mounted Instrumentation Flux Thimble Wear, January 1991 7.7.5 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.2-1 Sheet 1 of 3 Revision 20 November 2011 LIST OF REACTOR TRIPS
Reactor Trip Coinci-dence Logic
Interlocks
Comments
- 1. Power range high nuclear power 2/4 Manual block of low setting permitted by P-10 High and low settings; manual and automatic reset of low setting by P-10
- 2. Intermediate range high neutron flux 1/2 Manual block permitted by P-10 Manual block and automatic reset 3. Source range high neutron flux 1/2 Manual block permitted by P-6, interlocked with P-10 Manual block and automatic reset.
Automatic block above P-10 4. Power range high positive nuclear power rate 2/4 No interlocks - 5. Deleted in Revision 20. - - 6. OvertemperatureT 2/4 No interlocks - 7. Overpower T 2/4 No interlocks - 8. Pressurizer low pressure 2/4 Interlocked with P-7 Blocked below P-7 9. Pressurizer high pressure 2/4 No interlocks - DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.2-1 Sheet 2 of 3 Revision 20 November 2011 Reactor Trip Coinci-dence Logic Interlocks Comments
- 10. Pressurizer high water level 2/3 Interlocked with P-7 Blocked below P-7 11. Reactor coolant low flow 2/3 per loop Interlocked with P-7 and P-8 Low flow in one loop will cause a reactor trip when above P-8 and a low flow in two loops will cause a reactor trip with permissive P-7 enabled.
Blocked below P-7
- 12. Reactor coolant pump breakers open or redundant breaker open 2/4 Interlocked with P-7 Blocked below P-7 13. Reactor coolant pump bus under-voltage 1/2 on both buses Interlocked with P-7 Low voltage on all buses permitted below P-7 14. Reactor coolant pump bus under-frequency 2/3 on either bus Interlocked with P-7 Underfrequency on 2/3 sensors on either bus will trip reactor if above P-7 setpoint 15. Steam generator low- low level 2/3 per loop No interlocks -
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.2-1 Sheet 3 of 3 Revision 20 November 2011
Reactor Trip Coinci-dence Logic Interlocks Comments
- 16. Safety injection signal Coinci- dence with actuation of safety injection No interlocks (See Section 7.3 for engineered safety features actuation conditions) 17. Turbine trip- Reactor trip a. Low autostop oil pressure 2/3 Interlocked with P-9 Blocked below P-9 b. Turbine stop valve close 4/4 Interlocked with P-9 Blocked below P-9 18. Manual 1/2 No interlocks Reactor trip or Safety Injection Signal Actuation 19. Seismic 2/3 per axis No interlocks -
- 20. Reactor trip/bypass breakers 2/2 No interlocks Both trains 21. Automatic trip logic 1/2 No interlocks Both trains 22. General warning 2/2 No interlocks Both trains
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.2-2 Sheet 1 of 2 Revision 12 September 1998 PROTECTION SYSTEM INTERLOCKS Designation Derivation Function Power Escalation Permissives P-6 1/2 Neutron flux (intermediate range) above setpoint Allows manual block of source range reactor trip 2/2 Neutron flux (intermediate range) below setpoint Defeats the block of source range reactor trip P-10 2/4 Nuclear power (power range) above setpoint Allows manual block of power range (low setpoint) reactor trip
Allows manual block of intermediate range reactor trip and intermediate range rod stops (C-1)
Blocks source range reactor trip (backup for P-6)
Blocks subcooled margin monitor lo-margin alarm 3/4 Nuclear power (power range) below setpoint Defeats the block of power range (low set- point) reactor trip
Defeats the block of intermediate range reactor trip and intermediate range rod stops (C-1)
Input to P-7 Enables subcooled margin monitor lo-margin alarm DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.2-2 Sheet 2 of 2 Revision 12 September 1998 Designation Derivation Function Blocks of Reactor Trips P-7 3/4 Nuclear power (power range) below setpoint (from P-10), and 2/2 turbine impulse chamber pressure below setpoint (from P-13) Blocks reactor trip on: low flow or reactor coolant pump breakers open in more than one loop, undervoltage, underfrequency, pressurizer low pressure, and pressurizer high level P-8 3/4 Nuclear power (power range) below setpoint Blocks reactor trip on low flow in a single loop P-9 3/4 Neutron Flux (power range) below setpoint Blocks reactor trip on turbine trip P-13 2/2 Turbine impulse chamber pressure below setpoint Input to P-7
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.2-3 Sheet 1 of 4 Revision 21 September 2013 TRIP CORRELATION Trip Accident Tech Spec Section 15.2.1
- 1. Source range, high neutron flux (1) Uncontrolled RCCA bank withdrawal from a subcritical condition Not used in safety analysis Section 15.2.1
- 2. Intermediate range, high neutron flux (1) Uncontrolled RCCA bank withdrawal from a subcritical condition Not used in safety analysis Section 15.2.1
- 3. Power range, high nuclear power(low setpoint) (1) Uncontrolled RCCA bank withdrawal from a subcritical condition Table 3.3.1-1 Section 15.2.10 (2) Excessive heat removal due to feedwater system malfunction -- Section 15.4.6 (3) Rod ejection Table 3.3.1-1
Section 15.2.1
- 4. Power range, high nuclear power(high setpoint) (1) Uncontrolled RCCA bank withdrawal from a subcritical condition Table 3.3.1-1 Section 15.2.2 (2) Uncontrolled RCCA bank withdrawal at power -- Section 15.2.6 (3) Startup of an inactive reactor coolant loop -- Section 15.2.12 (4) Excessive load increase --
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.2-3 Sheet 2 of 4 Revision 21 September 2013 Trip Accident Tech Spec Section 15.2.14 (5) Accidental depressurization of the main system -- Section 15.4.6 (6) Rod ejection Table 3.3.1-1
Section 15.2.2
- 5. Power range high positive nuclear power rate (1) Uncontrolled RCCA bank withdrawal at power Table 3.3.1-1 Section 15.4.6 (2) Rod ejection Table 3.3.3-1
- 6. Deleted in Revision 20. -- --
Section 15.2.2 7. Overpower T (1) Uncontrolled RCCA bank withdrawal at power Table 3.3.1-1 Section 15.2.10 (2) Excessive heat due to feedwater system malfunction -- Section 15.2.12 (3) Excessive load increases --
Section 15.2.14 (4) Accidental depressurization of the main steam system -- Section 15.2.2 8. Overtemperature T (1) Uncontrolled RCCA bank withdrawal at power Table 3.3.1-1 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.2-3 Sheet 3 of 4 Revision 21 September 2013 Trip Accident Tech Spec Section 15.2.4 (2) Uncontrolled boron dilution
Section 15.2.7 (3) Loss of external electrical load and/or turbine trip Table 3.3.1-1 Section 15.2.10 (4) Excessive heat removal due to feedwater system malfunction -- Section 15.2.12 (5) Excessive load increase --
Section 15.2.13 (6) Accidental depressurization of the reactor coolant system -- Section 15.2.14 (7) Accidental depressurization of the main steam system -- Section 15.2.5
- 9. Reactor coolant low flow: (1) Partial loss of forced reactor coolant flow Table 3.3.1-1 Section 15.2.9 a. Undervoltage
- b. Underfrequency
- c. Low flow (1 of 4 loops) d. Low flow or pump breaker open (2 of 4 loops) (2) Loss of offsite power and main generator power to the station auxiliaries DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.2-3 Sheet 4 of 4 Revision 21 September 2013 Trip Accident Tech Spec Section 15.2.2
- 10. Pressurizer high pressure (1) Uncontrolled RCCA bank withdrawal at power Table 3.3.1-1 Section 15.2.7 (2) Loss of external electrical load and/or turbine trip -- Section 15.2.13 11. Pressurizer low water level (1) Accidental depressurization of the reactor coolant system Table 3.3.1-1 Section 15.2.2
- 12. Pressurizer high water level (1) Uncontrolled RCCA bank withdrawal at power Table 3.3.1-1 Section 15.2.7 (2) Loss of external electrical load and/or turbine trip -- Section 15.2.8
- 13. Steam generator low-low water level (1) Loss of normal feedwater Table 3.3.1-1
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 7.3-1 INSTRUMENTATION OPERATING CONDITION FOR ENGINEERED SAFETY FEATURES
No. Functional Unit No. of Channels No. of Channels To Trip 1. Safety Injection a. Manual 2 1
- b. High containment pressure 3 2
- c. Pressurizer low pressure 4 2 d. Low steam line pressure (lead/lag compensated) 12 (3/steam line) 2/3 in any steam line
- 2. Containment Spray
- a. Manual 2 2 coincident
- b. Containment pressure high-high 4 2 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.3-2 Sheet 1 of 2 Revision 11 November 1996 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION OPERATING CONDITIONS FOR ISOLATION FUNCTIONS
No. Functional Unit No. of Channels No. of Channels To Trip
- 1. Containment Isolation
- a. Safety injection (Phase A) (See Item No. 1 of Table 7.3-1) b. Containment pressure (Phase B) (See Item No. 2b of Table 7.3-1) c. Manual Phase A Phase B 2 (See Item No. 2a of Table 7.3-1) 1 2. Steam Line Isolation
- a. Low steam line pressure (lead/lag compensated) (See Item No. 1d of Table 7.3-1) b. High steam pressure rate (rate lag compensated) 12 (3/steam line) 2/3 in any steam line c. Containment pressure high- high 2/4 (See Item No. 2b of Table 7.3-1) d. Manual 1/loop 1/loop
- 3. Feedwater Line Isolation
- a. Safety injection (See Item No. 1 of Table 7.3-1) b. Steam generator high-high level 12 (3/steam generator) 2/3 in any steam generator DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.3-2 Sheet 2 of 2 Revision 11 November 1996
No. Functional Unit No. of Channels No. of Channels To Trip
- 4. Containment Ventilation Isolation
- a. Safety injection (See Item No. 1 of Table 7.3-1) b. Containment exhaust detectors 2 1 c. Containment isolation 1) Phase A (manual) 2 1 2) Phase B (manual) 2 2 3) Spray actuation (manual) 2 2
- 5. Control Room Air Intake Duct Isolation a. Safety injection (See Item No. 1 of Table 7.3-1) b. Control room air intake radiation monitor(a,b,c) 2 1 c. Manual 1 1 (a) Circuitry is not part of the safeguards system.
(b) Monitors on either unit control room air intake duct will initiate the isolation of both Units' control room ventilation systems. (c) Circuitry is not redundant.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.3-3 Sheet 1 of 2 Revision 20 November 2011 INTERLOCKS FOR ENGINEERED SAFETY FEATURES ACTUATION SYSTEM Designation Input Function Performed P-4 Reactor trip Actuates turbine trip
Closes main feedwater valves on Tavg below setpoint Prevents opening of main feedwater valves which were closed by safety injection or high steam generator water level Allows manual block of safety injection
Reactor not tripped Defeats the block of the automatic reactuation of safety injection P-11 2/3 Pressurizer pressure below setpoint Allows manual block of safety injection actuation on low pressurizer pressure signal Allows manual block of safety injection and steam line isolation on low steamline pressure. Steam line isolation on high negative rate steam line pressures is permitted when this manual block is accomplished 2/3 Pressurizer pressure above setpoint Defeats manual block of safety injection actuation Defeats manual block of safety injection and steam line isolation on low steam line pressure and defeats steam line isolation on high negative rate steam line pressure DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.3-3 Sheet 2 of 2 Revision 20 November 2011 Designation Input Function Performed P-12(a) 2/4 Tavg below setpoint Blocks steam dump condenser valves Allows manual bypass of steam dump block for the cooldown condenser valves only(b) Blocks trip open atmospheric dump
Blocks modulation of the dump valves according to sequence described in Sheet 10 of Figure 7.2-1 3/4 Tavg above setpoint Defeats the manual bypass of steam dump block Enables steam dump (all condenser dump valves except the cooldown dump valves) Enables steam dump (atmospheric dump valves) P-14 2/3 Steam generator water level above setpoint in any steam generator Closes all feedwater control valves Closes feedwater bypass valves
Trips all main feedwater pumps
Actuates turbine trip
(a) Circuitry is not part of safeguards system
(b) Operations procedures allow bypassing the P-12 interlock once the reactor is in Mode 3 and borated to cold shutdown conditions.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-1 Sheet 1 of 4 Revision 16 June 2005 MAIN CONTROL BOARD INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATOR (CONDITIONS II AND III EVENTS) Parameter No. of Channels Avail. Req. Range Available Indicated Accuracy(a) Indicator/ Recorder Purpose 1. Tcold &/or Thot (measured, wide-range) 1 Thot or 1 Tcold per loop 1 Thot & 1 Tcold any 2 operating loops 0 to 700°F +/-4% of full range All channels are recorded Ensure maintenance of proper cooldown rate and maintenance of proper relationship between system pressure and temperature for NDT considerations 2. Pressurizer Water Level 3 2 0 to 100% +/-6% span at 2250 psia All three channels indicated; one channel is selected for recording Ensure maintenance of proper reactor coolant inventory 3. RCS Pressure (wide-range) 2 2 0 to 3000 psig +/-4% of full range One channel indicated and one recorded Ensure maintenance of proper relationship between system pressure and temperature for NDT considerations 4. Containment Pressure (normal-range) 4 2 -5 to +55 psig +/-3.5% of full span All 4 are indicated Monitor containment conditions to indicate need for potential engineered safety features DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-1 Sheet 2 of 4 Revision 16 June 2005 Parameter No. of Channels Avail. Req. Range Available Indicated Accuracy(a) Indicator/ Recorder Purpose 5. Steam Line Pressure 3/Loop 2/Loop 0 to 1,200 psig+/-4.0% of full span All channels are indicated Monitor steam generator pressure conditions during hot shutdown and cooldown, and for use in recovery from steam generator tube ruptures 6. Steam Generator Water Level (wide-range) 1/Steam generato r N/A 0 to 100% +/-3% span(b) All channels recorded Ensure maintenance of reactor heat sink 7. Steam Generator Water level (narrow-range) 3/Steam generato r 2/Steam generator 0 to 100% +/-3% span(b) All channels indicated; the channels used for control are recorded Ensure maintenance of reactor heat sink 8. Intermediate Range Flux Level 2 N/A 8 decades logarithmic 10-11 to 10-3 amps overlapping the source range by 2 decades Indicator: -16.8% to +20.2% of input; Recorder: -24% to +30% of input(c) Both channels indicated. All channels are recorded. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-1 Sheet 3 of 4 Revision 16 June 2005 Parameter No. of Channels Avail. Req. Range Available Indicated Accuracy(a) Indicator/ Recorder Purpose 9. Power Range a.Uncompensated ion chamber current (top and bottom uncompensated ion chambers) 4 N/A 0 to 120% of full power current +/-1% of full span All 8 current signals indicated b. Average flux of the top and bottom ion chambers 4 N/A 0 to 120% of full power +/-3% of full power for indication, +/-2% for recording All 4 channels indicated. All channels are recorded. c. Average flux of the top and bottom ion chambers 4 N/A 0 to 200% of full power +/-2% of full power to 120% +/-6% of full power to 200% All 4 channels recorded d. Flux difference of the top and bottom ion chambers 4 N/A -30 to +30% +/-4% All 4 channels indicated. All channels are recorded. ______________________ (a) Includes channel accuracy and environmental effects during normal plant operation, but does not include post-accident environmental effects. Changes which are within the stated accuracy band or within the reading accuracy of the indicator are not reflected in this table. Actual values are found in design documents. The instrumentation accuracies listed are typical indicator values and are not directly comparable to the channel accuracies utilized in the Chapter 15 analysis. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-1 Sheet 4 of 4 Revision 16 June 2005 (b) Instrument accuracy only. The accuracy statement does not include the effect of density changes in the vessel.
(c) Does not include instrument drift allowance.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-2 Sheet 1 of 4 Revision 17 November 2006 MAIN CONTROL BOARD INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATOR (CONDITION IV EVENTS) Parameter No. of Channels Avail. Req. Range Available Indicated Accuracy(a) Indicator/ Recorder Purpose
- 1. Containment Pressure (normal range) 4 2 -5 to +55 psig +/-3.5% of full span All 4 are indicated Monitor post-LOCA containment conditions
- 2. Containment Sump Level (NR) 2 1 88.5 to 96.6 ft El. +/-6.5% of full span(e) Indicator Assess recirculation mode and general conditions
- 3. Refueling Water Storage Tank Water Level 3 2 0 to 100% of span +/-4.5% of level span All 3 are indicated and alarmed Ensure that water is flowing to the safety injection system after a LOCA, and determine when to shift from injection to recirculation mode
- 4. Steam Generator Water Level (narrow-range) 3/Steam generator 2/Steam generator 0 to 100% +/-3% of level span(b)(c) All channels indicated; the channels used for control are recorded Detect steam generator tube rupture; monitor steam generator water level following a feedwater line break DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-2 Sheet 2 of 4 Revision 17 November 2006 Parameter No. of Channels Avail. Req. Range Available Indicated Accuracy(a) Indicator/
Recorder Purpose
- 5. Steam Generator Water Level (wide range) 1/Steam generator N/A 0 to 100% +/-3% of level span(b)(c) All channels are recorded Detect steam generator tube rupture; monitor steam generator water level following a feedwater line break
- 6. Steam Line Pressure 3/Steam line 2/Steam line 0 to 1,200 psig +/-4% of full scale All channels are indicated Monitor steam line pressures following steam generator tube rupture or steam line break
- 7. Steam Line Flow 2/Steam line N/A 0 to 4.5 million pounds/hour Within +/-10% span when flow >25% All channels are indicated; the channels used for control are recorded Indication purposes only 8. Pressurizer Water Level 3 2 0 to 100% Indicate that level is somewhere between 0 and 100% of span All three channels are indicated, and one channel is selected for recording Indicate that water has returned to the pressurizer following cooldown after steam generator tube rupture or steam line break
- 9. Pressurizer Pressure 4 3 1250 to 2500 psig +/-3.5% of full span All channels indicated, one channel recordedDetect steam generator tube breaks DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-2 Sheet 3 of 4 Revision 17 November 2006 Parameter No. of Channels Avail. Req. Range Available Indicated Accuracy(a) Indicator/
Recorder Purpose
- 10. Intermediate Range Flux Level 2 N/A Logarithmic 10-11 to 10-3 amps Indicator: -16.8% to +20.2% of input; Recorder: -24% to
+30% of input(d) Both channels indicated. All channels are recorded. Assess rod cluster control assembly ejection 11. Power Range
- a. Un-compensated ion chamber current (top and bottom un-compensated ion chambers) 4 N/A 0 to 120% of full power current +/-1% of full span All 8 current signals indicated Assess rod cluster control assembly ejection b. Average flux of the top and bottom ion chambers 4 N/A 0 to 120% of full power +/-3% of full power for indication, +/-2% for recording All four channels indicated.
All channels are recorded. Assess rod cluster control assembly ejection (a) Includes channel accuracy and environmental effects for normal operation. Does not include post-accident environmental effects. The instrumentation accuracies listed are typical indicator values and are not directly comparable to the channel accuracies utilized in the Chapter 15 analysis. Changes which are within the stated accuracy band or within the reading accuracy of the indicator are not reflected in this table. Actual values are found in design documents. (b) For the steam break, when the water level channel is exposed to a hostile environment, the accuracy required can be relaxed. The indication need only convey to the operator that water level in the steam generator is somewhere between the narrow-range steam generator water level taps. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-2 Sheet 4 of 4 Revision 17 November 2006 (c) Instrument accuracy only. The accuracy statement does not include the effect of density changes in the vessel, mid-deck plate delta-P, and other process measurement or environmental uncertainties. (d) Does not include instrument drift allowance.
(e) Stated uncertainty applied to channel safety function as it is used in accordance with the EOPs. Channel uncertainty at 100% span is within +/-10% span.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-3 Sheet 1 of 8 Revision 18 October 2008 CONTROL ROOM INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATOR TO MONITOR SIGNIFICANT PLANT PARAMETERS DURING NORMAL OPERATION Parameter No. of Channels Available Indicated Range Indicator/ Accuracy(a) Indicator/Recorder Location Notes Nuclear Instrumentation
- 1. Source Range
- a. Count rate 2 1 to 106 counts/sec +/-7% of the linear full scale analog voltage Both channels indicated.
All channels are recorded. Control console Deenergize above P-6 b. Startup rate 2 -0.5 to 5.0 decades/min +/-7% of the linear full scale analog voltage Both channels indicated Control console Deenergize above P-6 2. Intermediate Range a. Flux level 2 8 decades logarithmic 10-11 to 10-3 amps overlapping the source by 2 decades Indicator: -16.8% to +20.2% of input; Recorder: -24% to +30% of input Both channels indicated. All channels are recorded. Control console b. Startup rate 2 -0.5 to 5.0 decades/min +/-7% of the linear full scale analog voltage Both channels indicated Control console DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-3 Sheet 2 of 8 Revision 18 October 2008 Parameter No. of Channels Available Indicated Range Indicator/ Accuracy(a) Indicator/Recorder Location Notes
- 3. Power Range a. Uncompensated ion chamber current (top and bottom uncompensated ion chambers) 4 0 to 5 mA +/-1% of full span All 8 current signals indicated NIS racks in control room c. Average flux of the top and bottom ion chambers 4 0 to 120% of full power +/-3% of full power for indication, +/-2% for recording All 4 channels indicated.
All channels are recorded. Control console d. Average flux of the top and bottom ion chambers 4 0 to 200% of full power +/-2% of full power to 120% +/-6% of full power to 200% All 4 channels recorded Control board e. Flux difference of the top and bottom ion chambers 4 -30 to +30% +/-4% All 4 channels indicated. All channels are recorded. Control console Reactor Coolant System 1. Taverage (measured) 1/Loop 530 to 630°F +/-4°F All channels indicated; auctioneered high is recorded Control console DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-3 Sheet 3 of 8 Revision 18 October 2008 Parameter No. of Channels Available Indicated Range Indicator/ Accuracy(a) Indicator/Recorder Location Notes 2. T (measured) 1/Loop 0 to 150% of full power T +/-4% of full power T All channels indicated. One channel is selected for recording Control console Tcold or Thot (measured, wide-range) 1-Thot and 1-Tcold per loop 0 to 700°F +/-4% Both channels recorded Control board 3. Overpower T Setpoint 1/Loop 0 to 150% of full power T +/-4% of full power T All channels indicated. One channel is selected for recording Control board & control console 4. Overtemperature T Setpoint 1/Loop 0 to 150% of full power T +/-4% of full power T All channels indicated. One channel is selected for recording Control board & control console 5. Pressurizer Pressure 4 1250 to 2500 psig +/-3.5% of span All channels indicated, controlling channel recorded Control board & control console 6. Pressurizer Level 3 0 to 100% +/-6.1% span at 2250 psia(b) All channels indicated. One channel is selected for recording Control board & control console Two-pen recorder used, second pen records reference level signal DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-3 Sheet 4 of 8 Revision 18 October 2008 Parameter No. of Channels Available Indicated Range Indicator/ Accuracy(a) Indicator/Recorder Location Notes
- 7. Primary Coolant Flow 3/Loop 0 to 120% of rated flow Repeatability of +/-4% of full flow All channels indicated Control board 8. Reactor Coolant Pump Motor Amperes 1/Loop 0 to 400 amp +/-2% All channels indicated Control board One channel for each motor 9. RCS Pressure Wide-range 2 0 to 3000 psig +/-4% One channel indicated and one recorded Control board 10. Pressurizer Safety Relief Valve Position 3 Open/closed NA All channels indicated Vertical board Reactor Control System
- 1. Demanded Rod Speed 1 8 to 72 steps/min +/-2 steps/min The one channel is indicated Control console 2. Auctioneered Taverage 1 530 to 630°F +/-4°F The one channel is recorded Control console The highest of the four Tavg channels into the auctioneer will be passed to the recorder 3. Treference 1 530 to 630°F +/-4°F The one channel is recorded Control console 4. Control Rod Position If system not available, borate and sample accordingly DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-3 Sheet 5 of 8 Revision 18 October 2008 Parameter No. of Channels Available Indicated Range Indicator/
Accuracy(a) Indicator/Recorder Location Notes a. Number of steps of demanded rod withdrawal 1/group 0 to 231 steps +/-1 step Each group is indicated. Control console These signals are used in conjunction with the measured position signals (4b) to detect deviation of any individual rod from the demanded position. A deviation will actuate an annunciator. An alarm annunciator is actuated when the last rod control bank to be withdrawn reaches the withdrawal limit, when any rod control bank reaches the low insertion limit, and when any rod control bank reaches the low-low insertion limit b. Full-length rod measured position 1 for each rod 0 to 228 steps +/-3 steps at full accuracy, +/-6 steps at 1/2 accuracy Each rod position is indicated Control board Containment System
- 1. Containment Pressure (normal range) 4 -5 to +55 psig +/-3.5% of full span All 4 channels indicated Control board DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-3 Sheet 6 of 8 Revision 18 October 2008 Parameter No. of Channels Available Indicated Range Indicator/
Accuracy(a) Indicator/Recorder Location Notes
- 2. Containment Pressure (narrow range) 1 -1 to +1.5 psig+/-0.1 psi Recorded Control board Feedwater and Steam Systems 1. Auxiliary Feedwater Flow 1/Steam generator 0 to 300 gpm +/-10% of full span All channels indicated Control board One channel to measure the flow to each steam generator
- 2. Steam Generator Level (narrow-range) 3/Steam generator 0 to 100% +/-3% of P span (hot) (b) All channels indicated. The channels used for control are trended indications. Control board &
control console 3. Steam Generator Level (wide-range) 1/Steam generator full load level 0 to 100% +/-3% of P span (hot) (b) All channels recorded Control board 4. Programmed Steam Generator Signal 1 for 4 Steam generators 0 to 100% +/-4% One channel indicated Control board 5. Main Feedwater Flow 2/Steam generator 0 to 4.5 million pounds per hour Within +/-10% span when flow >25% All channels indicated. The channels used for control are trended indications. Control board DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-3 Sheet 7 of 8 Revision 18 October 2008 Parameter No. of Channels Available Indicated Range Indicator/ Accuracy(a) Indicator/Recorder Location Notes
- 6. Magnitude of Signal Controlling Main and Bypass Feedwater Control Valve 1/main 1/bypass 0 to 100% of valve opening +/-2% All channels indicated Control board &
control console One channel for each main and bypass valve. OPEN/SHUT indication is provided in the control room for each main and bypass feedwater control valve
- 7. Steam Flow 2/Steam generator Unit 1: 0 to 4.5 million pounds per hour Unit 2: 0 to 4.5 million pounds per hour +/-10% span when flow >20% All channels indicated. The channels used for control are trended indications. Control board Accuracy is equipment capability; however, absolute accuracy depends on calibration against feedwater flow 8. Steam Line Pressure 3/Loop 0 to 1,200 psig +/-4.0% of full span All channels indicated Control board 9. Steam Dump Demand Signal 1 0 to 100% equivalent to 0 to 85% max calculated steam flow +/-2% span(c) The one channel is indicated Control board OPEN/SHUT indication is provided in the control room for each steam dump valve DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-3 Sheet 8 of 8 Revision 18 October 2008 Parameter No. of Channels Available Indicated Range Indicator/
Accuracy(a) Indicator/Recorder Location Notes
- 10. Turbine Impulse Chamber Pressure 2 0 to 110% of max calculated turbine load +/-3.5% of full span Both channels indicated Control board OPEN/SHUT indication is provided in the control room for each turbine stop valve
- 11. Condensate Storage Tank Level 1 0 to 100% +/-3.5% of full span Indicator and Recorded Control board Charging and Volume Control 1. Boric Acid Tank Level 1/Tank 0 to 100% +/-3.5% of full span Indicator Control board 2. Emergency Borate Flow 1 0 to 50 gpm +/-4% of full span Indicator Control board 3. Charging Pump Flow 1 0 to 200 gpm +/-10% span when flow >60 gpm Indicator Control console (a) Includes channel accuracy and environmental effects.
Changes which are within the stated accuracy band or within the reading accuracy of the indicator are not reflected in this table. Actual values are found in design documents. (b) Instrument accuracy only. The accuracy statement does not include the effect of density changes in the vessel.
(c) Indicator calibration tolerance.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-4 Sheet 1 of 2 Revision 21 September 2013 POSTACCIDENT MONITORING PANEL INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATOR Parameter No. of Channels Indicated Range Available Indicated Accuracy(j) Indicator/ Recorder Comments 1. Reactor vessel level (bottom of vessel to top) 2 0 to 120% (vessel span) +/-10% of calibrated span(h) Recorder/indicator 2. Reactor plenum level (hot leg pipe to top of vessel) 2 60 to 120% (vessel span) 25.4% of calibrated span total error band (i) Recorder 3. Containment pressure (wide-range) 2 -5 to 200 psig +/-4% of full span Recorder 4. Containment water level (wide-range) 2 64 ft to 98 ft -8 to +5.5 ft(e) Recorder 5. Containment radiation (high-range) 2 1 to 107 R/hr -50% to +60% reading(d) Recorder/indicator 6. Plant vent noble gas - extended range 1 10-4 to 105 µCi/cc +/-15% reading based on min. expected sample pressure(f) Recorder(c)/indicator 7. Containment hydrogen 2 0 to 10% +/-10% of full span Recorder 8. Degree of subcooling 2 -40 to +200°F < 20°F when RCS pressure >900 psig(e) and temperature 700°F Recorder (Train A)/ Indicator (Train B) 9. Plant vent monitor (ALARA) 1 0.1 to 107 mR/hr -40% to +55% reading Recorder 10. Gas decay tank pressure 1 per tank 0 to 200 psig +/-3.5% of full span(b) Indicator DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-4 Sheet 2 of 2 Revision 21 September 2013 Parameter No. of Channels Indicated Range Available Indicated Accuracy(j) Indicator/ Recorder Comments
- 11. Incore temperature 65 0 to 2300°F +/-5% of full span(g) Recorder/indicator 12. Liquid hold-up tank level 1 per tank 0 to 100% +/-5% of full span Indicator 13. Containment spray pump discharge flow 1 per pump 0 to 3000 gpm +/-5% of full span from 550 to 3000 gpm Indicator (a) Deleted. (b) Does not include sensor accuracy. (c) Indicator on RMS panels - Recorder available on EARS until the Central Radiation Processor is available. (d) Includes detector efficiency. (e) Accident scenario: HELB inside containment. (f) Indication accuracy is computed based on the expected detector efficiency. In calculating the offsite dose, however, the actual detector efficiency is taken into account for expected distribution of radioisotopes based on the accident condition. (g) The stated accuracy is met in the instrument range needed for operator action. (h) Levels 69.3% vessel span (top of hot leg) and coolant temperature 650°F. (i) Top of vessel and coolant temperature 600°F. (j) Changes which are within the stated accuracy band or within the reading accuracy of the indicator are not reflected in this table. Actual values are found in design documents.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-5 Sheet 1 of 2 Revision 16 June 2005 INFORMATION REQUIRED ON THE SUBCOOLEDMARGIN MONITORS (SCMMs) Display Information displayed TSAT - T, P - PSAT
Display type Digital and analog
Continuous or on demand Continuous
Single or redundant display Redundant
Location of displays Control board, (indicator from SCMM B) PAM 1 (recorder from SCMM A) PAM 3 and 4 (indicator and trend) Alarms 30°F, 20°F Subcooling from SCMM A or B Overall uncertainty <+20°F when RCS pressure >900 psig, temperature 700°F Range of display -40 to +200°F Qualifications Seismic
Calculator (Processors) Type Digital (shared with RVLIS)
If process computer is used, specify availability N/A Single or redundant calculators Redundant
Selection logic High T
Qualifications Seismic
Calculational technique Steam tables 0.1 to 3000 psi 150 to 750°F
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-5 Sheet 2 of 2 Revision 16 June 2005 Input Temperature 4 RTDs, hottest T/C
Temperature Hottest core exit T/C (per train) and 2 Reactor Hot Leg (per train) Range of temperature sensors 0 to 700°F (RTDs) (useful 150°F to 700°F) 100 to 2300°F (T/Cs) (useful 150°F to 750°F) Uncertainty(a) of temperature signal < +12°F (up to 700°F), < +23°F (up to 1200°F) Qualifications Seismic, environmental
Pressure Barton Model 763 or Rosemount Model 1153 Pressure 1 on loop 3 hot leg (train A input) 1 on loop 4 hot leg (train B input) Range of pressure sensors 0 to 3000 psi
Uncertainty(a) of pressure signal 35 psi Qualifications Seismic, environmental
(a) Uncertainties must address conditions of forced flow and natural circulation
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-6 Sheet 1 of 14 Revision 21 September 2013 SUMMARY OF COMPLIANCE WITH REGULATORY GUIDE 1.97 REV. 3 TYPE A VARIABLES RCS cold leg water temperature (see Item 4)
RCS hot leg water temperature (see Item 5) RCS pressure (see Item 7)
Core exit temperature (see Item 8)
Containment sump water level - wide range (see Item 12)
Containment sump water level - narrow range (see Item 13)
Containment pressure - normal range (see Item 14)
Refueling water storage tank level (see Item 38)
Pressurizer level (see Item 41)
Steam generator level - narrow range (see Item 46)
Steam generator level - wide range (see Item 46)
Steam generator pressure (see Item 47)
Auxiliary feedwater flow (see Item 50)
Condensate storage tank level (see Item 51)
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-6 Sheet 2 of 14 Revision 21 September 2013 Reg Guide 1.97 Variable RG 1.97 Category Instrument Range(a) Envr. Qual(b) Seismic Qual(c) QA(d) Redundant Power Supply Control Room Display at TS EOF Comments TYPE B VARIABLES Reactivity Control
- 1. Neutron flux NRC 1 10-6 -100% Full power Yes Yes Yes Yes 1E Continuous recording DCPP 1 10-8 -100% Full power Yes Yes Yes Yes 1E Continuous indication&
recording No No Note 27 Note 57 2. Control rod position NRC 3 Full in or not full in No No Yes No -- Continuous indication DCPP 3 Full range indication No No Yes No Non-1E Continuous indication Yes Yes 3. RCS soluble boron concentration Note 1 4. RCS cold leg water temp. NRC 1 50-700°F Yes Yes Yes Yes 1E Continuous recording DCPP 1 50-700°F Yes Yes Yes Yes 1E Continuous recording Yes Yes Note 47 Note 48 Note 58 Core Cooling
- 5. RCS hot leg water temp NRC 1 50-700°F Yes Yes Yes Yes 1E Continuous recording DCPP 1 0-700°F Yes Yes Yes Yes 1E Continuous recording Yes Yes Note 47 Note 48 Note 58
- 6. RCS cold leg water temp (see Item 4)
- 7. RCS pressure NRC 1 0-3000 psig Yes Yes Yes Yes 1E Continuous recording DCPP 1 0-3000 psig Yes Yes Yes Yes 1E Continuous indication &
recording Yes Yes Note 27 Note 48 8. Core exit temperature NRC 1 200-2300°F Yes Yes Yes Yes 1E Continuous recording DCPP 1 0-2300°F Yes Yes Yes Yes 1E Continuous indication & recording Yes Yes Note 48 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-6 Sheet 3 of 14 Revision 21 September 2013 Reg Guide 1.97 Variable RG 1.97 Category Instrument Range(a) Envr. Qual(b) Seismic Qual(c) QA(d) Redundant Power Supply Control Room Display at TS EOF Comments
- 9. Coolant level in reactor NRC 1 Bottom of hot leg to top of vessel Yes Yes Yes Yes 1E Continuous recording DCPP 1 Bottom to top of vessel Yes Yes Yes Yes 1E Continuous indication &
recording Yes Yes 10. Degrees of subcooling NRC 2 200°F subcooling to 35°F superheat Yes No Yes No Highly reliable Continuous indication DCPP 2 200°F subcooling to 40°F superheat Yes Yes Yes Yes 1E Continuous indication & recording Yes Yes Note 46 Maintaining Reactor Coolant System Integrity
- 11. RCS pressure (see Item 7)
- 12. Containment sump water NRC 1 Plant specific Yes Yes Yes Yes 1E Continuous recording level (WR) DCPP 1 64 ft (CNT bottom) to 98 ft Yes Yes Yes Yes 1E Continuous recording Yes Yes Note 48 13. Containment sump water Sump depth Yes No Yes No Highly reliable Continuous indication level (NR) DCPP 1 88.5-96.6 ft Yes Yes Yes Yes 1E Continuous indication No No Note 48 14. Containment pressure NRC 1 -5 psig to 3 times design pressure Yes Yes Yes Yes 1E Continuous recording Normal range DCPP 1 -5 to +55 psig Yes Yes Yes Yes 1E Continuous indication Yes Yes Note 48 Wide range DCPP 1 -5 to 200 psig Yes Yes Yes Yes 1E Continuous recording Yes Yes N0te 39 Maintaining Containment Integrity
- 15. Containment isolation valve NRC 1 Closed- not closed Yes Yes Yes Yes 1E Continuous recording position DCPP 1 Closed- Yes Yes Yes Yes 1E Indication Yes Yes Note 28 not closed Note 36 Note 49 Note 59
- 16. Containment pressure (see Item 14)
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-6 Sheet 4 of 14 Revision 21 September 2013 Reg Guide 1.97 Variable RG 1.97 Category Instrument Range(a) Envr. Qual(b) Seismic Qual(c) QA(d) Redundant Power Supply Control Room Display at TS EOF Comments TYPE C VARIABLES Fuel Cladding
- 17. Core exit temperature (see Item 8)
- 18. Radioactivity concentration in circulating primary coolant (see Note 18)
- 19. Analysis of primary coolant - gamma spectrum (seeNote 55)
Reactor Coolant Pressure Boundary
- 20. RCS pressure (see Item 7)
- 21. Containment pressure (see Item 14)
- 22. Containment sump water level (see Items 12 and 13)
- 23. Containment area radiation (see Item 65)
- 24. Effl. radio- activity-noble NRC 3 10-6 to 10-2 µCi/cc No No Yes No - Recording gas effl. from condenser air removal sys.
exhaust DCPP 3 10-4 to 3 µCi/cc No No Yes No non-1E Continuous indication, recording Yes Yes Note 3 Note 34 Containment
- 25. RCS pressure (see Item 7)
- 26. Containment hydrogen NRC 3 0-10% No No Yes No Highly Reliable Continuous recording concentration DCPP 3 0-10% No No Yes Yes Highly Reliable Continuous recording Yes Yes 27. Containment pressure (see Item 14)
- 28. Containment effluent radioactivity - noble gases from identified release points (see Item 67)
- 29. Effluent radioactivity - noble gases from buildings or areas where penetrations and hatches are located (see Item 67)
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-6 Sheet 5 of 14 Revision 21 September 2013 Reg Guide 1.97 Variable RG 1.97 Category Instrument Range(a) Envr. Qual(b) Seismic Qual(c) QA(d) Redundant Power Supply Control Room Display at TS EOF Comments TYPE D VARIABLES Residual Heat Removal System
- 30. RHR system flow NRC 2 0-110% design flow Yes No Yes No Highly reliable Continuous indication DCPP 2 0-1500 gpm (Lo) 0-5000 gpm (Hi) 0-7000gpm (HL) Yes No Yes No 1E Continuous indication Yes Yes Note 50 31. RHR heat exchanger NRC 2 40-350°F Yes No Yes No Highly reliable Continuous indication outlet temp. DCPP 2 50-400°F Yes No Yes No 1E Continuous recording Yes Yes Note 6 32. Accumulator tank level NRC 2 10%-90% volume No No Yes No Highly reliable Continuous indication Note 51 DCPP 3 10%-90% volume No No Yes No Highly reliable,non-1E Continuous indication No No 33. Accumulator tank pressure NRC 2 0-750 psig No No Yes No Highly reliable Continuous indication Note 51 DCPP 3 0-700 psig No No Yes Yes Highly reliable,non-1E Continuous indication Yes Yes Note 7 34. Accumulator isolation valve NRC 2 Closed or open Yes No Yes No Highly reliable Continuous indication position DCPP 3 Closed or open No No Yes No 1E Continuous indication No No Note 32 35. Boric acid charging flow NRC 2 0-110% design Yes No Yes No Highly reliable Continuous indication (charging inj header flow) DCPP 2 0-1000 gpm Yes No Yes No 1E Continuous indication Yes Yes 36. Flow in HPI system (SI NRC 2 0-110% design Yes No Yes No Highly reliable Continuous indication pump disch.) DCPP 2 0-750 gpm Yes No Yes No 1E Continuous indication Yes Yes 37. Flow in LPI system - RHR system (see Item 30)
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-6 Sheet 6 of 14 Revision 21 September 2013 Reg Guide 1.97 Variable RG 1.97 Category Instrument Range(a) Envr. Qual(b) Seismic Qual(c) QA(d) Redundant Power Supply Control Room Display at TS EOF Comments
- 38. Refueling water storage tank NRC 2 Top to bottom Yes No Yes No Highly reliable Continuous indication level DCPP 1 0-100% Yes Yes Yes Yes 1E Continuous indication Yes Yes Note 8 Note 28 Note 41 Note 48 Primary Coolant System
- 39. Reactor coolant pump status NRC 3 Motor current No No Yes No -- Continuous indication DCPP 3 Motor current 0-400 amp No No Yes No non-1E Continuous indication Yes Yes Note 21 40. Primary system safety relief NRC 2 Closed- not closed Yes No Yes No Highly reliable Continuous indication valve position DCPP 2 Closed- not closed Yes Yes Yes No 1E Continuous indication Yes Yes Note 9 Note 46
- 41. Pressurizer level NRC 1 Bottom to top Yes Yes Yes Yes 1E Continuous recording DCPP 1 0-100% Yes Yes Yes Yes 1E Continuous indication Yes Yes Note 8 Note 28 Note 33 Note 48
- 42. Pressurizer heater status NRC 2 Electric current Yes No Yes No Highly reliable Continuous indication DCPP 2 Electric power 0-600 kW Yes No Yes No 1E Continuous indication Yes Yes Note 45 43. Quench tank (PRT) level NRC 3 Top to bottom No No Yes No -- Continuous indication DCPP 3 0-100% No No Yes No Highly reliable,non-1E Continuous indication Yes Yes Note 8 44. Quench tank (PRT) NRC 3 50-750°F No No Yes No -- Continuous indication temperature DCPP 3 50-350°F No No Yes No Highly reliable,non-1E Continuous indication Yes Yes Note 10
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-6 Sheet 7 of 14 Revision 21 September 2013 Reg Guide 1.97 Variable RG 1.97 Category Instrument Range(a) Envr. Qual(b) Seismic Qual(c) QA(d) Redundant Power Supply Control Room Display at TS EOF Comments
- 45. Quench tank (PRT) pressure NRC 3 0 design No No Yes No -- Continuous indication DCPP 3 0-100 psig No No Yes No Highly reliable,non-1E Continuous indication Yes Yes Secondary System (Steam Generator)
- 46. Steam generator level NRC 1 From tube sheet to separators Yes Yes Yes Yes 1E Continuous recording Narrow range DCPP 1 From within the transition cone to separators. Yes Yes Yes Yes 1E Continuous indication Yes Yes Note 26 Note 28 Note 48 Wide range DCPP 1 From 12 inches above tube sheet to separators Yes Yes Yes Yes 1E Continuous recording Yes Yes Note 26 Note 36 Note 47 Note 48
- 47. Steam generator pressure NRC 2 From atm. press. to 20% above the lowest safety valve setting Yes No Yes No Highly reliable Continuous indication DCPP 1 0-1200 psig Yes Yes Yes Yes 1E Continuous indication Yes Yes Note 11 Note 28 Note 41 Note 48
- 48. Main steam flow NRC 2 -- Yes No Yes No Highly reliable Continuous indication DCPP 2 0-4.5 x 106 lb/hr Yes No Yes No 1E Continuous indication Yes Yes 49. Main feedwater flow NRC 3 0-110% design No No Yes No -- Continuous indication DCPP 3 0-4.5 x 106 lb/hr No No Yes No 1E Continuous indication Yes Yes Auxiliary Feedwater or Emergency Feedwater System
- 50. Auxiliary or emergency NRC 2 0-110% design Yes No Yes No Highly reliable Continuous indication feedwater flow DCPP 1 0-300 gpm Yes Yes Yes Yes 1E Continuous indication Yes Yes Note 26 Note 28 Note 47 Note 48 Note 52 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-6 Sheet 8 of 14 Revision 21 September 2013 Reg Guide 1.97 Variable RG 1.97 Category Instrument Range(a) Envr.
Qual(b) Seismic Qual(c) QA(d) Redundant Power Supply Control Room Display at TS EOF Comments
- 51. Condensate storage tank NRC 1 Plant specific Yes Yes Yes Yes 1E Continuous recording DCPP 1 0-100% Yes Yes Yes Yes 1E Continuous recording Yes Yes Note 37 Note 48 Containment Cooling Systems
- 52. Containment spray flow NRC 2 0-110% design Yes No Yes No Highly reliable Continuous indication DCPP 2 0-3000 gpm Yes No Yes No 1E Continuous indication No No 53. Heat removal by containment NRC 2 Plant specific Yes No Yes No Highly reliable Continuous indication fan heat removal system DCPP 2 See Note 12 Yes No Yes No 1E Continuous indication Yes Yes Note 12 54. Containment atmosphere NRC 2 40-400°F Yes No Yes No Highly reliable Continuous indication temperature DCPP 2 0-400°F Yes No Yes Yes 1E Continuous indication No No 55. Containment sump water NRC 2 50-250°F Yes No Yes No Highly reliable Continuous indication temperature DCPP 2 0-300°F Yes No Yes Yes 1E Continuous indication No No Chemical and Volume Control System
- 56. Makeup flow-in NRC 2 0-110% design Yes No Yes No Highly reliable Continuous indication DCPP 2 0-50 gpm 0-200 gpm Yes No Yes No 1E Continuous indication Yes Yes Note 53 57. Letdown flow-out NRC 2 0-110% design Yes No Yes No Highly reliable Continuous indication DCPP 2 0-200 gpm Yes No Yes No 1E Continuous indication Yes Yes 58. Volume control tank level NRC 2 Top to bottom Yes No Yes No Highly reliable Continuous indication DCPP 2 0-100% Yes No Yes No 1E Continuous indication Yes Yes Note 8 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-6 Sheet 9 of 14 Revision 21 September 2013 Reg Guide 1.97 Variable RG 1.97 Category Instrument Range(a) Envr.
Qual(b) Seismic Qual(c) QA(d) Redundant Power Supply Control Room Display at TS EOF Comments Cooling Water System
- 59. CCW temp. to ESF system NRC 2 40-200°F Yes No Yes No Highly reliable Continuous indication DCPP 2 0-200°F Yes No Yes No 1E Continuous indication Yes Yes 60. CCW flow to EFS system NRC 2 0-110% design Yes No Yes No Highly reliable Continuous indication DCPP 2 0-12,000 gpm Yes No Yes No 1E Continuous indication Yes Yes Radwaste Systems
- 61. High level radioactive NRC 3 Top to bottom No No Yes No -- Continuous indication liquid tank level DCPP 3 0-100% No No Yes No 1E Continuous indication No No Yes Yes 62. Radioactive gas holdup tank NRC 3 0-150% design No No Yes No -- Continuous indication pressure DCPP 3 0-200 psig No No Yes No 1E Continuous indication Yes Yes Note 54 Ventilation Systems
- 63. Emergency ventilation NRC 2 Open-closed Yes No Yes No Highly reliable Continuous indication damper position DCPP 2 Open-closed Yes No Yes No 1E Continuous indication No No Note 24 Power Supplies
- 64. Status of standby power NRC 2 Voltages, currents Yes No Yes No Highly reliable Continuous indication and other emergency sources DCPP 2 Voltages, currents Yes No Yes No 1E Continuous indication Yes Yes Note 13 Note 43 TYPE E VARIABLES Containment Radiation
- 65. Containment area radiation - NRC 1 1 to 107 R/hr Yes Yes Yes Yes 1E Continuous recording high range DCPP 1 1 to 107 R/hr Yes Yes Yes Yes 1E Continuous recording Yes Yes DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-6 Sheet 10 of 14 Revision 21 September 2013 Reg Guide 1.97 Variable RG 1.97 Category Instrument Range(a) Envr.
Qual(b) Seismic Qual(c) QA(d) Redundant Power Supply Control Room Display at TS EOF Comments Area Radiation
- 66. Radiation NRC 3 10-1 to 104 mR/hrNo No Yes No -- Recording exposure rate (inside bldgs or areas) DCPP 3 10-1 to 104 mR/hrNo No Yes No Non-1E Local indication and alarm No No Note 5 Note 34 Airborne Radioactive Materials Released From Plant
- 67. Noble gases and vent flow rate:
Containment or purge effluent (see Note 14) Reactor shield building annulus (see Note 14) Auxiliary building (see Note 14) Condenser air removal system exhaust (see Item 24) Noble gases from common-plant NRC 2 10-6 to 104µCi/cc Yes No Yes No Highly reliable Continuous recording vent + discharging any of above releases (including cont. purge) DCPP 2 10-6 to 104µCi/cc Yes No Yes No Highly reliable Continuous indication, recording Yes Yes Note 34 Plant vent flow NRC 2 0-110% design Yes No Yes No Highly reliable Continuous recording DCPP 2 0-30x104 cfm Yes No Yes No Highly reliable Continuous recording Vent from steam generator NRC 2 10-1 to 103µCi/cc Yes No Yes No Highly reliable Continuous recording safety relief valves or atmospheric dump valves DCPP 2 10-1 to 103µCi/cc Yes No Yes No 1E Continuous recording All other identified release points (see Note 56)
- 68. Particulates and halogens NRC 3 10-3 to 102µCi/cc No No Yes No -- Recording DCPP 2 Note 15 Yes No Yes No Highly reliable Continuous indication, recording Yes Yes Note 15 Note 34
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-6 Sheet 11 of 14 Revision 21 September 2013 Reg Guide 1.97 Variable RG 1.97 Category Instrument Range(a) Envr. Qual(b) Seismic Qual(c) QA(d) Redundant Power Supply Control Room Display at TS EOF Comments Environs Radiation and Radioactivity
- 69. Airborne radiohalogens NRC 3 10-9 to 10-3µCi/cc No No Yes No -- -- & particulates (portable with on-site analysis) DCPP 3 10-9 to 10-3µCi/cc No No Yes No -- -- -- -- 70. Plant and environs NRC - As specified in RG 1.97, Rev. 3 No No Yes No -- -- radiation (portable instrumentation) DCPP - As specified in RG 1.97, Rev. 3 No No Yes No -- -- -- -- 71. Plant and environs NRC 3 Isotopic analysis No No Yes No -- -- radioactivity (portable instrumentation) DCPP 3 Multichannel gamma-ray spectrometer No No Yes No -- -- -- -- Note 16 Meteorology
- 72. NRC As specified in RG 1.97, Rev. 3 No No No -- Recording DCPP As specified in RG 1.97, Rev. 3 No No No non-1E Indication, recording Yes Yes Note 38 Note 40 Accident Sampling Capability
- 73. Note 55
(a) Instrument Range - Where the NRC and Diablo Canyon instrument ranges are not directly comparable, the Diablo Canyon ranges meet or exceed the NRC ranges, unless otherwise noted (b) EQ (Environmental Qualification) - A "Yes" entry means that the instrumentation complies with 10 CFR 50.49. A "No" entry means there is no specific provision for environmental qualification of this instrumentation (c) Seismic Qualification - A "Yes" entry means that the instrumentation complies with Regulatory Guide (RG) 1.100. A "No" entry means there are no specific provisions for seismic qualification of this instrument. (d) QA (Quality Assurance) - A "Yes" entry means that the instrumentation complies with the applicable quality assurance provisions contained in RG 1.97 for the category of the instrument. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-6 Sheet 12 of 14 Revision 21 September 2013 1. Elimination of the boron concentration monitoring system (BCMS) and utilization of the post-accident monitoring system (PASS) was approved by NRC letter dated December 4, 2000. Elimination of the PASS was approved by License Amendments 149 (Unit 1) and 149 (Unit 2), dated July 13, 2001
- 2. Deleted in Revision 4.
- 3. Installed range is adequate since air ejector exhaust is routed to the plant vent.
- 4. Deleted in Revision 11.
- 5. The Reg Guide 1.97 instrument range is erroneously stated as 10-1 to 104 R/hr for this variable.
- 6. Installed range is adequate for the Diablo Canyon site as the RHR outlet temperature is not expected to be less than 50°F.
- 7. Installed range is adequate. Tank pressure limited to 700 psig by relief valve.
- 8. Zero to 100% indicates usable volume of tank.
- 9. Position indication for safety valves is provided by acoustic monitors and by position switches for the power operated relief valves. 10. Quench tank pressure is limited to 100 psig by a rupture disk, so water temperature cannot exceed the saturation temperature at 100 psig, or 338°F. Therefore, the range of 50-350°F is adequate. 11. Installed ranged is adequate. Redundant instrumentation is installed and all safety valves lift before 1200 psig. The relieving capability of the safety valves is greater than rated steam flow. Hence, pressure cannot physically reach 1200 psig.
- 12. Containment fan cooler unit (CFCU) operation is verified by white monitor lights (that confirm proper CFCU response to ESF actuation), CFCU ammeters, and CFCU motor speed indicating lights. Category 1 containment pressure (Variable 14) and Category 2 containment temperature (Variable 54) provide an overall indication of CFCU system performance. CFCU operation is an indirect measurement of these containment parameters that are of primary importance to plant operators.
- 13. Category 2 indications for vital 4 KV voltage, EDG wattage and amperage, 4 KV/480 V transformer primary side amperage, 480 V voltage, and battery voltage and amperage are provided. All indications are Class 1E except for battery voltage and amperage.
- 14. Not needed if effluent discharges through common plant vent.
- 15. The particulate monitor has a range of 10-12 to 10-7 µCi.cc. Additional range is achieved through use of particulate filters installed on postaccident grab sampling equipment. The iodine monitor has a range of 10-7 to 10-2 µCi/cc. Additional range is provided by postaccident grab sampling equipment up to 102 µCi/cc.
- 16. An offsite laboratory with gamma spectroscopy equipment is available for environmental analysis.
- 17. Deleted in Revision 4.
- 18. Category 1 instrumentation to monitor radiation level in circulating primary coolant is not provided. Routine reactor coolant sampling verifies fuel cladding integrity during normal operation. During an accident, rapid assessment of cladding failures can be obtained from the Category 1 containment high range area radiation monitors in conjunction with a DCPP emergency procedure titled, "Core Damage Assessment Procedure".
- 19. Deleted in Revision 4.
- 20. Deleted in Revision 7.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-6 Sheet 13 of 14 Revision 21 September 2013 21. Display at TSC and EOF is circuit breaker status. 22. Deleted in Revision 4.
- 23. Deleted in Revision 4.
- 24. Most of the critical damper positions are indicated at the TSC and EOF, enough to assure that the system is working as expected.
- 25. Deleted in Revision 11.
- 26. The narrow range steam generator level is the key variable for monitoring secondary heat sink if the water level is within the narrow range span. If the water level is below the narrow range span, auxiliary feedwater flow in conjunction with steam generator wide range level meet the Category 1 requirements for monitoring steam generator status.
- 27. Category 1 recording is provided for one channel.
- 28. This post-accident monitoring data is recorded/stored in the Transient Recording System (TRS). The TRS provides the data storage and recall functions associated with ERFDS. The TRS is a Class II, highly reliable computer system with uninterruptible battery backed power.
- 29. Deleted in Revision 11.
- 30. Deleted in Revision 7.
- 31. Deleted in Revision 7.
- 32. Accumulator isolation valve position indication is Category 3. Power is removed from the valve actuator during normal operation; hence, following an accident the valve is known to be in its correct (open) position. Power to these valves may be manually restored following a LOCA, but operation of the valves, and thus the position indication, is not critical for post-LOCA accident mitigation or plant shutdown. Power is also restored to these valves during certain (non-LOCA) emergency conditions when operation of the valves is required. However, the position switches will not be exposed to a harsh environment under these conditions, so the position switches will remain operable.
- 33. Pressurizer water level indication meets Category 1 requirements; the recorder for this variable is Instrument Class II and is common for all the channels. This combination of Category 1 indication and Class II recording is sufficient to meet the Regulatory Guide requirements.
- 34. Recording as necessary on EARS, ERFDS and/or TRS.
- 35. Deleted.
- 36. Redundant channels are powered from different Class 1E power supplies; however, electrical cabling does not meet separation criteria.
- 37. Zero to 100% indicates contained volume of tank.
- 38. The plant process computer is used as the indicating device to display meteorological instrument signals. In addition, Type E, Category 3 recorders are located in the meteorological towers.
- 39. Normal range containment pressure channels provide indication from -5 to +55 psig. Wide range channels provide recording from -5 to 200 psig, but only the positive pressure range is credited as Category 1. Recording negative pressures is not required as negative pressures would not be the range of interest during an accident when containment pressures can be expected to increase.
- 40. Control room indication is processed for display upon demand.
- 41. Recording of this Category 2 variable which PG&E classifies as Category 1 is not provided because variable trending does not provide essential information.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.5-6 Sheet 14 of 14 Revision 21 September 2013 42. DCPP instrument ranges are in terms of CPM or mR/hr., with conversion factors and graphs that allow easy conversion.
- 43. 480V and 4160V bus voltages are indicated on an indicator scale of 0 to 150; actual voltage is determined by applying a scaling factor (4 for the 480V bus, and 35 for the 4160V bus).
- 44. The recording capability associated with this variable is provided by a Category 3 multi-channel recorder. 45. Pressurizer heater power consumption is indicated, for groups 2 and 3 only, at CC-1 and (via ERFDS) the TSC and EOF. Although not credited for RG 1.97, circuit breaker status is also available at the TSC and EOF for groups 1 and 4.
- 46. Seismic qualification in accordance with NUREG-0737 requirements. 47. Redundancy is provided on a system basis as opposed to a per loop basis. Loop 1 and 2 channels are redundant to loop 3 and 4 channels. 48. Instrument channels are designated as Type A variables as they provide information required for operator action. 49. CIV position indication redundancy is provided on a per penetration basis as opposed to a per valve basis.
- 50. Each RHR train is monitored by 0-1500 gpm and 0-5000 gpm flow indicators in all modes of RHR operation except hot leg recirculation. The 0-7000 gpm flow indication monitors RHR system flow in the hot leg recirculation mode of operation.
- 51. In accordance with NRC guidance subsequent to issuance of Reg Guide 1.97, environmental qualification is not required for the accumulator tank pressure and level channels.
- 52. If flow exceeds instrument range, steam generator level instruments provide the necessary information to monitor steam generator status.
- 53. Emergency borate flowpath to charging pump suction monitored by 0-50 gpm flow indication. Charging pump discharge flow monitored by 0-200 gpm flow indication.
- 54. Gas decay tank pressure indication spans 0-200 psig. Control system maintains normal tank pressure in the range of 0-100 psig and relief valves limit tank pressure to 150 psig.
- 55. Post-accident sampling system requirements were deleted by License Amendments (LAs) 149 (Unit 1) and 149 (Unit 2), dated July 13, 2001. Three commitments were established to meet the conditions of LAs 149/149 to (1) maintain contingency plans for obtaining and analyzing highly radioactive samples of reactor coolant, containment sump, and containment atmosphere (T36279), (2) maintain a capability for classifying fuel damage events at the Alert level threshold (T36280), and (3) maintain the capability to monitor radioactive iodines that have been released to offsite environs (T36281).
- 56. The steam generator blowdown tank vent is a potential noble gas release point that is not discharged through the plant vent. However, the blowdown tank is only used intermittently and is automatically isolated on high radiation in the liquid blowdown effluent. This is not a credible noble gas release path. Grab sample capability is provided for the blowdown tank vent effluent.
- 57. Source, intermediate and power range nuclear instrumentation provide displays at TSC and EOF.
- 58. RCS loop 1 hot leg and cold leg temperature channels are not environmentally qualified for outside-containment line break accidents.
- 59. Containment isolation valves credited for RG 1.97 Category 1 position indication are defined as only those containment isolation valves that receive a Phase A, Phase B or containment ventilation isolation signal.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.7-1 Sheet 1 of 2 Revision 21 September 2013 PLANT CONTROL SYSTEM INTERLOCKS Designation Derivation Function C-1 1/2 Neutron flux (interme- diate range) above setpoint Blocks automatic and manual control rod withdrawal C-2 1/4 Nuclear power (power range) above setpoint Blocks automatic and manual control rod withdrawal C-3 2/4 Overtemperature T above setpoint Blocks automatic and manual control rod withdrawal
Actuates turbine runback via load reference
Defeats remote load dispatching C-4 2/4 Overpower T above setpoint Blocks automatic and manual control rod withdrawal
Actuates turbine runback via load reference
Defeats remote load dispatching C-5 1/1 Turbine impulse chamber pressure below setpoint Defeats remote load dispatching
Blocks automatic control rod withdrawal C-7A 1/1 Time derivative (absolute value) of turbine impulse chamber pressure (decreases only) above setpoint Makes condenser steam Dump valves available for either tripping or modulation DCPP UNITS 1 & 2 FSAR UPDATE TABLE 7.7-1 Sheet 2 of 2 Revision 21 September 2013 Designation Derivation Function C-7B 1/1 Time derivative (absolute value) of turbine impulse chamber pressure (decreases only) above setpoint Makes atmospheric steam dump valves available for either tripping or modulation P-4 Reactor trip Blocks steam dump control via load rejection Tavg controller
Makes condenser steam dump valves available for either tripping or modulation
Blocks atmospheric steam dump valves
Unblocks steam dump control via reactor trip Tavg controller C-9 Any condenser pressure above setpoint or All circulating water pump breakers open Blocks steam dump to condenser C-11 1/1 Bank D control rod position above setpoint Blocks automatic rod withdrawal
Revision 11 November 1996FIGURE 7.2-2 SETPOINT REDUCTION FUNCTION FOR OVERPOWER AND OVERPRESSURE T TRIPS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision11November1996FIGURE 7.2-3 ILLUSTRATION OF OVERPOWER AND OVER-TEMPERATURE T TRIP SETPOINTS T VERSUS TAVG UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 7.2-4 PRESSURIZER SEALED REFERENCE LEG LEVEL SYSTEM UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 7.2-5 DESIGN TO ACHIEVE ISOLATION BETWEEN CHANNELS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 7.2-6 (Sheet 1 of 2) SEISMIC SENSOR LOCATIONS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 7.2-6 (Sheet 2 of 2) SEISMIC SENSOR LOCATIONS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010FSAR UPDATE UNITS 1 AND 2 DIABLO CANYON SITE FIGURE 7.5-1 CONTAINMENT WATER LEVEL INDICATION (NOT AN ACTUAL LAYOUT) NOTE: Refer to Figure 7.5-1B for Unit 2 Wide-Range Diagram
Revision 19 May 2010FIGURE 7.5-1B CONTAINMENT WATER LEVEL WIDE-RANGE INDICATION WITH INSTALLED SPARE WIDE- RANGE LEVEL TRANSMITTER IN SERVICE (NOT AN ACTUAL LAYOUT) FSAR UPDATE UNIT 2 DIABLO CANYON SITE FIGURE 7.5-2 REACTOR VESSEL LEVEL INSTRUMENTATION PROCESS CONNECTION SCHEMATIC (TRAIN A) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 12 September 1998 Revision 12 September 1998FIGURE 7.5-2 REACTOR VESSEL LEVEL INSTRUMENTATION PROCESS CONNECTION SCHEMATIC (TRAIN A) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 7.7-1 SIMPLIFIED BLOCK DIAGRAM OF REACTOR CONTROL SYSTEM UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE TAVG()AUCTT)AUCT(ZLL= A T)(AUCT+BTAVG()AUCT+ CCOMPARATORAL1AL2DEMAND BANKSIGNALZLOW ALARMLOW-LOW ALARMCOMMON FOR ALL FOURCONTROL BANKSTYPICAL OF ONE CONTROL BANKNOTES: 1. The PPC is used for the comparator network. 2. Comparison is done for all control banks. FIGURE 7.7-2 CONTROL BANK ROD INSERTION MONIOTOR UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 16 June 2005 Revision 11 November 1996 FIGURE 7.7-3 ROD DEVIATION COMPARATOR UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE POWERRELIEFVALVE # 2TOVARIABLEHEATERCONTROLSPRAYCONTROLLERREMOTE MANUALPOSITIONINGTO BACKUPHEATERCONTROLPOWERRELIEFVALVE #1 and 3PIDCONTROLLERPRESSURIZER PRESSURESIGNALREFERENCEPRESSURE(+)(-)Note: Valve 1 = PCV 456 Valve 2 = PCV 474 Valve 3 = PCV 455C FIGURE 7.7-4 BLOCK DIAGRAM OF PRESSURIZER PRESSURE CONTROL SYSTEM UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 16 June 2005 FIGURE 7.7-5 BLOCK DIAGRAM OF PRESSURIZER LEVEL CONTROL SYSTEM UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 21 September 2013 TAVG FIGURE 7.7-8 BLOCK DIAGRAM OF STEAM DUMP CONTROL SYSTEM UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 Revision 11 November 1996FIGURE 7.7-9 BASIC FLUX MAPPING SYSTEM UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE DCPP UNITS 1 & 2 FSAR UPDATE Chapter 8 ELECTRIC POWER CONTENTS Section Title Page i Revision 21 September 2013
8.1 INTRODUCTION
8.1-1 8.1.1 Definitions 8.1-1
8.1.2 General Description 8.1-3
8.1.3 Power Transmission System 8.1-3 8.1.4 Safety Loads 8.1-4 8.1.5 Design Bases, Criteria, Safety Guides, and Standards 8.1-4 8.1.5.1 Design Bases 8.1-5 8.1.5.2 Applicable Design Basis Criteria 8.1-5 8.1.5.3 Codes and Standards 8.1-5
8.1.6 Reference Drawings 8.1-6
8.2 OFFSITE POWER SYSTEM 8.2-1
8.2.1 Design Bases 8.2-1 8.2.1.1 General Design Criterion 4, 1967 - Sharing of Systems 8.2-1 8.2.1.2 General Design Criterion 17, 1971 - Electric Power Systems 8.2-2 8.2.1.3 General Design Criterion 18, 1971 - Inspection and Testing of Electric Power Systems 8.2-3 8.2.1.5 Single Failure Requirements 8.2-3 8.2.1.6 10 CFR 50.63 - Loss of All Alternating Current Power 8.2-3 8.2.1.7 Safety Guide 32, August 1972 - Use of IEEE Standard 308-1971 Criteria for Class 1E Electric Systems for Nuclear Power Generating Stations 8.2-3 8.2.2 Description 8.2-3 8.2.2.1 230-kV System 8.2-3 8.2.2.2 500-kV 8.2-4
8.2.3 Safety Evaluation 8.2-6 8.2.3.1 General Design Criterion 4, 1967 - Sharing of Systems 8.2-6 8.2.3.2 General Design Criterion 17, 1971 - Electric Power Systems 8.2-6 8.2.3.3 General Design Criterion 18, 1971 Inspection and Testing of Electric Power Systems 8.2-12 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 8 CONTENTS (Continued)
Section Title Page ii Revision 21 September 2013 8.2.3.4 Transmission Capacity Requirements 8.2-12 8.2.3.5 Single Failure Requirements 8.2-13 8.2.3.6 10 CFR 50.63 Loss of All Alternating Current Power 8.2-14 8.2.3.7 Safety Guide 32, August 1972 Use of IEEE Standard 308-1971 Criteria for Class 1E Electric Systems for Nuclear Power Generating Stations 8.2-14
8.2.4 Tests and Inspections 8.2-15 8.2.5 Instrumentation Applications 8.2-15 8.2.6 References 8.2-15
8.2.7 Reference Drawings 8.2-16
8.3 ONSITE POWER SYSTEMS 8.3-1
8.3.1 AC Power Systems 8.3-1 8.3.1.1 Description 8.3-1 8.3.1.2 Analysis 8.3-56 8.3.1.3 Conformance with Appropriate Quality Assurance Standards 8.3-57 8.3.1.4 Independence of Redundant Systems 8.3-57 8.3.1.5 Physical Identification of Safety-Related Equipment 8.3-66 8.3.1.6 Station Blackout 8.3-69
8.3.2 DC Power Systems 8.3-71 8.3.2.1 Design Basis 8.3-72 8.3.2.2 System Description 8.3-75 8.3.2.3 Safety Evaluation 8.3-78 8.3.2.4 Tests and Inspections 8.3-85 8.3.2.5 Instrumentation Applications 8.3-85
8.3.3 References 8.3-85
8.3.4 Reference Drawings 8.3-87
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 8 TABLES Table Title iii Revision 21 September 2013 8.1-1 Applicable Design Basis Criteria 8.3-1 Notes for Tables
8.3-2 Timing Sequence and Intervals - No Safety Injection Signal
8.3-3 Maximum Steady State Load Demand - No Safety Injection Signal
8.3-4 Diesel Generator Loading - Timing Sequence and Intervals - With Safety Injection Signal 8.3-5 Diesel Generator Loading - Maximum Steady State Load Demand Following Loss-of-Coolant Accident 8.3-6 Vital 4160/480-Volt Load Centers Loading
8.3-7 Vital 480-Volt Load Centers Maximum Demand 8.3-8 Summary of Shop Testing of Diablo Canyon Diesel Engine Generator Units by Alco Engine Division 8.3-9 Summary of Preoperational Testing of Diablo Canyon Diesel Engine Generator Units by PG&E During Startup 8.3-10 Identification of Electrical Systems
8.3-11 Unit 1 125-Vdc Distribution Panel Safety-Related Loads
8.3-12 Deleted in Revision 11
8.3-13 Deleted in Revision 11
8.3-14 Deleted in Revision 11
8.3-15 Deleted in Revision 11
8.3-16 Deleted in Revision 11
8.3-17 Deleted in Revision 11 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 8 FIGURES Figure Title iv Revision 21 September 2013 8.1-1(a) Plant Single Line Diagram 8.2-1 Deleted in Revision 17
8.2-2 Deleted in Revision 17
8.2-3(a) General Arrangement 230-kV and 500-kV Switchyard 8.2-4(a) Deleted in Revision 17 8.2-5(a) Deleted in Revision 17 8.2-6(a) Arrangement of 12-kV Startup Transformers 8.3-1(a) Single Line Meter and Relay Diagram - Generator, Main, and Auxiliary Transformers, and Excitation 8.3-2(a) Single Line Meter and Relay Diagram kV System 8.3-3(a) Single Line Meter and Relay Diagram kV System 8.3-4(a) Single Line Meter and Relay Diagram kV System (Vital Bus) 8.3-5(a) Single Line Meter and Relay Diagram kV Startup System 8.3-6(a) Single Line Meter and Relay Diagram - 480-V System Bus Section F (Vital Bus)
8.3-7(a) Single Line Meter and Relay Diagram - 480-V System Bus Section G (Vital Bus)
8.3-8(a) Single Line Meter and Relay Diagram - 480-V System Bus Section H (Vital Bus)
8.3-9(a) Schematic Diagram kV Bus Section F Automatic Transfer 8.3-10 (a) Schematic Diagram kV Bus Section G Automatic Transfer 8.3-11 (a) Schematic Diagram kV Bus Section H Automatic Transfer 8.3-12 (a) Schematic Diagram kV Diesel Generators Controls DCPP UNITS 1 & 2 FSAR UPDATE Chapter 8 FIGURES (Continued) Figure Title v Revision 21 September 2013 8.3-13 (a) Schematic Diagram kV Diesel Generators and Associated Circuit Breakers 8.3-14 (a) Schematic Diagram kV Diesel Generators Auxiliary Motors 8.3-15 Deleted in Revision 11
8.3-16 (a) Logic Diagram - Automatic Transfer 4-kV buses F, G, and H 8.3-17 (a) Class 1E 125-Vdc System 8.3-18 (a) Normal (Non-Class 1E) 125-V and 250-Vdc System 8.3-19 (a) Pressurizer Heaters, Single Line Diagram 8.3-20 (a) Schematic Diagram Potential and Synchronizing 4160-Volt System (Vital Bus) 8.3-21 Typical Arrangement of Jumboduct Sleeve Through Concrete 8.3-22 Typical Detail of Four or More Jumboducts in Concrete Slab
8.3-23 Typical Arrangement of Transite Conduit Sleeve for Electrical Cables Through Concrete 8.3-24 Typical Fire Stop for Horizontal Cable Trays
8.3-25 Typical Fire Stop for Vertical Trays
8.3-26 Typical Fire Stop for Parallel Trays
8.3-27 Typical Vertical Tray Fire Stop
8.3-28 Typical Fire Barrier for Horizontal Trays
NOTE:
(a) This figure corresponds to a controlled engineering drawing that is incorporated by reference into the FSAR Update. See Table 1.6-1 for the correlation between the FSAR Update figure number and the corresponding controlled engineering drawing number.
DCPP UNITS 1 & 2 FSAR UPDATE vi Revision 21 September 2013 Chapter 8 APPENDICES Appendix Title 8.3A Deleted in Revision 11
8.3B INSULATED CABLE - CONSTRUCTION AND VOLTAGE RATINGS
8.3C MATERIALS FOR FIRE STOPS AND SEALS
DCPP UNITS 1 & 2 FSAR UPDATE 8.1-1 Revision 21 September 2013 Chapter 8 ELECTRIC POWER
8.1 INTRODUCTION
The electrical auxiliary power system at the Diablo Canyon Power Plant (DCPP) is designed to provide electric power to the necessary plant electrical equipment under all foreseeable combinations of plant operation and electric power source availability. The various subsystems provide adequate protection for electrical equipment during fault conditions, while maintaining maximum system flexibility and reliability. 8.1.1 DEFINITIONS The following definitions apply to the electrical auxiliary power system. Offsite Power System: The system that delivers electric power from the transmission network to the onsite distribution system Preferred Power Supply: The preferred power supply is the Offsite Power System. The preferred power supply is comprised of two physically independent offsite power circuits. The startup offsite power circuit (230-kV) and the auxiliary offsite power circuit (500-kV). Normal Onsite Power Source: The normal onsite power source is the electric source which is generated by DCPP via the main generator and distributed by the 25-kV system to the 4.16-kV system. Startup Offsite Power Circuit: The startup offsite power circuit (230-kV system) provides an immediate source of offsite power from either of the two 230-Kv transmission lines connecting to the 230-kV switchyard. Refer to Section 8.2.2.1 for description of the boundary of the startup offsite power circuit. Auxiliary Offsite Power Circuit: The auxiliary offsite power circuit (500-kV system) provides the delayed source of offsite power from any one of the three 500-kV transmission lines connecting to the 500-kV switchyard. Refer to Section 8.2.2.2 for description of the boundary of the auxiliary offsite power circuit . The main generator also feeds the auxiliary offsite DCPP UNITS 1 & 2 FSAR UPDATE 8.1-2 Revision 21 September 2013 power circuit during normal plant operation. Onsite Distribution System: The Class 1E distribution system (both ac and dc voltages) permits the functioning of structures, systems, and components important to safety. Refer to Sections 8.3.1.1.1 through 8.3.1.1.5 and 8.3.2 for detailed descriptions of the onsite distribution systems. There is also a non-Class 1E electrical distribution system (i.e., balance of plant). Those balance of plant (BOP) portions comprising part of an offsite power circuit are subject to offsite power requirements. Those portions supplied from a Class 1E bus are subject to Class 1E isolation requirements. The remainder of the non-Class 1E BOP electrical distribution system is outside the scope of GDC 17, 1971 and IEEE 308-1971. Standby Power Supply: The onsite emergency power supply. The emergency diesel generators (EDGs) are the ac standby power supply when the preferred power supply is not available. The dc standby power supply is comprised of the station batteries and the 125-Vdc system. Refer to Section 8.3.1.1.6 and 8.3.2 for detailed descriptions of the standby power supplies. Class 1E: The electrical equipment and components supporting PG&E Design Class I functions shown in Table 3.2-1. Non-Class 1E: The electrical equipment and components supporting PG&E Design Class II SSCs functions shown in Table 3.2-1. Source: In the context of GDC 17, 1971 and IEEE 308-1971, the Class 1E ac electrical distribution system has three sources: 1) the preferred power supply 2) the standby power supply 3) the normal onsite power supply Grid: The grid is the source of electrical power to the offsite power system. The grid is comprised of the electrical DCPP UNITS 1 & 2 FSAR UPDATE 8.1-3 Revision 21 September 2013 generation resources, transmission lines, interconnections with neighboring systems, and associated equipment, generally operated at voltages of 100-kV or higher. Transmission Network: The grid elements operating at a given voltage level. DCPP connects with the grid at both the 230-kV and 500-kV transmission network level. 8.1.2 GENERAL DESCRIPTION The electrical systems generate and transmit power to the high-voltage system, distribute power to the auxiliary loads, and provide control, protection, instrumentation, and annunciation power supplies for the units. Power is generated at 25-kV. Auxiliary loads are served at 12-kV, 4.16-kV, 480-V, 120-Vac, 250-Vdc, and 125-Vdc. The engineered safety feature (ESF) auxiliary loads are served directly by the 4.16-kV, 480-V, 120-Vac, and 125-Vdc Class 1E systems. Offsite ac power for plant auxiliaries is available from two 230-kV transmission circuits and three 500-kV transmission circuits.
Onsite ac auxiliary power is supplied by each unit's main generator and is also available for Class 1E loads from six diesel engine-driven generators. Three diesel generators are dedicated to each unit.
Onsite dc power is supplied from six 125-Vdc station batteries in each unit. Three batteries serve 125-Vdc Class 1E loads plus some non-Class 1E loads, and three batteries serve 125-Vdc non-Class 1E loads. Two of the three batteries supplying the non-Class 1E loads are also used together (i.e., in series) to supply 250-Vdc non-Class 1E loads (see Figure 8.3-18). 8.1.3 POWER TRANSMISSION SYSTEM The PG&E 500-kV ac transmission system overlays an extensive 230-kV ac transmission network. The 500-kV system is further connected through the 500-kV Pacific Intertie to the Western Systems Coordinating Council network covering the eleven western states plus British Columbia. Since March 31, 1998, the California Independent System Operator (CAISO) has been responsible for operating the transmission system within California. PG&E, as well as the other transmission system operators (owners) in the state, continues to own and operate their transmission facilities.
DCPP UNITS 1 & 2 FSAR UPDATE 8.1-4 Revision 21 September 2013 8.1.4 SAFETY LOADS A representative listing of each unit's systems and loads requiring electric power to perform their safety functions are listed below.
(1) Emergency core cooling system (ECCS), including two each of centrifugal charging pumps (CCP1 and CCP2), residual heat removal (RHR) pumps, safety injection (SI) pumps, motor-driven auxiliary feedwater pumps, and their associated valves and lube oil pumps (2) Containment spray system, including two pumps and associated valves (3) Containment ventilation system, including five fan cooler units (4) Auxiliary saltwater system (ASW), including two pumps and associated valves (5) Component cooling water system (CCW), including three pumps and associated motor-operated valves (6) Diesel fuel oil system, including two pumps and valves (7) Auxiliary building ventilation system, including fans, dampers, and control cabinets (8) Fuel handling building ventilation system, including fans, dampers, and control cabinets (9) Chemical volume and control system (CVCS), including boric acid transfer pumps, valves, and tank heaters Each of these and the other safety systems are discussed in detail in the appropriate section of this FSAR Update. The safety loads, plus additional important loads that are listed in Tables 8.3-5 and 8.3-6 are served from Class 1E buses at 4.16-kV or 480-V. These buses are designated buses F, G, and H; Unit 1 is shown, with its bus loads, in Figures 8.3-4, 8.3-6, 8.3-7, and 8.3-8. The Unit 1 Class 1E 125-Vdc and 120-Vac instrumentation systems, with their loads, are shown in Table 8.3-11 and Figures 8.3-17 and 7.6-1. The Class 1E 480-V buses are supplied through transformers fed from the Class 1E 4.16-kV buses. These, in turn, are supplied power from both the normal and the emergency power sources described in Sections 8.2 and 8.3. Unit 2 loads and configuration are similar to Unit 1.
8.1.5 DESIGN BASES, CRITERIA, SAFETY GUIDES, AND STANDARDS The electric power system is designed to provide reliable power for all necessary equipment during startup, normal operation, shutdown, and all emergency situations. DCPP UNITS 1 & 2 FSAR UPDATE 8.1-5 Revision 21 September 2013 Design criteria, as well as guides, codes, and applicable standards, are discussed in this section. 8.1.5.1 Design Bases The electrical systems are designed to ensure an adequate supply of electrical power to all essential auxiliary equipment during normal operation and under accident conditions. PG&E Design Class I loads receive power from Class 1E buses that meet the requirements for IEEE Class 1E systems as defined in IEEE 308-1971. Those electrical systems and components which are not classified Class 1E are designated non-Class 1E. Non-Class 1E 4.16-kV auxiliary buses are provided with two power sources: offsite power and power from the main generator. Class 1E buses have an additional source: onsite diesel generators. The Class 1E electrical systems are designed so that failure of any one electrical device will not prevent operation of the minimum required ESF equipment.
The overall plant single line diagram is shown in Figure 8.1-1. The loads on the Class 1E buses and the capabilities of the diesel generators are listed in Section 8.3. 8.1.5.2 Applicable Design Basis Criteria The documents listed in Table 8.1-1 were utilized in the design, construction, testing, and inspection of the electrical systems. Table 8.1-1 designates the electrical systems which have relevance to the indicated design basis criteria. The design basis criteria for each system are addressed in the relevant system sections of Chapter 8. Compliance of electrical systems with the general design criteria, including seismic and environmental qualifications, is also discussed in Chapter 3. 8.1.5.3 Codes and Standards The following codes and standards have been implemented where applicable:
IEEE Standard No. 279-1971, "Criteria for Protection Systems for Nuclear Power Generating Stations"
IEEE Standard No. 308-1971, "Criteria for Class 1E Electric Systems for Nuclear Power Stations"
IEEE Standard No. 317-1971, "Electrical Penetration Assemblies in Containment Structures for Nuclear Power Generating Stations"
DCPP UNITS 1 & 2 FSAR UPDATE 8.1-6 Revision 21 September 2013 IEEE Standard No. 323-1971, "IEEE Trial Use Standard: General Guide for Qualifying Class 1 Electric Equipment for Nuclear Power Generating Stations," except for formal organization of the documentation
IEEE Standard No. 334-1971, "IEEE Trial Use Guide for Type Tests of Continuous Duty Class 1 Motors Installed Inside the Containment of Nuclear Power Generating Stations"
IEEE Standard No. 336-1971, "Requirements for Instrumentation and Electric Equipment During the Construction of Nuclear Power Generating Stations-Installation, Inspection, and Testing"
IEEE Standard No. 344-1971, "Trial Use Guide for Seismic Qualification of Class I Electric Equipment for Nuclear Power Generating Stations"
(NOTE: Original Westinghouse-supplied equipment was qualified to IEEE 344-1971. Specific cases have been supplemented by seismic qualification criteria per IEEE 344-1975, "IEEE Recommended Practices for Seismic Qualification of Class I Electric Equipment for Nuclear Power Generating Stations")
IEEE Standard No. 485-1983, "Recommended Practice for Sizing Large Lead Storage Batteries for Generating Stations and Substations." ANSI Standard C37, 1972 Edition
ANSI Standard C57, 1971 Edition AIEE Publication S-135-1, (1962), "Power Cable Ampacities" IPCEA Standard S-66-524, (1971)
NEMA Standards MG-1, SG-5, SG-6, IC-1, VE-1, TR-1, (1971 Editions)
National Electric Code, 1968 Edition 8.1.6 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures. DCPP UNITS 1 & 2 FSAR UPDATE 8.2-1 Revision 21 September 2013 8.2 OFFSITE POWER SYSTEM The PG&E grid, which operates at several voltage levels, provides power to the DCPP preferred power supply as defined in Section 8.1. DCPP is interconnected to PG&E's electric grid system via two 230-kV and three 500-kV transmission lines emanating from their respective switchyards. These switchyards are physically and electrically separated and independent of each other. The 500-kV transmission lines out from the 500-kV switchyard provide for transmission of the plant's electric power output to the PG&E grid. The numbers of 230-kV and 500-kV transmission lines provide capability beyond that required to meet minimum NRC regulatory requirements to ensure reliability of the offsite power systems. The preferred power supply consists of the two independent circuits (230-kV and 500-kV) from the PG&E transmission networks. The preferred power supply consists of the offsite circuits from the switchyards' DCPP circuit breakers (including associated disconnect switches) 212 (230-kV) and 532, 542, 632 and 642 (500-kV) to the onsite distribution systems. The startup offsite power circuit consists of the 230-kV switchyard breaker (212) and lines to the standby startup transformers and the 12-kV onsite distribution which provides power to the onsite Class 1E 4.16-kV distribution system. The auxiliary offsite power circuit consists of the 500-kV switchyard breakers 532, 542, 632 and 642 and lines to the main transformers and the 25-kV onsite distribution system which also provide power to the onsite Class 1E 4.16-kV distribution system. The 12-kV system, the 25-kV system and the onsite Class 1E 4.16-kV system are addressed in Section 8.3. The startup offsite power circuit provides startup and standby power, and is immediately available following a loss-of-coolant accident to assure that core cooling, containment integrity, and other vital safety functions are maintained. The auxiliary offsite power circuit provides a delayed access source of preferred power supply after the main generator is disconnected following anticipated operational occurrences. A combination of the startup offsite power circuit and the auxiliary offsite power circuit provides the preferred power supply, as required by GDC 17, 1971. 8.2.1 DESIGN BASES 8.2.1.1 General Design Criterion 4, 1967 - Sharing of Systems The startup offsite power circuit is designed with a single line and breaker (212) which is shared with both Units startup offsite circuits. The startup offsite power circuit is designed such that the shared components do not impair plant safety. The startup offsite power circuit is designed with sufficient capacity and capability to operate the engineered safety features (ESF) for a design basis accident (or unit trip) on one unit, and those systems required for a concurrent safe shutdown of the second unit consistent with the requirements of Section 8 of IEEE 308-1971. Additionally, the startup offsite power circuit has sufficient capacity and capability to operate the ESF for a dual unit trip as a result of a seismic event or abnormal operational occurrences. DCPP UNITS 1 & 2 FSAR UPDATE 8.2-2 Revision 21 September 2013 8.2.1.2 General Design Criterion 17, 1971 - Electric Power Systems The DCPP preferred power supply is designed with two physically independent circuits. The preferred power supply has sufficient capacity and capability to assure that: (1) specified fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational occurrences, and (2) the core is cooled and containment integrity and other vital functions are maintained in the event of postulated accidents. Each of the offsite power circuits are designed to be available in sufficient time following a loss of all onsite alternating current power supplies and the other offsite power circuit, to assure that specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded. The startup offsite power circuit provides startup and standby power, and is immediately available following a design basis accident to assure that core cooling, containment integrity, and other vital safety functions are maintained. The auxiliary offsite power circuit provides a delayed access source of preferred power supply after the main generator is disconnected to assure specified fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operation occurrences. The auxiliary offsite power circuit is available in sufficient time to safely shutdown the plant following a loss of the normal onsite power source and the startup offsite power circuit. The combination of the startup offsite power circuit and the auxiliary offsite power circuit provide physical independent sources of preferred power supply, as required by GDC 17, 1971. The preferred power supply is designed to minimize the probability of losing electric power from the transmission network coincident with the loss of onsite power generated by the main generator or the loss of onsite electric power sources (standby power supply as defined in IEEE-308-1971). DCPP maintains protocols with the grid operator to help ensure grid reliability, to ensure that impacts on plant risk are understood, and to ensure the operability of the preferred power supply is maintained. 8.2.1.3 General Design Criterion 18, 1971 - Inspection and Testing of Electric Power Systems The preferred power supply and its components have provisions for periodic inspection and testing. The preferred power supply components have been provided with convenient and safe features for inspecting, and testing. DCPP UNITS 1 & 2 FSAR UPDATE 8.2-3 Revision 21 September 2013 8.2.1.4 Transmission Capacity Requirements Each of the 230-kV transmission lines feeding the DCPP 230-kV switchyard is independently able to support the loads for a design basis accident on one unit and loads required for concurrent safe shutdown on the other unit. 8.2.1.5 Single Failure Requirements The preferred power supply has sufficient independence, capacity and testability to permit the operation of the ESF systems assuming a failure of a single active component. 8.2.1.6 10 CFR 50.63 - Loss of All Alternating Current Power The preferred power supply is used for restoration of offsite power following a station blackout (SBO) event. 8.2.1.7 Safety Guide 32, August 1972 - Use of IEEE Standard 308-1971 Criteria for Class 1E Electric Systems for Nuclear Power Generating Stations Safety Guide 32, August 1972 identifies a conflict between IEEE 308-1971 and GDC 17, 1971 specifically with respect to the time at which the delayed access offsite power circuit is required. Safety Guide 32, August 1972 supports a delayed access offsite power circuit provided that the availability of the delayed access offsite power circuit conforms to the requirements of GDC 17, 1971. The startup offsite power circuit is the immediate source of the preferred power supply following a design basis accident or unit trip. The auxiliary offsite power circuit provides a delayed access source of preferred power supply within sufficient time as required by GDC 17, 1971. 8.2.2 DESCRIPTION 8.2.2.1 230-kV System Offsite electrical power for startup and standby service is provided from the 230-kV system. The two incoming 230-kV transmission lines, one from the Morro Bay switchyard (about 10 miles away) and the other from the Mesa Substation, feed the 230-kV switchyard (refer to Figure 8.1-1). Shunt capacitors at DCPP and Mesa Substations are utilized to provide voltage support when required by the 230-kV grid conditions. Each of the two 230-kV transmission lines feeding the 230-kV switchyard is provided with relay protection consisting of a carrier distance relaying terminal, including carrier distance and directional ground relays, with backup directional ground and fault detector relays, and automatic reclosing. DCPP UNITS 1 & 2 FSAR UPDATE 8.2-4 Revision 21 September 2013 A single tie-line from the 230-kV switchyard supplies the 230-kV/12-kV standby startup transformer for each unit through breaker 212. The 230-kV standby startup service power line from the 230-kV switchyard to the plant is provided with relay protection consisting of a differential pilot wire relay system with overcurrent and fault detector relays for backup. The single line diagram of the grid and the preferred offsite power supply to Units 1 and 2 is shown on Figure 8.1-1. Figure 8.2-3 shows the general location of the 230-kV (and 500-kV) switchyards. Reference 4 shows the arrangement of the 230-kV switch, bus, and circuit breaker structures. Figure 8.2-6 shows the arrangement of the 230-kV/12-kV standby startup transformers. The tap position on each 230-kV/12-kV standby startup transformer load tap changer (LTC) is monitored in the DCPP Main Control Room. Malfunction of the LTC is monitored in the Control Room through indication and annunciator action which could include taking manual control of the LTC or removing the transformer from service. Both units are designed to be supplied from a dedicated startup transformer, with the startup bus Unit 1-Unit 2 cross-tie breaker open. However, a single 230-kV/12-kV standby startup transformer can be aligned to both units via the cross-tie breaker. Operation in this configuration is restricted by Technical Specification. The DCPP surveillance program confirms the availability of the preferred power supply by verifying the correct breaker alignments, voltage levels, capacitor bank status, and any configuration control measures. The automatic load tap changers (LTCs) on the 230-kV/12-kV standby startup transformers, in addition to the grid shunt capacitors, enable the 230-kV system to be independent of Morro Bay generation (References 1 and 2). The 230-kV switchyard dc control power is provided by a lead-acid battery and two battery chargers. Each charger is capable of supplying the normal dc load of the 230-kV switchyard and maintaining the battery in a fully charged condition. Normally, one charger is operating with the second charger available on standby. Both chargers may be operated in parallel if desired. Each charger is equipped with an ac failure alarm that operates on loss of ac to the charger. The battery and chargers feed a 125-Vdc distribution panel that is equipped with a dc undervoltage relay that initiates an alarm if the dc voltage drops below a preset value. Separate dc control circuits are provided from the dc distribution panel for each 230-kV power circuit breaker. 8.2.2.2 500-kV System The 500-kV system provides for transmission of the plant's power output to the grid. The three 500-kV transmission lines, one from the Gates Substation (about 79 miles away) and two other from the Midway Substation (about 84 miles away), feed the DCPP 500-kV switchyard. DCPP UNITS 1 & 2 FSAR UPDATE 8.2-5 Revision 21 September 2013 Each 500-kV transmission line is provided with relay protection terminal equipment consisting of two line relay sets (directional comparison), each operating over physically separate channels, microwave and power line carrier, and each provided with a separate dc power circuit. Single-pole tripping is not enabled for any of the lines. High-speed automatic reclosing is not enabled for the circuit breakers at the DCPP end of the lines. Backup protection (provided by a distance relaying terminal, including distance and directional ground relays) is normally cut-out, and cut-in when either primary relay set is not operable. The 500-kV system provides power for station auxiliaries via the main transformer and the unit auxiliary transformers. Offsite electrical power is also provided from the 500-kV system. A single circuit to each unit from the 500-kV switchyard provides auxiliary offsite power through the 500-kV/25-kV main transformers and through breakers 532 and 632 (Unit 1) and breakers 542 and 642 (Unit 2). The dc motor operated main generator disconnecting switch is opened to provide auxiliary offsite power (backfeed). This telescoping disconnect switch is an integral part of the generator isolated phase bus. This switch is operated under manual control from the control room and is interlocked to prevent opening under load. Upon actuation, the motor-operated disconnect switch takes approximately 30 seconds to isolate the main generator from the main and the unit auxiliary transformers. In the event of a loss of main generator output, the auxiliary offsite power circuit could be placed in service after approximately 30 minutes. The position of the motor-operated disconnect switch is verified prior to backfeeding from the 500-kV switchyard. The position of the motor-operated disconnect switch is verified prior to backfeeding from the 500-kV switchyard.
Figure 8.1-1 (plant single line diagram) shows the three 500-kV transmission lines from the transmission network to the interconnections to the plant auxiliaries. Figure 8.2-3 shows the general location of the 230-kV and 500-kV switchyards. Reference 5 shows the arrangement of the 500-kV switches, buses, and circuit breaker structures. Each 500-kV line between the 500-kV switchyard and a generator step-up transformer bank is provided with redundant current differential protection channels. Directional over-current relays are available as backup. A Special Protection Scheme (SPS) supplements the existing DCPP 500-kV switchyard/line protection. Refer to Section 8.2.3.2.2. The 500-kV switchyard dc control power is provided by a lead-acid battery and two battery chargers. Each charger is capable of supplying the normal dc load of the 500-kV switchyard and maintaining the battery in a fully charged condition. Normally, one charger is operating with the second charger available on standby. Both chargers may be operated in parallel, if desired. Each charger is equipped with an ac failure alarm that operates on loss of ac to the charger. The battery and chargers feed two 125-Vdc distribution panels, one of which is equipped with a dc undervoltage relay that initiates an alarm if the dc voltage should drop below a preset value. Separate dc control circuits are provided for each 500-kV power circuit breaker.
DCPP UNITS 1 & 2 FSAR UPDATE 8.2-6 Revision 21 September 2013 8.2.3 SAFETY EVALUATION 8.2.3.1 General Design Criterion 4, 1967 - Sharing of Systems The startup offsite power circuit is designed such that the single 230-kV line from the 230-kV switchyard, including breaker 212, is shared by both Unit 1 and Unit 2 startup offsite power circuits. The shared components have sufficient capacity to operate the ESF for a design basis accident (or unit trip) on one unit, and those systems required for a concurrent safe shutdown of the second unit consistent with the requirements of Section 8 of IEEE 308-1971. Additionally, the startup offsite power circuit has sufficient capability to operate the ESF for a dual unit trip as a result of a seismic event or abnormal operational occurrences (Reference 8). The capacity of the shared startup offsite power circuit components is evaluated to ensure that a spurious ESF actuation on the non-accident unit, concurrent with a design basis accident on the other unit, would not result in the loss of the preferred power supply. Both units are designed to be supplied from a dedicated startup transformer, with the startup bus Unit 1-Unit 2 cross-tie breaker open. However, a single 230-kV/12-kV standby startup transformer can be aligned to both units via the cross-tie breaker. Operation in this configuration is restricted by Technical Specification. 8.2.3.2 General Design Criterion 17, 1971 - Electric Power Systems 8.2.3.2.1 Preferred Power Supply The preferred power supply is designed to provide two physically independent offsite power circuits (from the 230-kV and the 500-kV systems) for the Class IE buses. The startup offsite power circuit is the 230-kV power supply which includes the first inter-tie breaker (212) at the 230-kV switchyard, 230-kV/12-kV standby startup transformers and includes all equipment downstream such as transformers, switches, interrupting devices, cabling, and controls up to the Class 1E buses. The startup offsite power circuit is designed to provide the immediate access preferred power supply from the 230-kV switchyard to the Class 1E buses within a few seconds after a loss-of-coolant accident. The auxiliary offsite power circuit is the 500-kV power supply which includes inter-tie breakers (generator output breakers 532 and 632 for Unit 1, breakers 542 and 642 for Unit 2) at the 500-kV switchyard, 500-kV/25-kV main transformers and all equipment downstream such as isophase bus, breakers, transformers, switches, interrupting devices, cabling, and controls up to the Class 1E buses. The auxiliary offsite power circuit is designed to provide the delayed access source of preferred power supply from the 500-kV switchyard to the Class 1E buses after the main generator motor operated disconnect switch is opened. The auxiliary offsite power circuit is available in sufficient time to safely shutdown the plant following a loss of the auxiliary onsite power source and the startup offsite power circuit (refer to Section 8.2.3.7). DCPP UNITS 1 & 2 FSAR UPDATE 8.2-7 Revision 21 September 2013 The combination of the startup offsite power circuit and the auxiliary offsite power circuit provide physical independent sources of preferred power supply, as required by GDC 17, 1971. The preferred power supply is designed to minimize the probability of losing electric power from the transmission network coincident with the loss of onsite power generated by the main generator or the loss of onsite electric power sources (standby power supply as defined in IEEE-308-1971). 8.2.3.2.2 Analysis 8.2.3.2.2.1 Grid Load Flow Analysis Load flow analyses are performed for anticipated configurations of the grid (e.g., generating units out of service, transmission line(s) out of service, or voltage control devices out of service). For postulated design-basis events, the transmission system is assumed to be in steady state. Any external condition affecting the transmission network is assumed to occur in sufficient time prior to the transfer to the 230-kV system such that the voltage on the 230 kV/12 kV LTC has adjusted to the transient. PG&E's Grid Control Center controls the DCPP 230-kV switchyard voltage to meet or exceed the minimum allowed pre-trip voltage. The minimum voltage from the transmission network at the DCPP 230-kV switchyard is maintained at or above 218-kV for normal operation with all transmission lines in service. The minimum voltage from the transmission network at the DCPP 500-kV switchyard is maintained at or above 512-kV. With both DCPP units off-line, the preferred power supply is capable of providing 104 MW and 78 MVAR to DCPP for normal operation, safe shutdown and design basis accident mitigation. Depending upon system load and available voltage support, a degraded grid voltage condition could occur and result in DCPP configuration control measures (refer to Section 8.2.3.2.2.2). PG&E operating procedures are used by the California Independent System Operator (CAISO), Grid Control Center, the Diablo Canyon Control Center, and DCPP.
Configuration control measures and the voltages required to maintain operability are reviewed annually. The purpose of the review is to examine major changes in system load projections, generating capacity, and transmission grid connections. PG&E's Energy Delivery engineering staff performs the load flow studies using the current analytical model of the entire Western Electricity Coordinating Council (WECC). The initial conditions for the studies include the peak system loading, and only one DCPP unit generating. The 230-kV configurations modeled include all local transmission elements in service; one line out of service; two parallel lines out of service; split buses at nearby 230-kV substations; and capacitor banks unavailable. The results of the studies are calculated system equivalents and voltages with and without DCPP loading DCPP UNITS 1 & 2 FSAR UPDATE 8.2-8 Revision 21 September 2013 for each configuration. The results of the system load flow studies ensure transmission voltages are adequate to support a postulated DCPP post trip load transfer. 8.2.3.2.2.2 DCPP Load Flow and Dynamic Loading Analysis The startup offsite power circuit is the immediate source of preferred power supply following a design basis accident or unit trip. The DCPP design and licensing basis requires that the startup offsite power circuit have sufficient capacity and capability to: (1) operate the ESFs for a design-basis accident on one unit and concurrent safe shutdown (safe shutdown includes a unit trip) on the other unit, and (2) operate the ESFs for dual unit trips as a result of a seismic event or abnormal operational occurrences. Existing DCPP calculations demonstrate the capacity of the preferred power supply for anticipated operational occurrences and postulated post accident conditions. The calculations demonstrate that the preferred power supply has sufficient capacity and capability to start and operate the required loads. Depending upon system load and available voltage support, a degraded grid voltage condition can result. DCPP configuration control measures, including blocking the transfer of non-essential loads, may be necessary for certain transmission network configurations to ensure adequate voltage to the Class 1E buses and return to the startup offsite power circuit to operable status. PG&E operating procedures identify when configuration control measures are necessary based on surrounding area load, voltage, and the availability of critical transmission elements. When notified of adverse grid conditions, DCPP operating procedures identify what configuration control measures to invoke. Continued operation of the DCPP units under these conditions is procedurally controlled to ensure the preferred power supply meets DCPP operability requirements. Configuration control measures and the voltages required to maintain operability are reviewed annually. DCPP dynamic loading analyses are then performed, using the results of the transmission load flow studies as input. The DCPP analyses determine if the calculated voltages are adequate for starting of required plant loads and for the bus transfer to the startup offsite power circuit following a design basis accident on one unit and concurrent safe shutdown of the second unit, or a dual unit trip following a seismic event or other abnormal operational occurrences. If the voltages and existing configuration control measures are not adequate, the analysis is rerun with additional configuration control measures. Analyses are also performed to examine the effect of one 230 kV/12-kV standby startup transformer being unavailable, and for manual 230-kV/12-kV standby startup transformer LTC operation. DCPP procedures (which provide configuration control measures for the preferred power supply operability) are then modified to reflect the results of the analyses.
DCPP UNITS 1 & 2 FSAR UPDATE 8.2-9 Revision 21 September 2013 8.2.3.2.2.3 Grid Stability Analysis The licensing basis requires the grid to remain stable (no complete loss of power from the preferred power source) following the loss of a generator, the loss of a large load block, or a fault on the most critical transmission line. Grid stability analyses are performed periodically whenever there is a significant change in generation, load, or transmission capability to ensure that this criterion is met. These analyses, and the load flow and dynamic loading analyses discussed above, are done to demonstrate compliance with GDC 17, 1971. The fundamental purpose of the grid is to move electric power from the areas of generation to the areas of customer demand. The transmission network should be capable of performing this function under a wide variety of expected conditions. In addition to the more probable forced and planned outage contingencies, the planned ability to withstand less probable contingencies measure the robustness of a system.
The California transmission network (control area under CAISO) is designed and operated to comply with WECC reliability criteria (Reference 6). These criteria establish performance requirements for numerous grid contingencies, including the DCPP license basis contingencies which consist of the loss of any generator, the loss of a large load block, or a fault on the most critical transmission line.
The WECC criteria define four levels of transmission events, as follows:
Category A: No contingency, all facilities in service Category B: Events resulting in the loss of a single grid element Category C: Events resulting in the loss of two or more elements Category D: Extreme events resulting in two or more (multiple elements removed or cascading out of service)
The DCPP licensing basis contingencies identified earlier in this section are consistent with the above WECC Category B events. CAISO compliance with WECC Category B ensures the availability of offsite power to DCPP because the loss of multiple elements and cascading are not involved. The Category C and D events are beyond the licensing basis to satisfy GDC 17, 1971 criteria. CAISO compliance with WECC Category C and select Category D contingencies provides additional margin to ensure an adequate offsite power to Diablo Canyon Units by protecting against dual unit trips.
Grid stability analyses are performed periodically by PG&E Electrical Operations whenever there is a significant change in generation, load, or transmission capability (based on an annual review of configuration control measures and voltages required to maintain operability) to ensure that the Category B criterion is met. DCPP UNITS 1 & 2 FSAR UPDATE 8.2-10 Revision 21 September 2013 The model used in these studies represents PG&E grid and the interconnected western states in sufficient detail so that they properly address the electromechanical reaction of the combined systems to the cases studied. Scenarios modeled by PG&E include both a single-unit trip and a dual-unit trip of DCPP. Both worst case summer and winter loadings are simulated because the total area load and available generation varies with the season.
Assuming one DCPP unit already shutdown, the grid stability study concluded that the loss of the remaining generating unit at the Diablo Canyon site has little effect on the preferred power supply feeding the DCPP switchyard 230-kV buses and will not result in the complete loss of the preferred power supply. Both voltage and frequency will stabilize within several seconds. For a single-unit trip, the availability of the preferred power supply to the ESFs at Diablo Canyon will not be affected. For a dual-unit trip (WECC Category C event), the 230-kV switchyard will remain energized (i.e., non-cascading event). 8.2.3.2.2.4 Operation During Severe Grid Disturbances Analysis The CAISO exercises centralized control over generation and transmission facilities within California. CAISO schedules electric generation and operates the transmission network to minimize cascading during severe transmission network disturbances. The CAISO also coordinates the scheduled outage of the electric generation and transmission facilities for preventive maintenance and repair, thereby ensuring a nearly constant level of system reliability. It is the CAISO's responsibility to carry, at all times, operating reserve to satisfy the WECC Reliability Criteria and meet the requirements of the North American Electric Reliability Council.
To preserve the integrity of generating units during extreme grid disturbances, nuclear power plants (including DCPP) will be given the highest priority for restoration of power to their switchyards. PG&E and the CAISO have emergency restoration plans in place to utilize combustion turbine units, hydroelectric units, and the transmission grid to provide startup power to its major thermal electric generating plants. PG&E has several megawatts (MW) of its own hydro-generation within its control area that assists the grid through disturbances.
System disturbances can be initiated by trouble either within the CAISO control area or external to it. The 500-kV ac Pacific Intertie, running the length of PG&E's grid, provides an internal transmission network with ties to neighboring utilities. If the grid is subjected to a severe disturbance caused by upset conditions external to the PG&E grid, underfrequency protective relaying has been provided that will activate at the interface. This relaying automatically separates the PG&E grid from its neighbors DCPP UNITS 1 & 2 FSAR UPDATE 8.2-11 Revision 21 September 2013 should frequency drop below relay settings in accordance with Exhibit A of PG&E Utility Standard S1426 for Tie Lines. The WECC has prepared a coordinated response to underfrequency events. A coordinated response by all utilities and generation owners under WECC jurisdiction maximizes the integrity of the grid. PG&E has implemented a multi-step load shed scheme within WECC guidelines to maintain a balance between load and generation.
These guidelines include the separation of generation based on underfrequency setpoints that have been coordinated within the WECC areas of control. All setpoints for load shedding and generation tripping have been selected to minimize equipment damage and provide long term grid reliability. To minimize the possibility of a cascading failure and the possibility of severe overloading of generating units, underfrequency load shedding is used to automatically relieve load during an extreme emergency. This load is removed automatically in increments based on declining frequency. Should these measures fail to arrest system frequency decay, provisions have been made to automatically separate thermal power plants from the transmission network should abnormal low frequency conditions develop. DCPP has implemented setpoints and durations for conditions corresponding to those specified in Exhibit A of PG&E Utility Operations Standard S1426 for Thermal Power Plants. Additional manual load shedding may be required to stabilize the grid. Hydroelectric units connected to the transmission network have a broad capability to operate during underfrequency conditions. The hydroelectric units' underfrequency setpoints are lower than the thermal power plants, although most hydroelectric units do not have underfrequency control and would remain connected and continue to provide power to the transmission system. A Special Protection Scheme (SPS) has been added to supplement the existing DCPP 500-kV switchyard/line protection. This SPS was designed and installed by PG&E's transmission organization. An SPS is designed to detect abnormal grid conditions and take pre-planned, corrective action (other than the isolation of faulted elements) to provide acceptable grid performance. SPS actions may include, among others, changes in demand (e.g., load shedding), generation, or system configuration to maintain grid stability, acceptable voltages, or acceptable facility loadings. The use of an SPS is an acceptable transmission practice to meet the grid performance requirements as defined under WECC Categories A, B, or C. The Diablo Canyon switchyard SPS was installed to mitigate the potential loss of two Diablo Canyon Units after the occurrence of certain 500-kV Category C events. These events, if left unmitigated, would result in the loss of both Diablo Canyon Units. The SPS will prevent voltage dips that are in violation of the WECC standards. The SPS system will selectively open the generator output breakers of one generating unit (i.e., load rejection) when the pre-defined conditions exist regarding the DCPP outlet lines. The purpose of this corrective action is to prevent intensive swings that would otherwise result in the trip of both units by either RCP undervoltage or generator out-of-step protection. DCPP UNITS 1 & 2 FSAR UPDATE 8.2-12 Revision 21 September 2013 The measures outlined above, together with others, provide the basis for PG&E's confidence that the offsite power sources to the Diablo Canyon site are extremely reliable. The interconnection of Diablo Canyon to the 500-kV transmission network by way of Midway and Gates switchyards, and to the 230-kV transmission network by way of Morro Bay switchyard and Mesa substation, ensures access to PG&E's electrical grid systems. 8.2.3.3 General Design Criterion 18, 1971 Inspection and Testing of Electric Power Systems Periodic testing and surveillance of the standby startup transformers, unit auxiliary transformers, and the main transformer are part of the normal DCPP program for oil-filled transformers.
The DCPP surveillance program confirms the availability of the preferred power supply by verifying the correct breaker alignments, voltage levels, capacitor bank status, and any configuration control measures. 8.2.3.4 Transmission Capacity Requirements Each of the two 230-kV transmission lines feeding the DCPP 230-kV switchyard is independently able to support the loads for a design basis accident on one unit and loads required for concurrent safe shutdown on the other unit. The startup preferred power supply from the transmission network including the 230-kV/12-kV standby startup offsite power circuit is designed in a manner intended to obtain a high degree of service reliability and to minimize the time and extent of outage if failures do occur. Other than the failure mechanisms identified in Section 8.2.3.5, the startup offsite power circuit is designed for the following normal grid conditions: (1) Each transmission line (as described in Section 8.2.2) in service with full capacity. (2) Voltage support devices such as the automatic load tap changers and capacitor banks at DCPP and Mesa in service (3) Operating at full load under maximum expected transmission system load The startup offsite power circuit is capable of mitigating a design basis event without reliance on manual operator actions to restore capability. This startup offsite power circuit capability includes automatic operation of voltage support devices and transmission switching systems to re-stabilize the system following a loss of a single generator in the transmission network, transmission line, or voltage support device. For off normal conditions (e.g., following a loss of a single generator in the transmission network, transmission line, or voltage support device) such that transmission from one of the two 230-kV transmission lines is degraded, configuration control measures, that DCPP UNITS 1 & 2 FSAR UPDATE 8.2-13 Revision 21 September 2013 include the blocking of selective large loads (e.g., 12-kV buses D and E auto transfer, condensate/condensate booster pumps auto start), are required to maintain operability (capability to mitigate an accident in one unit and a concurrent trip of the other unit) from the other 230-kV transmission line. These configuration control measures are procedurally controlled based on grid conditions. 8.2.3.5 Single Failure Requirements The preferred power supply is designed such that both the offsite and the onsite power systems have sufficient independence, capacity and testability to permit the operation of the ESF systems assuming a failure of a single active component in each system. The combination of either two 230-kV line plus the 500-kV system provides a high degree of assurance that offsite power will be available when required. Occurrences that could result in the loss of the startup offsite power circuit are described below. Note that these occurrences do not result in a loss of the auxiliary offsite power circuit and therefore ensure the preferred power supply is available in the event of a loss of the startup offsite power circuit. (1) Loss of Morro Bay Switchyard or loss of both circuits of the 230-kV transmission line in the sections between the Morro Bay switchyard and Diablo Canyon site. It is noted that an outage of any one of the three 230-kV circuits (Morro Bay-Diablo Canyon, Diablo Canyon-Mesa, or Morro Bay-Mesa) would not result in interruption of the transmission supply to Diablo Canyon. (2) Loss of the 230-kV bus structure at the Diablo Canyon site. This 230-kV structure has a double bus arranged so that either bus can supply the feed to the 230-kV/12-kV standby startup transformers. A permanently faulted bus section can be isolated from the remaining unfaulted bus section by means of manual switching operations. These structures are suitably spaced from one another. Only an event of great physical extent would cause the loss of both buses. (3) Loss of the 230-kV line from the Diablo Canyon switchyard to the 230-kV/12-kV standby startup transformers, or loss of its associated 230-kV oil circuit breaker. If the power loss is due to mechanical or electrical failure of the oil circuit breaker, the circuit breaker can be isolated and bypassed by means of manual switching operations. A physical disruption of the short section of 230-kV line from the switchyard to the plant is considered highly unlikely. (4) Loss of either 230-kV/12-kV standby startup transformer 11 or 21 or the associated 12-kV breakers or buses. Standby startup transformers 11 and 21 are normally separated on the 12-kV side, with transformer 11 feeding Unit 1 and transformer 21 feeding Unit 2. In case of a failure of DCPP UNITS 1 & 2 FSAR UPDATE 8.2-14 Revision 21 September 2013 either transformer, the faulted transformer can be manually switched out of service, its bus can then be transferred to the other transformer by closing the 12-kV bus tie vacuum circuit breaker. This circuit breaker is common to the 12-kV standby startup buses of Units 1 and 2, and is normally kept open (i.e., procedurally controlled). (5) Failure of 12-kv/4.16-kV standby startup transformer 12 (22). By means of manual switching after a failure, the buses served from this transformer can be supplied from the 230-kV system by unit auxiliary transformer 12 (22) through unit auxiliary transformer 11 (21), fed from the 12-kV standby startup bus. This requires removal of links in the generator bus at the main transformer as well as opening of the disconnecting switch to the generator. This is an unusual configuration and is used only when better methods are not available. 8.2.3.6 10 CFR 50.63 Loss of All Alternating Current Power The 230-kV system or the 500-kV system is used for restoration of offsite power following a station blackout (SBO). The plant procedures for SBO use several different flow paths to restore ac power and place the plant in a safe, controlled condition. Refer to Section 8.3.1.6 for additional discussion. 8.2.3.7 Safety Guide 32, August 1972 Use of IEEE Standard 308-1971 Criteria for Class 1E Electric Systems for Nuclear Power Generating Stations Safety Guide 32, August 1972 identifies a conflict between IEEE 308-1971 and GDC 17, 1971 specifically with respect to the time at which the delayed access circuit is required. Safety Guide 32, August 1972 allows a delayed access circuit provided that the availability of the delayed access circuit conforms to requirements of GDC 17, 1971. The startup offsite power circuit provides standby startup power, and is immediately available following a loss-of-coolant accident to assure that core cooling, containment integrity, and other vital safety functions are maintained. The auxiliary offsite power circuit provides a delayed access source of preferred power supply to the plant auxiliary systems and Class 1E buses when the main generator is not in operation. The auxiliary offsite power circuit is available in sufficient time to safely shutdown the plant following anticipated operational occurrences. In the event of a loss of main generator output, the auxiliary offsite power circuit could be placed in service after about 30 minutes to ensure that specified acceptable fuel design limits and design conditions of the reactor coolant boundary are not exceeded. The position of the motor-operated disconnect switch is verified prior to backfeeding from the 500-kV switchyard.
DCPP UNITS 1 & 2 FSAR UPDATE 8.2-15 Revision 21 September 2013 After the two 500-kV breakers are opened, operations personnel coordinate with PG&E's Grid Control Center to realign plant protective relaying; open the generator disconnect; and re-close the generator output breakers. 8.2.4 TESTS AND INSPECTIONS Refer to Section 8.2.3.3 for inspection and testing of electric power systems. 8.2.5 INSTRUMENTATION APPLICATIONS The tap position on each 230-kV/12-kV startup/standby transformer LTC is monitored in the DCPP Main Control Room. Malfunctioning of the LTC is alarmed in the Main Control Room. 8.
2.6 REFERENCES
- 1. License Amendment Request 98-01 submitted to the NRC by PG&E letters DCL-98-008, dated January 14, 1998; DCL-98-076, dated May 19, 1998; DCL-99-013, dated February 5, 1999, and DCL-99-018, dated February 5, 1999.
Also PG&E letter DCL-99-014, dated February 5.
- 2. NRC letter to PG&E, dated April 29, 1999, granting License Amendments No. 132 to Unit 1 and No. 130 to Unit 2.
- 3. Deleted in Revision 21. 4. PG&E Substation and Transmission Drawing 435895, "Arrangement of 230-kV Switch, Bus, and Circuit Breaker Structures (DCPP)"
- 5. PG&E Substation and Transmission Drawing 57486, "Arrangement of 500-kV Switch, Bus, and Circuit Breaker Structures (DCPP)"
- 6. WECC "Reliability Criteria", Part 1, "NERC/WECC Planning Standards"
- 7. IEEE Standard 308-1971, Criteria for Class IE Electric Systems for Nuclear Power Generation
- 8. NRC Letter to PG&E, dated December 14, 2009, Safety Evaluation, Diablo Canyon Power Plant, Unit Nos. 1 and 2 - Request for Technical Specification Interpretation of 230 Kilovolt System Operability (TAC Nos. ME0711 and ME0712).
DCPP UNITS 1 & 2 FSAR UPDATE 8.2-16 Revision 21 September 2013 8.2.7 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-1 Revision 21 September 2013 8.3 ONSITE POWER SYSTEMS The onsite power systems consist of all sources of electric power and their associated distribution systems within the DCPP. Included are the main generators, emergency diesel generators (EDGs), and the vital and nonvital station batteries. 8.3.1 AC POWER SYSTEMS As described in the introduction (Section 8.1), the onsite ac systems consist of the 25-kV, 12-kV, 4.16-kV, and 480-V power systems, the 208Y/120-V lighting system, and the 120-Vac instrument supply systems. 8.3.1.1 Description Auxiliary power for normal plant operation is supplied by each unit's main generators through the unit auxiliary transformers (see Figure 8.1-1), except during startups and shutdowns. Auxiliary power for startups and shutdowns is supplied by offsite power sources. If offsite power is unavailable, auxiliary shutdown power is furnished by the emergency diesel generators. 8.3.1.1.1 25-kV System As described in Section 8.2.2.2, the auxiliary offsite power circuit consists of the 500-kV switchyard breakers 532, 542, 632 and 642 and lines to the main transformers and the portion of the 25-kV onsite distribution system which provide power to the onsite Class 1E 4.16-kV distribution system. 8.3.1.1.1.1 Design Bases 8.3.1.1.1.1.1 General Design Criterion 17, 1971 - Electric Power Systems The auxiliary offsite power circuit provides a delayed access source of preferred power supply after the main generator is disconnected to assure specified fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operation occurrences. The auxiliary offsite power circuit is available in sufficient time to safely shut down the plant following a loss of the normal onsite power source and the startup offsite power circuit. 8.3.1.1.1.1.2 General Design Criterion 18, 1971 - Inspection and Testing of Electric Power Systems The 25-kV system design permits appropriate periodic inspection and testing of functional and operational performance of the system as a whole and under conditions as close to design as practical. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-2 Revision 21 September 2013 8.3.1.1.1.1.3 10 CFR 50.63 - Loss of All Alternating Current Power The 25-kV system is used for restoration of the preferred power supply following a station blackout (SBO). 8.3.1.1.1.1.4 Safety Guide 32, August 1972 - Use of IEEE Standard 308-1971, Criteria for Class 1E Electrical Systems for Nuclear Power Generating Stations Safety Guide 32, August 1972 identifies a conflict between IEEE 308-1971 and GDC-17, 1971 with respect to the time at which the delayed access offsite power circuit is required. Safety Guide 32, August 1972 supports a delayed access offsite power circuit provided that the availability of the delayed access offsite power circuit conforms to the requirements of GDC 17, 1971. The auxiliary offsite power circuit provides a delayed access source of preferred power supply within sufficient time as required by GDC 17, 1971, after the main generator is disconnected. 8.3.1.1.1.1.5 Single Failure Requirements The preferred power supply has sufficient independence, capacity and testability to permit the operation of the ESF systems assuming a failure of a single active component. 8.3.1.1.1.2 System Description The main electrical generator output voltage is 25-kV. Approximately 96 percent of the generated power is transformed to 500-kV at the main transformers, and the remainder is transformed to 12-kV and 4.16-kV at the unit auxiliary transformers. The portion of the 25-kV system which is part of the auxiliary offsite power circuit provides access to the 500-kV preferred power supply after the main generator is disconnected by operating the isophase bus motor operated generator disconnect switch. 8.3.1.1.1.3 Safety Evaluation 8.3.1.1.1.3.1 General Design Criterion 17, 1971 - Electric Power Systems The portion of the 25-kV system which is part of the auxiliary offsite power circuit is designed to assure specified fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded in the event of the loss of the standby power source or the startup offsite power circuit. The capability and capacity of the auxiliary offsite power circuit is adequate to power both ESF and non-ESF functions. Refer to Section 8.2.3.2. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-3 Revision 21 September 2013 8.3.1.1.1.3.2 General Design Criterion 18, 1971 - Inspection and Testing of Electric Power Systems Periodic testing and surveillance of the 500-kV/25-kV main transformers and the 25-kV/4.16-kV transformers are part of the normal DCPP program for oil-filled transformers. The DCPP surveillance program confirms the availability of the auxiliary offsite power circuit by verifying the correct 25-kV isolated phase bus motor operated disconnect (MOD) switch alignment and voltage levels. 8.3.1.1.1.3.3 10 CFR 50.63 - Loss of All Alternating Current Power The 25-kV system is a part of the auxiliary offsite power circuit used for restoration of the preferred power supply following a SBO. Refer to Section 8.3.1.6 for further discussion of SBO. 8.3.1.1.1.3.4 Safety Guide 32, August 1972 - Use of IEEE Standard 308-1971, Criteria for Class 1E Electrical Systems for Nuclear Power Generating Stations The portion of the 25-kV system which is part of the auxiliary offsite power circuit provides access to the auxiliary offsite power circuit after the main generator is disconnected. Refer to Section 8.2.3.7. 8.3.1.1.1.3.5 Single Failure Requirements A failure of a single active component in the 25-kV portion of the auxiliary offsite power circuit does not result in a complete loss of the preferred power supply. Refer to Section 8.2.3.5. 8.3.1.1.1.4 Tests and Inspections Refer to 8.3.1.1.1.3.2 for test and inspection details. 8.3.1.1.1.5 Instrumentation Applications Equipment monitoring instrumentation is provided for the 25-kV isophase bus and main transformer banks. 8.3.1.1.2 12-kV System As described in Section 8.2.2.1, the startup offsite power circuit consists of the 230-kV switchyard breaker (212) and lines to the standby startup transformers and a portion of the 12-kV onsite distribution which provides power to the onsite Class 1E 4.16-kV distribution system. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-4 Revision 21 September 2013 8.3.1.1.2.1 Design Bases 8.3.1.1.2.1.1 General Design Criterion 2, 1967 - Performance Standards The portion of the 12-kV system which provides input to the reactor trip system (RTS), undervoltage (UV) relays and underfrequency (UF) relays, is designed to withstand the effects of, or is protected against, natural phenomena such as earthquakes, flooding, tornadoes, winds, and other local site effects. 8.3.1.1.2.1.2 General Design Criterion 4, 1967 - Sharing of Systems The 12-kV system and components are not shared by the DCPP Units unless safety is shown to not be impaired by the sharing. 8.3.1.1.2.1.3 General Design Criterion 11, 1967 - Control Room The 12-kV system is designed to support actions to maintain and control the safe operational status of the plant from the control room. 8.3.1.1.2.1.4 General Design Criterion 12, 1967 - Instrumentation and Control System Instrumentation and controls are provided as required to monitor and maintain 12-kV system variables within prescribed operating ranges. 8.3.1.1.2.1.5 General Design Criterion 15, 1967 - Engineered Safety Features Protection Systems The 12-kV system design provides input to the solid state protection system (SSPS) through bus monitoring UV and UF relays for the reactor coolant pumps (RCPs). The UV and UF relays monitor the 12-kV bus for accident situations through potential transformer sensing circuits. 8.3.1.1.2.1.6 General Design Criterion 17, 1971 - Electric Power Systems The startup offsite power circuit is designed to provide an immediate access source of preferred power supply from the 230-kV switchyard to the ESF buses within a few seconds after a loss-of-coolant accident. A portion of the 12-kV system (from the standby startup transformer 11(21) through the standby startup transformer 12(22) to the 4.16-kV Class 1E buses) is designed with sufficient capacity and capability, and is immediately available to operate the engineered safety features following a design basis accident to assure that core cooling, containment integrity, and other vital safety functions are maintained. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-5 Revision 21 September 2013 8.3.1.1.2.1.7 General Design Criterion 18, 1971 - Inspection and Testing of Electric Power Systems The 12-kV system design permits appropriate periodic inspection and testing of functional and operational performance of the system as a whole and under conditions as close to design as practical. 8.3.1.1.2.1.8 General Design Criterion 49, 1967 - Containment Design Basis The 12-kV system circuits routed through containment electrical penetrations are designed to support the containment design basis such that the containment structure can accommodate, without exceeding the design leakage rate, pressure and temperatures following a loss-of-coolant accident. 8.3.1.1.2.1.9 Single Failure Requirements The preferred power supply has sufficient independence, capacity and testability to permit the operation of the ESF systems assuming a failure of a single active component in the 12-kV system. 8.3.1.1.2.1.10 10 CFR 50.63 - Loss of All Alternating Current Power The 12-kV system is a part of the auxiliary offsite power circuit used for restoration of the preferred power supply following a SBO. 8.3.1.1.2.1.11 Safety Guide 32, August 1972 - Use of IEEE Standard 308-1971 Criterion for Class 1E Electric Systems for Nuclear Power Generating Stations Safety Guide 32, August 1972 identifies a conflict between IEEE 308-1971 and GDC 17, 1971 specifically with respect to the time at which the delayed access offsite power circuit is required. Safety Guide 32, August 1972 supports a delayed access offsite power circuit provided that the availability of the delayed access offsite power circuit conforms to the requirements of GDC 17, 1971. The startup offsite power circuit is the immediate source of the preferred power supply following a design basis accident or unit trip. 8.3.1.1.2.1.12 Regulatory Guide 1.63, Revision 1, May 1977 - Electrical Penetration Assemblies in Containment Structures for Light-Water-Cooled Nuclear Plants The 12-kV circuits routed through containment electrical penetrations are designed to the requirements of Regulatory Guide 1.63, Revision 1 regarding installation of redundant or backup fault current protection devices to limit fault current to less than DCPP UNITS 1 & 2 FSAR UPDATE 8.3-6 Revision 21 September 2013 that which the penetration can withstand, assuming a single random failure of the circuit overload protective device. 8.3.1.1.2.2 System Description The 12-kV system for each unit is a three-phase, three-wire, high-resistance-grounded non-Class 1E system that serves two circulating water pumps and the four reactor coolant pumps. The loads are divided into two groups, each served by a separate bus having two sources: one from the main generator through the unit auxiliary transformer 11(21) and one from the 230-kV transmission system through standby startup transformer 11(21), as shown in Figures 8.1-1, 8.3-1, 8.3-2, and 8.3-5. Auxiliary buildings and other loads not associated with power generation are normally fed from two 12-kV circuit breakers on the startup bus of each unit. The 12-kV system is provided with metalclad switchgear located indoors. Refer to Figures 8.1-1, 8.3-2 and 8.3-5 for detailed component ratings and vendor information. Each bus section is separated from the other by an aisle space, and each circuit breaker cubicle is separated from adjacent units by metal barriers. The 230-kV/12-kV standby startup transformer 11(21) load tap changers (LTCs) are described in Section 8.2.2. A grounding transformer is provided on each 12-kV source. No ESF loads are served at 12-kV; however, the startup bus is part of the startup offsite power circuit between the 230-kV switchyard and the 4.16-kV Class 1E buses for each respective unit (refer to Figure 8.1-1). 8.3.1.1.2.3 Safety Evaluation 8.3.1.1.2.3.1 General Design Criterion 2, 1967 - Performance Standards The 12-kV undervoltage and underfrequency circuits are contained within the PG&E Design Class II turbine building. This building or applicable portions have been designed not to impact PG&E Design Class I components and associated safety functions. Refer to Sections 3.2.1, 3.3.2.3.2.8, 3.4.1, 3.5.1.2, and 3.7.2.1.7.2 for additional information. Analyses have been performed to assure that the lack of seismic qualification and seismic installation of these inputs will not degrade the function of the RTS from these monitoring channels. Refer to Section 7.2.1.1.10 for additional discussion. 8.3.1.1.2.3.2 General Design Criterion 4, 1967 - Sharing of Systems The 12-kV system is designed with cross-tie capability to align a single 230-kv/12-kv standby startup transformer (11 or 21) to provide power to both units via the cross-tie breaker. Operation in this configuration is restricted by Technical Specification. The shared portion of the 12-kV system is designed with sufficient capacity and capability to operate the engineered safety features for a design basis accident (or unit trip) on one DCPP UNITS 1 & 2 FSAR UPDATE 8.3-7 Revision 21 September 2013 unit, and those systems required for a concurrent safe shutdown of the second unit consistent with the requirements of IEEE 308-1971, Section 8 (Reference 3). 8.3.1.1.2.3.3 General Design Criterion 11, 1967 - Control Room Each 12-kV bus is provided with a voltmeter and ammeter mounted on the control room main control board for remote indication to facilitate actions that maintain the safe operational status of the plant. 8.3.1.1.2.3.4 General Design Criterion 12, 1967 - Instrumentation and Control Systems The startup switchgear has internally mounted potential transformers (PT) and current transformers (CT) for maintaining and operating the 12-kV system within prescribed operating ranges through use of the 230-kV/12-kV standby startup transformer 11(21) load tap changer (LTC). Refer to Section 8.2.2.1 for additional discussion. 8.3.1.1.2.3.5 General Design Criterion 15, 1967 - Engineered Safety Features Protection Systems The 12-kV system provides input to the SSPS for reactor protection through UV and UF sensors. Refer to Section 7.2.1.1.1.4 for additional discussion. 8.3.1.1.2.3.6 General Design Criterion 17, 1971 - Electric Power System The DCPP offsite power system is designed to supply offsite electrical power by two physically independent circuits. The portion of the 12-kV system from the 230-kv/12-kV standby startup transformer 11(21) through the 12-kv/4.16-kv standby startup transformer 12(22) to the 4.16-kV Class 1E buses provide startup and standby power, and is immediately available following a design basis accident to assure that core cooling, containment integrity, and other vital safety functions are maintained. The portion of the 12-kV system which is part of the immediately available offsite power circuit is designed with sufficient capacity and capability to operate the engineered safety features (ESF) following a design basis accident. The startup bus portion of the 12-kV system is included in the startup offsite power circuit and provides input to the startup transformer 11(21) LTC controller for voltage control. The capability of the 12-kV startup bus is adequate to power both ESF and non-ESF functions. Refer to Section 8.2.3.2.1 for additional discussion of capacity and capability of the startup offsite power circuit. 8.3.1.1.2.3.7 General Design Criterion 18, 1971 - Inspection and Testing of Electric Power Systems Periodic testing and surveillance of the standby startup transformers and the 12-kV/4.16-kV transformers are part of the normal DCPP program for oil-filled transformers. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-8 Revision 21 September 2013 The DCPP surveillance program confirms the availability of the startup offsite power circuit by verifying the correct breaker alignments, voltage levels, and compensatory measures. 8.3.1.1.2.3.8 General Design Criterion 49, 1967 - Containment Design Basis The 12-kV circuits routed through containment electrical penetrations are each provided with electrical protection devices. This arrangement is such that with the failure of one device, the penetration remains protected from high current temperature by the other in-series device to ensure the containment penetration remains functional (refer to Section 3.8.1.1.3 and 8.3.1.4.8 for additional details). 8.3.1.1.2.3.9 Single Failure Requirements A failure of a single active component in the 12-kV portion of the startup offsite power circuit does not result in a complete loss of the preferred power supply. Refer to Section 8.2.3.5. 8.3.1.1.2.3.10 10 CFR 50.63 - Loss of All Alternating Current Power A portion of the 12-kV system is used as an attendant distribution system of the 230-kV offsite power circuits used for restoration of offsite power following a SBO event. The plant procedures for SBO and loss-of-offsite power (LOOP) use several different flow paths to restore ac power and place the plant in a safe, controlled cooldown. Refer to Section 8.3.1.6 for further discussion of SBO. 8.3.1.1.2.3.11 Safety Guide 32, August 1972 - Use of IEEE Standard 308-1971 Criterion for Class 1E Electric Systems for Nuclear Power Generating Stations The portion of the 12-kV system from the standby startup transformer 11(21) through the standby startup transformer 12(22) to the 4.16-kV Class 1E buses provides startup and standby power, and is immediately available following a design basis accident or unit trip to assure that core cooling, containment integrity, and other vital safety functions are maintained. The immediately available 12-kV startup bus is continuously energized to support the immediate availability of the startup offsite power circuit. Refer to Section 8.2.3.7. 8.3.1.1.2.3.12 Regulatory Guide 1.63, Revision 1, May 1977 - Electrical Penetration Assemblies in Containment Structures for Light-Water-Cooled Nuclear Plants 12-kV circuits routed through containment electrical penetrations are designed with redundant overcurrent protection. Refer to Section 8.3.1.4.8 for additional details. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-9 Revision 21 September 2013 8.3.1.1.2.4 Tests and Inspections Refer to Section 8.3.1.1.2.3.7 for test and inspection details. 8.3.1.1.2.5 Instrumentation Applications Refer to Section 8.3.1.1.2.3.4 for instrumentation applications. 8.3.1.1.3 4.16-kV System 8.3.1.1.3.1 Design Bases 8.3.1.1.3.1.1 General Design Criterion 2, 1967 - Performance Standards The Class 1E portion of the 4.16-kV system is designed to withstand the effects of, or is protected against, natural phenomena such as earthquakes, flooding, tornados, winds, and other local site effects. 8.3.1.1.3.1.2 General Design Criterion 3, 1971 - Fire Protection The Class 1E portion of the 4.16-kV system is designed and located to minimize, consistent with other safety requirements, the probability and effect of fires and explosions. 8.3.1.1.3.1.3 General Design Criterion 11, 1967 - Control Room The Class 1E portion of the 4.16-kV system is designed to support actions to maintain and control the safe operational status of the plant from the control room or from an alternate location if control room access is lost due to fire or other causes. 8.3.1.1.3.1.4 General Design Criterion 12, 1967 - Instrumentation and Control Systems Instrumentation and controls are provided as required to monitor and maintain 4.16-kV system variables within prescribed operating ranges. 8.3.1.1.3.1.5 General Design Criterion 17, 1971 - Electric Power Systems The Class 1E portion of the 4.16-kV system is designed with sufficient capacity, capability, independence, redundancy, and testability to perform its safety function assuming a single failure. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-10 Revision 21 September 2013 8.3.1.1.3.1.6 General Design Criterion 18, 1971 - Inspection and Testing of Electric Power Systems The Class 1E portion of the 4.16-kV system design permits appropriate periodic inspection and testing of functional and operational performance of the system as a whole and under conditions as close to design as practical. 8.3.1.1.3.1.7 General Design Criterion 21, 1967 - Single Failure Definition The Class 1E portion of the 4.16-kV system is designed to remain operable after sustaining a single failure. Multiple failures resulting from a single event shall be treated as a single failure. 8.3.1.1.3.1.8 General Design Criterion 40, 1967 - Missile Protection The portions of the Class 1E 4.16-kV system, that support ESF loads, are designed to be protected against dynamic effects and missiles that might result from plant equipment failures. 8.3.1.1.3.1.9 10 CFR 50.49 - Environmental Qualification of Electrical Equipment Important to Safety for Nuclear Power Plants The Class 1E 4.16-kV system electrical components that require environmental qualification (EQ) are qualified to the requirements of 10 CFR 50.49. 8.3.1.1.3.1.10 10 CFR 50.63 - Loss of All Alternating Current Power The Class 1E 4.16-kV system provides power to the loads required to support systems that assure core cooling and containment integrity is maintained following a SBO event. 8.3.1.1.3.1.11 10 CFR Part 50 Appendix R (Sections III.G, III.J, and III.L) - Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979 Section III.G - Fire Protection of Safe Shutdown Capability: Fire protection of the Class 1E portion of the 4.16-kV system is provided by a combination of physical separation, fire-rated barriers, and/or automatic suppression and detection. Section III.J - Emergency Lighting: Emergency lighting or battery operated lights (BOLs) are provided in areas where operation of the 4.16-kV system may be required to safely shut down the Unit following a fire. Section III.L - Alternative and Dedicated Shutdown Capability: Safe shutdown capabilities are provided in the control room and at an alternate location via the hot shutdown panel (HSP) or locally at the 4.16-kV switchgear, for equipment power by the 4.16-kV system required for the safe shutdown of the plant following a fire event. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-11 Revision 21 September 2013 8.3.1.1.3.1.12 Safety Guide 6, March 1971 - Independence Between Redundant Standby (Onsite) Power Sources and Between their Distribution Systems The Class 1E portion of the 4.16-kV system is designed so that electrically powered loads are separated into redundant load groups such that loss of any one group will not prevent the minimum safety functions from being performed. 8.3.1.1.3.1.13 Regulatory Guide 1.97, Revision 3, May 1983 - Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident The 4.16-kV system provides instrumentation in the control room to monitor 4.16-kV system electrical status for post-accident instrumentation. 8.3.1.1.3.2 System Description The 4.16-kV system is a three-phase, three-wire, high-resistance-grounded neutral system that serves motors from 200 to 3000 hp, and transformers for the smaller loads at the lower voltages. The Class 1E 4.16-kV distribution system provides power to ESF loads to safely shut down the unit. The 4.16-kV loads are divided into five groups; two of these groups are not vital to the ESFs and are connected to non-Class 1E 4.16-kV buses D and E. Each of the non-Class 1E buses has two sources of preferred power supply: one from the main generator (or the 500-kV system through the main transformer) through the 25-kV/4.16-kV unit auxiliary transformer 12(22), and one from the 230-kV transmission system through the 230-kV/12-kV standby startup transformers 11(21) and 12-kV/4.16-kV standby startup transformers 12(22). Refer to Figures 8.1-1, 8.3-3, and 8.3-5). Utility power for the 230-kV and 500-kV switchyards is provided from the Unit 1, non-Class 1E, 4.16-kV switchgear buses D and E, respectively. Refer to Sections 8.2.2.1 (230-kV system) and 8.2.2.2 (500-kV system) for further discussion. The other three load groups are important to safety and are connected to 4.16-kV Class 1E buses F, G, and H. Each of these buses has three sources: two being the the immediate and delayed preferred power supply, and the standby power supply from the diesel-driven generators (refer to Figures 8.3-3 and 8.3-4). As noted in Section 8.2.3.2, compensatory action will be taken as necessary to ensure that the ESF motor terminal voltages are within their acceptable voltage tolerance (typically +/-10 percent) when fed from the preferred power supply. Once started, the motors will operate with applied voltages as low as 70 percent of rated voltage without breakdown, but the time is limited because of motor heating.
The 4.16-kV system is provided with metal clad switchgear and breakers rated at 350-MVA interrupting capacity, and 78,000 amperes of closing and latching capability. The circuit breakers are in individual cubicles, each separated from the adjacent circuit breakers by metal barriers. All 4.16-kV switchgear is located in the turbine building. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-12 Revision 21 September 2013 The non-Class 1E 4.16-kV switchgear is located in the same room as the 12-kV switchgear and have the two bus sections separated by a common aisle. The Class 1E 4.16-kV switchgear is located in rooms separated from each other and from non-Class 1E equipment (refer to Figures 1.2-14, 1.2-15, 1.2-16, 1.2-18, 1.2-19, and 1.2-20). The unit auxiliary and standby startup transformers are equipped with an automatic water spray deluge system that can be manually actuated locally at the system valves or remotely from the control room (refer to Section 9.5.1.2.4). 8.3.1.1.3.3 Safety Evaluation 8.3.1.1.3.3.1 General Design Criterion 2, 1967 - Performance Standards The Class 1E 4.16-kV switchgear and associated 4.16-kV/120-Vac potential transformers and safeguard relay boards are located in the PG&E Design Class II turbine building. This building, or applicable portions thereof, has been designed not to impact PG&E Design Class I components and associated safety functions (refer to Section 3.7.2.1.7.2). The turbine building is designed to withstand the effects of winds and tornados (refer to Section 3.3.1.2 and 3.3.2.3.2.8), floods and tsunamis (refer to Section 3.4), external missiles (refer to Section 3.5), and earthquakes (refer to Section 3.7.2.1.7.2) to protect the Class 1E 4.16-kV switchgear and associated 4.16-kV/120-Vac potential transformers and safeguard relay boards, ensuring their design function will be performed. The 4.16-kV switchgear and associated 4.16-kV/120-Vac potential transformers and safeguard relay boards are seismically designed to perform their safety functions under the effects of earthquakes (refer to Section 3.10.2.7). 8.3.1.1.3.3.2 General Design Criterion 3, 1971 - Fire Protection The Class 1E 4.16-kV switchgear and cable spreading room are designed to the fire protection guidelines of Branch Technical Position (BTP) Auxiliary and Power Systems Branch (APCSB) 9.5-1 (refer to Appendix 9.5B Table B-1). Refer to Section 8.3.1.4.9 for further discussion on fire barriers and separation. 8.3.1.1.3.3.3 General Design Criterion 11, 1967 - Control Room The Class 1E 4.16-kV supply and load breakers are controlled remotely from the main control room and locally at their respective switchgear cubicles. The supply breaker for each Class 1E load center transformer is equipped with an isolation switch, located at the switchgear that disconnects breaker control from the control room in the event that the main control room is rendered uninhabitable. The hot shutdown panel (HSP), which is the alternate control location in the event that the main control room is rendered uninhabitable, is provided with a mode switch, control switch and status indication for each of the pumps required to bring the plant to a safe shutdown condition. It is also DCPP UNITS 1 & 2 FSAR UPDATE 8.3-13 Revision 21 September 2013 provided with a voltage indication of each Class 1E 4.16-kV bus. Transfer switches are located in the Class 1E 4.16-kV switchgear cubicles to isolate 4.16-kV circuit breaker control cables between the main control room and the switchgear and transfer control of the breaker locally to the HSP or the switchgear. Alarms are provided in the control room to monitor the status of the 4.16-kV system and alert the plant when an abnormal condition is detected. Refer to Section 8.3.1.1.3.3.4 for additional instrumentation and control information. 8.3.1.1.3.3.4 General Design Criterion 12, 1967 - Instrumentation and Control Systems Control switches, status indication and ammeters are provided in the main control room and at the respective switchgear cubicle for all the motor load and load center transformer feeder breakers. Additionally, watt and var meters are provided for each load center transformer feeder in the main control room as well as voltage indication for each 4.16-kV bus. The unit auxiliary and standby startup transformers feeding the 4.16-kV buses are provided with an ammeter, voltmeter, wattmeter, varmeter, watt-hour meter and an indicating light in the main control room. 8.3.1.1.3.3.5 General Design Criterion 17, 1971 - Electric Power Systems Each Unit's Class 1E 4.16-kV distribution system is comprised of three electrically independent and redundant load groups. Each Class 1E switchgear, including its associated relay board, is located in separate rooms and meets the single failure criteria. If a single failure occurs in any of the three load groups, the remaining load groups have sufficient capability and capacity to provide power to ESF loads required to safely shut the unit down. Each load group is normally supplied power from the main generator via the unit auxiliary transformer. In the event of a unit trip or accident condition, the power source to each Class 1E, 4.16-kV switchgear is automatically transferred to the immediate preferred power source via the standby startup transformers 11 and 12 (21 and 22) in series. If the transfer to the standby startup transformer is unsuccessful or if there is a loss of voltage or degraded voltage from the standby startup transformer, undervoltage protection for each Class 1E 4.16-kV bus is provided by the first level undervoltage relays (FLUR) and second level undervoltage relays (SLUR). These sets of relays and associated timers start the EDG, perform a load shed on its respective bus and transfer loading to the EDG in the event the preferred power supply is unavailable or in a degraded condition. Refer to Figure 8.3-16. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-14 Revision 21 September 2013 8.3.1.1.3.3.5.1 Class 1E Bus Undervoltage Protection Design Criteria The emergency electric power system including each Class 1E bus and its control, protection, and instrumentation is designed in accordance with IEEE 308-1971 (Reference 3), IEEE 279-1971 (Reference 4), and the following supplemental NRC positions regarding the susceptibility to sustained degraded voltage conditions and the interaction of the preferred power supply and standby power supply (Reference 26). (1) Second Level Undervoltage Protection with Time Delay: A second level of voltage protection for the onsite power system is provided (i.e. in addition to loss of voltage protection). The preferred power supply is the common source that normally supplies power to the redundant Class 1E buses. Any transient or sustained degradation of this common source will be reflected onto the onsite Class 1E electrical distribution system. A sustained degradation of the preferred power supply voltage could result in the loss of capability of the redundant safety loads, their control circuitry, and the associated electrical components required for performing safety functions. The following requirements ensure adequate protection from this common mode failure mechanism: (a) The selection of voltage and time set points are based on an analysis of the voltage requirements of the safety related loads at all onsite system distribution levels; (b) The voltage protection includes coincidence logic to preclude spurious trips of the preferred power supply; (c) The time delay selection is based on the following conditions: i) The allowable time delay, including margin, does not exceed the maximum time delay that is assumed in the accident analyses; ii) The time delay minimizes the effect of short duration disturbances from reducing the availability of the preferred power supply; iii) The allowable time duration of a degraded voltage condition at all distribution system levels does not result in failure of safety systems or components; (d) The voltage sensors automatically initiate the disconnection of the preferred power supply whenever the voltage set point and time delay limits have been exceeded; and (e) The voltage sensors are designed to satisfy the applicable requirements of IEEE 279-1971 (Reference 4). DCPP UNITS 1 & 2 FSAR UPDATE 8.3-15 Revision 21 September 2013 (2) Interaction of Onsite Power Supplies with Load Shed Feature: The second level undervoltage logic (i.e. degraded grid) input to the load shed feature for each Class 1E 4.16-kV bus is inhibited when the EDG output breaker is closed and the Auxiliary preferred power supply feeder breaker is open (i.e. bus is solely energized by the standby power supply). The second level undervoltage logic input to the load shed feature is automatically reinstated when the EDG output breaker opens. 8.3.1.1.3.3.5.2 Operation of 4.16-kV Distribution System The ESF loads and their onsite sources are grouped so the functions required during a major accident are provided regardless of any single failure in the electrical system. Any two of the three diesel generators and their buses are adequate to serve at least the minimum required ESF loads of a unit after a major accident.
During normal operation, the main generator supplies the auxiliary load for each unit. The circuit breakers on 4.16-kV Class 1E buses F, G, and H, which feed the ESFs, are aligned as follows:
(1) 4.16-kV circuit breakers that are open: (a) Diesel-driven generators (b) Standby startup Transformer 12 (22) (c) Safety injection pumps (d) Containment spray pumps (e) Auxiliary feedwater pumps (f) Residual heat removal (RHR) pumps (2) 4.16-kV circuit breakers that are closed: (a) Unit auxiliary transformer 12 (22) (b) 4.16-kV/480-V Class 1E load centers that provide power for pumps, fans, valves, and other low-voltage devices (3) 4.16-kV circuit breakers that may be either open or closed, depending on the operating conditions of the following pumps: (a) Charging pumps DCPP UNITS 1 & 2 FSAR UPDATE 8.3-16 Revision 21 September 2013 (b) Auxiliary saltwater (ASW) pumps (c) Component cooling water (CCW) pumps To achieve the objective of an adequate source of electrical power for the Class 1E 4.16 kV buses F, G, and H, the electrical systems are designed to operate as follows:
In the event of a loss of satisfactory electrical power from the main generating unit, due to a unit trip, a safeguard signal, or a loss of voltage on the bus, the Class 1E 4.16-kV buses are automatically disconnected immediately from the main unit as a source.
If power is available from the startup offsite power circuit, the Class 1E 4.16-kV buses are transferred to this source automatically after a short delay to allow for voltage decay on the motors that were running.
The delayed method of transfer is used to protect the ESF motors from overvoltage transients. The advantage of motor protection is greater than any disadvantage of reduced operating capacity during the short delay period, especially in view of the fact that when there is also a loss of startup offsite power circuit, the delay in transferring to emergency power is on the order of 10 seconds (the time for the diesel generators to reach minimum bus voltage) plus load sequencing. Schematic diagrams of the automatic transfer circuits for the ESF buses are presented in Figures 8.3-9, 8.3-10, and 8.3-11; logic diagrams are shown in Figure 8.3-16.
Because the individual loads are not tripped under these circumstances, they remain in the same operating state as before the transfer, except for the low-voltage loads operated by magnetic controllers having no maintained contact control circuits, such as the containment fan coolers. Without an SIS signal, individual timers start the containment fan coolers and the ASW pump. The containment fan coolers would operate at the low speed after the transfer of the Class 1E power supply. With an SIS signal, the Class 1E loads are started in sequence in the same manner as with the diesel generators. As noted in Table 8.3-4, an SIS signal only allows the containment fan coolers to start on low speed.
Also, if bus voltage is not restored, the associated diesel generator is started automatically and brought to a condition suitable for loading.
Each of the following initiates the starting of the diesel generators:
(1) A safety injection (SI) actuation signal from either Train A or B of the ESF actuation system. (2) Undervoltage on the startup offsite power circuit to each of the Class 1E 4.16-kV buses start its respective diesel.
DCPP UNITS 1 & 2 FSAR UPDATE 8.3-17 Revision 21 September 2013 (3) Sustained undervoltage or loss of voltage on any of the Class 1E 4.16-kV buses starts its respective diesel. In each case, an independent set of signals or relays is applied to start the diesel for its bus. The first level undervoltage relay (initiating load shedding signal) for the startup offsite power circuit of each Class 1E 4.16-kV bus has inverse time characteristics and a slight delay upon complete voltage failure. The first level undervoltage relay has three select voltages and time delay settings, with the lowest being set at approximately 818-V. The second level of undervoltage protection for each Class 1E 4.16-kV bus is set at approximately 3800-V. The protection consists of two relays for each bus having a two-out-of-two logic arrangement. Start of the respective diesel is delayed by 10 seconds. Bus loads are shed in 20 seconds, and bus transfer to the diesel generator takes place in 22 seconds. These timing features will prevent needless diesel starts during transient voltage dips, and provide adequate time delay for the startup offsite power circuit voltage to recover before transferring the bus to the diesel generator.
Should there be a loss of the startup offsite power circuit concurrent with the loss of onsite power (i.e., the main generating unit), the following events occur automatically, initiated by the first level of undervoltage protection:
(1) The 4.16-kV circuit breaker feeding the Class 1E 4.16-kV buses F, G, and H from the main generating unit is opened immediately. (2) All three diesel generators for the unit are started and accelerated to normal frequency and minimum bus voltage in a period of less than 10 seconds. (3) Should the startup offsite power circuit be restored before the diesel auto-transfer interlock relay actuates, the circuit breakers feeding the Class 1E 4.16-kV buses F, G, and H from the startup offsite power circuit are closed to restore power to the loads. First-level undervoltage relays have already shed loads. Loads, including certain ESF loads that may not have been operating, are started in the same manner and sequence as when fed from the diesel generator. The preferred power supply may be restored by reclosing the circuit breakers for the 230-kV transmission lines automatically and/or manually at Morro Bay switchyard under the control of the CAISO (refer to Section 8.2.3.2).
Should the startup offsite power circuit still be unavailable when the diesel generators have reached breaker close-in voltage, all circuit breakers from the standby power supply and startup offsite power circuit to these Class 1E 4.16-kV buses are given a trip signal independently to make sure they are open (the expected condition at this point). The startup offsite power circuit is automatically blocked from reclosing. The circuit breakers for all loads, except the 4.16-kV/480-V load center transformers, have already DCPP UNITS 1 & 2 FSAR UPDATE 8.3-18 Revision 21 September 2013 been opened by the first level undervoltage relays. Each of the Class 1E 4.16-kV buses has a separate pair of these relays. The relays have a two-out-of-two logic arrangement for each bus to prevent inadvertent tripping of operating loads during a loss of voltage either from a single failure in the potential circuits or from human error. Also, one of the relays has an inverse time characteristic and a slight delay of about 4 seconds at no voltage to prevent loss of operating loads during transient voltage dips, and to permit the startup offsite power circuit to pick up the load. The Class 1E buses are then isolated from the rest of the plant, and from each other, and therefore operate independently. Any required or desired bus interconnecting is done manually by the operator.
The 4.16-kV circuit breaker for each diesel generator then closes automatically to restore power to the Class 1E 4.16-kV bus, and, consequently, the 480-V and 120-Vac buses also. All 4.16-kV circuit breakers have stored-energy closing mechanisms and close in less than 0.1 seconds.
The loads that remain connected to the 480-V buses become energized at the same time as the buses (refer to Section 8.3.1.1.4). These loads are within the initial load pickup capability of the diesel generators and are composed of the Class 1E lighting, the battery chargers, etc.
Other 480-V and 120-Vac equipment that can also operate immediately are those that are under automatic process control, and those under control of the protection system for the ESFs. When the bus voltage is restored by the diesel generators, the undervoltage relays that previously had tripped the loads will reset automatically. The individual loads are put into operation in a staggered sequence to reduce the effects of momentary loads and motor starting on the diesel generators (refer to Technical Specifications (Reference 5)). The timing sequences have been given a nominal 4-second interval between steps during an SI signal, and a nominal 2 to 6 seconds between steps without an SI signal. The overall time to complete starting of all Class 1E loads is limited to less than 1 minute. The remaining loads can then be put into operation as desired.
The timing sequence for each Class 1E bus is initiated only when voltage is restored to the bus. When the startup offsite power circuit is available, power to the buses is restored in a few seconds when the residual voltage on the motors drops to 25 percent of normal. Otherwise, the delay is the time required for the diesel generators to transfer to the bus (shed loads and reach the minimum bus voltage, approximately 10 seconds or less).
To improve independence of control and to provide flexibility in setting the delays, individual adjustable timing relays are used for each motor. In addition, separate sets of these timing relays are used, depending on the presence or absence of the safety injection signal, so that response can be optimized for each condition. Should there be DCPP UNITS 1 & 2 FSAR UPDATE 8.3-19 Revision 21 September 2013 a second-level degraded grid condition, where the voltage of the Class 1E 4.16-kV buses remains at approximately 3,800 V or below, but above the setpoints of the first-level undervoltage relays, the following events occur automatically within the time periods stated in the Technical Specifications:
(1) After the specified time delay, the respective diesel generators will be started. (2) After the next specified time delay, if the undervoltage condition persists, the circuit breakers for all loads to the respective Class 1E 4.16-kV buses, except the 4.16-kV/480-V load center transformer, are opened. (3) Then the 4.16-kV circuit breakers from the normal onsite power source is given a trip signal to open the breaker feeding the bus and the standby power source breaker is already open, and then the circuit breaker for each respective diesel generator is closed. (4) Restoration of normal voltage to the Class 1E 4.16-kV buses, supplied by the individual diesel generators, actuates timers that put loads back into operation in a staggered sequence.
Each Class 1E 4.16-kV bus has its own set of second level undervoltage relays and associated timers causing the above sequences. Again, the Class 1E buses are now isolated from each other and from the rest of the plant and operate independently. Any required or desired bus interconnection has to be done manually by the operator. The transfer and subsequent operation of the Class 1E buses, because of degraded grid undervoltage protection, is the same as described above for loss of the startup offsite power circuit concurrent with a loss of onsite power. However, no attempt will be made to transfer to the startup offsite power circuit. Switching directly to the diesel generators ensures fast restoration of reliable power to the Class 1E 4.16-kV buses. The logic used in starting and loading the emergency diesel generators is shown in Figure 8.3 16. Schematic diagrams of these functions are shown in Figures 8.3-12, 8.3-13, and 8.3-14. A schematic diagram of the potential and synchronizing circuitry for the Class 1E buses is shown in Figure 8.3-20. The starting inrush and momentary loads that occur during the initial phases of each interval will be handled by the short-time overload capability of the diesel generators. The diesel generators can maintain the electric power frequency and voltage at satisfactory levels during the cumulative loading of the successive steps.
The engine has an adequate short-time overload capability along with a fast response governor to hold the frequency. The generator has a low subtransient reactance and a voltage regulator with a fast response and a high excitation ceiling that will hold the voltage to a minimum of 75 percent of nominal during motor starting.
DCPP UNITS 1 & 2 FSAR UPDATE 8.3-20 Revision 21 September 2013 The Class 1E 4.16kv/480-V load centers are left connected to their buses and are, therefore, energized first. Their initial load will consist of the momentary loads of the equipment that was left on, in addition to those initiated during the interruption. The net initial load on the load center consists of those loads that operate for a short time, such as motor operated valves, auxiliary lube oil pumps, etc., and the normal steady-state values for the remainder.
The starting loads of the larger motors that are started subsequently have also been included in the capabilities of the diesel generators. 8.3.1.1.3.3.5.3 4.16-kV Emergency Loads In the event of an emergency shutdown of the main generating unit in the absence of the preferred power supply, the loads supplied by the diesel generator are applied in the following manner:
(1) In the absence of a SI signal, the first set of timing relays will operate and start the loads listed: (a) The timing sequence and intervals are listed in Table 8.3-2. Notes for Table 8.3-2 and others in Section 8.3 are listed in Table 8.3-1. (b) The maximum steady-state load demand on the Class 1E 4.16-kV buses, immediately following a unit shutdown without a loss-of-coolant accident (LOCA), is as listed in Table 8.3-3. (2) In the presence of a safety injection signal, the second set of timing relays operate and start the loads for the injection phase as listed in Table 8.3-4. (3) The maximum steady-state load demand on the Class 1E 4.16-kV buses immediately following a unit shutdown, concurrent with a LOCA, is as listed in Table 8.3-5. (4) The loadings of the Class 1E 4.16-kV/480-V load centers, following a unit shutdown, with or without a LOCA, are listed in Table 8.3-6. These loads may not necessarily all be on simultaneously; however, to be conservative they are all considered in maximum demand. 8.3.1.1.3.3.6 General Design Criterion 18, 1971 - Inspection and Testing of Electric Power Systems Surveillance tests and inspections are performed periodically to demonstrate the 4.16-kV system's design basis requirements are met. The controls for the 4.16-kV system are designed to be capable of periodic testing to assure operational and functional performance of the Class 1E components and operability of the system as a whole.
DCPP UNITS 1 & 2 FSAR UPDATE 8.3-21 Revision 21 September 2013 8.3.1.1.3.3.7 General Design Criterion 21, 1967 - Single Failure Definition Each unit's Class 1E 4.16-kV distribution system is comprised of three electrically independent and redundant (refer to Section 8.3.1.4) Class 1E buses enclosed in separate rooms. If a single failure occurs in any of the three buses, the remaining buses have sufficient capability to provide power to ESF loads required to safely shut down the unit. 8.3.1.1.3.3.8 General Design Criterion 40, 1967 - Missile Protection The portions of the Class 1E 4.16-kV system that are located in zones where provision against dynamic effects must be made, are protected from missiles, pipe whip, or jet impingement from the rupture of any nearby high-energy line (refer to Sections 3.5, 3.6, 8.3.1.4.10.2 and 8.3.1.4.10.3). 8.3.1.1.3.3.9 10 CFR 50.49 - Environmental Qualification of Electrical Equipment Important to Safety for Nuclear Power Plants The Class 1E 4.16-kV system SSCs required to function in harsh environments under accident conditions are qualified to the applicable environmental conditions to ensure that they will continue to perform their safety functions. Section 3.11 describes the DCPP EQ program and the requirements for the environmental design of the electrical and related mechanical equipment. The affected components are listed in the EQ Master List. 8.3.1.1.3.3.10 10 CFR 50.63 - Loss of All Alternating Current Power The Class 1E portion of the 4.16-kV system serves to distribute power to loads required to bring the plant to a safe shutdown condition during a SBO. Refer to Section 8.3.1.6 for further discussion on station blackout. 8.3.1.1.3.3.11 10 CFR Part 50 Appendix R (Sections III.G, III.J, and III.L) - Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979 Section III.G - Fire Protection of Safe Shutdown Capability: 10 CFR Part 50 Appendix R requires the evaluation of the safe shutdown capability for DCPP in the event of a fire and loss of offsite power. The Class 1E 4.16-kV system satisfies the applicable requirements of 10 CFR Part 50 Appendix R, fire protection of safe shutdown capability (Appendix 9.5G). Section III.J - Emergency Lighting: Emergency lighting or battery operated lights (BOL) are provided in areas where operation of the 4.16-kV system may be required for safe shutdown following a fire as defined by 10 CFR Part 50, Appendix R, Section IIIJ (refer to Appendix 9.5D). DCPP UNITS 1 & 2 FSAR UPDATE 8.3-22 Revision 21 September 2013 Section III.L - Alternative and Dedicated Shutdown Capability: Safe shutdown capabilities are provided in the control room and at an alternate location via the HSP or locally at the 4.16-kV switchgear as defined by 10 CFR Part 50, Appendix R, Section III.L. Refer to Section 7.4 for a discussion of the HSP and local switchgear controls for the 4.16-kV system. The ability to safely shut down the plant following a fire in any fire area is summarized in Section 4.0 of Appendix 9.5A. Refer to Section 8.3.1.4.10.1 for additional discussion. 8.3.1.1.3.3.12 Safety Guide 6, March 1971 - Independence Between Redundant Standby (Onsite) Power Sources and Between their Distribution Systems The three Class 1E 4.16-kV buses are physically enclosed in separate rooms and are electrically independent from each other when powered from their respective emergency diesel generators. Refer to Section 8.3.1.4 for further discussion on independence of redundant systems. 8.3.1.1.3.3.13 Regulatory Guide 1.97, Revision 3, May 1983 - Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident Class 1E, Category 2 indication for each of the Class 1E 4.16-kV bus voltage and load center transformer primary amperage is provided in the control room for Regulatory Guide 1.97, Revision 3, monitoring. Refer to Table 7.5-6. 8.3.1.1.3.4 Tests and Inspections Refer to Section 8.3.1.1.3.3.6 for test and inspections details. 8.3.1.1.3.5 Instrumentation Applications Refer to Section 8.3.1.1.3.3.4 for instrumentation details. 8.3.1.1.4 480 Volt System 8.3.1.1.4.1 Design Bases 8.3.1.1.4.1.1 General Design Criterion 2, 1967 - Performance Standards The Class 1E portion of the 480-V system is designed to withstand the effects of, or is protected against, natural phenomena such as earthquakes, flooding, tornados, winds, and other local site effects. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-23 Revision 21 September 2013 8.3.1.1.4.1.2 General Design Criterion 3, 1971 - Fire Protection The Class 1E portion of the 480-V system is designed and located to minimize, consistent with other safety requirements, the probability and effect of fires and explosions. 8.3.1.1.4.1.3 General Design Criterion 4, 1967 - Sharing of Systems The 480-V system or components are not shared by the DCPP Units unless safety is shown not to be impaired by the sharing. 8.3.1.1.4.1.4 General Design Criterion 11, 1967 - Control Room The Class 1E portion of the 480-V system is designed to support actions to maintain and control the safe operational status of the plant from the control room or from an alternate location if control room access is lost due to fire or other causes. 8.3.1.1.4.1.5 General Design Criterion 12, 1967 - Instrumentation and Control Systems Instrumentation and controls are provided as required to monitor and maintain 480-V system variables within prescribed operating ranges. 8.3.1.1.4.1.6 General Design Criterion 17, 1971 - Electric Power Systems The Class 1E portion of the 480-V system is designed to have sufficient capacity, capability, independence, redundancy, and testability to perform its safety function assuming a single failure. 8.3.1.1.4.1.7 General Design Criterion 18, 1971 - Inspection and Testing of Electric Power Systems The Class 1E portion of the 480-V system design permits appropriate periodic inspection and testing of functional and operational performance of the system as a whole and under conditions as close to design as practical. 8.3.1.1.4.1.8 General Design Criterion 21, 1967 - Single Failure Definition The Class 1E portion of the 480-V system is designed to remain operable after sustaining a single failure. Multiple failures resulting from a single event shall be treated as a single failure. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-24 Revision 21 September 2013 8.3.1.1.4.1.9 General Design Criterion 40, 1967 - Missile Protection The portions of the Class 1E 480-V system that support ESF loads are designed to be protected against dynamic effects and missiles that might result from plant equipment failures. 8.3.1.1.4.1.10 General Design Criterion 49, 1967 - Containment Design Basis The Class 1E and non-Class1E 480-V circuits routed through containment electrical penetrations are designed to support the containment design basis such that the containment structure can accommodate, without exceeding the design leakage rate, pressures and temperatures following a loss of coolant accident. 8.3.1.1.4.1.11 10 CFR 50.49 - Environmental Qualification of Electrical Equipment The 480-V system electrical components that require environmental qualification are qualified to the requirements of 10 CFR 50.49. 8.3.1.1.4.1.12 10 CFR 50.63 - Loss of All Alternating Current Power The Class 1E 480-V system provides power to the loads required to support systems that ensure core cooling and containment integrity is maintained following a station blackout event. 8.3.1.1.4.1.13 10 CFR Part 50 Appendix R (Sections III.G, III.J, and III.L) - Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979 Section III.G - Fire protection of Safe Shutdown Capability: Fire protection of the Class 1E portion of the 480-V system is provided by a combination of physical separation, fire-rated barriers, and/or automatic suppression and detection. Section III.J - Emergency Lighting: Emergency lighting or BOLs are provided in areas where operation of the 480-V system may be required to safely shut down the unit following a fire. Section III.L - Alternative and Dedicated Shutdown Capability: Safe shutdown capabilities are provided in the control room and at an alternate location via the hot shutdown panel (HSP) or locally at the 480-V switchgear, for equipment powered by the 480-V system required for the safe shutdown of the plant following a fire event. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-25 Revision 21 September 2013 8.3.1.1.4.1.14 Safety Guide 6, March 1971 - Independence Between Redundant Standby (Onsite) Power Sources and Between their Distribution Systems The Class 1E portion of the 480-V system is designed such that electrically powered loads are separated into redundant load groups such that loss of any one group will not prevent the minimum safety functions from being performed. 8.3.1.1.4.1.15 Regulatory Guide 1.63, Revision 1, May 1977 - Electric Penetration Assemblies in Containment Structures for Light-Water-Cooled Nuclear Plants The Class 1E and non-Class1E 480-V circuits routed through containment electrical penetrations are designed to meet the requirements of Regulatory Guide 1.63, Revision 1, for the installation of redundant or backup fault current protection devices. The protection devices are designed to limit fault current to less than which the penetration can withstand assuming a single random failure of the circuit overload protective device. 8.3.1.1.4.1.16 Regulatory Guide 1.97, Revision 3, May 1983 - Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident The 480-V system provides instrumentation in the control room to monitor 480-V system electrical status for post-accident instrumentation. 8.3.1.1.4.1.17 NUREG-0737 (Items II.E.3.1 (1) and II.G.I (2)), November 1980 - Clarification of TMI Action Plan Requirements Item II.E.3.1 (1) - Emergency Power for Pressurizer Heaters: The non-Class 1E pressurizer heater power supply design provides the capability to supply, from either the preferred offsite power source or the standby power source (when offsite power is not available), to a predetermined number of pressurizer heaters and associated controls necessary to establish and maintain natural circulation at hot standby conditions. The required heaters and their controls are connected to the Class 1E emergency buses in a manner that will provide redundant power supply capability. Item II.G.1 (2) - Emergency Power for Pressurizer Equipment: Motive and control components associated with the PORV block valves are capable of being supplied from either the preferred offsite power source or the standby power source when the offsite power is not available. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-26 Revision 21 September 2013 8.3.1.1.4.2 System Description The 480-V system is a three-phase, three-wire, ungrounded system that provides power to motors not greater than 350 hp, lighting and electric heating systems, battery chargers, and instrument and control systems.
The 480-V loads are served from the 4.16-kV buses through 4.16-kV/480-V transformers closely coupled to either metal-enclosed low voltage switchgear or to motor control centers. Five transformers in a duplex arrangement are provided for the non-Class 1E 480-V loads; two in the turbine building, two in the auxiliary building, and one at the intake structure. Three additional transformers, connected radially, are provided for the Class 1E 480-V loads, and the units are isolated from each other to maintain separation for the redundant Class 1E loads (refer to Figures 1.2-6, 1.2-8, 1.2-14, 1.2-16, 1.2-18, 1.2-20, 8.3-6, 8.3-7, and 8.3-8). 8.3.1.1.4.2.1 Maximum Demand The maximum demands on the Class 1E 480-V load centers immediately following a unit shutdown are listed in Table 8.3-7. About 40 minutes after a major accident, the manual change-over of certain vital bus loads to support the recirculation phase would be completed. 8.3.1.1.4.2.2 Pressurizer Equipment Power Supplies Pressurizer equipment power supplies are designed to meet the requirements of GDC 17, 1971 and NUREG-0737 (Reference 2) in the event of loss of offsite power. For further discussion of pressurizer equipment, refer to Section 5.5.9. 8.3.1.1.4.2.2.1 Pressurizer Heaters The four pressurizer heater groups are normally connected to non-Class 1E 480-V power sources. All of the four pressurizer heater groups can be supplied with power from the offsite power sources when they are available.
When offsite power is not available, power can be provided to two out of four heater groups from the emergency power system (refer to Section 8.3.1.1.6) through Class 1E buses G and H (refer to Figure 8.3-19). Sufficient power (150 kW) is available from the Class 1E buses to energize enough heaters to maintain natural circulation at hot standby conditions. Redundancy is provided by supplying the two groups of heaters from the different Class 1E buses. The ability to supply emergency power to the heaters minimizes a potential loss of subcooling in the reactor coolant system after a loss of offsite power.
Transfer of pressurizer heater power supplies can be performed manually (in accordance with operating procedures) in less than 60 minutes using manual transfer switches located at the 100-foot elevation in the auxiliary building. Since the pressurizer DCPP UNITS 1 & 2 FSAR UPDATE 8.3-27 Revision 21 September 2013 heaters are non-Class 1E loads, they are automatically tripped off of the Class 1E buses upon occurrence of a safety injection actuation signal. Breaker and switchgear equipment interfacing the pressurizer heaters with the Class 1E buses is Class 1E and seismically qualified. 8.3.1.1.4.2.3 Lighting Normal lighting is operated at 208Y/120-V, three-phase, on a four-wire solidly grounded system supplied from the 480-V system through dry-type, delta-wye connected, 3-phase transformers.
The ac emergency lighting is supplied from two of the three Class 1E 480-V buses. Emergency lighting is located throughout the plant to provide minimum general lighting during a failure of normal lighting. Direct current emergency lighting is operated at 125-Vdc from the non-Class 1E station batteries. ESF equipment areas and various access routes thereto are provided with individual battery-operated lights (BOLs) capable of providing 8 hours of illumination when ac power to the BOL is lost. The batteries are continuously charged with a built-in charger. Rack area uninterruptible power supply (UPS) lighting is provided for the same purpose.
Refer to Section 9.5.3 and Appendices in 9.5 for Appendix R emergency lighting descriptions. 8.3.1.1.4.3 Safety Evaluation 8.3.1.1.4.3.1 General Design Criterion 2, 1967 - Performance Standards The Class 1E 480-V load center transformers and switchgear are located at 100 foot elevation of the auxiliary building, a PG&E Design Class I structure (refer to Figure 1.2-6). The auxiliary building is designed to withstand the effects of winds and tornados (refer to Section 3.3), floods and tsunamis (refer to Section 3.4), external missiles (refer to Section 3.5), and earthquakes (refer to Section 3.7). This design protects the Class 1E 480-V load center transformers and switchgear, ensuring their design function will be performed. The Class 1E 480-V load center transformers and switchgear are seismically designed to perform their safety functions under the effects of earthquakes (refer to Section 3.10.2.7.4). 8.3.1.1.4.3.2 General Design Criterion 3, 1971 - Fire Protection The Class 1E 480-V switchgear and cable spreading room are designed to the fire protection guidelines of Branch Technical Position (BTP) Auxiliary and Power Conversion Systems Branch (APCSB) 9.5-1 (refer to Appendix 9.5B, Table B-1). DCPP UNITS 1 & 2 FSAR UPDATE 8.3-28 Revision 21 September 2013 Refer to Section 8.3.1.4.9 for further discussion on fire barriers and separation. 8.3.1.1.4.3.3 General Design Criterion 4, 1967 - Sharing of Systems Portions of the control room ventilation system and control room pressurization system equipment required to maintain control room habitability are shared between Unit 1 and Unit 2, 480-V, Class 1E switchgear buses via mechanically interlocked transfer switches. Power to the technical support center, which is normally fed by a Unit 2, non-Class 1E, 480-V motor control center (MCC), may be manually transferred via a transfer switch to a Unit 2, Class 1E 480-V switchgear. If this power supply is not available, power can be transferred to the Unit 1 Class 1E 480-V switchgear via another transfer switch. The diesel fuel oil transfer pumps are powered from either Unit 1 or Unit 2 Class 1E 480-V bus via a manual transfer switch. The Unit 1 and Unit 2 communication room power distribution panels are normally fed from their corresponding Class 1E 480-V bus. Each is provided with a manual transfer switch, which allows transfer of power source to the other unit's Class 1E 480-V bus. Operation of these transfer switches is administratively controlled to ensure that a fault in one Unit is isolated from the other Units power source. 8.3.1.1.4.3.4 General Design Criterion 11, 1967 - Control Room The Class 1E 480-V switchgear and MCCs fed by a load transformer have a single phase voltmeter and an indicating potential light to monitor bus availability within the control room. The HSP, which is the alternate control location in the event that the control room is rendered uninhabitable, is provided with transfer switches, control switches and status indication for the 480-V components that are controllable at the HSP. Additionally, a cut-in/cut-out switch and relay located at the 480-V MCC is provided to isolate the HSP from the switchgear control circuits in the event of fire at the HSP. 8.3.1.1.4.3.5 General Design Criterion 12, 1967 - Instrumentation and Control Systems The Class 1E and non-Class 1E 480-V switchgear and MCCs that are directly fed from a load transformer are equipped with a ground detection circuit and ground indicating lights that provide annunciation in the main control room. The 480-V switchgears and MCCs are also provided with local bus monitoring devices. The load center transformers are equipped with winding temperature sensors with alarm contacts and provide automatic and manual control of the cooling fans. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-29 Revision 21 September 2013 8.3.1.1.4.3.6 General Design Criterion 17, 1971 - Electric Power Systems The Class 1E 480-V distribution system is comprised of three (3) electrically independent and redundant load groups (refer to Section 8.3.1.4). Each of the Class 1E MCCs are located in separate rooms for independence to meet the single failure criterion. If a single failure occurs in any of the three MCC groups, the remaining two MCC groups have sufficient capacity and capability (refer to Section 8.3.1.1.4.2.1) to provide power to ESF loads required to safely shut down the unit. 8.3.1.1.4.3.7 General Design Criterion 18, 1971 - Inspection and Testing of Electric Power Systems The Class 1E 480-V system is designed to be capable of periodic testing to assure operational and functional performance of the Class 1E components and operability of the system. Refer to Section 8.3.1.4.3.2 for further discussion on test and inspection for electrical cables. Each MCC is independently supplied power (refer to Section 8.3.1.4) from a load center transformer that derives power from a 4.16-kV switchgear and allows for testability of the 480-V distribution system. 8.3.1.1.4.3.8 General Design Criterion 21, 1967 - Single Failure Definition The Class 1E 480-V distribution system is comprised of three (3) electrically independent and physically separated redundant (refer to Section 8.3.1.4) Class 1E buses enclosed in separate rooms. If a single failure occurs in any of the Class 1E buses, the remaining two buses have sufficient capacity and capability to provide power to ESF loads required to safely shut down the unit. 8.3.1.1.4.1.9 General Design Criterion 40, 1967 - Missile Protection The portions of the Class 1E 480-V system that are located in zones where provision against dynamic effects must be made, are protected from missiles, pipe whip, or jet impingement from the rupture of any nearby high-energy line (refer to Sections 3.5, 3.6, and 8.3.1.4.10.2). 8.3.1.1.4.3.10 General Design Criterion 49, 1967 - Containment Design Basis The Class 1E and non-Class1E 480-V circuits routed through containment electrical penetrations are each provided with electrical protection devices. This arrangement is such that with the failure of one device, the penetration remains protected from high current temperature by the other in-series device to ensure the containment penetration remains functional. Refer to Sections 3.8.1.1.3.1 and 8.3.1.4.8 for additional details. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-30 Revision 21 September 2013 8.3.1.1.4.3.11 10 CFR 50.49 - Environmental Qualification of Electrical Equipment The Class 1E 480-V system SSCs required to function in harsh environments under accident conditions are qualified to the applicable environmental conditions to ensure that they will continue to perform their safety functions. Section 3.11 describes the DCPP EQ program and the requirements for the environmental design of the electrical and related mechanical equipment. The affected components are listed on the EQ Master List (refer to Section 3.11.1). 8.3.1.1.4.3.12 10 CFR 50.63 - Loss of All Alternating Current Power The Class 1E portion of the 480-V system serves to distribute power to loads required to bring the plant to a safe shutdown condition during a SBO. Refer to Section 8.3.1.6 for further discussion on SBO. 8.3.1.1.4.3.13 10 CFR Part 50 Appendix R (Sections III.G, III.J, and III.L) - Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979 Section III.G - Fire protection of Safe Shutdown Capability: The Class 1E 480-V system satisfies the applicable fire protection requirements of 10 CFR Part 50 Appendix R, Section III.G, fire protection of safe shutdown capability, by either meeting the technical requirements or by providing an equivalent level of fire safety. Refer to Section 8.3.1.4.10.1 and Appendix 9.5G for further discussion. Section III.J - Emergency Lighting: Emergency lighting or BOLs capable of providing 8 hours of illumination when ac power to the BOL is lost, are provided in areas where operation of the 480-V system may be required to safely shut down the unit following a fire as defined by 10 CFR Part 50, Appendix R, Section III.J. Refer to Sections 8.3.1.1.4.2.3, 9.5.3 and Appendix 9.5D for further discussion. Section III.L - Alternative and Dedicated Shutdown Capability: Safe shutdown capabilities are provided in the control room and at an alternate location via the HSP (refer to Section 7.4) as defined by 10 CFR Part 50, Appendix R, Section III.L. The ability to safely shut down the plant following a fire in any fire area is summarized in Section 4.0 of Appendix 9.5A and Appendix 9.5E. 8.3.1.1.4.3.14 Safety Guide 6, March 1971 - Independence Between Redundant Standby (Onsite) Power Sources and Between their Distribution Systems The three Class 1E 480-V buses are physically enclosed in separate rooms and are electrically independent from each other when powered from their respective emergency diesel generators. Refer to Section 8.3.1.4 for further discussion on independence of redundant systems. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-31 Revision 21 September 2013 8.3.1.1.4.3.15 Regulatory Guide 1.63, Revision 1, May 1977 - Electric Penetration Assemblies in Containment Structures for Light-Water-Cooled Nuclear Plants Class 1E and non-Class 1E 480-V circuits routed through containment electrical penetrations are designed with redundant overcurrent protection. Refer to Section 8.3.1.4.8 for further discussion. 8.3.1.1.4.3.16 Regulatory Guide 1.97, Revision 3, May 1983 - Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident Class 1E, Category 2 indications for each Class 1E 480-V bus voltage is provided in the control room for Regulatory Guide 1.97, Revision 3, monitoring. Refer to Table 7.5-6. 8.3.1.1.4.3.17 NUREG-0737 (Items II.E.3 (1) and II.G.1 (2)), November 1980 - Clarification of TMI Action Plan Requirements II.E.3.1 (1) - Emergency Power Supply for Pressurizer Heaters: Section 8.3.1.1.4.2.2.1 provides a discussion of the power supply design configuration for the pressurizer heaters in conformance with NUREG-0737, II.E.3.1 (1). II.G.1 (2) - Emergency Power for Pressurizer Equipment: The three Class 1E 480-V motor operated PORV block valves are each powered independently from the Class 1E 480-V ESF buses which are capable of being supplied from either the offsite source or the emergency power source when the offsite power source is not available. This conforms to the requirement of NUREG-0737, II.G.1 (2). 8.3.1.1.4.4 Tests and Inspections Refer to Section 8.3.1.1.4.3.7 for tests and inspections. 8.3.1.1.4.5 Instrumentation Applications Refer to Section 8.3.1.1.4.3.5 for instrumentation applications. 8.3.1.1.5 120-Vac Instrument Supply Systems 8.3.1.1.5.1 Design Bases 8.3.1.1.5.1.1 General Design Criterion 2, 1967 - Performance Standards The Class 1E 120-Vac system is designed to withstand the effects of, or is protected against, natural phenomena such as earthquakes, flooding, tornados, winds, and other local site effects. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-32 Revision 21 September 2013 8.3.1.1.5.1.2 General Design Criterion 3, 1971 - Fire Protection The Class 1E 120-Vac system is designed and located to minimize, consistent with other safety requirements, the probability and effect of fires and explosions. 8.3.1.1.5.1.3 General Design Criterion 4, 1967 - Sharing of Systems The 120-Vac system or components are not shared by the DCPP Units unless safety is shown not to be impaired by the sharing. 8.3.1.1.5.1.4 General Design Criterion 11, 1967 - Control Room The Class 1E portion of the 120-Vac system is designed to support actions to maintain and control the safe operational status of the plant from the control room or from an alternate location if control room access is lost due to fire or other causes. 8.3.1.1.5.1.5 General Design Criterion 12, 1967 - Instrumentation and Control Systems Instrumentation and controls are provided as required to monitor and maintain the 120-Vac system variables within prescribed operating ranges. 8.3.1.1.5.1.6 General Design Criterion 17, 1971 - Electric Power Systems The Class 1E 120-Vac system is required to have sufficient capacity, capability, independence, redundancy, and testability to perform its safety function assuming a single failure. 8.3.1.1.5.1.7 General Design Criterion 18, 1971 - Inspection and Testing of Electric Power Systems The Class 1E portion of the 120-Vac system design permits appropriate periodic inspection and testing of functional and operational performance of the system as a whole and under conditions as close to design as practical. 8.3.1.1.5.1.8 General Design Criterion 21, 1967 - Single Failure Definition The Class 1E portion of the 120-Vac system is designed to remain operable after sustaining a single failure. Multiple failures resulting from a single event shall be treated as a single failure. 8.3.1.1.5.1.9 General Design Criterion 24, 1967 - Emergency Power for Protection Systems The Class 1E portion of the 120-Vac system is designed to remain operable after a loss of all offsite power. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-33 Revision 21 September 2013 8.3.1.1.5.1.10 General Design Criterion 40, 1967 - Missile Protection The portions of the Class 1E 120-Vac system that support ESF loads are designed to be protected against dynamic effects and missiles that might result from plant equipment failures. 8.3.1.1.5.1.11 General Design Criterion 49, 1967 - Containment Design Basis The Class 1E and non-Class 1E 120-Vac circuits routed through containment electrical penetrations are designed to support the containment design basis such that the containment structure can accommodate, without exceeding the design leakage rate, the pressures and temperatures following a loss of coolant accident. 8.3.1.1.5.1.12 10 CFR 50.49 - Environmental Qualification of Electrical Equipment Important to Safety for Nuclear Power Plants The Class 1E 120-Vac system electrical components that require environmental qualification are qualified to the requirements of 10 CFR 50.49. 8.3.1.1.5.1.13 10 CFR 50.62 - Requirements for Reduction of Risk from Anticipated Transients without Scram (ATWS) Events for Light-Water-Cooled Nuclear Power Plants The non-Class 1E 120-Vac power source meets the electrical power requirements to provide a source to the ATWS mitigation actuation circuitry (AMSAC) that is independent from the protection system power supplies. 8.3.1.1.5.1.14 10 CFR 50.63 - Loss of All Alternating Current Power The Class 1E 120-Vac system provides power to the loads required to support systems that assure core cooling and containment integrity is maintained following a SBO event. 8.3.1.1.5.1.15 10 CFR Part 50 Appendix R (Sections III.G, III.J, and III.L) - Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979 Section III.G - Fire protection of Safe Shutdown Capability: Fire protection of the Class 1E portion of the 120-Vac system is provided by a combination of physical separation, fire-rated barriers, and/or automatic suppression and detection. Section III.J - Emergency Lighting: Emergency lighting or BOLs are provided in areas where operation of the 120-Vac system may be required to safely shut down the Unit following a fire. Section III.L - Alternative and Dedicated Shutdown Capability: Safe shutdown capabilities are provided in the control room and at an alternate location via the hot DCPP UNITS 1 & 2 FSAR UPDATE 8.3-34 Revision 21 September 2013 shutdown panel or locally at the 120-Vac switchgear, for equipment powered by the 120-Vac system required for the safe shutdown of the plant following a fire event. 8.3.1.1.5.1.16 Safety Guide 6, March 1971 - Independence Between Redundant Standby (Onsite) Power Sources and Between their Distribution Systems The Class 1E portion of the 120-Vac system is designed such that electrically powered loads are separated into redundant load groups such that loss of any one group will not prevent the minimum safety functions from being performed. 8.3.1.1.5.1.17 Regulatory Guide 1.63, Revision 1, May 1977 - Electric Penetration Assemblies in Containment Structures for Light-Water-Cooled Nuclear Power Plants The Class 1E and non-Class 1E 120-Vac circuits routed through containment electrical penetrations are designed to meet the requirements of Regulatory Guide 1.63, Revision 1, regarding installation of redundant or backup fault current protection devices to limit fault current to less than the penetration can withstand assuming a single random failure of the circuit overload protective device. 8.3.1.1.5.1.18 NUREG-0737 (Item II.G.1 (4)), November 1980 - Clarification of TMI Action Plan Requirements Item II.G.1 (4) - Emergency Power for Pressurizer Equipment (Pressurizer Level Indication): The pressurizer level indication instrument channels shall be powered from the Class 1E instrument buses. The buses shall have the capability of being supplied from either the preferred power supply or the standby power supply when the preferred power supply is not available. 8.3.1.1.5.2 System Description 8.3.1.1.5.2.1 Class 1E 120-Vac Instrument Power Supply System The 120-Vac Class 1E instrument bus system shown in Figure 7.6-1 supplies electric power for instrumentation, control, protection, and annunciation for the nuclear steam supply system (NSSS) and other Class 1E loads. The NSSS loads are divided into four redundant groups each with its own distribution panel(s) for each unit. The six panels are served by four dedicated uninterruptible power supplies (UPSs) supplied either from their associated Class 1E 480-V bus or from their associated Class 1E batteries. The UPSs are sized to continuously carry the maximum connected load without exceeding their nameplate rating. In addition, each UPS has a backup regulating transformer with manual transfer switch that can be fed from either of two 480-V Class 1E buses. This backup power is provided through the UPS static transfer switch or the UPS manual bypass switch, and supplies backup 120-Vac power to the instrument bus when its UPS DCPP UNITS 1 & 2 FSAR UPDATE 8.3-35 Revision 21 September 2013 is out of service. This four UPS design provides redundant, uninterrupted 120-V, 60-Hz, single-phase power to the Class 1E instrument buses. The dc power flow control of the inverter unit ensures that while the ac power input to the rectifier is available, the power to the distribution panels will be supplied through the rectifier and the inverter. When the ac power input to the rectifier is not available, the power to the distribution panel(s) will be supplied from the dc bus through the inverter 8.3.1.1.5.2.2 Non-Class 1E 120-Vac Instrument Power Supply System Other UPSs and inverters are supplied from the 480-V or 208Y/120-Vac systems and backed up by either station batteries or a dedicated UPS battery. UPSs and inverters are used to supply the plant's digital computers and other non-Class 1E plant instrumentation and control systems needing uninterrupted ac power. 8.3.1.1.5.3 Safety Evaluation 8.3.1.1.5.3.1 General Design Criterion 2, 1967 - Performance Standards The Class 1E 120-Vac UPSs, inverter, voltage regulating transformer and distribution panel equipment are located in the auxiliary building, which is a PG&E Design Class I structure, contained within the Class 1E 125-Vdc switchgear rooms (refer to Figure 1.2-5). The Class 1E 125-Vdc switchgear rooms are adjacent to the Class 1E 125-Vdc battery rooms. The auxiliary building is designed to withstand the effects of winds and tornados (refer to Section 3.3), floods and tsunamis (refer to Section 3.4), external missiles (refer to Section 3.5), and earthquakes (refer to Section 3.7) to protect the Class 1E 120-Vac UPSs, inverters, voltage regulating transformers and distribution panel equipment, ensuring their design function will be performed. Loss of dc switchgear/inverter room ventilation and Class 1E raceways located outdoors, associated with 120-Vac system that are exposed to effects of tornados, have been evaluated and they do not compromise the capability of shutting down the plant safely (refer to Section 3.3.2.3). The Class 1E 120-Vac UPSs, inverters, and voltage regulating transformers are seismically designed to perform their safety functions under the effects of earthquakes (refer to Section 3.10.2.1.4). 8.3.1.1.5.3.2 General Design Criterion 3, 1971 - Fire Protection The Class 1E inverters are located in the Class 1E 125-Vdc switchgear rooms. The 125-Vdc switchgear rooms are designed to the fire protection guidelines of Branch Technical Position APCSB 9.5-1 (refer to Appendix 9.5B Table B-1). Refer to Section 8.3.1.4.9 for further discussion on fire barriers and separation. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-36 Revision 21 September 2013 8.3.1.1.5.3.3 General Design Criterion 4, 1967 - Sharing of Systems The Class 1E 120-Vac system is shared between the control room ventilation system (CRVS) for both units through the use of manually operated mechanical transfer switches. Power to Unit 1 CRVS panels, which is normally fed from a Unit 1, Class 1E 120-Vac instrument supply system, may be manually transferred to a Unit 2 Class 1E 120-Vac instrument supply system, in the event the Unit 1 supply is not available, through the mechanical transfer switch. Similar operation can be accomplished for the Unit 2 CRVS panels. Safety is not impaired by the sharing since the transfer of power supply between the units is not done automatically but through the use of manually operated mechanical transfer switches. These transfer switches ensure that a fault in one Unit is isolated from the other Unit's power source. In addition, operation of these transfer switches is administratively controlled 8.3.1.1.5.3.4 General Design Criterion 11, 1967 - Control Room The dc power flow is monitored internally in the UPS, and dc input power to the inverter is supplied from the rectifier or from the dc bus as appropriate.
The loss of ac power to the distribution panels is alarmed in the control room. There are no UPS breaker controls on the control board, as transfers between Class 1E ac and dc sources will occur automatically without interruption due to loss of the 480-V power source. 8.3.1.1.5.3.5 General Design Criterion 12, 1967 - Instrumentation and Control Systems The loss of ac power to the distribution panels is alarmed in the control room. The Class 1E UPSs have locally mounted meters for dc input, bypass input, and ac output indications. They also have power available indication lights for ac input, dc input and bypass input power sources. An alarm mimic panel mounted on the face of the UPS panel is provided with alarm indication lights to indicate normal and abnormal conditions. 8.3.1.1.5.3.6 General Design Criterion 17, 1971 - Electric Power Systems The Class 1E UPSs are sized to continuously carry the maximum connected loads without exceeding their nameplate rating. The inverters are designed to maintain their outputs within the limits of 60 Hz +/- 0.5 percent and 120-Vac +/- 2 percent from zero to full load. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-37 Revision 21 September 2013 There are three independent Class 1E 480-V power sources, buses F, G, and H, in each unit. Bus F serves UPS 11, bus G serves UPS 12, and bus H serves UPSs 13 and 14. Three Class 1E 125-Vdc sources serve the four UPSs: UPS 11 is supplied power from battery 11, UPSs 12 and 14 are supplied power from battery 12, and UPS 13 is supplied power from battery 13. The UPSs operate normally on both the ac and dc systems. If either system is interrupted, the UPS will be supplied from the remaining source without interruption (refer to Figure 7.6-1).
Each of the four UPSs is independently connected to its respective channel instrument distribution panels so that the loss of a UPS cannot affect more than one channel of the system. 8.3.1.1.5.3.7 General Design Criterion 18, 1971 - Inspection and Testing of Electric Power Systems The Class 1E UPS inverters are routinely checked on a weekly basis and are inspected and tested on a refueling outage frequency. Periodic component replacements per manufacturer's specifications are performed to maintain the Class 1E qualification. Additional discussion on inspection and testing is found in Section 8.3.1.4.3.2 8.3.1.1.5.3.8 General Design Criterion 21, 1967 - Single Failure Definition The onsite Class 1E electrical power distribution system is designed with three independent 4.16-kV and 480-V Class 1E buses (F, G, and H) and three 125-Vdc Class 1E buses in each unit (refer to Section 8.3.1.1.5.3.6 and Figure 7.6-1). Each of the four UPSs is independently connected to its respective channel instrument distribution panels so that the loss of a UPS cannot affect more than one channel of the system. In addition, each of the four UPSs may be automatically transferred to a regulated 120-Vac backup power source by its static transfer switch. Each distribution panel can also receive power from the regulated 120 Vac backup source by its manual bypass switch. Each regulating transformer has its normal and alternate power source through a manual transfer switch. Each UPS has its rectifier connected to the inverter and the dc power source through a blocking diode that prevents the rectifier from backfeeding the dc system. The UPSs operate normally on both the ac and dc systems. If the ac system is interrupted, the inverter will be supplied from the Class 1E dc source without interruption (refer to Figure 7.6-1). The plant protection system (PPS) is designed with four input channels (I, II, III, and IV) powered from four 120-Vac Class 1E buses (1, 2, 3, and 4). The four channels provide input to the solid state protection system (SSPS) Trains A and B. Class 1E 120-Vac DCPP UNITS 1 & 2 FSAR UPDATE 8.3-38 Revision 21 September 2013 bus 1 and 4 provide power to the SSPS train A and train B output relays, respectively. The SSPS input relays are fail safe (with the exception of the input circuits that initiate containment spray, the radiation monitoring channels that initiate containment ventilation isolation, and the RCP underfrequency low flow trip channels ( refer to Sections 7.2.1.1.10 and 7.3.4.1.1), whereas the SSPS output relays require power to actuate. Each SSPS train actuates ESF equipment in the three Class 1E ac and dc buses and certain Non-Class 1E equipment in the Non-Class 1E ac and dc buses. As allowed per IEEE 308-1971, Class 1E dc bus 12 feeds Class 1E 120-Vac buses 12 and 14 in Unit 1 and Class 1E dc bus 22 feeds Class 1E 120-Vac buses 22 and 24 in Unit 2. For design basis accident scenarios concurrent with a loss of offsite power (LOOP), a single failure of the Unit 1 Class 1E dc bus 12 will cause the loss of Class 1E 120-Vac buses 12 and 14 in Unit 1. Similarly a single failure of the Unit 2 Class 1E dc bus 22 will cause the loss of Class 1E 120-Vac buses 22 and 24 in Unit 2. This is acceptable because the loss of Class 1E dc bus 12 in Unit 1 or Class 1E dc bus 22 in Unit 2 does not prevent the minimum safety functions from being performed. Loss of both IY/PY 12(22) and IY/PY 14(24) is acceptable because the remaining two 120-Vac inverters and buses can supply at least one full ESF train. Therefore, a single failure in the instrumentation and control power supply system or its associated power supplies does not prevent the minimum safety functions from being performed. 8.3.1.1.5.3.9 General Design Criterion 24, 1967 - Emergency Power for Protection Systems In the event of a loss of all offsite power, the Class 1E 120-Vac system is automatically powered from the Class 1E 125-Vdc system and will automatically be re-powered from the Class 1E 4.16-kV/480-V bus when the emergency diesel generator loads onto its Class 1E 4.16-kV bus. 8.3.1.1.5.3.10 General Design Criterion 40, 1967 - Missile Protection Class 1E 120-Vac instrument supply system equipment and cables are protected from internally generated missiles, pipe-whip and jet impingement. Detailed discussions of these protections are delineated in Sections 8.3.1.4.10.2 and 8.3.1.4.10.3 respectively. 8.3.1.1.5.3.11 General Design Criterion 49, 1967 - Containment Design Basis Class 1E and non-Class 1E 120-Vac circuits routed through containment are analyzed for redundant overcurrent protection and available fault energy. Circuits without direct in-line redundant protection have been analyzed to determine the available fault current is not of sufficient magnitude to damage the penetration conductor, penetration, or containment integrity. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-39 Revision 21 September 2013 Refer to Sections 3.8.1.1.3, 8.3.1.1.5.3.14, and 8.3.1.4.8 for additional details. 8.3.1.1.5.3.12 10 CFR 50.49 - Environmental Qualification of Electrical Equipment Important to Safety for Nuclear Power Plants The Class 1E 120-Vac system SSCs required to function in harsh environments under accidents conditions are qualified to the applicable environmental conditions to ensure that they will continue to perform their safety functions. Section 3.11 describes the DCPP EQ program and the requirements for the environmental design of the electrical and related mechanical equipment. The affected components are listed on the EQ Master List. 8.3.1.1.5.3.13 10 CFR 50.62 - Requirements for Reduction of Risk from Anticipated Transients without Scram (ATWS) Events for Light-Water-Cooled Nuclear Power Plants The ATWS Mitigation System Actuation Circuitry (AMSAC) System in both units is powered from the Non-Class 1E chemistry lab and counting room inverter. This inverter is powered from non-reactor protection system power supplies in either Unit 1 or 2. 8.3.1.1.5.3.14 10 CFR 50.63 - Loss of All Alternating Current Power The Class 1E UPSs are sized to continuously carry the maximum connected loads without exceeding their nameplate rating during a SBO event. To prevent receiving an spurious safety injection signal during a SBO condition, operator action is taken within 2 hours to provide at least two input channels of instrumentation to monitor system functions and actuate one train of safeguards equipment. The Class 1E portion of the 120-Vac system serves to distribute power to loads required to bring the plant to a safe shutdown condition during a SBO event. Refer to Section 8.3.1.6 for further discussion on station blackout. 8.3.1.1.5.3.15 10 CFR Part 50 Appendix R (Sections III.G, III.J, and III.L) - Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979 Section III.G - Fire protection of Safe Shutdown Capability: The Class 1E 120-Vac system satisfies the applicable fire protection requirements of 10 CFR Part 50, Appendix R, Section III.G fire protection of safe shutdown capability; by either meeting the technical requirements or by providing an equivalent level of fire safety. Refer to Section 8.3.1.4.10.1 and Appendix 9.5G. Section III.J - Emergency Lighting: Emergency lighting or BOLs capable of providing 8 hours of illumination when ac power to the BOL is lost are provided in areas where DCPP UNITS 1 & 2 FSAR UPDATE 8.3-40 Revision 21 September 2013 operation of the 120-vac system may be required to safely shut down the Unit following a fire as defined by 10 CFR Part 50, Appendix R, Section III.J. Refer to Section 9.5.3 and Appendix 9.5D. Section III.L - Alternative and Dedicated Shutdown Capability: Safe shutdown capabilities are provided in the control room and at an alternate location via the hot shutdown panel (refer to Section 7.4) as defined by 10 CFR Part 50, Appendix R, Section III.L. The ability to safely shut down the plant following a fire in any fire area is summarized in Section 4.0 of Appendix 9.5A and Appendix 9.5E. 8.3.1.1.5.3.16 Safety Guide 6, March 1971 - Independence Between Redundant Standby (Onsite) Power Sources and Between their Distribution Systems Each of the redundant onsite Class 1E 120-Vac power sources and its distribution system is independent from each other. The electrically powered loads are separated into redundant load groups such that loss of any one group will not prevent the minimum safety functions from being performed. For discussion related to independence of redundant systems, separation criteria for Class 1E systems and Class 1E separation and protection criteria, refer to Sections 8.3.1.4, 8.3.1.4.1 and 8.3.1.4.10, respectively. Further discussions on separation and isolations are found in Sections 8.3.1.4.2, 8.3.1.4.4 and 8.3.1.4.6. 8.3.1.1.5.3.17 Regulatory Guide 1.63, Revision 1, May 1977 - Electric Penetration Assemblies in Containment Structures for Light-Water-Cooled Nuclear Power Plants Class 1E and Non-Class 1E 120-Vac circuits routed through containment electrical penetrations are designed with redundant overcurrent protection. Circuits without direct in-line redundant protection have been analyzed to determine the available fault current is not of sufficient magnitude to damage the penetration conductor or penetration. Refer to Sections 8.3.1.1.5.3.11 and 8.3.1.4.8 for additional details. 8.3.1.1.5.3.18 NUREG-0737 (Item II.G.1 (4)), November 1980 - Clarification of TMI Action Plan Requirements Item II.G.1 (4) - Emergency Power for Pressurizer Equipment (Pressurizer Level Indication): The pressurizer level indication circuits are Class 1E and qualified for post-accident. The Class 1E instrument channels are supplied from inverters which are supplied from the ESF buses with automatic backup from the Class 1E emergency batteries. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-41 Revision 21 September 2013 8.3.1.1.5.4 Tests and Inspections Refer to Section 8.3.1.1.5.3.7 for tests and inspections details. 8.3.1.1.5.5 Instrumentation Applications Refer to Section 8.3.1.1.5.3.5 for instrumentation applications. 8.3.1.1.6 Diesel Generator Units The physical arrangement of the engine generator units is shown in Figures 9.5-10 and 9.5-11 for Unit 1; the arrangement is similar for Unit 2. Figure 9.5-12 shows the outline of the Unit 1 engine generators. The arrangement is similar for the Unit 2 generators with the exception of EDG 2-3, which is slightly different. The six diesel generators for Units 1 and 2 are essentially identical, self-contained units housed in individual compartments at elevation 85 feet in the turbine building. Three are located in the northwest or Unit 1 portion, and three are located in the southwest or Unit 2 portion of the structure. The compartments separate each diesel generator and its accessories from the adjacent units and conform to PG&E Design Class I requirements. 8.3.1.1.6.1 Design Bases 8.3.1.1.6.1.1 General Design Criterion 2, 1967 - Performance Standards The EDG system is designed to withstand the effects of, or is protected against natural phenomena such as earthquakes, flooding, tornados, winds, and other local site effects. 8.3.1.1.6.1.2 General Design Criterion 3, 1971 - Fire Protection The EDG system is designed and located to minimize, consistent with other safety requirements, the probability and effect of fires and explosions. 8.3.1.1.6.1.3 General Design Criterion 4, 1967 - Sharing of Systems The EDG system or components are not shared by the DCPP Units unless safety is shown not to be impaired by the sharing. 8.3.1.1.6.1.4 General Design Criterion 11, 1967 - Control Room The EDG system is designed to support actions to maintain and control the safe operational status of the plant from the control room or from an alternate location if control room access is lost due to fire or other causes. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-42 Revision 21 September 2013 8.3.1.1.6.1.5 General Design Criterion 12, 1967 - Instrumentation and Control Systems Instrumentation and controls are provided as required to monitor and maintain EDG system variables within prescribed operating ranges. 8.3.1.1.6.1.6 General Design Criterion 17, 1971 - Electric Power Systems The EDG system is designed to have sufficient capacity, independence, redundancy, and testability to perform its safety function assuming a single failure. 8.3.1.1.6.1.7 General Design Criterion 18, 1971 - Inspection and Testing of Electric Power Systems The EDG system design permits appropriate periodic inspection and testing of functional and operational performance of the system as a whole and under conditions as close to design as practical. 8.3.1.1.6.1.8 General Design Criterion 21, 1967 - Single Failure Definition The EDG system is designed to remain operable after sustaining a single failure. Multiple failures resulting from a single event shall be treated as a single failure. 8.3.1.1.6.1.9 Protection from High and Moderate Energy Systems and Internal Missiles The EDG systems are designed to be protected against dynamic effects and missiles that might result from plant equipment failure. 8.3.1.1.6.1.10 10 CFR 50.55a(g) - Inservice Inspection Requirements Applicable EDG system components are inspected to the requirements of 10 CFR 50.55a(g)(4) and 50.55a(g)(5) to the extent practical. 8.3.1.1.6.1.11 10 CFR 50.63 - Loss of All Alternating Current Power The EDG system meets the criterion of providing an alternate ac source within ten minutes of station blackout (SBO). 8.3.1.1.6.1.12 10 CFR Part 50 Appendix R (Sections III.G, III.J, and III.L) - Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979 Section III.G - Fire protection of Safe Shutdown Capability: Fire protection of the EDG system is provided by a combination of physical separation, fire-rated barriers, and/or automatic suppression and detection. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-43 Revision 21 September 2013 Section III.J - Emergency Lighting: Emergency lighting or battery operated lights (BOLs) are provided in areas where operation of the EDG system may be required to safely shut down the Unit following a fire. Section III.L - Alternative and Dedicated Shutdown Capability: Safe shutdown capabilities are provided in the control room and at an alternate location via the hot shutdown panel or locally at the EDG, for equipment powered by the EDGs required for the safe shutdown of the plant following a fire event. 8.3.1.1.6.1.13 Safety Guide 9, March 1971 - Selection of Diesel Generator Set Capacity for Standby Power Supplies The EDG system meets the applicable requirements of Safety Guide 9, March 1971 for steady state loading capability with one regulatory approved exception for DCPP: (1) Exception to loading sequence frequency requirements of Safety Guide 9, March 1971, Position C.4 for MDAFW pump loading on EDGS 1-1, 1-3, 2-2, and 2-3 (Reference 30). 8.3.1.1.6.1.14 Regulatory Guide 1.97, Revision 3, May 1983 - Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident The EDG instrumentation systems provide instrumentation in the control room to monitor EDG electrical status for post-accident instrumentation. 8.3.1.1.6.1.15 Regulatory Guide 1.108, Revision 1, August 1977 - Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants As required by Regulatory Guide 1.108, Revision 1, EDG testing simulates, where practical, the parameters of operation that would be expected if actual demand were to be placed on the system, as delineated in Technical Specification Bases 3.8.1. There are three regulatory approved exceptions to Regulatory Guide 1.108, Revision 1 for DCPP: (1) Exception to testing frequency guidelines of Regulatory Position C.2.a based on compliance with the TS 5.5.18 Surveillance Frequency Control Program (Reference 27). (2) Exception to EDG hot restart testing guidelines of Regulatory Position C.2.a (5) based on use of a modified hot restart test (Reference 28). (3) Exceptions to Regulatory Positions C.2.a (9), C.2.d, C.2.e and C.3 based on compliance with NUMARC 93-01, Rev. 2, "Industry Guidelines for DCPP UNITS 1 & 2 FSAR UPDATE 8.3-44 Revision 21 September 2013 Monitoring the Effectiveness of Maintenance at Nuclear Power Plants" (Reference 29). 8.3.1.1.6.2 System Description 8.3.1.1.6.2.1 Diesel Generator Unit Description Each diesel generator unit consists of a self-contained diesel engine directly connected to an alternating current generator, and the separate accessories needed for proper operation, all mounted on a common structural steel skid-type base. Mechanical power is provided by an 18 cylinder, vee configuration, four-cycle, 9-inch bore x 10-1/2 inch stroke, 12,024 cubic inch displacement, 3630 horsepower at 900 rpm, turbocharged and aftercooled, heavy-duty, stationary-type diesel engine.
The generator is rated at 3250 kVA, 0.8 PF, 4160 V, 60 Hz, three-phase, Y-connected, ungrounded, 80°C temperature rise, Class B insulation, with a drip-proof enclosure. The transient reactance is 14.1 percent, and the subtransient reactance is 8.1 percent. The exciter is a static series, boost-type exciter controlled by a static solid-state voltage regulator.
Five diesel engine generator units have been supplied by the ALCO Engine Division of White Industrial Power, Inc. The sixth diesel engine generator, EDG 2-3, was manufactured by G. E. Locomotives, the current owner and manufacturer of ALCO engines and locomotives at the time. In most respects, this EDG is similar to the other five EDGs; the differences and commercial grade dedication are documented in RPE M-6602. ALCO has supplied engine generator units to serve as emergency onsite standby power at several nuclear power plants. Among these are two ALCO units for the Palisades Nuclear Plant, which have the same engine as the first five DCPP engine generator units and a slightly smaller generator (2500kW continuous rating), and the two ALCO units for the Pilgrim I Nuclear Station, which has engines and generators that are identical to the first 5 at DCPP. Both of these nuclear power plants are in operation. In addition, the Salem 1 and 2 nuclear power plant has engine generator units with the same engines and generators as the first five DCPP engine generator units. The EDG auxiliary systems; starting air system, ventilation system, cooling water system, lubrication system, fuel oil storage and transfer system, and compartment ventilation system are described in Sections 9.4.7, 9.5.4, 9.5.5, 9.5.6 and 9.5.7. 8.3.1.1.6.2.2 Combustion Air Intake System The combustion air is taken into the engine through woven, dry-type, particulate filter media, encased in a cylindrical steel retaining structure. This air intake filter structure is supported from the ceiling in the radiator fan portion of the engine generator compartment. After passing through the filter, the combustion air is drawn into the engine through a 22-inch carbon steel pipe. The physical arrangement of the air intake filter and piping for Unit 1 is shown in Figures 9.5-10 and 9.5.11, and is similar for DCPP UNITS 1 & 2 FSAR UPDATE 8.3-45 Revision 21 September 2013 Unit 2. The diagram of the combustion air intake system is shown in Figure 3.2-21 (Sheets 7 and 8).
As shown in Figures 9.5-10 and 9.5-11 for Unit 1, the combustion air for the diesel engines is taken from the west side of the building, and the exhaust from the engines is directed upward through the roof on the north side of the turbine building for Unit 1. Unit 2 diesels are similar, except the exhaust is through the south wall of the turbine building. The exhaust is at a higher elevation than the combustion air intake. This arrangement ensures that the engine exhaust will be dispersed without the possibility of diluting the combustion air. There is no equipment or structure on the west side of the turbine building within the proximity of the combustion air intake that would create the potential for noncombustible or explosive gases being drawn into the engine.
Approximately 30 percent of the outside air drawn by the radiator fan is routed through ductwork providing ventilation for the diesel generator compartment. Refer to Section 9.4.7 for a complete description of the ventilation system. 8.3.1.1.6.3 Safety Evaluation 8.3.1.1.6.3.1 General Design Criterion 2, 1967 - Performance Standards The EDGs are located at elevation 85 foot of the turbine building, which is a PG&E Design Class II structure (refer to Figure 1.2-16 and 1.2-20). This building or applicable portions have been designed not to impact PG&E Design Class I components and associated safety functions (refer to Section 3.7.2.1.7.2). The turbine building is designed to withstand the effects of winds and tornados (refer to Section 3.3.1.2 and 3.3.2.3.2.8), floods and tsunamis (refer to Section 3.4), external missiles (refer to Section 3.5), and earthquakes (refer to Section 3.7.2.1.7.2) to protect the EDGs. The diesel generator excitation cubicle and control cabinet are seismically designed to perform their safety functions under the effects of earthquakes (refer to Section 3.10.2.6). The engine generator units and their associated auxiliary systems, as shown for Unit 1 in Figures 9.5-8, 9.5-9, and 9.5-10, and similarly for Unit 2, are installed in separate compartments that are protected from fires, flooding, and external missiles.
Any postulated external missile would not penetrate into more than one compartment. Section 3.3.2 provides more discussion on hypothetical external missiles generated by a postulated tornado. No common failure mode exists where one single event would disable more than one diesel generator.
It is not credible for a seismic event, the Hosgri event, to restrict the flow of exhaust gases from the diesel engine and thereby create excessive back pressure on the engine. The design of the exhaust system, shown schematically in Figure 3.2-21 (Sheet 7), precludes any major failures, such as a major failure of the silencer and/or DCPP UNITS 1 & 2 FSAR UPDATE 8.3-46 Revision 21 September 2013 the connecting piping, which would have to develop to produce any significant flow restriction. The internal baffles and chambers of the silencer are designed so that even if an internal baffle breaks completely loose, it will not block exhaust flow. The silencer supports, as well as the connecting piping supports, are designed in accordance with the same criteria as for PG&E Design Class I equipment supports, i.e., to withstand the Hosgri event with no loss of function.
The exhaust silencers and piping are located in separate compartments with no other piping or equipment that could adversely affect the silencers or piping during a Hosgri event. The exhaust lines of the Unit 1 diesels pass through the turbine building roof, and the exhaust lines of the Unit 2 diesels pass through the south wall of the turbine building, but are not considered a risk in the systems interaction program (SIP). The compartments are located immediately above the engine generators in the turbine building. An engineering review of the turbine building has shown that during a seismic event the building will not collapse. This analysis is discussed in Section 3.7.2.
Other equipment associated with the diesel generators that is seismically qualified includes:
(1) Fuel oil day tanks (2) Closed cooling water system, including fan and radiator (3) Fuel oil storage tanks and fuel oil piping (4) Lube oil system (5) Ventilation system 8.3.1.1.6.3.2 General Design Criterion 3, 1971 - Fire Protection The EDG areas are designed to the fire protection guidelines of Branch Technical Position APCSB 9.5-1 (refer to Appendix 9.5B, Table B-1). Refer to Section 8.3.1.4.9 for further discussion on fire barriers and separation. The portion of each compartment that houses the diesel generator is provided with a thermally actuated total flooding CO2 gas system, in accordance with NFPA Standard No. 12, 1973 (Reference 6). Temperature-actuated, automatic closing, roll-down fire-rated doors close ventilation air openings to prevent CO2 leakage. The CO2 flooding is restricted to the engine generator compartment by closing fire doors that isolate and seal the compartment. Refer to Section 9.5.1 for a complete description of the CO2 system. Additionally, two hose stations are provided adjacent to the compartment locations in each unit. The diesel generator installation is in accordance with NFPA 37 - 1970 (Reference 7).
DCPP UNITS 1 & 2 FSAR UPDATE 8.3-47 Revision 21 September 2013 Each engine generator compartment is provided with a CO2 flooding system for fire suppression. CO2 flooding will extinguish a fire in one compartment while the other engine generator units continue normal operation. In addition, 3-hour fire walls are provided between the individual compartments. A normally closed, 3-hour fire door separates the corridor connecting the diesel generator rooms from the main condenser area. This door is also designed to prevent a postulated condenser leak from flooding the diesel generator rooms (refer to Section 10.4.5). Section 9.5.1 provides more information on the fire protection system.
There is no combustible gas line or storage facility within or near the engine generator compartments. The only flammable liquids contained within the engine generator compartments are those necessary for the operation of the engines, i.e., engine lube oil and diesel fuel oil.
The startup transformers, located immediately north of the Unit 1 and south of the Unit 2 engine generator compartments, contain insulating oil, which is a potential fire hazard. However, the transformers are equipped with fire detection and fire suppression systems to quench potential fires. The engine generator compartment nearest the startup transformer is separated from the transformer by a 3-hour fire wall. The engine generator combustion air intakes are not affected by a transformer fire since combustion air is drawn from the west side of the building.
The main turbine seal oil systems are the closest source of flammable liquids within the turbine building. The seal oil units are located about 65 feet from the common corridor for each unit's diesel generators. Each seal oil unit is supplied with a fire detection and fire suppression system. A failure of the number 10 turbine bearing (between the exciter and generator) is the next closest potential fire hazard, since an open bay connects the turbine deck elevation (140 feet) with the diesel generator elevation (85 feet). The bay opening is located about 35 feet horizontally from the diesel generator common corridor. The Number 10 bearing is equipped with a fire detection and fire suppression system. The turbine building fire suppression systems would contain any turbine lube oil fire and prevent any hazard to the diesel engine generators. Refer to Section 9.5.1 for additional fire protection system information. 8.3.1.1.6.3.3 General Design Criterion 4, 1967 - Sharing of Systems The fuel oil storage and transfer subsystem of the EDG system are shared between Units 1 and 2. Refer to Section 9.5.4.3.3. 8.3.1.1.6.3.4 General Design Criterion 11, 1967 - Control Room Controls for engine generator functions are both local at the engine generator compartment and remote in the main control room. Each of the units may be manually started or stopped from either location to facilitate periodic testing. The generators may DCPP UNITS 1 & 2 FSAR UPDATE 8.3-48 Revision 21 September 2013 be synchronized from the control room so that they can be paralleled with the other power systems for testing. In addition, there is an emergency manual stop for each unit located outside each engine generator compartment. Automatic starting of the units occurs in the event of the conditions listed in Section 8.3.1.1.3.3.5.1. Each of the six units is provided with two independent starting control circuits for redundancy.
Engine generator units are normally controlled from the control room. A two-position local-remote switch located at each engine generator unit allows control of each unit to be switched from the control room (remote) to the engine generator compartment (local). Whenever control of any of the units is switched to the compartment (local), the operator is informed by a control room annunciator alarm. The alarm identifies the engine generator unit on local control. 8.3.1.1.6.3.5 General Design Criterion 12, 1967 - Instrumentation and Control Systems The units are fully instrumented to monitor important parameters and alarm abnormal conditions, both locally at the engine generator compartment and remotely in the main control room.
Each diesel generator is designed with two starting control circuits, one field flashing circuit, and one sensing circuit. These circuits receive Class 1E dc control power through a manual transfer switch. Class 1E dc power is from the same train as the diesel generator. In the event of failure of dc power to these control circuits, an alarm appears on the main annunciator. The manual transfer switch, located near the control panel at the diesel generator can be used to transfer to backup vital dc power. Loading of the diesel generators during the recirculation phase is under the control of the operator. To aid in loading these units, instruments are provided to indicate their load at all times. For additional information on instrumentation application, refer to Section 8.3.1.1.6.5 8.3.1.1.6.3.6 General Design Criterion 17, 1971 - Electric Power System The EDG system is required to have sufficient capacity, capability, independence, redundancy, and testability to perform its safety function assuming a single failure. The emergency power system includes onsite, independent, automatic starting diesel generators that supply power to essential auxiliaries if normal power sources are not available.
Three dedicated 4.16-kV, three-phase, 60-Hz, 2600-kW, 0.8-PF continuous rating diesel generators are provided for each unit as shown in Figure 8.1-1. The individual diesel generator units are physically isolated from each other and from other equipment. Each DCPP UNITS 1 & 2 FSAR UPDATE 8.3-49 Revision 21 September 2013 diesel generator supplies power to its associated 4.16-kV Class 1E bus (refer to Figures 8.3-4, 1.2-16, and 1.2-20). The ESF loads and their onsite sources are grouped so the functions required during a major accident are provided regardless of any single failure in the electrical system. Any two of the three diesel generators and their buses are adequate to serve at least the minimum required ESF loads of a unit after a major accident. Refer to Section 8.3.1.1.3.3.5.2 for additional discussion of ESF load grouping. Section 8.3.1.1.6.3.13 discusses EDG capacity and Section 8.3.1.1.6.4 demonstrates EDG system testability. 8.3.1.1.6.3.7 General Design Criterion 18, 1971 - Inspection and Testing of Electric Power Systems Descriptions of the inspections and tests are provided in Section 8.3.1.1.6.4. 8.3.1.1.6.3.8 General Design Criterion 21, 1967 - Single Failure Definition The ESF loads and their onsite standby sources (EDGs) are grouped so the functions required during a major accident or transient coincident with a complete loss of the preferred power source are provided regardless of a single failure of an EDG. Any two of the three diesel generators and their buses are adequate to serve the required ESF loads of a unit after a major accident or transient. The single failure criterion applies to the diesel fuel oil (DFO) system. Refer to Section 9.5.4.3.7 for discussion related to the DFO system. 8.3.1.1.6.3.9 Protection from High and Moderate Energy Systems and Missiles The engine generator units and their associated auxiliary systems, as shown for Unit 1 in Figures 9.5-8, 9.5-9, and 9.5-10, and similarly for Unit 2, are installed in separate compartments that provide protection from internal missiles. The possibility of flooding in the turbine building and in the diesel generator compartments is discussed in Sections 9.2.1, 10.4.5, and 10.4.6 under the ASW, circulating water and condensate and feedwater systems, respectively. High-energy line breaks outside the containment that could affect the turbine building are discussed in Section 3.6. There is no significant source of water within any of the engine generator compartments, and the design of the engine generator compartments (refer to Figures 1.2-16 and 1.2-20) prevents flooding within the generator compartments because the cross-sectional area for water to enter the compartments is less than the cross-sectional area for water to exit the compartments.
DCPP UNITS 1 & 2 FSAR UPDATE 8.3-50 Revision 21 September 2013 Because the engine generator units are separated from each other by the concrete walls of the compartments, the units are protected from postulated internal missiles. Any missile created by an explosion within a compartment would remain in that compartment. 8.3.1.1.6.3.10 10 CFR 50.55a (g) - Inservice Inspection Requirements Only the EDG jacket water cooling system components are included in the DCPP Inservice Inspection (ISI) Program per 10 CFR 50.55a(g)(4) and 10 CFR 50.55a(g)(5). 8.3.1.1.6.3.11 10 CFR 50.63 - Loss of All Alternating Current Power The SBO analysis demonstrated that the plant could be safely shutdown following a loss of offsite power utilizing either Buses G or H and their normally connected EDGs (Emergency AC sources) independent of the third EDG and its Bus F considered the alternate AC (AAC) source. The AAC source is a Class 1E EDG and meets the criterion for the AAC source to be available within 10 minutes with a target reliability of 0.95, and has sufficient capacity and capability to operate systems necessary for coping with a SBO for the required duration of 4 hours to maintain the unit in a safe shutdown condition. Refer to Section 8.3.1.6 for a complete discussion of SBO. 8.3.1.1.6.3.12 10 CFR Part 50 Appendix R (Sections III.G, III.J, and III.L) - Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979 Section III.G - Fire protection of Safe Shutdown Capability: The EDG system satisfies the applicable fire protection requirements of 10 CFR Part 50 Appendix R, Section III.G, fire protection of safe shutdown capability, by either meeting the technical requirements or by providing an equivalent level of fire safety. Refer to Section 8.3.1.4.10.1 and Appendix 9.5G. Section III.J - Emergency Lighting: Emergency lighting or ESF equipment areas and various access routes thereto are provided with individual (BOLs) capable of providing 8 hours of illumination when ac power to the BOL is lost. BOLs are provided in areas where operation of the EDG system may be required to safely shut down the Unit following a fire as defined by 10 CFR Part 50, Appendix R, Section III.J (refer to Section 9.5.3 and Appendix 9.5D). Section III.L - Alternative and Dedicated Shutdown Capability: Safe shutdown capabilities are provided in the control room and at an alternate location via the hot shutdown panel or locally at the EDGs (refer to Section 7.4 for a discussion of the HSP and local EDG controls for the EDG system) as defined by 10 CFR Part 50, Appendix R, Section III.L. The ability to safely shut down the plant following a fire in any fire area is summarized in Section 4.0 of Appendix 9.5A and Appendix 9.5E. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-51 Revision 21 September 2013 8.3.1.1.6.3.13 Safety Guide 9, March 1971 - Selection of Diesel Generator Set Capacity for Standby Power Supplies The diesel generators have a net continuous electrical output rating of 2600 kW at 0.8 power factor (PF), and 2752 kW at 0.8 PF, for 2000 hours per year. Short-term ratings of the diesel generators are 3000 kW at 0.8 PF for 2 hours per year, 2860 kW at 0.8 PF for 2 hours per 24-hour period, and 3250 kW at 0.8 PF for 30 minutes per 24-hour period. During the starting sequence for the safeguard loads, these machines can also carry short-time overloads. EDG loading meets the applicable criteria of Safety Guide 9, March 1971 (Reference 8). Momentary loads not included in Table 8.3-6 consist principally of transient inrush currents, relay and solenoid short-time currents, starting currents to motors, and starting and operating currents for motor-operated valves. These loads are within the short-time capability of the electric power systems and the engine generators.
During a design basis-loading scenario with nominal timer interval, these machines maintain the electric power frequency within 5 percent, hold voltages to a minimum of 75 percent, and recover successfully by complying with Safety Guide 9, March 1971 (Reference 8) with the exception of Regulatory Position C.4. Safety Guide 9, March 1971, Regulatory Position C.4 specifies that during the EDG loading sequence the frequency should be restored to within 2 percent of nominal in less than 40 percent of each load sequence time interval. For AFW pump loading for EDGs 1-1, 1-3, 2-2, and 2-3, the frequency is restored to within 2 percent of nominal in less than 60 percent of the load sequence time interval. Based on test data, EDGs 1-1, 1-3, 2-2, and 2-3 have adequate margin to prevent overlapping of loads and meet the objectives of Safety Guide 9, March 1971, Regulatory Position C.4. This exception to Safety Guide 9, March 1971, was approved in License Amendments 211/213 dated March 29, 2012. Refer to Section 8.3.1.1.3.3.5.2 for additional discussion of EDG ESF loading and functions. 8.3.1.1.6.3.14 Regulatory Guide 1.97, Revision 3, May 1983 - Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident Class 1E, Category 2 indications for each EDG wattage and amperage is provided in the control room for Regulatory Guide 1.97, Revision 3, monitoring. Refer to Table 7.5-6. 8.3.1.1.6.3.15 Regulatory Guide 1.108, Revision 1, August 1977 - Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants The EDGs are designed to permit inspection and testing of all important areas and features, especially those that have a standby function, in accordance with GDC 18, DCPP UNITS 1 & 2 FSAR UPDATE 8.3-52 Revision 21 September 2013 1971. This periodic testing ensures that the EDGs will meet their availability requirements. Periodic component tests are supplemented by extensive functional tests during refueling outages. Additionally, Generic Letter 1984-15 was issued to improve EDG reliability by reducing the number of cold fast starts and by eliminating excessive testing. Cold fast starting of EDGs is not applicable to DCPP as the EDGs are equipped with lube oil and water jacket heating devices to maintain the oil and water temperatures at levels which permit immediate assumption of load. Also, engine bearings are lubricated by motor-driven lube oil circulating pumps which run continuously prior to engine start. 8.3.1.1.6.4 Tests and Inspections The electrical systems have been designed to permit inservice inspection and periodic functional testing. The tests and scheduling are specified in the Technical Specifications. These tests are made to demonstrate that all Class 1E electrical systems are capable of performing their safety functions.
All six Diablo Canyon diesel engine generator units have undergone extensive shop testing to qualify the units as emergency standby power sources. A large part of the shop testing at ALCO Engine Division of White Industrial Power, Inc. was in addition to the normal manufacturer performance tests for units of this type. Special shop tests were conducted to verify the unit design capabilities, their reliability, and their conformance to specification requirements.
A summary of the ALCO shop testing is shown in Table 8.3-8. In addition, extensive preoperational qualification testing was performed for the engine generator units during DCPP startup. A summary of preoperational testing for the engine generators at Diablo Canyon is shown in Table 8.3-9.
Automatic starting of the diesel generators is tested by removal of available power from its offsite source or its bus, simulating a bus undervoltage condition, or by initiating a test from the reactor protection system. The bus should transfer to the offsite source automatically, and the diesel generators should start and reach normal operating conditions if bus voltage is not restored within one second.
The absence of offsite power is simulated by opening the bus feeder breaker, simulating a bus undervoltage condition, or removal of its potential to the transfer control circuits. The test is repeated, with the diesel generator as the source and the loading sequence for the absence of safety injection. In the presence of a test safety injection signal (SIS), the test is repeated with the loading sequence for this condition.
Should there be an actual SIS while the diesel generator is paralleled with the unit auxiliary transformer during a test, the SIS signal would trip the unit auxiliary transformer (preventing a potential overload of the diesel generators), and diesel generator breaker closed prevents transfer of this bus to the startup source. Loads DCPP UNITS 1 & 2 FSAR UPDATE 8.3-53 Revision 21 September 2013 already running on this bus will continue to run, other loads will be started by their SIS timers, and any containment fan coolers running on high will automatically be restarted on low speed. EDG test scope and test interval frequency meets the applicable criteria of Regulatory Guide 1.9, Revision 3 (Reference 25). 8.3.1.1.6.5 Instrumentation Applications All operating conditions that could normally be expected to render the diesel generators incapable of responding to an automatic emergency start signal are alarmed in the control room. A "diesel generator trouble" annunciator is alarmed in the main control room whenever any of the following conditions occur:
(1) Diesel is in manual or test condition (2) Loss of dc control power (3) Low fuel level in day tank (4) Low starting air pressure (5) Shutdown relay tripped (6) Lube oil system trouble (7) Primary filter high differential pressure (Unit 2 only) In addition to the diesel generator trouble annunciator window, there are alarm annunciator windows and data logger printouts for each of the above seven conditions.
The following abnormal conditions are annunciated in the main control room for each unit:
(1) Engine generator on local control, manual control, or test (2) Generator circuit breaker on local control (3) DC control undervoltage (a) Engine generator control (b) Circuit breaker control (4) Engine starting air pressure - low (5) Engine fails to start (overcrank)
DCPP UNITS 1 & 2 FSAR UPDATE 8.3-54 Revision 21 September 2013 (6) Engine lube oil system trouble (a) Low lube oil pressure (b) Low lube oil level
(c) High lube oil filter differential pressure (d) High lube oil temperature (e) Low lube oil temperature (f) Precirculating lube oil pump failure (7) Engine cooling system trouble (a) High jacket water temperature (b) Low jacket water level (c) High compartment air temperature (d) High radiator discharge air temperature (8) Engine fuel oil system trouble (a) High/low engine fuel oil day tank level (b) High/low storage fuel oil storage tank level (c) Fuel oil transfer pump overcurrent (d) Low engine fuel oil priming tank level (e) Fuel oil transfer pump running (9) Engine crankcase vacuum trouble (10) Generator stator temperature - high (11) Ground overcurrent (12) Generator negative sequence (13) Engine trip (shutdown relay tripped) DCPP UNITS 1 & 2 FSAR UPDATE 8.3-55 Revision 21 September 2013 (14) Engine generator circuit breaker trip (a) Reverse power (b) Loss of field (c) Generator differential overcurrent (15) Auxiliaries undervoltage or overcurrent (16) Engine generator on backup dc supply (17) High fuel oil transfer filter differential pressure (18) High diesel room temperature (temperature monitoring system) If the engine generator unit is started automatically on loss of standby power, or safety injection, or both, the engine trip or shutdown functions are limited to the following:
(1) Engine overspeed (2) Engine low lube oil pressure (3) Generator current differential (4) Emergency stop switch The engine overspeed trip is a mechanical device relying on centrifugal force to release a spring that, by mechanical action alone, stops the flow of fuel and shuts down the engine. Although a mechanical failure of the device could occur and cause a spurious shutdown of the engine, the manufacturer has many years of satisfactory operational experience with this device in all types of service. Also, the engine overspeed trip is a single-purpose device, designed specifically as a secondary or backup device in the event the normal speed control system malfunctions. Normal engine speed control is provided by the governor. The governor and the overspeed trip are considered independent, redundant devices.
The low lubricating oil pressure shutdown is actuated by two pressure switches in the engine lubricating oil system. Both devices must be actuated by low pressure to shut down the engine. A malfunction by one can be postulated but, by itself, could not generate an engine trip. Also, the low lubricating oil pressure trip is actually a low-low lubricating oil pressure condition. The setpoint for shutdown is 20 psig below the low lubricating oil pressure alarm point at which the operator is informed of the low-pressure condition.
DCPP UNITS 1 & 2 FSAR UPDATE 8.3-56 Revision 21 September 2013 The generator current differential relay has successfully undergone seismic testing as part of the relay boards, as reported in Section 3.10, so false operation due to an earthquake should not occur. False operation under conditions other than an earthquake would occur only due to failure of a particular internal component of the relay.
If the engine generator unit is started manually in the test mode, greater engine protection is provided and the following abnormal conditions, in addition to the four for automatic mode, will also trip the engine:
(1) Engine overcrank (after 10 seconds of engine cranking and failure to start) (2) Engine high jacket water temperature Protection of the electrical equipment associated with the engine generator units is provided by opening the generator circuit breaker in the event of any of the trips listed above, and any of the following abnormal electrical conditions: (1) Generator loss of field excitation (2) Generator reverse power (antimotoring) (3) Generator overcurrent (4) 4.16-kV bus current differential (5) Generator current differential (6) Generator field shorting contactor de-energized (loss of jacket water pressure and nominal speed less than 100 rpm)
A trip cutout switch disables the loss of field, reverse power, and overcurrent protection for each diesel generator during normal operation; that is, when the diesel is not in test mode. The switch is located in each bus's respective safeguard relay board and activates an alarm whenever protection is cut in.
Generator loss of field relay, reverse power relay, overcurrent relays, and bus differential relays have been successfully tested for seismic loads, as detailed in Section 3.10, so false operation due to an earthquake will not occur. 8.3.1.2 Analysis As previously described in this chapter, standby and preferred power supplies are provided, each adequately sized to permit functioning of systems, equipment, and components important to safety. An analysis of the preferred power supply is contained in Section 8.2.2. Section 8.3.1.1 contains an analysis and description of the design and DCPP UNITS 1 & 2 FSAR UPDATE 8.3-57 Revision 21 September 2013 operation of the preferred power supply, including a tabulation of diesel generator capabilities and loading. The design bases established for the design of the Class 1E electrical circuits, their conductors, and raceways ensure that the nuclear reactor and safeguards system and equipment can operate properly at all times. These bases comply with GDCs 17, 1971, GDC 18, 1971, Safety Guide 6, March 1971 (Reference 9), and IEEE 308-1971. In developing these design bases, careful consideration was given to the following factors:
(1) Separation and isolation of redundant electrical circuits (2) Construction, capacity, and loading of electrical conductors and cables (3) Construction, arrangement, and conductor fill of electrical raceways (4) Environmental conditions and protection from physical hazards (5) Electrical fault protection The power and control cable insulation used has been specified and tested to meet requirements that exceed IEEE, National Electric Code (NEC), or Insulated Power Cable Engineers Association (IPCEA) standards for flame retardance and self-extinguishing capabilities.
8.3.1.3 Conformance with Appropriate Quality Assurance Standards The Class 1E electrical systems, equipment, and components were designed, fabricated, installed, inspected, and tested under the formal quality assurance program developed during design and construction of the plant. The quality assurance program is described in Chapter 17. Reactor protection system testing is described in Chapter 7. 8.3.1.4 Independence of Redundant Systems This section presents the criteria and bases for the installation of Class 1E electrical systems. These criteria establish the minimum requirements for preserving the independence of redundant Class 1E electrical systems to ensure that they remain operational during any design basis event.
Each of the redundant, onsite, ac power sources and its distribution system is independent from the others. The Class 1E buses F, G, and H are each independently supplied by one diesel generator. No swing bus is utilized. There is no provision for automatically paralleling the standby power source of one load with the standby source of another load. There is no provision for automatically connecting one Class 1E load group with another load group or for the automatic transfer of load groups between redundant standby power sources.
DCPP UNITS 1 & 2 FSAR UPDATE 8.3-58 Revision 21 September 2013 8.3.1.4.1 Separation Criteria for Class 1E Systems Mutually redundant Class 1E electrical power equipment, devices, and circuits are physically separated from each other to meet single failure criteria of the standards. Diablo Canyon is not committed to Regulatory Guide 1.75 separation and isolation requirements.
Major Class 1E electric power distribution equipment is located in individual rooms isolated from non-Class 1E equipment, and also from other mutually redundant Class 1E equipment. In this case, separation of internal wiring is inherently achieved by the amount of spacing of the equipment, isolation by fire-rated concrete walls and floors, and use of fire-rated doors. Where Class 1E circuits of more than one mutually redundant system are in proximity in the same enclosure, panel, board, or unit of equipment, these circuits are run in separate metallic wireways or conduits and are typically connected to different terminal blocks. Separate wireways are not provided for certain low-energy steam generator wide-range water level instrument loops resulting from original plant construction. Exposed wiring at end connections to control devices (such as control switches) is separated by at least 5 inches for mutually redundant circuits. Less than 5 inches of separation is allowed for (a) low-energy signal (instrument loop) connections to indicating devices (such as recorders) that must be functionally grouped to enhance operator comprehension, and (b) certain existing Class 1E ammeters with 3 inches separation resulting from original plant construction. Mutually redundant circuits in boards and panels are separated by one of the following methods:
(1) Five-inch minimum separation in air (2) Metallic barrier (3) Metallic conduit (4) Glastic barrier (5) Sealtite Flex (6) "Scotch Brand" 7700 or equivalent electric arc and fireproofing tape with "Pluton" fabric exposed, and a minimum of a 1/4-inch overlap between wraps. This tape is held in place after application with AMP-TY stainless steel cable ties, or two complete wraps of Varglass silicone tying cord, Type 46. Maximum length between steel or cord ties does not exceed 18 inches (7) Varflex Type HA (heat-treated glassbraid) (8) Varflex silifex sleeving DCPP UNITS 1 & 2 FSAR UPDATE 8.3-59 Revision 21 September 2013 (9) Silicone RTV fire sealant material Methods (1) through (5) are used wherever possible. Methods (6) through (9) are used only where methods (1) through (5) are not feasible. In the main control board and console, mutually redundant Class 1E devices are placed in individual modules, 5 inches apart, which provide two thicknesses of metallic or electrical insulating material between them, or the devices are separated by one of the above methods. For low-energy devices (indicators and recorders) unit cases are relied upon for adequate separation. External connections for mutually redundant circuits are brought through separate floor openings and risers. In addition, design for routing of interconnecting wiring is based on a requirement that there be no direct line of sight exposure between mutually redundant circuit conductors.
Electrical conductors that interconnect separate units of equipment or devices throughout the plant are separated for redundant systems in these ways:
(1) Where a separate room is provided exclusively for a group of redundant equipment requiring circuits, the cables may be placed in trays or troughs within the room. With the exception of underfloor wiring beneath the protection racks, these are the only areas where cable trays are used. (2) In all other areas of the plant, Class 1E circuits are placed in metallic conduit for exposed conduit, and ABS plastic or rigid iron for embedded conduit. (3) Nuclear protection instrumentation channels are placed in separate raceways. Cable trays under the protection racks are enclosed beneath a subfloor and barriered from each other by solid structural floor support beams. Each protection channel output from the same channel to the same logic train shares the same raceway. Separate raceways are used for the direct inputs to logic Trains A or B. (4) In the cable spreading areas of each unit, electrical cables for redundant functions are placed in separate conduits. Circuit segregation can be on either a protection channel, train, Class 1E bus, or dc bus basis. All conductors in the cable spreading area associated with safety-related functions are enclosed in metallic conduits. Only non-Class 1E wiring is run in trays, with the exception of underfloor wiring beneath the protection racks.
For more details on separation of protective circuits, refer to Figure 7.3-50 (Sheets 1 and 2).
DCPP UNITS 1 & 2 FSAR UPDATE 8.3-60 Revision 21 September 2013 8.3.1.4.2 Separations and Isolations Electrical circuits are separated from each other according to class of service and to redundancy group. Separation criteria for mutually redundant circuits are given in the preceding section. Separate raceway systems are used for each of the following service categories:
(1) High-Voltage Power - This category contains all of the power circuits above 600-V; in this case, the 4160-V and 12,000-V conductors. (2) Low Voltage Power and Control - This category includes power circuits below 600-V; in this case, 480-V and 120/208-Vac, and also the 120-Vac and 125-Vdc control circuits. (3) Instrumentation - This category contains the circuits transmitting low-level sensitive signals for instrumentation and process control. It includes the conductors for thermocouples, resistance temperature detectors, and the transducers and transmitters used in the fluid process and electric power instrumentation systems. (4) Nuclear Instrumentation - This category contains the circuits for the nuclear instrumentation and control system. 8.3.1.4.3 Insulated Electrical Conductors Electrical conductors are copper, except for some thermocouple wire, and are stranded except for thermocouple, communications, and lighting branch circuits. Conductor sizes are based on the current and temperature ratings given in the National Electric Code (Reference 10) (NEC), the "Power Cable Ampacities," Publication S-135-1 (Reference 11) of the American Institute of Electrical Engineers (AIEE), or by the cable manufacturer, as appropriate. Cables have been derated for ambient temperature and cable grouping in a common raceway. Low-voltage small power cables have been derated as specified in the NEC, 1968 Edition, Table 3.10-12, and Notes 8 and 15. High-voltage and large power cables have been derated as specified in AIEE Publication S-135-1, Tables VII, VIII, and IX for grouping, and by using a conductor temperature that is less than the rating of the insulation by the same amount that the ambient is above the standard used in the table. Cables located in cable trays may be derated in accordance with Insulated Cable Engineers Association (ICEA) P-54-440 (Reference 19).
8.3.1.4.3.1 Construction and Voltage Ratings The insulation and jacket materials are selected for their superior electrical and physical characteristics and will perform their function under the most severe conditions expected for the application. The compounds are thermally stable and do not melt. All power and control cable jacket materials are flame retardant. Power and control cable DCPP UNITS 1 & 2 FSAR UPDATE 8.3-61 Revision 21 September 2013 insulations are also flame retardant. For exceptions to the fire retardant requirements, refer to Appendix 9.5B. Wire and cables run between equipment located in the conventional environment are insulated with ethylene-propylene rubber or cross-linked polyethylene (XLPE). Jacket materials are either neoprene, hypalon (chlorosulfonated polyethylene (CSPE)), XLPE or linear low density polyethylene. Silicon rubber, polyarlene, polyimide film, Tefzel, XLPE, or equivalent insulation material, with a silicone rubber, polyarlene, Tefzel, hypalon (CSPE), XLPE, or equivalent jacket material are used for circuits located where high ambient temperatures may be encountered. Within equipment, boards, panels, and devices, insulation is either fluorinated ethylene-propylene, cross-linked polyethylene, polyvinyl chloride (PVC) with an asbestos jacket (NEC Type TA), or PVC alone. The use of PVC has been kept to a minimum and is used only where a manufacturer has standardized production with this material. No PG&E Design Class 1 or Class 1E panel, board, or equipment has PVC insulated wires, except that devices such as relays, transmitters, and instruments may have some PVC. The small amount of PVC present does not present any problems with respect to toxic effects or corrosive products in the event of fire.
The insulated electrical conductors that externally interconnect separate units of equipment throughout the plant are described in Appendix 8.3B 8.3.1.4.3.2 Test and Inspection The construction and material composition of each type of cable has been selected based on careful investigation and analysis, including the results of tests performed in accordance with Underwriters' Laboratories (UL), IPCEA-NEMA, AEIC, and PG&E requirements.
All cables for circuits that externally interconnect separate units of equipment were given the production electrical and physical tests described in the standards. Flame tests for low-voltage power, control, and instrumentation cable were made according to UL and IPCEA standard procedures and to special PG&E methods using large groups of wires bundled in a cable tray and a large burner. The cable supplier was also required to make this test. Only cables that were self-extinguishing upon removal of the burner flame were selected. Refer to the previous section for those types of cables requiring flame retardant insulation. Conductors for equipment, boards, panels, and devices were selected and specified on the basis of UL approval for this service and special PG&E or manufacturer's tests.
Conductors required to operate in containment atmosphere during a LOCA were tested in a steam chamber, either by the manufacturer or PG&E, before approval for quotations. Refer to Section 3.11 for additional information on equipment required to operate during a LOCA.
DCPP UNITS 1 & 2 FSAR UPDATE 8.3-62 Revision 21 September 2013 A particular effort was made to ensure that manufacturing standards of the highest quality were maintained in the production of all cables for use in Class 1E circuits. To ensure that the cable, as manufactured, is of the highest quality, PG&E inspectors performed visual inspections and witnessed factory tests on sample reels from each production run of cable. 8.3.1.4.4 Electrical Raceways The total cross-sectional area of conductors in trays is limited generally to 30 percent of the tray cross-sectional area, with a maximum limit of 32 percent unless otherwise approved by an engineering evaluation. Electrical conduits are designed to the limits given in the NEC. The limit of 40 percent conduit fill is generally required, with a maximum of 42 percent fill unless otherwise approved by an engineering evaluation.
Electrical raceways that interconnect individual sets or units of equipment throughout the plant are arranged to provide separate raceways for each class of service and redundancy group. Also, separate raceways are provided for Class 1E electrical systems. Exposed raceways are either cable tray or metallic electrical conduit. Embedded raceways are ABS plastic of standard iron pipe size, except that some very short lengths are rigid iron. 8.3.1.4.5 Cable Trays Cable trays are generally of the ventilated uncovered type. Solid bottom or covered trays are placed in locations where protection is needed and ventilation may be reduced. Trays are made of formed steel, hot-dip galvanized, with sides 3 inches high and widths up to 24 inches. The trays comply with NEMA Standard VE-1-1965 for Class 2 construction. Aluminum trays are used in a few cases where severe corrosion of steel is a problem, such as at the intake structure. Aluminum is not used in the containment. Cable trays for Class 1E systems are only installed where a separate room is provided exclusively for each mutually redundant group of Class 1E circuits. 8.3.1.4.6 Conduit Metallic conduits are generally hot-dipped galvanized steel, either rigid iron or electrical metallic tubing (EMT). Aluminum conduit is used where magnetic induction may be a problem. Aluminum or PVC-coated rigid iron conduit may be used where corrosion is present, such as at the intake structure. Aluminum conduit is not used in the containment. Stainless steel conduit is used in a few cases where electrical circuits enter stainless steel liners. Flexible liquid-tight conduit is used in short sections where vibration or differential expansion may occur. An exception to this is the reactor head assembly where long flexible liquid-tight conduits exist for the convenience of the reactor head removal process upon refueling. Long flexible conduits in cable trays are also utilized in the cable spreading room for the white light circuits due to space limitations. Plastic (ABS) conduit is installed completely encased in concrete or in earth DCPP UNITS 1 & 2 FSAR UPDATE 8.3-63 Revision 21 September 2013 beneath a protective concrete slab. Metallic conduit is installed for mutually redundant Class 1E electrical circuits where they are close to, and exposed to, each other. 8.3.1.4.7 Supports Cable trays are supported on spans of 8 feet or less, and also at each end of the fittings. Unless otherwise approved by an engineering evaluation, exposed conduits are supported at intervals of 8-1/2 feet or less, and also within 4 feet of any termination. Supports for Class 1E electrical raceways are designed to withstand the seismic forces established for the location. Refer to Section 3.10 for more information on seismic design. PG&E Design Class I supports are not normally shared by mutually redundant Class 1E circuits. Exceptions to this are areas such as in the cable spreading room under the control room and in the fuel handling building at elevation 100 feet. However, as stated earlier, all PG&E Design Class I supports are seismically qualified. 8.3.1.4.8 Penetrations Cable penetrations through walls are (a) in jumboduct embedded in concrete (Figures 8.3-21 and 8.3-22), (b) in conduit embedded in concrete (Figure 8.3-23), or (c) in conduit passing through a wall opening with the space between the conduit and the concrete sealed as described below. Containment penetrations by high- and low-voltage and signal cables are either a canister-type design or feed through penetration modules that provide a single seal as part of the pressure barrier. Containment penetrations are also provided as part of the personnel and emergency airlocks. Additional information on the containment penetration design is provided in Section 3.8.1.1.3.1. These containment penetrations are LOCA qualified as described in Section 3.11. Overcurrent protection of the containment electrical penetrations meets the requirements of Regulatory Guide 1.63, Revision 1 (Reference 12). In addition, non-Class IE penetration overcurrent protection has procurement documentation or an engineering evaluation verifying the capability to protect the penetration during and after a Design Earthquake. 8.3.1.4.9 Fire Barriers and Separation Adequacy of design with regard to fire hazards in areas of concentration of electrical cables is analyzed in Section 8.3.1.4.10.1. Section 9.5.1 covers the fire protection system. Figures 9.5-1 and 9.5-3 show the fire protection water and CO2 systems, respectively.
Penetration fire stops and seals between rooms, fire seals inside conduits, fire stops on vertical and horizontal trays, and fire seals under equipment all serve to control and prevent propagation of fire from one redundant system to another, and from one room to another. All jumbo ducts for cable trays are provided with fire stops where they penetrate walls, floors, ceilings, and electrical equipment. In addition, fire stops are DCPP UNITS 1 & 2 FSAR UPDATE 8.3-64 Revision 21 September 2013 installed at intervals of 5 feet on vertical trays and 12 feet on horizontal trays, and within 5 feet of tray crossings, either above or below. Reference drawing 050029, DCP A-47854, DCP M-049476, and FHARES 101 and 103. Typical fire stops are shown in Figures 8.3-24 through 8.3-28. Conduits are provided with fire stops at the penetration of a fire barrier or at the nearest accessible point to that penetration. All cable entrances to the cable spreading room, control room areas, and interconnecting cable entrances between these two rooms are sealed to ensure the integrity of each area. Materials used for fire stops and seals are described in Appendix 8.3C. 8.3.1.4.10 Class 1E Separation and Protection Criteria Separation and protection of mutually redundant Class 1E systems prevent the loss of safeguard functions. Thus, a function is available even if the use of one redundant system is lost.
The criteria discussed in this section ensure protection for safeguard functions in case of fire, missiles, pipe whip, and jet impingement. (Protection from natural hazards such as earthquake, flood, and tornado is discussed in Sections 3.10, 3.4, and 3.3, respectively.) 8.3.1.4.10.1 Fire Specifications require that Class 1E cables be insulated with materials that do not support fire and are self-extinguishing. This prevents the spread or support of combustion from the original location of any fire along Class 1E cable. Outside of Class 1E equipment rooms, all mutually redundant Class 1E cables are required to be run in separate metallic conduit. This conduit prevents direct flame contact with Class 1E cable. Thus, it provides a second barrier to fire propagation along Class 1E cable.
Specifications require that electrical conductors have adequate ratings and overcurrent protection to prevent breakdown of insulation or excessive heating. Thus, fires will not be started in cable inside conduits due to overcurrent.
IEEE 308-1971 requires that Class 1E equipment be located in individual rooms. This isolates Class 1E equipment from non-Class 1E equipment and from mutually redundant Class 1E equipment. Isolation from fire is accomplished through the use of concrete walls with fire dampers and penetration seals, as necessary. It is not credible for fire to spread between rooms. Therefore, mutually redundant Class 1E equipment will not be disabled by a single fire.
10 CFR Part 50, Appendix R (Reference 13), Section III.G, provides criteria for protection of equipment and circuits required for safe shutdown. These criteria ensure that redundant safe shutdown trains will not be damaged as a result of a single fire. Protection of redundant trains is provided by a combination of physical separation, fire-rated barriers, and/or automatic suppression and detection. Exceptions to these criteria DCPP UNITS 1 & 2 FSAR UPDATE 8.3-65 Revision 21 September 2013 are documented based on the fire hazard in the area and/or other compensatory fire protection features provided.
Figure 9.5-2 shows that the diesel generator and Class 1E cable spreading rooms are protected by an automatic CO2 fire extinguishing system. Any fire starting in the cable spreading room will be extinguished in time to prevent the loss of safe shutdown capability. Class 1E cables are also run in rooms containing equipment that is not Class 1E. The possibility of fires starting in these rooms has been analyzed. It is not credible that any fire that may start in these rooms could destroy a protection function and impair plant safety.
As discussed above, fire will not cause a loss of any protection function for the following reasons:
(1) Class 1E equipment will not support fire or is protected by fire extinguishing equipment. (2) Class 1E systems are physically separated. (3) Redundant safe shutdown trains are separated and protected in accordance with Appendix R to 10 CFR Part 50, Section III.G, with exceptions. For further information on fire protection, refer to Reference 14. 8.3.1.4.10.2 Missiles The basic approach for protection of Class 1E equipment and cables from missiles is to ensure design adequacy against generation of missiles. Where missiles cannot be contained within parent equipment, missile protection is attained by routing or placing Class 1E cables and equipment in nonmissile-prone areas or by shielding the equipment.
Section 3.5 discusses postulated high-energy missiles. Class 1E cables and equipment are routed and placed so that they are protected from these missiles.
Outside of areas affected by high-energy missiles there is a very low probability of missile generation. Class 1E cables are protected from any possible low-energy missiles by the conduit in which they run.
Class 1E equipment, located in individual rooms, is protected from missiles generated outside the rooms by concrete walls and floors. After redundant Class 1E cables have passed into rooms where they make connections, they may be run in cable trays. However, mutually redundant wiring is not run in the same room. Therefore, missiles generated in the room will not cause a loss of any protection function.
DCPP UNITS 1 & 2 FSAR UPDATE 8.3-66 Revision 21 September 2013 8.3.1.4.10.3 Pipe Whip and Jet Impingement The protection of Class 1E equipment and cables from pipe whip and jet impingement has been studied (refer to Section 3.6). All Class 1E cables and equipment required for this accident are protected from damage caused by these hazards. 8.3.1.5 Physical Identification of Safety-Related Equipment Class 1E electrical power equipment is located in individual rooms isolated from non-Class 1E equipment and also from each other for mutually redundant sets of equipment. Nameplates on the sets of equipment and on the entrances to the rooms identify the equipment. 8.3.1.5.1 Color Coding Some electrical systems are color-coded:
(1) The Class 1E electrical power systems and equipment for each mutually redundant system (2) The reactor protection systems (3) The 120-Vac power circuits from the instrument inverters to the reactor protection channels (4) Control, indication, and annunciation circuits that are not required for safe shutdown that are in Class 1E raceways These colors are listed in Table 8.3-10 and have been applied to the Class 1E electrical circuits and their raceways that externally interconnect individual sets or units of equipment.
Internal wiring within units of equipment are not necessarily color-coded. Where a set of equipment is only one redundancy class that is clearly identified by other means, the circuits may have some or all of the conductors without any color coding. Standard Type TA switchboard wire, for example, is available in either black or gray colors only.
Where circuits of more than one mutually redundant system appear in the proximity or the same enclosure, the circuits have either the conductors, their bundling bands, or wireways identified by the assigned color code.
Conductors of control, indication, and annunciation circuits that are not required for safe shutdown may, to improve reliability, be purchased and installed as Class 1E and color-coded. These circuits are designed with sufficient isolation to ensure that a single failure does not propagate to the mutually redundant device. Circuits that do not serve safety-related functions, but are affiliated with safety-related devices, are colored DCPP UNITS 1 & 2 FSAR UPDATE 8.3-67 Revision 21 September 2013 consistent with the safety-related device, train, or circuit. Consequently, the coloring of these nonsafety-related circuits may not necessarily reflect the color code of their electric power sources.
Generally, non-Class 1E electric systems are assigned the color black. Because of certain industry standard practices, some non-Class 1E conductors are color-coded. These conductors are in circuits that are in no way related to those for operating the plant and are kept entirely separate. The functions of these systems are so obvious that there should be no confusion with the colors. These circuits are:
(1) Communication - these circuits are generally multiconductor with color-coded individual conductors. (2) Thermocouple - these circuits are always multiconductor and have individual conductors colored according to the ISA standard to denote the type of metal. However, the jacket is generally color-coded to match the assigned redundancy group. Special applications and systems may have other color-coding. (3) Lighting - these circuits have conductors color-coded according to the NEC.
Electrical conductors that interconnect separate units of equipment are identified by the color assigned to the system. On multiconductor cables, the color code is generally applied to the outer jacket and also to the individual conductors, except that thermocouple extension conductors have the ISA standard color designated for the type of metal. Each electrical raceway has its identification number stenciled in paint at readily visible places on its surface in the following colors:
(1) Black - all circuits 600 V and below (2) Red - all circuits above 600 V Cable tray designations are 1-inch high and spaced not more than 15 feet apart.
Conduit designations are 1-inch high, except that designations for conduits smaller than 1 inch are 1/2-inch high, and placed at each end of the conduit, at pull boxes, and at intermediate points to effectively identify the run.
In addition, each Class 1E raceway, either conduit or tray, is distinctly marked at termination points and at intermediate points with a vertical stripe, 2-inches wide, and colored to match the circuits within. The color code is given under the description of electrical conductors.
DCPP UNITS 1 & 2 FSAR UPDATE 8.3-68 Revision 21 September 2013 8.3.1.5.2 Design and Installation The design of electrical circuits is developed from the system requirements in conjunction with the manufacturer's circuits selected to perform the required functions. Past practices that have been successfully used by PG&E and the industry are also included in the design where possible. Functional analyses are made on the circuits by the designers and engineers during the completion of the schemes. Further review and coordination is made with persons whose interests are affected by the operation of the circuit. Final approval is made in the manner described in Chapter 17, Quality Assurance.
Electrical circuits are shown on the type of diagram appropriate to the information desired. Diagrams generally consist of these types: single line meter and relay, schematic, logic, block or functional, and connection. Conductor and main circuit numbers, as well as the equipment identification, are given in the schematic diagrams. Power conductor sizes are given in the single line meter and relay diagrams and checked by the responsible engineer.
Electrical circuits that interconnect separate units of equipment and devices throughout the plant are compiled, tabulated, and checked by electronic data processing equipment. Each termination point is given a unique designation, referred to as the location code, for convenience and to prevent ambiguity.
Each type of electrical conductor is given a unique code (known as the wire code) that identifies its class of service and redundancy group. Also, each individual electrical conductor has a unique identity given by its wire ID and circuit number. Each circuit is listed, giving the size and number of conductors, the raceway routing and termination points, and the identification symbol, coded to denote the circuit class of service and redundancy group and the conductor type, rating, and color. These listings are then checked manually against approved electrical diagrams. Also, the connection diagrams and a computer listing of circuits and conductors arranged by termination location are cross-checked manually. In addition, the computer checks that the circuits and raceways selected are of the same class of service and redundancy group.
Each raceway, tray, or conduit is assigned a unique code, referred to as the tray or conduit number. The raceway is then listed, giving its type, size, terminating or junction points, and the arrangement drawings showing its physical layout.
Separate circuit schedules are made for each class of service except for lighting branch circuits and telephone cables that are shown only on diagrams. Circuit schedules are typically not utilized for loads fed from the 12-kV underground distribution system.
The circuit information is stored by computer using a software program in the form of electronic drawings distributed by downloading from the network to individual computers. The electronic drawings can then be printed for use in the field. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-69 Revision 21 September 2013 The circuit information software checks that the raceway contains only the allowable grouping of circuits according to the class of service and redundancy. The software also calculates the percentage fill. Any overfills are corrected manually.
Individual circuit installation records for the installation and termination of the electrical circuits are derived from circuit data stored by computer using a software program. Each circuit installation record consists of installation and termination data. All predetermined data is entered in these forms.
The installation data may include the circuit schedule, termination locations, raceway routing, cable data, and purchase order or stock code.
Termination data may provide the diagram of connection for each termination point and the type and size of connectors and tools used.
Circuit and raceway installation data is retained for quality assurance purposes.
The methods and procedures for the design and installation of Class 1E electrical equipment and material are described in Chapter 17, Quality Assurance. 8.3.1.6 Station Blackout Station Blackout (SBO) at DCPP is defined as loss of power from the preferred power source with the failure of two emergency AC sources (EDGs) in the unit experiencing the SBO (References 20, 21, 22, and 23). The other unit is assumed to experience only a loss of offsite power. To comply with the requirements of 10 CFR 50.63, a sixth EDG was added to Unit 2 and the existing (swing) fifth EDG was made Unit 1 specific. There are now three dedicated EDGs per unit. The DCPP Units are assigned an allowed EDG target reliability of 0.950 and a SBO duration of 4 hours. The bus F EDGs 1-3 and 2-3, the designated AAC power sources, are available within ten minutes from the onset of the SBO event. These EDGs have sufficient capacity and connectability to operate systems necessary for mitigating a SBO event for the required duration of 4 hours to maintain the reactor in a safe shutdown condition. The DCPP SBO analysis was performed using the guidance provided in NUMARC 87-00, Rev. 0 (Reference 23) and Regulatory Guide 1.155, August 1988 (Reference 31) which contains guidance that is not provided in NUMARC 87-00. Using this guidance, (the postulated maximum SBO duration for DCPP was determined to be 4 hours. This SBO duration time was determined based on the following factors: (1) The site susceptibility to grid-related loss of offsite power events of greater than 5 minutes duration is expected to be less frequent than once per DCPP UNITS 1 & 2 FSAR UPDATE 8.3-70 Revision 21 September 2013 20 years. Grid-related loss of offsite power events are defined as losses of offsite power associated with the loss of the transmission and distribution system due to insufficient generating capacity, excessive loads, or dynamic instability. Although grid failure may also be caused by other factors, such as severe weather conditions or brush fires, these events are not considered grid-related since they are caused by external events. (2) The probability of loss of offsite power due to the occurrence of severe weather at the plant site is low based on historical weather data (Reference 23). (3) The plant is served by two offsite power circuits connected to the plant's Class 1E buses through two electrically independent switchyards. (4) The reliability of the EDGs is greater than or equal to 0.95. 8.3.1.6.1 Emergency AC (EAC) Analysis The emergency ac (EAC) classification for DCPP is Group C. For DCPP, the EAC criteria require that the unit under consideration be capable of attaining Mode 5 in the event of a LOOP and single failure (within each unit), without use of the designated alternate AC (AAC) source. The DCPP EAC analysis demonstrated that the plant could be safely shutdown to Mode 5 utilizing either buses G or H and their normally connected EDGs (EAC sources) independent of the third EDG and its bus F, considered the AAC source. The turbine-driven AFW pump is credited for operation with bus G (a motor-driven AFW pump is available on the bus H). The EAC analysis determined that the only required shutdown system not provided on bus H is the auxiliary salt water (ASW) system. However, ASW can be made available (even given an active failure or bus failure on the other unit) through the ASW hydraulic interconnection between units. To accomplish the unit-to-unit ASW interconnection, the analysis assumes the common unit valve FCV-601 would be manually opened. One ASW pump is capable of supplying sufficient flow to both a Unit 1 and a Unit 2 CCW heat exchanger, thus handling the shutdown heat loads from both units. Although the DCPP SBO EAC analysis takes credit for the hydraulic ASW interconnection between units, the electrical interconnection of the 4.16-kV buses within a unit to obtain the necessary ASW flow is not precluded. During a SBO event, operator action is necessary to energize the battery charger(s), within the 2-hour battery duty cycle, to provide at least two input channels of instrumentation to monitor system functions and actuate one train of safeguards equipment. This action involves closing an input and output breaker to battery charger 121(122) if bus G is not available. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-71 Revision 21 September 2013 Sufficient input channels may be deenergized such that a safety injection (SI) signal may be initiated. However, it was determined that generation of an inadvertent SI signal is acceptable and does not interfere with maintaining the safe shutdown of the unit. 8.3.1.6.2 Alternate AC (AAC) Analysis The SBO AAC analysis demonstrates that the bus F EDGs satisfy the criteria specified in Appendix B to NUMARC 87-00, and will be available within ten minutes of the onset of the SBO event, and has sufficient capacity and capability to operate systems necessary for the required duration of 4 hours to maintain the unit in a safe shutdown condition (Mode 3). However, during an SBO event, any of the three EDGs have the capability and capacity to be used as the AAC source. Because the AAC source is a Class 1E EDG, it meets the criterion for the AAC source to be available within 10 minutes and, therefore, no coping analysis was required to be performed. The SBO AAC analysis is not required to assume a concurrent single failure or design basis accident. In addition, 10 CFR 50.63 (Reference 20) permits the use of non-safety-related systems and equipment to respond to a SBO event. Based on the SBO AAC analysis, operation of several systems and components were evaluated for the required duration of 4 hours to maintain the unit in a safe shutdown condition. The only equipment not available from the AAC bus F is the diesel fuel oil transfer pumps which can be supplied from either bus G or bus H of the other unit. During an SBO event, operator action is necessary to energize the battery charger(s) within the 2 hour battery duty cycle, to provide at least two input channels of instrumentation to monitor system functions and actuate one train of safeguards equipment. This action involves closing an input and an output breaker to Battery Charger 131 (231). Sufficient input channels may be deenergized such that a safety injection (SI) signal may be initiated. The additional loading on bus F of the SI pump can be accommodated; such an inadvertent SI is acceptable. Plant-specific procedures were reviewed and updated to incorporate the requirements associated with the recovery from an SBO event. Recovery plans that include coordination with other power stations to re-route power to DCPP were also developed and implemented (Reference 21). 8.3.2 DC POWER SYSTEMS There are two dc power systems in each unit at Diablo Canyon. One is a non-Class 1E system serving 125-Vdc and 250-Vdc non-Class 1E loads. The other is a Class 1E system serving Class 1E 125-Vdc loads that include ESF loads and some non-Class 1E loads. Refer to Figures 8.3-17 and 8.3-18. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-72 Revision 21 September 2013 8.3.2.1 Design Bases 8.3.2.1.1 General Design Criterion 2, 1967 Performance Standards The Class 1E 125-Vdc system is designed to withstand the effects of or be protected against natural phenomena, such as earthquakes, tornados, flooding, winds, and other local site effects. 8.3.2.1.2 General Design Criterion 3, 1971 Fire Protection The Class 1E 125-Vdc system is designed and located to minimize, consistent with other safety requirements, the probability of events such as fires and explosions. 8.3.2.1.3 General Design Criterion 4, 1967 Sharing of Systems The 125-Vdc system or components are not shared by the DCPP Units unless it is shown safety is not impaired by such sharing. 8.3.2.1.4 General Design Criterion 11, 1967 Control Room The Class 1E 125-Vdc system is designed to support safe shutdown actions to maintain and control the safe operational status of the plant from the control room or from an alternate location if control room access is lost due to fire or other cause. 8.3.2.1.5 General Design Criterion 12, 1967 Instrumentation and Control The Class 1E 125-Vdc system design has instrumentation and controls to monitor and maintain system variables within prescribed operating ranges. 8.3.2.1.6 General Design Criterion 17, 1971 Electric Power Systems The Class 1E 125-Vdc system design has sufficient capacity, capability, independence, redundancy, and testability to perform its safety function assuming a single failure. 8.3.2.1.7 General Design Criterion 18, 1971 Inspection and Testing of Electric Power Systems The Class 1E 125-Vdc system design permits appropriate periodic inspection and testing of functional and operational performance of the system as a whole and under conditions as close to design as practical. 8.3.2.1.8 General Design Criterion 21, 1967 Single Failure Definition The Class 1E 125-Vdc system is designed to remain functional after sustaining a single failure. Multiple failures resulting from a single event shall be treated as a single failure. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-73 Revision 21 September 2013 8.3.2.1.9 General Design Criterion 24, 1967 Emergency Power for Protection Systems The Class 1E 125-Vdc system provides an alternate source of power to permit the required functioning of the protection systems in the event of loss of all offsite power. 8.3.2.1.10 General Design Criterion 40, 1967 Missile Protection The Class 1E 125-Vdc system is designed to be protected against dynamic effects and missiles that result from plant equipment failures. 8.3.2.1.11 General Design Criterion 49, 1967 Containment Design Basis The Class 1E 125-Vdc and non-Class 1E 125-Vdc circuits routed through containment electrical penetrations are designed to support the containment design basis so that the containment structure can accommodate, without exceeding the design leakage rate, the pressure and temperatures following a loss-of-coolant accident. 8.3.2.1.12 10 CFR 50.49 Environmental Qualification of Electric Equipment The Class 1E 125-Vdc system electric components that require environmental qualification (EQ) are qualified to the requirements of 10 CFR 50.49. 8.3.2.1.13 10 CFR 50.62 Requirements for Reduction of Risk from Anticipated Transients Without Scram (ATWS) Events for Light-Water-Cooled Nuclear Power Plants The non-Class 1E 125-Vdc power source, as required for ATWS, provides a source that is independent form the protection system power supplies. 8.3.2.1.14 10 CFR 50.63 Loss of All Alternating Current Power The Class 1E 125-Vdc system provides power to the loads required to support systems that ensure core cooling and containment integrity is maintained from the alternate ac source following a loss of all ac power (station blackout). 8.3.2.1.15 10 CFR Part 50 Appendix R (Sections III.G, III.J, and III.L) Fire Protection Program for Nuclear Power Facilities Operating Before January 1, 1979 Section III.G - Fire protection of Safe Shutdown Capability: Fire protection of the Class 1E 125-Vdc system is provided by a combination of physical separation, fire-rated barriers, and/or automatic suppression and detection. Section III.J - Emergency Lighting: Emergency lighting or battery operated lights (BOLs) are provided in areas where operation of the 125-Vdc system may be required to safely shut down the Unit following a fire. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-74 Revision 21 September 2013 Section III.L - Alternative and Dedicated Shutdown Capability: Safe shutdown capabilities are provided in the control room and at an alternate location, via the hot shutdown panel or locally at the 125-Vdc switchgear, for equipment powered by the 125-Vdc system required for the safe shutdown of the plant following a fire event. 8.3.2.1.16 Safety Guide 6, March 1971 Independence Between Redundant Standby (Onsite) Power Sources and Between Their Distribution Systems The Class 1E 125-Vdc system is designed so dc electrically powered safety loads are separated into redundant load groups so that loss of any one group will not prevent the minimum safety functions from being performed. Each dc load group should be energized by a battery and battery charger. The battery-charger combination should have no automatic connection to any other redundant dc load group. If means exist for manually connecting redundant load groups together, at least one interlock should be provided to prevent an operator error that would parallel the standby power sources. 8.3.2.1.17 Safety Guide 32, August 1972 Use of IEEE Standard 308-1971 Criteria for Class 1E Electric Systems for Nuclear Power Generating Stations Safety Guide 32, August 1972 identifies a conflict between IEEE 308-1971 and GDC 17, 1971, specifically with respect to battery charger supply. IEEE 308-1971 requires that each battery charger supply shall furnish electric energy for the steady-state operation of connected loads required during normal operation while maintaining its battery in a fully charged state, and have sufficient capacity to restore the battery from the design minimum charge to its fully charged state while supplying normal steady-state loads. In contrast, the equivalent provision of GDC 17, 1971 requires that the onsite electric power supplies shall have sufficient independence, redundancy, and testability to perform their safety functions assuming a single failure. This Safety Guide imposes GDC 17, 1971, which does not restrict the battery charger supply load to that of the steady-state condition during normal operation. 8.3.2.1.18 Regulatory Guide 1.63, Revision 1, May 1977 Electrical Penetration Assemblies in Containment Structures for Light-Water-cooled Nuclear Plants The Class 1E 125-Vdc and non-Class 1E 125-Vdc circuits routed through containment electrical penetrations are designed to the requirements of Regulatory Guide 1.63, Revision 1 for installation of redundant or backup fault current protection devices to limit fault current to less than that which the penetration can withstand, assuming a single random failure of the circuit overload protective device. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-75 Revision 21 September 2013 8.3.2.1.19 Regulatory Guide 1.97, Revision 3, May 1983 Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident The Class 1E 125-Vdc battery voltmeters and ammeters located in the control room are credited Regulatory Guide 1.97, Revision 3, indications for power supply status. 8.3.2.2 System Description 8.3.2.2.1 Non-Class 1E 125-Vdc / 250-Vdc Power System The non-Class 1E system consists of three 60-cell, 125-Vdc nominally rated batteries. Two of these batteries are connected in series to provide 250-Vdc power to a 250-Vdc motor control center (MCC). The MCC serves the non-Class 1E 250-Vdc loads, as shown in Figure 8.3-18, sheet 1 of 2. The 125-Vdc distribution panels associated with these batteries supply power non-Class 1E 125-Vdc loads, as shown in Figure 8.3-18. The third battery provides non-Class 1E 125-Vdc power to the plant process computer uninterruptible power supply. Each of the three batteries is continuously charged by a battery charger. The battery chargers are powered from separate 480-V non-Class 1E buses. 8.3.2.2.2 Class 1E 125-Vdc Power System The Class 1E dc system consists of, or has, the following features (see Figure 8.3-17):
(1) Three 60-cell (refer to Section 8.3.2.3.6.3 for 59-cell configuration), 125-Vdc batteries. (2) Three separate 125-Vdc power distribution switchgear assemblies, each including a 125-Vdc bus, circuit breakers, fuses, metering, and two distribution panels. (3) Five battery chargers. Each of the three 125-Vdc switchgear buses has a battery charger. Batteries 11(21)(a) and 12(22) have an additional swing backup battery charger that can be connected to either bus by manually closing one of the two interlocked breakers. The fifth battery charger is a backup charger for battery 13(23). Manual operation of a circuit breaker is required to place this battery charger in service on the bus. No interlock is provided between the two battery chargers on this bus. (4) The system and equipment is designed Class 1E from, and including, the batteries to, and including, the molded case distribution panel circuit breakers. (a) Each unit's dc power system is identical; therefore, unit identification is as follows: e.g., 11, 12, and 13 = Unit 1, and (21), (22), and (23) = Unit 2.
DCPP UNITS 1 & 2 FSAR UPDATE 8.3-76 Revision 21 September 2013 8.3.2.2.2.1 Class 1E Power Distribution System Equipment The dc power distribution system for each unit consists of three completely metal-enclosed switchgear assemblies, as follows:
(1) Three separate 125-Vdc copper buses 11(21), 12(22), and 13(23) are completely enclosed in their own metalclad switchgear. Each bus is rated at 1200 amperes continuous. There is one 125-Vdc, 60-cell (refer to Section 8.3.2.3.6.3 for 59-cell configuration) battery supplying each 125-Vdc bus. Source protection is provided by fuses rated at 3000 amperes. (2) Two 125-Vdc circuit breaker distribution panels are connected to each of the 125-Vdc buses 11(21), 12(22), and 13(23). The connection to buses 11(21) and 12(22) is made through drawout, manually operated air circuit breakers(b), and bus 13(23) connects directly to the panels. The air circuit breakers are rated 600 amperes with long- and short-time overcurrent elements. One panel per bus is generally utilized for Class 1E loads and the other typically used for non-Class 1E loads. The panels are an integral part of the respective switchgear and, therefore, they are all designed, engineered, and constructed as Class 1E panels. Each panel is ungrounded and has one main bus, rated 600 amperes continuous. Panel branch circuit breakers are molded case, thermal magnetic, quick-make and quick-break, rated 250-Vdc, 20,000-amperes interrupting capacity. The two panels on each bus have the same designation (e.g., on buses 11, both panels are called 125-Vdc distribution Panel 11) because they are electrically connected as one panel. However, typically they are physically separated on the left and right side of the switchgear to generally supply Class 1E and non-Class 1E loads, respectively. The left side panels typically provide power to the following loads: (a) Class 1E dc power and control (b) Class 1E dc diesel generator field flashing (c) Class 1E dc instrumentation. (d) Main annunciator (e) UPSs for nuclear instrumentation The right side panels typically provide power to the following loads: (b) These circuit breakers were required for the original design when buses 11(21) and 12(22) were connected in series to provide 250-Vdc non-Class 1E power.
DCPP UNITS 1 & 2 FSAR UPDATE 8.3-77 Revision 21 September 2013 (a) Non-Class 1E dc power and control (b) Non-Class 1E dc instrumentation (c) Auxiliary annunciators An additional 125-Vdc distribution panel 14(24) is a subpanel of distribution panel 13(23) for non-Class 1E loads. 8.3.2.2.2.2 Class 1E 125-Vdc Battery Chargers The 125-Vdc battery chargers are Class 1E power supplies. A total of ten battery chargers are supplied, five for Unit 1 and five for Unit 2. Three chargers serve two of the 125-Vdc buses (buses 11(21) and 12(22)) and two chargers serve 125-Vdc bus 13(23). Each of the chargers is connected to a bus through a molded case, manually operated thermal-magnetic 600 ampere breaker located in dc switchgear 11(21), 12(22), and 13(23). Normally, buses 11(21), 12(22), and 13(23) are supplied by one battery charger each. Buses 11(21) and 12(22) share a swing backup battery charger for closing in on bus 11(21) or 12(22) if either primary battery charger on 11(21) or 12(22) is not able to provide service. A second battery charger is a backup charger for bus 13(23). Each charger is constructed of high quality, reliable, solid-state components conservatively rated for long life. The chargers provide rated direct current output continuously at a voltage smoothly adjustable from 118-Vdc to 144-Vdc, and regulated to +/-0.5 percent through the entire range of input and local variations. The maximum output current is 110 percent of rated output under any loads or short circuit conditions. The charger is self-protected against transient voltages that may occur on the dc system. An alarm cutout switch is provided on the outside of each battery charger cabinet. Each cutout switch disables the following battery charger alarms:
(1) ac fuse failure (2) dc undervoltage and overvoltage (3) ac breaker trip (4) dc breaker trip The cutout switch is used to avoid unnecessary alarms and operator distractions when a battery charger is out of service or receiving maintenance. Proper use of the cutout switches is administratively controlled by operating procedures.
DCPP UNITS 1 & 2 FSAR UPDATE 8.3-78 Revision 21 September 2013 8.3.2.2.2.3 Class 1E 125-Vdc Batteries The 125-Vdc batteries are Class 1E power supplies. Mean life of the batteries is 20 years (refer to Section 3.10.2.8.1 for battery qualification). Each cell is contained in a sealed, heat resistant, shock absorbing, clear polycarbonate case. Similar cells were tested and met seismic and vibration requirements. A total of six batteries, 11(21), 12(22), and 13(23) are supplied for Units 1 and 2. Battery racks are provided with an analytically calculated, earthquake-proof, engineered rigid rack design to meet the seismic requirements of the battery room. The battery racks are of Unistrut construction and mounted to the floor and wall for rigid seismic mounting.
Diffusion vents on battery filling openings provide continuous and uniform dispersion of hydrogen produced by the batteries. These vents are designed to prevent localized hazardous concentrations of hydrogen. 8.3.2.2.2.4 Safety-Related Loads Normally, the battery chargers will supply the total load requirements of the dc system as well as maintain a constant floating charge on the batteries. The batteries are paralleled with the chargers and supply dc power to the system if the ac power fails. The nuclear instrumentation UPSs and the main annunciator are automatically supplied from either the 125-Vdc system or the 480-V system depending on their availability. The voltage level of the rectifier in the UPS unit is set such that the inverter preferentially feeds from the 480-V system via the rectifier. Considering normal starting times for the diesel generators and the battery charger dc output time delay circuit that prevents full charger output for 20 to 30 seconds, the first 40-second loads on each bus are supplied by its respective battery.
The dc loads on the bus after 40 seconds will be carried by the battery charger. The charger has sufficient capacity to carry loads up to 110 percent of its 400-ampere rating. When the chargers are not loaded to maximum rating, then excess capacity charges the battery. Refer to Section 8.3.2.3.6. 8.3.2.3 Safety Evaluation 8.3.2.3.1 General Design Criterion 2, 1967 Performance Standards The Class 1E 125-Vdc system is located in the auxiliary building which is a PG&E Design Class I structure (refer to Figure 1.2-5). The auxiliary building is designed to withstand the effects of winds and tornados (Section 3.3), floods and tsunamis (Section 3.4), external missiles (Section 3.5), and earthquakes (Section 3.7), to protect Class 1E 125-Vdc SSCs from damage due to these events to ensure they will continue to perform their safety function. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-79 Revision 21 September 2013 Loss of the 125-Vdc inverter room ventilation system and Class 1E 125-Vdc raceways located outdoors, and exposed to the effects of tornados, has been evaluated and the consequences of a tornado do not compromise the capability to safely shut down the plant. Refer to Section 3.3.2.3. Equipment included in the dc system was proved to be acceptable to seismic requirements by testing, analytical calculations, or testing on similar equipment. The manufacturers were required to conform to approved quality assurance procedures. Refer to Section 3.10.2.8 for a description of the seismic qualification for batteries, battery racks, battery chargers and dc switchgear. Although the ventilating system for the battery rooms is PG&E Design Class II, the supply and exhaust ductwork serving the battery rooms are designed and installed to meet Seismic Category I criteria. 8.3.2.3.2 General Design Criterion 3, 1971 Fire Protection The Class 1E 125-Vdc system is designed to the fire protection guidelines of BTP APCSB 9.5.1 (refer to Appendix 9.5B Table B-1). Ventilation for the Class 1E dc equipment is provided as follows:
(1) Battery rooms are ventilated to prevent accumulation of hydrogen gas and to maintain ambient temperature. For each unit, the three battery rooms are constructed of reinforced concrete and cement block grout walls.
Ventilation air is supplied by a common duct and supply fan, and is exhausted through an exhaust fan to a common duct that exhausts directly to the atmosphere. The ventilation system is PG&E Design Class II (2) The dc switchgear rooms have PG&E Design Class I ventilation supply and exhaust systems and are described in Section 9.4.9. These three separate rooms, housing separate buses, panelboards, and battery chargers, have a common ventilation system. In case of loss of forced ventilation, the calculated natural ventilation rate due to the thermal stack effect will maintain hydrogen gas below 1 percent by volume. This accumulation is below the allowable limit of 2 percent by volume as recommended by Regulatory Guide 1.128, Revision 1 (Reference 17). 8.3.2.3.3 General Design Criterion 4, 1967 Sharing of Systems The Class 1E 125-Vdc system for each unit is not shared with the other unit. The Class 1E 125-Vdc system is a support system for common unit systems and components listed in Section 1.2.2.10. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-80 Revision 21 September 2013 8.3.2.3.4 General Design Criterion 11, 1967 Control Room Each Class 1E bus is provided with a voltmeter and ammeter mounted on the control room main control board for remote indication.
The chargers have voltmeters and ammeters remotely located on the main control board to indicate operational status of battery chargers. 8.3.2.3.5 General Design Criterion 12, 1967 Instrumentation and Control Systems Each Class 1E bus is provided with a voltmeter mounted on the switchgear for local indication. Each charger has a locally mounted voltmeter, ammeter, and instrumentation for alarming dc undervoltage, dc overvoltage, ac fuse failure, dc breaker trip, and ac breaker trip (refer to Section 8.3.2.2.2.2), adjustable controls for both normal and equalizing charge settings, and a manually adjustable equalizing timer. Each of the Class 1E battery rooms is provided with an air temperature monitoring system. Refer to Section 9.4 for details. 8.3.2.3.6 General Design Criterion 17, 1971 Electric Power Systems Sufficient physical separation, electrical isolation, system coordination, and redundancy are provided to ensure availability of required dc power and to prevent the occurrence of common mode failure of each unit's Class 1E dc systems. The codes and standards that have been implemented, where applicable, in the design of the dc systems are listed in Section 8.1.4. 8.3.2.3.6.1 Class 1E 125-Vdc Distribution The Class 1E dc power circuits from the separate battery rooms 11(21), 12(22), and 13(23) are run in separate conduits to dc equipment rooms 11, 12, and 13. The battery chargers are in these rooms and are connected to the buses in the dc switchgear. The dc buses are connected to the molded case breaker panel board with load circuits channeled throughout the plant in Class 1E circuit systems with power (600 V and under) and control systems. The non Class 1E dc power feeders are channeled with non-Class 1E (600 V and under) ac power and control systems. DC feeder instrumentation circuits are channeled with low-level instrumentation circuits.
The dc system redundancy follows the redundant lines delineated by the 4.16-kV and 480-V Class 1E Systems:
(1) Battery 11(21), battery charger 11(21), switchgear bus 11(21), and distribution panel 11(21) are associated with 4.16-kV bus 1F(2F) and 480-V bus 1F(2F), and diesel 13(23).
DCPP UNITS 1 & 2 FSAR UPDATE 8.3-81 Revision 21 September 2013 (2) Battery 12(22), battery charger 12(22), switchgear bus 12(22), and distribution panel 12(22) are associated with 4.16-kV bus 1G(2G) and 480-V bus 1G(2G), and diesel 12(21). (3) Battery 13(23), battery charger 132(232), switchgear bus 13(23), distribution panel 13(23), and distribution Panel 14(24) are associated with 4.16-kV bus 1H(2H) and 480-V bus 1H(2H) and diesel 11(22). (4) Instrumentation dc circuits are also separated similarly to Items 1, 2, and 3 above. (5) Breakers on the distribution Panels 11(21), 12(22), and 13(23) can be used to disconnect all non-Class 1E loads from the batteries. 8.3.2.3.6.2 Class 1E 125-Vdc Battery Charger The input to the chargers is 480-V, 3-phase, 60 Hz. The 480-V buses F, G, and H supply chargers 11(21), 12(22), and 132(232), respectively. Backup battery chargers 121(221) and 131(231) receive their inputs from 480-V buses H and F, respectively. The chargers provide rated output voltage and current with an input voltage range from 432-Vac to 528-Vac. Each input is provided with a manual circuit breaker mounted on the front and an undervoltage alarm relay on the ac side of the rectifiers. During normal operation, power is furnished by these 480-V battery chargers at approximately 135 Vdc, with the electric storage batteries floating on the dc buses. Sufficient battery charger capacity, 400 amperes per charger, is provided to carry the normal continuous load and to recharge the batteries in a reasonable time with any one charger out of service. Battery chargers have sufficient capacity to carry the normal continuous load and to recharge the battery within 12 hours. The battery charger sizing is within the guidelines of IEEE-946, IEEE Recommended Practice for the Design of Safety Related DC Auxiliary Power Systems for Nuclear Power Generating Stations and Safety Guide 32, August 1972, B-2 and C-b (Reference 16). Refer also to Section 8.3.2.3.17. 8.3.2.3.6.3 Class 1E 125-Vdc Batteries The batteries are sized to provide sufficient power to operate the dc loads for the time necessary to safely shut down the unit, should a 480-V source to one or more battery chargers be unavailable. Although each battery consists of 60 cells, the battery sizing calculations are in place to support a 59-cell configuration. The 59-cell configuration may be necessary in case a defective cell needs to be bypassed. The battery cells are lead-acid type with lead-calcium grids. Each battery is rated at 2320 ampere-hours (8-hour rate, discharged to 1.75 V per cell) and has current ratings as follows: 1 minute 1 hour 8 hours 2080 amperes 1120 amperes 290 amperes DCPP UNITS 1 & 2 FSAR UPDATE 8.3-82 Revision 21 September 2013 Sufficient capacity is provided for all simultaneous loads to be superimposed for the following durations:
(1) Two hours for continuous loads, such as instrumentation and annunciation (2) One minute for all momentary loads such as dc control power for switchgear devices, inrush to continuous loads, and diesel generator field flashing The method used to determine battery sizing and recommendation for replacement of batteries is based on IEEE 485-1983 (Reference 15).
If a diesel generator associated with a particular bus fails to start and a redundant charger supplied from another Class 1E 480-V bus is not available, the battery has sufficient capacity to continue to carry dc loads for 2 hours on the associated bus. 8.3.2.3.7 General Design Criterion 18, 1971 Inspection and Testing of Electric Power Systems Battery capacity is verified by performing a battery performance test in accordance with IEEE 450-1995 (Reference 18) with the exception that if the battery shows signs of degradation, or if the battery has reached 85 percent of its expected service life and capacity is less than 100 percent of the manufacturer's rated capacity, the performance test is required on a 24-month frequency to coincide with a refueling outage instead of on an annual frequency as required by IEEE 450-1995. Battery monitoring and maintenance is controlled by a battery monitoring and maintenance program based on the recommendations of IEEE 450-1995. 8.3.2.3.8 General Design Criterion 21, 1967 Single Failure Definition DC loads for control of ESFs are divided into three groups, each served from a 125-Vdc battery. The grouping corresponds to the grouping of the ac loads and provides redundant service to ESFs (see Figure 8.3-17).
Should a failure occur on any 125-Vdc distribution circuit on panel 11(21) the associated molded case circuit breaker would trip to isolate this failure while the unaffected circuits in panel 11(21) would remain energized. If the distribution panel molded case circuit breaker failed to trip, the 600 ampere drawout breaker would trip to isolate distribution panel 11(21) from 125-Vdc bus 11(21). This latter event would be a single failure in the ESF panel 11(21). Similar analysis was applied to the 125-Vdc distribution circuits on panel 12(22). This would result in the loss of 125-Vdc power and control to 4.16-kV bus F and other related bus F power and control circuits. The ESFs would then be performed by 4.16-kV and 480-V buses G and H, and 125-Vdc buses 12(22) and 13(23), respectively. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-83 Revision 21 September 2013 8.3.2.3.9 General Design Criterion 24, 1967 Emergency Power for Protection Systems The safety-related loads on individual dc buses are as listed in Table 8.3-11. The dc power and control systems are specified, designed, engineered, and manufactured to perform the required ESF functions. The dc systems for control of ESFs are divided into three groups, each served from a 125-Vdc battery bus. The grouping corresponds to the grouping of the ac loads and provides redundant service to ESFs. Refer to Table 8.3-11. A descriptive analysis of the dc system is provided in Section 8.3.2.2.2. 8.3.2.3.10 General Design Criterion, 40, 1967 - Missile Protection The portions of the Class 1E 125 Vdc system that are located in zones where provision against dynamic effects must be made, are protected from missiles, pipe whip, or jet impingement from the rupture of any nearby high-energy line (refer to Sections 3.5, 3.6, and 8.3.1.4.10.2). 8.3.2.3.11 General Design Criterion 49, 1967 - Containment Design Basis The Class 1E 125-Vdc and non-Class 1E 125-Vdc circuits routed through containment electrical penetrations are each provided with electrical protection devices. This arrangement is such that with the failure of one device, the penetration remains protected from high current temperature by the other in-series device to ensure the containment penetration remains functional. Refer to Section 3.8.1.1.3 and 8.3.1.4.8 for additional details. 8.3.2.3.12 10 CFR 50.49 - Environmental Qualification of Electric Equipment The Class 1E 125-Vdc system SSCs required to function in harsh environments under accident conditions are qualified to the applicable environmental conditions to ensure that they will continue to perform their safety functions. Section 3.11 describes the DCPP EQ program and the requirements for the environmental design of electrical and related mechanical equipment. The affected components are listed on the EQ Master List. 8.3.2.3.13 10 CFR 50.62 - Requirements for Reduction of Risk from Anticipated Transients Without Scram (ATWS) Events for Light-Water-Cooled Nuclear Power Plants The ATWS mitigation system actuation circuitry (AMSAC) is designed to comply with 10 CFR 50.62. The AMSAC is required to be powered from a non-Class 1E 125-Vdc electrical power source that is independent from the protection system power supplies. Refer to Section 7.6.2.3 and 7.6.3.5 for additional details. DCPP UNITS 1 & 2 FSAR UPDATE 8.3-84 Revision 21 September 2013 8.3.2.3.14 10 CFR 50.63 - Loss of All Alternating Current Power With respect to battery adequacy, for an actual SBO response, procedures would provide battery charging and operation for all Class 1E instrument channels and reactor protection system (RPS) output trains. For purposes of the SBO analysis, it is assumed that operator action is taken within 2 hours to provide at least two input channels of instrumentation to monitor system functions and actuate one train of safeguards equipment. Refer to Section 8.3.1.6 for additional details. 8.3.2.3.15 10 CFR 50 Appendix R (Sections III.G, III.J, and III.L) - Fire Protection Program for Nuclear Power Facilities Operating Before January 1, 1979 Section III.G - Fire protection of Safe Shutdown Capability: The Class 1E 125-Vdc system satisfies the applicable fire protection requirements of 10 CFR Part 50 Appendix R, Section III.G, by either meeting the technical requirements or by providing an equivalent level of fire safety. Refer to Appendix 9.5G. Section III.J - Emergency Lighting: The 125-Vdc emergency lighting system is energized instantly upon loss of the emergency ac lighting system and is deenergized, after a 5-second time delay, on return of power supply to the emergency ac lighting system. These lights are powered from the non-Class 1E station batteries and will provide sufficient emergency lighting for at least one hour. Refer to Appendix 9.5D. Section III.L - Alternative and Dedicated Shutdown Capability: Safe shutdown capabilities are provided in the control room and at an alternate location via the hot shutdown panel (refer to Section 7.4) as defined by 10 CFR Part 50, Appendix R, Section III.L. The ability to safely shut down the plant following a fire in any fire area is summarized in Section 4.0 of Appendix 9.5A and Appendix 9.5E. 8.3.2.3.16 Safety Guide 6, March 1971 - Independence Between Redundant Standby (Onsite) Power Sources and Between Their Distribution Systems Each of the three 125-Vdc switchgear buses has a battery charger. Batteries 11(21) and 12(22) have an additional swing backup battery charger that can be connected to either bus by manually closing one of the two interlocked breakers. The fifth battery charger is a backup charger for battery 13(23). Manual operation of a circuit breaker is required to place this battery charger in service on the bus. No interlock is provided between the two battery chargers on this bus. Refer to Section 8.3.2.2.2 for additional detail. 8.3.2.3.17 Safety Guide 32, August 1972 - Use of IEEE Standard 308-1971 Criteria for Class 1E Electric Systems for Nuclear Power Generating Stations The supply to battery chargers is designed using the criteria of Safety Guide 32, August 1972 (Reference 16), paragraphs B-2 and C-b, so that abnormal long-term loads (e.g., DCPP UNITS 1 & 2 FSAR UPDATE 8.3-85 Revision 21 September 2013 hot or cold shutdown and postaccident shutdown) are not greater than the steady state loads during normal operation. The design requirements of the battery charger supply are as covered within GDC 17, 1971. Accordantly the capacity of the battery charger supply is based on the largest combined demands of the various steady-state loads and the charging capacity to restore the battery from the design minimum charge state to the fully charged state, irrespective of the status of the plant during which these demands occur. 8.3.2.3.18 Regulatory Guide 1.63, Revision 1, May 1977 - Electrical Penetration Assemblies in Containment Structures for Light-Water-cooled Nuclear Plants The Class 1E and non-Class 1E 125-Vdc circuits routed through containment electrical penetrations are designed to provide overcurrent protection. Refer to Section 8.3.1.4.8 for additional details. 8.3.2.3.19 Regulatory Guide 1.97, Revision 3, May 1983 - Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident Each 125-Vdc Class 1E bus is provided with a voltmeter and ammeter mounted on the control room main control board for remote indication. Refer to Table 7.5-6 for additional detail. 8.3.2.4 Tests and Inspections Refer to Section 8.3.2.3.7 for test and inspection details. 8.3.2.5 Instrumentation Applications Refer to Sections 8.3.2.3.4 and 8.3.2.3.5 for instrumentation applications 8.
3.3 REFERENCES
- 1. Deleted in Revision 21.
- 2. NUREG 0737, Clarification of TMI Action Plan Requirements, November 1980.
- 3. IEEE 308-1971, Criteria for Class IE Electric Systems for Nuclear Power Generating Stations.
- 4. IEEE 279-1971, Criteria for Protection Systems for Nuclear Power Generating Stations.
- 5. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
DCPP UNITS 1 & 2 FSAR UPDATE 8.3-86 Revision 21 September 2013 6. NFPA 12, Carbon Dioxide Extinguishing Systems, 1973. 7. NFPA 37, Installation and Use of Stationary Combustion Engines and Gas Turbines, 1970.
- 8. Safety Guide 9, Selection of Diesel Generator Set Capacity for Standby Power Supplies, March 1971.
- 9. Safety Guide 6, Independence Between Redundant Standby (Onsite) Power Sources and Between Their Distribution Systems, March 1971.
- 10. National Electric Code (NFPA 70-1968).
- 11. AIEE S-135-1, Power Cable Ampacities, 1962.
- 12. Regulatory Guide 1.63, Electric Penetration Assemblies in Containment Structures for Light-Water- Cooled Nuclear Power Plants, USNRC, Revision 1, May 1977.
- 13. 10 CFR Part 50, Appendix R, Sections III.G, III.J, and III.L, Fire Protection Program for Nuclear Facilities Operating Before January 1, 1979.
- 14. PG&E, Report on 10 CFR 50 Appendix R Review for DCPP Unit 1, submitted to NRC July 15, 1983, and its subsequent revisions.
- 15. IEEE 485-1983, Recommended Practice for Sizing Large Lead Storage Batteries for Generating Stations and Substations.
- 16. Safety Guide 32, Use of IEEE Standard 308-1971 Criteria for Class 1E Electric Systems for Nuclear Power Generating Stations, August 1972.
- 17. Regulatory Guide 1.128, Revision 1, Installation Design and Installation of Large Lead Storage Batteries for Nuclear Power Plants, USNRC, October 1978.
- 18. IEEE 450-1995, Recommended Practice for Maintenance, Testing, and Replacement of Large Lead Storage Batteries for Generating Stations and Substations.
- 19. ICEA P-54-440, Cables in Open-Top Cable Trays, 1975.
- 20. 10 CFR 50.63, Station Blackout (SBO) Rule, Loss of All Alternating Current Power.
- 21. PG&E Letter DCL-92-084 to USNRC, Revised Response to Station Blackout, April 13, 1992.
DCPP UNITS 1 & 2 FSAR UPDATE 8.3-87 Revision 21 September 2013 22. Supplemental Safety Evaluation of PG&E Response to Station Blackout Rule (10 CFR 50.63) for Diablo Canyon, USNRC, (TAC Nos. M68537 and M68538), May 29, 1992.
- 23. NUMARC 87-00, Rev. 0, Guidelines and Technical Bases for NUMARC Initiatives Addressing Station Blackout at Light Water Reactors, November 1987.
- 24. Deleted in Revision 21.
- 25. Regulatory Guide 1.9, Revision 3, Selection, Design, Qualification Testing, and Reliability of Diesel-Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants, July 1993
- 26. NRC (Mr. John Stolz) letter to PG&E (Mr. John Morrissey), dated November 22, 1977, Request for Additional Information - Diablo Canyon Nuclear Power Plant, Units 1 & 2. 27. License Amendments 200/201, Technical Specifications Change to Relocate Surveillance Test Intervals to a Licensee-Controlled Program, issued by the NRC, October 30, 2008. 28. License Amendments 105/104, Revision of Technical Specification for Diesel Generator Surveillance Testing, issued by the NRC, June 26, 1995. 29. License Amendments 135/135, Conversion to Improved Technical Specifications, issued by the NRC, May 28, 1999. 30. License Amendments 211/213, Revision to Technical Specification 3.8.1, "AC Sources - Operating," to Incorporate TSTF-163, Revision 2, issued by the NRC, March 29, 2012. 31. Regulatory Guide 1.155, Station Blackout, August 1988. 8.3.4 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 8.1-1 Sheet 1 of 4 Revision 21 September 2013 APPLICABLE DESIGN BASIS CRITERIA CRITERIA TITLE APPLICABILITY Electrical Power System 230-kV 500-kV 25-kV 12-kV 4.16-kV 480-V 120-Vac EDG SBO 125-Vdc Section 8.2.1 8.2.2 8.3.1.1.1 8.3.1.1.2 8.3.1.1.3 8.3.1.1.4 8.3.1.1.5 8.3.1.1.6 8.3.1.6 8.3.2 1. 10 CFR 50 - Domestic Licensing of Production and Utilization Facilities 50.49 Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants X X X X 50.55a(g) Inservice Inspection Requirements X 50.62 Requirements for Reduction of Risk from Anticipated Transients Without Scram (ATWS) Events for Light-Water-Cooled Nuclear Power Plants X X 50.63 Loss of All Alternating Current Power X X X X X X X X X X Appendix R Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979 X X X X X 2. General Design Criteria Criterion 2, 1967 Performance Standards X X X X X X Criterion 3, 1971 Fire Protection X X X X X Criterion 4, 1967 Sharing of Systems X X X X X X Criterion 11, 1967 Control Room X X X X X X Criterion 12, 1967 Instrumentation and Control Systems X X X X X X DCPP UNITS 1 & 2 FSAR UPDATE TABLE 8.1-1 Sheet 2 of 4 Revision 21 September 2013 CRITERIA TITLE APPLICABILITY Electrical Power System 230-kV 500-kV 25-kV 12-kV 4.16-kV 480-V 120-Vac EDG SBO 125-Vdc Section 8.2.1 8.2.2 8.3.1.1.1 8.3.1.1.2 8.3.1.1.3 8.3.1.1.4 8.3.1.1.5 8.3.1.1.6 8.3.1.6 8.3.2 2. General Design Criteria (continued) Criterion 15, 1967 Engineered Safety Features Protection Systems X Criterion 17, 1971 Electric Power Systems X X X X X X X X X Criterion 18, 1971 Inspection and Testing of Electric Power Systems X X X X X X X X X Criterion 21, 1967 Single Failure Definition X X X X X Criterion 24, 1967 Emergency Power For Protection Systems X X Criterion 40, 1967 Missile Protection X X X X Criterion 49, 1967 Containment Design Basis X X X X 3. Design Basis Functional Criteria Transmission Capacity Requirements X X Single Failure Requirements (Preferred Power Supply) X X X X Protection from High and Moderate Energy Systems and Internal Missiles X 4. Atomic Energy Commission (AEC) Safety Guides Safety Guide 6, March 1971 Independence Between Redundant Standby (Onsite) Power Sources and Between Their Distribution Systems X X X X DCPP UNITS 1 & 2 FSAR UPDATE TABLE 8.1-1 Sheet 3 of 4 Revision 21 September 2013 CRITERIA TITLE APPLICABILITY Electrical Power System 230-kV 500-kV 25-kV 12-kV 4.16-kV 480-V 120-Vac EDG SBO 125-Vdc Section 8.2.1 8.2.2 8.3.1.1.1 8.3.1.1.2 8.3.1.1.3 8.3.1.1.4 8.3.1.1.5 8.3.1.1.6 8.3.1.6 8.3.2 4. Atomic Energy Commission (AEC) Safety Guides (continued) Safety Guide 9, March 1971 Selection of Diesel Generator Set Capacity for Standby Power Supplies X Safety Guide 32, August 1972 Use of IEEE Std 308-1971 "Criteria for Class 1E Electrical Systems for Nuclear Power Generating Stations" X X X X X 5. Regulatory Guides Regulatory Guide 1.63, May 1977 Electric Penetration Assemblies in Containment Structures for Light Water Cooled Nuclear Power Plants X X X X Regulatory Guide 1.97, Revision 3, May 1983 Instrumentation For Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident X X X X Regulatory Guide 1.108, Revision 1, August 1977 Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants X DCPP UNITS 1 & 2 FSAR UPDATE TABLE 8.1-1 Sheet 4 of 4 Revision 21 September 2013 CRITERIA TITLE APPLICABILITY Electrical Power System 230-kV 500-kV 25-kV 12-kV 4.16-kV 480-V 120-Vac EDG SBO 125-Vdc Section 8.2.1 8.2.2 8.3.1.1.1 8.3.1.1.2 8.3.1.1.3 8.3.1.1.4 8.3.1.1.5 8.3.1.1.6 8.3.1.6 8.3.2 6. NRC NUREGs NUREG-0737 Clarification of TMI Action Plan Requirements X X 7. NRC Generic Letters 1984-15 Proposed Staff Actions to Improve and Maintain Diesel Generator Reliability X DCPP UNITS 1 & 2 FSAR UPDATE TABLE 8.3-1 Sheet 1 of 2 Revision 12 September 1998 NOTES FOR TABLES (a) When supplied from the diesel generators, these motors are started automatically in the absence of a safety injection signal. (b) These motors are two-speed, rated 300 and 100 horsepower, and are fed from the vital 480-V load centers. The low speed is used under loss-of-coolant accident (LOCA) and auto-bus transfer conditions. There are five motors: two on bus F, two on bus G, and one on bus H. (c) 1. The net power factor on any bus is expected to be not less than 90 percent; since the generators have a rated power factor of 80 percent, the margin is ample. 2. The power factor of the containment fan cooler units (CFCUs) at slow speed, however, is 49.7 percent. In this case, the total demand kW and kVAR are calculated separately using 49.7 percent power factor of the CFCUs and 90 percent power factor for the rest of the loads. The total demand kW and kVAR are vectorially added to calculate the kVA. (d) Deleted (e) Demand in kW for motors is equal to the maximum expected horsepower input to the driven device x 0746.MotorEfficiency (f) For total time, add approximately 1 second for offsite power, and 10 seconds for the diesel generators. (g) These loads are not required for nuclear safety but will probably operate at the same time to perform other important plant functions. (h) These items are shared between Units 1 and 2. (i) Two of the battery chargers are spares. Only one battery charger can be connected to a bus except during an abnormal operating condition which is time limited. (j) The Technical Support Center, pressurizer heaters, containment hydrogen purge system fans, spent fuel pit pump, internal hydrogen recombiners, and charcoal filter preheater are manually controlled loads that can be added to the vital buses, providing the load demand has diminished and the diesel generators will not be overloaded. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 8.3-1 Sheet 2 of 2 Revision 12 September 1998 (k) Containment spray is initiated after the time shown, provided "S" and "P" signals are present. All other components are started on the occurrence of an "S" signal. (l) Deleted in Revision 7.
(m) Does not include loads that are cut off prior to diesel generator connection to bus.
(n) Only one group of control room air conditioning and vent equipment can be connected to a bus at one time. (o) All tests conducted on all six diesel engine generator units, except as noted.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 8.3-2 TIMING SEQUENCE AND INTERVALS - NO SAFETY INJECTION SIGNAL Loads Starting Delay in Seconds After Power is Restored to the Vital Buses(f) Minimum Number Required Bus F Bus G Bus H Small loads (480 and 120 V) on vital 480-V load centers 0 0 0 2 Component cooling water pumps 5 5 5 2
Auxiliary saltwater pumps 10 10 - 1
Auxiliary feedwater pumps(a) 14 - 14 1 Centrifugal charging pumps (CCP1 and CCP2) 20 20 - 1 Containment fan coolers(b) 25 25 25 3 DCPP UNITS 1 & 2 FSAR UPDATE Revision 21 September 2013 TABLE 8.3-3 MAXIMUM STEADY STATE LOAD DEMAND - NO SAFETY INJECTION SIGNAL Quantity Rating Maximum Maximum Demand, kW(e) Load Per Unit (each) BHP Bus 1F Bus 2F Bus 1G Bus 2G Bus 1H Bus 2H 480-V load exclusive of containment fan coolers, fire pumps, momentary loads, and manually controlled loads(j) 3 1000 kVA 503 503 440 421 694 664 Load Center Transformer and Cable Losses 28 35 27 35 24 32 Component cooling water pumps 3 400 hp 435 hp 342 342 342 342 342 342 Auxiliary saltwater pumps 2 400 hp 465 hp 373 373 373 373 - - Auxiliary feedwater pumps(a) 2 600 hp 505 hp 394 394 - - 394 394 Centrifugal charging pumps (CCP1 and CCP2) 2 600 hp 650 hp 525 525 525 525 - - Containment fan coolers(b) 5 100 hp 103 hp 170 170 170 170 85 85 Maximum demand on vital 4160-V kW = 2335 2342 1877 1866 1539 1517 buses (c.1) kVAR = 1345 1348 1123 1117 852 842 kVA = 2695 2702 2187 2175 1759 1735 Diesel Generator Rating: Continuous = 2600 kW 2000 Hour = 2750 kW 2 Hour = 3000 kW
DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 8.3-4 DIESEL GENERATOR LOADING TIMING SEQUENCE AND INTERVALS - WITH SAFETY INJECTION SIGNAL Loads Starting Delay in Seconds After Power is Restored to the Vital Buses(f) Minimum Number Bus F Bus G Bus H Required Small loads (480 and 120 V) on vital 480-V load centers 0 0 0 2 Centrifugal charging pumps (CCP1 and CCP2) 2 2 - 1 Safety injection pumps 6 - 2 1
Residual heat removal pumps - 6 6 1
Containment fan coolers(b) 10,14 10,14 10 2 Component cooling water pumps 18 18 14 2
Auxiliary saltwater pumps 22 22 - 1
Auxiliary feedwater pumps 26 - 18 1
Containment spray pumps(k) - 26 22 1
DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 8.3-5 DIESEL GENERATOR LOADING MAXIMUM STEADY STATE LOAD DEMAND FOLLOWING A LOSS-OF-COOLANT ACCIDENT Quantity Rating Maximum Maximum Demand, kW(e) Load Per Unit (each) BHP Bus 1F Bus 2F Bus 1G Bus 2G Bus 1H Bus 2H 480-V load exclusive of containment fan coolers, fire pumps, momentary loads, and manually controlled loads(j) 3 1000 kVA 503 503 440 421 694 664 Load Center Transformer and Cable Losses 29 36 27 35 25 34 Centrifugal charging pumps (CCP1 and CCP2) 2 600 hp 650 hp 525 525 525 525 - - Safety injection pumps 2 400 hp 434 hp 344 344 - - 344 344 Containment spray pumps 2 400 hp 440 hp - - 350 350 350 350 Residual heat removal pumps 2 400 hp 424 hp - - 336 336 336 336 Containment fan coolers(b) 5 100 hp 103 hp 170 170 170 170 85 85 Component cooling water pumps 3 400 hp 435 hp 342 342 342 342 342 342 Auxiliary saltwater pumps 2 400 hp 465 hp 373 373 373 373 - - Auxiliary feedwater pumps 2 600 hp 505 hp 394 394 - - 394 394 Maximum demand on vital 4160-V buses kW = 2680 2687 2563 2552 2570 2549 upon a loss-of-coolant accident (c.2) kVAR = 1512 1515 1455 1450 1352 1341 kVA = 3077 3085 2947 2935 2904 2880 Diesel Generator Rating: Continuous = 2600 kW 2000 Hour = 2750 kW 2 Hour = 3000 kW DCPP UNITS 1 & 2 FSAR UPDATE TABLE 8.3-6 Sheet 1 of 3 Revision 18 October 2008 VITAL 4160/480-VOLT LOAD CENTERS LOADING List of Loads (Excluding Manually Operated Loads(j), Momentary Loads, Containment Quantity Rating Maximum Demand, kW(e) Fan Coolers, and Fire Pumps) Per Unit (each) Bus 1F Bus 2F Bus 1G Bus 2G Bus 1H Bus 2H Exhaust fans (auxiliary building including fuel handling area) 2 150 hp 130 130 - - 130 130 Supply fans (vital dc and low-voltage ac equipment) 2 50 hp 40 40 - - 40 40 Exhaust fans (vital dc and low-voltage ac equipment) 2 50 hp 40 40 - - 40 40 Exhaust fans (auxiliary saltwater pump rooms) 2 1 hp 1 1 1 1 - - Fuel handling area exhausts (iodine removal) 2 75 hp 61 61 - - 61 61 Supply fans (fuel handling area) - Fans S1 and S2 2 25 hp - - 21 21 21 21 Supply fans (auxiliary building) - Fans S31/33 and S32/34 2 60 hp - - 49 49 49 49 Supply fans (4-kV switchgear rooms) 3 1.5 hp 1.5 1.5 1.5 1.5 1.5 1.5 Main turbine-generator lube oil pump 1 60 hp - - 47 47 - - DCPP UNITS 1 & 2 FSAR UPDATE TABLE 8.3-6 Sheet 2 of 3 Revision 18 October 2008 List of Loads (Excluding Manually Operated Loads(j), Momentary Loads, Containment Quantity Rating Maximum Demand, kW(e) Fan Coolers, and Fire Pumps) Per Unit (each) Bus 1F Bus 2F Bus 1G Bus 2G Bus 1H Bus 2H Auxiliary lube oil pumps for component cooling water pumps 3 0.5 hp 0.5 0.5 0.5 0.5 0.5 0.5 Feedwater pumps turning gears 2 1 hp 1 1 - - 1 1
Makeup water transfer pumps 2(h) 30 hp - 27 - Primary water makeup pumps 2 15 hp 13 13 13 13 - -
Boric acid transfer pumps 2 15 hp 12 12 12 12 - -
Diesel fuel transfer pumps 2 5 hp - - 5 5 5 5
Charging pump (CCP1 and CCP2) auxiliary lube oil pumps 2 2 hp 2 2 2 2 - - Control room pressurization and ventilation(n) 2 72 kW - - 72 72 72 72 Unit 2 control room pressurization and ventilation(alternate source)(n) 2 72 kW 72 72 - - - - Containment hydrogen monitor 2 1.5 hp - - 2.5 3 2.5 3
Plant ventilation high radiation monitor 1 5 kVA - - - - 4 4 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 8.3-6 Sheet 3 of 3 Revision 18 October 2008 List of Loads (Excluding Manually Operated Loads(j), Momentary Loads, Containment Quantity Rating Maximum Demand, kW(e) Fan Coolers, and Fire Pumps) Per Unit (each) Bus 1F Bus 2F Bus 1G Bus 2G Bus 1H Bus 2H Containment air and gas radiation monitor pump 1 1.5 hp - - 1.5 1.5 - - Electric heat tracing boric acid system - - 10.2 10.1 3.4 9.4 13 18.9 RMS - 120 Vac distribution transformer 2 15 kVA - - 12 12 12 12 Electric heaters, boric acid tank 4 7.5 kW - - 7.5 8 7.5 8 Diesel generator auxiliary loads - - 42 42 42 42 42 42 Control rod position indication 1 - 8 8 - - - - Instrument ac system(a) - - - - 12 12 12 12 Battery chargers 5 82.5 kVA 46 46 46 46 46 46 Emergency ac lighting(g) - - - - 40 40 50 40 Communications 1 15 kVA - - - - 12 12 Inverter Rectifier 4 22.4 22 22.4 22 44.8 44 480-V load demand in kW, exclusive of the containment fan coolers and momentary loads kW = 502.6 502.1 440.3 419.9 693.8 662.9 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 8.3-7 Revision 18 October 2008 VITAL 480-V LOAD CENTERS MAXIMUM DEMAND
Quantity Rating Maximum Maximum Demand, kW(e) Load Per Unit (Each) BHP Bus 1F Bus 2F Bus 1G Bus 2GBus 1H Bus 2H 480-V load, exclusive of containment fan coolers, momentary loads, manually operated loads(j), and fire pumps 3 1000 kVA 503 503 440 421 694 664 Containment fan coolers(b) 5 100 hp 103 hp 170 170 170 170 85 85 Maximum demand on the vital 480-V load kW = 673 673 610 591 779 749 centers kVAR = 540 540 509 500 484 470 kVA = 863 863 794 774 917 884 Fire pumps (electric drive) None in Unit 2 2 200 hp 186 hp 147 --- --- --- 147 --- Maximum load demand on the vital 480-V load centers concurrent with a fire kW = 820 673 610 591 926 749 kVAR = 612 540 509 500 556 470 kVA = 1023 863 794 774 1080 884
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 8.3-8 Sheet 1 of 5 Revision 12 September 1998 SUMMARY OF SHOP TESTING OF DIABLO CANYON DIESEL ENGINE GENERATOR UNITS BY ALCO ENGINE DIVISION (Note 1) Test and Purpose(o) Conduct of Tests Results of Test
- 1. Standard Shop Tests To check out manufacturing and assembly A. Calibration testing of all meters, switches, and gauges.
B. Engine "break in" running and check out pressures. Engine generator units satisfactorily met all test requirements. C. Electrical wire-by-wire functional testing. D. Matching tests for engine with governor and generator with regulator. 2. Performance Run To prove performance and rating Unit performance run at 50, 75, 100, and 115% of full load, while recording pressures, temperatures, fuel consumption, etc. Engine generator units satisfactorily met all test requirements. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 8.3-8 Sheet 2 of 5 Revision 12 September 1998 Test and Purpose(o) Conduct of Tests Results of Test
- 3. Starting Capability To show capacity of starting air systems (conducted on one engine generator unit). A. Demonstrate 45 seconds of engine cranking for starting, with each of two redundant starting air systems, and without recharging air receivers. B. Demonstrate the number of successful engine starts, with each of two redundant starting air systems, and without recharging air receivers. A. Forty-five seconds of continuous cranking with each starting air system. 4. Starting Reliability To show reliability of starting (conducted on one engine generator unit). Demonstrate 100 consecutive engine generator unit starts, 50 with each redundant starting air system. Fifty consecutive successful unit starts with each start ing air system. 5. Acceleration To show capability of fast starting. Recorded time to accelerate units from standby condition (zero rpm) to rated speed (frequency) and voltage, with both redundant starting systems and with single failures in redundant start ing systems. All engine generator units accelerated to rated speed (frequency) and voltage in less than 8.5 seconds with both starting systems, and in less than 12.3 seconds with simulated failure in a redundant starting system.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 8.3-8 Sheet 3 of 5 Revision 12 September 1998 Test and Purpose(o) Conduct of Tests Results of Test
- 6. Motor Start To show capability of starting and accelerating a large induction motor (conducted on one engine generator unit). Recorded speed (frequency) and voltage decrease and time to recover to nominal when starting and accelerating an 800 hp induction motor, which is larger than any Diablo Canyon LOCA loads. Maximum voltage decrease did not exceed 75% of nominal, and maximum speed decrease (frequency) did not exceed 95% of nominal. Voltage was restored to within 10% of nominal, speed (frequency) was restored to within 2% of nominal, in less than 2 seconds. Engine generator unit is capable of starting and accelerating an induction motor larger than any for Diablo Canyon.
- 7. Dead Load Pick Up To show capability of picking up large resistive loads and, by evaluation, to show capability of starting and accelerating large induction motors. Recorded speed (frequency)and volt age decrease and the time to recover to nominal when picking up large resistive loads, starting with 500 kW and picking up successive loads in 100 kW increments up to at least 1300 kW. Performance of all units evaluated against the performance of the unit tested for motor start capability. (Test No. 6.) All engine generator units picked up resistive loads with speed (frequency) and voltage decrease and time to recover evaluated to satisfactorily show capability for starting and accelerating the large induction motors of the Diablo Canyon LOCA loads.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 8.3-8 Sheet 4 of 5 Revision 12 September 1998 Test and Purpose(o) Conduct of Tests Results of Test
- 8. Motor Starting - LOCA Sequence To show capability of starting and accelerating large induction motors in rapid succession. (Conducted on one engine generator unit.) Recorded speed (frequency) and voltage decrease and time to recover to nominal when starting and accelerating large induction motors, 400, 600, and 800 hp, in rapid succession and in the Diablo Canyon LOCA sequence. Load sequence time interval was 5 seconds. Maximum voltage decrease did not exceed 75% of nominal, and maximum speed decrease (frequency) did not exceed 95% of nominal. Voltage was restored to within 10% of of nominal, and speed (frequency) was restored to within 2% of nominal, in less than 2 seconds (40% of load sequence time interval). Engine generator units are capable of starting and accelerating large induction motors in rapid succession.
- 9. Simulated Motor Starting - LOCA Sequence To show capability of picking up resistive loads (simulating induction motors) in rapid succession and, by evaluation, to show capability of starting and accelerating large induction motors in rapid succession. Recorded speed (frequency) and voltage decrease and time to recover to nominal when picking up resistive loads in rapid succession and in Diablo Canyon LOCA sequence. Load sequence time interval was 5 seconds.
Resistive loading schedule simulated the LOCA load demand by the large induction motors. Performance of all units evaluated against the performance of the unit tested for Motor Starting LOCA sequence capability (Test No. 8.) All engine generator units picked up resistive loads with speed (frequency) and voltage decrease and time to recover evaluated to satisfactorily show capability for starting and accelerating in rapid succession the large induction motors of the Diablo Canyon LOCA sequence. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 8.3-8 Sheet 5 of 5 Revision 12 September 1998 Test and Purpose(o) Conduct of Tests Results of Test
- 10. Full Load Drop To show capability of large load step decrease (2,600 kW). Recorded speed (frequency) and voltage increase and time to recover to nominal following a full load drop (2,600 kW). Speed of the diesel generator units did not exceed 75% of the difference between the nominal speed, and either the overspeed trip setpoint or 115% of nominal.
Engine generator units are capable of recovery from the largest load reduction, a full load drop. ________________ Note 1: Original testing was done using a nominal 5-second load sequence time interval with the KWS relay installed. Since a nominal 4-second load sequence time interval is used in the design basis loading scenario and the EDG loading capability is demonstrated through computer simulation without KWS relays, the test results of Table 8.3-8 are of historical value.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 8.3-9 Revision 11 November 1996 SUMMARY OF PREOPERATIONAL TESTING OF DIABLO CANYON DIESEL ENGINE GENERATOR UNITS BY PG&E DURING STARTUP Test and Purpose Conduct of Tests
- 1. Standard Startup Tests To check out installation and onsite Startup, cleaning, flushing, performance performance. checks, load capability, acceleration tests, etc., were performed on all engine generator units.
- 2. Integrated Safety Injection To verify capability to accept loads Safety injection was initiated in rapid succession following the manually with offsite power not available.
LOCA. The sequential loading of all engine generator units was monitored by recording voltage and current decrease.
- 3. Onsite Power Redundancy To prove auxiliary devices of one Test procedures used AEC Regulatory Guide unit are not affected by failures in 1.41 as an outline. Test was conducted in other units. the same time period and in sequence with the Integrated Safety Injection tests described above.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 8.3-10 Revision 11 November 1996 IDENTIFICATION OF ELECTRICAL SYSTEMS Class 1E Equipment and Associated Buses(a) AC Systems DC Systems Unit 1 Unit 2 Unit 1 Unit 2 Orange Bus 1F Bus 2F Bus 11 Bus 21 Gray Bus 1G Bus 2G Bus 12 Bus 22 Purple Bus 1H Bus 2H Bus 13 Bus 23
Reactor Protection Systems Red Channel 1 Reactor protection system instrumentation White Channel 2 Reactor protection system instrumentation Blue Channel 3 Reactor protection system instrumentation Yellow Channel 4 Reactor protection system instrumentation Brown Train A Direct logic inputs Green Train B Direct logic inputs Power Circuits from Instrument Inverters Orange Reactor Protection Channel I Gray Reactor Protection Channel II Purple Reactor Protection Channel III Black/Yellow Reactor Protection Channel IV
(a) Circuits that do not serve a required Class 1E function may also be color-coded. (For instance, the main annunciator circuits are color-coded although the main annunciator system is not mutually redundant or required for safe shutdown.) In such cases, the color coding will normally follow the above conventions. There may, however, be infrequent instances where this is not practical; color coding in these instances will primarily indicate that these circuits were purchased and installed as Class 1E conductors. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 8.3-11 Revision 12 September 1998 UNIT 1 - 125-VDC DISTRIBUTION PANEL SAFETY-RELATED LOADS(a) DESCRIPTION Battery 11 Battery 12 Battery 13 Nuclear instrumentation UPS(b) 11 12 & 14 13 4-kV switchgear Bus F Bus G Bus H
DG Gauge Panel Normal Source DG 13 DG 12 DG 11
DG Gauge Panel Emergency Source DG 12 DG 11 DG 13
NU safeguards control board solenoid valves F G H
Safeguards relay board F G H
Reactor control board solenoid valves X X X
480-V MCC relay board F G H
Auxiliary safeguards cabinet Train A Train B -
Reactor trip breakers X X -
FWP turbine local control board 12 11 -
Auxiliary relay rack - X -
Dedicated shutdown panel - - X
(a) Unit 2 loads are similar.
(b) UPS fed via 480 V when bus is transferred to the diesel generator.
FIGURE 8.3-21 TYPICAL ARRANGEMENT OF JUMBODUCT SLEEVE THROUGH CONCRETE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 8.3-22 TYPICAL DETAIL OF FOUR OR MORE JUMBODUCTS IN CONCRETE SLAB UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 8.3-23 TYPICAL ARRANGEMENT OF TRANSITE CONDUIT SLEEVE FOR ELECTRICAL CABLES THROUGH CONCRETE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 8.3-24 TYPICAL FIRE STOP FOR HORIZONTAL CABLE TRAYS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 8.3-25 TYPICAL FIRE STOP FOR VERTICAL TRAYS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 8.3-26 TYPICAL FIRE STOP FOR PARALLEL TRAYS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 8.3-27 TYPICAL VERTICAL TRAY FIRE STOP UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 8.3-28 TYPICAL FIRE BARRIER FOR HORIZONTAL TRAYS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 DCPP UNITS 1 & 2 FSAR UPDATE
APPENDIX 8.3B INSULATED CABLE CONSTRUCTION AND VOLTAGE RATINGS DCPP UNITS 1 & 2 FSAR UPDATE 8.3B-1 Revision 21 September 2013 Appendix 8.3B INSULATED CABLE CONSTRUCTION AND VOLTAGE RATINGS The insulated cables that externally interconnect separate units of equipment throughout the plant are described below:
(1) High-voltage power cables for 4160- and 12,000-V service are rated 5000 and 15,000 V, respectively, for ungrounded or high-resistance grounded operation. All of these cables are rated 90°C because they are expected to operate only in an environment having a normal maximum temperature of 40 to 50°C. These cables are all single conductor, with ethylene-propylene insulation and a neoprene, hypalon (chlorosulfonated polyethylene (CSPE)), or linear low density polyethylene (LLDPE) jacket. These cables are provided with an extruded semiconducting shield surrounding the conductor and another over the insulation, all covered by a tinned or bare copper tape. A polyester-polypropylene tape and a nylon-neoprene tape are used as a heat shield between the copper tape and the jacket. A stress cone is provided at each terminal, with one of them grounded. (2) Low-voltage power cables are all of the single conductor type, rated 600 V. Generally, those expected to operate in a maximum ambient temperature of 40 to 50°C are rated 90°C and have ethylene-propylene insulation and a hypalon (CSPE) jacket for sizes 8 AWG and larger. Smaller cables are insulated with flame-retardant cross-linked polyethyelene (XLPE). Those cables located very near or connected to hot equipment and devices, or those required to operate in the atmosphere of the containment during a loss-of-coolant-accident (LOCA), are insulated with silicon rubber, XLPE, Tefzel, or equivalent insulation material and covered by a hypalon (CSPE), XLPE, Tefzel, or equivalent jacket material (except for power cables to the containment fan cooler motors and pressurizer heaters). Cables for the containment fan cooler motors are insulated with a combination of silicone resin-impregnated glass braid, polyimide (Kapton) tapes, an asbestos mat, and a jacket of hypalon. Heat-shrinkable tubing is provided at terminations and splices to seal the cable. Cables for the pressurizer heaters are rated 600 V, 1000°F, and are insulated with a combination of mica and glass tapes with a glass braid jacket. (3) Cables for control circuits are single and multiple conductor, rated 600 V. Generally, single conductor cables are not less than 12 AWG, and multiple conductor cables are not less than 14 AWG. Cables operating in normal maximum ambient temperature are rated 90°C and are insulated with cross-linked polyethylene with multiple conductor cables having an overall jacket of the same material. Cables that are located very near or connected to hot DCPP UNITS 1 & 2 FSAR UPDATE 8.3B-2 Revision 21 September 2013 equipment and devices, or required to operate in the atmosphere of the containment during a LOCA, are insulated with silicone rubber, XLPE, Tefzel, or equivalent insulation material and covered by a hypalon (CSPE), XLPE, Tefzel, Stilan, or equivalent jacket material. (4) Instrument cables composed of adjacent conductors have the conductors twisted and shielded with an aluminized mylar tape in continuous contact with a copper drain wire, grounded only at one point. Signal circuits are generally 16 AWG copper, and thermocouple circuits are also 16 AWG. Those cables operating in a normal environment are insulated with cross-linked polyethylene (XLPE) and covered by a jacket of the same material. Cables that are located very near or connected to hot equipment and devices, or required to operate in the atmosphere of the containment during a LOCA, are insulated with silicone rubber and covered by a silicone rubber, Tefzel, Stilan, XLPE, or equivalent jacket material. (5) Instrument cables of the coaxial and triaxial types have insulations of alkane-imide polymer and cross-linked polyolefin, and jackets of cross-linked polyethylene. Incore thermocouple extension wire is 20 AWG Chromel-Alumel for use in ambient up to 400°F. Primary insulation is a heavy polyimide enamel, and silicone-impregnated fiberglass braid covers the insulation.
DCPP UNITS 1 & 2 FSAR UPDATE
APPENDIX 8.3C MATERIALS FOR FIRE STOPS AND SEALS DCPP UNITS 1 & 2 FSAR UPDATE 8.3C-1 Revision 15 September 2003 Appendix 8.3C MATERIALS FOR FIRE STOPS AND SEALS
Materials used for fire stops and penetration seals are as follows:
(1) Refractory Ceramic Damming Materials - Approved damming material, when required as part of a PG&E Approved penetration seal design, is installed on the bottom of the penetration seal in floors/ceilings and on both sides of the penetration seal in walls. Variations are not allowed without Fire Protection Engineering Approval. Kaowool M board, or engineering approved equivalent, is also used as cable tray fire stop damming. Damming materials consist of the following: Board: - Thermal Ceramics Kaowool M Board - Johns-Manville (JM) Ceraform Board Type 103 - Johns-Manville (JM) Ceraboard Type 126/103 - Fire Protection Design Engineer, or designee, approved equivalent Blanket: - Thermal Ceramics Kaowool blanket - Chemtrol CT-23B alumina silica blanket - Johns-Manville (JM) Cerablanket - Fire Protection Design Engineer, or designee, approved equivalent Bulk Fiber: - Thermal Ceramics Kaowool bulk fiber - Chemtrol CT-23F alumina silica bulk fiber - Johns-Manville (JM) Cerafiber Bulk - Fire Protection Design Engineer, or designee, approved equivalent (2) Marinite Panels - These panels are composed of calcium silicate and inorganic binders. Can be used as tray fire stop damming or shielding. Can only be used as part of a penetration seal with engineering evaluation. ASTM Specification C5676. (3) Flamemastic 77 - This material, as manufactured by Flamemaster Corporation, is used in conjunction with Kaowool M board or Marinite Panels for tray fire stop construction. This material can only be used as part of a penetration seal design with engineering evaluation. DCPP UNITS 1 & 2 FSAR UPDATE 8.3C-2 Revision 15 September 2003 (4) Dow Corning 3-6548 Silicone RTV Foam - This material, as manufactured by Down Corning Corporation, is used in PG&E Engineering approved penetration seal and cable tray fire stop designs. (5) Dow Corning Sylgard 170 Silicone Elastomer - This material, as manufactured by Dow Corning Corporation, is used in PG&E Engineering approved penetration seal designs. (6) LDSE (Light Density Silicone Elastomer) - This material, as manufactured by PROMATEC, Inc., is used in PG&E Engineering approved penetration seal designs. (7) TS-MS-45B (Medium Density Silicone Elastomer) - This material, as manufactured by PROMATEC, Inc., is used in PG&E Engineering approved penetration seal designs and for internal bus duct sealing. (8) HDSE (High Density Silicone Elastomer) - This material, as manufactured by PROMATEC, Inc., is used in PG&E Engineering approved penetration seal designs, typically where gamma radiation shielding is a concern. (9) RADFLEX - This material, as manufactured by PROMATEC, Inc., is used in PG&E Engineering approved penetration seal designs, typically where gamma radiation shielding and mechanical pipe movement is a concern. (10) PROMAFLEX - This material, as manufactured by PROMATEC, Inc., is used in PG&E Engineering approved penetration seal designs, typically where mechanical pipe movement is a concern. (11) Approved Boot Fabric Material - This material is used in conjunction with PG&E Engineering approved penetration seal designs, typically where mechanical pipe movement is a concern. - Connecticut Hard Rubber (CHR) 1032 - Keene Grade 56493F031 - Fire Protection Design engineer, or designee, approved equivalent (12) Silicone Adhesive Sealant - Approved material is used in conjunction with PG&E Engineering approved penetration seal designs, or as an engineering approved sealant in other specific design applications. - Dow Corning 732 silicone adhesive sealant - Dow Corning 96-081 silicone adhesive sealant - Fire Protection design Engineer, or designee, approved equivalent DCPP UNITS 1 & 2 FSAR UPDATE 8.3C-3 Revision 15 September 2003 (13) Grout - This material is used in PG&E Engineering approved penetration seal designs, and as a barrier restoration material for poured n place concrete and concrete block barriers. Typically, the only approved grout material is a cement based grout. With limitation in certain design applications, Ceilcote 658N Epoxy resin grout is approved. (14) Pyrocrete - This material, as manufactured by Carboline, Inc., is used as a PG&E Engineering approved penetration seal design as a barrier restoration material around penetrants through Pyrocrete construction barriers. The specific type, grade, and thickness of Pyrocrete is dependent on the barrier contraction, or engineering evaluated equivalent. (15) Plaster - This material is used as a PG&E Engineering approved penetration seal design as a barrier restoration material around penetrants through Plaster construction barriers. The specific type, grade, and thickness of Plaster is dependent of the barrier construction or engineering evaluated equivalent. (16) Epoxy XR5126 - This material is used where electrical and pressure isolation is required. Fire barrier penetration seals and credited cable tray fire stops are visually inspected periodically.
DCPP UNITS 1 & 2 FSAR UPDATE i Revision 21 September 2013 Chapter 9 AUXILIARY SYSTEMS CONTENTS Section Title Page 9.1 FUEL STORAGE AND HANDLING 9.1-1 9.1.1 New Fuel Storage 9.1-1 9.1.1.1 Design Bases 9.1-2 9.1.1.2 Facilities Description 9.1-2 9.1.1.3 Safety Evaluation 9.1-3 9.1.2 Spent Fuel Storage 9.1-3 9.1.2.1 Design Bases 9.1-4 9.1.2.2 Facilities Description 9.1-4 9.1.2.3 Safety Evaluation 9.1-6 9.1.2.4 Tests and Inspections 9.1-10 9.1.3 Spent Fuel Pool Cooling and Cleanup System 9.1-10 9.1.3.1 Design Bases 9.1-11 9.1.3.2 System Description 9.1-14 9.1.3.3 Safety Evaluation 9.1-18 9.1.3.4 Inspection and Testing Requirements 9.1-19 9.1.3.5 Instrumentation Applications 9.1-19 9.1.3.6 Temporary Backup SFP Cooling System 9.1-20 9.1.4 Fuel Handling System 9.1-22 9.1.4.1 Design Bases - Refueling and Fuel Transfer Operations 9.1-22 9.1.4.2 System Description - Refueling and Fuel Transfer Operations 9.1-23 9.1.4.3 Safety Evaluation - Refueling and Fuel Transfer Operations 9.1-39 9.1.4.4 Inspection and Testing Requirements - Refueling and Fuel 9.1-45 Transfer Operations 9.1.4.5 Design Bases - Cask Loading Operations 9.1-45 9.1.4.6 System Description - Cask Loading Operations 9.1-45 9.1.4.7 Safety Evaluation - Cask Loading Operations 9.1-47 9.1.4.8 Inspection and Testing Requirements - Cask Loading 9.1-52 Operations 9.1.5 References 9.1-52
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 9 CONTENTS (Continued) Section Title Page ii Revision 21 September 2013 9.2 WATER SYSTEMS 9.2-1 9.2.1 Service Cooling Water System 9.2-1 9.2.1.1 Design Bases 9.2-1 9.2.1.2 System Description 9.2-1 9.2.1.3 Safety Evaluation 9.2-2 9.2.1.4 Tests and Inspections 9.2-2 9.2.1.5 Instrumentation Applications 9.2-3
9.2.2 Component Cooling Water System 9.2-3 9.2.2.1 Design Bases 9.2-4 9.2.2.2 System Description 9.2-7 9.2.2.3 Safety Evaluation 9.2-13 9.2.2.4 Tests and Inspections 9.2-23 9.2.2.5 Instrumentation Applications 9.2-23
9.2.3 Makeup Water System 9.2-23 9.2.3.1 Design Bases 9.2-24 9.2.3.2 System Description 9.2-25 9.2.3.3 Safety Evaluation 9.2-26 9.2.3.4 Tests and Inspections 9.2-29 9.2.3.5 Instrumentation Applications 9.2-29
9.2.4 Potable Water System 9.2-29
9.2.5 Ultimate Heat Sink 9.2-29 9.2.5.1 Design Bases 9.2-30 9.2.5.2 System Description 9.2-30 9.2.5.3 Safety Evaluation 9.2-31 9.2.5.4 Tests and Inspections 9.2-32 9.2.5.5 Instrumentation Applications 9.2-32 9.2.6 Condensate Storage Facilities 9.2-32 9.2.6.1 Design Bases 9.2-32 9.2.6.2 System Description 9.2-32 9.2.6.3 Safety Evaluation 9.2-33 9.2.6.4 Tests and Inspections 9.2-34 9.2.6.5 Instrumentation Applications 9.2-34
9.2.7 Auxiliary Saltwater System 9.2-34 9.2.7.1 Design Bases 9.2-34 9.2.7.2 System Description 9.2-37 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 9 CONTENTS (Continued) Section Title Page iii Revision 21 September 2013 9.2.7.3 Safety Evaluation 9.2-40 9.2.7.4 Tests and Inspections 9.2-49 9.2.7.5 Instrumentation Applications 9.2-49
9.2.8 Domestic Water System 9.2-50 9.2.8.1 Design Bases 9.2-50 9.2.8.2 System Description 9.2-50 9.2.8.3 Safety Evaluation 9.2-51 9.2.8.4 Tests and Inspections 9.2-51 9.2.8.5 Instrumentation Applications 9.2-51
9.2.9 References 9.2-51
9.3 PROCESS AUXILIARIES 9.3-1
9.3.1 Compressed Air System 9.3-1 9.3.1.1 Design Bases 9.3-1 9.3.1.2 System Description 9.3-1 9.3.1.3 Safety Evaluation 9.3-3 9.3.1.4 Tests and Inspections 9.3-5 9.3.1.5 Instrumentation Applications 9.3-5 9.3.1.6 Backup Air/Nitrogen Supply System 9.3-5
9.3.2 Sampling Systems 9.3-8 9.3.2.1 Nuclear Steam Supply System Sampling System 9.3-8 9.3.2.2 Post Accident Sampling System 9.3-15 9.3.2.3 Secondary Sampling System 9.3-17 9.3.2.4 Turbine Steam Analyzer System 9.3-17
9.3.3 Equipment and Floor Drainage Systems 9.3-18 9.3.3.1 Design Bases 9.3-18 9.3.3.2 System Description 9.3-18 9.3.3.3 Safety Evaluation 9.3-19 9.3.3.4 Tests and Inspections 9.3-20 9.3.3.5 Instrumentation Applications 9.3-20
9.3.4 Chemical and Volume Control System 9.3-20 9.3.4.1 Design Bases 9.3-20 9.3.4.2 System Description 9.3-22 9.3.4.3 Safety Evaluation 9.3-46 9.3.4.4 Tests and Inspections 9.3-49 9.3.4.5 Instrumentation Applications 9.3-49 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 9 CONTENTS (Continued) Section Title Page iv Revision 21 September 2013 9.3.5 Failed Fuel Detection 9.3-50 9.3.6 Nitrogen and Hydrogen Systems 9.3-50 9.3.6.1 Design Bases 9.3-50 9.3.6.2 System Description 9.3-51 9.3.6.3 Safety Evaluation 9.3-51 9.3.6.4 Tests and Inspections 9.3-52 9.3.6.5 Instrumentation Applications 9.3-52
9.3.7 Miscellaneous Process Auxiliaries 9.3-52 9.3.7.1 Auxiliary Steam System 9.3-53 9.3.7.2 Oily Water Separator and Turbine Building Sump System 9.3-54
9.3.8 References 9.3-54
9.4 HEATING, VENTILATION, AND AIR-CONDITIONING (HVAC) SYSTEMS 9.4-1
9.4.1 Control Room 9.4-2 9.4.1.1 Design Bases 9.4-2 9.4.1.2 System Description 9.4-3 9.4.1.3 Safety Evaluation 9.4-6 9.4.1.4 Inspection and Testing Requirements 9.4-9
9.4.2 Auxiliary Building 9.4-10 9.4.2.1 Design Bases 9.4-10 9.4.2.2 System Description 9.4-11 9.4.2.3 Safety Evaluation 9.4-13 9.4.2.4 Inspection and Testing Requirements 9.4-18 9.4.3 Turbine Building 9.4-19 9.4.3.1 Design Bases 9.4-19 9.4.3.2 System Description 9.4-20 9.4.3.3 Safety Evaluation 9.4-20 9.4.3.4 Inspection and Testing Requirements 9.4-21
9.4.4 Fuel Handling Area of the Auxiliary Building 9.4-21 9.4.4.1 Design Bases 9.4-21 9.4.4.2 System Description 9.4-22 9.4.4.3 Safety Evaluation 9.4-23 9.4.4.4 Inspection and Testing Requirements 9.4-25
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 9 CONTENTS (Continued) Section Title Page v Revision 21 September 2013 9.4.5 Containment 9.4-26 9.4.5.1 Design Bases 9.4-26 9.4.5.2 System Description 9.4-27 9.4.5.3 Safety Evaluation 9.4-31 9.4.5.4 Inspection and Testing Requirements 9.4-33
9.4.6 Intake Structure (Auxiliary Saltwater Pump Compartments) 9.4-33 9.4.6.1 Design Bases 9.4-33 9.4.6.2 System Description 9.4-33 9.4.6.3 Safety Evaluation 9.4-34 9.4.6.4 Inspection and Testing Requirements 9.4-34
9.4.7 Diesel Generator Compartments 9.4-34 9.4.7.1 Design Bases 9.4-35 9.4.7.2 System Description 9.4-36 9.4.7.3 Safety Evaluation 9.4-37 9.4.7.4 Inspection and Testing Requirements 9.4-39
9.4.8 4.16 kV Switchgear Room 9.4-40 9.4.8.1 Design Bases 9.4-40 9.4.8.2 System Description 9.4-40 9.4.8.3 Safety Evaluation 9.4-41 9.4.8.4 Inspection and Testing Requirements 9.4-41
9.4.9 125-Vdc and 480-Vac Switchgear Area 9.4-41 9.4.9.1 Design Bases 9.4-41 9.4.9.2 System Description 9.4-42 9.4.9.3 Safety Evaluation 9.4-43 9.4.9.4 Inspection and Testing Requirements 9.4-44 9.4.10 Post-Accident Sample Room 9.4-44 9.4.10.1 Design Bases 9.4-44 9.4.10.2 System Description 9.4-45 9.4.10.3 Safety Evaluation 9.4-45 9.4.10.4 Inspection and Testing Requirements 9.4-45
9.4.11 Technical Support Center 9.4-45 9.4.11.1 Design Bases 9.4-46 9.4.11.2 System Description 9.4-46 9.4.11.3 Safety Evaluation 9.4-47 9.4.11.4 Inspection and Testing Requirements 9.4-48 9.4.11.5 Instrumentation Requirements 9.4-48 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 9 CONTENTS (Continued) Section Title Page vi Revision 21 September 2013 9.4.12 Containment Penetration Area GE/GW 9.4-48 9.4.12.1 Design Basis 9.4-49 9.4.12.2 System Description 9.4-49 9.4.12.3 Safety Evaluation 9.4-50 9.4.12.4 Inspection and Testing Requirements 9.4-50
9.4.13 References 9.4-50
9.4.14 Reference Drawings 9.4-51
9.5 OTHER AUXILIARY SYSTEMS 9.5-1
9.5.1 Fire Protection System 9.5-1 9.5.1.1 Design Bases of the Fire Protection Program 9.5-2 9.5.1.2 Fire Protection System Description 9.5-5 9.5.1.3 System Evaluation 9.5-14 9.5.1.4 Inspection and Testing Requirements and Program Administration 9.5-14
9.5.2 Communications Systems 9.5-14 9.5.2.1 Design Bases 9.5-14 9.5.2.2 Description 9.5-14 9.5.2.3 Inspection and Testing Requirements 9.5-16
9.5.3 Lighting Systems 9.5-16
9.5.4 Diesel Generator Fuel Oil Storage and Transfer System 9.5-17 9.5.4.1 Design Bases 9.5-17 9.5.4.2 System Description 9.5-19 9.5.4.3 Safety Evaluation 9.5-20 9.5.4.4 Tests and Inspections 9.5-25 9.5.4.5 Instrumentation Application 9.5-26
9.5.5 Diesel Generator Cooling Water System 9.5-26 9.5.5.1 Design Bases 9.5-26 9.5.5.2 System Description 9.5-27 9.5.5.3 Safety Evaluation 9.5-28 9.5.5.4 Tests and Inspections 9.5-29 9.5.5.5 Instrumentation Applications 9.5-29
9.5.6 Diesel Generator Starting System 9.5-29 9.5.6.1 Design Bases 9.5-30 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 9 CONTENTS (Continued) Section Title Page vii Revision 21 September 2013 9.5.6.2 System Description 9.5-31 9.5.6.3 Safety Evaluation 9.5-32 9.5.6.4 Tests and Inspections 9.5-33 9.5.6.5 Instrumentation Applications 9.5-33
9.5.7 Diesel Generator Lubrication System 9.5-33 9.5.7.1 Design Bases 9.5-33 9.5.7.2 System Description 9.5-35 9.5.7.3 Safety Evaluation 9.5-35 9.5.7.4 Tests and Inspections 9.5-36 9.5.7.5 Instrumentation Applications 9.5-36
9.5.8 References 9.5-36
9.5.9 Reference Drawings 9.5-37
DCPP UNITS 1 & 2 FSAR UPDATE viii Revision 21 September 2013 Chapter 9 TABLES Table Title 9.1-1 Spent Fuel Pool Cooling and Cleanup System Design Data
9.1-2 Spent Fuel Pool Cooling and Cleanup System Design and Operating Parameters 9.2-1 Auxiliary Saltwater System Component Design Data
9.2-2 Auxiliary Saltwater System Malfunction Analysis
9.2-3 Component Cooling Water System Component Design Data
9.2-4 Components Cooled by the Component Cooling Water System
9.2-5 Component Cooling Water System Nominal Flows (in gpm)
9.2-6 Components With a Single Barrier Between Component Cooling Water and Reactor Coolant Water 9.2-7 Component Cooling Water System Malfunction Analysis 9.2-8 Deleted in Revision 5 9.2-9 Makeup Water System Equipment Design and Operating Parameters
9.3-1 Compressed Air System Equipment
9.3-2 Nuclear Steam Supply System Sampling System Component Design Data
9.3-3 Deleted in Revision 15
9.3-4 Deleted in Revision 15
9.3-5 Chemical and Volume Control System Design Data
9.3-6 Chemical and Volume Control System Principal Component Data Summary 9.3-7 Nitrogen Requirements DCPP UNITS 1 & 2 FSAR UPDATE Chapter 9 TABLES (Continued) Table Title ix Revision 21 September 2013 9.3-8 Hydrogen Requirements 9.4-1 Control Room HVAC System Component Design Data
9.4-2 Compliance With Regulatory Guide 1.52 (Revision 0, June 1973) Design, Testing, and Maintenance Criteria for Atmosphere Cleanup System Air Filtration and Adsorption Units of Light-Water Cooled Nuclear Power Plants 9.4-3 Deleted in Revision 10
9.4-4 Deleted in Revision 8
9.4-5 Auxiliary Building Heating and Ventilation System Components Design Data 9.4-6 Fuel Handling Area Heating and Ventilation System Components Design Data 9.4-7 Design Values for Turbine Building Ventilation System, Unit 1
9.4-8 Design Codes and Standards for Ventilation Systems
9.4-9 Estimated Control Room Area Heat Loads (Normal Operating Conditions - Mode 1) 9.4-10 Design Values for Auxiliary Building Ventilation System
9.4-11 Estimated NSSS Heat Losses Inside Containment
9.4.12 Estimated Total Heat Sources Inside Containment
9.5-1 Fire Protection System Component Design Data
9.5-2 Diesel Generator Fuel Oil System Component Design Data
DCPP UNITS 1 & 2 FSAR UPDATE x Revision 21 September 2013 Chapter 9 FIGURES Figure Title 9.1-1 New Fuel Storage
9.1-2 Spent Fuel Storage
9.1-2A Burnup vs Enrichment (All Cell)
9.1-2B Burnup vs Enrichment (2x2 Array) 9.1-3 Deleted in Revision 19 9.1-4 HI-TRAC 125D Transfer Cask
9.1-5 Spent Fuel Cask Restraint Spent Fuel Pool
9.1-6 Spent Fuel Pool Transfer Cask Restraint Cup
9.1-7 Heavy Load Handling Paths for the Transfer Cask/MPC
9.1-8 Manipulator Crane 9.1-8a Deleted In Revision 7 9.1-9 Spent Fuel Pool Bridge
9.1-10 New Fuel Elevator
9.1-11 Fuel Transfer System
9.1-11a Deleted In Revision 7
9.1-12 Rod Cluster Control Changing Fixture
9.1-12a Rod Cluster Control Changing Tool
9.1-13 Spent Fuel Handling Tool
9.1-14 New Fuel Assembly Handling Fixture
9.1-15 Reactor Vessel Head Lifting Device
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 9 FIGURES (Continued) Figure Title xi Revision 21 September 2013 9.1-15A Deleted in Revision 20 9.1-16 Reactor Internals Lifting Device
9.1-17 Reactor Vessel Stud Tensioner
9.1-18 Fuel Handling Tool Locations
9.1-19 Movable Partition Walls Location Plans
9.1-20 Movable Partition Walls Elevation at Column Line 157 or 203 9.1-21 Movable Partition Walls Details Showing Wall, Track, and Vertical Stop
9.1-22 Deleted in Revision 19
9.1-23 Deleted in Revision 19
9.1-24 Cask Washdown Area Restraint
9.1-25 Deleted in Revision 19
9.1-26 Deleted in Revision 19
9.2-1 Deleted in Revision 1
9.2-2 Arrangement of Intake Structure
9.2-3 Arrangement of Auxiliary Saltwater System Piping 9.2-4 Deleted in Revision 11 9.2-5 Deleted in Revision 11
9.2-6 Deleted in Revision 11
9.2-7 Deleted in Revision 11
9.2-8 Deleted in Revision 11
9.2-9 Deleted in Revision 11
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 9 FIGURES (Continued) Figure Title xii Revision 21 September 2013 9.2-10 Deleted in Revision 11 9.2-11 Deleted in Revision 11
9.2-12 Deleted in Revision 11
9.2-13 Deleted in Revision 11
9.2-14 Deleted in Revision 11
9.2-15 Deleted in Revision 11
9.2-16 Deleted in Revision 12
9.2-17 Deleted in Revision 18
9.2-18 Deleted in Revision 18
9.2-19 Deleted in Revision 6
9.3-1 Deleted in Revision 1
9.3-2 Deleted in Revision 1
9.3-3 Deleted in Revision 1
9.3-4 Deleted in Revision 1
9.3-5 Floor Drain 9.4-1(a) Air Conditioning, Heating, Cooling, and Ventilation Systems - Control Room 9.4-2(a) Air Conditioning, Heating, Cooling, and Ventilation Systems - Auxiliary Building 9.4-3(a) Air Conditioning, Heating, Cooling, and Ventilation Systems - Containment and Fuel Handling Area (Unit 1) 9.4-3a(a) Air Conditioning, Heating, Cooling, and Ventilation Systems - Containment and Fuel Handling Area (Unit 2) DCPP UNITS 1 & 2 FSAR UPDATE Chapter 9 FIGURES (Continued) Figure Title xiii Revision 21 September 2013 9.4-4 Containment Fan Cooler Unit - Containment Structure 9.4-5 Ventilation System - Intake Structure
9.4-6 Ventilation System - Diesel Generator
9.4-7 Ventilation System - 4 kV Switchgear Rooms 9.4-8(a) Ventilation System - Inverter Rooms and 480 V Switchgear Room in Auxiliary Building 9.4-9 Deleted in Revision 16 9.4-10(a) Ventilation Systems - Technical Support Center and Post-Accident Sampling Room 9.4-11 Ventilation Systems - Containment Area GE/GW
9.5-1 Fire Protection System - Water System
9.5-2 Fire Protection System - Seismically Qualified Portion of Water System
9.5-3 Fire Protection System - Carbon Dioxide System
9.5-4 Deleted in Revision 12
9.5-5 Primary Communications System
9.5-6 Secondary Communications System 9.5-7 Deleted in Revision 1 9.5-8(a) Diesel Fuel Oil Transfer Pump Vaults 9.5-9(a) Diesel Generator Fuel Oil Piping 9.5-10(a) Diesel Generator Arrangement Plan 9.5-11(a) Diesel Generator Arrangement Sections 9.5-12(a) Diesel Engine Generator (Typical) DCPP UNITS 1 & 2 FSAR UPDATE Chapter 9 FIGURES (Continued) Figure Title xiv Revision 21 September 2013 NOTE: (a) This figure corresponds to a controlled engineering drawing that is incorporated by reference into the FSAR Update. See Table 1.6-1 for the correlation between the FSAR Update figure number and the corresponding controlled engineering drawing number.
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 9 APPENDICES Appendix Title xv Revision 21 September 2013 9.5A FIRE HAZARDS ANALYSIS 9.5B REGULATORY COMPLIANCE SUMMARY
9.5C RCP OIL COLLECTION SYSTEM - EVALUATION TO 10 CFR 50, APPENDIX R, SECTION III.O 9.5D EMERGENCY LIGHTING CAPABILITY - EVALUATION TO 10 CFR 50, APPENDIX R, SECTION III.J 9.5E 10 CFR 50, APPENDIX R, SECTION III. L - ALTERNATE AND DEDICATED SHUTDOWN CAPABILITY 9.5F FIRE BARRIER FIGURES
9.5G EQUIPMENT REQUIRED FOR SAFE SHUTDOWN
9.5H INSPECTION AND TESTING REQUIREMENTS AND PROGRAM ADMINISTRATION DCPP UNITS 1 & 2 FSAR UPDATE 9.1-1 Revision 21 September 2013 Chapter 9 AUXILIARY SYSTEMS This chapter discusses auxiliary systems installed in Units 1 and 2 at the Diablo Canyon Power Plant (DCPP) site. Fuel storage and handling systems; water systems; process auxiliaries; and air conditioning, heating, cooling, and ventilation systems are described as well as other auxiliary systems. The design classifications for these various systems and their associated structures and components are discussed in Section 3.2. 9.1 FUEL STORAGE AND HANDLING The fuel storage and handling systems provide safe and effective means of storing, transporting, and handling new and irradiated nuclear fuel. These systems are located mainly in the fuel handling areas of the auxiliary building, adjacent to the east walls of the containment structures. Separate facilities are provided for each unit.
The fuel storage and handling systems comply with the criticality accident requirements of 10 CFR 50.68(b), "Criticality Accident Requirements," in lieu of maintaining a monitoring system capable of detecting a criticality as described in 10 CFR 70.24, "Criticality Accident Requirements." In accordance with 10 CFR 50.68(b)(6), radiation monitors are provided in storage and associated handling areas when fuel is present to detect excessive radiation levels and to initiate appropriate safety actions.
As described in Reference 14, the NRC has granted an exemption from the criticality requirements of 10 CFR 50.68(b)(1) during loading, unloading, and handling of the multi-purpose canister in the DCPP spent fuel pool (SFP).
Controls over special nuclear material are maintained to prevent a criticality accident. In addition to the controls discussed below for both new (fresh) and spent (burned) fuel, as required by 10 CFR 50.68(b)(5) the quantity and forms of special nuclear material other than nuclear fuel that are stored onsite in any given area are less than the quantities necessary for a critical mass. Special nuclear materials are required to be stored in inventory control areas except when in transit. 9.1.1 NEW FUEL STORAGE New fuel will be stored in racks in vaults in the fuel handling area of the auxiliary building, located as shown in Figure 9.1-1, or in the spent fuel racks. The racks are designed to store, protect, and prevent criticality of new fuel assemblies until used within the reactor.
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-2 Revision 21 September 2013 9.1.1.1 Design Bases For each unit, new fuel assemblies with possible inserts (e.g., rod cluster control assemblies, (RCCAs)) are stored to facilitate the unloading of new fuel assemblies from trucks. The storage vaults are designed to hold new fuel assemblies in specially constructed racks and are utilized primarily for the temporary storage of the replacement fuel every cycle. The new fuel storage vault for each unit consists of two racks with 35 storage cells per rack (70 cells per unit). The cells are arranged in a 5x7 array for each rack.
The fuel storage criticality analysis assumed the vault was completely filled with 5.0 weight percent U-235 fuel with no credit taken for any burnable absorber that may be present in the fuel assemblies (e.g., integral fuel burnable absorber, IFBA). Although the new fuel vault is normally dry, two accident scenarios were considered as part of the vault's design bases: (1) when fully flooded with unborated water, a keff 0.95 must be maintained after allowing for calculational uncertainties, and (2) when flooded with aqueous foam, a keff 0.98 must be maintained after allowing for calculational uncertainties.
For each case, calculations were made for both the Westinghouse standard and optimized fuel assembly designs, which have different fuel rod diameters. The standard fuel gave the higher reactivity for the aqueous foam case whereas the OFA fuel gave the higher reactivity under the fully flooded accident condition. For the fully flooded case, the calculated keff was 0.9380 +/- 0.0069 (95%/95%). For the aqueous foam case, the calculated keff was 0.8949 +/- 0.0053 (95%/95%). Thus, allowing for all uncertainties, the maximum keff was 0.9449 for the flooded case, and 0.9002 for the aqueous foam case. These maximum values are within their respective 0.95 and 0.98 10 CFR 50.68(b)(2) and (b)(3) limits.
In addition, the fuel vault racks must be capable of maintaining the horizontal center-to-center spacing of the fuel assemblies, and of supporting assemblies vertically under postulated seismic events. Currently, the new fuel racks are seismically qualified to store only four assemblies per rack, one at each corner, each with or without insert components, e.g., RCCAs. The assumed combined weight of each fuel assembly and insert was 1800 pounds. Also, together with these four corner assemblies, a maximum of two insert components may be stored in each storage rack in cells face-adjacent to the corner cells in diagonally opposite corners. The assumed weight of each of the two additional inserts was 170 pounds. 9.1.1.2 Facilities Description There are two new fuel storage racks for each unit. A rack is approximately 9 feet 6 inches wide, 13 feet long, and 13 feet 6 inches high (excluding centering cones). It is built from Type 304 stainless steel.
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-3 Revision 21 September 2013 The storage cells in the racks are in seven rows, five deep, and are spaced to have a nominal center-to-center distance of 22 inches. They are of Type 304 stainless steel and have a cone shaped top entrance to facilitate loading of fuel elements. They are shaped in a 9-inch square (cross section) hollow beam configuration, standing upright. At the base, they have a 1-inch thick bearing plate made of neoprene-impregnated fabric.
The new fuel storage racks and the anchorage of racks to the floor are designed for the design earthquake (DE) and double design earthquake (DDE) loading conditions and checked for a postulated Hosgri seismic event (Reference 1) with the racks containing fuel assemblies at the corners.
The racks are designed to withstand a vertical (uplift) force of 4000 pounds in the unlikely event that an assembly would bind in the rack while being lifted by the spent fuel bridge crane.
The racks are located in the fuel handling area of the auxiliary building at elevation 125 feet. Assembly access is from elevation 140 feet. 9.1.1.3 Safety Evaluation The storage racks are designed in accordance with the American Institute of Steel Construction, Specification for the Design, Fabrication, and Erection of Structural Steel for Buildings, published on February 12, 1969. The ASME Boiler and Pressure Vessel Code is used to determine allowable limits for materials not addressed by the AISC specification. Center-to-center assembly spacing is held to a tolerance of +/-1/16 inch to ensure a Keff of less than 0.95, even when the vault is flooded with unborated water. After the racks were installed, a dummy fuel element was inserted in each location and critical measurements taken to ensure proper arrangement and support. A metal cap covers the top of the rack. If a fuel assembly is accidentally dropped, it will only be able to drop into a holder and could not drop into the space between fuel assemblies. An accident analysis is presented in Chapter 15. 9.1.2 PERMANENT SPENT FUEL STORAGE The spent fuel storage pool, shown in Figure 9.1-2, is the storage space for irradiated spent fuel from the reactor. New fuel may also be stored in the SFP. This figure shows the arrangement of the permanent spent fuel storage racks. The SFP is not required for any plant operating mode safety-related function. As described in Section 3.2, the SFP concrete structure is Design Class I. Two pools are provided, one for each unit.
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-4 Revision 21 September 2013 9.1.2.1 Design Bases The SFPs are designed to accommodate both new and spent fuel assemblies in a subcritical array such that a keff < 1.0 is maintained if flooded with unborated water. They are constructed of reinforced concrete as part of the auxiliary building structure. The design is described in Section 3.8.2. The entire structure and the spent fuel racks have been designed in accordance with Design Class I seismic requirements. Criteria set by Safety Guide 13 (Reference 3) have been followed. Gaseous radioactivity about the spent fuel storage pool is maintained below the 10 CFR 20 limits. 9.1.2.2 Facilities Description The spent fuel storage pool for each unit is a reinforced concrete structure with seam-welded stainless steel plate liner. The pool volume is approximately 59,100 cubic feet. The pool is filled with borated water at a concentration greater than or equal to 2000 ppm boron as discussed in the Technical Specifications (Reference 2).
Each SFP is designed to hold 1324 assemblies in the permanent fuel racks, allowing for the concurrent storage of a full core of irradiated fuel assemblies and the normal quantity of spent fuel assemblies from reactor refueling operations (expected through 2007 for Unit 1 and 2008 for Unit 2). RCCAs and burnable poison rods requiring removal from the reactor are normally stored in the spent fuel assemblies.
The high density spent fuel racks for each fuel pool consist of a total of 16 stainless steel racks of various sizes, with a total of 1324 fuel assembly storage cells plus 10 miscellaneous storage locations. Individual storage cells have an 8.85 inch (nominal) square cross section, and each is sized to contain and protect a single Westinghouse-type PWR 17x17 fuel assembly. The cells are arranged with a nominal 11-inch center-to-center spacing in the 16 rack modules.
Three modules (290 cells), previously designated as Region 1 in each pool; contain a neutron-absorbing material, Boraflex, on all four sides of the individual storage cells in the rack module. There are 13 modules (1034 cells) previously designated as Region 2 in each pool. Constraints for storing fuel in the high density spent fuel racks are identified in the DCPP Technical Specifications. Fresh and burned fuel assembly storage in the SFP is maintained such that any four cells are in one of three configurations allowable by the DCPP Technical Specifications. The three allowable storage configurations specified by the DCPP Technical Specifications are: (a) the all-cell, (b) the 2x2 array, and (c) the checkerboard configuration. Spent fuel assemblies satisfying the discharge burnup requirements of Figure 9.1-2A can be stored in the all-cell configuration in the SFP. A fuel assembly, with an initial enrichment less than or equal to 4.9 weight percent U-235 or with an initial enrichment less than or equal to 5.0 weight percent U-235 and an IFBA loading equivalent to 16 rods each with 1.5 milligrams B-10 per inch over 120 inches, and three fuel assemblies satisfying the discharge burnup requirements of Figure 9.1-2B can be stored in the 2x2 array configuration. Fresh and spent fuel assemblies not satisfying the initial enrichment, DCPP UNITS 1 & 2 FSAR UPDATE 9.1-5 Revision 21 September 2013 discharge burnup, and IFBA loading requirements for the all-cell and 2x2 array configurations must be stored in the checkerboard configuration with water cells or non-fissile material. Figure 9.1-2 shows the arrangement of the rack modules for Unit 1. Unit 2 is a mirror image around column line 129 (south end of Unit 1 SFP). The racks are freestanding, with no connection to the pool floor, walls, or adjacent rack modules. The rack support feet rest on bridge plates on the pool floor. Each module is equipped with a girdle bar on the outside of each of the modules' four sides, near the top. Each girdle bar serves as a designated impact location, and each is designed to accommodate impact loads, which may occur during a seismic event. They also maintain a specified minimum gap between the cell walls of adjacent rack modules for all loading conditions.
The racks are designed for the DE, DDE, and postulated Hosgri seismic event with the racks filled with fuel assemblies. The racks are designed to withstand a vertical (uplift) force of 4400 pounds in the unlikely event that an assembly would bind in the rack while being lifted by the spent fuel bridge crane. The design classification of the spent fuel storage racks is discussed in Section 3.2, and the design requirements and acceptance criteria are discussed in Section 3.8.8.
Adjacent to the spent fuel storage pool is the stainless-steel-lined fuel transfer canal, which is connected to the refueling cavity (inside the containment). A leaktight door is provided between the pool and the fuel transfer canal.
Almost all components (handling tools, new fuel elevator, etc.) in contact with the SFP water are constructed of stainless steel, which has very good corrosion resistance. There are a few components made of bronze, which also has good corrosion resistance in aqueous environments. The compatibility of bronze and stainless steel maintains the integrity of the stainless steel components in the storage pool.
During transfer of spent fuel assemblies, the borated water level in the pool is maintained to provide at least 9 feet of water above the top of the active portion of the spent fuel assemblies. Normally, the borated water level in the pool is maintained to provide at least 23 feet of water over the top of the irradiated fuel assemblies seated in the storage racks as discussed in the Technical Specifications. This ensures sufficient water depth to remove 99 percent of all the iodine activity that could be released from a rupture of an irradiated fuel assembly. This water barrier serves as a radiation shield, limiting the gamma dose rate at the pool surface.
A cooling and cleanup system for the spent fuel storage pool water is described in Section 9.1.3.
A controlled and monitored ventilation system removes any gaseous radioactivity from the atmosphere above the spent fuel storage pool and discharges it through the plant vent. This system is described in Section 9.4.4.
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-6 Revision 21 September 2013 The spent fuel storage pool vent exhausts to the outside atmosphere through the plant vent where radiation monitors RM-14/RM-14R will continuously monitor the gases from the vents of the spent fuel storage pool areas and alarm when the activity level of the gases reaches a preset limit. Such an alarm will alert the operators to take appropriate action. See also Chapter 6 for a discussion of the ventilation system operation in the event high activity levels are detected. In addition, the fuel storage pool area monitors, RM-58 and RM-59 automatically will change the exhaust mode from normal to emergency (HEPA and charcoal filters) if measured area radiation levels increase to preset alarm levels.
A spent fuel storage pool area radiation monitoring system has been provided for personnel protection and general surveillance of the spent fuel storage pool area. This system is described in Section 11.4.2.3. Continuous monitoring and recording readouts and high radiation level alarms in the control room, plus local audible and visual indicators, are provided for use during the movement of irradiated fuel assemblies in the fuel handling building. See also Section 15.4 for a discussion of radiation monitoring and ventilation during a fuel handling accident. 9.1.2.3 Safety Evaluation The spent fuel storage racks are designed in accordance with Safety Guide 13 and the ASME Boiler and Pressure Vessel Code, Section III, Subsection NF.
In accordance with 10 CFR 50.68(b)(4), the high density spent fuel storage racks are designed to ensure that, with credit for soluble boron (References 8 and 9) and with fuel of the maximum fuel assembly reactivity, a Keff of less than or equal to 0.95 is maintained, at a 95 percent probability, 95 percent confidence level, if the racks are flooded with borated water, and a Keff off less than 1.0 is maintained, at a 95 percent probability, 95 percent confidence level, if the racks are flooded with unborated water.
The associated spent fuel criticality analysis (Reference 24) modeled a full pool representation of the storage racks and infinite arrays of fuel using the SCALE-PC computer code, which includes the CSAS25 control module and functional modules BONAMI, NITAWL-II and KENO-Va, and employs the 44 Group Evaluated Nuclear Data File Version 5 (ENDF/B-V) neutron cross section library. SCALE-PC has been validated against 30 critical experiments and the calculations adequately reproduced the data. The DIT computer code was used to generate a set of isotopic concentrations based on ENDF/B-VI. DIT has been benchmarked against Combustion Engineering PWR cores and against other PWR lattice codes, such as CASMO, with very good agreement.
Reference 24 considers the 2X2 Array and Checkerboard spent fuel configurations and fuel type and burnup characteristics specified in the DCPP Technical Specifications. The analysis assumed a fresh fuel assembly, which was a conservative representation of the Westinghouse OFA 17x17 fuel assembly with a nominal enrichment of 4.9 weight percent U-235 and no IFBAs. This fresh assembly conservatively envelopes the DCPP UNITS 1 & 2 FSAR UPDATE 9.1-7 Revision 21 September 2013 characteristics of possible fresh fuel types that may be used. The analysis assumed a burned fuel assembly, which was a conservative representation of a Westinghouse Standard 17x17 fuel assembly. This burned assembly conservatively envelopes the characteristics of burned fuel assemblies stored in the SFP. The analysis evaluated the region of the SFP, which does not contain Boraflex panels since the storage requirements for this region are more restrictive and yield more conservative reactivity results than the region containing Boraflex panels. Therefore, the analysis does not credit the negative reactivity associated with the Boraflex panels.
Reference 24 considered biases and uncertainties such that the Keff value was determined at a 95 percent probability, 95 percent confidence level. The biases considered included a KENO-Va computer code methodology bias and a reactivity bias to account for a range of SFP water temperature. The uncertainties considered included those due to fuel assembly manufacturing tolerances, rack fabrication tolerances, KENO-Va computer code methodology, fuel assembly reactivity, and absolute fuel assembly burnup.
Reference 24 assumed a core moderator average temperature of 579.95 F. Higher moderator temperature affects analysis results in a non-conservative direction (i .e., reduces margin). Since moderator temperature in the core can potentially reach 582.3 F, an evaluation was performed to assess the impact of this higher temperature on the analysis (Reference 25). The evaluation concluded that adequate margin exists such that the potentially higher moderator temperature is acceptable and can be accommodated in the existing SFP criticality analysis.
Reference 24 does not consider the "All Cell" storage configuration in the spent fuel pool (i.e., all cells filled and all fuel assemblies with discharge burnup in acceptable area of TS Fig. 3.7.17-2. A Holtec analysis (Reference 26) is the analysis of record (AOR) for that configuration. The core moderator average temperature value assumed for the Holtec AOR is 584 K [591.5 F] (Reference 25). This value bounds the maximum potential core average temperature of 582.3 F. Therefore, the AOR for the "All Cell" storage configuration is bounding for the maximum expected core moderator temperature.
For normal conditions (no SFP fuel mishandling or fuel drop accident), the SFP criticality analysis determined that a Keff of less than 1.0 is maintained, at a 95 percent probability, 95 percent confidence level, if the racks are flooded with unborated water.
Potential SFP fuel-mishandling accidents and fuel-drop accidents, which result in a reactivity insertion, were evaluated in the SFP criticality analysis such as the misplacement of a fresh fuel assembly in place of a burned fuel assembly within a rack module, the misplacement of a fresh fuel assembly outside the rack module, accidental drop of a fresh fuel assembly outside the rack module, and the T-Bone drop of a fresh assembly. The most limiting SFP accident was determined to be the misplacement of a fresh fuel assembly with 4.9 weight percent U-235 outside the rack module such that it is adjacent to a fresh fuel assembly with 4.9 weight percent U-235 within the rack DCPP UNITS 1 & 2 FSAR UPDATE 9.1-8 Revision 21 September 2013 module, resulting in two fresh assemblies adjacent to each other in the SFP. For the most limiting SFP accident, a SFP soluble boron concentration of 806 ppm is required to maintain Keff less than or equal to 0.95 at a 95 percent probability, 95 percent confidence level. The DCPP Technical Specifications require that the minimum SFP boron concentration is 2000 ppm. This boron concentration is more than sufficient concentration to maintain 5 percent subcriticality margin in the SFP during the most limiting SFP accident. Administrative procedures to ensure the presence of soluble boron in the SFP during fuel handling operations preclude the possibility of the simultaneous occurrence of two independent accident conditions such as a fuel assembly misplacement and loss of soluble boron.
An SFP boron dilution analysis was performed (Enclosure 6 to Reference 8) to evaluate the time and water volumes required to dilute the SFP from the DCPP Technical Specification required minimum boron concentration of 2000 ppm to approximately 800 ppm. The 800 ppm endpoint was utilized to ensure that the SFP Keff would remain less than or equal to 0.95.
A large volume of pure water (approximately 347,000 gallons) is necessary to dilute the SFP from 2000 ppm to 800 ppm. Dilution sources available which exceed 347,000 gallons (primary water makeup system, makeup water system, and fire protection system) were evaluated against the calculated dilution volumes to determine the potential of a SFP-dilution event. The dilution from seismic events or random pipes breaks is bounded by the primary water makeup system flow. Dilution due to the drain system was not evaluated since backflow through the system is not considered credible. Also, the SFP demineralizer was not evaluated since it cannot provide sufficient dilution. The boron dilution analysis demonstrates that adequate time is available to identify and mitigate the dilution event before the spent fuel rack Keff would exceed 0.95. A dilution event large enough to result in a significant reduction in the SFP boron concentration would involve the transfer of a large quantity of water from a dilution source and a significant increase in SFP level, which would ultimately overflow the pool. Such a large water volume turnover, and overflow of the SFP, would be readily detected and terminated by plant personnel. In addition, because of the large quantities of water required and the low dilution flow rates available, any significant dilution of the SFP boron concentration would only occur over a long period of time (hours to days). Detection of a SFP boron dilution via pool level alarms, visual inspection during normal operator rounds, significant changes in SFP boron concentration, or significant changes in the unborated water source volume, would be expected before a dilution event sufficient to increase Keff above 0.95 could occur. The results of the boron dilution analysis concluded that an unplanned or inadvertent event that would result in the dilution of the SFP boron concentration from 2000 ppm to 800 ppm is not a credible event. However, even if the SFP were diluted to zero ppm boron, which would take significantly more water than evaluated in the dilution analysis, the SFP would remain subcritical and the health and safety of the public would be protected. Sampling of the SFP boron concentration is required by the DCPP Technical DCPP UNITS 1 & 2 FSAR UPDATE 9.1-9 Revision 21 September 2013 Specifications on a 7-day frequency, which provides adequate assurance that smaller and less readily identifiable boron concentration reductions are not taking place.
Crane operation in the fuel handling area is such that the heavy loads cannot traverse over the spent fuel storage racks in the SFP. Redundant electrical interlocks are installed on the fuel handling area crane to prevent movement of heavy loads over the area of the spent fuel storage pool which can contain spent fuel. The backup interlock is connected to a different circuit than the primary interlock to preclude heavy loads movement over stored fuel that could result from failure of a single component.
These limitations on fuel handling area crane travel preclude the possibility of dropping heavy objects from above the spent fuel racks. The spent fuel bridge hoist and the moveable partition wall monorail are the only cranes capable of moving objects over the spent fuel racks. The rated capacity of the spent fuel bridge hoist is 2000 pounds. An object of this weight dropped on the racks will not affect the integrity of the racks. The rated capacity of the moveable partition wall monorail is 4000 pounds, however, physical restrictions (trolley stops) are provided to prevent movement of loads over the SFP. Lighting fixtures or other components of the building above the racks are not sufficiently massive to cause damage to the racks if they are assumed to fall into the pool. Protection of nuclear fuel assemblies from overhead load handling is a key element of the Control of Heavy Loads Program described in Section 9.1.4.3.5. 9.1.2.3.1 Spent Fuel Cask Accidents Evaluations have been performed to examine postulated accidents and off-normal events related to handling and loading (or unloading) of the HI-TRAC 125D transfer cask in the DCPP 10 CFR 50 facilities (the transfer cask is illustrated in Figure 9.1-4 of this section and its physical characteristics are shown in Table 4.2-3 of the Diablo Canyon ISFSI FSAR Update). The evaluations are described in Section 9.1.4.7. 9.1.2.3.2 Tornado Resistance As discussed in Section 3.3.2, the fuel handling area of the auxiliary building has been evaluated for tornado wind and missile loading. The calculated capabilities are given in Table 3.3-2. Note that some metal siding on the fuel handling building may detach during the postulated tornado.
The floor elevation of the spent fuel storage pool is 99 feet, and the normal water surface is at elevation 137 feet 8 inches. The spent fuel storage racks rest on bridge plates supported on the floor and have a total height of 14 feet 11 inches. Thus normal water depth over the racks is 23 feet 9 inches.
In General Electric Topical Report APED - 5696, Tornado Protection for the Spent Fuel Storage Pool (Reference 5, Section 3.3.3), a highly conservative model demonstrates that removal of more than 5 feet of water by a tornado mechanism is highly improbable. The 20 feet of water cover remaining over the fuel racks is shown to provide adequate DCPP UNITS 1 & 2 FSAR UPDATE 9.1-10 Revision 21 September 2013 protection against both fuel damage and liner penetration from a wide spectrum of tornado-generated missiles ranging up to a 3 inch diameter steel cylinder (7 feet long) or a 14 inch diameter wood pole (12 feet long). A potential for damage can only be shown by arbitrarily assuming long cylindrical objects hurled into the pool by winds acting on their maximum cross-sectional area and then impacting the pool with their minimum cross-sectional area. The probability of such an event is calculated to be about once per 1.4 billion reactor lifetimes. It is therefore concluded that adequate protection against tornado forces and tornado-generated missiles has been provided for the spent fuel storage pool. 9.1.2.4 Tests and Inspections After erection of the spent fuel racks, tests were conducted with a dummy fuel assembly by passing it into and out of each storage position to ensure that binding would not occur. 9.1.3 SPENT FUEL POOL COOLING AND CLEANUP SYSTEM The SFP cooling and cleanup system provides the following functions:
(1) Maintains a water inventory in the SFP sufficient to keep spent fuel immersed at all times. (2) Provides reactivity control (borated water) for mitigation of a postulated misplaced fuel assembly event. (3) Provides for a water inventory in the SFP over the spent fuel assemblies to support iodine decontamination factor assumptions used in the analysis of the mitigation of radiological consequences of a Chapter 15 Fuel Handling Accident. (4) Provides a highly reliable pumped-fluid system to transfer decay heat from the SFP to the Component Cooling Water (CCW) system via the SFP heat exchanger. (5) Maintains a water inventory in the SFP to provide radiation shielding for long-term storage of fuel assemblies in the SFP. (6) Purifies and demineralizes SFP water to maintain SFP water quality.
Each unit has a completely independent SFP cooling and cleanup system.
Sections 9.1.3.1 to 9.1.3.5 provide a description for the SFP cooling and cleanup system of one unit with the second unit having an identical system.
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-11 Revision 21 September 2013 In addition to the SFP cooling and cleanup system, a temporary backup SFP cooling system may be installed. The temporary backup system provides the following functions:
(1) Provides limited standby backup cooling for the SFP when the heat exchanger of the permanent SFP cooling and cleanup system serving that SFP is taken out of service for maintenance or inspection.
(2) Provides limited standby backup cooling for the SFP during refueling outages to extend the time-to-boil in the event that the permanent SFP cooling and cleanup system of the outage unit is not operable. Section 9.1.3.6 provides a description of the backup SFP cooling system. 9.1.3.1 Design Bases The SFP cooling and cleanup system design parameters are given in Table 9.1-1. 9.1.3.1.1 Spent Fuel Pool Cooling The Spent Fuel Pool Cooling system is designed to remove that amount of decay heat that is produced by spent fuel assemblies that are stored in the pool following a refueling. A cask pit rack was installed during Cycle 14, prior to the 14th refueling outage. During Cycle 15, the cask pit rack was removed from Unit 1. The cask pit rack in Unit 2 was removed during Cycle 16. PG&E has updated its SFP thermal-hydraulic analyses as part of the cask pit rack project (Reference 15). These updated analyses were performed using more recent analytical methods that have been previously accepted by the NRC. These analytical methods and the associated full core and emergency offload scenarios discussed below will bound both the installation of the cask pit rack and future DCPP SFP fuel storage requirements once the cask pit rack has been removed. These new analyses will serve as the new licensing basis of record for future spent fuel storage requirements, including the temporary supplemental spent fuel storage capacity provided by the cask pit rack.
The cask pit thermal-hydraulic analyses are based on the evaluation of three offload scenarios that bound the past and future operating practices at DCPP. For each scenario, the transient and steady state decay heat loads were combined to provide a total decay heat load on the SFP cooling system (Reference 15).
(1) The partial core offload scenario assumes a discharge of 96 fuel assemblies during the 15th refueling outage. All of the 96 fuel assemblies offloaded are conservatively assumed to have a burnup of 52,000 MWD/MTU.
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-12 Revision 21 September 2013 (2) The full core offload scenario assumes a discharge of 193 fuel assemblies during the 15th refueling outage. The 193 offloaded assemblies are separated into two distinct groups; 101 assemblies with 52,000 MWD/MTU burnup and 92 assemblies with 25,000 MWD/MTU burnup. (3) The emergency full core offload scenario assumes that the 15th refueling outage is completed in 30 days, leaving 104 assemblies in the SFP at restart. After 36 days of operation at 100 percent power in Cycle 16, an emergency full core offload is performed, completely filling all available storage locations. The 193 assemblies are separated into two distinct groups: 113 assemblies with 40,000 MWD/MTU burnup and 80 assemblies with 3,000 MWD/MTU burnup. All of these scenarios have been evaluated with a base decay heat load contribution from previously discharged fuel assemblies using actual operational data for operating Cycles 1 through 11. The contribution to the base decay heat load from fuel that will be discharged in Cycles 12 through 14 is based on an assumed discharge of 104 assemblies each Cycle using bounding assumptions on fuel assembly burnup and operating power. Cycle lengths assumed for Cycles 12 through 14 are assumed to be 18 months, which conservatively minimizes the decay time and maximizes the base decay heat load. All three of these scenarios assume a core offload rate of four assemblies per hour, starting 100 hours after reactor shutdown, and other appropriately conservative fuel assembly discharge and burnup assumptions.
Conservative values for pump flow and heat exchanger performance were selected to provide bounding calculations for the peak SFP bulk temperature. The thermal performance of the heat exchangers was determined with all heat transfer surfaces assumed to be fouled to their design basis maximum levels and also included an allowance for five percent tube plugging. CCW supplied to the heat exchanger was assumed to be 75°F at a flow rate of 3400 gpm which is bounded by SFP cooling system design parameters. Plant procedures are currently in place to limit the peak SFP temperature to within 140°F. The procedural controls currently suspend offload activities at a SFP temperature of 125°F to maintain peak SFP bulk temperatures less than 140°F. Past operating experience at DCPP has shown that peak SFP temperatures are typically less than 115°F during a typical full core offload. Due to the many variables that can have an impact on peak SFP temperature, DCPP may elect to use a cycle specific offload analysis in lieu of the operating restrictions of the bounding thermal analyses described above. Consideration will be given to the actual core power history, scheduled offload start time, offload rates, actual CCW temperature, and actual CCW and SFP cooling water flow rates to the SFP heat exchanger in the establishment of the specific control values. If DCPP elects to use a cycle specific analysis, plant procedures will require that core offload be suspended at a temperature, which would ensure that the 140°F limit is not exceeded. Results of the thermal-hydraulic analyses are described below. DCPP UNITS 1 & 2 FSAR UPDATE 9.1-13 Revision 21 September 2013 The partial core offload analysis resulted in a maximum pool bulk temperature of 127°F. The full core offload analysis resulted in a maximum pool bulk temperature of 157°F. The emergency core offload analysis resulted in a peak bulk temperature of less than 162°F.
The time-to-boil evaluation assumed that forced cooling was lost the moment the peak SFP bulk temperature for each case was reached. The SFP time to boil and corresponding maximum boil-off rates were then determined.
For the worst-case scenario, the emergency core offload, the calculated time-to-boil was determined to be 3.76 hours after a loss of forced cooling at the peak SFP bulk temperature. The corresponding maximum boil-off rate for this condition was approximately 87 gpm.
Given the conservatisms incorporated into the calculations, actual times-to-boil will be higher than these calculated values and actual boil-off rates will be lower than calculated. Based on the time-to-boil, plant personnel will have sufficient time to identify elevated SFP temperatures and adequate time to provide makeup to the SFP, if needed.
Local temperature analyses were also performed to determine maximum local water and fuel cladding temperatures. The worst case peak local water temperature is 188 °F and below the local saturation temperature (240 °F) at the depth of the cask pit rack. The results also demonstrate that the peak fuel cladding temperature of 213 °F for the hottest fuel assembly is below the local saturation temperature, and the critical heat flux for DNB is not exceeded. Therefore no bulk boiling will occur in the cask pit rack, and the local water and fuel temperatures are acceptable. The SFP cooling and cleanup system components are constructed in accordance with Safety Guide 13. However, a piping design analysis, including seismic loads, was performed to ensure that the cooling loop conforms to Design Class I piping criteria as indicated in the DCPP Q-List (see Reference 8 of Section 3.2). The failure or malfunction of any of the spent fuel cooling and cleanup system components, including failures resulting from the DE, DDE, or a Hosgri seismic event, will not cause the fuel to be uncovered. 9.1.3.1.2 Spent Fuel Pool Dewatering Protection System piping is arranged so that failure of any pipeline cannot inadvertently drain the SFP below the water level required for radiation shielding. This level is maintained by:
(1) pool suction piping located 20 feet above the top of the fuel assemblies, and (2) a siphon breaker on the cooling pipe's return line into the pool.
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-14 Revision 21 September 2013 This design ensures greater than ten feet of water exists over the top of the fuel assemblies should inadvertent drainage occur.
Normal SFP water levels are maintained a minimum of 23 feet over the top of irradiated fuel assemblies seated in the storage racks as discussed in Sections 9.1.2.2 and 9.1.2.3.2. 9.1.3.1.3 Water Purification The system's demineralizer and filters are designed to provide adequate purification of the SFP contents to permit access to the SFP storage area and maintain optical clarity of the SFP water. The optical clarity of the SFP water surface is maintained by use of the system's skimmers, strainer, and skimmer filter. The purification loop is capable of removing fission products and other contaminants from the pool water, including small quantities of fission products from leaking spent fuel assemblies.
A significant reduction of radioactive effluents is achieved through filtration and ion exchange, and by recycling refueling water as opposed to disposing of and making new refueling water. In addition, by concentrating impurities and radioactive particles on filter medium and demineralizer resin, which are more easily shielded, radiation levels are maintained ALARA. 9.1.3.2 System Description The SFP cooling and cleanup system, shown in Figure 3.2-13, removes decay heat from fuel stored in the SFP. Spent fuel is placed in the pool during the refueling sequence and stored there until it is shipped offsite. Heat is transferred through the SFP heat exchanger to the CCW system.
When the SFP cooling and cleanup system is in operation, water flows from the SFP to the SFP pump suction, is pumped through the tube side of the heat exchanger, and is returned to the pool. The suction line, which is protected by a strainer, is located at an elevation 4 feet below the normal SFP water level, while the return line contains an antisiphon hole near the surface of the water to prevent gravity drainage of the pool. While the heat removal operation is in process, a portion of the SFP water may be diverted away from the heat exchanger through the refueling water purification (RWP) filter, spent fuel pit demineralizer, spent fuel pit resin trap filter, and the spent fuel pit filter to maintain water clarity and purity. A resin trap and check valve, located upstream of the demineralizer, prevent backflushing demineralizer resins to the SFP. Transfer canal water may also be circulated through the same demineralizer and filter by opening the gate between the canal and the SFP. This purification loop removes fission products and other contaminants, which could be introduced if a fuel assembly with defective cladding is transferred to the SFP.
The exposure rate at the pool surface is routinely monitored with radiation surveys and monitoring equipment (see Section 12.3). The major contributor to the surface dose is DCPP UNITS 1 & 2 FSAR UPDATE 9.1-15 Revision 21 September 2013 the radioactivity within the pool water and not the spent fuel assemblies stored in the pool. The SFP demineralizer will be used as necessary to maintain radiation exposures ALARA.
The SFP demineralizer and filter flowpath bypasses the SFP heat exchanger. The demineralizer and filter may be brought into or out of service by manual operation of isolation valves. No other operator action is required. The bypass flowpath can be through the filter only, or through the filter and demineralizer in series, as shown in Figure 3.2-13. The piping configuration allows an alternate flowpath that utilizes the RWP filter upstream of the SFP demineralizer to allow optimization of filter and demineralizer operation. The demineralizer may also be used in conjunction with the RWP pump, filter, and resin trap to clean and purify the refueling water while SFP heat removal operations proceed.
The RWP system can be aligned to recirculate the contents of the refueling water storage tank (RWST). The RWP system is placed into service by manual operation of isolation valves and manual RWP pump start. This alignment enables tank mixing and cleanup of the RWST contents via the RWP filter, demineralizer, and resin trap filter. Processing the RWST contents through the RWP system enables the removal of radiological impurities to ensure RWST activities (Reference Table 12.1-13) and radiation exposure rates (Reference Table 12.1-14) are within 10 CFR 20 limits and are ALARA.
The RWP system filters and demineralizes the RWST water in order to maintain water quality and clarity for fuel transfer and inspection purposes. Refueling water clarity is both a personnel and equipment safety and radiation ALARA consideration. Also, the RWP system may be used to filter the contents of the RWST prior to employing a reverse osmosis system (ROS). The ROS is a temporary system, connected directly to the RWST, which may be used to reduce silica concentrations in the RWST. Design and administrative controls ensure minimum required RWST volume and boron concentrations are maintained throughout ROS operation.
During refueling outages, connections are provided such that the refueling water may be pumped from either the RWST or the refueling cavity, through the filter, demineralizer, and resin trap and discharged to either the refueling cavity or the RWST. In addition to this flowpath, it is possible to manually align the SFP cleanup system with the RWP system to clean the refueling canal water during fuel movement. The RWP pump may also be utilized to pump down the refueling canal by pumping water to the liquid hold-up tanks (LHUTs) through the RWP filter. To further assist in maintaining SFP water clarity, the water surface is cleaned by a skimmer loop. Water is removed from the surface by the skimmers, pumped through a strainer and filter, and returned to the pool surface at three locations remote from the skimmers.
The SFP was initially filled with water at 2000 ppm boron concentration. Additional boron, to maintain this concentration, is supplied from the RWST via the RWP system, or from other sources within the Chemical and Volume Control system. DCPP UNITS 1 & 2 FSAR UPDATE 9.1-16 Revision 21 September 2013 Demineralized makeup water can be added directly to the SFP by a Design Class I source. Water from the condensate storage tank is pumped to the SFP using the makeup water transfer pumps (see Section 9.2.6 and Table 9.2-9) and appropriate interconnecting piping and valves. This source has the capability of providing up to 200 gpm of demineralized water, if required. The above tank, pumps, piping, and valves are designed in accordance with Safety Guide 13. The transfer tank is another Design Class I source of pool makeup, and water can be pumped to the pool by the makeup water transfer pumps. However, the flowpath from the transfer tank is not completely Design Class I. In addition to the above source of makeup water, the Design Class I fire water tank could provide makeup from local hose reels.
A gate is installed between the SFP and the transfer canal so that the transfer canal may be drained to allow maintenance of the fuel transfer equipment. The water in the transfer canal is first pumped, using a portable pump, into the SFP and then is transferred to a holdup tank in the CVCS by the SFP pump. When needed for refueling operations, water is returned directly to the transfer canal by the holdup tank recirculation pump. 9.1.3.2.1 Component Description SFP cooling and cleanup system codes and classifications are given in the DCPP Q-List (see Reference 8 of Section 3.2). System design and operating parameters are given in Table 9.1-2. 9.1.3.2.1.1 Spent Fuel Pool Pump The SFP pumps are horizontal, centrifugal units, with all wetted surfaces being stainless steel or an equivalent corrosion-resistant material. The pumps are controlled manually from a local station. There are no Class 1E electrical loads in the SFP system; however, the SFP cooling pumps are powered from a Class 1E source. In all operational modes during electrical bus outages and maintenance periods, the standby/redundant pump may be temporarily aligned, using an approved temporary modification, to a non-vital power source until its Class 1E power supply is returned to service. In addition, for Modes 5, 6, and no mode operation during electrical bus outages and maintenance periods, the standby/redundant pump may be temporarily aligned to an alternate Class 1E source, using installed transfer switches, until its primary Class 1E power supply is returned to service. If connection to the alternate vital bus via the transfer switch is necessary in Modes 1 through 4, Engineering will be required to evaluate the acceptability of this configuration on a case by case basis prior to use of the transfer switch. 9.1.3.2.1.2 Spent Fuel Pool Skimmer Pump The SFP skimmer pump is a horizontal centrifugal unit, with all wetted surfaces being stainless steel or an equivalent corrosion-resistant material. The pump is controlled manually from a local station. DCPP UNITS 1 & 2 FSAR UPDATE 9.1-17 Revision 21 September 2013 9.1.3.2.1.3 Refueling Water Purification Pump The RWP pump is a horizontal centrifugal unit, with all wetted surfaces being stainless steel or an equivalent corrosion-resistant material. The pump is operated manually from a local station. 9.1.3.2.1.4 Spent Fuel Pool Heat Exchanger The spent fuel heat exchanger is of the shell and U-tube type with the tubes welded to the tubesheet. Component cooling water (CCW) circulates through the shell, and SFP water circulates through the tubes. Construction is carbon steel on the shell-side and stainless steel on the tube side. 9.1.3.2.1.5 Spent Fuel Pool Demineralizer The SFP demineralizer is a flushable, mixed bed demineralizer. The demineralizer is designed to provide adequate fuel pool water purity and limit dose rates at the surface of the pool. 9.1.3.2.1.6 Spent Fuel Pool Resin Trap Filter The SFP resin trap filter is designed to prevent resin beads from entering the SFP and connected systems. It is designed to remove particles 5 microns or greater. 9.1.3.2.1.7 Spent Fuel Pool Filter The SFP filter is designed to improve the pool water clarity by removing particles 5 microns or greater. 9.1.3.2.1.8 Spent Fuel Pool Skimmer Filter The SFP skimmer filter is used to remove particles that are not removed by the strainer. It is designed to remove particles 5 microns or greater. 9.1.3.2.1.9 Refueling Water Purification Filter The RWP filter is designed to improve the clarity of the refueling water in the refueling canal or in the RWST by removing particles 5 microns or greater. The RWP filter also filters the SFP contents and functions as a prefilter to the SFP demineralizer. 9.1.3.2.1.10 Spent Fuel Pool Strainer A strainer is located within the SFP on the pump suction enclosure for removal of relatively large particles, which might otherwise clog the SFP demineralizer or damage the SFP pump. It is a slotted screen design with stainless steel construction.
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-18 Revision 21 September 2013 9.1.3.2.1.11 Spent Fuel Pool Skimmer Strainer The SFP skimmer strainer is designed to remove debris from the skimmer process flow. It is an in-line basket strainer of stainless steel construction. 9.1.3.2.1.12 Spent Fuel Pool Skimmers Two SFP skimmers are provided to remove water from the surface of the SFP. The skimmer heads are manually positioned to take water from any elevation from the water surface to 4 inches below the surface. The skimmer, pipe, and supports are of stainless steel construction. 9.1.3.2.2 Valves Manual stop valves are used to isolate equipment, and manual throttle valves provide flow control. Valves in contact with SFP water are austenitic stainless steel or equivalent corrosion-resistant material. 9.1.3.2.3 Piping All piping in contact with SFP water is austenitic stainless steel. The piping is welded except where flanged connections are used to facilitate maintenance. 9.1.3.3 Safety Evaluation 9.1.3.3.1 Availability and Reliability The SFP cooling and cleanup system has no emergency function during an accident. This manually controlled system may be shut down for limited periods of time for maintenance or replacement of components. Redundancy of the SFP cooling and cleanup system components is not required because of the large heat capacity of the pool and the slow heatup rate. In the unlikely event that the SFP pump should fail, the backup pump can provide circulation of the pool water through the SFP heat exchanger. If a failure should occur that would prevent the use of the SFP heat exchanger for cooling the SFP water (e.g., severance of the piping which constitutes the cooling recirculation path), natural surface cooling would maintain the water temperature at or below the boiling point. A Design Class I backup makeup water source is provided to ensure that the water level in the SFP can be maintained.
In the event of cooling system failure, exhaust filters of the fuel handling area ventilation system will be tested after the period of emergency conditions described above occurs. The filter efficiency tests will be conducted in accordance with the fuel handling area ventilation system testing requirements discussed in Section 9.4.4.4. These tests will be performed in addition to the periodic testing described in the Plant Surveillance Test Procedure. DCPP UNITS 1 & 2 FSAR UPDATE 9.1-19 Revision 21 September 2013 9.1.3.3.2 Spent Fuel Pool Dewatering The most serious failure of this system would be complete loss of water in the storage pool. To protect against this possibility, the SFP cooling suction connection enters near the normal water level so that the pool cannot be gravity-drained. The cooling water return line contains an antisiphon hole to prevent the possibility of gravity draining the pool. 9.1.3.3.3 Water Quality Only a very small amount of water is interchanged between the refueling canal and the SFP while fuel assemblies are transferred in the refueling process. Whenever a leaking fuel assembly is transferred from the fuel transfer canal to the spent fuel storage pool, a small quantity of fission products may enter the spent fuel cooling water. The purification loop removes fission products and other contaminants from the water, thereby maintaining radioactivity concentration in the SFP water ALARA.
The SFP water meets the following water quality requirements:
Boric acid, ppm as boron, minimum 2000 pH at 77°F 4.1 to 8.0 Chloride, ppm maximum 0.15 Fluoride, ppm maximum 0.15
Boron concentrations in the SFP water are maintained as discussed in the Technical Specifications, and the pH of SFP water is controlled to prevent separation of top nozzles from a fuel assembly as a result of intergranular stress corrosion cracking. During refueling operations when the SFP water mixes through the fuel transfer tube with the reactor refueling cavity water, SFP chemistry is controlled to ensure compatibility with the Reactor Coolant System (RCS) and Residual Heat Removal system chemistry requirements to preclude a boron dilution accident.
During cask loading operations in the SFP, boron concentrations in the MPC cavity are maintained in accordance with the Diablo Canyon ISFSI Technical Specifications. For an MPC-32 loaded with one or more 5.0 wt-percent enriched fuel assemblies, a boron concentration in the MPC of 2600 ppm or greater is required. Boration levels up to 3,000 ppm in the MPC and SFP have been evaluated and determined to have no adverse effects on materials or thermal performance. 9.1.3.4 Inspection and Testing Requirements Active components of the SFP cooling and cleanup system are either in continuous or intermittent use during normal system operation. Periodic visual inspection and preventive maintenance are conducted using normal industry practice.
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-20 Revision 21 September 2013 9.1.3.5 Instrumentation Applications The instrumentation provided for the SFP cooling and cleanup system is discussed below. Alarms and indications are provided as noted. 9.1.3.5.1 Temperature Local instrumentation is provided to measure the temperature of the water in the SFP and give local indication as well as annunciation in the control room when normal temperatures are exceeded.
Local instrumentation is also provided to give indication of the temperature of the SFP water as it leaves the SFP heat exchanger. 9.1.3.5.2 Pressure Local instrumentation is provided to measure and give indication of pressures across the SFP, RWP, and skimmer pumps. Instrumentation is also provided to measure pressure differential on the SFP filter, SFP demineralizer, SFP resin trap filter, RWP filter, and SFP skimmer filter and strainer. 9.1.3.5.3 Flow Local instrumentation is provided to measure and give indication of flows in the outlet line of the SFP filter and the inlet line to the SFP demineralizer.
9.1.3.5.4 Level Instrumentation is provided to give an alarm in the control room when the water level in the SFP reaches either the high or low level setpoint. In the event of high level in the pool, water can be removed via the SFP pump and pumped to the LHUTs. Water can also be removed by the RWP pump delivering to the RWST. In the event of low water level, makeup water can be transferred to the pool from either design class I or design class II sources as described in Section 9.1.3.2. 9.1.3.6 Temporary Backup SFP Cooling System The temporary backup SFP cooling system is a common system for both Units. The temporary backup system is not credited in any safety analysis for SFP cooling. The backup cooling for the SFPs is evaporation with makeup water capabilities. The backup SFP cooling system is a defense in-depth system. 9.1.3.6.1 System Description The backup SFP cooling system is a temporary system of pumps, piping and hoses that may be deployed and placed in service if a SFP heat exchanger is unavailable. The DCPP UNITS 1 & 2 FSAR UPDATE 9.1-21 Revision 21 September 2013 system uses temporary pumps (up to 3), piping, and hoses to pump the warmer water from the SFP with the out of service heat exchanger to the SFP with an available heat exchanger. An identical system is used to pump cool water from SFP with the available heat exchanger to the SFP with the unavailable heat exchanger. This system will be used to increase the time to boil in the SFP with the out-of-service SFP heat exchanger and maintain proper SFP levels. Staging, deployment, and operation of the temporary backup SFP cooling system is controlled by plant maintenance and operating procedures.
When the temporary backup SFP cooling system is installed, the submersible pumps are set in a support cage with the bottom of the pump not lower than elevation 137 feet. This limits the pump minimum operating water level to approximately elevation 137 feet 5 inches. The recirculating water discharges into the SFP of the opposite unit through a vertical discharge pipe which terminates at approximately elevation 137 feet. Anti-siphoning holes are provided in the discharge pipe at elevation 137 feet 5 inches.
The pumps, piping, and wetted parts of the temporary hoses are stainless steel. Power for the pumps is taken from local 480V receptacles.
When the temporary cooling system is installed, doors between the fuel pool areas and the hot machine shop are open to route the temporary piping and hoses between the two SFPs. 9.1.3.6.2 Safety Evaluation 9.1.3.6.2.1 Availability and Reliability The temporary backup SFP cooling system will be available on the plant site, ready for deployment and installation, prior to a SFP heat exchanger being cleared for maintenance or inspection; or prior to fuel movement during a refueling outage. Since the temporary backup cooling system is to support risk management during maintenance and inspection of the SFP heat exchanger, and as backup cooling to the permanent SFP cooling system, redundancy of the temporary system is not required. Operation of the system is procedurally controlled to require frequent monitoring for flow, leakage, SFP pool levels, and SFP water temperatures.
If a failure should occur that would prevent the use of the temporary backup SFP cooling system, natural surface cooling would maintain the water temperature at or below the boiling point. A Design Class I backup makeup water source is provided to ensure that the water level in the SFP can be maintained. 9.1.3.6.2.2 Spent Fuel Pool Dewatering To protect against the possibility of significant loss of water in the SFPs, the submersible pumps will start cavitating and eventually stop pumping when the water DCPP UNITS 1 & 2 FSAR UPDATE 9.1-22 Revision 21 September 2013 level is below elevation 137 feet 5 inches. The anti-siphoning holes in the discharge pipes will prevent draining of the pools below elevation 137 feet 5 inches. At elevation 137 feet 5 inches the SFP water level is more than 23 feet above the top of the fuel assemblies. 9.1.3.6.3 Inspection and Testing Requirements The components of the temporary backup cooling system are normally stored at a dedicated location. Periodic visual inspection and preventive maintenance of the components, prior to and during deployment, are conducted in accordance with plant procedures. 9.1.3.6.4 Instrumentation Applications The instrumentation provided for the temporary backup SFP cooling system is discussed below. 9.1.3.6.4.1 Temperature Local temporary instrumentation is provided to monitor the temperature of the water in both SFPs when the backup SFP cooling system is in use during inspection and maintenance of the permanent SFP system. 9.1.3.6.4.2 Flow Local temporary flow indication is provided to indicate that flow exists in the backup SFP cooling system when it is in use. 9.1.3.6.4.3 Level The SFP level instrumentation provided for the permanent SFP cooling system is also applicable for use with the backup SFP cooling system. 9.1.4 FUEL HANDLING SYSTEM The fuel handling system (FHS) consists of equipment and structures utilized for handling new and spent fuel assemblies in a safe manner during refueling and fuel transfer and cask loading operations. Refueling and related fuel transfer operations are described and evaluated in Sections 9.1.4.1 through 9.1.4.4. Cask loading operations for transfer of spent fuel from the SFP to the Diablo Canyon ISFSI are described in Sections 9.1.4.5 through 9.1.4.8. 9.1.4.1 Design Bases - Refueling and Fuel Transfer Operations The following design bases apply to the FHS:
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-23 Revision 21 September 2013 (1) Fuel handling devices have provisions to avoid dropping or jamming of fuel assemblies during transfer operations. (2) Fuel lifting and handling devices are capable of supporting maximum loads under seismic conditions. The fuel handling equipment will not fail so as to cause damage to any fuel elements should the seismic event occur during a refueling operation. The earthquake loading of the fuel handling equipment is evaluated in accordance with the seismic considerations addressed in Section 9.1.4.3.2. (3) The fuel transfer system, where it penetrates the containment, has provisions to preserve the integrity of the containment pressure boundary. (4) Cranes and hoists used to lift spent fuel assemblies have a limited maximum lift height so that the minimum required depth of water shielding is maintained. 9.1.4.2 System Description - Refueling and Fuel Transfer Operations The FHS equipment needed for the refueling of the reactor core consists of cranes, lifting and handling devices including tools, and a fuel transfer system. The structures associated with the fuel handling equipment are the refueling cavity, the refueling canal, the spent fuel storage pool, and the new fuel storage area.
The reactor is refueled with fuel handling equipment designed to handle the spent fuel under water from the time it leaves the reactor vessel until it is placed in the SFP racks. Underwater transfer of spent fuel provides an effective, economic, and transparent radiation shield as well as a reliable cooling medium for removal of decay heat. Boric acid is added to the water to ensure subcritical conditions.
The associated fuel handling structures may be generally divided into three areas: (a) the refueling cavity and refueling canal which are flooded only during plant shutdown for refueling, (b) the SFP which is kept full of water and is always accessible to operating personnel, and (c) the new fuel storage area which is separate and protected for dry storage. The refueling canal and the SFP are connected by the fuel transfer tube. This tube is fitted with a quick opening hatch on the canal end and a gate valve on the SFP end. The quick opening hatch is in place, except during refueling, to ensure containment integrity.
Plant procedures do not permit more than one fuel assembly to be out of storage or in transit between its associated shipping cask and dry storage rack at one time. The new fuel containers are unloaded from the shipping vehicle and placed on the 115 foot elevation using the fuel handling area crane. New fuel assemblies are removed one at a time from the shipping containers using the new fuel handling tool and the spent fuel bridge hoist such that only one fuel assembly is moved or suspended at a time in a specific area. The assemblies are stored either in the new fuel storage racks in the fuel DCPP UNITS 1 & 2 FSAR UPDATE 9.1-24 Revision 21 September 2013 storage area or in the SFP. Each assembly is inspected for possible shipping damage prior to insertion into the reactor core.
New fuel is delivered to the reactor by first transferring the fuel with the spent fuel bridge hoist to the new fuel elevator. The fuel is lowered into the SFP where the spent fuel handling tool is interchanged with the new fuel tool. The assembly is then stored in the SFP or transferred to the upender for movement to the reactor.
The upender at either end of the fuel transfer tube is used to pivot a fuel assembly to the horizontal position for passage through the transfer tube. Fuel is carried through the tube on a transfer car. After the transfer car transports the fuel assembly through the transfer tube, the upender at that end of the tube pivots the assembly to a vertical position so that it can be lifted out of the fuel container. Fuel is moved between locations in the reactor vessel and the transfer mechanism by the manipulator crane.
In the SFP, fuel assemblies are moved about by the SFP bridge hoist. A long-handled tool is used with the bridge hoist to prevent the lifting of fuel assemblies any closer than 8 feet from the SFP surface; this ensures that sufficient radiation shielding is maintained. A shorter tool is used to handle new fuel, but the new fuel elevator must be used to lower the assembly to a depth at which the hoist and the long-handled tool can be used to place the new assembly into the upender or into a SFP cell.
When fuel repair or post-irradiation examinations are necessary, the fuel assemblies are reconstituted in the new fuel elevator. The new fuel elevator is modified temporarily by the insertion of hard stops and resetting the upper electrical limit switch to prevent raising the irradiated fuel assemblies to within eight feet of the SFP surface. The SFP bridge hoist is utilized to transfer fuel rods within the SFP. The tooling on the hoist is configured to maintain nine feet of water shielding over the active fuel.
Decay heat, generated by the spent fuel assemblies in the SFP, is removed by the SFP cooling and cleanup system.
The decontamination area has a stainless-steel-lined base, and a curb is provided around it to prevent the water and solvents used during decontamination from spreading over the building floor. Drains in the floor of the area remove the decontaminants to the waste disposal system for processing. 9.1.4.2.1 Component Description The following sections describe major components of the FHS as they relate to refueling and fuel transfer operations. 9.1.4.2.1.1 Manipulator Crane The manipulator crane shown in Figure 9.1-8 is a rectilinear bridge and trolley crane with a vertical mast extending down into the refueling water. The bridge spans the DCPP UNITS 1 & 2 FSAR UPDATE 9.1-25 Revision 21 September 2013 refueling cavity and runs on rails set into the edge of the refueling cavity. The bridge and trolley motions are used to position the vertical mast over a fuel assembly. A long tube with a pneumatic gripper on the end is lowered down out of the mast to grip the fuel assembly. The gripper tube is long enough so that the upper end is still contained in the mast when the gripper end contacts the fuel. A winch mounted on the trolley raises the gripper tube and fuel assembly up into the mast tube. While inside the mast tube, the fuel is transported to its new position.
All controls for the manipulator crane are mounted on a console on the trolley. The bridge is positioned on a coordinate system laid out on one rail. A video indexing system with a camera mounted to the bridge, over an indicating scale, and a monitor on the console indicates the position of the bridge. The trolley is positioned with the aid of a scale on the bridge structure. The scale is read directly by the operator at the console. The drives for the bridge, trolley, and winch are variable speed and include a separate inching control on the winch. Electrical interlocks and limit switches on the bridge and trolley drives prevent damage to the fuel assemblies. The winch is provided with a limit switch and a backup programmable limit switch to prevent a fuel assembly from being raised above a safe shielding depth. In an emergency, the bridge, trolley, and winch can be operated manually by means of handwheels on the motor shafts.
The manipulator crane structure is designed for Class C, Moderate Service, as defined by the Overhead Electric Crane Institute Specification No. 61. The electrical interlocks that ensure safe operation are designed to meet the single failure criteria of IEEE-279 (Reference 4). The electrical wiring meets the applicable requirements of the National Fire Code, Electrical, Volume 5, Article 610. The design of the crane meets the applicable requirements of Section 1910.179 of subpart N of the OSHA Code. The bridge, trolley, and hoist drive motors are NEMA Class D induction motors with Class H insulation. The hoist rope is stainless steel, and the load rating is sufficient to support five times the design load. The crane design class is provided in the DCPP Q-List (see Reference 8 of Section 3.2).
The manipulator crane design load is the dead weight plus 4500 lb (three times the fuel assembly weight). The crane was erected in the shop and given a complete functional test including a load test at 110 percent of the design load. The maximum operating load of fuel assembly plus gripper is approximately 2500 lb. Test loads during the life of the facility will be in accordance with requirements established by the State of California Division of Occupational Safety and Health as part of its responsibilities for implementing OSHA in the state. 9.1.4.2.1.2 Spent Fuel Pool Bridge The SFP bridge, shown in Figure 9.1-9, is a wheel-mounted walkway spanning the SFP and carrying two monorail hoists on an overhead structure. One hoist has a maximum lift capability of 21 feet. The second hoist has a lift capability of 61 feet. This hoist is used for maintenance of the fuel transfer system and for removing new fuel assemblies from their shipping containers. Fuel assemblies are moved within the SFP by means of DCPP UNITS 1 & 2 FSAR UPDATE 9.1-26 Revision 21 September 2013 a long-handled tool suspended from either hoist. The bridge, trolley, and hoists are all electrically driven. The maximum lift of either hoist, combined with the long-handled tool length, is designed to maintain a safe shielding depth above a spent fuel assembly within the pool.
For fuel repairs and post-irradiation examinations, the fuel rod handling tool configuration on the hoist is required to be physically verified to maintain nine feet of water shielding in the SFP prior to handling irradiated fuel rods. The fuel rod handling tool configuration on the hoist will be controlled by an approved procedure.
The design class of the bridge is given in the DCPP Q-List (see Reference 8 of Section 3.2). 9.1.4.2.1.3 Fuel Handling Area Crane The fuel handling area crane is an overhead bridge crane located in the fuel handling area at elevation 170 feet. This crane, shown in Figure 3.8-59, has a 125 ton capacity main hook for handling spent fuel casks and a 15 ton capacity auxiliary hook for handling new fuel shipping containers. The crane structures and components responsible for lifting of the maximum critical load and distribution of the load to the fuel handling building superstructure have been upgraded to meet single-failure-proof criteria through the replacement of the original trolley and reanalysis of existing structures retained in the new design.
Structural, mechanical, and electrical design is in accordance with ASME NOG-1, as conformed to the requirements of NUREG-0554 per the guidance of NUREG-0612, Appendix C. Furthermore, the crane structural design has been demonstrated to envelope the structural requirements of the original design codes as enumerated below. The main hoist, trolley, and bridge members meet ASME NOG-1, Type I, design standards. Original bridge members and components retained for the current single-failure-proof design has been reanalyzed and inspected in accordance with the guidance provided by NUREG-0612, Appendix C. The 15-ton auxiliary hoist meets ASME NOG-1, Type II standards and therefore is not considered as single-failure-proof.
The crane was originally designed and fabricated to the Specification for Electrical Overhead Traveling Cranes for Steel Mill Service, Association of Iron and Steel Engineers Standard No. 6 (tentative) dated May 1, 1969. All members not covered by that standard are designed and fabricated in accordance with the Specification for the Design, Fabrication and Erection of Structural Steel for Buildings by the American Institute of Steel Construction (AISC), dated February 12, 1969.
The electrical installation and all electrical equipment is in accordance with the National Electrical Code dated 1968, and the National Electrical Manufacturers Association.
Design, fabrication, and erection of the crane rail and crane support structure is in accordance with the AISC specifications. The fuel handling area crane complies with DCPP UNITS 1 & 2 FSAR UPDATE 9.1-27 Revision 21 September 2013 the requirements of OSHA Subpart N, Materials Handling and Storage, of 29 CFR 1910, Section 1910.179.
The integrity of the crane load transfer path is ensured by the following measures:
(1) The main hoist sister hook is designed such that the loads imposed by the maximum critical load at both the pin location and the hooks result in factors of safety of 3.45 against yield strength of the hook material. The application of the maximum critical load (MCL) is considered to be fully carried by each of the attachment points. Stresses in the shank and nut are designed to remain below levels resulting in a factor of safety of 10 against the ultimate strength of the hook and nut material. (2) The main hook and nut is shop tested at 2 times the maximum critical load. (3) Following the shop test, the main hook receives a volumetric and liquid penetrant inspection. (4) The main hoist hooks and auxiliary hoist hook are field tested for 10 minutes at 1-1/4 times their rated loads. (5) The main hoist ropes are designed with greater than 10:1 safety factor against breaking strength. They are part of a four part double reeving system that is designed to withstand the loss of any one of the four ropes without the loss of function and without significant vertical motion of the MCL.
(6) All components in the load transference path that must retain their structural integrity are considered to be Critical Items as defined by NOG-1. These Critical Items have material traceability and are subject to appropriate non-destructive examination to provide assurance against material failure. (7) The crane is equipped with redundant main hoist drive trains, brakes and reeving. The failure of any one component in the reeving or drive train will not result in a load drop or excessive vertical motion of the load. (8) The electrical power supply to the crane contains a means for automatic disconnection should a seismic event occur. The loss of power results in the brakes setting to retain any load that may be currently lifted and assures that un-commanded motion due to relay chatter or other interaction will not occur. An emergency lowering procedure is available should this be necessary. (9) The crane is equipped with redundant protections against overload. A trip signal is provided from the weight monitoring system, which provide direct DCPP UNITS 1 & 2 FSAR UPDATE 9.1-28 Revision 21 September 2013 indication, as well as the main hoist variable frequency drive control system, which provides load sensing by monitoring the motor torque. (10) The crane is equipped with redundant protections against two-blocking. The first line of protection is provided by a limit switch that provides a trip signal if the bottom block approaches a two-block condition. The second level of protection is provided by the weight monitoring system, which will provide a trip signal if sensed load exceeds a preset value. A third level of protection is provided by the upper block hydraulic support system, which is designed to mitigate the loadings created during an actual two-block event. The upper block pivot arm limit switch functions to assure hoist motion is stopped prior to the end of hydraulic cylinder travel. The two-block protection system is fully shop tested at each protection level to verify the effectiveness of the system. (11) The crane has been subjected to a Cold Proof Test as allowed in NUREG-0554, since verification of the Nil Ductility Transition characteristics of the existing bridge components is not available. The Cold Proof Test provides assurance that the crane will not fail due to brittle fracture. The operation of the crane is administratively controlled such that crane operations are not allowed when the structure temperature is below the temperature at which the Cold Proof Test has been performed. Conservative fleet angles, drum diameter and sheave diameter are utilized in the design in accordance with NOG-1 and NUREG-0554. These conservative design parameters assure wear and fatigue of the ropes is minimized. The hoisting ropes are 1-1/2 inch Python Power 9 V EEIPS with a 172.8 ton breaking strength. The hoisting rope for the main hook is stainless steel. The hoisting rope for the auxiliary hook is 3/8 inch Python stainless steel with a breaking strength of 11.2 tons.
Each hoist drive has two brakes, one with time delay application. These brakes are automatically, mechanically applied in the absence of motion command or crane power. A regenerative type brake is also supplied to provide controlled lowering of a load should the main hoist motor fail to operate. Should the regenerative brake fail, emergency lowering procedures utilizing controlled manual release of the redundant mechanical brakes are available. All hoist brakes are rated at 150 percent of maximum torque that can be developed by its respective system. Trolley and bridge brakes are rated at 100 percent of motor full load torque. The bridge and trolley braking systems are manually adjusted to allow motion in the N-S and E-W directions during a seismic event. The brake adjustment is administratively controlled and is required to ensure the qualification of the fuel handling building superstructure. A vertical stop is provided along the entire length of the runway to prevent bridge uplift and derailing. Vertical restraints are also provided on the trolley to prevent uplift and derailing.
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-29 Revision 21 September 2013 The fuel handling area crane is equipped with a skeleton cab containing a control console chair. The crane may also be controlled by a radio remote control, which may be harness mounted and worn by the operator. Transfer of operation of the crane to the remote control is provided by a control chair mounted transfer switch.
The fuel handling area crane is also used to relocate the movable partition walls, which function to segregate the Unit 1 and Unit 2 spent fuel pool areas from the hot shop as described in Section 9.1.4.2.1.4. The crane control chair and radio remote control are equipped with switches to latch and unlatch the mechanism connecting the partition walls to the crane bridge structure. Indication of a latched condition is provided in two locations on the underside of the bridge girders.
Following erection, the hooks, lifting mechanisms, cables, brakes, trolleys, and structural members of the fuel handling area crane are tested at 1/2, 3/4, 1, and 1-1/4 times the rated load. The test loads are maintained for a minimum of 10 minutes prior to changing to a different load.
During fabrication of the upgraded trolley assembly, each hoist was functionally load tested at 1 times the rated load and proof load tested at 1-1/4 times the rated load. The emergency manual load lowering function of the main hoist was tested at 1 times the rated load. Following installation atop the existing bridge crane girders, each hoist was proof load tested at 1-1/4 times the rated load. During the site proof load test of each hoist, the trolley and bridge motions were also tested to the maximum extent practicable.
The State of California assumed responsibility for the implementation of OSHA on January 1, 1974. The crane test loads to be used throughout the life of the facility will meet specific regulations for such loads, as established by the California Division of Industrial Safety.
The conservative design stress limits and redundant design features afforded by the single-failure-proof trolley and reanalyzed crane structures provide the added reliability to justify considering the crane as single-failure-proof. Nonetheless, the travel of both hooks over the SFP is restricted as described in Section 9.1.2. 9.1.4.2.1.4 Fuel Handling Area Movable Partition Walls Movable partition walls allow the fuel handling area crane access to the fuel handling areas for both units and to the hot shop area, while maintaining proper operation of the fuel handling area heating and ventilation systems. The fuel handling area heating and ventilation systems are described in Section 9.4.4. Additionally, the moveable wall panel in Unit 1 and the moveable wall panel in Unit 2 (panel 1 and panel 4 as shown in Figure 9.1-19) are equipped with a monorail.
The fuel handling area crane may be used in the fuel handling area for Unit 1, the fuel handling area for Unit 2, or the hot shop area. Two movable partition walls are provided DCPP UNITS 1 & 2 FSAR UPDATE 9.1-30 Revision 21 September 2013 for the plant. These movable walls are repositioned when it is necessary to move the fuel handling area crane from one area to another. This repositioning is accomplished prior to the start of any fuel handling operations. The location of the movable partition walls is shown in Figure 9.1-19. Figure 9.1-20 shows a movable partition wall in place along either column line 157 or column line 203 where the wall serves to isolate the fuel handling area heating and ventilation systems from the hot shop area.
A monorail is attached to the side of the moveable wall panels, each with a capacity of 4000 pounds. Travel is limited to the eastern end of these monorails to prevent the lifting of heavy loads over spent fuel. Any lifting of items in the western portions will be administratively controlled by the Control of Heavy Loads Program (Section 9.1.4.3.5).
The movable partition walls travel on wheels on the same rail track used by the fuel handling area crane. A movable partition wall is moved by securely attaching it to the fuel handling area crane and moving both the crane and the movable partition wall along the track as an integrated unit.
All members are designed as described in Section 3.8.2. The applicable code used in the design and fabrication is the Specification for the Design Fabrication and Erection of Structural Steel for Buildings, AISC, February 12, 1969. The moveable wall panels have been evaluated for a Hosgri earthquake concurrent with a maximum lifted load attached.
Wheels for the movable partition walls are double flanged. Additional assurance that derailing cannot take place is provided by a vertical stop running the entire length of each track. Details showing the movable partition wall, track, and vertical stop are shown in Figure 9.1-21. 9.1.4.2.1.5 Containment Structure Polar Crane The containment structure polar crane (one for each unit) is an overhead gantry crane located on top of the circular crane wall at elevation 140 feet. This polar crane has a main hook capacity of 200 tons and an auxiliary hook capacity of 35 tons. In addition to the main and auxiliary hooks, the polar crane is equipped with a dome service crane. The dome service crane has a manbasket rated at 750 pounds to lift tools and personnel for inspection and maintenance of the spray ring headers and upper containment structure. It also has an auxiliary hoist rated at 1950 pounds. The arrangement for the polar crane is shown in Figure 3.8-23.
Structural design is in accordance with the Specification for Electrical Overhead Traveling Cranes for Steel Mill Service, Association of Iron and Steel Engineers Standard No. 6 (tentative) dated May 1, 1969. All members not covered by that standard are designed according to the Specification for the Design, Fabrication, and Erection of Structural Steel for Buildings, AISC, dated February 12, 1969.
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-31 Revision 21 September 2013 The electrical installation and all electrical equipment is in accordance with the National Electrical Code, dated 1968, and the National Electrical Manufacturers Association. The containment structure polar crane complies with the requirement of OSHA Subpart N, Materials and Handling Storage, of 29 CFR 1910, Section 1910.179. Fabrication and erection of the crane support rail is in accordance with the AISC specifications. Design, fabrication, and erection of the concrete supporting structure is described in Section 3.8.1.
The integrity of the crane hooks is ensured by the following measures:
(1) Stresses in the hooks and all other mechanical parts are limited to 80 percent of yield strength for the effect of maximum torque of the motors, braking, or collision of the trolley against the rail stops. (2) Each hook is shop tested at 1-1/2 times its rated load. (3) Following the shop test, each hook is magnetic particle inspected. (4) Both hooks are field tested for 10 minutes at 1/2, 3/4, and 1-1/4 times the rated loads.
The pitch diameter of running sheaves is required to be not less than 24 times the nominal rope diameter. Likewise, the drum diameter is required to be not less than 24 times the nominal rope diameter.
The hoisting ropes are 6 x 37, uncoated, extra flexible, preformed, improved plow steel rope with hemp core or independent wire rope core. The maximum calculated stress in the ropes considering the efficiency of the reeving and weight of the blocks in addition to the crane rated load, is limited to 1/6 of the manufacturer's specified breaking strength.
The entire reeving system is designed so that minimum and commonly accepted fleet angles are maintained, and the rope is guarded against leaving the drum grooves or sheaves.
Each hoist drive on the Unit 1 and Unit 2 polar crane has two sets of brakes. The primary set is an alternating current, quick acting brake and the secondary set is a direct current, inherently slower acting brake. All these brakes are automatic and mechanically applied when the current to the motors is cut off. All hoist brakes are rated at 150 percent of maximum torque that can be developed by its respective system. Trolley and gantry brakes are rated at 100 percent of motor full load torque.
After installation, the gantry legs and beam were tested as a structure (without running gear) with a load of 414 tons for 1 hour. With a 250 ton load, two 10-minute lifts plus gantry and trolley travel tests of the assembled crane were conducted. The maximum operating load for the containment polar crane will be 185 tons. As for the fuel handling area crane, the crane test loads to be used throughout the life of the facility will meet the DCPP UNITS 1 & 2 FSAR UPDATE 9.1-32 Revision 21 September 2013 specific regulations for such loads, as established by the California Division of Industrial Safety.
The conservative design stress limits, the dual braking system, the preoperational tests and the test loads used throughout the life of the facility all combine to provide assurance against the modes of failure that otherwise might be assigned to a gantry crane. Nonetheless, the travel of both hooks over the opened reactor vessel is restricted and controlled by administrative procedures.
During plant operation, the polar crane is parked unlocked and provided with guides to prevent derailment due to a seismic event. The guides resist horizontal shear normal to the crane rails. The crane rail is anchored continuously to the concrete by special clamps, capable of resisting forces due to an earthquake. 9.1.4.2.1.6 New Fuel Elevator The new fuel elevator shown in Figure 9.1-10 consists of a box-shaped elevator assembly with its top end open and sized to house one fuel assembly. Depth of the structure is slightly less than the overall length of the fuel assembly, which rests on the bottom plate. The design class of the new fuel elevator is listed in the DCPP Q-List (see Reference 8 of Section 3.2).
The new fuel elevator is used to lower a new fuel assembly to the bottom of the SFP where it is transported to the fuel transfer system by the SFP bridge hoist. It is also used to raise the dummy fuel assembly out of the SFP for transfer between units and occasionally for raising a newly received assembly to the surface for additional inspection. The new fuel elevator can also be used for handling a spent fuel assembly, for example, during fuel assembly repair or post-irradiation examinations. The restriction imposed by the minimum water shielding requires that:
(1) Administrative controls are imposed to maintain an adequate submergence. (2) The upper limit switch is adjusted to trip the hoist at a lower elevation to ensure adequate submergence. (3) Mechanical stops are installed prior to insertion of a spent fuel assembly in the new fuel elevator to physically limit the raising of the elevator to ensure minimum submergence. (4) No other fuel assembly movement is allowed in the SFP while an assembly is in the new fuel elevator.
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-33 Revision 21 September 2013 9.1.4.2.1.7 Fuel Transfer System The fuel transfer system (Figure 9.1-11) includes a transfer car that runs on tracks extending from the refueling canal through the transfer tube into the SFP and an upender lifting frame at each end of the transfer tube. The upender in the refueling canal receives a fuel assembly in the vertical position from the manipulator crane. The fuel assembly is then pivoted to a horizontal position for passage through the transfer tube and pivoted to a vertical position by the upender in the SFP. The SFP bridge hoist takes the fuel assembly to a position in the spent fuel storage racks.
A quick opening hatch is used to close the refueling canal end of the transfer tube to seal the reactor containment. The terminus of the tube outside the containment is closed by a gate valve. The design class of the fuel transfer system is given in the DCPP Q-List. (see Reference 8 of Section 3.2) 9.1.4.2.1.8 Rod Cluster Control Changing Rod cluster control (RCC) elements inside containment are transferred from one fuel assembly to another by the RCC changing fixture shown in Figure 9.1-12. The five major subassemblies of the changing fixture are: frame and track structure, carriage, guide tube, gripper, and drive mechanism. The carriage is a movable container supported by the frame and track structure. The tracks provide a guide for the four flanged carriage wheels and allow horizontal movement of the carriage during changing operations. Positioning stops on both the carriage and frame locate each of the three carriage compartments directly below the guide tube. Two of these compartments hold individual fuel assemblies while the third supports a single RCC element. The guide tube, situated above the carriage and mounted on the refueling canal wall, provides for the guidance and proper orientation of the gripper and RCC element as they are being raised or lowered. The pneumatically actuated gripper engages the RCC element. Two flexure fingers can be inserted into the top of the RCC element when air pressure is applied to the gripper piston. Normally, the fingers are locked in a radially extended position. Mounted on the operating deck, the drive mechanism assembly includes the manual carriage drive mechanism, revolving stop operating handle, pneumatic selector valve for actuating the gripper piston, and electric hoist for elevation control of the gripper. The fixture is located in the containment refueling canal. The design class of the RCC changing fixture is Design Class II.
RCCAs in the SFP are transferred from one fuel assembly to another by the RCC changing tool shown in Figure 9.1-12a. The RCC changing tool is portable and functions in a manner similar to the RCC changing fixture described above. This tool is suspended from the SFP bridge crane hoist and is operated from the bridge crane walkway. The tool is lowered by the bridge hoist until it rests upon the nozzle of the desired fuel assembly seated in the spent fuel storage rack. The gripper actuator is then lowered and latched onto the RCC spider which allows the entire RCC to be drawn up inside the guide tube of the tool. Once this operation is completed, the tool may be repositioned over another fuel assembly. The above process is then reversed for DCPP UNITS 1 & 2 FSAR UPDATE 9.1-34 Revision 21 September 2013 reinsertion of the RCC. The RCC changing tool is Design Class II and is stored on the wall of the fuel transfer canal or SFP as needed. The tool consists of three basic assemblies: the guide tube, the support tube, and the drive mechanism.
The guide tube is similar to that in the RCC changing fixture described above. It is the square cross-sectioned tube at the bottom of the tool. Guide plates are provided over the entire length of the tube to prevent damaging the rod clusters and to properly align the gripper. The gripper actuator is also contained within the guide tube. It is a pneumatic device, which operates the gripper from an air hose reaching through the support tube to the drive mechanism. Two limit switches provide upper and lower limits for the motion of the unit. The bottom of the guide tube is equipped with guide pins to insure alignment of the tool with the fuel assembly.
Above the guide tube is the support tube, which gives the proper length to the tool, provides support for the gripper actuator, and supplies protection for the lift cable. Also enclosed within the support tube are the air hose for the gripper and the electrical cable for the limit switches. To prevent tangling of the hose and cable, the cable has been placed inside the coiled air hose with seals at each end to allow separation of the two.
The drive mechanism, at the top of the tool, consists of a winch powered by an ac electric motor, the operator's panel, and four limit switches. One of the limit switches provides overload protection in the event of an RCC hang-up. The other three are geared limit switches; two providing upper and lower limits and the third controls the pneumatic system. 9.1.4.2.1.9 Spent Fuel Handling Tool The manually actuated spent fuel handling tool, shown in Figure 9.1-13, is used to handle new and spent fuel in the SFP. It is mounted on the end of a long pole suspended from the SFP bridge hoist. An operator on the SFP bridge guides and operates the tool. The tool is stored on the wall of the SFP. 9.1.4.2.1.10 New Fuel Assembly Handling Fixture The short-handled new fuel assembly handling fixture, shown in Figure 9.1-14, is used to handle new fuel on the operating deck of the fuel storage area, to remove the new fuel from the shipping container, and to facilitate inspection and storage of the new fuel and loading of fuel into the new fuel elevator. 9.1.4.2.1.11 Reactor Vessel Head Lifting Device The reactor vessel head lifting device, shown in Figure 9.1-15, consists of a welded and bolted structural steel frame with suitable rigging to enable the crane operator to lift the head and store it during refueling operations. The lifting lugs are permanently attached to the reactor vessel head. The design class of this device is given in the DCPP Q-List (see Reference 8 of Section 3.2). DCPP UNITS 1 & 2 FSAR UPDATE 9.1-35 Revision 21 September 2013 9.1.4.2.1.12 Reactor Internals Lifting Device The reactor internals lifting device, shown in Figure 9.1-16, is a structural frame suspended from the overhead crane. The frame is lowered onto the guide tube support plate of the internals, and is manually bolted to the support plate by three bolts. Bushings on the frame engage guide studs in the vessel flange to provide guidance during removal and replacement of the internals package. The device is stored on a Design Class II stand in the containment refueling canal. 9.1.4.2.1.13 Reactor Vessel Stud Tensioner Stud tensioners, shown in Figure 9.1-17, are employed to secure the head closure joint at every refueling. The stud tensioner is a hydraulically operated device that permits preloading and unloading of the reactor vessel closure studs at cold shutdown conditions. A hydraulic pumping unit operates the tensioners, which are hydraulically connected in series. 9.1.4.2.2 Tool Storage Locations and Supports The storage locations of miscellaneous fuel handling tools are shown in Figure 9.1-18. The design classifications for these locations (containment structure, fuel handling building, and support racks) are given in the DCPP Q-List (see Reference 8 of Section 3.2). Many of the major and miscellaneous tool supports are designed to meet Design Class I requirements. If not, the tools are stored in an area such that their failure or failure of their supports would not endanger plant operation or prevent safe plant shutdown during a seismic event. 9.1.4.2.3 Refueling Procedure The refueling operation follows a detailed procedure that provides a safe, efficient refueling operation. The following significant points are ensured by the refueling procedure:
(1) The refueling water and the reactor coolant contain a minimum of approximately 2000 ppm boron. This concentration, together with the negative reactivity of control rods, is sufficient to keep the core approximately 10 percent k/k subcritical during the refueling operations (Keff is limited to less than or equal to 0.95). It is also sufficient to maintain the core subcritical if all of the RCCAs were removed from the core. (2) The water level in the refueling cavity is high enough to keep the radiation levels within acceptable limits when the fuel assemblies are being removed from the core. This water also provides adequate cooling for the fuel assemblies during transfer operations.
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-36 Revision 21 September 2013 (3) The potential for grid strap damage during refueling operations is minimized by exercising care during the handling operations. Such care includes proper training of operators, ensuring adequate water clarity and lighting, confirmation of proper functioning and alignment of the fuel handling and transfer equipment, and implementation of appropriate fuel handling precautions. The refueling operation is divided into four major phases: (a) preparation, (b) reactor disassembly, (c) fuel handling, and (d) reactor assembly. A general description of a typical refueling operation through the four phases is given below:
(1) Phase I - Preparation The reactor is shut down and cooled to cold shutdown conditions with a minimum boron concentration of 2000 ppm in the reactor coolant and a Keff 0.95. Following a radiation survey, the containment is entered. At this time, the coolant level in the reactor vessel is lowered to a point slightly below the vessel flange. The fuel transfer equipment and manipulator crane are then checked for proper operation. (2) Phase II - Reactor Disassembly All cables, air ducts, and insulation are removed from the vessel head.
The refueling cavity is then prepared for flooding by sealing off the reactor cavity; checking the underwater lights, tools, and fuel transfer system; closing the refueling canal drain holes; and removing the quick opening hatch from the fuel transfer tube. With the refueling cavity prepared for flooding, the vessel head is unseated, raised, and placed on the head storage stand. Water from the RWST is pumped into the RCS causing the water to overflow into the refueling cavity. The control rod drive shafts are disconnected and, with the upper internals, removed from the vessel. The fuel assemblies and RCCAs are now free from obstructions, and the core is ready for refueling. Prior to moving the upper internals over fuel, each containment penetration will be in the following status: (a) Equipment hatch capable of being closed and held in place by a minimum of four bolts (b) One door in each air lock capable of being closed (c) Each penetration providing direct access from the containment atmosphere to the outside atmosphere will be capable of being closed by manual or automatic isolation valve, blind flange, or DCPP UNITS 1 & 2 FSAR UPDATE 9.1-37 Revision 21 September 2013 equivalent; or be capable of being closed by an operable automatic containment purge and exhaust valve. Otherwise, all operations involving movement of the upper internals over fuel will be suspended. (3) Phase III - Fuel Handling The refueling sequence consists of either a full core off-load or a partial core off-load and incore shuffle. The full core off-load consists of removing all of the fuel assemblies from the core, storing them in the SFP, and then returning the partially spent assemblies, as well as the new assemblies that replace the fully spent assemblies, to the core according to the final reload configuration. An incore shuffle consists of removing the fully spent fuel assemblies from the core to the SFP, rearranging the remaining partially spent assemblies in the core, and adding new assemblies to replace the removed fully spent assemblies. The general fuel handling sequence is: (a) The manipulator crane is positioned over a fuel assembly in the core. (b) The fuel assembly is lifted by the manipulator crane to a predetermined height to clear the reactor vessel and still leave sufficient water coverage to eliminate any radiation hazard to the operating personnel. (c) If the removed assembly contains a RCCA, the assembly may be placed in the RCCA changing fixture by the manipulator crane. The RCCA is removed from the spent fuel assembly and put in a new fuel assembly or in a partially spent fuel assembly. This activity may be performed in the RCCA changing fixture or in the SFP. (d) The fuel transfer car is moved into the refueling canal from the SFP. (e) The fuel assembly container is pivoted to the vertical position by the upender. (f) The manipulator crane is moved to line up the fuel assembly with the fuel transfer system. DCPP UNITS 1 & 2 FSAR UPDATE 9.1-38 Revision 21 September 2013 (g) The manipulator crane loads a fuel assembly into the fuel assembly container of the fuel transfer car. (h) The container is pivoted to the horizontal position by the upender. (i) The fuel container is moved through the fuel transfer tube to the SFP by the transfer car. (j) The fuel assembly container is pivoted to the vertical position. The fuel assembly is unloaded by the spent fuel handling tool attached to the SFP bridge hoist. Crane operations with loads over the SFP will be suspended with less than 23 feet of water over the top of irradiated fuel assemblies seated in the storage racks. The water level is specified in the Technical Specifications. Crane operations with loads containing recently irradiated fuel over the SFP will be suspended with no Fuel Handling Building Ventilation trains operable. Recently irradiated fuel is defined as fuel that has been part of a critical reactor within the last 100 hours. Crane operations with loads containing recently irradiated fuel over the SFP may proceed with one Fuel Handling Building ventilation train inoperable provided the operable train is capable of being powered from an operable emergency power source and is in operation and discharging through at least one train of HEPA filters and charcoal absorbers. (k) The fuel assembly is placed in the spent fuel storage rack. (l) The procedure for off-load is continued until all assemblies identified by the off-load procedure are removed. The core may be either partially or fully off-loaded. (m) On core reload, assemblies are moved from the SFP storage location (or the new fuel storage vault via the new fuel elevator) to the fuel assembly container according to the reload procedure, and the fuel assembly container is pivoted to the horizontal position and the transfer car is moved back into the refueling canal. (n) For an incore shuffle, partially spent fuel assemblies are relocated in the reactor core, and new fuel assemblies are added to the core. DCPP UNITS 1 & 2 FSAR UPDATE 9.1-39 Revision 21 September 2013 (o) Any new assembly or transferred fuel assembly that is placed in a control position may be placed in the RCC changing fixture or in the SFP to receive an RCC. (p) This procedure is continued until refueling is completed.
(4) Phase IV - Reactor Assembly Reactor assembly, following refueling, is essentially achieved by reversing the operations given in Phase II - Reactor Disassembly. 9.1.4.3 Safety Evaluation - Refueling and Fuel Transfer Operations Conformance with the requirements of Safety Guide Number 13 ensures safety under normal and postulated accident conditions.
9.1.4.3.1 Safe Handling Electrical interlocks (i.e., limit switches) are provided for minimizing the possibility of damage to the fuel during fuel handling operations. Mechanical stops are provided as the primary means of preventing fuel handling accidents. For example, safety aspects of the manipulator crane depend on the use of electrical interlocks and mechanical stops. The electrical interlocks for the manipulator are not specifically designed to the requirements of Reference 4 because of the primary dependence on mechanical stops.
The manipulator crane design includes the following provisions to ensure safe handling of fuel assemblies: (1) Bridge, trolley, and winch drives are mutually interlocked, using redundant interlocks, to prevent simultaneous operation of any two drives. (2) Bridge and trolley drive operation is prevented except when both gripper tubeup position switches are actuated. (3) An interlock is supplied that prevents the operation of either the engaging or disengaging solenoid valves unless the load and elevation requirements are satisfied. As backup protection for this interlock, the mechanical weight-actuated lock in the gripper prevents operation of the gripper under load even if air pressure is applied to the operating cylinder. (4) An excessive suspended weight switch opens the hoist drive circuit in the up direction when the loading is in excess of 110 percent of a fuel assembly weight. DCPP UNITS 1 & 2 FSAR UPDATE 9.1-40 Revision 21 September 2013 (5) An interlock of the hoist drive circuit in the up direction permits the hoist to be operated only when either the open or closed indicating switch on the gripper is actuated. (6) An interlock of the bridge and trolley drives prevents the bridge drive from traveling beyond the edge of the core unless the trolley is aligned with the refueling canal centerline. The trolley drive is locked out when the bridge is beyond the edge of the core. (7) Restraints are provided between the bridge and trolley structures and their respective rails to prevent derailing due to the Hosgri Earthquake. The manipulator crane is designed to prevent disengagement of a fuel assembly from the gripper under the DDE. (8) The main and auxiliary hoists are equipped with two independent braking systems. A solenoid release-spring set electric brake is mounted on the motor shaft. This brake operates in the normal manner to release upon application of current to the motor and set when current is interrupted. The second brake is a mechanically actuated load brake internal to the hoist gear box that sets if the load starts to overhaul the hoist. It is necessary to apply torque from the motor to raise or lower the load. In raising, the motor cams release the brake open; in lowering, the motor slips the brake allowing the load to lower. This brake actuates upon loss of torque from the motor for any reason and is not dependent on any electrical circuits. On the main hoist the motor brake is rated at 350 percent of operating load and the mechanical brake at 300 percent. The working load of fuel assembly plus gripper is approximately 2500 pounds.
The gripper itself has four fingers gripping the fuel, any two of which will support the fuel assembly weight.
The following safety features are provided for in the fuel transfer system control circuit:
(1) Transfer car operation is possible only when both upenders are in the down position as indicated by the limit switches. (2) The remote control panels have a permissive switch in the transfer car control circuit that prevents operation of the transfer car in either direction when either switch is open, i.e., with two remote control panels, one in the refueling canal and one in the SFP, the transfer car cannot be moved until both "go" switches on the panels are closed.
(3) An interlock allows upender operation only when the transfer car is at either end of its travel. DCPP UNITS 1 & 2 FSAR UPDATE 9.1-41 Revision 21 September 2013 (4) Transfer car operation is possible only when the transfer tube gate valve position switch indicates the valve is fully open. (5) The refueling canal upender is interlocked with the manipulator crane. The upender cannot be operated unless the manipulator crane gripper tube is in the fully retracted position or the crane is over the core. In the event of a power failure, no hazardous condition would exist during refueling or spent fuel handling. Electric motors associated with the manipulator crane, SFP bridge, fuel handling are a crane, fuel transfer system, and new fuel elevator have solenoid-actuated brakes capable of holding the rated loads during a power failure. When current is interrupted to the motor, the solenoid brake is spring set. During a power failure, a fuel assembly being handled would remain in the position held at the time of failure. 9.1.4.3.2 Seismic Considerations The maximum design stress for the fuel handling crane structures and for all parts involved in gripping, supporting, or hoisting the fuel assemblies is 1/5 ultimate strength of the material. This requirement applies to normal working load and emergency pullout loads, when specified, but not to earthquake loading. To resist earthquake forces, the fuel handling crane structures are designed to limit the stress in the load bearing parts to either 0.96 times the ultimate stress for a combination of normal working load plus DDE forces, or 1 times the ultimate strength for a combination of normal working load plus Hosgri earthquake forces, whichever is greater. To ensure the ability of the lifting and handling devices to support maximum loads under seismic conditions, the design safety factor of the lifting and handling devices has been evaluated against the actual calculated Hosgri loads. The evaluation indicates the inherent design safety factor is sufficient to envelope the combined normal working load plus DDE or Hosgri loads. 9.1.4.3.3 Containment Pressure Boundary Integrity The fuel transfer tube that connects the refueling canal (inside the containment) and the SFP (outside the containment) is closed on the refueling canal side by a quick opening hatch at all times except during refueling operations. Two seals are located around the periphery of the quick opening hatch with leak-check provisions between them. 9.1.4.3.4 Radiation Shielding During all phases of spent fuel transfer, the gamma dose rate at the surface of the water is limited by maintaining a minimum of 8 feet of water above the top of the fuel assembly during all handling operations. This corresponds to about 9 feet of water shielding over the active fuel.
The two cranes used to lift spent fuel assemblies are the manipulator crane and the SFP bridge hoist. The manipulator crane contains positive stops, which prevent the top DCPP UNITS 1 & 2 FSAR UPDATE 9.1-42 Revision 21 September 2013 of a fuel assembly from being raised to within 8 feet of the water level in the refueling cavity. The hoist on the SFP bridge moves spent fuel assemblies with a long-handled tool. Hoist travel and tool length likewise limit the maximum lift of a fuel assembly to assure 8 feet of water shielding in the SFP.
When handling irradiated fuel rods, during fuel repairs and post-irradiation examinations, nine feet of water will be maintained above the active fuel. 9.1.4.3.5 Control of Heavy Loads Program 9.1.4.3.5.1 Program Overview NRC Generic Letter 80-113 (Reference 18) required PG&E to review their provisions for handling and control of heavy loads at DCPP to determine the extent to which the guidelines of NUREG-0612 Phase I and II were satisfied and to commit to mutually agreeable changes and modifications that would be required to fully satisfy these guidelines. An overview of the DCPP heavy loads program is presented in this section.
PG&E has developed and is maintaining a robust heavy loads control program at DCPP to minimize the potential for adverse interaction between overhead load handling operations and: 1) nuclear fuel assemblies to ensure a subcritical configuration and preclude radiological consequences and; 2) structures, systems and components (SSCs) selected to ensure safe, cold shutdown of the plant following a postulated heavy load drop event. The bases of the NRC-accepted program are summarized in Reference 7. The objective of the program is to ensure that all load handling systems are designed, operated, and maintained such that their probability of failure is uniformly small and appropriate for the critical tasks in which they are employed. The program is based on all seven general guideline areas of NUREG-0612 Section 5.1.1, also known as Phase I (Safe Load Paths; Load Handling Procedures; Crane Operator Training; Special Lifting Devices; General Lifting Devices; Crane Inspection, Testing and Maintenance, and Crane Design). Implementation of Sections 5.1.2 to 5.1.6 of NUREG-0612, also known as Phase II, was determined by the NRC in Generic Letter 85-11 to not require NRC review. While not a requirement, the NRC encouraged the implementation of any licensee actions identified in Phase II that are considered appropriate.
To accomplish the program, PG&E defined as heavy load targets nuclear fuel assemblies and selected SSCs necessary to safely shut down the plant and maintain the plant in a safe, cold shutdown condition. Initial plant operating modes of normal operation, shutdown, and refueling were considered in the selection of the target equipment. Overhead load handling operations and heavy load target SSCs were then evaluated for potential interaction. Mitigation measures for minimizing adverse interactions include as applicable: (1) to the extent possible, changing methods, routes or scheduling of the overhead load handling operation to avoid the interaction; (2) analyzing the intervening floor structural capacity for protection of target SSCs against postulated damage due to a load drop, and restricting overhead loads in the DCPP UNITS 1 & 2 FSAR UPDATE 9.1-43 Revision 21 September 2013 plant area by weight and handling height above the intervening floor (i.e., restricted area); and (3) excluding the plant area from non-essential overhead load handling operations (i.e., exclusion area). PG&E plans and capabilities to handle heavy loads at DCPP are described in PG&E correspondence to the NRC in response to NUREG-0612 and are summarized in Reference 7. Sections 2.2.4, 2.3.4, and 2.4.2 of PG&E's NUREG-0612 submittals (References 19 and 20) provide the results of various load drop analyses.
The results of these evaluations are used to create administrative controls for overhead load handling operations in plant areas where heavy load targets exist. The Plant Staff Review Committee is responsible for reviewing administrative controls for overhead load handling operation in exclusion areas (see Section 17.2.4). Additional controls for the training of crane operators, design, operation, maintenance and inspection of rigging, lifting devices, and overhead load handling systems are administered through plant procedures. 9.1.4.3.5.2 Reactor Pressure Vessel Head (RPVH) Lifting Procedures DCPP procedures are used to control the lift and replacement of the RPVH. These procedures establish limits on load height, load weight, and medium present under the load. The procedures: (1) use the guidance and acceptance criteria in NEI 08-05, Industry Initiative on Control of Heavy Loads (Reference 21), particularly in regards to Section 2 of the initiative, which addresses criteria for RPVH load drop and consequences analysis; and (2) provide additional assurance that the core will remain covered and cooled in the event of a postulated RPVH drop.
9.1.4.3.5.3 Safety Evaluation for RPVH Load Drop RPVH drop analyses have been performed for DCPP Units 1 and 2 by Sargent & Lundy, LLC, in accordance with NEI 08-05, which was endorsed by the NRC, with exceptions, in the NRC safety evaluation of NEI 08-05 (Reference 22). The DCPP analyses were performed in accordance with the NRC exceptions, as follows:
(1) "The staff considers the ASME Code, Section III, Appendix F acceptance criteria for limiting events (i.e., Service Level D) acceptable for the analytical methods proposed in the guidance." Therefore, the NEI 08-05 stress based criteria using ASME Section III, Appendix F, were used in the DCPP head drop analysis evaluation for coolant retaining components. (2) "For energy balance evaluations using the large-displacement finite element methods described in the guidance, the staff finds the criteria applied to pipe whip restraint evaluations (i.e., one-half of ultimate strain) acceptable for the analytical methods proposed in the draft guidance."
The Standard Review Plan 3.6.2, Rev. 1, criteria applicable to pipe whip restraint evaluations is 0.5 of the ultimate uniform strain limit for pure DCPP UNITS 1 & 2 FSAR UPDATE 9.1-44 Revision 21 September 2013 tension members. Therefore, the uniform tensile strain in tensile plus bending support members was limited to 0.5 of the ultimate strain. The purpose of the analysis was to evaluate the consequences of a postulated heavy load drop of the RPVH in the reactor cavity, while raising or lowering the RPVH during outages at DCPP. The existing RV heads (old heads) are being replaced with new heads during refueling outages in 2009 and 2010. Because the new heads weigh more than the old heads (370 Kip vs. 332 Kip with lead shielding and lifting tripod added), the consequences of the new head drop bound those of the old head drop. For analysis purposes, a conservative head weight of 380 Kip dropping a distance of 38 ft in air was assumed. The RV head centerline is considered concentric with the RV centerline. The 38-ft height limit is removed once the RPVH centerline is outside the RV flange outside diameter. The dynamic head drop analysis methodology used for DCPP is an acceptable methodology per NEI 08-05, Section 2.3, and the NRC safety evaluation of NEI 08-05 (Reference 22). Details of the analysis and results are provided in Reference 23.
The dynamic impact model includes a system of non-linear springs and masses of the falling head with the upper service structures, and impact on an integrated spring mass model of the RV target structures. The target structures consist of the RV shell, nozzles, the reactor coolant system (RCS) loop piping, reactor coolant pumps (RCPs), and the steam generators (SGs). An impact damping ratio of 5 percent was applied in the analysis to address the plastic deformation of the contact surfaces of the head and the vessel flanges. The load-deflection curve of the non-linear spring elements are developed from a non-linear finite element analysis model of the components. The dynamic impact analysis results indicate, for all drop cases, stresses in the RV shell, RV nozzles, RCS loop piping, bottom mounted instrumentation piping and all RCS attached piping meet the allowable stresses per ASME B&PV Code, Section III, Appendix F, for faulted conditions per the NEI 08-05 Guideline as endorsed by the NRC. Stresses in the reactor coolant pressure retaining components are below the ASME Section III, Appendix F, stress limits for faulted conditions.
Concrete under the RV support base steel plate exceeds the local bearing stress limit, thus the RV supports were considered to be ineffective after the concrete crushing. Local concrete under the pipe whip saddle inside the wall penetration also partially crushed, however, the strain in pipe whip support plates remains below the allowable strain. Thus, the RPVH, RV, and RCS piping remain supported after the impact.
The SG and RCP nozzle loads and support loads due to head drop load impact are less than or approximately the same as the component faulted design loads (based on combined LOCA, seismic, pressure, and deadweight loads). Thus, the RCP and SG support structures would remain functional to support the weight of the RCS components after the head drop accident.
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-45 Revision 21 September 2013 In conclusion, controls implemented by NUREG-0612 Phase I elements make the risk of a load drop very unlikely, and, in the event of a postulated RPVH drop, the load drop analysis demonstrates that the consequences are acceptable. Restrictions on load height, load weight, and medium under the load consistent with analysis assumptions are reflected in plant procedures. 9.1.4.4 Inspection and Testing Requirements - Refueling and Fuel Transfer Operations As part of normal plant operations, the fuel handling equipment is inspected for operating conditions prior to each refueling operation. During the operational testing of this equipment, procedures are followed that will affirm the correct performance of the FHS interlocks. 9.1.4.5 Design Bases - Cask Loading Operations The following FHS design bases apply during cask handling and loading operations in the DCPP 10 CFR 50 facilities:
(a) Fuel lifting and handling devices are capable of supporting maximum loads under seismic conditions. The fuel handling equipment will not fail so as to cause damage to any fuel elements should the seismic event occur during cask handling or loading operations. The earthquake loading of the cask handling equipment is evaluated in accordance with the seismic considerations addressed in Section 9.1.4.7.2. (b) Upgraded cranes and hoists used during cask handling and loading minimize the potential for load drops. In particular, the FHB crane bridge and main hoist have been upgraded to meet single-failure-proof criteria, as described in Section 9.1.4.2.1.3. 9.1.4.6 System Description - Cask Loading Operations A summary description of the FHS equipment for cask loading operations is provided in this section. Additional details are included in References 10, 11, and 12.
The FHS equipment needed to load spent fuel into a cask for transfer to the Diablo Canyon ISFSI consists of cranes, lifting and handling devices including tools, a low profile transporter (LPT), and an SFP transfer cask restraint cup. The primary structures associated with this equipment are the SFP, the cask loading area of the SFP, and the Unit 2 cask washdown area (CWA).
While in the Unit 2 CWA, the HI-TRAC will be seismically restrained by the CWA seismic restraint system. This system includes a wall mounted restraint and service platform and a floor restraint plate.
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-46 Revision 21 September 2013 Decay heat, generated by the spent fuel assemblies in the SFP, is removed by the SFP cooling and cleanup system. When fuel is to be moved to the Diablo Canyon ISFSI, selected assemblies are removed from the racks and loaded into an MPC that is located inside a transfer cask (the HI-TRAC 125D cask shown in Figure 9.1-4). The cask handling route within the FHB/AB is shown in Figure 9.1-7. The minimum cooling time for fuel to be loaded into the transfer cask is 5 years.
The cranes, lifting and handling devices, and tools used for cask loading operations are essentially the same as those used for refueling and fuel transfer operations (described in Section 9.1.4.2). They are, however, configured differently for cask loading operations, as further described below in Section 9.1.4.6.1. The LPT is used to move the empty transfer cask into the FHB/AB. The transfer cask is detached from the LPT and moved into the Unit 2 CWA seismic restraint using the FHB crane. While located in the CWA, the empty transfer cask/MPC is restrained as shown in Figure 9.1-24. When the transfer cask is moved to the cask loading area, it is lowered into the SFP transfer cask restraint cup (Figure 9.1-6), which provides lateral support of the cask while it is lowered, loaded with fuel, and lifted from the SFP. Once the loaded cask is raised out of the SFP, it is moved to the Unit 2 CWA for decontamination, MPC processing, and preparation for transport to the CTF. When ready, the loaded cask is lifted out of the Unit 2 CWA, fastened onto the LPT, and moved out of the FHB/AB for subsequent transport to the CTF using the cask transporter. 9.1.4.6.1 Component Descriptions The following sections describe major components of the FHS as they relate to cask loading operations in the FHB/AB. The cranes, lifting and handling devices, and tools described in Section 9.1.4.2.1 for refueling and fuel transfer operations are essentially the same as those used for cask loading operations. There are, however, some configuration differences. The component descriptions in this section focus on the configuration differences for the cranes, lifting and handling devices, and tools, as well as describing those components unique to cask loading and handling in the FHB/AB. Other FHS components not addressed in this section remain the same as described in Sections 9.1.4.2.1 and 9.1.4.2.2. 9.1.4.6.1.1 HI-STORM 100 Interchangeable MPCs The HI-STORM MPC provides for confinement of radioactive materials, criticality control, and the means to dissipate decay heat from the stored fuel. It is a welded cylindrical canister with a honeycombed fuel basket, which contains Boral neutron absorbers for criticality control. Although several types of MPCs, with different internal arrangements, are certified for use at DCPP, only the MPC-32 will be used. The MPC-32 is designed for intact spent fuel. All MPC-32s have the same outside dimensions and use the same transfer cask.
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-47 Revision 21 September 2013 9.1.4.6.1.2 HI-TRAC 125D Transfer Cask The HI-TRAC 125D transfer cask (Figure 9.1-4) contains the MPC during loading, unloading, and transfer operations. The physical characteristics of the 125D cask are shown in Table 4.2-3 of the Diablo Canyon ISFSI FSAR Update. It provides shielding and structural protection of the MPC in the FHB/AB and from the SFP to the CTF. The transfer cask is a multi-walled (carbon steel/lead/carbon steel) cylindrical vessel with a built-in exterior water jacket. The maximum weight including the lifting yoke during any loading, unloading, or transfer operation does not exceed 125 tons. 9.1.4.6.2 Transfer Cask/MPC Loading Process The transfer cask/MPC loading process is briefly summarized in this section. Additional detail is provided in Section 3.2 of Reference 10 and in Section 5.1 of Reference 12.
An empty MPC is loaded into the transfer cask in the FHB/AB using the FHB crane. Borated water is added to the MPC and the transfer cask is lifted above the SFP wall using the FHB crane.The cask is then traversed into position over the cask loading area of the SFP and SFP transfer cask restraint cup. The cask is lowered into the SFP transfer cask restraint cup, which rests on a platform near the bottom of the cask loading area. The restraint precludes tipping or damage to adjacent fuel racks.
After fuel loading is complete, a lid is placed on the MPC, the transfer cask is lifted out of the SFP, traversed and lowered into the Unit 2 CWA seismic restraint, and decontaminated. The MPC lid is welded to the MPC shell, hydro leak tested, water is drained from the MPC, and the MPC is dehydrated, filled with Helium, isolated, Helium leak tested, and seal welded to closure. The top lid is then installed on the transfer cask.
The FHB crane is then used to lift the loaded transfer cask out of the CWA restraint and to place the loaded transfer cask onto the LPT. The cask is fastened to the LPT and the LPT is moved out of the FHB/AB on removable tracks to a position where it is rigged to the cask transporter for movement to the CTF. 9.1.4.6.3 Unloading Operations While unlikely, certain conditions described in Reference 12 may require unloading of the fuel assemblies from the transfer cask/MPC. The unloading process is generally the reverse order of the loading process. 9.1.4.7 Safety Evaluation - Cask Loading Operations Potential spent fuel cask accidents and off-normal events related to handling and loading (or unloading) of the MPC in the HI-TRAC 125D transfer cask, including potential drops and tipovers, operational errors and mishandling events, MPC boron dilution; the potential impacts of seismic events and tornadoes; safe handling as related DCPP UNITS 1 & 2 FSAR UPDATE 9.1-48 Revision 21 September 2013 to use of cranes and lifts; support system malfunctions; and fires are addressed in this section. Additional details of the methodology, acceptance criteria, and results are provided in Section 4.3 of Reference 10 and in Reference 13. 9.1.4.7.1 Drops and Tipovers The transfer cask, MPC and its internals, MPC lids, and spent fuel assemblies must be handled in and around the SFP and spent fuel (in the SFP and MPC). With the exception of the spent fuel assemblies, all of these items represent heavy loads.
The potential for drops or tipovers of any of these heavy loads is extremely small due to DCPP's Control of Heavy Loads Program and fuel-handling operations procedures. The Control of Heavy Loads Program provides procedures, training, and designs to minimize the potential for load drops, meets PG&E's commitments to NUREG-0612, and has been accepted by the NRC. The single-failure-proof upgrade to the FHB crane further reduces the potential for a crane-related failure or mishandling event that could result in the drop of a cask. The Control of Heavy Loads Program, as it applies to dry cask load handling operations in the 10 CFR 50 facilities, is described in Section 9.1.4.7.8.
Nonetheless, the following potential heavy-load drops have been postulated and evaluated, where credible, in accordance with the guidance of NUREG-0612, Section 5.1, demonstrating defense in depth.
Loaded Transfer Cask Drops PG&E has provided defense in depth through crane enhancements (described in Section 9.1.4.6) in those locations where a drop could have unacceptable consequences. Use of a single-failure-proof FHB crane ensures that an uncontrolled drop onto the edge of the SFP wall, which could allow the cask to tip or tumble horizontally into the SFP or into the CWA, is not credible. The single-failure-proof FHB crane also precludes drops during the placement of the transfer cask/MPC onto the LPT.
Further, movement of heavy loads over fuel in the SFP, or over any other safe shutdown systems or equipment identified in PG&E's NUREG-0612 submittals, is controlled by procedures and considers the design of the single-failure-proof crane system and/or travel limit devices.
To ensure the cask does adversely affect the stored spent fuel in the adjacent racks, the cask is inserted and seated in the transfer cask restraint cup during fuel loading or unloading operations. Structurally separating the transfer cask restraint cup from the fuel storage racks is the spent fuel cask restraint. The restraint is made of 12-inch Schedule 80S Type 304 stainless steel pipe, as shown in Figure 9.1-5.
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-49 Revision 21 September 2013 Fuel Assembly Drop into Loaded Transfer Cask While very unlikely, analysis of this event shows that a fuel assembly drop into the MPC could result in physical deformation that would challenge criticality margins. However, the results of the analysis show that the criticality margins would continue to meet the licensing basis (keff <0.95) and that the radiological consequences are enveloped by the existing fuel assembly drop accident described in Section 15.5.22.1.
MPC or Transfer Cask Lids, AWS, or Lifting Yoke Drops into Loaded Cask While these components are classified as heavy loads and handling them over the MPC is required for dry fuel operations, drops are not considered credible because they are handled with a single-failure-proof overhead load handling system and rigged in accordance with the Control of Heavy Loads Program. 9.1.4.7.2 Operational Errors and Mishandling Events The proposed design of the dry cask handling system and associated procedures provide assurance that operational errors and mishandling events will not result in an increase in the probability or consequences of an accident previously analyzed. The following operational errors and mishandling events were evaluated and found to either have consequences within the design or licensing basis of DCPP, be precluded by compliance with the Control of Heavy Loads Program and/or operations procedures, or to not be credible.
- SFP Liner Breach Due to Cask Drop
- Crane Mishandling Operation with Transfer Cask/MPC Resulting in Horizontal Impact or Drops Outside of the Analyzed Lift Points
- Loss of the Transfer Cask Water Jacket Water During MPC and Cask Handling Operations
- Boron Dilution of the SFP and Associated Criticality Concerns
- Loading of an Unauthorized Fuel Assembly 9.1.4.7.3 MPC Boron Dilution A boron dilution analysis was performed and submitted to the NRC (Reference 13) to determine the time available for operator action to ensure criticality does not occur in an MPC-32 during fuel loading and unloading operations. The analysis results show that operators have approximately 5 hours available to identify and terminate the source of unborated water flow from the limiting boron dilution event to ensure criticality in the MPC-32 does not occur. To minimize the possibility of a dilution event, a temporary administrative control will be implemented while the MPC is in the SFP that will require, DCPP UNITS 1 & 2 FSAR UPDATE 9.1-50 Revision 21 September 2013 with the exception of the 1-inch line used to rinse the cask as it is removed from the SFP, at least one valve in each potential flow path of unborated water to the SFP to be closed and tagged out. During the cask rinsing process, the MPC will have a lid in place that will minimize entry of any unborated water into the MPC. The flow path with the highest potential flow rate of 494 gpm will be doubly isolated by having two valves closed and tagged out while the MPC is in the SFP.
Based on the alarms, procedures, administrative controls, assumption of zero burnup fuel, and availability of trained operators described in Reference 13, the NRC has granted an exemption from the criticality requirements of 10 CFR 50.68(b)(1) during loading, unloading, and handling of the MPC in the DCPP SFP (Reference 14). 9.1.4.7.4 Support System Malfunctions The following support system malfunctions have been evaluated and found to not adversely affect plant safety:
- Loss of Electrical Power or Component Failures During Handling Operations
- Rupture of MPC Dewatering, Vacuum, FHD, or Related Closure System Lines or Equipment
- Failure of the Transport Frame/Rail Dolly or Crane Handling Systems 9.1.4.7.5 Natural Phenomena Seismic The potential impact of seismic events on cask loading, handling, closure, and transport activities has been considered in the evaluation of the cask system components and in the design and evaluation of the interfaces with 10 CFR 50 facilities. Two structures, the SFP transfer cask restraint cup and the Unit 2 CWA seismic restraint structure, are designed to preclude unacceptable movement of the cask system components, assuring all involved SSCs remain within their design bases.
Seismic analyses have been performed that demonstrate the adequacy of the SFP transfer cask restraint cup and Unit 2 CWA restraint to preclude unacceptable movement or impact on the 10 CFR 50 facilities.
Tornado Winds and Tornado Generated Missiles The overall tornado resistance of the fuel handling area of the auxiliary building is addressed in Section 9.1.2.3.2. The effects of tornado wind loads acting on the cask suspended from the FHB crane are enveloped by the seismic analysis for this configuration. However, cask handling introduces new tornado missile targets. DCPP UNITS 1 & 2 FSAR UPDATE 9.1-51 Revision 21 September 2013 Analysis results demonstrate that the 125-ton transfer cask satisfies all functional requirements under postulated impact scenarios and the system will not be subject to a loss of load due to a missile impact. 9.1.4.7.6 Safe Handling The safe handling discussion in Section 9.1.4.3.1 for the FHB cranes and lifts applies to cask loading operations. In addition, the FHB crane will be configured and operated as described in Section 9.1.4.2.1.3 when performing cask loading and handling operations. 9.1.4.7.7 Fires The DCPP Fire Protection Program is described in Section 9.5.1. The program has been modified to incorporate the requirements of the ISFSI fire analyses, such that the required controls are provided to ensure the plant and the ISFSI components remain within their licensing bases.
Inside the FHB/AB The transporter and its associated fuel tank remain outside of the buildings. However, transient materials brought into the FHB/AB associated with dry cask storage activities could provide additional fire loading. These activities and materials are under the control of DCPP's Fire Protection Program. The current program ensures that ignition sources are monitored and that combustible loading requirements for the FHB/AB areas are followed. To the extent practical, combustibles will be kept away from the transfer cask to minimize the effects of any potential fire. Outside the FHB/AB The Fire Protection Program has been modified to ensure potential fires during the transport and storage are handled consistently with the plant program requirements and meet the assumptions described in the Diablo Canyon ISFSI FSAR Update. Prior to any cask transport, a walkdown will be performed to ensure local combustible materials, including transient combustibles, are controlled in accordance with ISFSI fire protection requirements. 9.1.4.7.8 Control of Heavy Loads Program The Control of Heavy Loads Program for refueling and fuel transfer operations is described in Section 9.1.4.3.5. The Control of Heavy Loads Program for cask loading operations, which includes revisions for loading the HI-STORM System components within the 10 CFR 50 facility, complies with the guidelines of NUREG-0612, as described in Section 9.1.4.3.5. Details specific to cask loading and handling in the FHB/AB are provided in References 10 and 11.
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-52 Revision 21 September 2013 9.1.4.8 Inspection and Testing Requirements - Cask Loading Operations Prior to each cask loading operation, the fuel and cask handling equipment is inspected for operating conditions During operational testing of the equipment, procedures are followed to affirm the correct performance of interlocks and controls. 9.
1.5 REFERENCES
- 1. Seismic Evaluation for Postulated 7.5M Hosgri Earthquake, Units 1 and 2, Diablo Canyon Site, Pacific Gas and Electric Company, 1977.
- 2. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
- 3. U.S. Atomic Energy Commission, "Spent Fuel Storage Facility Design Basis," Safety Guide 13, March 1971.
- 4. IEEE Standard, 279-1971, Criteria for Protection Systems for Nuclear Power Generating Stations, The Institute of Electrical and Electronics Engineers, Inc.
- 5. NRC letter to PG&E, dated May 30, 1986, granting License Amendments No. 8 to Unit 1 and No. 6 to Unit 2.
- 6. License Amendment Request 95-01, submitted to the NRC by PG&E letters DCL-95-28, dated February 6, 1995; DCL-95-063, dated March 23, 1995; DCL-95-112, dated May 22, 1995; and DCL-95-178, dated August 22, 1995. 7. PG&E Letter (DCL-96-111) to the NRC, "Response to NRC Bulletin 96-02, 'Movement of Heavy Loads Over Spent Fuel, Over Fuel in the Reactor Core, or Over Safety-Related Equipment,'" dated May 13, 1996.
- 8. License Amendment Request 01-02, Credit for Soluble Boron in the Spent Fuel Pool Criticality Analysis, PG&E Letter DCL-01-096, dated September 13, 2001, supplemented by PG&E Letter DCL-02-022, dated February 27, 2002.
- 9. License Amendments 154/154, Credit for Soluble Boron in the Spent Fuel Pool Criticality Analysis, issued by the NRC, September 23, 2003.
- 10. License Amendment Request 02-03, Spent Fuel Cask Handling, PG&E Letter DCL-02-044, dated April 15, 2002.
- 11. License Amendments 162 and 163, Spent Fuel Cask Handling, issued by the NRC, September 26, 2003.
- 12. Diablo Canyon ISFSI Final Safety Analysis Report Update.
DCPP UNITS 1 & 2 FSAR UPDATE 9.1-53 Revision 21 September 2013 13. PG&E Letter (DCL-03-126) to the NRC, "Request for Exemption from 10 CFR 50.68, Criticality Accident Requirements, for Spent Fuel Cask Handling," dated October 8, 2003, supplemented by PG&E Letters (DCL-03-150 and DIL-03-014), "Response to NRC Request for Additional Information Regarding Potential Boron Dilution Events with a Loaded MPC in the DCPP SFP," dated November 25, 2003.
- 14. NRC Letter to PG&E, dated January 30, 2004, "Exemption from the Requirements of 10 CFR 50.68(b)(1)."
- 15. License Amendment Request 04-07, Revision to Technical Specifications 3.7.17 and 4.3 for Cycles 14-16 for a Cask Pit Spent Fuel Storage Rack, PG&E Letter DCL-04-149 dated November 3, 2004
- 16. Deleted in Revision 20.
- 17. Deleted in Revision 20.
- 18. NRC Generic Letter GL 80-113, "Control of Heavy Loads," December 22, 1980.
- 19. PG&E Letter to NRC, "Control of Heavy Loads (NUREG-0612)," September 30, 1982.
- 20. PG&E Letter to NRC, "Control of Heavy Loads (NUREG-0612)," May 9, 1983.
- 21. NEI 08-05 (Rev. 0), "Industry Initiative on Control of Heavy Loads," July 2008. 22. NRC Safety Evaluation, "NEI 08-05, Revision 0, Industry Initiative on Control of Heavy Loads," September 5, 2008.
- 23. PG&E Calculation SAP DIR No. 9000040722, Legacy HID-12, Binder No. MR-11 (S&L Calculation 2008-13003, "Analysis of Postulated Reactor Vessel Head Drop for DCPP," Proprietary and Confidential, Sargent & Lundy, LLC).
- 24. Westinghouse Calculation No. A-DP1 -FE-0001, "DCPP Units 1 &2 Spent Fuel Criticality Analysis," September 2001 .
- 25. PG&E Vendor Document 6021773-88, "WCAP-16985-P Rev.2, DCPP Tavg & Tfeed Ranges Program NSSS Engineering Report," April 2009.
- 26. Holtec Report HI-931 077 Rev. 3, "Criticality Safety Evaluation of Region 2 of the Diablo Canyon Spent Fuel storage Racks w/ 5% Enrichment," June 1995 DCPP UNITS 1 & 2 FSAR UPDATE 9.2-1 Revision 21 September 2013 9.2 WATER SYSTEMS This section describes all of the auxiliary water supply and cooling water systems in the plant except for the fire protection system, which is discussed in Section 9.5.1 and the seawater supply to the service cooling water (SCW) heat exchangers, which is described in Section 10.4.5. Water used in the plant is a combination of processed seawater and well water.
9.2.1 SERVICE COOLING WATER SYSTEM The SCW system, shown in Figure 3.2-15, is a closed system used to cool equipment in the secondary portion of the plant. The following sections provide information on (a) design bases, (b) system description, (c) safety evaluation, (d) tests and inspections, and (e) instrumentation applications. 9.2.1.1 Design Bases The SCW system is used in the secondary or steam and power conversion portion of the plant only. The design classification for the SCW system is given in the DCPP Q-List (see Reference 8 of Section 3.2). The design requirements for flow are based on the heat load demands of the various components cooled by the SCW system. The SCW system does not cool any component required for safe shutdown. 9.2.1.2 System Description The SCW system is a closed system that supplies buffered cooling water for the following plant equipment: (1) Plant air compressors and aftercoolers (2) Main turbine lube oil reservoir coolers (3) Electrohydraulic control coolers (4) Condensate pump motor upper bearing (5) Condensate booster pump lube oil cooler (6) Generator seal oil coolers (7) Incore instrument chiller (Supply and return to this system is isolated and is not in use) (8) Personnel access control room air conditioning (9) Plant air dryer cooler DCPP UNITS 1 & 2 FSAR UPDATE 9.2-2 Revision 21 September 2013 (10) Condenser vacuum pump seal water cooler (11) Heater No. 2 drain pump (12) Feed pump drive turbine Nos. 1 and 2 lube oil coolers (13) Fuse wheel cooler (14) Generator exciter coolers (15) Isophase bus coolers (16) Onsite technical support center air conditioning condenser (17) Post-loss-of-coolant accident (LOCA) sampling system room air conditioning (18) Air conditioning for traveling crew facilities room (Unit 2 only) (19) Secondary process isothermal bath water chiller The service water heat exchangers are cooled by the circulating water system (CWS) described in Section 10.4.5. Makeup water to the system is from the makeup water system (MWS) described in Section 9.2.3. This is controlled automatically by the level in the service water head tank.
9.2.1.3 Safety Evaluation Since no safety-related (Design Class I) components are cooled by the SCW system, complete shutdown of the system does not affect safe operation or shutdown of the reactor. In all safety analyses where loss of offsite power is postulated, the SCW system is assumed to be unavailable. The low operating pressure and temperature of the system minimize the probability of line failures; and the physical location of the lines and components cooled by the system is such that the failure of a service water header would not create an adverse environment for any Design Class I components. 9.2.1.4 Tests and Inspections The operating components are in either continuous or intermittent use during normal plant operation, and no additional periodic tests are required. Periodic visual inspections and preventive maintenance are conducted in accordance with normal plant operating practices.
DCPP UNITS 1 & 2 FSAR UPDATE 9.2-3 Revision 21 September 2013 9.2.1.5 Instrumentation Applications The operation of the system is monitored with the following instrumentation:
(1) High and low level alarms in the service water head tank (2) Automatic pump start pressure switches on the common pump discharge (3) Temperature sensing devices at: (a) Main turbine reservoir lube oil coolers outlet (b) SCW supply header (c) Isophase bus cooler fans hot air inlet (d) Generator exciter and fuse wheel cooler water return (e) Air compressor cooling water returns (f) Post-LOCA sampling system room air conditioning system inlet and outlet (4) Pressure sensing devices at: (a) SCW pumps outlet (b) CCW Chemical Addition System (c) SCW heat exchanger inlets and outlets (d) Main turbine lube oil coolers water supply (e) Post-LOCA sampling system room air conditioning system inlet and outlet 9.2.2 COMPONENT COOLING WATER SYSTEM The component cooling water (CCW) system, shown in Figure 3.2-14, is a closed-cycle cooling system that transfers heat from nuclear (primary) plant equipment and other systems/components (Reference Table 9.2-4) during normal plant operation, plant cooldown, and following a LOCA or main steam line break (MSLB) to the auxiliary saltwater (ASW) system. Except for normally closed makeup lines and seal water make-up to the waste gas compressor, there is no direct connection between the CCW system and other systems. The CCW system provides a monitored intermediate barrier DCPP UNITS 1 & 2 FSAR UPDATE 9.2-4 Revision 21 September 2013 between equipment and components handling radioactive fluids and the auxiliary saltwater (ASW) system.
9.2.2.1 Design Bases 9.2.2.1.1 General Design Criterion 2, 1967 - Performance Standards The CCW system is designed to withstand the effects of or is protected against natural phenomena, such as earthquakes, tornados, flooding conditions, winds, ice, and other local site effects. 9.2.2.1.2 General Design Criterion 3, 1971 - Fire Protection The CCW system is designed and located to minimize, consistent with other safety requirements, the probability and effect of fires and explosions. 9.2.2.1.3 General Design Criterion 4, 1967 - Sharing of Systems The CCW systems or components are not shared by the DCPP Units unless safety is not impaired by the sharing. 9.2.2.1.4 General Design Criterion 11, 1967 - Control Room The CCW system is designed to support safe shutdown and to maintain safe shutdown from the control room or from an alternate location if control room access is lost due to fire or other causes. 9.2.2.1.5 General Design Criterion 12, 1967 - Instrumentation and Control Systems Instrumentation and controls are provided as required to monitor and maintain CCW system variables within prescribed operating ranges. 9.2.2.1.6 General Design Criterion 17, 1967 - Monitoring Radioactivity Releases The CCW system includes means to detect the presence of in-leakage from interfacing systems that may be radioactive to avoid potential releases to the environment. 9.2.2.1.7 General Design Criterion 53, 1967 - Containment Isolation Valves CCW system containment penetrations that require closure for the containment isolation function are protected by redundant valving and associated apparatus. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-5 Revision 21 September 2013 9.2.2.1.8 General Design Criterion 57, 1967 - Provisions for Testing Isolation Valves The CCW system provides capability for testing functional operability of valves and associated apparatus essential to the containment function for establishing that no failure has occurred and for determining that valve leakage does not exceed acceptable limits. 9.2.2.1.9 10 CFR 50.49 - Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants CCW system electric components that require environmental qualification (EQ) are qualified to the requirements of 10 CFR 50.49. 9.2.2.1.10 10 CFR 50.55a(f) - Inservice Testing Requirements CCW system ASME Code components are tested to the requirements of 10 CFR 50.55a(f)(4) and 10 CFR 50.55a(f)(5) to the extent practical. 9.2.2.1.11 10 CFR 50.55a(g) - Inservice Inspection Requirements CCW system ASME Code components (including supports) are inspected to the requirements of 10 CFR 50.55a(g)(4) and 10 CFR 50.55a(g)(5) to the extent practical. 9.2.2.1.12 10 CFR 50 Appendix R (Sections III.G, III.J, III.L Only) - Fire Protection Program for Nuclear Power Facilities Operating Before January 1, 1979 The CCW system is designed to provide decay heat removal to achieve and maintain a safe shutdown condition for fire events. 9.2.2.1.13 CCW System Safety Function Requirements (1) Waste Heat Removal The CCW system is designed to remove waste heat from the nuclear (primary) plant equipment and components during normal plant operation, plant cooldown, and design basis accidents. (2) Single Failure The CCW system and ASW system are essentially considered a single heat removal system for the purpose of assessing the ability to sustain either a single active or passive failure and still perform design basis heat removal. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-6 Revision 21 September 2013 (3) Dynamic Effects Vital portions of the CCW system are designed, located, or protected against dynamic effects. (4) Redundancy The CCW system components considered vital are redundant. (5) Isolation The CCW system includes provision for isolation of system components and may be split into separate trains during long term post-LOCA conditions. (6) Leak Detection The CCW system serves as an intermediate system between normally or potentially radioactive systems and the ASW system. 9.2.2.1.14 Regulatory Guide 1.97 Revision 3, May 1983 - Instrumentation for Light-Water Cooled Nuclear Power Plants to Assess Plant and Environs Condition During and Following an Accident The CCW system provides instrumentation to monitor CCW flow and temperature and containment isolation valve (CIV) position indication on the monitor light box (for applicable CCW valves) during and following an accident. 9.2.2.1.15 Generic Letter 89-10, June 1989 - Safety Related Motor-Operated Valve Testing and Surveillance The CCW system safety related and position changeable motor-operated valves meet the requirements of GL 89-10 and associated GL 96-05. 9.2.2.1.16 Generic Letter 89-13, July 1989 - Service Water System Problems Affecting Safety Related Equipment The CCW system heat exchangers are subject to monitoring and maintenance programs to ensure capability to perform their safety function as an alternative to a testing program. Maintenance practices, operating and emergency procedures, and training ensure effectiveness of these programs. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-7 Revision 21 September 2013 9.2.2.1.17 Generic Letter 96-06, September 1996 - Assurance of Equipment Operability and Containment Integrity During Design-Basis Accident Conditions The CCW system is designed so that it is not subject to the hydrodynamic effects of water hammer, reduced cooling effectiveness due to two phase flow conditions, or overpressurization of isolated piping during a LOCA or MSLB event. 9.2.2.1.18 NUREG-0737 II.K.3.25, November 1980 - Effect of Loss of Alternating Current Power on Pump Seals The CCW system is designed such that the reactor coolant pump seals can withstand a complete loss of offsite alternating current power for at least two hours. 9.2.2.1.19 10 CFR 50.63 - Loss of All Alternating Current Power The CCW system is required to perform its safety function of waste heat removal in the event of a Station Blackout. 9.2.2.2 System Description The CCW system is designed to provide cooling water to vital and nonvital components and to operate in all plant operating modes, including normal power operation, plant cooldown, and emergencies, including a LOCA or MSLB.
The CCW system includes three CCW pumps, two CCW heat exchangers, and an internally baffled CCW surge tankas described in Table 9.2-3. The piping system consists of three parallel headers. Two are separable redundant vital service headers A and B, which serve only the unit's ESF equipment and the post-LOCA sample cooler (header A only). A miscellaneous service loop C serves nonvital equipment. Except for normally closed makeup lines and seal water make-up to the waste gas compressor, there is no direct connection between the CCW system and other systems. The equipment cooled is tabulated in Table 9.2-4. Nominal flows for major CCW system operating modes are tabulated in Table 9.2-5. Cooling water for the CCW heat exchangers is supplied from the ASW system. Together, CCW/ASW support heat transfer to the UHS. The CCW system serves as an intermediate system between the RCS and ASW system, ensuring that any leakage of radioactive fluid from the components being cooled is contained within the plant. Operation under normal and accident conditions will be as follows:
(1) Normal Operation During normal operation, all loops are in operation. Two CCW pumps and one or two CCW heat exchangers are in use and are capable of serving all DCPP UNITS 1 & 2 FSAR UPDATE 9.2-8 Revision 21 September 2013 operating components. The third pump and the second heat exchanger generally provide backup during normal operation. (2) Plant Cooldown During the cooldown phase of a unit shutdown, all loops are operated with two or three pumps and two heat exchangers used for the removal of residual and sensible heat from the RCS through the residual heat removal (RHR) system (see Figure 3.2-10). If one of the pumps or one of the heat exchangers is inoperative, orderly shutdown is not affected, but the time for cooldown is extended. (3) Accident Conditions In the event of a LOCA or MSLB, three CCW pumps are placed in service to provide protection against an active failure. The safety injection (SI) signal initiates an automatic start signal for the standby CCW pump. When containment pressure reaches the high containment pressure setpoint, a Phase A isolation signal is generated and CCW flow to the excess letdown heat exchanger is isolated. When the containment pressure reaches the high-high containment pressure setpoint (containment Phase B isolation), a signal to close the C (non-vital) header isolation valve is generated because components on the C header are not required for post-accident cooling. The portion of the non-vital header that serves the reactor coolant pumps and vessel support coolers located within the reactor primary shield wall is independently isolated (Phase B), due to its vulnerability during a LOCA, to assure isolation The CCW system is required to provide cooling water to the ESF pump coolers and the CFCUs during the injection and recirculation phase of a LOCA and during an MSLB. The CCW system is flow balanced to ensure that adequate flow is maintained to each component. Following the post-LOCA injection phase, the CCW system is realigned for the recirculation phase by valving in the RHR heat exchangers to cool the water collected in the containment sump. Additionally, if a containment Phase B isolation signal has occurred but the C header does not automatically isolate during the injection phase, it is manually isolated prior to realignment for recirculation. The additional heat load on the CCW system is controlled by plant operators by limiting the heat input equipment (operating CFCUs and RHR heat exchangers) based on the available heat removal equipment (operating CCW heat exchangers and ASW pumps) to prevent the CCW system supply temperature from exceeding its design basis limit.
DCPP UNITS 1 & 2 FSAR UPDATE 9.2-9 Revision 21 September 2013 During long-term postaccident recirculation operation, the CCW system may be manually realigned into two separate redundant loops. Each loop has a pump and a heat exchanger and is capable of fulfilling the minimum long-term cooling requirements. This provides protection against a passive failure in one loop. Should one loop fail, the other loop is unaffected, and the ESF components that it serves remain operative. Due to its vulnerability to a loss of inventory, the CCW system should be split into separate trains as soon as possible after aligning for long-term post LOCA recirculation if plant conditions are acceptable. The decision to split CCW trains will be made by the Technical Support Center based on the physical integrity of the trains, the availability of active components, and the reliability of power systems. This long-term postaccident alignment provides further assurance of the capability to withstand a passive failure. See Reference 8. Design data for some major CCW system equipment are listed in Table 9.2-3. The CCW system consists of the following major pieces of equipment. 9.2.2.2.1 Component Cooling Water Pumps The three CCW pumps that circulate CCW through the CCW system are horizontal, double suction, centrifugal units. The pumps operate on electric power from the vital 4.16 kV buses that can be supplied from either normal or emergency sources. 9.2.2.2.2 Component Cooling Water Heat Exchangers The two CCW heat exchangers are shell and tube type. Seawater circulates through the tube side. The shell is carbon steel, and the tubes are 90-10 Cu-Ni. 9.2.2.2.3 Component Cooling Water Surge Tank The CCW surge tank, which is connected by two surge lines to the vital headers on the pump suction piping, is constructed of carbon steel. The tank is internally divided into two compartments by a partial height partition to hold two separate volumes of water. This arrangement provides redundancy to accommodate a passive failure when the CCW system is manually realigned into two trains.
The surge tank accommodates thermal expansion and contraction, and in- or out-leakage of water from the system. The tank is normally pressurized with nitrogen to a minimum of 17 psig to provide sufficient static head to prevent boiling and two-phase flow conditions in the CCW to the CFCUs during a postulated large break LOCA coincident with a loss of offsite power. The primary source of nitrogen is the Class II nitrogen system. (Reference 7)
DCPP UNITS 1 & 2 FSAR UPDATE 9.2-10 Revision 21 September 2013 A back-pressure regulator is provided downstream of the surge tank vent valve to prevent the pressure in the surge tank from exceeding the desired pressure range. This back-pressure control valve maintains surge tank pressure at all times at its setpoint by relieving excess nitrogen to the atmosphere. The surge tank vent valve closes when a high radiation level is detected by radiation monitors provided in the CCW pump discharge headers. The monitor also actuates an alarm in the control room.
In the event of a low level in the surge tank, makeup water is automatically added to the system through control valves from the MWS (see Section 9.2.3). 9.2.2.2.4 Chemical Addition System The closed chemical addition system supplies various treatment chemical solutions to the CCW. The system contains chemical addition tanks, an injection pump, pressure and flow indication, and a fume hood for personnel protection. The system is common to Unit 1 and Unit 2 CCW and also supplies chemicals to the SCW. 9.2.2.2.5 Component Cooling Water Corrosion Monitor A corrosion test loop is provided to monitor the effectiveness of the corrosion inhibitor used in the CCW system. The test loop consists of four coupon locations and two spare connections for future use. Test coupons of representative materials are exposed to CCW system conditions for a period of time and then analyzed to determine the overall corrosion rates. 9.2.2.2.6 Residual Heat Removal Heat Exchangers Control room operated air-actuated valves control the CCW flow to the RHR heat exchangers (described in Chapter 5) in order to place these components in service during plant cooldown or after a LOCA. The valves, which open on loss of air, are provided with a Design Class I backup air supply to allow positive operator control after loss of the plant compressed air system. 9.2.2.2.7 Containment Fan Coolers CCW is supplied to the containment fan coolers (described in Chapter 6) by the two vital headers. Two fan coolers are on loop A and three on header B. Drain and isolation valves are provided on each side of the fan coolers allowing each cooler to be isolated individually for leakage testing. The flow of CCW through the fan coolers is throttled (position fixed) by a manual valve downstream of each fan cooler to ensure adequate flow to support design basis accident analyses as discussed below. The air-actuated temperature control valves, provided originally to limit the flow to the CFCUs, are not required. Therefore, instrument air to these valves has been isolated and the valves remain in the fully open position. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-11 Revision 21 September 2013 The above valve alignment assures minimum required flow through each fan cooler under accident conditions without any immediate automatic or operator action. The only required manual action would be header C isolation when transferring to post-LOCA recirculation. The ability of the CCW system to adequately remove heat from containment without overheating the CCW fluid is demonstrated by several transient analyses. For determining adequate containment heat removal, the minimum CCW flow rate to CFCUs is 1600 gpm to the cooling coils. For determining maximum CCW temperature, the maximum CCW flow rate to CFCU cooling coils is 2500 gpm. Data presented in Tables 9.2-5 and 6.2-26 are nominal data that are enveloped by these extremes. CCW is also supplied to a separate cooling coil located in the CFCU motor enclosure. This cooling flow path is in parallel to the CFCU cooling coil flow path.
Specific conditions, such as inlet and outlet temperatures to the CFCUs, are dynamically calculated and vary over the course of the transient according to the scenario assumptions. 9.2.2.2.8 Reactor Vessel Supports Cooling water is provided to the reactor vessel supports (described in Chapter 3) to prevent overheating and dehydration of the concrete for the reactor vessel support shoes. This is accomplished by the use of water-cooled steel blocks between each of the four vessel support pads and its support shoe. CCW flows in labyrinth flow passages in the blocks providing heat removal sufficient to prevent the concrete from dehydrating. 9.2.2.2.9 Valves The valves in the CCW system are standard commercial valves constructed of carbon steel with carbon steel, bronze, or stainless steel trim. Since the CCW is normally not radioactive, special features to prevent leakage to the atmosphere are not provided. Self-actuated spring-loaded relief valves are provided for lines and components that may be pressurized to above their design pressure by improper operation or malfunction. The valves associated with CCW pumps, the CCW heat exchangers, large piping and associated instrumentation are located outside the containment and are therefore available for maintenance and inspection during power operation. CCW valves associated with containment isolation are discussed as a part of the containment isolation system (Section 6.2.4). The equipment vent and drain lines have manual valves that are normally closed (the surge tank vent line has an automatic back-pressure regulator that is also normally closed) unless the equipment is being vented or drained for maintenance or repair operations. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-12 Revision 21 September 2013 The relief valves on the CCW lines downstream of the sample, letdown, seal water, spent fuel pool, and RHR heat exchangers are sized to relieve the volumetric expansion occurring if the exchanger shell-side is isolated and high-temperature coolant flows through the tube side. The relief pressures do not exceed 150 psig.
Relief valves for volumetric expansion are provided on the downstream side of the waste gas compressor heat exchanger and the abandoned in place boric acid and waste evaporator condenser. Relief pressures do not exceed 150 psig. Waste gas compressor relief and evaporator packages relief is back to the return line downstream of the respective shutoff valve.
The relief valve on the CCW surge tank is sized to relieve the maximum flow-rate of water that could enter the surge tank following an RHR heat exchanger tube rupture. The discharge from this valve is directed to the skirted area under the surge tank and then enters a floor drain routed to the auxiliary building sump. 9.2.2.2.10 Piping All piping components of the CCW system are designed to the applicable codes and standards listed in the DCPP Q-List (Reference 8 of Section 3.2). CCW system piping is carbon steel, with welded joints and flanged connections at components, and designed to USAS B31.7 for Class II and Class III pipe. A molybdate blend solution is added to the CCW as a corrosion inhibitor. 9.2.2.2.11 Component Cooling Water Filter Housing The CCW side-stream filter is provided in order to remove particulates in the CCW system. The filter housing is designed for 150 psig at 200°F. 9.2.2.2.12 Radiation Monitoring Leaks in components being cooled are detected by radiation monitors located in the two CCW pump discharge headers. Because the discharge of all three CCW pumps is into these two headers, the flow from any combination of pumps placed in operation is monitored continuously. During normal plant operations, the inservice CCW pump discharge header is determined by which of the two CCW heat exchangers is operating (see Figure 3.2-14). A single failure in the radiation monitoring system on the discharge header in operation alarms in the control room. The operator can take action to correct the problem or to put into operation the redundant heat exchanger and header. This action places the redundant radiation monitoring system into operation. During operation with both heat exchangers in service, both radiation monitors are in service continuously. Because of the discharge piping configuration, only the radiation monitor associated with the in-service CCW heat exchanger is sampling flow representative of the bulk system. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-13 Revision 21 September 2013 The CCW may become contaminated with radioactive water from any of the following sources: (1) Leakage in any heat exchanger tube or tubesheet in the chemical and volume control system (CVCS), the nuclear steam supply system (NSSS) sampling system, the RHR system, the spent fuel pool cooling system, or the gaseous radwaste system (2) Leakage in a cooling coil for the thermal barrier cooler on a reactor coolant pump (3) Leakage in a containment fan cooler coil following an accident 9.2.2.3 Safety Evaluation Refer to Section 3.1 for a more comprehensive discussion of General Design Criteria applicable to DCPP. In addition to Section 3.1, other UFSAR sections are referenced, where appropriate, for individual design basis requirements discussed under 9.2.2.3. 9.2.2.3.1 General Design Criterion 2, 1967 - Performance Standards The buildings that contain the majority of the CCW system SSCs (containment, auxiliary and fuel handling building, and the turbine building) are Design Class I or QA Class S (Section 3.8). These buildings or applicable portions thereof are designed to withstand the effects of winds and tornados (Section 3.3), floods and tsunami (Section 3.4), external missiles (Section 3.5), earthquakes (Section 3.7), and other appropriate natural phenomena and to protect CCW SSCs, and their safety functions, from damage due to these events. The loss of CCW components that are not contained within these buildings, and are directly exposed to potential wind and tornado loads, has been evaluated. Loss of this equipment does not compromise the capability to safely shut down the plant (Section 3.3.2.3). The CCW system SSCs important to safety are designed to perform their safety functions under the effects of earthquakes. The Design Class I portions of the CCW system are safety related and Seismic Category I. The Design Class II portions of CCW (except the chemical addition system) as well as components from other systems served by the non-vital CCW header (header C) have been analyzed to Seismic Category I requirements to ensure pressure boundary integrity is maintained. The chemical addition system is not required for the system to perform its safety function and is normally isolated at the Design Class I to Class II code break boundary. The makeup water for the CCW surge tank is provided by the makeup water system (MWS). This source is backed up by several alternative sources, including the Condensate Storage Tank (CST). Seismic design capability of makeup sources is discussed in Section 9.2.3. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-14 Revision 21 September 2013 The primary source of nitrogen pressurization for the CCW surge tank is the nonseismically-qualified Design Class II nitrogen system. If this supply is lost, Design Class I nitrogen is automatically supplied from dedicated bottles. The Class II plant instrument air supply (with a normally closed valve) is also available to provide the required pressurization of the tank. 9.2.2.3.2 General Design Criterion 3, 1971 - Fire Protection The CCW system is designed to the fire protection guidelines of BTP APCSB 9.5.1 (Appendix 9.5B Table B-1) 9.2.2.3.3 General Design Criterion 4, 1967 - Sharing of Systems The design basis of the CCW system does not require sharing of SSCs between Units 1 and 2 because each unit has its own CCW system. A means to cross-tie the Unit 1 and Unit 2 CCW systems (valving associated with the spare waste gas compressor piping) is available in the event of a loss of surge tank for supplying CCW from a unit with an operating CCW system to a unit with an inoperable system (e.g., to permit shutdown). However, the associated valves to Unit 2 CCW are normally closed and cross-connection is procedurally controlled. Therefore, safety is not impaired by the sharing. 9.2.2.3.4 General Design Criterion 11, 1967 - Control Room Appropriate CCW system instruments and controls are provided to permit system operation from the control room. (Section 9.2.2.5) The CCWS pumps are designed to be remotely operated from the hot shutdown panel in the event that the main control room is uninhabitable (Section 7.4.2.1.2.2). 9.2.2.3.5 General Design Criterion 12, 1967 - Instrumentation and Control Systems Required controls for CCW components are provided for system operation. Instrumentation is provided for monitoring CCW system parameters during normal operations and accident conditions (Section 9.2.2.5). 9.2.2.3.6 General Design Criterion 17, 1967 - Monitoring Radioactivity Releases A radiation monitor associated with each of the two CCW pump discharge headers monitors the CCW system for radioactive in-leakage. Because the discharge of all three CCW pumps is into these two headers, the flow from any combination of pumps placed in operation is monitored continuously. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-15 Revision 21 September 2013 9.2.2.3.7 General Design Criterion 53, 1967 - Containment Isolation Valves The CCW system containment penetrations that are credited as part of the containment isolation system include CCW supply/return for containment fan cooler (Group D), reactor coolant pump (Group A), and excess letdown heat exchangers (Group C). These lines can be isolated remotely from the control room. The configuration / requirements for each Group are described in Section 6.2.4.1 and a description of the isolation valves / piping configuration for each penetration is provided in Table 6.2-39. 9.2.2.3.8 General Design Criterion 57, 1967 - Provisions for Testing Isolation Valves CCW system piping that penetrates containment is provided with the capability for leak detection and operability testing. Most of the piping, valves, and instrumentation inside the containment, including the vital components, are located outside the crane wall at an elevation above the water level in containment following an accident. Exceptions are the cooling lines for the reactor coolant pumps and the reactor vessel support which are on miscellaneous nonvital header "C." This location affords radiation shielding which permits maintenance and inspection during power operation if required. 9.2.2.3.9 10 CFR 50.49 - Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants CCW system SSCs required to function in harsh environments under accident conditions are qualified to the applicable environmental conditions to ensure that they will continue to perform their safety functions. Section 3.11 describes the DCPP EQ Program and the requirements for the environmental design of electrical and related mechanical equipment. The affected components include valves, switches and flow transmitters and are listed on the EQ Master List. 9.2.2.3.10 10 CFR 50.55a(f) - Inservice Testing Requirements The inservice testing (IST) requirements for CCW system components are contained in the IST Program Plan and comply with the ASME Code for Operation and Maintenance of Nuclear Power Plants. 9.2.2.3.11 10 CFR 50.55a(g) - Inservice Inspection Requirements The inservice inspection (ISI) requirements for CCW system components are contained in the ISI Program Plan and comply with the ASME B&PV Code Section XI. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-16 Revision 21 September 2013 9.2.2.3.12 10 CFR 50 Appendix R (Sections III.G, III.J, III.L Only) - Fire Protection Program for Nuclear Power Facilities Operating Before January 1, 1979 10 CFR Appendix R requires the evaluation of the safe shutdown capability for DCPP in the event of a fire and the loss of offsite power. The CCW system satisfies the applicable requirements of 10 CFR Appendix R Section III G, fire protection of safe shutdown capability (see Appendix 9.5G), Section III J, emergency lighting (see Appendix 9.5D), and Section III L (alternative dedicated shutdown capability (see Appendix 9.5E), by either meeting the Appendix R technical requirements or by providing an equivalent level of fire safety. 9.2.2.3.13 CCW System Safety Function Requirements A malfunction analysis of pumps, heat exchangers, and valves is presented in Table 9.2-7. (1) Waste Heat Removal The CCW system is designed to remove waste heat from nuclear (primary) plant equipment and components during normal plant operation, plant cooldown, and accident conditions. Analytical results show that the CCW system performs adequately during design basis accidents while providing cooling to all safety-related components cooled by CCW. In the event of a LOCA or MSLB, non-vital / unnecessary heat loads are isolated and analyses demonstrate that the CCW system does not exceed its design basis temperature limit under maximum mechanistically calculated heat loads. At least two CCW pumps must be in operation to ensure that the minimum CCW flow rates are achieved. Safety analyses for containment peak pressure demonstrate that only one ASW pump and one CCW heat exchanger is required to provide sufficient heat removal from containment to mitigate a MSLB or LOCA (see Section 6.2). The analyses were performed assuming minimum CCW flow rate to the CFCUs. Other critical assumptions incorporated into those analyses include the CCW flow rate to the CCW heat exchanger, and CCW heat exchanger UA (heat transfer index and area of the heat exchanger, see Section 6.2). Analyses that demonstrate the CCW system does not exceed its design basis temperature limit following a LOCA or MSLB credit one or two ASW pumps, depending on the assumed single failure. A single CCW heat exchanger was assumed to be in service throughout the transient (except as noted in Section 9.2.2.2). These analyses assume single failures that maximize heat input to the CCW system and maximum flow rates consistent with the system flow balance. The limiting post-LOCA injection phase CCW temperature transient is an SSPS Train A failure scenario. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-17 Revision 21 September 2013 The limiting post-LOCA recirculation phase CCW temperature transient results from an SSPS Train A failure scenario that conservatively assumes that only three CFCUs are in operation during the injection phase. The highest peak CCW temperature following an MSLB results from a split rupture at 30 percent power with the failure of a main steamline isolation valve. All of the limiting CCW temperature analyses assume 64°F ocean water and a single CCW heat exchanger in service. A separate set of analyses assuming a 70°F ocean water temperature credit two CCW heat exchangers in service to address operation with an elevated UHS temperature (Reference 3). Technical Specifications require that the second CCW heat exchanger be placed in service when the UHS temperature is greater than 64°F. The CCW system is qualified for a maximum post-accident supply temperature of 140°F for a period of up to 6 hours, and a long-term continuous supply temperature of 120°F. Therefore, predicted CCW temperatures during both normal and accident conditions are within the limits of the CCW system temperature qualification. (2) Single Failure The CCW system is designed to continue to perform its safety function following an accident assuming a single active failure during the short-term recovery period and either a single active or passive failure during the long-term recovery period. Refer to Section 3.1.1 for a description of DCPP single failure criteria and definition of terms. During normal operation and up to 24 hours after an accident (the short-term recovery period), the CCW headers are crosstied. This configuration will withstand a single active failure without the loss of safety function. For a passive failure (up to a 200 gpm leak for 20 minutes), operator mitigation action (consisting of valve manipulations) is credited to stop leaks (see Table 9.2-7). The CCW headers are evaluated for separation, per procedure, during long term post LOCA recirculation. When separated during the remainder of the recovery period, this configuration will withstand either an active failure or a passive failure without the loss of safety function. (3) Dynamic Effects The plant is designed so that a postulated piping failure will not cause the loss of needed functions of safety related systems and structures that would prevent safe shutdown. The measures taken in design and construction of the plant for protection against dynamic effects both inside and outside containment are discussed in Section 3.6. CCW SSCs important to safety are designed, located, or protected against dynamic effects. With respect to post-accident conditions in containment, DCPP UNITS 1 & 2 FSAR UPDATE 9.2-18 Revision 21 September 2013 most of the piping, valves, and instrumentation are located outside the crane wall at an elevation above the water level in containment following an accident. Exceptions are the cooling lines for the reactor coolant pumps and the reactor vessel support which are on portions of header C inside the crane wall. The vital portions of the CCW system within the containment are protected during accidents from dynamic effects associated with accidents by routing piping away from high energy lines and from credible internal missiles by separation / barriers (Section 6.2.4.1.5). The CCW pumps, heat exchangers and associated valves, and all of the large piping and instrumentation are located outside containment. Each CCW pump is protected against flooding due to rupture of another because they are located in separate compartments with a raised curb in the doorway to prevent water in the rest of the auxiliary building from entering the compartment. Check valves are provided on each pump discharge to prevent back leakage into a compartment from an operating pump. Flooding of the CCW heat exchangers is highly improbable because of their location on the turbine building ground level where there are large door openings to allow water to run out, several floor drains, sumps, and a large condenser pit below the elevation of the heat exchangers. Based on this, operation of the heat exchangers would not be impaired by flooding. (4) Redundancy The CCW system components that are considered vital are redundant. The redundant vital CCW headers served by headers A and B supply cooling water to the containment fan coolers, the RHR heat exchangers, each redundant set of ESF pumps (safety injection, centrifugal charging, and RHR), and the CCW pumps. The automatic flow cutoff (closure of inlet valve) of the non-vital header (served by header C) on containment Phase B isolation is not redundant and operator action is credited prior to realignment for recirculation if automatic isolation fails. However, analyses that assume a failure to isolate during the LOCA injection phase, or during an MSLB, demonstrate that CCW heat removal capability continues to support post-accident cooling requirements without exceeding design temperature limitations (140°F peak and 120°F for six hours). The three CCW pump motors are on separate vital 4.16 kV buses that have diesel generator standby power sources. The CCW surge tank, which is connected by two surge lines to the vital headers near the pump suction, is internally divided into two compartments by a partial height partition to hold two separate volumes of water. This arrangement DCPP UNITS 1 & 2 FSAR UPDATE 9.2-19 Revision 21 September 2013 provides redundancy to accommodate a passive failure when the CCW system is manually realigned into two trains. In the event of loss of the Design Class II nitrogen supply, Design Class I nitrogen is supplied from dedicated bottles, or the plant instrument air system will be available to provide the required pressurization of the tank. Makeup water is supplied to the CCW system through two redundant makeup valves feeding into the two redundant CCW surge lines, described in Section 9.2.3 and schematically shown in Figure 3.2-16. These air-actuated level control valves open automatically when surge tank level decreases below the associated setpoint, and normal operating conditions for the MWS allow immediate makeup to the CCW system through the makeup valves whenever they open. Redundant radiation monitors are provided in the system for detection of radioactivity entering the CCW system from the reactor coolant system (RCS) and its associated auxiliary systems. (5) Isolation The CCW piping design includes valving for isolating cooling water flow associated with individual components and for complete isolation of a header. In addition to facilitating maintenance and testing, valving is used to: 1) stop leaks from / into the CCW system, 2) prevent an unmonitored release in the event of a radiation monitor alarm, 3) isolate non-vital header C to accommodate higher heat load under accident conditions, 4) separate CCW into two trains to enhance protection against passive failure for long term accident recovery. Leaks from the CCW system arise from open drain valves or severed piping, ruptured heat exchanger tube, or other malfunction. The location of a leak can be determined by sequential isolation or visual inspection of equipment and hence stopped by closing the appropriate valve(s). Refer to Table 9.2-7 for an evaluation of leakage from the system. Leaks into the CCW system can result from heat exchanger tube failures. For the RCP thermal barrier, the system design is to contain the in-leakage to the CCW system within the containment structure. This is accomplished by closure of the outboard containment isolation valve associated with return of CCW from all reactor coolant pump thermal barriers on a high flow signal. All piping and valves required to contain this in-leakage are designed for an RCS design pressure of 2485 psig. Should a coolant leak develop from the postulated failure mode that does not result in automatic flow isolation, the corresponding increase in CCW volume is accommodated by the relief valve on the CCW surge tank. The four relief valves on the CCW returns from thermal barriers are sized to DCPP UNITS 1 & 2 FSAR UPDATE 9.2-20 Revision 21 September 2013 relieve volumetric expansion and are set to relieve at RCS design pressure. Table 9.2-6 shows components in the CCW system with a single barrier between CCW and reactor coolant water. As shown in Table 9.2-6, the pressure and temperature design requirements of the barriers in the RHR heat exchangers, the letdown heat exchanger, and the seal water heat exchanger are less than the RCS pressure and temperature during full power operation. For the letdown heat exchanger and the seal water heat exchanger, this condition results because the pressure and temperature of the reactor coolant water are reduced to the values shown in the table before the flow reaches the components. In the case of the RHR heat exchangers and RHR pumps (seal coolers), the RCS pressure and temperature are reduced to less than or equal to 390 psig and 350°F before the RHR system is brought into service to complete the cooldown of the reactor. The RHR system is protected from overpressurization as discussed in Section 5.5.7. The controls and interlocks provided for the isolation valves between the RCS and the RHR system are described in Section 7.6.2.1. Tube failure in components with design pressures and temperatures less than RCS design condition may initiate a leak into the CCW system. The radioactivity associated with the reactor coolant would actuate the CCW system radiation monitor. The monitor in turn would annunciate in the control room and close the vent valve located just upstream of the CCW surge tank back-pressure regulator to prevent the regulator from venting after sensing high radiation. The operator would then take the appropriate action to isolate the failed component. In addition to the radiation monitoring system, the operator would also receive high level and high-pressure alarms from the surge tank as it filled. If the in-leakage continued after the vent valve closed, the surge tank pressure would increase until the high surge tank pressure alarm was received and then the relief valve setpoint was reached. The relief valve on the surge tank will protect the system from overpressurization. The maximum postulated in-leakage into the CCW system is based on an RHR heat exchanger tube rupture. The relief valve will accommodate this flow. Relief valve discharge from the CCW system surge tank is routed to the skirted area under the surge tank, which then enters a floor drain routed to the auxiliary building sump. Refer to Table 9.2-7 for an evaluation of leakage into the CCW system. Under accident conditions, automatic isolation is initiated for CCW flow to the excess letdown heat exchanger on a containment Phase A isolation DCPP UNITS 1 & 2 FSAR UPDATE 9.2-21 Revision 21 September 2013 signal and for the C (non-vital) header on a containment Phase B isolation signal. Independently, the portion of the C header serving the reactor coolant pumps and vessel support coolers is also isolated. (6) Leak Detection Leakage from the CCWS can be detected by a decreasing level in the component cooling water surge tank. Using the tank geometry, an estimate of leakage rate can be determined by timing the change in indicated level. A maximum 200 gpm leak or rupture is postulated. Refer to Table 9.2-7 for a discussion of leakage from the system. A radiation monitor associated with each of the two CCW pump discharge headers is provided for the CCW system to detect radioactivity entering the CCW system from the reactor coolant system (RCS) and its associated auxiliary systems. In-leakage from components being cooled is detected by a radiation monitor associated with each of the two CCW pump discharge headers. Because the discharge of all three CCW pumps is into these two headers, the flow from any combination of pumps placed in operation is monitored continuously. Leaks can also be detected by surge tank level instrumentation and alarms. 9.2.2.3.14 Regulatory Guide 1.97 Revision 3, May 1983 - Instrumentation for Light-Water Cooled Nuclear Power Plants to Assess Plant and Environs Condition During and Following an Accident CCW post-accident instrumentation for meeting RG 1.97 guidelines consist of flow indication for CCW supply headers A & B, temperature indication for each CCW heat exchanger outlet, and containment isolation valve (CIV) position indication on the monitor light box for applicable CCW valves (Section 7.5.3.6). 9.2.2.3.15 Generic Letter 89-10, June 1989 - Safety Related Motor-Operated Valve Testing and Surveillance CCW system motor operated valves are addressed by the DCPP MOV Program Plan, and the plan applies the recommendations of GL 89-10 and associated GL 96-05. 9.2.2.3.16 Generic Letter 89-13, July 1989 - Service Water System Problems Affecting Safety Related Equipment The applicable recommendations of GL 89-13 for ongoing surveillance and control have been applied to the CCW system, including a monitoring program combining flow testing, trending, inspection, and frequent preventive maintenance. Corrosion inhibitors and additives to prevent biofouling are included as part of preventive maintenance. The CCW heat exchangers provide pressure differential indication in the control room to DCPP UNITS 1 & 2 FSAR UPDATE 9.2-22 Revision 21 September 2013 alert operators to the need for cleaning and sample coupons are used to assess conditions and effectiveness of the program. 9.2.2.3.17 Generic Letter 96-06, September 1996 - Assurance of Equipment Operability and Containment Integrity during Design-Basis Accident Condtions GL 96-06 identified the potential for waterhammer or two-phase flow in the portion of the CCW system serving the containment fan cooler units (CFCUs) and for overpressurization of piping in systems that penetrate containment during accident conditions. The CCW nitrogen pressurization system was installed in response to the waterhammer concern to mitigate the possibility of flashing and subsequent waterhammer. Subsequent review concluded that a limited amount of cavitation was possible during normal operation in the CCW flow downstream of the exit from the CFCUs, but that postaccident conditions would not result in a significant increase in the condition. Because CCWS flow balance, and thus operability, is not affected, there is no impact on the ability of the CCWS to perform its design basis function. A comprehensive review identified all containment mechanical piping and tubing penetrations and isolated piping segments inside containment. For CCW, other than the nitrogen pressurization system, no other actions were required to be taken. 9.2.2.3.18 NUREG-0737 II.K.3.25, November 1980 - Effect of Loss of Alternating Current Power on RCP Seals NUREG-0737 II.K.3.25 required confirmation that RCP thermal barriers can withstand a loss of CCW cooling water to the RCP seal coolers due to a loss of AC power for at least two hours. This requirement is accommodated because the CCW pumps are supplied from vital buses that have emergency on-site backup power (Section 9.2.2.2.1). The associated containment isolation valves are also supplied with emergency on-site backup power or are check valves (Section 6.2.4.1). 9.2.2.3.19 10 CFR 50.63 - Loss of All Alternating Current Power The CCWS provides for safe shutdown and cooldown of the reactor by removing heat from safety-related system components after a Station Blackout. The CCW system is used to cool the reactor coolant pump RCP thermal barriers to prevent overheating and degradation of the RCP seals following an SBO. The CCW pumps can be provided with alternate AC power (AAC) within 10 minutes of an SBO event. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-23 Revision 21 September 2013 9.2.2.4 Tests and Inspections The active components of the CCW system are in either continuous or intermittent use during normal plant operation, and no additional periodic tests are required. Periodic visual inspections and preventive maintenance are conducted in accordance with normal plant operating practice. 9.2.2.5 Instrumentation Applications The operation of the system is monitored with the following major or vital instrumentation:
(1) Temperature detectors at the inlet and at the outlet of each CCW heat exchanger, with control room temperature indication and alarm for heat exchanger outlet high/low temperatures (2) A control room flow indicator and low flow alarm for each header (3) Low-pressure switches with alarms and auto pump start near the inlet to each vital supply header (4) Radiation monitor and alarm in the two pump discharge headers (5) Control room level indicator and high/low level alarm for each half of the CCW surge tank (6) Flow indication, temperature indication, or pressure indication on the equipment return lines (7) Surge tank low and high pressure alarms in the control room (8) Valve position indications in the control room Design flowrates for normal, loss of coolant, and cooldown conditions are listed in Table 9.2-5.
9.2.3 MAKEUP WATER SYSTEM The MWS, shown in Figure 3.2-16, supplies demineralized makeup water of the quality and quantity necessary for normal reactor coolant services, secondary system makeup, firewater, and miscellaneous plant uses. The system has the capacity necessary to meet the water requirements of a cold plant shutdown and subsequent startup from cold conditions at a time late in core life. The MWS provides makeup to the CCW surge tank. The MWS also supplies water to the CST, which provides a supply of water for the AFW system. The following sections provide information on (a) design bases, DCPP UNITS 1 & 2 FSAR UPDATE 9.2-24 Revision 21 September 2013 (b) system description, (c) safety evaluation, (d) tests and inspections, and (e) instrumentation applications. 9.2.3.1 Design Bases The MWS has two sources of raw water supply: well water and seawater. The well water is filtered and then discharged to the reservoir by a rental pretreatment system. The seawater is treated in the rental seawater reverse osmosis systems and then pumped to the reservoir.
The reservoir water is treated in the rental makeup water system, which consists of filters, a reverse osmosis system, a vacuum deaerator, and mixed bed ion exchangers.
The seawater evaporators are not in service at this time. The water quality produced by the rental MWS meets the specification of various plant operating services, which fall under the following categories:
(1) Makeup water for the primary system (2) Makeup water for the secondary system (3) Makeup water for the CCW system and SCW system (4) Water in adequate quantity for fire fighting (5) Water supply to the AFW system (6) Provide an adequate reserve of water for startup and upset conditions for the secondary systems (7) Supply water for dilution, flushing, and cleanup The MWS provides the following levels of water quality: (1) Raw reservoir water (2) Demineralized water Most of the piping in the MWS, except the rental system piping, is constructed in accordance with ANSI B31.1, except the lines supplying water to the CVCS, firewater pumps header, AFW pumps, and CCW system. The design classifications for these various systems, structures, and components are discussed in the DCPP Q-List (see Reference 8 of Section 3.2).
DCPP UNITS 1 & 2 FSAR UPDATE 9.2-25 Revision 21 September 2013 9.2.3.2 System Description The rental seawater reverse osmosis system pumps seawater through a two-stage pressure filtration unit. The filtered seawater flows through ultraviolet sterilizers and cartridge filters. The treated seawater is then pressurized to up to 1000 psig by the high pressure feed pumps and enters the reverse osmosis pressure tubes containing seawater membrane elements. The pressurized water passes through the membrane elements as desalted product water, while nearly all dissolved salts remain in concentrated stream as brine. The desalted product water is pumped to a 5.0 million gallon open reservoir system with plastic lined concrete walls.
The well water is pumped to a 100,000 gallon raw water storage tank. From the raw water storage tank, the water is processed through the rental pretreatment system and then discharged to the open reservoir. The reservoir water is treated with sodium hypochlorite to retard algae growth.
The reservoir water is treated by a rental makeup water system. The system is capable of producing up to 600 gpm of deoxygenated/demineralized water for makeup to the CST or primary water storage tank. The rental makeup water system consists of reverse osmosis, vacuum deaerator, and mixed-bed demineralizers. The system supplies makeup water of the quality and quantity necessary for normal reactor coolant services, secondary system makeup, and miscellaneous plant uses.
The water produced by the rental MWS is distributed to the condensate, primary, or transfer tank for storage. The CST is used to supply the secondary system makeup, the AFW system, the auxiliary boiler, and the CCW system. The primary water storage tank, which has a diaphragm seal to minimize O2 contact, supplies water for the primary system. 9.2.3.2.1 Raw Water Reservoir The raw water reservoir has a combined capacity of 5.0 million gallons. It has concrete-lined walls and is primarily intended to serve as fresh water storage for fire protection. The reservoir also serves as a source to the MWS and the AFW pumps, providing a large water storage reserve when the raw water supply is lower than the MWS demand. 9.2.3.2.2 Transfer, Distribution, and Storage The 200,000 gallon primary water storage tank is diaphragm-sealed to maintain the low oxygen content required for the reactor makeup water. Water may not enter the reactor makeup loop except through the demineralized water system. Design and operating parameters of the primary water storage tank are given in Table 9.2-9.
The primary water storage tanks have been designed and erected to Design Class II standards and should contain only highly purified water. Gross leakage from the tanks DCPP UNITS 1 & 2 FSAR UPDATE 9.2-26 Revision 21 September 2013 can be detected by level indication or visual inspection. The tank level is continuously monitored by the plant computer, and a high or low water level will initiate a control room alarm. 9.2.3.3 Safety Evaluation The water for decay heat removal by the AFW pumps is reserved in the CSTs (one for each unit) and supplied to the pump suction through Design Class I piping. The AFW reserved supply of approximately 225,000 useable gallons of water (approximately 13,000 gallons of the CST volume are not usable) is ensured by installed internal plenums at the connections for all other consumers of CST inventory in the usable volume region. Refer to Section 6.5.2.1.1 for additional information on usable inventory. The raw water reservoir source is also used as a backup for the AFW pumps.
There is no direct connection between the raw water supply header in the plant and the CST such that any single failure of a component could cause the loss of both CST AFW and reservoir water. A failure of the normal supply header from the CST to the AFW pumps would require opening the manually-operated valves to use the raw water reservoir as a source of auxiliary feedwater. Check valves prevent back-flow of raw water through the failed header. Back-flow of condensate tank water from the AFW pumps suctions through the connections to a postulated break in the raw water supply header is prevented by check valves and normally closed manually-operated stop valves.
A portion of the suction piping to each of the three AFW pumps for each unit is common to the two feedwater sources, the reservoir, and the CST. A failure in this portion of the suction piping to the AFW pumps could draw from both sources. However, the manual stop valve to the raw water supply header is normally closed so the supply of raw reservoir water to the other unit would be unaffected by such a failure. In the affected unit, only one type of AFW pump, either turbine-driven or motor-driven, would be made inoperable by such a failure.
Makeup water for the CCW system can be provided from various water sources and through various pumps and flowpaths in the MWS. Normal operating conditions for the MWS allow immediate makeup to the CCW system through the makeup valves whenever they open (shown in the CCW system piping schematic, Figure 3.2-14). These air-actuated level control valves open automatically in the event of low level in the CCW surge tank. They close automatically when the normal operating level in the surge tank is restored or on loss of air or control power. Opening these valves is annunciated in the control room, indicating that CCW system makeup is required. Makeup water to the CCW system is normally supplied from the transfer tank through the makeup water transfer pumps. The MWS supplies water to the 150,000 gallon transfer tank. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-27 Revision 21 September 2013 The CST can be aligned as a backup water supply for the CCW system through the makeup water transfer pumps. Both the CST and the transfer path to the CCW system are Design Class I. The CST, which has a maximum capacity of 425,000 gallons, is described in Section 9.2.6. A minimum reserve of approximately 225,000 gallons is provided in this tank for auxiliary feedwater (AFW) pump operation, and approximately 13,000 gallons of the tank volume are not usable. Therefore, up to 187,000 gallons for Unit 1 and 187,000 gallons for Unit 2 may be available for makeup water to the CCW system. Refer to Section 6.5.2.1.1 for additional information on usable inventory. The most demanding transient on the water inventory of the condensate system and the CST is a full load reduction. After such a transient, as much as 345,000 gallons remain in the CST, leaving 107,000 gallons available for makeup to the CCW system. This inventory provides for more than one complete refill of the CCW system. One refill is considered adequate makeup reserve capacity. Makeup water to the CCW system from the CST cannot be assumed to be available at all times due to the possibility of the AFW system reducing inventory below the CCW system makeup nozzle or the failure of non-seismically qualified Class II piping connections to the CST located at the same elevation as the CCW system makeup water nozzle. The firewater tank, which is also seismically qualified, can be aligned as an additional makeup water supply for the CCW system. Water from the primary water storage tanks is not used for normal makeup to the CCW system as a result of IE Bulletin No. 80-10. The primary water makeup to CCW system isolation valve is normally locked closed. The lock was installed to preclude opening the valve and contaminating the CCW system with tritiated water. If the valve is to be opened, the plant operator must obtain concurrence from the chemistry and radiation protection group. The CSTs for Units 1 and 2 are cross-connected so that additional makeup is available from the other unit if required. The makeup water from the CSTs, both Units 1 and 2, is pumped from the tank to the CCW system by the Design Class I makeup water transfer pumps. Two redundant, full capacity, makeup water transfer pumps are each capable of delivering approximately 250 gpm makeup to the CCW system. Each pump is powered from the vital 480 V electrical buses, which are energized by either normal sources or the emergency diesel engine-generator units. All piping and valves in the makeup path from the CSTs (including their cross-connections) through the makeup water transfer pumps up to and including the makeup valves on the CCW system lines, are Design Class I. A 250 gpm makeup rate is considered to be greater than any credible leakage from the CCW system during normal operation or postaccident injection. This conclusion is based on the low operating pressures and the protection afforded large piping and equipment. The available sources of makeup water to the CCW system are listed below with their respective makeup capacities. The design classification for each of the tanks and pumps is identified in the DCPP Q-List (see Reference 8 of Section 3.2). DCPP UNITS 1 & 2 FSAR UPDATE 9.2-28 Revision 21 September 2013 Source Pumps (1) Transfer tank Makeup water transfer pumps, two 250 gpm pumps (2) Condensate storage tank Makeup water transfer pumps, two 250 gpm pumps (3) Primary water storage tank (Unit 1) Primary water makeup pumps (Unit 1), two 150 gpm pumps (4) Primary water storage tank (Unit 2) Primary water makeup pumps (Unit 2), two 150 gpm pumps (5) Firewater tank, 300,000 gallons Makeup water transfer pumps, two 250 gpm pumps (6) Rental makeup water system (600 gpm) can supply water to CCW system directly or via other storage tanks (condensate storage, primary water storage and firewater tanks) Makeup water transfer pumps, two 250 gpm pumps Primary water makeup pumps, four 150 gpm pumps Flowpaths 1, 3, 4, 5, and 6 are not completely Design Class I, but the number of methods does provide considerable redundancy in backup provisions for makeup water to the CCW system. The rental makeup water system is common for both units. No safety-related systems are dependent on the output of the makeup water system for their operation. Makeup water to the spent fuel pool is supplied by the MWS as described in Section 9.1.3.2. Although the raw water reservoir is not a safety-related item, its location, on a bench excavated into the ridge above the power plant at elevation 310 feet, as shown in Figure 1.2-1, poses a small potential flood risk to the site. Since a portion of the reservoir bench drains toward the power plant, the reservoir was lowered by excavating the basin entirely in rock, eliminating the risk of flooding due to dike failure. The discussion of slope stability in Section 2.5.5 provides assurances that the slope between the power plant yard and the reservoir bench will not fail. Slope failure in any other direction, which results in a reservoir rupture will release the water into Diablo Canyon.
The discussion of flooding in Section 2.4.4 provides assurance that the drainage capacity of Diablo Canyon is sufficient to pass the entire reservoir volume safely by the plant in less than 1 minute. The reservoir is lined with Hypalon sheet on reinforced concrete to prevent leakage. The level in the raw water reservoir is indicated in the DCPP UNITS 1 & 2 FSAR UPDATE 9.2-29 Revision 21 September 2013 control room and at the hot shutdown panel and low level is annunciated in the control room.
The two pipelines (12 and 6 inches) between the reservoir and the plant have been examined for their potential for flooding. The maximum combined flow from these lines if ruptured would be 7000 to 8000 gallons per minute. This flow-rate would be intercepted by the site storm drainage systems and diverted from safety-related equipment.
The 8 inch raw water supply header in the auxiliary building presents the potential flooding source with the largest volume of water (the raw water reservoir). Flooding of the auxiliary building from this header would be recognized by the annunciation of the auxiliary building sump high-level alarm. The flow would be terminated by an operator using the appropriate manual isolation valve. A volume of 345,000 gallons in the auxiliary building pipe tunnel for sump overflow storage is available to receive water flooding from this source. This storage capacity allows the operator sufficient time to close the stop valve in the yard to prevent overflooding. The flow rate of water flooding from this line is defined by MELB analysis criteria, and is bounded by that from other HELB/MELB sources. 9.2.3.4 Tests and Inspections The operating components of the rental MWS are in either continuous or intermittent use during normal plant operation and no additional periodic tests are required. Periodic visual inspections and preventive maintenance are conducted in accordance with plant procedures for plant controlled distribution system components, or in accordance with vendor procedures for the vendor-owned water treatment facilities. 9.2.3.5 Instrumentation Applications The vendor-owned makeup water treatment facility is equipped with dissolved oxygen, conductivity, silica, and organic carbon monitoring instrumentation. In the event the product from the makeup water plant exceeds the values established in plant procedures, the product is automatically diverted to the raw water reservoir until corrected. 9.2.4 POTABLE WATER SYSTEM There is no separate potable water system. Potable water is supplied by the domestic water system as discussed in Section 9.2.8. 9.2.5 ULTIMATE HEAT SINK The ultimate heat sink (UHS) dissipates residual heat after normal and emergency shutdown conditions. The following sections provide information on (a) design bases, DCPP UNITS 1 & 2 FSAR UPDATE 9.2-30 Revision 21 September 2013 (b) system description, (c) safety evaluation, (d) tests and inspections, and (e) instrumentation applications. 9.2.5.1 Design Bases 9.2.5.1.1 General Design Criterion 2, 1967 - Performance Standards The UHS is designed to withstand the effects of natural phenomena, such as earthquakes, tornadoes, flooding conditions, winds, ice, and other local site effects. 9.2.5.1.2 General Design Criterion 4, 1967 - Sharing of Systems The UHS (Pacific Ocean) is shared between the DCPP units, but safety is not impaired by the sharing. 9.2.5.1.3 General Design Criterion 11, 1967 - Control Room The UHS is available to support safe shutdown from the control room or an alternate location if control room access is lost due to fire or other causes. 9.2.5.1.4 General Design Criterion 12, 1967 - Instrumentation and Control Systems Instrumentation is provided as required to monitor UHS system variables. 9.2.5.1.5 AEC Safety Guide 27, March 23, 1972 - Ultimate Heat Sink for Nuclear Power Plants The UHS will provide in excess of 30-day supply of cooling water to be available for shutdown and cooldown after normal and emergency conditions. 9.2.5.2 System Description The Pacific Ocean is the UHS. The Pacific Ocean is the source of cooling water to the safety-related ASW system, along with other non-safety related cooling water systems discussed in Sections 9.2.3 and 10.4.5. The seawater from the Pacific Ocean passes through screening equipment located in the intake upstream of the pumps for which it supplies cooling water.
The ocean water supply to the ASW system provides the cooling and heat absorption capability required to remove waste heat under normal and emergency conditions from the nuclear steam supply system (NSSS). The waste heat from containment and other plant equipment is transferred to the CCW system. The heat picked up by the CCW system is transferred to the ASW system by the CCW heat exchangers. The auxiliary saltwater flows into the main condenser circulating water discharge structure and then into the ocean. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-31 Revision 21 September 2013 9.2.5.3 Safety Evaluation 9.2.5.3.1 General Design Criterion 2, 1967 - Performance Standards The availability of the heat sink to provide cooling when required under severe conditions is discussed in detail in Section 2.4.11.6. The most severe oceanographic phenomenon to consider is a tsunami as discussed in Section 2.4.6.6. Estimates of wave runup on the plant facility are referenced in Section 2.4.6. The expected downsurge during short periods of time would be to 9 feet below mean lower low water (MLLW). The arrangement of the intake channel and the design of the ASW pumps allow operation down to 17.4 feet below MLLW in the normal one-pump one-heat exchanger alignment. For reference, MLLW equals mean sea level (MSL) minus 2.6 feet. MSL is ground elevation zero. The auxiliary saltwater portion of the intake structure and piping systems associated with the UHS are designed to the seismic conditions and requirements described in Section 2.5 and Sections 3.7 to 3.10, respectively. These components are constructed of materials compatible with the saltwater environment, or provided with protective features, to ensure the functionality of the components required for delivering the required cooling water supply to the ASW system and CCW heat exchangers. 9.2.5.3.2 General Design Criterion 4, 1967 - Sharing of Systems The Pacific Ocean is the UHS. The Pacific Ocean is the source of cooling water to the safety-related ASW system. Because of the location of the plant on the ocean and the separation of intake and discharge structures, insignificant recirculation occurs. 9.2.5.3.3 General Design Criterion 11, 1967 - Control Room Temperature of the UHS is measured at the circulating water pumps discharge and monitored in the control room. 9.2.5.3.4 General Design Criterion 12, 1967 - Instrumentation and Control Systems Temperature of the UHS is measured at the circulating water pumps discharge and monitored in the control room. Also, the temperature is measured outside the bar racks and recorded near the hot shutdown panel. 9.2.5.3.5 AEC Safety Guide 27, March 23, 1972, - Ultimate Heat Sink for Nuclear Power Plants Maximum temperature limits exist on the UHS to ensure the heat removal capability of the ASW/CCW system in normal and accident conditions. When the UHS exceeds 64°F, both CCW heat exchangers must be placed in service. Operation with elevated DCPP UNITS 1 & 2 FSAR UPDATE 9.2-32 Revision 21 September 2013 UHS temperatures as high as 70°F is acceptable with two CCW heat exchangers in service. It has also been confirmed that the CCW heat exchangers will operate in a one pump two heat exchanger configuration. The limiting condition for operation and surveillance requirements of the UHS is discussed in the Technical Specifications (Section 3.7.9 of Reference 1). The ocean as a single water source for the UHS will provide in excess of 30 days of cooling water during normal and emergency shutdown conditions as required by AEC Safety Guide 27, March 23, 1972. 9.2.5.4 Tests and Inspections Tests and inspections of piping systems between the reactor heat source and the UHS are discussed in their respective sections. 9.2.5.5 Instrumentation Applications Temperature of the UHS is measured at the circulating water pumps discharge and monitored in the control room. Also, the temperature is measured outside the bar racks and recorded near the hot shutdown panel. 9.2.6 CONDENSATE STORAGE FACILITIES The condensate storage facilities, shown in Figure 3.2-16, provide for the storage and transfer of demineralized water from the MWS to the AFW system and to supply the normal makeup and rejection requirements of the steam plant. The following sections provide information on (a) design bases, (b) system description, (c) safety evaluation, (d) tests and inspections, and (e) instrumentation applications. 9.2.6.1 Design Bases The CST capacity is based on supplying the normal makeup and rejection requirements of the steam plant, and providing a source of feedwater for the AFW system. The seismic evaluation of these tanks is discussed in Section 3.9.3.7. All outdoor tanks are designed for atmospheric pressure and for 32 to 200°F design temperature.
The design classifications of the refueling water storage tanks, the CST, the firewater and transfer tank, and the primary water storage tanks are given in the DCPP Q-List (see Reference 8 of Section 3.2). 9.2.6.2 System Description Design and operating parameters for the condensate storage facilities are given in Table 9.2-9. The condensate storage facilities consist of a CST for each unit and a common transfer tank located outside the east end of the auxiliary building. The CST has a floating roof to minimize oxygen absorption by the stored water. The capacity of DCPP UNITS 1 & 2 FSAR UPDATE 9.2-33 Revision 21 September 2013 each CST is 425,000 gallons, which includes a minimum reserve of approximately 225,000 usable gallons for auxiliary feed pump operation and a drainable but not usable volume of approximately 13,000 gallons. Refer to Section 6.5.2.1.1 for additional information on usable inventory. (See Section 6.5.3 for a description of the AFW system.) The capacity of the transfer tank is 150,000 gallons. The CST is used for condensate makeup and rejection. The Unit 1 CST serves as a source of water to the auxiliary boiler. Makeup water to other plant systems can be supplied from the CSTs by use of the makeup water transfer pump (Section 9.2.2.3.3). The transfer tank provides a holding storage capacity while transferring water. The condensate storage facilities are shown in Figure 3.2-16.
A gravity flow line is also provided to allow water to flow between the transfer tank and condensate tank when required.
In an emergency, water can be supplied from other sources through a hose bib connected to the CST hydrazine recirculation line.
The makeup water transfer pumps can be used to pump water to the condensate tanks of Units 1 and 2 and the transfer tank. 9.2.6.3 Safety Evaluation The safety of the minimum reserve in the CST of approximately 225,000 usable gallons is discussed in Section 6.5.3. The usable volume CST reserve is ensured by internal plenums at the connections of all consumers of CST inventory in the usable volume region. Refer to Section 6.5.2.1.1 for additional information on usable inventory. The Units 1 and 2 CSTs are crosstied through a 4 inch line with normally closed double valves. The crosstie line nozzles on each tank are 19 feet above the AFW suction pipe nozzles, thereby ensuring that failure of the crosstie line cannot reduce the condensate storage capacity for steam generator makeup from the AFW pumps. The suction lines for the AFW pumps for the two units are not crosstied but do have two sources of water (the CST and the raw water storage reservoir).
The suction lines from the CSTs to the makeup water transfer pumps, which can supply makeup water to the CCW system are crosstied between Units 1 and 2 but are isolated by two manual valves. If necessary, the Unit 2 storage tank can provide an additional source of makeup water to the Unit 1 CCW system, and vice versa. The Unit 1 and 2 crosstie provides an operating flexibility that minimizes the possibility of system failure.
The storage tanks are located outside the auxiliary building and, therefore, will not be subject to any unusual postaccident environment. The codes to which the tanks were built consider normal atmospheric conditions such as wind and rain in the design guides. Protective coats of paint are applied to the outside of each tank.
DCPP UNITS 1 & 2 FSAR UPDATE 9.2-34 Revision 21 September 2013 The tornado wind and associated missiles capability of the CST is given in Table 3.3-2. As discussed in Section 3.3.2, a tornado-induced tank failure causing an instantaneously large leak and flood is extremely unlikely. Loss of this tank does not significantly compromise safe shutdown capability, since the raw water reservoir provides a backup supply of water for the AFW pumps. Leakage from the CSTs, firewater and transfer storage tank, primary water storage tanks, or refueling water storage tanks due to tornado or missile-induced damage will not result in the flooding of safety-related equipment in the auxiliary building since essentially watertight cover plates are installed over the pipe entranceway from each tank into the auxiliary building. The water will drain away from the building via the plant yard drainage system. 9.2.6.4 Tests and Inspections The water in the CSTs will be sampled periodically to determine chemical quality. In addition, the activity level of the water will be checked, and if steam generator leakage is suspected, the frequency of the activity samples of water will be increased. 9.2.6.5 Instrumentation Applications The water level in each CST is displayed on a Design Class I local indicator and redundant Design Class I recorders in the control room. High, low, and low-low water levels are alarmed in the control room. The low-level alarm on both Unit 1 and Unit 2 annunciates when the tank level is approaching the top of the internal plenums of the Class II nozzles. Refer to Section 6.5.2.1.1 for additional information on usable inventory. The purpose of the low-low level alarm is to notify the operator that the AFW supply is running low and he must align an alternate water supply. The alarm provides the operator with at least a 20 minute supply of water for the auxiliary feed pumps at a net flowrate of 880 gpm. 9.2.7 AUXILIARY SALTWATER SYSTEM The auxiliary saltwater (ASW) system, shown in Figure 3.2-17, is an open-cycle system that supplies cooling water to the CCW heat exchangers from the UHS (UHS), the Pacific Ocean, during normal operation, plant cooldown, and following a LOCA or MSLB. It transfers waste heat from the CCW system, via each CCW heat exchanger to the UHS. 9.2.7.1 Design Bases 9.2.7.1.1 General Design Criterion 2, 1967 - Performance Standards The ASW system is designed to withstand the effects of or is protected against natural phenomena, such as earthquakes, tornados, flooding conditions, winds, ice, and other local site effects. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-35 Revision 21 September 2013 9.2.7.1.2 General Design Criterion 3, 1971 - Fire Protection The ASW system is designed and located to minimize, consistent with other safety requirements, the probability and effect of fires and explosions. 9.2.7.1.3 General Design Criterion 4, 1967 - Sharing of Systems The ASW systems or components are not shared by the DCPP Units unless safety is not impaired by the sharing. 9.2.7.1.4 General Design Criterion 11, 1967 - Control Room The ASW system is designed to support safe shutdown and to maintain safe shutdown from the control room or from an alternate location if control room access is lost due to fire or other causes. 9.2.7.1.5 General Design Criterion 12, 1967 - Instrumentation and Control Systems Instrumentation and controls are provided as required to monitor and maintain ASW system variables within prescribed operating ranges. 9.2.7.1.6 10 CFR 50.55a(f) - Inservice Testing Requirements ASW system ASME Code components are tested to the requirements of 10 CFR 50.55 a(f)(4) and a(f)(5) to the extent practical 9.2.7.1.7 10 CFR 50.55a(g) - Inservice Inspection Requirements ASW system ASME Code components (including supports) are inspected to the requirements of 10 CFR 50.55a(g)(4) and (5) to the extent practical. 9.2.7.1.8 10 CFR 50 Appendix R (Sections III.G, III.J, III.L Only) - Fire Protection Program for Nuclear Power Facilities Operating Before January 1, 1979 The ASW system is designed to provide decay heat removal to achieve and maintain a safe shutdown condition for fire events. 9.2.7.1.9 ASW System Safety Function Requirements (1) Waste Heat Removal The ASW/CCW systems are designed to remove waste heat from the nuclear (primary) plant equipment and components during normal plant operation, plant cooldown, and design basis accidents. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-36 Revision 21 September 2013 (2) Single Failure The ASW system and CCW system are essentially considered a single heat removal system for the purpose of assessing the ability to sustain either a single active or passive failure and still perform design basis heat removal. (3) Dynamic Effects Vital portions of the ASW system are designed, located, or protected against dynamic effects. (4) Redundancy Vital ASW System components are redundant. (5) Isolation The ASW system includes provision for isolation of system components and may be split into separate trains during long term post-LOCA conditions. (6) Leak Detection The CCW system serves as an intermediate system between normally or potentially radioactive systems and the ASW system, which is an open-cycle system that discharges to the UHS (Pacific Ocean). 9.2.7.1.10 Generic Letter 89-10, June 1989 - Safety Related Motor-Operated Valve Testing and Surveillance The ASW system safety-related and position-changeable motor-operated valves meet the requirements of Generic Letter 89-10 and associated Generic Letter 96-05. 9.2.7.1.11 Generic Letter 89-13, July 1989 - Service Water System Problems Affecting Safety-Related Equipment The CCW heat exchangers cooled by the ASW system are subject to monitoring and maintenance programs to ensure capability to perform their safety function as an alternative to a testing program. Maintenance practices, operating and emergency procedures, and training ensure effectiveness of these programs. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-37 Revision 21 September 2013 9.2.7.1.12 Generic Letter 91-13, September 1991 - Essential Service Water System Failures at Multi-Unit Sites The DCPP procedures establish periodic flow testing, surveillance, and operability of the ASW cross-tie valve FCV-601. 9.2.7.1.13 10 CFR 50.63 - Loss of All Alternating Current Power The ASW system is configured to provide manual opening of the ASW cross-tie valve FCV-601 in support of the SBO alternate alternating current (AAC) option for recovery from SBO and for decay heat removal for safe shutdown. 9.2.7.2 System Description There is a separate ASW system for Unit 1 and Unit 2. Each unit is provided with two ASW trains with crosstie capability. Each train consists of a full capacity electric motor-driven pump, the tubeside of the CCW heat exchanger and associated supply and discharge piping for the CCW heat exchanger. Upstream of the pumps, there is a unit ASW traveling water screen and a suction bay gate for each pump. There is a vacuum relief system on each ASW supply header piping to prevent water hammer. In addition, the Unit 1 and Unit 2 ASW piping system is arranged with interunit crosstie capability.
Each train is designed with the capability of providing adequate cooling to the CCW system during normal operation, plant safe shutdowns following normal operation, and refueling modes. Equipment design margins and system redundancy allow either an active or a passive failure of any component without degrading the system's cooling function under all modes of operation, including a design basis accident.
All system boundary components are located within the turbine building, the vacuum breaker vault, and the intake structure. These locations provide access for inspections and maintenance during either normal or postaccident operation.
The components are connected via buried, plastic-lined, carbon steel pipes between these structures. The buried piping is accessible for inspections and maintenance during train outages of sufficient duration (typically refueling). 9.2.7.2.1 Auxiliary Saltwater Pumps The ASW pumps are powered from separate Class 1E 4.16-kV buses, which can be energized by either the normal source or the emergency diesel generators. All train components satisfy PG&E Design Class I criteria. The pumps are single stage, vertical, wet pit type driven by 4-kV motors. The design data for the ASW pumps are tabulated in Table 9.2-1. The piping and other essential lines (power, sensing, and control) that pass from the pumps to the main portion of the plant are shown in Figure 9.2-3.
DCPP UNITS 1 & 2 FSAR UPDATE 9.2-38 Revision 21 September 2013 9.2.7.2.2 Electrical Conduits The route of circuits F, G, and H carrying these Class 1E power and instrument signals to the ASW pumps parallels the piping between the turbine building and the intake structure, as shown in Figure 9.2-3. Embedded plastic (ABS) conduits are used. These conduits are encased in a sand envelope with a reinforced concrete slab cover throughout the entire run except at structure crossings and the portion from bluff penetration to the intake structure where they are encased in reinforced concrete envelopes. All connections to pull boxes or structures are flexible. The electrical aspects of these safety-related circuits are described in Section 8.3. 9.2.7.2.3 Intake Structure and Equipment The ASW pumps are installed at the intake structure, as shown in Figure 9.2-2. This arrangement provides a separate bay and intake bay gate for each pump. The design classification of the intake structure is given in the DCPP Q-List (see Reference 8 of Section 3.2) and the seismic analysis is presented in Section 3.7.2. The PG&E Design Class I equipment located in the intake structure are the ASW pumps, ASW motor-operated valves, ASW piping, including valves in the piping, ASW pump compartment HVAC, and some ASW instrumentation. Each unit's pair of ASW pump trains share a common traveling screen to remove floating debris from the incoming seawater. If the common screen for a unit becomes clogged with debris, seawater may be supplied to the ASW pump bays from the unit's circulating water pump bays via the demusseling valves. Level transmitters are provided on both the inlet and outlet of the ASW common traveling screen in each unit for the purpose of indication and annunciation of water level differential across the common screen and for automatic screen start. The level transmitters are shown in Figure 3.2-17. Provisions exist to control marine fouling buildup in the ASW system pump forebays, piping and the CCW heat exchanger to minimize flow blockage, and slime buildup in tubes. Flow testing is routinely performed and heat exchanger differential pressure is monitored to ensure adequate flow for heat removal capabilities. Biofouling is controlled by continuous chlorination.
The ASW pumps, traveling screens, gates, and guides are cathodically protected to protect the equipment from corrosion. 9.2.7.2.4 Piping The design classification for all ASW piping is given in the DCPP Q-List (see Reference 8 of Section 3.2). The ASW piping is designed to perform its function and maintain its integrity considering the effects of the environment and load combinations due to varying pressures, temperatures, and seismic conditions. The arrangement of the ASW system buried supply piping between the intake structure and turbine building DCPP UNITS 1 & 2 FSAR UPDATE 9.2-39 Revision 21 September 2013 is shown in Figure 9.2-3. The supply lines exit the east wall of the intake structure and are supported by thrust blocks and surrounding soil in the filled area. The supply lines are typically anchored to the circulating water conduits and are buried in the same trenches except for the new bypass piping just outside of the intake structure that is buried in soil and supported by large reinforced concrete thrust blocks. See Section 2.5.4.8 for discussion of potential liquefaction of soil beneath a portion of buried ASW piping. The supply lines are anchored in concrete to the circulating water conduits at 40-foot intervals. The pipe trench is backfilled with compacted granular fill between the anchors. Within the turbine building, the pipes are embedded in concrete.
A separate ASW line from each CCW heat exchanger discharges to the ocean at the discharge structure.
The pipe used in the ASW system is standard weight ASTM A53 and A106 seamless steel with a 1/8 inch thick layer of polyvinyl chloride thermally bonded to the pipe's interior surface and over the full face of the flanged ends. The exterior surface of the pipe is coated with epoxy for corrosion resistance.
The buried ASW supply pipes are cathodically protected by an impressed current system. In addition, the ASW supply pipes near the turbine building are also protected by a sacrificial anode system.
Due to the vulnerability of the buried portions of the ASW system supply piping to potential corrosion damage, corrosion protection for the piping is provided by an internal lining and external coating applied directly to the piping and cathodic protection systems installed at selected locations. 9.2.7.2.5 Discharge Structure The discharge structure is a massive energy dissipating device located in the coastal bluff. The arrangement of the structure and the ASW pipe discharge is illustrated in Figure 11.2-9. The structure is divided into two chambers (one for each unit) that are open to the ocean under all conditions. The two ASW return lines for each unit discharge into the chamber of that unit. The base slab of the discharge structure is keyed into and poured on sound rock. Where possible, the walls were formed directly against sound rock. 9.2.7.2.6 Heat Exchangers The design details of the CCW heat exchangers are given in Table 9.2-3. Performance of the CCW heat exchanger is based on performance curves provided by the manufacturer. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-40 Revision 21 September 2013 9.2.7.3 Safety Evaluation 9.2.7.3.1 General Design Criterion 2, 1967 - Performance Standards The design classification for PG&E Class I ASW Structures, Systems, and Components (SSC) is identified in the DCPP Q-List (see Reference 8 of Section 3.2). The PG&E Design Class I equipment located in the intake structure are the ASW pumps, ASW motor-operated valves, ASW piping, including valves in the piping, ASW pump compartment HVAC, and some ASW instrumentation. In order to provide assurance that the function of PG&E Design Class I equipment will not be adversely affected even in the unlikely event of a seismic event, the intake structure (QA Class S) was reviewed to ensure that it would not collapse. The failure analysis was based on the Hosgri earthquake discussed in Section 3.7.2. The capability of the intake structure to withstand winds, tornadoes, and associated missiles is discussed in Section 3.3, and to withstand design flood events is discussed in Sections 2.4 and 3.4. The invert depth in the ASW channel is 31.5 feet below MSL. The ASW pump's intake bells are at 23 feet below MSL, and the pumps are designed to operate with a water level at 20 feet below MSL, which envelopes the postulated tsunami drawdown conditions (see Section 2.4.6 and 2.4.11). The pump's mounting plates are located at the pump deck 2.1 feet below MSL with the motor drivers at 4 feet above MSL. Pumps and motors are situated in watertight compartments that are ventilated by forced air through a roof ventilation shaft with vent extensions (snorkels) having a high point of 49.4 feet above MSL and a low point of 45.57 feet above MSL. The ASW pump room vents are extended with steel snorkels to prevent seawater ingestion due to splash-up during the design flood event as described in Section 3.4. PG&E Design Class I equipment is thus ensured of operation during extreme tsunami drawdown and combined tsunami and storm wave runup conditions. During tsunami drawdown, each ASW pump will deliver about 85 percent of design flow due to increased static head losses. This is a temporary condition and would not result in excessive temperatures in components to be cooled. If a second ASW pump is available, the temporary condition can be avoided by running two pumps in parallel. For operation with two CCW heat exchangers with no second pump available, operator action is required to isolate one of the heat exchangers during the tsunami drawdown as described in Sections 2.4.11.5 and 2.4.11.6. Design flow can readily be maintained during high water conditions. MSL is ground elevation zero; MSL (mean sea level in feet) equals MLLW (mean lower low water in feet) plus 2.6 feet. The ASW system is the only safety-related system that has components within the projected sea wave zone. The ASW pumps are housed in watertight compartments in the intake structure. These compartments are ventilated by forced air through a roof ventilator as described in Section 2.4.5.7. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-41 Revision 21 September 2013 ASW pump vents are extended with steel snorkels that face eastward to prevent seawater ingestion due to splash-up during the design flood event and are described in Section 2.4.5.7. The pump and piping are designed to handle the increased pressure in the system due to the combination of normal system operating and temporary-high wave conditions. The expected downsurge during short periods of time would be to 9 feet below mean lower low water (MLLW). The arrangement of the intake channel and the design of the ASW pumps allow operation down to 17.4 feet below MLLW in the normal one-pump one-heat exchanger alignment. For operation with two CCW heat exchangers in service, operator action would be required to isolate one of the heat exchangers during the tsunami drawdown as described in Sections 2.4.11.5 and 2.4.11.6. PG&E Design Class I equipment is therefore assured of operation during extreme tsunami drawdown and combined tsunami and storm wave runup conditions. For reference, MLLW equals mean sea level (MSL) minus 2.6 feet. MSL is ground elevation zero. The piping and Class 1E electrical circuits associated with the ASW system are buried except for short exposed portions at the intake structure vacuum breaker vault and at the turbine building, and therefore not subject to damage due to missiles from rotating equipment or tornadoes, or due to collapse of nonseismic structures. Seismic design for the PG&E Design Class I piping (including buried and embedded portions) is provided in the applicable ASW piping stress analysis and discussed in Section 3.7. Since no surface fault movement is postulated for the site (as discussed in Section 2.5) and since consideration has been given to the ductility of the material (as discussed in Section 3.8.2.5) and the method of construction for the conduit runs, they can be assured to remain in service during and following seismic events. Wave protection measures at ground level and below to protect the ASW system buried piping and electrical conduits from tsunami/storm conditions include concrete covers, revetments, roadway slabs, pavement and gabion mattresses. The ASW pumps are housed in watertight compartments preventing flooding from occurring from sources external to the compartments. Differential rock movement would be required to overload the discharge structure. Differential rock movement or faulting is not a design criterion (see Section 2.5.4). However, if a collapse of the structure were postulated, it is not likely that the ASW flow would be obstructed. There is insufficient rubble from such a postulated collapse to block the flow from both ASW pipes. 9.2.7.3.2 General Design Criterion 3, 1971 - Fire Protection The ASW system is designed to the fire protection guidelines of NRC BTP Auxiliary Power and Chemical System Branch (APCSB) 9.5.1 (Appendix 9.5B Table B-1). Electrical conductor insulation used for these runs is flame retardant as described in Section 8.3. For exception to the cable jacket material flame retardancy requirement, refer to Appendix 9.5B. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-42 Revision 21 September 2013 9.2.7.3.3 General Design Criterion 4, 1967 - Sharing of Systems A normally closed motor-operated valve provides separation between the Unit 1 and Unit 2 ASW supply headers and is shown in Figure 3.2-17. Since the valve is normally closed, the crosstie does not expose either unit to an additional active failure. The unit crosstie provides operating flexibility in that it is possible to have the Unit 2 standby pump provide water to Unit 1 in the event the Unit 1 standby pump is inoperable and vice versa. The operating condition of Unit 2 will be considered before crosstying to prevent jeopardizing the safety of Unit 2. If Unit 2 is already in a shutdown condition during a postulated accident on Unit 1, then the Unit 2 standby saltwater pump can provide backup to Unit 1. 9.2.7.3.4 General Design Criterion 11, 1967 - Control Room Appropriate ASW system instruments and controls are provided to permit system operation from the control room (Section 9.2.7.5). The ASW pumps are designed to be remotely operated from the hot shutdown panel in the event that the main control room is uninhabitable (Section 7.4.1.2.2). 9.2.7.3.5 General Design Criterion 12, 1967 - Instrumentation and Control Systems The ASW system is monitored by the instrumentation listed in section 9.2.7.5. 9.2.7.3.6 10 CFR 50.55a(f) - Inservice Testing Requirements The ASW system contains pumps and valves classified as PG&E Design Class I. The inservice testing requirements for these components are contained in the IST Program Plan and comply with the ASME Code. 9.2.7.3.7 10 CFR 50.55a(g) - Inservice Inspection Requirements The inservice inspection (ISI) requirements for CCW system components are contained in the ISI Program Plan and comply with the ASME Code. 9.2.7.3.8 10 CFR 50 Appendix R (Sections III.G, III.J, III.L Only) - Fire Protection Program for Nuclear Power Facilities Operating Before January 1, 1979 The ASW system meets the requirements of 10 CFR 50 Appendix R Sections III G, J and L. Tables 9.5G-1 and 9.5G-2 for DCPP Units 1 and 2, respectively, list the minimum equipment required to bring the plant to a cold shutdown condition as defined by 10 CFR 50, Appendix R, Section III.G. DCPP UNITS 1 & 2 FSAR UPDATE 9.2-43 Revision 21 September 2013 The ability to safely shutdown the plant following a fire in any fire area is summarized in Section 4.0 of Appendix 9.5A. The ASW system is a support system for safe shutdown following a fire event. It is protected by fire protection system equipment installed in Fire Zones 30-A-1 and 30-A-2, with additional modifications; e.g., smoke detectors added outside ASW pump rooms in Fire Zone IS-1. 9.2.7.3.9 ASW System Safety Function Requirements (1) Waste Heat Removal The ASW system is designed to provide sufficient heat removal to maintain the CCW system within its design basis temperature limits for normal operation, plant cooldown and design basis accident conditions. The CCW system transfers heat from both vital and non-vital systems to the UHS via the ASW system during normal operations and reactor shutdown. During normal operation, both ASW pumps and one supply header are aligned with the operating CCW heat exchanger. Only one pump is required to run; the second pump, being on standby, provides backup against an active failure. By means of unit and redundant supply header crosstie motor-operated valves, the standby pump for one plant unit may act as a second standby for the other unit. The ASW system capability to perform its design basis function assumes the ASW pumps are capable of providing the minimum required flow under conditions of low tide, high CCW heat exchanger tube side differential pressure and supply temperatures up to 64°F. As discussed in Section 9.2.5, the Technical Specifications require a second CCW heat exchanger be placed in service when UHS temperature exceeds 64°F. The ASW flow rate and minimum acceptable flow are a function of the number of ASW pumps and CCW heat exchangers in service based on operating conditions and assumed single failure. The ASW system is designed to provide sufficient heat removal to maintain the CCW system within its design basis temperature limits for normal CCW system conditions. During plant cooldown the ASW and CCW systems operate together to remove heat from vital equipment as follows:
- Reactor decay heat (RHR)
- Equipment and cooling DCPP UNITS 1 & 2 FSAR UPDATE 9.2-44 Revision 21 September 2013 During the cooldown phase of a routine plant shutdown, both ASW pumps and CCW heat exchangers are in operation. If one pump or supply header is inoperative during cooldown, cooling would be accomplished safely, but the cooldown time would be extended. Following design basis accidents with a postulated single active or passive failure, the ASW and CCW systems operate together to remove heat from vital equipment including heat loads as follows:
- Reactor Decay Heat
- Containment Accident Heat Loads
- Vital Loads The ASW/CCW system must be able to remove the minimum required heat in order to ensure that the containment design pressure and temperature is not exceeded. Additionally, the ASW system must be able to remove sufficient heat from the CCW system so as to not exceed the CCW system design basis temperature limits when the containment heat removal equipment is operating at maximum predicted heat removal rates. The adequacy of the heat sink provided by the ASW/CCW systems has been evaluated to ensure that the minimum heat removal function is satisfied following a LOCA or MSLB (References 5 and 6). The ability of the ASW/CCW system to support the maximum containment heat removal without exceeding the CCW system design basis temperature limits following LOCA or MSLB has also been demonstrated (Reference 3). During the safety injection phase or upon loss of the offsite power supply, both ASW pumps receive a start signal. On a bus transfer with no SI signal or loss of the offsite power supply, the previously operating ASW pump will immediately be restarted and the standby pump will receive a start signal. This design ensures both pumps in operation following the event of accident or upset condition, excluding the condition of a Class 1E F or G bus failure. In the injection and post-LOCA recirculation phases of the accident, no operator action is required for operation or reconfiguration of the ASW system and its components. A decision to split the ASW system into separate trains to mitigate a passive failure would be made by the Technical Support Center if it became required. (Reference 8) The capacity of the ASW system is based on post-design basis accident heat rejection requirements. The ASW and CCW systems operate together to remove heat from containment and safety-related loads following a design basis accident. Together the ASW and CCW systems DCPP UNITS 1 & 2 FSAR UPDATE 9.2-45 Revision 21 September 2013 must be able to remove the minimum required heat loads to ensure that the containment design pressure and temperature limits are not exceeded. The ASW system is designed to provide sufficient heat removal to maintain the CCW system within its design basis temperature limits for post-accident CCW system conditions. The ASW system and CCW system are essentially considered a single heat removal system for the purpose of assessing the ability to sustain either a single active or passive failure and still perform design basis heat removal. The heat removal capability of the ASW/CCW system has been evaluated to ensure that the minimum containment heat removal function is satisfied following a LOCA or MSLB (References 5 and 6). A single train of ASW (one ASW pump and one CCW heat exchanger) provides sufficient heat removal from containment to mitigate an MSLB or LOCA. The ability of the ASW and CCW systems to support the maximum containment heat removal without exceeding the CCW maximum supply temperature design basis limit following a LOCA or MSLB has also been demonstrated (Reference 3). The mechanistic analyses credited one or two ASW pumps, depending on the assumed single failure. A single CCW heat exchanger was assumed to be in service throughout the transient (except when the UHS temperature exceeds 64°F, two CCW heat exchangers are assumed in service). No credit was taken for operator action to align the second CCW heat exchanger or an ASW pump from the opposite unit. The design basis for ASW system performance to support analysis for peak containment pressure is described in Section 6.2. The design basis for ASW system performance to support the analysis for peak CCW temperature transients is described in Section 9.2.2. Critical ASW system assumptions include maximum ASW temperature, minimum ASW flow rate to the CCW heat exchanger, and single pump/heat exchanger operation. (See References 3, 5, and 6.) (2) Single Failure A malfunction analysis is presented in Table 9.2-2. The ASW system and CCW system are essentially considered a single heat removal system for the purpose of assessing the ability to sustain either a single active or passive failure and still perform design basis heat removal. Refer to Section 3.1.1 for a description of DCPP single failure criteria and definition of terms. During post-LOCA long term recirculation, the ASW trains should remain cross-tied to assure that any active failure in the ASW or CCW system would not result in the loss of CCW system cooling. While vulnerable to a DCPP UNITS 1 & 2 FSAR UPDATE 9.2-46 Revision 21 September 2013 passive failure in this configuration, the ASW system capacity is such that the ASW system function would not be affected. A decision to split the ASW system into separate trains to mitigate a passive failure would be made by the Technical Support Center if it became required. (Reference 8) The ASW system is comprised of active components for which design classifications are given in the DCPP Q-List (see Reference 8 of Section 3.2). The ASW system can sustain either an active or a passive failure and still perform its function. (3) Dynamic Effects No systems that are required for safe shutdown are rendered inoperable due to flooding caused by a postulated break in the ASW piping. The low operating pressure and temperature of the saltwater system minimizes the possibility of a line severance. However, a severance would be detected and alarmed to the control room as low differential pressure across the heat exchanger and a high temperature rise across the CCW system, and possibly a pump motor failure. Sufficient valving is provided to isolate the units and their redundant trains from the failed section of piping. Most of the ASW piping is buried except for short sections in the intake structure, the vacuum breaker vaults and the turbine building. A pipe break inside an ASW pump room or outside the boundary of both unit rooms in the Intake would not jeopardize the other pump motors. Each pump is housed in its own watertight compartment; therefore a pipe break would only flood one compartment. No components required to be operated for safe shutdown are located in the vacuum breaker vault. Failure of the ASW supply inside the turbine building would result in draining to the turbine building sumps; a break in the ASW system discharge piping to the ocean would not result in flooding of the turbine building unless flow blockage in the line occurs, since the line pressure is negative. In the event that the entire contents of the hotwell and heater drain tanks are discharged to the turbine building, the operability of PG&E Design Class I equipment (component cooling water heat exchangers) in the building is not endangered. The volume of water that would be discharged is within the capacity of the turbine building drain system. This system includes one 18-inch drain line from the turbine building sump of each unit to the circulating water system discharge structure (see Figure 3.2-27 and refer to Table 1.6-1). If this drain were clogged, the water flow would begin to fill the turbine building sumps and equipment pits below 85 feet (see Figures 1.2-16 and 1.2-20). However, the capacity (58,000 cubic DCPP UNITS 1 & 2 FSAR UPDATE 9.2-47 Revision 21 September 2013 feet) below this elevation is more than the potential flooding volume. Refer to Section 10.4.7 for further discussion of flooding in the turbine building. The ASW system is physically separated from all piping carrying high-energy fluid. The ASW system is a moderate-energy system as described in Section 3.6. (4) Redundancy Redundancy is provided by having two ASW pumps, one running and one on standby, and two CCW heat exchangers, with one normally in service and one in standby. The ASW system can be cross-connected within trains and between units so that various pump-heat exchanger combinations can be used for cooling. Redundant vacuum breakers are installed at the vertical bend of each line to eliminate water hammer. Each unit's pair of ASW pump trains shares a common traveling screen to remove floating debris from the incoming seawater. If the common screen for a unit becomes clogged with debris, seawater may be supplied to the ASW pump bays from the unit's circulating water pump bays via the demusseling valves. Level transmitters are provided on both the inlet and outlet of the ASW common traveling water screen in each unit for the purpose of indication and annunciation of water level differential across the common screen and for automatic screen start. The level transmitters are shown in Figure 3.2-17. (5) Isolation The design classification of the CCW heat exchangers is listed in the DCPP Q-List (see Reference 8 of Section 3.2). Rupture of the heat exchanger tubes or channel is considered highly unlikely because of low operating pressures and the use of corrosion-resistant materials. However, a leaking heat exchanger can be identified by sequential isolation or visual inspection. If the leak should be in the operating heat exchanger, the standby heat exchanger will be placed in operation and the leaking heat exchanger isolated and repaired. (6) Leak Detection Provisions exist to isolate the CCW heat exchanger on both the ASW (tube-side) and CCW (shell-side). Large leakage could be detected by differential pressure across the tube side of the heat exchanger, by a decrease in CCW flow out of the heat exchanger, or by makeup to the CCW system.
DCPP UNITS 1 & 2 FSAR UPDATE 9.2-48 Revision 21 September 2013 The ASW discharges directly to the UHS. The ASW system provides cooling to the CCW heat exchanger. The CCW system is normally non-radioactive; however, the radiation level of the CCW system is monitored and an alarm is provided with a predetermined radiation level setpoint (refer to Section 11.4). In the event of an alarm for radiation on the CCW system, immediate efforts would be made to isolate the in-leakage. If the in-service CCW heat exchanger developed a leak at the same time, the heat exchanger would be isolated and the standby heat exchanger placed in service. Potential radioactive leakage into the CCW system is monitored to prevent/minimize release to the environment, via the ASW System, in the event of a concurrent leak in the heat exchanger. Molybdate concentration in the CCW system is maintained by procedure for corrosion prevention. In the event of a leak, small or large, the chemical concentration in plant effluent would be greatly reduced by dilution with the ASW system and then by the main CWS. 9.2.7.3.10 Generic Letter 89-10, June 1989 - Safety-Related Motor-Operated Valve Testing and Surveillance The ASW system motor-operated valves subject to the requirements of GL 89-10 and associated GL 96-05 meet the requirements of the DCPP MOV Program Plan. 9.2.7.3.11 Generic Letter 89-13, July 1989 - Service Water System Problems Affecting Safety-Related Equipment Design fouling is considered in accident analyses. Fouling is a combination of tube microfouling and tube flow blockage resulting from marine life. Mechanical tube plugging is limited to two percent of the tubes before the performance of the heat exchanger, as defined by the curves, is impacted. As noted in Section 9.2.7.2.3, provisions exist to control marine fouling on the tube side (ASW) of the CCW heat exchanger. Cathodic protection is provided on the tube side of the heat exchanger in the waterboxes. 9.2.7.3.12 Generic Letter 91-13, September 1991 - Essential Service Water System Failures at Multi-Unit Sites A normally closed motor-operated valve provides separation between the Unit 1 and Unit 2 ASW supply headers and is shown in Figure 3.2-17. Since the valve is normally closed, the crosstie does not expose either unit to an additional active failure. The unit crosstie provides operating flexibility in that it is possible to have the Unit 2 standby pump provide water to Unit 1 in the event the Unit 1 standby pump is inoperable and vice versa. The operating condition of Unit 2 will be considered before crosstying to prevent jeopardizing the safety of Unit 2. If Unit 2 is already in a shutdown condition during a postulated accident on Unit 1, then the Unit 2 standby saltwater pump can DCPP UNITS 1 & 2 FSAR UPDATE 9.2-49 Revision 21 September 2013 provide backup to Unit 1. Equipment Control Guideline 17.1, "Auxiliary Saltwater Cross-Tie Valve FCV-601," provides requirements for the valve operability. 9.2.7.3.13 10 CFR 50.63 - Loss of All Alternating Current Power Inter-unit cross-tying is not credited for additional heat removal capability by the ASW and CCW system for any design basis accident analyses. However, ASW inter-unit crosstie capability via FCV-601 has been credited in the station blackout analysis and in response to NRC Generic Letter 91-13. 9.2.7.4 Tests and Inspections The operating components are in either continuous or intermittent use during normal plant operation. Periodic testing of the standby feature of the ASW pump, testing of alarm setpoints, and visual inspections and preventive maintenance will be conducted in accordance with normal plant operating practices. 9.2.7.5 Instrumentation Applications The ASW system is monitored by the following instrumentation:
(1) Differential pressure transmitters for both CCW heat exchangers (2) ASW header pressure indicators (3) Automatic start feature of the standby pump on loss of header pressure with pump status indicator in the control room (4) Temperature indicators on the CCW heat exchanger, ASW (tube side) inlet and outlet (5) Valve position indicators in the control room (6) Differential level across the traveling water screens (7) ASW pump room high water level alarm (8) ASW pump room watertight door alarm (9) High-temperature alarm for the ASW pump room (10) ASW pump motor temperature indicators: upper/lower bearings and motor stator winding (11) Inlet gate position indicator DCPP UNITS 1 & 2 FSAR UPDATE 9.2-50 Revision 21 September 2013 (12) CCW heat exchanger, CCW (shell side) outlet temperature indicators (13) ASW pump bay level indication (14) ASW pump bay level alarm 9.2.8 DOMESTIC WATER SYSTEM The domestic water system (DWS) processes raw water from the reservoir to provide water suitable for human consumption. The following sections provide information on (a) design bases, (b) system description, (c) safety evaluation, (d) tests and inspections, and (e) instrumentation applications.
9.2.8.1 Design Bases The DWS is designed to provide drinking water at the plant. It is a Design Class III system. 9.2.8.2 System Description The DWS receives its water from the rental domestic water treatment system. The rental domestic water treatment system takes water from the reservoir and processes it through a multi-media filter, a reverse osmosis module, a neutralizing-media filter, an activated carbon filter, and finally through a 10-micron cartridge filter. Prior to transferring the water to the domestic water storage and distribution piping system, it is disinfected using chlorine. The water is then supplied to the plant for drinking. The radioactively uncontaminated utilities that receive domestic water include:
(1) Lavatories (2) Water heaters (3) Showers (4) Maintenance connections (5) Water closets (6) Emergency eye wash (7) Hose bibs (8) Kitchen sinks (9) Chemical laboratory sink in the chlorination building DCPP UNITS 1 & 2 FSAR UPDATE 9.2-51 Revision 21 September 2013 (10) Drinking fountains (11) Chemical laboratory sinks in maintenance shop buildings (12) Landscape irrigation After use, the domestic water passes into the plant sewage system where it is treated in a sewage treatment plant before being discharged to the ocean.
The potentially radioactively contaminated utilities that use domestic water are:
(1) Hot showers
(2) Laundry facilities (3) Laboratory sinks (4) Washdown area in hot machine shop This water, after being used, drains to the liquid radwaste system (see Section 11.2) for treatment. 9.2.8.3 Safety Evaluation Failure of this system will not affect nuclear safety. Back-flow preventers are provided to prevent contamination of the domestic water by back-siphonage from potentially radioactively contaminated areas. 9.2.8.4 Tests and Inspections Water quality tests and system integrity inspections will be performed periodically in accordance with normal plant operating procedures. 9.2.8.5 Instrumentation Applications Local flow, pressure, and temperature indicators are used to monitor the system condition. 9.
2.9 REFERENCES
- 1. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
- 2. Deleted in Revision 8
DCPP UNITS 1 & 2 FSAR UPDATE 9.2-52 Revision 21 September 2013 3. Evaluation of Peak CCW Temperature Scenarios for Diablo Canyon Units 1 and 2, WCAP-14282, Revision 1. 4. Deleted in Revision 12.
- 5. Analysis for Containment Response Following Loss-of-Coolant Accidents for Diablo Canyon Units 1 and 2, December 1993, WCAP-13907.
- 6. Analysis for Containment Response Following Main Steam Line Break for Diablo Canyon Units 1 and 2, December 1993, WCAP-13908.
- 7. NRC Letter, dated May 13, 1999, "Issuance of Amendments for Diablo Canyon Nuclear Power Plant, Unit No. 1 (TAC No. M98829) and Unit No. 2 (TAC No. M98830) and Close-out of Generic Letter 96-06 (TAC Nos. M96804 and M96805) (License Amendments 134/132)
- 8. NRC Letter, dated January 13, 2000, "Issuance of Amendments for Diablo Canyon Nuclear Power Plant Unit Nos. 1 and 2 (TAC Nos. MA 1406 and MA 1407) (License Amendments 138/138)
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-1 Revision 20 November 2011 9.3 PROCESS AUXILIARIES The process auxiliaries consist of those auxiliary systems associated with the reactor process systems. These systems include the compressed air systems, the backup air/nitrogen supply system, the sampling system, equipment and floor drainage systems, the chemical and volume control system (CVCS), failed fuel detection (performed using the sampling system), nitrogen and hydrogen systems, and miscellaneous process auxiliaries (i.e., the auxiliary steam system, and the oily water separator and turbine building sump system). 9.3.1 COMPRESSED AIR SYSTEM The compressed air system, shown in Figure 3.2-25, provides compressed air for process control systems and for station service throughout Units 1 and 2 under normal operating conditions. The compressed air system is not required for containment isolation. The compressed air system, excluding the backup air/nitrogen supply system, as described in Section 9.3.1.6, is not required for reactor protection, containment isolation, or engineered safety features (ESF). The following sections provide information on: (a) design bases, (b) system description, (c) safety evaluation, (d) tests and inspections, and (e) instrumentation applications. 9.3.1.1 Design Bases The compressed air system is shared by Units 1 and 2. The DCPP Q-List (see Reference 8 of Section 3.2) lists its design classification.
9.3.1.2 System Description The compressed air system arrangement for Units 1 and 2 is shown in Figure 3.2-25. Table 9.3-1 lists design data for the components.
Four reciprocating air compressors, rated 334 scfm each, and two rotary screw compressors, rated 650 scfm each are located in the turbine area of Unit 1, in addition to one rotary compressor, rated at 650 scfm located at the Unit 1 west buttress. These compressors supply instrument air to Units 1 and 2. Normally, one of the rotary screw compressors operates as a base loaded machine and the other rotary compressors and the reciprocating compressors are on automatic standby - start control. A master compressor loading controller automatically loads and unloads the reciprocating compressors at preselected system supply header pressures. Each rotary screw compressor has its own control panel and local loading/unloading switch sensing pressure at the system supply header. Start and stop operation of rotary screw compressors is manual from their local control panel. Once started, these compressors load and unload automatically.
The compressors have nonlubricated cylinders to provide an oil-free air system. (Local oiling units are provided on the service air system where equipment requires DCPP UNITS 1 & 2 FSAR UPDATE 9.3-2 Revision 20 November 2011 lubricated air.) Except for the rotary screw compressor at the Unit 1 west buttress, each compressor has a water-cooled aftercooler separator. The rotary screw compressor at the Unit 1 west buttress is an air-cooled machine identical to the water-cooled rotary compressors inside the turbine building. An additional water-cooled after cooler and moisture separator with drain trap is provided downstream of the rotary screw compressors in the common line going to pre-filters to further reduce the water load of the air entering the air dryers.
Prefilters upstream of the air dryers protect the desiccant beds from contamination by entrained water, pipe scale etc.; thereby extending desiccant life. The system has two air dryers, one of which is an "adsorbent heat-regenerative" type and the other a "heatless" type. Both air dryers are designed to produce -40°F pressure dewpoint with a dryer inlet air temperature of 100°F and a pressure of 100 psig. However, the system components served by instrument air do not require that the system pressure dewpoint be maintained at -40°F. The air system pressure dewpoint is maintained at least 18°F below the minimum temperature at any point in the instrument air system to preclude water blockage of instrument air lines and to prevent a buildup of rust that can break free and block instrument air lines. The system pressure dewpoint is monitored by a direct reading dewpoint indicator, with a "high moisture content" local alarm and "common trouble alarm" in the main control room.
Dry air leaving the air receiver is filtered through a 1 micron positive seal type after-filter before passing to the instrument air distribution system. The after-filter is provided with differential pressure indication, with a "high differential pressure" local alarm and a "common trouble alarm" in the control room. The two air receivers provided act as "pulsation dampers" to eliminate the pressure pulses that reciprocating compressors generate. They also provide storage capacity to meet occasional high demands for compressed air.
Alarms in the control room indicate:
(1) "Common trouble" instrument air (2) "Common trouble" service air (3) Status of the standby reciprocating air compressors The "Common Trouble" Instrument Air alarms are comprised of various system and component abnormal operations, which are flashed at the local annunciator "PK-80" located near the compressors at the 85 ft elevation in the turbine building.
The "common trouble" service air alarms are comprised of:
(1) Service air high moisture DCPP UNITS 1 & 2 FSAR UPDATE 9.3-3 Revision 20 November 2011 (2) Service air low pressure Local indications for the service air system moisture and pressure are provided near Unit 2 containment access controls at elevation 140 ft of the turbine building.
That portion of the air distribution piping penetrating the containment is isolated automatically following a containment isolation signal.
The service air system - located outdoors east of Unit 2 transformer yard, has two rotary screw compressors: one rated at 650 scfm and the other at 1050 scfm. Power supply to these compressors is from the 12 kV underground distribution system. Normally, one of the rotary compressors operates as a base-loaded machine and the other rotary compressor is on automatic standby - start control. Rotary compressors automatically load and unload at pre-selected system supply header pressures. Each rotary compressor has its own control panel and local loading/unloading switch sensing pressure at the system supply header. Start and stop operation of the compressors is manual from its local control panels. Once started, these compressors load and unload automatically.
The system has three air dryers, two of which are "heatless" type and the other a "heat of compression" type. Like the instrument air system air dryers, these dryers are also designed to produce -40°F pressure dewpoint. The service air system pressure dewpoint is also maintained within the limits stated above for the instrument air system. Dry air leaving the air dryers is filtered through a micron positive seal type after-filter before passing to the service air distribution system. Additional temporary compressors are used, as appropriate, to supply supplemental service air. During normal operation the service air system is isolated from the instrument air system. A cross-tie line between the service air and the instrument air system can be used to supply instrument air in the event of a failure of the instrument air compressors. To maintain instrument air purity, the backfeed air enters the instrument air system upstream of the instrument air after filters. 9.3.1.3 Safety Evaluation The compressed air system is required for startup and normal operation of the plant, but it is not required for safe shutdown, reactor protection, containment isolation, or ESFs. Consequently, except for the portion of the backup air/nitrogen supply system described in Section 9.3.1.6, and the portion of the air distribution piping penetrating the containment, the compressed air system is Design Class II. The portion of the air distribution piping penetrating the containment is Design Class I and meets single failure criteria required for containment isolation as described in Section 6.2.4.
Pneumatically operated devices are identified in the piping schematics of the various systems in Section 3.2. Loss of the normal air supply from the compressed air system will result in a safe shutdown of the unit. Most pneumatically operated devices in the DCPP UNITS 1 & 2 FSAR UPDATE 9.3-4 Revision 20 November 2011 plant that have safety-related functions are designed to maintain a safe position or to assume a safe position upon loss of air pressure. Movement to this safe position (or maintaining this safe position) is accomplished by means of spring-return actuators and compressed gas from the backup air/nitrogen supply system. All such pneumatically operated devices are designed to achieve this safe position in the required time under the most limiting conditions, including gradual loss of the normal air supply from the compressed air system. If an air operated valve is required to operate after an assumed loss of the compressed air system, then that valve is also provided with a backup supply of compressed gas from the backup air/nitrogen supply system. Tables 3.9-9 and 6.2-39 show how valves will fail on loss of air or electrical power and the desired condition for safe shutdown. The tabulations show that most air-operated valves fail in the safe shutdown position upon loss of power or air. The tabulations also show the air operated valves that are required to operate or be maintained in a certain position for safe shutdown after an assumed loss of the compressed air system and that they are supplied with compressed gas from the backup air/nitrogen supply system. Therefore, safe shutdown will not be compromised upon loss of power or the compressed air system.
The main steam isolation valves receive a close signal on indication of a main steam line rupture (low steam line pressure, above P-11 setpoint, or high steam line pressure rate, below P-11 setpoint, in any steam line), or high-high containment pressure. Locally mounted air reservoirs, protected against system failure by check valves, can hold open the main steam isolation valves for a short duration of time to allow for recovery of the air system. However, if the air system cannot be recovered, the plant can still be safely shutdown with the main steam isolation valves closed. Since the compressed air system is not required for proper operation of pneumatically operated devices which have safety-related functions, the system is not automatically switched to emergency diesel generator power in the event of a loss of power. However, if diesel generator loading conditions permit, the air compressors can be manually restarted on emergency diesel generator power.
In order to ensure that oil, water, or other impurities will not result in the failure of instrumentation or other equipment, the compressed air system is provided with oil-free compressor cylinders, prefilter, moisture separator, air dryers, and 1-micron after-filters.
Since the compressed air system is not required for proper operation of pneumatically operated devices, which have safety-related functions, sharing one air system for both units does not affect plant safety. A major failure of the distribution system for one unit could result in a loss of air pressure for the second unit but would not affect the safety of either unit. Manual isolation valves between units and on all major distribution headers allow isolation of sections of the system without affecting the normal operation of the remainder of the system. Automatic containment isolation will prevent accident conditions from propagating through the air system.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-5 Revision 20 November 2011 Equipment essential for a safe and maintained reactor shutdown is located near major components of the compressed air system. This equipment is separated from these components by a Design Class I concrete wall. As discussed in Section 3.5.2, the air receiver tanks (shown in Table 3.9-6) are capable of withstanding the thrust developed by failure of the largest pipe connected to them. The stresses in the tank holddown structure relating from this thrust do not exceed yield strength. Thus there is no danger to safe shutdown from postulated missiles created by the compressed air system. 9.3.1.4 Tests and Inspections The compressed air system was tested and inspected prior to initial plant operation. Provisions are made for functional tests of the low air pressure alarm and containment isolation. Filters, air dryers, and air receivers are periodically inspected. 9.3.1.5 Instrumentation Applications Instruments are provided to indicate operational status of the major components of the compressed air system. Activation of the standby reciprocating air compressor to full operational status is displayed in the control room. 9.3.1.6 Backup Air/Nitrogen Supply System The plant can be taken to and maintained at hot shutdown without the use of air-operated valves. However, some air-operated valves are required for going from hot shutdown to cold shutdown. Section 9.3.1.6.1 describes the backup air/nitrogen supply system, which provides a backup supply of compressed gas to the air-operated valves that are required to take the plant to cold shutdown and for those pneumatic operated valves that require a backup supply of compressed gas for other functions. 9.3.1.6.1 System Description The backup air/nitrogen supply system supplies the motive force to operate certain pneumatic components in the event of a loss of the compressed gas system. In some cases the backup air/nitrogen supply system supplements the compressed gas system rather than serving as a backup air / nitrogen supply. The backup air/nitrogen supply system utilizes as its source instrument air supplied from the compressed air system, and high pressure nitrogen supplied from the nitrogen system, which is then stored for use in accumulators. In addition, high pressure bottled air, high pressure bottled nitrogen and low pressure nitrogen from the nitrogen system are utilized. Compressed gas from these sources are supplied to pneumatic components that normally use instrument air from the compressed air system or high-pressure nitrogen from the nitrogen supply system.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-6 Revision 20 November 2011 Most pneumatic-operated valves are designed to fail to their safe position in the event of a loss of the compressed gas system. However, some pneumatic-operated valves are required to operate or be maintained in a certain position after an assumed loss of the compressed gas system and are supplied with compressed gas from the backup air/nitrogen supply system.
The backup air/nitrogen supply system supplies compressed gas to the safety-related pneumatic-operated components that are required to perform an active safety-related function after the loss of the compressed air system. The backup air/nitrogen supply system also supplies air/nitrogen to selected components, pursuant to PG&E's commitments to the NRC to provide a seismically qualified backup air/nitrogen supply; hence these components are classified as safety-related even though operability of the valves is not strictly a safety-related function. Design classifications are included in the PG&E Q-List (see Section 3.2).
In addition to the safety-related components described above, there are a number of nonsafety-related components that have a backup supply of air/nitrogen in the event of loss of the compressed air system to prevent undesirable transients and/or to facilitate normal operation and shutdown. In addition, there are some components, or group of components, that when actuated require more air than can readily be supplied through the air/nitrogen supply connection. In these cases, local accumulators or receivers are provided that contain enough stored gas to allow these components to respond in the desired time. Design classifications are included in the PG&E Q-List (see Section 3.2).
To take the plant to cold shutdown from hot shutdown, compressed gas from the backup air/nitrogen supply system is provided to valves for charging/spray capability, steam dump capability, and reactor coolant system (RCS) boration sample capability. In addition, the operator also will have available the pressurizer power-operated relief valves (PORVs) required for overpressure protection, the capacity of letdown by line isolation valves, and containment fire water isolation valves. Backup air is also supplied to component cooling water (CCW) control valves on the outlet of the residual heat removal (RHR) heat exchanger and the auxiliary saltwater (ASW) control valves on the inlet of the CCW heat exchanger to ensure that these valves may be operated or maintained in the required position for safe shutdown.
Backup air/nitrogen for shutdown is provided in four ways:
(1) RCS boration sample valves are equipped with air accumulators that are protected from back flow into the main system by check valves. These can be used because the number of cycles for each valve is small, the air required for each valve is small, and the valves do not consume air in the quiescent state. The containment fire water isolation valve, the RHR heat exchanger CCW outlet valves and CCW heat exchanger ASW inlet valves are also equipped with accumulators to ensure that the valves can be operated or maintained in the required position for safe shutdown in the event of a loss of offsite power that causes the loss of the compressed air DCPP UNITS 1 & 2 FSAR UPDATE 9.3-7 Revision 20 November 2011 system. The containment fire water isolation valve is equipped with a seismically qualified accumulator to help ensure the valve can remain open in the event of a fire after an earthquake so that manual fire fighting capabilities are available inside containment to the safety-related equipment. (2) Throttling valves (the steam generator 10 percent atmospheric steam dump valves, or ADVs) and charging pump valve (the discharge to regenerative heat exchanger) consume air in the quiescent state. These valves are supplied with backup nitrogen supplies. The nitrogen system is capable of supplying motive gas as long as required since the requirements are small compared to the system capacity. The nitrogen system is not seismically qualified, so a second backup system is provided. It is composed of compressed air bottles for the 10 percent ADVs which can supply varying amounts of air via solenoid valves controlled from the control room and a nitrogen accumulator for the charging pump valve. Should the compressed air system and the nitrogen backup systems both fail, the compressed air bottles will be enabled by the operator to allow the operator to position the 10 percent ADVs at any position desired. The charging pump valve (the discharge to regenerative heat exchanger) needs only to be placed in the open or closed position, so its backup consists of a control-room-operated solenoid valve that can supply motive gas from the nitrogen accumulator bypassing the normal control system. (3) Letdown line isolation valves are supplied with backup nitrogen from the nitrogen system. (4) The pressurizer PORVs, charging pump valves (to loop 3 and loop 4 of the cold leg), and the pressurizer auxiliary spray valve are special cases of on-off valves. Due to the number of cycles and the size of the valves, normal air receivers would be huge. Therefore, a high pressure nitrogen accumulator for each valve is provided which is supplied by the nitrogen system at approximately 850 psig. These high-pressure accumulators are capable of providing sufficient motive gas to meet all the requirements on loss of both the compressed air and nitrogen systems. (It should be noted that the cycling requirements for the PORVs comes from overpressure protection, not shutdown requirements.) 9.3.1.6.2 Design Requirements The Class I portion of the backup air/nitrogen supply system is installed in accordance with the quality assurance requirements for Instrument Class IA equipment. The accumulators are fabricated in accordance with the quality assurance requirements for Design Class I, Code Class C piping.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-8 Revision 20 November 2011 The Class I tubing is installed and protected in accordance with the Design Class I air piping requirements. The equipment is seismically qualified for its location in the plant to the applicable Hosgri spectra as described in Section 3.7. All accumulators and bottles are wall- or column-mounted as close to the application as possible, except for the PORV accumulators, which are mounted at the elevation 140 feet operating deck.
This equipment is not part of a Design Class I pressure boundary, so it is not subject to ASME Section III or ANSI B31.7. 9.3.2 SAMPLING SYSTEMS The plant sampling systems provide a means for obtaining liquid and gas samples for laboratory analyses of chemical and radiochemical conditions of the designated reactor and secondary plant systems. The systems are designed to permit sampling during all modes of plant operation. The sampling systems provide the means for manual, grab type, sample collection, and where applicable, on-line monitoring of key chemistry parameters. Assurance of a representative sample will be by administrative procedures based on experience and good sampling techniques. These will include purging of sample lines prior to taking a sample and utilizing appropriate precleaned sampling containers. 9.3.2.1 Nuclear Steam Supply System Sampling System 9.3.2.1.1 Design Bases The nuclear steam supply system (NSSS) sampling system is designed for manual operation on an intermittent basis, under conditions ranging from full power operation to cold shutdown. Pipe internal diameters are sized such that solids do not clog the lines.
Sampling system discharge flows are limited under normal and anticipated fault conditions (malfunctions or failure) to preclude any radioactivity release beyond the site boundary in excess of plant release limitations. Adequate safety features are provided to protect laboratory personnel and prevent the spread of contamination from the sampling room. The reactor coolant hot leg samples are routed through a sufficiently long length of tubing inside containment, and flowrates are controlled to permit decay of the short-lived N16 isotope to a level that permits normal access to the sampling room. Equipment required for sampling capability to confirm reactor coolant system boron concentration is seismically qualified to allow the plant to be taken to cold shutdown conditions following a design basis seismic event. Backup air or nitrogen is provided to the required pneumatic-operated valves as described in Section 9.3.1.6. 9.3.2.1.2 System Description The sampling system, shown in Figure 3.2-11, provides the representative samples for laboratory analyses. The analyses show both chemical and radiochemical conditions and provide guidance in the operation of the RCS, RHR, CVCS. Typical information DCPP UNITS 1 & 2 FSAR UPDATE 9.3-9 Revision 20 November 2011 obtained includes reactor coolant boron and chloride concentrations, fission product radioactivity level, hydrogen, oxygen, and fission gas content, conductivity, pH, corrosion product concentration, chemical additive concentration, etc. The information is used in regulating boron concentration adjustments, evaluating fuel element integrity and CVCS mixed bed demineralizer performance, and regulating additions of corrosion-inhibiting chemicals to the systems.
Samples are drawn from the following locations:
(1) Inside Containment (a) The pressurizer steam space (RCS) (b) The pressurizer liquid space (RCS) (c) Hot legs of reactor coolant loops (2 points in the RCS) (d) Each accumulator (safety injection system) (2) Outside Containment (a) The letdown line (2 points, upstream and downstream of the demineralizers) (CVCS) (b) Each RHR heat exchanger outlet (RHRS) (c) The volume control tank gas and liquid space (CVCS)
Local sample connections are provided at various locations throughout the plant. These connections are not considered part of the sampling system. Samples originating from locations within the containment flow through lines to the sampling room in the auxiliary building. Each line is equipped with a manual isolation valve close to the sample source, a remote air-operated valve immediately downstream of the isolation valve, and containment boundary isolation valves located inside and outside the containment. Manual valves are located inside the sampling room for component isolation, sample flow control, and routing. High-temperature sample lines also contain a sample heat exchanger.
The reactor coolant hot leg samples are routed through a sufficiently long length of tubing inside containment, and flow rates are controlled to permit decay of the short-lived N16 isotope to a level that permits normal access to the sampling room. This room has controlled ventilation and drainage to control radioactivity release.
All sample lines originating from locations outside the containment are provided with manual isolation valves. The RHRS sample lines and the VCT liquid sample line have, DCPP UNITS 1 & 2 FSAR UPDATE 9.3-10 Revision 20 November 2011 in addition, a remote air-operated sampling valve. Manual valves are located in the sampling room for flow control and routing.
The sample sink, which is located in the sampling room, contains a drain line to the waste disposal system. Local instrumentation is provided to permit manual control of sampling operations and to ensure that the samples are at suitable temperatures and pressures before diverting flow to the sample sink. All sample lines are provided with a sample valve located at the sample sink, except for the volume control tank gas sample. The sample sink has a hood that is connected to the building ventilation exhaust system. 9.3.2.1.2.1 Component Description Component codes and classifications are given in the DCPP Q-List (see Reference 8 of Section 3.2), and component design parameters are listed in Table 9.3-2. 9.3.2.1.2.1.1 Sample Heat Exchangers The sample heat exchangers are of the shell and coil tube type. Sample flow circulates through the tube side, while component cooling water circulates through the shell-side. The tube side connections have socket-welded joints for connections to the high-pressure sample lines. 9.3.2.1.2.1.2 Sample Pressure Vessels The sample vessels are sized to provide sufficient gas volume to perform a radiochemical analysis on the volume control tank gas space constituents, or sufficient reactor coolant volume for dissolved hydrogen and fission gas analyses.
Integral isolation valves are furnished with the vessel. Quick disconnect couplings containing poppet-type check valves are connected to nipples extending from the valves on each end. 9.3.2.1.2.1.3 Sample Sink The sample sink is located in a hooded enclosure equipped with an exhaust ventilator. The work area around the sink and the enclosure is large enough for sample collection and storage, as well as for the radiation monitoring equipment.
The enclosure is penetrated by the various sample lines from the reactor systems and by a demineralized water line, all of which discharge into the sink which drains to the waste disposal system. The sink and work area material is stainless steel.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-11 Revision 20 November 2011 9.3.2.1.2.1.4 Delay Line The high-pressure reactor coolant loop sample line has sufficient length to provide at least a 40-second sample transit time within the containment. Additional transit time from the reactor containment to the sampling hood is provided by the sampling line. This allows for decay of the short-lived isotope, N16, to a level that permits normal access to the sampling room. 9.3.2.1.2.1.5 Piping All liquid and gas sample lines are austenitic stainless steel tubing and are designed for high-pressure service. Lines are so located as to protect them from accidental damage during routine operation and maintenance. 9.3.2.1.2.1.6 Valves Stop valves within the containment are remotely operated from the sampling room. They are used to isolate all sample points and to route sample flow. A remotely operated isolation valve is provided for samples originating from the RHRS so that the operator need not enter a possibly high radiation area following a loss-of-coolant accident (LOCA). Two isolation valves are provided, one inside and one outside the containment, on all sample lines leaving the containment. The valves trip closed upon actuation of the containment isolation signal. All valves in the system are constructed of austenitic stainless steel or equivalent corrosion-resistant material. 9.3.2.1.2.1.7 Hot Sample Sub-System (Unit 1 only) The RCS Hot Sample Sub-system provides the capability to collect samples filtered from a side stream of the hot-leg sample flow. Filters to collect solids from the flow are located both upstream and downstream of a heat exchanger. The sub-system includes temperature, flow, and pressure instruments as well as valves and tubing. 9.3.2.1.2.2 System Operation 9.3.2.1.2.2.1 Reactor Coolant Loop and Pressurizer Liquid Samples Reactor coolant loop and pressurizer liquid samples are obtained by opening the remotely operated isolation valve of the selected sample point. The sample heat exchangers cool the liquid samples.
A valve downstream of each heat exchanger is manually throttled to obtain the correct liquid sample flowrate. The sample stream flows through the sampling system to either sample sink 1-1 and 2-1 or the volume control tank in the CVCS until sufficient volume is purged to ensure that a representative sample will be obtained. When purging is completed, flow is diverted, if necessary, into the sample sink, and a sample is collected in a suitable container. DCPP UNITS 1 & 2 FSAR UPDATE 9.3-12 Revision 20 November 2011 To obtain a reactor coolant loop liquid or pressurizer liquid sample for dissolved gas content, flow is diverted by opening and closing the appropriate valves into the appropriate sample pressure vessel. A valve is adjusted to the required downstream pressure for obtaining the correct sample flowrate. After the sample pressure vessel is purged and the sample collected by closing the isolation valves, the sample vessel is removed by opening the quick disconnect couplings. Note that pressurized samples of reactor coolant for gas analysis are normally obtained from the CVCS demineralizer inlet sample lines as described below. 9.3.2.1.2.2.2 Pressurizer Steam Space Samples Pressurizer steam space samples are obtained by opening the remotely operated isolation valves. The sample heat exchanger condenses and cools the steam and the pressure is reduced by a manual valve. The condensate flows through a sample pressure vessel and into either sample sink 1-1 and 2-1 or the volume control tank in the CVCS until sufficient purge flow has been passed. The sample pressure vessel is then isolated and removed. 9.3.2.1.2.2.3 Residual Heat Removal Samples During plant shutdown operations, samples are withdrawn from the outlet line of the RHR heat exchangers at a maximum temperature of 350°F. The correct sample flowrate is obtained by adjusting the valve downstream of the hot leg sample heat exchanger.
The fluid temperature is reduced in the sample heat exchanger by manual regulation of the sample flow to the heat exchanger. After sufficient volume has been purged to either sample sink 1-1 and 2-1 or the volume control tank in the CVCS to ensure that a representative sample will be obtained, flow is diverted, if necessary, to the sample sink for collection. If the pressure and temperature is low in the RHRS, local samples off the pump discharge can be taken. 9.3.2.1.2.2.4 Letdown Line Samples Samples are obtained from the letdown line at a point upstream of the mixed bed demineralizers and at a point upstream of the volume control tank. After throttling, the fluid is initially purged to either sample sink 1-1 and 2-1 or the volume control tank in the CVCS and then routed into the sample sink for collection. 9.3.2.1.2.2.5 Volume Control Tank Gas Samples After the volume control tank gas sample line has been drained of condensate, the gas is sampled by collection with a pressurized sample vessel or laboratory apparatus.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-13 Revision 20 November 2011 9.3.2.1.2.2.6 Volume Control Tank Liquid Samples Volume control tank liquid samples are obtained by opening the remotely operated isolation valve and purging the line to the sample sink. Following sufficient purging, a sample may be taken at the sample sink. 9.3.2.1.2.2.7 Accumulator Samples Accumulator samples are obtained by opening the remotely operated isolation valve of the selected accumulator and purging the line to sample sink 1-1 and 2-1. Following sufficient purging, a sample is drawn at the sample sink. 9.3.2.1.2.2.8 Reactor Coolant Solids Samples (Unit 1 only) Samples of solids from the reactor coolant system are obtained by opening manual valves on the hot sample panel to direct a small flow through the sampling filters. The filter effluent is directed to the inlet of the CVCS demineralizers. After the sub-system is isolated, collected solids can be dried and examined in onsite or offsite laboratories. 9.3.2.1.3 Safety Evaluation 9.3.2.1.3.1 Availability and Reliability The sampling system is neither required to function during an emergency nor is it required to take action to prevent an emergency condition. In the event of a LOCA, the system is isolated at the containment boundary. Reactor coolant system sampling capability is available following a design basis seismic event. 9.3.2.1.3.2 Leakage Provisions Samples are collected under a hood provided with a vent to the building exhaust ventilation system. Liquid leakage in the sample sink is collected in the sink and drained to the waste disposal system. If there is any leakage from the system inside the containment (e.g., valve stem leakage), it is collected in the containment sump. 9.3.2.1.3.3 Exposure Control The sampling room is equipped with a ventilated sample hood to reduce the potential for airborne radioactivity exposure of operating personnel. Sufficient length and flow control is provided in the reactor coolant sample line to reduce personnel exposure from short-lived radionuclides. Shielding is provided, as necessary, to reduce personnel exposures. The operating procedures specify the precautions to be observed when purging and drawing samples. All sampling operations are conducted with strict adherence to plant health physics safety regulations.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-14 Revision 20 November 2011 9.3.2.1.3.4 Incident Control The system is designed to be operated on an intermittent basis under administrative control. The system is normally closed with no flow, except for the pressurizer steam space sample, which may be left open to provide a continuous purge. The reactor coolant hotleg sample may be open for extended periods of time for operation of the Hot Sample Panel Sub-system (Unit 1 only).
Sample lines penetrating the containment are equipped with remotely operated isolation valves that close on receipt of a containment isolation signal. In addition, the isolation valve in the CVCS letdown line outside the containment will close on containment isolation signal, isolating the letdown line sample lines from the containment. 9.3.2.1.4 Tests and Inspections The sampling system is in use daily. Periodic visual inspection and preventive maintenance are conducted using normal industry practice. 9.3.2.1.5 Instrumentation Applications The instrumentation provided for the sampling system is discussed below. All of the instrumentation gives local indication. 9.3.2.1.5.1 Temperature Instrumentation is provided to measure the temperature of the sample flow in the outlet line of each sample heat exchanger. 9.3.2.1.5.2 Pressure Instrumentation is provided to measure the pressure in the sample lines downstream of each of the three sample vessels: (a) pressurizer steam sample vessel, (b) pressurizer liquid sample vessel, and (c) hot leg sample vessel. 9.3.2.1.5.3 Flow Instrumentation is provided to measure the sample purge flow of all liquid samples to the volume control tank in the CVCS and also the volume control tank gas sample purge to the vent header in the gaseous waste system. 9.3.2.1.5.4 Chemical Instrumentation is provided to measure dissolved hydrogen and oxygen in the letdown line sample. These in-line instruments provide an alternate to manual collection.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-15 Revision 20 November 2011 9.3.2.2 Post Accident Sampling System The Post Accident Sampling System (PASS) provides facilities for sampling and analysis of reactor coolant, containment sump (RHR pumps discharge), and containment atmosphere following an accident. This system may be used to obtain further information on accident conditions in the RCS and containment.
The system is designed and located such that plant personnel are able to obtain the necessary samples and analyses under accident conditions while limiting personnel radiation exposure. 9.3.2.2.1 Design Bases The PASS system, the sample room enclosure, the electrical supply, and the heating, ventilation, and air conditioning system are all designated as Design Class II. 9.3.2.2.1.2 Personnel Protection The shielding panels provided in the sampling system cabinets and the 2 foot thick concrete walls that enclose the post accident sampling room and its access ways, provide the necessary shielding to allow occupancy of the sample room and operation of the sampling system following a LOCA.
The ventilation system for the sample room is designed to aid in the protection of plant personnel from radiological contamination. This system is discussed in Section 9.4.10. An area radiation monitor with local annunciation is installed in the post accident sampling room to warn personnel occupying the sampling room of high or increasing radiation. High radiation in the sampling room is also alarmed at the main control room annunciator.
An eyewash station is provided in the post accident sampling room. 9.3.2.2.2 System Description The PASS, shown in Figure 3.2-11, is composed of the reactor coolant and containment sump (RHR pumps discharge) liquid sampling system and the containment atmosphere monitoring system. The equipment location for this system is also shown in Figure 3.2-11. 9.3.2.2.2.1 PASS Liquid Sampling System The PASS liquid sampling system consists of the liquid sample panel and the sample coolers.
The following liquid samples are received at the liquid sample panel: DCPP UNITS 1 & 2 FSAR UPDATE 9.3-16 Revision 20 November 2011 (1) Reactor coolant hot legs 1 and 4 2) RHR pump discharge All samples received at the liquid sample panel are taken from existing lines outside of containment.
The liquid samples flow from their sources through the sample cooler to the liquid sample panel.
The liquid sample panel provides the means to purge each sample through its sample line and the sample panel to ensure representative samples are obtained for analysis.
All sample lines can be flushed with makeup water following each sampling operation, thereby reducing the radiation level in the sampling system. The sample coolers for the liquid sampling system are installed in a sample cooler rack. One sample cooler is provided for each liquid sample line.
The cooling water sides of the sample coolers are arranged into two cooling banks. Each bank consists of five sample coolers connected in series and is provided with the following:
(1) Cooling water overtemperature switch (2) Cooling water underpressure switch (3) Cooling water low flow switch (4) Cooling water relief valve sized to relieve a full bore flow from a broken sample coil (5) Cooling water isolation valves for the inlet and discharge for each bank Each sample line is provided with an inlet isolation valve for maintenance purposes.
9.3.2.2.2.2 Containment Atmosphere Monitoring System The containment atmosphere monitoring system is designed to sample the containment atmosphere for isotopic analysis.
The containment atmosphere samples are collected in the containment and routed through a containment penetration, then through the sample panel, and returned to the containment atmosphere. A containment atmosphere dilution system provides the capability to obtain grab samples of diluted containment atmosphere. For particulate and iodine isotopic analysis, removable particulate and silver zeolite filters are provided in the sampling panel. DCPP UNITS 1 & 2 FSAR UPDATE 9.3-17 Revision 20 November 2011 The sample flow to the containment atmosphere sample panel is established with a nitrogen gas flow through an eductor.
Special features are employed to prevent particulate and iodine plateout in the inlet line to the first air sample flask. These features include electrical heat tracing on the sample line, minimum radius bends in the sample lines, and the use of plug valves that avoid changes in the sample conditions.
The sampling panel design provides the means to purge or flush the sample system. 9.3.2.2.3 Control Provisions Controls are provided on the control panel in the post accident sampling room that allow the operator to route these selected samples to the PASS room. Controls are also provided on the control panel to position the electrically operated containment isolation valves on the containment air monitoring system.
Under accident conditions, post accident sampling waste is returned to the containment via a local valve and a remote valve with controls at the control panel in the post accident sample room. 9.3.2.3 Secondary Sampling System Samples from the secondary side of the steam generators originate at several points in the turbine cycle. These samples are taken from the discharge of condensate pumps, condensate booster pumps, condensate demineralizers, condensate drain pump, feedwater heaters, mainsteam leads and steam generator blowdown lines. Samples may be obtained at various local panels or at the secondary process control room for analysis. The analysis may be used to determine action level, condenser leak detection, corrosion product transport, and/or annunciator alarm signals. The main condensers are equipped with tube sheet and condensate tray salt water leak detection systems. These systems identify sea water ingress to the condenser. The leak detection system consists of eight in-line tube sheet monitors and seven in-line condensate tray monitors. Each sample point is monitored separately to identify condenser in-leakage. 9.3.2.4 Turbine Steam Analyzer System A turbine steam analyzer system, which was originally installed to provide continuous direct sampling and analysis of both the low and high pressure turbine steam on Unit 1 and only high pressure steam on Unit 2, is no longer being used at DCPP. Other chemistry methods for evaluating steam chemistry are used.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-18 Revision 20 November 2011 9.3.3 EQUIPMENT AND FLOOR DRAINAGE SYSTEMS The equipment and floor drainage systems collect and channel waste liquids to be either reprocessed or discharged from the plant, except for those originating in the turbine building. The equipment and floor drainage systems are part of the liquid radwaste system (LRS) and are described in detail in Section 11.2. Figure 3.2-19 shows detailed piping schematics of these systems. 9.3.3.1 Design Bases The equipment and floor drainage systems are designed to provide adequate drainage during normal operation and postulated flooding conditions following equipment failure including inadvertent actuation of a single fire water sprinkler head. Provisions are made for: (a) multiple drainage of certain areas, (b) prevention of backflooding, and (c) visual inspection of flow in drain lines wherever space permits, i.e., most lines above elevation 70 feet. The floor drainage systems also provide a detection method in the event of flooding.
However, the water accumulation that will result from any postulated failure of the drain system will not preclude safe shutdown of the plant. 9.3.3.2 System Description 9.3.3.2.1 Equipment Drain or Closed Drain System The closed drain system is so called because drains from equipment are connected directly to the drainage system. Liquid waste is not exposed to the atmosphere once it leaves the equipment until it reaches its destination, which is either the miscellaneous equipment drain tank or the liquid holdup tanks. The system provides drainage for equipment located both inside and outside containment. 9.3.3.2.2 Floor Drain or Open Drain System The open drain system, also known as the floor drainage system, drains potentially contaminated areas in the containment and auxiliary building and collects liquids from equipment located in those areas which normally do not handle reactor coolant. The piping systems or trenches used in this system permit exposure of contents to the atmosphere.
The auxiliary building has been divided into a number of drainage zones. Each equipment compartment or area within a zone is drained by several screened outlets as shown in Figure 9.3-5. The individual floor drains are 2 inches in diameter and feed 4 inch diameter headers, which eventually drain to a common collection header leading to the auxiliary building sump. Each header is provided with a check valve and loop seal as it enters the sump to prevent backup of water.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-19 Revision 20 November 2011 9.3.3.3 Safety Evaluation An analysis of the consequences of leakage from the liquid radwaste system, including normal operation and postulated accidental releases, is presented in Chapters 11 and 15.
Flooding due to line or equipment failure in the auxiliary building is controlled by the open drain system. Several floor drains are located within each drainage zone and in the immediate vicinity of all safety-related equipment to preclude local flooding should one outlet become plugged. If the sump is filled to capacity due to excessive flow, the sump will overflow to the pipe trench instead of backing up into adjacent zones. In the event of flooding within one equipment area, across-the-floor drainage is acceptable.
The operator would be alerted to equipment failure or pipe rupture leading to flooding by the annunciation of the faulted system's pressure, temperature, flow, level, overcurrent, etc., alarms (located in the control room) in addition to the auxiliary building high-sump level alarm. High-flow alarms are installed in the fire water and makeup water systems since they are high-capacity nonradioactive systems. The location of failures in radioactive systems would be aided by the control room annunciation of area radiation monitors located throughout the auxiliary building as described in Section 11.4. The operator would be alerted to incipient failures by routine visual observation of sight glasses provided for the drainage header of each zone. These sight glasses are located in the corridor adjacent to the auxiliary building sump.
Potential sources of flooding, the consequences of postulated flooding, and other precautions to prevent such flooding are more specifically discussed in subsections on systems with a potential for causing flooding. These systems include: (1) RHRS (Section 5.5.6) (2) Auxiliary saltwater system (Section 9.2.7) (3) CCWS (Section 9.2.2) (4) Makeup water system (Section 9.2.3) (5) Condensate storage facilities (Section 9.2.6) (6) Fire protection water system (Section 9.5.1) (7) Circulating water system (Section 10.4.5) (8) Condensate and feedwater system (Section 10.4.7) (9) Chilled water system, for cable spreading room air conditioning system (Section 9.4.9) DCPP UNITS 1 & 2 FSAR UPDATE 9.3-20 Revision 20 November 2011 9.3.3.4 Tests and Inspections The drainage systems were tested and inspected prior to plant operation and are periodically monitored during plant operation. 9.3.3.5 Instrumentation Applications Flow and level instruments are provided for control, indication, and alarm in the drainage systems piping, collection tanks, and sumps. These instruments are described in Section 11.2. 9.3.4 CHEMICAL AND VOLUME CONTROL SYSTEM The CVCS, shown in Figure 3.2-8, provides the following services to the RCS:
(1) Control of water chemistry conditions, activity level, soluble chemical neutron absorber concentration, and makeup water (2) Maintenance of required water inventory in the RCS (3) Filling, draining, and pressure testing (4) Maintenance of seal water injection flow to the reactor coolant pumps (5) Processing of effluent reactor coolant to effect recovery and reuse of soluble chemical neutron absorber and makeup water (6) High-head safety injection pumps for the ECCS The following sections provide information on (a) design bases, (b) system description, (c) safety evaluation, (d) tests and inspections, and (e) instrumentation applications for the CVCS.
The CVCS is required for safe shutdown of the plant. 9.3.4.1 Design Bases 9.3.4.1.1 Reactivity Control The CVCS regulates the concentration of chemical neutron absorber in the reactor coolant to control reactivity changes resulting from the change in reactor coolant temperature between cold shutdown and hot full power operation, burnup of fuel and burnable poisons, and xenon transients.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-21 Revision 20 November 2011 9.3.4.1.1.1 Reactor Makeup Control (1) The CVCS is capable of borating the RCS through either one of two flowpaths and from either one of two boric acid sources. (2) The amount of boric acid stored in the CVCS always exceeds that amount required to borate the RCS to cold shutdown concentration assuming that the control assembly with the highest reactivity worth is stuck in its fully withdrawn position. This amount of boric acid also exceeds the amount required to bring the reactor to hot shutdown and to compensate for subsequent xenon decay. (3) The CVCS is capable of counteracting inadvertent positive reactivity insertion caused by the maximum boron dilution accident. 9.3.4.1.2 Regulation of Reactor Coolant Inventory The CVCS maintains the proper coolant inventory in the RCS for all normal modes of operation including startup from cold shutdown, full power operation, and plant cooldown. This system also has sufficient makeup capacity to maintain the minimum required inventory in the event of minor RCS leaks.
The CVCS flowrate is based on the requirement that it permits the RCS to be either heated to or cooled from hot standby condition at the design rate and maintain proper coolant level.
9.3.4.1.3 Reactor Coolant Purification The CVCS removes fission products and corrosion products from the reactor coolant during operation of the reactor and maintains these within acceptable levels. The CVCS can also remove excess lithium from the reactor coolant, keeping the lithium ion concentration within the desired limits for pH control.
The CVCS is capable of removing fission and activation products, in ionic form or as particulates, from the reactor coolant to provide access to those process lines carrying reactor coolant during operation and to minimize activity released due to leakage. 9.3.4.1.4 Chemical Additions The CVCS provides a means for adding chemicals to the RCS to control the pH of the coolant during initial startup and subsequent operation, scavenge oxygen from the coolant during startup, and control the oxygen level of the reactor coolant due to radiolysis during all operations subsequent to startup. The CVCS is capable of maintaining the oxygen content and pH of the reactor coolant within limits specified in Table 5.2-15. There is also a capability to add zinc acetate to inhibit primary water stress corrosion cracking in Alloy 600 steam generator tubes. DCPP UNITS 1 & 2 FSAR UPDATE 9.3-22 Revision 20 November 2011 9.3.4.1.5 Seal Water Injection The CVCS is able to continuously supply filtered water to each reactor coolant pump seal, as required by the reactor coolant pump design. 9.3.4.1.6 Hydrostatic Testing of the Reactor Coolant System The CVCS is capable of supplying water at the maximum test pressure specified to verify the integrity of the RCS through the use of a temporary hydrostatic test pump. 9.3.4.1.7 Emergency Core Cooling Centrifugal charging pumps CCP1 and CCP2 in the CVCS also serve as the high-head safety injection pumps in the ECCS. Other than centrifugal charging pumps CCP1 and CCP2 and associated piping and valves, the CVCS is not required to function during a LOCA. During a LOCA, the CVCS is isolated except for centrifugal charging pumps CCP1 and CCP2 and the piping in the safety injection path.
9.3.4.2 System Description The CVCS is shown in Figure 3.2-8 with system design parameters listed in Table 9.3-5.
The CVCS consists of several subsystems: the charging, letdown, and seal water system; the chemical control, purification and makeup system; and the boron recycle system. 9.3.4.2.1 Charging, Letdown, and Seal Water System The charging and letdown functions of the CVCS are employed to maintain a programmed water level in the RCS pressurizer, thus maintaining proper reactor coolant inventory during all phases of normal plant operation. This is achieved by means of a continuous feed and bleed process during which the feed rate is automatically controlled based on pressurizer water level. The bleed rate can be chosen to suit various plant operational requirements by selecting the proper combination of letdown orifices in the letdown flowpath.
Reactor coolant is discharged to the CVCS from the reactor coolant loop piping between the reactor coolant pump and the steam generator; it then flows through the shell-side of the regenerative heat exchanger where its temperature is reduced by heat transfer to the charging flow passing through the tubes. The coolant then experiences a large pressure reduction as it passes through a letdown orifice and flows through the tube side of the letdown heat exchanger where its temperature is further reduced to the operating temperature of the mixed bed demineralizers. Downstream of the letdown heat exchanger a second pressure reduction occurs. This second pressure reduction is performed by the low-pressure letdown valve, the function of which is to maintain upstream pressure, which prevents flashing downstream of the letdown orifices. DCPP UNITS 1 & 2 FSAR UPDATE 9.3-23 Revision 20 November 2011 The coolant then flows through one of the two mixed bed demineralizers. The flow may then pass through the cation bed demineralizer, which is used intermittently when additional purification of the reactor coolant is required.
The coolant then flows through the reactor coolant filter and into the volume control tank through a spray nozzle in the top of the tank. The gas space in the volume control tank is filled with hydrogen. The partial pressure of hydrogen in the volume control tank determines the concentration of hydrogen dissolved in the reactor coolant. The charging pumps normally take suction from the volume control tank and return the cooled, purified reactor coolant to the RCS through the charging line. Normal charging flow is handled by one of the three charging pumps. The bulk of the charging flow is pumped back to the RCS through the tube side of the regenerative heat exchanger. The letdown flow in the shell-side of the regenerative heat exchanger raises the charging flow to a temperature approaching the reactor coolant temperature. The flow is then injected into a cold leg of the RCS. Two charging paths are provided from a point downstream of the regenerative heat exchanger. A flowpath is also provided from the regenerative heat exchanger outlet to the pressurizer spray line. An air-operated valve in the spray line is employed to provide auxiliary spray from the charging pumps to the vapor space of the pressurizer during plant cooldown. This provides a means of cooling the pressurizer near the end of plant cooldown, when the reactor coolant pumps are not operating.
A portion of the charging flow is directed to the reactor coolant pumps through a seal water injection filter. It enters the pumps at a point between the labyrinth seals and the No. 1 seal. Here the flow splits and a portion enters the RCS through the labyrinth seals and thermal barrier. The remainder of the flow is directed up the pump shaft, cooling the lower bearing, and leaves the pump via the No. 1 seal. Most of the No. 1 seal flow discharges to a common manifold, exits the containment, and then passes through the seal water return filter and the seal water heat exchanger to the suction side of the charging pumps, or by alternate path to the volume control tank. A very small portion of the seal flow leaks through to the No. 2 seal. Seal No. 3 is a double-dam seal, providing a final barrier to leakage to containment atmosphere.
An excess letdown path from the RCS is provided in the event that the normal letdown path is inoperable. Reactor coolant can be discharged from a cold leg and flows through the tube side of the excess letdown heat exchanger. Downstream of the heat exchanger a remote-manual control valve controls the excess letdown flow. The flow normally joins the No. 1 seal discharge manifold and passes through the seal water return filter and heat exchanger to the volume control tank. The excess letdown flow can also be directed to the reactor coolant drain tank. When the normal letdown line is not available, the normal purification path is also not in operation. Therefore, this alternative condition would allow continued power operation for limited periods of time dependent on RCS chemistry and activity. The excess letdown flowpath may also be used to provide additional letdown capability when needed. This capability may be needed during RCS heatup, as a result of coolant expansion. This path removes some of the excess reactor coolant due to expansion of the system as a result of the RCS DCPP UNITS 1 & 2 FSAR UPDATE 9.3-24 Revision 20 November 2011 temperature increase. In this case, the excess letdown is diverted to the reactor coolant drain tank.
Surges in RCS inventory due to load changes are accommodated for the most part in the pressurizer. The volume control tank provides surge capacity for reactor coolant expansion not accommodated by the pressurizer. If water level in the volume control tank exceeds the normal operating range, a proportional controller modulates a three-way valve downstream of the reactor coolant filter to divert a portion of the letdown to the holdup tanks in the boron recovery system. If the high-level limit in the volume control tank is reached, an alarm is actuated in the control room and the letdown is completely diverted to the holdup tanks.
Liquid effluent in the holdup tanks is processed as a batch operation. This liquid is pumped by the gas stripper feed pumps through the evaporator feed ion exchangers. It then flows through the ion exchanger filter, and then the liquid is drained to the liquid radwaste system for processing. Low level in the volume control tank initiates makeup from the reactor makeup control system (RMCS). If the RMCS does not supply sufficient makeup to keep the volume control tank level from falling to a lower level, an emergency low-level signal causes the suction of the charging pumps to be transferred to the refueling water storage tank.
A temporary hydrostatic test pump is used to perform hydrostatic tests that verify the integrity and leaktightness of the RCS. The pump can pressurize the RCS to the maximum designated test pressure. The hydrostatic test is performed prior to initial operation and as part of the periodic RCS inservice inspection program. The volume control tank is located above the charging pumps to provide sufficient net positive suction head (NPSH). All parts of the charging and letdown system are shielded as necessary to limit dose rates during operation with 1 percent fuel defects assumed. The regenerative heat exchanger, excess letdown heat exchanger, letdown orifices, and seal bypass orifices are located within the reactor containment. All other system equipment is located inside the auxiliary building. 9.3.4.2.2 Chemical Control, Purification, and Makeup System 9.3.4.2.2.1 pH Control The pH control chemical employed is lithium hydroxide. This chemical is chosen for its compatibility with the materials and water chemistry of borated water/stainless steel/zirconium alloy/Inconel systems. In addition, lithium is produced in the core region due to irradiation of the dissolved boron in the coolant.
The lithium hydroxide is introduced into the RCS via the charging flow. The solution is prepared in the laboratory and poured into the chemical mixing tank. Primary makeup water is then used to flush the solution to the suction manifold of the charging pumps. DCPP UNITS 1 & 2 FSAR UPDATE 9.3-25 Revision 20 November 2011 The concentration of lithium hydroxide in the RCS is maintained in the range specified for pH control (Table 5.2-15). If the concentration exceeds this range, as it may during the early stages of core life, the cation bed demineralizer is employed in the letdown line in series operation with a mixed bed demineralizer. Since the amount of lithium to be removed is small and its buildup can be readily calculated, the flow through the cation bed demineralizer is not required to be full letdown flow. 9.3.4.2.2.2 Oxygen Control During reactor startup from the cold condition, hydrazine is employed as an oxygen-scavenging agent. The hydrazine solution is introduced into the RCS in the same manner as described above for the pH control agent. Hydrazine is not employed at any time other than startup from the cold shutdown state.
Dissolved hydrogen is employed to control and scavenge oxygen produced due to radiolysis of water in the core region. Sufficient partial pressure of hydrogen is maintained in the volume control tank such that the specified equilibrium concentration of hydrogen is maintained in the reactor coolant. A pressure control valve maintains a minimum pressure in the vapor space of the volume control tank. This valve can be adjusted to provide the correct equilibrium hydrogen concentration. 9.3.4.2.2.3 Reactor Coolant Purification Mixed bed demineralizers are provided in the letdown line to provide cleanup of the letdown flow. The demineralizers remove ionic corrosion products and certain fission products. One demineralizer is usually in continuous service for normal letdown flow and can be supplemented intermittently by the cation bed demineralizer, if necessary, for additional purification. The cation resin removes principally cesium and lithium isotopes from the purification flow.
The deborating demineralizers are located downstream of the mixed bed and cation bed demineralizers and can be used intermittently to remove boron from the reactor coolant near the end of the core life when boron concentration is low. When the deborating demineralizers are in operation, the letdown stream passes through the mixed bed demineralizers and then through the deborating demineralizers and into the volume control tank after passing through the reactor coolant filter.
A further cleanup feature is provided for use during cold shutdown and residual heat removal. A remotely operated valve admits a bypass flow from the RHRS into the letdown line upstream of the letdown heat exchanger. The flow passes through the heat exchanger, through a mixed bed demineralizer and the reactor coolant filter to the volume control tank. The fluid is then returned to the reactor control system via the normal charging route.
Filters are provided at various locations to ensure filtration of particulate and resin fines and to protect the seals on the reactor coolant pumps. DCPP UNITS 1 & 2 FSAR UPDATE 9.3-26 Revision 20 November 2011 Fission gases are removed from the system by venting the volume control tank to the waste disposal system. 9.3.4.2.2.4 Chemical Shim and Reactor Coolant Makeup The soluble neutron absorber (boric acid) concentration and the reactor coolant inventory are controlled by the RMCS. In addition, for emergency boration and makeup, the capability exists to provide refueling water or 4 weight percent boric acid (7,000 ppm boron) to the suction of the charging pump.
The boric acid is stored in two boric acid tanks. Two boric acid transfer pumps are provided with one pump normally aligned with one boric acid tank running continuously at low speed to provide recirculation of the boric acid system. The second pump is aligned with the second boric acid tank and is considered as a standby pump, with service being transferred as operation requires. This second pump also circulates fluid, as needed, through the second boric acid tank. Manual or automatic initiation of the RMCS will activate the running pump to the higher speed to provide normal makeup of boric acid solution as required.
The primary makeup water pumps, taking suction from the primary makeup water storage tank, are employed for various makeup and flushing operations throughout the systems. One of these pumps also starts on demand from the RMCS and provides flow to the boric acid blender. The flow from the boric acid blender is directed to either the suction manifold of the charging pumps or the volume control tank through the letdown line and spray nozzle. During reactor operation, changes are made in the reactor coolant boron concentration for the following conditions:
(1) Reactor startup - boron concentration must be decreased from shutdown concentration to achieve criticality. (2) Load follow - boron concentration must be either increased or decreased to compensate for the xenon transient following a change in load. (3) Fuel burnup - boron concentration must be decreased to compensate for fuel burnup. (4) Cold shutdown - boron concentration must be increased to the cold shutdown concentration.
The RMCS instruments provide a manually preselected makeup composition to the charging pump suction header or the volume control tank. The makeup control functions are those of maintaining desired operating fluid inventory in the volume control tank and adjusting reactor coolant boron concentration for reactivity control. DCPP UNITS 1 & 2 FSAR UPDATE 9.3-27 Revision 20 November 2011 Automatic Makeup of Reactor Makeup Control System The automatic makeup mode of operation of the RMCS provides boric acid solution preset to match the boron concentration in the RCS. The automatic makeup compensates for minor leakage of reactor coolant without causing significant changes in the coolant boron concentration.
Under normal plant operating conditions, the RMCS mode and makeup stop valves are set in the "automatic makeup" position. A preset low-level signal from the volume control tank level controller causes the automatic makeup control action to start a primary makeup water pump, switch a boric acid transfer pump to high-speed operation, open the makeup stop valve to the charging pump suction, throttle the concentrated boric acid control valve and the primary makeup water control valve. The flow controllers then blend the makeup stream according to the preset concentration. Makeup addition to the charging pump suction header causes the water level in the volume control tank to rise. At a preset high-level point, the makeup is stopped, the primary makeup water pump stops, the primary makeup water control valve closes, the boric acid transfer pump returns to low-speed operation, the concentrated boric acid control valve closes, and the makeup stop valve to charging pump suction closes.
If the automatic makeup fails or is not aligned for operation and the tank level continues to decrease, a low-level alarm is actuated. Manual action may correct the situation or, if the level continues to decrease, an emergency low-level signal from both channels opens the stop valves in the refueling water supply line and closes the stop valves in the volume control tank outlet line.
Dilute The dilute mode of operation permits the addition of a preselected quantity of primary makeup water at a preselected flowrate to the RCS. The operator sets the RMCS mode to "dilute," the primary makeup water flow setpoint to the desired flowrate, the primary makeup water batch to the desired quantity, and initiates system start. This opens the primary makeup water control valve to the volume control tank and starts a primary water makeup pump that will deliver water to the volume control tank. From here the water goes to the charging pump suction header. Excessive rise of the volume control tank water level is prevented by automatic actuation (by the tank level controller) of a three-way diversion valve which routes the reactor coolant letdown flow to the holdup tanks in the boron recovery system. When the preset quantity of water has been added, the RMCS causes the pump to stop and the control valve to close. Alternate Dilute The alternate dilute mode of operation is similar to the dilute mode except a portion of the dilution water flows directly to the charging pump suction and a portion flows into the volume control tank via the spray nozzle and then flows to the charging pump suction. DCPP UNITS 1 & 2 FSAR UPDATE 9.3-28 Revision 20 November 2011 Borate The borate mode of operation permits the addition of a preselected quantity of concentrated boric acid solution at a preselected flowrate to the RCS. The operator sets the RMCS mode to "borate," the concentrated boric acid flow setpoint to the desired flowrate, the concentrated boric acid batch to the desired quantity, and initiates system start. This opens the makeup stop valve to the charging pumps' suction and switches the boric acid transfer pump to high-speed operation, which delivers a 4 weight percent boric acid solution (7,000 ppm boron) to the charging pump suction header. The total quantity added in most cases is so small that it has only a minor effect on the volume control tank level. When the preset quantity of concentrated boric acid solution is added, the RMCS returns the boric acid transfer pump to low-speed operation and closes the makeup stop valve to the suction of the charging pumps. Manual The manual mode of operation permits the addition of a preselected quantity and blend of boric acid solution to the RCS, to the refueling water storage tank, or to the holdup tanks in the boron recovery system. While in the manual mode of operation, automatic makeup to the RCS is precluded. The discharge flowpath must be prepared by opening manual valves in the desired path.
The operator then sets the RMCS mode to "manual," the concentration of boric acid is set and the required batch gallons are set to the desired flowrates, the boric acid and primary makeup water batch to the desired quantities, and initiates system start. The system start actuates the boric acid flow control valve and the primary makeup water flow control valve to the boric acid blender and starts the preselected primary makeup water pump and switches the boric acid transfer pump to high-speed operation.
When the preset quantities of boric acid and primary makeup water have been added, the primary makeup water pump stops, the boric acid transfer pump returns to low-speed operation, the boric acid control valve, and the primary makeup water flow control valve closes. This operation may be stopped manually by initiating system stop.
If either batch setpoint is satisfied before the other has recorded its required total, the pump and valve associated with the setpoint, which has been satisfied will terminate flow. The flow controlled by the other setpoint will continue until that setpoint is satisfied. Alarm Functions The RMCS is provided with alarm functions to call the operator's attention to the following conditions:
(1) Deviation of primary makeup water flowrate from the control setpoint.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-29 Revision 20 November 2011 (2) Deviation of concentrated boric acid flowrate from control setpoint. (3) High level in the volume control tank. This alarm indicates that the level in the tank is approaching high level and a resulting 100 percent diversion of the letdown stream to the holdup tanks in the boron recovery system. (4) Low level in the volume control tank. This alarm indicates that the level in the tank is approaching emergency low level and resulting realignment of charging pump suction to the refueling water storage tank. 9.3.4.2.3 Boron Recovery System The boron recovery system collects borated water that results from the following plant operations. In each of these operations, the excess reactor coolant is diverted from the letdown line to the holdup tanks as a result of high volume control tank level.
(1) Dilution of reactor coolant to compensate for core burnup (2) Load follow (3) Hot shutdowns and startups (4) Cold shutdowns and startups (5) Refueling shutdown and startup Excess liquid effluents containing boric acid and flow from the RCS through the letdown line are collected in the holdup tanks. As liquid enters the holdup tanks, the nitrogen cover gas is displaced to the gas decay tanks in the waste disposal system through the waste vent header. The concentration of boric acid in the holdup tanks varies through core life from the refueling concentration to near zero at the end of the core cycle. A holdup tank recirculation pump is provided to transfer liquid from one holdup tank to another.
Liquid effluent in the holdup tanks is processed as a batch operation. This liquid is pumped by the gas stripper feed pumps through the evaporator feed ion exchangers. It then flows through the ion exchanger filter, and then the liquid is drained to the liquid radwaste system for processing. 9.3.4.2.4 Component Description A summary of principal CVCS component design parameters is given in Table 9.3-6. CVCS safety classifications and design codes are given in the DCPP Q-List (see Reference 8 of Section 3.2). All CVCS piping that handles radioactive liquid is austenitic stainless steel. All piping joints and connections are welded, except where DCPP UNITS 1 & 2 FSAR UPDATE 9.3-30 Revision 20 November 2011 flanged connections are required to facilitate equipment removal for maintenance and hydrostatic testing. 9.3.4.2.4.1 Charging Pumps Three charging pumps inject coolant into the RCS and are of the single-speed, horizontal, centrifugal type. All parts in contact with the reactor coolant are fabricated of austenitic stainless steel or other material of adequate corrosion-resistance. There is a minimum flow recirculation line on each centrifugal charging pump discharge header to protect them against a closed discharge valve condition.
Charging flowrate is determined from a pressurizer level signal. Charging flow control is accomplished by a modulating valve on the discharge side of the centrifugal pumps. Centrifugal charging pumps CCP1 and CCP2 also serve as safety injection pumps in the ECCS. 9.3.4.2.4.2 Boric Acid Transfer Pumps Two horizontal, centrifugal, two-speed pumps with mechanical seals are supplied. Normally, one pump is aligned with one boric acid tank and runs continuously at low speed to provide recirculation of the boric acid system. The second pump is aligned with the second boric acid tank then considered as a standby pump, with service being transferred as operation requires. This second pump also intermittently circulates fluid through the second tank. Manual or automatic initiation of the reactor coolant makeup control system will activate the running pump to the higher speed to provide normal makeup of boric acid solution as required. For emergency boration, supplying of boric acid solution to the suction of the charging pump can be accomplished by manually actuating either or both pumps. The transfer pumps also function to transfer boric acid solution from the batching tank to the boric acid tanks. In addition to the automatic actuation by the makeup control system, and manual actuation from the main control board, these pumps may also be controlled locally at the hot shutdown panel.
The pumps are heat-traced to prevent crystallization of the boric acid solution. All parts in contact with the solution are of austenitic stainless steel. 9.3.4.2.4.3 Gas Stripper Feed Pumps The two gas stripper feed pumps supply feed through the evaporator feed ion exchangers from the holdup tanks and route it to the liquid radwaste system. The nonoperating pump is a standby and is available for operation in the event the operating pump malfunctions. These centrifugal pumps are constructed of austenitic stainless steel.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-31 Revision 20 November 2011 9.3.4.2.4.4 Holdup Tank Recirculation Pump The recirculation pump is used to mix the contents of a holdup tank for sampling or to transfer the contents of a holdup tank to another holdup tank. The wetted surface of this pump is constructed of austenitic stainless steel. 9.3.4.2.4.5 Boric Acid Reserve Tank Pumps The two boric acid reserve tank pumps discharge water from the boric acid reserve tanks to other portions of the CVCS. The pumps are constructed of austenitic stainless steel. 9.3.4.2.4.6 Boric Acid Reserve Tank Recirculation Pumps Two boric acid reserve tank recirculation pumps are provided for each tank. Only one pump per tank is running at a time with the other on standby. These pumps are used to recirculate boric acid through installed piping, equipment, and an inline heater to maintain a fluid temperature above 80°F. These pumps are seal-less and the wetted surface is constructed of austenitic stainless steel. 9.3.4.2.4.7 Concentrates Holding Tank Transfer Pumps The four concentrates holding tank transfer pumps are abandoned in place and no longer in use. 9.3.4.2.4.8 Regenerative Heat Exchanger The regenerative heat exchanger is designed to recover heat from the letdown flow by reheating the charging flow, which reduces thermal shock on the charging penetrations into the reactor coolant loop piping.
The letdown stream flows through the shell of the regenerative heat exchanger, and the charging stream flows through the tubes. The unit is made of austenitic stainless steel and is of all-welded construction.
The temperatures of both outlet streams from the heat exchanger are monitored with indication given in the control room. High alarm is given on the main control board if the temperature of the letdown stream exceeds desired limits.
Excessive pressure in the letdown line at the regenerative heat exchanger would be indicated in the control room by signals from:
(1) Pressure sensors located on Loop 4 of the RCS (2) Pressure sensors located on the pressurizer DCPP UNITS 1 & 2 FSAR UPDATE 9.3-32 Revision 20 November 2011 9.3.4.2.4.9 Letdown Heat Exchanger The letdown heat exchanger cools the letdown stream to the operating temperature of the mixed bed demineralizers. Reactor coolant flows through the tube side of the exchanger while component cooling water flows through the shell-side. All surfaces in contact with the reactor coolant are austenitic stainless steel, and the shell is carbon steel.
The letdown temperature control indicates and controls the temperature of the letdown flow exiting from the letdown heat exchanger. The temperature sensor, which is part of the CVCS, provides input to the controller in the CCWS. The exit temperature is controlled by regulating the component cooling water flow through the letdown heat exchanger by using the control valve located in the component cooling water discharge line. Temperature indication is provided on the main control board. Abnormally high temperature on the letdown line downstream of the regenerative heat exchanger or the letdown heat exchanger is indicated by a high-temperature alarm.
Pressure in the letdown line at the letdown heat exchanger is indicated in the control room by signals from the pressure sensor in the letdown line downstream of the letdown heat exchanger. Excessive pressure could lift the relief valve located downstream of the letdown orifices. This would be indicated by a temperature sensor located in the relief valve of the relief discharge line. 9.3.4.2.4.10 Excess Letdown Heat Exchanger The excess letdown heat exchanger cools reactor coolant letdown flow, which is equivalent to the nominal seal injection flow which flows downward through the reactor coolant pump labyrinth seals.
The excess letdown heat exchanger can be employed either when normal letdown is temporarily out of service to maintain the reactor in operation or it can be used to supplement maximum letdown during the final stages of heatup. The letdown flows through the tube side of the unit and component cooling water is circulated through the shell side. All surfaces in contact with reactor coolant are austenitic stainless steel, and the shell is carbon steel. All tube joints are welded.
A temperature detector measures temperature of excess letdown downstream of the excess letdown heat exchanger. High-temperature alarm and indication are provided on the main control board.
A pressure sensor indicates the pressure of the excess letdown flow downstream of the excess letdown heat exchanger and excess letdown control valve. Pressure indication is provided on the main control board.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-33 Revision 20 November 2011 9.3.4.2.4.11 Seal Water Heat Exchanger The seal water heat exchanger is designed to cool fluid from three sources: reactor coolant pump seal water returning to the CVCS, reactor coolant discharged from the excess letdown heat exchanger, and centrifugal charging pump bypass flow. Reactor coolant flows through the tube side of the heat exchanger, and component cooling water is circulated through the shell side. The design flowrate is equal to the sum of the excess letdown flow, maximum design reactor coolant pump seal leakage, and bypass flow from the centrifugal charging pumps. The unit is designed to cool the above flow to the temperature normally maintained in the volume control tank. All surfaces in contact with reactor coolant are austenitic stainless steel, and the shell is carbon steel. 9.3.4.2.4.12 Volume Control Tank The volume control tank provides surge capacity for part of the reactor coolant expansion volume not accommodated by the pressurizer. When the level in the tank reaches the high-level setpoint, the remainder of the expansion volume is accommodated by diversion of the letdown stream to the holdup tanks. It also provides a means for introducing hydrogen into the coolant to maintain the required equilibrium concentration, is used for degassing the reactor coolant, and serves as a head tank for the suction of the charging pumps.
A spray nozzle located inside the tank on the letdown line nozzle provides liquid-to-gas contact between the incoming fluid and the hydrogen atmosphere in the tank.
For degassing, the tank is provided with a remotely operated solenoid valve backed up by a pressure control valve, which ensures that the tank pressure does not fall below minimum operating pressure during degassing to the waste disposal system. Relief protection, gas space sampling, and nitrogen purge connections are also provided. The tank can also accept the seal water return flow from the reactor coolant pumps, although this flow normally goes directly to the suction of the charging pumps.
Volume control tank pressure and temperature are monitored with indication given in the control room. Alarm is given in the control room for high- and low-pressure conditions and for high temperature. Two level channels govern the water inventory in the volume control tank. These channels provide local and remote level indication, level alarms, level control, makeup control, and emergency makeup control.
If the volume control tank level rises above the normal operating range, one channel provides an analog signal to a proportional controller, which modulates the three-way valve downstream of the reactor coolant filter to maintain the volume control tank level within the normal operating band. The three-way valve can split letdown flow so that a portion goes to the holdup tanks and a portion to the volume control tank. The controller would operate in this fashion during a dilution operation when primary makeup water is being fed to the volume control tank from the RMCS.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-34 Revision 20 November 2011 If the modulating function of the channel fails and the volume control tank level continues to rise, then the high-level alarm will alert the operator to the malfunction and the letdown flow can be manually diverted to the holdup tanks. If no action is taken by the operator and the tank level continues to rise, the letdown flow will be automatically diverted to protect the tank from an overpressure condition.
During normal power operation, a low level in the volume control tank initiates automatic makeup, which injects a preselected blend of boron and water into the charging pump suction header. When the volume control tank is restored to normal, automatic makeup stops.
If the automatic makeup fails or is not aligned for operation and the tank level continues to decrease, a low-level alarm is actuated. Manual action may correct the situation or, if the level continues to decrease, an emergency low-level signal from both channels opens the stop valves in the refueling water supply line and closes the stop valves in the volume control tank outlet line. 9.3.4.2.4.13 Boric Acid Tanks The combined boric acid tank capacity is sized to store sufficient boric acid solution for a cold shutdown from full power operation immediately following refueling with the most reactive control rod not inserted, plus operating margins.
The concentration of boric acid solution in storage is maintained between 4.0 and 4.4 percent by weight (7,000 to 7,700 ppm boron). Periodic manual sampling and corrective action, if necessary, ensure that these limits are maintained. As a consequence, measured amounts of boric acid solution can be delivered to the reactor coolant to control the concentration.
Each of two electric heaters in each boric acid tank is designed to maintain the temperature of the boric acid solution at 165°F with ambient air temperature of 40°F, thus ensuring a temperature in excess of the solubility limit. Heater controls maintain the temperature of the boric acid solution at nominally between 110 and 120°F.
A temperature sensor provides temperature measurement of each tank's contents. Local temperature indication is provided as well as high- and low-temperature alarms which are indicated on the main control board.
A level detector indicates the level in each boric acid tank. Level indication with high, low, and low-low level alarms is provided on the main control board. The low alarm is set to indicate the minimum level of boric acid in the tank to ensure sufficient boric acid to provide for a cold shutdown with one stuck rod. DCPP UNITS 1 & 2 FSAR UPDATE 9.3-35 Revision 20 November 2011 9.3.4.2.4.14 Batching Tank The batching tank is used for mixing a makeup supply of boric acid solution for transfer to the boric acid tanks or the boric acid reserve tanks. The tank may also be used for solution storage.
A local sampling point is provided for verifying the solution concentration prior to transferring it out of the tank. The tank is provided with an agitator to improve mixing during batching operations and a means for heating the boric acid solution. 9.3.4.2.4.15 Chemical Mixing Tank The primary use of the chemical mixing tank is in the preparation of lithium hydroxide solutions for pH control and hydrazine for oxygen scavenging. 9.3.4.2.4.16 Holdup Tanks A total of five holdup tanks are provided for Units 1 and 2. Two of these tanks serve Unit 1, and two serve Unit 2. The fifth tank can be used with either unit. The holdup tanks hold radioactive liquid, which enters from the letdown line. The liquid is released from the RCS during startup, shutdowns, load changes, and from boron dilution to compensate for burnup. The contents of one tank are normally being processed by the ion exchangers and while the other tank is being filled. The tank shared by the two units is typically kept empty to provide additional storage capacity, when needed, and can be used to store supplemental refueling water. The total liquid storage capacity of three holdup tanks is approximately equal to two RCS volumes. The tanks are constructed of austenitic stainless steel. 9.3.4.2.4.17 Boric Acid Reserve Tanks Two boric acid reserve tanks are provided for storage of boric acid to meet operational needs for a ready supply of boric acid solution. One tank is maintained on a short recirculation through an inline circulation heater to maintain the tank contents and the associated piping and equipment above 80°F. The other tank is maintained on long recirculation, which also includes the transfer piping in the recirculation loop. Recirculation is normally accomplished by using either one of the two installed recirculation pumps. A transfer pump is provided to send boric acid to the boric acid tank or to the batch tank. The boric acid storage tanks can be filled from the boric acid evaporator concentrates or from the batch tank.
Flush water can be provided from the MWS to flush the boric acid from the piping, through the flush bypass line, to the liquid holdup tanks. In addition, water from the boric acid reserve tank can also be pumped to the processed waste receiver or to the liquid holdup tanks via installed connections.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-36 Revision 20 November 2011 The tanks are provided with a Hypalon coated floating cover that will prevent absorption of oxygen by the boric acid solution. In addition, the annular space around the side of the cover between the fluid surface and the bladder attachment point is continuously purged with nitrogen to further reduce the absorption of oxygen by the boric acid. The nitrogen purge vents out vent holes in the bladder attachment bar inside the tank and the vents to the room atmosphere through the tank vent.
Recirculating flow indication and a low flow alarm are provided for each tank. Also provided are a tank low temperature alarm and a high-low tank level alarm. 9.3.4.2.4.18 Concentrates Holding Tank The concentrates holding tanks are abandoned in place and no longer in use. 9.3.4.2.4.19 Mixed Bed Demineralizers Two flushable mixed bed demineralizers assist in maintaining reactor coolant purity. A lithium-form cation resin and hydroxyl-form anion resin are charged into the demineralizers. Both forms of resin remove fission and corrosion products. The resin bed is designed to reduce the concentration of ionic isotopes in the purification stream except for cesium, yttrium, and molybdenum by a minimum factor of 10.
Each demineralizer nominally has sufficient capacity for approximately one core cycle with 1 percent defective fuel rods. One demineralizer serves as a standby unit for use if the operating demineralizer becomes exhausted during operation. The normal resin volume is 30 cubic feet per demineralizer. The maximum resin volume is 39 cubic feet per demineralizer. Resin volumes greater than 30 cubic feet cannot be regenerated in the vessel and must be flushed when no longer needed. Resin volumes less than 30 cubic feet may be used for special resins or to meet various requirements.
A temperature sensor measures temperature of the letdown flow downstream of the letdown heat exchanger and controls the letdown flow to the mixed bed demineralizers by means of a three-way valve. If the letdown temperature exceeds the allowable resin operating temperature, the flow is automatically bypassed around the demineralizers. Temperature indication and high alarm are provided on the main control board. The air-operated three-way valve failure mode directs flow to the volume control tank. 9.3.4.2.4.20 Cation Bed Demineralizer The flushable cation resin bed in the hydrogen form is located downstream of the mixed bed demineralizers and is used intermittently to control the concentration of Li7 which builds up in the coolant from the B10 (n, ) Li7. The demineralizer also has sufficient capacity to maintain the cesium-137 concentration in the coolant below 1 µCi/cc with DCPP UNITS 1 & 2 FSAR UPDATE 9.3-37 Revision 20 November 2011 1 percent defective fuel. The resin bed is designed to reduce the concentration of ionic isotopes, particularly cesium, yttrium, and molybdenum, by a minimum factor of 10.
The cation bed demineralizer has sufficient capacity for approximately one core cycle with 1 percent defective fuel rods. 9.3.4.2.4.21 Deborating Demineralizers When required, two anion demineralizers remove boric acid from the RCS fluid. The demineralizers are provided for use near the end of a core cycle, but can be used at any time when boron concentration is low. As an alternative, one of these demineralizers may be filled with a mixed bed and used for removal of radionuclides during forced oxygenation.
The normal resin volume is 30 cubic feet per demineralizer. The maximum resin volume is 39 cubic feet per demineralizer. Resin volumes greater than 30 cubic feet cannot be regenerated in the vessel and must be flushed when no longer needed.
Hydroxyl-based ion exchange resin is used to reduce RCS boron concentration by releasing a hydroxyl ion when a borate is absorbed. Facilities are provided for regeneration. When regeneration is no longer feasible, the resin is flushed to the spent resin storage tank.
The demineralizers are sized to remove approximately 100 ppm of boric acid from the RCS to maintain full power operation near the end of core life should the holdup tanks be full. 9.3.4.2.4.22 Evaporator Feed Ion Exchangers Two trains of ion exchangers purify the feed and routes it to the liquid radwaste system. Each train consists of two demineralizer vessels in series. The resin beds in these demineralizers remove cationic impurities including cesium and molybdenum, and anionic impurities including chlorides, fluorides, and sulfur species. One train is in service during evaporator operation and the other is on standby. 9.3.4.2.4.23 Evaporator Condensate Demineralizers The evaporator condensate demineralizers are abandoned in place and no longer in use. 9.3.4.2.4.24 Reactor Coolant Filter The reactor coolant filter is located on the letdown line upstream of the volume control tank. The filter collects resin fines and particulates from the letdown stream. The nominal flow capacity of the filter is equal to the maximum purification flowrate.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-38 Revision 20 November 2011 Two local pressure indicators are provided to show the pressures upstream and downstream of the reactor coolant filter and thus provide filter differential pressure. A redundant reactor coolant filter has been installed as a standby. 9.3.4.2.4.25 Seal Water Injection Filters Two seal water injection filters are located in parallel in a common line to the reactor coolant pump seals; they collect particulate matter that could be harmful to the seal faces. Each filter is sized to accept flow in excess of the normal seal water requirements.
A differential pressure indicator monitors the pressure drop across each seal water injection filter and gives local indication with high differential pressure alarm on the main control board. 9.3.4.2.4.26 Seal Water Return Filter The filter collects particulates from the reactor coolant pump seal water return and from the excess letdown flow. The filter is designed to pass flow in excess of the sum of the excess letdown flow and the maximum design leakage from the reactor coolant pump seals.
Two local pressure indicators are provided to show the pressures upstream and downstream of the filter and thus provide the differential pressure across the filter. 9.3.4.2.4.27 Boric Acid Filter The boric acid filter collects particulates from the boric acid solution being pumped to the charging pump suction line or boric acid blender. The filter is designed to pass the design flow of two boric acid transfer pumps operating simultaneously.
The condition of the filter can be ascertained using a local differential pressure indicator. 9.3.4.2.4.28 Ion Exchange Filter This filter collects resin fines and particulates from the gas stripper feed pumps and routes it to the liquid radwaste system. Local pressure indicators indicate the pressure upstream and downstream of the filter and thus provide filter differential pressure. 9.3.4.2.4.29 Condensate Filter The condensate filter is abandoned in place and no longer in use. DCPP UNITS 1 & 2 FSAR UPDATE 9.3-39 Revision 20 November 2011 9.3.4.2.4.30 Concentrate Filter The concentrate filter is abandoned in place and no longer in use. 9.3.4.2.4.31 Boric Acid Reserve Tank Recirculation Heaters Twelve kilowatt heaters are provided in the boric acid reserve tank recirculation paths to heat the boric acid. This will in turn maintain the tank contents and the associated recirculation piping above 80°F. The heaters are controlled by a temperature controller that senses tank temperature and regulates the power supplied to the heaters accordingly. An over temperature controller is provided which senses heater temperature and cuts power to the heater when a high temperature is sensed at the heating element. 9.3.4.2.4.32 Boric Acid Blender The boric acid blender promotes thorough mixing of boric acid solution and reactor makeup water for the reactor coolant makeup circuit. The blender consists of a conventional pipe tee fitted with a perforated tube insert. The blender decreases the pipe length required to homogenize the mixture for taking a representative local sample. A sample point is provided in the piping just downstream of the blender. 9.3.4.2.4.33 Letdown Orifices The three letdown orifices are arranged in parallel and serve to reduce the pressure of the letdown stream to a value compatible with the letdown heat exchanger design. Two of the three are sized such that either can pass normal letdown flow; the third can pass less than the normal letdown flow. One or both standby orifices may be used with the normally operating orifice in order to increase letdown flow such as during reactor heatup operations. This arrangement also provides a full standby capacity for control of letdown flow. Orifices are placed in and taken out of service by remote-manual operation of their respective isolation valves.
A flow monitor provides indication in the control room of the letdown flowrate and high alarm to indicate unusually high flow.
A low-pressure letdown controller controls the pressure downstream of the letdown heat exchanger to prevent flashing of the letdown liquid. Pressure indication and high-pressure alarm are provided on the main control board. 9.3.4.2.4.34 Gas Stripper-Boric Acid Evaporator Package Liquid effluent in the holdup tanks is processed as a batch operation. This liquid is pumped by the gas stripper feed pumps through the evaporator feed ion exchangers. It then flows through the ion exchanger filter, and then the liquid is drained to the liquid DCPP UNITS 1 & 2 FSAR UPDATE 9.3-40 Revision 20 November 2011 radwaste system for processing. The boric acid evaporator system is abandoned in place and no longer in use. 9.3.4.2.4.35 Electric Heat Tracing Electric heat tracing is installed under the insulation on piping, valves, line-mounted instrumentation, and components normally containing concentrated boric acid solution. Even though the heat tracing is not required to maintain the 4 percent boric acid solution above the 65°F precipitation temperature, it does provide added assurance against falling below this limit. The existing boric acid heat tracing provides two parallel nonsafety-related heater circuits in a bifilar arrangement. One circuit is used for normal operations and the second serves as a backup. The size of the section heated by each pair of circuits is determined by the capacity of the heaters and their feeders, as well as the temperatures required.
There are no heat tracings on:
(1) Lines that may transport concentrated boric acid but are subsequently flushed with reactor coolant or other liquid of low boric acid concentration during normal operation (2) The boric acid tanks, which are provided with immersion heaters (3) The boric acid reserve tanks, which are provided with inline recirculation heaters (4) The batching tank, which is provided with a steam jacket (5) The concentrates holding tanks, which are provided with immersion heaters (abandoned in place)
Each circuit is controlled independently by a thermostat at a location having the most representative temperature of the circuit. The backup circuits are set to operate at a slightly lower temperature than the normal circuits. A thermocouple to detect metal temperature is installed under the thermal insulation near the thermostats. The thermocouples are monitored, and both low and high temperatures are alarmed. The low-temperature alarm setpoint is within the operating range of the backup heater.
The Boric Acid Storage Tank sample lines to the sample sink are provided with a single circuit of self-regulating heat trace. Because the precipitation temperature of 4 percent boric acid solution is below normal room temperature, the boric acid line heat tracing functions as a precautionary measure, and is not safety related. The circuit is monitored by an indicating light.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-41 Revision 20 November 2011 9.3.4.2.4.36 Valves Valves, other than diaphragm valves, that perform a modulating function are equipped with two sets of packing and an intermediate leakoff connection. Valves are normally installed such that, when closed, pressure is not on the packing. Basic material of construction is stainless steel for all valves. Isolation valves are provided for all lines entering the reactor containment. These valves are discussed in detail in Section 6.2.4.
Relief valves are provided for lines and components that might be pressurized above design pressure by improper operation or component malfunction. These discharges are collected and routed to the pressurizer relief tank inside containment to minimize activity releases in the auxiliary building. Charging Line Downstream of Regenerative Heat Exchanger If the charging side of the regenerative heat exchanger is isolated while the hot letdown flow continues at its maximum rate, the volumetric expansion of coolant on the charging side of the heat exchanger is relieved to the RCS through a spring-loaded check valve. The spring in the valve is designed to permit the check valve to open in the event that the differential pressure exceeds the design pressure differential of 200 psi. Letdown Line Downstream of Letdown Orifices The pressure-relief valve downstream of the letdown orifices protects the low-pressure piping and the letdown heat exchanger from overpressure when the low-pressure piping is isolated. The capacity of the relief valve exceeds the maximum flowrate through all letdown orifices. The valve set pressure is equal to the design pressure of the letdown heat exchanger tube side. Letdown Line Downstream of Low-pressure Letdown Valve The pressure-relief valve downstream of the low-pressure letdown valve protects the low-pressure piping, demineralizers, and filter from overpressure when this section of the system is isolated. The overpressure may result from leakage through the low-pressure letdown valve. The capacity of the relief valve exceeds the maximum flowrate through all letdown orifices. The valve set pressure is equal to the design pressure of the demineralizers. Volume Control Tank The relief valve on the volume control tank permits the tank to be designed for a lower pressure than the upstream equipment. This valve has a capacity greater than the summation of the following items: maximum letdown, maximum seal water return, excess letdown, and nominal flow from one reactor makeup water pump. The valve set pressure equals the design pressure of the volume control tank.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-42 Revision 20 November 2011 Charging Pump Suction A relief valve on the charging pump suction header relieves pressure that may build up if the suction line isolation valves are closed or if the system is overpressurized. The valve set pressure is equal to the design pressure of the associated piping and equipment. Seal Water Return Line (Inside Containment) This relief valve is designed to relieve overpressurization in the seal water return piping inside the containment if the motor-operated isolation valve is closed. The valve is designed to relieve the total leakoff flow from the No. 1 seals of the reactor coolant pumps plus the design excess letdown flow. The valve is set to relieve at the design pressure of the piping. Seal Water Return Line (Charging Pumps Bypass Flow) This relief valve protects the seal water heat exchanger and its associated piping from overpressurization. If either of the isolation valves for the heat exchanger is closed and if the bypass line is closed, the piping may be overpressurized by the bypass flow from the centrifugal charging pumps. It is assumed that all centrifugal pumps are running with full bypass flow. The valve is set to relieve at the design pressure of the heat exchanger. 9.3.4.2.4.37 Piping All CVCS piping handling radioactive liquid is austenitic stainless steel. All piping joints and connections are welded, except where flanged connections are required to facilitate equipment removal for maintenance and hydrostatic testing. 9.3.4.2.4.38 Zinc Injection Sub-systems The CVCS includes a skid-mounted zinc injection sub-system that provides the capability to inject a zinc acetate solution to a line leading to the volume control tank. The chemical solution is injected into the non-safety related portion of the CVCS.
This sub-system includes a storage and mixing tank, 3 chemical feed pumps with electrical controls, and the associated piping, tubing, valves, controls, and instrumentation. The tank has a divider that separates the chemical supply for either unit. There is one chemical feed pump dedicated to each unit and a common pump that can serve either unit. The valves and pumps associated with this sub-system are all manually controlled from the skid. A nitrogen blanket is provided in the tank to exclude oxygen. Make-up water to prepare the zinc acetate solution is provided from the primary water storage tank. Power is provided from a non-Class 1E power source.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-43 Revision 20 November 2011 9.3.4.2.4.39 Argon Injection Sub-systems The CVCS includes a wall mounted argon injection sub-system that provides the capability to inject high purity argon into the zinc acetate supply line. The zinc acetate injection sub-system is described in 9.3.4.2.4.38. The argon injection sub-system is non-safety related and connects to a non-safety portion of the CVCS.
Argon injection aids in the identification of small primary to secondary steam generator tube leaks. Trace amounts of argon is injected to generate a short half-life isotope (Ar-41) that can easily be detected by the condenser off gas steam jet air ejector radiation monitor in the event of a steam generator tube teak.
This sub-system includes an argon bottle, regulator, valves and controls connected via tubing. A flow indicating controller and relief valve is installed downstream from the regulator to control the injection rate and provide over pressure protection. A check valve is located upstream of the zinc injection system tie-in. Other valves associated with this sub-system are all manually controlled from the skid. Power for the flow controller is provided from a non-Class 1E power source. 9.3.4.2.5 System Operation 9.3.4.2.5.1 CVCS Operation During Reactor Startup Reactor startup is defined as the operations, which bring the reactor from cold shutdown to normal operating temperature and pressure. Reactor pressure vessel heatup and cooldown and compliance with ASME Code Section III, Appendix G, is discussed in Section 5.2. It is assumed that:
(1) Normal RHR is in progress.
(2) RCS boron concentration is at or above the cold shutdown concentration. (3) RMCS is set to provide makeup at or above the cold shutdown concentration. (4) RCS is either water-solid or drained to minimum level for the purpose of refueling or maintenance. If the RCS is water-solid, system pressure is controlled by letdown through the RHRS and through the letdown pressure control valve. (5) The charging and letdown lines of the CVCS are filled with coolant at the cold shutdown boron concentration. The letdown orifice isolation valves are closed. DCPP UNITS 1 & 2 FSAR UPDATE 9.3-44 Revision 20 November 2011 If the RCS requires filling and venting, the general process is as follows (depending on plant conditions, the startup process may vary):
(1) One charging pump is started, which provides blended flow from the RMCS (or RWST) at the cold shutdown boron concentration. (2) The vents on the head of the reactor vessel and pressurizer are vented. (3) The various portions of the RCS are filled and the vents closed.
The charging pump and the low-pressure letdown valve continue to pressurize the system. When the system pressure is adequate for operation of the reactor coolant pumps, seal water flow to the pumps is established (if not already in service) and the pumps are sequentially operated and the RCS is vented until all gases are cleared from the system.
After the filling and venting operations are completed, pressurizer heaters are energized and the reactor coolant pumps are operated to heat up the system. After the reactor coolant pumps are started, the RHR pumps are stopped, but pressure control via the RHRS and the low-pressure letdown line is continued. At this point, steam formation in the pressurizer is accomplished by adjusting charging flow and the pressurizer pressure controller. When the pressurizer level reaches the no-load programmed setpoint, the pressurizer level is controlled to maintain the programmed level. The RHRS is then configured in its ECCS alignment.
The reactor coolant boron concentration is now reduced by operating the RMCS in the "dilute" mode. The reactor coolant boron concentration is adjusted to the point where the control rods may be withdrawn and criticality achieved. Power operation may then proceed with corresponding manual adjustment of the reactor coolant boron concentration to balance the temperature coefficient effects and maintain the control rods within their operating range. During operation, the appropriate combination of letdown orifices is used to provide necessary letdown flow.
Prior to and during the heatup process, the CVCS is employed to obtain the correct chemical properties in the RCS. The RMCS is operated on a continuing basis to ensure correct control rod position. Chemicals are added through the chemical mixing tank as required to control reactor coolant chemistry such as pH and dissolved oxygen content. Hydrogen overpressure is established in the volume control tank to ensure the appropriate hydrogen concentration in the reactor coolant. 9.3.4.2.5.2 Power Generation and Hot Standby Operation Base Load At a constant power level, the rates of charging and letdown are dictated by the requirements for seal water to the reactor coolant pumps and the normal purification of DCPP UNITS 1 & 2 FSAR UPDATE 9.3-45 Revision 20 November 2011 the RCS. Typically, one charging pump is employed and charging flow is controlled automatically from pressurizer level. The only adjustments in boron concentration necessary are those to compensate for core burnup. Rapid variations in power demand are accommodated automatically by control rod movement. If variations in power level occur, and the new power level is sustained for long periods, some adjustment in boron concentration may be necessary to maintain the control groups at their desired position.
During typical operation, normal letdown flow is maintained and one mixed bed demineralizer is in service. Reactor coolant samples are taken periodically to check boron concentration, water quality, pH, and activity level. The charging pump flow to the RCS is controlled by the pressurizer level control signal through the discharge header flow control valve. Load Follow (not normally performed) A power reduction will initially cause a xenon buildup followed by xenon decay to a new, lower equilibrium value. The reverse occurs if the power level increases; initially, the xenon level decreases and then it increases to a new and higher equilibrium value associated with the amount of the power level change.
The RMCS is used to vary the reactor coolant boron concentration to compensate for xenon transients occurring when reactor power level is changed.
One indication available to the plant operator (enabling him to determine whether dilution or boration of the RCS is necessary) is the position of the control rods within the desired band. If, for example, the control rods are moving down into the core and are approaching the bottom of the desired band, the operator must borate the reactor coolant to bring the rods outward. If not, the control rods may move into the core beyond the insertion limit. If, on the other hand, the rods are moving out of the core, the operator dilutes the reactor coolant to keep the rods from moving above the top of the desired band.
During periods of plant loading, the reactor coolant expands as its temperature rises. The pressurizer absorbs most of this expansion as the level controller raises the level setpoint to the increased level associated with the new power level. The remainder of the excess coolant is let down and may be accommodated in the volume control tank or liquid holdup tanks. During this period, the flow through the letdown orifice remains constant and the charging flow is reduced by the pressurizer level control signal, resulting in an increased temperature at the regenerative heat exchanger outlet. The temperature controller downstream from the letdown heat exchanger increases the CCW flow to maintain the desired letdown temperature.
During periods of plant unloading, the charging flow is increased to make up for the coolant contraction not accommodated by the programmed reduction in pressurizer level.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-46 Revision 20 November 2011 Hot Standby If required for periods of maintenance or following reactor trips, the reactor can be held subcritical, but with the capability to return to full power within the period of time it takes to withdraw control rods. During this hot standby period, temperature is maintained at no-load Tavg by dumping steam to remove core residual heat. Following shutdown, xenon buildup and decay results in a variation in the degree of shutdown. During this time, boration and dilution of the system are performed to counteract these xenon variations. 9.3.4.2.5.3 Reactor Shutdown Reactor shutdown is defined as the operations that bring the reactor to cold shutdown for maintenance or refueling.
Before initiating a cold shutdown, the RCS hydrogen concentration is reduced by reduction of the volume control tank overpressure and venting the gases to the waste gas vent header.
Before cooldown and depressurization of the reactor plant is initiated, the reactor coolant boron concentration is increased to the value required for the corresponding target temperature. The operator uses the RMCS to add the volume of concentrated boric acid solution necessary to perform the boration. After the boration is completed, the operator uses the RMCS to maintain the desired reactor coolant boron concentration. Subsequent reactor coolant samples are taken to verify that the RCS boron concentration is correct. Contraction of the coolant during cooldown of the RCS results in actuation of the pressurizer level control to maintain normal pressurizer water level. The charging flow is increased, relative to letdown flow, and results in a decreasing volume control tank level. The RMCS initiates makeup to maintain the inventory.
Coincident with plant cooldown, a portion of the reactor coolant flow may be diverted from the RHRS to the CVCS for cleanup. Demineralization of ionic radioactive impurities and stripping of fission gases reduce the reactor coolant activity level sufficiently to permit personnel access for refueling or maintenance operations. 9.3.4.3 Safety Evaluation 9.3.4.3.1 Reactivity Control Any time that the plant is at power, the quantity of boric acid retained and ready for injection always exceeds that quantity required for the normal cold shutdown assuming that the control assembly of greatest worth is in its fully withdrawn position. This quantity always exceeds the quantity of boric acid required to bring the reactor to hot DCPP UNITS 1 & 2 FSAR UPDATE 9.3-47 Revision 20 November 2011 shutdown and to compensate for subsequent xenon decay. An adequate quantity of boric acid is also available in the refueling water storage tank (RWST) to achieve cold shutdown.
When the reactor is subcritical - i.e., during cold or hot shutdown, refueling, and approach to criticality - the neutron source multiplication is continuously monitored and indicated. Any appreciable increase in the neutron source multiplication, including that caused by the maximum physical boron dilution rate, is slow enough to give ample time to start a corrective action (boron dilution stop and boration) to prevent the core from becoming critical. The rate of boration, with a single boric acid transfer pump operating, is sufficient to take the reactor from full power operation to 1 percent shutdown in the hot condition, with no rods inserted, in 150 minutes. In an additional 3 hours, enough boric acid can be injected to compensate for xenon decay, although xenon decay below the full power equilibrium level will not begin until approximately 25 hours after shutdown. Additional boric acid is employed if it is desired to bring the reactor to cold shutdown conditions. Boric acid can also be added by injection through the reactor coolant pump seals at approximately 5 gpm per pump (20 gpm total). At this rate enough boric acid solution to compensate for xenon decay is added in less than 5 hours. Two separate and independent flowpaths are available for reactor coolant boration; i.e., the charging line and the reactor coolant pump seal injection. A single failure does not result in the inability to borate the RCS. An alternate flowpath is always available for emergency boration of the reactor coolant.
As backup to the normal boric acid supply, the operator can align the RWST outlet to the suction of the charging pumps or safety injection pumps when all the reactor vessel head bolts are fully detensioned. If a safety injection pump is used for boration, it is aligned to take suction from the RWST and discharge to the cold legs of the RCS, and the boundary valves from the CVCS to the SIS are closed. At least one flowpath is available for boron injection whenever fuel is in the reactor, and the capability of such injection is adequate to ensure that cold shutdown can be maintained.
The reactor will not be made critical unless redundant boration capability is available in quantity sufficient to ensure shutdown to cold conditions.
An upper limit to the boric acid tank boron concentration, and a lower limit to the temperature for the tank and for flowpaths from the tank are specified in order to ensure that solution solubility is maintained.
In the event of loss of offsite power, the safety (boration) function of the CVCS would be maintained. Power to centrifugal charging pumps CCP1 and CCP2 or safety injection pumps and associated valves would be available from the diesel generators. CCP1 or CCP2 or safety injection pump is sufficient to meet boron injection requirements for shutdown. Since each charging pump (CCP1 and CCP2) or safety injection pump is loaded on a separate diesel generator, a single failure of any one diesel generator will DCPP UNITS 1 & 2 FSAR UPDATE 9.3-48 Revision 20 November 2011 not impair the safety function of the pumps. A natural circulation test program was conducted during startup testing to demonstrate that the boron mixing and cooldown functions associated with taking the plant to cold shutdown can be accomplished under natural circulation.
Since inoperability of a single component does not impair ability to meet boron injection requirements, plant operating procedures allow components to be temporarily out of service for repairs. However, with an inoperable component, the ability to tolerate additional component failure is limited. Therefore, operating procedures require immediate action to effect repairs of an inoperable component, restrict permissible repair time, and require verification of the operability of the redundant component. Boron injection system operability requirements are discussed in Reference 1. 9.3.4.3.2 Reactor Coolant Purification The CVCS is capable of reducing the concentration of ionic isotopes in the purification stream as required in the design basis. This is accomplished by passing the letdown flow through the mixed bed demineralizers that remove ionic isotopes except those of cesium, molybdenum, and yttrium with a minimum decontamination factor of 10. Through occasional use of the cation bed demineralizer, the concentration of cesium can be maintained below 1 µCi/cc, assuming 1 percent of the power is being produced by defective fuel. The cation bed demineralizer is capable of passing the normal letdown flow, though only a portion of this capacity is normally utilized. Each mixed bed demineralizer is capable of processing the maximum letdown flowrate. If the normally operating mixed bed demineralizer's resin has become exhausted, the second demineralizer can be placed in service. Each demineralizer is designed, however, to operate for one core cycle with 1 percent defective fuel. The maximum temperature that will be allowed for the mixed bed and cation bed demineralizers is approximately 140°F. If the temperature of the letdown stream approaches this level, the flow will be diverted automatically so as to bypass the demineralizers. If the letdown is not diverted and temperature increases, ion exchange takes place at a faster rate. However, there would be a decrease in overall ion removal capacity. Ion removal capacity starts to decrease when the temperature of the resin goes above approximately 160°F for anion resin or above approximately 250°F for cation resin. The resins do not lose their exchange capability immediately. However, with increasing temperature, the resin loses some of its ion exchange sites along with the ions that were held at the lost sites. The ions lost from the sites may be re-exchanged farther down the bed, if the resin is not near the end of its design life. The number of sites lost is a function of the temperature reached in the bed and of the time the bed remains at the high temperature.
There would be no safety problem associated with overheating of the demineralizer resins. The only effect on reactor operating conditions would be the possibility of a slight increase in the reactor coolant activity level and RCS chemical contaminants.
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-49 Revision 20 November 2011 9.3.4.3.3 Seal Water Injection Flow to the reactor coolant pumps' seals is ensured by the fact that there are three charging pumps, any one of which is capable of supplying the normal charging line flow plus the nominal seal water flow. 9.3.4.3.4 Hydrostatic Testing of the Reactor Coolant System A temporary hydrostatic test pump can pressurize the RCS to its maximum specified hydrostatic test pressure. The pump is capable of producing a hydrostatic test pressure greater than that required. 9.3.4.3.5 Leakage Provisions CVCS components, valves, and piping that see radioactive service are designed to present essentially zero leakage to the atmosphere. The components are provided with welded connections except where flanged connections are provided to permit removal for maintenance.
The volume control tank in the CVCS provides an inferential measurement of leakage from the CVCS as well as the RCS. Low level in the volume control tank actuates makeup at the prevailing reactor coolant boron concentration. The amount of leakage can be inferred from the amount of makeup added by the RMCS. 9.3.4.4 Tests and Inspections As part of plant operation, periodic tests, surveillance inspections, and instrument calibrations are made to monitor equipment condition and performance.
Most components are in use regularly; therefore, assurance of the availability and performance of the systems and equipment is provided by control room and/or local indication.
Technical specifications have been established concerning calibration, checking, and sampling of the CVCS. 9.3.4.5 Instrumentation Applications Process control instrumentation is provided to acquire data concerning key parameters about the CVCS. The location of the instrumentation is shown in Figure 3.2-8.
The instrumentation furnishes input signals for monitoring and/or alarming purposes. Indications and/or alarms are provided for the following parameters:
(1) Temperature DCPP UNITS 1 & 2 FSAR UPDATE 9.3-50 Revision 20 November 2011 (2) Pressure (3) Flow (4) Water level (5) Boron concentration (Continuous indication not provided. Periodic concentration measurements are provided by grab samples using the nuclear steam supply system sampling system or post-LOCA sampling system.)
The instrumentation also supplies input signals for control purposes. Some specific control functions are:
(1) Letdown flow is diverted to the volume control tank upon high-temperature indication upstream of the mixed bed demineralizers (2) Pressure downstream of the letdown heat exchangers is controlled to prevent flashing of the letdown liquid (3) Charging flow rate is controlled during charging pump operation (4) Water level is controlled in the volume control tank (5) Temperature of the boric acid solution in the batching tank is maintained (6) Reactor makeup is controlled 9.3.5 FAILED FUEL DETECTION Failed fuel detection is provided by analyzing reactor coolant grab samples via the nuclear steam supply sampling system.
9.3.6 NITROGEN AND HYDROGEN SYSTEMS 9.3.6.1 Design Bases The nitrogen and hydrogen systems supply gases required for cover gases, accumulator fill, certain instrumentation operations, degasification purging, layup of steam generators and feedwater heaters, and generator cooling. The nitrogen and hydrogen systems are not required for reactor protection, containment isolation, or ESFs. The following sections provide information on: (a) design bases, (b) system description, (c) safety evaluation, (d) tests and inspections, and (e) instrumentation applications for the nitrogen and hydrogen systems. The design classifications for these systems are given in the DCPP Q List (see Reference 8 of Section 3.2). The supply sources of nitrogen and hydrogen are shared by both units but delivered by DCPP UNITS 1 & 2 FSAR UPDATE 9.3-51 Revision 20 November 2011 separate supply headers. The backup air/nitrogen supply system is described in Section 9.3.1.6. 9.3.6.2 System Description 9.3.6.2.1 Nitrogen System The nitrogen system consists of a liquid nitrogen storage facility, which is the nitrogen source for both the low pressure gaseous nitrogen header and a series of high pressure gaseous nitrogen storage bottles. Nitrogen from the liquid supply tank is (a) gasified and supplied directly to the low pressure header or (b) compressed, then gasified, and supplied to the high pressure storage bottles.
The nitrogen system is capable of delivering nitrogen gas for various purposes. Pressure regulators are capable of reducing the pressure down to 1 psig. This is accomplished through a series of regulators from the supply source to the required equipment. Relief valves are set appropriately to prevent overpressure on the equipment. See Table 9.3-7 for the list of equipment requiring nitrogen and their supply pressures and flows. The pressure and flow data envelope the actual operating conditions.
All piping penetrating the containment is isolated automatically by a containment isolation signal. 9.3.6.2.2 Hydrogen System The hydrogen system is capable of delivering hydrogen gas for various purposes at a supply pressure of 2200 psig and reduced by pressure regulators in series to the required pressures. Relief valves are set at 2400 psig on the supply header. Other relief valves downstream of pressure regulators are set appropriately to prevent overpressure on the equipment. See Table 9.3-8 for the list of equipment requiring hydrogen and their supply pressures and flows.
No piping associated with the hydrogen system penetrates the containment.
In fire zones containing equipment required for safe shutdown, the hydrogen system is enclosed in guard pipes and enclosures such that if leaks occur, the leakage is vented to areas that do not contain equipment required for safe shutdown. Enclosures containing valves and instrumentation have flanges or doors that make the instrumentation and valves accessible for operation and maintenance. 9.3.6.3 Safety Evaluation That portion of the nitrogen system piping penetrating the containment is Design Class I and meets the single failure criterion required for containment isolation as described in Section 6.2.4. The remainder of the hydrogen and nitrogen systems is Design Class II. DCPP UNITS 1 & 2 FSAR UPDATE 9.3-52 Revision 20 November 2011 9.3.6.4 Tests and Inspections Periodic inspections will be made on the system. Periodic visual inspection and preventive maintenance will be made using normal industry practice. Functional and leakage tests are performed on the containment isolation valves. 9.3.6.5 Instrumentation Applications The instrumentation for the nitrogen and hydrogen systems is given below. 9.3.6.5.1 Temperature Local temperature indicators measure the temperature of the nitrogen and hydrogen supply. 9.3.6.5.2 Pressure Local pressure indicators measure the pressures in the various lines of the nitrogen and hydrogen systems.
Pressure transmitters located on the nitrogen and hydrogen supply headers are used to transmit the pressure to indicators on the auxiliary building control board. Pressure switches also located on the headers give a low-pressure alarm on the auxiliary building control board. Low pressure nitrogen header pressure is also alarmed in the control room of each unit.
9.3.6.5.3 Flow An excess flow check valve, FCV-39/40, is provided in the hydrogen supply header at each unit. The excess flow check valve (flow fuse) is a flow control device that limits the flow of hydrogen to the plant loads. 9.3.7 MISCELLANEOUS PROCESS AUXILIARIES The process auxiliary systems not associated with the reactor process system but necessary for plant operation are:
(1) Auxiliary steam system (2) Oily water separator and turbine building sump system Their design classification is given in the DCPP Q-List (see Reference 8 of Section 3.2).
DCPP UNITS 1 & 2 FSAR UPDATE 9.3-53 Revision 20 November 2011 9.3.7.1 Auxiliary Steam System This system is required to supply steam to certain pieces of equipment and plant locations. Steam is required for the following:
(1) Cask decontamination area (2) Caustic storage tank (3) Boric acid batching tank and water preheater (4) Waste concentrator (abandoned) (5) Boric acid evaporators and preheaters (abandoned) (6) Gland steam supply for the main turbine and main feedwater pump drive turbines (7) Makeup water evaporator air ejector (abandoned) (8) Steam jet air ejector (main condenser) (9) Containment atmosphere (10) Steam for service cleaning and equipment maintenance inside containment (11) Building heating reboiler: (a) Containment purge air (b) Fuel handling area (c) Auxiliary building (d) Machine shop (12) Main condenser deaeration steam (13) Caustic regeneration system (14) Carbon dioxide vaporizer An auxiliary boiler, used primarily during refueling or other outages of the unit or startup, is capable of supplying the 100 psig steam when main steam is not available. During shutdown, it will be necessary to supply steam to the boric acid batch tank. All pressure DCPP UNITS 1 & 2 FSAR UPDATE 9.3-54 Revision 20 November 2011 parts and accessories are designed, constructed, inspected, and stamped in accordance with applicable ASME Boiler and Pressure Vessel codes. The net steam output is 57,000 1b/hr at 110 psig. No. 2 fuel oil will be burned.
9.3.7.2 Oily Water Separator and Turbine Building Sump System The oily water separator, common to both units, is designed to separate oil and floating material from drains originating from the turbine building sumps (Units 1 and 2). The clear water effluent normally is discharged to the condenser circulating water discharge tunnel. If required, it can be routed to the auxiliary building floor drain receivers. The radioactive content of liquids discharged from the turbine building is monitored by a radiation monitor and flow element in the process lines to the oily water separator. 9.
3.8 REFERENCES
- 1. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
- 2. NUREG-0737, Clarification of TMI Action Plan Requirements, U. S. Nuclear Regulatory Commission, November 1980.
DCPP UNITS 1 & 2 FSAR UPDATE 9.4-1 Revision 21 September 2013 9.4 HEATING, VENTILATION, AND AIR-CONDITIONING (HVAC) SYSTEMS The normal design outdoor ambient air temperature for the HVAC systems described in this section is very conservatively selected as 78°F and maximum as 91°F.
The ASHRAE (Reference 5) recommended value of 2-1/2 percent design temperature for the Diablo Canyon Power Plant (DCPP) site is not higher than 71°F. The 2-1/2 percent values are those, which will be equaled or exceeded by about 73 hours per year during the four months between June and September.
Since the DCPP design was completed, ASHRAE has developed new criteria for design temperatures in Southern California (Reference 6). Also, PG&E has reviewed 9 years of onsite hourly ambient outdoor temperature data for the period May 1973 through April 1982. The most conservative of these is the 0.1 percent level (0.1 percent on an annual basis for 9 hours per year). The 0.1 percent level for the DCPP site is calculated as 78°F. ASHRAE suggests that the "0.1 percent 9-hour level should be used only for extremely conservative work, i.e., sensitive computer installations, heavy internal loads, etc. - the occasional project that must hold the desired temperature regardless of outside conditions." None of the safety-related equipment cooled by HVAC systems is that sensitive to the small variations in ambient temperature. The maximum and minimum recorded onsite ambient outdoor temperature for this 9-year period were 91°F and 39°F, respectively, although DCPP has since experienced temperatures outside of this range. (See Section 2.3.2.2.2).
The 0.1 percent values on an annual basis are those that will be equaled or exceeded about 9 hours per year. Based on the 78°F normal design outdoor temperature and the allowable 26°F rise, the ambient indoor air temperatures will be maintained below 104°F at all times, except for areas as noted in subsequent sections. Under design worst conditions, the indoor ambient temperatures could exceed the design temperature for 9 hours per year. The 9 hours would not be continuous but would occur only for a very short duration on any given day.
In fact, the above room temperature conditions are not likely to be reached every year. The Class 1E electrical equipment is capable of operating for short periods at temperatures in excess of 117°F. This will have an insignificant effect on the aging of the electrical insulation.
The DCPP Equipment Control Guidelines identify rooms/areas monitored by the area temperature monitoring system, along with their corresponding temperature limits. The ambient air temperatures in these areas are monitored continuously. Air temperatures exceeding the established setpoints are recorded along with the times. An alarm is also transmitted to the control room. The cause and effects of high temperature are investigated and corrected in accordance with the DCPP Equipment Control Guidelines.
DCPP UNITS 1 & 2 FSAR UPDATE 9.4-2 Revision 21 September 2013 The criteria for monitoring air temperature are given below: (1) Where only one Class 1E redundant train or division of safety-related electrical equipment is in a given room or area and the ventilation there is neither redundant nor Class 1E, the ambient air temperature monitoring system will be redundant. The temperature monitor will meet Class 1E requirements for supply and separation or have two reliable and redundant non-Class 1E supplies (2) Where only one Class 1E redundant train or division is in a given room or area and the ventilation is Class 1E, but is not redundant within the area, one temperature monitor will be used to monitor the area ambient temperature. The temperature monitor will meet Class 1E requirements for supply and separation or have two reliable and redundant non-Class 1E supplies. (3) Where one or more Class 1E redundant trains or divisions are in a given room or area and the ventilation is Class 1E and redundant, one non-redundant temperature monitor will be supplied. In calculating the performance of ventilating and air conditioning systems, no credit was taken for wind cooling of buildings and structures and heat absoption by equipment at elevated temperatures. The maximum solar load was checked for selected areas that housed safety-related equipment and was found to have negligible effect on the calculated indoor temperatures in these areas. The design classifications for the various HVAC systems are given in the DCPP Q-List (see Reference 8 of Section 3.2). 9.4.1 CONTROL ROOM The control room HVAC system functions during all design accident conditions. The system permits continuous occupancy of control rooms under normal and design accident conditions. The following sections provide information on (a) design bases, (b) system description, (c) safety evaluation, and (d) inspection and testing requirements for the control room HVAC system. 9.4.1.1 Design Bases The bases for control room HVAC system temperature design are as follows:
(1) Design indoor ambient temperatures based on 78°F outdoor design temperature: (a) Control room and safeguard rooms 85°F DCPP UNITS 1 & 2 FSAR UPDATE 9.4-3 Revision 21 September 2013 (b) HVAC equipment rooms 104°F (2) Indoor ambient temperature based on 91°F maximum outdoor temperature as described in Section 9.4: (a) Control room and safeguard rooms 96°F (b) HVAC equipment rooms 115°F (3) The upper limit of temperature environment for the control room is 120°F The bases for providing plant operator safety include: (1) Protection from smoke generated inside or outside the control room area (2) Protection from airborne radioactivity outside the control room and provisions for cleanup of activity trapped in the room (3) Protection from airborne toxic gas outside the control room (4) Considerations for carbon dioxide buildup inside the control room during periods when airborne contaminants prevent the use of outside makeup air The design classification for the control room HVAC system is given in the DCPP Q-List (see Reference 8 of Section 3.2). The design data for the system components are given in the itemized list in Table 9.4-1. Design codes and standards are given in Table 9.4-8.
9.4.1.2 System Description The control room HVAC system is comprised of two trains, one serving the Unit 1 area and one serving the Unit 2 area. Each train, as itemized in Table 9.4-1, consists of redundant air conditioning units, supply fans, pressurization fans, electrical humidity control heaters for charcoal adsorber units, filter booster fans and monitoring devices, and a single train of ducts and charcoal adsorber filter unit. The arrangement is shown in Figure 9.4-1. The Unit 1 area served by the system includes one computer room, one instrument safeguards room, one records storage room, one office, one kitchen area, one control room area, and one mechanical equipment area. The Unit 2 area served by the system includes one computer room, one instrument safeguards room, one toilet room, one control room area, one office, and one mechanical equipment area. Positive pressurization intakes are located at the SW and NW ends of the turbine building. A small non Design Class I exhaust fan (also itemized in Table 9.4-1) and a non-Design Class I electric duct heater per unit is also provided. The exhaust fan provides control room exhaust during normal operations (Mode 1) and for smoke removal (Mode 2). The electric duct heaters are provided only to maximize personnel DCPP UNITS 1 & 2 FSAR UPDATE 9.4-4 Revision 21 September 2013 comfort control. Additionally, the computer room in each Unit is provided with a supplemental non-design Class I air conditioning system. The system consists of three each air conditioning units, air cooled condensing units, and interconnecting refrigeration piping. The air conditioning units are staged by associated room thermostats. These units provide a suitable environment for the non-safety related computers. All redundant equipment receives power from vital buses separated to meet single failure criteria.
The control room HVAC System has four modes of operation. They are as follows: Mode 1: Conditioned air is supplied and returned through ducts to the designated service area of each unit. Approximately 27 percent of the return air is normally exhausted to the atmosphere and 73 percent of the return air is normally recirculated. The recirculated air is mixed with 27 percent outdoor makeup air and filtered through roughing filters, cooled (or heated), and supplied to the control room. Estimated control room area heat loads for this mode of operation are listed in Table 9.4-9. Mode 2: In the event of a fire in the control room, provisions are made for once through, 100 percent outdoor air operation. This mode exhausts the smoke from the room, thereby making it habitable. Roughing filters are used for filtering the outdoor air. The mode is manually initiated. Mode 3: In the event of airborne toxic gas outside the control room, provisions are made for manual zone isolation, 100 percent recirculated air with 27 percent passing through the high-efficiency particulate air (HEPA) filters and charcoal banks. Human detection (odor/smell) is used to initiate this mode. Mode 4: A mode of operation has been provided for use in the event of airborne radioactivity and the requirement of long-term occupancy of the control room. This mode isolates and pressurizes the control room and mechanical equipment room through the HEPA and charcoal filters with air from a low activity region to reduce local infiltration. The opposite control room HVAC train operates concurrently in Mode 3 recirculation. In the event an accident occurs in one unit, the system automatically selects the pressurization intake train of the opposite unit. With radiation detected at both pressurization intakes, one of the trains will start. However, the operator manually switches to the intake with lowest contamination. There are four manual selector switches on each unit: two mode selector switches and two bus selector switches. Two manual selector switches on the ventilation control panel are used to operate the control room HVAC system. One switch determines the mode of operation while the other switch selects one of two redundant trains of fans and air conditioning units to be used. DCPP UNITS 1 & 2 FSAR UPDATE 9.4-5 Revision 21 September 2013 The influx of airborne contaminants through the normal supply duct is limited by monitoring devices, which, upon detection of radioactive contaminants, automatically initiate Mode 4 HVAC operation. Closure of isolation dampers for Modes 3 and 4 (Figure 9.4-1) require within 10 seconds after manual initiation of this mode. Flow characteristics of the dampers are such that the average flow over the closure time is less than 60 percent of full flow.
Both Units 1 and 2 control room ventilation systems are designed to initiate Mode 4 operation, and Mode 3 operation on the opposite unit, automatically upon any one of the following signals:
(1) Safety injection signal from Unit 1 (2) Safety injection signal from Unit 2 (3) High outside air activity from control room 1 monitor (4) High outside air activity from control room 2 monitor Monitoring devices for control room HVAC systems are capable of detecting low levels of airborne contaminants: (1) Smoke detectors have sensitivity to detect trace amounts of combustion products. (2) Two outside air activity monitors per intake sample air entering the control room supply duct are scintillation-type general-purpose monitors with a 10-2 to 103 mR/hr range. Two outside air activity area monitors per intake sample air entering the pressurization system duct; they are G.M. tube-type general purpose monitors with a 10-2 to 104 mR/hr range. These monitors have an instrument failure alarm, control room readout, and alarm. The control room alarm is used for automatic initiation of Mode 4 zone isolation with automatic pressurization on one control room HVAC train and Mode 3 recirculation on the opposite control room HVAC train. (3) One area monitor is mounted on the radiation monitoring racks in the control room. This monitor is a G.M. tube-type general-purpose monitor with a 10-1 to 104 mR/hr range. This monitor has an instrument failure alarm, local readout, local alarm, and remote alarm. (4) The chlorine monitors at the pressurization outside air duct are abandoned in place as there is no bulk chlorine on site.
High smoke or airborne radioactivity is annunciated in the control room so that the operator can take appropriate action. DCPP UNITS 1 & 2 FSAR UPDATE 9.4-6 Revision 21 September 2013 Manual transfer switches are provided for the control room pressurization systems for supplying each unit's redundant logic and control power from the other unit's redundant power supplies. This enables operation of both Units 1 and 2 control room pressurization systems from the operating unit power in the event one unit is not operable.
The control room area is provided with minimum leakage dampers, weather-stripped doors, door vestibules, and absence of outdoor windows. Administrative controls ensure that all control room entranceways are normally closed.
Further protective options are provided by self-contained breathing apparatus located in the control room as stated in Section 6.4. 9.4.1.3 Safety Evaluation 9.4.1.3.1 Regulatory Guide 1.52 The control room HVAC systems are considered part of the engineered safety features (ESF) habitability systems. In Table 9.4-2, these systems are analyzed as to the positions in NRC Regulatory Guide 1.52, Design, Testing, and Maintenance Criteria for Atmosphere Cleanup System Air Filtration and Adsorption Units of Light-Water-Cooled Nuclear Power Plants (Reference 11). Each item of noncompliance is explained in full. 9.4.1.3.2 Single Failure Criteria Control room HVAC systems have two trains. Each train comprises two redundant full capacity active components. The two pressurization fans for each unit's air intake and the charcoal adsorber filter bank for each unit are common to both units and are fully redundant. Two independent and redundant control room HVAC trains, i.e. one train for each unit, are provided to ensure that at least one is available if a single active failure disables the other train. The source of the power for each electrically powered primary unit of equipment is from a vital bus, and parallel units are powered from separate vital buses.
Pneumatic dampers have a designated position that they will assume upon loss of the control air supply. This position would be the same as for Mode 3 or 4 operation. Electric dampers that must assume a position in any mode of operation are supplied with power from vital buses. A common warning light is provided on the control room panel to alert the operator if a ventilation damper is out of position. The position of each damper is indicated on a panel in the ventilation equipment room. Separation of the electrical supply from the vital buses has been followed throughout the installation. 9.4.1.3.3 Capability of Ensuring Ambient Temperature Conditions The system provides normal ambient temperature of 75°F with one set of redundant air conditioning equipment of each train operating. Based on an outside design DCPP UNITS 1 & 2 FSAR UPDATE 9.4-7 Revision 21 September 2013 temperature of 78°F, inside air temperature will be less than 85°F except in the computer room which is designed to have a temperature of 72 +/-4°F. The cooling capacity of each HVAC train is 31 tons based on normal operating conditions. The estimated cooling load for each unit area, including a portion of the computer room load, is 19.0 tons under normal operating conditions. The air flow into each unit area is 7475 cfm which provides nine control room and fifteen computer room air changes per hour. The system also provides 325 cfm to the HVAC equipment room of each unit to maintain the ambient temperature below 104°F. Electric duct heaters reheat or temper the air as necessary. The heaters are not redundant and are provided only to help balance the cooling system. In the event of heater malfunction, no vital control room air normalization functions are adversely affected. 9.4.1.3.4 Anticipated Degradation of Control Room Equipment if Temperature Levels are Exceeded The upper limit of temperature environment for the control room instrumentation is 120°F. Below this point, degradation of the equipment will not be an important factor. The system is designed to meet single failure criteria, so that one train of cooling will be available at all times. With only one train of cooling equipment operating, the temperature in the control room area is calculated to be approximately 89°F and the instrument safeguard room of the unit without air conditioning is approximately 116°F. Local hot areas within the equipment cabinets will be identified under operating conditions and provisions made for ventilation. 9.4.1.3.5 Capability of HEPA Filters for Particulate Removal Individual HEPA filters have been tested and are specified by the manufacturer to be able to remove 99.97 percent of particles 0.3 microns and larger, based on dioctylphathalate smoke particles in a standard test procedure. The overall efficiency of the filter bank will be dependent on the initial efficiency of the individual filters, the care with which the filters have been stored and installed, and the sealing effectiveness of the filter frames with the supporting members of the bank. A penetration and leakage test was performed in place prior to putting the system in operation. Plant procedures for receiving, storing, and handling HEPA filters are employed to ensure factory performance of all HEPA filters. 9.4.1.3.6 Capability of Charcoal Banks for Iodine Removal Individual charcoal filters have been tested and are specified by the manufacturer to be able to remove 99 percent of radioactive iodine in the form of elemental iodine and 95 percent of radioactive iodine in the form of methyl iodide. A bypass leakage test was performed in place prior to putting the system in operation.
DCPP UNITS 1 & 2 FSAR UPDATE 9.4-8 Revision 21 September 2013 9.4.1.3.7 Ability to Detect and Control Airborne Contaminants 9.4.1.3.7.1 Smoke A smoke detector located in the return air duct detects combustion products before visible smoke is present. The presence of combustion products will be alarmed in the control room where the operator will take corrective action. The control room is equipped with an adequate number of proper types of fire extinguishers and is manned by an operator(s) trained in fire fighting procedures. In the event of a large amount of smoke, the operator has the option to switch the HVAC system into the 100 percent makeup mode of operation. This mode will purge the room of smoke.
In the event that either damper 7 or 8 (Figure 9.4-1) fails to open during Mode 2 ventilation, the rate of air removal from the control room is reduced. If damper 7 fails to open, the air removal rate is approximately 2100 cfm. If damper 8 fails to open, the air removal rate is approximately 5375 cfm. Reduced air removal rates result in slower removal of smoke. 9.4.1.3.7.2 Activity Mode 4 operation of the control room HVAC systems is automatically initiated on a safety injection or outside air activity monitor signal. Initiation of Mode 4 operation on a control room HVAC system train initiates Mode 3 operation on the opposite train. Intake closure occurs within 10 seconds or less after initiation of closure signal and prevents any significant amount of activity from entering the control room. Infiltration of activity from outdoors and other areas of the auxiliary building is limited by minimum leakage dampers, zero leakage penetrations, weather-stripped doors, and the absence of outside windows. Administrative controls ensure that all control room entrance ways are normally closed. An evaluation of post-accident control room radiological exposures is presented in Section 15.5. 9.4.1.3.7.3 Carbon Dioxide With complete recirculation of the ventilation air, the carbon dioxide buildup is not expected to exceed an acceptable concentration of 1 percent by volume with 800 manhours of occupancy in the control room complex (e.g. 20 persons for 40 hours). Mode 4 ventilation operation will maintain acceptable CO2 levels inside the control room area. 9.4.1.3.7.4 Airborne Toxic Gas Mode 3 operation of the control room HVAC systems may be manually initiated on human detection of any airborne toxic gas by the control room operators. Intake closure occurs within 10 seconds after manual actuation. Infiltration of the toxic gas from outdoors and other areas of the auxiliary building is limited by minimum leakage DCPP UNITS 1 & 2 FSAR UPDATE 9.4-9 Revision 21 September 2013 dampers, zero leakage penetrations, weather-stripped doors, vestibules, and the absence of outside windows.
Administrative controls ensure that all control room entrance ways are normally closed.
The plant complies with NRC Regulatory Guide 1.78 (Reference 16). 9.4.1.3.8 Capability of Equipment to Withstand a Tornado Missile The only components of the control room HVAC system that have the potential of being damaged by a tornado missile are the normal intake and exhaust louvers and the Control Room Pressurization Section (CRPS) fans, ductwork, dampers and associated controls located on the turbine building operating deck and the auxiliary building roof. The ability of the normal intake and exhaust louvers to sustain tornado wind and missile damage is detailed in Section 3.3.2.3.2.1. The tornado missile design features of the CRPS components are detailed in Section 3.3.2.3.2.12. 9.4.1.4 Inspection and Testing Requirements 9.4.1.4.1 Initial System Inspection and Tests Initial checks of the motors, dampers, compressors, controls, monitors, etc., are made at the time of installation. A system air balance test and adjustment to design conditions are conducted. The final tests performed prior to actual operation of the HVAC system are the in-place tests of the HEPA and charcoal filter banks. Compliance of these tests with Regulatory Guide 1.52 is given in Table 9.4-2. 9.4.1.4.2 Routine System Tests The HVAC system is functionally tested periodically as required by the Technical Specifications (Reference 10) for proper operation of the modes of operation. This test includes checking the function of the dampers in Modes 1, 3, and 4 and measuring air flow through the filter as required by the Technical Specifications.
Control room radiation monitors are periodically tested and calibrated as required by the Technical Specifications.
The control room ventilation smoke detectors are demonstrated "operable" as required by the Equipment Control Guidelines.
An in-place test of the HEPA and/or charcoal filter banks is performed periodically as required by the Technical Specifications. Compliance of these tests with Regulatory Guide 1.52 is given in Table 9.4-2.
DCPP UNITS 1 & 2 FSAR UPDATE 9.4-10 Revision 21 September 2013 9.4.2 AUXILIARY BUILDING The following rooms/areas of the auxiliary building are provided with separate ventilation systems and are described in other sections:
(1) Control room - Section 9.4.1 (2) 125-Vdc and 480-Vac switchgear rooms - Section 9.4.9 (3) Battery charger and inverter rooms - Section 9.4.9 (4) Hot shutdown panel area - Section 9.4.9 (5) Cable spreading rooms - Section 9.4.9 The system described in this section includes the following rooms/areas: (1) ESFs electrical equipment areas: Component cooling water (CCW) pump rooms, safety injection pumps room, containment spray pumps room, residual heat removal (RHR) pump room, and centrifugal charging pumps CCP1 and CCP2 rooms (2) Radwaste areas The auxiliary building ventilation system has the primary function of maintaining the temperature of the ESF pump motors within acceptable limits during their operation. The secondary function of this system is to provide ventilation to the auxiliary building. The system also provides a flowpath which serves as a portion of one train of the containment hydrogen purge system. The following subsections provide information on (a) design bases, (b) system description, and (c) safety evaluation for the auxiliary building ventilation system. 9.4.2.1 Design Bases The system satisfies the following design bases in order to fulfill the functions outlined above: (1) Single Failure Criteria The initiation circuitry and all primary nonstatic components of the system, except the electric heater, are redundant with full capacity for each train.
Each train is also powered from separate emergency sources. All dampers fail in the positions required for emergency conditions (parallel dampers fail open, series dampers fail closed). DCPP UNITS 1 & 2 FSAR UPDATE 9.4-11 Revision 21 September 2013 (2) Flow Distribution The flow of air is always directed from areas of low potential contamination to areas of higher potential contamination. The building is under a slight negative pressure. (3) Cooling of ESF Pump Motors The ventilation system supplies cooling air for the ESF pump motors. Motors are designed for continuous operation at an ambient air temperature of 104°F. The supply fans and their associated dampers need to be in operation under both normal and accident conditions to maintain the environmental qualification and long term operation of the ESF pump motors. (4) Cleanup of Exhaust Air The normal building exhaust air is filtered through HEPA filters, and upon a safety injection signal, the emergency cooling exhausts air through both HEPA filters and charcoal filter banks. Following a loss-of-coolant accident (LOCA), the ventilation system can tolerate a relatively large RHR system leak during the recirculation cycle in the auxiliary building. (5) Design Classification and Design Codes and Standards The design classification for the auxiliary building ventilation system is given in the DCPP Q-List (see Reference 8 of Section 3.2). The design codes and standards are given in Table 9.4-8. 9.4.2.2 System Description The auxiliary building ventilating system provides all outside air supply for the auxiliary building under all operating conditions. It also serves its primary purpose of providing cooling air for the ESF pump motors. The air flow pattern is arranged so that the air flows from areas of lower potential contamination to areas of higher potential contamination, and is then discharged to the plant vent. This is accomplished by supplying air to the occupied areas then exhausting the air from each equipment area separately. The system is balanced so that the building is normally under a slight negative pressure. The exhaust ducts from potentially high activity areas are so routed as to minimize exposure to normally occupied areas.
The fans for the system receive power from the vital 480 V buses. Each full capacity fan of a redundant set receives power from a separate vital bus. The dampers for the system are redundant, pneumatically operated, and designed to fail in the positions required for emergency conditions. Dampers are arranged in parallel if the fail position is open, and in series if the fail position is closed. DCPP UNITS 1 & 2 FSAR UPDATE 9.4-12 Revision 21 September 2013 The supply system consists of two full capacity fans (each powered from a separate vital bus), roughing filters, and duct work for distribution. The exhaust system consists of two full capacity fans (each powered from a separate vital bus), two full capacity combined roughing and HEPA filter banks, one full capacity combined electric heater, roughing, HEPA and charcoal filter bank, and exhaust duct network (as shown in Figures 9.4-2 and 9.4-3). The major equipment for the system is listed in Table 9.4-5. The containment hydrogen purge line connects to the inlet plenum for the filter bank containing the charcoal filter (see Sections 6.2.5 and 9.2.5 and Figures 6.2-15, 9.4-3 and 9.4-3A). Manually controlled valves in this line allow flow to leave the containment and exhaust to the plant vent through the charcoal filter.
The logic control devices for both Units 1 and 2 control system are solid-state units providing a full selection of logic functions designed for binary system operation. The control system is based on a programmable logic controller (PLC). The basis for qualification of the Triconex PLC and associated software follows the guidance of Branch Technical Position (BTP) 7-14 and 7-18 (see References 21 and 22). The logic control system has output to solenoids and dry contact relays for the control functions. Both the logic controls and relays are redundant and have power sources from vital buses. The operation of the system is initiated from the ventilation control board in the control room. The logic control will position the dampers and start the system for normal operation. The supply fan and exhaust fan are interlocked in a manner as to ensure the building will not be subjected to an appreciable amount of positive pressure. High-temperature and fan-failure alarms and damper position are provided to the main annunciator from the supply fan room. The auxiliary building ventilation system has three modes of operation: Mode 1: During normal plant operation the system is designed to be in the "Building Only Ventilation" mode. In this mode, one of two 100 percent capacity supply fans and one of two 100 percent capacity exhaust fans operates. Outside air is drawn through intake louvers, roughing filters, and ducted to the building space through the building only ventilation mode supply duct system. In the building only ventilation operating mode, exhaust air passes through the roughing and HEPA filter train. In any mode of operation the exhaust air is discharged through the plant vent.
Mode 2: The system automatically shifts to Mode 2 operation, "Building and Engineered Safety Ventilation," when the control logic receives:
(1) A safety injection signal (2) An indication that any one of the motors for the centrifugal charging pumps CCP1 or CCP2, RHR pumps, safety injection pumps, or containment spray pumps has started DCPP UNITS 1 & 2 FSAR UPDATE 9.4-13 Revision 21 September 2013 Mode 2 may also be manually selected from the control panel in the control room for test or for operation. In this mode, the redundant set of supply and exhaust fans are designed to operate so that two supply and two exhaust fans are operating simultaneously. As in Mode 1, outside air is drawn through intake louvers, roughing filters and ducted to the building via the building only ventilation mode supply duct system and also through the ESF supply duct system. Depending on the presence of a safety injection signal, the exhaust air is handled as follows: (1) If the system receives a safety injection signal, the exhaust air from the ESF pump rooms and RHR heat exchanger rooms passes through the manually actuated electric heater, roughing, HEPA, and charcoal filters, and the exhaust air from all other areas passes through the redundant roughing and HEPA filter trains. (2) In the absence of safety injection signal, the exhaust air from all areas passes through both roughing and HEPA filter trains.
Mode 3: Mode 3 operation is the "Engineered Safety Ventilation Only" mode. This mode is automatically actuated if a supply or an exhaust fan fails while the system is in Mode 2 operation. The system supplies air only through the ESF supply duct system utilizing one exhaust fan and one supply fan. Depending on the presence of a safety injection signal, the exhaust is handled as follows:
(1) If the system receives a safety injection signal, the exhaust air from the ESF pump rooms and RHR heat exchanger rooms passes through the manually actuated electric heater, roughing, HEPA, and charcoal filters. (2) In the absence of a safety injection signal, the exhaust air from all areas passes through both roughing and HEPA filters trains.
Design values for the auxiliary building ventilation system are listed in Table 9.4-10. 9.4.2.3 Safety Evaluation Compliance of the auxiliary building ventilation system with Regulatory Guide 1.52 requirements is presented in Table 9.4-2. 9.4.2.3.1 Single Failure Criteria The auxiliary building ventilation system has redundancy for all primary nonstatic components, except for the electric heater. The fans are each full capacity, sized to handle the ESF pump motor cooling. In the event of the loss of an exhaust fan coincident with a safety injection signal, the second exhaust fan will start and the dampers will position themselves to route the air through the ESF ducts to the combined HEPA and charcoal filter banks.
DCPP UNITS 1 & 2 FSAR UPDATE 9.4-14 Revision 21 September 2013 The auxiliary building ventilation systems are provided with a single, full capacity roughing, HEPA, and charcoal filter bank (including an electric heater) to limit the offsite exposures from a post-LOCA RHR pump seal failure. A single charcoal filter train is provided because the failure of the charcoal filter train in conjunction with a LOCA and RHR pump seal would constitute a second failure as discussed in Section 15.5.17.
The power for the fans and the initiating (logic) circuitry is taken from vital buses with separation of redundant components. The dampers are positioned by pneumatic actuators supplied from the plant compressed air supply. The dampers are designed to assume the position required for emergency conditions on the failure of the air supply. If a damper fail position is normally open, two dampers are mounted in parallel. Conversely, if the damper fail position is normally closed, two dampers are mounted in series. The initiating (logic) circuitry is redundant, including relays and solenoids required to actuate the system. Each control train serves similar control functions, in addition to switching over circuits in the event of a failure to the other train. Separation has been maintained for the electrical circuits from each vital bus.
All ductwork serving ESF equipment has been designed to withstand any internal pressure that may be generated by any fan in the system, and braced according to Design Class I criteria to prevent earthquake damage to the ducts. All static ventilation components (i.e., volume dampers and air diffusers) have locking devices to prevent accidental closing. No duct liner or other insulating substance, which might sag or fall down, thereby blocking the duct, has been installed in any ductwork. 9.4.2.3.2 Flow Distribution The ventilation system serves the auxiliary building (including the radwaste area, excluding the fuel handling area). The general flow pattern is from areas of lower potential contamination to areas of higher potential contamination. This concept has been followed throughout. This flow pattern will be maintained under the first two modes of operation. However, when the system is operating under the "engineered safety ventilation only" mode, the total air flow will be exhausted through the ESF motor compartments only. 9.4.2.3.3 ESF Air Flow Relative Humidity In the unlikely event of a LOCA accompanied by RHR loop leakage in the auxiliary building, flashing of leakage water would increase the relative humidity of the auxiliary building ESF exhaust air flow. To enhance the efficient performance of the charcoal filters, manually actuated, 54 kW electric heater located upstream of the auxiliary building charcoal filters is sized to reduce the relative humidity of the ESF air flow. Operation of this heater is not required for this system to perform its safety function.
This heater is sized on the following assumptions: DCPP UNITS 1 & 2 FSAR UPDATE 9.4-15 Revision 21 September 2013 (1) Outside air conditions of 45°F and 100 percent relative humidity. These conditions represent a reasonable bound on expected conditions that maximizes the relative humidity of ESF air flow entering the auxiliary building charcoal filters. (2) Auxiliary building heat loads that result in a temperature rise of 16.5°F due to an increase in sensible heat of the 73,500 cfm ESF air flow. The only heat loads included are those associated with equipment that is required to operate following a LOCA and that would be expected to be operating during the period of postulated RHR loop leakage. These heat loads include motor losses and heat losses from piping and equipment associated with emergency core cooling systems (ECCS) and ESF ventilation system operation. Two trains of ECCS pumps, one containment spray system train, and two CCW pumps are assumed to be operating. (3) Adiabatic mixing of 738 lb/hr steam (3.1 percent flashing of 50 gpm leakage, see Section 15.5.17) with that portion of the ESF air flow which passes through the RHR pump rooms. Condensation is assumed that results in 100 percent relative humidity prior to mixing this portion of the ESF airflow with the remainder of the ESF air. Using these assumptions, and assuming operation of the 54 kW electric heater, results in less than 70 percent relative humidity for ESF air flow entering the auxiliary building charcoal filters. However, the charcoal used in the filters is tested to 95 percent relative humidity and the electric heater is not required for filter operability. 9.4.2.3.4 Containment Hydrogen Purging Containment hydrogen purging flows are of small magnitude and can be scheduled to avoid periods of peak load on the auxiliary building ventilation system. Containment hydrogen purging is manually controlled and, when required, operates only intermittently. No single failure can accidentally initiate flow.
Containment hydrogen purge is required for plant safety but is not required until several weeks following a LOCA (see Section 6.2.5). By this time, most of the ESF pumps are no longer in operation and the heat load on the ventilation system is well below its maximum. In addition, purging would be conducted only about 3 hours a day, at times desired by the operator. This further guarantees the ability to avoid peak load periods on the ventilation system. In any case, the maximum expected purge flow of only 300 cfm would not have a significant effect on the ventilation system.
DCPP UNITS 1 & 2 FSAR UPDATE 9.4-16 Revision 21 September 2013 9.4.2.3.5 Ambient Temperature Limits The ventilation system has been designed to maintain a maximum design room temperature of 104°F in the auxiliary building with a normal design outdoor ambient air temperature of 78°F with the following exceptions:
(1) The liquid holdup tank rooms shall have a maximum design room temperature of 130°F. (2) The ambient temperature in the area of the boric acid transfer pumps may reach a maximum temperature of approximately 124°F after one hour following the postulated event of one train of the auxiliary building ventilation system being inoperable post LOCA. The boric acid transfer pump may be required to operate within this period post LOCA. During any other operating conditions, the maximum design room temperature in this area shall be 104°F.
The airflow requirements have been based on the ESF motor cooling load. The allowable ambient air temperature for continuous operation of the ESF motors is 104°F. 9.4.2.3.6 Differential Pressures Regarding the differential pressures, the total auxiliary building was considered as an open building. However, the exhaust system will remove approximately 9 percent more air than the supply system will provide. The extra air quantity must be made up by infiltration. Each equipment compartment is exhausted separately or through another compartment of higher potential contamination. This flow distribution, combined with the system air flow balance, will establish a slight negative pressure within the compartments. No provision other than this has been made to maintain or monitor this negative pressure. 9.4.2.3.7 Monitoring The air flow from the auxiliary building is monitored for abnormal radiation levels of both particulate and gaseous nature at the plant vent monitor. In addition, effluent from the RHR equipment compartments is monitored for abnormal radiation levels. The sample for this monitor may be taken from either RHR compartment exhaust ducts so that an evaluation of any detected leakage may be made. The radiological monitoring system is described in Section 11.4.
The ambient air temperatures in areas containing safety-related electrical equipment will be monitored continuously where excessive temperatures could possibly occur. Additional information about the temperature monitoring system is provided in Section 3.11.
DCPP UNITS 1 & 2 FSAR UPDATE 9.4-17 Revision 21 September 2013 9.4.2.3.8 Treatment of Exhaust Air The exhaust air from the auxiliary building is normally ("building ventilation" mode of operation) routed through roughing and HEPA filter banks for the purpose of removing particulates that may be in the ventilation air. When the system is in the "building and engineered safety ventilation" or "engineered safety ventilation only" modes of operation without safety injection signal, air that is exhausted from the ESF pump motor areas is routed through roughing and HEPA filter banks. In the presence of a safety injection signal in conjunction with the system in one of the latter two modes, the exhaust air from the ESF pump motor area passes through the combined roughing, HEPA, and charcoal filters. The specifications for the exhaust filters are given in Table 9.4-5. 9.4.2.3.9 System Failure Analysis The ventilation system is designed to meet single failure criteria by having the primary nonstatic elements installed in redundancy. All dampers that must fail in the open position are redundant. Failure in the open condition maintains cooling air flow through the ESF pump motor compartments.
The radwaste area is primarily that area served by the system that is not included in the "engineered safety ventilation only" mode of operation. Two conditions will interrupt the air flow to the radwaste area. The first condition involves a double failure, the loss of either an exhaust or a supply fan and a coincident safety injection signal or the start of an ESF pump motor. The second condition is the loss of control air supply to the building exhaust duct dampers 4A and 4B (see Figure 9.4-3). Either case is an abnormal condition that is indicated to the control room operator who then takes action to minimize the leakage of radioactive material to the compartments and/or to the ventilation system. Experience at the Humboldt Bay reactor has shown that normal leakage or vents from the radwaste system are not a large contributor to airborne radioactivity.
The occurrence of complete failure of the auxiliary building ventilation flow would result in a slow rise in airborne activity in the building only if a significant amount of leakage existed from equipment carrying radioactive fluids prior to the failure of ventilation flow. If concentrations should rise to significant levels, personnel can be kept out of the area by administrative controls, or wear protective respiratory equipment during any required maintenance work. Specific limits on plant operation and requirements for shutdown under conditions of reduced or lost ventilation flow are contained in the Technical Specifications. The characteristics of the monitors and sampling procedures for auxiliary building areas are given in Section 11.4. There are no public safety implications of failure of the auxiliary building ventilation during normal plant operation, since reduced exhaust flow would only result in increased holdup and decay of airborne activity before release from the plant. With regard to simultaneous coincident major failures in both the ventilation system and a major radwaste component, an analysis of the most severe consequences of such events is contained in Chapter 15. DCPP UNITS 1 & 2 FSAR UPDATE 9.4-18 Revision 21 September 2013 Assessments of long-term exposures from small equipment leakages are included in Chapters 11 and 12. 9.4.2.3.10 Failure of Radwaste Tank Radioactive iodines and particulates, for the removal of which the auxiliary building ventilation system is potentially effective, are generally stored at low pressure in the auxiliary building. Failure of a low-pressure storage vessel would be extremely unlikely and would not generate a pressure pulse sufficient to damage the auxiliary building ventilation system. A larger pressure pulse would result from the rupture of a gas decay tank or the volume control tank, as discussed in Section 15.4.7. The failure probability for these tanks is very low. As an upper bound, the pressure resulting from the rupture of a gas decay tank pressurized to 100 psig has been assumed to equalize instantaneously within the four interconnected cells housing the four gas decay tanks. The resulting pressure would be 2.63 psig. A similar calculation for the volume control tank results in an equalized pressure of 1.5 psig for the tank compartment and the one adjacent to it.
These pressures are sufficient to cause local damage to the duct work and release of radioactive materials into other auxiliary building areas. As shown in Figure 9.4-2, such a pressure pulse can propagate and dissipate for a considerable distance down the main exhaust duct from the tanks before reaching normally occupied areas of the auxiliary building. While some momentary release of radioactivity to these areas could result from a pressure pulse, any damage to the ductwork is likely to be confined to either (a) the branch serving the gas decay tanks and waste gas compressors, or (b) the branch serving the volume control tank and the sample heat exchangers. After the initial pulse of pressure and release of radioactive materials, any airborne activity in areas served by the auxiliary building ventilating system will be drawn toward the high efficiency filters of the system. Any local damage to the duct should affect only the ventilation in the immediate area.
In case of the spread of radioactive materials to other auxiliary building areas, the operating restrictions, described under System Failure Analysis, above, can be instituted if necessary. As described in Section 15.4.7, no credit is taken for radioactivity removal by the auxiliary building ventilation system in calculating offsite doses resulting from postulated failure of a gas decay tank. 9.4.2.4 Inspection and Testing Requirements 9.4.2.4.1 Initial System Inspection and Tests An initial checkout of the motors, dampers, fans, controls, etc., is made at the time of installation. A system air balance test and adjustment to design conditions are conducted. The final tests performed prior to actual operation of the ventilation system DCPP UNITS 1 & 2 FSAR UPDATE 9.4-19 Revision 21 September 2013 will be the functional test of the HEPA and charcoal filter banks. These tests determine the overall effectiveness of the filter banks. 9.4.2.4.2 Routine System Tests The system will be operationally tested in accordance with the Technical Specifications. These tests will include checking the function of the dampers and controls under each mode of operation and determination of total air flow.
A functional test of the HEPA and/or charcoal filter banks will be performed whenever a filter element is replaced. A charcoal sample will be removed at least once every 18 months to determine the effectiveness of the charcoal bank. 9.4.3 TURBINE BUILDING The turbine building ventilation system basically provides for personnel comfort and is not a safety-related system.
Although the onsite technical support center (TSC) is adjacent to the turbine building, the TSC is provided with its own ventilation system. The TSC ventilation system is discussed in Section 9.4.11. Separate safety-related ventilation systems in the turbine building are provided for the diesel generator rooms, discussed in Section 9.4.7, and the 4.16 kV switchgear and cable spreading rooms, discussed in Section 9.4.8.
The following sections provide information on (a) design bases, (b) system description, (c) safety evaluation, and (d) inspection and testing requirements for the turbine building ventilation system. 9.4.3.1 Design Bases The turbine building ventilation system has been designed basically for the purpose of providing personnel comfort in the operation of the turbine-generator equipment. This system is generally not necessary for airborne radioactivity control because of the low potential for contamination in the steam cycle. Because the existence of some airborne activity in the turbine building atmosphere is possible as a result of water or steam leakage from the steam system, the following design objectives have been established:
(1) Maintain airborne radioactive material concentrations in normal work areas in the turbine building within the maximum permissible concentration (MPC) values given in Appendix B, Table I, of 10 CFR 20.1-20.601 (2) Operate in conjunction with other sources of gaseous releases to ensure that the dose from concentrations of airborne radioactive materials in unrestricted areas beyond the site boundary are within the limits specified in Appendix I to 10 CFR 50 DCPP UNITS 1 & 2 FSAR UPDATE 9.4-20 Revision 21 September 2013 (3) Provide the ability to maintain and/or reduce the airborne radioactive material concentrations in normally unoccupied areas within plant structure to levels that will allow periodic access as required for nonroutine work Because significant airborne activity is not expected on a continuous basis in the turbine building, continuous monitoring equipment is not provided. If significant activity levels are observed in the air ejector offgas, however, periodic sampling will be initiated to determine turbine building airborne activity. If sampling indicates the need for continuous sampling, it will be provided. A description of the sampling procedures is presented in Section 12.3 and monitoring procedures are described in Section 11.4.
Regarding the requirements for the treatment of exhaust air from the turbine building, a detailed analysis of potential doses to the public from various sources of gaseous release is provided in Chapter 11. As a result of this analysis, it can be concluded that, at the DCPP site, treatment of turbine building exhaust air is not required to meet the exposure limits listed in Appendix I to 10 CFR 50.
The requirements for system temperature design are described in Section 9.4.
The design classification of the turbine building ventilation system is given in the DCPP Q-List (see Reference 8 of Section 3.2). 9.4.3.2 System Description The 15 supply fans direct air into the turbine building through the east wall both above and below the elevation 140 feet operating deck. The four exhaust fans and their related duct systems, located on the west side of the building, ensure air flow across the building below the operating deck. The exhaust fans discharge the air vertically up above the operating deck. All the air that is supplied to the building is exhausted to atmosphere through a vent located on the top of the turbine building. Each fan can be operated independently through a manual motor starter with power from a nonvital bus. The locations of all fans, vents, and compartments are shown in the following: Figures 1.2-13, 1.2-14, 1.2-15, 1.2-16, 1.2-17, 1.2-24, 1.2-25, and 1.2-26. The major equipment for the system is listed in Table 9.4-7. 9.4.3.3 Safety Evaluation The turbine building ventilation system is not a safety-related system, and its complete failure has no safety implication. Because of the many fans in the system, failure of any fan or group of fans will not cause excessive temperatures in building compartments. Furthermore, if ventilation flow were not available, doors can be opened to provide natural flow. In the event that airborne activity exists in the building at a time when ventilation flow is not available, some increase in concentrations could occur. Because of the low level of this activity, however, it is not expected that concentrations above 10 CFR 20.1-20.601 MPC levels could exist with the building doors open. In any event, sampling or monitoring will be in effect under these conditions. DCPP UNITS 1 & 2 FSAR UPDATE 9.4-21 Revision 21 September 2013 Each of the 15 supply fans and 4 exhaust fans can be operated independently through manual motor starters. Should there be single or double fan failure, the net effect on the turbine building would be negligible. Should all nonvital power to fans be de-energized, all doors on the east and west walls (elevation 85 feet) could be opened, allowing the building to function on gravity ventilation. 9.4.3.4 Inspection and Testing Requirements Initial checks of the fan housings, bearings, motors, bolts, controls, etc., were made at the time of installation. A system air balance test and adjustment to design conditions was conducted. 9.4.4 FUEL HANDLING AREA OF THE AUXILIARY BUILDING The fuel handling area heating and ventilation system serves the fuel handling area, rooms containing the motor-driven and turbine-driven auxiliary feed pumps, and fire pump room.
The prime function of the fuel handling area heating and ventilation system is to sweep radiolytic gases from the surface of the spent fuel pool and to treat the exhaust air in order to remove radioactive iodine. The purpose of the treatment of the exhaust air is to reduce the offsite dose to acceptable levels in the event of a fuel handling accident. The sweeping effect of the ventilation air over the surface of the pool will also reduce personnel exposures in the event of a fuel handling accident. The following sections provide information on (a) design bases, (b) system description, (c) safety evaluation, and (d) inspection and testing requirements for the fuel handling area ventilation system. 9.4.4.1 Design Bases The requirements for the system design are as follows:
(1) Provide an air flow pattern sweeping the spent fuel pool surface (2) Meet the single failure criteria (3) Remove more air than is supplied so that all potential air leakages will be inward (4) Automatically function in the event of a fuel handling accident involving recently irradiated fuel (5) Provide pretreatment of supply air (a) Roughing filters DCPP UNITS 1 & 2 FSAR UPDATE 9.4-22 Revision 21 September 2013 (b) Heating provisions (6) Provide post-treatment of exhaust air (a) Particulate (b) Gaseous (7) Design, build, and install equipment according to design classifications given in the DCPP Q-List (see Reference 8 of Section 3.2) (8) Maintain room ambient design air temperature as described in Section 9.4 except the Unit 1 spent fuel pool pump room has a design room temperature of 109°F and the Unit 2 spent fuel pool pump room has a design room temperature of 112°F The evaluation of the fission product removal performance of the system is contained in Section 15.4, in connection with the description of the fuel handling accidents.
9.4.4.2 System Description The fuel handling area heating and ventilating system has the capability to provide ventilation air for the fuel handling area separately from the rest of the auxiliary building. The fuel handling area for each unit is physically isolated from the rest of the auxiliary building. The system as shown in Figure 9.4-3 consists of redundant supply and exhaust fans, and redundant HEPA and charcoal filter banks. A third set of full capacity exhaust fans and HEPA filter bank trains is provided for normal operation. Each HEPA filter bank is preceded by a roughing filter bank. The major equipment for the system is listed in Table 9.4-6. The supply airflow, was selected on the basis of the heat dissipated by the equipment. The exhaust air flow (35,750 cfm) consists of approximately 81 percent exhausted from the spent fuel pool area by drawing the air flow over the pool. The balance of the flow is ducted and exhausted by the exhaust fan from other areas in the fuel handling building.
The heating coil is used to temper the air that is supplied to the area. The supply air is ducted to corridors and equipment compartments on the floor levels below the operating level. The air flow pattern is from these compartments through the spent fuel shipping cask decontamination area up to the spent fuel pool. Exhaust grilles over and along one side of the spent fuel pool draw the air in a sweep across the pool surface. The exhaust air is then filtered and discharged to the plant vent. High temperature alarms are provided to the main annunciator for the fuel handling area supply fan room.
The system is provided with three modes of operation that affect the filtering of the exhaust air.
DCPP UNITS 1 & 2 FSAR UPDATE 9.4-23 Revision 21 September 2013 Mode 1: The first mode is for normal use. The mode may be selected manually from pool side or from the control room. Under this mode all of the exhaust air passes through roughing and HEPA filter banks only. The exhaust fan for this mode is powered from a nonvital bus. Mode 2: The second mode of operation is for the removal of potential radioactive particulates and/or radioactive gases in the exhaust air. This mode of operation is automatically initiated by an exhaust fan failure while in Mode 1, or it may be selected manually from the pool side or from the control room. This mode routes all the exhaust air through roughing, HEPA, and charcoal filters. The fans and filter banks for this mode of operation are redundant. The fans are powered from separate vital buses. Mode 3: The third mode of operation (emergency mode) is also for the removal of radioactive particulate and/or radioactive gases in the exhaust air. This mode is physically the same as Mode 2 except for automatic initiation by a radiation detector. The radiation detectors located near the fuel storage areas will automatically initiate this mode when radiation levels exceed the setpoint level in Table 11.4-1. The control logic devices for both Units 1 and 2 fuel handling area are solid-state units providing a full selection of logic functions, designed for binary system operation. The control system is based on a programmable logic controller (PLC). The basis for qualification of the Triconex PLC and associated software follows the guidance of Branch Technical Position (BTP) 7-14 and 7-18 (see References 21 and 22). The logic control system has output to solenoids and dry contact relays for the control functions. Both the logic controls and relays are redundant and have power sources from vital buses. 9.4.4.3 Safety Evaluation Compliance of the heating and ventilating system for the fuel handling area with Regulatory Guide 1.52 requirements is presented in Table 9.4-2. 9.4.4.3.1 Air Flow Pattern The ventilating air is discharged from duct work into the corridors and equipment compartments below the spent fuel pool floor. The air exhausts from the fuel handling area after passing over the pool surface. Two exhaust air headers remove the air from above and from one side of the pool to achieve a sweeping movement of gases above the pool surface.
The fuel handling area is separated from the rest of the auxiliary building by partitions and doors on all floors. The separating doors, partitions, and outside walls are of standard construction with no particular leaktight consideration. The exhaust fans DCPP UNITS 1 & 2 FSAR UPDATE 9.4-24 Revision 21 September 2013 remove more air than is supplied. This extra air is made up by infiltration from the outside and adjoining areas of the auxiliary building. 9.4.4.3.2 Single Failure Criteria The system has redundancy for all primary nonstatic components. The fans are each full capacity. The exhaust fan and corresponding filter bank used for normal ventilation (Mode 1) are not necessary for emergency operation and are not redundant. If the exhaust fan or its associated mode damper used in the normal ventilation Mode 1 were to fail, Mode 2 would be automatically initiated. If a supply fan or its associated mode damper should fail, or if the exhaust fan or exhaust mode damper used in Modes 2 or 3 should fail, the redundant fan and damper system for that mode would be automatically started. Off-delay timers, set for a nominal time delay of 2 seconds, keep supply fans running during a change of ventilation mode to prevent the loss of supply fan air flow and the subsequent shutting down of the supply fan. The power sources for the redundant fans are taken from vital buses with separation of redundant components. The dampers are positioned with pneumatic actuators with air supplied from the plant compressed air system. The dampers are designed to assume the position required for emergency conditions on the failure of the control air supply.
The initiating (logic) circuitry, including the relays and solenoids required to actuate the system, is redundant. Each control train serves similar control functions and switches circuits in the event of a failure to the other train. Separation has been maintained for the electrical circuits from each bus.
All ductwork has been designed to withstand any internal pressure that may be generated by any fan in the system, and braced according to Design Class I criteria to prevent earthquake damage to the ducts. All static ventilation components (i.e., volume dampers, air diffusers) have locking devices to prevent accidental closing. No duct liner or other insulating substance that might sag or fall down, thereby blocking the duct, has been installed in any ductwork. 9.4.4.3.3 Effects of Ventilation System Failure The administrative controls specified in the Technical Specifications preclude the handling of recently irradiated fuel in the event of ventilation system inoperability or failure. Although it is conceivable that a fuel handling accident might occur coincident with a failure in the building ventilation system, this combination of events is not regarded to be of sufficient likelihood to warrant system design changes. In any event, personnel will be leaving the fuel handling area immediately following any indication of a major fuel handling accident. Personnel exposure is not expected to be significant in any of these events because of the presence of the area monitor and continuous air monitor functioning during any operations involving irradiated fuel. These provisions are described more fully in Section 12.1-4 and the Technical Specifications.
DCPP UNITS 1 & 2 FSAR UPDATE 9.4-25 Revision 21 September 2013 9.4.4.3.4 Automatic Function The ventilation system has manual selection for Mode 1 and Mode 2 operations. It also has an automatic initiation of the emergency operation (Mode 3). The automatic initiation is from radiation monitors mounted near the fuel storage areas. Radiation levels greater than the setpoint level will change the operation of the system from Mode 1 to Mode 3 operation. For setpoint radiation level, see Table 11.4-1. 9.4.4.3.5 Treatment of Air The supply air for the fuel handling area passes through roughing filters to remove dust and lint that may be in the atmosphere. The supply filters have a minimum dust spot efficiency of 30 percent for atmospheric dust (NBS or AFI method). The supply air may be heated to provide a level of comfort in the fuel handing area.
The exhaust air for the fuel handling area is filtered through roughing filters and HEPA filters during normal operation. Modes 2 and 3 operations have, in addition, charcoal filters. The charcoal filter banks have been sized to take the full air flow of the ventilation system without exceeding the manufacturer's recommendations for flow through each individual module of the bank. Thirty-six modules with three filter trays per module are provided for each full capacity filter bank. The total amount of activated impregnated charcoal in each filter bank is a function of the charcoal-containing capacity and the density of the charcoal. The charcoal-containing capacity is 40 pounds nominal (46 pounds actual) per tray. The total number of trays per filter bank is 108. Therefore, the total amount of charcoal is 4320 pounds nominal (4968 pounds actual). This amount of charcoal is adequate to adsorb radioactive gases from any projected design fuel handling accident without overloading with iodine or overheating from decay heat. The exhaust air for the system is routed to the plant vent. All air flow through the plant vent is monitored for radioactivity. 9.4.4.4 Inspection and Testing Requirements 9.4.4.4.1 Initial System Inspection and Tests The system was installed under field inspection by PG&E General Construction and Quality Assurance personnel. An initial checkout of the motors, dampers, controls, etc., was made at that time. A system air balance test and adjustment to design conditions were conducted. The final tests performed prior to actual operation of the fuel handling area ventilation system were the functional tests of the HEPA and charcoal filter banks. These tests determined the overall efficiency of the filter banks. 9.4.4.4.2 Routine System Test Testing of the fuel handling area ventilation system will be in accordance with the requirements of the Technical Specifications.
DCPP UNITS 1 & 2 FSAR UPDATE 9.4-26 Revision 21 September 2013 9.4.5 CONTAINMENT The containment HVAC system is designed to maintain temperature and pressure within the containment at acceptable levels for equipment operation and personnel access at power for inspection, maintenance, and testing. Following a LOCA, the fan cooler units function to reduce the containment atmosphere temperature and pressure.
The containment HVAC systems include the following:
(1) Containment fan cooler system (CFCS) (2) Control rod drive mechanism (CRDM) exhaust system (3) Iodine removal system (4) Incore instrument room cooling system (Abandoned in place) (5) Containment purge system (6) Pressure relief line (7) Vacuum relief line (8) Hydrogen purge system, described in Section 6.2 (9) Postaccident sampling station ventilation system, described in Section 9.4.10 The CFCS is also designed to operate during accident conditions as a part of the containment heat removal system (CHRS) and is described in Section 6.2.2.
The following sections provide information on (a) design bases, (b) system description, (c) safety evaluation, and (d) inspection and testing requirements. 9.4.5.1 Design Bases The design bases for the sizing of the HVAC equipment are the normal operational heat sources in the containment of 8.5 x 106 Btu/hr, as given in Table 9.4-11, and the reactor coolant system (RCS) leakage rate of 50 pounds per day with 1 percent defective fuel cladding. The design bases for the containment HVAC system are as follows:
(1) Maintain the containment ambient temperature between 50 and 120°F during normal plant operation DCPP UNITS 1 & 2 FSAR UPDATE 9.4-27 Revision 21 September 2013 (2) Maintain temperatures of 150°F or below in the CRDM shroud area and 135°F or below inside the primary concrete shield during normal plant operation (3) Maintain a pressure between 1.0 psig and +1.2 psig in the containment during normal operation (4) Provide the proper atmosphere and adequate ventilation for personnel before and during periods of personnel access for refueling operations and maintenance when the plant is shut down (5) CFCS works in conjunction with the containment spray system to reduce the containment ambient temperature and pressure during accident conditions (see CHRS in Section 6.2.2) (6) Accept a single active failure and still provide adequate cooling to the components inside the containment (7) Codes and standards applicable to the containment HVAC systems are listed in Table 9.4-8 The containment HVAC system shares some of these design bases with the CCS, which is described in detail in Section 6.2.3.
The containment HVAC system is designed, built, and installed according to the design classification given in the DCPP Q-List (see Reference 8 of Section 3.2).
9.4.5.2 System Description The containment ventilation system (fan coolers) is initiated for normal operation by manual switches in the control room. Depending on the ambient temperature inside the containment, four out of five units are normally utilized. The design details and logic of the instrumentation are discussed in Chapter 7.
The iodine removal units and the CRDM fans are operated by manual switches in the 480 V switchgear room area. Indication is provided to the operator as to the operation of these fans.
The containment HVAC systems are shown schematically in Figures 9.4-3 and 9.4-3A. 9.4.5.2.1 Performance Objectives The performance objectives of the system design are as follows:
(1) Normal Operation DCPP UNITS 1 & 2 FSAR UPDATE 9.4-28 Revision 21 September 2013 (a) Flowrates (4 of 5 fan coolers operating) 440,000 cfm (b) Heat transfer (4 of 5 fan coolers operating) 12.56 x 106 Btu/hr (c) Temperature range 50 to 120°F max (d) Humidity no requirement (e) Radiation limits for entry to containment 6.3 x 10-9 µCi/cc (f) Flowrate iodine removal units (2 units operating) 24,000 cfm (g) Time to achieve equilibrium value I-131 - 1 percent defective cladding -
50 lb/day RCS leakage 15 hours (h) Flowrate CRDM ventilation (2 out of 3 fans operating) 73,500 cfm (i) Temperature in the cavity area above the CRDM shroud 127°F max (j) Heat removal for CRDM 2.26 x 106 Btu/hr (k) Containment purge flow inlet 50,000 cfm outlet 55,000 cfm (l) Pressure relief flow average 700 cfm instantaneous, max. 6000 cfm (m) Incore instrument room fan coil unit (Abandoned in place) (2) Emergency Operation (a) Flowrates, fan coolers (2 out of 5 units operating) 94,000 cfm (b) Pressure in containment 47 psig at saturated steam-air mixture
DCPP UNITS 1 & 2 FSAR UPDATE 9.4-29 Revision 21 September 2013 (c) Heat transfer - fan cooler units 81 x 106 Btu/hr (2 out of 5 operating) (each cooler)
(d) Iodine removal units shut down (e) CRDM ventilation shut down (f) Containment purge system shut down (g) Incore instrument room fan coil unit(Abandoned in place) 9.4.5.2.2 Containment Fan Cooler System The CFCS is located inside the containment but outside the missile shield and consists of five coolers, ductwork and supports as shown in Figure 9.4-4.
The fan coolers and their fan/motor coupling that limits reverse rotation (ARRD/coupling) are Design Class I. The section of duct between the containment purge exhaust isolation valve and its debris screen, including the flexible connection, is also classified as Design Class I. The remaining ductwork is Design Class II and the supports are Seismic Category I.
Normally up to four out of five fan coolers operate to recirculate and cool the air within the containment during normal plant operation by drawing the air through their inlet dampers, cooling coils, fans, and ductwork. The CFCS is designed to operate during accident conditions as a part of the containment heat removal system and is described in Section 6.2.2. 9.4.5.2.3 Control Rod Drive Mechanism Exhaust System The CRDM ventilation system consists of three exhaust fans mounted on the air plenum of the integrated head assembly. Two out of three fans operate at 73,500 cfm total, exhaust air from the area surrounding the CRDMs, and discharge to the containment atmosphere to remove heat from the CRDM area during normal plant operation. This system is not designed to operate during accident conditions. 9.4.5.2.4 Iodine Removal System The iodine removal system consists of two one-half capacity iodine removal units that have roughing, HEPA, and charcoal filter banks. These units are provided for pre-entry cleanup of the containment atmosphere. The iodine removal system is not designed to be operated during accident conditions.
DCPP UNITS 1 & 2 FSAR UPDATE 9.4-30 Revision 21 September 2013 9.4.5.2.5 Incore Instrument Room Cooling System The incore instrument room cooling system is abandoned in place and is no longer in use. 9.4.5.2.6 Containment Purge System Prior to entry of personnel into the containment shortly before or after shutdown from normal power operation, the airborne radioactive concentration in the containment atmosphere will be reduced as necessary by employing the iodine cleanup and containment purge systems. After the cleanup process, the containment purge system provides the supply air to and exhaust air from the containment for purge and ventilation.
The containment purge flow, also used for ventilation during extended outages, is routed to the plant vent for monitored exhaust. The purge exhaust fan takes suction from the containment ventilation distribution duct system via a branch duct off the annular ring connecting to the containment purge exhaust isolation valve. The containment atmosphere is monitored for radioactivity by the containment and plant vent air particulate and/or gas effluent monitors. The ranges of the containment monitors are as follows:
(1) Containment air particulate (RE-11): 5 x 10-11 to 5 x 10-6 µCi/cc (2) Containment noble gas (RE-12): 5 x 10-6 to 5 x 10-1 µCi/cc The plant vent is a large duct installed on the side of the containment structure discharging to the atmosphere at the 234 foot elevation. The discharges from the vent are monitored for radiation from both particulate and gaseous material by the plant vent air particulate and noble gas effluent monitors, RE-28 (or RE-28R) and RE-14 (or RE-14R), respectively. The ranges of these monitors are as follows: (1) Plant vent air particulate effluent (RE-28, RE-28R): 1 x 10-12 to 2.27 x 10-4 µCi/cc (2) Plant vent noble gas effluent (RE-14, RE-14R): 2.2 x 10-8 to 2.2 x 10-1 µCi/cc 9.4.5.2.7 Pressure Relief Line The containment pressure relief line connects to the suction side of the containment purge fan, E-3, which then discharges into the plant vent. The pressure relief flow is driven by the pressure differential between the containment and the outside atmosphere, and does not require operation of fan E-3.
DCPP UNITS 1 & 2 FSAR UPDATE 9.4-31 Revision 21 September 2013 9.4.5.2.8 Vacuum Relief Line The vacuum relief line uses suction air from the containment purge air supply fan plenum to release the vacuum inside the containment. The function is independent of the purge system operation and manually operated. 9.4.5.3 Safety Evaluation The fan coolers are designed to cool the containment air. The air flow for normal operation is 110,000 cfm per unit with a total system static pressure of 8 inches w.g. at 0.075-lb/ft3 air density. This system is a total recirculation system. The cooling coils are each sized to remove 3.14 x 106 Btu/hr from 120°F entering air when supplied with 90°F cooling water. The normal operational design requires that up to four out of the five fan coolers remain in operation, which allows for the estimated heat removal capacity given in Table 9.4-12. The total heat load for the nuclear steam supply system is given in Table 9.4-11.
The fan coolers will reduce the motor speed from nominal 1200 to 600 rpm, draw the high density steam through cooling coils, and provide 81 x 106 Btu/hr cooling capacity per cooler during accident conditions. The safety evaluation is described in Section 6.2.2.
Evaluation of the ventilation provisions for the primary shield, neutron detectors and cables, and CRDMs indicates that the present designs are adequate to ensure plant safety during normal plant operating conditions. Loss of air cooling during normal plant operation would be indicated by temperature instrumentation provided for this purpose. In general, the effects of elevated temperature on the above equipment take place gradually over a period of hours, so that sufficient time would be available to take appropriate corrective action, including an orderly plant shutdown, to avert any possible safety problem. With respect to accident conditions, none of this equipment is required to function during the postaccident recovery period. 9.4.5.3.1 Evaluation of Cooling Water Supply The normal cooling water requirements for all five fan coolers can be supplied by any two of the three component cooling water pumps and in conjunction with one of the two auxiliary saltwater (ASW) pumps.
Water flow through each fan cooler is balanced to the design flow by a manual valve on the discharge header from the cooling units.
Fouling of the waterside of the heat transfer area is minimized with the use of buffered condensate in the component cooling system. If a complete severance of a fan cooler water tube is postulated, double-ended flow must be assumed. This flow can be accommodated by the trough under the fan coolers and is piped to the containment DCPP UNITS 1 & 2 FSAR UPDATE 9.4-32 Revision 21 September 2013 sump. Instrumentation is provided in the drain line from each fan cooler unit to indicate abnormally large flow.
The fan coolers are supplied by individual lines from the CCW headers. Each unit inlet and discharge line is provided with a manual shutoff valve and drain valve. This permits isolation of each cooler for testing purposes.
The evaluation of cooling water supply following accident conditions is discussed in Section 6.2.2. 9.4.5.3.2 Iodine Cleanup System The iodine cleanup system is used to reduce the concentration of fission product particulate activities in the containment atmosphere prior to routine personnel access at power or in advance of a scheduled reactor shutdown. With sufficient reduction of these activities, particularly iodine and cesium, the personnel dose is due mainly to whole body and inhalation exposures from the unfilterable noble gases. Total capacity is based on the I-131 activity required to limit the airborne concentration of this isotope to approximately seven times occupational 10 CFR 20.1-20.601 MPC. (I-131 occupational 10 CFR 20.1-20.601, MPC 40 = 9 x 10-9 µCi/cc.) This is consistent with the total exposure limitation of 100 mR received during a 2-hour access period. On this basis, two 12,000 cfm capacity units are provided. This capacity is based on assumptions of 1 percent defective fuel cladding and a 50 pound/day leakage from the RCS. The I-131 activity is reduced to the design equilibrium value by operating the two units for 15 hours. 9.4.5.3.3 Vacuum Relief Line The vacuum relief line takes air from the containment purge system supply fan plenum so that the suction air can be filtered and heated before it goes into the containment. 9.4.5.3.4 Single Failure Criteria The containment HVAC system is designed to meet single failure criteria. The fan cooler units are powered from vital buses and have a standby unit. The iodine removal units are not necessary for cleanup during accident conditions, so they are neither redundant nor powered from vital buses. The CRDM exhaust fans are powered from a nonvital bus. The iodine cleanup system is not considered an ESF and is not designed to the requirements of Regulatory Guide 1.52. Because of their very sporadic use, they are unlikely to be operating at the time of a LOCA. If operating, they will be manually shut off.
DCPP UNITS 1 & 2 FSAR UPDATE 9.4-33 Revision 21 September 2013 9.4.5.4 Inspection and Testing Requirements 9.4.5.4.1 Initial System Inspection and Tests An initial checkout of the motors, dampers, and controls was made at the time of installation. A system air balance test and adjustment to design conditions were conducted. 9.4.5.4.2 Routine System Tests The containment HVAC system is tested in accordance with the requirements of the Technical Specifications. 9.4.6 INTAKE STRUCTURE (AUXILIARY SALTWATER PUMP COMPARTMENTS) The ASW pump ventilation system has the function of maintaining the temperature of the ASW pump motors within acceptable limits during their operation. The following sections provide information on (a) design bases, (b) safety evaluation, and (c) tests and inspections for the ASW pump ventilation system. 9.4.6.1 Design Bases The ASW pump ventilation system must be in operation when an ASW pump is operating. Redundant necessary components, along with separated vital power sources, give the system the capability of meeting single failure criteria. The requirements for the system temperature design are discussed in Section 9.4. Outside air is drawn into an ASW pump room through ducting, passes through the motor area, and is exhausted to the atmosphere through the exhaust fan and related duct system. Treatment of the air is not necessary since the potential for contamination is negligible.
The system is designed, built, and installed according to the design classification given in the DCPP Q-List (see Reference 8 of Section 3.2). 9.4.6.2 System Description As described in Section 9.2, each unit is provided with two 100 percent redundant ASW pumps, each of which is installed in a separate watertight compartment to ensure continued operation during combined tsunami and storm wave runup conditions. Proper ventilation of these compartments is ensured by providing each supply and exhaust safeguard compartment with a separate ventilation system. Each system consists of a coaxial supply and exhaust safeguard duct and an exhaust fan. The outside air is drawn into the compartment through the outer space of the coaxial ducts. The air passes through the ASW pump motor area and is exhausted to the atmosphere by the in-line exhaust fan through the inner space of the coaxial exhaust duct as shown DCPP UNITS 1 & 2 FSAR UPDATE 9.4-34 Revision 21 September 2013 in Figure 9.4-5. The intake and exhaust duct discharge points are located above the highest water level resulting from the combined effects of tsunami and storm wave runup.
Each exhaust fan starts automatically whenever its associated ASW pump is started. One pump and its associated ventilation system normally operate, with the second set providing system redundancy. 9.4.6.3 Safety Evaluation 9.4.6.3.1 Single Failure Criteria The redundant ASW pumps are each provided with a completely independent ventilation system. There are no common components. Each fan in the system receives power from the same vital bus as its respective ASW pump. Separation has been maintained for the electrical circuits from each vital bus. 9.4.6.3.2 Capability of Ensuring Proper Temperature Conditions The system has been designed to maintain the inside air temperature below 104°F with an outdoor ambient design temperature described in Section 9.4. The 1 hp vane axial fans have been sized to provide a minimum air flow of 4000 cfm. The air flow requirements have been based on the ASW pump motor cooling load and the heat transfer through the coaxial duct. No credit is taken for wind cooling the intake structure. The maximum solar load on the ventilating system, as determined from solar tables for heat gain calculations (Reference 8), is about 2 percent of the pump motor cooling load. Because of the lag resulting from the thick concrete roof, this load does not occur until late afternoon, well after the maximum outside ambient air temperature. High temperatures exceeding the equipment maximum temperature rating are monitored and alarmed in the control room. 9.4.6.4 Inspection and Testing Requirements Initial checks of the motors, controls, etc., were made at the time of installation. A verification of air flow and necessary adjustments to design conditions was made. 9.4.7 DIESEL GENERATOR COMPARTMENTS VENTILATION SYSTEM Ventilation of diesel generator compartments is accomplished through the use of the same engine-driven fans that provide cooling air to the diesel generator radiators. The diesel generator cooling air system is described in Section 9.5.5. The following sections provide information on (a) design bases, (b) system description, (c) safety evaluation, and (d) inspection and testing requirements for diesel generator compartment ventilation systems.
DCPP UNITS 1 & 2 FSAR UPDATE 9.4-35 Revision 21 September 2013 9.4.7.1 Design Bases 9.4.7.1.1 General Design Criterion 2, 1967 - Performance Standards The EDG compartment ventilation system is designed to withstand the effects of, or is protected against natural phenomena such as earthquakes, flooding, tornados, winds, and other local site effects. 9.4.7.1.2 General Design Criterion 3, 1971 - Fire Protection The EDG compartment ventilation system is designed and located to minimize, consistent with other safety requirements, the probability and effect of fires and explosions. 9.4.7.1.3 General Design Criterion 11, 1967 - Control Room The EDG compartment ventilation system is designed to support safe shutdown and to maintain safe shutdown from the control room or from an alternate location if control room access is lost due to fire or other causes. 9.4.7.1.4 General Design Criterion 12, 1967 - Instrumentation and Control Systems Instrumentation and controls are provided as required to monitor and maintain EDG compartment ventilation system variables within prescribed operating ranges. 9.4.7.1.5 General Design Criterion 21, 1967 - Single Failure Definition The EDG compartment ventilation system is designed to remain operable after sustaining a single failure. Multiple failures resulting from a single event are treated as a single failure. 9.4.7.1.6 Protection from High and Moderate Energy Systems and Internal Missiles The EDG compartment ventilation system is designed to be protected against dynamic effects and missiles that might result from plant equipment failure. 9.4.7.1.7 10 CFR Part 50 Appendix R (Sections III.G, III.J, and III.L) - Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979 Section III.G - Fire protection of Safe Shutdown Capability: Fire protection of the EDG compartment ventilation system is provided by a combination of physical separation, fire-rated barriers, and/or automatic suppression and detection. DCPP UNITS 1 & 2 FSAR UPDATE 9.4-36 Revision 21 September 2013 Section III.J - Emergency Lighting: Emergency lighting or Battery Operated Lights (BOLs) are provided in areas where operation of the EDG compartment ventilation system may be required to safely shutdown the Unit following a fire. Section III.L - Alternative and Dedicated Shutdown Capability: Safe shutdown capabilities are provided in the control room and at an alternate location via the hot shutdown panel or locally at the EDG, for equipment powered by the EDGs and required for the safe shutdown of the plant following a fire event. 9.4.7.2 System Description The ventilation system for each diesel generator compartment has the function of maintaining compartment air temperature within acceptable limits during operation of the diesel generator. The system satisfies the requirements for system temperature design as described in Section 9.4 and satisfies the following design bases:
(1) Design compartment temperature at diesel engine 120°F (2) Heat removal from generator 6,830 Btu/min (3) Heat loss from engine surfaces 12,000 Btu/min The above design bases are for continuous operation at rated diesel generator load.
No special provision for heating diesel generator compartments is required since diesel engine generator jacket water and lubricating oil are kept warm by thermostatically controlled heaters during periods when diesel generators are not operating. Because no significant potential for airborne radioactivity exists in the vicinity of the diesel generator compartments, no filtration or treatment of ventilating air is required.
The ventilation system for each diesel generator compartment is designed, built, and installed according to the design classification given in the DCPP Q-List (refer to Reference 8 of Section 3.2).
As described in Section 8.3.1.1.6.3.1, each diesel generator is located in a separate compartment in the turbine building. Diesel engine cooling is provided by a closed-loop jacket water system with a radiator and a direct engine-driven fan. Approximately 70 percent of the required radiator cooling air is outside ambient air drawn by the fan from outside the compartment. The remaining 30 percent (approximately 36,000 cfm) of outside ambient air is drawn through duct work, providing ventilation for the diesel generator compartment. The ventilation air flow passes through the compartment, cooling the generator and absorbing surface heat losses from the diesel engine. Other heat loads in the compartment are negligible. In passing through the compartment, the design temperature of the ventilation air is raised by approximately 30°F when the diesel generators are operating continuously at rated load. The ventilation air then passes through the radiator and is exhausted outside the compartment by the direct DCPP UNITS 1 & 2 FSAR UPDATE 9.4-37 Revision 21 September 2013 engine-driven fan. The ventilation system for the diesel generator compartments is shown in Figure 9.4-6.
No credit is taken for wind cooling of the turbine building containing the diesel generator compartments. The maximum solar load was determined by the method in Reference 8 for the exposed outside west wall of the radiator compartment. It was found to add less than 0.1°F to the temperature of the air drawn through the radiator compartment with the ventilation system in operation. Although the air flow through the diesel generator compartment is less, the effect of the maximum solar load on that compartment will also be negligible since it has no outside walls.
The design value for outdoor ambient air temperature for the HVAC systems is described in Section 9.4.
The design condition for the diesel generator compartment ventilation is for the long-term recirculation period when the diesel generators are required for continuous emergency power following a LOCA. It is considered highly unlikely that a LOCA and a loss of offsite power would occur simultaneously with an ambient outside air temperature in excess of the design value of 78°F. It is considered incredible that the two events would occur simultaneously with an ambient outside air temperature of 91°F or greater.
However, if the outside air temperature is postulated at a peak above the maximum design value of 91°F when the diesel generator units are required for emergency power immediately following a LOCA, the thermal capacity and overload capability of the diesel generator units ensure satisfactory performance during the short period until the outside air temperature drops. The temperatures at only a few locations in the diesel generator compartments would rise above 120°F under these conditions, but the units are capable of operating satisfactorily for at least 4 hours, which is longer than any peak is expected to last. The diesel engine itself is not a concern since engines of this type are operated continuously at similar temperatures in hot weather environments. For example, this particular type of engine is employed in locomotive and shipboard duty where continuous operation at temperatures over 120°F is common, e.g., the Great Pacific Southwest Desert and the eastern Atlantic Ocean off the coast of Africa. 9.4.7.3 Safety Evaluation 9.4.7.3.1 General Design Criterion 2, 1967 - Performance Standards The EDGs are located in the turbine building, which is a PG&E Design Class II structure (refer to Figure 1.2-16 and 1.2-20). This building or applicable portions have been designed not to impact PG&E Design Class I components and associated safety functions (refer to Section 3.7.2.1.7.2). The turbine building is designed to withstand the effects of winds and tornados (refer to Section 3.3.1.2 and 3.3.2.3.2.8), floods and tsunamis (refer to Section 3.4), external missiles (refer to Section 3.5), and earthquakes (refer to Section 3.7.2.1.7.2) to protect the EDGs, ensuring their design function will be performed. DCPP UNITS 1 & 2 FSAR UPDATE 9.4-38 Revision 21 September 2013 The EDG units and their associated auxiliary systems, as shown for Unit 1 in Figures 9.5-8, 9.5-9, and 9.5-10, and similarly for Unit 2, are installed in separate compartments that are protected from fires, flooding, and external missiles. An engineering review of the turbine building has shown that during a seismic event, the building may deform, but will not collapse. This analysis is discussed in Section 3.7.2. The design classification for the walls around each engine generator compartment and for the walls isolating the engine generator compartments from other parts of the turbine building are given in the DCPP Q-List (refer to Reference 8 of Section 3.2). The EDG compartments are isolated from the turbine building with normally closed fire doors. In the event of a high-energy line break in the turbine building, it is not possible that steam could flow from the turbine building into the engine generator compartments. 9.4.7.3.2 General Design Criterion 3, 1971 - Fire Protection The EDG areas are designed to the fire protection guidelines of Branch Technical Position APCSB 9.5-1 (refer to Appendix 9.5B, Table B-1). 9.4.7.3.3 General Design Criterion 11, 1967 - Control Room The DCPP Equipment Control Guidelines identify rooms/areas monitored by the area temperature monitoring system, along with their corresponding temperature limits. The ambient air temperatures in these areas are monitored continuously. Air temperatures exceeding the established setpoints are recorded along with the times. An alarm for high temperature is also transmitted to the control room. The cause and effects of high temperature are investigated and corrected in accordance with the DCPP Equipment Control Guidelines. Refer to Section 8.3.1.1.6.3.4 for additional discussion related to compliance to GDC 11, 1967. 9.4.7.3.4 General Design Criterion 12, 1967 - Instrumentation and Control Systems The EDG compartment ventilation system instrumentation and controls are discussed in Sections 8.3.1.1.6.3.5 and 8.3.1.1.6.5. 9.4.7.3.5 General Design Criterion 21, 1967 - Single Failure Definition Ventilation of a diesel generator compartment is required only when the diesel generator is operating. This is assumed because ventilation for each compartment is provided by the same direct engine-driven fan that provides cooling air to the radiator. There are no active components in the ventilation system other than the diesel generator itself and the direct engine-driven fan. Refer to Section 8.3.1.1.6.3.8 for addition discussion regarding single failure. DCPP UNITS 1 & 2 FSAR UPDATE 9.4-39 Revision 21 September 2013 9.4.7.3.6 Protection from High and Moderate Energy Systems and Internal Missiles The EDG units and their associated auxiliary systems, as shown for Unit 1 in Figures 9.5-8, 9.5-9, and 9.5-10, and similarly for Unit 2, are installed in separate compartments that are protected from internal missiles. Because engine generator units are separated from each other by the concrete walls of the compartments, the units are protected from postulated internal missiles. Any missile created by an explosion within a compartment would remain in that compartment. The possibility of flooding in the turbine building and in the diesel generator compartments is discussed in Section 8.3.1.1.6.3.9. 9.4.7.3.7 10 CFR Part 50 Appendix R (Sections III.G, III.J, and III.L) - Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979 Fresh air intakes to areas containing safety-related equipment are located remote from exhaust air outlets to the extent practicable. The possibility of contaminating the intake air with products of combustion is extremely unlikely. The approximate distance between air supply intakes and the nearest exhaust air outlets for the EDG area is 40 feet. Refer to Section 8.3.1.1.6.3.12 for additional discussion on compliance to 10 CFR Part 50 Appendix R. 9.4.7.4 Tests and Inspections No separate tests or inspections of the ventilation system are required because tests and inspections associated with the diesel generators will also serve the ventilation system. Initial testing of EDGs has verified the adequacy of the ventilating system. 9.4.7.5 Instrumentation Application The criterion for monitoring air temperature in an EDG compartment is as follows: Where only one Class 1E redundant train or division is in a given room or area and the ventilation is Class 1E, but is not redundant within the area, one temperature monitor will be used to monitor the area ambient temperature. The temperature monitor will meet Class 1E requirements for supply and separation or have two reliable and redundant non-Class 1E supplies. Refer to Section 8.3.1.1.6.5 for additional discussion on EDG compartment ventilation system instrumentation. DCPP UNITS 1 & 2 FSAR UPDATE 9.4-40 Revision 21 September 2013 9.4.8 4.16 kV SWITCHGEAR ROOM The following sections provide information on the 4.16 kV switchgear room ventilation system: (a) design bases, (b) system description, (c) safety evaluation, and (d) inspection and testing requirements for the 4.16 kV switchgear room ventilation system. 9.4.8.1 Design Bases The 4.16 kV switchgear room ventilation system is designed to be in operation at all times to provide adequate ventilation for the switchgear and cabling. The design basis of the system is to minimize temperature excursions above the temperature assumed in the environmental qualification aging analysis (see Section 3.11). This will also provide for the safety and comfort of operating personnel during normal conditions. Other atmospheric conditions, including humidity, atmospheric chemicals, smoke, radiation, and other contaminants are not considered to have significant effect on the switchgear and are not controlled. However, these abnormal conditions may limit operator access to these areas.
The requirements for the system temperature design are as described in Section 9.4.
The system is designed, built, and installed according to the design classification given in the DCPP Q-List (see Reference 8 of Section 3.2). Applicable codes and standards are listed in Table 9.4-8. Each train is provided with an independent ventilation train. There are no common components. Each ventilation train receives power from the same electrical train as the switchgear that it serves. This provides separate Class 1E electrical supplies to power redundant equipment. 9.4.8.2 System Description The areas served are the switchgear and cable spreading rooms for the three trains of 4.16 kV switchgear. Each ventilation train consists of a supply fan, supply duct, and a vent stack to the turbine building operating floor, as shown in Figure 9.4-7. The ventilation flow consists of 100 percent outside air. The heat load of the switchgear is such that no tempering of the outside air supply is required. Wind cooling and solar effects are negligible.
Outside air enters the ventilation equipment room through louvers on the north/south wall of the turbine building. Each fan draws air through a roughing filter integral with the fan and supplies the air through the supply duct to the associated cable spreading and switchgear rooms. The rooms exhaust to the turbine building operating floor without the use of exhaust fans.
Each fan is turned on and off by a one-stage thermostat located in the associated switchgear room. A switch is provided on each local motor starter panel for manual starting and stopping of the fans and for selecting automatic operation of the fans. DCPP UNITS 1 & 2 FSAR UPDATE 9.4-41 Revision 21 September 2013 9.4.8.3 Safety Evaluation Each ventilation train provides adequate air flow to maintain the temperature of its associated switchgear and cable spreading rooms within acceptable limits. The trains operate completely independently and are powered independently, receiving power from the same electrical train as the switchgear that they each serve. Adequate physical separation between the trains has been provided. The system design is such that no unacceptable component failures can occur and adequate physical protection is provided against physical hazards in the areas through which the system is routed. Functional and electrical independence and physical separation and protection ensure that no single failure of any active component can affect more than one ventilation train. 9.4.8.4 Inspection and Testing Requirements Initial checks of the motors, controls, system balance, etc. were made at the time of installation. This included a verification of the adequacy of the calculated flowrates. The system will be periodically inspected to ensure that all equipment is functioning properly. 9.4.9 125-VDC AND 480-VAC SWITCHGEAR AREA The 125 Vdc and 480 Vac switchgear area ventilation system serves the following electrical areas:
(1) 125 Vdc switchgear and battery chargers (2) 480 Vac switchgear (3) Hot shutdown remote control panel (4) Process Control System (PCS) and Plant Protection System (PPS) rack area in the cable spreading room. To provide partial backup cooling whenever the Class II cable spreading room air conditioning system is inoperable The following sections provide information on (a) design bases, (b) system description, (c) safety evaluation, and (d) inspection and testing requirements for the 125 Vdc and 480 Vac switchgear area ventilation system.
9.4.9.1 Design Bases The 125 Vdc and 480 Vac switchgear ventilation system will provide adequate ventilation for the switchgear. This will also provide for the safety and comfort of operating personnel during normal conditions. Other atmospheric conditions, including humidity, atmospheric chemicals, smoke, radiation, and other contaminants are not DCPP UNITS 1 & 2 FSAR UPDATE 9.4-42 Revision 21 September 2013 considered to have significant effects on the switchgear and are not controlled. These abnormal conditions may limit operator access to these areas, however.
The requirements for the system temperature design are described in Section 9.4. In addition, the system design indoor temperature is 104°F for the 125 Vdc switchgear and battery chargers, the 480-V switchgear, and the hot shutdown remote control panel. Indoor design temperature for the PCS and PPS rack area in the cable spreading room is 72 +/-5°F during normal operation of Class II air conditioning system and 108°F when the backup Class I 480-V switchgear area ventilation system serves that area.
Redundancy is provided for all active components. Separate Class 1E electrical power supplies are used to power redundant equipment.
The system is designed, built, and installed according to the design classification given in the DCPP Q-List (see Reference 8 of Section 3.2). Applicable codes and standards are listed in Table 9.4-8. 9.4.9.2 System Description The areas served by the system are the compartments housing the three redundant trains of 480 V switchgear and dc switchgear and the four redundant trains of inverters, battery chargers, and hot shutdown remote control panel areas. The system consists of two sets of redundant 100 percent capacity supply and exhaust fans, a common supply and exhaust duct, dampers, air outlets and inlets, and fire dampers as shown in Figure 9.4-8. The system also provides partial backup ventilation for the cable spreading room, which is normally served by non-Class I ventilation air conditioning systems as shown in Figure 9.4-8. The backup service in the cable spreading room requires manual alignment of dampers in the interconnecting ductwork.
The ventilation system is a once-through type with 100 percent outside air supply. The heat load of all electrical equipment inside the areas served by the system requires no tempering of the air supply. Wind cooling and solar effects are negligible. In Unit 1 outside air is drawn by one of the two redundant supply fans, discharging through a common supply ductwork and roughing filter and introduced to each area by supply registers. The Unit 2 configuration is the same except that the filter is located at the inlet side of the fans.
Exhaust air from each area is drawn by one of the two redundant exhaust fans and discharged to the atmosphere.
The system intake louver is located in the intake plenum and the exhaust air is discharged away from the supply air intake. The supply duct is routed from the supply fans at the roof of the auxiliary building, penetrating the turbine building siding, then down along the wall outside the auxiliary building where it then enters the auxiliary building in the dc switchgear area. The exhaust duct is routed alongside the supply duct up to their respective penetrations in the wall of the auxiliary building and the DCPP UNITS 1 & 2 FSAR UPDATE 9.4-43 Revision 21 September 2013 turbine building siding. Both redundant supply and exhaust fans are located on the roof of the auxiliary building.
A switch in a local control station is used to select either automatic operation or to start each fan manually. Automatic operation is for "operational convenience" and is not a design function credited in any safety analysis. When the switch is in the automatic mode, the exhaust fan starts after its corresponding supply fan is started. The redundant set of supply and exhaust fans automatically starts if the normally operating set fails.
Normally, the cable spreading room is cooled by a Design Class II air conditioning system (CSR/AC). The system is designed to provide a relatively constant temperature and humidity within the room to enhance the service life of electronic devices installed in the room.
The system consists of an air conditioning unit with chilled water coil that recirculates air from the cable spreading room. One of two, redundant, 100 percent capacity, Design Class II air-cooled water chillers servicing Units 1 and 2 provides chilled water to the air conditioning units (ACU), one ACU per cable spreading room., and to a condensing coil (one per unit) The CSR/AC system is interconnected with the 125 Vdc and 480Vac switchgear area ventilation (Class I) system to provide partial back up cooling whenever the CSR/AC system is inoperable.
The cable spreading room temperature is controlled, when the CSR/AC system is in operation, by modulating the amount of chilled water flowing through the cooling coil in the ACU in response to a room thermostat. The cable spreading room humidity is stabilized by use of a condensing cooling coil in the supply air duct bringing outside air into the room.
The chillers, circulating chilled water pumps, and ACUs are manually started through local control stations. 9.4.9.3 Safety Evaluation The ventilation system with either one set of supply and exhaust fans operating was designed to provide adequate air flow in all the areas served by the system to maintain ambient temperature below 104°F with outside ambient temperature as described in Section 9.4, except for the cable spreading room which is also served by a non-Class I system. The redundant train of supply and exhaust fans are physically separated and powered from separate Class 1E electrical power supplies to ensure that any single failure of an active component will not prevent the ventilation system from supplying the required air flow. The system design is such that no unacceptable passive component failures can occur and such that physical protection is adequately provided against physical hazards in the areas through which the system is routed.
DCPP UNITS 1 & 2 FSAR UPDATE 9.4-44 Revision 21 September 2013 The interconnection between the Class II cable spreading room air conditioning system and the 125 Vdc and 480 Vac switchgear area ventilation system (Class I) is made through normally closed manually operated dampers which are part of the Class I system. To avoid transfer of seismic loads between the systems, the intertie is made via a flexible connection.
Sufficient design provisions are provided (e.g., door curbs, hatch curbs) to limit any flooding to the Elevation 115 ft area due to a chilled water line break of the CSR ACU. Cable penetrations are sealed to prevent carryover of water to other areas. The chilled water system does not have automatic makeup. Therefore, the total water volume of the chilled water system, less than 390 gallons, would cause the water to rise to a level of no more than 0.8 inches within the curbed area. The minimum height of the curbs is 2 inches. 9.4.9.4 Inspection and Testing Requirements Initial checks of the motors, controls, system balance, etc., were made at the time of installation. This included a verification of the adequacy of the calculated flow rates. The system will be periodically inspected to ensure that all normally operating equipment is functioning properly. Redundant components will be periodically tested to ensure system availability. 9.4.10 POST-ACCIDENT SAMPLE ROOM The post-accident sample room complex is located in the auxiliary building; however, it is provided with its own HVAC system. The following sections provide information on: (a) design bases, (b) system description, (c) safety evaluation, and (d) inspection and testing requirements for this system. 9.4.10.1 Design Bases The post-accident sample room HVAC system is designed to provide ventilation, heating, and cooling to the sample room for plant personnel comfort during normal plant operation.
Following an accident, the system provides protection for plant personnel from radiological contaminants.
The design classification of the post-accident sample room HVAC system is given in the DCPP Q-List (see Reference 8 of Section 3.2). The design class requirements for the system, except the air conditioner, are supplemented with more stringent seismic criteria; the system has been evaluated for a postulated Hosgri event. The calculated stresses are within the allowables for Design Class I systems.
The air conditioner is so supported that it will remain in place after a Hosgri event.
DCPP UNITS 1 & 2 FSAR UPDATE 9.4-45 Revision 21 September 2013 9.4.10.2 System Description The post-accident sample room HVAC system is an independent system as shown in Figure 9.4-10. During normal plant operation, a ventilation fan will deliver 300 cfm of outside air to the sample room complex.
Following a LOCA, one of two 100 percent capacity redundant pressurization fans will deliver 1000 cfm of carbon-filtered outside air to the complex and maintain it at a positive pressure with respect to surrounding plant areas. The fans are manually initiated.
The sample panel and the sample station hood located in the complex are maintained at a negative pressure when an exhaust fan is in operation. The exhaust air from the panels and hoods is manifolded together, charcoal filtered, and discharged by the exhaust fan to the atmosphere. One of the two 100 percent capacity, redundant, manually initiated, ventilation exhaust fans will discharge 700 cfm exhaust air to atmosphere.
The air conditioning portion of the HVAC system will maintain the sampling room at a temperature ranging between 65 and 90°F during normal plant operation. 9.4.10.3 Safety Evaluation The post-accident sample room HVAC system is not a safety-related system. However, the redundant supply and exhaust fans and filters, the seismic design of the system, and the shielding provided for in the sample room complex will provide the required personnel protection and equipment ventilation following an accident. 9.4.10.4 Inspection and Testing Requirements The initial checks of the motors, controls, system balance, etc. were made at the time of installation. The verification of the calculated flowrates was also accomplished at this time.
The system is periodically inspected and tested to ensure that all equipment is functioning properly. 9.4.11 TECHNICAL SUPPORT CENTER The basic function of the TSC HVAC system is to provide protection for personnel working in the center from radiological contaminants and to provide heating, ventilation, and air conditioning for working areas and equipment. DCPP UNITS 1 & 2 FSAR UPDATE 9.4-46 Revision 21 September 2013 9.4.11.1 Design Bases 9.4.11.1.1 General Design Criterion 4, 1967 - Sharing of Systems The TSC HVAC system or components are not shared by the DCPP Units unless safety is shown not to be impaired by the sharing. 9.4.11.1.2 10 CFR 50.47 - Emergency Plans The TSC HVAC system is adequate to support the use of the TSC for emergency response. 9.4.11.1.3 NUREG-0737 (Items II.B.2 and III.A.1.2), November 1980 - Clarification of TMI Action Plan Requirements II.B.2 - Design Review of Plant Shielding and Environmental Qualification of Equipment for Spaces/Systems Which May be Used in Post Accident Operations: Adequate access to the TSC is provided by design changes, increased permanent or temporary shielding, or post-accident procedural controls. III.A.1.2 - Upgrade Emergency Support Facilities: NUREG-0737, Supplement 1 (January 1983) provides the requirements for III.A.1.2 as follows: Section 8.2.1.e - The TSC is environmentally controlled to provide room air temperature, humidity, and cleanliness appropriate for personnel and equipment. Section 8.2.1.f - The TSC is provided with radiological protection and monitoring equipment necessary to assure that radiation exposure to any person working in the TSC would not exceed 5 rem whole body, or its equivalent to any part of the body, for the duration of the accident. 9.4.11.2 System Description The TSC is provided with its own PG&E Design Class II HVAC system that is schematically shown in Figure 9.4-10. The entire system is manually initiated and is designed to maintain the occupied areas of the TSC at a temperature below 85ºF. During normal operation, all the makeup air and recirculated air passes through a roughing filter and the air conditioning unit. Makeup air in the normal operation mode is supplied via the outside air intake by a single makeup air fan. The TSC HVAC system has the capability to manually isolate the area from outside air and to recirculate air via the air conditioning system. In the radiological accident mode of operation, the TSC HVAC system makeup air is supplied by the control room pressurization system (CRPS) in order to maintain the TSC area at a minimum of +1/8 inch water gauge pressure. Penetrations into the TSC are equipped with penetration seals and floor drain traps with make-up water supplies to DCPP UNITS 1 & 2 FSAR UPDATE 9.4-47 Revision 21 September 2013 prevent exfiltration of the positive pressure from within the TSC through these paths. The pressurization air, and a portion of the recirculated air, is passed through HEPA and charcoal filters for cleanup purposes and supplied to the general area rooms along with the majority of the recirculated air. Exhaust air leaves the TSC by exfiltration. The TSC HVAC System is fed from a non-Class 1E power source, although it has the capability to be supplied power from a Class 1E bus. The system is not seismically qualified but the ducting, duct supports, and equipment supports are designed and analyzed to seismic requirements. The ducting and components associated with the TSC pressurization air supply are PG&E Design Class I up to and including the manual damper upstream of the redundant duct heaters associated with the TSC filter bank. (refer to Reference 8 of Section 3.2). The duct heaters maintain the relative humidity of the pressurization air below 70 percent. 9.4.11.3 Safety Evaluation 9.4.11.3.1 General Design Criterion 4, 1967 - Sharing of Systems The TSC HVAC system is common to Unit 1 and Unit 2 and therefore requires sharing of SSCs between Units. The TSC HVAC system serves no safety functions. The TSC HVAC system is designed to provide adequate heating, ventilation, and air conditioning for working areas and equipment within the TSC. In addition, the CRPS is shared between the control room and the TSC. Sharing of the CRPS by the control room and the TSC is addressed in Section 9.4.1.3.2. 9.4.11.3.2 10 CFR 50.47 - Emergency Plans The TSC HVAC system meets applicable requirements and is maintained in support of emergency response (refer to Sections 9.4.11.1.3 and 9.4.11.3.3). 9.4.11.3.3 NUREG-0737 (Items II.B.2 and III.A.1.2), November 1980- Clarification of TMI Action Plan Requirements Item II.B.2 - Design Review of Plant Shielding and Environmental Qualification of Equipment for Spaces/Systems Which May be Used in Post Accident Operations Plant shielding has been evaluated with regard to radiation doses at equipment locations and requirements for vital area access/occupancy (including the TSC) for post-accident plant operations. Item III.A.1.2 - Upgrade Emergency Support Facilities: NUREG-0737, Supplement 1 (January 1983) DCPP UNITS 1 & 2 FSAR UPDATE 9.4-48 Revision 21 September 2013 Section 8.2.1.e - During normal operation, all the TSC HVAC makeup air and recirculated air passes through the climate control units (CCUs). The CCUs are designed to maintain the occupied areas of the TSC below 85°F, and provide for humidity and cleanliness appropriate for personnel and equipment. The TSC HVAC system is a PG&E Design Class II system. The pressurization air for the system is supplied by the designated PG&E Design Class I control room pressurization system . The radiological accident mode of operation maintains the TSC area at a positive pressure. The relative humidity of the pressurization air is maintained below 70 percent. The air cleanup portion of the system is equipped with redundant fans and heaters and a power supply that may be manually switched over to a Class 1E bus source. Post-accident dose in the TSC is discussed in Section 6.4.2. Section 8.2.1.f - TSC area radiation monitoring instruments provide continuous indication of the general area ambient radiation levels and provide local alarm annunciation in various areas and work spaces. TSC ventilation air monitoring instruments provide continuous sampling of the TSC HVAC return air ducts for detection of airborne radiation and provide for alarm annunciation in the TSC computation center. 9.4.11.4 Inspection and Testing Requirements Initial checks of the motors, controls, system balance, etc. were made at the time of installation. The system is periodically inspected to ensure that all equipment is functioning properly.
9.4.11.5 Instrumentation Requirements TSC area radiation monitoring instruments provide continuous indication of the general area ambient radiation levels and provide local alarm annunciation in various areas and work spaces. TSC ventilation air monitoring instruments provide continuous sampling of the TSC HVAC return air ducts for detection of airborne radioactivity and provide for alarm annunciation in the TSC computation center. Instrumentation related to post-accident operation includes indication and alarm on low pressurization flow and an alarm for high temperature in the charcoal filter section of the charcoal/HEPA filter bank. 9.4.12 CONTAINMENT PENETRATION AREA GE/GW The containment penetration area GE/GW ventilation system has the function of maintaining the ambient temperature and pressure of the GE/GW area within acceptable limits during normal operations. The following sections provide information DCPP UNITS 1 & 2 FSAR UPDATE 9.4-49 Revision 21 September 2013 on (a) design, (b) system description, (c) safety evaluation, and (d) tests and inspections for the GE/GW area ventilation systems. 9.4.12.1 Design Bases The GE/GW area ventilation system was designed to:
(1) Provide means of monitoring GE/GW exhaust for airborne radioactivity during normal plant operation (2) Maintain the ambient temperature at maximum average temperature of 104°F during normal plant operation (3) Maintain the GE/GW area at a slight negative pressure with respect to outdoors (4) Maintain steam relief flow path during High Energy Line Break Accident (HELBA)
The design classification of the containment penetration area GE/GW ventilation system is given in the DCPP Q-List (see Reference 8 of Section 3.2). Applicable codes and standards are listed in Table 9.4-8. 9.4.12.2 System Description The GE/GW area ventilation system is a non-safety related draw-through type ventilation system. Ductwork weld connection to plant vent meets seismic Category I requirements. All other components are design Class II.
One of the two full capacity exhaust fans runs to exhaust air from the GE/GW areas. This running fan maintains the GE/GW areas at a slight negative pressure relative to the outdoors.
The ventilation flow consists of 100 percent outside air drawn through the intake louvers located on the wall of GW area. Four (4) recirculation fans move the entering air to the areas farthest from the intake louver. The ventilation air flows to the enclosed annular gap on Elevation 140 ft, into the duct connected to the exhaust fan and discharged into the plant vent, where it is monitored. The system is shown in Figure 9.4-11.
Each exhaust fan is manually turned on and off by a switch on the local control panel mounted near the exhaust fans. Switchover to standby unit is done manually. The recirculation fans are initiated by thermostat located in the area where recirculation fan is located. The isolation dampers are operated by their associated pressure differential switches. The shut-off dampers are interlocked to their corresponding exhaust fans "on-off" switches. DCPP UNITS 1 & 2 FSAR UPDATE 9.4-50 Revision 21 September 2013 9.4.12.3 Safety Evaluation The containment penetration area GE/GW ventilation system is not a safety-related system, and its complete failure has no safety implication. Two redundant 100 percent capacity fans are provided, so that failure of one fan will not result in loss of ventilation for these areas during the normal plant operation.
The enclosure over the annular space between containment wall and auxiliary building roof at Elevation 140 ft is provided with blow-out type bellows to provide steam relief flow path during HELBA.
Duct weld connection to the plant vent meets seismic Category I requirements to maintain structural integrity of the plant vent. 9.4.12.4 Inspection and Testing Requirements Initial checks of the fan housings, bearings, motors, bolts, controls, etc., are made at the time of installation. A system air balance test and adjustment to design conditions are conducted.
The system will be periodically inspected to ensure that all equipment is functioning properly. 9.4.13 REFERENCES 1. Deleted in Revision 8. 2. Deleted in Revision 8.
- 3. Deleted in Revision 10.
- 4. Deleted in Revision 10.
- 5. Recommended Outdoor Design Temperatures, Southern California, Arizona, and Nevada, Third Edition, Southern California Chapter, American Society of Heating, Refrigeration and Air-Conditioning Engineers, Inc., March 1964.
- 6. Ibid, Fourth Edition, October 1972.
- 7. Deleted in Revision 10.
- 8. Trane Solar Tables for Heat Gain Calculations, The Trane Company, La Crosse, Wisconsin, April 1968.
- 9. R. R. Bellamy, Elemental Iodine and Methyl Iodine Adsorption on Activated Charcoal at Low Concentrations, 13th Air Cleaning Conference, 1974.
DCPP UNITS 1 & 2 FSAR UPDATE 9.4-51 Revision 21 September 2013 10. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
- 11. Regulatory Guide 1.52, Design, Testing, and Maintenance Criteria for Post Accident Engineered-Safety-Feature Atmosphere Cleanup System Air Filtration and Absorption Units of Light-Water-Cooled Nuclear Power Plants, USNRC, Rev. 0, June 1973.
- 12. G. W. Kielholts, Filters, Sorbents, and Air Cleaning Systems as Engineered Safeguards in Nuclear Installations, ORNL-NSIC-13, October 1966.
- 13. NUREG-0570, "Toxic Vapor Concentrations in the Control Room Following a Postulated Accidental Release," James Wing, USNRC-ONRR, June 1979.
- 14. Deleted in Revision 10.
- 15. Deleted in Revision 10.
- 16. Regulatory Guide 1.78, Assumptions for Evaluating the Habitability of a Nuclear Power Plant Control Room During a Postulated Hazardous Chemical Release, USNRC, Rev. O, June 1974.
- 17. Deleted in Revision 8.
- 18. Deleted in Revision 10.
- 19. Deleted in Revision 10.
- 20. Deleted in Revision 10.
- 21. Branch Technical Position 7-14, Guidance on Software Reviews for Digital Computer-Based Instrumentation and Control Systems, Revision 5, March 2007. 22. Branch Technical Position 7-18, Guidance on the Use of Programmable Logic Controllers in Digital Computer-Based Instrumentation and Control Systems, Revision 5, March 2007. 9.4.14 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures.
DCPP UNITS 1 & 2 FSAR UPDATE 9.5-1 Revision 21 September 2013 9.5 OTHER AUXILIARY SYSTEMS This section provides information on plant auxiliary systems that do not otherwise apply to the preceding sections of this chapter. 9.5.1 FIRE PROTECTION SYSTEM A Fire Protection Program for DCPP Units 1 and 2 has been established by PG&E. The program outlines the fire protection policy for the protection of structures, systems, and components important to safety as well as the procedures, equipment, and personnel required to implement the program.
This section summarizes the basic principles of the Fire Protection Program at DCPP Units 1 and 2 and contains the following information:
(1) A description of the design bases of the Fire Protection Program (Section 9.5.1.1) (2) A system description of the fire protection features (Section 9.5.1.2) (3) Evaluations of the fire protection systems and design features (Section 9.5.1.3) (4) Inspection and testing requirements and program administration (Section 9.5.1.4) (5) A description of the methods and assumptions used in evaluating the Fire Protection Program, and a detailed fire hazards analysis for all plant areas, including the safe shutdown analysis as required by 10 CFR 50, Appendix R, Section III.G (Appendix 9.5A) (6) A comparison of the Fire Protection Program with the guidelines of the NRC Branch Technical Position (BTP) APCSB 9.5-1 and with Appendix R to 10 CFR 50, Sections III.J, III.L, and III.0 (Appendices 9.5B, C, D, E) (7) Figures showing the various fire areas and zones (Appendix 9.5F), and tables defining the safe shutdown equipment required to satisfy the requirements of Appendix R to 10 CFR 50, Section III.G (Appendix 9.5G) (8) Administrative procedures governing the program are described in Appendix 9.5H DCPP UNITS 1 & 2 FSAR UPDATE 9.5-2 Revision 21 September 2013 9.5.1.1 Design Bases of the Fire Protection Program 9.5.1.1.1 Licensing Background In response to letters from the director of the division of project management, dated May 3, 1976, and September 30, 1976, the NRC transmitted to PG&E copies of revised Standard Review Plan 9.5.1, "Fire Protection," and Appendix A to BTP APCSB 9.5-1, "Guidelines for Fire Protection for Nuclear Power Plants Docketed Prior to July 1, 1976."
In addition to transmitting the above documents, the NRC requested that PG&E evaluate the fire protection provisions at DCPP Units 1 and 2. The fire hazards analysis was developed in response to this request.
On July 27, 1977, PG&E submitted Amendment 51 to its application for an operating license for Units 1 and 2. The amendment was titled "Fire Protection Review, Units 1 and 2 Diablo Canyon Site." The NRC Staff reviewed the document and issued 58 NRC fire protection review questions. PG&E responded to the questions in four letters dated February 6, July 7, August 3, and November 13, 1978. The NRC Staff documented its review and acceptance of the DCPP Fire Protection Program in Supplemental Safety Evaluation Reports (SSERs) 8, 9, and 13.
On October 1, 1981, PG&E submitted a letter documenting the Fire Protection Plan's compliance with Sections III.G, III.J, III.L, and III.0 of Appendix R to 10 CFR 50. This submittal was required by Section 2.C(6).b of Facility Operating License DPR-76. In reviewing the requirements of the noted sections of Appendix R, PG&E recognized that the approved Fire Protection Plan had deviated from Appendix R. Since these deviations had previously been accepted by the NRC in its review of Diablo Canyon to BTP APCSB 9.5-1 Appendix A, PG&E concluded that the deviations were approved exemptions from Appendix R. Subsequently, the NRC requested that the deviations from Appendix R and their justifications be re-documented.
Accordingly, on July 15, 1983, PG&E submitted its Report on 10 CFR 50 Appendix R Review for Unit 1 for NRC review and approval. PG&E responded to questions from the NRC review and further clarified the July 15 report in letters dated September 23 and 27, 1983; October 3, 6, 11, 14, and 21, 1983; November 4, 1983; April 17, 1984; and May 16, 1984. In June 1984 the NRC issued SSER 23 to document the approval of those areas for which PG&E requested exemptions. The NRC Staff stipulated that several modifications be completed prior to exceeding 5 percent of power. The NRC's SSER 27 for DCPP, dated July 1984, documents the approval of the requested modifications and the removal of the condition on the license.
The Unit 2 Report on 10 CFR 50 Appendix R Review was issued for NRC review and approval on December 6, 1984. PG&E responded to questions from the NRC review and further clarified the December 6 report in letters dated January 29, February 4, and April 22, 1985. In April 1985, the NRC issued SSER 31 to document the approval of those areas for which PG&E had requested exemptions.
DCPP UNITS 1 & 2 FSAR UPDATE 9.5-3 Revision 21 September 2013 9.5.1.1.2 Design Goals of the Fire Protection System The Fire Protection Program at DCPP has been established to provide reasonable assurance that a fire:
(1) Would not cause unacceptable risk to public health and safety (2) Would not prevent the performance of necessary safe shutdown functions (3) Would not significantly increase the risk of radioactive release to the environment (4) Would have a limited probability of occurrence (5) Would produce limited property loss BTP APCSB 9.5-1, Appendix A, and 10 CFR 50, Appendix R, Sections III.G, III.J, III.L, and III.0 provide specific guidelines used to review the Fire Protection Program at DCPP. Whenever applicable, these guidelines have been addressed (see Appendices 9.5B, C, D, and E). To provide broader guidelines for evaluating Diablo Canyon's program, additional criteria were selected to serve as the basis for overall evaluation. These criteria are outlined below.
9.5.1.1.3 General Design Criterion 3 (10CFR 50, Appendix A) - Fire Protection GDC 3 states: Structures, systems, and components important to safety shall be designed and located to minimize, consistent with other safety requirements, the probability and effect of fires and explosions. Noncombustible and heat-resistant materials shall be used wherever practical throughout the unit, particularly in locations such as the containment and control room. Fire detection and fighting systems of appropriate capacity and capability shall be provided and designed to minimize the adverse effects of fires on structures, systems and components important to safety. Fire fighting systems shall be designed to ensure that their rupture or inadvertent operation does not significantly impair the safety capability. 9.5.1.1.4 Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979 (10 CFR 50, Appendix R) Appendix R to 10 CFR 50 establishes fire protection features for nuclear power plants licensed prior to January 1, 1979. These features are required to satisfy GDC 3 to Appendix A of 10 CFR 50. PG&E is committed to meet the provisions of 10 CFR 50, Appendix R, Sections III.G, III.J, III.L, and III.O. DCPP has been reviewed and documented according to the requirements of 10 CFR 50, Appendix R, Sections III.G, III.J, III.L, and III.0. Deviations are described in SSERs 23 and 31. DCPP UNITS 1 & 2 FSAR UPDATE 9.5-4 Revision 21 September 2013 9.5.1.1.5 Defense in Depth For each fire hazard, a suitable combination of prevention, detection and suppression capability, and ability to withstand the effects of a fire shall be provided. Both equipment and procedural aspects of each shall be considered. 9.5.1.1.6 Fire Suppression Capacity and Capability Adequate fire suppression capability shall be provided. The fire suppression equipment will have enough capacity to extinguish any fire that could adversely affect equipment and components important to safety. For areas where fire hazards might affect redundant systems or components important to achieving safe shutdown, total reliance for fire protection shall not depend on any single fire suppression system. Fire-retardant coating for the redundant system and/or appropriate backup fire suppression capability shall be provided. 9.5.1.1.7 Single Failure Criterion No single active failure shall result in complete loss of protection of both primary and backup fire suppression capability. 9.5.1.1.8 General Design Criterion 19 (10 CFR 50, Appendix A) - Control Room GDC 19 states: A control room shall be provided from which actions can be taken to operate the nuclear power unit safely under normal conditions, and to maintain it in a safe condition under accident conditions, including loss-of-coolant accidents. Equipment at appropriate locations outside the control room shall be provided (a) with a design capability for prompt hot shutdown to maintain the unit in a safe condition during hot shutdown, and (b) with a potential capability for subsequent cold shutdown of the reactor through the use of suitable procedures. 9.5.1.1.9 Occurrence of Fire and Other Phenomena In accordance with 10 CFR 50, Appendix R, fire is not considered to occur simultaneously with other accidents or phenomena, such as a design-basis accident with the exception of a loss of offsite power for areas that credit alternate shutdown (Section III.G.3 of 10 CFR 50, Appendix R). Capability is provided consistent with GDC 19 and 10 CFR 50, Appendix R, Section III.G, to safely shut down the plant in the event of any single fire that can credibly occur.
Systems and components required to achieve and maintain a safe shutdown condition in spite of postulated fires must be identified. The general functional safe shutdown requirements are: DCPP UNITS 1 & 2 FSAR UPDATE 9.5-5 Revision 21 September 2013 (1) The fission product boundary integrity shall not be affected. (2) The reactivity control function shall be capable of achieving and maintaining cold shutdown reactivity conditions. (3) The reactor coolant makeup function shall be capable of maintaining and controlling primary system coolant inventory. (4) The reactor heat removal function shall be capable of achieving and maintaining decay heat removal. (5) The process monitoring function shall be capable of providing direct readings of the process variables necessary to perform and control the above functions. (6) The supporting function shall be capable of providing the process cooling, lubrication, etc, necessary to permit the operation of the equipment used for safe shutdown. (7) The equipment and systems used to achieve and maintain hot standby conditions and cold shutdown conditions shall be capable of being powered by onsite emergency power. The systems and equipment required to fulfill these functions are identified in Appendix 9.5G of this report. An explanation of the ability to safely shut down the plant during a postulated fire in any fire area or zone can be found in Appendix 9.5A of this report. 9.5.1.2 Fire Protection System Description 9.5.1.2.1 Water Supply Two sources provide firewater supply for the Fire Protection System.
(1) One source for the site is a 5.0 million gallon raw water storage reservoir. The reservoir is elevated above the plant and provides approximately 93 psi static pressure by gravity feed into the yard loop at plant grade.
The reservoir supplies the firewater system via an epoxy-lined asbestos cement pipeline, 12 inches in diameter. (2) Another water supply is provided by two 1500 gpm electric-motor-driven fire pumps, which are installed in parallel and draw suction from a 300,000-gallon firewater storage tank. Both pumps start automatically and sequentially upon low system pressure and are located within the power block. DCPP UNITS 1 & 2 FSAR UPDATE 9.5-6 Revision 21 September 2013 The system's static pressure is maintained by the reservoir. This water system is designed to supply the largest water suppression system identified in the Equipment Control Guidelines (see Chapter 16), plus 500 gpm for hose streams for 2 hours. 9.5.1.2.2 Firewater Distribution System The plant has two fire distribution systems, interconnected as follows:
(1) The power block underground loop, shown in Figure 9.5-1, is fed by the raw water reservoir with gravity feed pressure, and by the south site firewater distribution system, which is normally isolated from the underground yard loop by manual valves. When aligned with the south site firewater system, the power block loop is normally prevented from backfeeding the south site loop by check valves. (2) A seismically qualified firewater system, within the turbine building, auxiliary building, and containment structure, is designed to provide an uninterrupted water supply to hose stations servicing safety-related areas of the plant following a Hosgri earthquake. The seismically qualified firewater system is shown in Figure 9.5-2. The qualified system consists of: (a) The 300,000 gallon firewater storage tank (Tank 0-1) (b) Two 1500 gpm electric-motor-driven fire pumps (pumps 01 and 02), powered from separate vital buses (refer to Table 9.5-1 for pump design data) (c) Feed mains and piping required to provide firewater to hose reel stations in safety-related areas of the plant (d) Valves to isolate the seismically qualified system from the nonqualified system This system is supplemented by the yard loop and is isolated by check valves. These valves isolate the qualified system from the nonqualified system by preventing water loss through the nonqualified yard loop.
Nonqualified sprinkler piping in the turbine building can be isolated from the qualified system by closing two valves per unit. The sprinkler system piping protecting the reactor coolant pumps is seismically qualified but can be isolated by closing the air-operated containment firewater isolation valve, or by closing the manual isolation valves on the containment firewater line inside or outside of containment. All nonqualified sprinkler piping protecting the auxiliary building can be isolated from the qualified system by closing the sprinkler isolation valves. The auxiliary building sprinkler DCPP UNITS 1 & 2 FSAR UPDATE 9.5-7 Revision 21 September 2013 piping in safe shutdown areas has been seismically qualified to ensure that a piping failure would not endanger safe shutdown components.
Plant procedures require walkdowns following an earthquake because failure of nonqualified system piping following a seismic event must be postulated. Failed portions of the system can be isolated by sectionalizing valves. As previously discussed, the water supply from the two 1500 gpm fire pumps is normally isolated from the yard loop by check valves because of seismic considerations. These check valves isolate the yard loop and direct the system water flow to the turbine building, auxiliary building, and containment structure to provide a seismically qualified water supply to hose stations. Normally closed bypass valves around each check valve may be opened to supply the yard loop if additional water supply or pressure is required.
The 300,000 gallon seismically qualified firewater tank that provides suction for the two 1500 gpm pumps is located inside the makeup water storage tank as a separate container. A flow path is available from the makeup water storage tank, but a check valve prevents reverse flow.
The plant yard firewater distribution system can be sectionalized to isolate any section without disrupting service to other fire protection systems or to the remainder of the plant. 9.5.1.2.3 Firewater Hose Reel and Hydrant System Outdoor fire hose stations and hydrants are supplied from the underground yard loop. Fire hydrants are spaced a maximum of 250 feet apart. Hose stations and hydrants are spaced so that outside areas may be reached by at least two hose streams. The hose reel stations are equipped with a minimum of 100 feet of 1-1/2 inch rubber-lined fire hose, a combination nozzle, and a spanner wrench. The hose stations and fire hydrants are threaded compatible with the local fire department's equipment.
The supply piping for the plant interior firewater hose reel system is a seismically qualified system, which can be isolated by sectionalizing within the plant. Hose stations are provided within the plant areas and zones so that all areas and zones may be reached by a minimum of one hose stream. These hose stations are supplied by 4 inch and 2 inch diameter risers, which are located throughout the plant. Hose reels are provided with 1-1/2 inch diameter, woven-jacketed, rubber-lined fire hose in 50 foot, 75 foot, and 100 foot lengths with listed or approved adjustable nozzles.
Three portable, trailer-mounted, diesel-driven, 250 gpm pumps provide the capability to refill the firewater storage tank(s) and pressurize the firewater hose reel system from an alternative water source. Connections on the condenser hotwell (condensate) and the component cooling water heat exchanger shell (seawater) can be utilized to supply water to the firewater system. Cross-connection from these alternative water sources is provided by a 4 inch suction hose.
DCPP UNITS 1 & 2 FSAR UPDATE 9.5-8 Revision 21 September 2013 9.5.1.2.4 Water Spray Systems Automatic water spray deluge systems are provided in the power block for the following:
(1) Main transformers (2) Auxiliary transformers (3) Standby/startup transformers (4) Hydrogen seal oil units (5) Feedwater pump turbines (6) Lube oil piping at the turbine generator bearings Automatic actuation of these systems is provided by pilot lines. Manual actuation is provided locally at system valves, or remotely by the control room. Each deluge system is provided with a flow alarm that annunicates both locally and in the control room.
9.5.1.2.5 Wet Pipe Sprinkler Systems Automatic wet pipe sprinkler systems are provided for the following plant areas:
(1) Turbine building, elevation 85 feet (2) Turbine building, elevation 104 feet (3) Turbine building, elevation 119 feet (4) Turbine building cold machine shop (5) Technical support center
(6) Work planning center (7) Corridor outside diesel generator rooms
(8) 4.16 kV switchgear ventilation fan rooms (9) Auxiliary boilers (10) Solid radwaste storage area (11) Design Class II and III document storage rooms DCPP UNITS 1 & 2 FSAR UPDATE 9.5-9 Revision 21 September 2013 (12) Component cooling water heat exchange rooms (13) Component cooling water pump rooms (14) Charging pump rooms (15) Access Control and laboratory area
(16) Auxiliary feedwater pump room (17) Boric acid transfer pump area (18) Security diesel generator room (19) Reactor coolant pumps (20) Auxiliary building ventilation supply fan room (21) Control room ventilation equipment room (22) Penetration area outside containment, elevation 100 feet (23) Penetration area outside containment, elevation 115 feet (24) Fuel handling building corridor, elevation 100 feet (25) Miscellaneous areas: electric repair shop, operations ready room (26) Radioactive waste storage and laundry buildings (27) Calibration Lab The sprinkler systems are provided with zone flow alarms, which provide remote annunciation in the control room.
Sprinkler piping in safe shutdown areas has been seismically qualified to ensure that the leakage from damaged piping or the piping itself will not endanger equipment required for safe shutdown. Interfaces between qualified and nonqualified portions of the firewater system are capable of being isolated by sectionalizing valves. Pendent fire sprinklers in the plant are installed without return bends as required by NFPA 13 (1969 edition). This condition has been evaluated and will not adversely impact the ability to achieve and maintain safe shutdown in the event of a fire (Reference 8). DCPP UNITS 1 & 2 FSAR UPDATE 9.5-10 Revision 21 September 2013 9.5.1.2.6 Carbon Dioxide (CO2) Suppression system 9.5.1.2.6.1 Low Pressure CO2 A 7-1/2 ton capacity refrigerated tank stores the low-pressure carbon dioxide for the fire suppression systems. Design details are presented in Table 9.5-1. The sizing of this system is based on a dual function of generator purge (two complete purges assumed) and fire suppression (two complete flooding discharges to the single largest hazard plus a reserve to operate local hose reels).
Automatic low-pressure, total flooding CO2 systems, shown in Figure 9.5-3, are provided in the following areas:
(1) Diesel generator rooms (2) Turbine lube oil reservoir rooms (3) Turbine generator No. 10 bearing (local application) (4) Cable spreading rooms (5) Design Class I document storage rooms Manually initiated low-pressure CO2 hose reels of 100 foot lengths are provided for the following areas: (1) 12 kV switchgear rooms (2) 4.16 kV switchgear rooms (3) 4.16 kV cable spreading rooms (4) 25 kV potential transformer area (5) 480 V switchgear rooms (6) 125 Vdc battery and inverter rooms (7) Electric load center rooms Heat detectors installed for coverage of the hazard areas initiate automatic actuation for the total flooding CO2 systems. Upon detection, a predischarge alarm of approximately 45 seconds (30 seconds for the lube oil storage room) is begun. During the predischarge alarm, the master select valve (located at the 7-1/2 ton tank) is opened and the carbon dioxide fills the piping to the hazard select valve. Once the predischarge alarm has expired, the hazard select valve is opened, discharging the DCPP UNITS 1 & 2 FSAR UPDATE 9.5-11 Revision 21 September 2013 carbon dioxide into the hazard. The vents, dampers, and doors in the hazard area are also closed when the hazard select valve is opened. Remote annunciation of system discharge is sent to the control room via a pressure switch.
Manual actuation of the total flooding carbon dioxide systems is available both locally and from the control room. Local manual discharge can also be accomplished by mechanical means if power is lost. The diesel generator (DG) room carbon dioxide systems have a different operating sequence. The heat detection system for the DG rooms is designed to close the west roll-up doors in addition to operating as discussed above. Upon alarm of these detectors, the roll-up doors are closed and the CO2 is discharged into the hazard. A remote manual switch for each DG room is provided to parallel the heat detection system for remote activation of the CO2 and the closure of the west roll-up doors. The design sequence for CO2 actuation precludes a single spurious alarm from simultaneously disabling all DGs in one unit.
Mechanical disable switches are provided for each area that is protected by carbon dioxide. The disable switches are supplied for personnel safety during maintenance in the area. Their operation annunciates in the control room and locally by rotating amber beacons, within the hazard area.
The CO2 hose reels are designed to pressurize when the play pipe (nozzle) is removed from its mount. The hose reel system may also be pressurized by manual operation of the selector valve. Pressurization of this pipe system is annunciated in the control room.
The CO2 systems are not seismically qualified. However, the low-pressure CO2 in areas containing equipment required for safe shutdown has been reviewed to ensure that the piping will not endanger the equipment that is being protected. 9.5.1.2.6.2 High Pressure Carbon Dioxide A high-pressure automatic CO2 total flooding system is furnished in the circulating water pump motors for Units 1 and 2. The discharge includes an initial high flow rate to provide design concentration and a 20 minute extended discharge at reduced flow to maintain CO2 concentration during motor coastdown. High-pressure system discharge is initiated automatically by heat detection. The system may also be actuated manually by operating a high-pressure actuation cylinder or by manually operating the pilot outlet valve on the system supply cylinders.
A pressure switch trips on pressurization of hazard piping to indicate actual system release. Like the low-pressure systems, this system can be released by remote pushbutton from the control room. Unlike the low-pressure system with its mechanical disables, the high-pressure system is equipped with an electrical disable on the access door. The high-pressure system is also provided with a predischarge alarm to allow safe exit from the hazard area. DCPP UNITS 1 & 2 FSAR UPDATE 9.5-12 Revision 21 September 2013 9.5.1.2.7 Portable Fire Extinguishers Portable fire extinguishers are provided throughout the plant area and switchyards. Extinguishers are selected for the potential hazards in the area and located to limit travel distance required for the proper unit. The fire extinguishers are mounted in a manner to facilitate easy identification. Types of extinguishers provided are:
(1) Pressurized water (2) Carbon dioxide (3) Multipurpose dry chemical (4) Halon 1211 9.5.1.2.8 Smoke and Heat Control The plant ventilation supply and exhaust systems provide manual smoke and heat venting capability in the event of a fire. The ventilation systems either supply fresh outside air to rooms or exhaust air from rooms into a closed duct system (or both for some areas). Ventilation capability exists in all plant areas.
Plant ventilation systems are isolated by dampers upon activation of total flooding gaseous fire protection systems.
Plant ventilation systems or portable fans may be used after the fire by the fire brigade to clear the area of smoke. Consideration has been given to the loss of offsite power to ensure availability of those systems.
Fire dampers are provided with 1-1/2 or 3-hour UL-listed fusible link, electrical thermal link (ETL), or pneumatic release type. Situations where rated fire dampers have been provided include:
(1) Rooms that have total flooding CO2 protection
(2) Where heat or smoke transmission through a fire barrier might result in a fire propagating to an adjacent fire area The fractional horsepower electric fans can be readily plugged into the receptacles for the normal or emergency ac lighting.
These fans can be arranged to exhaust to the outside or nearby operating ventilation exhaust ducts. If the normal ventilation systems are used for heat and smoke removal, system design is such that heat and smoke would be discharged outside, and not to other compartments. Gas-powered fans are provided in the event that ac power is lost. Control room ventilation isolation capability is discussed in Section 9.4. DCPP UNITS 1 & 2 FSAR UPDATE 9.5-13 Revision 21 September 2013 9.5.1.2.9 Fire Doors Fire barriers separating safe shutdown equipment are provided with doors with rating commensurate with that of the barrier. Otherwise, an engineering evaluation is provided to justify the adequacy of the door assembly. This evaluation is performed to the guidelines of Generic Letter 86-10. 9.5.1.2.10 Breathing Apparatus Self-contained breathing apparatuses of the nominal 1/2-hour type are located within the plant area. Locations are based on accessibility prior to entering hazard areas. Additional breathing apparatuses are located in the vicinity of the control room. Spare cylinders and recharging facilities are provided for this equipment. 9.5.1.2.11 Communications Systems The communications systems include internal (inplant) and external communication designed to provide convenient and effective operational communication among various plant locations and between the plant and locations external to the plant. 9.5.1.2.11.1 Intra-Plant System A direct-dial company telephone is the primary communication facility within the plant. It has conference call features and consists of an emergency conference circuit that will handle a sufficient number of parties, including the control room operator. Fire alarms may be dialed from any telephone, and a feature is provided that sounds a horn to identify an emergency. Response to this alarm is covered by procedures. Where background noise is high, telephones designed especially for use in high noise level areas are provided.
A manually initiated emergency signal is operated from the control console. The emergency signal is utilized for site evacuation. A public address system is installed in the plant and is accessible through the phone system via access numbers. This system is available as a plant notification system.
A multichannel intercommunication system is the secondary communication facility within the plant. It operates between the control room master station, fuel handling building, and the containment building.
The in-plant radio system provides dedicated frequencies for operations and security. The system consists of base radios, portable radios, and control consoles and is a half duplex repeater system.
DCPP UNITS 1 & 2 FSAR UPDATE 9.5-14 Revision 21 September 2013 9.5.1.2.11.2 Plant-to-Offsite System The primary system of notification for offsite fire response agencies is by public telephone. Additionally, radio/intercom capability in the control room and technical support center provides a direct communications link to the county fire department emergency command center. 9.5.1.3 System Evaluation The adequacy of the plant fire protection systems and plant design features that ensure the capability to achieve safe shutdown is discussed in Section 9.5.1.2 and Appendix 9.5A. 9.5.1.4 Inspection and Testing Requirements and Program Administration The inspection and testing requirements for the fire equipment as well as the fire protection organization and administrative responsibilities are described in Inspection and Testing Requirements and Program Administration (Appendix 9.5H of this report). 9.5.2 COMMUNICATION SYSTEMS The communications systems include internal inplant and external communication designed to provide convenient and effective operational communications among various plant locations and between the plant and locations external to the plant. 9.5.2.1 Design Bases The communications systems are designed to ensure continuous intraplant and plant-to-offsite operation by the use of primary, secondary, and tertiary routings.
The design classification of the communication systems is given in the DCPP Q-List (see Reference 8 of Section 3.2). 9.5.2.2 Description 9.5.2.2.1 Intra-Plant System A direct dial company telephone system is the primary communication facility within the plant. It has conference call features consisting of emergency conference and regular conference circuits. The emergency conference circuit and regular conference circuits will handle a sufficient number of parties. Each of the four regular "Meet Me" conference circuits will handle a total of nine parties. There is a radio paging system for paging plant personnel within the plant and in surrounding communities. Fire alarms may be dialed from any telephone in the plant, and the caller verbally identifies the location of the fire to the control room operator. Response to this alarm is covered by DCPP UNITS 1 & 2 FSAR UPDATE 9.5-15 Revision 21 September 2013 procedures. Where background noise is high, telephones designed especially for use in high noise level areas are provided.
A multichannel intercommunication system is the secondary communication facility within the plant and operates between the control room master station, fuel handling building, and containment building areas.
A manually initiated emergency signal is the tertiary communication facility. It is operated from the control console.
A public address system (PAS) provides audio announcements over a majority of the plant complex. The PAS divides the plant into zones and is capable of selectively reaching single zones, groups of zones, or all zones simultaneously.
Response to any of the signals mentioned will be governed by procedures.
Control room operators have access to breathing masks with integral microphones/amplifiers for communication in hazardous environments. 9.5.2.2.2 Plant-to-offsite System Two communication links are utilized between DCPP and the PG&E Energy Control Center in San Francisco. Each communication link carries approximately one-half of the voice/data traffic.
The primary communication link between the plant and the PG&E Energy Control Center in San Francisco is the PG&E West Valley Microwave System. This system transmits administrative and control voice communication, system load dispatch teletype data links, and 500 kV protective relaying tone channels. The system is based on digital equipment and is provided with battery power for emergency operation. The system has dual transmitters/receivers in the event one does not operate. See Figure 9.5-5 for system routing.
The secondary communications link between the plant and the PG&E Energy Control Center in San Francisco is on common carrier facilities. This system transmits simultaneously with the West Valley system all information except 500 kV protective relaying. It is an all-fiber-optic network. See Figure 9.5-6 for system routing.
The tertiary communications link between the plant and the PG&E Telecommunication Control Center are the Public Switched Telephone Network lines that carry voice and the protective relaying circuit tones. 9.5.2.2.3 Communications Systems Evaluation All intraplant systems, except the public address system, and all plant-to-offsite communications utilize tertiary backup and multiple power sources, therefore preventing DCPP UNITS 1 & 2 FSAR UPDATE 9.5-16 Revision 21 September 2013 the failure of individual components from causing a discontinuity of communications. The public address system does not have multiple power sources for its many distributed amplifier centers. 9.5.2.3 Inspection and Testing Requirements Every critical component of the communications systems, such as the microwave radio system, the 48 V batteries, and the associated equipment, has major functions alarmed locally and at the PG&E Telecommunication Control Center (TCC). Routine maintenance procedures require testing and lineup of microwave radio multiplex and battery equipment to take place on a regularly scheduled basis. Tests were conducted to ensure that the plant radios do not affect the instrumentation systems for the Reactor Protection and Engineered Safety Features for Unit 1. Those plant areas that were determined to be affected were made radio exclusion zones. Since plant similarity exists for both units, plant modifications identified by these tests for Unit 1 were also implemented in Unit 2. All communications equipment serving the power plant will be continuously operating and this will provide operational quality checks. 9.5.3 LIGHTING SYSTEMS Normal lighting is operated at 208Y/120 V, three-phase on a four-wire solidly grounded system, supplied from the 480-V system through dry type, delta-wye connected three-phase transformers.
The dc emergency lighting is supplied at 125 V from the nonvital station batteries. The dc emergency lighting fixtures are located principally in electrical equipment rooms, stairways, exits and entrances, corridors, passageways, and at lower levels in all other areas.
The ac emergency lighting is supplied from two of the three vital 480-V buses through dry type, single-phase transformers, and is sized to provide a maximum load of 112 kW for Unit 1 and 100 kW for Unit 2. The ac emergency lighting fixtures are located throughout the plant to provide minimum lighting.
The ac emergency lighting circuits are routed in separate conduits from the normal ac lighting on the secondary transformer sides to panels and fixtures. On the primary side, the ac power from the vital 480-V buses is run in separate conduits or in respective vital routes. The 208Y/120-V circuits are routed in normal power conduits. The dc circuits are in separate conduits in vital operating areas of the plant.
After the diesels start and the single-phase ac emergency transformers receive power, the dc emergency lights are automatically turned off. The average period of operation of the dc lights is 18 seconds, (approximately 13 seconds for diesel generator loading and 5 seconds for time delay of contactor pick-up in the emergency dc lighting panel). DC lights in the fuel handling building at all elevations will be on for 10 minutes. Engineered safety feature (ESF) equipment areas and various access routes thereto DCPP UNITS 1 & 2 FSAR UPDATE 9.5-17 Revision 21 September 2013 are provided with battery-operated lights (BOLs) or UPS-powered lights capable of providing 8 hours of illumination if ac power to the BOLs is lost. The batteries are continuously charged with a built-in charger.
Lighting in the containment structure and radiation areas of the spent fuel area and part of Area K of the auxiliary building has incandescent light fixtures. In the fuel handling building on the 140-foot elevation in the spent fuel and machine shop areas, the light fixtures are HID pulse start metal halide lights.
BOLs for areas containing safety-related equipment or to enable operator action to meet Appendix R safe shutdown requirements are seismically qualified. For the same reason, the pipeway UPS is also seismically qualified.
Also see Appendix 9.5D, "Emergency Lighting Capability and Evaluation to Appendix R, Section III.J," for additional discussion. 9.5.4 DIESEL GENERATOR FUEL OIL STORAGE AND TRANSFER SYSTEM The diesel generator fuel oil system, shown in Figures 3.2-21, 9.5-8 and 9.5-9, maintains adequate storage of diesel fuel oil and supplies it to the six emergency diesel generators. The following subsections provide information on (a) design bases, (b) system description, and (c) safety evaluation for the system. 9.5.4.1 Design Bases 9.5.4.1.1 General Design Criterion 2, 1967 - Performance Standards The EDG fuel oil storage and transfer system is designed to withstand the effects of or is protected against natural phenomena, such as earthquakes, flooding, tornados, winds, and other local site effects. 9.5.4.1.2 General Design Criterion 3, 1971 - Fire Protection The EDG fuel oil storage and transfer system is designed and located to minimize, consistent with other safety requirements, the probability and effect of fires and explosions. 9.5.4.1.3 General Design Criterion 4, 1967 - Sharing of Systems The EDG fuel oil storage and transfer system or components are not shared by the DCPP Units unless safety is shown not to be impaired by the sharing. DCPP UNITS 1 & 2 FSAR UPDATE 9.5-18 Revision 21 September 2013 9.5.4.1.4 General Design Criterion 11, 1967 - Control Room The EDG fuel oil storage and transfer system is designed to support actions to maintain and control the safe operational status of the plant from the control room or from an alternate location if control room access is lost due to fire or other causes. 9.5.4.1.5 General Design Criterion 12, 1967 - Instrumentation and Control Systems Instrumentation and controls are provided as required to monitor and maintain EDG fuel oil storage and transfer system variables within prescribed operating ranges. 9.5.4.1.6 General Design Criterion 17, 1971 - Electric Power Systems The EDG fuel oil storage and transfer system is designed with sufficient capacity, capability, independence, redundancy, and testability to perform its safety function assuming a single failure. 9.5.4.1.7 General Design Criterion 21, 1967 - Single Failure Definition The EDG fuel oil storage and transfer system is designed to remain operable after sustaining a single failure. Multiple failures resulting from a single event shall be treated as a single failure. 9.5.4.1.8 Protection from High and Moderate Energy Systems and Internal Missiles The EDG fuel oil storage and transfer system is protected from the internal dynamic effects due to a postulated pipe failure or pipe crack and internally generated missiles. 9.5.4.1.9 10 CFR Part 50 Appendix R (Sections III.G, III.J, and III.L) - Fire Protection Program for Nuclear Power Facilities Operating Before January 1, 1979 Section III.G - Fire protection of Safe Shutdown Capability: Fire protection of the EDG fuel oil storage and transfer system is provided by a combination of physical separation, fire-rated barriers, and/or automatic suppression and detection. Section III.J - Emergency Lighting: Emergency lighting or Battery Operated Lights (BOLs) are provided in areas where operation of the EDG fuel oil storage and transfer system may be required to safely shutdown the Unit following a fire. Section III.L - Alternative and Dedicated Shutdown Capability: Safe shutdown capabilities are provided in the control room and at an alternate location via the hot shutdown panel or locally at the EDG, for the EDG fuel oil storage and transfer system, for the safe shutdown of the plant following a fire event. DCPP UNITS 1 & 2 FSAR UPDATE 9.5-19 Revision 21 September 2013 9.5.4.1.10 Regulatory Guide 1.137, Revision 1, October 1979 - Fuel-Oil Systems for Standby Diesel Generators For proper operation of the EDGs, it is necessary to ensure the proper quality of the fuel oil. It is also necessary to adhere to recommended fuel oil practices of checking and removing accumulated water from the day tank and main storage tank, respectively, as well as draining the fuel stored in the fuel storage tanks to remove accumulated sediments and to clean the tanks. 9.5.4.2 System Description The diesel generator fuel oil system diagram is shown in Figure 3.2-21. The physical arrangement of the engine generator units is shown in Figures 9.5-10 and 9.5-11 for Unit 1; the arrangement is similar for Unit 2. Figure 9.5-12 shows the outline of the Unit 1 engine generators; the arrangement is similar for the Unit 2 generators with the exception of EDG 2-3, which is slightly different. The design data is given in Table 9.5-2. The system consists of the following major components and features:
(1) Two underground diesel fuel oil storage tanks, each with a storage capacity of 50,000 gallons. (2) Two diesel fuel oil transfer pumps located below ground level, each adjacent to a storage tank but in separate compartments. Each transfer pump delivers more than 55 gpm at a discharge pressure of approximately 50 psig. Pumps are of the positive displacement rotary screw type with 5-hp motors. One pump is more than adequate to supply the six diesel generators of Units 1 and 2 running at rated load. A duplex-type strainer is installed upstream of each fuel oil transfer pump to protect the pump from particles that could damage it. A cartridge-type fuel oil filter is located at the discharge of the fuel oil transfer pumps to prevent any fuel oil contamination from reaching the engine-base-mounted diesel fuel oil tanks. The diagram of the engine fuel oil transfer system is shown in Figure 3.2-21. The physical arrangement of the fuel oil transfer system is shown in Figures 9.5-8 and 9.5-9. (3) Two diesel fuel oil supply headers to each unit routed in separate trenches.
The motor controllers for the two transfer pumps are located inside the auxiliary building. Manual pump control stations and manual controls for the valves are located near each diesel generator set.
The other engine generator auxiliary systems and accessories are essentially as provided on all engine generator units of this size. Each engine generator unit is equipped with a skid-mounted fuel oil tank that has a capacity of 550 gallons, which provides about 2-1/2 hours of full load operation before fuel oil must be transferred from DCPP UNITS 1 & 2 FSAR UPDATE 9.5-20 Revision 21 September 2013 the underground storage tanks. Fuel is transferred to each diesel generator skid-mounted fuel oil tank via two level control valves (and two associated upstream isolation valves) per diesel generator. Each of the two level control valves and associated upstream isolation valves on each diesel generator is associated with a separate diesel fuel oil transfer system train; however, the level control valves, the isolation valves immediately upstream from the level control valves, and the skid-mounted fuel oil tank are part of the associated diesel generator rather than the diesel fuel oil transfer system. The fuel oil transfer pumps start automatically on low level in the engine generator unit tanks. The two 50,000-gallon storage tanks provide a 7-day supply of fuel.
Each emergency diesel generator day tank has the capacity for approximately 2.5 hours of continuous full-load operation. The fuel oil transfer system is designed to replenish the day tanks from the underground fuel oil storage tanks to ensure onsite power is available following a design-basis accident. Each day tank has two associated redundant fuel oil transfer system level control valves (LCVs) that automatically open to replenish the tank. The LCVs are air-operated by the associated diesel starting air receiver tanks. To ensure the starting air system is capable of supporting the required automatic LCV operation, the leakage of each diesel starting air system is verified periodically (Reference 6).
Experience with the PG&E transmission system indicates that in the event of complete loss of offsite power, restoration of normal power sources could be accomplished within a few hours. However, 7 days of onsite power generation has been used as a conservative upper limit for design and safety evaluations of fuel storage capacity for the tanks, even though it is highly improbable that the diesel generators would be required to furnish plant auxiliary power for this long a period. 9.5.4.3 Safety Evaluation 9.5.4.3.1 General Design Criterion 2, 1967 - Performance Standards The EDG units and their associated auxiliary systems, as shown for Unit 1 in Figures 9.5-8, 9.5-9, and 9.5-10, and similarly for Unit 2, are installed in separate compartments that are protected from fires, flooding, and external missiles. The system valves, fittings, and piping are fabricated and inspected to ANSI Code for Pressure Piping B31.1 and B31.7 where applicable. The diesel fuel oil storage tanks are designed and fabricated to UL Standard 58. Seismic effects on the buried tanks are determined by a soil structure interaction analysis. Seismic effects are combined with gravity effects, including those resulting from the weight of the tanks and their contents, and the weight of the soil overburden.
Protection against corrosion problems is provided for underground portions of the system. Tank supports have firm foundations to minimize uneven settling and prevent seismic damage. DCPP UNITS 1 & 2 FSAR UPDATE 9.5-21 Revision 21 September 2013 The exterior surfaces of the tanks have a corrosion-resistant fiberglass reinforced plastic (FRP) wrap. Cathodic protection was provided to protect the tanks and underground piping from corrosion in case of damage to the coating. This cathodic protection system provided minimal protection, is no longer functioning, and has been abandoned in place (Reference 7). Most jurisdictions (including San Luis Obispo County) do not require cathodic protection for fiberglass reinforced plastic clad double wall tanks. California Code of Regulations 23 CCR 2635 does not require cathodic protection for this type of tank construction. ANSI/ANS-59.51-1997 states the use of a double wall tank design is an adequate means of meeting corrosion requirements.
Underground steel piping is provided protection from the effects of long term corrosion by coating or wrapping, in accordance with NACE Standard Practice SP0169. The transfer and vent piping is electrically isolated from the tanks in accordance with NACE Standard Practice SP0169. Magnesium anodes are utilized to protect the tank hold down straps.
The design considerations to prevent water from flooding or groundwater from entering the fuel oil storage tanks, concrete vaults, and pipe trenches were:
(1) As discussed in Section 2.4, the risk of surface water flooding at this site is essentially zero. No groundwater has been encountered at or below the buried tanks, pump vaults, or pipe trenches. Therefore, the source potential for water flooding the fuel oil system is negligible. In addition, the below-ground system is completely sealed with the vent line extending approximately 2 feet above ground. (2) Fuel oil tank vent lines running above ground are protected by concrete boxes and are surrounded by warning posts to alert any vehicular traffic.
The concrete boxes will protect redundant vent lines from any credible common-mode failure. (3) The two transfer pumps are in separate, underground, reinforced concrete vaults with solid covers protected from surface runoff due to their location inside the west buttress and condensate polishing system structure. The vault's manway hatch covers are made of steel and are provided with concrete curbing to prevent water intrusion into the vaults. These vaults are drained to the building sump and are protected with backwater valves. Flooding of the transfer pump vaults is alarmed at the turbine building sump local annunciator and on the Unit 1 main annunciator. (4) The two redundant fuel oil supply headers are in separate, below-ground reinforced concrete pipe trenches with solid steel or concrete covers that are generally flush with the adjacent ground level, except as noted below. Since the trenches collect water from surface runoff, drainage is provided through floor drains to manholes, which are pumped to the turbine building sumps or standpipes that can be connected to portable pumps. Portions DCPP UNITS 1 & 2 FSAR UPDATE 9.5-22 Revision 21 September 2013 of the fuel oil supply header trenches routed in the rooms housing the EDGs are provided with metal grating. The grating provides physical protection of the headers, allows for visual inspection, and provides access for manual control of the fuel oil level control valves using a wrench. Because the grating is located indoors, the potential for flooding is extremely small. The trenches, with the exception of that in the room housing EDG 2-3, drain back to the header trenches. The trench in the room housing EDG 2-3 main header does not drain to a sump and must be pumped out manually. (5) The design classification for the diesel fuel oil piping within the trenches is given in the DCPP Q-List (refer to Reference 8 of Section 3.2). A calculation was performed to determine the maximum ambient temperature inside the pump vaults due to heat output of fuel oil transfer pump motor (Reference 5). The motor is rated to withstand this maximum temperature. The design outdoor design temperature is based on 9 years of onsite hourly data, and the minimum recorded onsite outdoor temperature during this 9-year period is 39°F (refer to Section 9.4). Based on the results of the calculations, and the fact that the extreme low temperature recorded at the DCPP site was above freezing point, it is concluded that neither heating nor cooling is required to perform safe operation of the fuel oil pumps. However, for personnel protection, temporary portable ventilation equipment will be used as required to restore the confined space for habitability inside the vaults during periodic inspection and maintenance, in accordance with the plant administrative procedures. 9.5.4.3.2 General Design Criterion 3, 1971 - Fire Protection The EDG areas are designed to the fire protection guidelines of Branch Technical Position APCSB 9.5-1 (refer to Appendix 9.5B, Table B-1). Refer to Section 8.3.1.4.9 for further discussion on fire barriers and separation. To ensure good fire protection practice, the diesel engine generator installation was designed in accordance with NFPA Standard No. 37, Standard for the Installation and Use of Stationary Combustion Engines and Gas Turbines. This standard permits a maximum capacity of 660 gallons (550 imperial gallons) for an integral fuel oil day tank. It also provides sufficient time for all necessary operator actions to ensure that diesel generator operation is not interrupted in the event of any malfunctions in the system that transfers fuel oil from the underground storage tanks to the day tanks.
The two diesel fuel oil storage tanks are buried, and are designed to the criteria of Part 2, Bulk Underground Storage, of NFPA Standard No. 30, Standard for the Storage, Handling and Use of Flammable Liquids. The National Fire code does not require any specific fire protection system for this type of underground storage tank. Physical separation of the two tanks precludes the possibility of a fire in one storage tank from spreading to another tank. Fire risk is further minimized by the fact that the only source of oxygen to support a fire is through the 4 inch tank vent. If sufficient heat were DCPP UNITS 1 & 2 FSAR UPDATE 9.5-23 Revision 21 September 2013 generated to damage and collapse the storage tank, dirt would cave in and help smother the fire. Two yard hose reel stations are available for fighting any above ground fires at the tank location. 9.5.4.3.3 General Design Criterion 4, 1967 - Sharing of Systems The diesel generator fuel oil system is provided to supply diesel oil to the emergency diesel engine generators for Units 1 and 2. The design classification of this system is given in the DCPP Q-List (refer to Reference 8 of Section 3.2). The fuel storage capacity provides 7 days of onsite power generation in order to operate (a) the minimum required ESF equipment following a loss-of-coolant accident (LOCA) for one unit, and the equipment for the second unit in either the hot or cold shutdown condition, or (b) the equipment for both units in either the hot or cold shutdown condition. The supply of fuel beyond the 7 day period is ensured by the availability of offsite sources and a reliable delivery method.
Safety of the reactor facilities is not impaired by the sharing of the fuel oil systems as any combination of one storage tank and one pump is capable of serving all six-day tanks. Each unit normally supplies power to one transfer pump from one Class 1E 480-V bus (refer to Section 8.3.1.1.4.3.3). Provisions are made to manually switch both pumps to the Class 1E buses of either unit, in case one unit should be placed in a prolonged cold shutdown condition. 9.5.4.3.4 General Design Criterion 11, 1967 - Control Room System instrumentation and control is provided on the tanks and pumps as follows: (1) The base-mounted day tanks have two separate redundant transfer pump start-stop level switches. Each level switch starts a transfer pump and opens the supply header solenoid valve corresponding to the respective transfer pump, A or B. The start setting for the header A level switches is slightly different from those for header B, allowing one to be a backup. (2) The start of transfer pump A or B is indicated both locally and in the control room. (3) Local controls at each diesel generator and manual crosstie valving between headers allow manual starting of either transfer pump and filling of the base-mounted day tanks from either header system A or B. (4) High- and low-level alarm switches are installed on all base-mounted day tanks that activate alarms both locally and in the control room to alert the operators. (5) High- and low-level alarm switches are installed on both fuel oil storage tanks that will activate alarms in the control room. Additionally, dipstick-DCPP UNITS 1 & 2 FSAR UPDATE 9.5-24 Revision 21 September 2013 type indicators and a local level indicator are provided for each storage tank. Additionally, a monitoring system to detect the leakage of oil from the fuel oil transfer system piping in the fuel oil transfer trenches is provided to comply with California Underground Storage Tank regulations. 9.5.4.3.5 General Design Criterion 12, 1967 - Instrumentation and Control Systems Refer to Section 9.5.4.3.4 for discussion related to instrumentation and control. 9.5.4.3.6 General Design Criterion 17, 1971 - Electric Power Systems The EDG system has sufficient capacity, capability, independence, redundancy, and testability to perform its safety function assuming a single failure. Refer to Sections 9.5.4.2 and 9.5.4.3.7 for details on the system. 9.5.4.3.7 General Design Criterion 21, 1967 - Single Failure Definition The diesel generator fuel oil system is designed to remain operable after sustaining a single failure of either an active or a passive component. The capability to meet the single failure criterion is met by providing redundancy in tanks, pumps, valves, piping, and power supplies. The system arrangement provides sufficient separation of the tanks and their associated transfer pumps so that the possibility of damage to both simultaneously as a result of a single event is considered highly unlikely. The fuel oil transfer piping, transfer pumps, and tank manifolding are arranged so a single failure of any pipe, valve, tank, or pump will not disable the system. The design incorporates sufficient redundancy so that a malfunction or failure of either an active or a passive component will not impair the ability of the system to supply fuel oil. As discussed in the preceding paragraph, the diesel fuel oil system transfer components and power sources are redundant up to and including fill valves and connections on the engine day tanks, so that a single malfunction will not prevent the transfer of oil. In the unlikely event of malfunctions in both redundant fuel oil headers, such as a pump failure in one and piping blockage in the other, low level will be alarmed when sufficient fuel oil remains in the base-mounted day tank for a nominal one hour period of operation of the engine at full load. This nominal one hour period is adequate for an operator (a) to correct a malfunction on one of the two redundant transfer headers, or (b) to line up manually the valves of the two headers into one path that will transfer oil. All the valves necessary for this action are readily accessible in the compartments for the diesel fuel oil transfer pumps. DCPP UNITS 1 & 2 FSAR UPDATE 9.5-25 Revision 21 September 2013 Each diesel generator has a dedicated shaft driven fuel pump, priming tank and day tank along with instrumentation, and fuel injectors such that failure of this engine mounted fuel equipment affects its associated diesel generator only. 9.5.4.3.8 Protection from High and Moderate Energy Systems and Internal Missiles The EDG units and their associated auxiliary systems, as shown for Unit 1 in Figures 9.5-8, 9.5-9, and 9.5-10, and similarly for Unit 2, are installed in separate compartments that are protected from internal missiles. The possibility of flooding in the turbine building and in the diesel generator compartments is discussed in Section 8.3.1.1.6.3.9. 9.5.4.3.9 10 CFR Part 50 Appendix R (Sections III.G, III.J, and III.L) - Fire Protection Program for Nuclear Power Facilities Operating Before January 1, 1979 Refer to Section 8.3.1.1.6.3.12 for discussion regarding compliance to the requirements of 10 CFR Part 50 Appendix R. 9.5.4.3.10 Regulatory Guide 1.137, Revision 1, October 1979 - Fuel-Oil Systems for Standby Diesel Generators There is no specific DCPP commitment to use Regulatory Guide 1.137 guidance to establish fuel oil quantity requirements for 7 day EDG operation. The Technical Specification required fuel oil quantity for 7 day EDG operation is based on the calculated fuel oil consumption necessary to support the operation of the EDGs to power the minimum ESF systems required to mitigate a design basis loss of coolant accident (LOCA) in one unit and those minimum required systems for a concurrent non-LOCA safe shutdown in the other unit (both units initially in Mode 1 operation). Proper operation of the EDGs requires following recommended fuel oil practices to ensure proper quality. These practices include checking and removing accumulated water from the day tanks and main storage tanks and draining the main fuel storage tanks, removing accumulated sediment, and cleaning the tanks. Regulatory Guide 1.137 recommends surveillance frequencies for these practices as well as assurance of fuel oil quality in accordance with applicable industry standards. 9.5.4.4 Tests and Inspections The diesel fuel supply headers are hydrostatically or pneumatically tested during construction and all active system components, pumps, valves, and controls are functionally tested during startup and periodically thereafter. The diesel fuel oil in storage will be periodically tested for any possible contamination or deterioration. DCPP UNITS 1 & 2 FSAR UPDATE 9.5-26 Revision 21 September 2013 The underground Diesel Fuel Oil and Transfer System is demonstrated operable as required by the Technical Specifications and at least once per ten years by:
(1) Draining each fuel oil storage tank, removing the accumulated sediment, and cleaning the tank using a sodium hypochlorite or equivalent solution, and (2) Performing a visual examination of accessible piping during an operating pressure leak test. 9.5.4.5 Instrumentation Application Refer to Section 9.5.4.3.4 for discussion related to instrumentation application. 9.5.5 DIESEL GENERATOR COOLING WATER SYSTEM The diesel generator cooling water system is shown schematically in Figure 3.2-21. The physical arrangement of the EDG units is shown in Figures 9.5-10 and 9.5-11 for Unit 1; the arrangement is similar for Unit 2. Figure 9.5-12 shows the outline of the Unit 1 EDGs. The arrangement is similar for the Unit 2 EDGs with the exception of EDG 2-3, which is slightly different.. 9.5.5.1 Design Bases 9.5.5.1.1 General Design Criterion 2, 1967 - Performance Standards The EDG cooling water system is designed to withstand the effects of, or is protected against natural phenomena such as earthquakes, flooding, tornados, winds, and other local site effects. 9.5.5.1.2 General Design Criterion 3, 1971 - Fire Protection The EDG cooling water system is designed and located to minimize, consistent with other safety requirements, the probability and effect of fires and explosions. 9.5.5.1.3 General Design Criterion 11, 1967 - Control Room The EDG cooling water system is designed to support actions to maintain and control the safe operational status of the plant from the control room or from an alternate location if control room access is lost due to fire or other causes.
DCPP UNITS 1 & 2 FSAR UPDATE 9.5-27 Revision 21 September 2013 9.5.5.1.4 General Design Criterion 12, 1967 - Instrumentation and Control Systems Instrumentation and controls are provided as required to monitor and maintain EDG cooling water system variables within prescribed operating ranges. 9.5.5.1.5 General Design Criterion 21, 1967 - Single Failure Definition The EDG cooling water system is designed to remain operable after sustaining a single failure. Multiple failures resulting from a single event shall be treated as a single failure. 9.5.5.1.6 Protection from High and Moderate Energy Systems and Internal Missiles The EDG cooling water system is protected from the internal dynamic effects due to a postulated pipe failure or pipe crack and internally generated missiles. 9.5.5.1.7 10 CFR 50.55a(g) - Inservice Inspection Requirements Applicable EDG cooling water system components must meet the requirements of 10 CFR 50.55a(g). The EDG jacket water cooling system is the only EDG component included in the DCPP Inservice Inspection (ISI) Program. 9.5.5.1.8 10 CFR Part 50 Appendix R (Sections III.G, J, & L) - Fire Protection Program for Nuclear Power Facilities Operating Before January 1, 1979 Section III.G - Fire protection of Safe Shutdown Capability: Fire protection of the EDG cooling water system is provided by a combination of physical separation, fire-rated barriers, and/or automatic suppression and detection. Section III.J - Emergency Lighting: Emergency lighting or BOL are provided in areas where operation of the EDG cooling water system may be required to safely shutdown the Unit following a fire. Section III.L - Alternative and Dedicated Shutdown Capability: Safe shutdown capabilities are provided in the control room and at an alternate location via the hot shutdown panel or locally at the EDG, for the EDG cooling water system, for the safe shutdown of the plant following a fire event. 9.5.5.2 System Description A closed loop jacket water-cooling system is provided for each of the six diesel engines. The engine generator skid has an integrally mounted radiator with a direct engine-driven fan for cooling the engine jacket water. Cooling air is largely outside ambient air, drawn by the fan from outside the building through the tornado missile shield into the radiator-fan portion of the engine generator compartment, and then through the radiator core. DCPP UNITS 1 & 2 FSAR UPDATE 9.5-28 Revision 21 September 2013 The diesel generator ventilation system is described in Section 9.4.7. This closed system allows the diesel generator unit to function in a self-contained manner, independent of outside cooling water systems and electric motor-driven fans.
The radiator is a jacket water-to-air heat exchanger of all copper and brass construction. Makeup to the jacket water cooling system can be added through a fill line after removing the radiator cap, labeled RV-71 in Figure 3.2-21 (Sheets 13 and 14). A low jacket water level alarm notifies the operator that makeup is required.
Engine jacket water is circulated by a jacket water pump directly driven by the engine. A three-way temperature regulating valve bypasses a portion of engine jacket cooling water around the radiator to maintain proper system temperature. Lubricating oil is cooled by a shell and tube heat exchanger using the jacket water as the coolant. Thermostatically controlled immersion heaters keep the jacket water warm for fast starting while the engine is in a shutdown condition.
The generators on these units are air-cooled by a shaft-mounted blower. The cooling system is shown schematically in Figure 9.4-6. 9.5.5.3 Safety Evaluation 9.5.5.3.1 General Design Criterion 2, 1967 - Performance Standards Refer to Section 8.3.1.1.6.3.1 for discussion regarding the protection of the EDGs, and their associated auxiliary systems from flooding and external missiles. 9.5.5.3.2 General Design Criterion 3, 1971 - Fire Protection Refer to Section 8.3.1.1.6.3.2 for discussion regarding the design of the fire protection system for the EDGs and their associated auxiliary systems. 9.5.5.3.3 General Design Criterion 11, 1967 - Control Room Refer to Section 8.3.1.1.6.3.4 for discussion regarding the design of the EDGs and their associated auxiliary systems to support safe shutdown and to maintain safe shutdown from the control room or from an alternate location if the control room access is lost due to fire or other causes. 9.5.5.3.4 General Design Criterion 12, 1967 - Instrumentation and Control Systems Refer to Sections 8.3.1.1.6.3.5 and 8.3.1.1.6.5 for discussions regarding the instrumentation and control for the EDGs and their associated auxiliary systems provided as required to monitor and maintain their variables within prescribed operating ranges. DCPP UNITS 1 & 2 FSAR UPDATE 9.5-29 Revision 21 September 2013 9.5.5.3.5 General Design Criterion 21, 1967 - Single Failure Definition Each diesel generator has a dedicated radiator/fan set, water pump and expansion tank such that failure of the cooling equipment affects its associated diesel generator only. Refer to Section 8.3.1.1.6.3.8 for discussion regarding single failure criterion. 9.5.5.3.6 Protection from High and Moderate Energy Systems and Internal Missiles The EDG units and their associated auxiliary systems, as shown for Unit 1 in Figures 9.5-8, 9.5-9, and 9.5-10, and similarly for Unit 2, are installed in separate compartments that are protected from internal missiles. Because EDG units are separated from each other by the concrete walls of the compartments, the units are protected from postulated internal missiles. Any missile created by an explosion within a compartment would remain in that compartment. The possibility of flooding in the turbine building and in the diesel generator compartments is discussed in Section 8.3.1.1.6.3.9. 9.5.5.3.7 10 CFR 50.55a(g) - Inservice Inspection Requirements Refer to Section 8.3.1.1.6.3.10 for discussion regarding compliance to the requirement of 10 CFR 50.55a(g). 9.5.5.3.8 10 CFR Part 50 Appendix R (Sections III.G, III.J, and III.L) - Fire Protection Program for Nuclear Power Facilities Operating Before January 1, 1979 Refer to Section 8.3.1.1.6.3.12 for discussion regarding compliance to the requirements of 10 CFR Part 50 Appendix R. 9.5.5.4 Tests and Inspections Refer to Section 8.3.1.1.6.4 for discussion regarding the inspection and testing associated with the EDGs and their associated auxiliary systems. 9.5.5.5 Instrumentation Applications Instrumentation application for this system is discussed in Section 8.3.1.1.6.5. 9.5.6 DIESEL GENERATOR STARTING SYSTEM The diesel generator starting system is is shown schematically in Figure 3.2-21. The physical arrangement of the engine generator units is shown in Figures 9.5-10 and 9.5-11 for Unit 1; the arrangement is similar for Unit 2. Figure 9.5-12 shows the outline DCPP UNITS 1 & 2 FSAR UPDATE 9.5-30 Revision 21 September 2013 of the Unit 1 engine generators. The arrangement is similar for the Unit 2 generators with the exception of EDG 2-3, which is slightly different. Each diesel generator is designed with two starting control circuits, one field flashing circuit, and one sensing circuit. These circuits receive Class 1E dc control power through a manual transfer switch. Normal Class 1E dc power is from the same train as the diesel generator. In the event of failure of dc power to these control circuits, an alarm appears on the main annunciator. The manual transfer switch, located near the control panel at the diesel generator can be used to transfer to backup Class 1E dc power. 9.5.6.1 Design Bases 9.5.6.1.1 General Design Criterion 2, 1967 - Performance Standards The EDG starting system is designed to withstand the effects of, or is protected against natural phenomena such as earthquakes, flooding, tornados, winds, and other local site effects. 9.5.6.1.2 General Design Criterion 3, 1971 - Fire Protection The EDG starting system is designed and located to minimize, consistent with other safety requirements, the probability and effect of fires and explosions. 9.5.6.1.3 General Design Criterion 11, 1967 - Control Room The EDG starting system is designed to support actions to maintain and control the safe operational status of the plant from the control room or from an alternate location if control room access is lost due to fire or other causes. 9.5.6.1.4 General Design Criterion 12, 1967 - Instrumentation and Control Systems Instrumentation and controls are provided as required to monitor and maintain EDG starting system variables within prescribed operating ranges. 9.5.6.1.5 General Design Criterion 21, 1967 - Single Failure Definition The EDG starting system is designed to remain operable after sustaining a single failure. Multiple failures resulting from a single event are treated as a single failure. 9.5.6.1.6 Protection from High and Moderate Energy Systems and Internal Missiles The EDG starting system is protected from the internal dynamic effects due to a postulated pipe failure or pipe crack and internally generated missiles. DCPP UNITS 1 & 2 FSAR UPDATE 9.5-31 Revision 21 September 2013 9.5.6.1.7 10 CFR Part 50 Appendix R (Sections III.G, IIIJ, and III.L) - Fire Protection Program for Nuclear Power Facilities Operating Before January 1, 1979 Section III.G - Fire protection of Safe Shutdown Capability: Fire protection of the EDG starting system is provided by a combination of physical separation, fire-rated barriers, and/or automatic suppression and detection. Section III.J - Emergency Lighting: Emergency lighting or BOL are provided in areas where operation of the EDG starting system may be required to safely shutdown the Unit following a fire. Section III.L - Alternative and Dedicated Shutdown Capability: Safe shutdown capabilities are provided in the control room and at an alternate location via the hot shutdown panel or locally at the EDG, for the EDG starting system, for the safe shutdown of the plant following a fire event. 9.5.6.2 System Description Each diesel engine of the six engine generator sets is provided with two separate and redundant air-start systems. Normally two trains, four starting air motors, operate together in combination with the turbo-charger air assist system to ensure that the engine generator set starts and accelerates to rated speed and to minimum bus voltage in less than 10 seconds. In the event that one of the air start systems fails or is unavailable, the remaining air-start system with turbo assist is capable of starting and accelerating the engine to rated speed and to minimum bus voltage in 10 seconds. Each of the two air-starting systems consists of an air receiver; a non-Class 1E electric motor-driven air compressor to charge the receiver; two air-starting motors that engage and turn the engine flywheel; and all piping, valves, and controls necessary to provide a complete system. Each of the two redundant PG&E Design Class II air compressors for each engine generator unit is fed from different Class 1E buses so that the possibility of simultaneous loss of both air compressors is minimized. The diesel engine vendor sizing criteria for each air start receiver is to provide sufficient capacity for three consecutive 15-second cranking cycles. Additional cranking cycles can be made as the PG&E Design Class II air compressors replenish their air receivers. In addition to the above described two air-start systems, each diesel engine is equipped with an engine turbocharger boost system. The turbocharger boost system serves two functions: it aids in acceleration of the large rotating mass of the turbocharger, and it provides extra air to the engine to improve combustion during acceleration. The additional air is necessary since the turbocharger is inefficient at low speeds. The turbocharger boost system consists of one PG&E Design Class II air compressor, one air receiver, and all piping, valves, and controls necessary to provide a complete system. The turbocharger boost system with two air-starting motors is capable of starting and accelerating the engine generator set to rated speed and to minimum bus voltage in 10 seconds. The starting air system and the turbocharger boost systems are DCPP UNITS 1 & 2 FSAR UPDATE 9.5-32 Revision 21 September 2013 shown schematically in Figure 3.2-21 (Sheets 3 through 6). The physical arrangement of those systems is shown in Figures 9.5-10 and 9.5-11. 9.5.6.3 Safety Evaluation 9.5.6.3.1 General Design Criterion 2, 1967 - Performance Standards Refer to Section 8.3.1.1.6.3.1 for discussion regarding the protection of the EDGs and their associated auxiliary systems from flooding and external missiles. 9.5.6.3.2 General Design Criterion 3, 1971 - Fire Protection Refer to Section 8.3.1.1.6.3.2 for discussion regarding the design of the fire protection system for the EDGs and their associated auxiliary systems. 9.5.6.3.3 General Design Criterion 11, 1967 - Control Room Refer to Section 8.3.1.1.6.3.4 for discussion regarding the design of the EDGs and their associated auxiliary systems to support safe shutdown and to maintain safe shutdown from the control room or from an alternate location if the control room access is lost due to fire or other causes. 9.5.6.3.4 General Design Criterion 12, 1967 - Instrumentation and Control Refer to Sections 8.3.1.1.6.3.5 and 8.3.1.1.6.5 for discussions regarding the instrumentation and control for the EDGs and their associated auxiliary systems provided as required to monitor and maintain their variables within prescribed operating ranges. 9.5.6.3.5 General Design Criterion 21, 1967 - Single Failure Definition Each diesel engine of the six engine generator sets is provided with two separate and redundant air-start systems. Normally two trains, four starting air motors, operate together in combination with the turbo-charger air assist system to ensure that the engine generator set starts and accelerates to rated speed and to minimum bus voltage in less than 10 seconds. In the event that one of the air start systems fails or is unavailable, the remaining air-start system with turbo assist is capable of starting and accelerating the engine to rated speed and to minimum bus voltage in 10 seconds.
Each diesel generator has dedicated air start receiver tanks (redundant), and a turbocharger receiver tank along with solenoid valves such that failure of this air start equipment affects its associated diesel only. Refer to Section 8.3.1.1.6.3.8 for discussion regarding single failure criterion. DCPP UNITS 1 & 2 FSAR UPDATE 9.5-33 Revision 21 September 2013 9.5.6.3.6 Protection from High and Moderate Energy Systems and Internal Missiles The EDG units and their associated auxiliary systems, as shown for Unit 1 in Figures 9.5-8, 9.5-9, and 9.5-10, and similarly for Unit 2, are installed in separate compartments that are protected from internal missiles. Because EDG units are separated from each other by the concrete walls of the compartments, the units are protected from postulated internal missiles. Any missile created by an explosion within a compartment would remain in that compartment.
The possibility of flooding in the turbine building and in the diesel generator compartments is discussed in Section 8.3.1.1.6.3.9. 9.5.6.3.7 10 CFR Part 50 Appendix R (Sections III.G, III.J, and III.L) - Fire Protection Program for Nuclear Power Facilities Operating Before January 1, 1979 Refer to Section 8.3.1.1.6.3.12 for discussion regarding compliance to the requirements of 10 CFR Part 50 Appendix R. 9.5.6.4 Tests and Inspections Refer to Section 8.3.1.1.6.4 for discussion regarding the inspection and testing associated with the EDGs and their associated auxiliary systems. 9.5.6.5 Instrumentation Applications Instrumentation application for this system is discussed in Section 8.3.1.1.6.5. 9.5.7 DIESEL GENERATOR LUBRICATION SYSTEM The diesel generator lubrication system is shown schematically in Figure 3.2-21. The physical arrangement of the engine generator units is shown in Figures 9.5-10 and 9.5-11 for Unit 1; the arrangement is similar for Unit 2. Figure 9.5-12 shows the outline of the Unit 1 engine generators. The arrangement is similar for the Unit 2 generators with the exception of EDG 2-3, which is slightly different. 9.5.7.1 Design Bases 9.5.7.1.1 General Design Criterion 2, 1967 - Performance Standards The EDG lubrication system is designed to withstand the effects of, or is protected against natural phenomena such as earthquakes, flooding, tornados, winds, and other local site effects. DCPP UNITS 1 & 2 FSAR UPDATE 9.5-34 Revision 21 September 2013 9.5.7.1.2 General Design Criterion 3, 1971 - Fire Protection The EDG lubrication system is designed and located to minimize, consistent with other safety requirements, the probability and effect of fires and explosions. 9.5.7.1.3 General Design Criterion 11, 1967 - Control Room The EDG lubrication system is designed to support actions to maintain and control the safe operational status of the plant from the control room or from an alternate location if control room access is lost due to fire or other causes. 9.5.7.1.4 General Design Criterion 12, 1967 - Instrumentation and Control Systems Instrumentation and controls are provided as required to monitor and maintain EDG lubrication system variables within prescribed operating ranges. 9.5.7.1.5 General Design Criterion 21, 1967 - Single Failure Definition The EDG lubrication system is designed to remain operable after sustaining a single failure. Multiple failures resulting from a single event are treated as a single failure. 9.5.7.1.6 Protection from High and Moderate Energy Systems and Internal Missiles The EDG lubrication system is protected from the internal dynamic effects due to a postulated pipe failure or pipe crack and internally generated missiles. 9.5.7.1.7 10 CFR Part 50 Appendix R (Sections III.G, III.J, III.L) - Fire Protection Program for Nuclear Power Facilities Operating Before January 1, 1979 Section III.G - Fire protection of Safe Shutdown Capability: Fire protection of the EDG lubrication system is provided by a combination of physical separation, fire-rated barriers, and/or automatic suppression and detection. Section III.J - Emergency Lighting: Emergency lighting or BOL are provided in areas where operation of the EDG lubrication system may be required to safely shutdown the Unit following a fire. Section III.L - Alternative and Dedicated Shutdown Capability: Safe shutdown capabilities are provided in the control room and at an alternate location via the hot shutdown panel or locally at the EDG, for the EDG lubrication system, for the safe shutdown of the plant following a fire event. DCPP UNITS 1 & 2 FSAR UPDATE 9.5-35 Revision 21 September 2013 9.5.7.2 System Description The lubricating oil system for each engine is entirely contained on that engine's baseplate. The system is schematically shown in Figure 3.2-21 (Sheet 11). During engine operation, all required lubricating oil is drawn from the engine crankcase through a shaft-mounted oil pump to a lubricating oil filter with a built-in pressure relief device to bypass lubricating oil flow in the event that the filter becomes excessively dirty. The oil is then cooled in the jacket water-cooled heat exchanger and returned to the engine bearings through a duplex strainer. During normal operation, engine cooling water will not leak into the lubricating oil due to a leak in the lubricating oil heat exchanger since the operating pressure of the lubricating oil system is above 75 psig, and the operating pressure of the cooling water system is about 35 psig. Instrumentation provided in the lubricating oil circuit is described in Section 8.3.1.1.6.5. While the engine is idle, oil is continually circulated by means of a small precirculating pump. A thermostatically controlled immersion heater on the outlet of the precirculating pump maintains a 90-110°F oil temperature to ensure rapid and safe startup of the engine at any time. 9.5.7.3 Safety Evaluation 9.5.7.3.1 General Design Criterion 2, 1967 - Performance Standards Refer to Section 8.3.1.1.6.3.1 for discussion regarding the protection of the EDGs and their associated auxiliary systems from flooding, and external missiles. 9.5.7.3.2 General Design Criterion 3, 1971 - Fire Protection Refer to Section 8.3.1.1.6.3.2 for discussion regarding the design of the fire protection system for the EDGs and their associated auxiliary systems. 9.5.7.3.3 General Design Criterion 11, 1967 - Control Room Refer to Section 8.3.1.1.6.3.4 for discussion regarding the design of the EDGs and their associated auxiliary systems to support safe shutdown and to maintain safe shutdown from the control room or from an alternate location if the control room access is lost due to fire or other causes. 9.5.7.3.4 General Design Criterion 12, 1967 - Instrumentation and Control Systems Refer to Sections 8.3.1.1.6.3.5 and 8.3.1.1.6.5 for discussions regarding the instrumentation and control for the EDGs and their associated auxiliary systems provided as required to monitor and maintain their variables within prescribed operating ranges. DCPP UNITS 1 & 2 FSAR UPDATE 9.5-36 Revision 21 September 2013 9.5.7.3.5 General Design Criterion 21, 1967 - Single Failure Definition Each diesel generator has a dedicated lubrication oil tank, cooler, recirculation pump, and pre-circulation pump such that failure of this equipment affects the associated diesel generator only. Refer to Section 8.3.1.1.6.3.8 for discussion regarding single failure criterion. 9.5.7.3.6 Protection from High and Moderate Energy Systems and Internal Missiles The EDG units and their associated auxiliary systems, as shown for Unit 1 in Figures 9.5-8, 9.5-9, and 9.5-10, and similarly for Unit 2, are installed in separate compartments that are protected from internal missiles. Because EDG units are separated from each other by the concrete walls of the compartments, the units are protected from postulated internal missiles. Any missile created by an explosion within a compartment would remain in that compartment. The possibility of flooding in the turbine building and in the diesel generator compartments is discussed in Sections 8.3.1.1.6.3.9. 9.5.7.3.7 10 CFR Part 50 Appendix R (Sections III.G, III.J, and III.L) - Fire Protection Program for Nuclear Power Facilities Operating Before January 1, 1979 Refer to Section 8.3.1.1.6.3.12 for discussion regarding compliance to the requirements of 10 CFR Part 50 Appendix R. 9.5.7.4 Tests and Inspections Refer to Section 8.3.1.1.6.4 for discussion regarding the inspection and testing associated with the EDGs and their associated auxiliary systems. 9.5.7.5 Instrumentation Applications Instrumentation application for this system is discussed in Section 8.3.1.1.6.5. 9.
5.8 REFERENCES
- 1. Pacific Gas and Electric Company, Fire Protection Review, Units 1 and 2 (Diablo Canyon Power Plant), Facility Operating License No. DPR-76, Amendment No. 51; July 27, 1977.
- 2. Pacific Gas and Electric Company, Report on 10 CFR 50 Appendix R Review (Diablo Canyon Power Plant, Unit 1), July 15, 1983.
DCPP UNITS 1 & 2 FSAR UPDATE 9.5-37 Revision 21 September 2013 3. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
- 4. Report on 10 CFR 50, Appendix R Review (Diablo Canyon Power Plant, Unit 2), Pacific Gas and Electric Company, December 6, 1984.
- 5. Diablo Canyon Engineering Calculation HVAC 83-11, Pacific Gas and Electric Company, Nuclear Power Generation files.
- 6. Pacific Gas and Electric Company Probabilistic Risk Assessment Calculation File No. PRA04-11, Potential Loss of DFO Day Tank LCVs Following a Seismically Induced LOOP, July 5, 2005.
- 7. Pacific Gas and Electric Company Design Change Package DDP: 1000000205, Diesel Fuel Oil Storage Tank Cathodic Protection System Abandonment, April 2009
- 8. NECS File: 131.95, FHARE 160, Lack of Return Bends in Fire Sprinkler Piping. 9.5.9 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.1-1 Sheet 1 of 2 Revision 20 November 2011 SPENT FUEL POOL COOLING AND CLEANUP SYSTEM ANALYSIS DATA(a) Spent Fuel Pool Permanent Storage Capacity 1,324 assemblies(b) Spent Fuel Pool Water Volume, cubic feet 47,215
Minimum Boron Concentration of the Spent Fuel Pool Water, ppm 2,000 (Up to 2600 during MPC Loading)* Partial core off-load (Case 1): 96 fuel assemblies from current refueling assumed to have 52,000 MWD/MTU burnup. Conservative assumptions have been used to minimize decay time and maximize base decay hear load. Spent fuel pool HX CCW inlet temp, °F 75 Decay heat production, Btu/hr 22.92 x 106 Spent fuel pool water temperature, °F 127 Partial core off-load (Case 2): 193 fuel assemblies from current refueling separated into two burnup groups: 101 assemblies at 52,000 MWD/MTU and 92 assemblies at 25,000 MWD/MTU. Conservative assumptions have been used to minimize decay time and maximize base decay heat load. Spent fuel pool HX CCW inlet temp, °F 75 Decay heat production, Btu/hr 36.67 x 106 Spent fuel pool water temperature, °F 157 Emergency full core off-load (Case 3): 193 assemblies from current refueling after 36 days of operation at full power. Fuel assemblies are separated into two burnup groups: 113 assemblies at 40,000 MWD/MTU and 80 assemblies at 3,000 MWD/MTU. Conservative assumptions have been used to minimize decay time and maximize base decay heat load. Spent fuel pool HX CCW inlet temp, °F 75 Decay heat production, Btu/hr 38.71 x 106 Spent fuel pool water temperature, °F 162 Spent Fuel Pool Water Heat Inertia Time to heat from 127 to 212°F for partial offload Case 1 above and no heat loss, hr 11.27 Time to heat from 157 to 212°F for full offload Case 2 4.35 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.1-1 Sheet 2 of 2 Revision 20 November 2011 above, hr Time to heat from 162 to 212°F for emergency offload Case 3 above, hr 3.76
- Refer to Diablo Canyon ISFSI Technical Specifications (a) DCPP thermal-hydraulic analyses have been changed per LAR 04-07, Enclosure 1, Section 4.3 as part of the temporary cask pit spent fuel storage rack project (b) The maximum number of irradiated fuel assemblies stored in the SFP during normal plant operations is limited to 1433 fuel assemblies per DCPP TS LCO 3.7.17.C.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.1-2 Sheet 1 of 3 Revision 16 June 2005 SPENT FUEL POOL COOLING AND CLEANUP SYSTEM DESIGN AND OPERATING PARAMETERS Pumps 1-1/2-1 Pumps 1-2/2-2 Spent Fuel Pool Pump Number, per unit 1 1 Design pressure, psig 150 100 Design temperature, °F 225 225 Design flow, gpm 2,300 3,000 Material Stainless steel Stainless steel
Spent Fuel Pool Skimmer Pump Number, per unit 1 Design pressure, psig 50 Design temperature, °F 200 Design flow, gpm 100 Material Stainless steel
Refueling Water Purification Pump Number, per unit 1 Design pressure, psig 150 Design temperature, °F 200 Design flow, gpm 400 Material Stainless steel
Spent Fuel Pool Heat Exchanger Number, per unit 1 Design heat transfer, Btu/hr 11.95 x 106 Shell Tube Design pressure, psig 150 150 Design temperature, °F 250 250 Design flow, lb/hr 1.49 x 106 1.14 x 106 Inlet temperature, °F 95 120 Outlet temperature, °F 103 109.5 Fluid circulated Component cooling water Spent fuel pool water Material Carbon steel Stainless steel
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.1-2 Sheet 2 of 3 Revision 16 June 2005 Spent Fuel Pool Demineralizer Number, per unit 1 Design pressure, psig 200 Design temperature, °F 250 Design flow, (min. to max.), gpm 27 to 109 Resin volume, ft3 39 Material Stainless steel
Spent Fuel Pool Filter Number, per unit 1 Design pressure, psig 200 Design temperature, °F 250 Design flow, gpm 150 Filtration requirement 98% retention of particles above 5 microns Material, vessel Stainless steel
Spent Fuel Pool Resin Trap Filter Number, per unit 1 Design pressure, psig 200 Design temperature, °F 250 Design flow, gpm 150 Filtration requirement 98 percent retention of particles above 5 microns Material, vessel Stainless steel
Spent Fuel Pool Skimmer Filter Number, per unit 1 Design pressure, psig 200 Design temperature, °F 250 Rated flow, gpm 150 Filtration requirement 98% retention of particles above 5 microns Material, vessel Stainless steel
Refueling Water Purification Filter Number, per unit 1 Design pressure, psig 200 Design temperature, °F 250 Design flow, gpm 400 Filtration requirement 98% retention of particles above 5 microns
Demineralizer Resin Trap Number, per unit 1 Slot opening, inches 0.010 Material Stainless steel
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.1-2 Sheet 3 of 3 Revision 16 June 2005 Spent Fuel Pool Strainer Number, per unit 1 Rated flow, gpm 2300 Perforation, inches Approximately 0.2 Material Stainless steel
Spent Fuel Pool Skimmer Strainer Number, per unit 1 Rated flow, gpm 100 Design pressure, psig 50 Design temperature, °F 200 Perforation, inches 1/8 Material Stainless steel
Spent Fuel Pool Skimmers Number, per unit 2 Design flow, gpm 50
Piping and Valves Design pressure, psig 150 Design temperature, °F 200 Material Stainless steel
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.2-1 Revision 12 September 1998 AUXILIARY SALTWATER SYSTEM COMPONENT DESIGN DATA Auxiliary Saltwater Pumps Number, per unit 2 Type Vertical, wet pit, single stage Rated capacity, gpm 11,000 Rated head, feet of sea water 125 Efficiency, % 83 Motor horsepower 465(a) Speed, rpm 900 Column and discharge head material exposed to salt water 316L stainless steel Design temperature, °F 120 Casing rated pressure, psig 100 Submergence required, ft 3 Minimum flow to prevent overheating, gpm 1,400
(a) Nameplate rating is 400 HP; analyzed to be capable of operating at 465 brake HP DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.2-2 Revision 21 September 2013 AUXILIARY SALTWATER SYSTEM MALFUNCTION ANALYSIS Component Malfunction Consequences and Comments 1. Auxiliary saltwater pump Pump casing rupture The casing is designed for 100 psig, which exceeds maximum operating conditions. Pump is inspectable. Standby pump provides redundancy. 2. Auxiliary saltwater pump Pump fails to start One operating pump supplies either normal or minimum postaccident flow. Second pump provides full redundancy. Indication in control room shows pump status. 3. Auxiliary saltwater pump Manual valve at discharge closed or check valve sticks closed This will be prevented by prestartup and operational checks. Indication in control room shows position of remotely operated valves and whether flow is established. 4. Component cooling water heat exchanger Tube or channel rupture Rupture is considered highly unlikely because of low operating pressures and use of corrosion resistant materials. However, the leaking heat exchanger can be identified by sequential isolation or visual inspection. If the leak is in the on-line heat exchanger, the standby heat exchanger would be placed in service and the leaking exchanger isolated. 5. Piping and general Any leakage from system via open vent or drain valve, ruptured heat exchanger tube, or other malfunction of equipment served by the system The leaking component can be identified by sequential isolation or visual inspection. Rupture in a main cooling header would be indicated in the control room as low differential pressure across the heat exchanger and high component cooling water temperature. The operator can remotely or manually transfer flow to the redundant supply header restoring the system's cooling function before there is a significant temperature rise in the component cooling water system. 6. Motor Pipe rupture at pump-motor enclosure Rupture is considered highly unlikely because of low operating pressures and use of corrosion-resistant materials in contact with the saltwater. However, each pump is located in an isolated enclosure. Rupture could flood one compartment but the other motor would be protected. Level transmitters in pump enclosures alarm to the control room when flooding is detected. 7. Traveling Screen Screen clogging Clogging of the ASW common traveling screen with debris is discussed in Section 9.2.7.2.3, "Intake Structure and Equipment."
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.2-3 Revision 21 September 2013 COMPONENT COOLING WATER SYSTEM COMPONENT DESIGN DATA Component Cooling Water Pumps Number, per unit 3 Type Horizontal centrifugal Rated capacity, gpm 9200 Rated head, ft 145 Motor horsepower 400 Casing material ASTM A-216 Gr. WCB carbon steel Design pressure, psig 150 Design temperature, °F 300
Component Cooling Water Heat Exchangers Number, per unit 2 Type Shell and tube Heat transferred, Btu/hr 258.8 x 106 Shell-side Component cooling water outlet temperature, °F 125.0 Component cooling water inlet temperature, °F 171.7 Component cooling water flow rate, gpm 11,210 Design pressure, psig 150 Design temperature, °F 300 Tube side Auxiliary saltwater inlet temperature, °F 70 Auxiliary saltwater outlet temperature, °F 120 Auxiliary saltwater flow rate, gpm 10,580 Design pressure, psig 100 Design temperature, °F 200 Tube material ASME SB-111 and/or ASME SB-543, 90-10 CuNi Shell material ASME SA 515 Gr. 70 Component Cooling Water Surge Tank Number, per unit 1 Type Horizontal cylindrical with elliptical head: approximately 8 ft diameter x 30 ft long, internally baffled Volume Total, gal 10,750 Normal operating, gal Greater than 4,000 Design pressure, psig 150 Design temperature, °F 300 Material ASME SA-285 Gr C
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.2-4 Revision 20 November 2011 COMPONENTS COOLED BY THE COMPONENT COOLING WATER SYSTEM Loop A Loop B Loop C Containment fan coolers 2 3
Residual heat removal heat exchangers 1 1
Residual heat removal pump seal water coolers 1 1
Centrifugal charging pumps CCP1 and CCP2 oil coolers 1 1
Safety injection pump oil and seal water coolers 1 1
Component cooling water pump oil coolers and stuffing boxes 2 1 Post-LOCA sampling cooler 1
Spent fuel pool heat exchanger 1
Seal water heat exchanger 1
Letdown heat exchanger 1
Excess letdown heat exchanger 1
NSSS sample heat exchangers - Unit 1 5 NSSS sample heat exchangers - Unit 2 4 Steam generator blowdown sample heat exchangers 5
Reactor coolant pump thermal barriers and motor oil coolers 4 Boric acid evaporator condenser, distillate cooler, vent condenser, and sample cooler (abandoned in place) Auxiliary steam drain receiver vent condenser (abandoned in place) 1 Waste gas compressors 2
Reactor vessel support coolers 4
Sample panel coolers 1 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.2-5 Sheet 1 of 2 Revision 20 November 2011 COMPONENT COOLING WATER SYSTEM NOMINAL FLOWS(a) (in gpm) Normal LOCA(b) Cooldown(c) Containment fan coolers and motors 10,250 4,560 10,250 RHR heat exchangers - 5,000 10,000 RHR pumps(f) 20 10 20 Centrifugal charging pumps CCP1 and CCP2(f) 30 15 30 Safety injection pumps(d)(f) 48 24 48 Component cooling water pumps(e)(f) 30 10 30 Spent fuel pool heat exchanger(i) 3,400 - 3,400 Seal water heat exchanger 210 - 210 Letdown heat exchanger 1,000 - 300 Excess letdown heat exchanger - - - NSSS sample heat exchanger 50 - 50 CCW sample line 10 - 10 Steam generator blowdown HX 40 - 40 Reactor coolant pumps 780 - 780 Boric acid evaporator package(h) - - - Waste concentrator package(h) - - - Auxiliary steam vent condenser(h) - - - Waste gas compressors 100 - 100 Reactor vessel support coolers 100 - 100 Sample panel coolers 40 - 40 Post-LOCA sample cooler - - - No. of pumps required 2 2 3(g) No. of pumps normally in service 2 2 (one for each vital loop 3 No. of pumps installed 3 3 3 _________________
(a) Unless noted otherwise, the data contained in this table are nominal flows. For the purpose of design basis analyses, lower assumed flows may be used to evaluate equipment, containment heat removal capability, or different alignments (such as Section XI testing or RHR heat exchanger operation); higher assumed flows may be used to evaluate maximum CCW temperatures. (b) Recirculation phase (flows are for vital header "B" which is greater than those of vital header "A"). The minimum required post-LOCA flow rates are shown. The flow rate for the CFCUs represents a minimum flow of 1490 gpm to the cooling coils and 30 gpm to the motor coolers. Note that during the injection phase the total minimum CFCU flow rate is 1650 gpm. (c) 20 hours after initiation of reactor cooldown.
(d) For safety injection pumps, the minimum required cooling flow following a LOCA is 24 gpm per pump. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.2-5 Sheet 2 of 2 Revision 20 November 2011 (e) For component cooling water pumps, a minimum flow of 10 gpm per pump is required for stuffing box cooling flushing. Additional flow is required for lube oil cooling and is controlled by throttling to maintain lube oil temperature. (f) Flow rates are minimum required following a LOCA. Flow rates during normal operation are higher, depending on system alignment. (g) Three pumps are desirable. Loss of one extends cooldown time but does not create an unsafe condition. (h) The waste concentrator package, boric acid evaporator package, and auxiliary steam vent condenser have been abandoned in place and are currently isolated from the CCW system. (i) During core offload
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.2-6 Revision 15 September 2003 COMPONENTS WITH A SINGLE BARRIER BETWEEN COMPONENT COOLING WATER AND REACTOR COOLANT WATER
Barrier Design Temperature,
°F Barrier Design
- Pressure, psig Temperature Range of Reactor Coolant Water, °F Pressure Range of Reactor Coolant Water, psig RHR heat exchangers 400 630 350 600 RHR pumps (seal coolers) 800 5140 350 600 Reactor coolant pumps(thermal barrier cooling coils) 650 2485 600 2485 Letdown heat exchanger 400 600 380 600 Excess letdown heat exchanger 650 2485 600 2485 Seal water heat exchanger 250 150 200 150 Sample heat exchangers 680 2485 652.7 2485
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.2-7 Sheet 1 of 3 Revision 21 September 2013 COMPONENT COOLING WATER SYSTEM MALFUNCTION ANALYSIS Component Malfunction Consequences and Comments 1. Component cooling water pumps Pump casing rupture The casing is designed for 150 psig and 300°F which exceeds maximum operating conditions. Pump is inspectable and protected against credible missiles. Rupture is not considered credible. Standby pump provides redundancy.
- 2. Component cooling water pumps Pump fails to start Two operating pumps supply normal flow. Third standby provides redundancy. 3. Component cooling water pumps Manual valve at pump suction or discharge closed or check valve sticks closed This will be prevented by prestartup and operational checks. Further, periodic checks during normal operation would show that a valve was closed. 4. Component cooling water heat exchanger Tube or shell rupture Because of low operating pressures, rupture is considered incredible in normal or postaccident injection phase service; however, a leaking exchanger could be ascertained by sequential isolation or visual inspection. If a leak is in the on-line component cooling water heat exchanger, the standby exchanger would be put on stream and the leaking exchanger isolated and repaired. The leaking exchanger could be left in service with leakage up to the capacity of the makeup line to the system from the condensate storage tank, which is 250 gpm. During long-term postaccident recirculation the component cooling water system (CCWS) may be operated as two separate loops, either of which could sustain this failure with the other providing the minimum required engineered safety features.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.2-7 Sheet 2 of 3 Revision 21 September 2013 Component Malfunction Consequences and Comments 5. General Any leakage from system via open or drain valve severed loop piping, ruptured heat exchanger tube or other malfunction of equipment served by the system Leakage from the CCWS can be detected by a falling level in the component cooling water surge tank. Observation of the time for the water level to fall a given amount and the area of the water surface in the tank will permit a determination of the leakage rate. The leaking component can be ascertained by sequential isolation or visual inspection of equipment in the system or complete isolation of a header. The 4000 gallons remaining in the surge tank after a makeup valve open alarm and the makeup flow will provide time for the closure of valves external to the containment for the isolation of all but the largest leaks. A 200 gpm maximum leak or rupture is postulated, so the operator has at least 20 minutes to isolate the leak before the surge tank is empty. The period is extended if the automatically operated, Design Class II, normal makeup path functions as designed and adds makeup water to the system. If the operator observes a rapidly falling surge tank level, he can elect to align/start a backup makeup water flow to the system before trying to isolate the leak (a backup source of water to the CCWS is provided from the condensate storage tank). The 250 gpm, Design Class I, makeup water flowpath, described in Section 9.2.3.3, can be started within 10 minutes. Because the makeup rate is greater than the postulated leak, the sequential isolation of components to stop the leak can proceed in an orderly manner. The 200 gpm leak is within the capacity of the auxiliary building drainage system. The complete rupture of large pipes or equipment with rapid loss of water is considered highly unlikely in normal operation or postaccident injection phase operation since all vital system piping and heat exchangers are located in the missile protected area of the containment. However, any of the three headers can be isolated. The two vital headers may be separated in accordance with EOP E-1.4 based on plant conditions during long-term postaccident operation and a passive failure in either would not impair the minimum engineered safety features supported by the other. Leaks into the CCW system can result from heat exchanger tube failure. For the RCP thermal barrier, the system design is to contain the in-leakage to the CCW system within the containment structure. The outboard containment isolation valve returning CCW from all reactor coolant pump thermal barriers closes on a high flow signal indicating in-leakage from the higher pressure RCS. All piping and valves DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.2-7 Sheet 3 of 3 Revision 21 September 2013 required to contain this in-leakage are designed for an RCS design pressure of 2485 psig. Should a coolant leak develop from the postulated failure mode that does not result in automatic flow isolation, the corresponding increase in CCW volume is accommodated by the relief valve on the CCW surge tank. The four relief valves on the CCW returns from thermal barriers are sized to relieve volumetric expansion and are set to relieve at RCS design pressure. Tube failure in components with design pressures / temperatures less than RCS design condition can also initiate a leak into the CCW system. The radioactivity associated with the reactor coolant would actuate the CCW system radiation monitor (see Section 9.2.2.2.12). The monitor in turn would annunciate in the control room and close the vent valve located just upstream of the CCW surge tank back-pressure regulator to prevent the regulator from venting after sensing high radiation. The operator would also receive high level and high-pressure alarms from the surge tank as it filled. Continued in-leakage would increase the pressure in the surge tank until the high surge tank pressure alarm is actuated and the relief valve setpoint is reached. The relief valve on the surge tank protects the system from overpressurization. The maximum postulated in-leakage into the CCW system is based on an RHR heat exchanger tube rupture. The relief valve can accommodate this flow. Relief valve discharge from the CCW system surge tank is routed to the skirted area under the surge tank where it enters a floor drain routed to the auxiliary building sump. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.2-9 Sheet 1 of 4 Revision 19 May 2010 MAKEUP WATER SYSTEM EQUIPMENT DESIGN AND OPERATING PARAMETERS Lime Tank(a) Number, shared 1 (35 gal.) Chemical Lime Lining Thermo-setting resin Size, in. 48 x 48 Material Carbon steel Tank mixer, hp 1/4
Coagulant Tank(a) Number, shared 1 (100 gal.) Chemical Ferrous sulfate Lining Thermo-setting resin Size, in. 48 x 48 Material Carbon steel Tank mixer, hp 1/4
Chemical Feed(a) Pumps Diaphragm and metering pump - 2 pumps, 2 drive motors
Mixed Bed Demineralizers Regeneration System Caustic day tank Number, total 1 Lining Thermo-setting resin Size, in. 42 (dia) x 48 (straight side) Material Carbon steel
Caustic storage tank(a) Number, total 1 Design pressure, psia 65 Design temperature, °F 400 Operating pressure, psia 35 Operating temperature, °F 90 Size, gal. 6710 Type Horizontal with saddle steam heater Material ASME SA-36
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.2-9 Sheet 2 of 4 Revision 19 May 2010 Acid storage tank(a) Number, total 1 Design pressure, psia 65 Design temperature, °F 400 Operating pressure, psia 35 Operating temperature, °F 70 Size, gal. 6710 Type Horizontal Material ASME SA-36
Miscellaneous equipment Caustic dilution water heater Electric, 125 kW @ 460 V Caustic Feed pump Diaphragm, 98 gph @ l30 psig
Reverse Osmosis (RO) System(a) Flowrate (influent), gpm 200 Permeate flow rate, gpm 150 Reject flow rate, gpm 50 Operating pressure, psig 432 Total dissolved solid removal capacity, % minimum 90 RO pressure vessels First stage 6 Second stage 3 RO elements, per vessel 6 RO element type ROGA (spiral wound)
RO Auxiliary Equipment(a) RO booster pumps (total) 2 Flow rate, gpm 200 Operating Head, psig 432 Motor, hp 100
RO prefilters Cartridge filters, total 2 Filters rating, microns 5 Cartridge material Polypropylene Flow rate, gpm 100 Operating pressure, psig 150 Filter casing construction material 304 stainless steel
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.2-9 Sheet 3 of 4 Revision 19 May 2010 Hypochlorite feed Day tank size, in. 28 (dia) x 48 (straight side) Tank volume, gal. 100 Mixer volume, gal. 1/4 Hypochlorite feed pumps 2 each, positive displacements, 1/6 hp
Acid feed Acid day tank size, in. 60 (dia) x 48 (straight side) Tank volume, gal. 400 Lining Lithcote lined with cover Acid feed pump 2 each, positive displacement 1/6 hp
Hexametaphosphate feed Hexametaphosphate day tank size, in. 28 (dia) x 42 (high) Tank volume, gal. 100 Hexametaphosphate feed pumps 2 each, positive displacement 1/6 hp
Dechlorination system Sodium bisulfate day tank size, in. 28 (dia) x 42 (high) Tank volume, gal. 100 Sodium bisulfate feed pumps 2 each, positive displacement, l/6 hp
Makeup Water Degassifier(a) Number, total 1 Design pressure atmospheric Design temperature, °F 90 Design flowrate, gal. 150 Air blower, scfm 440 @ 5 in H2O Blower motor, hp 1 Holding Tank size, in. 84 (dia) x 108 (high) Tower size, in. 36 (dia) x 104 (high) Construction material Reinforced polyester fiberglass Makeup Water Storage Tanks Primary water storage tank Number, per unit 1 Type Vertical diaphragm sealed tank Capacity, gal. 200,000 Size, ft 30 (dia) x 40 (straight side) Material 304L stainless steel DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.2-9 Sheet 4 of 4 Revision 19 May 2010 Condensate storage tank Number, per unit 1 Type Vertical tank with floating roof Capacity, gal. 425,000 Size, ft 40 (dia) x 47 (straight side) Material Carbon steel with reinforced concrete wall Fire water and transfer storage tank - serves both units Number 1 Type Vertical dual compartment tank Capacity - fire water, gal. 300,000 transfer, gal. 150,000 Size - fire water, ft 33 (dia) x 51 (straight side) transfer, ft 40 (dia) x 51 (straight side) Material Carbon steel Inner tank - carbon steel Outer tank - carbon steel with reinforced concrete wall Primary water makeup pumps Number, per unit 2 Design pressure, psia 128 Design temperature, °F 70 Operating flow, gpm 150 Operating head, ft 222 Fluid Water Driver, hp 15 Material 316 stainless steel Type Vertical in-line Makeup water transfer pumps Number, shared 2 Design pressure, psia 205 Design temperature, °F 70 Operating flow, gpm 250 Operating head, ft 240 Fluid Water Driver, hp 30 Material Class 30 cast iron Type Horizontal end suction (a) These items are abandoned in place per administrative procedure. DCPP uses a rental seawater reverse osmosis system and a rental makeup water pretreatment system. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.3-1 Sheet 1 of 2 Revision 12 September 1998 COMPRESSED AIR SYSTEM EQUIPMENT A. INSTRUMENT AIR SYSTEM Compressors Number 4 Type Oil-free, single-stage, double-acting, reciprocating Capacity 334 scfm each Pressure 100 psig
Number 2 Type Oil-free, two stage, water cooled, rotary screw Capacity 650 scfm each Pressure 110 psig
Number 1 Type Oil-free, two stage, air cooled, rotary screw Capacity 650 scfm each Pressure 110 psig
Air Dryers Number 2 Type Adsorbent, heat-regenerative (1) and heatless (1) Capacity 1500 scfm each Inlet pressure 100 psig Inlet temperature 100°F Exit dew point -40°F at 100 psig and inlet air 100°F sat. Pre-Filters Number 2 Type Positive-seal Capacity 2800 scfm each Filtration 0.6 microns
After Filters Number 2 Type Positive-seal Capacity 3600 scfm each Filtration 1 micron
Receivers Number 2 Capacity 650 cu ft each Pressure 120 psig Material ASME SA 515 Gr. 70 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.3-1 Sheet 2 of 2 Revision 12 September 1998 B. SERVICE AIR SYSTEM Compressors Number 1 Type Oil-free, two stage, air-cooled, rotary screw Capacity 650 scfm Pressure 125 psig
Number 1 Type Oil-free, two stage, air-cooled, rotary screw Capacity 1050 scfm each Pressure 125 psig
Air Dryers Number 3 Type Heatless (2) and heat of compression (1) Capacity 1500 scfm Inlet pressure 100 psig Exit dew point -40°F Pre-Filters Number 2 Type Positive-seal Capacity 2100 scfm Filtration 1 micron
After Filters Number 2 Type Positive-seal Capacity 2400 scfm Filtration 1 micron
Receiver Number 1 Capacity 750 cu ft Pressure 125 psig DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 9.3-2 NUCLEAR STEAM SUPPLY SYSTEM SAMPLING SYSTEM COMPONENT DESIGN DATA Sample Heat Exchanger Number, per unit 3 Design heat transfer rate (duty for 652.7°F sat. steam to 127°F liquid), each, Btu/hr 2.12 x 105 Shell Tube Design pressure, psig 150 2485 Design temperature, °F 350 680 Design flow, gpm 14.1 0.42 Temperature, in, °F 95 652.7 (max) Temperature, out, °F 125 127 (max) Fluid Component cooling water Sample Material Carbon steel Austenitic stainless steel Sample Pressure Vessel Number, per unit 4 Volume, ml 150 Design pressure, psig 2485 Design temperature, °F 680 Material Austenitic stainless steel
DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 9.3-5 CHEMICAL AND VOLUME CONTROL SYSTEM DESIGN DATA General: Seal water supply flow rate, four pumps, nominal, gpm 32 Seal water return flow rate, four pumps, nominal, gpm 12 Letdown flow: Normal, gpm 75 Minimum, gpm 45 Maximum, gpm 120 Charging flow (excludes seal water): Normal, gpm 55 Minimum, gpm 25 Maximum, gpm 100 Temperature of letdown reactor coolant entering system, °F 545 Temperature of charging flow directed to reactor coolant system, °F 494 Centrifugal charging pump (CCP1 and 2) bypass flow (each), gpm 60 Centrifugal charging pump (CCP3 bypass flow (each), gpm 50 Amount of 4% boric acid solution required to meet design basis shutdown requirements, gal. (fuel cycle dependent) 14,042 Maximum pressurization required for hydrostatic testing of reactor coolant system, psig 3107 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.3-6 Sheet 1 of 8 Revision 20 November 2011 CHEMICAL AND VOLUME CONTROL SYSTEM PRINCIPAL COMPONENT DATA SUMMARY Centrifugal Charging Pumps CCP1 and CCP2 Number, per unit 2 Design pressure, psig 2800 Design temperature, °F 300 Design flow, gpm 150 Design head, ft 5800 Material Austenitic stainless steel
Centrifugal Charging Pump CCP3 Number, per unit 1 Design pressure, psig 3200 Design temperature, °F 300 (a) Design flow, gpm 150 Design head, ft 5700 Material Austenitic stainless steel
Boric Acid Transfer Pump Number, per unit 2 Design pressure, psig 150 Design temperature, °F 250 Design flow, gpm 75 Design head, ft 235 Material Austenitic stainless steel
Gas Stripper Feed Pumps Number, per unit 2 Design pressure, psig 150 Design temperature, °F 200 Design flow, gpm 30 Design head, ft 320 Material Austenitic stainless steel
Holdup Tank Recirculation Pump Number, per unit 1 Design pressure, psig 75 Design temperature, °F 200 Design flow, gpm 500 Design head, ft 100 Material Austenitic stainless steel DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.3-6 Sheet 2 of 8 Revision 20 November 2011 Boric Acid Reserve Tank Pumps Number, per unit 2 Design pressure, psig 150 Design temperature, °F 200 Design flow, gpm 150 Design head, ft 200 Material Austenitic stainless steel Boric Acid Reserve Tank Recirculation Pump Number, shared 2 per tank Design pressure, psig 300 Design temperature, °F 400 Design flow, gpm 25 Design head, ft. 100 Material Austenitic stainless steel Concentrates Holding Tanks 0-1,0-2 Transfer Pumps (abandoned in place) Number (per tank), shared 2 Design pressure, psig 100 Design temperature, °F 250 Design flow, gpm 40 Design head, ft 150 Material Austenitic stainless steel Regenerative Heat Exchanger Number, per unit 1 Heat transfer rate at design conditions, Btu/hr 10.3 x 106 Shell side Design pressure, psig 2485 Design temperature, °F 650 Fluid Borated reactor coolant Material Austenitic stainless steel Tube side Design pressure, psig 2735 Design temperature, °F 650 Fluid Borated reactor coolant Material Austenitic stainless steel Shell side (Letdown) Flow, lb/hr 37,050 Inlet temperature, °F 545 Outlet temperature, °F 290 Tube Side (Charging) Flow, lb/hr 27,170 Inlet temperature, °F 130 Outlet temperature, °F 495 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.3-6 Sheet 3 of 8 Revision 20 November 2011 Letdown Heat Exchanger Number, per unit 1 Heat transfer rate at design conditions, Btu/hr 14.8 x 106 Shell side Design pressure, psig 150 Design temperature, °F 250 Fluid Component cooling water Material Carbon steel Tube side Design pressure, psig 600 Design temperature, °F 400 Fluid Borated reactor coolant Material Austenitic stainless steel Shell side Design Normal Flow, lb/hr 492,000 203,000 Inlet temperature, °F 95 95 Outlet temperature, °F 125 125 Tube Side (Letdown) Flow, lb/hr 59,280 37,050 Inlet temperature, °F 380 290 Outlet temperature, °F 127 127 Excess Letdown Heat Exchanger Number, per unit 1 Heat transfer rate at design conditions, Btu/hr 4.61 x 106 Shell Side Tube Side Design pressure, psig 150 2485 Design temperature, °F 250 650 Design flow, lb/hr 115,000 12,380 Inlet temperature, °F 95 545 Outlet temperature, °F 135 195 Fluid Component cooling water Borated reactor coolant Material Carbon steel Austenitic stainless steel DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.3-6 Sheet 4 of 8 Revision 20 November 2011 Seal Water Heat Exchanger Number, per unit 1 Heat transfer rate at design conditions, Btu/hr 2.49 x 106 Shell side Tube Side Design pressure, psig 150 150 Design temperature, °F 250 250 Design flow, lb/hr 99,500 160,600 Inlet temperature, °F 95 143 Outlet temperature, °F 120 127 Fluid Component cooling water Borated reactor coolant Material Carbon steel Austenitic stainless steel Volume Control Tank Number, per unit 1 Volume, ft3 400 Design pressure, psig 75 Design temperature, °F 250 Spray nozzle flow (maximum), gpm 120 Material Austenitic stainless steel Boric Acid Tank Number, per unit 2 Capacity, gal. 8,060 Design pressure Atmospheric Design temperature, °F 180 Material Austenitic stainless steel Boric Acid Batching Tank Number, shared 1 Capacity, gal. 800 Design pressure Atmospheric Design temperature, °F 300 Material Austenitic stainless steel Chemical Mixing Tank Number, per unit 1 Capacity, gal. 5 Design pressure, psig 150 Design temperature, °F 200 Material Austenitic stainless steel DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.3-6 Sheet 5 of 8 Revision 20 November 2011 Holdup Tanks Number, shared 5 Volume, gal. 83,220 Design pressure, psig 15 Design temperature, °F 200 Material Austenitic stainless steel
Boric Acid Reserve Tanks Number, per unit 2 Capacity, gal. 24,610 Design pressure Atmospheric Design temperature, °F 150 Material Austenitic stainless steel with membrane seal Concentrates Holding Tank (abandoned in place) Number, shared 2 Capacity, gal. 2,000 Design pressure Atmospheric (0-1) 20 psig (0-2) (b) Design temperature, °F 250 Material Austenitic stainless steel
Mixed Bed Demineralizers Number, per unit 2 Design pressure 200 Design temperature, °F 250 Design flow, gpm 120 Normal resin volume, each, ft3 30 Maximum resin volume, each, ft3 (flush only) 39 Material Austenitic stainless steel
Boric Acid Reserve Tank Recirculation Heater Number, shared 1 per tank Design pressure, psig 150 Design temperature, °F 500 Design flow, gpm 25 Material Austenitic stainless steel DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.3-6 Sheet 6 of 8 Revision 20 November 2011 Cation Bed Demineralizer Number, per unit 1 Design pressure, psig 200 Design temperature °F 250 Design flow, gpm 120 Resin volume, each, ft3 27 Material Austenitic stainless steel
Deborating Demineralizers Number, per unit 2 Design pressure 200 Design temperature, °F 250 Design flow, gpm 120 Normal resin volume, each, ft3 30 Maximum resin volume, each, ft3 (flush only) 39 Material Austenitic stainless steel
Evaporator Feed Ion Exchangers Number, per unit 4 Design pressure, psig 200 Design temperature, °F 250 Design flow, gpm 30
Resin volume (maximum), ft3 16 Material Austenitic stainless steel
Evaporator Condensate Demineralizers (abandoned in place) Number, per unit 2 Design pressure 200 Design temperature, °F 250 Design flow, gpm 30 Resin volume, each, ft3 12 Material Austenitic stainless steel Reactor Coolant Filters Number, per unit 2 Design pressure, psig 200 (1-1, 2-1), 300 (1-2, 2-2) Design temperature, °F 250 Design flow, gpm 150 (1-1, 2-1), and 250 (1-2, 2-2) Particle retention 98% of 25 micron size 100% of 50 micron size Material, vessel Austenitic stainless steel
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.3-6 Sheet 7 of 8 Revision 20 November 2011 Seal Water Injection Filters Number, per unit 2 Design pressure, psig 2,735 Design temperature, °F 200 Design flow, gpm 80 Particle retention 98% of 5 micron size Material, vessel Austenitic stainless steel
Seal Water Return Filter Number, per unit 1 Design pressure, psig 200 Design temperature, °F 250 Design flow, gpm 150 Particle retention 98% of 25 micron size Material, vessel Austenitic stainless steel
Boric Acid Filter Number, per unit 1 Design pressure, psig 200 Design temperature, °F 250 Design flow, gpm 150 Particle retention 5 micron or less Material, vessel Austenitic stainless steel
Ion Exchanger Filter Number, per unit 1 Design pressure, psig 200 Design temperature, °F 250 Design flow, gpm 35 Particle retention 98% of 25 micron size Material, vessel Austenitic stainless steel
Condensate Filter (abandoned in place) Number, per unit 1 Design pressure, psig 200 Design temperature, °F 250 Design flow, gpm 35 Particle retention 5 micron or less Material, vessel Austenitic stainless steel
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.3-6 Sheet 8 of 8 Revision 20 November 2011 Concentrates Filter (abandoned in place) Number, per unit 1 Design pressure, psig 200 Design temperature, °F 250 Design flow, gpm 35 Particle retention 98% of 25 micron size Material, vessel Austenitic stainless steel
Boric Acid Blender Number, per unit 1 Design pressure, psig 150 Design temperature, °F 250 Material Austenitic stainless steel
Letdown Orifice 45 gpm 75 gpm Number, per unit 1 2 Design flow, lb/hr 22,230 37,050 Differential pressure at design flow, psia 1,900 1,900 Design pressure, psig 2,485 2,485 Design temperature, °F 650 650 Material Austenitic stainless steel Austenitic stainless steel Gas Stripper - Boric Acid Evaporator Package (abandoned in place) Number, per unit 1 Design flow, gpm 15 Concentration of concentrate (boric acid), 4 weight percent Concentration of condensate <10 ppm boron as H3BO3 Material Stainless steel (a) The design temperature of 300°F is for the structural integrity of the pump but not the limitation for operation. (b) Formerly part of the liquid radwaste system and operates near atmospheric pressure conditions.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.3-7 Sheet 1 of 2 Revision 20 November 2011 NITROGEN REQUIREMENTS Supply Pressure,Supply Flow, Equipment psig scfm Comments Pressurizer relief tank 3 8.5 Initial gas cover
Unit 1 Reactor coolant drain tank <15 20 (27 max.)Gas cover/purge (refueling outage) Unit 2 Reactor coolant drain tank <15 20 (40 max.)Gas cover/purge Volume control tank 18 8.3 Initial gas cover (2950 scf total for all 3 tanks above, per refueling cycle) Spray additive tank 5 5
Gas decay tanks 5 15
Waste concentrator condenser 2 10 (abandoned in place)
Boric acid concentrator 2 10 (abandoned in place)
Boric acid tanks 1 10
Concentrates holding tank 0-1 1 6 (abandoned in place)
Concentrates holding tank 0-2 1 8 (abandoned in place)
Liquid holdup tank 3 4 (70 max.)
Accumulators 650 22 103,000 scf initial fill, based on 700 psig and 40% gas space per refueling cycle Boric acid reserve tanks 1.5 1
Various replenishment requirements Degasification purging during cold shutdown, 8400 scf per cold shutdown Nitrogen layup system for steam generators 400 lb of nitrogen gas required to purge 4 main steam lines and provide initial charge of nitrogen on steam generators at 5 psig DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.3-7 Sheet 2 of 2 Revision 20 November 2011 Supply Pressure,Supply Flow, Equipment psig scfm Comments Nitrogen layup for 12 feedwater heaters Same requirement as for steam generators except need 760 lb of nitrogen CCW surge tank pressurization with N2 20 25 (max) Intermittent (to maintain surge tank pressure) Condenser 30 (max) 20 Continuous
Zinc Tank 2" H2O <1 Intermittent (to maintain N2 blanket in the zinc tank) DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.3-8 Revision 14 November 2001 HYDROGEN REQUIREMENTS Equipment Supply Pressure, psig Supply Flow, scfm Comments Generator 75 (max.) 200 (makeup) Initial fill of 34,390 scf
Volume control tank 15 to 26 8.3 960 scf required for purge and initial fill DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.4-1 Sheet 1 of 2 Revision 16 June 2005 CONTROL ROOM HVAC SYSTEM COMPONENT DESIGN DATA Filter Bank Unit (per unit) No. Size, in. Efficiency, %(d) Rated Air Flow Per Filter, cfm Roughing filters 2 24 x 24 x 6 80-85(a) 1000 @ 0.30"SPHEPA filters 2 24 x 24 x 11-1/2 99.97(b) 1150 @ 1.00"SPCharcoal filters 6 26 x 26 x 6 99/85(c) 333 @ 1.3"SP (cells or trays)
Charcoal Filter Humidity Control Heater (per unit) No. Capacity, kW Voltage, V Electric heater 2 5.0 480
Fans (per unit) Static Pressure, Air Flow, No. in H2O cfm Motor, hp Main supply 2 1.75 7800 7.5 Filter booster 2 5.40 2100 3 Exhaust 1 1.00 1700 3/4 Pressurization(e) 4 5.00 2100 7.5 Air Conditioning Units (per unit) Two full-capacity air conditioning units are provided, each consisting of a reciprocating compressor, cooling coil, and fan air-cooled condenser. The refrigeration capacity for each condenser is 31.0 tons using Freon 22 at 37°F suction temperature and 107°F condenser temperature. The cooling coils are each capable of handling 7800 cfm of air at 400 fpm face velocity. The air conditions for the cooling coil are:
Entering air: 84.0°F D.B./64.8°F W.B. Leaving air: 54°F D.B./53°F W.B. Friction drop through the coil: 0.41 in. H2O
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.4-1 Sheet 2 of 2 Revision 16 June 2005 Airborne Contaminant Detectors (per unit) No. Location Sensitivity Smoke 2 Return air duct Trace amounts of combustion products 2 Control room normal intake Trace amounts of combustion products Radioactivity 2 Control room normal intake 1 x 10-2 to 10+3 mR/hr 2 Pressurization intakes 10-2 mR/hr (Sensitivity range is 10-2 to 10+4 mR/hr with setting point of 2 mR/hr) Chlorine(f) - - -
(a) Minimum efficiency requirements. Efficiency based on American Filter Institute (AFI) dust spot test (b) Based on standard DOP test 0.3 micron particles
(c) Radioactive elemental iodine and radioactive iodide as methyl iodide, respectively (Efficiency rates are for filters as originally specified. Replacement filters shall comply with the requirements of Regulatory Guide 1.52 and ANSI N509.) (d) Efficiency rates for HEPA and charcoal filters are for individual components (for filter efficiency rates during a DBA, refer to the respective accident analysis in Chapter 15) (e) All four fans are common to both Units 1 and 2
(f) Chlorine monitors are abandoned in place or removed as there is no bulk chlorine onsite DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.4-2 Sheet 1 of 4 Revision 21 September 2013 COMPLIANCE WITH REGULATORY GUIDE 1.52, (REVISION 0, JUNE 1973) DESIGN, TESTING, AND MAINTENANCE CRITERIA FOR ATMOSPHERE CLEANUP SYSTEM AIR FILTRATION AND ADSORPTION UNITS OF LIGHT-WATER COOLED NUCLEAR POWER PLANTS Regulatory Position Compliance Reasons or Comments
- 2. SYSTEM DESIGN CRITERIA
- a. Redundant systems and required components Yes, except: (1) No demisters. (1) Demisters are not provided since they are not required for this filtration system design. In the control room, the outside air intake plenum is designed to present a tortuous path for flow in order to remove entrained water. At the time of operating the hydrogen vent system, several weeks after the DBA, no moisture will be entrained in the containment. Filters in fuel handling area and auxiliary building are not in direct contact with outside air.
(2) No HEPA after-filters. (2) Charcoal is thoroughly cleaned before insertion in filter trays. Formation of charcoal fines is not considered significant. (3) Auxiliary building ventilation system does not have redundant charcoal filters. (3) As discussed in Section 15.5.17, failure of an RHR pump seal was already assumed as the single failure, an additional failure of the auxiliary building charcoal filter need not be postulated. Therefore, the charcoal filters need not be redundant. (4) Auxiliary building ventilation system does not have redundant electric heaters.
Fuel handling building H&V system does not have electric heaters (see 3.b below). (4) Installation of one electric heater for the auxiliary building H&V system is consistent with the commitments made as discussed in Section 15.5.17. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.4-2 Sheet 2 of 4 Revision 21 September 2013 Regulatory Position Compliance Reasons or Comments 2. SYSTEM DESIGN CRITERIA b. Physical separation, including missile protection Yes, except some ventilation systems in the plant are not specifically designed against tornadoes (see Section 3.3.2) or against local damage of ducting by missiles. However, the control room positive pressurization system is specifically designed for protection against tornado missiles (Reference Section 9.4.1.3.8). The remainder of the control room ventilation system is enclosed within reinforced concrete structures. No damage to components essential to safe plant shutdown or to protection of the public. d. Protection against pressure surges Not applicable. Auxiliary building ventilation system not specifically designed for pressure surge due to failure of gas decay tank. Since insignificant amounts of radioiodine are contained in the tank, loss of this system will not affect offsite exposures. f. Maximum air flow rate per train and preferred filter array Air flow rate for the fuel handling fuel handing building H&V system is 35,000 cfm and auxiliary building ventilation system is 73,500 cfm versus recommended 30,000 cfm. In either case, filters are easily replaced. Structural platforms and traveling hoists are permanently installed in filter rooms. In only one case are filters aligned more than three high above the floor or a platform. g. Flow and P signal, alarm and record in control room No control room recorders or alarms. Systems are tested at least once each 31 days when required to be operable per Technical Specifications. Fan status and damper position indicator lights are provided in the control room for the auxiliary and fuel handling buildings H&V systems. The control room HVAC system is provided with a system trouble alarm in the control room. j. Total enclosure and intact replacement Not replaceable intact. Each filter train consists of a totally enclosed unit, which cannot be replaced intact due to the as-built dimensions of the filter train room and access doors. Filter train components can be individually replaced. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.4-2 Sheet 3 of 4 Revision 21 September 2013 Regulatory Position Compliance Reasons or Comments 3. COMPONENT DESIGN CRITERIA & QUALIFICATION TESTING a. Demisters quality to MSAR 71-45 & UL Class I Not applicable. No demisters. b. Heaters to reduce RH to 70% under DBA The fuel handling building H&V system does not have electric heaters. Heaters are installed for the control room and the auxiliary building ventilation systems. Heaters not required for the fuel handling building, control room, and auxiliary building ventilation systems. Charcoal samples are tested to 95% RH. Relative humidity of the exhaust air of these systems is not expected to exceed the tested condition. 4. MAINTENANCE i. Entire standby atmosphere cleanup train should be operated at least 10 hours per month, with the heaters on (if so equipped), in order to reduce the buildup of moisture. No. Site climate should not lead to an excessive buildup of moisture on the filters; however, at least once per 31 days, when required by the Technical Specifications for operability, flow is initiated through the filters for at least 15 minutes to verify flow (Reference Section 9.4.1.3.8.) 5. IN-PLACE TESTING CRITERIA In-place penetration of HEPA filters should conform to ANSI N101.1-1972. Adsorber banks should be leak tested in accordance with USAEC Report DP-1082. No. Visual inspection, in-place penetration and bypass leakage testing of HEPA filter and adsorber banks performed in accordance with ANSI N510-1980. The in-place testing criteria are established in the Technical Specifications. The 1980 revision of ANSI N510 encompasses the testing criteria required by ANSI N101.1-1972 and USAEC Report DP-1082. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.4-2 Sheet 4 of 4 Revision 21 September 2013 Regulatory Position Compliance Reasons or Comments 6. LABORATORY TESTING CRITERIA FOR ACTIVATED CARBON a. Activated carbon adsorber section should be assigned the decontamination efficiencies given in Table 2. No. The control room ventilation system decontamination efficiencies assumed in the accident analysis are 90% / 70% for elemental and organic iodine respectively. The control room HVAC system charcoal samples are tested at 30°C/95% RH per ASTM D3803-89 with a 2.5% acceptance criteria versus using RDT M16-1T (1972) at DBA conditions. The laboratory test acceptance criteria are established in the Technical Specifications. Testing per RDT M16-1T (1972) has been superseded by the more conservative test requirements in ASTM D3803-1989. The auxiliary building ventilation system decontamination efficiencies assumed in the accident analysis are 90%/70% for elemental and organic iodine, respectively, versus 95%/95% as assigned by RG 1.52, Table 2. Additionally, the charcoal samples are tested at 30°C/95% RH per ASTM D3803-89 with a 15% acceptance criterion versus using RDT M16-1T (1972) at DBA conditions. The decontamination efficiencies used in the accident analysis are more conservative than the values stated in RG 1.52. The laboratory test acceptance criteria are established in the Technical Specifications. Testing per RDT M16-1T (1972) has been superseded by the more conservative test requirements in ASTM D3803-1989. The fuel handling building ventilation system decontamination efficiencies assumed in the accident analysis are 90%/70% for elemental and organic iodine, respectively, versus 95%/95% as assigned by RG 1.52, Table 2. Additionally, the charcoal samples are tested at 30°C/95% RH per ASTM D3803-89 with a 15% acceptance criterion versus using RDT M16-1T (1972) at DBA conditions. The decontamination efficiencies used in the accident analysis are more conservative than the values stated in RG 1.52. The laboratory test acceptance criteria are established in the Technical Specifications. Testing per RDT M16-1T (1972) has been superseded by the more Conservative test requirements in ASTM D3803-1989. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.4-5 Revision 21 September 2013 AUXILIARY BUILDING VENTILATION SYSTEM COMPONENTS DESIGN DATA Filters, per unit No. Size, in Efficiency, %(d) Rated Air Flow Per Filter, cfm Supply roughing 70 24x24x26 30 (minimum)(e) 2,000 @ 0.17" SP Exhaust roughing 172 24x24x12 80-85(a) 2,000 @ 0.55" SP Exhaust HEPA 273 24x24x 99.97(b) 1,150 @ 1.00" SP 11-1/2
Exhaust charcoal (module composed of 3 cells or trays) 77 27-5/32 x 26-3/8 x 28-1/2 99/85(c) 1,000 @ 1.3" SP (Air enters from rear of tray) Fans, per unit No. Max. Static Pressure H2O, in Air Flow, cfm
Motor, hp Supply (S31 & S32) 2 2.80 67,500 60
Exhaust (E1 & E2) 2 10.00 73,500 150 Electric Heaters, per unit No. Rating Exhaust (EH-30) 1 54 kW, 480 V, 3d (a) Minimum efficiency requirements (Efficiency based on National Bureau of Standard (NBS) methods, dust spot test.) (b) Based on standard DOP test 0.3 micron particles (c) Radioactive elemental iodine and radioactive iodide as methyl iodide, respectively. Efficiency rates are for filters as originally specified. Replacement filters shall comply with the requirements of Regulatory Guide 1.52 and ANSI N509. (d) Efficiency rates for HEPA and charcoal filters are for individual components. For filter efficiency rates during a DBA, refer to the respective accident analysis in Chapter 15. (e) Average dust spot efficiency requirement (Efficiency based on ASHRAE Standard 52.1 test) (f) Supply filters are nominal values and may not reflect the as-built conditions. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.4-6 Sheet 1 of 2 Revision 12 September 1998 FUEL HANDLING AREA HEATING AND VENTILATION SYSTEM COMPONENTS DESIGN DATA Filters, per unit No. Size, in. Efficiency, %(d) Rated Air Flow Per Filter, cfm Supply roughing 21 24x24x13 30(a) 2,500 @ 0.35" SP Exhaust roughing 120 24x24x12 80-85(a)2,000 @ 0.55" SP Exhaust HEPA 107 24x24x 99.97(b)1,150 @ 1.00" SP 11-1/2
Exhaust charcoal (module composed of 3 cells or trays) 72 27-5/32 x 26-3/8 x 28-1/2 99/85(c)1,000 @ 1.3" SP (Air enters from rear of tray) Fans, per unit No. Max. Static Pressure H2O, in. Air Flow, cfm
- Motor, hp Supply (S1 & S2) 2 2.90-3.30 23,300 25
Exhaust (E4) 1 6.75 35,750 75 (E5 & E6) 2 7.55 35,750 75 Heating Coils, per unit Heating Capacity, Btu/hr Area, sq ft Air Flow, cfm Entering Temp., °F Leaving Temp., °F Steam Press., psig 1,400,000 61.8 23,300 35 70 15 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.4-6 Sheet 2 of 2 Revision 12 September 1998 (a) Minimum efficiency requirements (Efficiency based on National Bureau of Standards (NBS) methods, dust spot test.)
(b) Based on standard DOP test 0.3 micron particles (c) Radioactive elemental iodine and radioactive iodide as methyl iodide, respectively (Efficiency rates are for filters as originally specified. Replacement filters shall comply with the requirements of Regulatory Guide 1.52 and ANSI N509.) (d) Efficiency rates for HEPA and charcoal filters are for individual components (For filter efficiency rates during a DBA, refer to the respective accident analysis in Chapter 15.)
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.4-7 Revision 13 April 2000 DESIGN VALUES FOR TURBINE BUILDING VENTILATION SYSTEM, UNIT 1 Turbine building volume, ft3 5,125,000 15 Supply fans rating, cfm/fan 28,000
4 Exhaust fans rating, cfm/fan 40,000
Estimated Heat Losses Btu/Hr Piping and valves 1,100,000 H.P. heaters 384,000 Electric motors 1,600,000 Lights 1,586,000 Turbine-generator 500,000 Solar and fabric 1,050,000 Contingency 632,000 TOTAL 6,852,000 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.4-8 Sheet 1 of 3 Revision 15 September 2003 DESIGN CODES AND STANDARDS FOR VENTILATION SYSTEMS Building or Area Code Control room State of California, Industrial Safety Orders, Title 8, Sub-Chapter 7 American Society of Heating, Refrigerating and Air Conditioning Engineers (ASHRAE) Guide Sheet Metal, Air Conditioning Contractors' National Association (SMACNA) Code Air Movement and Control Association (AMCA) - Standards for Air Moving Devices Auxiliary building (excluding fuel handling area) State of California, Industrial Safety Orders, Title 8, Sub-Chapter 7 ASHRAE Guide
SMACNA Code
AMCA - Standards for Air Moving Devices
American Conference of Governmental Industrial Hygienists - Industrial Ventilation Manual Turbine building State of California, Industrial Safety Orders, Title 8, Sub-Chapter 7 ASHRAE Guide
SMACNA Code
AMCA - Standards for Air Moving Devices
Fuel handling area of the auxiliary building State of California, Industrial Safety Orders, Title 8, Sub-Chapter 7 ASHRAE Guide
SMACNA Code
AMCA - Standards for Air Moving Devices DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.4-8 Sheet 2 of 3 Revision 15 September 2003 Building or Area Code Containment State of California, Industrial Safety Orders, Title 8, Sub-Chapter 7 ASHRAE Guide
SMACNA Code
AMCA - Standards for Air Moving Devices
Auxiliary saltwater pump vaults State of California, Industrial Safety Orders, Title 8, Sub-Chapter 7 ASHRAE Guide
SMACNA Code
AMCA - Standards for Air Moving Devices
125 Vdc/480 Vac switchgear area State of California, Industrial Safety Orders, Title 8, Sub-Chapter 7 ASHRAE Guide
SMACNA Code
AMCA - Standards for Air Moving Devices
4.16 kV Switchgear room State of California, Industrial Safety Orders, Title 8, Sub-Chapter 7 ASHRAE Guide
SMACNA Code
AMCA - Standards for Air Moving Devices
Post-accident sample room ASHRAE Guide
SMACNA Code
AMCA - Standards for Air Moving Devices
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.4-8 Sheet 3 of 3 Revision 15 September 2003 Building or Area Code Technical support center ASHRAE Guide
SMACNA Code
AMCA - Standards for Air Moving Devices
Containment Penetration Area GE/GW AMCA 99 (1972) - Standards Handbook
AMCA 210 (1974) - Test Code For Air Moving Devices AMCA 500 (1975) - Test Methods for Louvers, Dampers and Shutters ANSI N509-1980 - Nuclear Power Plants Air Cleaning Units and Components SMACNA - HVAC Duct Construction Standards 1985 SMACNA - Round Industrial Duct Construction Standard
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.4-9 Revision 13 April 2000 ESTIMATED CONTROL ROOM AREA HEAT LOADS(a) (NORMAL OPERATING CONDITIONS - MODE 1) Area Btu/hr Control Room Floor and wall 14,990 Occupants 3,200 Lighting 35,495 Annunciators, control boards, and nuclear instrumentation 109,365 Computer Room Floor and wall 8,900 Occupants 1,280 Lighting 8,765 Computers and analog control system 3,865 67,580(b) Record Storage and Office Floor and wall 3,450 Occupants 1,150 Lighting 5,300 Safeguard Room Floor and walls 2,545 Occupants 640 Lighting 3,030 Solid state protection system 18,770 Control Room Area Outside Air 2,835
Total Heat Loads 223,580 Total Tonnage - 19.0 Tons
(a) All loads are given for Unit 1. Unit 2 heat loads are considered the same. The information contained in this table is "representative" of Units 1 and 2. Refer to the applicable design calculations for the current heat loads. This table will not be revised to reflect current design bases heat loads. (b) Unit 1 computer room cooling load handled by supplemental computer room air conditioning units. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.4-10 Sheet 1 of 2 Revision 21 September 2013 DESIGN VALUES FOR AUXILIARY BUILDING VENTILATION SYSTEM Auxiliary Building Ventilation System (per unit) Mode 1: Building Ventilation 1 Supply fan Rating, cfm/fan 67,500 1 Exhaust fan Rating, cfm/fan 73,500 Item Heat Load, Btu/hr Lighting 286,500 Equipment, piping, and cables 780,200 Electric motors 526,300 TOTAL 1,593,000 Mode 2: Building and Engineered Safety Ventilation 2 Supply fans Rating, cfm/fan 67,500 2 Exhaust fans Rating, cfm/fan 73,500
Item Heat Load, Btu/hr Lighting 286,500 Equipment, piping, and cables 1,194,000 Electric motors 1,271,200 TOTAL 2,751,700 Mode 3: Engineered Safety Ventilation 1 Supply fan Rating, cfm/fan 67,500 1 Exhaust fan Rating, cfm/fan 73,500
Item Heat Load, Btu/hr Lighting 286,500 Equipment, piping, and cables 1,194,000 Electric motors 1,103,400 TOTAL 2,583,900 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.4-10 Sheet 2 of 2 Revision 21 September 2013 Fuel Handling Building Heating and Ventilation System (per unit) Mode 1, Mode 2, and Mode 3 (not including auxiliary feed pumps) 1 Supply fan Rating, cfm/fan 23,300
1 Exhaust fan Rating, cfm/fan 35,750
Item Heat Load, Btu/hr Lighting 114,700 Equipment, piping, and cables 245,500 Electric motors 209,000 TOTAL 569,200 Mode 1, Mode 2, and Mode 3 (including auxiliary feed pumps) 1 Supply fan Rating, cfm/fan 23,300
1 Exhaust fan Rating, cfm/fan 35,750
Item Heat Load, Btu/hr Lighting 114,700 Equipment, piping, and cables 245,500 Electric motors 352,900 TOTAL 713,100
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.4-11 Revision 20 November 2011 ESTIMATED NSSS HEAT LOSSES INSIDE CONTAINMENT Piping Btu/hr (x 106) Reactor Coolant System 0.09 Other Piping 0.04 Equipment Reactor Vessel(a) Above seal 0.037 Below seal 0.125 Reactor Coolant Pumps(b) 3.600 Steam Generators 0.800 Pressurizer(c) 0.133 Control Rod Drive Mechanisms(d) 2.260 Pressurizer Relief Tank 0.022 Primary Concrete Shield 0.015 Regenerative Heat Exchanger 0.022 Excess Letdown Heat Exchanger 0.010 Total 7.154 Contingency 1.106 Total(e) 8.260 (a) Does not include supports
(b) Each pump: motor - 0.75 x 106 Btu/hr; uninsulated section - 0.15 x 106 Btu/hr (c) Includes supports and heater terminal connections
(d) Includes heat losses from control rod drive mechanisms, and control rod penetration housings (e) The following heat losses have not been included
Heat losses from piping and equipment not considered part of NSSS Daily and seasonal ambient temperature changes Solar heat load Fan input power DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.4-12 Revision 11 November 1996 ESTIMATED TOTAL HEAT SOURCES INSIDE CONTAINMENT Heat Sources Btu/hr (x 106)
- a. Steam and feedwater lines 0.30
- b. Solar 0.10
- c. Control rod drive fans 0.35
- d. Ventilation fans (4 running) 2.94
- e. NSSS(a) 8.50
- f. Contingency for heat sources a, b, c, & d 0.37
Total 12.56
(a) The assumed NSSS sources of heat losses are shown in Table 9.4-11
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5-1 Revision 18 October 2008 FIRE PROTECTION SYSTEM COMPONENT DESIGN DATA Fire Pumps Number, shared 2 Type Horizontal centrifugal Rated capacity, gpm 1,500 Rated head, ft 290 Motor horsepower 200 Design pressure (casing), psig 175 Casing material Cast iron, Class 30
Carbon Dioxide System Number, shared 1 Type Packaged unit, low pressure CO2 Size, tons 7-1/2 Carbon dioxide Pressure, psig 300 Temperature, °F 0 Storage container Design pressure, psig 350 Operating pressure range, psig 295 - 305 Material Carbon steel Code ASME Section VIII, Division I Refrigeration unit Type Compressor and coil Motor horsepower 2 Vaporizer type Steam
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11A April 1997 TABLE 9.5-2 DIESEL GENERATOR FUEL OIL SYSTEM COMPONENT DESIGN DATA Storage Tanks Number, shared 2 Type Horizontal, underground Capacity, gal 50,000 Pressure Atmospheric Temperature Ambient ground temperature Material Carbon steel/fiberglass
Transfer Pumps Number, shared 2 Type Rotary, two-screw Viscosity range, ssu 35 - 100 Rated capacity, gpm 58 Discharge pressure, psig 50 Suction pressure, in Hg 20 Casing material Nodular iron Motor horsepower 5
Revision11November1996FIGURE 9.1-1 NEW FUEL STORAGE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 9.1-2 SPENT FUEL STORAGE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE UNACCEPTABLE FOR FUEL WITHEITHER PELLET DIAM.1.52.02.53.03.54.04.55050001000015000200002500030000350004000045000MINIMUM REQUIRED ASSEMBLY DISCHARGEBURNUP AS A FUNCTION OF INITIAL ENRICHMENT AND FUEL PELLET DIAMETER FOR AN ALL CELL STORAGE CONFIGURATION.INITIAL ENRICHMENT, WT% U-235ASSEMBLY DISCHARGE BURNUP, MWD/MTUMINIMUM BURNUP FOR FUEL WITH 0.3225 IN. PELLET DIAM.MINIMUM BURNUP FOR FUEL WITH 0.3088 IN. PELLET DIAM.ACCEPTABLE FOR FUEL WITHEITHER PELLET DIAM..0 Revision 16 June 2005FIGURE 9.1-2A BURNUP VS. ENRICHMENT (ALL CELL) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE 0500010000 1500020000 25000 300003500040000 450005000055000 600001.01.52.02.53.03.54.04.55.0Initial Enrichment, Wt% U-235Assembly Discharge Burnup, MWD/MTUACCEPTABLEUNACCEPTABLE MINIMUM REQUIRED ASSEMBLY DISCHARGE BURNUP AS A FUNCTION OF INITIAL ENRICHMENT FOR A 2X2 ARRAY STORAGE CONFIGURATION Revision 15 September 2003FIGURE 9.1-2B BURNUP VS. ENRICHMENT (2 X 2 ARRAY) UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE TOP LID LIFTING TRUNNION NEUTRON SHIELD (WATER) LEAD SHIELDING WATER JACKET POOL LID Revision 19 May 2010FIGURE 9.1-4 HI-TRAC 125D TRANSFER CASK UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008FIGURE 9.1-5 SPENT FUEL CASK RESTRAINT SPENT FUEL POOL UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010FIGURE 9.1-6 SPENT FUEL POOL TRANSFER CASK RESTRAINT CUP UNITS 1 AND 2 FSAR UPDATE Dimensions and elevations are estimates DIABLO CANYON SITE FIGURE 9.1-7 HEAVY LOAD HANDLING PATHS FOR THE TRANSFER CASK/MPC UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010 Revision 11 November 1996FIGURE 9.1-8 MANIPULATOR CRANE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 9.1-9 SPENT FUEL POOL BRIDGE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 9.1-10 NEW FUEL ELEVATOR UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 9.1-11 FUEL TRANSFER SYSTEM UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 9.1-12 ROD CLUSTER CONTROL CHANGING FIXTURE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 9.1-12a ROD CLUSTER CONTROL CHANGING TOOL UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 9.1-13 SPENT FUEL HANDLING TOOL UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 9.1-14 NEW FUEL ASSEMBLY HANDLING FIXTURE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE REACTOR VESSEL HEAD LIFT LUG CONNECTION LOCATIONS FIGURE 9.1-15 REACTOR VESSEL HEAD LIFT RIG ASSEMBLY UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 20 November 2011 Revision 11 November 1996 FIGURE 9.1-16 REACTOR INTERNALS LIFTING DEVICE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 9.1-17 REACTOR VESSEL STUD TENSIONER UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 9.1-18 FUEL HANDLING TOOL LOCATIONS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 9.1-19 MOVEABLE PARTITION WALLSLOCATION PLANS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010 V1S9Movable Partition Wall Panels (1 or 4)(As shown in place along bothCol. lines and )157203DetailShown onFig. 9.1-21Door Metal SidingPermanent Partition Wall(As shown along Col. line Opp. hd.along Col. line )203157Movable PartitionWall Monorails onPanels 1 & 4.Access DoorFin. Slab El. 140'-0" UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 9.1-20 MOVEABLE PARTITION WALLSELEVATION AT COLUMN LINE157 OR 203 Revision 19 May 2010 1/2" CLR.4"INSIDE FACE OF COL.C CRANE TRACKVERTICAL STOPMOVABLE WALLGIRDER3/4"T.O. CRANE RAILMOVABLE PARTITIONWALL MONORAILS, ONPANELS 1 & 4. FIGURE 9.1-21 MOVEABLE PARTITION WALLSDETAILS SHOWING WALL, TRACK, AND VERTICAL STOPRevision 19 May 2010UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 9.1-24 CASK WASHDOWN AREA RESTRAINTUNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010 PLAN AT ELEVATION (-) 31.5' Revision 12 September 1998FIGURE 9.2-2 ARRANGEMENT OF INTAKE STRUCTURE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 12 September 1998FIGURE 9.2-3 ARRANGEMENT OF AUXILIARY SALTWATER SYSTEM PIPING UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 9.3-5 FLOOR DRAIN UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 9.4-4 CONTAINMENT FAN COOLER UNITCONTAINMENT STRUCTURE UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 20 November 2011 Revision 11 November 1996 FIGURE 9.4-5 VENTILATION SYSTEM INTAKE STRUCTURE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 16 June 2005FIGURE 9.4-6 VENTILATION SYSTEM DIESEL GENERATION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 9.4-7 VENTILATION SYSTEM 4KV SWITCHGEAR ROOMS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 9.4-11 VENTILATION SYSTEMS CONTAINMENT PENETRATION AREA GE/GW UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE
FIGURE 9.5-1 TO BE WITHHELD FROM PUBLIC PER 10 CFR 2.390 AND SECY-04-0191.
FIGURE 9.5-2 TO BE WITHHELD FROM PUBLIC PER 10 CFR 2.390 AND SECY-04-0191.
FIGURE 9.5-3 TO BE WITHHELD FROM PUBLIC PER 10 CFR 2.390 AND SECY-04-0191. SUBSTA. DISPATCH VOICESUBSTA. DISPATCH VOICE SUBSTA. DISPATCH VOICEADMIN. VOICE GRADE #1-5ENERGY CONTROL DISPATCH TELEMETERING AND CONTROL (TO LOS BANOS)(TO MIDWAY) (TO GATES)(TO SFGO)(TO SFGO) (TO SFGO)DIABLOCANYONP.P.#1CIRCUITSTRANSFER TRIP RELAYINGTRANSFER TRIP RELAYINGPHASE ANGLE RELAYINGPHASE ANGLE RELAYINGDIABLO 500KV SWYD DATACOMM. EQUIP'T FAILURE ALARM (TO MIDWAY)(TO GATES)(TO MIDWAY)(TO GATES)(TO SFGO)(TO SFGO)DIABLOCANYON500KVSWYDCIRCUITSSUBSTA. DISPATCH VOICETRANSFER TRIP RELAYING PHASE ANGLE RELAYING MIDWAYSUBCIRCUITSSUBSTA. DISPATCH VOICETRANSFER TRIP RELAYINGPHASE ANGLE RELAYING GATESSUBCIRCUITSSUBSTA. DISPATCH VOICELOS BANOSENERGY CONTROL DISPATCHTELEMETERING AND CONTROLDIABLO 500KV SWYD DATAADMIN. VOICE GRADE #1-#5S.F.G.O.CIRCUITSTCCCOMM. EQUIP'T FAILURE ALARMFAIRFIELDCIRCUITSLEGENDMW TERMINALMW REPEATERWEST VALLEYMICROWAVE SYSTEMDIABLO CANYON500KV SWYDBLACK BUTTELAS YEGUASMIDWAY500KV SUBKETTLEMANGATES500KV SUB LOS BANOS 500KV SUBSANTA RITAHENRIETTAMONTEBELLORIDGESFGOFFIOCFIBERCABLEFIBERCABLE
FIGURE 9.5-5 PRIMARY COMMUNICATIONS SYSTEM UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 15 September 2003 DIABLO CANYON 500KV SWITCHYARD DATA (TO SFGO)500KVSWITCHYARDCIRCUITSENERGY CONTROL DISPATCH (TO SFGO)TELEMETERING AND CONTROL (TO SFGO) COMMUNICATIONS EQUIPMENT FAILURE ALARM TO (SFGO)DCPPUNIT 1CIRCUITSENERGY CONTROL DISPATCHTELEMETERING AND CONTROL DIABLO CANYON 500KV SWITCHYARD DATAADMIN. VOICE GRADE #1-5COMMUNICATIONS EQUIPMENT FAILURE ALARMSFGOCIRCUITSCOMMUNICATIONS EQUIPMENT FAILURE ALARMFFIOCCIRCUITSLEGENDMINIMUM POINT OF ENRTYCOMMON CARRIERFACILITIESDCPPSFGOFFIOCFIBERCABLEFIBERCABLECOMMONCARRIER
FIGURE 9.5-6 SECONDARY COMMUNICATIONS SYSTEM UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 15 September 2003 DCPP UNITS 1 & 2 FSAR UPDATE
APPENDIX 9.5A FIRE HAZARDS ANALYSIS
DCPP UNITS 1 & 2 FSAR UPDATE 9.5A-1 Revision 21 September 2013 APPENDIX 9.5A FIRE HAZARDS ANALYSIS
DISCUSSION Engineering analyses/calculations are the bases for this appendix and the means of implementing a post-fire safe shutdown. Therefore, any changes, deletions, or additions to the analyses/calculations are reviewed for impact on plant implementing procedures. Any changes, deletions, or additions to the implementing procedures are reviewed to ensure that compliance is maintained with the analyses/calculations. The Fire Hazards Analysis for each Appendix R fire area is comprised of six sections. A summary description for each section and an index to the analyses are provided below, followed by the analyses for the fire areas. 1.0 PHYSICAL CHARACTERISTICS This section provides a detailed description of the fire area/zone and the location and boundaries of the fire area/zone. The fire ratings are given for the barriers that make up the fire area/zone on the north, south, east, and west walls, as well as the floors and ceilings. This section also describes any penetrations and barrier configurations approved in Fire Hazards Appendix R Evaluations (FHAREs). 2.0 COMBUSTIBLES The combustible loading of the fire area/zone is described in this section. Both in situ and transient combustible materials present in the fire area/zone are documented in an itemized list. Each fire area/zone is categorized into an area of low, moderate, or high fire severity. These categories were derived from the fire duration that indicates the amount of time it would take for all of the combustible materials in the fire area/zone to completely burn assuming a fuel consumption rate of 80,000 Btu/hr-ft2. The itemized list of combustible materials is administratively controlled in PG&E Engineering Calculation M-824. The use of transient combustible materials within the power plant fire area/zones is strictly controlled in accordance with Inter-Departmental Administrative Procedure OM8.ID4, "Control of Flammable and Combustible Materials." Each fire area/zone is categorized by fire duration as follows:
- LOW: less than 60,000 Btu/ft2 (less than 45 minute)
- MODERATE: 60,000 to 160,000 Btu/ft2 (45 minutes to 2 hours)
- HIGH: over 160,000 Btu/ft2 (over 2 hours)
DCPP UNITS 1 & 2 FSAR UPDATE 9.5A-2 Revision 21 September 2013 These categories are more conservative than those referenced in the National Fire Protection Association (NFPA) Handbook, 14th edition, pages 6-79, British Fire Loading Studies. To be conservative, borderline cases are classified in the next higher category to allow for fluctuations. 3.0 FIRE PROTECTION This section describes the type of detection and suppression systems available to protect the fire area/zone. 4.0 SAFE SHUTDOWN This section identifies safe shutdown equipment that may be affected by a fire in each fire area/zone. 10 CFR 50, Appendix R, requires that fire damage be limited such that one train of safe shutdown equipment that is necessary to achieve and maintain hot shutdown is free from fire damage, and systems necessary to achieve and maintain cold shutdown are free from fire damage or can be repaired within 72 hours (10 CFR 50, Appendix R, Section III.G.1). Where cables or equipment of redundant trains of systems necessary to achieve and maintain hot shutdown conditions are located within the same area, then one of the following methods is provided to ensure that one train of safe shutdown components is free from fire damage (10 CFR 50, Appendix R, Section III.G.2): A. Outside Containment 1. Separation of redundant components by a 3-hour fire rated barrier 2. Separation of redundant components by a horizontal distance of more than 20 ft with no intervening combustible or fire hazards, in conjunction with the availability of fire detectors and an automatic fire suppression system in the fire area/zone 3. Enclosure of one train of redundant components in a 1-hour fire rated barrier, in conjunction with the availability of fire detectors and an automatic fire suppression system in the fire area/zone B. Inside Containment - one of the fire protection means specified above (for outside containment), or 1. Separation of redundant trains by a horizontal distance greater than 20 ft with no intervening combustibles or fire hazards, or 2. Detection and automatic suppression, or 3. Separation of redundant trains by a radiant energy shield. DCPP UNITS 1 & 2 FSAR UPDATE 9.5A-3 Revision 21 September 2013 Alternative or dedicated shutdown capability (see Appendix 9.5E) is provided (10 CFR 50, Appendix R, Section III.G.3 and III.L) where the protection of systems whose function is required for hot shutdown does not satisfy the requirements of categories A and B listed above. NRC approved deviations have been granted in cases where the requirements of 10 CFR 50, Appendix R, Section III.G have not been met. The NRC-approved deviations are described in SSERs 23 and 31. For some areas, a detailed evaluation is also documented in FHAREs.
In some cases, a manual action has been credited to mitigate fire damage to safe shutdown cables, to secure the non-credited train/system, or to align safe shutdown flowpaths for cooldown and transition to cold shutdown. The feasibility of performing the operator manual actions is documented in PG&E Engineering Calculations M-928 Appendix A, M-944, and M-1088. The use of manual actions is part of DCPP's original and current post-fire safe shutdown methodology for both III.G.2 and III.G.3 fire areas.[SAPN 50503925] 4.1 Spurious Automatic Actuation Signals Components that are required for postfire safe shutdown may be impacted by a spurious plant protection system (PPS) actuation. For example, a safety injection signal (SIS) results in automatically starting emergency core cooling system (ECCS) pumps and positioning valves. The auto position of the postfire safe shutdown components may or may not be in the required position credited in the compliance analysis. Because the input signals to the PPS are not identified as safe shutdown circuits in PG&E Engineering Calculation 134-DC and because multiple input signals will be required to complete the logics for a safety function initiation, operator actions are identified in Section I, Attachment 4, of Calculation 134-DC to override or defeat the spurious protection system signal. 4.2 Multiple Fire-Induced Spurious Actuations Because NRC guidelines on multiple fire-induced spurious operation are vague and have been interpreted differently throughout the industry, the compliance analysis has conservatively assumed multiple spurious actuations will occur for a given fire area. Operator actions have been identified to defeat each spurious actuation that could adversely affect safe shutdown. The ability to safely shut down the plant in the event of a fire in any fire area is evaluated using the safe shutdown logic diagrams documented in PG&E Engineering Calculation M-680 and M-928, and the evaluations are summarized in Section 4.0 for each fire area. DCPP UNITS 1 & 2 FSAR UPDATE 9.5A-4 Revision 21 September 2013
5.0 CONCLUSION
The conclusion section summarizes the methods of compliance used to achieve safe shutdown, as well as the fire protection features available in the fire area/zone to meet the requirements of 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
Throughout each fire area/zone discussion, there are references to calculations, FHAREs, approved Appendix R deviations, letters to the NRC, etc. This section gives the information that is necessary to retrieve these documents. DCPP UNITS 1 & 2 FSAR UPDATE INDEX TO FIRE HAZARD ANALYSES (UNIT 1) Fire Area Fire Zone Description Appendix R Area Page 9.5A-5 Revision 21 September 2013 1 1-A Containment, Annular Area X 9.5A-12 1-B Containment, Steam Generator Area X 9.5A-13 1-C Containment, Reactor Cavity and X 9.5A-13 Operating Deck 2 -- Auxiliary Boiler 3-B-1 -- RHR Pump and Hx Room X 9.5A-20 3-B-2 -- RHR Pump and Hx Room X 9.5A-24 3-BB -- Containment Penetration Area X 9.5A-28 3-H-1 -- Centrifugal Charging Pumps CCP1&2 Room X 9.5A-46 3-H-2 -- Centrifugal Charging Pump CCP3 Room X 9.5A-51 3-P-1 -- Ventilation Room 3-P-5 -- Ventilation Room 3-P-12 -- Ventilation Room 3-Q-1 -- Auxiliary Feedwater Pump Room X 9.5A-54 5-A-1 -- 480 V Vital Switchgear, F Bus X 9.5A-59 5-A-2 -- 480 V Vital Switchgear, G Bus X 9.5A-59 5-A-3 -- 480 V Vital Switchgear, H Bus X 9.5A-59 5-A-4 -- 480 V Nonvital Switchgear and Hot X 9.5A-74 Shutdown Panel Area 6-A-1 -- Battery, Inverter and DC Switchgear, X 9.5A-82 F Bus 6-A-2 -- Battery, Inverter and DC Switchgear, X 9.5A-82 G Bus 6-A-3 -- Battery, Inverter and DC Switchgear, X 9.5A-82 H Bus 6-A-4 -- Reactor Trip Switchgear X 9.5A-100 6-A-5 -- Electrical Area X 9.5A-105 7-A -- Cable Spreading Room X 9.5A-111 7-C -- Communications Room 8-G -- Safeguards Room - Unit 1 X 9.5A-122 10 -- 12-kV Switchgear Room X 9.5A-127 11-D -- Hallway Outside Diesel Generator Rooms X 9.5A-133 13-D -- Excitation Switchgear Room X 9.5A-138 13-E -- Switchgear Ventilation Fan Room X 9.5A-142 13-F -- Storage Room 14-B -- Clean and Dirty Lube Oil 15 -- Turbine Lube Oil Reservoir 17 -- Unit 1 and 2 Warehouse 26 -- Unit 1 and 2 Chemical and Gaseous Storage 27-A -- Boxed Waste Zone 27-B -- Drum Storage Zone DCPP UNITS 1 & 2 FSAR UPDATE INDEX TO FIRE HAZARD ANALYSES (UNIT 1) Fire Area Fire Zone Description Appendix R Area Page 9.5A-6 Revision 21 September 2013 27-C -- Contaminated Oil Storage 28 -- Unit 1 Main Transformer X 9.5A-147 30-A-1 -- Auxiliary Saltwater Pump 1-1 Vault X 9.5A-152 30-A-2 -- Auxiliary Saltwater Pump 1-2 Vault X 9.5A-152 35-A -- Diesel Fuel Oil Transfer Pump Vault X 9.5A-156 35-B -- Diesel Fuel Oil Transfer Pump Vault X 9.5A-156 AB-1 3-B-3 Boron Injection Tank, Unit 1 X 9.5A-159 3-F Containment Spray Pump, Unit 1 X 9.5A-164 3-J-1 Component Cooling Water Pump 1-1 X 9.5A-168 3-J-2 Component Cooling Water Pump 1-2 X 9.5A-168 3-J-3 Component Cooling Water Pump 1-3 X 9.5A-168 3-M Safety Injection Pump, Unit 1 3-Q-2 Motor-Driven Auxiliary Feedwater Pump, X 9.5A-176 Unit 1 FB-1 3-0 Fuel Handling Building 31 Fuel Handling Building X 9.5A-180 S-8 Stairwell S-9 Stairwell TB-1 11-A-1 Emergency Diesel Generator 1-1 X 9.5A-184 11-A-2 Emergency Diesel Generator 1-1 Radiator X 9.5A-184 TB-2 11-B-1 Emergency Diesel Generator 1-2 X 9.5A-184 11-B-2 Emergency Diesel Generator 1-2 Radiator X 9.5A-184 TB-3 11-C-1 Emergency Diesel Generator 1-3 X 9.5A-184 11-C-2 Emergency Diesel Generator 1-3 Radiator X 9.5A-184 TB-4 12-A 4.16-kV Cable Spreading Room X 9.5A-194 13-A 4.16-kV Switchgear Room, F Bus X 9.5A-194 TB-5 12-B 4.16-kV Cable Spreading Room X 9.5A-203 13-B 4.16 kV Switchgear Room, G Bus X 9.5A-203 TB-6 12-C 4.16 kV Cable Spreading Room X 9.5A-212 13-C 4.16 kV Switchgear Room, H Bus X 9.5A-212 TB-7 12-E Isophase Room X 9.5A-220 14-A Main Turbine Building X 9.5A-224 14-C Electrical Load Center 14-D Turbine Deck X 9.5A-232 14-E CCW Heat Exchangers X 9.5A-236 16 Machine Shop TB-14 -- Reverse Osmosis Area TB-15 -- Buttress Area Unit 1 V-1 3-P-2 Ventilation Room 3-P-3 Ventilation Room X 9.5A-241 3-P-4 Ventilation Room DCPP UNITS 1 & 2 FSAR UPDATE INDEX TO FIRE HAZARD ANALYSES (UNIT 1) Fire Area Fire Zone Description Appendix R Area Page 9.5A-7 Revision 21 September 2013 3-P-9 Ventilation Room V-2 3-P-6 Ventilation Room 3-P-7 Ventilation Room 3-P-8 Ventilation Room 3-P-10 Ventilation Room 3-P-11 Ventilation Room 3-P-13 Ventilation Room 4-A -- Counting and Chemical Laboratory X 9.5A-245 4-A-1 -- Chemical Lab Area, G Bus Compartment X 9.5A-262 4-A-2 -- Chemical Lab Area, H Bus Compartment X 9.5A-262 4-B -- Showers, Lockers and Access Control X 9.5A-273 4-B-1 -- G Bus Compartment X 9.5A-288 DCPP UNITS 1 & 2 FSAR UPDATE INDEX TO FIRE HAZARD ANALYSES (COMMON AREA) Fire Area Fire Zone Description Appendix R Area Page 9.5A-8 Revision 21 September 2013 4-B-2 -- H Bus Compartment X 9.5A-288 34 -- Outside Building El 140 ft X 9.5A-299 AB-1 3-A Liquid Holdup Tank Area X 9.5A-304 3-AA Auxiliary Building E1 115 ft - App. R Area X 9.5A-309 3-C Auxiliary Building E1 54, 64 and 73 ft X 9.5A-316 3-L Auxiliary Building E1 85 and 100 ft X 9.5A-325 3-R Spent Fuel Pool, Unit 1 3-S Fuel Handling Building E1 140 ft X 9.5A-332 3-W Spent Fuel Pool, Unit 2 3-X Auxiliary Building, E1 100 ft X 9.5A-336 8-B-1 Supply Fan Room 8-B-2 Supply Fan Room X 9.5A-344 S-2 Stairwell S-3 Stairwell X 9.5A-348 S-4 Stairwell X 9.5A-353 AB-2 8-B-5 Electrical Area/Ventilation Room 8-B-6 Electrical Area/Ventilation Room S-5 Stairwell AB-3 8-B-7 Electrical Area/Ventilation Room 8-B-8 Electrical Area/Ventilation Room S-1 Stairwell CR-1 8-A Unit 1 Computer Room X 9.5A-359 8-B-3 Unit 1 CR Ventilation Equipment Room X 9.5A-359 8-B-4 Unit CR Ventilation Equipment Room X 9.5A-359 8-C Control Room X 9.5A-359 8-D Unit 2 Computer Room X 9.5A-359 8-E Office X 9.5A-359 8-F Shift Technical Advisor Office X 9.5A-359 IS-1 30-A-5 Circulating Water Pump Room X 9.5A-370 30-B Intake Structure Control Room 3-CC -- Containment Penetration Area X 9.5A-374 3-D-1 -- RHR Pumps and Hx Room X 9.5A-392 3-D-2 -- RHR Pumps and Hx Room X 9.5A-396 3-I-1 -- Centrifugal Charging Pumps CCP1&2 Room X 9.5A-400 3-I-2 -- Centrifugal Charging Pump CCP3 Room X 9.5A-404 3-T-1 -- Auxiliary FW Pump Room X 9.5A-408 3-V-1 -- HVAC, Filters, Fans 3-V-5 -- HVAC, Filters, Fans 3-V-12 -- HVAC, Filters, Fans
DCPP UNITS 1 & 2 FSAR UPDATE INDEX TO FIRE HAZARD ANALYSES (UNIT 2) Fire Area Fire Zone Description Appendix R Area Page 9.5A-9 Revision 21 September 2013 5-B-1 -- 480 V Vital Switchgear, F Bus X 9.5A-412 5-B-2 -- 480 V Vital Switchgear, G Bus X 9.5A-412 5-B-3 -- 480 V Vital Switchgear, H Bus X 9.5A-412 5-B-4 -- 480 V Nonvital Switchgear and Hot X 9.5A-429 Shutdown Panel 6-B-1 -- Battery, Inverter, and X 9.5A-437 DC Switchgear, F Bus 6-B-2 -- Battery, Inverter, and X 9.5A-437 DC Switchgear, G Bus 6-B-3 -- Battery, Inverter, and X 9.5A-437 DC Switchgear, H Bus 6-B-4 -- Reactor Trip Switchgear X 9.5A-455 6-B-5 -- Electrical Area X 9.5A-460 7-B -- Cable Spreading Room X 9.5A-466 7-D -- Communications Room 8-H -- Safeguards Room X 9.5A-476 9 9A Containment Building, Annular Area X 9.5A-481 9B Containment Building, Steam Generator X 9.5A-481 Area 9C Containment Building, Reactor Cavity and X 9.5A-481 Operating Deck 18 -- Turbine Lube Oil Reservoir 20 -- 12-kV Switchgear Room and Cable X 9.5A-489 Spreading Room 22-C -- Corridor Outside Diesel Generator Rooms X 9.5A-495 24-D -- Excitation Switchgear Room X 9.5A-500 29 -- Unit 2 Main Transformer X 9.5A-505 30-A-3 -- Auxiliary Saltwater Pump Room X 9.5A-510 30-A-4 -- Auxiliary Saltwater Pump Room X 9.5A-510 33 -- Security Diesel Generator Room AB-1 3-D-3 Boron Injection Tank, Unit 2 X 9.5A-514 3-G Containment Spray Pump, Unit 2 X 9.5A-519 3-K-1 Component Cooling Water Pump 2-1 X 9.5A-522 3-K-2 Component Cooling Water Pump 2-2 X 9.5A-522 3-K-3 Component Cooling Water Pump 2-3 X 9.5A-522 3-N Safety Injection Pump, Unit 2 3-T-2 Motor Driven Auxiliary Feedwater Pump, X 9.5A-532 Unit 2 FB-2 3-U Fuel Handling Building 32 Fuel Handling Building X 9.5A-533 S-10 Stairwell DCPP UNITS 1 & 2 FSAR UPDATE INDEX TO FIRE HAZARD ANALYSES (UNIT 2) Fire Area Fire Zone Description Appendix R Area Page 9.5A-10 Revision 21 September 2013 S-11 Stairwell TB-7 19-A Main Turbine Building X 9.5A-529 19-B Electrical Load Center 19-C Oil Reclamation and Shortage Room 19-D Turbine Deck X 9.5A-536 19-E CCW Heat Exchangers X 9.5A-540 23-E Isophase Room X 9.5A-545 S-6 Stairwell TB-8 22-A-1 Emergency Diesel Generator 2-1 X 9.5A-558 22-A-2 Emergency Diesel Generator 2-1 Radiator X 9.5A-558 TB-9 22-B-1 Emergency Diesel Generator 2-2 X 9.5A-558 22-B-2 Emergency Diesel Generator 2-2 Radiator X 9.5A-558 TB-17 22-C-1 Emergency Diesel Generator 2-3 X 9.5A-558 22-C-2 Emergency Diesel Generator 2-3 Radiator X 9.5A-558 TB-10 23-A F Bus 4kV Cable Spreading Room X 9.5A-567 24-A F Bus 4kV Switchgear Room X 9.5A-567 TB-11 23-B G Bus 4kV Cable Spreading Room X 9.5A-575 24-B G Bus 4kV Switchgear Room X 9.5A-575 TB-12 23-C H Bus 4kV Cable Spreading Room X 9.5A-587 24-C H Bus 4kV Switchgear Room X 9.5A-587 TB-13 23-C-1 Corridor Outside 4kV Cable Spreading Room X 9.5A-595 24-E Switchgear Ventilation Fan Room X 9.5A-596 25 Operations Ready Room S-7 Stairwell X 9.5A-601 TB-16 -- Buttress Area Unit 2/Technical Support Center V-3 3-V-2 HVAC Room 3-V-3 HVAC Room X 9.5A-606 3-V-4 HVAC Room 3-V-9 HVAC Room V-4 3-V-6 HVAC Room 3-V-7 HVAC Room 3-V-8 HVAC Room 3-V-10 HVAC Room 3-V-11 HVAC Room 3-V-13 HVAC Room 36-A-1 ISFSI Storage Area 36-A-2 ISFSI Security Building Note: Fire hazard analyses are provided for 10 CFR 50, Appendix R, Fire Areas/Zones only. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 1 FIRE ZONES 1-A, 1-B, 1-C 9.5A-11 Revision 21 September 2013 FIRE AREA 1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Unit 1 Containment Building, El. 91 through 140 ft - containment annulus area.
1.2 Description Fire Area 1 is divided into three fire zones:
- 1-A Containment Annulus Area
- 1-B Reactor Steam Generator Area
- 1-C Reactor Cavity and Operating Deck Fire Zone 1-A is the annular region within containment between El. 91 ft and the operating deck at El. 140 ft. The annular region is bounded by the containment wall and the shield wall separating 1-A from 1-B.
Fire Zone 1-B is a cylindrical shaped region in the central part of containment. It is separated from Zone 1-A by the shield wall and from 1-C by the concrete operating deck. Fire Zone 1-C is comprised of the reactor cavity and the area above the reactor from El. 140 ft and above. The outer wall of this zone is the containment wall. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. 1.3.1 Fire Zone 1-A
- 3-hour rated containment barrier (outer wall)
- A nonrated reinforced concrete shield wall separates this zone from zone 1-B
- Nonrated openings and steel grating to 1-C
- A nonrated reinforced concrete shield ceiling separates this zone from 1-C
- Containment penetrations consisting of schedule 80 pipe sleeves at El. 115 ft to fire area 3-P-2 are in the area. The electrical conductors pass through a steel header plate and are encased in fire retardant epoxy. The space between the header plates is pressurized with nitrogen.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 1 FIRE ZONES 1-A, 1-B, 1-C 9.5A-12 Revision 21 September 2013 1.3.2 Fire Zone 1-B
- A nonrated reinforced concrete shield wall separates this zone from Zone 1-A.
- Nonrated reinforced concrete operating deck separates this zone from Zone 1-C. Nonrated opening, hatches, piping and ventilation penetrations are present.
1.3.3 Fire Zone 1-C
- 3-hour rated containment wall. NC
- Nonrated reinforced concrete separates this zone from Zones 1-A and 1-B. There are also nonrated openings into 1-B.
- Nonrated equipment and personnel hatches communicate through the containment wall (Ref. 6.8).
2.0 COMBUSTIBLES (for entire area)
2.1 Floor Area: 26,551 ft2 2.2 In situ Combustible Loading Materials
- Oil (in RCPs, cranes, fan cooler motors)
- Grease (in valve operators, cranes, fan cooler motors)
- Cable
- Charcoal
- HEPA filters
- Resin
- Rubber
- PVC
- Neoprene
- Plastics 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and PG&E Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 1 FIRE ZONES 1-A, 1-B, 1-C 9.5A-13 Revision 21 September 2013
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Fire Zone 1-A 3.1.1 Detection
- Smoke detection 3.1.2 Suppression
- Hose stations 3.2 Fire Zone 1-B 3.2.1 Detection
- Smoke detection above each RCP 3.2.2 Suppression
- Wet pipe automatic sprinklers over each RCP with remote annunciator
- Hose stations 3.3 Fire Zone 1-C 3.3.1 Detection
- Flame detection on operating deck 3.3.2 Suppression
- Hose stations DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 1 FIRE ZONES 1-A, 1-B, 1-C 9.5A-14 Revision 21 September 2013 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Fire Zone 1A 4.1.1 Chemical and Volume Control System Pressurizer auxiliary spray valves 8145 and 8148 may be affected by a fire in this area. Redundant valves 8107, 8108, or HCV-142 will remain available to prevent uncontrolled pressure reduction. A cold shutdown repair will allow manual initiation of auxiliary spray. (Ref 6.9) Prior to initiating auxiliary spray, block valve 8000C is closed to prevent spurious opening of PCV-456. Valves 8146 and 8147 may be affected by a fire in this area. An available seal injection flowpath will provide the required charging function. These valves can be manually closed in order to initiate auxiliary spray following a fire inside containment.
CVCS valves 8149A, 8149B, 8149C, LCV-459, and LCV-460 may be affected by a fire in this area. Valves 8149A, 8149B, and 8149C can be failed closed for letdown isolation. CVCS valves 8166, 8167, and HCV-123 may be affected by a fire in this area. Since HCV-123 fails closed in the event of a fire, excess letdown will remain isolated and safe shutdown is not affected. A fire in this area might result in the spurious closure of charging pump discharge flow control valve FCV-128. This valve can be opened from the control room after switching to manual control. 4.1.2 Emergency Power A fire in this area may result in a loss of power supplies associated with PY17N. Redundant power supply PY16 remains available. 4.1.3 Main Steam System Main steam system valves FCV-760, FCV-761, FCV-762, and FCV-763 may be affected by a fire in this area. The following redundant valves will remain available to isolate steam generator blowdown lines: FCV-151, FCV-250, FCV-154, FCV-248, FCV-157, FCV-246, FCV-160, and FCV-244. Therefore, safe shutdown is not affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 1 FIRE ZONES 1-A, 1-B, 1-C 9.5A-15 Revision 21 September 2013 A fire in this area may affect steam generator level for all four loops. Only one steam generator is necessary for safe shutdown. Therefore, steam generator level indication for SG 1-4, from LT-547 will remain available because it has been provided with a 1 hour fire wrap. (Ref. 6.10) 4.1.4 Reactor Coolant System RCS valves 8000A, 8000B, 8000C, and pressurizer PORVs PCV-455C, PCV-456, and PCV-474 may be affected by a fire in this area. Valves 8000A, 8000B and 8000C are required closed if the pressurizer PORVs are open during hot standby to prevent uncontrolled pressure reduction. A 1-hour fire wrap is provided on junction box BJX112 and penetration boxes BTX12E, BTX19E and BTX26E and conduits containing circuits are blocked to ensure the integrity of the circuits for the subject valves. Conduits containing circuits for the pressurizer PORVs are administratively blocked to prevent inclusion of other circuits that could spuriously open the valves. Since PCV-455C, PCV-456 and PCV-474 fail closed, uncontrolled pressure reduction will not occur due to a fire in this area. Auxiliary spray remains available for depressurization via a cold shutdown repair if the PORVs are not available. Prior to initiating auxiliary spray, block valve 8000C is closed to prevent spurious opening of PCV-456. RCS reactor vessel head vent valves 8078A, 8078B, 8078C and 8078D may be affected by a fire in this area. The valves can be failed closed for reactor coolant system isolation. Pressurizer level transmitters LT-406, LT-459, LT-460 and LT-461 may be affected by a fire in this area. Only one of the four level transmitters is required for safe shutdown. Since the LT-406 circuitry is separated from the LT-459 circuitry by 20 ft with no intervening combustibles, either one of these level transmitters will be available for safe shutdown. Source range monitors NE-31, NE-32, NE-51 and NE-52 may be affected by a fire in this area. Since NE-31 and NE-32 are separated by more than 20 ft with no intervening combustibles, one of these channels will be available to provide neutron flux indication. Therefore, safe shutdown will not be affected. RCS pressure transmitter, PT-406 may be affected by a fire in this area. PT-403 and PT-405 will remain available to provide RCS pressure indication. A fire in this area may fail PCV-455A and PCV-455B closed. Since these valves fail in the desired, closed position, safe shutdown is not affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 1 FIRE ZONES 1-A, 1-B, 1-C 9.5A-16 Revision 21 September 2013 Temperature indication on TE-413A, TE-413B, TE-423A, TE-423B, TE-433A, TE-433B, TE-443A and TE-443B may be affected by a fire. Due to the presence of 1-hour rated fire wraps, temperature indication on steam generator loops 3 and 4 will remain operational in the event of a fire. (Ref. 6.11) 4.1.5 Residual Heat Removal RHR valves 8701 and 8702 may be affected by a fire in this area. These valves are normally closed with power removed and will not spuriously operate. These valves can be manually operated to their safe shutdown position. 4.1.6 Safety Injection System SI valves 8808A, 8808B, 8808C and 8808D may be affected by a fire in this area. These valves can be manually closed for RCS pressure reduction. 4.2 Fire Zone 1B 4.2.1 Chemical and Volume Control System CVCS valves LCV-459 and LCV-460 may be affected by a fire in this area. Valves 8149A, 8149B and 8149C remain available to provide letdown isolation. 4.2.2 Emergency Power A fire in this area may result in a loss of power supplies associated with PY17N. Redundant power supply PY16 remains available. 4.2.3 Main Steam System Main steam system valves FCV-760, FCV-761, FCV-762 and FCV-763 may be affected by a fire in this area. The following redundant valves remain available to isolate steam generator blowdown lines: FCV-151, FCV-250, FCV-154, FCV-248, FCV-157, FCV-246, FCV-160 and FCV-244. Therefore, safe shutdown is not affected. 4.2.4 Reactor Coolant System RCS valves 8000A, 8000B, 8000C and pressurizer PORVs PCV-455C, PCV-456 and PCV-474 may be affected by a fire in this area. Valves 8000A, 8000B and 8000C, or the pressurizer PORVs, are required closed to prevent uncontrolled pressure reduction. Since PCV-455C, PCV-456 and PCV-474 fail closed in the DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 1 FIRE ZONES 1-A, 1-B, 1-C 9.5A-17 Revision 21 September 2013 event of a fire, uncontrolled pressure reduction will not occur. Auxiliary spray remains available. Therefore, safe shutdown is not affected. A fire in this area may affect instrument sensing lines for the following pressurizer level instruments: LT-459, LT-460, LT-461 and LT-406. These instrument sensing lines are either shielded by the pressurizer vessel or protected by a heat shield. No electrical circuitry for these instruments exists in this fire zone. Therefore, safe shutdown is not affected. A fire in this zone may affect instrument sensing lines for PT-406. This instrument is either shielded by the pressurizer vessel or protected by a heat shield. No electrical circuitry for this instrument exists in this fire zone. Therefore, safe shutdown is not affected. Source range monitors NE-31, NE-32, NE-51 and NE-52 may be affected by a fire in this area. Since NE-31 and NE-32 are separated by more than 20 ft with no intervening combustibles, one of these channels will be available to provide neutron flux indication in the event of a fire. Therefore, safe shutdown will not be affected. The following instrumentation for hot leg and cold leg temperatures: TE-413A, TE-413B, TE-423A, TE-423B, TE-433A, TE-433B, TE-443A and TE-443B may be affected by a fire in this area. TE-413A and TE-411B, and TE-423A and TE-423B, are separated by over 20 ft from TE-433A and TE-433B, and TE-443A and TE-443B, with no intervening combustibles. Therefore, safe shutdown will not be affected. RCS reactor vessel head vent valves 8078A, 8078B, 8078C, and 8078D may be affected by a fire in this area. The valves can be failed closed for reactor coolant system isolation. 4.2.5 Residual Heat Removal System RHR valve 8702 may be affected by a fire in this area. 8702 is normally closed with its power removed during normal operations and will not spuriously open. This valve can be manually operated to its safe shutdown position. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 1 FIRE ZONES 1-A, 1-B, 1-C 9.5A-18 Revision 21 September 2013 4.3 Fire Zone 1C 4.3.1 Reactor Coolant System RCS valves 8000A, 8000B, 8000C and pressurizer PORVs PCV-455C, PCV-456 and PCV-474 may be affected by a fire in this area. Valves 8000A, 8000B and 8000C are required closed if the pressurizer PORVs are open during hot standby to prevent uncontrolled pressure reduction. Since PCV-455C, PCV-456 and PCV-474 fail closed in the event of a fire, uncontrolled pressure reduction will not occur. Therefore, safe shutdown is not affected. Auxiliary spray will remain available for RCS pressure reduction. Source range monitors NE-31, NE-32, NE-51 and NE-52 may be affected by a fire in this area. Since NE-31 and NE-32 are separated by more than 20 ft with no intervening combustibles, one of these channels will be available in the event of a fire. Therefore, safe shutdown will not be affected. RCS reactor vessel head vent valves 8078A, 8078B, 8078C and 8078D may be affected by a fire in this area. The valves can be failed closed for reactor coolant system isolation.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the ability to achieve safe shutdown.
- Safe shutdown equipment utilized for safe plant shutdown are not adversely effected by a fire in this area due to spatial separation, installation of fire barriers, blocked conduits, or availability of redundant equipment.
- Automatic wet pipe sprinklers are provided over each RCP.
- Smoke detection is provided for Zone 1-A and above each RCP in Zone 1-B.
- Flame detection is provided on the operating deck of Zone 1-C.
- Manual firefighting equipment is provided for this area. An RCP lube oil collection system is provided for the RCPs in Zone 1-B. A deviation from the requirements of 10 CFR 50, Appendix R, Section III.0 was requested. This deviation was granted in SSER 23. For additional information, refer to Appendix 9.5C.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 1 FIRE ZONES 1-A, 1-B, 1-C 9.5A-19 Revision 21 September 2013 A deviation from the requirements of 10 CFR 50, Appendix R Section III.G.2 was requested in the report on 10 CFR 50, Appendix R Review because a non combustible radiant energy shield between redundant shutdown divisions was not provided when separation was less than 20 ft. A 1-hour rated fire barrier was provided and SSER 23 concluded that the modifications brought the area into compliance and that no deviation was required.
6.0 REFERENCES
6.1 Drawing Nos. 515569, 515570, 515571 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R, Rev. 1 6.3 Deleted in Revision 13. 6.4 Calculation M-824, Combustible Loading 6.5 Drawing 065126, Fire Protection Information Report, Unit 1 6.6 Report on 10 CFR 50, Appendix R Review 6.7 SSER 23, June 1984 6.8 NECS File: 131.95, FHARE:94, Containment Personnel Airlock Doors 6.9 NECS File: 131.95, FHARE:101, Separation of Pressurizer PORV and Auxiliary Spray Valve Circuits in the Containment Annular Area 6.10 NECS File: 131.95, FHARE:105, Non-Rated Mechanical Panels in Containment 6.11 DCP A-47568, Containment Fire Wrap Mods 6.12 Calculation 134-DC, Electrical Appendix R Analysis 6.13 Calculation M-928, 10 CFR 50, Appendix R Safe Shutdown Analysis DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-B-1 9.5A-20 Revision 21 September 2013 FIRE AREA 3-B-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This fire area is located at the northern end of the Unit 1 Auxiliary Building and occupies El. 54 ft through 115 ft. 1.2 Description This area contains residual heat removal pump 1-1 and RHR heat exchanger 1-1. The area extends upward to El. 115 ft to encompass the vertical heat exchanger shaft. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- 3-hour rated barrier separates this area from containment (El. 64 ft),NC Zone 3-B-3 (El. 73 ft), and Area 3-BB at higher elevations.
- A lesser rated penetration seal to Area 3-BB (El. 85 ft). (Ref. 6.13 and 6.15)
- A lesser rated penetration seal to Zone 3-B-3. (Ref. 6.13 and 6.15) South:
- 3-hour rated barrier separates this area from Zone 3-C (El. 54 ft and 64 ft), Area 3-H-1 (El. 73 ft),NC Zone 3-L and Area 4-A (El. 85 ft) and Zone 3-X and Area 5-A-4 (El. 100 ft).
- Over flow opening communicates to Zone 3-C (El. 54 ft). (Ref. 6.15)
- Ventilation opening without a fire damper communicates to Area 3-H-1 (El. 73 ft). (Ref. 6.15) East:
- 3-hour rated barrier separates this area from zone 3-B-3 (El. 54 ft and 64 ft), Areas 3-H-1 (El. 73 ft),NC 3-BB (El. 85 ft) and Zone 3-X (El. 100 ft).
- A 1-1/2-hour rated door communicates to Zone 3-B-3 (El. 64 ft). (Ref. 6.15)
- Duct penetration without a fire damper penetrates to Zone 3-B-3 (El. 64 ft). (Ref. 6.15)
- A lesser rated penetration seal to Zone 3-B-3. (Ref. 6.15)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-B-1 9.5A-21 Revision 21 September 2013
- A 3-hour-equivalent rated double door with a monorail cutout and water spray protection communicates to Zone 3-B-3 (El. 64 ft). (Ref. 6.14 and 6.15)
- An open doorway and security gate and nonrated penetrations to Area 3-H-1 (El. 73 ft). NC (Ref. 6.15)
- Duct penetration without a fire damper penetrates to Zone 3-X (El. 100 ft). (Ref. 6.15)
- A 2-hour rated plaster blockout panel communicates to Fire Zone 3-B-3. (Refs. 6.10 and 6.15)
West:
- 3-hour rated barrier separates this area from Zone 3-C (El. 64 ft), Zone 3-J-3 (El. 73 ft), and Areas 4-A-2 (El. 85 ft) and 5-A-4 (El. 100 ft).
- Duct penetration with no fire damper penetrates to Zone 3-C (El. 64 ft). (Ref. 6.15)
Floor/Ceiling:
- Ceiling: a 3-hour rated barrier with a 3-hour rated concrete equipment hatch communicates to Fire Zone 3-AA El. 115 ft on unprotected steel supports with unsealed gaps. (Refs. 6.8 and 6.9)
- Floor: a 3-hour rated barrier to grade. NC 2.0 COMBUSTIBLES
2.1 Floor Area: 706 ft2 2.2 In situ Combustible Materials
- Clothing/Rags
- PVC
- Grease
- Oil
- Misc. Class A Combustibles 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-B-1 9.5A-22 Revision 21 September 2013
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Partial smoke detection over the RHR pump and at the top of the heat exchanger (Ref. 6.6) 3.2 Suppression
- Water spray system for double door at El. 64 ft. (Ref. 6.3)
- Portable fire extinguishers in adjacent Zone 3-C
- Fire hose stations in adjacent Zone 3-C 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Residual Heat Removal System RHR pump 1-1 and Recirc Valve FCV-641A may be lost due to a fire in this area. RHR pump 1-2 and its Recirc Valve FCV-641B will be available to provide the RHR function.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Safe shutdown will not be affected by the loss of safe shutdown functions in this zone due to the availability of redundant equipment.
- Limited and dispersed combustible loading.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-B-1 9.5A-23 Revision 21 September 2013
- Smoke detection provided over RHR pump and heat exchanger.
- Manual fire fighting equipment is available for use.
The existing fire protection features provide a level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.2.
6.0 REFERENCES
6.1 DCPP Unit 1 review of 10 CFR 50, Appendix R (Rev. 1) 6.2 Drawing No. 515566, 515567, 515568, 515569 6.3 SSER 23, June 1984 6.4 Calculation M-824, Combustible Loading 6.5 Drawing 065126, Fire Protection Information Report, Unit 1 6.6 NECS File: 131.95, FHARE: 21, Evaluation Of Partial Smoke Detector Coverage 6.7 Deleted in Revision 13. 6.8 NECS File: 131.95, FHARE: 14, Concrete Equipment Hatches 6.9 PLC Report: Structural Steel Analysis for Diablo Canyon, Rev. 2 (7/08/86) 6.10 NECS File: 131.95, FHARE: 50, Plaster Block-out Panels in 3-hour Barriers 6.11 Calculation 134-DC, Electrical Appendix R Analysis 6.12 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.13 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.14 NECS File: 131.95, FHARE 159, Unrated Doors Protected by Local Automatic Sprinklers. 6.15 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-B-2 9.5A-24 Revision 21 September 2013 FIRE AREA 3-B-2 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This fire area is located at the northern end of the Unit 1 Auxiliary Building and occupies El. 54 ft through 115 ft. 1.2 Description This area contains residual heat removal pump 1-2 and RHR heat exchanger 1-2. The area extends upward to El. 115 ft to encompass the vertical heat exchanger shaft. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- A lesser rated penetration seal to Area 3-BB (El. 85 ft). (Refs. 6.14 and 6.16)
- 3-hour rated barrier separates this area from containment (El. 54 ft and 64 ft); NC Zones 3-B-3 and 3-F (El. 73 ft); and Area 3-BB at higher elevations.
- A lesser rated penetration seal to Zone 3-B-3. (Ref. 6.14 and 6.16) South:
- 3-hour rated barrier separates this area from Zone 3-C (El. 54 ft and 64 ft), Area 3-H-2 and 3-H-1 (El. 73 ft), Zone 3-L (El. 85 ft) and Zone 3-X (El. 100 ft).
- Ventilation penetrations with 3-hour rated fire damper communicate to Area 3-H-2 (El. 73 ft).
- Overflow opening communicates to Zone 3-C (El. 54 ft). (Ref. 6.16)
- Duct penetration with no fire damper penetrates to Zone 3-X. El. 100 ft (Ref. 6.16). East:
- 3-hour rated barrier separates this area from Zones 3-C (El. 64 ft), 3-F (El. 73 ft), 3-M (El. 85 ft), and 3-X (El. 100 ft).
- Three duct penetrations with no fire dampers penetrate to Zone 3-C (El. 64 ft). (Refs. 6.3 and 6.16)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-B-2 9.5A-25 Revision 21 September 2013
- One duct penetration with no fire damper penetrates to Zone 3-M (El. 85 ft). (Ref. 6.16)
West:
- 3-hour rated barrier separates this area from Zone 3-B-3 (El. 64 ft), Area 3-H-1 (El. 73 ft), and Zones 3-BB (El. 85 ft) and 3-X (El. 104 ft).
- Two duct penetrations with fire dampers penetrate to Zone 3-B-3 (El. 64 ft). (Ref. 6.16)
- A 1-1/2-hour rated door communicates to Zone 3-B-3 (El. 64 ft). (Ref. 6.16)
- A 3-hour-equivalent rated double door with a monorail cutout and water spray protection communicates to Zone 3-B-3 (El. 64 ft). (Ref. 6.15 and 6.16)
- Nonrated pipe penetrations to Area 3-H-1 (El. 73 ft). (Ref 6.16)
- A 3-hour rated door communicates to area 3-H-1 (El. 73 ft). (Ref 6.16)
- A 2-hour rated plaster blockout panel communicates to Zone 3-B-3. (Ref. 6.10 and 6.16)
- Lesser rated penetration seal to Zone 3-B-3 and 3-B-2. (Refs. 6.14 and 6.16) Ceiling:
- 3-hour rated barrier with a concrete equipment hatch communicating to Zone 3-AA (El. 115 ft). (Refs. 6.8 and 6.9)
Floor:
- 3-hour rated barrier to grade. NC 2.0 COMBUSTIBLES 2.1 Floor Area: 706 ft2 2.2 In situ Combustible Materials
- Clothing/Rags
- PVC
- Oil
- Grease
- Misc. Class A combustibles 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-B-2 9.5A-26 Revision 21 September 2013
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Partial smoke detection over the RHR pump and at the top of the heat exchanger. (Ref. 6.6) 3.2 Suppression
- Water spray system for double door at El. 64 ft. (Ref. 6.3)
- Portable fire extinguishers in adjacent zones.
- Fire hose stations in adjacent zones.
4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Residual Heat Removal System RHR pump 1-2 and Recirc Valve FCV-641B may be lost due to a fire in this area. RHR pump 1-1 and its Recirc Valve FCV-641A will be available to provide the RHR function.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-B-2 9.5A-27 Revision 21 September 2013
- Safe shutdown will not be affected by the loss of safe shutdown functions in this zone due to the availability of redundant equipment.
- Limited and dispersed combustible loading.
- Smoke detection provided over RHR pump and heat exchanger.
- Manual fire fighting equipment is available for use. The existing fire protection features provide a level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.2.
6.0 REFERENCES
6.1 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.2 Drawing No. 515566, 515567, 515568, 515569 6.3 SSER 23, June 1984 6.4 Calculation M-824, Combustible Loading 6.5 Drawing 065126, Fire Protection Information Report, Unit 1 6.6 NECS File: 131.95, FHARE 21, Evaluation of Partial Smoke Detection Coverage 6.7 Deleted in Revision 13 6.8 NECS File: 131.95, FHARE: 14, Concrete Equipment Hatches 6.9 PLC Report: Structural Steel Analysis for Diablo Canyon, Rev. 2 (7/08/86) 6.10 NECS File: 131.95, FHARE: 50, Plaster Block-out Panels in 3-hour Barriers 6.11 NECS File: 131.95, FHARE: 136, Unrated HVAC Duct Penetrations 6.12 Calculation 134-DC, Electrical Appendix R Analysis 6.13 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.14 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.15 NECS File: 131 .95, FHARE 159, Unrated Doors Protected by Local Automatic Sprinklers. 6.16 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-BB 9.5A-28 Revision 21 September 2013 FIRE AREA 3-BB 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This fire area is the Unit 1 containment penetration area and is located between Unit 1 Containment Building and Auxiliary Building on El. 85 ft through 115 ft. 1.2 Description Fire Area 3-BB is the electrical and mechanical penetration area for the containment. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. El. 85 ft North:
- 3-hour rated barrier to containment building with an 8-inch seismic and vent gap separation. (Ref. 6.25)
- Ventilation louvers without fire dampers that communicate with the exterior (Fire Area 28). NC (Ref. 6.25)
South:
- 3-hour rated barrier to Fire Areas 3-B-1, 3-B-2, 4-A, 4-A-1, 4-A-2, and Zones 3-L and 3-M.
- Duct penetrations without fire dampers to Fire Areas 4-A-1 and 4-A-2. (Ref. 6.25)
- Lesser rated penetration seals to Fire Zones 3-L, 3-M, 4-A-2, 3-B-1, and 3-B-2. (Refs. 6.21and 6.25)
- A 1-1/2-hour rated door to Fire Zone 3-L. (Ref. 6.25)
- A 1-1/2-hour rated door to Fire Zone S-3. (Ref. 6.25) East:
- 3-hour rated barriers to below grade, NC Fire Zones S-3 and Fire Area 3-B-2.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-BB 9.5A-29 Revision 21 September 2013 West:
- 3-hour rated barrier to Fire Zone 14-A, and Fire Area 3-B-1.
- A 3-hour rated double door to Fire Zone 14-A.
- Three 3-hour rated fire dampers to Fire Zone 14-A.
- Penetration to Fire Zone 14-A. (Ref. 6.13 and 6.25)
- Lesser rated penetration seals to Fire Zone 14-A. (Ref. 6.21 and 6.25) Floor:
- 3-hour rated barrier to Zones 3-J-3, 3-B-3, 3-F and to grade. NC
- Lesser rated penetration seal to Zone 3-J-3, 3-B-3, and 3-H-1. (Ref. 6.21 and 6.25) Ceiling:
- Concrete slab with nonrated penetrations to the 100-ft elevation of 3BB. NC (Ref. 6.5)
- 3-hour rated barrier to Fire Zone 3-X.
El. 100 ft North:
- 3-hour rated barrier to containment building with an 8-inch seismic and vent separation. (Ref. 6.25)
- 3-hour rated barrier to fire zone 3-R with the exception of an 8-inch seismic gap.
- Ventilation louvers without fire dampers that communicate with the exterior (Fire Area 28). NC (Ref. 6.25) South:
- 3-hour rated barrier to Fire Areas 3-B-1, 3-B-2, 5-A-1, 5-A-2, 5-A-3 and 5-A-4 and Zone 3-X.
- Unrated structural gap seal to Fire Zone 3-X. (Ref. 6.20)
- Lesser rated penetration seals to Fire Zone 3-X. (Ref. 6.21)
- A 1-1/2-hour rated door to Fire Zone 3-X. (Ref. 6.25) East:
- 3-hour rated barrier to Fire Zones 3-0, 3-Q-2 and 3-R.
- A 1-1/2-hour rated door to Fire Zone 3-Q-2. (Ref. 6.25)
- Lesser rated penetration seals to Fire Zone 3-0 and 3-Q-2. (Ref. 6.21)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-BB 9.5A-30 Revision 21 September 2013 West:
- 3-hour rated barrier to Fire Zone 14-A.
- 3-hour rated door to Fire Zone 14-A.
Floor/Ceiling:
- Concrete slab with nonrated penetrations to the same fire area. NC (Ref. 6.5) El. 115 ft North:
- 3-hour rated barrier to containment building with an 8-inch seismic and vent separation. (Ref. 6.25)
- Ventilation louvers without fire dampers that communicate with the exterior (Fire Area 28). NC (Ref. 6.25)
- A nonrated barrier to Fire Zone 3-P-2. NC (Ref. 6.14) South:
- 3-hour rated barrier to Fire Areas 6-A-1, 6-A-2, 6-A-3, 6-A-4, and 7-A, and Fire Zone 3-AA.
- A 1-1/2-hour rated door to Fire Zone 3-AA. (Ref. 6.25)
- A lesser rated penetration seal to Fire Zone 3-AA. (Ref. 6.21)
- A nonrated penetration to Fire Zone 7-A. (Ref. 6.17) East:
- 3-hour rated barrier to Fire Zone 3-R.
- A 1-1/2-hour rated door to Fire Zone 3-R. (Ref. 6.25) West:
- 3-hour rated barrier to Fire Zone 14-A.
- Lesser rated penetration seals to Fire Zone 14-A. (Ref. 6.21)
- Nonrated blowout panels, which communicate with the main-steam pipe tunnel, Fire Zone 14-A, that have closed head water spray on the turbine building side. (Ref. 6.5, 6.22, 6.23, 6.24, and 6.25)
- A 3-hour-equivalent rated door to Fire Zone 14-A, with water spray on the turbine building side. (Ref. 6.24)
- Nonrated main steam line penetration with water spray on the turbine building side. (Refs. 6.11 and 6.25)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-BB 9.5A-31 Revision 21 September 2013 Floor:
- Concrete slab with nonrated penetrations to the same fire area. NC (Ref. 6.5) Ceiling:
- 3-hour rated barrier. NC
- Unsealed pipe penetrations and a seismic gap communicate with Fire Area 34 (outside roof area) at El. 140 ft. (Ref. 6.25) Protective
Enclosure:
- A fire resistive enclosure with an approximate fire rating of 3 hours, although 1 hour is committed, for several conduits and pull boxes. (Refs. 6.9, and 6.16)
- Cables essential for safe shutdown pass through three concrete vaults (one for each vitality) in the southwest corner of the fire area at El. 85 ft. The vault walls extend above 85 ft floor level to form an 8-inch curb. The curb around the vaults reduces the possibility of combustible fluid leakage into the vaults due to a spill on the floor. The vaults are covered with 3/8-inch thick metal plates. One foot thick concrete walls provide sufficient separation between redundant cables in adjacent vaults. As discussed in Section 2 below, due to the negligible fixed combustibles at El. 85 ft and the unlikelihood of transient combustibles being present in the area, propagation of fire into the vaults is precluded. A deviation to the requirements of Appendix R, Section III.G.2 was approved for this configuration in SSER 23 (Refs. 6.5 and 6.19).
- A deviation to the requirements of Appendix R, Section III.G.2 was made based on the existing construction of the vaults which includes the concrete walls, the 3/8-inch checker plate covers, and the curb located around the vaults (Refs. 6.5 and 6.19).
(Note: The containment electrical assembly is not a tested configuration. (Ref. 6.10))
2.0 COMBUSTIBLES
2.1 Floor Area: 6900 ft (For each elevation) 2.2 In situ Combustible Materials ELEVATION: 85 ft 100 ft 115 ft
- Oil
- Cable
- Cable
- Cable
- Grease
- Grease DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-BB 9.5A-32 Revision 21 September 2013 ELEVATION: 85 ft 100 ft 115 ft
- Rubber
- Rubber
- Rubber
- Clothing/Rags* Miscellaneous
- Neoprene
- Paper
- Polyethylene
- Polyethylene
- PVC
- Oil
- Plastic
- Wood
- Clothing/Rags
- Paper
- Plastic 2.3 Transient Combustible Materials (total for all 3 elevations)
Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity (for all 3 elevations)
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Partial smoke detection at each elevation of this zone.
(1) El. 85 ft - post-LOCA only (2) El. 100 ft - at tray only (3) El. 115 ft - at tray only (Ref. 6.8)
3.2 Suppression
- Wet pipe automatic sprinkler protection throughout El. 100 and 115 ft.
- A closed head sprinkler to spray the blowout panels and adjacent door (El. 115 ft).
- Portable fire extinguishers.
- Fire hose stations.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-BB 9.5A-33 Revision 21 September 2013 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Fire Zone 3BB - 85 ft 4.1.1 Auxiliary Feedwater A fire in this area may affect LCV-106, LCV-107, LCV-110, and LCV-111. Redundant valves LCV-113 and LCV-115 will remain available from AFW Pp 1-3 to steam generator Loops 3 and 4, respectively. 4.1.2 Component Cooling Water A fire in this area may spuriously close FCV-364 and FCV-365. These valves can be manually opened in order to provide CCW to the RHR heat exchangers. 4.1.3 Containment Spray Containment spray pump 1-2 may spuriously operate due to a fire in this area. Since valve 9001B will remain closed, this will not affect safe shutdown. Containment pressure transmitter cables run through this zone and could cause a spurious CS actuation signal. Open knife switches and open breakers 52-HG-07 and 52-HH-09 to prevent CS pump operation. 4.1.4 Chemical and Volume Control System A fire in this area may affect valves 8108 and HCV-142. Since redundant components (valves 8107, or 8145 and 8148) will remain available to isolate auxiliary spray. The charging injection flow path will remain available for RCS make-up. Safe shutdown is not affected. Valves LCV-112B and LCV-112C may spuriously close or become nonfunctional due to a fire in this area. Charging pump suction path may be transferred to the Boric Acid Transfer System by automatically opening valve 8104 to either Boric Acid Transfer Pump 1-1 or 1-2. Valves SI-8805A and SI-8805B may also be affected by a fire in this area. The running charging pump can be tripped from the control room to prevent cavitation and a charging pump restarted after aligning the RWST valves and isolating the volume control tank (VCT) supply valves. Valve SI-8805A or SI-8805B can be manually opened to provide water from the RWST to the charging pump suction. If necessary, valve LCV-112B or LCV-112C can be manually closed in order to isolate the volume control tank. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-BB 9.5A-34 Revision 21 September 2013 4.1.5 Emergency Power A fire in this area may disable the diesel generator 1-1 automatic transfer circuit. Manual control will remain available in the control room to transfer and load the diesel generator. In addition, offsite power will remain available for safe shutdown. 4.1.6 Main Steam System A fire in this area may spuriously close FCV-95 which will result in the loss of AFW pump 1-1. Redundant AFW pump 1-3 will remain available for safe shutdown to steam generators 1-3 and 1-4. Pressure indication PT-514 may be lost due to a fire in this area. Indication from PT-515 and PT-516 will remain available. 4.1.7 Main Feed System A fire in this area may affect 4-20mA DC control cables, which affect valves FCV-510, FCV-520, FCV-530, FCV-540, FCV-1510, FCV-1520, FCV-1530, and FCV-1540 and result in failure to isolate MFW. The MFW pumps are not affected in this fire area and can be tripped to isolate MFW flow to the steam generators. 4.1.8 Reactor Coolant System RCS pressure indication PT-403 and PT-405 may be lost due to a fire in this area. PT-406 will remain available to provide RCS pressure indication. 4.1.9 Residual Heat Removal System A fire in this area may affect RHR Pump 1-2 recirculation valve FCV-641B resulting in loss of control and spurious operation. Redundant RHR pump 1-1 will be available along with redundant RHR pump recirculation valve FCV-641A. 4.1.10 Safety Injection System A fire in this area may prevent the operation of valves 8805A and 8805B. The BASTs will be available to provide RCS make-up until these valves can be manually opened to provide RWST water to the charging pumps. Manual valves 8460A, 8460B, 8476, and 8471 will need to be opened to align the BAST flowpath to the charging pump suction. Charging pump suctions may be transferred to the Boric Acid Transfer System by automatically opening valve 8104 to either Boric Acid Transfer Pump 1-1 or 1-2 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-BB 9.5A-35 Revision 21 September 2013 4.2 Fire Zone 3BB -100 ft 4.2.1 Auxiliary Feedwater A fire in this area may affect the following AFW valves: LCV-106, 107, 108, 109, 110, 111, 113, and 115. Steam generator 1-2 is credited for shutdown in this area because of availability of SG level, SG pressure and RCS temperature indicators on that loop. Manual action can be performed to locally align LCV-111 using AFW Pump 1-2, and LCV-110 can also be manually aligned to provide flow to a second steam generator. 4.2.2 Component Cooling Water A fire in this area may spuriously close FCV-357and isolate RCP seal cooling. Seal injection will be available for RCP seal cooling. Valves FCV-364 and FCV-365 may spuriously close due to a fire in this area. Either of these two valves can be manually opened to provide CCW to the RHR heat exchangers.
CCW Header C flow transmitter (FT-69) may be affected by a fire in this area. Flow in header C is not credited, therefore loss of flow indication will not affect safe shutdown. 4.2.3 Containment Spray Containment spray pump 1-2 may spuriously operate due to a fire in this area. Since valve 9001B will remain closed, this will not affect safe shutdown. 4.2.4 Chemical and Volume Control System A fire in this area may affect valves 8104 and FCV-110A. The RWST valves 8805A and 8805B will remain available to provide boration and makeup capability. A fire in this area might result in the spurious closure of charging pump discharge flow control valve FCV-128. This valve can be opened from the control room after switching to manual control. Valves 8107 and 8108 may be affected by a fire in this area. These valves will fail in the desired, open position. Redundant valves will be available to isolate auxiliary spray in hot standby. A fire in this area may affect valves 8145, and HCV-142. Either valves 8145 and 8148 or HCV-142 are required closed in order to isolate auxiliary spray. A deviation in SER 23 was approved for this area to the extent that one shutdown DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-BB 9.5A-36 Revision 21 September 2013 division will remain free of fire damage. HCV-142 will remain available for auxiliary spray isolation since the cable is located in a conduit that is administratively blocked to prevent inclusion of other circuits that could spuriously operate HCV-142. Valve 8148 will remain available for pressure reduction. Valves 8146 and 8147 may be affected by a fire in this area. Since redundant components exist and these valves can be manually operated, safe shutdown is not affected. A fire in this area may spuriously open valves 8149A, 8149B, 8149C, LCV-459 and LCV-460. Either valves LCV-459, LCV-460 or valves 8149A, 8149B and 8149C must be closed for letdown isolation. Operator action can be taken to fail 8149A, 8149B, and 8149C closed. Therefore, safe shutdown is not affected. A fire in this area may spuriously open valves 8166 and 8167 and fail HCV-123 open. Circuits associated with valve HCV-123 are either embedded in the ceiling or protected with a fire barrier having an approximate fire rating of 3 hours, although only 1 hour is required, and the valve can be closed for excess letdown isolation. Therefore, safe shutdown will not be affected. A fire in this area may cause HCV-142 to fail open. This valve is required operational for a fire in this area to provide auxiliary spray isolation. The circuits for HCV-142 are located in dedicated conduit and will remain available. Valves LCV-112B and LCV-112C may be affected by a fire in this area. The running charging pump can be tripped from the control room to prevent cavitation and a charging pump restarted after aligning the RWST valves and isolating the VCT supply valves. These valves can be manually closed to isolate the volume control tank. A fire in this area may affect circuits associated with flow transmitter, FT-128 and pressure transmitter, PT-142. Loss of charging pump header flow and pressure indication will not affect safe shutdown. A fire in this area may affect circuits associated with letdown flow transmitter, FT-134. Operator action is credited to isolate letdown flowpath. FT-134 will not be available for diagnosis of loss of letdown flow. A fire in this area may affect equipment and circuits associated with VCT level transmitter, LT-112. This instrument is credited for diagnosis of failure of VCT discharge valves LCV-112B and LCV-112C in the open position. The RWST supply valves are not affected in this area and would be available for safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-BB 9.5A-37 Revision 21 September 2013 4.2.5 Emergency Power A fire in this area may disable diesel generator 1-1 automatic transfer circuit. Manual control will remain available in the control room to transfer and load the diesel generator. In addition, offsite power is not affected in this area and will remain available. 4.2.6 Main Feed System A fire in this area may affect 4-20mA DC control cables, which affect valve FCV-510 and result in failure to isolate. The MFW pumps can be tripped from the control room to isolate MFW flow to the steam generators. 4.2.7 Main Steam System A fire in this area may spuriously open FCV-151, 154, 157, 160, 244, 246, 248, 250, 760, 761, 762 and 763. Operator action can be taken to fail FCV-151, 154, 248, 250, 762 and 763 closed to isolate steam generator blowdown. A fire in this area may prevent closing of FCV-41, FCV-42 and FCV-43 and may spuriously open FCV-24 and FCV-25. Operator action taken to fail SGBD valves FCV-762 and FCV-763 closed will also isolate power to FCV-43, and FCV-44. These valves can be manually closed to control reactor coolant system temperature. A fire in this area may spuriously close FCV-95 which would disable AFW pump 1-1. However, redundant AFW pumps 1-2 and 1-3 will remain available. A fire in this area may result in the loss of level and pressure indication for all four steam generators. The separation between the exposed conduits for two of the four redundant trains of level indication (LT-517, LT-527, LT-537, LT-547 and LT-519, LT-529, LT-539 and LT-549) is at least 40 ft with no intervening combustibles. In addition, circuits associated with LT-519 and LT-549 are protected with a fire barrier having an approximate fire rating of 3 hours, although only 1 hour is committed, and will be available. Smoke detection and automatic sprinklers are also present which satisfies the separation requirement of Appendix R. The conduits containing circuits for steam generator pressure indicators PT-526, PT-534, PT-535, PT-536, PT-544 and PT-545 are embedded in the ceiling. The exposed pull box covers for conduits containing circuits associated with PT-526, PT-536, PT-535 and PT-545 are protected by a fire barrier having an approximate fire rating of 3 hours, although only 1 hour is committed. Therefore, one train of pressure indication will remain available. A fire in this area may affect circuits which prevent operation of the 10 percent dump valves PCV-19 and PCV-20. These valves can be manually operated to ensure safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-BB 9.5A-38 Revision 21 September 2013 4.2.8 Reactor Coolant System Pressurizer PORVs (PCV-455C, 456 and 474) and blocking valves (8000A, 8000B and 8000C) may be affected by a fire in this area. The circuits for the PORVs are not routed with other circuits. Therefore, hot shorts are not credible. Since the PORVs will not spuriously open, uncontrolled pressure reduction will not occur. Auxiliary spray will remain available for RCS pressure reduction if the PORVs fail closed. A fire in this area may affect pressurizer level indication (LT-406, LT-459, LT-460 and LT-461). The circuits associated with LT-460 are protected with a 1-hr fire barrier and will be available. The Appendix R separation requirements for LT-459 and LT-461 are satisfied because they are partially embedded in the ceiling of El. 100 ft and, when exposed, are separated by 40 ft with no intervening combustibles. This configuration, along with the detection and suppression systems, was approved in SSER 23. Therefore, safe shutdown is not affected. RCS pressure indication from PT-403, PT-405 and PT-406 may be lost due to a fire in this area. Only one pressure transmitter is necessary for safe shutdown. The conduit and associated pull-box cover for PT-403 is protected by a fire barrier with a fire rating of approximately 3 hours, although a 1 hour barrier was committed. This configuration, along with the area-wide suppression and partial detection systems, was approved in SSER 23. A fire in this area may affect temperature indication circuits TE-413A, TE-413B, TE-433A, TE-433B, TE-443A and TE-443B. TE-423A and TE-423B are not affected at El. 100 ft, therefore, SG 1-2 will be available for cooldown. A fire in this area may cause the loss of indication from NE-51 and NE-52. Redundant components NE-31 and NE-32 will remain available. A fire in this area may affect valves PCV-455A and PCV-455B. Since these valves fail in the desired, closed position, safe shutdown is not affected. 4.2.9 Residual Heat Removal System A fire in this area may affect valves 8701 and 8702. These valves have their power removed during normal operations and will not spuriously open. 8701 and 8702 can be manually open for RHR operations. 4.2.10 Safety Injection System A fire in this area may affect valves 8801A and 8801B. Redundant valves 8803A and 8803B can be closed to isolate the diversion flowpath. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-BB 9.5A-39 Revision 21 September 2013 A fire in this area might prevent the refueling water supply valves 8805A and 8805B from auto opening on low VCT level. However, manual operation of these valves, from the control room, remains available. A fire in this area may affect accumulator isolation valves 8808A, 8808B, 8808C and 8808D. These valves can be manually closed to ensure safe shutdown. 4.2.11 HVAC HVAC equipment S-44 and E-44 may be lost due to a fire in this area. Redundant HVAC equipment S-43 and E-43 will be available to provide necessary HVAC support. 4.3 Fire Zone 3BB - 115 ft 4.3.1 Auxiliary Feedwater A fire in this area may affect valves LCV-108, LCV-109, LCV-113 and LCV-115. Redundant valves LCV-110 and LCV-111 will remain available to align AFW flow to steam generators 1-1 and 1-2 via AFW Pump 1-2. In addition, AFW flow to steam generators 1-3 and 1-4 can be provided by manually operating these valves. 4.3.2 Component Cooling Water A fire in this area may spuriously close valves FCV-364 and FCV-365. Manual action may be necessary to open these valves. A fire in this area may affect circuits associated with CCW flow transmitter for Header C, (FT-69). This Instrument is credited to indicate a loss of CCW flow. Loss of the indicator will not affect CCW flow to C header and will not affect safe shutdown. 4.3.3 Containment Spray Containment spray pump 1-2 may spuriously operate due to a fire in this area. However, the corresponding discharge valve, 9001B will remain closed. Therefore, the spurious containment spray pump operation has no impact on safe shutdown. Containment pressure transmitter cables run through this zone and could cause a spurious CS actuation signal. Open knife switches and open breakers 52-HG-07 and 52-HH-09 to prevent CS pump operation. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-BB 9.5A-40 Revision 21 September 2013 4.3.4 Chemical and Volume Control System A fire in this area may affect valves 8104 and FCV-110A. Valve 8104 can be manually opened in order to provide boric acid to the charging pumps. Valves 8145 and 8148 may be affected by a fire in this area. Cold shutdown repair action can be taken to manually operate valve 8145 for RCS depressurization, and redundant valves will be available to isolate auxiliary spray. Therefore, safe shutdown is not affected. A fire in this area might result in the spurious closure of charging pump discharge flow control valve FCV-128. This valve can be opened from the control room after switching to manual control. Valves 8146 and 8147 may be affected by a fire in this area. These valves can be manually operated to provide pressurizer spray capability. A fire in this area may spuriously open valves 8149A, 8149B, 8149C, LCV-459 and LCV-460. Operator action can be taken to fail 8149A, 8149B, and 8149C. A fire in this area may spuriously open valves 8166, 8167 and fail close HCV-123. One of these valves is required closed to isolate excess letdown. Since HCV-123 fails closed when its associated supply breaker is opened, safe shutdown will not be affected. Valve HCV-142 may spuriously open due to a fire in this area. However, safe shutdown is not affected since this valve fails in the desired, open position when using auxiliary spray. CCW to the RCP thermal barrier Heat exchanger will remain available to provide seal cooling. Valves LCV-112B and LCV-112C may be affected by a fire in this area. The running charging pump can be tripped from the control room to prevent cavitation, and a charging pump restarted after opening the RWST supply valve and isolating the VCT supply. These valves can be manually closed in order to isolate the volume control tank. If these valves are closed, then valve 8805A or 8805B must be opened to provide water to the charging pumps from the RWST. A fire in this area may affect circuits associated with flow transmitter, FT-128 and pressure transmitter, PT-142. Loss of charging pump header flow and pressure indication will not affect safe shutdown. A fire in this area may affect circuits associated with letdown flow transmitter, FT-134. Operator action is credited to isolate letdown flowpath. FT-134 will not be available for diagnosis of loss of letdown flow. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-BB 9.5A-41 Revision 21 September 2013 A fire in this area may affect equipment and circuits associated with VCT level transmitter, LT-112. This instrument is credited for diagnosis of failure of VCT discharge valves LCV-112B and LCV-112C in the open position. The RWST supply valves are not affected in this area and will remain available for safe shutdown. 4.3.5 Emergency Power A fire in this area may disable diesel generator 1-1 automatic transfer circuit. Manual control will remain available in the control room to transfer and load the diesel generator. In addition, offsite power is not affected in this area and will remain available. 4.3.6 Main Steam System A fire in this area may spuriously open valves FCV-151, 154, 157, 160, 244, 246, 760, 761, 762 and 763. Operator action can be taken to fail FCV-151, 154, 248, 250, 762 and 763 closed to isolate steam generator blowdown. A fire in this area may affected valves FCV-43, FCV-44, FCV-22, FCV-23 and FCV-25. Manual action can be taken to close these valves. A fire in this area may spuriously close FCV-95 which will disable AFW pump 1-1. However, AFW pumps 1-2 will remain available. Level and pressure indications for all four steam generators may be lost due to a fire in this area. The separation between the conduits for two of the four redundant trains of level transmitters (LT-517, 527, 537, 547 and LT-519, 529, 539, 549) is 40 ft with no intervening combustibles. Since suppression and detection systems are provided, the separation requirement of Appendix R is satisfied. The circuits for steam generator 1-3 and 1-4 pressure transmitters are separated by 12 ft with no intervening combustibles and are protected by suppression and detection systems. The separation and fire protection features in this area justify an exemption to the Appendix R requirements. Furthermore, the separation between redundant trains of steam generator pressure transmitters PT-524 and (PT-515 and PT-525) is 15 ft-6 in. The separation between (PT-514 and PT-524) and (PT-536 and PT-546) is 23 ft. Because of the separation between redundant indication and the existence of suppression and detection systems, SSER 23 accepts that these conditions are equivalent to Appendix R criteria. Valves PCV-19, PCV-20, PCV-21 and PCV-22 may be affected by a fire in this area. These valves can be manually operated to ensure safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-BB 9.5A-42 Revision 21 September 2013 4.3.7 Main Feed System A fire in this area may affect 4-20mA DC control cables, which affect valves FCV-510, FCV-520, FCV-530, FCV-540, FCV-1510, FCV-1520, FCV-1530, and FCV-1540 and result in failure to isolate MFW. The MFW pumps are not affected in this fire area and can be tripped to isolate MFW flow to the steam generators. 4.3.8 Reactor Coolant System A fire in this area may affect pressurizer PORVs PCV-455C, PCV-456 and PCV-474 and blocking valves 8000A, 8000B and 8000C. The PORVs can be manually closed using the emergency close switch of the hot shutdown panel during hot standby to prevent uncontrolled pressure reduction. Auxiliary spray will be used for pressure reduction in this area. Therefore, safe shutdown will not be affected. A fire in this area may affect pressurizer level indication (LT-406, LT-459, LT-460 and LT-461). The conduits for LT-459 and LT-461 are embedded in the floor slab of El. 115 ft and stub up at the north end where they are separated from conduits KT350 and KT 358 by 40 ft with no intervening combustibles. Detection and suppression systems are provided. Therefore, this condition satisfies the separation requirements of Appendix R. RCS pressure indication from PT-403, PT-405 and PT-406 may be lost due to a fire in this area. Only one pressure transmitter is necessary. Since the conduit for PT-403 is provided with a fire barrier having an approximate fire rating of 3 hour, although 1 hour is committed, and is protected by detection and suppression systems, the safe shutdown criteria of Appendix R is met. A fire in this area may affect reactor coolant system temperature indication from TE-413A, TE-413B, TE-423A, TE-423B, TE-433A, TE-433B, TE-443A and TE-443B. A deviation was approved in SSER #23 to the extent that at least one division of RCS temperature indicators would remain free of fire damage. Reactor vessel head vent valves 8078A, 8078B, 8078C and 8078D may be affected by a fire in this area. Operator action can be taken to fail 8078A, 8078B, 8078C and 8078D closed. A fire in this area may affect NE-31, NE-32 and NE-52. The separation between the circuits for redundant detectors NE-31 and NE-32 is 20 ft with no intervening combustibles. These circuits are also protected by automatic sprinklers and smoke detection. If NE-52 is lost, NE-51 will remain available to provide indication. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-BB 9.5A-43 Revision 21 September 2013 A fire in this area may affect valves PCV-455A and PCV-455B. Since these valves fail in the desired, closed position, safe shutdown is not affected. 4.3.9 Residual Heat Removal System A fire in this area may affect valves 8701 and 8702. These valves are normally closed with their power supply removed and will not spuriously open. These valves can be manually opened for RHR operations. 4.3.10 Safety Injection System Valve 8801B may be lost due to a fire in this area. This valve is not required because redundant valve 8801A will remain available to align charging injection, and redundant valves 8803A and 8803B will remain available to isolate this path during pressure reduction. A fire in this area may affect accumulator isolation valves 8808A, 8808B, 8808C and 8808D. These valves can be manually operated to ensure safe shutdown. A fire in this area might prevent the refueling water supply valves 8805A and 8805B from auto opening on low VCT level. However, manual operation of these valves, from the control room, remains available. 4.3.11 HVAC One train of required HVAC equipment S-44 and E-44 may be lost due to a fire in this area. Redundant HVAC equipment S-43 and E-43 will be available to provide necessary HVAC support.
5.0 CONCLUSION
This area does not meet the requirements of 10 CFR 50, Appendix R, Section III.G.2. which requires the separation of redundant shutdown divisions by 20 ft, free of intervening combustibles, and the installation of area-wide fire detection and suppression systems.
- A deviation from these requirements was requested and granted in SSER 23. The following features will mitigate the consequences of a design basis fire and assure the ability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-BB 9.5A-44 Revision 21 September 2013
- Smoke detection provided for post accident sample area (El. 85 ft), cable tray area (El. 100 ft and 115 ft).
- Automatic wet pipe sprinkler provided for protection of safe shutdown circuitry (at El. 100 ft and 115 ft).
- Sprinklers on the blowout panels (El. 115 ft) will limit the potential spread of fire.
- Low Fire Severity.
- The physical location and separation of redundant safe shutdown functions, in this zone, minimize the effects of a design basis fire.
- Although only 1-hour fire barriers are required/credited for safe shutdown circuits associated with; junction box BTG14E; conduits KK204, KT359, KT354; and 3 embedded pull boxes at El. 100 ft (as previously accepted in SSER 23), these barriers were replaced with 3-hour barrier systems as a means of providing additional margin in the level of fire protection.
The existing fire protection provides an acceptable level of fire safety equipment to that provided by Section III G.2.
6.0 REFERENCES
6.1 Drawing Nos. 515568, 515569, 515570 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065126, Fire Protection Information Report, Unit 1 6.5 SSER 23, June 1984 6.6 DCN DC1-E-H-5497 Rev. 0, - 3 hr. Barrier of CCW Piping Penetration Area 6.7 DCN DC1-EA-11962, Flashing to Seal Walls of Fire Area 3-BB 6.8 DCN DC1-EE-13771, Provide Additional Smoke Detectors (El. 115 ft west of column line 2) 6.9 DCN DC1-EA-15251, Provide 1 Hour Barrier for Conduits and Pull Boxes 6.10 58 Fire Review Questions, Question No. 5 6.11 NECS File 131.95, FHARE 5 "Main Steam Line Penetration Protection" 6.12 Appendix 3 for EP M-10 Unit 1 - Fire Protection of Safe Shutdown Equipment 6.13 NECS File 131.95, FHARE 12 "Winch Cable Penetration For Post-LOCA Sampling Room Shield Wall" 6.14 NECS File 131.95 FHARE 91 "Nonrated Barrier Between Fire Area/Zone 3BB (3CC) and 3-P-2 (3-V-2)" 6.15 DCP A-47966 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-BB 9.5A-45 Revision 21 September 2013 6.16 PG&E Design Change Notice DC1-EA-049070, Unit 1 ThermoLag Replacement 6.17 NECS File: 131.95, FHARE: 130, "Inaccessible Jumbo Duct Penetrants" 6.18 Calculation 134-DC, Electrical Appendix R Analysis 6.19 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.20 NECS File: 131.95, FHARE 134, "Non-rated Structural Gap Seals in Fire Barriers" 6.21 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.22 PG&E Letter to NRC DCL-84-185, 5/16/84 - Exemption Request on APP R Review Fire Doors 6.23 PG&E Letter to NRC, 10/14/83 - Schedule for Fire Door Modifications 6.24 NECS File: 131.95, FHARE 159, Unrated Doors Protected by Local Automatic Sprinklers. 6.25 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-H-1 9.5A-46 Revision 21 September 2013 FIRE AREA 3-H-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This fire area is located at the north side of the Auxiliary Building at El. 75 ft.
1.2 Description This area houses the Unit 1 centrifugal charging pumps (1-1 and 1-2).
1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- 3-hour rated barrier separates this area from Zones 3-B-2, 3-B-3 and 3-J-3 and Area 3-B-1. NC
- A 3-hour rated door communicates to Zone 3-B-3.
- A duct penetration with no fire damper penetrates to Zone 3-B-3. (Ref. 6.15)
- A ventilation opening with no fire damper communicates to Area 3-B-1. (Ref. 6.15 )
- A 3-hour rated door communicates to Zone 3-J-3. (Ref. 6.3) South:
- 3-hour rated barrier separates this area from Zone 3-C.
- Two duct penetrations without fire dampers penetrate into Zone 3-C. (Refs. 6.7 and 6.15)
- Two 3-hour-equivalent rated double doors with monorail cutouts and water spray protection communicate into Zone 3-C. (Ref. 6.14 and 6.15) There is a 2-hour rated blockout above each of the doors. (Ref. 6.8)
- A nonrated opening penetrates into Zone 3-C. (Ref. 6.7)
- Lesser rated penetration seals to Fire Zone 3-C. (Ref. 6.13)
East:
- 3-hour rated barrier separates this area from Areas 3-H-2, 3-B-2 and 3-C.
- Two 3-hour rated doors communicate into Areas 3-C and 3-H-2 (which has a 2-hour rated blockout above the door (Ref. 6.8)) (1 into each area).
- 3-hour rated door communicates to area 3-B-2.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-H-1 9.5A-47 Revision 21 September 2013
- A 3-hour rated door with water spray protection communicates to Zone 3-C. (Ref. 6.14 and 6.15) There is a 2-hour rated blockout above the door. (Ref. 6.8)
- Lesser rated penetration seals to Area 3-H-2 and 3-B-2. (Ref. 6.13)
West:
- Open doorway, security gate, and non-rated penetrations to area 3-B-1. NC (Ref. 6.15)
- 3-hour rated barrier separates this area from Zone 3-J-3 and Area 3-B-1. NC
- Nonrated pipe penetrations penetrate into Area 3-B-1. NC (Ref. 6.15) Floor/Ceiling:
- 3-hour rated barriers.
- A duct penetration without a fire damper communicates through the floor into Zone 3-C (Below). (Ref. 6.15)
- Lesser rated penetration seal to Fire Area 3-BB. (Ref. 6.13) 2.0 COMBUSTIBLES
2.1 Floor Area: 900 ft2 2.2 In situ Combustible Materials
- Cable
- Plastic
- PVC
- Oil 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-H-1 9.5A-48 Revision 21 September 2013 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Partial smoke detection. (Ref. 6.10) 3.2 Suppression
- Automatic wet pipe sprinkler system (partial). (Ref. 6.10)
- Closed head water spray system protecting two double doors in south wall and one door in east wall.
- Portable fire extinguishers.
- Hose stations. 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Chemical and Volume Control System Circuitry for charging pumps 1-1, 1-2, 1-3 and ALOPs 1-1 and 1-2 may be damaged due to a fire in this area. Charging pump 1-3 can be manually started at the 4-kV switchgear room to provide charging flow. 4.2 Residual Heat Removal System RHR pumps 1-1 and 1-2 may be lost due to a fire in this area. Either RHR pump 1-1 or 1-2 can be manually started at their respective 4-kV switchgear rooms to provide RHR flow. A fire in this area may affect the AC power cables and DC control cables for FCV-641A and FCV-641B. Prior to starting either RHR Pump 2-1 or 2-2, the respective recirc can be manually opened, and then re-closed after the RHR pump reaches full flow. 4.3 Safety Injection System Charging injection valves 8803A and 8803B may be affected by a fire in this area. RCS flow through the regenerative heat exchanger and RCP seals will be available. Redundant valves 8801A and 8801B to isolate diversion flow from charging injection are available, thus no manual actions are required. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-H-1 9.5A-49 Revision 21 September 2013
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Safe shutdown will not be adversely affected by the loss of equipment in this area due to the availability of redundant equipment and/or manual actions.
- Smoke detection over charging pumps.
- Automatic wet pipe sprinkler protection over the pumps.
- Manual fire fighting equipment is available for use.
The existing fire protection features provide a level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.2 Drawing No. 515567 6.3 SSER 23, June 1984 6.4 Calculation M-824, Combustible Loading 6.5 Drawing 065126, Fire Protection Information, Unit 1 6.6 SSER 31, April 1985 6.7 NECS File: 131.95, FHARE: 25, Nonrated Features in the Units 1 and 2 Centrifugal Charging Pump Rooms (CCP1 and CCP2) 6.8 NECS File: 131.95, FHARE: 50, Plaster Block-out Panels in 3-Hour Barriers 6.9 Appendix 3 for EP M-10 Unit 1 "Fire Protection of Safe Shutdown Equipment" 6.10 NECS File: 131.95, FHARE: 47, Partial Detection and Suppression Protection 6.11 Calculation 134-DC, Electrical Appendix R Analysis 6.12 Calculation M-928, 10CFR50, Appendix R Safe Shutdown Analysis 6.13 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.14 NECS File: 131.95, FHARE 159, Unrated Doors Protected by Local Automatic Sprinklers. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-H-1 9.5A-50 Revision 21 September 2013 6.15 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-H-2 9.5A-51 Revision 21 September 2013 FIRE AREA 3-H-2 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This area is located at the north side of the Auxiliary Building at El. 73 ft.
1.2 Description This area houses the Unit 1 centrifugal charging pump (1-3).
1.3 Boundaries North:
- 3-hour rated barrier separates this area from Zone 3-F and Area 3-B-2.
- Ventilation penetrations with 3-hour rated fire damper communicate to Area 3-B-2.
- A duct penetration with no fire damper penetrates to Zone 3-F. (Refs. 6.6 and 6.12) South:
- 3-hour rated barrier separates this area from Zone 3-C.
- A duct penetration with no fire damper penetrates to Zone 3-C. (Refs. 6.6, 6.7 and 6.12) East:
- 3-hour rated barrier separates this area from Zone 3-F.
- An open doorway with security gate communicates to Zone 3-F. (Refs. 6.6 and 6.12) West:
- 3-hour rated barrier separates this area from Area 3-H-1 and Zone 3-C.
- A 3-hour rated fire door communicates to Area 3-H-1. There is a 2-hour rated plaster blockout above the door. (Ref. 6.8)
- Lesser rated penetration seals to Area 3-H-1. (Ref. 6.11) Floor/Ceiling:
- 3-hour rated barriers except for a duct penetration without a fire damper in the floor (to 3-C) and ceiling (to 3-M). (Refs. 6.6 and 6.12)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-H-2 9.5A-52 Revision 21 September 2013 2.0 COMBUSTIBLES 2.1 Floor Area: 235 ft2 2.2 In situ Combustible Materials
- PVC
- Lube Oil 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection 3.2 Suppression
- Automatic wet pipe system
- Portable fire extinguishers
- Fire hose stations 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Chemical and Volume Control System Charging pump 1-3 may be lost due to a fire in this area. Redundant charging pumps 1-1 and 1-2 will be available to provide charging flow.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-H-2 9.5A-53 Revision 21 September 2013
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Safe shutdown will not be adversely affected by the loss of the equipment in this area due to the availability of redundant equipment and/or manual actions.
- Smoke detection over charging pumps.
- Automatic wet pipe sprinkler protection over the pumps.
- Manual fire fighting equipment is available for use. The existing fire protection features provide a level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.2 Drawing No. 515567 6.3 SSER 23, June 1984 6.4 Calculation M-824, Combustible Loading 6.5 Drawing 065126, Fire Protection Information Report, Unit 1 6.6 SSER 31, April 1985 6.7 NECS File: 131.95, FHARE: 25, Nonrated Features in the Units 1 and 2 Centrifugal Charging Pump Rooms (CCP1 and CCP2) 6.8 NECS File: 131.95, FHARE: 50, Plaster Block-out Panels in 3-Hour Barriers 6.9 Calculation 134-DC, Electrical Appendix R Analysis 6.10 Calculation M-928, 10 CFR 50, Appendix R Safe Shutdown Analysis 6.11 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.12 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-Q-1 9.5A-54 Revision 21 September 2013 FIRE AREA 3-Q-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location South end of the Unit 1 Fuel Handling Building adjacent to the Auxiliary Building, El. 100 ft. 1.2 Description This fire area adjoins Zones 31 and 3-0 on the north; 3-A and 3-X on the South; 3-Q-2 on the west; and below grade on the east. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- 3-hour rated barrier separates this area from Zone 3-0 except for a nonrated concrete shield wall. (Ref. 6.14)
- 3-hour rated barrier separated this area from Zone 31 except for a 1-1/2-hour rated double door in a 2-hour rated plaster barrier. (Ref. 6.14)
- Unique penetration seals in plaster walls to Area 31. (Ref. 6.9)
- Lesser rated penetration seals to Area 31. (Ref. 6.12) South:
- 3-hour rated barrier separates this area from Zone 3-A, except for a 2-hour rated blockout. (Ref. 6.7)
- 3-hour rated barrier separates this area from Zone 3-X except for 2-hour rated blockout above a 3-hour rated double door. (Ref. 6.7)
- Unique penetration seals in plaster walls to Area 3-X. (Ref. 6.9)
- Lesser rated penetration seals to Zones 3-A and 3-X. (Ref. 6.12) East:
- 3-hour rated wall to below grade. NC West:
- Unique penetration seals in plaster walls to zone 3-Q-2. (Ref. 6.9)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-Q-1 9.5A-55 Revision 21 September 2013
- A 1-hour rated barrier separates this area from Zone 3-Q-2 with a 3-hour rated door and a 3-hour rated double door. (Ref. 6.13)
- A 1-1/2-hour rated damper communicates to Zone 3-Q-2. (Ref. 6.14)
- A duct penetration without a fire damper penetrates to Zone 3-Q-2. (Ref. 6.14)
- Lesser rated penetration seal to Zone 3-Q-2. (Ref. 6.12)
Floor/Ceiling:
- A duct penetration without a fire damper penetrates to Zone 3-R above. (Ref. 6.14) [CR V-9.5A (19) SAPN 50569573]
- Nonrated pipe penetrations to Zone 3-R above. (Ref. 6.8)
- An opening to a ventilation duct routed outside the fuel handling building at El. 140 ft. (Ref.6.2) 2.0 COMBUSTIBLES
2.1 Floor Area: 754 ft2 2.2 In situ Combustible Materials
- Cable insulation
- Oil
- Grease
- Polyethylene
- Clothing/Rags
- Plastic
- Wood (fir)
- Rubber
- Hydrogen line - this line has a guard pipe and there is an excess flow valve at the source to isolate the line in case of a H2 line break. 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-Q-1 9.5A-56 Revision 21 September 2013
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Area wide smoke detection 3.2 Suppression
- Area wide automatic wet pipe sprinklers
- Portable fire extinguishers
- Hose station 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Auxiliary Feedwater AFW pump 1-1 may be affected by a fire in this area. AFW pumps 1-2 and 1-3 will remain available for safe shutdown. Valves FCV-436 and FCV-437 are located in Fire Area 3-Q-1 and will be affected by a fire in this area. FCV-437 can be manually opened to provide a flowpath from the raw water storage reservoir to the AFW pumps 1-2 and 1-3. The Raw Water Supply Valves for AFW Pump 1-1 (FCV-436) and AFW Pumps 1-2 and 1-3 (FCV-437), and AFW Pump 1-1 suction valve (1-121) are located in this fire area. A fire will not damage the normally closed (1-121 is normally open) manual valves. However, FCV-437 will need to be manually opened and 1-121 will need to be manually closed prior to CST inventory depletion to ensure that a suction source for AFW Pumps 1-2 and 1-3 is maintained. 4.2 Safety Injection System A fire in this area may affect circuits associated with RWST Level Transmitter LT-920. This level transmitter is credited for diagnosis of spurious operation of equipment that may divert RWST inventory. There are no cables affected in this area that may result in diverting the RWST inventory. Therefore, loss of this instrument will not affect safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-Q-1 9.5A-57 Revision 21 September 2013
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Manual fire fighting equipment is available.
- Limited and dispersed combustible loading.
- Area wide smoke detection and automatic suppression are provided.
The existing fire protection features in this area provide an acceptable level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.2.
6.0 REFERENCES
6.1 Drawing No. 515569 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065126, Fire Protection Information, Unit 1 6.5 SSER 23, June 1984 6.6 Deleted in Revision 13. 6.7 NECS File: 131.95, FHARE 125, Lesser Rated Plaster Blockouts And Penetration Seal Configurations 6.8 NECS File: 131.95, FHARE 128, Nonrated Pipe Penetrations 6.9 NECS File: 131.95, FHARE 121, Pipe Penetration Seals Through Plaster Walls in the Unit 1 AFW Pump Rooms 6.10 Calculation 134-DC, Electrical Appendix R Analysis 6.11 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.12 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.13 PG&E Letter DCL-84-329, 10/19/84 - 10 CFR 50 Appendix R Review Report. 6.14 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-A-1, 5-A-2, 5-A-3 9.5A-58 Revision 21 September 2013 FIRE AREAS 5-A-1, 5-A-2, 5-A-3 1.0 PHYSICAL CHARACTERISTICS
1.1 Location These three fire areas are located in the northwest part of the Unit 1 Auxiliary Building, El. 100 ft. 1.2 Description Fire Areas 5-A-1, 5-A-2, and 5-A-3 contain the 480V vital switchgear rooms (F, G, and H Buses respectively). These areas are situated side by side with Fire Area 5-A-2 located in the center. Area 5-A-1 is west of 5-A-2 and Fire Area 5-A-3 is east of 5-A-2. Due to the similarities between these three areas, they have been combined in one section. 1.3 Boundaries 1.3.1 Fire Area 5-A-1 North:
- A 3-hour rated barrier separates this area from Area 3-BB. South:
- A 3-hour rated barrier with a nonrated seismic gap separates this area from Area 5-A-4. (Ref. 6.8)
- A 3-hour rated door communicates to Area 5-A-4.
- A protected duct penetration without a fire damper penetrates to Area 5-A-4. (Refs. 6.5 and 6.11)
- A lesser rated penetration seal to Area 5-A-4. (Ref. 6.15)
East:
- A 3-hour rated barrier with a nonrated seismic gap separates this area from Area 5-A-2. (Ref. 6.8)
- A 3-hour rated door communicates to Area 5-A-2.
- A protected duct penetration without a damper communicates to Area 5-A-2. (Ref. 6.5)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-A-1, 5-A-2, 5-A-3 9.5A-59 Revision 21 September 2013 West:
- A 3-hour rated barrier with a nonrated seismic gap separates this area from Area 5-A-4. (Ref. 6.8)
- A 3-hour rated door communicates to Area 5-A-4.
- Two protected duct penetrations without fire dampers penetrate to Area 5-A-4. (Refs. 6.5 and 6.11)
Floor/Ceiling:
- 3-hour rated barrier. Floor: To fire areas 4-A and 4-A-1 Ceiling: To fire area 6-A-1 1.3.2 Fire Area 5-A-2 North:
- 3-hour rated barrier separates this area from Area 3-BB. South:
- A 3-hour rated barrier with a nonrated seismic gap separates this area from Area 5-A-4. (Ref. 6.8)
- A 3-hour rated door communicates to Area 5-A-4.
- A duct penetration with a 1-1/2 rated fire damper penetrates to Area 5-A-4. (Refs. 6.5, 6.7, and 6.11)
East:
- A 3-hour rated barrier with a nonrated seismic gap separates this area from Area 5-A-3. (Ref. 6.8)
- A protected duct penetration without a fire damper penetrates to Area 5-A-3. (Refs. 6.5 and 6.7)
- A 3-hour rated door communicates to Area 5-A-3.
West:
- A 3-hour rated barrier with a nonrated seismic gap communicates to Area 5-A-1. (Ref. 6.8)
- A 3-hour rated door communicates to Area 5-A-1.
- A protected duct penetration without a fire damper penetrates to Area 5-A-1. (Ref. 6.5)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-A-1, 5-A-2, 5-A-3 9.5A-60 Revision 21 September 2013 Floor/Ceiling:
- 3-hour rated barrier. Floor: To fire areas 4-A and 4-A-1 Ceiling: To fire area 6-A-1 1.3.3 Fire Area 5-A-3 North:
- A 3-hour rated barrier separates this area from Area 3-BB.
South:
- A 3-hour rated barrier with a nonrated seismic gap separates this area from Area 5-A-4. (Ref. 6.8) In addition, localized sections of structural steel for blockwalls were not provided with 3-hour rated fireproofing. (Ref. 6.12)
- A 3-hour rated door communicates to Area 5-A-4.
- A duct penetration with a 1-1/2-hour rated fire damper penetrates to Area 5-A-4. (Refs. 6.5, 6.7, and 6.11)
East:
- A 3-hour rated barrier with a nonrated seismic gap separates this area from Area 5-A-4. (Ref. 6.8) In addition, localized sections of structural steel for blockwalls were not provided with fire proofing. (Ref. 6.12)
- A 3-hour rated door communicates to Area 5-A-4.
West:
- A 3-hour rated barrier with a nonrated seismic gap separates this area from Area 5-A-2. (Ref. 6.8)
- A 3-hour rated door communicates to Area 5-A-2.
- A protected duct penetration without a fire damper penetrates to Area 5-A-2. (Ref. 6.5)
Floor/Ceiling:
- Floor: 3-hour rated barrier to Fire Area 4-A.
- Ceiling: 3-hour rated barriers 6-A-1, 6-A-2, and 6-A-3. Protective
Enclosure:
(for all three areas)
- 1-hour rated fire resistive covering is provided for HVAC ducts in the fire areas. (Ref. 6.5)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-A-1, 5-A-2, 5-A-3 9.5A-61 Revision 21 September 2013 2.0 COMBUSTIBLES (typical for each area) 2.1 Floor Area: 444 ft2 2.2 In situ Combustible Materials
- Cable
- Plastic 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION (typical for each area)
3.1 Detection
- Smoke detection in each area 3.2 Suppression
- CO2 hose stations
- Hose stations
- Portable fire extinguishers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-A-1, 5-A-2, 5-A-3 9.5A-62 Revision 21 September 2013 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Fire Area 5-A-1 4.1.1 Auxiliary Feedwater AFW pump 1-3 may be lost due to a fire in this area. Steam generator 1-3 is credited for safe shutdown in this area. Redundant AFW pump 1-1 will remain available to provide AFW flow to steam generator 1-3.
AFW valves LCV-113 and LCV-115 may be affected by a fire in this area. Redundant AFW valve LCV-108 will remain available to provide AFW flow to steam generator 1-3 via AFW Pump 1-1. In addition LCV-109 will remain available to provide AFW flow to a second steam generator 1-4. 4.1.2 Chemical and Volume Control System Charging pump 1-1 and ALOP 1-1 may be lost due to a fire in this area. Redundant charging pumps 1-2, 1-3 and ALOP 1-2 will be available to provide charging flow. Boric acid transfer pump 1-1 may be lost due to a fire in this area. Redundant boric acid transfer pump 1-2 will be available for this function. CVCS valve 8105 may be affected by a fire in this area. Since the VCT and the RWST will be aligned to the charging pump suction, safe shutdown will not be affected if 8105 were to close in the event of a fire. CVCS valve 8107 may be affected by a fire in this area. Since valve 8107 has redundant components, this valve's position will not have an affect on safe shutdown. A fire in this area may spuriously open let down orifice valves 8149A, 8149B, 8149C and LCV-459 or LCV-460. Operator action can be taken to fail 8149A, 8149B and 8149C closed. Therefore, safe shutdown is not affected. Volume control outlet valve LCV-112B may be affected by a fire in this area. If LCV-112B is lost then valve 8805B can be opened to provide water from the RWST to the charging pump suction. Redundant valve LCV-112C will be available to isolate the volume control tank. Level indication for BAST 1-2 from LT-106 may be affected by a fire in this area. If level indication for boric acid storage tank 1-2 is lost, borated water from the RWST will be available. Therefore, BAST level will not be required. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-A-1, 5-A-2, 5-A-3 9.5A-63 Revision 21 September 2013 4.1.3 Component Cooling Water CCW pump 1-1 and ALOP 1-1 may be lost due to a fire in this area. Redundant CCW pumps and ALOPs 1-2 and 1-3 will be available to provide CCW. CCW valve FCV-430 may be affected by a fire in this area. If FCV-430 is lost, then CCW heat exchanger 1-1 will be unavailable. However, CCW heat exchanger 1-2 and redundant valve FCV-431 will be available for use. CCW valve FCV-750 may be affected by a fire in this area. Since seal injection will remain available, this will provide adequate cooling and FCV-750 will not be required. 4.1.4 Emergency Power A fire in this area may disable diesel generator 1-2 backup control circuit. The normal control circuit will remain available. A fire in this area may disable diesel generator 1-3. Diesel generators 1-1 and 1-2 will remain available for safe shutdown. A fire in this area may disable startup transformer 1-2. Onsite power from diesel generators 1-1 and 1-2 will remain available. All power supplies on the "F" Bus may be lost due to a fire in this area. These power supplies are not necessary since redundant trains on the "G" and "H" Buses will be available. A fire in this area may disable dc panel SD13 backup battery charger ED131. Normal battery charger ED132 will remain available. 4.1.5 Main Steam System The following steam generator level and pressure instrumentation may be lost due to a fire in this area: LT-516, LT-526, LT-529, LT-536, LT-539, LT-546, PT-514, PT-524, PT-534 and PT-544. Redundant instrumentation for all four steam generators will be available for safe shutdown. Valve PCV-19 may be affected by a fire in this area. Since this valve fails closed which is its desired position, safe shutdown can still be achieved. A redundant dump valve will be available for cooldown purposes. Main steam system valve FCV-38 may be affected by a fire in this area. This valve can be manually operated in the event of a fire to ensure that AFW pump 1-1 can provide auxiliary feedwater to steam generator 1-3. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-A-1, 5-A-2, 5-A-3 9.5A-64 Revision 21 September 2013 4.1.6 Makeup System Condensate storage tank level indication LT-40 may be lost due to a fire in this area. Water from the raw water storage reservoir will be available through FCV-436 to provide auxiliary feedwater. The normally closed manual valve can be locally opened prior to CST depletion. 4.1.7 Reactor Coolant System Loss of LT-406, LT-459, NE-31, NE-51, PT-406, TE-413A, TE-413B, TE-423A and TE-423B due to a fire will not affect safe shutdown since redundant components are available. A fire in this area may affect pressurizer PORV PCV-474 and its block valve 8000A. Cables associated with PCV-474 are routed in a conduit that is administratively controlled to ensure that no sources of hot shorts are added. Therefore, the PORV will remain closed. A redundant PORV will remain available for pressure reduction. 4.1.8 Safety Injection System A fire in this area may spuriously energize SI pump 1-1 and may prevent the operation of accumulator isolation valve 8808A. SI pump 1-1 and valve 8808A are required off and closed during RCS pressure reduction. Valve 8808A can be manually closed and SI pump 1-1 can be locally de-energized to ensure safe shutdown. Valves 8801A, 8803A and 8805A may be lost due to a fire in this area. Safe shutdown is not affected since redundant valves are available. ASW pump 1-1 may be lost due to a fire in this area. Redundant ASW pump 1-2 will remain available. A fire in this area may affect ASW valve FCV-601. Valves FCV-495 and FCV-496 can be closed to provide ASW system integrity if FCV-601 spuriously opens. A fire in this area may affect FCV-602. Since ASW pump 1-2 is used in this area, loss of FCV-602 will not affect safe shutdown. 4.1.9 HVAC HVAC equipment E-103, E-43, S-43, S-69 and FCV-5045 may be lost due to a fire in this area. Safe shutdown is not affected because E-103 and S-69 are not necessary during a fire in this area and E-43, S-43 and FCV-5045 have DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-A-1, 5-A-2, 5-A-3 9.5A-65 Revision 21 September 2013 redundant components (S-44, E-44, FCV-5046) that will be available to provide HVAC support. 4.2 Fire Area 5-A-2 4.2.1 Auxiliary Feedwater AFW valves LCV-106, LCV-107, LCV-108, and LCV-109 may be affected by a fire in this area. Steam generators 1-1 and 1-2 are credited for safe shutdown in this area. Redundant valves LCV-110 and LCV-111 will remain available to provide AFW flow. 4.2.2 Chemical and Volume Control System Charging pumps 1-2 and 1-3 and ALOP 1-2 may be lost due to a fire in this area. Redundant charging pump 1-1 and ALOP 1-1 will be available to provide charging flow. Boric acid transfer pump 1-2 may be lost due to a fire in this area. Redundant boric acid transfer pump 1-1 will remain available. Valve 8106 may be affected by a fire in this area. Since the RWST will be aligned to the charging pump suction, valve 8106 is not necessary during a fire in this area. Valve 8108 may be affected by a fire in this area. Since valve 8108 has redundant components available to provide the same function, this valve's position will not have an affect on safe shutdown. Valves 8104 and FCV-110A may be affected by a fire in this area. Safe shutdown is not affected since FCV-110A fails open and is still able to provide boric acid to the charging pump suction. Manual positioning of valve 8471 will be required if valve FCV-110A is used. Valves 8146, 8147 and 8148 may be affected by a fire in this area. Safe shutdown is not affected because redundant valves exist to isolate auxiliary spray, provide a charging flowpath and to provide for pressure reduction. Valves FCV-128 and HCV-142 may be affected by a fire in this area. Failure of HCV-142 will not affect safe shutdown since redundant valves and flowpaths are available for charging. Spurious closure of FCV-128 will isolate seal injection flow. A manual action will be taken to open FCV-128 after placing its controller in the control room to manual to provide seal injection to the RCPs. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-A-1, 5-A-2, 5-A-3 9.5A-66 Revision 21 September 2013 Valve LCV-112C may be affected by a fire in this area. Redundant valve 8805A remains available in order to provide water from the RWST to the charging pump suction. The volume control tank can be isolated by closing redundant valve LCV-112B. A fire in this area may affect the transmitter and circuits associated with charging pump header flow transmitter, FT-128, and pressure transmitter, PT-142. Because RWST valve 8805A and charging pump 1-1 is available for charging flow, the loss of these instruments will not adversely affect safe shutdown. 4.2.3 Component Cooling Water CCW pump 1-2 and ALOP 1-2 may be lost due to a fire in this area. Redundant CCW pumps 1-1 and 1-3 and ALOPs 1-1 and 1-3 will be available to provide CCW. CCW valve FCV-431 may be affected by a fire in this area. Redundant valve FCV-430 will remain available to allow use of CCW heat exchanger 1-1. CCW valve FCV-365 may be affected by a fire in this area. If power to this valve is lost, it fails open which is its desired position. Redundant valve FCV-364 can also be available. The seal injection flowpath can also be affected due to fire-induced spurious closure of FCV-128. The potential for a loss of all seal cooling can occur if the valves in these flowpaths spuriously close simultaneously. A manual action will be taken to open FCV-128 after placing its controller in the control room to manual to provide seal injection to the RCPs. 4.2.4 Containment Spray A fire in this area may spuriously energize containment spray pump 1-1 and may spuriously open valve 9001A. Operator action can be taken to trip CS pump 1-1. Therefore, safe shutdown will not be affected. Valve 9003A may be affected by a fire in this area. Manual action can be taken to close valve 9003A. 4.2.5 Diesel Fuel Oil System Diesel fuel oil pump 0-2 may be lost due to a fire in this area. Redundant diesel fuel oil pump 0-1 remains available. Diesel fuel oil day tank valves LCV-85, LCV-86 and LCV-87 may be lost due to a fire in this area. Redundant valves LCV-88, LCV-89 and LCV-90 remain available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-A-1, 5-A-2, 5-A-3 9.5A-67 Revision 21 September 2013 4.2.6 Emergency Power A fire in this area may disable the diesel generator 1-1 backup control circuit. The normal control circuit will remain available. A fire in this area may disable diesel generator 1-2. Diesel generators 1-1 and 1-3 will remain available for safe shutdown. If power is available to bus SPG, breaker 52HG10 at SHG should be opened to preclude spurious operation of train "G" components. All power supplies on the "G" Bus may lose power due to a fire in this area. These power supplies are not necessary since redundant trains on the "F" and "H" Buses will be available. 4.2.7 Main Steam System The following instrumentation may be lost due to a fire in this area: LT-519, LT-549, PT-515, PT-525, PT-535 and PT-545. Since redundant trains of indication will be available for each steam generator, safe shutdown will not be affected. Valve PCV-21 may be affected by a fire in this area. Since this valve fails in its desired position safe shutdown is not affected. Redundant components will remain available for cooldown. Valves FCV-760 and FCV-761 may be lost due to a fire in this area. FCV-761 has redundant valves FCV-154 and FCV-248 while FCV-760 has redundant valves FCV-151 and FCV-250, which will be available for isolation of steam generator blowdown. Therefore, safe shutdown is not affected. Valve FCV-95 may be lost due to a fire in this area which would disable AFW pump 1-1. Steam generators 1-1 and 1-2 are credited for safe shutdown in this area. Redundant AFW pump 1-2 will remain available to provide AFW to the steam generators 1-1 and 1-2. Main steam isolation valves FCV-41, FCV-42 and bypass valve FCV-24 may be affected by a fire in this area. These valves can be manually closed during a fire. 4.2.8 Reactor Coolant System The following instrumentation may be lost due to a fire in this area: LT-460, NE-32, TE-433A, TE-433B, TE-443A and TE-443B. All of these components have redundant components that are available for safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-A-1, 5-A-2, 5-A-3 9.5A-68 Revision 21 September 2013 Pressurizer PORV PCV-455C and blocking valve 8000B may be affected by a fire in this area. Since PCV-455C fails closed and circuits are located in a conduit that is administratively controlled to prevent inclusion of hot short sources, safe shutdown is not affected. A redundant PORV will remain available for pressure reduction. A fire in this area may prevent RCPs 1-1, 1-2, 1-3 and 1-4 from being tripped. In order to prevent uncontrolled pressure reduction, PCV-455A and PCV-455B should be verified shut to isolate normal spray. Operation of reactor coolant pumps will not affect safe shutdown for a fire in this area. Seal injection is available to provide RCP seal cooling. Pressurizer heater groups 1-2, 1-3 and 1-4 may be affected by a fire in this area. Manual actions can be taken to de-energize heater group 1-4 and switch heater group 1-3 to the vital power source. Therefore, safe shutdown is not affected. 4.2.9 Residual Heat Removal System RHR pump 1-1 and outlet valve 8700A may be lost due to a fire in this area. Redundant RHR pump 1-2 and outlet valve 8700B will be available to provide the RHR function. RHR valve 8701 may be affected by a fire in this area. This valve is closed with its power removed during normal operation and will not spuriously open. This valve can be manually opened for RHR operations. A fire in this area may affect power to FCV-641A. A fire in this area may also affect AC control cables which spuriously close FCV-641A, and DC control cables which spuriously trip RHR PP 1-1. Since the other train is available (RHR PP 1-2 and valves 8700B and FCV-641B) this will not affect safe shutdown. 4.2.10 Safety Injection System SI valves 8801B, 8803B and 8805B may be lost due to a fire in this area. Redundant valves 8801A, 8803A and 8805A remain available to provide the same functions. Also, the PORVs will be available for pressure reduction. Therefore, safe shutdown is not affected. Valve 8804A may be affected by a fire in this area. Since this valve can be manually closed, safe shutdown is not affected. SI valves 8808B and 8808D may be affected by a fire in this area. Since these valves can be manually closed, safe shutdown is not affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-A-1, 5-A-2, 5-A-3 9.5A-69 Revision 21 September 2013 A fire in this area may affect valve 8982A. Power to the valve is administratively removed by maintaining a toggle switch in the Control Room in the open position. The valve is normally closed, and spurious opening is not expected to occur. In addition, an operator action can be taken to open the power breaker to further preclude spurious operation. Therefore, safe shutdown will not be affected. 4.2.11 Auxiliary Saltwater System ASW pump 1-2 may be lost due to a fire in this area. Redundant pump 1-1 will be available to provide the ASW function. ASW valve FCV-603 may be affected by a fire in this area. Redundant valve FCV-602 remains available, to provide ASW. 4.2.12 HVAC A fire in this area may affect E-101 and S-68. Redundant fans E-103 and S-67 and S-69 will remain available. 4.3 Fire Area 5-A-3 4.3.1 Auxiliary Feedwater AFW pump 1-2 may be lost due to a fire in this area. Redundant AFW Pump 1-3 will be available to provide AFW. Valves LCV-110 and LCV-111 are affected by a fire in this area. Steam generator 1-3 is credited for safe shutdown in this area. Redundant valve LCV-115 will remain available via AFW Pump 1-3. LCV-113 will also remain available to align AFW flow to a second steam generator. 4.3.2 Chemical and Volume Control System CVCS valve 8145 may be affected by a fire in this area. Redundant valves 8107, 8108 or HCV-142 are available to isolate auxiliary spray and the PORVs will be available for RCS pressure reduction. Thus, no manual actions are required. A fire in this area may result in the loss of boric acid storage tank 1-1 level indication from LT-102. Borated water from the RWST will remain available. Therefore, BAST level indication is not required. A fire in this area may affect circuits associated with letdown flow transmitter, FT-134. Loss of this instrument will not be available for diagnosis of letdown flow isolation. Letdown isolation valves (LCV-459, LCV-460, 8149A, 8149B and DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-A-1, 5-A-2, 5-A-3 9.5A-70 Revision 21 September 2013 8149C) are not affected in this area and will remain available to isolate letdown. Loss of this indication will not affect safe shutdown. 4.3.3 Component Cooling Water CCW pump 1-3 and ALOP 1-3 may be lost due to a fire in this area. Redundant pumps 1-1 and 1-2 and ALOPs 1-1 and 1-2 will be available to provide CCW. A fire in this area may spuriously close CCW return valve FCV-357. Since seal injection will remain available FCV-357 will not be required open. CCW supply valve FCV-355 may spuriously close during a fire in this area. FCV-355 can be manually operated for safe shutdown. CCW supply valve FCV-364 may be affected by a fire in this area. Safe shutdown will not be affected since this valve fails open which is the desired position. 4.3.4 Containment Spray A fire in this area may spuriously start containment spray pump 1-2 and may spuriously open valve 9001B. Operator action can be taken to trip CS pump 1-2. Therefore, safe shutdown will not be affected. A fire in this area may spuriously open valve 9003B. This valve can be manually closed to ensure safe shutdown. 4.3.5 Diesel Fuel Oil System Diesel fuel oil pump 0-1 may be lost due to a fire in this area. Redundant diesel fuel oil pump 0-2 will remain available. Diesel fuel oil day tank valves LCV-88, LCV-89 and LCV-90 may be lost due to a fire in this area. Redundant valves LCV-85, LCV-86 and LCV-87 remain available. 4.3.6 Emergency Power A fire in this area may disable diesel generator 1-1. Diesel generators 1-2 and 1-3 will remain available for safe shutdown. If power is available to bus SPH, breaker 52HH10 at SHH should be opened to preclude spurious operation of train "H" components. A fire in this area may disable diesel generator 1-3 backup control circuit. The normal control circuit will remain available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-A-1, 5-A-2, 5-A-3 9.5A-71 Revision 21 September 2013 All power supplies on the "H" Bus may be lost due to a fire in this area. These power supplies are not necessary since redundant trains on the "G" and "F" buses will be available. A fire in this area may disable dc panel SD11 and SD12 backup battery charger ED121. Normal battery chargers ED11 and ED12 will remain available. 4.3.7 Main Steam System The power to the following instrumentation may be lost due to a fire: LT-518, LT-528, LT-538, LT-548, PT-526 and PT-536. Safe shutdown is not affected since redundant trains of indication for all four steam generators are available. A fire in this area may affect PCV-20. This valve fails in the desired, closed position. Redundant valves PCV-19, PCV-21 and PCV-22 will remain available for cooldown. A fire in this area may spuriously close FCV-37. AFW pump 1-3 will remain available to provide auxiliary feedwater to the steam generators 1-3 and 1-4. FCV-762 and FCV-763 may be lost due to a fire in this area. Redundant valves FCV-157 and FCV-246 for FCV-762 and FCV-160 and FCV-244 for FCV-763 will be available for isolation of steam generator blowdown. Therefore, safe shutdown is not affected. Valves FCV-43 and FCV-44 may be affected by a fire in this area. These valves can be manually closed. 4.3.8 Reactor Coolant System The following components may be lost due to a fire in this area: LT-461, NE-52 and PT-403. Since redundant trains will be available safe shutdown will not be affected. Pressurizer PORV PCV-456 and blocking valve 8000C may be affected by a fire in this area. Since PCV-456 fails closed and circuits are located in a conduit that is administratively controlled to prevent inclusion of hot short sources, safe shutdown is not affected. A redundant PORV will remain available for safe shutdown. A fire in this area may spuriously start reactor coolant pumps 1-1, 1-2, 1-3 and 1-4. Since the normal spray valves cannot be spuriously opened by a fire in this area, safe shutdown will not be affected. Seal injection will remain available for RCP seal cooling. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-A-1, 5-A-2, 5-A-3 9.5A-72 Revision 21 September 2013 Pressurizer heaters 1-1,1-2, and 1-3 may be affected by a fire in this area. Manual actions can be taken to de-energize heater group 1-1 and switch heater group 1-2 to the vital power supply. Therefore, safe shutdown will not be affected. Loss of circuits for pressurizer heater 1-3 will not affect safe shutdown. 4.3.9 Residual Heat Removal System RHR pump 1-2 and valve 8700B may be affected by a fire in this area. Since RHR pump 1-1 and valve 8700A remain available, safe shutdown is not affected. Valve 8702 may be affected by a fire in this area. During normal operations this valve is closed with its power removed and will not spuriously open. This valve can be manually positioned for RHR operation. A fire in this area may also affect AC power and control cables for FCV-641B and cause the valves to spuriously operate. FCV-641A will remain available. 4.3.10 Safety Injection System SI pump 1-2 may spuriously operate due to a fire in this area. Local manual action may be required to defeat this spurious operation. A fire in this area might prevent the refueling water supply valves 8805A and 8805B from auto opening on low VCT level. However, manual operation of these valves, from the control room, remains available. Valve 8808C may be affected by a fire in this area. This valve can be manually closed to ensure safe shutdown. A fire in this area may affect valve 8982B. Power to the valve is administratively removed by maintaining a toggle switch in the Control Room in the open position. The valve is normally closed, and spurious opening is not expected to occur. In addition, an operator action can be taken to open the power breaker to further preclude spurious operation. Therefore, safe shutdown is not affected. 4.3.11 Auxiliary Saltwater System ASW valves FCV-495 and FCV-496 may be affected by a fire in this area. Valve FCV-601 will remain available to provide ASW system integrity. 4.3.12 HVAC A fire in this area may affect E-44, S-44, S-67 and FCV-5046. Since S-67 is not necessary and redundant components S-43, E-43 and FCV-5045 remain available, safe shutdown is not affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-A-1, 5-A-2, 5-A-3 9.5A-73 Revision 21 September 2013
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Automatic smoke detection is provided.
- Manual fire fighting equipment is available for use.
- The loss of safe shutdown functions in each fire area does not affect the redundant train.
The existing fire protection features provide an acceptable level of safety equivalent to that provided by Section III.G.2.
6.0 REFERENCES
6.1 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.2 Drawing No. 515569 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065162, Fire Protection Information Report, Unit 1 6.5 NECS File: 131.95, FHARE: 15, HVAC Ducts Wrapped with Pyrocrete 6.6 Appendix 3 for EP M-10 Unit 1 Fire Protection of Safe Shutdown Equipment 6.7 NECS File: 131.95, FHARE: 80, Fire Dampers Installed at Variance with Manufacturers Instructions 6.8 NECS File: 131.95, FHARE: 6, "Seismic Gap At Concrete Block Walls" 6.9 Deleted in Revision 14. 6.10 NECS File: 131.95, FHARE 73, Undampered Ducts 6.11 SSER 23, June 1984 6.12NECS File: 131.95, FHARE 104, "Fire Proofing on Structural Steel for Block Walls" 6.13 Calculation 134-DC, Electrical Appendix R Analysis 6.14 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.15 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.16 NECS File: 131.95, FHARE 152, Evaluation of Fire Dampers in 480V Switchgear and Battery Rooms DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 5-A-4 9.5A-74 Revision 21 September 2013 FIRE AREA 5-A-4 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Northwest end of the Unit 1 Auxiliary Building, hot shutdown panel and nonvital 480V switchgear room area, El. 100 ft. 1.2 Description The area houses the hot shutdown panel and 480V switchgear. It occupies the northwest corner of the Auxiliary Building at El. 100 ft. A "no storage" area sign is posted in the hot shutdown panel area. 1.3 Boundaries North:
- A 3-hour rated barrier separates this area from Areas 3-BB and 3-B-1.
- A 3-hour rated barrier with nonrated seismic gaps separates this area from Areas 5-A-1, 5-A-2, and 5-A-3. (Ref. 6.12)
- Five 3-hour rated doors communicate into Areas 5-A-1, 5-A-2, 5-A-3 (1 door in Area 5-A-2 and two each to Areas 5-A-1 and 5-A-3).
- Three 1-1/2-hour rated fire dampers communicate to Areas 5-A-1, 5-A-2, 5-A-3 (1 damper in each area). (Refs. 6.23 and 6.11)
- Two protected duct penetrations without a fire damper penetrate to Area 5-A-1. (Refs. 6.7, 6.11 and 6.23)
- A duct penetration without a fire damper penetrates to Area 5-A-1. (Refs. 6.4., 6.8 and 6.23)
- A 3-hour rated barrier to the exterior.
- A lesser rated penetration seal to Area 5-A-1. (Refs. 6.20 and 6.23) South:
- A 3-hour rated barrier with nonrated seismic gap seals separates this area from Area 5-B-4. (Ref. 6.12)
- 3-hour rated barrier separates this area from Area S-5 and S-1.
- Two 3-hour rated doors communicate to Area 5-B-4.
- A duct penetration without a fire damper penetrates to Zone S-5. (Refs. 6.21 and 6.23) [CR V-9.5A (19) SAPN 50569573]
- Ventilation register with a 3-hour rated fire damper communicates with Zone S-1, the duct shaft. (Refs. 6.4 and 6.9)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 5-A-4 9.5A-75 Revision 21 September 2013 East:
- 3-hour rated barrier to area 5-A-1.
- 3-hour rated barrier separates the area from Zones 3-X and S-2 and Areas S-5 and 3-B-1.
- A duct penetration without a damper to area 5-A-1. (Refs. 6.4, 6.8 and 6.23)
- A 1-1/2-hour rated door communicate to Area S-5. (Ref. 6.23)
- A 3-hour rated door communicates to area 5-A-1. West:
- 3-hour rated barrier separates this area from Zone 14-A and 5-A-3.
- 3-hour rated barrier to Zone S-1.
- A 3-hour rated door communicates to area 5-A-3. Floor/Ceiling:
- 3-hour rated barriers to Areas 4-A, 4-A-1 and 4-B below and Areas 6-A-1, 6-A-2, 6-A-3, 6-A-4 and 6-A-5 above.
- Nonrated equipment hatch communicates to Area 4-B below and Area 6-A-5 above. (Ref. 6.23)
- One duct penetration to Area 6-A-5 without fire damper. (Refs. 6.4, 6.8 and 6.23) Protective
Enclosure:
- 1-hour rated fire resistive is provided for several HVAC ducts. (Refs. 6.7 and 6.11)
- Conduit K7450 is provided with a fire resistive wrap with an approximate fire rating of 3 hours, although 1 hour was committed. (Refs. 6.10, 6.17, and 6.22) 2.0 COMBUSTIBLES 2.1 Floor Area: 2,622 ft2 2.2 In situ Combustible Materials
- Cable Insulation
- Paper
- Rubber DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 5-A-4 9.5A-76 Revision 21 September 2013 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection in the area and inside hot shutdown panel.
3.2 Suppression
- CO2 hose stations
- Hose stations
- Portable fire extinguishers 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Auxiliary Feedwater A fire in this area may prevent the operation from the hot shutdown panel of AFW pumps 1-2 and 1-3. Since AFW pumps 1-2 and 1-3 will remain operational from the control room, safe shutdown will not be affected. Control of valves LCV-106, LCV-107, LCV-108 and LCV-109 from the hot shutdown panel may be lost due to a fire in this area. Operation of LCV-106 and LCV-107 will remain available from the control room. These valves are required for operation of AFW flow via AFW Pump 1-1. Since AFW Pump 1-1 is not credited for safe shutdown in this area, safe shutdown is not affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 5-A-4 9.5A-77 Revision 21 September 2013 Control of valves LCV-110, LCV-111, LCV-113 and LCV-115 from the Control Room or hot shutdown panel may be affected by a fire in this area. Steam generators 1-1 and 1-2 are credited for safe shutdown. Manual actions can be taken to align LCV-110 and LCV-111 to steam generators 1-1 and 1-2. 4.2 Chemical and Volume Control System A fire in this area may prevent the operation of the following components from the hot shutdown panel: valve 8104, boric acid transfer pumps 1-1 and 1-2 and charging pumps 1-1 and 1-2. Since charging pumps 1-1 and 1-2, boric acid transfer pump 1-2 and valve 8104 will remain operational from the control room, safe shutdown will not be affected. Valves 8149A, 8149B and 8149C may be lost due to a fire in this area. Redundant valves LCV-459 and LCV-460 will remain available to isolate letdown. Valves HCV-142 and FCV-128 may be affected by a fire in this area. If HCV-142 cannot be closed to isolate auxiliary spray during hot standby, existing redundant valves can be closed. The charging injection flow path is not affected by a failure of either HCV-142 or FCV-128. Spurious closure of FCV-128 will isolate seal injection flow. To achieve cold shutdown,FCV-128 may have to be bypassed and HCV-142 manually operated to establish auxiliary spray flow. A fire in this area may affect the transmitter and circuits associated with charging pump header flow transmitter, FT-128, and pressure transmitter, PT-142. Both charging pumps are available in this fire area to provide charging flow. Loss of these instruments will not affect safe shutdown. A fire in this area may affect circuits associated with letdown flow transmitter, FT-134. Loss of this instrument will not be available for diagnosis of letdown flow isolation. Letdown isolation valves LCV-459 and LCV-460 are not affected in this area and will remain available to isolate letdown. Loss of this instrument will not affect safe shutdown. 4.3 Component Cooling Water A fire in this area may prevent the operation of CCW pumps 1-1, 1-2 and 1-3 from the hot shutdown panel. However, operation of CCW pumps 1-1, 1-2 and 1-3 will remain available from the control room. Therefore safe shutdown will not be affected. A fire in this area may spuriously close FCV-355. FCV-355 can be manually operated for safe shutdown.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 5-A-4 9.5A-78 Revision 21 September 2013 Valves FCV-430 and FCV-431 may be affected by a fire in this area. FCV-430 can be manually operated to ensure safe shutdown. A fire in this area may affect valve FCV-356. The seal injection flowpath can also be affected by fire-induced spurious closure of FCV-128. The potential for a loss of all RCP seal cooling can occur if the valves in these flowpaths spuriously close simultaneously. To provide water to the RCP thermal barrier heat exchanger, locally open FCV-356 after opening its power breaker. A fire in this area may affect the circuits associated with the CCW flow transmitter on Header C (FT-69). This instrument is credited to indicate a loss of CCW flow. Loss of this indication will not affect flow to CCW Header C. Therefore, loss of this indicator will not affect safe shutdown. 4.4 Containment Spray A fire in this area may spuriously open valve 9001B. Since containment spray pump 1-2 will remain available, safe shutdown will not be affected with this valve open. 4.5 Diesel Fuel Oil System A fire in this area may affect Unit 2 power circuits for DFO transfer pumps 01 and 02. The circuits are protected by a fire barrier having an approximate rating of 3 hours although 1 hour was committed. Manual action may be necessary transfer power supplies from Unit 1 to Unit 2 in order to ensure safe shutdown. 4.6 Emergency Power System A fire in this are may affect Startup Transformers 1-1, 1-2, 2-1 and 2-2. Onsite power will remain available from all diesel generators for both Units 1 and 2. A fire in this area may result in a loss of power supplies associated with PY17N. Redundant power supply PY16 remains available. 4.7 Main Steam System A fire in this area may result in the loss of the following equipment: PT-514, PT-524, PT-534 and PT-544. Since two other trains of pressure indication for each steam generator will remain available, safe shutdown will not be affected. Valves FCV-248 and FCV-250 may be affected by a fire in this area. Valves FCV-761 and FCV-760 will remain available to isolate steam generator blowdown. Therefore, safe shutdown is not affected by a fire in this area. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 5-A-4 9.5A-79 Revision 21 September 2013 A fire in this area may result in the loss of FCV-95. Since AFW pump 1-2 will remain available to provide AFW, FCV-95 is not necessary for safe shutdown. Ten percent dump valves PCV-19, PCV-20, PCV-21 and PCV-22 may be affected by a fire in this area. Steam generator 1-1 and 1-2 are credited for safe shutdown. PCV-19 and PCV-20 can be manually operated to ensure safe shutdown. 4.8 Makeup System Level for the condensate storage tank, LT-40 may be lost due to a fire in this area. Feedwater will be available from the raw water storage reservoir through valves FCV-437. The normally closed manual valve can be locally opened prior to CST depletion. 4.9 Reactor Coolant System A fire in this area may affect the following components: LT-459, LT-460, NE-51, NE-52, TE-443A, TE-443B, TE-433A and TE-433B. Safe shutdown is not affected since redundant components will be available. Pressurizer PORVs PCV-455C, 456 and PCV-474 may be affected by a fire in this area. Since PORV blocking valves and auxiliary spray remain available, safe shutdown will not be affected. A fire in this area may spuriously start or prevent tripping of all four reactor coolant pumps. However, safe shutdown will not be affected since normal spray can be isolated which prevents inadvertent RCS pressure reduction. Seal injection will remain available for RCP seal cooling. A fire in this area may spuriously energize pressurizer heater groups 1-1, 1-2, 1-3 and 1-4. These heater groups can be manually de-energized to ensure safe shutdown. 4.10 Safety Injection System A fire in this area may prevent the refueling water supply valves 8805A and 8805B from auto opening on low VCT level. However, manual operation of these valves, from the control room, remains available. A fire in this area may spuriously open accumulator isolation valve 8808C. Manual action can be taken to close this valve. Circuits for containment sump isolation valve 8982B may be affected by a fire in this area. Power to the valve is administratively removed by maintaining a toggle DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 5-A-4 9.5A-80 Revision 21 September 2013 switch in the Control Room in the open position. The valve is normally closed, and spurious opening is not expected to occur. Therefore, safe shutdown is not affected. 4.11 Auxiliary Saltwater System A fire in this area may prevent the operation of ASW pumps 1-1 and 1-2 from the hot shutdown panel. However, safe shutdown will not be affected since the operation of ASW pumps 1-1 and 1-2 will remain available from the control room. Valves FCV-495 and FCV-496 may be lost due to a fire in this area. Valve FCV-601 will remain closed to provide ASW system integrity. A fire in this area may spuriously close valves FCV-602 and FCV-603. Manual action can be taken to open valve FCV-602. 4.12 HVAC HVAC equipment E-101, E-43, S-43 and S-44 may be affected by a fire in this area. Redundant equipment E-103 and E-44 is available for E-101 and E-43 respectively. If S-43 and S-44 are lost for at least 8 hours, portable fans must be used to provide HVAC. (Refs. 6.14 and 6.15)
5.0 CONCLUSION
This area does not meet the technical requirements of 10 CFR 50, Appendix R, Section III.G.3 because area wide automatic suppression system is not provided. The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- The loss of safe shutdown function in this area does not affect safe shutdown due to the availability of redundant functions and/or measures provided to preclude the effects of fire.
- Area wide smoke detection is provided.
- Manual fire fighting equipment is available.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 5-A-4 9.5A-81 Revision 21 September 2013 The existing fire protection features provide an acceptable level of safety equivalent to that achieved by compliance with Section III.G.2.
6.0 REFERENCES
6.1 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.2 Drawing No. 515569 6.3 DCN-DC1-EE-9913 provides isolator on RPM Tach-Pack 6.4 SSER 23, June 1984 6.5 Calculation M-824, Combustible Loading 6.6 Drawing 065126, Fire Protection Information Report, Unit 1 6.7 NECS File: 131.95, FHARE: 15, HVAC Ducts Wrapped in Pyrocrete 6.8 NECS File: 131.95, FHARE: 73, Undampered Ducts 6.9 DCN DC0-EA-37379, Install Fire Dampers to Vent Shaft 6.10 DCN DC2-EA-22612 Rev. 0, Fireproof Conduit 6.11 NECS File: 131.95, FHARE: 80, Fire Dampers Installed at Variance with Manufacturer Instructions 6.12 NECS File: 131.95, FHARE: 6, "Seismic Gap At Concrete Block Walls" 6.13 Deleted in Revision 14. 6.14 Calculation M-911, Evaluation of Safe Shutdown Equipment During Loss of HVAC 6.15 Calculation M-912, HVAC Interactions For Safe Shutdown 6.16 DCNs DC1-EE-47591, DC1-EE-47593 and DC1-EE-47594 Provide Transfer Switches at the 4kV Switchgear and Mode Selector Switches at the Hot Shutdown Panel 6.17 PG&E Design Change Notice DC2-EA-049070, Unit 1 ThermoLag Replacement 6.18 Calculation 134-DC, Electrical Appendix R Analysis 6.19 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.20 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.21 NECS File: 131.95, FHARE 27, Undampered Duct Penetrations in Concrete Lined Shafts 6.22 SSER-31, April 1985 6.23 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-A-1, 6-A-2, 6-A-3 9.5A-82 Revision 21 September 2013 FIRE AREAS 6-A-1, 6-A-2, 6-A-3 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Northwest side of the Unit 1 Auxiliary Building. Unit 1 battery, inverter, and dc switchgear rooms, El. 115 ft. 1.2 Description Fire Areas 6-A-1, 6-A-2, and 6-A-3 are separate fire areas each containing redundant batteries, inverters, and dc switchgear, one train of which is required for safe shutdown. These fires areas are situated side by side, with Fire Area 6-A-2 located between Fire Area 6-A-1 to the west and Fire Area 6-A-3 to the east. Due to similarities between these three areas, they have been combined into one section. Battery room ventilation is provided by a supply fan and an exhaust fan located in separate fire zones isolated by 25 ft of open space (Fire Zones 8-B-5 and 8-B-7). Either fan provides adequate flow to limit hydrogen concentration well below the explosive concentration. Control room annunciation is provided for loss of battery room ventilation. Additionally control room annunciation is provided for dc overvoltage which could result in excessive hydrogen generation. Ventilation for the inverter and dc switchgear room is provided by two 100 percent supply fans which also supply ventilation for the 480V vital switchgear and are unrelated to the battery room ventilation. (Ref. 6.9) The battery rooms are separated from the inverter and switchgear rooms. (Ref. 6.6) 1.3 Boundaries 1.3.1 Fire Area 6-A-1 North:
- 3-hour rated barrier separates this area from Area 3-BB.
South:
- 3-hour rated barrier separates this area from Area 6-B-1.
- Unrated structural gap seal to Fire Area 6-B-1. (Ref. 6.12).
- A 3-hour rated door communicates to Area 6-B-1.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-A-1, 6-A-2, 6-A-3 9.5A-83 Revision 21 September 2013 East:
- 3-hour rated barrier separates this area from Area 6-A-2.
- A 3-hour rated door communicates to Area 6-A-2.
- A ventilation opening with a 3-hour rated fire damper penetrates to Area 6-A-2.
- Four protected ducts with no fire damper penetrate Area 6-A-2. Dampers are provided at the registers. (Refs. 6.8 and 6.5) West:
- 3-hour rated barrier separates this area from Areas 6-A-5, 6-B-5.
- A 3-hour rated door communicates to Area 6-A-5.
- A ventilation opening with a 1 1/2-hour rated fire damper penetrates to Area 6-A-5.
- Three protected ducts with no fire damper penetrate to Area 6-A-5. Dampers are provided at the registers. (Ref. 6.5) Floor/Ceiling:
- 3-hour rated barriers.
1.3.2 Fire Area 6-A-2 North:
- 3-hour rated barrier separates this area from Area 3-BB. South:
- 3-hour rated barrier separates this area from Area 6-B-2.
- Unrated structural gap seal to Fire Area 6-B-2. (Ref. 6.12).
- A 3-hour rated door communicates to Area 6-B-2.
East:
- 3-hour rated barrier separates this area from Area 6-A-3.
- A 3-hour rated door communicates to Area 6-A-3.
- A ventilation opening with a 3-hour rated fire damper penetrates to Area 6-A-3.
- Four protected ducts with no fire damper penetrate to Area 6-A-3. Dampers are provided at the registers. (Refs. 6.8 and 6.5)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-A-1, 6-A-2, 6-A-3 9.5A-84 Revision 21 September 2013 West:
- 3-hour rated barrier separates this area from Areas 6-A-1.
- A 3-hour rated door communicates to Area 6-A-1.
- A ventilation opening with a 3-hour rated fire damper penetrates to Area 6-A-1.
- Four protected ducts with no fire damper penetrate to Area 6-A-1. Dampers are provided at the registers. (Refs. 6.8 and 6.5)
Floor/Ceiling:
- 3-hour rated barriers. 1.3.3 Fire Area 6-A-3 North:
- 3-hour rated barrier separates this area from Area 3-BB. South:
- 3-hour rated barrier separates this area from Area 6-B-3.
- Unrated structural gap seal to Fire Area 6-B-3s. (Ref. 6.12)
- A 3-hour rated door communicates to Area 6-B-3.
East:
- 3-hour rated barrier separates this area from Area 6-A-4.
- A 3-hour rated door communicates to Area 6-A-4.
- Two protected ducts with no fire damper penetrate to Area 6-A-4. Dampers are provided at the registers. (Refs. 6.8 and 6.5)
West:
- 3-hour rated barrier separates this area from Areas 6-A-2.
- A 3-hour rated door communicates to Area 6-A-2.
- A ventilation opening with a 3-hour rated fire damper penetrates to Area 6-A-2.
- Four protected ducts with no fire damper penetrate Area 6-A-2. Dampers are provided at the registers. (Refs. 6.8 and 6.5)
Floor/Ceiling:
- 3-hour rated barriers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-A-1, 6-A-2, 6-A-3 9.5A-85 Revision 21 September 2013 2.0 COMBUSTIBLES (typical for each area) 2.1 Floor Area: 672 ft2 2.2 In situ Combustible Materials
- Paper
- Plastic
- Cable insulation
- Wood 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION (typical for each area) 3.1 Detection
- Smoke detection in the inverter, the dc switchgear rooms and the battery rooms. (Ref. 6.7) 3.2 Suppression
- CO2 hose stations
- Fire hose stations
- Portable fire extinguishers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-A-1, 6-A-2, 6-A-3 9.5A-86 Revision 21 September 2013 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Fire Area 6-A-1 4.1.1 Auxiliary Feedwater AFW pump 1-3 may be lost due to a fire in this area. Redundant AFW pumps 1-1 will be available to provide AFW to steam generator 1-3 and 1-4.
A fire in this area may affect AFW supply valves LCV-113 and LCV-115. Steam generator 1-3 and 1-4 is credited for safe shutdown. Redundant valves LCV-108 and LCV-109 will remain available for AFW flow from AFW pump 1-1. 4.1.2 Chemical and Volume Control System Charging pump 1-1 and ALOP 1-1 may be lost due to a fire in this area. Redundant charging pump 1-2 and ALOP 1-2 and charging pump 1-3 will be available to provide charging flow. Boric acid transfer pump 1-1 may be lost due to a fire in this area. Redundant boric acid transfer pump 1-2 will remain available Valve 8105 may be affected by a fire in this area. Safe shutdown will not be affected since the RWST can be made available to provide a charging suction flowpath. A fire in this area may affect valve 8107. Since valve 8107 has redundant components available to provide the required functions, this valve's position will not have an affect on safe shutdown. A fire in this area may spuriously open valves 8149A, 8149B, 8149C, LCV-459 or LCV-460. Operator action can be taken to fail 8149A, 8149B and 8149C closed. Therefore, safe shutdown is not affected. Valves 8146 and 8147 may fail open due to a fire in this area. This condition will not affect safe shutdown since the PORVs will remain available for pressure reduction. Valve LCV-112B may be affected by a fire in this area. If control of this valve is lost, the VCT can be isolated by closing valve LCV-112C. Valve 8805B can be opened to provide water to the charging pumps from the RWST. Boric acid storage tank 1-2 level indication from LT-106 may be lost due to a fire in this area. Borated water from the RWST will be available. Therefore, BAST level indication is not required. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-A-1, 6-A-2, 6-A-3 9.5A-87 Revision 21 September 2013 4.1.3 Component Cooling Water CCW pump 1-1 and ALOP 1-1 may be lost due to a fire in this area. Redundant CCW pumps and ALOPs 1-2 and 1-3 will be available to provide CCW. FCV-430 may be affected by a fire in this area. Valve FCV-431 will remain available to enable the use of redundant CCW heat exchanger 1-2. A fire in this area may spuriously close FCV-750. Since RCP seal injection will remain available, adequate RCP seal cooling will be provided and FCV-750 will not be required open. 4.1.4 Emergency Power A fire in this area may disable the diesel generator 1-2 backup control circuit. The normal control circuit will remain available. A fire in this area may disable diesel generator 1-3. Diesel generators 1-1 and 1-2 will remain available for safe shutdown. A fire in this area may disable startup transformers 1-1, 1-2, 2-1 and 2-2. Onsite power from diesel generators 1-1 and 1-2 will remain available for Unit 1 and all three diesel generators 2-1, 2-2 and 2-3 will remain available for Unit 2. All power supplies on the "F" Bus may be lost due to a fire in this area. These power supplies are not required since redundant trains on the "G" and "H" Buses will be available. A fire in this area may disable dc panel SD13 backup battery charger ED131. Normal battery charger ED132 will remain available. A fire in this area may result in a loss of power supplies associated with PY17N. Redundant power supply PY16 remains available. 4.1.5 Main Steam System A fire in this area may affect the following instrumentation: LT-516, LT-526, LT-529, LT-536, LT-539, LT-546, PT-514, PT-524, PT-534 and PT-544. Safe shutdown is not affected since there are redundant trains of instrumentation for all four steam generators. Valve PCV-19 may be affected by a fire in this area. Air can be isolated and vented to fail PCV-19 in the desired, closed position. Redundant dump valves (PCV-20, PCV-21 and PCV-22) will remain available to provide cooldown capability. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-A-1, 6-A-2, 6-A-3 9.5A-88 Revision 21 September 2013 A fire in this area may spuriously close FCV-38. This valve can be manually opened to ensure safe shutdown. 4.1.6 Makeup System Condensate storage tank level indication, LT-40 may be lost due to a fire in this area. Water from the raw water storage reservoir will remain available through valve FCV-436 in order to provide auxiliary feedwater. A manual action can be performed to locally open the normally closed valve prior to CST depletion. 4.1.7 Reactor Coolant System A fire in this area may result in the loss of the following components: LT-406, LT-459, NE-31, NE-51, PT-406, PT-403, TE-413A, TE-413B, TE-423A and TE-423B. Since redundant instrumentation exists safe shutdown is not affected. Pressurizer PORV blocking valve 8000A may be affected by a fire in this area. Since pressurizer PORV PCV-474 will remain closed, the position of valve 8000A will not affect safe shutdown. A fire in this area may prevent the tripping of the four reactor coolant pumps. If the RCPs are not tripped, safe shutdown will not be affected because valves PCV-455A and PCV-455B will remain available to isolate normal spray. Seal injection will remain available for RCP seal cooling. Pressurizer heater group 1-4 may spuriously operate due to a fire in this area. This heater group can be manually tripped to defeat any spurious operation. 4.1.8 Safety Injection System SI pump 1-1 and accumulator isolation valve 8808A are required off and closed. A fire in this area spuriously energize SI pump 1-1 and may open valve 8808A. Valve 8808A can be manually operated and SI pump 1-1 can be manually tripped to ensure safe shutdown. A fire in this area may result in the loss of the following valves: 8801A, 8803A and 8805A. Redundant valves 8801B, 8803B and 8805B will remain available to ensure safe shutdown. 4.1.9 Auxiliary Saltwater System ASW pump 1-1 may be lost due to a fire in this area. The redundant ASW pump 1-2 will remain available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-A-1, 6-A-2, 6-A-3 9.5A-89 Revision 21 September 2013 A fire in this area may spuriously open valve FCV-601. FCV-495 and FCV-496 can be closed to provide ASW system integrity. Valve FCV-602 may be affected by a fire in this area. FCV-602 will be used with ASW pump 1-1. Since ASW pump 1-2 is used during a fire in this area, FCV-602 is not required. 4.1.10 HVAC HVAC equipment E-103, E-43, S-43, FCV-5045 and S-69 may be affected by a fire in this area. E-103 and S-69 will not be necessary during a fire in this area. S-43, E-43 and FCV-5045 have the following redundant components: S-44, E-44 and FCV-5046. Therefore, safe shutdown is not affected by a fire in this area. 4.2 Fire Area 6-A-2 4.2.1 Auxiliary Feedwater A fire in this area may affect valves LCV-106, LCV-107, LCV-108 and LCV-109. Steam generators 1-1 and 1-2 are credited for safe shutdown. Redundant valves LCV-110 and LCV-111 will remain available. 4.2.2 Chemical and Volume Control System Charging pumps 1-2 and 1-3 and ALOP 1-2 may be lost due to a fire in this area. Redundant charging pump and ALOP 1-1 will be available to provide charging flow. Boric acid transfer pump 1-2 may be lost due to a fire in this area. Redundant boric acid transfer pump 1-1 will remain available. Valve 8106 may be affected by a fire in this area. Since the RWST will be aligned to the charging pump suction, safe shutdown will not be affected. A fire in this area may cause valve 8108 to spuriously operate. Since valve 8108 has redundant components available, safe shutdown is not affected. Valves 8104 and FCV-110A may be affected by a fire in this area. In order to provide boric acid to the charging pump suction, one of these valves must be open. FCV-110A fails open to provide a charging path, however, manual valve 8471 must also be opened. Valve 8104 can be opened from the hot shutdown panel in order to provide boric acid to the charging pump suction. Therefore, either of these two paths can be used to ensure safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-A-1, 6-A-2, 6-A-3 9.5A-90 Revision 21 September 2013 A fire in this area may affect valves 8146, 8147 and 8148. Safe shutdown is not compromised because the PORVs will remain available for pressure reduction. Valves FCV-128 and HCV-142 may be affected by a fire in this area. Valve HCV-142 is not necessary during a fire in this area because redundant components exist. Spurious closure of FCV-128 will isolate seal injection flow. An operator action can be taken in the control room to open FCV-128 after taking its controller to the manual mode of operation. Volume control tank outlet valve LCV-112C may be affected by a fire in this area. If LCV-112C spuriously closes then valve 8805A can be opened to provide water from the RWST to the charging pump suction. Otherwise, the VCT may be isolated by closing LCV-112B. Letdown isolation valves LCV-459 and LCV-460 may be affected by a fire in this area. However, safe shutdown is not affected since redundant valves 8149A, 8149B and 8149C will be available. Boric acid storage tank 1-2 level indication from LT-106 may be lost due to a fire in this area. Borated water from the RWST will remain available. Therefore, BAST level indication is not required. A fire in this area may affect the transmitter and circuits associated with charging pump header flow transmitter, FT-128, and pressure transmitter, PT-142. Because either charging pump 1-1 or 1-2 is not affected in this area, the loss of these instruments will not adversely affect safe shutdown. 4.2.3 Component Cooling Water CCW pump 1-2 and ALOP 1-2 may be lost due to a fire in this area. Redundant CCW pumps and ALOPs 1-1 and 1-3 will be available to provide CCW. Valve FCV-431 may be affected by a fire in this area. Redundant valve FCV-430 will remain available. A fire in this area may spuriously close FCV-365, making RHR HX 1-1 unavailable. Redundant valve FCV-364 will be available and allow RHR HX 1-2 to be used. A fire in this area may spuriously close valve FCV-356. The seal injection flowpath can also be affected in this area due to fire-induced spurious closure of FCV-128. The potential for a loss of all seal cooling can occur if the valves in these flowpaths spuriously close simultaneously. A operator action can be taken in the control room to open FCV-128 after taking its controller to the manual mode of operation, to provide RCP seal injection. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-A-1, 6-A-2, 6-A-3 9.5A-91 Revision 21 September 2013 A fire in this area may affect circuits associated with CCW flow transmitters for Header B (FT-65) and Header C (FT-69). Redundant CCW Header A is credited for a fire in this fire area, and flow transmitter FT-68 will remain available. Loss of CCW to header C will also remain available, and loss of FT-69 indication will not affect flow to the header.
A fire in this area may affect circuits associated with the differential pressure transmitter for CCW Hx 1-2 (PT-6). Redundant CCW Hx 1-1 will remain available for safe shutdown. Loss of this instrument will not affect safe shutdown. 4.2.4 Containment Spray A fire in this area may spuriously operate containment spray pump 1-1 and open 9001A. Operator action can be taken to trip CS pump 1-1. Therefore, safe shutdown will not be affected. Valve 9003A may be spuriously opened due to a fire in this area. This valve can be manually closed in order to isolate containment spray. 4.2.5 Diesel Fuel Oil System Diesel fuel oil pump 0-2 may be lost due to a fire in this area. Redundant diesel fuel oil pump 0-1 remains available. Valves LCV-85, LCV-86 and LCV-87 may be lost due to a fire in this area. However, safe shutdown is not affected because redundant valves LCV-88, LCV-89 and LCV-90 will remain available. 4.2.6 Emergency Power A fire in this area may disable the diesel generator 1-1 backup control circuit. The normal control circuit will remain available. A fire in this area may disable diesel generator 1-2. Diesel generators 1-1 and 1-3 will remain available for safe shutdown. A fire in this area may disable startup transformers 1-1, 1-2, 2-1 and 2-2. Onsite power from diesel generators 1-2 and 1-3 will remain available for Unit 1 and all three diesel generators will remain available for Unit 2. All power supplies on the "G" Bus may be lost due to a fire in this area. These power supplies are not necessary since redundant trains on the "F" and "H" Buses will be available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-A-1, 6-A-2, 6-A-3 9.5A-92 Revision 21 September 2013 A fire in this area may result in a loss of power supplies associated with PY17N and PY16. Loss of power to PY17N and PY16 results in the spurious closure of FCV-128 when in the automatic mode. FCV-128 can be opened by setting its controller in the control room to manual. 4.2.7 Main Steam System A fire in this area may affect the power supplies to the following instruments: LT-519, LT-549, PT-515, PT-525, PT-535 and PT-545. Since redundant instrumentation exists for each steam generator, safe shutdown will not be affected. A fire in this area may affect valve PCV-21. Air can be isolated and vented to fail PCV-21 closed. Redundant dump valves (PCV-19, PCV-20 and PCV-22) will remain available to provide cooldown capability. Valves FCV-760 and FCV-761 may be affected by a fire in this area. Redundant valves FCV-154 and FCV-248 for FCV-761 and FCV-151 and FCV-250 for FCV-760 remain available to isolate steam generator blowdown. A fire in this area may affect valve FCV-95. AFW pumps 1-2 and 1-3 will remain available if FCV-95 is unable to provide steam to AFW pump 1-1. Main steam isolation valves FCV-41, FCV-42 and bypass valve FCV-24 may be affected by a fire in this area. These valves can be manually operated to ensure safe shutdown. 4.2.8 Reactor Coolant System A fire in this area may result in the loss of power for the following equipment: LT-460, NE-32, TE-433A, TE-433B, TE-443A and TE-443B. Since redundant components exist, safe shutdown is not affected. Valves PCV-455C and 8000B may be affected by a fire in this area. PCV-455C will fail in the desired, closed position. Redundant valves PCV-456 and 8000C will be available for pressure reduction. Therefore, safe shutdown is not affected. A fire in this area may prevent the tripping of reactor coolant pumps 1-1, 1-2, 1-3 and 1-4. Since PCV-455A and PCV-455B can isolate normal spray in order to prevent uncontrolled pressure reduction, safe shutdown will not be affected if the reactor coolant pumps continue to operate. Seal injection will remain available for seal cooling. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-A-1, 6-A-2, 6-A-3 9.5A-93 Revision 21 September 2013 Pressurizer heaters groups 1-3 and 1-4 may be affected by a fire in this area. Manual actions can be taken to de-energize heater group 1-4 and switch heater group 1-3 to the vital power supply. Therefore, safe shutdown is not affected. 4.2.9 Residual Heat Removal System RHR pump 1-1, FCV-641A and outlet valve 8700A may be lost due to a fire in this area. The redundant train RHR pump 1-2, FCV-641B, and 8700B will be available so safe shutdown will not be affected. Valve 8701 may be affected by a fire in this area. This valve is closed with its power removed during normal operation and will not spuriously open. This valve can be manually operated for RHR operations. 4.2.10 Safety Injection System Valves 8801B, 8803B and 8805B may be lost due to a fire in this area. Safe shutdown will not be affected because redundant valves 8801A, 8803A and 8805A will remain available. Valves 8808B and 8808D may be affected by a fire in this area. These valves can be manually closed to ensure safe shutdown. A fire in this area may damage circuits for valve 8982A. Power to the valve is administratively removed by maintaining a toggle switch in the Control Room in the open position. The valve is normally closed, and spurious opening is not expected to occur. In addition, an operator action can be taken to open the power breaker to the valve to further preclude spurious operation. Therefore, safe shutdown is not affected. A fire in this area may spuriously open valve 8804A. This valve can be manually closed to ensure safe shutdown. 4.2.11 Auxiliary Saltwater System ASW pump 1-2 may be lost due to a fire in this area. Redundant ASW pump 1-1 will be available to provide the ASW function. Valve FCV-603 may be lost due to a fire in this area. Since redundant valve FCV-602 remains available, safe shutdown is not affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-A-1, 6-A-2, 6-A-3 9.5A-94 Revision 21 September 2013 4.2.12 HVAC A fire in this area may affect E-101 and S-68. Since these components are not required to be operational during a fire and redundant components are available, safe shutdown is not affected. 4.3 Fire Area 6-A-3 4.3.1 Auxiliary Feedwater AFW pump 1-2 may be lost for a fire in this area. Redundant AFW pump 1-3 will be available to provide AFW to steam generators 1-3 and 1-4. Valves LCV-110 and LCV-111 may be affected by a fire in this area. Redundant valves LCV-113 and LCV-115 will remain available to provide AFW flow to steam generators 1-3 and 1-4. 4.3.2 Chemical and Volume Control System Valve 8145 may be affected by a fire in this area. Redundant components will remain available to isolate auxiliary spray and the PORVs can be used for RCS depressurization, safe shutdown will not be affected. Boric acid storage tank 1-1 level indication from LT-102 may be lost due to a fire in this area. Borated water from the RWST will remain available. Therefore, BAST level is not required. A fire in this area might result in the spurious closure of charging pump discharge flow control valve FCV-128. This valve can be opened from the control room after switching to manual control. A fire in this area may affect valves LCV-459 and LCV-460. Redundant components 8149A, 8149B and 8149C are available to isolate letdown, safe shutdown is not affected. A fire in this area may affect circuits associated with letdown flow transmitter, FT-134. Letdown isolation valves 8149A, 8149B, and 8149C will remain available to isolate letdown. Therefore, the loss of this indication will not affect safe shutdown. 4.3.3 Component Cooling Water CCW pump 1-3 and ALOP 1-3 may be lost for a fire in this area. Redundant pumps and ALOPs 1-1 and 1-2 are available to provide CCW. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-A-1, 6-A-2, 6-A-3 9.5A-95 Revision 21 September 2013 CCW valve FCV-357 may be affected by a fire in this area. Since seal injection will remain available, FCV-357 will not be required open. A fire in this area may spuriously close FCV-355. FCV-355 can be manually operated for safe shutdown. FCV-364 may spuriously close due to a fire in this area. If this valve closes, redundant RHR HX 1-1 will be available to provide this safe shutdown function. A fire in this area may affect circuits associated with CCW flow transmitter for Header C (FT-69). Flow through CCW Header C is not credited in this fire area. Therefore, loss of flow indication will not affect safe shutdown. 4.3.4 Containment Spray Circuits for containment spray pump 1-2 and outlet valve 9001B may be damaged by a fire in this area. Operator action can be taken to trip CS pump 1-2. Therefore, safe shutdown is not affected. A fire in this area may spuriously open valve 9003B. This valve can be manually closed. 4.3.5 Diesel Fuel Oil System Diesel fuel oil pump 0-1 may be lost due to a fire in this area. The redundant diesel fuel oil pump 0-2 remains available. Valves LCV-88, LCV-89 and LCV-90 may be lost due to a fire in this area. Redundant valves LCV-85, LCV-86 and LCV-87 will remain available. 4.3.6 Emergency Power A fire in this area may disable diesel generator 1-1. Diesel generators 1-2 and 1-3 will remain available for safe shutdown. A fire in this area may disable the diesel generator 1-3 backup control circuit. The normal control circuit will remain available. All power supplies on the H Bus may be lost due to a fire in this area. These power supplies are not necessary since redundant trains on the G and F Buses will be available. A fire in this area may disable dc panel SD11 backup battery charger ED121. Normal battery charger ED11 will remain available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-A-1, 6-A-2, 6-A-3 9.5A-96 Revision 21 September 2013 A fire in this area may disable dc panel SD12 backup battery charger ED121. Normal battery charger ED12 will remain available. A fire in this area may affect vital Uninterrupted Power Supply (UPS) IY13 and IY14 and vital instrument ac distribution panels PY 13 and PY14. Redundant UPS IY11 and IY12 and distribution panels PY11 and PY12 will remain available. A fire in this area may result in a loss of power supplies associated with PY17N and PY16. Loss of power to PY17N and PY16 results in the spurious closure of FCV-128 when in the automatic mode. FCV-128 can be opened by setting its controller in the control room to manual. 4.3.7 Main Steam System A fire in this area may result in the loss of the following components: LT-517, LT-527, LT-537, LT-547, PT-516, PT-526, PT-536, PT-546, LT-518, LT-528, LT-538 and LT-548. Since redundant trains of instrumentation exist for all four steam generators, safe shutdown is not affected. Valves PCV-20 and PCV-22 may be affected by a fire in this area. Air can be isolated and verified to fail PCV-20 and PCV-22 closed. Safe shutdown is not affected. Redundant valve PCV-21 will remain available for cooldown. A fire in this area may spuriously close FCV-37. Safe shutdown will not be affected since AFW pump 1-3 will remain available to provide AFW to the steam generators 1-3 and 1-4. Valves FCV-762 and FCV-763 may spuriously open due to a fire in this area. Valves FCV-157 and FCV-246 can be shut to provide steam generator blowdown in place of FCV-762 and FCV-160 and FCV-244 can perform the same function for FCV-763. A fire in this area may affect FCV-43 and FCV-44. These valves can be manually shut to ensure safe shutdown. 4.3.8 Reactor Coolant System A fire in this area may affect LT-461, NE-52, PT-403 and PT-405. These instruments have redundant components available for safe shutdown. A fire in this area may prevent all four reactor coolant pumps from being tripped. In order to prevent uncontrolled pressure reduction, PCV-455A and PCV-455B can be closed to isolate normal spray. Therefore, operation of the reactor coolant pumps will not affect safe shutdown. Seal injection will remain available for RCP seal cooling. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-A-1, 6-A-2, 6-A-3 9.5A-97 Revision 21 September 2013 Pressurizer heater groups 1-1, 1-2, 1-3 and 1-4 may be affected by a fire in this area. Manual actions can be taken to de-energize heater groups 1-1, 1-3 and 1-4 and switch heater group 1-2 to the vital power supply. Therefore, safe shutdown is not affected. Pressurizer PORV PCV-456 and blocking valve 8000C may be affected by a fire in this area. Since PCV-456 fail closed during a fire and PCV-455C will remain available for pressure reduction, safe shutdown is not affected. 4.3.9 Residual Heat Removal System RHR pump 1-2, valve FCV-641B and outlet valve 8700B may be lost for a fire in this area. The redundant train (RHR PP 1-1 and 8700A, and FCV641A) will be available to provide the RHR function. Valve 8702 may be affected by a fire in this area. This valve is closed during normal operation and can not spuriously open. This valve can be manually operated for RHR operations. 4.3.10 Safety Injection System SI pump 1-2 and valve 8808C are required off and closed during RCS pressure reduction. A fire in this area may spuriously operate SI pump 1-2 and may prevent the operation of 8808C. SI pump 1-2 can be manually de-energized and valve 8808C can be manually closed in order to achieve safe shutdown. A fire in this area may damage circuits for valve 8982B. Power to the valve is administratively removed by maintaining a toggle switch in the Control Room in the open position. The valve is normally closed, and spurious opening is not expected to occur. Therefore, safe shutdown will not be compromised. A fire in this area may affect circuits associated with RWST Level Transmitter LT-920. RWST inventory could be diverted due to spurious operation of Containment Spray pump and discharge valve. Manual action is credited to mitigate the spurious operation, and this indicator will not be available for diagnosis. 4.3.11 Auxiliary Saltwater System Valves FCV-495 and FCV-496 may be affected by a fire in this area. FCV-601 will remain closed to provide ASW system integrity. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-A-1, 6-A-2, 6-A-3 9.5A-98 Revision 21 September 2013 4.3.12 HVAC One train of HVAC components (E-44, S-44, FCV-5046 and S-67) may be lost due to a fire in this area. S-67 is not required for a fire in this area. A redundant train of HVAC components (S-43, E-43 and FCV-5045) will remain available to provide the HVAC function. 4.3.13 Unit 2 Components 4.3.13.1 Main Steam System A fire in this area may result in the loss of the following components: LT-517, LT-527, LT-537, LT-547, PT-516, PT-546. Since redundant trains of instrumentation exist for all four steam generators, safe shutdown is not affected. 4.3.13.2 Reactor Coolant System A fire in this area may result in the loss of the RCS pressure transmitter PT-405. Redundant instruments PT-403 and PT-406 are not affected and will be available for safe shutdown.
5.0 CONCLUSION
- The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Loss of safe shutdown functions in an area does not adversely affect safe shutdown.
- Automatic smoke detection in inverter and dc switchgear rooms.
- Manual fire fighting equipment is available for use. These areas meet the intent of 10 CFR 50, Appendix R, Section III.G and no exemptions or deviations have been requested.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-A-1, 6-A-2, 6-A-3 9.5A-99 Revision 21 September 2013
6.0 REFERENCES
6.1 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.2 Drawing No. 515570 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065126, Fire protection Information Report, Unit 1 6.5 NECS File: 131.95, FHARE: 15, HVAC Ducts Wrapped With Pyrocrete 102 6.6 NECS File: 131.95, FHARE: 26, Non-rated Barrier 6.7 DCN DC0-EE-35151, Provide Smoke Detection for Battery Rooms 6.8 NECS File: 131.95, FHARE: 80, Fire Dampers Installed at Variance to Manufactures Instructions 6.9 Response to Q.21 of PG&E letter dated November 13, 1978 6.10 Calculation 134-DC, Electrical Appendix R Analysis 6.11 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.12 NECS File: 131.95, FHARE 134, "Non-rated Structural Gap Seals in Fire Barriers" 6.13 NECS File: 131.95, FHARE 152, Evaluation of Fire Dampers in 480V Switchgear and Battery Rooms DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-A-4 9.5A-100 Revision 21 September 2013 FIRE AREA 6-A-4 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Northwest side of the Auxiliary Building, El. 115 ft.
1.2 Description This fire area is east of the H Bus battery inverter and dc switchgear room, Fire Area 6-A-3. Unit 1 reactor trip switchgear and rod programmer area. 1.3 Boundaries North:
- 3-hour rated barrier separates this area from Area 3-BB and Zone 3-AA.
South:
- 3-hour rated barrier separates this area from Area 6-B-4 and Zone S-5.
- Unrated structural gap seal to Fire Area 6-B-4. (Ref. 6.10)
- A 3-hour rated door communicates to Area 6-B-4.
- A duct penetration without a fire damper penetrates to Zone S-5. (Ref. 6.5)
East:
- 3-hour rated barrier separates this area from Zones 3-AA, S-2, and S-5.
- A 3-hour rated door communicates to Zone S-5. West:
- 3-hour rated barrier separates this area from Area 6-A-3.
- A 3-hour rated door communicates to Area 6-A-3.
- Two duct penetrations without fire dampers penetrate to Area 6-A-3. (Ducts are protected within 6-A-3 with dampers at registers.) (Ref. 6.7)
Floor/Ceiling:
- 3-hour rated barriers separate this area from Area 5-A-4 below and Areas 7-A and 7-C above.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-A-4 9.5A-101 Revision 21 September 2013 2.0 COMBUSTIBLES 2.1 Floor Area: 1,222 ft2 2.2 In situ Combustible Materials
- Cable insulation
- Plastic
- Rubber
- Oil
- Paper 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection 3.2 Suppression
- CO2 hose stations
- Hose stations
- Portable fire extinguishers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-A-4 9.5A-102 Revision 21 September 2013 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Chemical and Volume Control System Valve 8145 may be affected by a fire in this area. Redundant valves exist to prevent uncontrolled pressure reduction. A fire in this area may affect cables associated with Centrifugal Charging Pump 1-3. Redundant charging pumps 1-1 and 1-2 will remain available for the RCS inventory control function A fire in this area may affect circuits associated with letdown flow transmitter, FT-134. Letdown isolation valves LCV-459, LCV-460, 8149A, 8149B, and 8149C will remain available to isolate letdown. Therefore, the loss of this indication will not affect safe shutdown. A fire in this area may result in spurious closure of charging pump discharge flow control valve FCV-128. This valve can be opened from the control room after switching to manual control.
4.2 Component Cooling Water A fire in this area may spuriously close FCV-364. Heat exchanger 1-1 will be available for safe shutdown. 4.3 Emergency Power A fire in this area may result in the loss of power supplies associated with PY17N and PY16. Loss of power to PY17N and PY16 results in the spurious closure of FCV-128 when in the automatic mode. FCV-128 can be opened by setting its controller in the control room to manual. 4.4 Main Steam System A fire in this area may result in the loss of the following components: LT-517, LT-527, LT-537, LT-547, PT-516 and PT-546. Since each steam generator has a redundant train of components, safe shutdown is not affected. 4.5 Reactor Coolant System A fire in this area may affect circuits for the reactor vessel vent valves 8078A, 8078B, 8078C and 8078D. Valves 8078A and 8078B are in series, likewise for 8078C and 8078D. Operator action can be taken to fail the valves closed. Therefore, safe shutdown is not affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-A-4 9.5A-103 Revision 21 September 2013 Valve PCV-456 may be lost due to a fire in this area. Blocking valve 8000C may be closed for RCS isolation and pressure control. PCV-455C will remain available for pressure reduction. RCS pressure indication, PT-405 may be lost due to a fire in this area. Redundant components PT-406 and PT-403 will remain available. Pressurizer heater groups 1-1, 1-2, 1-3 and 1-4 may be affected by a fire in this area. Manual actions can be taken to de-energize heater 1-1 and 1-4 and switch heater groups 1-2 and 1-3 to the vital power supply. Therefore, safe shutdown is not affected. 4.5 Safety Injection System A fire in this area may affect circuits for valve 8982B. Power to the valve is administratively removed by maintaining a toggle switch in the Control Room in the open position. The valve is normally closed, and spurious opening is not expected to occur. Therefore, safe shutdown will not be affected. 4.6 HVAC S-44 and E-44 may be lost due to a fire in this area. Redundant components S-43 and E-43 will remain available to provide the HVAC function.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- The loss of safe shutdown functions located in this area will not affect safe shutdown capability.
- Automatic smoke detection is provided.
- Manual fire fighting equipment is provided.
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
The existing fire protection features provide an acceptable level of safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.2. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-A-4 9.5A-104 Revision 21 September 2013
6.0 REFERENCES
6.1 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.2 Drawing No. 515570 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065126, Fire protection Information Report, Unit 1 6.5 NECS File: 131.95, FHARE: 27, Undampered Duct Penetrations in Concrete Lined Shafts 6.6 NECS File: 131.95, FHARE: 15, HVAC Duct Wrapped in Pyrocrete 6.7 NECS File: 131.95, FHARE: 80, Fire Dampers Installed at Variance with Manufacturers Instructions 6.8 Calculation 134-DC, Electrical Appendix R Analysis 6.9 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.10 NECS File: 131.95, FHARE 134, "Non-rated Structural Gap Seals in Fire Barriers" DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-A-5 9.5A-105 Revision 21 September 2013 FIRE AREA 6-A-5 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Northwest corner of the Auxiliary Building, El. 115 ft.
1.2 Description Unit 1 Electrical Area, 6-A-5, is just west of the F Bus battery inverter and dc switchgear room, Area 6-A-1. Raceways for safe shutdown functions are routed through this fire area. No storage in this area. 1.3 Boundaries North:
- 3-hour rated barrier separates this area from Zone 14-A. South:
- 3-hour rated barrier to S-1.
- 3-hour rated door communicates to Area 6-B-5 and is provided with a 2-hour rated blockout above the door. (Ref. 6.9)
East:
- 3-hour rated barrier separates this area from Area 6-A-1.
- A 3-hour rated door communicates to Area 6-A-1.
- A duct penetration with a 1-1/2-hour rated fire damper penetrates to Area 6-A-1. (Ref. 6.15)
- Three penetrations with no fire dampers penetrate to Area 6-A-1 via protected ductwork. (Refs. 6.7, 6.11 and 6.15) West:
- 3-hour rated barrier separates this area from the Fire Zone 14-A and Area S-1.
- Two penetrations with no fire damper penetrates to the Turbine Building. (Ref. 6.15)
- A protected (1-hour) duct without a fire damper communicates to Zone S-1. (Refs. 6.7, 6.10, 6.11 and 6.15)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-A-5 9.5A-106 Revision 21 September 2013 Floor/Ceiling:
- 3-hour rated barriers.
- Two duct penetrations with no fire damper penetrate to Area 5-A-4 below. (One protected and one not protected) (Refs. 6.8 and 6.15)
- Nonrated equipment hatches communicate to Area 5-A-4 below (Ref. 6.15) and Area 7-A above. The nonrated hatch to Zone 7-A contains HVAC duct penetrants. (Ref. 6.12 and 6.15)
- Two duct penetrations with 3-hour rated dampers to Area 7A above. Protective
Enclosure:
- 1-hour rated fire resistive covering for several HVAC ducts. (Refs. 6.7, 6.11 and 6.15) 2.0 COMBUSTIBLES
2.1 Floor Area: 660 ft2 2.2 In situ Combustible Materials
- Paper
- Cable insulation
- Plastic
- Rubber 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-A-5 9.5A-107 Revision 21 September 2013 3.0 FIRE PROTECTION 3.1 Detection
- Smoke detection 3.2 Suppression
- CO2 hose stations
- Hose stations
- Portable fire extinguishers 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Auxiliary Feedwater Valves LCV-110, LCV-111, LCV-113 and LCV-115 may require manual positioning due to a fire. Redundant valves LCV-106 and LCV-107 will remain available to provide AFW flow to steam generators 1-1 and 1-2. 4.2 Chemical and Volume Control System Valves 8146 and 8147 may be affected by a fire in this area. Since these valves fail in the desired position and the PORVs are available for pressure reduction, safe shutdown can be achieved. Valves LCV-459 and LCV-460 may be affected by a fire in this area. Redundant valves 8149A, 8149B and 8149C will remain available to isolate letdown. A fire in this area may result in spurious closure of charging pump discharge flow control valve FCV-128. This valve can be opened from the hot shutdown panel after switching to manual control. 4.3 Component Cooling Water A fire in this area may affect the following valves: FCV-355, FCV-356, FCV-430 and FCV-431. FCV-355, FCV-430 and FCV-431 can be manually opened for CCW flow. Operation of FCV-356 is not necessary because seal injection will be available. A fire in this area may affect circuits associated with CCW flow transmitter for Header C (FT-69). Flow through CCW Header C is not credited in this fire area. Therefore, loss of flow indication will not affect safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-A-5 9.5A-108 Revision 21 September 2013 4.4 Containment Spray A fire in this area may spuriously open valve 9001B. Since CS pump 1-2 is not affected by a fire in this area, safe shutdown will not be affected. 4.5 Emergency Power System A fire in this area may disable startup transformers 1-1, 1-2, 2-1 and 2-2. Onsite power will remain available from all diesel generators for both Units 1 and 2. A fire in this area may result in a loss of power supplies associated with PY17N. Redundant power supply PY16 remains available. 4.6 Main Steam System A fire in this area may spuriously open FCV-248 and FCV-250. FCV-761 and FCV-760 will remain available to isolate steam generator blowdown. Therefore, safe shutdown is not affected. A fire in this area may fail PCV-20 to the desired closed position. Redundant dump valves will remain available for cooldown. 4.7 Makeup System Condensate storage tank level indication from LT-40 may be lost due to a fire in this area. Water from the raw water storage reservoir will be available through FCV-436. Manual action can be performed to locally open this normally closed manual valve. 4.8 Reactor Coolant System A fire in this area may result in the loss of power for the following components: NE-52, TE-443A, TE-443B, TE-433A and TE-433B. Safe shutdown is not affected because redundant instrumentation exists. Control of all four reactor coolant pumps may be affected by a fire in this area. In order to prevent uncontrolled pressure reduction, PCV-455A and PCV-455B can be closed to isolate normal spray. Therefore, operation of the reactor coolant pumps will not affect safe shutdown. Seal injection will remain available for RCP seal cooling. Pressurizer heater group 1-4 may spuriously operate due to a fire in this area. This heater group can be manually tripped. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-A-5 9.5A-109 Revision 21 September 2013 4.9 Safety Injection System Control of accumulator isolation valve, 8808C may be lost due to a fire in this area. This valve can be manually closed to ensure safe shutdown. 4.10 Auxiliary Saltwater System Valves FCV-495 and FCV-496 may be lost due to a fire in this area. Redundant valve FCV-601 will remain closed to provide ASW system integrity. A fire in this area may spuriously close FCV-602 and FCV-603. These valves can be manually opened to ensure safe shutdown. 4.11 HVAC S-43 and E-43 may be lost due to a fire in this area. Redundant components E-44 and S-44 remain available to provide HVAC.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Loss of the safe shutdown functions in this area will not affect safe shutdown due to redundant equipment and/or measures taken to mitigate the effects of fire.
- Manual fire fighting equipment is available.
- Light combustible loading. The existing fire protection features provide an acceptable level of safety equivalent to that provided by section III.G.2.
6.0 REFERENCES
6.1 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.2 Drawing No. 515570 6.3 DCN - DC1-EE-9913 - Provides Isolators on RPM Tach Packs 6.4 SSER 23, June 1984 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-A-5 9.5A-110 Revision 21 September 2013 6.5 Calculation M-824, Combustible Loading 6.6 Drawing 065126, Fire Protection Information Report, Unit 1 6.7 NECS File: 131.95, FHARE: 15, HVAC Ducts Wrapped in Pyrocrete 6.8 NECS File: 131.95, FHARE: 73, Undampered Ducts 6.9 NECS File: 131.95, FHARE: 118, Appendix R Fire Area Boundary Plaster Barriers 6.10 DCN DCD-EH-37379, Install Fire Dampers to Vent Shaft 6.11 PG&E letter to NRC dated 7/15/83, Appendix R Deviation Request 6.12 NECS File: 131.95, FHARE: 126, HVAC Ducts through Modified Unrated Hatches 6.13 Calculation 134-DC, Electrical Appendix R Analysis 6.14 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.15 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-A 9.5A-111 Revision 21 September 2013 FIRE AREA 7-A 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This area is located directly under the Control Room at El. 127 ft in the Auxiliary Building. 1.2 Description Fire Area 7-A, Unit 1 cable spreading room, is directly under the Unit 1 Control Room and north of the Unit 2 cable spreading room. 1.3 Boundaries North:
- 3-hour rated barrier separates this area from Fire Zone 14-A and Area 3-BB.
- A nonrated penetration to Fire Zone 3-BB. (Refs. 6.14 and 6.21) South:
- 3-hour rated barrier separates this area from Area 7-B and Zone S-1. In addition, localized sections of structural steel for blockwalls were not provided with 3-hour rated fireproofing. (Refs. 6.13 and 6.21)
- Unrated structural gap seals to Fire Area 7-B. (Refs. 6.19 and 6.21)
- Two 3-hour rated doors communicate to Area 7-B.
- Lesser-rated Unistrut seals to Fire Area 7-B. (Refs. 6.20 and 6.21) East:
- 3-hour rated barrier separates this area from Area 7-C and Zones 3-AA, S-5.
- Two 1-1/2-hour rated doors communicate to Area 7-C. (Refs. 6.8 and 6.21)
- A 1-1/2-hour rated door communicates to Zone S-5. (Refs. 6.8 and 6.21)
- A ventilation duct with a 3-hour rated damper communicates to Zone S-5. West:
- 3-hour rated barrier separates this area from the Fire Zone 14-A and Zone S-1.
- A 3-hour rated fire damper communicates to Zone S-1.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-A 9.5A-112 Revision 21 September 2013 Floor/Ceiling:
- 3-hour rated barrier.
- Two ducts with 3-hour rated dampers to 6-A-5 below.
- Nonrated steel with HVAC duct penetrants equipment hatch. (Refs. 6.15 and 6.21)
- Unrated penetrations to Areas 8A, 8C, and 8E above. (Ref. 6.18 and 6.21) 2.0 COMBUSTIBLES 2.1 Floor Area: 3,612 ft2 2.2 In situ Combustible Loading
- Cable
- Wood
- Paper
- Plastic
- Polyethylene
- Resin
- PVC 2.3 Transient Combustible Loading Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Moderate DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-A 9.5A-113 Revision 21 September 2013 3.0 FIRE PROTECTION 3.1 Detection
- Smoke detection
- Heat detection 3.2 Suppression
- Total flooding CO2 system actuated by heat detection (also protects Area 7-C)
- Hose stations
- Portable fire extinguishers 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Auxiliary Feedwater A fire in this area may affect Auxiliary Feedwater Supply valves LCV-106, 107, 108, 109, 110, 111, 113, and 115. Manual actions will enable valves LCV-106, 107, 108, and 109 to be controlled from the hot shutdown panel. Valves LCV-110, 111, 113, and 115 can be manually operated. The ability to operate AFW pumps 1-2 and 1-3 from the control room may be lost due to a fire in this area. Manual action can be taken to operate these pumps from the 4-kV switchgear or from the hot shutdown panel. (Ref. 6.10) A fire in this area may affect FCV-37, FCV-38 and FCV-95. These valves are associated with AFW pump 1-1. AFW pump 1-1 is not necessary since AFW PPs 1-2 and 1-3 will remain available. Condensate storage tank level indication from LT-40 may be affected by a fire in this area. Valves FCV-436 and FCV-437 can be manually opened in order to supply water from the raw water storage reservoir. 4.2 Chemical and Volume Control System A fire in this area may affect valves 8801A, 8801B, 8803A, and 8803B. RCS flow through the charging injection flow path can be secured by manual operation of (either 8801A or 8801B) and (either 8803A or 8803B). Prior to initiation of auxiliary spray, charging injection flowpath will need to be isolated. A fire in this area may affect valves 8107, 8108, 8145, 8148, FCV-128, 8146, 8147 and HCV-142. Operation of HCV-142 will remain available from the hot shutdown panel to isolate the auxiliary spray flowpath with the controller at the DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-A 9.5A-114 Revision 21 September 2013 hot shutdown panel placed in the manual mode. Charging flow to the RCS will remain available through the seal injection flow path. Repairs and operator actions can be taken to use the auxiliary spray flow path and isolate diversion flowpaths for RCS pressure reduction. Valve 8145 can be operated from the dedicated shutdown panel, and valve HCV-142 can be operated from the hot shutdown panel. A fire in this area may spuriously open 8166, 8167 and fail HCV-123 closed. Only one of these valves is required closed to provide excess letdown isolation. Since HCV-123 fails closed, safe shutdown is not affected. A fire in this area may affect the ability to operate valves LCV-459, LCV-460, 8149A, 8149B and 8149C from the control room. Manual actions will enable valves 8149A, 8149B and 8149C to be operated from the hot shutdown panel to isolate letdown. The ability to operate charging pumps 1-1 and 1-2 and 1-3 from the control room may be lost due to a fire in this area. Manual actions will enable charging pumps 1-1 and 1-2 to be operated from the 4-kV switchgear and the hot shutdown panel. Manual action can be taken to isolate circuits for Charging Pump 1-3 at 4kv switchgear SHG. (Ref. 6.10) A fire in this area may result in spurious closure of the charging pump discharge flow control valve FCV-128 which must be opened if charging pump 1-1 or 1-2 are used for RCP seal flow. FCV-128 can be opened from the hot shutdown panel after taking the controller to manual. A fire in this area may spuriously close valves 8105 and 8106. Since the RWST will be aligned to the charging pumps, these valves are not required open. A fire in this area may result in the loss of boric acid storage tank 1-1 and 1-2 level indication from LT-102 and LT-106. Borated water from the RWST will remain available. Therefore, BAST level indication is not required. The ability to operate boric acid transfer pumps 1-1 and 1-2 from the control room may be lost due to a fire in this area. Manual actions will enable these pumps to be operated from the hot shutdown panel. Valves HCV-104 and HCV-105 may fail closed due to a fire in this area. Since these valves fail in the desired position, safe shutdown is not affected. Valves FCV-110A and 8104 may be affected by a fire in this area. Manual actions can be taken to enable valve 8104 to be operated from the hot shutdown panel. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-A 9.5A-115 Revision 21 September 2013 A fire in this area may spuriously open valves FCV-110B and FCV-111B. These valves can be manually closed to ensure safe shutdown. A fire in this area may affect valves LCV-112B, LCV-112C, 8805A and 8805B. All of these valves can be manually operated to ensure safe shutdown. A fire in this area may affect the transmitter and circuits associated with charging pump header flow transmitter, FT-128, and pressure transmitter, PT-142. Alternative shutdown from the hot shutdown panel is credited in this area, and these instruments are not credited. A fire in this area may affect circuits associated with letdown flow transmitter, FT-134. Alternative shutdown from the hot shutdown panel is credited in this area, and this flow transmitter is not required. Letdown is isolated at the hot shutdown panel. A fire in this area may affect equipment and circuits associated with VCT level transmitter LT-112. This instrument is credited for diagnosis of failure of the VCT discharge valves LCV-112B or LCV-112C to automatically close. Alternative shutdown from the hot shutdown panel is credited in this area, and this level transmitter is not required. 4.3 Component Cooling Water A fire in this area may cause FCV-356, FCV-357 and FCV-750 to spuriously close and fail to provide component cooling water to the reactor coolant pump thermal barriers if seal injection is not available. Control of HCV-142 to provide seal injection for RCP seal cooling will be available at the hot shutdown panel. Therefore, safe shutdown is not compromised. The ability to operate CCW pumps 1-1, 1-2 and 1-3 from the control room may be lost due to a fire in this area. Manual action will enable these pumps to be operated from the 4-kV switchgear or the hot shutdown panel. (Ref. 6.10) A fire in this area may affect valves FCV-430 and FCV-431. Either of these valves can be manually operated in order to provide a CCW flowpath. Valves FCV-364 and FCV-365 may be affected by a fire in this area. Either valve can be manually opened in order to ensure RHR system operation. A fire in this area may spuriously close FCV-355. This valve can be manually opened if seal injection is not available. A fire in this area may affect circuits associated with CCW flow transmitters for DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-A 9.5A-116 Revision 21 September 2013 Header A (FT-68), Header B (FT-65), and Header C (FT-69). Availability of these instruments is not credited for safe shutdown.
A fire in this area may affect circuits associated with the differential pressure transmitters for CCW Hx 1-1 (PT-5) and CCW Hx 1-2 (PT-6). Availability of these instruments is not credited for safe shutdown. 4.4 Containment Spray A fire in this area may spuriously start two containment spray pumps or may spuriously open the discharge valves 9001A and 9001B. Operator action can be taken to trip CS Pumps 1-1 and 1-2. Therefore, safe shutdown will not be affected. 4.5 Emergency Power A fire in this area may disable remote control and auto transfer of diesel generator 1-1. The diesel can be manually started and loaded at the diesel generator local panel and at the 4-kV switchgear room. (Ref. 6.11) A fire in this area may disable remote control and auto transfer of diesel generator 1-2. The diesel can be manually started and loaded at the diesel generator local panel and at the 4-kV switchgear room. (Ref. 6.11) A fire in this area may disable remote control and auto transfer of diesel generator 1-3. The diesel can be manually started and loaded at the diesel generator local panel and at the 4-kV switchgear room. (Ref. 6.11) A fire in this area may spuriously trip the 480-volt feeder breakers. These breakers can be locally closed at the switchgear. A fire in this area may result in a loss of power supplies associated with PY17N. Redundant power supply PY16 remains available. 4.6 Main Steam System A fire in this area may spuriously open the main steam isolation valves (FCV-41, 42, 43 and 44) an their bypasses (FCV-22, 23, 24 and 25). These valves can be manually closed. A fire in this area may supuriously open the steam generator inboard isolation valves (FCV-760, 761, 762 and 763) and the outboard isolation valves (FCV-151, 154, 157, 160 and FCV-244, 246, 248, 250). Operator action can be taken to close the valves and isolate SG blowdown. Therefore, safe shutdown will not be affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-A 9.5A-117 Revision 21 September 2013 Steam generator pressure indication in the control room and hot shutdown panel may be lost due to a fire in this area. Steam generator pressure for steam generators 1-1, 1-2, 1-3, 1-4 can be read off of PI-518, PI-528, PI-538 and PI-548, respectively. A fire in this area may result in the loss of steam generator level instruments LT-517, 518, 519, 527, 528, 529, 537, 538, 539, 547, 548 AND 549. Steam generator level indication will remain available from LT-516, 526, 536 and 546 at the dedicated shutdown panel. A fire in this area may prevent the ten percent dump valves (PCV-19, 20, 21, 22) from being opened. These valves are required closed for hot standby and can be manually opened for subsequent cooldown. 4.7 Reactor Coolant System A fire in this area may spuriously energize heater groups 1-1, 1-2, 1-3 and 1-4. These heaters can be manually de-energized. Reactor coolant system pressure indication from PT-403 and PT-405 may be lost due to a fire in this area. This indication can be monitored using PT-406 at the dedicated shutdown panel. A fire in this area may affect PORVs PCV-456, PCV-474 and PCV-455C and blocking valves 8000A, 8000B and 8000C. If the PORVs were to spuriously open due to a hot short, they can be closed from the hot shutdown panel in order to prevent uncontrolled pressure reduction. The auxiliary spray flowpath will be available for RCS pressure reduction. Therefore, safe shutdown is not affected. A fire in this area may prevent reactor coolant pumps 1-1, 1-2, 1-3 and 1-4 from being secured. Manual actions at the 12-kV switchgear may be necessary to secure the reactor coolant pumps. A fire in this area may affect all RCP seal cooling sources (seal injection and CCW to the RCP Thermal Barrier Heat Exchanger). To prevent thermal shock of the RCP seals, seal injection and CCW to the RCP TBHX can be isolated by operation of valves8382A, 8382B, 8396A and FCV-357. The charging injection flowpath will be credited for RCS makeup. Source range monitors NE-31 and NE-32 may be lost due to a fire in this area. NE-51 and NE-52 will be available at the hot shutdown panel to provide source range indication. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-A 9.5A-118 Revision 21 September 2013 Pressurizer level indication from LT-459, LT-460 and LT-461 may be lost due to a fire in this area. LT-406 will remain available at the dedicated shutdown panel to provide level indication. A fire in this area may affect reactor vessel head vent valves 8078A, 8078B, 8078C and 8078D. Operator action can be taken to fail the valves closed. Safe shutdown is not affected. Hot and cold leg temperature instrumentation in the control room may be lost due to a fire in this area. TE-413A and TE-413B will remain available at the dedicated shutdown panel. 4.8 Residual Heat Removal System RHR pumps 1-1 and 1-2 may be affected by a fire in this area. Manual action can be taken to operate either RHR pump from the 4-kV switchgear to provide RHR flow. Valves 8701 and 8702 are closed with their power removed during normal operations and will not spuriously open. Valves 8701 and 8702 can be manually operated for RHR operations. A fire in this area may affect 8700A and 8700B. These valves can be manually operated to ensure safe shutdown. A fire in this area may affect FCV-641A and FCV-641B or cause spurious operation of the valves. During the transition to cold shutdown conditions, prior to starting the RHR Pump, the respective recirc valve can be manually operated. 4.9 Safety Injection System SI pumps 1-1 and 1-2 may spuriously operate due to a fire in this area. Local manual action may be required to defeat this spurious operation. A fire in this area may spuriously open valves 8982A, 8982B, 9003A and 9003B may spuriously open due to a fire in this area. Power to 8982A and 8982B is administratively removed by maintaining a toggle switch in the Control Room in the open position. The valve is normally closed, and spurious opening is not expected to occur. However, an operator action can be taken to open the power breaker to preclude spurious opening of 8982A and 8982B. Valve 8980 can be manually operated in order to defeat any spurious signals. Accumulator isolation valves 8808A, 8808B, 8808C and 8808D may be affected by a fire in this area. These valves can be manually closed which is the desired safe shutdown position. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-A 9.5A-119 Revision 21 September 2013 A fire in this area may spuriously open valve 8804A. This valve can be manually closed to ensure safe shutdown. A fire in this area may affect circuits associated with RWST Level Transmitter LT-920. Alternative shutdown capability is credited in this fire area, and this transmitter is not credited for safe shutdown. 4.10 Auxiliary Saltwater System The ability to operate ASW pumps 1-1 and 1-2 from the control room may be lost due to a fire in this area. Manual actions can be taken to operate the pumps from the 4-kV switchgear or hot shutdown panel. A fire in this area may affect valves FCV-495 and FCV-496 and may spuriously open FCV-601. Due to similar system pressures between Unit 1 and Unit 2, operation with FCV-601 open will not affect safe shutdown. A fire in this area may spuriously close valves FCV-602 and FCV-603. These valves can be manually opened to ensure safe shutdown. 4.11 Unit 2 Components 4.11.1 Main Steam System Steam generator pressure indication in the control room and hot shutdown panel may be lost due to a fire in this area. Steam generator pressure for steam generators 2-1, 2-2, 2-3, 2-4 can be read off of PI-518, PI-528, PI-538 and PI-548, respectively. A fire in this area may result in the loss of steam generator level instruments LT-517, 518, 519, 527, 528, 529, 537, 538, 539, 547, 548 and 549. Steam generator level indication will remain available from LT-516, 526, 536 and 546 at the dedicated shutdown panel. 4.11.2 Reactor Coolant System Reactor coolant system pressure indication from PT-403 and PT-405 may be lost due to a fire in this area. This indication can be monitored using PT-406 at the dedicated shutdown panel. Pressurizer level indication from LT-459, LT-460 and LT-461 may be lost due to a fire in this area. LT-406 will remain available at the dedicated shutdown panel to provide level indication. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-A 9.5A-120 Revision 21 September 2013 Hot and cold leg temperature instrumentation in the control room may be lost due to a fire in this area. TE-413A and TE-413B will remain available at the dedicated shutdown panel.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Smoke and heat detection are provided.
- Total flooding CO2 system is provided.
The fire protection features provided in this area provide an acceptable level of fire safety equivalent to that provided by section III.G.
6.0 REFERENCES
6.1 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.2 Drawing No. 515572 6.3 DCN DC1-EE-11694 - Provides Isolation Contact on DG 6.4 DCN DC1-EE-11670 - Provides Disconnect Switch at HSD Panel 6.5 Calculation M-824, Combustible Loading 6.6 Drawing 065126, Fire Protection Information Report, Unit 1 6.7 SSER 23, June 1984 6.8 DCPP Unit 1 Report on 10 CFR 50, Appendix R Review (Rev. 0) 6.9 File 131.95, Memo from S. Lynch to P. Hypnar dated December 8, 1983 regarding current transformer protection 6.10 DCNs DC1-EE-47591, DC1-EE-47593, and DC1-EE-47594, Provide Transfer Switches at the 4kV Switchgear and Mode Selector Switches at the Hot Shutdown Panel 6.11 DCN DC1-EE-45132, Provides Local Control Capability for DGs. 6.12 DCN DC1-EE-47600, DG 1-3 Starting Circuit Power Supply Transfer Switch/APPR Modifications 6.13 NECS File: 131.95, FHARE: 104, "Fireproofing on Structural Steel for Block Walls" 6.14 NECS File: 131.95, FHARE: 130, "Inaccessible Jumbo Duct Penetrants" 6.15 NECS File: 131.95, FHARE: 126, HVAC Ducts through Modified Unrated Hatches 6.16 Calculation 134-DC, Electrical Appendix R Analysis DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-A 9.5A-121 Revision 21 September 2013 6.17 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.18 NECS File 131.95, FHARE 137, Unrated Penetrations through Unit 1 Control Room Floor (Barrier 458) 6.19 NECS File: 131.95, FHARE 134, "Non-rated Structural Gap Seals in Fire Barriers" 6.20 NECS File: 131.95, FHARE 147, "Evaluation of Lesser Rated Unistrut Configurations in 128 ft Cable Spreading Room." 6.21 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 8-G 9.5A-122 Revision 21 September 2013 FIRE AREA 8-G 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This area is located in the northwest corner of the Unit 1 Auxiliary Building at El. 140 ft. 1.2 Description Area 8-G, Unit 1 Safeguards Room, houses Unit 1 solid state protection cabinets. Automatic reactor trip, SIS, containment/ isolation, and other safeguard signals are generated from these cabinets. 1.3 Boundaries North:
- 3-hour rated barrier separates this area from the outside.
South:
- 1-hour rated barrier separates this area from Zone 8-E. (Ref. 6.7)
- A duct penetration without a fire damper. (Ref. 6.9)
East:
- 3-hour rated barrier separates this area from Zone 8-A.
- A 3-hour rated door communicates to Area 8-A.
- A duct penetration without a fire damper (the duct is protected within Area 8-G) with a 3-hour rated fire damper at the outlet of the protected ductwork. (Ref 6.8)
West:
- 3-hour rated barrier separates this area from Fire Zone 14-D (Turbine Building).
Floor/Ceiling:
- 3-hour rated barrier.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 8-G 9.5A-123 Revision 21 September 2013 2.0 COMBUSTIBLES 2.1 Floor Area: 225 ft2 2.2 In situ Combustible Materials
- Cable Insulation 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection 3.2 Suppression
- Portable fire extinguishers
- Hose stations 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Auxiliary Feedwater AFW pumps 1-2 and 1-3 may be lost due to a fire in this area. Redundant AFW pump 1-1 will be available to provide AFW. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 8-G 9.5A-124 Revision 21 September 2013 4.2 Chemical and Volume Control System CVCS valves 8107 or 8108 may be lost due to a fire in this area. Redundant CVCS valves HCV-142, or 8145 and 8148 remain available to isolate auxiliary spray and the PORVs will remain available for RCS pressure reduction. CVCS valves 8149A, 8149B and 8149C may be lost due to a fire in this area. Redundant CVCS valves LCV-459 and LCV-460 remain available for letdown isolation. Operator action can also be credited to isolate letdown by de-energizing 8149A, 8149B, and 8149C to fail them in the closed position. CVCS valves LCV-112B and LCV-112C may be lost due to a fire in this area. Redundant SIS valves 8805A and 8805B remain available to provide a flow path to the charging pumps. Manual action can be taken to operate either LCV-112B or LCV-112C to isolate the volume control tank. 4.3 Component Cooling Water The ability to operate CCW pumps 1-1, 1-2 and 1-3 from the control room may be lost due to a fire in this area. Manual actions will enable these pumps to be operational from the 4-kV switchgear or the hot shutdown panel. CCW valves FCV-356, FCV-357 and FCV-750, which provide component cooling water to reactor coolant pump thermal barriers, may be affected by a fire in this area. Since seal injection will be available to cool RCP seals, these valves are not required open and their position will not affect safe shutdown. CCW valve FCV-355 may spuriously close due to a fire in this area. Operator action can be credited to manually open FCV-355.for safe shutdown. 4.4 Containment Spray Containment spray pumps 1-1 and 1-2 and their associated discharge valves 9001A and 9001B are affected by a fire in this area. Operator action can be taken to trip CS pumps 1-1 and 1-2. Therefore, safe shutdown will not be affected. 4.5 Emergency Power A fire in this area may disable diesel generators 1-1, 1-2 and 1-3 automatic transfer circuits. Manual control will remain available in the control room to transfer and load the diesel generator. Offsite power will remain available for safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 8-G 9.5A-125 Revision 21 September 2013 4.6 Main Steam System Main steam system inboard isolation valves FCV-760, 761, 762, 763 or outboard isolation valves FCV-151, 154, 157, 160 and FCV-244, 246, 248 and 250 may fail for a fire in this area. The ability to manually isolate the steam generator blowdown lines will remain available. Therefore, safe shutdown is not affected. Main steam isolation valves FCV-41, FCV-42, FCV-43 and FCV-44 may be lost due to a fire in this area. Manual action may be necessary to close the valves. A fire in this area may prevent the 10% dump valves PCV-19, PCV-20, PCV-21 and PCV-22 from being opened. These valves are required closed for hot standby and can be manually operated for cooldown purposes. 4.7 Reactor Coolant System Control of pressurizer PORV PCV-456 will be lost due to completion of operator actions to SGBD valves. Control of PCV-455C will remain available. 4.8 Safety Injection System SI pumps 1-1 and 1-2 may spuriously operate for a fire in this area. Local manual action may be required to defeat this spurious operation prior to RCS depressurization. SI valves 8801A, 8801B, 8803A and 8803B may be affected by a fire in this area. A charging flowpath to the reactor will remain available through RCP seal injection. The PORV will remain available for pressure reduction. SI valves 8805A and 8805B may be affected by a fire in this area. Manual actions may be required to provide water to the charging pumps. SI accumulator isolation valves 8808A, 8808B, 8808C and 8808D may be affected by a fire in this area. Manual actions may be required to operate the valves. 4.9 Auxiliary Saltwater System ASW pumps 1-1 and 1-2 may be lost due to a fire in this area. Manual actions will enable both pumps to be started from the 4-kV switchgear or the hot shutdown panel. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 8-G 9.5A-126 Revision 21 September 2013
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- The safe shutdown functions located in this area are not required once the reactor is tripped.
- Smoke detection is provided.
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown. The existing fire protection features provide an level of safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.2.
6.0 REFERENCES
6.1 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.2 Drawing No. 515571 6.3 SSER 23, June 1984 6.4 Calculation M-824, Combustible Loading 6.5 Drawing 065126, Fire Protection Information Report, Unit 1 6.6 NECS File: 131.95, FHARE: 15, HVAC Duct Wrapped in Pyrocrete 6.7 NECS File: 131.95, FHARE: 75, 1-hour rated Barrier 6.8 NECS File: 131.95, FHARE: 80, Fire Dampers installed at Variance with Manufacturers Instruction 6.9 NECS File: 131.95, FHARE 129, Duct penetrations through common walls associated with fire zones 8-A, 8-D, 8-E, 8-F, 8-G, and 8-H 6.10 Calculation 134-DC, Electrical Appendix R Analysis 6.11 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 10 9.5A-127 Revision 21 September 2013 FIRE AREA 10 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Unit 1, northeast corner of the Turbine Building at El. 76 ft and 85 ft.
1.2 Description This area includes the 12-kV switchgear room at El. 85 ft and the 12-kV cable spreading room beneath at El. 76 ft. The cable spreading room is accessed by open stairwells communicating between the two elevations of this area. 1.3 Boundaries North: 85' Elevation
- 2-hour rated barrier separates this area from the exterior (Fire Area 28). (Ref. 6.22)
- A 3-hour rated roll-up door communicates to Area 28.
- Unrated small diameter penetration to Area 28. (Ref. 6.17)
- Unsealed Bus duct penetration to Area 28. (Ref. 6.6) 76' Elevation (Ref 6.26)
- Unrated conduit penetration seals (Reference 6.25). South:
85' Elevation
- A 3-hour rated barrier separates this area from Area 14-A. (TB-7)
- A 3-hour rated door communicates to Area 14-A. 76' Elevation (Ref 6.26)
- Unrated conduit penetration seals (Reference 6.25). East:
85' Elevation
- A 2-hour rated barrier separates this area from Area 28. (Refs. 6.11 and 6.22)
- Three 3-hour rated roll-up doors (2 over wall louvers and 1 over a nonrated door) communicate to Area 28. (Refs. 6.11 and 6.16)
- Unsealed Bus duct penetration to Area 28. (Ref. 6.6)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 10 9.5A-128 Revision 21 September 2013 76' Elevation (Ref 6.26)
- Unrated conduit penetration seals (Reference 6.25). West:
85' Elevation
- A 3-hour rated barrier separates this area from Area 11-D. (Ref. 6.22)
- Unrated small diameter penetration to Area 11-D. (Ref. 6.17)
- A 3-hour rated fire damper communicates to Area 11-D.
- A 3-hour rated door communicates to Area 11-D.
- A 3-hour rated roll-up door communicates to Area 11-D. 76' Elevation (Ref 6.26)
- Unrated conduit penetration seals (Reference 6.25). Floor/Ceiling:
- 3-hour rated barrier with the following exceptions: - A 2-hour rated enclosed stairwell with a nonrated ceiling and a 1 1/2-hour rated door communicates to Area 12-E above (El. 107 ft). (Ref. 6.8) - A 3-hour rated concrete equipment plug communicates to Fire Zone 12-B (above) on unprotected steel supports with unsealed gaps.
(Refs. 6.7 and 6.12) - Unprotected structural steel supporting the ceiling (El. 85 ft). (Ref. 6.12) - Lesser rated penetration seal to Area 12-E above. (Ref. 6.23) Fire Resistive
Enclosures:
- 2-hour fire resistive enclosures for F and G Bus power circuits are routed to Fire Zones 12-A, 12-B, and 12-C from 85 ft and above. Below 85 ft they are either enclosed in a noncombustible barrier or embedded in concrete.
(Refs. 6.10, 6.11, 6.13, 6.14, 6.15, 6.16, 6.18, and 6.24)
- 3-hour fire resistive covering is provided for all the structural steel on El. 76 ft. (Refs. 6.5 and 6.12) 2.0 COMBUSTIBLES
2.1 Floor Area: 4095 ft2 (El. 76 ft) 6160 ft2 (El. 85 ft) DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 10 9.5A-129 Revision 21 September 2013 2.2 In situ Combustible Materials El. 76 ft 85 ft
- Cable insulation
- Cable insulation
- Rubber
- Paper
- PVC
- Wood (fir)
- Fiberglass 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low (El. 76 ft)
- Low (El. 85 ft) 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection at both elevations.
3.2 Suppression
- Portable fire extinguishers
- CO2 hose stations
- Hose stations 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Auxiliary Feedwater System DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 10 9.5A-130 Revision 21 September 2013 A fire in this area may disable AFW Pp 1-2 and 1-3 and level control valves LCV-110, LCV-111, LCV-113 and LCV-115 may be lost due to a fire in this area. Redundant AFW Pump 1-1 and associated valves LCV-106, LCV-107, LCV-108 and LCV-109 will remain available for safe shutdown. 4.2 Containment Spray Containment spray pump 1-2 may spuriously operate due to a fire in this area. However, the corresponding discharge valve, 9001B will remain closed. Therefore, containment spray pump 1-2 will run on recirculation and safe shutdown is not affected. Containment spray pump 1-1 is protected by a 2-hour rated fire barrier and will not be affected. 4.3 Emergency Power A fire in this area may disable the automatic transfer circuit for diesel generator 1-1. Manual control will remain available in the control room to transfer and load the diesel generator. The circuits associated with diesel generators 1-1 and 1-3 are protected with a 2-hour fire rated enclosure and will remain available for safe shutdown. A fire in this area may disable startup transformers 1-1, 1-2, 2-1 and 2-2. Manual action can be taken to locally trip the Startup Transformer breakers prior to starting and loading DGs 1-1, 1-2, and 1-3. Onsite power from diesel generators 1-1 and 1-3 will remain available for Unit 1 due to the 2-hr fire rated enclosure, and all three diesel generators will remain available for Unit 2. A fire in this area may result in a loss of power supplies associated with PY17N. Redundant power supply PY16 remains available. 4.4 Reactor Coolant System A fire in this area may affect all four reactor coolant pumps. Since spray isolation with PCV-455A and PCV-455B, thermal barrier cooling and seal injection will remain available, safe shutdown will not be affected if the RCPs are running. 4.5 Other Systems A fire in this area may affect power and control circuits for safe shutdown equipment on Buses "F", "G" and "H". These buses are separated by a minimum 2 hour fire rated barrier. Evaluations have determined that this configuration will not affect safe shutdown. (Refs. 6.10, 6.13, 6.14, 6.15, 6.16, 6.19, and 6.24) DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 10 9.5A-131 Revision 21 September 2013
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Safe shutdown circuitry utilized in safe plant shutdown is not adversely affected due to the fire barriers provided (min. 2-hour enclosure) on F and G Bus and partial enclosure of H Bus) and the spatial separation provided (H Bus and F Bus DG). (Refs. 6.10, 6.13, 6.14, 6.15, 6.16 and 6.19)
- Smoke detection is provided at both elevations.
- Portable fire extinguishers and CO2 hose stations are available within the area and hose stations are nearby.
The existing fire protection provides an acceptable level of safety equivalent to that provided by 10 CFR 50, Appendix R Section III.G.
6.0 REFERENCES
6.1 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.2 Drawing No. 515562 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065126, Fire Protection Information Report, Unit 1 6.5 DCN-DC1 EA-35409, Structural Steel Fire Rated Covering 6.6 NECS File: 131.95, FHARE: 20, Unsealed Bus Duct Penetrations 6.7 NECS File: 131.95, FHARE: 14, Concrete Equipment Hatches 6.8 NECS File: 131.95, FHARE: 4, Stairwell Nonrated Ceiling 6.9 Deleted in Revision 12. 6.10 NECS File: 131.95, FHARE: 18, Conduits Not Enclosed in 2 hour Enclosure 6.11 SSER 8, November 1978 6.12 PLC Report: Structural Steel Analysis for Diablo Canyon Rev. 2 (07/08/86) 6.13 NECS File: 131.95, FHARE: 45, 3-M Fire Wrap Repair of Pyrocrete Enclosures 6.14 PG&E Design Change Notice DC1-EA-049070, Unit 1 ThermoLag Replacement DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 10 9.5A-132 Revision 21 September 2013 6.15 "Fire Endurance Test of Pyrocrete Box Fire Protective Envelopes," Test Report by Omega Point Laboratories, October 18, 1996 (PG&E Chron No. 231589) 6.16 PG&E Design Change Notice DC1-EC-049339, Pyrocrete Panels at Unit 1 12-kV Switchgear Room and Transit Panels below El. 85 ft 6.17 NECS File: 131.95, FHARE: 123, Unsealed penetrations with fusible link chain penetrations through fire barriers 6.18 Question 25, PG&E letter to NRC dated 8/3/78 6.19 NECS File: 131.95 FHARE 138, Drain Holes in Pyrocrete Panels in Fire Area 10 and 20 6.20 Calculation 134-DC, Electrical Appendix R Analysis 6.21 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.22 NECS File: 131.95, FHARE 133, Seismic/Construction Gaps in the 12-kV Switchgear Rooms 6.23 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.24 NECS File 131.95, FHARE 145, Pyrocrete Enclosure Thickness 6.25 NECS File 131.95, FHARE 151, Evaluation of Fire Area Boundaries for the 76' Elevation of Fire Areas 10 and 20 6.26 NECS File 131.95, FHARE 154, Removal of Below Grade 12-kV Cable Spreading Room Barriers from the Fire Protection Program. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 11-D 9.5A-133 Revision 21 September 2013 FIRE AREA 11-D 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Unit 1 Turbine Building, corridor outside diesel generator rooms, El. 85 ft. 1.2 Description Fire Area 11-D is the corridor at El. 85 ft in the Unit 1 Turbine Building that separates the diesel generator rooms (Zones 11-A-1, 11-A-2, and 11-A-3) from the 12-kV switchgear room (Fire Area 10). 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- A 3-hour rated barrier with a 3-hour rated double door separates this area from Area 28.
South:
- A 3-hour rated barrier with a 3-hour rated double door separates this area from Zone 14-A.
East:
- A 3-hour rated barrier separates this area from Area 10. (Ref. 6.15)
- Unrated small diameter penetration to Area 10. (Ref. 6.12)
- A duct penetration with a 3-hour rated damper to Area 10.
- A 3-hour rated door communicates to Area 10.
- A 3-hour rated roll-up door communicates to Area 10. West:
- 3-hour rated barrier separates this area from Zones 11-A-1, 11-A-2, 11-B-1, 11-C-1. (Refs. 6.16 and 6.17)
- Three 3-hour rated roll-up doors (1 communicating with each Zone 11-A-1, 11-B-1, 11-C-1).
- Three small diameter unrated penetrations (1 communicating with each Zone 11-A-1, 11-B-1, 11-C-1). (Ref. 6.12)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 11-D 9.5A-134 Revision 21 September 2013
- Three 3-hour rated doors (1 each to Zones 11-A-1, 11-B-1 and 11-C-1)
- Nonrated personnel access hatch to Zone 11-C-2. (Refs. 6.5 and 6.9)
Floor/Ceiling:
- Floor: concrete on grade NC
- Ceiling: hour rated barrier to Zones 12-A, 12-B and 12-C. - A duct penetration without a fire damper to Zone 12-B. (Ref. 6.5) 2.0 COMBUSTIBLES
2.1 Floor Area: 459 ft2 2.2 In situ Combustible Materials
- Cable
- Rubber
- Clothing/Rags
- Plastics 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity:
- Low DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 11-D 9.5A-135 Revision 21 September 2013 3.0 FIRE PROTECTION 3.1 Detection None
3.2 Suppression
- Automatic wet pipe sprinklers with remote annunciation
- Portable fire extinguishers
- Fire hose stations 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Diesel Fuel Oil System A fire in this area may affect diesel fuel oil transfer pumps 01 and 02. The circuits for these pumps are enclosed in fire barriers. SSER 23 documents a deviation for this condition which has been accepted by the NRC. Offsite power will be available for safe shutdown in the event diesel fuel oil circuits are damaged by a fire. Therefore, safe shutdown will not be affected by a fire in this area. A fire in this area may affect valves LCV-85, 86, 87, 88, 89 and 90. The circuits for these valves are enclosed in fire barriers and the deviation mentioned above also applies to these valves. Offsite power will be available for safe shutdown in the event diesel fuel oil circuits are damaged by a fire. Therefore, safe shutdown will not be affected by a fire in this area. 4.2 Emergency Power System A fire in this area may affect the diesel generator 1-1 circuits that are enclosed in a fire barrier. Circuits which could spuriously energize the emergency stop switch are in embedded conduit, located between the stop switch and the relay cabinet in the diesel room, and will not be affected by a fire in this area. SSER 23 justifies any deviations from the requirements in Section III.G.2 of Appendix R. Offsite power will be available for safe shutdown in the event emergency diesel generator circuits are damaged in a fire. (Refs. 6.7, and 6.14) A fire in this area may affect the diesel generator 1-2 circuits that are enclosed in a fire barrier. Circuits which could spuriously energize the emergency stop switch are in embedded conduit, located between the stop switch and the relay cabinet in the diesel room, and will not be affected by a fire in this area. SSER 23 justifies any deviations from the requirements in Section III.G.2 of Appendix R. In addition, offsite power will be available for safe shutdown in this DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 11-D 9.5A-136 Revision 21 September 2013 fire area. Therefore, the fire barriers protecting the diesel generator circuits are not necessary. (Ref. 6.14) A fire in this area may affect the diesel generator 1-3 circuits that are enclosed in a fire barrier. Circuits which could spuriously energize the emergency stop switch are in embedded conduit, located between the stop switch and the relay cabinet in the diesel room, and will not be affected by a fire in this area. SSER 23 justifies any deviations from the requirements in Section III.G.2 of Appendix R. In addition, offsite power will be available for safe shutdown in this fire area. Therefore, the fire barriers protecting the diesel generator circuits are not necessary. (Ref. 6.14) A fire in this area may affect the CO2 system manual actuation switches for each Unit 1 diesel generator room. The cables for these switches are mineral insulated with a fire rating of 2-hours to preclude spurious actuation of the CO2 suppression system and automatic closure of the diesel generator room rollup door.
5.0 CONCLUSION
The following features will adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Although not required, a fire rated enclosure is provided for redundant safe shutdown circuits.
- An automatic wet pipe sprinkler system.
- Manual fire fighting equipment is provided. The existing fire protection for this area provides an acceptable level of safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 Drawing No. 515562 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065126, Fire Protection Information Report, Unit 1 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 11-D 9.5A-137 Revision 21 September 2013 6.5 SSER 23, June 1984 6.6 DCN DC1-EE-9913, Provide Isolator 6.7 DCN DC1-EA-15251, Provide 1 Hour Barriers 6.8 Deleted in Revision 13 6.9 Deleted in Revision 13 6.10 NCR DC0-91-EN-N027 6.11 DCN DC1-EA-47386 6.12 NECS File: 131.95, FHARE 123, Unsealed penetrations with fusible link chain in penetrants through fire barriers 6.13 Calculation 134-DC, Electrical Appendix R Analysis 6.14 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.15 NECS File: 131.95, FHARE 133, Seismic/Construction Gaps in the 12-kV Switchgear Rooms 6.16 NECS File: 131.95, FHARE 103, Fire Barrier Configurations in the Emergency Diesel Generator Rooms 6.17 NECS File: 131.95, FHARE 30, Unrated Gaps in Appendix R Barriers in the Turbine Building DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 13-D 9.5A-138 Revision 21 September 2013 FIRE AREA 13-D 1.0 PHYSICAL CHARACTERISTICS
1.1 Location North end of Unit 1 Turbine Building at El. 119 ft, excitation switchgear room.
1.2 Description This fire area is between the 4-kV switchgear rooms and 4-kV switchgear ventilation fan room at El. 119 ft. There is no safe shutdown equipment installed in this fire area. However, ventilation ducts providing cooling to safety-related 4-kV switchgear required for safe shutdown passes through this area. 1.3 Boundaries North:
- A 2-hour rated barrier separates this area from Area 28 (exterior).
- A 3-hour rated fire damper communicates to Area 28. South:
- A 3-hour rated barrier separates this area from Zone 12-E.
- Unrated structural gap seals to Fire Zone 12-E. (Ref. 6.15).
- A 1-1/2-hour rated door communicates to Zone 12-E. (Ref. 6.10)
- The non-rated gap assemblies in fire barriers to Zone 12-E were deemed acceptable. (Ref. 6.16)
East:
- A 3-hour rated barrier separates this area from Zones 13-A, 13-B, 13-C.
- Unrated structural gap seals to Fire Zones 13A, 13B, and 13C. (Ref. 6.15).
- Three 1-1/2-hour rated fire dampers (1 fire damper within protected ductwork communicates to each Zone: 13-A, 13-B, 13-C). (Ref. 6.19)
- Three 1-1/2-hour rated doors (1 door communicates to each Zone: 13-A, 13-B, and 13-C). (Ref. 6.19)
West:
- A 3-hour rated barrier separates this area from Area 13-E.
- Unrated structural gap seals to Fire Area 13-E. (Ref 6.15).
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 13-D 9.5A-139 Revision 21 September 2013
- Structural steel modifications for the block walls were deemed acceptable with no fireproofing. (Ref. 6.11)
- Four duct penetrations without fire dampers penetrate to Area 13-E. (Ref. 6.5)
- A 1-1/2 hour door communicates to Zone 13-E. (Ref. 6.18)
- Lesser rated penetration seals to Zone 13-E. (Ref. 6.17)
Floor/Ceiling: 3-hour rated with the following exceptions:
- 3-hour rated equipment hatches penetrate the floor and ceiling to Zones 12B and 14D, respectively. (Ref. 6.7) The steel supporting these hatches is unprotected. (Ref. 6.9)
- Undampered ventilation duct to Zone 12-A below. (Refs. 6.5 and 6.12) Protective
Enclosure:
- The duct work and supports of the 3 ducts penetrating the east wall to Zones 13-A, 13-B and 13-C have a 1-hour fire resistive coating.
(Refs. 6.6 and 6.19) 2.0 COMBUSTIBLES
2.1 Floor Area: 1236 ft2 2.2 In situ Combustible Materials
- Cable insulation
- Rubber
- Paper
- PVC 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 13-D 9.5A-140 Revision 21 September 2013 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Area wide smoke detection 3.2 Suppression
- CO2 hose stations
- Hose stations
- Portable fire extinguishers 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Emergency Power A fire in this area may disable the diesel generators 1-1, 1-2 and 1-3 automatic transfer circuit or may spuriously close their auxiliary transformer 12 circuit breaker. Manual actions will enable the diesels to either be locally loaded or loaded from the control room.
5.0 CONCLUSION
The following features will adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Loss of the safe shutdown circuitry in this area does not affect the ability to transfer to the emergency DGs.
- Area wide smoke detection is provided.
- Manual fire fighting equipment is provided. The existing fire protection in this area provides an acceptable level of safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 13-D 9.5A-141 Revision 21 September 2013
6.0 REFERENCES
6.1 Drawing No. 515564 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065126, Fire Protection Information Report, Unit 1 6.5 NECS File: 131.95, FHARE: 31, Undampered Duct Penetration from Fan Room 6.6 NECS File: 131.95, FHARE: 15, HVAC Duct Wrapped in Pyrocrete 6.7 NECS File: 131.95, FHARE: 14, Concrete Equipment Hatches 6.8 NECS File: 131.95, FHARE: 33, Undampered Duct Penetrations with 1 Hour Fire Resistive Coating 6.9 PLC Report: Structural Steel Analysis for Diablo Canyon Rev. 2 (07/08/86) 6.10 Deleted in Revision 13. 6.11 NECS File: 131.95, FHARE: 106, Block Walls Modified in the 4kV Switchgear Area 6.12 NECS File: 131.95, FHARE: 136, Unrated HVAC Duct Penetrations 6.13 Calculation 134-DC, Electrical Appendix R Analysis 6.14 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.15 NECS File: 131.95, FHARE 134, "Non-rated Structural Gap Seals in Fire Barriers" 6.16 NECS File: 131.95, FHARE 135, "Gaps in Appendix A Fire Rated Boundaries" 6.17 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.18 SSER - 23 6.19 PG&E Letter to NRC dated 11/13/78, Docket Number 5-275-0L, 50-323-01
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 13-E 9.5A-142 Revision 21 September 2013 FIRE AREA 13-E 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This fire area is located at the north end of the Turbine Building at El. 107 ft and 119 ft. 1.2 Description This fire area consists of the 4-kV switchgear ventilation fan room (El. 119 ft) and a triangular section above the southeast corner of fire zone 11-C-1 (El. 107 ft). The 4-kV switchgear ventilation supply fans are located at El. 119 ft. The air supply for these fans is from an El. 119 ft louvered opening in the north wall of the turbine building. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
El. 107 ft
- 3-hour rated barrier to Fire Zone 11-C-2 (TB-3).
El. 119 ft
- A nonrated louvered opening to the exterior NC. (Ref. 6.22) South:
El. 107 ft
- 3-hour barrier to Fire Zone 14-A (TB-7)
- 3-hour rated door to Fire Zone 14-A (TB-7)
El. 119 ft
- 3 hour barrier to Fire Zone 14-A (TB-7)
- 3-hour rated double door Fire Zone 14-A (TB-7)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 13-E 9.5A-143 Revision 21 September 2013 East: El. 107 ft
- 3-hour rated barrier to Fire Zone 12-A (TB-4) with the following exception: - A 1-1/2-hour rated door to Fire Zone 12-A (TB-4) (Ref. 6.22) - Unrated structural gap seal to Fire Zone 12-A (TB-4). (Ref. 6.17)
El. 119 ft
- 3-hour rated barrier to Fire Area 13-D with the following exceptions: - Unrated structural gap seals to Fire Area 13-D. (Ref. 6.17) 1/2-hour rated door to Fire Area 13-D. (Ref. 6.22) - Four ducts without fire dampers communicate to Area 13-D. (Refs. 6.20 and 6.22) - Structural steel modifications for the block walls were deemed acceptable with no fireproofing. (Ref. 6.12) - Lesser rated penetration seals to Area 13-D. (Ref. 6.19)
- 3-hour rated barrier to Fire Zone 12-E with the following exception:
- A duct without a fire damper to Fire Zone 12-E. (Refs. 6.21 and 6.22) - Unrated structural gap seals to Fire Zone 12-E. (Ref. 6.17)
West:
El. 107 ft
- A 3-hour rated barrier and door to fire zone 11-C-2. (Ref. 6.18) El. 119 ft
- 3-hour rated barrier to Fire Area 13-F. - Structural steel modifications for the block walls were deemed acceptable with no fireproofing. (Ref. 6.12) - Unrated structural gap seals to Fire Zone 13-F. (Ref. 6.17).
- Two 1 1/2-hour rated doors to Fire Area 13-F. (Ref. 6.22)
- A duct with a 1-1/2-hour rated fire damper communicates to Fire Area 13-F. (Ref. 6.22)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 13-E 9.5A-144 Revision 21 September 2013 Floor/Ceiling:
- 3-hour rated barrier and sealed diesel exhaust stack communicates with Fire Zone 14-D (TB-7) above and 11-C-2 (TB-3) below. (Ref. 6.18)
- Lesser rated penetration seals to Fire Zones 11-C-2 and 14-D. (Ref. 6.19)
- El. 107 ft and 119 ft of Area 13-E are joined by an open ventilation grating.
- Three 1-1/2-hour rated dampered ventilation ducts to Zones 12-A, 12-B and 12-C below El. 119 ft. (Ref. 6.22)
- An undampered ventilation duct to Zone 12-B below. (Refs. 6.20 and 6.13) 2.0 COMBUSTIBLES
2.1 Floor Area: 1,980 ft2 (Ref. 6.13) 2.2 In situ Combustible Materials
- Cable
- Filters
- Rubber 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection is provided throughout the 119-ft elevation area.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 13-E 9.5A-145 Revision 21 September 2013 3.2 Suppression
- A wet pipe automatic sprinkler system on El. 119 ft with remote annunciation.
- Portable fire extinguishers.
- CO2 hose station.
- Fire hose station.
4.0 SAFE SHUTDOWN FUNCTIONS 4.1 HVAC 4-kV switchgear room supply fans S-67, 68, and 69 may be lost for a fire in this area. The 4-kV switchgear will not be affected by a loss of the supply fans. (Refs. 6.9 and 6.10)
5.0 CONCLUSION
Fire Area 13-E does not meet the requirements of Appendix R, Section III.G.2(a) in that ducts without fire dampers penetrate into Fire Areas TB-5, TB-7, and 13-D, and nonrated steel hatches to Areas TB-1 and TB-3. The following fire protection features will adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- CO2 hose and fire hose stations.
- Portable fire extinguishers.
- Limited and dispersed combustible loading.
- Smoke detection available at El. 119 ft.
- Automatic wet pipe sprinkler system at El. 119 ft.
The existing fire protection provides an acceptable level of fire safety equivalent to that provided by Section III.G because fans are not required for safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 13-E 9.5A-146 Revision 21 September 2013
6.0 REFERENCES
6.1 Drawing Nos. 515562, 515563, 515564, 515565 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065126, Fire Protection Information Report, Unit 1 6.5 SSER 23, June 1984 6.6 SSER 8, November 1978 6.7 DCN DC1-EA-15261 - Provide 1 Hour Rating for Personnel and Equipment Hatches 6.8 NECS File: 131.95, FHARE: 33, Duct Penetration, without Fire Damper, with 1 Hour Fire Resistive Coating 6.9 Calculation M-911, Evaluation of Safe Shutdown Equipment During Loss of HVAC 6.10 Calculation M-912, HVAC Interactions for Safe Shutdown. 6.11 Deleted in Revision 13 6.12 NECS File: 131.95, FHARE: 106, Block Walls Modified in the 4kV Switchgear Area 6.13 NECS File: 131.95, FHARE: 136, Unrated HVAC Duct Penetrations 6.14 DCP H-50117, Diesel Generator Air Flow Improvement Modification, Units 1 and 2 6.15 Calculation 134-DC, Electrical Appendix R Analysis 6.16 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.17 NECS File: 131.95, FHARE 134, "Non-rated Structural Gap Seals in Fire Barriers" 6.18 NECS File: 131.95, FHARE 30, Unrated Gaps in Appendix R Barriers in the Turbine Building 6.19 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.20 NECS File: 131.95, FHARE 31, Undampered Duct Penetrations from the Fan Room 6.21 NECS File: 131.95, FHARE 56, Undampered Ventilation Duct Penetrations 6.22 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 28 9.5A-147 Revision 21 September 2013 FIRE AREA 28 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Yard area surrounding the Unit 1 buildings including the main transformer area.
1.2 Description This fire area is the open yard area surrounding the Unit 1 power plant buildings at El. 85 ft. The fire area includes the transformer area located north of the containment. The fire area also includes the area north and northeast of the Turbine Building. The three main transformers and one spare main transformer are a minimum distance of 50 ft from the Turbine Building, the two auxiliary transformers and two spare auxiliary transformers are approximately 30 ft away from the Turbine Building, and the three startup transformers are approximately 20 ft away from the Turbine Building. Spilled oil will drain away from the Turbine and Containment Buildings due to the pavement grade. The pipe chase outside containment is approximately 40 ft away from one of the nearest transformers. The I&C Building is also located in the fire area; it is approximately 30 ft west of the Unit 1 Turbine Building. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- El. 85 ft and 104 ft hour rated barrier to TB-14. NC.
- Outside nonrated area. South:
- El. 85 ft and 104 ft hour barrier to TB-14. NC
- El. 85 ft, 104 ft, and 119 ft - non-rated louvers to Fire Area 3-BB. NC. (Ref. 6.11)
- El. 85 ft, 104 ft, and 119 ft - non-rated barrier to Fire Zone 14-.A. NC
- 3-hour rated barrier to containment. Turbine Building
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 28 9.5A-148 Revision 21 September 2013
- Unrated small diameter penetration to Fire Area 10. (Ref. 6.9)
- Unsealed bus duct penetration to Fire Area 10. (Ref. 6.10)
- 2-hour rated barrier to Fire Area 10. (Ref. 6.8)
- 3-hour rated barrier to Fire Area 11-D.
- Doors and ventilation openings fitted with Class "A" labeled devices to Fire Areas 10 and 11-D.
- Nonrated walls and louvers to common exhaust plenum for diesel generator Fire Zones 11-A-2 (Fire Area TB-1), NC 11-B-2 (TB-2) NC and 11-C-2 (TB-3) NC and north end of hallway (Fire Area 12-C). (Refs. 6.11 and 6.12)
- 2-hour rated gypsum board shaft type fire barrier interior walls at El. 107 ft and 119 ft to Fire Zones 12-C and 13-C and Fire Area 13-D. (Refs. 6.14 and 6.15)
East:
- Outside nonrated area. West:
- El. 107 ft and 119 ft - 2 hour rated barrier to Fire Zone 12-E. NC
- El. 119 ft non-rated isophase bus penetrations to Fire Zone 12-E. NC
- Unsealed bus duct penetrations to Fire Area 10. (Ref. 6.10)
- 2-hour rated concrete barrier except for doors with ventilation openings fitted with Class "A" labeled devices to Fire Area 10. (Refs. 6.8 and 6.13)
- Nonrated walls and roll-up door fitted with Class "A" labeled devices to Fire Area TB-14 NC (reverse osmosis room - to be designated).
- 2-hour rated gypsum board shaft type fire barrier interior walls at El. 107 ft and 119 ft to Fire Zones 13-A, 13-B, 13-C, 12-A, 12-B, and 12-C. (Refs. 6.14 and 6.15)
- El. 85 ft, 104 ft and 119 ft - non-rated barrier to Fire Zone 14-A. NC 2.0 COMBUSTIBLES 2.1 Floor Area: 17,482 ft2 2.2 In situ Combustible Materials
- Bulk Cable
- Transformer oil contained in the main transformer.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 28 9.5A-149 Revision 21 September 2013 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- High 3.0 FIRE PROTECTION
3.1 Detection
- None 3.2 Suppression
- The three main transformers, two auxiliary transformers, and three startup transformers are provided with automatic spray systems with remote annunciation.
- Hose stations.
- Yard hydrant with fully equipped hose houses.
- Portable fire extinguishers.
4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Auxiliary Feedwater Manual positioning may be required for AFW valves LCV-106, LCV-107, LCV-110 and LCV-111 due to a fire in this area. Redundant valves LCV-108, LCV-109, LCV-113 and LCV-115 are available to provide AFW to the steam generators. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 28 9.5A-150 Revision 21 September 2013 4.2 Emergency Power A fire in this area may result in a loss of power supplies associated with PY17N. Redundant power supply PY16 remains available. 4.3 Main Steam System Various instrumentation may be lost for a fire in this area. Steam generator 1-1 and 1-2 pressure instrumentation that may be lost are the following: PT-514, 515, 516, 524, 525, and 526. However, steam generator pressure indication from PT-534, 535, 536, 544, 545 and 546 will remain available for steam generators SG 1-3 and SG 1-4. Main steam system valves FCV-24, FCV-25, FCV-41 and FCV-42 may fail for a fire in this area. These valves have a fusible link which melts and fails the valves closed. These valves can also be manually positioned to ensure safe shutdown. A fire in this area may prevent PCV-19 and PCV-20 from opening and prevent the operation of the valves from the hot shutdown panel. Redundant valves PCV-21 and PCV-22 will remain available for cooldown. Isolation of these valves is ensured by removing air sources from instrument air, backup air, and accumulators. Manual actions will be required in the fire area. As a means to help mitigate potential spurious operation of equipment, the main feedwater pumps are tripped. 4.4 Main Feedwater System A fire in this area may affect main feedwater valves FCV-1510, FCV-1520, FCV-510, and FCV-520. The main feedwater pumps may be tripped from the control room to stop main feedwater flow through the valves. 4.5 Reactor Coolant System Source range monitor NE-51 may be lost for a fire in this area. Redundant source range monitors NE-31, 32 and 52 will be available to provide necessary indications to the operator.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- The redundant trains of safe shutdown functions located in this fire area are unaffected by fire in this area due to spatial separation by fire in this area due to spatial separation and barriers provided.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 28 9.5A-151 Revision 21 September 2013
- Automatic water spray systems operate to control a fire involving the transformer area.
- Additional fire fighting equipment is provided.
- The grade of the transformer area is sloped to divert spilled oil away from the Turbine and Containment Buildings.
- Many exposed walls of adjacent fire areas/zones are at least 2-hour rated with penetrations sealed commensurate with the hazard.
This area complies with the requirements of 10 CFR 50, Appendix R, Section III.G and no exemptions have been requested.
6.0 REFERENCES
6.1 Drawing No. 515562 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation 134-DC, Electrical Appendix R Analysis 6.4 Calculation M-824, Combustible Loading Calculation 6.5 DCM M-62 App. A, ID of SSD Raceways/Fire Zones 6.6 Drawing 065126, Fire Protection Information Report, Unit 1 6.7 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.8 NECS File: 131.95 FHARE 133, Seismic/Construction Gaps in the 12kV Switchgear Rooms 6.9 NECS File: 131.95, FHARE 123, Unsealed Penetrations with Fusible Link Chain Penetrations 6.10 NECS File: 131.95, FHARE 20, Bus Duct Penetrations 6.11 SSER - 23 6.12 NECS File: 131.95, FHARE 30 unrated Gaps in Barriers 6.13 Question 25, PG&E Letter to NRC 8/3/78 6.14 Question 27, PG&E Letter to NRC 11/13/78 6.15 Question 29, PG&E Letter to NRC 11/13/78 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 30-A-1, 30-A-2 9.5A-152 Revision 21 September 2013 FIRE AREAS 30-A-1 AND 30-A-2 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Both fire areas are in the Intake Structure (El. 2 ft).
1.2 Description These areas consist of the ASW pump vaults inside the Intake Structure, surrounded by Fire Area IS-1 (Zone 30-A-5). 1.3 Boundaries 1.3.1 Fire Area 30-A-1 Northeast and Northwest:
- 3-hour rated wall with non-rated penetration seals to Fire Zone 30-A-5. (Ref. 6.6)
Southeast:
- 3-hour rated wall Fire Area 30-A-2. Southwest:
- 3-hour rated wall with an nonrated steel watertight door to Fire Zone 30-A-5. (Ref. 6.10)
Ceiling:
- Penetrated by a ventilation stack without a fire damper. (Ref. 6.10)
- 3-hour rated concrete hatch to the exterior. (Ref. 6.7) 1.3.2 Fire Area 30-A-2 Northeast and Southeast:
- 3-hour rated wall with non-rated penetration seals to Fire Zone 30-A-5. (Ref. 6.6)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 30-A-1, 30-A-2 9.5A-153 Revision 21 September 2013 Northwest:
- 3-hour rated wall Fire Area 30-A-1. Southwest:
- 3-hour rated wall with an nonrated steel watertight door to Fire Zone 30-A-5. (Ref. 6.10)
Ceiling:
- Penetrated by a ventilation stack without a fire damper. (Ref. 6.10)
- 3-hour rated concrete hatch to the exterior. (Ref. 6.7) 2.0 COMBUSTIBLES (Typical for each fire area) 2.1 Floor Area: 126 ft2 2.2 In situ Combustible Materials
- Lubricating oil
- Cable insulation
- PVC
- Rubber 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 30-A-1, 30-A-2 9.5A-154 Revision 21 September 2013 3.0 FIRE PROTECTION 3.1 Detection
- None
- Smoke detector outside of the entry to these areas in Fire Zone 30-A-5 3.2 Suppression
- Portable fire extinguishers available in adjacent fire area.
- Hose stations in the vicinity. 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Fire Area 30-A-1 4.1.1 Auxiliary Saltwater System Circuitry for ASW pumps 1-1 and 1-2 may be damaged due to a fire in this area. ASW pump 1-2 may be locally started to provide ASW flow. ASW valve FCV-495 may be affected for a fire in this area. Valves FCV-495 and FCV-601 are available, thus no manual actions are required. 4.1.2 HVAC HVAC exhaust fan E-103 may be lost for a fire in this area. HVAC exhaust fan E-101 will be available to provide necessary HVAC support. 4.2 Fire Area 30-A-2 4.2.1 Auxiliary Saltwater System Circuitry for ASW pumps 1-1 and 1-2 may be damaged by a fire in this area. ASW pump 1-1 can be locally started to provide ASW flow. ASW valve FCV-496 may be affected for a fire in this area. Valves FCV 495 and FCV-601 are available, thus no manual actions are required. 4.2.2 HVAC HVAC exhaust fan E-101 may be lost for a fire in this area. HVAC exhaust fan E-103 will be available to provide necessary HVAC support. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 30-A-1, 30-A-2 9.5A-155 Revision 21 September 2013
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- 3-hour rated walls except for nonrated steel watertight doors and non-rated penetration seals.
- Steel watertight doors would be able to confine smoke and hot gases to one side of the barrier.
- Smoke detection is available immediately outside the entrance of the areas.
- Manual fire protection equipment is available in the immediate vicinity.
In these areas existing fire protection will provide an acceptable level of fire safety equivalent to that provided 10 CFR 50, Appendix R, Section III.G.2.
6.0 REFERENCES
6.1 Drawing No. 515580 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065126, Fire Protection Information Report, Unit 1 6.5 SSER 23, June 1984 6.6 FHARE 114, Non-Rated Penetration Seals in the ASW Pump Room Barriers 6.7 FHARE 14, Concrete Equipment Hatches 6.8 Calculation 134-DC, Electrical Appendix R Analysis 6.9 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.10 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 35-A, 35-B 9.5A-156 Revision 21 September 2013 FIRE AREAS 35-A AND 35-B 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Unit 1 Turbine Building, west buttress, below El. 85 ft.
1.2 Description Fire Areas 35-A and 35-B are adjacent to each other and house the diesel fuel oil transfer pumps. Transfer Pump 0-1 is located in Area 35-A and Transfer Pump 0-2 is located in Area 35-B. The associated fuel oil piping, power and control circuitry for each transfer pump is also located in their respective fire area. 1.3 Boundaries Fire Areas 35-A and 35-B are bounded by 3-hour rated barriers with the following exceptions: (Ref 6.8) Ceiling
- A 3/8-inch thick steel hatch bounded by a 6" curb covers the access opening.
- Concrete hatches with caulked gaps provide restricted access for equipment removal.
Pipe Trench
- Sealed pipe penetrant communicates with each associated pump. The pipe trench associated with pump 0-1 is separated from the pipe branch for pump 0-2 by a 6-inch reinforced concrete barrier with a single sealed pipe penetration. DCN DC1-EA-35567 provided a seal for the open pipeway.
2.0 COMBUSTIBLES (typical for each Fire Area)
2.1 Floor Area: 105 ft2 each Fire Area) 2.2 In situ Combustible Materials (each Fire Area)
- Fuel oil DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 35-A, 35-B 9.5A-157 Revision 21 September 2013 2.3 Transient Combustible Materials (each Fire Area) Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Moderate 3.0 FIRE PROTECTION
3.1 Detection
- None 3.2 Suppression
- Portable fire extinguishers
- Hose stations 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Fire Area 35-A 4.1.1 Diesel Fuel Oil System Diesel fuel oil pump 0-1 may be lost due to a fire in this area. Diesel fuel oil pump 0-2 will remain available to provide fuel oil to the diesels. 4.2 Fire Area 35-B 4.2.1 Diesel Fuel Oil System Diesel fuel oil pump 0-2 may be lost due to a fire in this area. Diesel fuel oil pump 0-1 will remain available to provide fuel oil to the diesels. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 35-A, 35-B 9.5A-158 Revision 21 September 2013
5.0 CONCLUSION
The following features mitigate the effects of the design basis fire and assure the capability to achieve safe shutdown:
- Concrete hatches are caulked. Restricting air supply for combustion and preventing spilled flammable/combustible liquids from above from entering.
- Manual fire fighting equipment is available.
- 3-hour rated reinforced concrete barriers.
- Curbing around steel hatches covers to prevent a path of entrance for flammable/combustible liquids.
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
The existing fire protection in each zone provides an acceptable level of safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.2.
6.0 REFERENCES
6.1 Drawing No. 515579 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065126, Fire protection Information Report, Unit 1 6.5 SSER 23, June 1984 6.6 Calculation 134-DC, Electrical Appendix R Analysis 6.7 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.8 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-B-3 9.5A-159 Revision 21 September 2013 FIRE AREA AB-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This fire zone is in the Auxiliary Building at El. 54, 64 and 73 ft on the North side adjacent to containment and is called the Unit 1 Boron Injection Tank (BIT) room. 1.2 Description Fire Zone 3-B-3 constitutes the corridor that separates the RHR pump rooms from each other at the 54-ft and 64-ft elevation. The Boron Injection Tank (which has been taken out of service) occupies this zone. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. El. 54 ft North, South, East, West:
- 3-hour rated barriers: North to Containment NC South to Fire Zone 3C NC East to Fire Area 3-B-2 West to Fire Area 3-B-1
Floor:
- 3-hour rated barrier to grade. NC El. 64 ft North:
- 3-hour rated barrier to containment. NC South:
- 3-hour rated barrier with an opening to Zone 3-C. NC East:
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-B-3 9.5A-160 Revision 21 September 2013
- 3-hour rated barrier to Fire Area 3-B-2.
- A 1-1/2-hour rated door to Fire Area 3-B-2. (Ref. 6.5)
- Two duct penetrations without fire dampers communicate to Fire Area 3-B-2. (Ref. 6.5)
- A 3-hour equivalent rated double door with a monorail cutout that has water spray protection communicates to Fire Area 3-B-2. (Ref. 6.12)
- Unsealed valve operator shaft penetrations to Fire Area 3-B-2. (Ref. 6.7) West:
- 3-hour rated barrier to Fire Area 3-B-1.
- A 1-1/2-hour rated door to Fire Area 3-B-1. (Ref. 6.5)
- A duct penetration without a fire damper communicates to Fire Area 3-B-1. (Ref. 6.5)
- A 3-hour-equivalent rated double door with a monorail cutout that has water spray protection communicates to Fire Area 3-B-1. (Ref. 6.12)
- Lesser rated penetration seal to Fire Area 3-B-1. (Ref. 6.11) Ceiling:
- 3-hour rated to 3-H-1.
El. 73 ft North:
- 3-hour rated barrier to containment NC South:
- 3-hour rated barrier to Fire Areas 3-B-1, 3-B-2 and 3-H-1.
- 3-hour rated door to Fire Area 3-H-1.
- A duct penetration without damper to Fire Area 3-H-1. (Ref. 6.5)
- A 2-hour rated plaster block-out panel communicates to Fire Areas 3-B-1 and 3-B-2. (Ref. 6.8).
- A lesser rated penetration seal to Fire Areas 3-B-1 and 3-B-2. (Ref. 6.11) East:
- 3-hour rated barrier to Fire Zone 3-F and below grade. NC
- Two duct penetrations without dampers to Fire Area 3-F. NC (Ref. 6.6)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-B-3 9.5A-161 Revision 21 September 2013 West:
- 3-hour rated barrier to below grade. NC Ceiling:
- 3-hour rated to 3BB.
- Lesser rated penetration seals to Fire Area 3-BB. (Ref. 6.11) Floor:
- 3-hour rated to Fire Areas 3-B-1 and 3-B-2. 2.0 COMBUSTIBLES
2.1 Floor Area: 583 ft2 2.2 In situ Combustible Materials
- Oil
- Plastic 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-B-3 9.5A-162 Revision 21 September 2013 3.0 FIRE PROTECTION 3.1 Detection
- None 3.2 Suppression
- Portable fire extinguishers
- Fire hose stations 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Safety Injection System SI valves 8803A and 8803B may be affected by a fire in this area. A charging path through the regenerative heat exchanger or the RCP seals will remain available. Also, valves 8801A and 8801B can be used to isolate the charging injection flow path during RCS pressure reduction. Thus, no manual actions are required. 4.2 Residual Heat Removal System A fire in this area may affect DC control cables for RHR Pumps 1-1 and 1-2 recirculation valves, FCV-641A and FCV-641B. Prior to starting either RHR Pump 1-1 or 1-2 from the control room, manual operation can taken to locally open its respective recirculation valve.
5.0 CONCLUSION
The following features will adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Portable fire extinguishers and fire hose stations are available.
- Limited combustible loading.
- Redundant safe shutdown functions are located outside this zone.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-B-3 9.5A-163 Revision 21 September 2013 The existing fire protection provides an acceptable level of fire safety equivalent to that provided by Section III.G.2.
6.0 REFERENCES
6.1 Drawing Nos. 515566, 515567 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation M-824 Combustible loading 6.4 Drawing 065126, Fire Protection Information Report, Unit 1 6.5 SSER 23, June 1984 6.6 NECS File: 131.95, FHARE: 67, Undampered Duct Penetration 6.7 Deleted in Revision 13. 6.8 NECS File: 131.95, FHARE: 50, Plaster Block-out Panels in 3-Hour Barriers 6.9 Calculation 134-DC, Electrical Appendix R Analysis 6.10 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.11 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.12 NECS File: 131 .95, FHARE 159, Unrated Doors Protected by Local Automatic Sprinklers.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-F 9.5A-164 Revision 21 September 2013 FIRE AREA AB-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Zone 3-F is located in the Auxiliary Building at El. 73 ft on the northeast side and is called the Unit 1 Containment Spray Pump Area. 1.2 Description This fire zone contains the Unit 1 containment spray pumps 1-1 and 1-2, the spray additive tank and a nonvital motor control center. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- 3-hour rated barrier to Fire Zone S-3 and to below grade. NC South:
- 3-hour rated barrier with a duct penetration without a damper to Fire Area 3-H-2. (Ref. 6.5)
- 3-hour rated barrier to Fire Zone S-3 and Fire Area 3-B-2.
- Non-rated barrier with openings to Fire Zone 3-C. NC East:
- 3-hour rated barrier to Fire Zone S-3 and to below grade. NC
- A nonrated barrier to Fire Zone 3-A. NC
- A nonrated door to Fire Zone 3-A. NC West:
- 3-hour rated barrier to Fire Areas 3-B-2 and 3-H-2, and to Fire Zones 3-B-3 NC and S-3.
- A 1-1/2-hour rated door to Fire Zone S-3.
- Two duct penetrations without dampers communicate with Fire Zone 3-B-3. NC (Ref. 6.6)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-F 9.5A-165 Revision 21 September 2013
- An open doorway with a security gate communicates to Fire Area 3-H-2. (Ref. 6.9)
- Duct penetration without a damper to Fire Area 3-H-2. (Ref. 6.5)
Floor:
- 3-hour rated barrier to Zone 3-C and Fire Area S-3 below. Ceiling:
- 3-hour rated barrier to Areas 3-P-3, NC S-3, 3-M, NC and 3-BB above. 2.0 COMBUSTIBLES
2.1 Floor Area: 2,870 ft2 2.2 In situ Combustible Materials
- Cable
- Clothing/Rags
- Miscellaneous
- Lubricating Oil
- Wood
- Plastic
- Rubber 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-F 9.5A-166 Revision 21 September 2013 3.0 FIRE PROTECTION 3.1 Detection
- Smoke detection 3.2 Suppression
- Portable fire extinguishers
- Fire hose station 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Chemical and Volume Control System Charging pump 1-3 may be lost due to a fire in this area. Redundant charging pumps 1-1 and 1-2 will be available to provide charging flow.
5.0 CONCLUSION
The following features will adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Limited combustible loading.
- Smoke detection.
- Fire protection equipment is provided.
- Redundant safe shutdown functions are outside this zone. The existing fire protection provides an acceptable level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.2.
6.0 REFERENCES
6.1 Drawing No. 515567 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-F 9.5A-167 Revision 21 September 2013 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065126, Fire Protection Information Report, Unit 1 6.5 SSER 23, June 1984 6.6 NECS File: 131.95, FHARE: 67, Undampered Duct Penetrations 6.7 Calculation 134-DC, Electrical Appendix R Analysis 6.8 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONES 3-J-1, 3-J-2, 3-J-3 9.5A-168 Revision 21 September 2013 FIRE AREA AB-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location These zones are in the northwest corner of the 75-ft elevation of the Auxiliary Building. The zones are side by side with 3-J-2 between 3-J-1 on the west and 3-J-3 to the east. 1.2 Description These zones contain the component cooling water (CCW) pumps. Zone 3-J-1 contains CCW Pump 1-1. Zone 3-J-2 contains CCW Pump 1-2. Zone 3-J-3 contains CCW Pump 1-3. Zones 3-J-1 and 3-J-2 are similar in size but Zone 3-J-3 is larger. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. 1.3.1 Fire Zone 3-J-1 North:
- 3-hour rated barrier to below grade. NC South:
- Open to Fire Zone 3-C (see Note 1). (Ref. 6.3) East:
- 1-hour rated barrier to Fire Zone 3-J-2. (Ref. 6.6)
- A duct penetration without a damper to Fire Zone 3-J-2. (Ref. 6.3)
West:
- 3-hour rated barrier to below grade. NC Floor/Ceiling:
- 3-hour rated barriers.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONES 3-J-1, 3-J-2, 3-J-3 9.5A-169 Revision 21 September 2013 1.3.2 Fire Zones 3-J-2 North:
- 3-hour rated barrier to below grade. NC South:
- Open to Fire Zone 3-C (see Note). (Ref. 6.3) East:
- 1-hour rated barrier to Fire Zone 3-J-3. (Ref. 6.6)
- Two duct penetrations without fire dampers communicate to Fire Zone 3-J-3. (Ref. 6.3)
West:
- 1-hour rated barrier to Fire Zone 3-J-1. (Ref. 6.3, 6.6)
- A duct penetration without a fire damper communicates to Fire Zone 3-J-1. (Ref. 6.3)
Floor/Ceiling:
- Duct penetration without a damper communicates to Fire Zone 3-C below. (Ref. 6.3)
- 3-hour rated barriers: Floor to Fire Zone 3-C Ceiling to Fire Areas 4A-1 and 4-A 1.3.3 Fire Zone 3-J-3 North:
- 3-hour rated barrier to below grade. NC South:
- Open to Fire Zone 3-C (see Note). (Ref. 6.3)
- 3-hour rated barrier and door to Fire Area 3-H-1 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONES 3-J-1, 3-J-2, 3-J-3 9.5A-170 Revision 21 September 2013 East:
- 3-hour rated barrier to below grade. NC
- 3-hour rated barrier to Fire Area 3-B-1.
- 3-hour rated barrier to Fire Area 3-H-1. West:
- 3-hour rated barrier to below grade. NC
- 1-hour rated barrier to Fire Zone 3-J-2. (Ref. 6.6)
- Two duct penetrations without dampers communicate to Fire Zone 3-J-2. (Ref. 6.3)
Ceiling/Floor:
- Two open penetrations to Zone 3-C below. (Ref. 6.7)
- 3-hour rated barriers: Floor: To Fire Zone 3-C Ceiling: To Fire Areas 4-A-1, 4-A-2, and 4-A
- Lesser rated penetration seal to Area 3-BB. (Ref. 6.10)
(Note: For all three zones the openings south to 3-C are provided with an approximately 4-inch-high curb to prevent oil spillage from communications between zones.) (Ref. 6.3) 2.0 COMBUSTIBLES
2.1 Fire Zones 3-J-1 and 3-J-2 (typical of each area) 2.1.1 Floor Area: 405 ft2 2.1.2 In situ Combustible Materials
- Cable insulation
- Lubricating oil
- Grease 2.1.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONES 3-J-1, 3-J-2, 3-J-3 9.5A-171 Revision 21 September 2013
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.1.4 Fire Severity
- Low (3-J-1)
- Low (3-J-2) 2.2 Fire Zone 3-J-3 2.2.1 Floor Area: 781 ft2 2.2.2 In situ Combustible Materials
- Cable insulation
- Lubricating oil
- Rubber 2.2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.2.4 Fire Severity
- Low DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONES 3-J-1, 3-J-2, 3-J-3 9.5A-172 Revision 21 September 2013 3.0 FIRE PROTECTION 3.1 Detection Zone 3-J-1: Smoke detection provided Zone 3-J-2: Smoke detection provided Zone 3-J-3: Smoke detection provided 3.2 Suppression Zone 3-J-1:
- Wet pipe automatic sprinkler system with remote annunciation
- Fire hose stations
- Portable fire extinguishers Zone 3-J-2:
- Wet pipe automatic sprinkler system with remote annunciation
- Fire hose stations
- Portable fire extinguishers Zone 3-J-3:
- Partial wet pipe automatic sprinkler system with remote annunciation is provided for the pump room and the pipe chase but not for the ante room.
- Fire hose station
- Portable fire extinguishers 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Fire Zone 3-J-1 4.1.1 Component Cooling Water CCW pump and ALOP 1-1 may be lost due to a fire in this area. SSER 23 justifies that CCW pumps 1-2 and 1-3 and ALOPs 1-2 and 1-3 will remain available in the event of a fire. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONES 3-J-1, 3-J-2, 3-J-3 9.5A-173 Revision 21 September 2013 4.1.2 Diesel Fuel Oil System Diesel fuel oil pump 0-2 may be affected by a fire in this area. The circuits for diesel fuel oil pump 0-2 are protected by a fire barrier. The circuits for diesel fuel oil pump 0-1 are located 15 ft away. SSER 23 justifies that diesel fuel oil pump 0-1 will remain operational to provide fuel oil to the diesel generators. However, offsite power will be available for safe shutdown in the event the diesel fuel oil pump circuits are damaged. (Ref. 6.9) 4.1.3 HVAC Exhaust fan E-101 may be lost due to a fire in this area. Exhaust fan E-103 will be available to provide necessary HVAC support. 4.2 Fire Zone 3-J-2 4.2.1 Chemical and Volume Control System Charging pump 1-3 and ALOPs 1-1 and 1-2 may be lost due to a fire in this area. Charging pumps 1-1 and 1-2 can be locally tripped at their respective switchgear. Redundant Charging Pump 1-3 will remain available for safe shutdown. 4.2.2 Component Cooling Water CCW pumps 1-1 and 1-2 and ALOPs 1-1 and 1-2 may be lost due to a fire in this area. SSER 23 justifies that CCW pump 1-3 and ALOP 1-3 will be available to provide CCW flow. 4.2.3 Residual Heat Removal System A fire in this area may affect an AC control cable for RHR Pp 1-1 recirc valve FCV-641A. Redundant recirc valve FCV-641B will remain available for cold shutdown functions using RHR Pump 1-2. 4.2.4 Safety Injection System Valves 8803A and 8803B may be affected by a fire in this area. A charging path through the regenerative heat exchanger or the RCP seals will remain available. Also, valves 8801A and 8801B will remain available to isolate the charging injection flowpath during RCS pressure reduction. Thus, no manual actions are required. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONES 3-J-1, 3-J-2, 3-J-3 9.5A-174 Revision 21 September 2013 4.3 Fire Zone 3-J-3 4.3.1 Chemical and Volume Control System Charging pumps 1-1, 1-2 and 1-3 and ALOPs 1-1 and 1-2 may be lost due to a fire in this area. Charging pumps 1-1 and 1-2 can be locally started to provide charging flow. 4.3.2 Component Cooling Water CCW pump 1-3 and ALOP 1-3 may be lost due to a fire in this area. SSER 23 justifies that CCW pumps 1-1 and 1-2 and ALOPs 1-1 and 1-2 will be remain available to provide CCW flow. 4.3.3 Residual Heat Removal System A fire in this area may affect AC power cable for RHR Pump 1-2 recirculation valve FCV-641B and AC control cables for RHR Pumps 1-1 and 1-2 recirculation valves, FCV-641A and FCV-641B. Prior to starting either RHR Pump 1-1 or 1-2 from the control room, manual action can be taken to open its respective recirc valve (FCV-641A or FCV-641B). 4.3.4 Safety Injection System Valves 8803A and 8803B may be affected by a fire in this area. A charging path through the regenerative heat exchanger or the RCP seals will remain available. Also, valves 8801A and 8801B will remain available to isolate the charging injection flowpath during RCS pressure reduction. Thus, no manual actions are required.
5.0 CONCLUSION
The following features will adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Smoke detection in each zone.
- Automatic sprinkler system.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONES 3-J-1, 3-J-2, 3-J-3 9.5A-175 Revision 21 September 2013
- Limited combustible loading.
- Manual suppression equipment is available.
The existing fire protection provides an acceptable level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.2.
6.0 REFERENCES
6.1 Drawing No. 515567 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 SSER 23, June 1984 6.4 Calculation M-824, Combustible Loading 6.5 Drawing 065126, Fire Protection Information Report, Unit 1 6.6 NECS File: 131.95, FHARE: 37, Rating of Barriers Between CCW Pump Rooms 6.7 NECS File: 131.95, FHARE: 124, Unsealed Penetrations through Barrier 119 6.8 Calculation 134-DC, Electrical Appendix R Analysis 6.9 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.10 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-Q-2 9.5A-176 Revision 21 September 2013 FIRE AREA AB-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Zone 3-Q-2 is located in the south end of the Unit 1 Fuel Handling Building at El. 100 ft. This zone is adjacent to the northeast wall of the Auxiliary Building. 1.2 Description This zone contains AFW Pump 1-2 and 1-3 and is actually in the Fuel Handling Building and is called the Unit 1 Auxiliary Feedwater Motor Driven Pump Room. 1.3 Boundaries North:
- 3-hour rated barrier to Fire Zone 3-0.
- A 1-1/2-hour rated door to Fire Zone 3-0.
South:
- 3-hour rated barrier to Fire Zone S-3. East:
- 1-hour rated barrier to Fire Zone 3-Q-1. (Ref. 6.11)
- A 3-hour rated double door and a 3-hour rated door to Fire Zone 3-Q-1.
- A 1-1/2-hour rated fire damper to Fire Zone 3-Q-1. (Ref. 6.5)
- A duct penetration without a damper to Fire Zone 3-Q-1. (Ref. 6.5)
- Unique penetration seals in plaster walls to Fire Zone 3-Q-1. (Ref. 6.7)
- Lesser rated penetration seals to Fire Zone 3-Q-1. (Ref. 6.10)
West:
- 3-hour rated barrier to Fire Zone 3-BB.
- Lesser rated penetration seals to Fire Zone 3-BB. (Ref. 6.10)
- A 1-1/2-hour rated door to Fire Zone 3-BB. (Ref. 6.5)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-Q-2 9.5A-177 Revision 21 September 2013 Floor/Ceiling:
- 3-hour rated barrier: Floor: To Fire Zone S-3 Ceiling: To Fire Zone 3-R
- Ventilation opening communicates with Fire Zone 3-R above. (Ref. 6.6) 2.0 COMBUSTIBLES
2.1 Floor Area: 400 ft2 2.2 In situ Combustible Materials
- Lubricants
- Cable
- Clothing/Rags
- Wood (fir) 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection is provided DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-Q-2 9.5A-178 Revision 21 September 2013 3.2 Suppression
- Wet pipe automatic sprinkler system with remote annunciation.
- Portable fire extinguishers.
- Fire hose stations. 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Auxiliary Feedwater AFW pumps 1-2 and 1-3 may be lost due to a fire in this area. Redundant AFW pump 1-1 will be available to provide AFW.
5.0 CONCLUSION
The following features will adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Portable fire extinguishers and hose stations.
- Redundant safe shutdown function located outside this zone.
- Limited and dispersed combustible loading.
- Automatic wet pipe sprinkler system.
- Smoke detection provided. The existing fire protection features provide a level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 Drawing No. 515569 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065126, Fire Protection Information Report, Unit 1 6.5 SSER 23, June 1984 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-Q-2 9.5A-179 Revision 21 September 2013 6.6 NECS File: 131.95, FHARE: 9, Ventilation Opening Above AFW Pump Room 6.7 NECS File: 131.95, FHARE 121, Pipe Penetration Seals Through Plaster Walls in the Unit 1 AFW Pump Rooms 6.8 Calculation 134-DC, Electrical Appendix R Analysis 6.9 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.10 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.11 PG&E Letter DCL-84-329 Dated 10/19/84
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA FB-1 FIRE ZONE 31 9.5A-180 Revision 21 September 2013 FIRE AREA FB-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This zone is located at the east end of the Unit 1 Fuel Handling Building at the 104-ft elevation. 1.2 Description This zone consists of the Fuel Handling Building corridor.
1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- A 3-hour barrier to Zone 3-P-3. NC
- A 3-hour barrier to Zone 3-P-2. NC
- Duct penetrations without fire dampers penetrate to Zones 3-P-2 NC and 3-P-3. NC (Ref. 6.3)
- A 3-hour barrier to Zone S-9.
- A 1-1/2-hour rated door to Zone S-9.
South:
- A 2-hour fire rated barrier separates this zone from Area 3-Q-1.
- A 1-1/2-hour rated double door in a 2-hour rated plaster barrier communicates to Area 3-Q-1. (Refs. 6.10 and 6.11)
- A 3-hour fire rated barrier to Zone 3-R. NC
- Unique penetration seals in plaster walls to Area 3-Q-1. (Ref. 6.6)
- Lesser rated penetration seals to Area 3-Q-1. (Ref. 6.9) East:
- A 3-hour rated barrier to below grade. NC West:
- A 3-hour barrier to Zone 3-P-3. NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA FB-1 FIRE ZONE 31 9.5A-181 Revision 21 September 2013
- A 3-hour barrier to Zone 3-P-2 with a duct penetration without a fire damper. NC (Ref. 6.3)
- A 3-hour barrier to Zones S-8 and S-9.
- A non-rated door communicates to Zone 3-P-2. NC
- A 1-1/2-hour rated door communicates to Zone S-8.
- A 3-hour fire barrier to Zone 3-R. NC
- A 3-hour barrier to Zone 3-O. NC Floor:
- A 3-hour rated floor to Zone 3-P-3. NC Ceiling:
- Non-rated barrier to Zones 3-R NC and 3-P-4.NC
- Vent openings to 3-P-4. NC
- Vent opening to 3-R. NC 2.0 COMBUSTIBLES
2.1 Floor Area: 2,089 ft2 2.2 In situ Combustible Materials
- Tray Cable
- Lube Oil 2.3 Transient Combustible Loading Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA FB-1 FIRE ZONE 31 9.5A-182 Revision 21 September 2013 3.0 FIRE PROTECTION
3.1 Detection
- None 3.2 Suppression
- Automatic wet pipe sprinklers 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Make-up System Condensate storage tank level indication from LT-40 may be lost due to a fire in this area. Water from the raw water storage reservoir will remain available through FCV-436 and FCV-437. Manual action can be performed to locally open the normally closed manual valves. Manual valves 0-1557 and 0-280 are also located in this fire area, and will need to be manually operated to align RWSR to the AFW Pump suction flowpaths for both Units 1 and 2. 4.2 Safety Injection System A fire in this area may affect circuits associated with RWST Level Transmitter LT-920. This level transmitter is credited for diagnosis of spurious operation of equipment that may divert RWST inventory. There are no cables affected in this area that may result in diverting the RWST inventory. Therefore, loss of this instrument will not affect safe shutdown.
5.0 CONCLUSION
The following features mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- A trained fire brigade is onsite at all times and is responsible for fire suppression.
- Redundant components are not affected by a fire in this area.
- Area wide fire suppression is provided. This area complies with the requirements of 10 CFR 50, Appendix R, Section III.G.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA FB-1 FIRE ZONE 31 9.5A-183 Revision 21 September 2013
6.0 REFERENCES
6.1 Drawing No. 515569 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 NECS File: 131.95, FHARE: 40, Undampered Ventilation Ducts 6.4 Calculation No. M-824, Combustible Loading 6.5 PG&E Letter to the NRC, Question No. 25, 8/3/78 6.6 NECS File: 131.95, FHARE 121, Pipe Penetration Seals Through Plaster Walls in the Unit 1 AFW Pump Rooms 6.7 Calculation 134-DC, Electrical Appendix R Analysis 6.8 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.9 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.10 SSER - 23 6.11 NECS File: 131.95, FHARE 50, Plaster Blockout Panels in 3-Hour Barriers
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS TB-1, TB-2, TB-3 FIRE ZONES 11-A-1, 11-A-2, 11-B-1, 11-B-2, 11-C-1, 11-C-2 9.5A-184 Revision 21 September 2013 FIRE AREAS TB-1, TB-2, TB-3 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Northwest corner of Unit 1 Turbine Building; consists of the diesel generator rooms (El. 85 ft) and the diesel generator air intakes (El. 85 ft and 107 ft). 1.2 Description Fire Areas TB-1, TB-2, and TB-3 are divided into Fire Zones 11-A-1, 11-A-2, 11-B-1, 11-B-2, 11-C-1 and 11-C-2 to differentiate between the generator rooms and the ventilation intake and exhaust rooms. Fire Zones 11-A-1, 11-B-1, and 11-C-1 contain diesel generators 1-1, 1-2, and 1-3 respectively. These areas are located side by side with 11-B-1, located between 11-C-1 on the south side and 11-A-1 on the north. Fire Zones 11-A-1, 11-B-1, and 11-C-1 are provided with curbs at all door openings to contain any oil leakage. Several 4-inch floor drains are provided underneath the day tanks in each diesel generator room. A common 4-inch pitched header, which is a minimum of 3-1/2 ft below the drain openings, connects the drains from each room with the Turbine Building sump. No fire traps are provided and the drainage system will drain the quantity of the postulated day tank fuel oil spillage to the Turbine Building sump. The diesel generator intake and exhaust rooms (Fire Zones 11-A-2 (TB-1), 11-B-2 (TB-2), and 11-C-2 (TB-3)) communicate air between the 85-ft elevation, the 107-ft elevation and the exterior (Fire Area 28) area. The area north of Zone 11-A-1, which above the 107-ft elevation is separated by walls into Zone 11-A-2, 11-B-2 and 11-C-2, becomes an open common exhaust air plenum below the 107-ft elevation. Due to the similarities of these three fire areas, they are evaluated together.
1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS TB-1, TB-2, TB-3 FIRE ZONES 11-A-1, 11-A-2, 11-B-1, 11-B-2, 11-C-1, 11-C-2 9.5A-185 Revision 21 September 2013 1.3.1 El. 85 ft 1.3.1.1 Fire Zones 11-A-1, 11-B-1, 11-C-1 North:
- 3-hour rated barrier from: - Zone 11-A-1 to Zones 11-A-2 (Ref. 6.7), 11-B-2 and 11-C-2.
- Zone 11-B-1 to Zone 11-A-1. (Ref. 6.7) - Zone 11-C-1 to Zone 11-B-1. (Ref. 6.7)
South:
- 3-hour rated barrier from:
- Zone 11-A-1 to Zone 11-B-1. (Refs. 6.7 and 6.16) - Zone 11-B-1 to Zone 11-C-1. (Refs. 6.7 and 6.16) - Zone 11-C-1 to Zone 14-A. (Ref. 6.7)
East:
- 3-hour rated barriers to Area 11-D. (Refs. 6.7 and 6.10)
- A 3-hour rated roll up door, one from each zone to Area 11-D.
- Unrated small diameter penetration one from each zone to Area 11-D. (Ref. 6.11)
- A 3-hour rated door, one from each Zone to Area 11-D. West:
- 3-hour rated barrier.
- Two 3-hour rated roll-up doors.
- A drive shaft penetration.
All of the above exist between each of the following:
- Zone 11-A-1 to Zone 11-A-2 - Zone 11-B-1 to Zone 11-B-2 - Zone 11-C-1 to Zone 11-C-2
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS TB-1, TB-2, TB-3 FIRE ZONES 11-A-1, 11-A-2, 11-B-1, 11-B-2, 11-C-1, 11-C-2 9.5A-186 Revision 21 September 2013 Floor/Ceiling:
- Floor: Reinforced concrete on grade. NC
- Ceiling: 3-hour rated, except for diesel exhaust stack 11-A-1 to 11-A-2, 11-C-1 to 11-C-2, 11-B-1 to 11-B-2. (Ref. 6.10) 1.3.1.2 Fire Zones 11-A-2, 11-B-2, 11-C-2 (Radiator Rooms) El. 85 ft North:
- Nonrated barrier to the exterior (Fire Area 28) and radiator exhaust plenum NC (see Section 1.3.1.3). (Ref. 6.18)
- 3-hour rated barrier from: (Ref. 6.7)
- Zone 11-B-2 to Zone 11-A-2 - Zone 11-C-2 to Zone 11-B-2
- 3-hour rated door from: - Zone 11-B-2 to Zone 11-A-2
- Zone 11-C-2 to Zone 11-B-2
South:
- 3-hour rated barrier from: (Ref. 6.7) - Zone 11-A-2 to Zone 11-B-2
- Zone 11-B-2 to Zone 11-C-2 - Zone 11-C-2 to Zone 14-A
- 3-hour rated door from:
- Zone 11-A-2 to Zone 11-B-2 - Zone 11-B-2 to Zone 11-C-2
- A 1-inch sliding steel door (DR No. 115) from 11-C-2 to Fire Zone 14-A. This door is normally locked shut and welded closed for plant security.
East:
- 3-hour rated barrier.
- Two 3-hour rated roll up doors.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS TB-1, TB-2, TB-3 FIRE ZONES 11-A-1, 11-A-2, 11-B-1, 11-B-2, 11-C-1, 11-C-2 9.5A-187 Revision 21 September 2013
- A drive shaft penetration. All of the above exist between each of the following:
- Zone 11-A-2 to Zone 11-A-1 - Zone 11-B-2 to Zone 11-B-1 - Zone 11-C-2 to Zone 11-C-1
West:
- Nonrated barrier to the exterior. NC (Ref. 6.18) Floor/Ceiling:
- Floor: Reinforced concrete on grade. NC
- Ceiling: Open to 107-ft elevations.
1.3.1.3 Fire Zones 11-A-2, 11-B-2, 11-C-2 North Common Exhaust Plenum (El. 85 ft) North:
- The barriers of these zones adjacent to the exterior (Fire Area 28) have open louvers which provide flow paths for the diesel generator radiator exhaust. NC (Ref. 6.18)
South:
- 3-hour rated barrier to Zone 11-A-1. (Ref. 6.7) East:
- 3-hour rated barrier to Area 11-D. (Ref. 6.7)
- A nonrated metal personnel access hatch to Area 11-D. (Refs. 6.17 and 6.18)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS TB-1, TB-2, TB-3 FIRE ZONES 11-A-1, 11-A-2, 11-B-1, 11-B-2, 11-C-1, 11-C-2 9.5A-188 Revision 21 September 2013 West:
- Nonrated barrier. NC (Ref. 6.18) Floor/Ceiling:
- Floor: Reinforced concrete on grade. NC 1.3.2 El. 107 ft North:
- Nonrated barriers to the exterior. NC (Ref. 6.18)
- 3-hour rated barrier and door from zone 11-B-2 to zone 11-A-2. (Ref. 6.7)
- A lesser rated penetration seal from Zone 11-B-2 to Zone 11-A-2. (Ref. 6.15)
- 3-hour rated barrier and door from zone 11-C-2 to zone 11-B-2. (Ref. 6.7)
South:
- 3-hour rated barrier from zone 11-C-2 to Zone 13-E.
- 3-hour rated barrier and door from zone 11-C-2 to zone 14-A. (Ref. 6.7) East:
- 3-hour rated barriers from: Zone 11-A-2 to Zone 11-B-2. (Ref. 6.7) Zone 11-B-2 to Zone 11-C-2. (Ref. 6.7) Zone 11-C-2 to Zones 13-E, 12-A, 12-B, 12-C. (Ref. 6.7)
- 3-hour rated door communicates from zone 11-C-2 to zone 13-E.
West:
- Nonrated barriers to the exterior NC (Refs. 6.9 and 6.18).
- 3-hour rated barriers from: Zone 11-B-2 to Zone 11-A-2 (Ref. 6.7) Zone 11-C-2 to Zone 11-B-2 (Ref. 6.7)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS TB-1, TB-2, TB-3 FIRE ZONES 11-A-1, 11-A-2, 11-B-1, 11-B-2, 11-C-1, 11-C-2 9.5A-189 Revision 21 September 2013 Floor/Ceiling:
- Floor: 3-hour barrier to 11-A-1, 11-B-1 and 11-C-1 except for Diesel Exhaust Stacks. (Ref. 6.10) Floor opening to 11-A-2 (common exhaust plenum). (Ref. 6.9)
- Ceiling: 3-hour barrier to 13-E and 13-F above. (Ref. 6.7) Lesser rated penetration seals to Zones 13-E and 13-F. (Ref. 6.15) 2.0 COMBUSTIBLES
Fire Areas TB-1, TB-2, and TB-3 at El. 85 ft each have approximately the same area and combustible loading. At the 107-ft elevation there is no in situ combustible loading. The following information applies to each fire area. 2.1 Floor Area: 770 ft2 (11-A-1, 11-B-1, 11-C-1), 1532 ft2 (11-A-2) (Ref. 6.10) 1383 ft2 (11-B-2) (Ref. 6.10) 1658 ft2 (11-C-2) (Ref.6.10) 2.2 In situ Combustible Materials
- Lube oil
- Fuel oil
- Bulk Cable
- Polyethylene
- Plastic
- Rubber
- Paper 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS TB-1, TB-2, TB-3 FIRE ZONES 11-A-1, 11-A-2, 11-B-1, 11-B-2, 11-C-1, 11-C-2 9.5A-190 Revision 21 September 2013
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Moderate (11-A-1, 11-B-1, 11-C-1)
- Low (11-A-2, 11-B-2, 11-C-2) 3.0 FIRE PROTECTION (applies for each area)
3.1 Detection
- Heat detection which: (a) releases east doors, (b) releases west doors, (c) activates CO2 system. 3.2 Suppression
- Total flooding CO2
- Portable fire extinguishers
- Fire hose stations 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Fire Zones 11-A-1 and 11-A-2 4.1.1 Diesel Fuel Oil System Diesel fuel oil pumps (DFO) 0-1 and the cables affecting the transfer of fuel to DG 1-1 from DFO pump 0-2 may be affected by a fire in this area. The ability to transfer diesel fuel to DG 1-2 and 1-3 from DFO pump 0-2 will remain available. In addition, offsite power will not be affected in this area and will remain available. A fire in this area may result in the loss of LCV-85 and LCV-88 . Day tank level control for DGs 1-2 and 1-3 will be maintained by LCV-86 and LCV-87. In addition, offsite power will not be affected in this area and will remain available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS TB-1, TB-2, TB-3 FIRE ZONES 11-A-1, 11-A-2, 11-B-1, 11-B-2, 11-C-1, 11-C-2 9.5A-191 Revision 21 September 2013 4.1.2 Emergency Power A fire in this area may disable diesel generator 1-1. Diesel generators 1-2 and 1-3 will remain available. In addition, offsite power will not be affected in this area and will remain available. 4.2 Fire Zones 11-B-1 and 11-B-2 4.2.1 Diesel Fuel Oil System Diesel fuel oil (DFO) pump 0-2 and circuits affecting the transfer of fuel to DG 1-2 from DFO pump 0-1 may be lost due to a fire in this area. The ability to transfer fuel to DGs 1-1 and 1-3 from DFO pump 0-1 will remain available. In addition, offsite power will not be affected in this fire area and will remain available. Valves LCV-86 and LCV-89 may be lost due to a fire in this area. Day tank level control will be maintained by LCV-88 and LCV-90. In addition, offsite power will not be affected in this fire area and will remain available. 4.2.2 Emergency Power A fire in this area may disable diesel generator 1-2. Diesel generators 1-1 and 1-3 will remain available for safe shutdown. In addition, offsite power will not be affected in this fire area and will remain available. 4.3 Fire Zones 11-C-1 and 11-C-2 4.3.1 Diesel Fuel Oil System A fire in this area may prevent DFOS PPs 0-1 and 0-2 from providing fuel oil to DG 1-3. These pumps will be able to provide fuel oil to DGs 1-1 and 1-2. In addition, offsite power is not affected in this area and will remain available. A fire in this area may cause LCV-87 and LCV-90 to be unavailable. Since DG 1-3 will be unavailable, these valves will not be necessary for safe shutdown. In addition, offsite power is not affected in this area and will remain available. 4.3.2 Emergency Power System A fire in this area may disable DG 1-3. DGs 1-1 and 1-2 will remain available for safe shutdown. In addition, offsite power is not affected in this area and will remain available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS TB-1, TB-2, TB-3 FIRE ZONES 11-A-1, 11-A-2, 11-B-1, 11-B-2, 11-C-1, 11-C-2 9.5A-192 Revision 21 September 2013
5.0 CONCLUSION
The following fire protection features will adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Manual fire fighting equipment is available for use in the areas.
- Floor drainage system will drain postulated day tank fuel oil spillage to the Turbine Building sump.
- A total flooding CO2 suppression system is provided for the DG rooms.
- The drainage system described in Section 1.2 does not contain fire traps. A commitment to provide fire traps was accepted by the NRC in SSER 8. This commitment was then withdrawn and the existing floor drainage system justified and found acceptable. (Ref. 6.6)
- The fire hazard is minimal in the ventilation intake and exhaust rooms. Smoke and hot gases would either be vented outside through the louvers in the exterior wall or confined within the area by the fire rated perimeter construction until the fire brigade arrives.
The existing fire protection for the areas provides an acceptable level of safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.2.
6.0 REFERENCES
6.1 Drawing No. 515562 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065126, Fire Protection Information Report, Unit 1 6.5 SSER 23, June 1984 6.6 58 Fire Review Questions (11/13/78) 6.7 NECS File: 131.95, FHARE: 30, Unrated Gaps in Appendix R Barriers in the Turbine Building 6.8 Deleted in Revision 13 6.9 DCP H-49117 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS TB-1, TB-2, TB-3 FIRE ZONES 11-A-1, 11-A-2, 11-B-1, 11-B-2, 11-C-1, 11-C-2 9.5A-193 Revision 21 September 2013 6.10 PG&E Engineering Calculation File: 131.95, FHARE 103, Fire Barrier Configurations in the Emergency Diesel Generator Rooms 6.11 NECS File: 131.95, FHARE 123, Unsealed penetrations with fusible link chain penetrants through fire barrier 6.12 DCP H-50117, Diesel Generator Air Flow Improvement Modification for Units 1 and 2 6.13 Calculation 134-DC, Electrical Appendix R Analysis 6.14 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.15 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.16 NECS File: 131.95, FHARE 141, Fireproofing on Unistruts Attached to Structural Steel Members 6.17 NECS File: 131.95, FHARE 68, Non-rated Hatch 6.18 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-4 FIRE ZONES 12-A, 13-A 9.5A-194 Revision 21 September 2013 FIRE AREA TB-4 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Area TB-4 is in the northeast corner of the Unit 1 Turbine Building and consists of Fire Zone 12-A, at El. 107 ft, and Fire Zone 13-A, at El. 119 ft. 1.2 Description Fire Area TB-4 consists of the 4-kV F Bus cable spreading room (at 107 ft), Fire Zone 12-A, the 4-kV F Bus switch gear room (at 119 ft), and Fire Zone 13-A, in the Turbine Building. At least two of the three vital divisions are required for safe shutdown. 1.3 Boundaries 1.3.1 Fire Zone 12-A (El. 107 ft) North:
- A 2-hour rated barrier to Fire Zone 12-B (TB-5). (Refs. 6.5 and 6.19)
- Unrated structural gap seals to Fire Zone 12-B (TB-5). (Ref. 6.15)
- Two 3-hour rated doors to Fire Zone 12-B (TB-5).
- A 1-1/2-hour rated door to Fire Zone 12-B (TB-5). (Ref. 6.19)
- A lesser rated penetration seal to Fire Zone 12-B (TB-5). (Ref. 6.17)
South:
- 3-hour rated barrier to Fire Zone 14-A (TB-7), at col. line 5, C5.
- 2-hour rated barrier to Fire Zone 12-E (TB-7).
- Unrated structural gap seals to Fire Zone 12-E (TB-7). (Ref. 6.15)
- Two 1-1/2-hour rated doors to Fire Zone 12-E (TB-7). (Ref. 6.19)
East:
- 2-hour rated barrier to Fire Zone 12-E
- 2-hour rated barrier to the exterior (Area 28)
- 1-1/2-hour rated door to Fire Zone 12-E DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-4 FIRE ZONES 12-A, 13-A 9.5A-195 Revision 21 September 2013 West:
- 3-hour rated barrier to Fire Area 13-E and Zone 11-C-2 (Fire Area TB-3) (Ref. 6.16) and to Fire Zone 12-B (Fire Area TB-5).
- Unrated structural gap seals to Fire Area 13-E. (Ref. 6.15)
- A 1-1/2-hour rated door to Fire Area 13-E. (Ref. 6.18) Floor/Ceiling:
Ceiling:
- 3-hour rated concrete slab.
- A ventilation duct without a 3-hour rated fire damper communicates with Fire Area 13-D (above). (Refs. 6.8 and 6.12)
- A ventilation duct with a 3-hour rated fire damper communicates with Fire Area 13-E (above). (Ref. 6.6)
- A vent opening to Fire Zone 13-A. Floor:
- 3-hour rated concrete slab on unprotected steel to Fire Areas 10 and 11-D. (Ref. 6.9) 1.3.2 Fire Zone 13-A (El. 119 ft)
North:
- A 2-hour rated barrier to Fire Zone 13-B (Fire Area TB-5). (Ref. 6.20)
- Unrated structural gap seals to Fire Zone 13-B (Fire Area TB-5). (Ref. 6.15)
- A 1-1/2-hour rated door to Fire Zone 13-B. (Ref. 6.20)
South:
- 3-hour rated barrier to Fire Zone 12-E (Fire Area TB-7).
- A 1-1/2-hour rated door to Fire Zone 12-E. (Ref. 6.20) East:
- 2-hour rated barrier to the exterior (Area 28). (Ref. 6.20)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-4 FIRE ZONES 12-A, 13-A 9.5A-196 Revision 21 September 2013 West:
- 3-hour rated barrier to Fire Area 13-D.
- Unrated structural gap seals to Fire Area 13-D. (Ref. 6.15)
- A 1-1/2-hour rated door to Fire Area 13-D. (Ref. 6.20)
- A 1-1/2-hour rated damper to Fire Area 13-D. (Ref. 6.20)
- 3-hour rated pyrocrete blockout around the door. (Ref. 6.10) Floor/Ceiling:
Ceiling:
- 3-hour rated concrete slab.
- A ventilation exhaust opening to the main turbine deck (El. 140 ft) with a 3-hour rated fire damper.
Floor:
- 3-hour rated concrete slab.
- A vent opening to Fire Zone 12-A.
Protective
Enclosure:
- All corner gaps are sealed, and structural steel have fire resistive coverings. (Note: Some structural steel modifications for the block walls (at El. 119 ft) were deemed acceptable with no fireproofing. (Ref. 6.11))
2.0 COMBUSTIBLES
2.1 Fire Zone 12-A (107 ft) 2.1.1 Floor Area: 1482 ft2 2.1.2 In situ Combustible Materials
- Bulk Cable
- Rubber
- Plastic DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-4 FIRE ZONES 12-A, 13-A 9.5A-197 Revision 21 September 2013 2.1.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.1.4 Fire Severity
- Low 2.2 Fire Zone 13-A (119 ft) 2.2.1 Floor Area: 855 ft2 2.2.2 In situ Combustible Material
- Bulk Cable
- Rubber
- Plastic 2.2.3 Transient Combustible Material Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-4 FIRE ZONES 12-A, 13-A 9.5A-198 Revision 21 September 2013 2.2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection is provided in Fire Zones 12-A and 13-A.
3.2 Suppression (for each zone)
- Portable fire extinguishers
- CO2 hose station
- Fire hose station 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Fire Zones 12-A and 13-A 4.1.1 Auxiliary Feedwater AFW pump 1-3 may be lost for a fire in this area. Steam generators 1-3 and 1-4 are credited for safe shutdown in this area, and redundant AFW pump 1-1 will be available to provide AFW. AFW valves LCV-113 and LCV-115 may be affected by a fire in this area. Redundant valves LCV-108 and LCV-109 will remain available to provide AFW flow to Steam Generators 1-3 and 1-4 via AFW Pump 1-1. 4.1.2 Chemical and Volume Control System Charging pump 1-1 and ALOP 1-1 may be lost due to a fire in this area. Redundant charging pumps 1-2, 1-3 and ALOP 1-2 will remain available to provide charging flow. Boric acid transfer pump 1-1 may be lost due to a fire in this area. Redundant boric acid pump 1-2 will be available for this function. CVCS valve 8107 may be affected by a fire in this area. CVCS valves 8108, HCV-142, or 8145 and 8148 will remain available to isolate auxiliary spray. Two other charging flowpaths will remain available. The PORVs can be used for pressure reduction. Since valve 8107 has redundant components, safe shutdown is not affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-4 FIRE ZONES 12-A, 13-A 9.5A-199 Revision 21 September 2013 CVCS valve LCV-112B may be affected by a fire in this area. SIS valve 8805B remains available to provide water from the RWST to the charging pump suction. The volume control tank can be isolated by closing LCV-112C. Boric acid storage tank 1-2 level indication from LT-106 may be lost due to a fire in this area. Since borated water from the RWST will remain available, BAST level indication is not required. 4.1.3 Component Cooling Water CCW pump 1-1 and ALOP 1-1 may be lost due to a fire in this area. CCW pumps and ALOPs 1-2 and 1-3 will remain available to provide CCW. CCW valve FCV-430 may be affected by a fire in this area making heat exchanger 1-1 unavailable for CCW cooling. Redundant valve FCV-431 will remain available making CCW heat exchanger 1-2 available. Thus no manual actions are required. 4.1.4 Emergency Power A fire in this area may disable the backup control circuit for diesel generator 1-2. The normal control circuit will remain available. A fire in this area may disable diesel generator 1-3. Diesel generators 1-1 and 1-2 will remain available for safe shutdown. A fire in this area may disable Startup Transformer 1-2. Onsite power from diesel generators 1-1 and 1-2 will remain available for safe shutdown. All power supplies on the "F" Bus may be lost due to a fire in this area. These power supplies are not necessary since redundant trains on the "G" and "H" Buses will be available. A fire may disable dc panel SD13 backup battery charger ED131. Normal battery charger ED132 will remain available. A fire in this area may result in a loss of power supplies associated with PY17N. Redundant power supply PY16 remains available. 4.1.5 Main Steam System A fire in this area may result in the loss of LT-516, LT-526, LT-529, LT-536, LT-539, LT-546, PT-514, PT-524, PT-534 and PT-544. Since redundant instrumentation will be available all four steam generators, safe shutdown will not be affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-4 FIRE ZONES 12-A, 13-A 9.5A-200 Revision 21 September 2013 Main steam system valve PCV-19 may fail due to a fire in this area. Since this valve fails in its desired position, safe shutdown can still be achieved. Redundant dump valves PCV-21 and PCV-22 will remain available for cooldown purposes using steam generators 1-3 and 1-4. 4.1.6 Makeup System The level transmitter for the condensate storage tank, LT-40 may be lost due to a fire in this area. Feedwater will remain available through FCV-436 from the raw water storage reservoir. Manual action can be performed to locally open FCV-436 prior to CST depletion. 4.1.7 Reactor Coolant System The following instrumentation may be lost due to a fire in this area: TE-413A, TE-413B, TE-423A, TE-423B, PT-403, PT-406, LT-406, LT-459, NE-31 and NE-51. Redundant instrumentation will be available to provide necessary indications to the operator. RCS valve 8000A may be affected by a fire in this area. This valve is normally open and fails "as is." PCV-474 will remain closed to prevent uncontrolled pressure reduction through the PORV path. 4.1.8 Safety Injection System SI pump 1-1 may spuriously operate due to a fire in this area. Local manual action may be required to defeat this spurious operation prior to RCS depressurization. SI valves 8801A, 8803A and 8805A may be affected by a fire in this area. Since these valves have redundant components, safe shutdown is not affected. SI valve 8808A may be affected by a fire in this area. Manual action may be necessary to close 8808A. 4.1.9 Auxiliary Saltwater System Circuitry of ASW pumps 1-1 and 1-2 may be damaged by a fire in this area. ASW pump 1-2 can be started locally to provide ASW flow. A fire in this area may affect valve FCV-602. This valve fails in the desired safe shutdown position. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-4 FIRE ZONES 12-A, 13-A 9.5A-201 Revision 21 September 2013 4.1.10 HVAC HVAC equipment E-103, E-43, S-43, FCV-5045 and S-69 may be lost due to a fire in this area. E-103 and S-69 will not be necessary during a fire in this area. S-43, E-43 and FCV-5045 have redundant components S-44, E-44 and FCV-5046 that will remain available to provide necessary HVAC support to the 480-volt switchgear.
5.0 CONCLUSION
The following fire protection features mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Smoke detection is provided for the fire area.
- Portable fire extinguishers, CO2 hose stations and fire hose stations are available.
- Redundant safe shutdown capability is provided outside of this fire area. In this fire area, existing fire protection features provide an acceptable level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.
6.0 REFERENCES
6.1 Drawing Nos. 515562, 515563, 515564, 515565 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065126, Fire Protection Information Report, Unit 1 6.5 SSER 8, November 1978 6.6 DCN DC1-EH-15047, Provide 3 hour related dampers to Fire Area 12-A 6.7 DCN DC1-E-E9408, Rev. 0, Alternate Means Provided to Start AFW Pumps 6.8 NECS File: 131.95, FHARE: 31, Undampered Duct Penetrations From the Fan Room 6.9 PLC report: Structural Steel Analysis for Diablo Canyon (Rev. 2) 7/8/86 6.10 DCN DC1-EA-15662 R4, provide 3-hour rated pyrocrete blockout DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-4 FIRE ZONES 12-A, 13-A 9.5A-202 Revision 21 September 2013 6.11 NECS File: 131.95, FHARE: 106, Block Walls Modified in the 4kV Switchgear Area 6.12 NECS File: 131.95, FHARE: 136, Unrated HVAC Duct Penetrations 6.13 Calculation 134-DC, Electrical Appendix R Analysis 6.14 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.15 NECS File: 131.95, FHARE 134, "Non-rated Structural Gap Seals in Fire Barriers" 6.16 NECS File: 131.95, FHARE 30, Unrated Gaps in Appendix R Barriers in the Turbine Building 6.17 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.18 SSER - 23 6.19 Question 27, PG&E Letter to NRC Dated 11/13/78 6.20 Question 29, PG&E Letter to NRC Dated 11/13/78
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-5 FIRE ZONES 12-B, 13-B 9.5A-203 Revision 21 September 2013 FIRE AREA TB-5 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Area TB-5 is in the Northeast corner of the Unit 1 Turbine Building and consists of Fire Zones 12-B, at El. 107 ft, and Fire Zone 13-B, at El. 119 ft. 1.2 Description Fire Area TB-5 consists of the 4-kV "G" bus cable spreading at El. 107 ft, Zone 12-B, and the 4-kV "G" bus switchgear room at El. 119 ft in the Turbine Building. At least two of the three vital divisions are required for safe shutdown. 1.3 Boundaries 1.3.1 Fire Zone 12-B (El. 107 ft) North:
- A 2-hour rated barrier to Fire Zone 12-C (TB-6). (Ref. 6.5 and 6.18)
- Unrated structural gap seals to Fire Zone 12-C. (Ref. 6.15)
- Two 3-hour rated doors to Fire Zone 12-C.
- A 1-1/2-hour rated door to Fire Zone 12-C. (Ref. 6.18) South:
- A 2-hour rated barrier to Fire Zone 12-A (TB-4). (Ref. 6.18)
- Unrated structural gap seals to Fire Zone 12-A (TB-4). (Ref. 6.15)
- A 1-1/2-hour rated door to Fire Zone 12-A. (Ref. 6.18)
- Two 3-hour rated doors to Fire Zone 12-A.
- A lesser rated penetration seal to Fire Zone 12-A (TB-4). (Ref. 6.17)
East:
- 2-hour rated barrier to the exterior (Area 28). (Ref. 6.18)
- 2-hour rated barrier to Fire Zones 12-A and 12-C. (Ref. 6.18) West:
- 2-hour rated barrier to Fire Zone 12-C. (Ref. 6.18)
- 3-hour rated barrier to Fire Zone 11-C-2 (TB-3). (Ref. 6.16)[O-9.5A(4)]
- Floor/Ceiling:
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-5 FIRE ZONES 12-B, 13-B 9.5A-204 Revision 21 September 2013 Ceiling: To Fire Zones 13-B, 13-D, and 13-E
- 3-hour rated concrete slab.
- 3-hour rated concrete equipment hatch to Fire Area 13-D. (Ref. 6.7) The equipment hatch is supported by removable steel beams, which are unprotected. (Ref. 6.8)
- A ceiling vent opening to Fire Zone 13-B. (Ref. 6.18)
- A ventilation duct without a fire damper communicates with Fire Area 13-E (above). (Refs. 6.9 and 6.12)
- A ventilation duct with a 3-hour rated fire damper communicates with Fire Area 13-E (above). (Ref. 6.6)
Floor: To Fire Areas 10 and 14-D
- 3-hour rated concrete slab on unprotected steel. (Ref. 6.8)
- 3-hour rated concrete equipment hatch to Fire Area 10. The equipment hatch is supported by removable steel beams, which are not fire protected. (Ref. 6.7)
- The floor is penetrated by a duct without a fire damper communicating with Fire Area 11-D below. (Ref. 6.9) 1.3.2 Fire Zone 13-B (El. 119 ft)
North:
- A 2-hour rated wall to Fire Zone 13-C (Fire Area TB-6). (Ref. 6.19)
- Unrated structural gap seals to Fire Zone 13-C (Fire Area TB-6). (Ref. 6.15)
- A 1-1/2-hour rated door to Fire Zone 13-C (TB-6). (Ref. 6.19)
South:
- A 2-hour rated wall to Fire Zone 13-A (TB-4). (Ref. 6.19)
- Unrated structural gap seals to Fire Zone 13-A (TB-4). (Ref. 6.15)
- A 1-1/2-hour rated door to Fire Zone 13-A. (Ref. 6.19) East:
- 2-hour rated wall to the exterior (Area 28). (Ref. 6.19) West:
- 3-hour rated wall to Fire Area 13-D.
- Unrated structural gap seals to Fire Area 13-D. (Ref. 6.15)
- A 1-1/2-hour rated door to Fire Area 13-D. (Ref. 6.19)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-5 FIRE ZONES 12-B, 13-B 9.5A-205 Revision 21 September 2013
- A 1-1/2-hour rated damper to Fire Area 13-D. (Ref. 6.19)
- 3-hour rated pyrocrete blockout around the door. (Ref. 6.10)
Floor/Ceiling:
Ceiling:
- 3-hour rated concrete slab.
- 3-hour rated fire damper in a ventilation exhaust penetration to the main turbine deck (140-ft elevation) Fire Zone 14-D (Fire Area TB-7).
Floor: To Fire Zone 12-B
- 3-hour rated concrete slab.
- A floor vent opening to Fire Zone 12-B (below). (Ref. 6.18)
Protective
Enclosure:
- All corner gaps are sealed and structural steel have fire resistive coverings. (Note: Some structural steel modifications for the block walls (at E1.119 ft) were deemed acceptable with no fireproofing. (Ref. 6.11))
2.0 COMBUSTIBLES
2.1 Fire Zone 12-B (El. 107 ft) 2.1.1 Floor Area: 1,423 ft2 2.1.2 In Situ Combustible Materials
- Cable insulation
- Miscellaneous
- Plastic
- Rubber 2.1.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-5 FIRE ZONES 12-B, 13-B 9.5A-206 Revision 21 September 2013
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.1.4 Fire Severity
- Low 2.2 Fire Zone 13-B (El. 119 ft) 2.2.1 Floor Area: 855 ft2 2.2.2 In situ Combustible Materials
- Cable
- Plastic
- Rubber 2.2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection is provided in Fire Zones 12-B and 13-B.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-5 FIRE ZONES 12-B, 13-B 9.5A-207 Revision 21 September 2013 3.2 Suppression (available for both zones)
- Portable fire extinguishers
- CO2 hose stations
- Fire hose stations 4.0 SAFE SHUTDOWN
4.1 Fire Zones 12-Band 13-B 4.1.1 Auxiliary Feedwater A fire in this area may affect LCV-106, LCV-107, LCV-108, and LCV-109. Steam generators 1-1 and 1-2 are credited for safe shutdown. Redundant valves LCV-110 and LCV-111 will remain available from AFW Pump 1-2. 4.1.2 Chemical and Volume Control System Valve 8108 may be lost due to a fire in this area. Valve 8107 can be shut to isolate auxiliary spray. One other charging flowpath will be available. Also, the PORVs will be available for pressure reduction. Since this valve has redundant functions, safe shutdown is not affected. A fire in this area may affect valves 8104 and FCV-110A. Safe shutdown is not affected because FCV-110A fails open and manual actions can be taken to open valve 8471 in order to provide boric acid flow. Valves 8146, 8147 and 8148 may be affected by a fire in this area. Since redundant components are available safe shutdown is not affected. Charging pumps 1-2 and 1-3 and ALOP 1-2 may be affected by a fire in this area. Redundant charging pump 1-1 and ALOP 1-1 will remain available for safe shutdown. Boric acid transfer pump 1-2 may be affected by a fire in this area. Redundant boric acid transfer pump 1-1 will remain available. HCV-142 may be affected by a fire in this area. HCV-142 is not necessary for a fire in this area since redundant components exist to isolate auxiliary spray (8107), to provide a charging flowpath (charging injection) and to provide for pressure reduction (PORVs). A fire in this area might result in the spurious closure of charging pump discharge flow control valve FCV-128. This valve can be opened from the control room after switching to manual control. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-5 FIRE ZONES 12-B, 13-B 9.5A-208 Revision 21 September 2013 A fire in this area may affect LCV-112C. Redundant valve 8805A will be available to provide water to the charging pump suction. The volume control tank can be isolated by closing LCV-112B. 4.1.3 Component Cooling Water CCW pump and ALOP 1-2 may be lost due to a fire in this area. Redundant CCW pumps 1-1 and 1-3 and ALOPs 1-1 and 1-3 will be available to provide CCW. A fire in this area may affect FCV-431. Redundant valve FCV-430 will enable the use of the other CCW train. Valve FCV-365 may be affected by a fire in this area. Since this valve fails in the desired, open position and redundant valve FCV-364 will remain available, safe shutdown is not affected. 4.1.4 Containment Spray Containment spray pump 1-1 may spuriously operate due to a fire in this area. However, the pump discharge valve, 9001A will not operate. Therefore, the spurious containment spray pump operation has no impact on safe shutdown. 4.1.5 Diesel Fuel Oil System Diesel fuel oil pump 0-2 may be lost due to a fire in this area. Redundant diesel fuel oil pump 0-1 will remain available. A fire in this area may affect valves LCV-85, LCV-86 and LCV-87. Redundant valves LCV-88, LCV-89 and LCV-90 will provide day tank level control for all diesels. 4.1.6 Emergency Power A fire in this area may disable the diesel generator 1-1 automatic transfer circuit and backup control circuit. The normal control circuit and manual control will remain available in the control room to transfer and load the diesel generator. A fire in this area may disable diesel generator 1-2. Diesel generators 1-1 and 1-3 will remain available for safe shutdown. A fire in this area may disable the backup control circuit for diesel generator 1-3. The normal control circuit will remain available. A fire in this area may disable startup transformer 1-2. Onsite power from diesel generators 1-1 and 1-3 will remain available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-5 FIRE ZONES 12-B, 13-B 9.5A-209 Revision 21 September 2013 All power supplies on the "G" Bus may be lost due to a fire in this area. These power supplies are not necessary since redundant trains on the "F" and "H" buses will be available. 4.1.7 Main Steam System A fire in this area may result in the loss of the following components: LT-519, LT-549, PT-515, PT-525, PT-535 and PT-545. Safe shutdown is not affected since redundant trains of instrumentation exists for all four steam generators. PCV-21 may be affected by a fire in this area. Since this valve fails in the desired closed position, safe shutdown is not affected. Redundant dump valves PCV-19 and PCV-20 will be available for cooldown. A fire in this area may affect FCV-95. This valve is not necessary since two other AFW pumps will remain available. Valves FCV-41 and FCV-42 may be affected by a fire in this area. These valves can be manually closed to ensure safe shutdown. A fire in this area may result in a loss of power supplies associated with PY17N and PY16. Loss of power to PY17N and PY16 results in the spurious closure of FCV-128 when in the automatic mode. This valve can be opened from the control room after switching to manual control. 4.1.8 Reactor Coolant System A fire in this area may affect LT-460, NE-32, TE-433A, TE-433B, TE-443A and TE-443B. All of these components have redundant instrumentation for safe shutdown. A fire in this area may affect valves 8000B and PCV-455C. PCV-455C fails closed. Since PCV-455C fails closed, uncontrolled pressure reduction will not occur. A redundant PORV is available for pressure reduction. Control of reactor coolant pumps 1-1, 1-2, 1-3 and 1-4 may be lost due to a fire in this area. Safe shutdown is not affected if the ability to trip all four RCPs is lost. Pressurizer heater groups 1-3 and 1-4 may be affected by a fire in this area. Manual actions can be taken to de-energize heater group 1-4 and switch heater group 1-3 to the vital power supply. Therefore, safe shutdown will not be affected. A fire in this area may affect DC control cables that could result in loss of control of FCV-641A. Since the redundant train is available (RHR Pp 1-2 and FCV-641B), this will not affect safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-5 FIRE ZONES 12-B, 13-B 9.5A-210 Revision 21 September 2013 4.1.9 Residual Heat Removal System RHR pump 1-1 may be lost for a fire in this area. Redundant pump 1-2 will be available to provide the RHR function. Valve 8701 may be affected by a fire in this area. This valve is closed with power removed during normal operations and will not spuriously open. Also, this valve can be manually operated for RHR operations. 4.1.10 Safety Injection System A fire in this area may result in the loss of valves 8801B, 8803B and 8805B. Redundant valves 8801A, 8803A and 8805A will remain available for safe shutdown. Valves 8808B and 8808D may be affected by a fire in this area. These valves can be manually closed to ensure safe shutdown. 4.1.11 Auxiliary Saltwater System Circuitry for ASW pumps 1-1 and 1-2 may be damaged by a fire in this area. ASW pump 1-1 may be started locally to provide ASW flow. A fire in this area may affect valve FCV-603. Since this valve fails in the desired, open position, safe shutdown is not affected. 4.1.12 HVAC One train of required HVAC equipment, E-101 and S-68 may be lost due to a fire in this area. Neither of these components will be necessary because redundant HVAC equipment will be available to provide necessary HVAC support.
5.0 CONCLUSION
The following fire protection features will mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Smoke detection is provided for the fire area.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-5 FIRE ZONES 12-B, 13-B 9.5A-211 Revision 21 September 2013
- Portable fire extinguishers, CO2 hose stations and fire hose stations are available in the fire area.
- Redundant safe shutdown capability is provided outside of this fire area. In this fire area, existing fire protection features provide an acceptable level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 Drawing Nos. 515562, 515563, 515564, 515565 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065126, Fire Protection Information Report, Unit 1 6.5 SSER 8, November 1978 6.6 DCN DC1-EH-15047, Provide 3-hour rated dampers to Fire Area 12-B 6.7 NECS File: 131.95, FHARE: 14, Concrete equipment hatch 6.8 PLC report: Structural Steel Analysis for Diablo Canyon (Rev. 2) 7/8/86 6.9 NECS File: 131.95, FHARE: 31, Undampered Duct Penetrations From the Fan Room 6.10 DCN DC1-EA-15662 R4, provide 3-hour rated pyrocrete blockout 6.11 NECS File: 131.95 FHARE: 106, Block Walls Modified in the 4kV Switchgear Area 6.12 NECS File: 131.95, FHARE: 136, Unrated HVAC Duct Penetrations 6.13 Calculation 134-DC, Electrical Appendix R Analysis 6.14 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.15 NECS File: 131.95, FHARE 134, "Non-rated Structural Gap Seals in Fire Barriers" 6.16 NECS File: 131.95, FHARE 30, Unrated Gaps in Appendix R Barriers in the Turbine Building 6.17 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.18 Question 27, PG&E Letter to NRC, Dated 11/13/78 6.19 Question 29, PG&E Letter to NRC, Dated 11/13/78
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-6 FIRE ZONES 12-C, 13-C 9.5A-212 Revision 21 September 2013 FIRE AREA TB-6 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Area TB-6 is in the Northeast corner of the Unit 1 Turbine Building and consists of Fire Zone 12-C at El. 107 ft, and Fire Zone 13-C at El. 119 ft. 1.2 Description Fire Area TB-6 consists of the 4-kV H bus cable spreading room (El. 107 ft), Fire Zone 12-C, the 4-kV H Bus switchgear room (El. 119 ft), and Fire Zone 13-C, in the Turbine Building. At least two of the three vital divisions are required for safe shutdown. 1.3 Boundaries 1.3.1 Fire Zone 12-C (El. 107 ft) North:
- A 2-hour rated barrier to the exterior. (Ref. 6.14)
- A 3-hour rated fire damper to the exterior.
- Nonrated barrier to the exterior, Area 28, (corridor area). (Ref. 6.8)
South:
- A 2-hour rated barrier to Fire Zone 12-B (Area TB-5). (Ref. 6.6 and 6.14)
- Unrated structural gap seals to Fire Zone 12-B (TB-5). (Ref. 6.13)
- A 1-1/2-hour rated door to Fire Zone 12-B (TB-5). (Ref. 6.14)
- Two 3-hour rated doors to Fire Zone 12-B (TB-5). East:
- 2-hour rated barrier to the exterior (Area 28). (Ref. 6.14)
- 2-hour rated barrier to Fire Zone 12-B. (Ref. 6.14) West:
- 3-hour rated barrier to Fire Zone 11-C-2 (TB-3). (Ref. 6.8)
- 2-hour rated barrier to Fire Zone 12-B. (Ref. 6.14)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-6 FIRE ZONES 12-C, 13-C 9.5A-213 Revision 21 September 2013 Floor/Ceiling: Ceiling:
- 3-hour rated concrete slab.
- A ventilation duct with a 3-hour rated fire damper communicates with fire area 13-E (above). (Ref. 6.2)
- A ceiling vent opening without a fire damper communicates to Fire Zone 13-C. (Ref. 6.15)
Floor:
- 3-hour rated concrete slab on unprotected steel. (Ref. 6.7) 1.3.2 Fire Zone 13-C (El. 119 ft)
North:
- 2-hour rated barrier to the exterior (Area 28). (Ref. 6.15)
South:
- 2-hour rated barrier to Fire Zone 13-B (TB-5). (Ref. 6.15)
- Unrated structural gap seals to Fire Zone 13-B. (Ref. 6.13)
- 1-1/2-hour rated door to Fire Zone 13-B. (Ref. 6.15) East:
- 2-hour rated barrier to the exterior (Area 28). (Ref. 6.15) West
- 3-hour rated barrier to Fire Area 13-D.
- Unrated structural gap seals to Fire Area 13-D. (Ref. 6.13)
- 1-1/2-hour rated door to Fire Area 13-D. (Ref. 6.15)
- 1-1/2-hour rated damper to fire Area 13-D. (Ref. 6.6)
- 3-hour rated pyrocrete barrier around the door. (Ref. 6.9)
Ceiling: To Fire Zone 14-D
- 3-hour rated concrete slab.
- A ventilation exhaust opening to the main turbine deck (El. 140 ft) with a 3-hour rated fire damper.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-6 FIRE ZONES 12-C, 13-C 9.5A-214 Revision 21 September 2013 Floor: To Fire Zone 12-C
- 3-hour rated concrete slab.
- A vent opening to Fire Zone 12-C. (Ref. 6.15)
Protective
Enclosure:
- All corner gaps are sealed, except at the north end of the west wall of Fire Zone 12-C where it abuts Fire Zone 11-C-2 (TB-3). Structural steel has fire resistive coverings. (Refs. 6.8 and 6.7)
(Note: Some structural steel modifications for the block walls (at El. 119 ft) were deemed acceptable with no fireproofing. (Ref. 6.10))
2.0 COMBUSTIBLES
2.1 Fire Zone 12-C (107 ft) 2.1.1 Floor Area: 1,437 ft2 2.1.2 In situ Combustible Materials
- Cable insulation
- Rubber
- Plastic 2.1.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.1.4 Fire Severity
- Low DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-6 FIRE ZONES 12-C, 13-C 9.5A-215 Revision 21 September 2013 2.2 Fire Zone 13-C (119 ft) 2.2.1 Floor Area: 958 ft2 2.2.2 In Situ Combustible Materials
- Cable
- Rubber
- Plastic 2.2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection is provided in Fire Zone 12-C and 13-C.
3.2 Suppression (available for both zones)
- Portable fire extinguishers
- CO2 hose stations
- Fire hose stations DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-6 FIRE ZONES 12-C, 13-C 9.5A-216 Revision 21 September 2013 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Fire Zones 12-C and 13-C 4.1.1 Auxiliary Feedwater AFW pump 1-2 may be lost due to a fire in this area. Redundant AFW pumps 1-1 and 1-3 will be available to provide AFW.
A fire in this area may affect valves LCV-110 and LCV-111. Redundant valves LCV-106, LCV-107, LCV-108, and LCV-109 will remain available via AFW Pump 1-1, and LCV-113 and LV-115 will remain available via AFW Pump 1-3. 4.1.2 Chemical and Volume Control System A fire in this area may result in the loss of boric acid storage tank 1-1 level indication from LT-102. Since borated water from the RWST will remain available, BAST level indication is not required. Valve 8145 may be affected by a fire in this area. Since this valve fails in the desired closed position, and the PORVs will be available for pressure reduction, safe shutdown is not affected. 4.1.3 Component Cooling Water CCW pump and ALOP 1-3 may be lost for a fire in this area. Redundant pumps and ALOPs 1-1 and 1-2 will be available to provide CCW. A fire in this area may affect valve FCV-364. Since this valve fails in the desired, open position safe shutdown is not affected. 4.1.4 Containment Spray Containment spray pump 1-2 may spuriously operate due to a fire in this area. However, the corresponding discharge valve 9001B will not operate. Therefore, the spurious containment spray pump operation has no impact on safe shutdown. 4.1.5 Diesel Fuel Oil System Diesel fuel oil pump 0-1 may be lost due to a fire in this area. The redundant diesel fuel oil pump 0-2 remains available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-6 FIRE ZONES 12-C, 13-C 9.5A-217 Revision 21 September 2013 Valves LCV-88, LCV-89 and LCV-90 may be affected by a fire in this area. Redundant valves LCV-85, LCV-86 and LCV-87 will be available for day tank level control. 4.1.6 Emergency Power A fire in this area may disable diesel generator 1-1. Diesel generators 1-2 and 1-3 will remain available for safe shutdown. A fire in this area may disable the diesel generator 1-3 backup control circuit. The normal control circuit will remain available. A fire in this area may disable startup transformer 1-2. Onsite power from diesel generators 1-2 and 1-3 will remain available for safe shutdown. All power supplies on the "H" Bus may be lost due to a fire in this area. These power supplies are not necessary since redundant trains on the "G" and "F" Buses will be available. A fire in this area may disable dc panel SD11 backup battery charger ED121. Normal battery charger ED11 will remain available. A fire in this area may disable dc panel SD12 backup battery charger ED121. Normal battery charger ED12 will remain available. A fire in this area may result in a loss of power supplies associated with PY17N. Redundant power supply PY16 remains available. 4.1.7 Main Steam System A fire in this area may result in the loss of the following instrumentation: LT-518, LT-528, LT-538, LT-548, PT-526 and PT-536. Since redundant instrumentation exists for all four steam generators, safe shutdown is not affected. PCV-20 may be affected by a fire in this area. This valve fails in the desired, closed position, safe shutdown will not be affected. A redundant dump valve will remain available. A fire in this area may affect valves FCV-43 and FCV-44. These valves can be manually operated to ensure safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-6 FIRE ZONES 12-C, 13-C 9.5A-218 Revision 21 September 2013 4.1.8 Reactor Coolant System A fire in this area may result in the loss of LT-461, NE-52 and PT-403. Safe shutdown will not be affected since redundant components will be available. A fire in this area may affect Pressurizer PORV and block valve PCV-456 and 8000C. Since redundant valves will remain available for pressure reduction safe shutdown will not be affected. Control of reactor coolant pumps 1-1, 1-2, 1-3 and 1-4 may be lost due to a fire in this area. Operation of the reactor coolant pumps will not affect safe shutdown. RCP seal cooling will remain available via the seal injection flowpath or the CCW thermal barrier heat exchanger. Pressurizer heater groups 1-1 and 1-2 may be affected by a fire in this area. Manual actions can be taken to de-energize heater group 1-1 and switching heater group 1-2 to the vital power supply. Therefore, safe shutdown is not affected. 4.1.9 Residual Heat Removal System RHR pump 1-2 and FCV-641B may be lost for a fire in this area The redundant train is available (RHR Pp 1-1 and FCV-641A), this will not affect safe shutdown. Valve 8702 may be affected by a fire in this area. This valve is closed and has its power removed during normal operations and will not spuriously open. Also, this valve can be manually operated for RHR operation. 4.1.10 Safety Injection System SI pump 1-2 may spuriously operate due to a fire in this area. Local manual action may be required to defeat this spurious operation. Accumulator isolation valve 8808C may be affected by a fire in this area. This valve can be manually closed. 4.1.11 Auxiliary Saltwater System A fire in this area may affect valves FCV-495 and FCV-496. FCV-601 will remain closed to provide ASW system integrity. 4.1.12 HVAC A fire in this area may result in the loss of one train of HVAC components (E-44, S-44, FCV-5046 and S-67). S-67 is not necessary for a fire in this area. The DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-6 FIRE ZONES 12-C, 13-C 9.5A-219 Revision 21 September 2013 HVAC function will be supplied by a redundant train of components (S-43, E-43 and FCV-5045).
5.0 CONCLUSION
The following fire protection features mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Smoke detection is provided for the fire area.
- Portable fire extinguishers, CO2 hose stations and fire hose stations are available in the fire area.
- Redundant safe shutdown capability is provided outside this fire area. In this fire area, existing fire protection features provide an acceptable level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 Drawing Nos. 515562, 515563, 515564, 515565 6.2 DCN DC1-EH-15047, Provide 3-hour rated dampers to Fire Area 12-C 6.3 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.4 Calculation M-824, Combustible Loading 6.5 Drawing 065126, Fire Protection Information Report, Unit 1 6.6 SSER 8, November 1978 6.7 PLC report: Structural Steel Analysis for Diablo Canyon (Rev. 2) 7/8/86 6.8 NECS File: 131.95, FHARE: 30, Unrated Gaps in Appendix R Barriers in the Turbine Building 6.9 DCN DC1-EA-15662 R4, provide 3-hour rated pyrocrete blockout 6.10 NECS File: 131.95, FHARE: 106, Block Walls Modified in the 4kV Switchgear Area 6.11 Calculation 134-DC, Electrical Appendix R Analysis 6.12 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.13 NECS File: 131.95, FHARE 134, "Non-rated Structural Gap Seals in Fire Barriers" 6.14 Question 27, PG&E Letter to NRC, Dated 11/13/78 6.15 Question 29, PG&E Letter to NRC, Dated 11/13/78 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 12-E 9.5A-220 Revision 21 September 2013 FIRE AREA TB-7 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Iso-Phase bus duct area, Unit 1 Turbine Building, El. 107 ft.
1.2 Description This fire zone is a part of Fire Area TB-7 and occupies the elevations from 107 ft through 140 ft. An enclosed stairwell on the south wall provides access to Area 10 below and a stair along north wall provides access to Area 13-A at El. 119 ft. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- 3-hour rated barrier separates this zone from Zones 12-A and 13-A, and Area 13-D, with the following exceptions: - A 1-1/2-hour rated door communicates to zone 12-A and 13-A. (Ref. 6.14)
- A 1-1/2-hour rated door communicates to Area 13-D. (Ref. 6.14) - Structural steel modifications for the block walls (at El. 119 ft) were deemed acceptable with no fireproofing. (Ref. 6.7) - Unrated structural gap seals to Fire Zone 12-A, Area 13-D. (Refs. 6.10 and 6.11) South:
- 3-hour rated barrier separates this zone from Zone 14-A. NC
- A 3-hour rated door communicates to Zone 14-A. NC
- A nonrated isophase bus penetration communicates to Zone 14-A. NC
- 2-hour rated barrier separates Zone 12-E from Area 10 except for: - A 1-1/2-hour rated door communicates to Area 10.
- Nonrated ceiling for stairwell communicating to Area 10. (Ref. 6.5) DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 12-E 9.5A-221 Revision 21 September 2013 East:
- 2-hour rated barrier separates this zone from Area 28, and Fire Area 10. NC
- A nonrated isophase bus penetration communicates to Area 28. NC West:
- 2-hour rated barrier to Fire Area 10.
- 3-hour rated barrier separates this zone from Area 13-E (El. 119 ft).
- Unrated structural gap seals to Fire Area 13-E. (Ref. 6.10)
- 2-hour rated barrier separates this zone from Zone 12-A (El. 104 ft).
- A 1-1/2-hour rated door communicates to Zone 12-A. (Ref. 6.14)
- A duct penetration without a fire damper penetrates to Area 13-E. (Ref. 6.13)
Floor/Ceiling:
- 3-hour rated floor separates this zone from Area 10.
- Lesser rated penetration seal to Fire Area 10. (Ref. 6.12)
- 3-hour rated ceiling separates this zone from Zone 14-D NC with the exception of an open stairwell.
2.0 COMBUSTIBLES
2.1 Floor Area: 1,920 ft2 2.2 In situ Combustible Materials
- Cable Insulation
- Rubber
- Plastic
- Wood 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 12-E 9.5A-222 Revision 21 September 2013
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection None
3.2 Suppression
- CO2 hose stations
- Portable fire extinguishers
- Fire hose stations 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Emergency Power A fire in this area may disable the diesel generators 1-1, 1-2 and 1-3 automatic transfer circuit or may spuriously close the auxiliary transformer 12 circuit breaker. After operator actions, the diesel can either be locally loaded or loaded from the control room. In addition, offsite power is not affected in this area and would be available for safe shutdown.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Manual fire fighting equipment is provided.
- Low fire severity.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 12-E 9.5A-223 Revision 21 September 2013
- Safe plant shutdown will not be adversely impacted due to the loss of the safe shutdown functions located in this zone.
The fire protection in this area provides an acceptable level of safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.2 Drawing Nos. 515563, 515564, 515565 6.3 Calculation M-824, Combustible loading 6.4 Drawing 065126, Fire Protection Information Report, Unit 1 6.5 NECS File: 131.95, FHARE: 4, Stairwell Nonrated Ceiling 6.6 Deleted in Revision 14. 6.7 NECS File: 131.95, FHARE: 106, Block Walls Modified in the 4kV Switchgear Area 6.8 Calculation 134-DC, Electrical Appendix R Analysis 6.9 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.10 NECS File: 131.95, FHARE 134, "Non-rated Structural Gap Seals in Fire Barriers" 6.11 NECS File: 131.95, FHARE 135, "Gaps in Appendix A Fire Rated Boundaries" 6.12 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.13 NECS File: 131.95, FHARE 56, Undampered Ventilation Duct Penetration 6.14 Question 27, PG&E Letter to NRC, Dated 11/13/78
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 14-A 9.5A-224 Revision 21 September 2013 FIRE AREA TB-7 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Main condenser, feedwater, and condensate equipment area, Unit 1 Turbine Building El. 85 ft through 119 ft. 1.2 Description This fire zone comprises the bulk of the Unit 1 Turbine Building at El. 85 ft, 104 ft, and 119 ft. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. 1.3.1 El. 85 ft North:
- 3-hour rated barriers separate this zone from Areas 10, 14-B, and 11-D and Zones 11-C-1, 11-C-2. (Ref. 6.19)
- A 3-hour rated door communicates to Area 10.
- A 3-hour rated double door communicates to Area 11-D.
- A non-rated sliding door communicates to Zone 11-C-2. (Ref. 6.5)
- A non-rated barrier to area 28. NC South:
- 3-hour rated barriers separate this zone from Areas 4A, 14-B, 14-E NC and Zone 16. NC
- Two duct penetrations with a 3-hour rated fire damper penetrates to Area 14-E. NC
- A 3-hour rated roll up door communicates to Zone 16. NC
- A 3-hour rated doors communicate to Area 14-B.
- The non-rated gap assemblies in fire barriers to Area 14-B were deemed acceptable. (Ref. 6.18)
- A 1-1/2-hour rated door communicates to Fire Zone 19-A. NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 14-A 9.5A-225 Revision 21 September 2013 East:
- A 3-hour rated barrier with a 3-hour door to Fire Area 4-B.
- A 3-hour rated barrier separates this zone from Areas 3-BB and 14-E. NC
- A 3-hour rated double door communicates to Area 3-BB.
- Three 3-hour rated fire dampers communicate to Area 3-BB.
- A nonrated barrier separates this zone from Area 28 NC and TB-14. NC
- A nonrated door communicates to Area 28. NC
- A penetration to Area 3-BB. (Ref. 6.10)
- A 1-1/2-hour rated exterior roll up fire door communicates to Fire Zone S-1.
- Lesser rated penetration seals to Area 3-BB. (Ref. 6.20)
- A 3-hour rated barrier with a 1-1/2-hour door to Fire Zone S-1.
West:
- A 3-hour rated barrier with 2 duct penetrations with 3-hour rated dampers to Fire Area 14-B.
- A nonrated barrier separates this zone from the buttress area TB-15. NC
- A nonrated roll-up door communicates to the buttress area TB-15. NC
- A nonrated door communicates to the exterior. NC
- A 3-hour rated door communicates to Fire Zone 16. NC
- A 3-hour rated barrier to Fire Zone 14-E. NC Floor: Reinforced concrete on grade. NC 1.3.2 El. 104 ft North:
- 3-hour rated barriers separate this zone from Area 13-E and Zones 11-C-2, 12-A and 12-E. NC
- A 3-hour rated door communicates to Zone 12-E.
- A 3-hour rated barrier and door communicates to Area 13-E. (Ref. 6.19)
- A 3-hour rated door communicates to zone 11-C-2
- A non-rated barrier and door to the exterior. NC South:
- 3-hour rated barriers separate this zone from Areas 5-A-4 and 15 and Zone 16. NC
- A 3-hour rated door communicate to Area 15.
- Two 3-hour rated roll-up doors communicate to Zone 16. NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 14-A 9.5A-226 Revision 21 September 2013 East:
- A 3-hour rated barrier containing a duct opening with a 3-hour damper to Fire Area 15.
- A nonrated barrier separates this zone from Area 28. NC
- A 3-hour rated barrier separates this zone from Area 3-BB, and Zones 6-A-5 and S-1.
- A nonrated fire barrier separates this zone from Fire Area TB-14. NC
- A 3-hour rated door communicates to Area 3-BB.
- A 3-hour rated double door communicates to Area 15.
West:
- A 3-hour rated barrier with duct opening with a 3-hour rated damper to Fire Area 15.
- A nonrated barrier separates this zone from the exterior (Area 28). NC
- A 3-hour rated barrier with a 3-hour rated door to Fire Zone 16. NC Floor:
- A nonrated steel hatch communicates to Fire Area 14-E (CCW Heat Exchanger Room). (Ref. 6.14) 1.3.3 El. 119 ft North:
- 3-hour rated barriers separates this zone from Areas 13-E, 13-F NC and Zone 12-E. NC
- A 3-hour rated double door communicates to Zone 13-E.
- A nonrated Isophase bus penetration seal communicates to Zone 12-E. NC
- A non-rated barrier to the exterior. NC South:
- 3-hour rated barriers separate this zone from Area 15 and Zones 14-C, NC 16, NC, and 6-A-5. NC.
- The non-rated gap assemblies in the fire barriers to Area 15 and Zone 14-C NC were deemed acceptable. (Ref. 6.18)
- A 3-hour rated double door communicates to Zone 16. NC
- Two 3-hour rated roll-up doors communicate to Zone 16. NC
- Two duct penetrations with 3-hour rated fire dampers penetrate to Area 15 and Zone 14-C.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 14-A 9.5A-227 Revision 21 September 2013
- Non-rated pipe penetration to Area 15. (Ref. 6.15)
- A 3-hour-equivalent rated door communicate to Zone 14-C. NC East:
- A nonrated barrier separates this zone from Area 28. NC
- A 3-hour rated barriers separates this zone from Area 3-BB, and Zones S-1, 6-A-5, and 14-C. NC
- A 3-hour-equivalent rated door and 2 sets of blowout panels, both of which are protected with directional water spray supply system, (Refs. 6.2 and 6.22, SSER 23, under "Fire Doors") communicates to Area 3-BB.
- Two nonrated duct penetrations penetrate to Zone 6-A-5. (Ref. 6.5)
- Two main steam line penetrations, provided with directional water spray system, communicate to Fire Area 3-BB. (Ref. 6.8)
- 3-hour rated doors communicate to Zones 14-C NC and S-1.
- Duct penetration with a 3-hour rated damper penetrates to 14-C. NC West:
- A nonrated barrier separates this zone from the exterior (Area 28). NC
- 3-hour rated barrier to Fire Area 15.
Ceiling: 3-hour rated barrier with open stairwells to Fire Zone 14-D. NC 2.0 COMBUSTIBLES
2.1 Floor Area: 29,493 ft2 (El. 85 ft), 30,698 ft2 (El. 104 ft), 31,216 ft2 (El. 119 ft) 2.2 In situ Combustible Materials El.: 85 ft 104 ft 119 ft
- Cable
- Cable
- Cable
- Acetylene
- Alcohol
- Rubber
- Resin
- Rubber
- Lube Oil
- Rubber
- Lube Oil
- Clothing/Rags
- Gasoline
- Clothing/Rags
- Paper
- Lube Oil
- Paper
- Plastic
- Clothing/Rags
- Plastic
- PVC
- Paper
- PVC
- Plastic
- PVC
- Wood DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 14-A 9.5A-228 Revision 21 September 2013 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low (El. 85 ft)
- Low (El. 104 ft)
- Low (El. 119 ft) 3.0 FIRE PROTECTION
3.1 Detection
- None 3.2 Suppression
- Automatic wet pipe sprinklers with remote annunciation area wide.
- Deluge spray systems for hydrogen seal oil unit, and feedwater pump turbines.
- Portable fire extinguishers.
- Hose stations.
- Directional water spray at nonrated door and blowout panels at El. 119 ft. (Ref. 6.2) 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Auxiliary Feedwater A fire in this area may affect control of LCV-113 and LCV-115 from the control room and hot shutdown panel. Redundant valves LCV-106, LCV-107, LCV-108, LCV-109, LCV-110 and LCV-111 are not affected and will remain available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 14-A 9.5A-229 Revision 21 September 2013 4.2 Component Cooling Water System A fire in this area may affect circuits associated with CCW flow transmitters for Header A (FT-68), Header B (FT-65), and Header C (FT-69). Loss of these instruments will not affect safe shutdown. 4.3 Emergency Power The CO2 Manual Actuation switches for the Unit 1 diesel generator rooms may be affected by a fire in this area. Although the switches are enclosed by a fire barrier, offsite power will be available for safe shutdown in the event of an inadvertent operation of the CO2 system. (Refs. 6.12, 6.13 and 6.17). A fire in this area may result in a loss of power supplies associated with PY17N. Redundant power supply PY16 remains available. 4.4 Reactor Coolant System The control of reactor coolant pumps 1-1, 1-2, 1-3 and 1-4 may be lost due to a fire in this area. Operation of the reactor coolant pumps will not affect safe shutdown. 4.5 HVAC Exhaust fan E-43 and supply fan S-43 may be lost due to a fire in this area. Safe shutdown is not affected because fans E-44 and S-44 will remain available to provide necessary HVAC support.
5.0 CONCLUSION
The following features mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Area wide automatic wet pipe sprinkler coverage.
- Manual fire fighting equipment is available.
- Train 1-1 AFW pump remains available for use if train 1-2 and 1-3 are lost.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 14-A 9.5A-230 Revision 21 September 2013
- Isolators have been provided to preclude the effects of hot shorts in the RPM indication circuits.
- Substantial fire zone boundaries will confine the postulated fire to this zone.
- The nonrated door, blowout panels and main steam line penetrations communicating to 3-BB are provided with a directional water spray.
The existing fire protection for this area provides an acceptable level of safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G. DCPP Unit 1 "Report on 10 CFR 50, Appendix R Review" included a deviation to the requirements of 10 CFR 50, Appendix R, Section III.G.2(b), due to redundant low signal RPM indication circuits. Isolators were provided to preclude premature trips of DGs due to short circuits. (Ref. 6.1)
6.0 REFERENCES
6.1 DCN DC1-EE-9913, Provide Isolator 6.2 DCN DC1-OM-21829, Provide sprinklers over blowout panel 6.3 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.4 Drawing Nos. 515562, 515563, 515564 6.5 SSER 23, June 1984 6.6 Calculation M-824, Combustible Loading 6.7 Drawing 065126, Fire Protection Information Report, Unit 1 6.8 FHARE: 5, Main steam penetrations 6.9 Deleted in Revision 13 6.10 FHARE: 12, Winch Cable Penetrations For Post-LOCA Sampling Room Shield Wall 6.11 Deleted in Revision 13 6.12 NCR DC0-91-EN-N027 6.13 DCN DC1-EA-47386 6.14 Deleted in Revision 13 6.15 NECS File: 131.95, FHARE 131, Non-rated Pipe Penetrations in the Clean and Dirty Lube Oil Room and Unit 1 and Unit 2 Turbine Lube Oil Reservoir Rooms 6.16 Calculation 134-DC, Electrical Appendix R Analysis 6.17 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.18 NECS File: 131.95, FHARE 135, "Gaps in Appendix A Fire Rated Boundaries" 6.19 NECS File: 131.95, FHARE 30, Unrated Gaps in Appendix R Barriers in the Turbine Building 6.20 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 14-A 9.5A-231 Revision 21 September 2013 6.21 NECS File: 131.95, FHARE 120, CCW Heat Exchanger Rooms 6.22 NECS File: 131 .95, FHARE 159, Unrated Doors Protected by Local Automatic Sprinklers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 14-D 9.5A-232 Revision 21 September 2013 FIRE AREA TB-7 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Unit 1 Turbine Deck, El. 140 ft.
1.2 Description This fire zone comprises the Unit 1 Turbine Operating Deck at El. 140 ft.
1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- A nonrated barrier separates this zone from Area 28. NC South:
- There is no boundary separating Zone 14-D from Zone 19-D. East:
- A nonrated barrier separates this zone from Area 34 and the outside. NC
- A nonrated roll up door communicates to Area 34. NC
- A 3-hour rated barrier separates this zone from Area 8-G.
- A 3-hour rated barrier separates this zone from Area 8-E.
- A 3-hour-equivalent rated door communicates to Area 8-E.
- A 3 hour fire barrier separates this area from Area S-1.
- A 3-hour rated door communicates to Area S-1.
- A 3-hour rated barrier separates this zone from the Unit 2 office area. West:
- A nonrated barrier separates this zone from Area 28. NC Floor:
- 3-hour rated floor to Fire Zones 14-A, NC 13-F, NC 12-E, NC 14-C, NC 15, 16, NC 17, NC 13-A, 13-B, 13-C, 13-D, 13-E.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 14-D 9.5A-233 Revision 21 September 2013
- Ventilation exhaust openings from Zones 13-A, 13-B, and 13-C with 3-hour fire dampers.
- Open stairwells to Zones 12-E and 14-A.
- A 3-hour rated equipment hatch communicates to Zone 13-D. (Ref. 6.4)
- Two 3-hour rated diesel exhaust stacks come from Zone 13-E and one 3-hour rated diesel exhaust stack comes from Zone 13-F.
- A 3-hour rated equipment hatch communicates to Zone 15. (Ref. 6.4)
- A lesser rated penetration seal to Zone 13-E. (Ref. 6.9)
- An open equipment hatch communicates to the 85-ft elevation of Zone 16. NC
- Unsealed blockout openings communicate to Zone 15. (Ref. 6.8)
- A non-rated vent and exhaust opening to Fire Zone 14-A. NC Ceiling:
- A nonrated ceiling to the exterior .NC
- An open ventilation exhaust vent along the center ridge of the roof. NC 2.0 COMBUSTIBLES
2.1 Floor Area: 52,600 ft2 2.2 In situ Combustible Materials
- Bulk Cable
- Hydrogen
- Rubber
- Lube Oil
- Clothing Rags
- Paper
- Plastic
- Wood (Fir) 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 14-D 9.5A-234 Revision 21 September 2013
- Wood
- Plastic
- Paper Note: Temporary facilities, consisting of a Main Containment Access Facility Main (CAF) and CAF Annex, were added to the Unit 1 Turbine Deck at Elevation 140 ft to house personnel supporting the activities of the Unit 1 and Unit 2 Steam Generator Replacement Projects that were performed in 2008 and 2009. Following completion of the SGR Projects, the Main CAF was removed and the CAF Annex was left installed to support the Unit 2 and Unit 1 Reactor Vessel Closure Head (RVCH) Replacement Projects performed, respectively, in 2009 and 2010. These facilities will be used strictly for personnel occupancy purposes and will not be used for fabrication, welding, machining, or hot work. Placement of these temporary facilities has no adverse effect upon any assumptions for Fire Area TB-7, Fire Zone 14-D. While an increase in the combustion loading to this fire area will be experienced through placement of the temporary facilities, the facilities themselves are equipped with fire protection systems and equipment in order to meet the requirements of NFPA to ensure that Fire Area TB-7, Fire Zone 14-D continues to meet the level of safety required by 10 CFR 50, Appendix R, Section III.G. With the removal of the Main CAF, the Fire Hazards Analysis performed to support the placements and removals of temporary facilities on the Turbine Deck determined that the decrease in fire severity level from Moderate to Low was acceptable.
2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Heat Detection at Bearing No. 10.
3.2 Suppression
- Water Deluge Systems for all Turbine Bearings except No. 10.
- Localized CO2 System for Turbine Bearing No. 10.
- Hose Stations.
- Portable Fire Extinguishers.
- Wet Pipe Automatic Sprinkler System to various offices and occupied spaces in the Turbine Building 140 ft.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 14-D 9.5A-235 Revision 21 September 2013 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 HVAC Exhaust and Supply fans E-43 and S-43 may be lost due to a fire in this area. Redundant supply and exhaust fans S-44 and E-44 will remain available. Therefore, safe shutdown is not affected.
5.0 CONCLUSION
The following features mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- A trained fire brigade is on-site at all times and is responsible for fire suppression responsibilities.
- Local (partial) fire detection is provided.
- Local (partial) fire suppression is provided.
- Manual fire suppression equipment is available.
- Redundant components are available for safe shutdown.
The existing fire protection for this area meets the level of safety required by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 Drawing No. 515565 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation M-824, Combustible Loading 6.4 NECS File: 131.95, FHARE: 14, Concrete Equipment Hatches 6.5 Drawing 065126, Fire Protection Information Report, Unit 1 6.6 Calculation 134-DC, Electrical Appendix R Analysis 6.7 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.8 NECS File: 131.95, FHARE 3, Valve Operator Shafts Through Barrier 6.9 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 Fire Zone 14-E 9.5A-236 Revision 21 September 2013 FIRE AREA TB-7 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Zone 14-E is part of Fire Area TB-7, and is located in the southeast corner of the Unit 1 Turbine Building at El. 85 ft. 1.2 Description Fire Zone 14-E is the component cooling water heat exchanger room. This area is completely separated from the rest of the Turbine Building by 3-hour barriers constructed of reinforced concrete walls, concrete block walls, and fire rated covering (on the Turbine Building side only). The south end of this fire area extends above the 3-hour rated ceiling of the entry corridor and abuts the wall separating the machine shop from the machinery of the Turbine Building. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- 3-hour rated barrier to Fire Zone 14-A (TB-7). NC (Ref. 6.12) South:
- 3-hour rated door to Fire Zone 14-A (TB-7). NC
- 3-hour rated unidirectional fire barrier to Fire Zone 14-A (TB-7). NC and Fire Area 16 (above 95 ft). NC (Ref. 6.12) East:
- 3-hour rated barrier to Fire Zone 14-A (TB-7), NC Fire Area 4-A and 4-B. (Ref. 6.12)
- 3-hour rated fire damper to Fire Zone 14-A (TB-7). NC West:
- 3-hour rated undirectional fire barrier to Fire Zone 14-A (TB-7). NC (Ref. 6.12)
- 3-hour rated fire door to 14-A (TB-7). NC
- 3-hour rated fire damper to 14-A (TB-7). NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 Fire Zone 14-E 9.5A-237 Revision 21 September 2013 Floor/Ceiling:
- 3-hour rated reinforced concrete barrier with the following exceptions: - The upper portion of the south end of the fire area extends over an entry corridor to the plant. The corridor's ceiling is metal lath and plaster and is provided with automatic sprinklers. - A nonrated steel hatch that connects Fire Zone 14-E to the 104-ft elevation of Fire Zone 14-A. NC Protective
Enclosure:
- A reinforced concrete missile shield separates the redundant heat exchangers and extends approximately 2.5 ft beyond the ends and above the tops of the heat exchangers.
2.0 COMBUSTIBLES
2.1 Floor Area: 1,899 ft2 2.2 In situ Combustible Materials
- Cable insulation
- Miscellaneous
- Rubber
- Lube Oil
- Clothing/Rags
- Plastic
- PVC
- Wood 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 Fire Zone 14-E 9.5A-238 Revision 21 September 2013 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection is provided except under alcove area. (Ref. 6.9) 3.2 Suppression
- Automatic wet pipe sprinkler protection is provided with remote annunciation except for under the alcove area (north end of area). (Ref. 6.9)
- Portable fire extinguishers
- Fire hose stations 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Component Cooling Water In the event of a fire in this area CCW valves FCV-430 and FCV-431 fail as is. Since one of these valves is normally open and the other is normally closed safe shutdown is not compromised because only one CCW flow path is required. A fire in this area may affect circuits associated with CCW flow transmitters for Header A (FT-68), Header B (FT-65), and Header C (FT-69). Therefore, loss of these instruments will not affect safe shutdown. A fire in this area may affect circuits associated with the differential pressure transmitters for CCW Hx 1-1 (PT-5) and CCW Hx 1-2 (PT-6). CCW pumps are not affected in this fire area, and fire damage to the CCW valves FCV-430 and FCV-431 will result in at least one of the valves failing in the open position. Therefore, loss of these instruments will not affect safe shutdown. 4.2 Auxiliary Saltwater System ASW valves FCV-602 and FCV-603 may be affected by a fire in this area. Manual action may be required to position these valves. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 Fire Zone 14-E 9.5A-239 Revision 21 September 2013
5.0 CONCLUSION
This fire area does not meet the requirements of Appendix R, Section III.G.2(c) in that a 1 hour enclosure is not provided around one train of redundant safe shutdown equipment. A deviation was requested, and granted as stated in SSER 23.
The following features will adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Smoke detection is provided.
- Failure of ASW valve circuits would result in loss of ASW to CCW heat exchangers but manual action can be taken to restore it.
- Failure of CCW valve circuits will result in motor operated valves failing as is with one valve open and one valve closed, providing adequate CCW cooling for safe shutdown.
- Wet pipe automatic sprinkler system.
- Fire hose stations and portable fire extinguishers.
- A missile barrier separates the two CCW heat exchangers.
The fire protection in this area produces an acceptable level of fire safety equivalent to that provided by Section III.G.
6.0 REFERENCES
6.1 Drawing No. 515562 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065126, Fire Protection Information Report, Unit 1 6.5 SSER 23, June 1984 6.6 Not used DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 Fire Zone 14-E 9.5A-240 Revision 21 September 2013 6.7 Memorandum from G. A. Tidrick/C. E. Ward to P. R. Hypnar dated May 3, 1983, Re: CCW System, Files 140.061 and 131.91 6.8 DCN DC1-EE-9913, Provide RPM Tach Isolator 6.9 NECS File: 131.95, FHARE: 51, Lack of Suppression and Detection in Alcove Area. 6.10 Procedure: EP M-10, Emergency Procedure Fire Protection of Safe Shutdown Equipment. 6.11 Not used. 6.12 FHARE 120, CCW Heat Exchanger Room Boundary Walls 6.13 Calculation M-928, 10 CFR 50, Appendix R Safe Shutdown Analysis 6.14 Calculation 134-DC, Electrical Appendix R Analysis
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA V-1 FIRE ZONE 3-P-3 9.5A-241 Revision 21 September 2013 FIRE AREA V-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fuel Handling Building, El. 85 ft, 93 ft, l00 ft, and 115 ft; Auxiliary Building Main Exhaust Fan Room No. 2, El. 115 ft; Auxiliary Building Exhaust Filter Room, El. 100 ft; Auxiliary Building Normal Concrete Exhaust Duct, El. 93 ft, and Plenum, El. 85 ft. 1.2 Description This fire zone is located in the north end of the Unit 1 Fuel Handling Building at El. 100 ft and 115 ft and includes a concrete exhaust air duct at El. 93 ft running from the auxiliary building to this zone. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North: Three-hour rated barriers. NC South: Three-hour rated barriers NC with the following exceptions: El. 85 ft:
- A 1-hour rated barrier to Fire Zone 3-L. NC (Ref. 6.8)
- A 1-1/2 hour equivalent rated door communicating with Zone 3-L. NC
- Duct penetrations without fire dampers penetrate to Zones 3-A NC and 3-L NC (two ducts into 3-A and 3-L). El. 100 ft:
- 3 nonrated doors communicating with Zone 3-P-2. NC
- Duct penetrations without fire dampers penetrate to Zone 31. NC (Ref. 6.5) El. 115 ft:
- 5 nonrated doors communicating with Zone 3-P-9. NC
- A duct penetration without a fire damper penetrates to Zone 3-P-9. NC
- A vent penetration without a damper penetrates to Zone 3-P-9. NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA V-1 FIRE ZONE 3-P-3 9.5A-242 Revision 21 September 2013 East: 3-hour rated barriers NC with the following exception:
- El. 100 ft - A duct penetration without a fire damper penetrates to the outside. NC (Ref. 6.5)
- El. 115 ft - non-rated barrier to the outside. NC West: 3-hour rated barriers. NC Floor/Ceiling:
- El. 85 ft and 115 ft - Duct Penetrations without fire dampers. NC 2.0 COMBUSTIBLES 2.1 Floor Area: 1,150 ft2 2.2 In situ Combustible Materials
- Cable
- Oil
- Paper
- Plastic
- Rubber 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA V-1 FIRE ZONE 3-P-3 9.5A-243 Revision 21 September 2013 3.0 FIRE PROTECTION 3.1 Detection
- Smoke detection at 115-ft elevation. 3.2 Suppression
- Portable fire extinguishers
- Hose stations 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Fire Zone 3-P-3 4.1.1 Auxiliary Feedwater AFW pumps 1-2 and 1-3 may be lost due to a fire in this area. AFW pump 1-1 will be available to provide auxiliary feedwater.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- AFW Pump l-l and Associated components are independent of this fire zone and remain available for safe shutdown. (Ref. Section 4.0)
- Smoke detection provided in areas of combustible loading only (El. 115 ft).
- Manual fire fighting equipment is available.
- Boundaries are 3-hour rated with limited lesser rated boundaries. While these lesser rated boundaries constitute a deviation to Appendix R, 3 hour requirements, the unusual configuration of this zone and the isolated location of the circuits in this zone assure the capability to achieve safe shutdown.
This area complies with the requirements of 10CFR50, Appendix R, Section III.G. No exemptions have been requested. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA V-1 FIRE ZONE 3-P-3 9.5A-244 Revision 21 September 2013
6.0 REFERENCES
6.1 Drawing Nos. 515568, 515569, 515570 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065126, Fire Protection Information Report, Unit 1 6.5 NECS File: 131.95, FHARE 40, Undampered Ventilation Ducts 6.6 Calculation 134-DC, Electrical Appendix R Analysis 6.7 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.8 NECS File: 131.95, FHARE 38, Undampered Ventilation Duct and Unrated Door in 1-Hour Rated Barrier DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-A 9.5A-245 Revision 21 September 2013 FIRE AREA 4-A 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Area 4-A is located in the Northwest corner of the Unit 1 Auxiliary Building, El. 85 ft. 1.2 Description This is the chemical laboratory area. A 1-hour rated drop ceiling covers the entire area, except in the F, G, and H Bus compartments, separating all electrical conduits from the laboratory environment under the drop ceiling. Above the drop ceiling, safe shutdown circuits for buses F, G, and H are separated by a horizontal distance in excess of 20 ft or are separated by 2-hour rated walls, or 2-hour rated fire wrap. (Refs. 6.14, 6.15, and 6.16) 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- 3-hour rated barrier separates this area from Areas 3-B-1, 3-BB and Fire Zone 14-A.
- 2-hour rated barrier separates this area from Areas 4-A-1, 4-A-2. (Ref. 6.17)
- 1-1/2-hour rated doors communicate to Areas 4-A-1, 4-A-2 (One into each area). (Ref. 6.17)
- A duct penetration with no fire damper penetrates to Areas 4-A-2 and 4-A-1. (Ref. 6.17) South:
- Non rated barrier separates this area from Area 4-B. NC (Refs. 6.14, 15)
- Three 1-1/2-hour rated doors communicate to Area 4-B. NC (Ref. 6.17)
- Ten duct penetrations with l-l/2-hour rated fire dampers penetrate to Area 4-B NC. (Ref. 6.17)
- A duct penetration with no fire damper penetrate to Area 4-B. NC (Ref. 6.17)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-A 9.5A-246 Revision 21 September 2013 East:
- 2-hour rated barrier separates this area from Area 4-A-2 and Zone 3-L (Area AB-1). (Ref. 6.17)
- A duct penetration with no fire damper penetrates to Zone 3-L (Area AB-1). (Ref. 6.17)
- 2-hour rated barrier separates this area from Area 4-A-1. (Ref. 6.13) West:
- Duct penetration with a 1-1/2-hour rated damper communicates to Fire Area 4-B. NC (Ref. 6.17)
- 3-hour rated barrier separates this area from Fire Areas 14-A and 14-E
- Non rated barrier with a 1-1/2-hour rated door to Fire Area 4-B. NC (Refs. 6.14, 6.15)
Floor:
- 3-hour rated barrier to 3-J-1, 3-J-2, 3-J-3, 3-H-1, and 3C.
Ceiling:
- 3-hour rated barrier to 5-A-1, 5-A-2, 5-A-3 and 5-A-4.
- Ventilation duct penetrations with 1-1/2-hour rated fire dampers. (Ref. 6.17)
- A 1-hour rated drop ceiling covers the entire area. (Ref. 6.17)
- All access hatches, in the dropped ceiling, are 1-1/2-hour rated. (Ref. 6.17) Above Ceiling:
- In Bus-G compartment, a 2-hour rated barrier separates Bus G safe shutdown circuit K6944 from VCT outlet valve conduits K7223 and K7229.
(Refs. 6.14, 6.15, and 6.16).
- 2-hour fire wrap around Bus F safe shutdown circuit K6934 from barrier 194 to ceiling. (Refs. 6.14 and 6.15) 2.0 COMBUSTIBLES 2.1 Floor Area: 2,078 ft2 2.2 In situ Combustible Materials
- Oil
- Acetic Acid
- Methane
- Class A
- Acetylene
- Polyethylene
- Plastic
- Alcohol
- Paper DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-A 9.5A-247 Revision 21 September 2013
- Rubber
- Clothing/Rags
- PVC
- Foam Rubber
- Leather
- Resin
- Wood (fir) 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection is provided and is area wide below the false ceiling. It is not area wide above the false ceiling. (Ref. 6.9) 3.2 Suppression
- Automatic wet pipe sprinklers beneath drop ceiling except in "F" Bus compartment.
- Localized sprinkler protection is provided for HVAC ducts above the drop ceiling.
- Hose stations
- Portable fire extinguishers 4.0 SAFE SHUTDOWN FUNCTIONS
(Note: Bus "F", "G" or "H" may be lost due to a fire in this area. Only one of these redundant buses may be lost due to a fire in this area as documented in SSER 23. The approved deviation credits the passive protection provided by the conduits, insignificant combustible loading above the ceiling, automatic detection DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-A 9.5A-248 Revision 21 September 2013 above and below the 1-hr fire rated ceiling, the automatic suppression system below the ceiling and physical separation of redundant cables to provide assurance that at least one division (2 out of 3 buses) would remain free of fire damage. Therefore, the analysis for this area is presented first with the "F" bus lost, then the "G" bus lost, and then the "H" bus lost. (Ref. 6.10))
4.1 4-A ("F" Bus Lost) 4.1.1 Auxiliary Feedwater AFW pump 1-3 may be lost for a fire in this area. Redundant AFW pump 1-1 will remain available. Valves LCV-110, LCV-111, LCV-113 and LCV-115 may be affected by a fire in this area. Redundant valves LCV-108 and 109 will remain available to supply AFW flow to steam generators 1-3 and 1-4 via AFW Pump 1-1. 4.1.2 Chemical and Volume Control System A fire in this area may affect valve 8104. FCV-110A and manual valve 8471 will remain available to provide boric acid to the charging pumps. Valve 8107 may be lost due to a fire in this area. Redundant valves 8108, HCV-142, or 8145 and 8148 can be shut to isolate auxiliary spray. The charging injection and seal injection flowpaths will remain available. The PORVs can be used for pressure reduction. Since this valve has redundant components, safe shutdown is not affected. Charging pump 1-1 and ALOPs 1-1 and 1-2 may be lost due to a fire in this area. Redundant charging pump 1-2 can be locally started to provide charging flow. Charging pump 1-2 will remain available and may be started without its ALOP. Both boric acid transfer pumps 1-1 and 1-2 may be lost due to a fire in this area. Based on a deviation granted in SSER 23, one pump will remain operational because of sufficient separation between circuits. A fire in this area may spuriously operate valves LCV-112B and LCV-112C. The approved deviation in SSER 23 credits the passive protection provided by the conduits, insignificant combustible loading above the ceiling, automatic detection above and below the 1-hr fire rated ceiling, the automatic suppression system below the to provide assurance that cables would remain free of fire damage. Although it is therefore not anticipated that fire damage to these cables would occur, spurious closure of the VCT valve could cavitate a running charging pump. The running charging pumps can be tripped from the control room to prevent DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-A 9.5A-249 Revision 21 September 2013 cavitation, and charging pump 1-2 restarted after the RWST is aligned and the VCT supply valve is isolated. Level indication for boric acid storage tank 1-2 from LT-106 may be lost due to a fire in this area. Borated water from the RWST will remain available. Therefore, BAST level indication is not required. 4.1.3 Component Cooling Water CCW pump and ALOP 1-1 may be lost due to a fire in this area. Redundant CCW pumps and ALOPs 1-2 and 1-3 are available to provide CCW. A fire in this area may affect valves FCV-430 and FCV-431. Although it is not anticipated that a fire in this area would damage the cables, both of these valves can be manually operated to ensure safe shutdown. The approved deviation credits the passive protection provided by the conduits, insignificant combustible loading above the ceiling, automatic detection above and below the 1-hr fire rated ceiling, the automatic suppression system below the ceiling to provide assurance that the cables would remain free of fire damage. A fire in this area may spuriously close valve FCV-356. Safe shutdown will not be affected because seal injection will remain available, therefore RCP seal integrity will not be affected. 4.1.4 Diesel Fuel Oil System Diesel fuel oil pumps 0-1 and 0-2 may be lost due to a fire in this area. Based on a deviation granted in SSER 23, one pump will survive and be available for use. 4.1.5 Emergency Power A fire in this area may disable the backup control circuit for diesel generator 1-2. The normal control circuit will remain available. A fire in this area may disable generator 1-3. Diesel generators 1-1 and 1-2 will remain available for safe shutdown. A fire in this area may disable startup transformers 1-1, 1-2, 2-1 and 2-2. Onsite power from diesel generators 1-1 and 1-2 will remain available for Unit 1, and all diesel generators will remain available for Unit 2. All power supplies on the "F" Bus may be lost due to a fire in this area. These power supplies are not necessary since redundant trains on the "G" and "H" Buses will be available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-A 9.5A-250 Revision 21 September 2013 A fire in this area may disable dc panel SD13 backup battery charger ED131. Normal battery charger ED132 will remain available. 4.1.6 Main Steam System A fire in this area may result in the loss of the following components: LT-516, LT-526, LT-529, LT-536, LT-539, LT-546, PT-514, PT-524, PT-534 and PT-544. Safe shutdown is not affected because redundant trains of indication will remain available for all four steam generators. Valve PCV-19 may be affected by a fire in this area. Since this valve fails in the desired, closed position, safe shutdown is not affected. A redundant dump valve will remain available for cooldown. 4.1.7 Makeup System LT-40, level indication for the condensate storage tank may be lost. Feedwater will be available from the raw water storage reservoir via manual operation of FCV-436. Manual action can be performed to locally open normally closed manual valve FCV-436. 4.1.8 Reactor Coolant System A fire in this area may result in the loss of the following components: LT-406, LT-459, NE-31, NE-51, PT-403, PT-406, TE-413A, TE-413B, TE-423A and TE-423B. All of these instruments have redundant components available for safe shutdown. A fire in this area may affect valve 8000A. PCV-474 will remain closed to prevent uncontrolled pressure reduction through the PORV path. Control of RCPs 1-1, 1-2, 1-3 and 1-4 may be lost due to a fire in this area. Safe shutdown is not affected if the ability to trip all four RCPs is lost. 4.1.9 Residual Heat Removal System A fire in this area may affect AC power and control cables associated with RHR Pump 1-1 recirculation valve FCV-641A . Redundant pump RHR Pp 1-2 and associated recirc valve FCV-641B will remain available for safe shutdown. 4.1.10 Safety Injection System SI pump 1-1 may spuriously operate due to a fire in this area. Local manual action may be required to defeat this spurious operation. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-A 9.5A-251 Revision 21 September 2013 A fire in this area may affect valves 8801A, 8803A, 8805A and 8805B. Loss of valves 8801A and 8803A will not affect safe shutdown because redundant valves 8801B and 8803B can be opened to provide a charging injection flowpath. The PORVs can be used for pressure reduction. Although it is not anticipated that a fire would damage cables to valves 8805A and 8805B, they can be manually opened to provide RWST to the charging pumps. The approved deviation credits the passive protection provided by the conduits, insignificant combustible loading above the ceiling, automatic detection above and below the 1-hr fire rated ceiling, and the automatic suppression system below the ceiling to provide assurance that the cables would remain free of fire damage. A fire in this area may affect accumulator isolation valve 8808A. This valve can be manually closed to ensure safe shutdown. 4.1.11 Auxiliary Saltwater System ASW pump 1-1 may be lost due to a fire in this area. ASW pump 1-2 will remain available to provide the ASW function. A fire in this area may affect valves FCV-495 and FCV-496. FCV-601 will remain closed to provide ASW system integrity. A fire in this area may spuriously close FCV-602 and FCV-603. Although it is not expected that fire damage will occur to both valves, these valves can be manually opened to ensure safe shutdown. The approved deviation credits the passive protection provided by the conduits, insignificant combustible loading above the ceiling, automatic detection above and below the 1-hr fire rated ceiling, and the automatic suppression system below the ceiling to provide assurance that the cables would remain free of fire damage. 4.1.12 HVAC Circuits for HVAC equipment E-101, E-103, E-43, S-43, FCV-5045 and S-69 are present in this area. E-101 should survive a fire in this area due to existing fire protection features and circuit operation as documented in SSER 23. S-69 is not necessary due to a fire in this area. The redundant HVAC train (S-44, E-44, FCV-5046) will remain available for safe shutdown. The approved deviation credits the passive protection provided by the conduits, insignificant combustible loading above the ceiling, automatic detection above and below the 1-hr fire rated ceiling, and the automatic suppression system below the ceiling to provide assurance that the cables would remain free of fire damage. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-A 9.5A-252 Revision 21 September 2013 4.2 4-A (G Bus Lost) 4.2.1 Auxiliary Feedwater AFW pump 1-3 may be lost due to a fire in this area. Redundant AFW pump 1-2 will be available. A fire in this area may affect valves LCV-106, 107, 108 and 109 from AFW Pump 1-1 and LCV-110, 111, 113 and 115 from AFW Pumps 1-2 and 1-3. Steam generators 1-1 and 1-2 are credited for safe shutdown, if the "G" bus is lost. Although it is not expected that fire damage will occur to redundant cables, LCV-110 and LCV-111 can be manually operated to regulate AFW flow to the steam generators. The approved deviation credits the passive protection provided by the conduits, insignificant combustible loading above the ceiling, automatic detection above and below the 1-hr fire rated ceiling, and the automatic suppression system below the ceiling to provide assurance that the cables would remain free of fire damage. 4.2.2 Chemical and Volume Control System Valve 8108 may be lost due to a fire in this area. Redundant valve 8107 can be closed to isolate auxiliary spray. An alternate charging flowpath is available. The PORVs will remain available for pressure reduction. Since redundant components are available, safe shutdown will not be affected. A fire in this area may affect valves 8104 and FCV-110A. One of these valves must be open to provide boric acid to the charging pumps. FCV-110A fails open and 8471 can be manually operated. Therefore, safe shutdown is not affected. A fire in this area may affect valves 8146, 8147 and 8148. Since these valves fail in the desired position and redundant components are available, safe shutdown is not affected. A fire in this area may affect charging pumps 1-1, 1-2, 1-3 and ALOPs 1-1 and 1-2. Due to the fire barrier configuration specified in Ref. 6.14, a single fire will not affect both the Bus G and the VCT outlet valves LCV-112B, C. Therefore, at least one charging pump will remain available. If Charging Pump 1-1 is needed, it can be started locally at the switchgear. Boric acid transfer pumps 1-1 and 1-2 may be lost due to a fire in this area. Based on a deviation granted in SSER 23, pump 1-1 will remain operational. Valve HCV-142 may be lost due to a fire in this area. This valve is not necessary since redundant components will be available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-A 9.5A-253 Revision 21 September 2013 A fire in this area may affect valves LCV-112B, LCV-112C, SI-8805A, and SI-8805B. Although it is not expected that the cables would be damaged by a fire in this area, spurious closure of the VCT valve could cavitate a running charging pump. The running charging pump can be tripped from the control room to prevent cavitation, and charging pump 1-1 can be started locally after the RWST supply is aligned and the VCT supply isolated. If valves LCV-112B or LCV-112C spuriously close, then either valve SI-8805A or SI-8805B can be manually opened to provide water from the RWST to the charging pump suction. LCV-112B and LCV-112C can be manually closed to isolate the volume control tank. An approved deviation credits the passive protection provided by the conduits, insignificant combustible loading above the ceiling, automatic detection above and below the 1-hr fire rated ceiling, and the automatic suppression system below the ceiling to provide assurance that the cables would remain free of fire damage. 4.2.3 Component Cooling Water CCW pumps and ALOPs 1-1 and 1-2 may be lost due to a fire in this area. Redundant CCW pump and ALOP 1-3 will remain available. Valve FCV-431 may be affected by a fire in this area. Redundant valve FCV-430 will enable the use of CCW heat exchanger 1-1. A fire in this area may affect valve FCV-365. Since this valve fails in the desired, open position, safe shutdown is not affected. A fire in this area may spuriously close FCV-356. Because seal injection will remain available, RCP seal integrity will not be affected. Therefore, safe shutdown will not be affected. 4.2.4 Diesel Fuel Oil System Diesel fuel oil transfer pumps 0-1 and 0-2 may be lost due to a fire in this area. As documented in SSER 23, one pump should survive and remain available. Valves LCV-85, LCV-86 and LCV-87 may be lost due to a fire in this area. Day tank level control will be maintained by LCV-88, LCV-89 and LCV-90. 4.2.5 Emergency Power A fire in this area may disable the backup control circuit for diesel generator 1-1. The normal control circuit will remain available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-A 9.5A-254 Revision 21 September 2013 A fire in this area may affect the normal control circuit for diesel generator 1-2. Although the backup control circuit will be available, bus SPG may be lost, and diesel generators 1-1 and 1-3 will remain available for safe shutdown. A fire in this area may affect startup transformers 1-1, 1-2, 2-1 and 2-2. Onsite power will remain available from diesel generators 1-1 and 1-3 for Unit 1 and all three diesel generators for Unit 2. All power supplies on the "G" Bus may be lost due to a fire in this area. These power supplies are not necessary since redundant trains on the "F" and "H" buses will be available. 4.2.6 Main Steam System A fire in this area may result in the loss of the following components: LT-519, LT-549, PT-515, PT-525, PT-535 and PT-545. Since redundant trains of instrumentation are available for all four steam generators, safe shutdown will not be affected. A fire in this area may affect valve PCV-21. Since this valve fails in the desired, closed position, safe shutdown is not affected. Redundant dump valves will remain available for cooldown. Valve FCV-95 may be affected by a fire in this area. AFW 1-2 will remain available to provide AFW. A fire in this area may affect valves FCV-41 and FCV-42. These valves can be manually closed to isolate the main steam lines. 4.2.7 Reactor Coolant System A fire in this area may affect LT-460, NE-32, TE-433A, TE-433B, TE-443A and TE-443B. All of these instruments have redundant components available for safe shutdown. Valves 8000B and PCV-455C may be affected by a fire in this area. Uncontrolled pressure reduction will not occur since PCV-455C fails closed. A redundant PORV is available for pressure reduction. Control of RCPs 1-1, 1-2, 1-3 and 1-4 may be lost due to a fire in this area. Safe shutdown is not affected if the reactor coolant pumps continuously run. Seal injection will remain available to provide RCP seal cooling. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-A 9.5A-255 Revision 21 September 2013 A fire in this area may affect heater groups 1-3 and 1-4. Manual actions can be taken to de-energize heater group 1-4 and switching heater group 1-3 to the vital power supply. Therefore, safe shutdown is not affected. 4.2.8 Residual Heat Removal System A fire in this area may affect AC power and control cables associated with RHR Pump 1-1 and recirculation valve FCV-641A. Redundant pump RHR Pp 1-2 and associated recirc valve FCV-641B will remain available for safe shutdown. A fire in this area may affect valve 8701. This valve is closed with its power removed during normal operations and will not spuriously open. Also, valve 8701 can be manually operated for RHR operations. 4.2.9 Safety Injection System SI pump 1-1 may spuriously operate due to a fire in this area. Local manual action may be required to defeat this spurious operation. Valves 8801B, 8803A, 8803B, 8805A and 8805B may be affected by a fire in this area. Valves 8801A and 8803A are not necessary because another charging flowpath through seal injection exists. Also, the PORVs will be available for pressure reduction. Although it is not expected that fire damage would affect redundant valves 8805A and 8805B, the valves can be manually operated to provide water from the RWST to the charging pumps. The approved deviation credits the passive protection provided by the conduits, insignificant combustible loading above the ceiling, automatic detection above and below the 1-hr fire rated ceiling, and the automatic suppression system below the ceiling to provide assurance that the cables would remain free of fire damage. A fire in this area may affect valves 8808B and 8808D. These valves can be manually closed to their desired, safe shutdown position. 4.2.10 Auxiliary Saltwater System ASW pump 1-1 and 1-2 may be lost due to a fire in this area. ASW pump 1-1 can be locally started to ensure safe shutdown. A fire in this area may affect valves FCV-495 and FCV-496. FCV-601 will remain closed to provide ASW system integrity. Valves FCV-602 and FCV-603 may spuriously close due to a fire in this area. Although it is not expected that fire damage would affect redundant valves, these valves can be manually opened to ensure safe shutdown. The approved deviation credits the passive protection provided by the conduits, insignificant DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-A 9.5A-256 Revision 21 September 2013 combustible loading above the ceiling, automatic detection above and below the 1-hr fire rated ceiling, and the automatic suppression system below the ceiling to provide assurance that the cables would remain free of fire damage. 4.2.11 HVAC HVAC equipment E-101, E-103, S-68 and S-69 may be lost due to a fire in this area. Based on a deviation granted in SSER 23, E-103 will remain operational during a fire in this area. E-101, S-68 and S-69 are not necessary for safe shutdown. The approved deviation credits the passive protection provided by the conduits, insignificant combustible loading above the ceiling, automatic detection above and below the 1-hr fire rated ceiling, the automatic suppression system below the ceiling and physical separation of redundant cables to provide assurance that at least one train of ASW fans (E-103) would remain free of fire damage. 4.3 4-A ("H" Bus Lost) 4.3.1 Auxiliary Feedwater AFW pumps 1-2 and 1-3 may be lost due to a fire in this area. Redundant pump 1-1 will be available to provide AFW. A fire in this area may affect valves LCV-110, LCV-111, LCV-113 and LCV-115. Redundant valves LCV-106, LCV-107, LCV-108, and LCV-109 will remain available for safe shutdown. 4.3.2 Chemical and Volume Control System Charging pumps and ALOPs 1-1 and 1-2 may be lost due to a fire in this area. Charging pump 1-2 can be manually started to provide charging flow. A fire in this area might result in the spurious closure of charging pump discharge flow control valve FCV-128. This valve can be opened from the control room after switching to manual control. Boric acid transfer pumps 1-1 and 1-2 may be affected by a fire in this area. As documented in SSER 23, one pump will survive and remain available. Valve 8104 may be affected by a fire in this area. FCV-110A and manual valve 8471 will remain available to provide a path for boric acid to the charging pumps. A fire in this area may spuriously close LCV-112B and LCV-112C. Valves SI-8805A and SI-8805B may also be affected by a fire in this area. The approved deviation credits the passive protection provided by the conduits, insignificant DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-A 9.5A-257 Revision 21 September 2013 combustible loading above the ceiling, automatic detection above and below the 1-hr fire rated ceiling, and the automatic suppression system below the ceiling to provide assurance that these cables would remain free of fire damage. Although it is not anticipated that fire damage to the cables would occur in this area, spurious closure of the VCT valve could cavitate a running charging pump. The running charging pump can be tripped from the control room, and charging pump 1-2 can be restarted locally after the RWST supply is aligned and the VCT supply is isolated. Either valve SI-8805A or SI-8805B can be manually opened to provide water from the RWST to the charging pumps. Valves LCV-112B and LCV-112C can be manually closed to isolate the volume control tank. Level indication for boric acid storage tank 1-1 from LT-102 may be lost due to a fire in this area. Borated water from the RWST will remain available. Therefore, BAST level indication will not be required. A fire in this area may affect valve 8145. This valve fails closed to isolate auxiliary spray during hot standby. Since the PORVs will be available for pressure reduction, valve 8145 is not necessary. 4.3.3 Component Cooling Water CCW pumps 1-1 and 1-3 and ALOP 1-1 may be lost due to a fire in this area. Redundant CCW pump and ALOP 1-2 will remain available. A fire in this area may spuriously close FCV-356. Since seal injection will remain available, RCP seal integrity will not be affected and safe shutdown can be achieved. Valve FCV-364 may be affected by a fire in this area. This valve fails open upon loss of power which is the desired position for safe shutdown. A fire in this area may affect valves FCV-430 and FCV-431. Although it is not expected that redundant valves would be affected by a fire, these valves can be manually operated. The approved deviation credits the passive protection provided by the conduits, insignificant combustible loading above the ceiling, automatic detection above and below the 1-hr fire rated ceiling, and the automatic suppression system below the ceiling to provide assurance that the cables would remain free of fire damage. 4.3.4 Diesel Fuel Oil System Diesel fuel oil pumps 0-1 and 0-2 may be affected by a fire in this area. As documented in SSER 23 one pump will survive and remain available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-A 9.5A-258 Revision 21 September 2013 Valves LCV-88, LCV-89 and LCV-90 may be lost due to a fire in this area. Day tank level control will be maintained by redundant valves LCV-85, LCV-86 and LCV-87 will remain available. 4.3.5 Emergency Power A fire in this area may affect diesel generator 1-1 normal control circuit. Although the backup control circuit will be available, bus SPH may be lost, and DGs 1-2 and 1-3 will be available for safe shutdown. A fire in this area may disable the diesel 1-3 backup control circuit. The normal control circuit will remain available. A fire in this area may disable startup transformers 1-1, 1-2, 2-1 and 2-2. Onsite power from diesel generators 1-2 and 1-3 will remain available for Unit 1, and all three diesel generators will remain available for Unit 2. A fire in this area may result in a loss of power supplies associated with PY17N and PY16. Loss of power to PY17N and PY16 results in the spurious closure of FCV-128 when in the automatic mode. This valve can be opened from the control room after switching to manual control. All power supplies on the "H" bus may be lost due to a fire in this area. These power supplies are not necessary since redundant trains on the "G" and "F" Buses will be available. A fire in this area may disable dc panel SD11 and SD12 backup battery charger ED121. Normal battery chargers ED11 and ED12 will remain available. 4.3.6 Main Steam System A fire in this area may result in the loss of the following components: LT-518, LT-528, LT-538, LT-548, PT-526 and PT-536. Since redundant trains of instrumentation exist for all four steam generators, safe shutdown will not be affected. Valve PCV-20 may be affected by a fire in this area. Since this valve fails in the desired, closed position, safe shutdown is not affected. Redundant dump valves will remain available for cooldown. A fire in this area may affect valves FCV-43 and FCV-44. These valves can be manually closed to ensure safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-A 9.5A-259 Revision 21 September 2013 4.3.7 Reactor Coolant System LT-461, NE-52 and PT-403 may be lost due to a fire in this area. All of these instruments have redundant components available for safe shutdown. A fire in this area may affect pressurizer PORV PCV-456 and blocking valve 8000C. PCV-456 fails closed. Therefore, uncontrolled pressure reduction is prevented. Redundant PORV PCV-455C will remain available for pressure reduction. The ability to trip RCPs 1-1, 1-2, 1-3 and 1-4 may be lost due to a fire in this area. Safe shutdown is not affected if the RCPs continuously run. A fire in this area may affect pressurizer heater groups 1-1 and 1-2. Manual actions can be taken to de-energize heater group 1-1 and switch heater group 1-2 to the vital power supply. A fire in this area may also affect power to pressurizer heater group 1-3. Loss of power to heater group 1-3 will not affect safe shutdown. 4.3.8 Residual Heat Removal System RHR pump 1-2 and FCV-641A (Recirc valve for RHR Pump 1-1) may be lost due to a fire in this area. Redundant pump 1-1 will be available to provide the RHR function. and its recirc valve FCV-641A can be manually opened for safe shutdown. Valve 8702 may be affected by a fire in this area. This valve is closed with its power removed during normal operation and will not spuriously open. Also, valve 8702 can be manually operated for RHR operations. 4.3.9 Safety Injection System SI pump 1-1 may spuriously operate for a fire in this area. Local manual action may be required to defeat this spurious operation. A fire in this area may affect valves 8805A and 8805B. Although it is not expected that redundant valves would be affected by a fire, one of these valves can be manually opened for charging suction. The approved deviation credits the passive protection provided by the conduits, insignificant combustible loading above the ceiling, automatic detection above and below the 1-hr fire rated ceiling, and the automatic suppression system below the ceiling to provide assurance that the cables would remain free of fire damage. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-A 9.5A-260 Revision 21 September 2013 Valve 8803A may be lost due to a fire in this area. This valve is not necessary for safe shutdown since redundant charging paths and pressure reduction methods will remain available. A fire in this area may affect accumulator isolation valve 8808C. This valve can be manually closed to ensure safe shutdown. 4.3.10 Auxiliary Saltwater System ASW pump 1-1 may be lost due to a fire in this area. Redundant ASW pump 1-2 is available to provide the ASW function. Valves FCV-495 and FCV-496 may be affected by a fire in this area. FCV-601 will remain available to provide ASW system integrity. A fire in this area may spuriously close FCV-602 and FCV-603. Although it is not expected that fire damage would occur to redundant valves, these valves can be manually opened to defeat any spurious actions. The approved deviation credits the passive protection provided by the conduits, insignificant combustible loading above the ceiling, automatic detection above and below the 1-hr fire rated ceiling, and the automatic suppression system below the ceiling to provide assurance that the cables would remain free of fire damage. 4.3.11 HVAC HVAC equipment E-44, S-44, FCV-5046 and S-67 may be lost due to a fire in this area. S-67 is not necessary for a fire in this area. A redundant train of HVAC equipment (S-43, E-43 and FCV-5045) will remain available for safe shutdown. A fire in this area may affect E-101 and E-103. As stated in SSER 23, one of these ASW pump fans will remain operational. The approved deviation credits the passive protection provided by the conduits, insignificant combustible loading above the ceiling, automatic detection above and below the 1-hr fire rated ceiling, and the automatic suppression system below the ceiling to provide assurance that at least one train of ASW fans (E-101) would remain free of fire damage. Fan S-69 may be lost due to a fire in this area. Safe shutdown is not affected since this fan is not necessary for safe shutdown.
5.0 CONCLUSION
Several modifications have been incorporated to improve the fire protection provided in this area. (Refs. 6.6 and 6.7) The following features will adequately mitigate the consequences of a design basis fire and assure the capability to achieve safe shutdown: DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-A 9.5A-261 Revision 21 September 2013
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Smoke detection provided.
- Manual fire fighting equipment is available.
- Automatic sprinkler system. The existing fire protection features provide a level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 Drawing No. 515568 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 SSER 23, June 1984 6.4 Calculation M-824, Combustible Loading 6.5 Drawing 065126, Fire Protection Information Report, Unit 1 6.6 DCN DC1-EA-15251 - Upgrade Wall 6.7 DCN DC1-EE-13771 - Provide Smoke Detection 6.8 NECS File: 131.95, FHARE: 77, Fiberglass HVAC Ducts 6.9 NECS File: 131.95, FHARE: 78, Smoke Detection in the False Ceiling Area 6.10 Chron No. 200042, Memo to File, Dated 12/4/92 6.11 Calculation 134-DC, Electrical Appendix R Analysis 6.12 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.13 NECS File: 131.95, FHARE 118, Appendix R Fire Area Boundary Plaster Barriers 6.14 NECS File: 131.95, FHARE 117, Rev. 1, Safe Shutdown Analysis For Modifying Fire Area 4-A and 4-B Boundary Barriers 6.15 DCP M-049536, Combine Fire Areas 4-A and 4-B 6.16 AT-MM AR A0635366, Install Fire Separation Barriers for Conduits K6944, K7223, and K7229. 6.17 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-A-1, 4-A-2 9.5A-262 Revision 21 September 2013 FIRE AREAS 4-A-1, 4-A-2 1.0 PHYSICAL CHARACTERISTICS
1.1 Location These two areas are located at the north end of the Auxiliary Building next to the counting and chemical laboratory, El. 85 ft. 1.2 Description These areas are separate Fire Areas containing "G" and "H" bus circuitry. These areas are situated side by side with Fire Area 4-A-1 to the west and Fire Area 4-A-2 to the east. Due to similarities between these fire areas, they have been combined into one section. 1.3 Boundaries 1.3.1 Fire Area 4-A-1 North:
- 3-hour rated barrier separates this area from Area 3-BB.
- A duct penetration with no fire damper penetrates to Area 3-BB. (Ref. 6.5) South:
- 2-hour rated barrier separates this area from Area 4-A. (Ref. 6.5)
- A 1-1/2-hour rated door communicates to Area 4-A. (Ref. 6.5)
- A duct penetration with no fire damper penetrates to Fire Zone 4-A. (Ref. 6.5)
East:
- 3-hour rated barrier separates this area from Area 4-A-2. West:
- 2-hour rated barrier separates this area from Area 4-A. (Ref. 6.8)
- A 3-hour rated door communicates to Area 4-A. Floor:
- 3-hour rated barrier to Zones 3-J-2 and 3-J-3.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-A-1, 4-A-2 9.5A-263 Revision 21 September 2013 Ceiling:
- 3-hour rated barrier to Areas 5-A-1 and 5-A-2. 1.3.2 Fire Area 4-A-2 North:
- 3-hour rated barrier separates this area from Area 3-BB.
- A duct penetration with no fire damper penetrates to Area 3 BB. (Ref. 6.5)
- A lesser rated penetration seal to Area 3-BB. (Ref.6.9)
South:
- 2-hour rated barrier separates this area from Area 4-A. (Ref. 6.5)
- A 1-1/2-hour rated door communicates to Area 4-A. (Ref. 6.5)
- A duct penetration with no fire damper penetrates to Area 4-A. (Ref. 6.5) East:
- 3-hour rated barrier separates this area from Area 3-B-1. West:
- 3-hour rated barrier separates this area from Area 4-A-1.
- A 2-hour rated barrier separates this area from Area 4-A. (Ref. 6.5) Ceiling:
- 3-hour rated to areas 5-A-3 and 5-A-4.
Floor:
- 3-hour rated to area 3-J-3. 2.0 COMBUSTIBLES
2.1 Fire Area 4-A-1 2.1.1 Floor Area: 120 ft2 2.1.2 In situ Combustible Materials
- Cable DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-A-1, 4-A-2 9.5A-264 Revision 21 September 2013 2.1.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.1.4 Fire Severity
- Low 2.2 Fire Area 4-A-2 2.2.l Floor Area: 102 ft2 2.2.2 In situ Combustible Materials
- Cable 2.2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.2.4 Fire Severity
- Low DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-A-1, 4-A-2 9.5A-265 Revision 21 September 2013 3.0 FIRE PROTECTION (typical for each area) 3.1 Detection
- Smoke detection is provided. 3.2 Suppression
- Portable fire extinguishers in adjacent area/zones.
- Hose Stations in adjacent area/zones. 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Fire Area 4-A-1 4.1.1 Auxiliary Feedwater Valves LCV-106, 107, 108 and 109 may be affected by a fire in this area. Redundant valves LCV-110 and LCV-111 will remain available to provide AFW flow to steam generators 1-1 and 1-2. 4.1.2 Chemical and Volume Control System Charging pumps 1-2 and 1-3 and ALOP 1-2 may be lost due to a fire in this area. Redundant charging pump and ALOP 1-1 will be available to provide charging flow. Boric acid transfer pump 1-2 may be lost for a fire in this area. Redundant boric acid transfer pump 1-1 will be available for this function. Valve 8108 may be affected by a fire in this area. Redundant valve 8107 can be closed to isolate auxiliary spray. The charging injection flowpath will be available if the charging flowpath through the regenerative heat exchanger is disabled. The PORVs can be used for pressure reduction. Since valve 8108 has redundant components, safe shutdown will not be affected. A fire in this area may affect valves 8104 and FCV-110A. Since valve FCV-110A fails in the desired open position, safe shutdown is not affected. Manual valve 8471 must also be opened if FCV-110A is used for boric acid transfer. Valves 8146, 8147 and 8148 may be affected by a fire in this area. Valve 8148 fails closed and isolates auxiliary spray during hot standby. The PORVs will remain available for pressure reduction. Valves 8146 and 8147 fail in the desired open position which will allow charging through the regenerative heat exchanger. Also, the charging injection flowpath will be available. The PORVs can be used DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-A-1, 4-A-2 9.5A-266 Revision 21 September 2013 for pressure reduction during cold shutdown. Since redundant components are available, safe shutdown is not affected. A fire in this area may result in the loss of HCV-142. This valve is not necessary for a fire in this area. Therefore, safe shutdown is not affected. Valve LCV-112C may be affected by a fire in this area. If this occurs, valve 8805A can be opened to provide water from the RWST to the charging pump suction and valve LCV-112B can be closed to isolate the volume control tank. 4.1.3 Component Cooling Water A fire in this area may affect CCW pump and ALOP 1-2. CCW pumps and ALOPs 1-1 and 1-3 will remain available to provide component cooling water. A fire in this area may affect valve FCV-431. Component cooling water heat exchanger 1-1 will remain available. Valve FCV-365 may be affected by a fire in this area. Since this valve fails in the desired open and redundant valve will be available, safe shutdown is not affected. 4.1.4 Containment Spray Containment spray pump 1-1 may spuriously operate due to a fire in this area. However, the discharge valve 9001A will not operate. Therefore, the spurious containment spray pump operation has no impact on safe shutdown. 4.1.5 Diesel Fuel Oil System Diesel fuel oil pump 0-2 may be lost due to a fire in this area. The redundant diesel fuel oil pump 0-1 remains available. A fire in this area may affect valves LCV-85, LCV-86 and LCV-87. Redundant valves LCV-88, LCV-89 and LCV-90 will remain available. 4.1.6 Emergency Power A fire in this area may disable the diesel generator 1-1 backup control circuit. The normal control circuit will remain available. A fire in this area may disable diesel generator 1-2. Diesel generators 1-1 and 1-3 will remain available for safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-A-1, 4-A-2 9.5A-267 Revision 21 September 2013 A fire in this area may disable startup transformer 1-2. Onsite power from diesel generators 1-1 and 1-3 will remain available for safe shutdown. All power supplies on the G Bus may be lost due to a fire in this area. These power supplies are not necessary since redundant trains on the F and H Buses will be available. A fire in this area may result in a loss of power supplies associated with PY17N. Redundant power supply PY16 remains available. 4.1.7 Main Steam System A fire in this area may result in the loss of the following components: LT-519, LT-549, PT-515, PT-525, PT-535 and PT-545. Safe shutdown is not affected because redundant trains of components exist for all four steam generators. Valve PCV-21 may be affected by a fire in this area. Since this valve fails in the desired closed position and a redundant dump valves PCV-19 and PCV-20 will remain available, safe shutdown will not be affected. A fire in this area may prevent FCV-95 from delivering steam to AFW pump 1-1. Since AFW pump 1-2 will remain available to provide AFW flow to steam generators 1-1 and 1-2, safe shutdown will not be affected. Valves FCV-41 and FCV-42 may be affected by a fire in this area. Manual actions can be taken to make these valves operational. 4.1.8 Reactor Coolant System A fire in this area may result in the loss of the following components: LT-460, NE-32, TE-433A, TE-433B, TE-443A and TE-443B. Safe shutdown is not affected since redundant instrumentation exists. Valves PCV-455C and 8000B may be affected by a fire in this area. Since PCV-455C fails in the desired, closed position and a redundant PORV will remain available, safe shutdown will not be affected. Control of the reactor coolant pumps may be lost due to a fire in this area. Safe shutdown is not affected if the RCPs continuously run. CCW to the RCP thermal barrier heat exchanger will remain available to provide RCP seal cooling. Heater groups 1-3 and 1-4 may be affected by a fire in this area. Manual actions can be taken to de-energize heater group 1-4 and switch heater group 1-3 to the vital power supply. Therefore, safe shutdown is not affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-A-1, 4-A-2 9.5A-268 Revision 21 September 2013 4.1.9 Residual Heat Removal System RHR pump 1-1 and Recirc Valve FCV-641A may be lost due to a fire in this area. Redundant RHR pump 1-2 and recirc valve FCV-641B will be available to provide the RHR function. Valve 8701 may be affected by a fire in this area. This valve is closed with power removed during normal operations and will not spuriously open. Also, this valve can be manually operated for RHR operations. 4.1.10 Safety Injection System A fire in this area may result in the loss of the following valves: 8801B, 8803B, 8805B. The following redundant valves: 8801A, 8803A and 8805A will remain available to ensure safe shutdown. Valves 8808B and 8808D may be affected by a fire in this area. These valves can be manually closed. 4.1.11 Auxiliary Saltwater System ASW pump 1-2 may be lost due to a fire in this area. Redundant ASW pump 1-1 will be available to provide the ASW function. A fire in this area may cause FCV-603 to be lost. Since a redundant ASW train will be available safe shutdown will not be affected. 4.1.12 HVAC A fire in this area may result in the loss of fans E-101 and S-68. Since these fans are not required for a fire in this area, safe shutdown is not affected. 4.2 Fire Area 4-A-2 4.2.1 Auxiliary Feedwater AFW pump 1-2 may be lost due to a fire in this area. Redundant pumps 1-1 and 1-3 will be available to provide AFW. A fire in this area may affect valves LCV-110 and LCV-111. Redundant valves LCV-106, LCV-107, LCV-108, LCV-109, LCV-113, and LCV-115 will remain available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-A-1, 4-A-2 9.5A-269 Revision 21 September 2013 4.2.2 Chemical and Volume Control System Valve 8145 may be lost due to a fire in this area. The PORVs will remain available for pressure reduction. Since redundant components exist, valve 8145 will not be necessary. A fire in this area may result in the loss of boric acid storage tank 1-1 level indication from LT-102. Borated water from the RWST will be available. Therefore, BAST level indication is not required. 4.2.3 Component Cooling Water CCW pump and ALOP 1-3 may be lost for a fire in this area. Redundant CCW pumps and ALOPs 1-1 and 1-2 will be available to provide CCW. Valve FCV-364 may be affected by a fire in this area. Since this valve fails in the desired, open position, safe shutdown is not affected. 4.2.4 Containment Spray Containment spray pump 1-2 may spuriously operate due to a fire in this area. However, the corresponding discharge valve, 9001B will not operate. Therefore, the spurious containment spray pump operation has no impact on safe shutdown. 4.2.5 Diesel Fuel Oil System One diesel fuel oil pump 0-1 may be lost due to a fire in this area. Redundant diesel fuel oil pump 0-2 remains available. A fire in this area may result in the loss of the following valves: LCV-88, LCV-89 and LCV-90. These valves can be lost since redundant valves: LCV-85, LCV-86 and LCV-87 will be available. 4.2.6 Emergency Power A fire in this area may disable diesel generator 1-1. Diesel generators 1-2 and 1-3 will remain available for safe shutdown. A fire in this area may disable diesel generator 1-3 backup control circuit. The normal control circuit will remain available. A fire in this area may disable startup transformer 1-2. Onsite power from diesel generators 1-2 and 1-3 will remain available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-A-1, 4-A-2 9.5A-270 Revision 21 September 2013 All power supplies on the H Bus may be lost due to a fire in this area. These power supplies are not necessary since redundant trains on the G and F Buses will be available. A fire in this area may disable dc panel SD11 backup battery charger ED121. Normal battery charger ED11 will remain available. A fire in this area may disable dc panel SD12 backup battery charger ED121. Normal battery charger ED12 will remain available. 4.2.7 Main Steam System A fire in this area may result in the loss of the following components: LT-518, LT-528, LT-538, LT-548, PT-526, and PT-536. Redundant components exist for all four steam generators, therefore, safe shutdown is not affected. Valve PCV-20 may be affected by a fire in this area. Since this valve fails in its desired closed position and a redundant dump valve will remain available, safe shutdown is not affected. A fire in this area may affect valves FCV-43 and FCV-44. These valves can be manually closed to ensure safe shutdown. 4.2.8 Reactor Coolant System A fire in this area may result in the loss of the following instrumentation: LT-461, NE-52 and PT-403. Since all of these instruments have redundant components, safe shutdown is not affected. Valves PCV-456 and 8000C may be affected by a fire in this area. Since PCV-456 fails in the desired, closed position and a redundant PORV will remain available for pressure reduction, safe shutdown is not affected. Control of all four reactor coolant pumps may be lost due to a fire in this area. Safe shutdown is not affected if the RCPs continuously run as PCV-455A and PCV-455B can be verified shut. A fire in this area may affect pressurizer heater groups 1-1 and 1-2. Manual actions can be taken to de-energize heater group 1-1 and switch heater group 1-2 to the vital power supply. Therefore, safe shutdown is not affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-A-1, 4-A-2 9.5A-271 Revision 21 September 2013 4.2.9 Residual Heat Removal System RHR pump 1-2 and recirc valve FCV-641B may be lost for a fire in this area. Redundant RHR pump 1-1 and recirc valve FCV-641A will be available to provide the RHR function. Valve 8702 may be affected by a fire in this area. This valve is closed with its power removed during normal operations and will not spuriously open. Also, this valve can be manually operated for RHR operations. 4.2.10 Safety Injection System SI pump 1-2 may spuriously operate due to a fire in this area. Local manual action may be required to defeat this spurious operation. Valve 8808C may be affected by a fire in this area. This valve can be manually closed. 4.2.11 Auxiliary Saltwater System A fire in this area may affect valves FCV-495 and FCV-496. FCV-601 will remain closed to provide ASW system integrity. 4.2.12 HVAC A fire in this area may result in the loss of one train of required HVAC equipment (FCV-5046, E-44, S-44 and S-67). Fan S-67 is not required and a redundant train of HVAC equipment (FCV-5045, E-43 and S-43) will be available to provide necessary HVAC support.
5.0 CONCLUSION
The following features adequately mitigate consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Safe shutdown will not be adversely affected by the loss of the equipment in each area due to the availability of redundant systems.
- Smoke detection is provided.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-A-1, 4-A-2 9.5A-272 Revision 21 September 2013
- Manual fire fighting equipment is available.
- Limited combustible loading.
The existing fire protection features provide a level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.2 Drawing No. 515568 6.3 Drawing 065126, Fire Protection Information Report, Unit 1 6.4 Calculation M-824, Combustible Loading 6.5 SSER 23, June 1984 6.6 Calculation 134-DC, Electrical Appendix R Analysis 6.7 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.8 NECS File: 131.95, FHARE 118, Appendix R Fire Area Boundary Plaster Barriers 6.9 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-B 9.5A-273 Revision 21 September 2013 FIRE AREA 4-B 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Area 4-B is located in the southwest corner of the Unit 2 Auxiliary Building at El. 85 ft. 1.2 Description This fire area contains showers, lockers, restrooms, storage areas and the radiological access control area for Units 1 and 2. A nonrated suspended ceiling is provided throughout the zone. "No Storage Area" signs are posted under the equipment hatches. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- 3-hour rated barrier to Fire Areas S-1 and S-5.
- Non rated barrier to Fire Area 4-A. NC (Refs. 6.19 and 6.20)
- A duct penetration without a fire damper to Fire Zone 4-A. NC (Ref. 6.21)
- Three 1-1/2-hour rated fire doors to Fire Area 4-A. NC (Ref. 6.21)
- Nine duct penetrations with 1-1/2-hour rated fire dampers communicate to Fire Area 4-A. NC (Ref. 6.21) South:
- 3-hour rated barrier to Fire Areas 3-D-1, 3-CC and Fire Zones 19-A, S-1, and S-5.
- 2-hour rated barrier to Fire Areas 4-B-1 and 4-B-2. (Ref. 6.21)
- Pyrocrete enclosure surrounds junction box BPG5 on the 4-B side of the barrier between 4-B and 4-B-2. (Ref. 6.15)
- Lesser rated penetration seals to Fire Area 4-B-2. (Ref. 6.18) East:
- 3-hour rated barrier to Fire Zones 3-L, S-2 and S-5.
- A 1-1/2-hour rated door to Fire Zone S-5. (Ref. 6.21)
- A 1-1/2-hour rated double door to Fire Zone S-2. (Ref. 6.21)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-B 9.5A-274 Revision 21 September 2013
- A duct penetration without a fire damper to Fire Zone 3-L. (Ref. 6.21)
- 3-hour rated barrier to Fire Areas 3-D-1 and 4-B-1.
- 3-hour rated door to Fire Area 4-B-1.
- Non rated barrier to 4-A. NC (Refs. 6.18 and 6.19) West:
- 3-hour rated barrier to Fire Zone S-1.
- 3-hour rated barrier to Fire Areas 19-A and 14-A.
- Unrated small diameter penetration to Fire Area 19-A. (Ref. 6.14)
- A 3-hour rated door to Fire Area 19-A.
- A 3-hour rated roll-up door to Fire Area 19-A.
- A 1-1/2-hour rated door to Fire Zone S-1. (Ref. 6.21)
- Four duct penetrations with 3-hour rated fire dampers communicate with Fire Zone S-1. (Ref. 6.9)
- 2-hour rated barrier to Fire Area 4-B-2. (Ref. 6.21)
- 1-1/2-hour rated access hatch to Fire Area 4-B-2. (Ref. 6.21)
- Unrated HVAC duct penetration without a fire damper to Fire Area TB-7. (Ref. 6.11) Floor:
- 3-hour rated barriers to Fire Zones 3-J-1, 3-K-1, 3-K-2, 3-K-3, 3C, and Fire Area 3-1-1.
Ceiling:
- 2 steel equipment hatches to Fire Area 5-A-4 and 5-B-4 above. (Ref. 6.21)
- 3-hour rated barriers to Fire Areas 5-A-4, 5-B-4, 5-B-3, 5-B-2, and 5-B-1. Above Ceiling:
- 2-hour rated barrier to Fire Area 4-A around conduit K6944. (Refs. 6.18, 6.19 and 6.21) Protective
Enclosure:
- A fire rated enclosure with an approximate rating of 3 hours, although 1 hour is committed, provided for conduit K6944. (Refs. 6.7 and 6.13)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-B 9.5A-275 Revision 21 September 2013 2.0 COMBUSTIBLES 2.1 Floor Area: 4,908 ft2 2.2 In situ Combustible Materials
- Wood
- Charcoal
- Cable insulation
- Alcohol
- Clothing/Rags
- Foam Rubber
- Polyethylene
- Resin
- Rubber
- Lube Oil
- Leather
- Paper
- Plastic
- PVC 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection provided (both above and below suspended ceiling). (Ref. 6.8) 3.2 Suppression
- Wet pipe automatic sprinkler system with remote annunciation provided except for F bus area and above the suspended ceiling.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-B 9.5A-276 Revision 21 September 2013
- Portable fire extinguishers available.
- Fire hose stations available.
4.0 SAFE SHUTDOWN FUNCTIONS
(Note: A fire in this area may cause a loss of Unit 2 480 V Bus SPF or SPH. The "G" Bus cables are protected by a fire barrier having an approximate fire rating of 3 hours, although 1 hour is committed. Only one of these redundant buses may be lost due to a fire in this area, as documented in SSER 31. The approved deviation is based on the low fire loading, automatic sprinkler systems below the suspended ceiling, automatic detection system above and below the ceiling, and a 1-hr fire barrier protecting the "G" 480-V switchgear SPG. Therefore, the losses and manual actions for this area are different based on which bus fails.
(Ref. 6.12)) 4.1 UNIT 1 4.1.1 Component Cooling Water System A fire in this area may spuriously close FCV-355. FCV-355 can be manually operated for safe shutdown. A fire in this area may spuriously close FCV-356. Since seal injection will remain available to the thermal barrier, FCV-356 is not necessary for safe shutdown. Valves FCV-430 and FCV-431 may be affected by a fire in this area. These valves can be manually opened to ensure safe shutdown. 4.1.2 Containment Spray System A fire in this area may spuriously open valve 9001B. Since CS PP 1-2 is not affected, this will not affect safe shutdown. 4.1.3 Diesel Fuel Oil System Circuits for diesel fuel oil transfer pumps 0-1 and 0-2 are routed through this area. However, as documented in SSER 23, at least one pump is protected by a fire barrier. Offsite power will also be available for safe shutdown in the event the diesel fuel pump circuits are damaged by the fire. Therefore, safe shutdown will not be affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-B 9.5A-277 Revision 21 September 2013 4.1.4 Safety Injection System A fire in this area may spuriously open 8808C. This valve can be manually closed to ensure safe shutdown. 4.1.5 Saltwater System Valves FCV-495 and FCV-496 may be affected by a fire in this area. FCV-601 will remain closed to provide ASW system integrity. A fire in this area may spuriously close FCV-602 and FCV-603. FCV-602 can be manually opened to allow the use of ASW pump 1-1. 4.1.6 HVAC A fire in this area may affect fan E-101 which provides HVAC for ASW pump 1-2. ASW pump 1-1 will remain available along with E-103 for HVAC. 4.2 UNIT 2 4.2.1 4-B (F Bus Lost) 4.2.1.1 Auxiliary Feedwater AFW pump 2-3 may be lost for a fire in this area. Redundant AFW pumps 2-1 will remain available. Valves LCV-110, LCV-111, LCV-113 and LCV-115 may be affected by a fire in this area. Redundant valves LCV-107 and LCV-108 will remain available. 4.2.1.2 Chemical and Volume Control System A fire in this area may affect valve 8104. Borated water from the RWST is credited for a fire in this area. However, if the boric acid transfer is utilized, FCV-110A and manual valve 8471 will remain available. The approved deviation in SSER 31 is based on the low fire loading, automatic sprinkler systems below the suspended ceiling, automatic detection system above and below the ceiling, and the performance of manual actions to reestablish the flowpath, which all provide assurance that at least one train would remain available for safe shutdown. Valve 8107 may be affected by a fire in this area. Redundant valves 8108 or HCV-142 can be closed to isolate auxiliary spray. Two other charging flowpaths (seal injection and charging injection) are available if the charging flowpath through the regenerative heat exchanger is disabled. The PORVs can be used DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-B 9.5A-278 Revision 21 September 2013 for pressure reduction. Since valve 8107 has redundant components, safe shutdown will not be affected. Charging pump 2-1 and ALOPs 2-1 and 2-2 may be lost due to a fire in this area. Redundant charging pump 2-2 can be locally started to provide charging flow. A deviation was approved in SSER 31 based on the low fire loading, automatic sprinkler systems below the suspended ceiling, automatic detection system above and below the ceiling, and the performance of manual actions, which all provide assurance that at least one train would remain available for safe shutdown. Both boric acid transfer pumps 2-1 and 2-2 may be affected by a fire in this area. As documented in SSER 31, one pump will survive and remain available. In addition, borated water from the RWST would also be available. A fire in this area may spuriously operate valves LCV-112B and LCV-112C. A deviation was approved in SSER 31 based on the low fire loading, automatic sprinkler systems below the suspended ceiling, automatic detection system above and below the ceiling, and the performance of manual actions to reestablish the flowpath, which all provide assurance that at least one train would remain available for safe shutdown. Although it is therefore not anticipated that redundant valves would be affected by a fire in this area, these valves can be manually operated to isolate the volume control tank. Valves 8805A and 8805B are required to be open to supply water to the charging pumps if LCV-112B or LCV-112C are closed. Level indication for boric acid storage tank 2-1 from LT-106 may be lost due to a fire in this area. Borated water from the RWST will remain available. Therefore, BAST level indication is not required. 4.2.1.3 Component Cooling Water CCW pump and ALOP 2-1 may be lost due to a fire in this area. Redundant CCW pumps and ALOPs 2-2 and 2-3 are available to provide CCW. A fire in this area may affect valves FCV-430 and FCV-431. Both of these valves can be manually operated to ensure safe shutdown. FCV-355 may spuriously close due to a fire in this area. FCV-355 can be manually operated for safe shutdown. A fire in this area may spuriously close valve FCV-356. Safe shutdown will not be affected because seal injection will remain available, therefore RCP seal integrity will not be affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-B 9.5A-279 Revision 21 September 2013 4.2.1.4 Containment Spray System A fire in this area may spuriously open valve 9001B. Since CS PP 2-2 will remain off, safe shutdown is not affected. 4.2.1.5 Emergency Power A fire in this area may disable the diesel generator 2-1 backup control circuit. However, power for the normal control circuit will remain available. A fire in this area may disable diesel generator 2-3. Diesel generators 2-1 and 2-2 will remain available for safe shutdown. A fire in this area may disable startup transformer 2-2. Onsite power from diesel generators 2-1 and 2-2 will remain available for safe shutdown. All power supplies on the "F" Bus may be lost due to a fire in this area. These power supplies are not necessary since redundant trains on the "G" and "H" buses will be available. A fire in this area may disable dc panel SD23 backup battery charger ED231. Normal battery charger ED232 will remain available. 4.2.1.6 Main Steam System A fire in this area may result in the loss of the following components: LT-516, LT-526, LT-529, LT-536, LT-539, LT-546, PT-514, PT-524, PT-534 and PT-544. Safe shutdown is not affected because redundant trains of indication will remain available for all four steam generators. Valve PCV-19 may be affected by a fire in this area. Since this valve fails in the desired, closed position and a redundant dump valve will remain available, safe shutdown is not affected. 4.2.1.7 Makeup System LT-40, level indication for the condensate storage tank may be lost. Feedwater will be available from the raw water storage reservoir via FCV-436. Manual action can be performed to locally open normally closed manual valve FCV-436. 4.2.1.8 Reactor Coolant System A fire in this area may result in the loss of the following components: LT-406, LT-459, NE-31, NE-51, PT-403, PT-406, TE-413A, TE-413B, TE-423A and DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-B 9.5A-280 Revision 21 September 2013 TE-423B. All of these instruments have redundant components available for safe shutdown. A fire in this area may affect valve 8000A. PCV-474 will remain closed to prevent uncontrolled pressure reduction through the PORV path. Control of RCPs 2-1, 2-2, 2-3 and 2-4 may be lost due to a fire in this area. Safe shutdown is not affected if the RCPs continuously run. CCW to the thermal barrier heat exchanger or seal injection will remain available for RCP seal cooling. 4.2.1.9 Residual Heat Removal System A fire in this area may affect AC power and control cables associated with RHR Pump 2-1. recirculation valve FCV-641A. Redundant Pump 2-2 and recirc valve FCV-641B will remain available for safe shutdown. 4.2.1.10 Safety Injection System SI pump 2-1 may spuriously operate due to a fire in this area. Local manual action may be required to defeat this spurious operation prior to RCS depressurization. A fire in this area may affect valves 8801A, 8803A, 8805A and 8805B. Loss of valves 8801A and 8803A will not affect safe shutdown because redundant valves 8801B and 8803B will be available to provide a charging injection flowpath. The PORVs can be used for pressure reduction. Although it is not anticipated that fire damage would occur to redundant valves 8805A and 8805B, the valves can be manually operated to provide RWST water to the charging pumps. A deviation was approved based on the low fire loading, automatic sprinkler systems below the suspended ceiling, automatic detection system above and below the ceiling, and manual actions to reestablish the flowpath, all of which provide assurance that at least one train would remain available for safe shutdown. A fire in this area may affect accumulator isolation valves 8808A and 8808C. These valves can be manually closed to ensure safe shutdown. 4.2.1.11 Auxiliary Saltwater System ASW pump 2-1 may be lost due to a fire in this area. ASW pump 2-2 will remain available to provide the ASW function. A fire in this area may affect valves FCV-495 and FCV-496. FCV-601 will remain closed to provide ASW system integrity. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-B 9.5A-281 Revision 21 September 2013 A fire in this area may spuriously close FCV-602 and FCV-603. Although it is not expected that fire damage would occur to the redundant valves, these valves can be manually opened to ensure safe shutdown. A deviation was approved based on the low fire loading, automatic sprinkler systems below the suspended ceiling, automatic detection system above and below the ceiling, and manual actions to reestablish the flowpath, all of which provide assurance that at least one train would remain available for safe shutdown. 4.2.1.12 HVAC Circuits for HVAC equipment E-102, E-104, E-45, S-45, FCV-5045 and S-69 are routed through this area. As documented in SSER 31, E-102 should survive a fire in this area due to the existing fire protection features and circuit operation. S-69 is not necessary due to a fire in this area. The redundant HVAC train (S-46, E-46, FCV-5046) will remain available for safe shutdown. A deviation was approved based on the low fire loading, automatic sprinkler systems below the suspended ceiling, and automatic detection system above and below the ceiling to provide assurance that at least one train would remain available for safe shutdown. 4.2.2 4-B ("H" Bus Lost) 4.2.2.1 Auxiliary Feedwater AFW pumps 2-2 and 2-3 may be lost due to a fire in this area. Redundant pump 2-1 will be available to provide AFW. A fire in this area may affect valves LCV-110, LCV-111, LCV-113 and LCV-115. Redundant valves LCV-107 and LCV-108 will remain available to provide AFW flow to steam generators 2-2 and 2-3. 4.2.2.2 Chemical and Volume Control System Charging pumps 2-1 and ALOPs 2-1 and 2-2 may be lost due to a fire in this area. Charging pump 2-2 can be manually started to provide charging flow. A deviation was approved based on the low fire loading, automatic sprinkler systems below the suspended ceiling, automatic detection system above and below the ceiling, and manual actions to reestablish the flowpath, all of which provide assurance that at least one train would remain available for safe shutdown. Boric acid transfer pumps 2-1 and 2-2 may be lost due to a fire in this area. As documented in SSER 31, one pump will survive and remain available. In addition, borated water from the RWST would be available for safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-B 9.5A-282 Revision 21 September 2013 Valve 8104 may be affected by a fire in this area. Borated water from the RWST is credited for a fire in this area. However, if the boric acid transfer is utilized, FCV-110A and 8471 will remain available to provide a path for boric acid to the charging pumps. A deviation was approved based on the low fire loading, automatic sprinkler systems below the suspended ceiling, automatic detection system above and below the ceiling, and manual actions to reestablish the flowpath, all of which provide assurance that at least one train would remain available for safe shutdown. A fire in this area may spuriously close LCV-112B and LCV-112C. Either valve 8805A or 8805B will remain available to provide water from the RWST to the charging pumps. Although it is not anticipated that a fire will damage redundant valves LCV-112B and LCV-112C, the valves can be manually closed to isolate the volume control tank. A deviation was approved based on the low fire loading, automatic sprinkler systems below the suspended ceiling, automatic detection system above and below the ceiling, and manual actions to reestablish the flowpath, all of which provide assurance that at least one train would remain available for safe shutdown. Level indication for boric acid storage tank 2-2 from LT-102 may be lost due to a fire in this area. Since borated water from the RWST will remain available, BAST level indication is not required. A fire in this area may affect valve 8145. This valve fails closed to isolate auxiliary spray during hot standby. Since the PORVs will be available for pressure reduction, valve 8145 is not necessary. 4.2.2.3 Component Cooling Water CCW pumps 2-1 and 2-3 and ALOP 2-1 may be lost due to a fire in this area. Redundant CCW pump 2-2 and ALOP 2-2 will remain available. Valve FCV-364 may be affected by a fire in this area. This valve fails open upon loss of power which is the desired position for safe shutdown. A fire in this area may affect valves FCV-430 and FCV-431. These valves can be manually operated. A fire in this area may spuriously close FCV-355. FCV-355 can be manually operated for safe shutdown. A fire in this area may spuriously close FCV-356. Since seal injection will be available to the RCP thermal barrier, this valve is not necessary for safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-B 9.5A-283 Revision 21 September 2013 4.2.2.4 Containment Spray System A fire in this area may spuriously open valve 9001B. Since CS PP 2-2 will remain off, safe shutdown is not affected. 4.2.2.5 Diesel Fuel Oil System Diesel fuel oil pump 0-1 may be lost due to a fire in this area. Redundant diesel fuel oil pump 0-2 will remain available. Valves LCV-88, LCV-89 and LCV-90 may be lost due to a fire in this area. Day tank level control will be maintained by redundant valves LCV-85, LCV-86 and LCV-87 will remain available. 4.2.2.6 Emergency Power A fire in this area may disable diesel generator 2-2. Diesel generators 2-1 and 2-3 will remain available for safe shutdown. A fire in this area may disable the diesel generator 2-3 backup control circuit. The normal control circuit will remain available. The "H" Bus may be lost due to a fire in this area. Redundant buses "F" and "G" will remain available for safe shutdown. A fire in this area may disable startup transformer 2-2. Onsite power from diesel generators 2-1 and 2-3 will remain available for safe shutdown. All power supplies on the "H" bus may lose power due to a fire in this area. These power supplies are not necessary since redundant trains on the "G" and "F" buses will be available. A fire in this area may result in a loss of power supplies associated with PY17N. Redundant power supply PY16 remains available. A fire in this area may disable dc panel SD21 backup battery charger ED221. Normal battery charger ED21 will remain available. A fire in this area may disable dc panel SD22 backup battery charger ED221. Normal battery charger ED22 will remain available. 4.2.2.7 Main Steam System A fire in this area may result in the loss of the following components: LT-518, LT-528, LT-538, LT-548, PT-526 and PT-536. Since redundant trains of DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-B 9.5A-284 Revision 21 September 2013 instrumentation exist for all four steam generators, safe shutdown will not be affected. Valve PCV-20 may be affected by a fire in this area. Since this valve fails in the desired, closed position, and a redundant dump valve will remain available, safe shutdown is not affected. A fire in this area may affect valves FCV-43 and FCV-44. These valves can be manually failed closed by isolating air to the valve and then venting residual air to ensure safe shutdown. 4.2.2.8 Reactor Coolant System LT-461, NE-52 and PT-403 may be lost due to a fire in this area. All of these instruments have redundant components available for safe shutdown. A fire in this area may affect pressurizer PORV PCV-456 and blocking valve 8000C. PCV-456 fails closed. Therefore, uncontrolled pressure reduction is prevented. Redundant PORV PCV-455C will remain available for pressure reduction. The ability to trip RCPs 2-1, 2-2, 2-3 and 2-4 may be lost due to a fire in this area. Safe shutdown is not affected if the RCPs continuously run. CCW to the thermal barrier heat exchanger or seal injection will remain available for RCP seal cooling. A fire in this area may affect heater groups 2-1 and 2-2. Manual actions can be taken to deenergize heater group 2-1 and switch heater group 2-2 to the vital power supply. Therefore, safe shutdown is not affected. 4.2.2.9 Residual Heat Removal System RHR pump 2-2 may be lost due to a fire in this area. Redundant pump 2-1 will be available to provide the RHR function. A fire in this area may affect AC power and control cables associated with RHR Pump 2-1 recirculation valve FCV-641A. Prior to starting RHR Pp 2-1, manual action can be taken to locally open FCV-641A. Valve 8702 may be affected by a fire in this area. This valve is closed with power removed during normal operations and will not spuriously open. Also, this valve can be manually operated for RHR operations. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-B 9.5A-285 Revision 21 September 2013 4.2.2.10 Safety Injection System SI pump 2-1 may spuriously operate for a fire in this area. Local manual action may be required to defeat this spurious operation. A fire in this area may affect valves 8805A and 8805B. Although it is not expected that a fire will damage redundant valves in this area, one of these valves can be manually opened for charging suction. A deviation was approved based on the low fire loading, automatic sprinkler systems below the suspended ceiling, automatic detection system above and below the ceiling, and manual actions to reestablish the flowpath, all of which provide assurance that at least one train would remain available for safe shutdown. Valve 8803A may be lost due to a fire in this area. This valve is not necessary for safe shutdown since redundant charging paths and pressure reduction methods will remain available. A fire in this area may affect accumulator isolation valve 8808C. This valve can be manually closed to ensure safe shutdown. 4.2.2.11 Auxiliary Saltwater System ASW pump 2-1 may be lost due to a fire in this area. Redundant ASW pump 2-2 is available to provide the ASW function. Valves FCV-495 and FCV-496 may be affected by a fire in this area. FCV-601 will remain available to provide ASW system integrity. A fire in this area may spuriously close FCV-602 and FCV-603. Although it is not expected that fire damage will affect redundant valves, these valves can be manually opened to defeat any spurious actions. A deviation was approved based on the low fire loading, automatic sprinkler systems below the suspended ceiling, automatic detection system above and below the ceiling, and manual actions to reestablish the flowpath, all of which provide assurance that at least one train would remain available for safe shutdown. 4.2.2.12 HVAC HVAC equipment E-46, S-46, FCV-5046 and S-67 may be lost due to a fire in this area. S-67 is not necessary for a fire in this area. A redundant train of HVAC equipment (S-45, E-45 and FCV-5045) will remain available for safe shutdown. A fire in this area may affect E-102 and E-104. SSER 31 documents that one of these ASW pump fans will remain operational. A deviation was approved based on the low fire loading, automatic sprinkler systems below the suspended ceiling, DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-B 9.5A-286 Revision 21 September 2013 and automatic detection system above and below the ceiling to provide assurance that at least one train would remain available for safe shutdown. Fan S-69 may be lost due to a fire in this area. Safe shutdown is not affected since this fan is not necessary for safe shutdown.
5.0 CONCLUSION
This area does not meet the requirements of 10 CFR 50, Appendix R, Section III.G.2, which requires the installation of an automatic fire detection and suppression system and the protection of one shut down division by a fire rated barrier. The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Smoke detection provided.
- Manual fire fighting equipment available.
- Automatic sprinkler system. The existing fire protection features provide a level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 Drawing Number 515568 6.2 DCPP Unit 2 review of 10 CFR 50, Appendix R (Rev.2) 6.3 SSER 23, June 1984 6.4 SSER 31, April 1985 6.5 Calculation M-824, Combustible Loading 6.6 Drawing 065126 and 065127, Fire Protection Information Report, Unit 1 and 2 6.7 DCN DC2-EA-22612, Upgrade Wall and Provide l Hour Barriers 6.8 DCN DC2-EA-14771, Provide area wide smoke detection 6.9 DCN DCO-EH-37379, Install fire dampers to vent shaft 6.10 Appendix 3 for EP M-10 Unit 2 Fire Protection of Safe Shutdown Equipment 6.11 NECS File: 131.95, FHARE: 58, Undampered Duct Penetrations 6.12 Chron No. 200042, Memo to File, Dated 12/4/92 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 4-B 9.5A-287 Revision 21 September 2013 6.13 PG&E Design Change Notice DC2-EA-050070, Unit 2 ThermoLag Replacement 6.14 NECS File: 131.95, FHARE 123, Unsealed penetrations with fusible link chain penetrants through fire barriers 6.15 DCN DC2-SA-50330, Restore the 2-Hour Fire Barrier Between Fire Area 4-B and 4-B-2 6.16 Calculation 134-DC, Electrical Appendix R Analysis 6.17 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.18 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.19 NECS File: 131.95, FHARE 117, Safe Shutdown Analysis For Modifying Fire Area 4-A and 4-B Boundary Barriers 6.20 DCP M-049536, Combine Fire Areas 4-A and 4-B 6.21 NECS File: 131.95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-B-1, 4-B-2 9.5A-288 Revision 21 September 2013 FIRE AREAS 4-B-1 AND 4-B-2 1.0 PHYSICAL CHARACTERISTICS
1.1 Location These two areas are located at the south end of the Auxiliary Building next to the Counting and Chemical Laboratory, El. 85 ft. 1.2 Description These areas are separate fire areas containing "G" and "H" bus circuitry. These areas are situated side by side with Fire Area 4-B-1 to the west and Fire Area 4-B-2 to the east. Due to similarities between these fire areas, they have been combined into one section. 1.3 Boundaries 1.3.1 Fire Area 4-B-1 North:
- 2-hour rated barrier separates this area from Area 4-B. (Ref. 6.5)
- Lesser rated penetration seals to Area 4-B. (Ref. 6.10) South:
- 3-hour rated barrier separates this area from Area 3-CC.
East:
- 3-hour rated barrier separates this area from Area 4-B-2. West:
- 3-hour rated barrier separates this area from Area 4-B.
- A 3-hour rated door communicates to Area 4-B. 1.3.2 Fire Area 4-B-2 North:
- 2-hour rated barrier separates this area from Area 4-B. (Ref. 6.5)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-B-1, 4-B-2 9.5A-289 Revision 21 September 2013
- Pyrocrete enclosure surrounds junction box BPG5 on the 4-B side of the barrier. (Ref. 6.7)
South:
- 3-hour rated barrier separates this area from Area 3-CC.
East:
- 2-hour rated barrier with a 1 1/2-hour rated hatch separates this area from Area 4-B.
West:
- 3-hour rated barrier separates this area from Area 4-B-1.
Floor/Ceiling (for both areas 4-B-1 and 4-B-2):
- 3-hour rated barriers.
- Floor to areas 3-K-2 and 3-K-3
- Ceiling to areas 5-B-1, 5-B-2, 5-B-3, and 5-B-4 2.0 COMBUSTIBLES
2.1 Fire Area 4-B-1 2.1.1 Floor Area: 120 ft2 2.1.2 In situ Combustible Materials
- Cable insulation 2.1.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-B-1, 4-B-2 9.5A-290 Revision 21 September 2013
- Paper 2.1.4 Fire Severity
- Low 2.2 Fire Area 4-B-2 2.2.1 Floor Area: 102 ft2 2.2.2 In situ Combustible Materials
- Cable insulation 2.2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.2.4 Fire Severity
- Low 3.0 FIRE PROTECTION (typical for each area)
3.1 Detection
- Smoke detection provided. 3.2 Suppression
- Portable fire extinguishers
- Hose stations DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-B-1, 4-B-2 9.5A-291 Revision 21 September 2013 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Fire Area 4-B-1 4.1.1 Auxiliary Feedwater Valves LCV-106, 107, 108 and 109 may be affected by a fire in this area. Redundant valves LCV-110, LCV-111, LCV-113 and LCV-115 will remain available for safe shutdown.
4.1.2 Chemical and Volume Control System Charging pumps 2-2 and 2-3 and ALOP 2-2 may be lost due to a fire in this area. Redundant charging pump and ALOP 2-1 will be available to provide charging flow. Boric acid transfer pump 2-2 may be lost due to a fire in this area. Redundant boric acid transfer pump 2-1 will be available for this function. Valve 8108 may be affected by a fire in this area. Redundant valve 8107 can be shut to isolate auxiliary spray during hot standby. The charging injection flowpath will remain available if the charging flowpath through the regenerative heat exchanger is disabled. The PORVs can be used for pressure reduction. Since this valve has redundant components, safe shutdown will not be affected. A fire in this area may affect valves 8104 and FCV-110A. Since valve FCV-110A fails in the desired open position, safe shutdown is not affected. Manual valve 8471 must also be opened if FCV-110A is used for boric acid transfer. Valves 8146, 8147 and 8148 may be affected by a fire in this area. Valve 8148 fails in the desired, closed position to isolate auxiliary spray during hot standby. The PORVs will remain available for pressure reduction. Valves 8146 and 8147 are required open if charging through the regenerative heat exchanger is desired. These valves fail open which is desired position and another charging flow path exists through the charging injection flowpath. The PORVs can be used for pressure reduction. Since redundant components are available, safe shutdown is not affected. A fire in this area may result in the loss of HCV-142. This valve is not necessary for a fire in this area. Therefore, safe shutdown is not affected. Valve LCV-112C may be affected by a fire in this area. Valve 8805A will remain available to provide water from the RWST to the charging pump suction. The volume control tank can be isolated by closing LCV-112B. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-B-1, 4-B-2 9.5A-292 Revision 21 September 2013 A fire in this area may affect valves LCV-459 and LCV-460. Safe shutdown is not affected since redundant valves 8149A, 8149B, and 8149C will be available to isolate letdown. 4.1.3 Component Cooling Water A fire in this area may affect CCW pump and ALOP 2-2. CCW pumps and ALOPs 2-1 and 2-3 will remain available to provide component cooling water. A fire in this area may affect valve FCV-431. Component cooling water heat exchanger 2-1 will remain available. Valve FCV-365 may be affected by a fire in this area. Since this valve fails in the desired open and redundant valve FCV-364 will be available, safe shutdown is not affected. 4.1.4 Containment Spray Containment spray pump 2-1 may spuriously operate due to a fire in this area. However, the discharge valve 9001A will remain closed. Therefore, the spurious containment spray pump operation has no impact on safe shutdown. 4.1.5 Diesel Fuel Oil System Diesel fuel oil pump 0-2 may be lost due to a fire in this area. The redundant diesel fuel oil pump 0-1 remains available. A fire in this area may affect valves LCV-85, LCV-86 and LCV-87. Redundant valves LCV-88, LCV-89 and LCV-90 will remain available. 4.1.6 Emergency Power A fire in this area may disable diesel generator 2-1. Diesel generators 2-2 and 2-3 will remain available for safe shutdown. A fire in this area may disable the diesel generator 2-2 backup control circuit. The normal control circuit will remain available. A fire in this area may disable startup transformer 2-2. Onsite power from diesel generators 2-2 and 2-3 will remain available for safe shutdown. All power supplies on the "G" Bus may be lost due to a fire in this area. These power supplies are not necessary since redundant trains on the "F" and "H" buses will be available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-B-1, 4-B-2 9.5A-293 Revision 21 September 2013 4.1.7 Main Steam System A fire in this area may result in the loss of the following components: LT-519, LT-549, PT-515, PT-525, PT-535 and PT-545. Safe shutdown is not affected because redundant trains of components exist for all four steam generators. Valve PCV-21 may be affected by a fire in this area. Since this valve fails in the desired closed position and a redundant dump valve will remain available, safe shutdown will not be affected. A fire in this area may prevent FCV-95 from delivering steam to AFW pump 2-1. Since AFW pumps 2-2 and 2-3 will remain available, safe shutdown will not be affected. Valves FCV-41 and FCV-42 may be affected by a fire in this area. Manual actions can be taken to make these valves operational. 4.1.8 Reactor Coolant System A fire in this area may result in the loss of the following components: LT-460, NE-32, TE-433A, TE-433B, TE-443A and TE-443B. Safe shutdown is not affected since redundant instrumentation exists. Valves PCV-455C and 8000B may be affected by a fire in this area. Since PCV-455C fails in the desired, closed position and a redundant PORV will remain available, safe shutdown will not be affected. Control of the reactor coolant pumps may be lost due to a fire in this area. Safe shutdown is not affected if the RCPs continuously run. CCW to the thermal barrier heat exchanger will remain available for RCP seal cooling. Heater groups 2-3 and 2-4 may be affected by a fire in this area. Manual actions can be taken to de-energize heater group 2-4 and switch heater group 2-3 to the vital power supply. Therefore, safe shutdown will not be affected. 4.1.9 Residual Heat Removal System RHR pump 2-1 and Recirc Valve FCV-641A may be lost due to a fire in this area. Redundant RHR pump 2-2 and recirc valve FCV-641B will be available to provide the RHR function. Valve 8701 may be affected by a fire in this area. This valve is closed with its power removed during normal operation and will not spuriously operate. Also, this valve can be manually operated for RHR operations. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-B-1, 4-B-2 9.5A-294 Revision 21 September 2013 4.1.10 Safety Injection System A fire in this area may result in the loss of the following valves: 8801B, 8803B and 8805B. The following redundant valves: 8801A, 8803A and 8805A will remain available to ensure safe shutdown. Valves 8808B and 8808D may be affected by a fire in this area. These valves can be manually closed. 4.1.11 Auxiliary Saltwater System ASW pump 2-2 may be lost due to a fire in this area. Redundant ASW pump 2-1 will be available to provide the ASW function. A fire in this area may cause FCV-603 to be lost. Since a redundant ASW train will be available safe shutdown will not be affected. 4.1.12 HVAC A fire in this area may result in the loss of one train of required HVAC equipment (E-102 and S-68). Safe shutdown is not affected since these two fans are not required for a fire in this area. 4.2 Fire Area 4-B-2 4.2.1 Auxiliary Feedwater AFW pump 2-2 may be lost due to a fire in this area. Redundant pumps 2-1 and 2-3 will be available to provide AFW. A fire in this area may affect valves LCV-110 and LCV-111. Redundant valves LCV-106, LCV-107, LCV-108 and LCV-109 from AFW Pump 2-1 and LCV-113 and LCV-115 from AFW Pump 2-3 will remain available. 4.2.2 Chemical and Volume Control System Valve 8145 may be lost due to a fire in this area. Since redundant components exist, this valve will not be necessary. A fire in this area may result in the loss of boric acid storage tank 2-2 level indication from LT-102. Borated water from the RWST will be available. Therefore, BAST level indication is not required. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-B-1, 4-B-2 9.5A-295 Revision 21 September 2013 Valve FCV-110A may be affected by a fire in this area. Since this valve fails in the desired, closed position, and redundant valve 8104 is available, safe shutdown is not affected. 4.2.3 Component Cooling Water CCW pump and ALOP 2-3 may be lost for a fire in this area. Redundant CCW pumps and ALOPs 2-1 and 2-2 will be available to provide CCW. Valve FCV-364 may be affected by a fire in this area. Since this valve fails in the desired, open position, safe shutdown is not affected. Redundant valve FCV-365 will also remain available for safe shutdown. 4.2.4 Containment Spray Containment spray pump 2-2 may spuriously operate due to a fire in this area. However, the corresponding discharge valve, 9001B will not operate. Therefore, the spurious containment spray pump operation has no impact on safe shutdown. 4.2.5 Diesel Fuel Oil System Diesel fuel oil pump 0-1 may be lost due to a fire in this area. Redundant diesel fuel oil pump 0-2 remains available. A fire in this area may result in the loss of the following valves: LCV-88, LCV-89 and LCV-90. These valves can be lost since redundant valves: LCV-85, LCV-86 and LCV-87 will be available. 4.2.6 Emergency Power A fire in this area may disable diesel generator 2-2. Diesel generators 2-1 and 2-3 will remain available for safe shutdown. A fire in this area may disable diesel generator 2-3 backup control circuit. The normal control circuit will remain available. A fire in this area may disable startup transformer 2-2. Onsite power from diesel generators 2-1 and 2-3 will remain available for safe shutdown. The power supply on the "H" Bus may be lost due to a fire in this area. Redundant trains on the "G" and "F" buses will be available. A fire in this area may disable dc panel SD21 backup battery charger ED221. Normal battery charger ED21 will remain available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-B-1, 4-B-2 9.5A-296 Revision 21 September 2013 A fire in this area may disable dc panel SD22 backup battery charger ED221. Normal battery charger ED22 will remain available. 4.2.7 Main Steam System A fire in this area may result in the loss of the following components: LT-518, LT-528, LT-538, LT-548, PT-526, and PT-536. Redundant components exist for all four steam generators, therefore, safe shutdown is not affected. Valve PCV-20 may be affected by a fire in this area. Since this valve fails in its desired closed position, and redundant dump valves will remain available for cooldown, safe shutdown is not affected. A fire in this area may affect valves FCV-43 and FCV-44. These valves can be manually closed to ensure safe shutdown. 4.2.8 Reactor Coolant System A fire in this area may result in the loss of the following instrumentation: LT-461, NE-52 and PT-403. Since all of these instruments have redundant components, safe shutdown is not affected. Valves PCV-456 and 8000C may be affected by a fire in this area. Since PCV-456 fails in the desired, closed position, and PORV PCV-455C will be available for RCS pressure reduction, safe shutdown is not affected. Control of reactor coolant pumps 2-1, 2-2, 2-3 and 2-4 may be lost due to a fire in this area. Safe shutdown is not affected if the RCPs continuously run. CCW to the thermal barrier heat exchanger or seal injection will remain available for RCP seal cooling. A fire in this area may affect pressurizer heater groups 2-1, 2-2 and 2-3. Manual actions can be taken to de-energize heater group 2-1 and switch heater group 2-2 to the vital power supply. Loss of vital power to pressurizer heater group 2-3 will not affect safe shutdown. 4.2.9 Residual Heat Removal System RHR pump 2-2 and Recirc Valve FCV-641B may be lost for a fire in this area. Redundant RHR pump 2-1 and recirc valve FCV-641A will be available to provide the RHR function. Valve 8702 may be affected by a fire in this area. This valve is closed with its power removed during normal operations and will not spuriously open. Also, this valve can be manually operated for RHR operations. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-B-1, 4-B-2 9.5A-297 Revision 21 September 2013 4.2.10 Safety Injection System SI pump 2-2 may spuriously operate due to a fire in this area. Local manual action may be required to defeat this spurious operation. Valve 8808C may be affected by a fire in this area. This valve can be manually closed. 4.2.11 Auxiliary Saltwater System A fire in this area may affect valves FCV-495 and FCV-496. FCV-601 will remain closed to provide ASW system integrity. 4.2.12 HVAC A fire in this area may result in the loss of one train of required HVAC equipment (FCV-5046, E-46, S-46 and S-67). Fan S-67 is not required and a redundant train of HVAC equipment (FCV-5045, E-45 and S-45) will be available to provide necessary HVAC support.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Safe shutdown will not be adversely affected by the loss of the equipment in each area due to the availability of redundant systems.
- Smoke detection is provided.
- Manual fire fighting equipment is available.
- Limited combustible loading.
The existing fire protection features provide a level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 4-B-1, 4-B-2 9.5A-298 Revision 21 September 2013
6.0 REFERENCES
6.1 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.2 Drawing No. 515568 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065126, Fire Protection Information Report, Unit 1 6.5 DCPP Unit 2 Report on 10 CFR 50, Appendix R Review (Rev. 0) 6.6 NRC Supplemental Safety Evaluation Report 31 for Diablo Canyon Power Plant, April 1985 6.7 DCN DC2-SA-50330, Restore the 2-Hour Fire Barrier Between Fire Area 4-B and 4-B-2 6.8 Calculation 134-DC, Electrical Appendix R Analysis 6.9 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.10 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 34 9.5A-299 Revision 21 September 2013 FIRE AREA 34 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Roof area above the Auxiliary Building (El. 140 ft and 154 ft).
1.2 Description This area is the space above the Auxiliary Building between the Unit 1 and Unit 2 Containment Buildings and the Fuel Handling Building. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
Unit 1 Containment Building
- 3-hour rated walls with some nonrated personnel and equipment hatches. NC (Ref 6.7) South:
Unit 2 Containment Building
- 3-hour rated walls and some nonrated personnel and equipment hatches. NC (Ref. 6.7) East:
Fuel Handling Building
- Nonrated exterior walls and doors to Fire Area 3-S, NC 3-R, NC 3-W NC and S-3. NC West:
Turbine Building
- Nonrated exterior walls. NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 34 9.5A-300 Revision 21 September 2013 Auxiliary Building
- 3-hour rated walls with some nonrated penetrations and/or openings. This fire area communicates with Fire Areas S-2, 8-B-3, NC 8-B-4, NC 8-B-5, NC 8-B-6, NC 8-B-7, NC and 8-B-8 NC through ventilation exhaust and intake openings without fire dampers.
- Nonrated exterior walls to Fire Areas 8-B-1 NC and 8-B-2. NC (Ref. 6.12). Control Room
- 3-hour rated walls with penetrations sealed commensurate with the hazards to which they could be exposed to Fire Zones 8A, 8C, 8D, and Fire Areas 8H and 8G.
2.0 COMBUSTIBLES
2.1 Floor Area: 24,536 ft2 2.2 In Situ Combustible Materials
- Bulk Cable
- Clothing/Rags
- Neoprene
- Polyethylene
- Paper
- Plastic
- Rubber
- Wood (fir) 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 34 9.5A-301 Revision 21 September 2013 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- None 3.2 Suppression
- Hose stations
- Portable fire extinguishers
- Wet pipe automatic sprinkler systems in both outage access control facilities 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Unit 1 Equipment 4.1.1 Chemical and Volume Control System A fire in this area may result in the loss of boric acid storage tank 1-2 level indication from LT-106. Borated water from the RWST will remain available. Therefore, BAST level is not required. 4.1.2 Main Steam System Ten percent dump valves PCV-21 and PCV-22 may be affected due to a fire in this area. Air can be isolated and vented to fail PCV-21 and PCV-22 closed. Redundant dump valves PCV-19 and PCV-20 will remain available for cooldown. 4.1.3 HVAC Fans S-44, E-44, S-43 and E-43 may be lost due to a fire in this area. Operator actions may be necessary to install portable fans. 4.2 Unit 2 Equipment 4.2.1 Chemical and Volume Control System A fire in this area may result in the loss of boric acid storage tank 2-1 and 2-2 level indication from LT-106 and LT-102, respectively. Borated water from the RWST will remain available. Therefore, BAST level is not required. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 34 9.5A-302 Revision 21 September 2013 4.2.2 Main Steam System A fire in this area may affect valve PCV-21 and PCV-22. Redundant dump valves PCV-19 and PCV-20 will remain available for cooldown. 4.2.3 HVAC A fire in this area may affect fans S-45, E-45, S-46 and E-46. Operator action may be necessary to install portable fans. (Refs. 6.8 and 6.9)
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- The redundant train, of the 10% relief valves will not be affected by fire in this area due to spatial separation.
- Manual fire protection equipment is available in the vicinity to provide adequate capabilities.
- Automatic wet pipe sprinklers are provided for both Unit-1 and Unit-2 Outage Access Control Facilities. Flow alarms annunciate in the Control Room for immediate response by the fire brigade.
- Open-air location provides for rapid dissipation of heat and the products of combustion generated by a fire.
This fire area meets the requirements of 10 CFR 50, Appendix R, Section III.G and there are no exemptions requested.
6.0 REFERENCES
6.1 Drawing Nos. 515571, 515572 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 SSER 23, June 1984 6.4 SSER 31, April 1985 6.5 Calculation M-824, Combustible Loading 6.6 Drawing 065126 and 065127, Fire Protection Information Report, Units 1 and 2 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 34 9.5A-303 Revision 21 September 2013 6.7 NECS File: 131.95, FHARE: 94, Containment Personnel Airlock Doors 6.8 Calculation M-911, Evaluation of Safe Shutdown Equipment During Loss of HVAC 6.9 Calculation M-912, HVAC Interactions for Safe Shutdown 6.10 Calculation 134-DC, Electrical Appendix R Analysis 6.11 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.12 NECS File: 131.95, FHARE 155, Removal of Auxiliary Building Supply Fan Room Exterior Walls from the Fire Protection Program DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-A 9.5A-304 Revision 21 September 2013 FIRE AREA AB-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This zone is located at the east end of the Auxiliary Building and occupies El. 55 ft through 104 ft. 1.2 Description This zone houses the liquid hold up tanks for both units and is compartmentalized for each hold up tank. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. El. 64 ft North:
- A 3-hour rated barrier to below grade. NC South:
- A 3-hour rated barrier to below grade. NC East:
- A 3-hour rated barrier to below grade. NC West:
- A nonrated barrier to fire zone 3-C. NC Floor:
- A 3-hour barrier to below grade. NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-A 9.5A-305 Revision 21 September 2013 El. 73 ft North:
- A 3-hour rated barrier to below grade. NC South:
- A 3-hour rated barrier to below grade. NC West:
- A nonrated door communicates to zone 3-F. NC
- A nonrated barrier to zone 3-F. NC
- A nonrated barrier to zone 3-C. NC
- A nonrated barrier to zone 3-G. NC
- A nonrated door communicates to zone 3-G. NC East:
- A 3-hour barrier to below grade. NC El. 85 ft North:
- A 3-hour rated barrier to zone 3-P-3. NC
- A duct penetration without a fire damper to zone 3-P-3. NC (Ref. 6.4) South:
- A 3-hour rated barrier to zone 3-V-3. NC
- A duct penetration without a fire damper to zone 3-V-3. NC (Ref. 6.4) East:
- A 3-hour rated barrier to below grade. NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-A 9.5A-306 Revision 21 September 2013 West:
- A nonrated barrier to zone 3-L. NC
- A non-rated barrier containing duct penetration without dampers to Fire Areas 3-P-3 NC and 3-V-3. NC El. 100 ft North:
- A 3-hour rated barrier to Fire Area 3-Q-1, except for a 2-hour rated blockout. (Ref. 6.5)
- A lesser rated penetration seal to Fire Area 3-Q-1. (Ref. 6.9) South:
- A 3-hour rated barrier to Fire Area 3-T-1, except for a 2-hour rated blockout. (Ref. 6.5)
- Lesser rated penetration seal to Fire Area 3-J-1. (Ref. 6.9) East:
- A 3-hour rated barrier to below grade. NC West:
- A nonrated barrier to zone 3-X. NC
- Six duct penetrations without fire dampers to Fire Zone 3-X. NC
- Two nonrated doors communicate to zone 3-X. NC Ceiling:
- A nonrated barrier to zone 3-AA above. NC 2.0 COMBUSTIBLES
2.1 Floor Area: 2,832 ft2 2.2 In situ Combustible Materials
- Rubber DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-A 9.5A-307 Revision 21 September 2013 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- None 3.2 Suppression
- None 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Chemical and Volume Control System A fire in this area may spuriously close FCV-110A. Redundant valve 8104 will remain available for safe shutdown. Boric acid storage tank 2-1 level indication from LT-106 may be lost due to a fire in this area. Borated water from the RWST will remain available. Therefore, BAST level indication is not required. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-A 9.5A-308 Revision 21 September 2013
5.0 CONCLUSION
The following features mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- A trained fire brigade is on-site at all times and is responsible for fire suppression.
- Redundant components are available outside of the fire area. These functions are considered adequate to assure that safe shutdown capability will not be compromised from a design basis fire in this zone/area.
6.0 REFERENCES
6.1 Drawings: 515566, 515567, 515568, 515569 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation No. M-824, Combustible Loading 6.4 FHARE 60, Undampered Ventilation Ducts 6.5 NECS File: 131.95, FHARE 125, Lesser rated plaster blockouts and penetration seal configurations 6.6 Drawing 065127, Fire Protection Information Report, Unit 2 6.7 Calculation 134-DC, Electrical Appendix R Analysis 6.8 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.9 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-AA 9.5A-309 Revision 21 September 2013 FIRE AREA AB-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Zone 3-AA is located on the east side of the Auxiliary Building at El. 115 ft. It runs from the Unit 1 Fuel Handling Building and Containment Penetration Area (3-BB) on the north to the Unit 2 Fuel Handling Building and Containment Penetration Area (3-CC) on the south. 1.2 Description This zone contains the boric acid storage tanks and radwaste processing equipment. The north half of Fire Zone 3-AA contains the tanks for Unit 1; the south half contains Unit 2 equipment. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- 3-hour rated barriers to Fire Areas 3-BB and 6-B-4 and to Fire Zones S-2, S-3 and 3-R. NC
- Three 1-1/2-hour rated doors, one to Fire Area 3-BB and to Fire Zone S-3, one to Fire Zone S-2. (Ref. 6.12).
- Lesser rated penetration seal to Fire Area 3-BB. (Ref. 6.11)
- A 3-hour rated roll-up door to Fire Zone 3-R. NC
- Duct penetration without a fire damper communicates to Fire Zone 3-R. NC South:
- 3-hour rated barriers to Fire Areas 3-CC and 6-A-4 and Fire Zones S-4 and 3-W, NC S-2.
- Three 1-1/2-hour rated doors, one to each of the Fire Area 3-CC and Zones S-4 and S-2. (Ref. 6.13)
- Two 3-hour rated roll-up doors to Fire Zone 3-W. NC
- Two duct penetration without fire dampers communicate to Fire Zone 3-W. NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-AA 9.5A-310 Revision 21 September 2013 East:
- 3-hour rated barriers to Fire Zones S-3 and S-4.
- Nonrated barrier to the exterior (Fire Areas 28 and 29) (Grade Level).
- A nonrated door to the exterior (Area 28) (Grade Level).
- A nonrated roll up door to the exterior (Area 28) (Grade Level).
West:
- 3-hour rated barrier to Fire Areas 6-A-4 and 6-B-4, and to Zones S-3 and S-4.
Floor/Ceiling:
- Nonrated barriers: Floor to Fire Zones 3A, NC 3X, NC and 3C NC Ceiling to Fire Zone 3-S, NC and Areas 34, NC 8-B-1, NC and 8-B-2. NC
- Duct penetrations without fire dampers communicate to Fire Zone 3-X. NC.
- Equipment hatches to Fire Zones 3-X NC below, and 3-S NC above.
- A 3-hour rated concrete equipment hatch in 3-hour rated barrier communicates to Fire Zones 3-B-1, 3-B-2, 3-D-1, and 3-D-2 (below) on unprotected steel supports with unsealed gaps. (Refs. 6.7 and 6.8) 2.0 COMBUSTIBLES
2.1 Floor Area: 16,674 ft2 2.2 In situ Combustible Loading
- Cable Insulation
- Lubricants
- Paper
- Wood
- Rubber
- Oil (#2 fuel)
- Miscellaneous Class A and B Combustibles 2.3 Transient Combustible Loading Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-AA 9.5A-311 Revision 21 September 2013
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Partial smoke detection (in the vicinity of boric acid storage tanks and spent resin storage tanks.)
3.2 Suppression
- Portable fire extinguishers
- Fire hose stations
- Automatic sprinkler system in the vicinity of the radwaste compaction area 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Unit 1 Equipment 4.1.1 Auxiliary Feedwater A fire in this area may affect condensate storage tank level indication from LT-40. FCV-436 and FCV-437 can be manually opened to supply water from the raw water storage reservoir.
4.1.2 Chemical and Volume Control System Valves 8104 and FCV-110A may be affected by a fire in this area. One of these valves must be open to provide boric acid solution to the charging pumps. Valve 8104 can be manually opened to provide this function. A fire in this area may spuriously open FCV-110B and FCV-111B. These valves can be manually closed. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-AA 9.5A-312 Revision 21 September 2013 Valves HCV-104 and HCV-105 may be affected by a fire in this area. One of these valves must be closed when a boric acid transfer pump is running. Therefore, since both of these valves fail closed, safe shutdown is not affected. A fire in this area may affect valves LCV-112B, LCV-112C, 8805A and 8805B. The running charging pump 1-1 or 1-2 can be tripped from the control room, and then restarted after aligning the RWST supply and isolating the VCT supply valves. Both sets of valves can be manually operated to isolate the VCT (LCV-112B, 112C) and provide water to the charging pumps from the RWST (8805A and 8805B). A fire in this area may result in the loss of LT-102 and LT-106 which provide BAST1-1 and 1-2 level indication. Borated water from the RWST will remain available. Therefore, BAST level is not required. 4.1.3 Main Steam System A fire in this area may result in the loss of the following valves: FCV-244, FCV-246, FCV-248, FCV-250, FCV-151, FCV-154, FCV-157 and FCV-160. Since redundant components FCV-760, 761, 762 and 763 are available, safe shutdown will not be affected. Main steam isolation valves FCV-43 and FCV-44 and their bypass valves FCV-22 and FCV-23 may be affected by a fire in this area. These valves can be manually operated to ensure safe shutdown. 4.1.4 Reactor Coolant System A fire in this area may affect pressurizer heater groups 1-1. This heater group can be manually de-energized. Therefore, safe shutdown is not affected. Control of reactor coolant pumps 1-2 and 1-4 may be lost due to a fire in this area. However, operation of these pumps will not affect safe shutdown. CCW to the thermal barrier heat exchanger or seal injection will remain available for RCP seal cooling. 4.1.5 Residual Heat Removal System Control circuitry for RHR pumps 1-1, 1-2, FCV-641A and FCV-641B may be damaged by a fire in this area. Prior to locally starting either RHR Pump 1-1 or 1-2, locally open its respective recirc valve (FCV-641A or FCV-641B). . DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-AA 9.5A-313 Revision 21 September 2013 4.1.6 Safety Injection System A fire in this area may affect RWST Level Transmitter LT-920. Spurious operation of equipment that may divert the RWST inventory is not affected in this fire area. Therefore, loss of this instrument will not affect safe shutdown. 4.2 Unit 2 Equipment 4.2.1 Auxiliary Feedwater A fire in this area may affect condensate storage tank level indication from LT-40. FCV-436 and FCV-437 can be manually opened to supply water from RWSR. 4.2.2 Chemical and Volume Control System Valves 8104 and FCV-110A may be affected by a fire in this area. One of these valves must be open to provide boric acid solution to the charging pumps. Valve 8104 can be manually opened to provide this function. A fire in this area may spuriously open FCV-110B and FCV-111B. These valves can be manually closed. Valves HCV-104 and HCV-105 may be affected by a fire in this area. One of these valves must be closed when a boric acid transfer pump is running. Therefore, since both of these valves fail closed, safe shutdown is not affected. A fire in this area may affect valves LCV-112B, LCV-112C, 8805A and 8805B. The running charging pumps 2-1 and 2-2 can be tripped from the control room to prevent cavitation and restarted after aligning the RWST supply and isolating the VCT supply valves. Both sets of valves can be manually operated to isolate the VCT (LCV-112B, 112C) and provide water to the charging pumps from the RWST (8805A and 8805B). A fire in this area may result in the loss of LT-102 and LT-106 which provide BAST 2-2 and 2-1 level indication. Borated water for the RWST will remain available. Therefore, BAST level is not required. 4.2.3 Main Steam System A fire in this area may result in the loss of the following valves: FCV-244, FCV-246, FCV-248, FCV-250, FCV-151, FCV-154, FCV-157 and FCV-160. Since redundant components FCV-760, 761, 762 and 763 area available, safe shutdown will not be affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-AA 9.5A-314 Revision 21 September 2013 A fire in this area may result in the loss of LT-529 and LT-539 which provide steam generator 2-2 and 2-3 level indication. Redundant level transmitters will remain available for steam generator level indication. 4.2.4 Reactor Coolant System A fire in this area may affect valve PCV-455A. Since this valve fails in the desired, closed position, safe shutdown is not affected. A fire in this area may spuriously energize pressurizer heater group 2-1. This heater group can be manually tripped to ensure safe shutdown. A fire in this area may affect valve PCV-455B and prevent RCP 2-2 from turning off. Safe shutdown is not affected if the reactor coolant pumps continuously run. 4.2.5 Residual Heat Removal System RHR pumps 2-1, 2-2, FCV-641A and FCV-641B may be lost for a fire in this area. Prior to starting either RHR Pump 2-1 or 2-2, locally open its respective recirc valve (FCV-641A or FCV-641B).
4.2.6 Safety Injection System A fire in this area may affect RWST Level Transmitter LT-920. Spurious operation of equipment that may divert the RWST inventory is not affected in this fire area. Therefore, loss of this instrument will not affect safe shutdown.
5.0 CONCLUSION
The following features will adequately mitigate the consequences of a design basis fire and assure the ability to achieve safe shutdown.
- Detection in the vicinity of the BA tanks and spent resin storage tanks.
- Automatic sprinklers in the south-east corner of the area.
- Manual action that will mitigate the effects of a design basis fire. This zone meets the requirements of 10 CFR 50, Appendix R, Section III.G. and no exemptions or deviations have been requested.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-AA 9.5A-315 Revision 21 September 2013
6.0 REFERENCES
6.1 Drawing No. 515570 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.4 Calculation M-824, Combustible Loading 6.5 Drawing 065126 and 065127, Fire Protection Information Report, Units 1 and 2 6.6 Appendix 3 for EP M-10 Unit 1 - Fire Protection of Safe Shutdown Equipment 6.7 NECS File: 131.95, FHARE 14, Concrete Equipment Hatches 6.8 PLC Report: Structural Steel Analysis for Diablo Canyon, Rev. 2 (7/08/86) 6.9 Calculation 134-DC, Electrical Appendix R Analysis 6.10 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.11 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.12 SSER - 23 6.13 SSER - 31
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-C 9.5A-316 Revision 21 September 2013 FIRE AREA AB-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Zone 3-C is in the Auxiliary Building at elevations below 85 ft. It is the bulk of the center of the Auxiliary Building and is called the Units 1 and 2 Drain Receiving Tank and Gas Decay Tanks. 1.2 Description This zone incorporates El. 54 ft, 64 ft and 73 ft except for various Units 1 and 2 pump and equipment rooms to the north and south of this zone. Fire Zone 3-C contains Unit 1 and 2 equipment drain tanks, floor drain tanks, waste gas compressors, gas decay tanks, Auxiliary Building sump pumps, radwaste filters, and waste concentrator tanks and associated transfer pumps. Additionally, Fire Zone 3-C contains the Tool Room Area, located on the 60-ft elevation bounded by column lines 192 and 203 by column lines H1 and L. (Reference 6.15)
(Note: The east-west corridor on the 64-ft elevation bounded by column lines 186 and192 by column lines H and L, and the north-south corridor on the 60-ft elevation bounded by column lines 192 and 203 by column lines H and J are subjected to a combustible loading limitation.)
1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. El. 54 ft North:
- 3-hour rated barrier to Fire Areas 3-B-1 and 3-B-2, Fire Zone 3-B-3, NC and to below grade. NC
- 3-hour rated barrier to Fire Zone S-2. This barrier includes an unsealed penetration covered by a grate. (Ref 6.17).
- A 1-1/2-hour rated door to Fire Zone S-2.
- Overflow openings to Fire Areas 3-B-1 and 3-B-2. (Ref. 6.3)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-C 9.5A-317 Revision 21 September 2013 South:
- 3-hour rated barrier to Fire Areas 3-D-1 and 3-D-2, Fire Zone 3-D-3, NC and to below grade. NC
- 3-hour rated barrier to Fire Zone S-2. This barrier includes an unsealed penetration covered by a grate. (Ref 6.17).
- A 1-1/2-hour rated door to Fire Zone S-2.
- Overflow opening to Fire Areas 3-D-1 and 3-D-2. (Ref. 6.7) East/West:
- 3-hour rated barrier to below grade. NC
- 3-hour rated barrier to the west to Fire Zone S-2. This barrier includes an unsealed penetration covered by a grate. (Ref 6.17) El. 60 ft - Tool Room Area (Unit 2 side of Fire Zone 3-C)
North:
- 3-hour rated barrier to Fire Zone 3-C. NC
- 3 duct penetrations with 3-hour rated dampers to Fire Zone 3-C (Ref. 6.16). South:
- 3-hour barrier to grade. NC East:
- 3-hour rated barrier to Fire Area 3-D-1. West:
- 3-hour rated barrier to Fire Zone 3-C.
- Two 3-hour rated doors to Fire Zone 3-C. Ceiling:
- 3-hour rated barrier to Fire Area 3-I-1 and Fire Zones 3-K-1, 3-K-2, and 3-K-3.
- One duct penetration with a 3-hour rated damper to Fire Zone 3-K-2 (Ref. 6.16).
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-C 9.5A-318 Revision 21 September 2013 El. 64 ft North:
- 3-hour rated barrier to Fire Areas 3-D-2, 3-B-1 and 3-B-2, and to Fire Zones S-2 and S-3.
- A 1-1/2-hour rated door to Fire Zone S-2.
- 1 1-1/2-hour rated doors to Fire Zone S-3.
- An opening in the 3-hour fire barrier to Fire Zone 3-B-3. NC South:
- 3-hour rated barrier to Fire Areas 3-B-2, 3-D-1 and 3-D-2, and to Fire Zones S-2 and S-4, and to below grade. NC
- A 1-1/2-hour rated doors to Fire Zone S-4.
- A 1-1/2-hour rated door to Fire Zone S-2.
- An opening in the 3-hour fire barrier to Fire Zone 3-D-3. NC East:
- A nonrated barrier to Fire Zone 3-A. NC
- 3-hour rated barrier to Fire Zones S-2, S-3, S-4, and below grade. NC
- 3-hour rated barrier with a duct penetration without a damper to Fire Areas 3-B-1 and 3-D-1. (Refs. 6.3 and 6.7)
West:
- 3-hour rated barrier to Fire Zones S-2, S-3, and S-4, and to below grade. NC
- A 1-1/2-hour rated door to Fire Zones S-2, S-3, and S-4.
- 3 duct penetrations without dampers to Area 3-B-2. (Refs. 6.3 and 6.11)
- 3-hour rated barrier with three undampered duct penetrations to each Fire Area 3-B-2 and 3-D-2. (Refs. 6.3 and 6.7)
Ceiling:
- Two open penetrations to the 73-ft elevation of 3-J-3. (Ref. 6.8)
- One duct penetration without a damper to Zone 3-J-2. Floor:
- 3-hour barrier to grade. NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-C 9.5A-319 Revision 21 September 2013 El. 73 ft North:
- 3-hour rated barrier to Fire Areas 3-H-1 and 3-H-2, and to Fire Zone S-2.
- A 1-1/2-hour rated door to Fire Zone S-2.
- Two 3-hour-equivalent rated fire doors with water spray directed on them communicate to Fire Area 3-H-1. (Ref. 6.18)
- Two duct penetrations without damper to Area 3-H-1. (Ref. 6.3)
- A duct penetration without damper to Area 3-H-2. (Ref. 6.3)
- Zone opens to Zone 3-F, 3-J-1, 3-J-2, and 3-J-3. (Ref. 6.3)
- A nonrated opening penetrates into Zone 3-H-1. (Ref. 6.9)
- Lesser rated penetration seals into Zone 3-H-1. (Ref. 6.14)
South:
- 3-hour rated barrier to Fire Areas 3-I-1 and 3-I-2, and to Fire Zone S-2.
- A 1-1/2-hour rated door to Fire Zone S-2.
- Two duct penetrations without dampers to Fire Area 3-I-1. (Ref. 6.7)
- Lesser rated penetration seal to Fire Area 3-I-1. (Ref. 6.14)
- A duct penetration without dampers to Fire Area 3-I-2. (Ref. 6.7)
- Two 3-hour-equivalent rated fire doors with water spray directed on them communicate to Fire Area 3-I-1. (Ref. 6.18)
- Zone opens to Zones 3-G, 3-K-1, 3-K-2 and 3-K-3. (Ref. 6.7)
East:
- 3-hour rated barrier to Fire Zone S-2.
- Nonrated barrier to Fire Zone 3-A. NC
- A 2-hour rated plaster blockout panel communicates to Areas 3-H-1 and 3-I-1. (Ref. 6.10)
West:
- Two 3-hour rated doors with water spray directed on them communicate to Areas 3-H-1 and 3-I-1. (Ref. 6.18)
- 3-hour rated barrier to Fire Zone S-2 and to below grade. NC Ceiling:
- Duct penetrations communicate to Fire Zone 3-L. NC
- Two equipment hatches to Fire Zone 3-L. NC
- 3-hour rated barrier to Fire Zones 4A and 4B.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-C 9.5A-320 Revision 21 September 2013 2.0 COMBUSTIBLES
2.1 Floor Area: 10,772 ft2 2.2 In situ Combustible Materials
- Cable insulation
- Lube Oil
- Clothing/Rags
- Plastic
- Rubber
- Paper
- PVC
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity 2.4.1 Fire Zone 3-C, Excluding Tool Room Area (Floor Area = 9131 ft2)
- Low 2.4.2 Tool Room Area (Floor Area = 1641 ft2)
- Low DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-C 9.5A-321 Revision 21 September 2013 2.5 Limitation of Combustible Loading The east-west corridor on the 64-ft elevation bounded by column lines 186 and 192 by column lines H and L, and the north-south corridor on the 60-ft elevation bounded by column lines 192 and 203 by column lines H and J are limited in the amount of combustible material (plastic/rubber/Class A) that may be stored there.
The limit is 375 lb for both of these areas. This ensures a fire duration of 3 minutes or less in these areas. No extension cords or flammable fluids can be stored in this area. The Tool Room area, located on the 60-ft elevation bounded by column lines 192 and 203 by column lines H1 and L is limited in the amount of combustible material (plastic/rubber/Class A) that may be stored there. The limit is 10,000 lb. This ensures a fire-duration of 37 minutes or less in this area. 3.0 FIRE PROTECTION
3.1 Detection
- Partial smoke detection 3.2 Suppression
- Portable fire extinguishers
- Fire hose stations 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Unit 1 Equipment 4.1.1 Chemical and Volume Control System A fire in this area may damage charging pump 1-3. Redundant charging pumps 1-1 and 1-2 will remain available for safe shutdown. 4.1.2 Diesel Fuel Oil System Diesel fuel oil pump 0-1 and 0-2 may be affected by a fire in this area. SSER 23 justifies that at least one of these pumps will remain available for safe shutdown. Offsite power will also be available for safe shutdown in the event diesel fuel oil pump circuits are damaged by a fire. Therefore, safe shutdown will not be affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-C 9.5A-322 Revision 21 September 2013 4.1.3 Residual Heat Removal System Control circuitry for RHR pumps 1-2, FCV-641A and FCV-641B may be damaged by a fire in this area. Redundant RHR pump 1-1 will remain available. Prior to starting either RHR Pump 2-1 or 2-2, locally open its respective recirc valve (FCV-641A or FCV-641B) located in fire area 3D1 and 3D2 after opening its associated power supply breaker (52-2G-29 or 52-2H-15) located in SPG and SPH. 4.1.4 Auxiliary Saltwater System ASW valves FCV-495 and FCV-496 may be affected by a fire in this area. Redundant valve FCV-601 will remain available, thus no manual actions are required. 4.2 Unit 2 Equipment 4.2.1 Chemical and Volume Control System A fire in this area may damage charging pump 2-3. Redundant charging pumps 2-1 and 2-2 will remain available for safe shutdown. 4.2.2 Residual Heat Removal System Control circuitry for RHR pumps 2-1, 2-2, FCV-641A and FCV-641B may be damaged by a fire in this area. Prior to starting either RHR Pump 2-1 or 2-2, locally open its respective recirculation valve (FCV-641A or FCV-641B) located in fire area 3D1 and 3D2 after opening its associated power supply breaker (52-2G-29 or 52-2H-15) located in SPG and SPH. 4.2.3 Auxiliary Saltwater System ASW valves FCV-495 and FCV-496 may be affected by a fire in this area. Redundant valve FCV-601 will be available, thus no manual actions are required. 4.2.4 HVAC A fire in this area may result in the loss of one train of E-102. Redundant HVAC equipment, E-104 will be available to provide necessary HVAC support.
5.0 CONCLUSION
This zone does not meet the requirements of 10 CFR 50, Appendix R, Section III G.2, because area wide automatic fire suppression is not provided in this zone. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-C 9.5A-323 Revision 21 September 2013
- A request for a deviation was requested and was granted as stated in SSERs 23 and 31.
This zone does not meet requirements of 10 CFR 50, Appendix R, Section III.G.2, because doors installed in fire rated barriers that separate redundant shutdown divisions, are required to have a fire rating equal to the barrier:
- A request for a deviation was submitted and was granted as stated in SSERs 23 and 31.
The following features will adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Fire protection equipment is available.
- Limited combustible loading.
- Partial smoke detection is provided.
- Redundant functions are adequately protected from a fire in this zone.
The east-west corridor on the 64-ft elevation bounded by column lines 186 and 192 by column lines H and L, and the north-south corridor on the 60-ft elevation bounded by column lines 192 and 203 by column lines H and J are limited to a combustible loading of 4,000 Btus/ft2. This limitation is to ensure the combustible load in this portion of Fire Zone 3-C is very low, which is credited in SSERs 23 and 31 for the vicinity around the CCW pump rooms. Section 9.6.1.7 of SSER 31 characterizes 4,600 Btu/ft2 with an equivalent fire severity of 3.4 minutes as a "low fire load". The DCPP fire protection group has established, based on this SSER characterization, that 4,000 Btu/ft2, with an equivalent fire severity of 3 minutes, is low combustible loading and will be used as the limitation for the area described above. A fire severity of 3 minutes is an insignificant fire and will not impact the CCW pump rooms above the area where the limitation is being imposed. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-C 9.5A-324 Revision 21 September 2013 The Tool Room area is enclosed within 3-hour rated barriers, doors, and dampers to prevent a fire in this area from impacting the vicinity around the CCW pump rooms. The existing fire protection will provide an acceptable level of fire safety equivalent to that provided by Section III G.2.
6.0 REFERENCES
6.1 Drawings 515566 and 515567 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 SSER 23, June 1984 6.4 Calculation M-824, Combustible Loading 6.5 Drawings 065126 and 065127, Fire protection Information Report, Units 1 and 2 6.6 DCPP Unit 2 - Review of 10 CFR 50, Appendix R (Rev. 2) 6.7 SSER 31, April 1985 6.8 NECS File: 131.95, FHARE: 124, Unsealed penetrations through barrier 119 6.9 NECS File: 131.95, FHARE: 25, Nonrated Features in the Units 1 and 2 Centrifugal Charging Pump Rooms (CCP1 and CCP2) 6.10 NECS File: 131.95, FHARE 50, Plaster Block-out Panels in 3-Hour Barriers 6.11 NECS File: 131.95, FHARE 136, Unrated HVAC Duct Penetrations 6.12 Calculation 134-DC, Electrical Appendix R Analysis 6.13 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.14 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.15 Design Change Package C-49819, Installation of Fire Barriers for Tool Room Area in 60 ft Elevation Auxiliary Building. 6.16 NECS File: 131.95, FHARE 149, Non-Rated Fire Dampers. 6.17 NECS File: 131.95, FHARE 156, Unsealed Penetrations in Barriers between Fire Zones 3-C and S-2 within Fire Area AB-1. 6.18 NECS File: 131 .95, FHARE 159, Unrated Doors Protected by Local Automatic Sprinklers.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-L 9.5A-325 Revision 21 September 2013 FIRE AREA AB-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This zone is the boric acid and waste evaporator area and is located at the west end of the Auxiliary Building at El. 85 and 100 ft. Note: The boric acid and waste evaporator have been abandoned in place. 1.2 Description This fire zone consists of the bulk of the 85-ft elevation of the Auxiliary Building to the east of access control. The central portion of the zone extends up to El. 115 ft. This zone serves Unit 1 and Unit 2. 1.3 Boundaries Elevation 85 ft NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- 3-hour rated barriers to Fire Areas 3-BB, 3-B-1 and 3-B-2, to Fire Zones 3-P-3, NC 3-M, NC S-2 and S-3.
- One 1-1/2-hour rated door to each of Zones 3-M NC and S-2 and Area 3-BB.
- Lesser rated penetration seals to Fire Area 3-BB. (Ref. 6.11)
- A 1-1/2-hour-equivalent rated door and exhaust duct penetration without a fire damper in 1-hour pyrocrete walls communicates with concrete exhaust ducts to Zone 3-P-3. NC (Ref. 6.6)
South:
- 3-hour rated barrier to Fire Areas 3-CC, 3-D-1, and 3-D-2, and to Fire Zones 3-V-3, NC 3-N, NC S-2, and S-4.
- One 1-1/2-hour rated door to each of 3-N, NC S-2, and S-4, and to Area 3-CC.
- A 1-1/2-hour-equivalent rated door and exhaust duct penetration without a fire damper in 1-hour pyrocrete walls communicates with concrete exhaust ducts to Zone 3-V-3. NC (Ref. 6.6)
- Lesser rated penetration seals to Area 3-CC. (Ref. 6.11)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-L 9.5A-326 Revision 21 September 2013 East:
- 3-hour rated barrier to Fire Zones S-3, S-4, 3-M, NC and 3-N. NC
- Nonrated wall to Fire Zone 3-A.
West:
- 3-hour rated barrier to Fire Zones S-2, S-3, S-4, 3-M, NC 3-N, NC and 4B.
- 2-hour rated barrier to Fire Area 4-A.
- 1-1/2-hour rated doors communicate to Fire Zones S-3 and S-4.
- Duct penetrations without fire dampers communicate with Fire Areas 4-A and 4-B. (Ref. 6.13)
Floor/Ceiling:
- 3-hour rated barriers to Areas 3-H-1, 3-H-2, 3-I-1 and 3-I-2.
- Two equipment hatches to Fire Areas 3-C NC below and 3-X NC above. Elevation 100 ft North:
- A nonrated barrier to Fire Zone 3-X. NC South:
- A nonrated barrier to Fire Zone 3-X. NC East:
- A nonrated barrier to Fire Zone 3-X. NC West:
- A 3-hour rated barrier to Fire Zone S-2.
Ceiling:
- A nonrated barrier to Fire Zone 3-AA. NC (Note: Electrical and mechanical penetrations through rated fire area boundaries have seals installed which provide a fire rating commensurate with the hazard to which they may be exposed.)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-L 9.5A-327 Revision 21 September 2013 2.0 COMBUSTIBLES
2.1 Floor Area: 7,588 ft2 2.2 In situ Combustible Materials
- Cable insulation
- Lubricants
- Methane
- Alcohol
- Clothing/Rags
- Paper
- Wood (fir)
- Miscellaneous (RP)
- Plastic
- Rubber 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Partial smoke detection DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-L 9.5A-328 Revision 21 September 2013 3.2 Suppression
- Portable fire extinguishers
- Fire hose stations 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Unit 1 Equipment 4.1.1 Auxiliary Feedwater AFW pumps 1-2 and 1-3 may be lost due to a fire in this area. Although AFW pump 1-2 and 1-3 circuits are protected by a fire barrier enclosure, redundant AFW pump 1-1 will remain available to provide AFW to the steam generators. 4.1.2 Chemical and Volume Control System Valve 8104 may be lost due to a fire in this area. Valves FCV-110A and 8471 (manual valve) will remain available to provide boric acid solution to the Chemical and Volume Control System. Charging pump 1-3 and ALOP 1-2 may be lost due to a fire in this area. Charging pump 1-1 and ALOP 1-1 will remain available to provide charging flow. A fire in this area may affect valves LCV-112B, LCV-112C, 8805A and 8805B. The running charging pumps can be tripped from the control room, and charging pump 1-1 restarted after aligning the RWST supply valve and isolating the VCT supply valve. Valves LCV-112B and LCV-112C can be manually closed to isolate the volume control tank while valves 8805A and 8805B can be manually opened to provide water from the RWST to the charging pump suction. Boric acid transfer pumps 1-1 and 1-2 may be lost due to a fire in this area. However, this is acceptable based on the boron inventory available through the RWST. A fire in this area may affect FT-134. Because letdown isolation valves LCV-459, LCV-460, 8149A, 8149B, and 8149C are not affected in this fire area and will remain available to isolate letdown, this diagnostic indication is not required. 4.1.3 Main Steam System Main steam system valves FCV-244, FCV-246, FCV-248, and FCV-250 may be affected by a fire in this area. Valves FCV-760, FCV-761, FCV-762 and FCV-763 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-L 9.5A-329 Revision 21 September 2013 will remain available to close the steam generator blowdown isolation lines in order to control reactor coolant temperature. Therefore, no manual actions are required. 4.1.4 Residual Heat Removal System Control circuitry for RHR pumps 1-1 and 1-2 FCV-641A and AC control cables for FCV-641A and FCV-641B may be damaged by a fire in this area. Prior to starting either RHR Pump 1-1 or 1-2, locally open its respective recirc valve (FCV-641A or FCV-641B) located in fire area 3B1 and 3B2 after opening its associated power supply breaker (52-1G-29 or 52-1H-15) located in SPG and SPH. 4.2 Unit 2 Equipment 4.2.1 Auxiliary Feedwater AFW pumps 2-2 and 2-3 may be lost for a fire in this area. Although AFW pump 2-2 and 2-3 circuits are protected by a fire barrier enclosure, redundant AFW pump 2-1 pump will be available to provide AFW. 4.2.2 Chemical and Volume Control System Valve 8104 may be lost due to a fire in this area. Valves FCV-110A and 8471 (manual valve) will remain available to provide boric acid solution to the Chemical and Volume Control System. Charging pumps 2-2 and 2-3, and ALOP 2-2 may be lost due to a fire in this area. Charging pump 2-1 and ALOP 2-1 remain available to provide charging flow. A fire in this area may affect valves LCV-112B, LCV-112C, 8805A and 8805B. The running charging pumps can be tripped from the control room, and charging pump 2-1 can be restarted after aligning the RWST supply valve and isolating the VCT supply valve. Valves LCV-112B and LCV-112C can be manually closed to isolate the volume control tank while 8805A and 8805B can be manually opened to provide water from the RWST to the charging pump suction. Boric acid transfer pumps 2-1 and 2-2 may be lost due a fire in this area. However, this is acceptable based on the boration capability available through the RWST. A fire in this area may affect circuits associated with, FT-134. Because letdown isolation valves LCV-459, LCV-460, 8149A, 8149B, and 8149C are not affected DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-L 9.5A-330 Revision 21 September 2013 in this fire area and will remain available to isolate letdown, this diagnostic indication is not required. 4.2.3 Main Steam System Main steam system valves FCV-244, FCV-246, FCV-248 and 250 may be affected by a fire in this area. Valves FCV-760, FCV-761, FCV-762 and FCV-763 remain available to close the steam generator blowdown isolation lines in order to control reactor coolant temperature. Therefore, no manual actions are required. 4.2.4 Residual Heat Removal System RHR pumps 2-1 and 2-2 AC power cables for FCV-641A and AC control cables for FCV-641A and FCV-641B may be lost due to a fire in this area. Prior to starting either RHR Pump 2-1 or 2-2, locally open its respective recirc valve (FCV-641A or FCV-641B) located in fire area 3D1 and 3D2 after opening its associated power supply breaker (52-2G-29 or 52-2H-15) located in SPG and SPH.
5.0 CONCLUSION
The following features will adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3 hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Low Fire Severity.
- Partial smoke detection is provided.
- Manual suppression equipment is available.
- Redundant safe shutdown functions are located outside this zone or protective enclosures are provided.
The existing fire protection features provide a level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-L 9.5A-331 Revision 21 September 2013
6.0 REFERENCES
6.1 Drawings 515568 and 515569 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.4 Calculation M-824, Combustible Loading 6.5 Drawings 065126 and 065127, Fire Protection Information Report, Units 1 and 2 6.6 NECS File: 131.95, FHARE 38, Undampered Ventilation Duct and Unrated Door in 1-hour rated Barrier 6.7 Appendix 3 for EP M-10 Unit 1 Fire Protection of Safe Shutdown Equipment 6.8 PG&E Design Change Notice DC1-EA-049070, Unit 1 ThermoLag Replacement 6.9 Calculation 134-DC, Electrical Appendix R Analysis 6.10 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.11 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.12 Not Used. 6.13 SSER - 23
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-S 9.5A-332 Revision 21 September 2013 FIRE AREA AB-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This zone is located at the west end of the auxiliary building located at El. 140 ft.
1.2 Description This zone consists of the hotshop.
1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- A nonrated barrier to zones 3-R NC and S-3. NC
- A nonrated door and a nonrated double door communicate to 3-R. NC South:
- A nonrated barrier to zones 3-W NC and S-4. NC
- A nonrated door and a nonrated double door communicate to zone 3-W. NC East:
- A nonrated barrier to the exterior. NC
- A nonrated roll up door communicates to the exterior. NC West:
- A nonrated barrier to the exterior. NC
- A nonrated roll up door communicates to the exterior. NC
- Two nonrated doors communicate to the exterior. NC Floor:
- An open equipment hatch communicates to zone 3-AA. NC
- A nonrated floor to zone 3-AA. NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-S 9.5A-333 Revision 21 September 2013 Ceiling:
- Nonrated ceiling to the exterior. NC 2.0 COMBUSTIBLES
2.1 Floor Area: 6,608 ft2 2.2 In situ Combustible Materials
- Bulk Cable
- Acetylene
- Alcohol
- Rubber
- Lube Oil
- Clothing/Rags
- Leather
- Paper
- Plastic
- Wood (Fir) 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Flame Detection DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-S 9.5A-334 Revision 21 September 2013 3.2 Suppression
- Portable Fire Extinguishers
- Fire Stations 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Unit 1 4.1.1 Chemical and Volume Control System Boric acid storage tank 1-2 level indication from LT-106 may be lost due to a fire in this area. Borated water from the RWST will remain available. Therefore, BAST level indication is not required. 4.2 Unit 2 4.2.1 Chemical and Volume Control System Boric acid storage tank 2-1 level indication from LT-106 may be lost due to a fire in this area. Borated water from the RWST will remain available. Therefore, BAST level indication is not required.
5.0 CONCLUSION
The following features mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- A trained fire brigade is on-site at all times and is responsible for fire suppression.
- Local fire detection is provided.
- Manual fire suppression equipment is available.
- Redundant components are not affected by a fire in this area. These features are considered adequate to assure that safe shutdown capability will not be compromised from a design basis fire in this zone/area. This area complies with the requirements of 10 CFR 50, Appendix R, Section III.G.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-S 9.5A-335 Revision 21 September 2013
6.0 REFERENCES
6.1 Drawing No. 515571 6.2 DCPP Units 1 and 2 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation No. M-824, Combustible Loading 6.4 Drawings 065126 and 065127, Fire Protection Information Report, Units 1 and 2 6.5 Calculation 134-DC, Electrical Appendix R Analysis 6.6 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-X 9.5A-336 Revision 21 September 2013 FIRE AREA AB-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Zone 3-X is at the 100-ft elevation of the Auxiliary Building and incorporates most of the east end of this elevation. 1.2 Description This fire zone houses Unit 1 and 2 volume control tanks and CVCS demineralizers. This zone is the bulk of the Auxiliary Building at Elevation 100 ft and surrounds Fire Zone 3-L. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- Non-rated barrier to Fire Zone 3-L. NC
- 3-hour rated barrier to Fire Areas 3-BB, 3-B-1, 3-B-2, and 3-Q-1, and Fire Zone S-3 and S-2.
- Unrated structural gap seal to Fire Area 3-BB. (Ref. 6.14)
- Lesser rated penetration seals to Fire Areas 3-BB and 3-Q-1. (Ref. 6.15)
- 3-hour rated double door to Fire Zone 3-Q-1.
- A 1-1/2-hour rated door to Fire Area 3-BB and Fire Zones 3-Q-1 and S-2. (Ref. 6.6.).
- A duct penetration without a fire damp to Fire Area 3-B-2. (Ref. 6.6)
- Unique penetration seals in plaster walls to Area 3-Q-1. (Ref. 6.10) South:
- Non-rated barrier to Fire Zone 3-L. NC
- 3-hour rated barriers to Fire Areas 3-CC, 3-D-1, 3-D-2, and to Fire Zones S-2 and S-4.
- Unrated structural gap seal to Fire Area 3-CC. (Ref. 6.14)
- Lesser rated penetraiton seals to Area 3-CC and 3-T-1. (Ref. 6.15)
- 2-hour rated blockout above door to Fire Area 3-T-1. (Ref. 6.13).
- A 1-1/2-hour rated door to Areas 3-CC and 3-T-1, and to Fire Zone S-2.
- A duct penetration without a damper to Fire Area 3-D-2. (Ref. 6.7)
- 3-hour rated double door to Fire Area 3-T-1.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-X 9.5A-337 Revision 21 September 2013 East:
- 3-hour rated barrier to Fire Areas 3-B-2 and 3-D-2, and to Fire Zones S-3 and S-4.
- A nonrated barrier to Fire Zone 3-A. NC
- Six duct penetrations without fire dampers to Fire Zone 3-A. NC
- Two unrated doors to Fire Zone 3-A. NC West:
- 3-hour rated barrier to Fire Areas 3-B-1, 3-D-1, 5-A-4, 3-B-2, 3-D-2, and 5-B-4, and Fire Zones S-3 and S-4.
- 2 1-1/2-hour rated doors to Fire Zones S-3 and S-4.
- A nonrated barrier to Fire Zone 3-L. NC
- Duct penetrations without dampers to Fire Areas 3-B-1 and 3-D-1. (Refs. 6.6 and 6.7) Floor/Ceiling:
- A nonrated barrier to Zones 3-L NC below and 3-AA NC above.
- 3-hour rated barrier to Fire Areas 3-BB (85-ft elevation) and 3-CC (85-ft elevation).
- 3-hour rated barrier to Fire Zones 3-M NC and 3-N NC below. 2.0 COMBUSTIBLES
2.1 Floor Area: 10,528 ft2 2.2 In situ Combustible Materials
- Cable Insulation
- Wood
- Lube Oil
- Miscellaneous
- Polyethylene
- Plastic
- Rubber DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-X 9.5A-338 Revision 21 September 2013 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Partial detection in the vicinity of boric acid transfer pumps (east of column line T).
3.2 Suppression
- Fire hose stations.
- Partial wet pipe automatic sprinklers for the part of the zone east of column line T, near the boric acid transfer pumps.
- Portable fire extinguishers. 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Unit 1 Equipment 4.1.1 Chemical and Volume Control System Valves 8104 and FCV-110A may be affected by a fire in this area. Valve 8104 can be manually opened to ensure safe shutdown. A fire in this area may affect valves FCV-110B and FCV-111B. These valves can be manually closed if the boric acid tank is used for safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-X 9.5A-339 Revision 21 September 2013 Valves LCV-112B, LCV-112C, 8805A and 8805B may be affected by a fire in this area. The running charging pump can be tripped from the control room to prevent cavitation, and charging pumps 1-1 and 1-2 can be restarted after aligning the RWST supply valve and isolating the VCT supply valve. Valves LCV-112B and LCV-112C can be manually closed to isolate the volume control tank while 8805A and 8805B can be manually opened to provide water from the RWST to the charging pump suction. A fire in this area might result in the spurious closure of charging pump discharge flow control valve FCV-128. This valve can be opened from the control room after switching to manual control. Boric acid transfer pumps 1-1 and 1-2 may be lost due to a fire in this area. However, this is acceptable based on the boron inventory available through the RWST. A fire in this area may affect charging pump 1-3. Redundant charging pumps 1-1 and 1-2 will remain available. A fire in this area may affect the transmitter and circuits associated with charging pump header flow transmitter, FT-128, and pressure transmitter, PT-142. Loss of these instruments will not adversely affect safe shutdown.
A fire in this area may affect circuits associated with letdown flow transmitter, FT-134. Because letdown isolation valves LCV-459, LCV-460, 8149A, 8149B, and 8149C are not affected in this fire area and will remain available to isolate letdown, this diagnostic indication is not required. A fire in this area may affect equipment and circuits associated with VCT level transmitter LT-112. 4.1.2 Main Steam System Main steam system valves FCV-244, FCV-246, FCV-248 and FCV-250 may be affected by a fire in this area. Redundant valves FCV-760, FCV-761, FCV-762 and FCV-763 will remain available to close steam generator blowdown isolation lines in order to control reactor coolant temperature. Thus, no manual actions are required. 4.1.3 Reactor Coolant System A fire in this area may spuriously energize pressurizer heater group 1-1. This heater group can be manually de-energized to ensure safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-X 9.5A-340 Revision 21 September 2013 The control of reactor coolant pumps 1-2 and 1-4 may be lost due to a fire in this area. Operation of the RCPs will not affect safe shutdown. 4.1.4 Residual Heat Removal System RHR pumps 1-1 and 1-2 may be lost due to a fire in this area. Either RHR pump 1-1 or 1-2 can be locally started. A fire in this area may affect the AC control cables for FCV-641A and FCV-641B Prior to starting either RHR Pump 1-1 or 1-2, locally open its respective recirc valve (FCV-641A or FCV-641B) located in 3B1 and 3B2 after opening its associated power supply breaker (52-1G-29 or 52-1H-15) located in SPG and SPH. 4.1.5 Safety Injection System A fire in this area may affect RWST Level Transmitter LT-920. This level transmitter is to credited for diagnosis of spurious operation of equipment that may divert RWST inventory. Spurious operation of equipment that may divert the RWST inventory is not affected in this fire area. 4.2 Unit 2 Equipment 4.2.1 Chemical and Volume Control System Valves 8104 and FCV-110A may be affected by a fire in this area. Valve 8104 can be manually opened to ensure safe shutdown. A fire in this area may affect valves FCV-110B and FCV-111B. These valves can be manually closed if the boric acid tank is used for safe shutdown. Valves LCV-112B, LCV-112C, 8805A and 8805B may be affected by a fire in this area. The running charging pump can be tripped from the control room to prevent cavitation, and charging pumps 2-1 and 2-2 restarted after aligning the RWST supply valve and isolating the VCT supply valve. Valves LCV-112B and LCV-112C can be manually closed to isolate the volume control tank while 8805A and 8805B can be manually opened to provide water from the RWST to the charging pump suction. A fire in this area may affect FT-128, and pressure transmitter, PT-142. Because either charging pump 2-1 or 2-2 is not affected in this area, the loss of these instruments will not adversely affect safe shutdown. A fire in this area may affect circuits FT-134. Because letdown isolation valves LCV-459, LCV-460, 8149A, 8149B, and 8149C are not affected in this fire area DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-X 9.5A-341 Revision 21 September 2013 and will remain available to isolate letdown, this diagnostic indication is not required. Boric acid transfer pumps 2-1 and 2-2 may be lost for a fire in this area. However, this is acceptable based on the boron inventory available through the RWST. A fire in this area may affect charging pump 2-3. Redundant charging pumps 2-1 and 2-2 will remain available. 4.2.2 Main Steam System Main steam system valves FCV-244, FCV-246, FCV-248, and FCV-250 may be affected by a fire in this area. Redundant valves FCV-760, 761, FCV-762, and FCV-763 will remain available to close steam generator blowdown isolation lines in order to control reactor coolant temperature. Thus, no manual actions are required. 4.2.3 Reactor Coolant System A fire in this area may spuriously energize pressurizer heater group 2-1 and de-energize heater group 2-2. Pressurizer heater group 2-1 can be manually de-energized to ensure safe shutdown. Loss of power to heater group 2-2 will not affect safe shutdown. A fire in this area may prevent RCP 2-2 from being secured. Operation of RCP 2-2 will not affect safe shutdown. 4.2.4 Residual Heat Removal System RHR pumps 2-1 and 2-2 may be lost due to a fire in this area. Manual action can be performed to locally start either RHR pump. A fire in this area may affect the AC control cables for FCV-641A and FCV-641B. Prior to starting either RHR Pump 2-1 or 2-2, locally open its respective recirc valve (FCV-641A or FCV-641B) located in fire area 3D1 and 3D2 after opening its associated power supply breaker (52-2G-29 or 52-2H-15) located in SPG and SPH.
4.2.5 Safety Injection System A fire in this area may affect RWST Level Transmitter LT-920. This level transmitter is credited for diagnosis of spurious operation of equipment that may divert RWST inventory. Spurious operation of equipment that may divert the RWST inventory is not affected in this fire area. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-X 9.5A-342 Revision 21 September 2013
5.0 CONCLUSION
A fire in the shielded compartments housing the volume control tank, CVCS safe shutdown Valves 8104 and FCV-110A, and other miscellaneous valves would not result in a breach of the volume control tank or a significant release of radioactivity. Even if a volume control tank rupture were postulated, resulting offsite doses would be well below 10 CFR 100 limits (see Diablo Canyon FSAR Update, Table 15.5-52). The most likely fire in these compartments would be a minor grease fire associated with a valve motor operator. The fire would stay confined to the immediate vicinity of the affected component and would ultimately burn itself out as insufficient combustibles are present in the area to allow any significant propagation. Such a fire does not adversely affect safe shutdown capability. (Ref. 6.8) The RCP seal water injection filters are individually enclosed within radiation barriers along with the other CVCS filters. The radiation barriers enclose each filter on three sides as well as on top and bottom. The only access to the filters is a narrow crawlway behind the filters. The flowpath through the seal water injection filters is one of several possible charging and boration flowpaths that can be used to attain safe shutdown. No combustible materials are located in this area, nor would any material be stored inside such a high radiation area. In the unlikely event of a fire caused by transient combustibles inside an RCP seal water injection filter compartment, the magnitude of any reasonably postulated fire would be insufficient to breach the pressure boundary of the piping or filter housing. Safe shutdown capability cannot be affected by a fire in the vicinity of the seal water injection filters. Exemptions have been requested of, and granted by, the NRC from Appendix R Section III.G.2(a) for undampered duct penetrations from Fire Zone 3-X to Fire Areas 3-B-1 and 3-B-2 in SSER 23 and 3-D-1 and 3-D-2 in SSER 31. The following features will adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3 hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shut down.
- Manual operator action can be performed and/or redundant safe shutdown functions are available outside the fire zone, which assure the ability to safely shut down the plant.
- Partial smoke detection.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-X 9.5A-343 Revision 21 September 2013
- Partial wet pipe automatic sprinkler system. This zone meets the requirements of 10 CFR 50, Appendix R Section III.G. and no exemptions or deviations have been requested.
6.0 REFERENCES
6.1 Drawing No. 515569 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.4 Calculation M-824, Combustible Loading 6.5 Drawings 065126 and 065127, Fire Protection Information Report, Units 1 and 2 6.6 SSER 23, June 1984 6.7 SSER 31, April 1985 6.8 FSAR Update, Table 15.5-52 6.9 Appendix 3 for EP M-10 Unit 1 Fire Protection of Safe Shutdown Equipment 6.10 NECS File: 131.95, FHARE 121, Pipe Penetration Seals through Plaster Walls in the Unit 1 Auxiliary Feedwater Pump Rooms 6.11 Calculation 134-DC, Electrical Appendix R Analysis 6.12 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.13 NECS File: 131.95, FHARE 118, Appendix R Fire Area Boundary Plaster Barriers 6.14 NECS File: 131.95, FHARE 134, "Non-rated Structural Gap Seals in Fire Barriers" 6.15 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 8-B-2 9.5A-344 Revision 21 September 2013 FIRE AREA AB-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This zone is located at the south end of the Auxiliary Building at the 140-ft elevation. 1.2 Description This zone consists of the Auxiliary Building Supply Fan Room.
1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- A 3-hour barrier separates this zone from Zone S-2.
- A 3-hour barrier separates this zone from the exterior, Area 34 NC
- Open louvers to the exterior, Area 34. NC
- A 3-hour barrier separates this zone from 8-C. South:
- Unrated barriers and open louvers separate this zone from the exterior, Area 34. NC.
- A 1-1/2 hour equivalent rated door communicates to the exterior, Area 34. NC East:
- Unrated barriers to the exterior, Area 34. NC
- Open louvers to the exterior, Area 34. NC West:
- Unrated barrier with open louvers to exterior Area 34. NC
- A 3-hour rated barrier separates this zone from Zone 8-C. Floor:
- A 3-hour rated barrier to Zones 3-AA and 6-B-4.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 8-B-2 9.5A-345 Revision 21 September 2013
- Two ventilation openings to 3-AA. (Ref. 6.4) Ceiling:
- A 3-hour rated barrier to Zone 8-B-4.
2.0 COMBUSTIBLES
2.1 Floor Area: 1,737 ft2 2.2 In situ Combustible Materials
- Foam Rubber
- Rubber
- Lube Oil
- Paper
- Plastic 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection is provided.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 8-B-2 9.5A-346 Revision 21 September 2013 3.2 Suppression
- Local automatic sprinkler system (fan room only). 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Chemical and Volume Control System Valve 8104 may be lost due to a fire in this area. Redundant valves FCV-110 and 8471 will be available to provide boric acid solution to the Chemical and Volume Control System. Boric acid storage tank 2-1 and 2-2 level indication from LT-106 and LT-102 may be lost due to a fire in this area. Borated water from the RWST will remain available. Therefore, BAST level indication is not required. A fire in this area may affect valves LCV-112B and 8805A. Redundant valves LCV-112C and 8805B will remain available for safe shutdown. 4.2 Main Steam System The outboard steam generator blowdown isolation valves FCV-160, FCV-244, FCV-157, FCV-246, FCV-154 and FCV-151 may be lost due to a fire in this area. The redundant inboard steam generator blowdown isolation valves FCV-760, FCV-761, FCV-762 and FCV-763 will remain available. A fire in this area may affect RWST Level Transmitter LT-920. Spurious operation of equipment that may divert the RWST inventory is not affected in this fire area.
5.0 CONCLUSION
The following features mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- A trained fire brigade is on-site at all times and is responsible for fire suppression.
- Local (partial) fire detection is provided.
- Local (partial) fire suppression is provided.
- Manual fire suppression equipment is available.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 8-B-2 9.5A-347 Revision 21 September 2013
- Redundant components are available and manual operation can be taken to achieve safe shutdown.
The existing fire protection for this area provides an acceptable level of safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 Drawing No. 515571 6.2 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation No. M-824, Combustible Loading 6.4 PG&E Letter to NRC, Question No. 23 dated 11/13/78 6.5 Drawings 065126 and 065127, Fire Protection Information Report, Units 1 and 2 6.6 Calculation 134-DC, Electrical Appendix R Analysis 6.7 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.8 NECS File 131.95, FHARE 155, Removal of Auxiliary Building Supply Fan Room Exterior Walls from the Fire Protection Program
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE S-3 9.5A-348 Revision 21 September 2013 FIRE AREA AB-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Zone S-3 is a stairwell in the northeastern corner of the Auxiliary Building and runs from El. 64 ft up to El. 140 ft. 1.2 Description This stairwell communicates with Unit 1 Fire Area 3-BB (85 ft) and with Zones 3-C (64 ft), 3-F (73 ft), 3-L, 3-BB, 3-P-3 (85 ft), 3-X (100 ft), 3-Q-2 (104ft), 3-R (115 ft, 140 ft), 3-AA (115 ft), and 3-S (140 ft). 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. Elevation 64 ft North:
- 3-hour rated barrier to below grade. South:
- 3-hour rated barrier to Fire Zone 3-C.
- A 1-1/2-hour rated door to Fire Zone 3-C.
East:
- 3-hour rated barrier to Fire Zone 3-C.
- A 1-1/2-hour rated door to Fire Zone 3-C.
West:
- 3-hour rated barrier to Fire Zone 3-C.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE S-3 9.5A-349 Revision 21 September 2013 Elevation 73 ft North:
- 3-hour rated barrier to Fire Zone 3-F. South:
- 3-hour rated barrier to Fire Zone 3-F.
East:
- 3-hour rated barrier to Fire Zone 3-F.
- A l-l/2-hour rated door to Fire Zone 3-F.
West:
- 3-hour rated barrier to Fire Zone 3-F. Elevation 85 ft North:
- 3-hour rated barrier to below grade.
- A l-l/2-hour rated door to Fire Area 3-BB. (Ref. 6.7)
South:
- 3-hour rated barrier to Fire Zone 3-L. East:
- 3-hour rated barrier to Fire Zones 3-P-3 and 3-L.
- A l-l/2-hour rated door to Fire Zone 3-L. West:
- 3-hour rated barrier to Fire Area 3-BB and Zone 3-L. Elevation 100 ft North:
- 3-hour rated barrier to Fire Zone 3-Q-2.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE S-3 9.5A-350 Revision 21 September 2013 South:
- 3-hour rated barrier to Fire Zone 3-X. East:
- 3-hour rated barrier to Fire Zone 3-X.
- A 1-1/2-hour rated door to Fire Zone 3-X. West:
- 3-hour rated barrier to Fire Zone 3-X.
Elevation 115 ft North:
- 3-hour rated barrier to Fire Zone 3-R.
- A 1-1/2-hour rated door to Fire Zone 3-R. South:
- 3-hour rated barrier to Fire Zone 3-AA.
- A 1-1/2-hour rated door to Fire Zone 3-AA. East:
- 3-hour rated barrier to Fire Zone 3-AA.
West:
- 3-hour rated barrier to Fire Zone 3-AA. Elevation 140 ft North:
- 3-hour rated barrier to Fire Zone 3-R. NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE S-3 9.5A-351 Revision 21 September 2013 South:
- A nonrated barrier to Fire Zone 3-S. NC East:
- 3-hour rated barrier to Fire Zone 3-R. NC
- Open to Fire Zone 3-S. West:
- A nonrated barrier to Fire Zone 3-S. NC 2.0 COMBUSTIBLES
2.1 Floor Area: 162 ft2 2.2 In situ Combustible Materials
- Bulk cable
- Paper
- Plastic 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE S-3 9.5A-352 Revision 21 September 2013 3.0 FIRE PROTECTION 3.1 Detection None
3.2 Suppression
- Fire hose stations available
- Portable fire extinguishers available 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Auxiliary Feedwater AFW pumps 1-2 and 1-3 may be lost due to a fire in this area. AFW pump 1-1 will be available to provide flow to the steam generators.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Low Fire Severity.
- Portable fire extinguishers and fire hose stations are available.
- Redundant safe shutdown functions are located out of the influence of this fire zone.
This area meets the requirements of 10 CFR 50, Appendix R, Section III.G and no exemptions or deviations have been requested for this zone.
6.0 REFERENCES
6.1 Drawing Nos. 515566, 515567, 515568, 515569, 515570, 515571 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation M-824, Combustible Loading 6.4 Drawings 065126 and 065127, Fire Protection Information Report, Units 1 and 2 6.5 Calculation 134-DC, Electrical Appendix R Analysis 6.6 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.7 SSER - 31 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE S-4 9.5A-353 Revision 21 September 2013 FIRE AREA AB-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Zone S-4 is a stairwell in the southeastern corner of the Auxiliary Building and runs from at El. 64 ft up to El. 140 ft. 1.2 Description This stairwell communicates with Unit 2 Fire Area 3-CC (85 ft) and with Fire Zones 3-C (64 ft), 3-G (73 ft), 3-L, 3-V-3, 3-CC (85 ft), 3-X, 3-T-2 (100 ft), 3-W (115 ft), 3-AA (115 ft), and 3-S and 3-W (140 ft). 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. Elevation 64 ft North:
- 3-hour rated barrier to Fire Zone 3-C.
- A 1-1/2-hour rated door to Fire Zone 3-C. South:
- 3-hour rated barrier to below grade.
East:
- 3-hour rated barrier to Fire Zone 3-C.
- A 1-1/2-hour rated door to Fire Zone 3-C.
West:
- 3-hour rated barrier to Fire Zone 3-C.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE S-4 9.5A-354 Revision 21 September 2013 Elevation 73 ft North:
- 3-hour rated barrier to Fire Zone 3-G. South:
- 3-hour rated barrier to Fire Zone 3-G.
East:
- 3-hour rated barrier to Fire Zone 3-G.
- A 1-1/2-hour rated door to Fire Zone 3-G.
West:
- 3-hour rated barrier to Fire Zone 3-G. Elevation 85 ft North:
- 3-hour rated barrier to Fire Zone 3-L. South:
- 3-hour rated barrier to below grade.
- 1-1/2-hour rated door to Fire Area 3-CC. (Ref. 6.7) East:
- 3-hour rated barriers to Fire Zones 3-V-3 and 3-L.
- A 1-1/2-hour rated door to Fire Zone 3-L. West:
- 3-hour rated barriers to Fire Area 3-CC and zone 3-L. Elevation 100 ft North:
- 3-hour rated barrier to Fire Zone 3-X.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE S-4 9.5A-355 Revision 21 September 2013 South:
- 3-hour rated barrier to Fire Zone 3-T-2. East:
- 3-hour rated barrier to Fire Zone 3-X.
- A 1-1/2-hour rated door to Fire Zone 3-X. West:
- 3-hour rated barrier to Fire Zone 3-X.
Elevation 115 ft North:
- 3-hour rated barrier to Fire Zone 3-AA.
- A 1-1/2-hour rated door to Fire Zone 3-AA. South:
- 3-hour rated barrier to Fire Zone 3-W.
- A 1-1/2-hour rated door to Fire Zone 3-W. East:
- 3-hour rated barrier to Fire Zones 3-AA.
West:
- 3-hour rated barrier to Fire Zone 3-AA. Elevation 140 ft North:
- A nonrated barrier to Fire Zone 3-S. NC South:
- 3-hour rated barrier to Fire Zone 3-W. NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE S-4 9.5A-356 Revision 21 September 2013 East:
- 3-hour rated barrier to Fire Zone 3-W. NC
- Open to Fire Zone 3-S.
West:
- A nonrated barrier to Fire Zone 3-S. NC 2.0 COMBUSTIBLES
2.1 Floor Area: 162 ft2 2.2 In situ Combustible Materials
- Paper
- Cable Insulation
- Plastics 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- None DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE S-4 9.5A-357 Revision 21 September 2013 3.2 Suppression
- Fire hose station available
- Portable fire extinguishers available 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Auxiliary Feedwater AFW pumps 2-2 and 2-3 may be lost due to a fire in this area. AFW pump 2-1 will be available to provide AFW to the steam generators. 4.2 Chemical and Volume Control System Boric acid storage tank 2-2 and 2-1 level indication from LT-102 and LT-106 may be lost due to a fire in this area. Borated water from the RWST will remain available. Therefore, BAST level indication is not required. A fire in this area may affect RWST Level Transmitter LT-920. Spurious operation of equipment that may divert the RWST inventory is not affected in this fire area.
5.0 CONCLUSION
The following features adequately mitigate the consequences of a design basis fire and assure the capability to achieve safe shutdown:
- Low Fire Severity.
- Portable fire extinguishers and fire hose stations are available.
- Redundant safe shutdown functions are located out of the influence of this fire zone.
This area meets the requirements of 10 CFR 50, Appendix R, Section III.G, and no exemptions or deviations have been requested for this zone.
6.0 REFERENCES
6.1 Drawing Nos. 515566, 515567, 515568, 515569, 515570, 515571, 515577, 515578 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation M-824, Combustible Loading 6.4 Drawings 065127, Fire Protection Information Report, Unit 2 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE S-4 9.5A-358 Revision 21 September 2013 6.5 Calculation 134-DC, Electrical Appendix R Analysis 6.6 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.7 SSER - 31 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA CR-1 FIRE ZONES 8-A, 8-B-3, 8-B-4 8-C, 8-D, 8-E, 8-F 9.5A-359 Revision 21 September 2013 FIRE AREA CR-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Area CR-1 is the Unit 1 and Unit 2 Control Room Complex. It is located in the west side of the Auxiliary Building at El. 140 ft and 163 ft. 1.2 Description The area encompasses the following zones:
- 1) Fire Zone 8-A, Unit 1 Computer Room
- 2) Fire Zone 8-D, Unit 2 Computer Room
- 3) Fire Zone 8-C, Control Room
- 4) Fire Zone 8-E, Office
- 5) Fire Zone 8-F, Shift Technical Advisor Office
- 6) Fire Zone 8-B-3, Unit 1 Control Room Ventilation Equipment Room
- 7) Fire Zone 8-B-4, Unit 1 Control Room Ventilation Equipment Room
Fire Areas 8-G (Unit 1) and 8-H (Unit 2) are within the Control Room Complex, but are considered separate fire areas. 1.3 Boundaries The boundaries described below are the boundaries of the zones and areas that constitute the perimeter of the Control Room Complex. The interior boundaries between the zones that constitute the Control Room Complex are not addressed. Fire Areas 8-G and 8-H are described in their respective analyses. The adequacy of the interior boundaries is addressed in several evaluations. (Refs. 6.10, 6.26) NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA CR-1 FIRE ZONES 8-A, 8-B-3, 8-B-4 8-C, 8-D, 8-E, 8-F 9.5A-360 Revision 21 September 2013 Elevation 140 ft North:
- 3-hour rated barrier from Zone 8-F to S-1.
- 3-hour rated barrier to the exterior (Fire Area 34) from Zones 8-C and 8-A, and Area 8-G.
- 3-hour rated barrier from Zone 8-C to S-5. South:
- 3-hour rated barrier from Zone 8-C to 8-B-2.
- 3-hour rated barrier to the exterior (Fire Area 34) from Zones 8-C and 8-D, and Area 8-H.
- 3-hour rated barrier form Zone 8-E to S-1. East:
- 3-hour rated barriers to Fire Zones 3-B-1, 3-B-2, S-2 and S-5.
- A 3-hour-equivalent rated door with sprinkler protection to Fire Zone S-5.
- A lesser rated penetration seal to Fire Zone 8-B-4. (Ref. 6.25)
West:
- 3-hour rated barrier from Zone 8-E and Area 8-G to Zone 14-D, from Zone 8-C to Zone S-1, and from Zone 8-F and Area 8-H to Zone 19-D.
- A lesser rated penetration seal from Zone 8-F to Zone S-1. (Ref. 6.25)
- A 3-hour-equivalent rated door with sprinkler protection from Zone 8-E to Zone 14-D.
- A 3/4-hour-equivalent rated door with sprinkler protection from Zone 8-C to Zone S-1. (Ref. 6.4)
- A lesser rated penetration seal from Zone 8-C to Zone S-1. (Ref. 6.25)
Floor/Ceiling:
- 3-hour rated barriers: Floor to Fire Areas 7A and 7B. Ceiling to Fire Areas 8-B-5, 8-B-6, 8-B-7 and 8-B-8.
- Unrated penetrations to Areas 7A and 7B below. (Refs. 6.23 and 6.24)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA CR-1 FIRE ZONES 8-A, 8-B-3, 8-B-4 8-C, 8-D, 8-E, 8-F 9.5A-361 Revision 21 September 2013 Protective
Enclosure:
(for CR-1)
- Ducts and supports in Zones 8-A, 8-C, and 8-D are provided with a 1-hour rated fire resistive covering. (Refs. 6.6, 6.13, 6.14 and 6.20)
(Note: For the interface to Fire Areas 8-G and 8-H, refer to the fire hazard analysis for the respective area. (Ref. 6.12))
Elevation 163 ft (Zones 8-B-3 and 8-B-4) North:
- 3-hour rated barrier except for open louvers to the exterior (Fire Area 34). NC (Ref. 6.4)
South:
- 3-hour rated barrier except for open louvers to the exterior (Fire Area 34). NC (Ref. 6.4)
East:
- 3-hour rated barrier except for open louvers to the exterior (Fire Area 34). NC (Ref. 6.4)
West:
- 3-hour rated barrier except for duct penetrations down to El. 140 ft of Zone 8-C (same fire area).
- Lesser rated penetration seals to Zone 8-C. (Ref. 6.25)
- Zone S-2 is a stairwell (south of 8-B-3 and north of 8-B-4). There is a 1-1/2-hour rated door from 8-B-3 to S-2 and a 3-hour rated door from 8-B-4 to S-2.
- 1-1/2-hour rated door from Fire Zone 8-B-3 to 8-B-4. NC 2.0 COMBUSTIBLES
Fire Zone: 8-A 2.1 Floor Area: 464 ft2 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA CR-1 FIRE ZONES 8-A, 8-B-3, 8-B-4 8-C, 8-D, 8-E, 8-F 9.5A-362 Revision 21 September 2013 2.2 In situ Combustible Materials
- Cable
- Paper
- Wood
- Plastic
- Rubber 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low Fire Zone: 8-B-3 2.1 Floor Area: 1,988 ft2 2.2 In situ Combustible Materials
- Cable
- Oil
- Clothing/Rags
- Paper
- Plastic
- Rubber DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA CR-1 FIRE ZONES 8-A, 8-B-3, 8-B-4 8-C, 8-D, 8-E, 8-F 9.5A-363 Revision 21 September 2013 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low Fire Zone: 8-B-4 2.1 Floor Area: 1,988 ft2 2.2 In situ Combustible Materials
- Cable
- Clothing/Rags
- Lube Oil
- Paper
- Plastic
- Rubber 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA CR-1 FIRE ZONES 8-A, 8-B-3, 8-B-4 8-C, 8-D, 8-E, 8-F 9.5A-364 Revision 21 September 2013
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low Fire Zone: 8-C 2.1 Floor Area: 4,734 ft2 2.2 In situ Combustible Materials
- Cable insulation
- Paper
- Resin
- Plastic
- Combustible vinyl ceiling lighting diffusers
- Carpet
- Ceiling tile
- Filter material
- Wood
- PVC 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA CR-1 FIRE ZONES 8-A, 8-B-3, 8-B-4 8-C, 8-D, 8-E, 8-F 9.5A-365 Revision 21 September 2013 2.4 Fire Severity
- Low Fire Zone: 8-D 2.1 Floor Area: 464 ft2 2.2 In situ Combustible Materials
- Cable
- Paper
- Plastic
- Rubber
- Wood (fir) 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low Fire Zone: 8-E 2.1 Floor Area: 315 ft2 2.2 In situ Combustible Materials
- Clothing/Rags DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA CR-1 FIRE ZONES 8-A, 8-B-3, 8-B-4 8-C, 8-D, 8-E, 8-F 9.5A-366 Revision 21 September 2013
- Paper
- Wood
- Plastic
- Rubber
- Bulk Cable
- Foam Rubber 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low Fire Zone: 8-F 2.1 Floor Area: 390 ft2 2.2 In situ Combustible Materials
- Cable
- Paper
- Wood
- Plastic
- Rubber DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA CR-1 FIRE ZONES 8-A, 8-B-3, 8-B-4 8-C, 8-D, 8-E, 8-F 9.5A-367 Revision 21 September 2013 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection is provided. 3.2 Suppression (Refs. 6.4 and 6.5)
- Wet pipe automatic sprinkler system for Zones 8-B-3, 8-B-4, and 8-E.
- Portable fire extinguishers.
- Fire hose station in the vicinity.
4.0 SAFE SHUTDOWN FUNCTIONS
The only cabinets in the Control Room which contain safety related cabling from redundant electrical circuits are in the operator's control panel and the main control board. These cabinets contain smoke detectors. Nonsafety-related panels (RODFW1 and RODFW2) and safety-related panels (POV1 and POV2) for Units 1 and 2 do not contain smoke detectors. FHARE 93 evaluates acceptability of not installing smoke detectors. (Ref. 6.15)
(Note: A fire in the control room is similar to fire in both areas 7-A and 7-B combined. Both units will require evacuation of the control room with DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA CR-1 FIRE ZONES 8-A, 8-B-3, 8-B-4 8-C, 8-D, 8-E, 8-F 9.5A-368 Revision 21 September 2013 control taken locally at the hot shutdown panel. See fire areas 7-A (Unit 1) and 7-B (Unit 2) for operator actions that are required for this fire area.)
5.0 CONCLUSION
This area does not meet the requirements of 10 CFR 50, Appendix R, Section III.G.3, because it does not have an area-wide automatic fire suppression system installed in an area for which an alternate shutdown capability has been provided.
- A deviation from Section III.G.3 requirements was requested, and granted by the NRC as stated in SSER 23.
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3 hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Alternate equipment remote to this location can be used to achieve safe shutdown.
- Smoke detection is provided.
- Portable fire extinguishers.
- This is a continuously manned area.
- The fire protection features provide an acceptable level of safety equivalent to that achieved by compliance with Section III.G.2.
6.0 REFERENCES
6.1 Drawing No. 515571 6.2 DCPP Unit 1 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.4 SSER 23, June 1984 6.5 SSER 31, April 1985 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA CR-1 FIRE ZONES 8-A, 8-B-3, 8-B-4 8-C, 8-D, 8-E, 8-F 9.5A-369 Revision 21 September 2013 6.6 Calculation Number M-680 - Appendix R Safe Shutdown Equipment List 6.7 Calculation M-824, Combustible Loading 6.8 Drawings 065126 and 065127, Fire protection Information Report, Units 1 and 2 6.9 Deleted in Revision 21. 6.10 NECS File: 131.95, FHARE: 75, 1-hour rated Barrier 6.11 Deleted - Revision 6 6.12 Deleted in Revision 13. 6.13 NECS File: 131.95, FHARE: 15, HVAC Ducts Wrapped in Pyrocrete 6.14 NECS File: 131.95, FHARE: 80, Fire Dampers Installed at Variance with Manufacturers Instructions 6.15 NECS File: 131.95, FHARE: 93, Smoke Detectors in Control Room Cabinets 6.16 DCNs DC1-EE-47591, DC1-EE-47593, and DC1-EE-47594 Provide Transfer Switches at the 4kV Switchgear Panel and Mode Selector Switches at the Hot Shutdown Panel 6.17 DCN DC1-EE-45132, Provides Local Control Capacity for DGs 6.18 DG 1-3 Starting Circuit Power Supply Transfer Switch 6.19 DG 2-2 Starting Circuit Power Supply Transfer Switch 6.20 NECS File: 131.95, FHARE 129, Duct penetrations through common walls associated with fire zones 8-A, 8-D, 8-E, 8-F, 8-G, and 8-H 6.21 Calculation 134-DC, Electrical Appendix R Analysis 6.22 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.23 NECS File: 131.95, FHARE 137, Unrated Penetrations through Unit 1 Control Room Floor (Barrier 458) 6.24 NECS File: 131.95, FHARE 140, Unrated Penetrations through Unit 2 Control Room Floor (Barrier 458) 6.25 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.26 NECS File: 131.95, FHARE 153, Removal of Selected Fire Barriers Internal to Fire Area CR-1 from the Fire Protection Program
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA IS-1 FIRE ZONE 30-A-5 9.5A-370 Revision 21 September 2013 FIRE AREA IS-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Intake structure, El. -2 ft and +18 ft, common (Units 1 and 2) intake structure.
1.2 Description Fire Zone 30-A-5 compress the bulk of the intake structure at El. -2 ft. The intake structure contains functions for both units and is isolated from the power block by over 100 yards. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. Fire Zone 30-A-5 is bounded by a 3-hour rated barrier with the following exceptions:
- Non-rated doors to the exterior. NC
- Open stairways to the exterior. NC
- Non-rated concrete machinery access plugs and other openings to the exterior. NC
- Non-rated steel watertight doors and nonrated penetration seals communicating with Areas 30-A-1, 30-A-2, 30-A-3, and 30-A-4. (Refs. 6.13 and 6.16)
- Nonrated walls between this zone and 30-B NC (at stairs).
- 3-hour rated barriers to Fire Areas 30-A-1, 30-A-2, 30-A-3, and 30-A-4. 2.0 COMBUSTIBLES 2.1 Floor Area: 12,390 ft2 2.2 In situ Combustible Materials
- Alcohol
- Charcoal
- Clothing/Rags
- Polyethylene
- Paper
- Plastic DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA IS-1 FIRE ZONE 30-A-5 9.5A-371 Revision 21 September 2013
- PVC
- Resin
- Rubber
- Oil
- Lube oil (in circ. pumps)
- Cable Insulation 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection at entrance to aux. saltwater pump vaults.
3.2 Suppression
- Heat activated - local application CO2 system for each circulating water pump motor.
- Sprinkler head above junction boxes BJZ114 in Unit 1 and BJZ110 in Unit 2.
- Portable fire extinguishers.
- Hose stations.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA IS-1 FIRE ZONE 30-A-5 9.5A-372 Revision 21 September 2013 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 ASW Pumps and HVAC Circuits for ASW pumps 1-1, 1-2, 2-1 and 2-2, and fans E-101, E-102, E-103 and E-104 may be damaged by a fire in this area. The circuits associated with redundant Unit 1 ASW pumps 1-1/1-2 and associated fans E-103/101, and redundant Unit 2 ASW pumps 2-1/2-2 and associated fans E-104/102 are separated by greater than 20 ft with no intervening combustibles. FHARE 110 evaluates the separation of redundant circuits. Therefore, at least one train of ASW pump and associated exhaust fan circuits for each unit will be available for safe shutdown. (Ref. 6.9) 4.2 ASW Inlet Gates The gate operators for saltwater inlet gates 1-8, 1-9, 2-8, and 2-9 are located in this area. Each gate is normally open. A fire induced hot short within the gate operator local panel may spuriously close the gate if power is available to the gate operator. Therefore, to preclude spurious operation of the gates, the 480 V breaker for each operator is administratively controlled in the open position. 4.3 Emergency Power A fire in this area may result in a loss of power supplies associated with PY17N. Redundant power supply PY16 remains available.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3 hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Local smoke detection (at entrance to ASW pump vaults). (Ref. Section 3.1)
- Local CO2 suppression system for each circ. water pump motor. (Ref. Section 3.2)
- Sprinkler head above junction boxes BJZ114 in Unit 1 and BJZ110 in Unit 2.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA IS-1 FIRE ZONE 30-A-5 9.5A-373 Revision 21 September 2013
- Manual firefighting equipment. (Ref. Section 3.2) * "No Storage of Combustible Materials" is designated around perimeter of ASW pump vaults.
- Redundant train of safe shutdown functions are separated by a horizontal distance of 20 ft with no intervening combustibles, and one train will not be adversely affected by a fire in this zone.
This fire zone meets the requirements of 10 CFR 50, Appendix R, Section III.G, and no deviations are requested.
6.0 REFERENCES
6.1 Drawing No. 515580 6.2 Calculation M-928, "Appendix R Safe Shutdown Analysis" 6.3 Calculation M-824, Combustible Loading 6.4 Drawings 065126 and 065127, Fire Protection Information Report, Units 1 and 2 6.5 Deleted in Revision 13 6.6 Deleted in Revision 13 6.7 Field Change A-16160, Rev. 0 (DCN DC1-EA-47386) Provide 3 Hour Fire Wraps for Applicable Conduits in 30-A-5 6.8 Field Change A-16159, Rev. 0 (DCN DC2-EA-48386) Provide 3 Hour Fire Wraps for Applicable Conduits in 30-A-5 6.9 NECS File 131.95 FHARE 110, "Separation of Redundant ASW Pump and Exhaust Fan Circuits in the Intake Structure" 6.10 DCP M-49261, Add Fire Suppression Sprinkler Head, Units 1 and 2 6.11 SSER 23, June 1984 6.12 SSER 31, April 1985 6.13 FHARE 114, Non-Rated Penetration Seals in the ASW Pump Room Barriers 6.14 Calculation 134-DC, Electrical Appendix R Analysis 6.15 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.16 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-CC 9.5A-374 Revision 21 September 2013 FIRE AREA 3-CC 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This fire area is the Unit 2 Containment Penetration area and is located between Unit 2 Containment Building and Auxiliary Building on El. 85 ft up to 115 ft. 1.2 Description Fire Area 3-CC is the electrical and mechanical penetration area for the containment. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. Elevation 85 ft South:
- 3-hour rated barrier to Containment Building with an 8 inch seismic and vent gap separation. (Ref. 6.5)
- Ventilation louvers without fire dampers that communicate with the exterior. NC (Ref. 6.23) North:
- 3-hour rated barrier to Fire Areas 3-D-1, 3-D-2, 4-B, 4-B-1, 4-B-2, and Zones 3-L and 3-N.
- A 1-1/2-hour rated door to Fire Zone 3-L. (Ref. 6.23)
- A 1-1/2-hour rated door to Fire Zone S-4. (Ref. 6.23)
- Lesser rated penetration seals to 3-D-2, 3-L, and 3-N. (Ref. 6.21) East:
- 3-hour rated barriers to Fire Zone S-4 and Fire Area 3-D-2 and to below grade. NC West:
- 3-hour rated barrier to Fire Zone 19-A and Fire Area 3-D-1.
- 3-hour rated double door to Fire Zone 19-A.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-CC 9.5A-375 Revision 21 September 2013
- 3 1-1/2-hour rated fire dampers to Fire Zone 19-A.
- A penetration to Fire Zone 19-A. (Ref. 6.14)
- Lesser rated penetration seals to Fire Zone 19-A. (Ref. 6.21) Floor:
- 3-hour rated barrier to Fire Zones 3-K-3, 3-D-3, 3-G, and to grade. NC
- Lesser rated penetration seals to Fire Zone 3-K-3, 3-D-3, and 3-I-1. (Refs. 6.21 and 6.23) Ceiling:
- Concrete slab with nonrated penetrations to the 100-ft Elevation of 3-CC. NC
- 3-hour rated barrier to Fire Zone 3-X.
Elevation 100 ft South:
- 3-hour rated barrier to Containment Building with an 8-inch seismic and vent separation. (Ref. 6.5)
- 3-hour rated barrier to Fire Zone 3-W with the exception of the 8-inch seismic gap.
- 3-hour rated barrier with ventilation louvers without fire dampers that communicate with the exterior. NC (Ref. 6.23) North:
- 3-hour rated barrier to Fire Areas 3-D-1, 3-D-2, 5-B-1, 5-B-2, 5-B-3, and 5-B-4, and Fire Zone 3-X.
- Unrated structural gap seal to Fire Zone 3-X. (Ref. 6.20)
- Lesser rated penetration seals to Fire Zone 3-X. (Ref. 6.21)
- A 1-1/2-hour rated door to Fire Zone 3-X. (Ref. 6.23) East:
- 3-hour rated barrier to Fire Zones 3-U, 3-T-2, and 3-W.
- A 1-1/2-hour rated door to Fire Zone 3-T-2. (Ref. 6.23)
- Lesser rated penetration seals to Fire Zone 3-T-2 and 3-U. (Ref. 6.21)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-CC 9.5A-376 Revision 21 September 2013 West:
- 3-hour rated barrier to Fire Zone 19-A.
- 3-hour rated door to Fire Zone 19-A.
Floor/Ceiling:
- Concrete slab with nonrated penetrations. NC (Same Fire Area) Elevation 115 ft South:
- 3-hour rated barrier to containment building with an 8-inch seismic and vent separation. (Ref. 6.5)
- 3-hour rated barrier with ventilation louvers without fire dampers that communicate with the exterior. NC (Ref. 6.23)
- A nonrated barrier to Fire Zone 3-V-2. (Ref. 6.16) North:
- 3-hour rated barrier to Fire Areas 6-B-1, 6-B-2, 6-B-3, and 6-B-4, and Fire Zone 3-AA.
- A 1-1/2-hour rated door to Fire Zone 3-AA. (Ref. 6.23) East:
- 3-hour rated barrier to Fire Zone 3-W.
- A 1-1/2-hour rated door to Fire Zone 3-W. (Ref. 6.23) West:
- 3-hour rated barrier to Fire Zone 19-A.
- Nonrated blowout panels, which communicate with the main steam pipe tunnel, Fire Zone 19-A, that have water spray on the Turbine Building side.
(Refs. 6.23 and 6.10)
- Lesser rated penetration seals to Fire Zone 19-A. (Refs. 6.21 and 6.23)
- A nonrated door to Fire Zone 19-A, with water spray on the Turbine Building side (Latch removed). (Refs. 6.10, 6.12, 6.22 and 6.23)
- Nonrated seal on the main steam line penetration to Fire Zone 19-A. (Ref. 6.15)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-CC 9.5A-377 Revision 21 September 2013 Floor:
- Concrete slab with numerous penetrations. NC Ceiling:
- 3-hour rated barrier. NC
- Unsealed pipe penetrations and a seismic gap communicate with Fire Area 34 (outside roof area) at El. 140 ft. (Ref. 6.23) NC
- Note: Containment electrical assembly is not a tested configuration. (Ref. 6.11) Protective
Enclosures:
- Cables essential for safe shutdown pass through concrete vaults. (One for each vitality) in the northwest corner of the fire area at El. 85 ft. The vault walls extend above 85 ft floor level to form an 8-inch curb. The curb around the vaults eliminates the possibility of combustible fluid leakage into the vaults due to a spill on the floor. The vaults are covered with 3/8 in-thick metal plates. One-foot thick concrete walls provide sufficient separation between redundant cables in the adjacent vaults. As discussed in Section 2 below, due to the negligible fixed combustibles at El. 85 ft and unlikelihood of transient combustibles being present in the area, propagation of fire into the vaults is precluded.
An exemption to the requirements of Appendix R, Section III.G.2 was made based on the existing construction of the vaults which includes the concrete walls, the 3/8-inch checker plate covers, and the curb located around the vaults. (Ref. 6.5)
- At El. 100 ft and 115 ft, partial area smoke detection and area wide automatic suppression are provided. Redundant instrument trains have less than 20-ft separation. Modifications to provide 1-hour fire barriers to "separate" these trains (or exemption requests where justified) have been made. Although 1-hour fire barriers are committed, a barrier which would provide approximately 3 hours of fire penetration was installed. Systems required for safe shutdown either have adequate redundancy available or credit is being taken to manually operate certain valves. Modifications to provide additional smoke detectors at El. 115 ft are incorporated and several penetration boxes are provided with fire barriers. (Refs. 6.8, 6.9 and 6.17)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-CC 9.5A-378 Revision 21 September 2013 2.0 COMBUSTIBLES 2.1 Floor Area: 6,900 ft2 (for each area) 2.2 In situ Combustible Materials ELEVATION: 85 ft 100 ft 115 ft
- Oil
- Cable
- Cable
- Wood
- Grease
- Grease
- Clothing/Rags
- Rubber
- Rubber
- Rubber
- Paper
- Hydrogen
- Paper
- Clothing/Rags
- Neoprene
- PVC
- Lube Oil
- Plastic
- Polyethylene
- Polyethylene
- Plastic
- Oil 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity ELEVATION: 85 ft 100 ft 115 ft Low Low Low 3.0 FIRE PROTECTION
3.1 Detection
- Partial smoke detection at each elevation of this zone. (Ref. 6.5)
(1) El. 85 ft - Post-LOCA only (2) El. 100 ft - At tray only (3) El. 115 ft - At tray and area wide west of column Line L.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-CC 9.5A-379 Revision 21 September 2013 3.2 Suppression
- Wet pipe automatic sprinkler protection throughout El. 100 and 115 ft.
- A closed head sprinkler to spray the blowout panels and adjacent door (115 ft).
- Portable fire extinguishers.
- Fire hose stations.
4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Fire Zone 3CC-85 ft 4.1.1 Auxiliary Feedwater A fire in this area may affect LCV-106, LCV-107, LCV-110 and LCV-111. Redundant valves LCV-113 and LCV-115 will remain available to provide AFW flow to steam generators 2-3 and 2-4. 4.1.2 Component Cooling Water A fire in this area may spuriously close FCV-364 and FCV-365. These valves can be manually opened in order to provide CCW to the RHR heat exchangers. A fire in this area may affect circuits associated with CCW flow transmitter for Header C (FT-69). Flow through CCW Header C is not credited in this fire area. Therefore, loss of flow indication will not affect safe shutdown 4.1.3 Containment Spray Containment spray pump 2-2 may spuriously operate due to a fire in this area. Since valve 9001B will remain closed, safe shutdown is not affected. 4.1.4 Chemical and Volume Control System A fire in this area may affect valves 8108 and HCV-142. Redundant valves 8107, or 8145 and 8148 can be closed to isolate auxiliary spray. If control of valves 8108 and HCV-142 is lost, the charging injection flowpath will remain available. The PORVs can be used for pressure reduction. Since redundant components will remain available, safe shutdown is not affected. A fire in this area may affect circuits associated with charging pump header flow transmitter, FT-128, and pressure transmitter, PT-142. Loss of charging pump header flow and pressure indication will not affect safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-CC 9.5A-380 Revision 21 September 2013 A fire in this area may affect circuits associated with letdown flow transmitter, FT-134. Operator manual actions are credited to isolate the letdown flowpath. This instrument will not be available for diagnosis of loss of letdown flow. Valves LCV-112B and LCV-112C may spuriously close or become nonfunctional due to a fire in this area. Spurious closure of these valves could cavitate the running charging pump. Two other redundant charging pumps would remain available for safe shutdown. They can be started after a suction path is aligned and the VCT isolated. Valves 8805A and 8805B can be opened to provide water from the RWST to the charging pump suction. If necessary, valves LCV-112B and LCV-112C can be manually closed in order to isolate the volume control tank. A fire in this area may affect equipment and circuits associated with VCT level transmitter LT-112. This instrument is credited for diagnosis of failure of the VCT discharge valves LCV-112B or LCV-112C to automatically close. This indication would not be available to provide diagnostic information. The RWST supply valves are not affected in this area and would be available to align to the charging suction path. 4.1.5 Emergency Power A fire in this area may disable the diesel generator 2-2 automatic transfer circuit. Manual control will remain available in the control room to transfer and load the diesel generator. In addition, offsite power is not affected in this area and will remain available. 4.1.6 Main Steam System A fire in this area may spuriously close FCV-95 which will result in the loss of AFW pump 2-1. Redundant AFW pumps 2-2 and 2-3 will remain available for safe shutdown.
A fire in this area may affect valves FCV-41, FCV-42, FCV-24 and FCV-25. These valves can be manually closed in order to control reactor coolant system temperature while in hot standby. Redundant MSIVs (FCV-43 and FCV-44) and bypass valves (FCV-22 and FCV-23) will remain available to isolate main steam for steam generators 2-2 and 2-3.
A fire in this area may spuriously operate PCV-19 and PCV-20. PCV-19 and PCV-20 may be failed closed by manually isolating instrument air, backup air, and nitrogen and venting the supply line. PCV-21 and PCV-22 will remain available if needed for cooldown purposes via steam generators 2-3 and 2-4.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-CC 9.5A-381 Revision 21 September 2013 A fire in this area may prevent PCV-19 and PCV-20 from opening. PCV-21 and PCV-22 will remain available if needed for cooldown purposes via steam generators 2-3 and 2-4.
A fire in this area may affect pressure indicators PT-514, PT-515, PT-516, PT-524, PT-525 and PT-526, making SG 2-1 and SG 2-2 unavailable. Pressure indicators for SG 2-3 and SG 2-4 are not affected, therefore, safe shutdown is not affected.
4.1.7 Main Feedwater System A fire in this area may affect 4-20mA DC control cables which affect FCV-510. Trip main feedwater pumps from the control room.
4.1.8 Reactor Coolant System RCS pressure indication PT-403 and PT-405 may be lost due to a fire in this area. PT-406 will remain available to provide RCS pressure indication. 4.1.9 Safety Injection System A fire in this area may prevent the operation of valves 8805A and 8805B. Redundant borated water source from the Boric Acid Storage Tank is not affected at this elevation and will remain available. Operator manual action to locally open valves 8460A (or 8460B), 8476 and 8471 will need to be performed to align the BAST supply. In addition, the RWST supply valves can be manually opened to provide RWST water to the charging pumps. 4.2 Fire Zone 3CC-100 ft 4.2.1 Auxiliary Feedwater A fire in this area may affect the following AFW valves: LCV-106, 107, 108, 109, 110, 111, 113, and 115. Steam generators 2-3 and 2-4 are credited for safe shutdown. Therefore, LCV-113 and LCV-115 can be manually operated to regulate the flow of auxiliary feedwater to the steam generator 2-3 and 2-4 from AFW Pump 2-3. 4.2.2 Component Cooling Water A fire in this area may spuriously close FCV-357 and isolate CCW flow from RCP thermal barriers. Redundant valve HCV-142 will be available to provide seal injection flow to RCP seals. Therefore, safe shutdown is not affected.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-CC 9.5A-382 Revision 21 September 2013 Valves FCV-364 and FCV-365 may spuriously close due to a fire in this area. Either of these two valves can be manually opened to provide CCW to the RHR heat exchangers. 4.2.3 Containment Spray Containment spray pump 2-2 may spuriously operate due to a fire in this area. However, the corresponding discharge valve, 9001B will not operate. Therefore, the spurious containment spray pump operation has no impact on safe shutdown.
Containment pressure transmitters 934 - 937 could cause a spurious CS actuation signal. Open knife switches and open breakers 52-HG-07 and 52-HH-09 to prevent CS pump operation. 4.2.4 Chemical and Volume Control System A fire in this area may affect valves 8104 and FCV-110A. One of these valves is required open to provide boric acid to the charging pumps. Valve 8104 can be manually opened. Therefore safe shutdown is not affected.
Valves 8107 and 8108 may be affected by a fire in this area. These valves will fail in the desired, open position for auxiliary spray operation (RCS depressurizeation). During hot standby, these valves are required closed to isolate inadvertent auxiliary spray operation. Redundant valves (HCV-142 or 8145 and 8148) are physically separated with existing automatic suppression and partial coverage detection systems in the area. A deviation was approved for this configuration to ensure that a means to isolate auxiliary spray is available for hot standby.
A fire in this area may affect valves 8145, 8148 and HCV-142. Either valves 8145 and 8148 or HCV-142 are required closed in order to isolate auxiliary spray for hot standby. During hot standby, these valves are required closed to isolate inadvertent auxiliary spray operation. Redundant valves (8107 or 8108,) are physically separated with existing automatic suppression and partial coverage detection systems in the area. A deviation was approved for this configuration to ensure that a means to isolate auxiliary spray is available for hot standby.
Valves 8146 and 8147 may be affected by a fire in this area. One of these valves is required open to provide a charging flowpath through the regenerative heat exchanger, and closed during RCS pressure reduction. Since redundant components exist to provide RCS makeup (HCV-142 via the seal injection flowpath). During RCS pressure reduction, these valves can be manually operated. Therefore, safe shutdown is not affected.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-CC 9.5A-383 Revision 21 September 2013 A fire in this area may spuriously open valves 8149A, 8149B, 8149C, LCV-459, and LCV-460. Either valves LCV-459, LCV-460 or valves 8149A, 8149B, and 8149C must be closed for letdown isolation. Operator action can be taken to fail 8149A, 8149B, and 8149C closed. Therefore, safe shutdown is not affected.
A fire in this area may spuriously open valves 8166 and 8167. Redundant valve HCV-123 can be closed for excess letdown isolation. Therefore, safe shutdown will not be affected.
A fire in this area may cause HCV-142 to fail open. This valve is required operational for a fire in this area to provide auxiliary spray isolation and seal injection flow control. Operator action can be taken to control HCV-142 from the Hot Shutdown Panel.
Valves LCV-112B and LCV-112C may be affected by a fire in this area. The running charging pump can be tripped from the control room to prevent cavitation and then restarted when the RWST supply is aligned and the VCT supply is isolated. These valves can be manually closed to isolate the volume control tank. Either valve 8805A or 8805B can be opened to provide water from the RWST to the charging pump suction.
Containment pressure transmitters 934 - 937 could cause a spurious CS actuation signal. Open CS pump feeder breakers to prevent CS pump operation. 4.2.5 Emergency Power A fire in this area may disable the diesel generator 2-2 automatic transfer circuit. Manual control will remain available in the control room to transfer and load the diesel generator. In addition, offsite power is not affected in this area and will remain available for safe shutdown. 4.2.6 Main Steam System A fire in this area may spuriously open FCV-151, 154, 157, 160, 244, 246, 248, 250, 760, 761, 762 and 763. Operator action can be taken to isolate SG Blowdown flowpath.
A fire in this area may prevent closing of FCV-41, FCV-42, FCV-43, and FCV-44, and may spuriously open FCV-24 and FCV-25. These valves can be manually closed to control reactor coolant system temperature.
A fire in this area may spuriously close FCV-95 which would disable AFW pump 2-1. However, redundant AFW pump 2-3 will remain available to provide AFW flow to steam generators 2-3 and 2-4.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-CC 9.5A-384 Revision 21 September 2013 A fire in this area may affect level indication (LT-517 through 547, LT-518 through 548, and LT-519 through 549) for all four steam generators. The pullbox covers for this instrumentation are provided with a fire barrier having an approximate fire rating of 3 hours, although 1 hour is committed. This area is also protected by an automatic sprinkler system and partial-coverage smoke detection at this elevation. A deviation for the partial smoke detection was approved in SSER 31. Therefore, steam generator level indication will remain available.
A fire in this area may affect pressure transmitters for steam generators 2-1 and 2-2. The circuits for these transmitters are exposed and may be lost due to a fire. However, the pullbox covers for steam generators 2-3 and 2-4 are protected by a fire barrier having an approximate fire rating of 3 hours, although 1 hour is committed. This area is also protected by an automatic sprinkler system and partial-coverage smoke detection system at this elevation. A deviation for the partial smoke detection was approved in SSER 31. Therefore, these pressure transmitters will be available during a fire in this area. A fire in this area may prevent valves PCV-19 and PCV-20 from opening. PCV-21 and PCV-22 will remain available for cooldown through steam generators 2-3 and 2-4. 4.2.7 Reactor Coolant System Pressurizer PORVs (PCV-455C, 456, and 474) and blocking valves (8000A, 8000B, and 8000C) may be affected by a fire in this area. The blocking valves fail open but the PORVs can be manually closed using the emergency close switch from the hot shutdown panel to prevent uncontrolled pressure reduction. In addition, automatic suppression and partial-coverage smoke detection is provided at this elevation. A deviation for the partial smoke detection was approved in SSER 31. Redundant auxiliary spray valves will be utilized for RCS depressurization using a cold shutdown repair procedure.
A fire in this area may affect pressurizer level indication (LT-406, LT-459, LT-460, and LT-461). The pullbox covers for LT-459, LT-460, and LT-461 are protected by a fire barrier having an approximate fire rating of 3 hours, although 1 hour is committed, to ensure the availability of pressurizer level indication. LT-406 will not be available for safe shutdown.
RCS pressure indication from PT-403, PT-405 and PT-406 may be lost due to a fire in this area. Only one pressure transmitter is necessary for safe shutdown. The separation between the circuits for PT-405 and PT-403 from the circuits for PT-406 is 25 ft with no intervening combustibles. An exemption was approved based on the partial detection and area wide suppression as documented in SSER 31.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-CC 9.5A-385 Revision 21 September 2013 A fire in this area may affect temperature indication circuits for TE-413A, TE-413B, TE-423A, TE-423B, TE-433A, TE-433B, TE-443A and TE-443B. The conduits for the instrumentation for SG 2-3 (TE-433A and TE-433B) and SG-2-4 (TE-443A and TE-443B) are provided with a fire barrier having an approximate rating of 3-hours, although 1 hour is committed. Therefore, these instruments will remain available following a fire. In addition, automatic suppression and partial-coverage smoke detection is provided at this elevation. A deviation for the partial smoke detection was approved in SSER 31.
The reactor vessel head vent valves 8078A, 8078B, 8078C and 8078D may be spuriously opened by a fire in this area. Operator action can be taken to fail the valves closed. A fire in this area may cause the loss of indication from NE-51 and NE-52. Redundant components NE-31 and NE-32 are located at El. 115 ft and will remain available. In addition, automatic suppression and partial-coverage smoke detection is provided at this elevation. A fire in this area may affect valves PCV-455A and PCV-455B. Since these valves fail in the desired, closed position, safe shutdown is not affected. 4.2.8 Residual Heat Removal System A fire in this area may affect valves 8701 and 8702. These valves are closed with power removed during normal operations and will not spuriously open. Also, these valves can be manually opened for RHR operations. 4.2.9 Safety Injection System A fire in this area may affect valves 8801A and 8801B. Redundant valves 8803A and 8803B can be closed to isolate the diversion flowpath.
A fire in this area may affect accumulator isolation valves 8808A, 8808B, 8808C and 8808D. These valves can be manually closed to ensure safe shutdown. 4.2.10 HVAC HVAC equipment S-46 and E-46 may be lost due to a fire in this area. Redundant HVAC equipment S-45 and E-45 will be available to provide necessary HVAC support. 4.3 Fire Zone 3CC-115 ft 4.3.1 Auxiliary Feedwater A fire in this area may affect valves LCV-108, LCV-109, LCV-113 and LCV-115. Steam generators 2-3 and 2-4 are credited for safe shutdown in this area, and DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-CC 9.5A-386 Revision 21 September 2013 the associated LCVs can be manually operated to regulate auxiliary feedwater flow. 4.3.2 Component Cooling Water A fire in this area may spuriously close valves FCV-364 and FCV-365. Manual action may be necessary to open these valves.
A fire in this area may affect circuits associated with CCW flow transmitter for Header C (FT-69). Flow through CCW Header C will not be affected due to loss of the instrument. Therefore, loss of flow indication will not affect safe shutdown. 4.3.3 Containment Spray Containment spray pump 2-2 may spuriously operate due to a fire in this area. However, the corresponding discharge valve, 9001B will remain closed. Therefore, the spurious containment spray pump operation has no impact on safe shutdown. 4.3.4 Chemical and Volume Control System A fire in this area may affect valves 8104 and FCV-110A. Valve 8104 can be manually opened in order to provide boric acid to the charging pumps.
Valves 8145 and 8148 may be affected by a fire in this area. Redundant valves 8107 and 8108 will remain available to isolate auxiliary spray. Cold shutdown repair will enable valves 8145 and 8148 to be manually operated to provide pressurizer spray capability.
Valves 8146 and 8147 may be affected by a fire in this area. If these valves spuriously close, then the charging injection flowpath can be used. Cold shutdown repair will enable valves 8146 and 8147 to be manually operated to provide pressurizer spray capability.
A fire in this area may spuriously open valves 8149A, 8149B, 8149C, LCV-459 and LCV-460. Operator action can be taken to fail valves 8149A, 8149B, and 8149C closed.
A fire in this area may spuriously open valves 8166, 8167 and close HCV-123. One of these valves is required closed to isolate excess letdown. Since HCV-123 fails closed, safe shutdown will not be affected.
Valve HCV-142 may spuriously open due to a fire in this area. However, safe shutdown is not affected since this valve fails in the desired, open position.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-CC 9.5A-387 Revision 21 September 2013 Valves LCV-112B and LCV-112C may be affected by a fire in this area. The running charging pump can be tripped from the control room to prevent cavitation. A pump can be restarted after alignment of the RWST supply and isolation of the VCT supply valve. These valves can be manually closed in order to isolate the volume control tank. If these valves are closed, then valve 8805A or 8805B must be opened to provide water to the charging pumps from the RWST. 4.3.5 Emergency Power A fire in this area may disable the diesel generator 2-2 automatic transfer circuit. Manual control will remain available in the control room to transfer and load the diesel generator. In addition, offsite power is not affected in this area and will remain available for safe shutdown. 4.3.6 Main Feedwater System A fire in this area may affect MFW valves FCV-510, FCV-520, FCV-530, FCV-540 and bypass valves FCV-1510, FCV-1520, FCV-1530 and FCV-1540. These valves will fail in the desired closed position and will not affect safe shutdown. Main feedwater pumps are tripped from the control room. 4.3.7 Main Steam System A fire in this area may spuriously open valves FCV-151, 154, 157, 160, 244, 246, 760, 761, 762, and 763. Operator action can be taken to isolate the SG blowdown flowpath. A fire in this area may affected valves FCV-43, FCV-44, FCV-22, FCV-23, and FCV-25. Manual action can be taken to close these valves. A fire in this area may spuriously close FCV-95 which will disable AFW pump 2-1. However, AFW pumps 2-2 and 2-3 will remain available. A fire in this area may result in the loss of all but one train of steam generator level instrumentation for all four steam generators. There is at least 35 ft of separation between the circuits for LT-517, 527, 537 and 547 and the circuits for LT-519, 529, 539, and 549. Area-wide detection is not provided so an exemption was taken to the Appendix R requirements as justified in SSER 31. Therefore, at least one train of level indication for all four steam generators will remain available at this elevation. The orientation of all four steam generator pressure indication circuits has been determined to be equivalent to the circuit separation and the detection and suppression criteria outlined in Appendix R. SSER 31 justifies this deviation. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-CC 9.5A-388 Revision 21 September 2013 Therefore, steam generator pressure indication will not be lost due to a fire in this area. Valves PCV-19, PCV-20, PCV-21, and PCV-22 may be affected by a fire in this area. Steam generators 2-3 and 2-4 are credited for safe shutdown. PCV-21 and PCV-22 can be manually operated for cooldown through steam generators 2-3 and 2-4. 4.3.8 Reactor Coolant System A fire in this area may affect pressurizer PORVs PCV-455C, PCV-456, and PCV-474 and blocking valves 8000A, 8000B, and 8000C. The PORVs are required to be closed during hot standby to prevent uncontrolled pressure reduction. The PORV circuits are enclosed in a fire barrier having an approximate rating of 3 hours, although 1 hour is committed. Therefore, they can be manually closed by using the emergency close switch at the hot shutdown panel. Heater groups 2-2 and 2-3 may be lost due to a fire in this area. This will not affect safe shutdown since the pressurizer heaters are not necessary to achieve cold shutdown conditions. A fire in this area may affect pressurizer level indication (LT-406, LT-459, LT-460, and LT-461). The conduits for LT-459 and LT-461 are separated by 34 ft with no intervening combustibles. A deviation from the criteria of Appendix R, Section III.G.2 requiring full area detection in combination with area-wide suppression and 20 ft separation was made. SSER 31 documents this deviation. RCS pressure indication from PT-403, PT-405 and PT-406 may be lost due to a fire in this area. Only one pressure transmitter is necessary. There is a 13 ft-8 inch separation between PT-405 and PT-406 with no intervening combustibles. An exemption to the Appendix R requirements was made based on the low in-situ combustibles, the area wide suppression, the partial area detection. (Ref. SSER 31) A fire in this area may affect reactor coolant system temperature indication from TE-413A, TE-413B, TE-423A, TE-423B, TE-433A, TE-433B, TE-443A and TE-443B. A fire barrier with an approximate rating of 3 hours, although 1 hour is committed, is provided for circuits associated with loops 3 and 4 temperature indication. In addition, automatic suppression and partial-coverage smoke detection is provided at this elevation. A deviation to the Appendix R requirements was justified in SSER 31. Therefore, safe shutdown will not be affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-CC 9.5A-389 Revision 21 September 2013 Reactor vessel head vent valves 8078A, 8078B, 8078C, and 8078D may spuriously open due to a fire in this area. Operator action can be taken to fail the valves closed. Therefore, safe shutdown is not affected. A fire in this area may affect NE-31, NE-32 and NE-52. Redundant component NE-51 will remain available to provide indication. A fire in this area may affect valves PCV-455A and PCV-455B. Since these valves fail in the desired, closed position, safe shutdown is not affected. 4.3.9 Residual Heat Removal System A fire in this area may affect valves 8701 and 8702. These valves are closed with their power removed during normal operations and will not spuriously open. Also, these valves can be manually opened for RHR operations. 4.3.10 Safety Injection System Valve 8801B may be lost due to a fire in this area. This valve is not required because redundant valve 8801A will remain available to align charging injection, and redundant valves 8803A and 8803B will remain available to isolate this path during pressure reduction. A fire in this area may affect accumulator isolation valves 8808A, 8808B, 8808C, and 8808D. These valves can be manually operated to ensure safe shutdown. 4.3.11 HVAC One train of required HVAC equipment S-46 and E-46 may be lost due to a fire in this area. Redundant HVAC equipment S-45 and E-45 will be available to provide necessary HVAC support.
5.0 CONCLUSION
This area does not meet the requirements of 10 CFR 50, Appendix R, Section III.G.2. which requires the separation of redundant shutdown divisions by 20 ft, free of intervening combustibles, and the installation of area-wide fire protection and suppression systems.
- A deviation from these requirements was requested and granted in SSER 31. The following features will mitigate the consequences of a design basis fire and assure the ability to achieve safe shutdown:
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-CC 9.5A-390 Revision 21 September 2013
- Deviations to requirements for 3 hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Smoke detection provided for cable tray areas (El. 100 ft and 115 ft).
- Automatic wet pipe sprinkler provided (El. 100 ft and 115 ft).
- Low Fire Severity.
- The physical location and separation of redundant safe shutdown functions; in this zone, minimize the effects of a design basis fire.
The existing fire protection provides an acceptance level of fire safety equipment to that provided by Section III G.2.
6.0 REFERENCES
6.1 Drawings Numbers: 515568, 515577, 515569, 515578, 515570 6.2 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation M-824, Combustible Loading 6.4 Drawings 065126 and 065127, Fire Protection Information Report, Units 1 and 2 6.5 SSER 31, April 1985 6.6 DCN DC2-EC-6497, Provide 3 Hour Barrier of CCW Piping Penetration Area 6.7 DCN DC2-EC-8115, Provide Ventilation and Fire Barriers in Alcove of Elevation 85 ft 6.8 DCN DC2-EE-14771, Provide Additional Smoke Detectors (Elev. 115' West of Column Line 2) 6.9 DCN DC2-EA-22612, Provide 1-Hour Barrier for Conduits and Pullboxes 6.10 DCN DC2-EM-26455, Provide Water Spray for Opening Created by Steam Blowout Panels at Elev. 115 ft 6.11 Fire Review Questions, Question No. 5 6.12 DCN DC2-EA-22607, Remove Latch on Door 364-2 for HELB Considerations 6.13 Appendix 3 For EP M-10 Unit 2 Fire Protection of Safe Shutdown Equipment 6.14 NECS File: 131.95, FHARE: 12, Winch Cable Penetrations For Post LOCA Sampling Room Shield Wall 6.15 NECS File: 131.95, FHARE: 13, Unique Blockout Penetration Seal Through Barrier Between The Unit 2 Turbine/Containment Penetration Areas DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-CC 9.5A-391 Revision 21 September 2013 6.16 NECS File: 131.95, FHARE: 91, "Nonrated Barrier Between Fire Area/Zone 3BB (3CC) and 3-P-2 (3-V-2)" 6.17 PG&E Design Change Notice DC2-EA-050070, Unit 2 ThermoLag Replacement 6.18 Calculation 134-DC, Electrical Appendix R Analysis 6.19 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.20 NECS File: 131.95, FHARE 134, "Non-rated Structural Gap Seals in Fire Barriers" 6.21 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.22 NECS File: 131.95, FHARE 159, Unrated Doors Protected by Local Automatic Sprinklers. 6.23 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-D-1 9.5A-392 Revision 21 September 2013 FIRE AREA 3-D-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This fire area is located at the southern end of the Unit 2 Auxiliary Building and occupies El. 54 ft through 115 ft. 1.2 Description The area contains residual heat removal pump 2-1 and RHR heat exchanger 2-1. The area extends upward to El. 115 ft to encompass the vertical heat exchanger shaft. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. South:
- 3-hour rated barrier separates this area from Containment (Elevation 54 ft and 64 ft), NC Zone 3-D-3 (Elevation 73 ft), and Area 3-CC at higher elevations.
- Lesser rated penetration seal to Zone 3-D-3. (Ref. 6.14) North:
- 3-hour rated barrier separates this area from Zone 3-C (El. 54 ft and 64 ft), Area 3-I-1 (El. 73 ft), NC Zone 3-L and Area 4-B (El. 85 ft) and Zone 3-X and Area 5-B-4 (El. 100 ft).
- Overflow opening communicates to Zone 3-C (El. 54 ft). (Ref. 6.16)
- Ventilation opening without a fire damper communicates to area 3-I-1 (El. 73 ft). (Ref. 6.16)
East:
- 3-hour rated barrier separates this area from Zone 3-D-3 (El. 54 ft and 64 ft), Areas 3-I-1 (El. 73 ft), NC 3-CC (El. 85 ft) and Zone 3-X (El. 100 ft).
- A 1-1/2-hour rated door communicates to Zone 3-D-3 (El. 64 ft). (Ref. 6.16)
- Duct penetration without a fire damper penetrates to Zone 3-D-3 (El. 64 ft). (Ref. 6.16)
- A 3-hour-equivalent rated double door with a monorail cutout and water spray protection communicates to Zone 3-D-3 (El. 64 ft). (Ref. 6.15 and 6.16)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-D-1 9.5A-393 Revision 21 September 2013
- An open doorway with a security grate and nonrated penetrations to area 3-I-1 (El. 73 ft). (Ref. 6.16)
- Duct penetration without a fire damper penetrates to Zone 3-X (El. 100 ft). (Ref. 6.16)
- A 2-hour rated plaster blockout panel communicates to Zone 3-D-3. (Ref. 6.11 and 6.16) West:
- 3-hour rated barrier separates this area from below grade (El. 54 ft and 64 ft) and Zone 3-C (El. 64 ft), NC Zone 3-K-3 (El. 73 ft), and Area 4-B (El. 85 ft) and 5-B-4 (El. 100 ft).
- Duct penetration with no fire damper penetrates to Zone 3-C (El. 64 ft). (Ref. 6.16), however, this duct is protected by a 3-hour rated barrier in Fire Zone 3-C. This duct enclosure was installed to prevent a fire in the Tool Room (Fire Zone 3-C) from propagating into Fire Area 3-D-1.
Ceiling:
- 3-hour rated barrier with a concrete equipment hatch communicating to Zone 3-AA (El. 115 ft). (Above) (Refs. 6.9, 6.10 and 6.16) Floor:
- 3-hour rated barrier to grade. NC 2.0 COMBUSTIBLES
2.1 Floor Area: 706 ft2 2.2 In situ Combustible Materials
- Grease
- Oil
- Miscellaneous
- Clothing/Rags 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-D-1 9.5A-394 Revision 21 September 2013
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Partial smoke detection over the RHR pump and at the top of the heat exchanger shaft. (Ref. 6.7) 3.2 Suppression
- Water spray system for double door at El. 64 ft, on the 3-D-3 side of the door only. (Ref. 6.3)
- Fire hose stations.
- Portable fire extinguishers. 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Residual Heat Removal System RHR pump 2-1 may be lost for a fire in this area. RHR pump 2-2 will be available to provide the RHR function. A fire in this area may affect AC power and DC control cables that could result in loss of power and control of FCV-641A. Since the redundant train is available (RHR Pp 2-2 and FCV-641B), this will not affect safe shutdown.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-D-1 9.5A-395 Revision 21 September 2013
- Safe shutdown will not be affected by the loss of safe shutdown functions in this zone due to the availability of redundant equipment.
- Low fire severity.
- Smoke detection provided over the RHR pump and RHR heat exchanger.
- Manual fire fighting equipment is available for use.
The existing fire protection features provide a level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.2.
6.0 REFERENCES
6.1 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.2 Drawing Nos. 515566, 515567, 515568, 515569 6.3 SSER 31, April 1985 6.4 Calculation M-824, Combustible Loading 6.5 Drawings 065126 and 065127, Fire Protection Information Report, Units 1 and 2 6.6 SSER 23, June 1984 6.7 NECS File: 131.95, FHARE: 21, Evaluation of Partial Smoke Detector Coverage 6.8 Deleted in Revision 13 6.9 NECS File: 131.95, FHARE 14, Concrete Equipment Hatches 6.10 PLC Report: Structural Steel Analysis for Diablo Canyon, Rev. 2 (7/08/86) 6.11 NECS File: 131.95, FHARE 50, Plaster Block-out Panels in 3-Hour Barriers 6.12 Calculation 134-DC, Electrical Appendix R Analysis 6.13 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.14 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.15 NECS File: 131 .95, FHARE 159, Unrated Doors Protected by Local Automatic Sprinklers 6.16 NECS File: 131.95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-D-2 9.5A-396 Revision 21 September 2013 FIRE AREA 3-D-2 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This fire area is located at the southern end of the Unit 2 Auxiliary Building and occupies El. 54 ft through 115 ft. 1.2 Description This area contains residual heat removal pump 2-2 and RHR heat exchanger 2-2. The area extends upward to El. 115 ft to encompass the vertical heat exchanger shaft. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. South:
- 3-hour rated barrier separates this area from containment (El. 54 ft and 64 ft) NC Zones 3-D-3 and 3-G (El. 73 ft), and Area 3-CC at higher elevations.
- Lesser rated penetration seal to Zone 3-D-3 and Area 3-CC. (Refs. 6.14 and 6.16) North:
- 3-hour rated barrier separates this area from Zone 3-C (El. 54 ft and 64 ft), Areas 3-I-1, 3-I-2 (El. 73 ft), Zone 3-L (El. 85 ft), and Zone 3-X (El. 100 ft).
- Ventilation penetrations with 3-hour rated fire damper communicate to Area 3-I-2 (El. 73 ft).
- Overflow opening communicates to Zone 3-C (El. 54 ft). (Ref. 6.16)
- Duct penetration with no fire damper penetrates to Zone 3-X. (Ref. 6.16) East:
- 3-hour rated barrier separates this area from below grade (El. 54 ft and 64 ft), NC and Zones 3-C (El. 64 ft), NC 3-G (El. 73 ft), 3-N (El. 85 ft), and 3-X (El. 100 ft).
- 3 duct penetrations with no fire dampers penetrate to Zone 3-C (El. 64 ft). (Ref. 6.16)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-D-2 9.5A-397 Revision 21 September 2013
- 1 duct penetration with no fire damper penetrates to Zone 3-N (El. 85 ft). (Ref. 6.16) West:
- 3-hour rated barrier separates this area from Zone 3-D-3 (El. 54 ft and 64 ft), Area 3-I-1 (El. 73 ft), and Zones 3-CC (El. 85 ft) and 3-X (El. 100 ft).
- 2 duct penetrations without fire dampers penetrate to Zone 3-D-3 (El. 64 ft). (Ref. 6.16)
- A 1-1/2-hour rated door communicates to Zone 3-D-3 (El. 64 ft). (Ref. 6.16)
- A 3-hour-equivalent rated double door with a monorail cutout and water spray protection communicates to Zone 3-D-3 (El. 64 ft). (Refs. 6.15 and 6.16)
- A 3-hour rated door communicates to Area 3-I-1 (El. 73 ft)
- A 2-hour rated plaster blockout panel communicates to Zone 3-D-3. (Refs. 6.11 and 6.16).
Ceiling:
- 3-hour rated barrier with a concrete equipment hatch communicating to Zone 3-AA (El. 115 ft). (Refs. 6.9 and 6.10)
Floor:
- 3-hour rated barrier to grade NC. 2.0 COMBUSTIBLES
2.1 Floor Area: 706 ft2 2.2 In situ Combustible Materials
- Oil
- Grease
- Miscellaneous
- Clothing/Rags 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-D-2 9.5A-398 Revision 21 September 2013
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Partial smoke detection over the RHR pump and at the top of the heat exchanger shaft. (Ref. 6.7) 3.2 Suppression
- Water spray system for double door at El. 64 ft, on the 3-D-3 side of the door only. (Refs. 6.3 and 6.6)
- Fire hose stations.
- Portable fire extinguishers.
4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Residual Heat Removal System RHR pump 2-2 may be lost due to a fire in this area. RHR pump 2-1 will be available to provide the RHR function. A fire in this area may affect AC power and DC control cables that could result in loss of power and control of FCV-641B. Since the redundant train is available (RHR Pp 2-1 and FCV-641A), this will not affect safe shutdown.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-D-2 9.5A-399 Revision 21 September 2013
- Safe shutdown will not be affected by the loss of safe shutdown functions in this zone due to the availability of redundant equipment.
- Low fire severity.
- Smoke detection provided over the RHR pump and heat exchanger.
- Manual fire fighting equipment is available for use.
The existing fire protection features provide a level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.2.
6.0 REFERENCES
6.1 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.2 Drawing Nos. 515566, 515567, 515568, 515569 6.3 SSER 31, April 1985 6.4 Calculation M-824, Combustible Loading 6.5 Drawings 065126 and 065127, Fire Protection Information Report, Units 1 and 2 6.6 SSER 23, June 1984 6.7 NECS File: 131.95, FHARE: 21, Evaluation of Partial Smoke Detector Coverage 6.8 Deleted in Revision 13 6.9 NECS File: 131.95, FHARE 14, Concrete Equipment Hatches 6.10 PLC Report: Structural Steel Analysis for Diablo Canyon, Rev. 2 (7/08/86) 6.11 NECS File: 131.95, FHARE 50, Plaster Block-out Panels in 3-Hour Barriers 6.12 Calculation 134-DC, Electrical Appendix R Analysis 6.13 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.14 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.15 NECS File: 131.95, FHARE 159, Unrated Doors Protected by Local Automatic Sprinklers 6.16 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-I-1 9.5A-400 Revision 21 September 2013 FIRE AREA 3-I-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This fire area is located at the south side of the Auxiliary Building at El. 73 ft.
1.2 Description This area houses the Unit 2 Centrifugal Charging Pumps (2-1 and 2-2).
1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. South:
- 3-hour rated barrier separates this area from Zones 3-D-3 and 3-K-3 Area 3-D-1, NC 3-D-2 and 3-I-2.
- 3-hour rated door communicates to Zone 3-D-3.
- A duct penetration with no fire damper penetrates to Zone 3-D-3. (Refs. 6.6 and 6.14)
- A ventilation opening with no fire damper communicates to Area 3-D-1. (Ref. 6.14)
- 3-hour rated door communicates to Zone 3-K-3.
North:
- 3-hour rated barrier separates this area from Zone 3-C.
- Two duct penetrations without fire dampers penetrates into Zone 3-C. (Refs. 6.7 and 6.14)
- Two 3-hour-equivalent rated double doors with monorail cutouts and water spray protection communicate into Zone 3-C. (Refs. 6.13 and 6.14) There is a 2-hour rated blockout above each door. (Ref. 6.8)
East:
- 3-hour rated barrier separates this area from Zones 3-I-2, 3-D-2 and 3-C.
- Two 3-hour rated doors communicate into areas 3-D-2 and 3-I-2 (there is a 2-hour rated blockout above the door (one into each area). (Ref. 6.8)
- A 3-hour rated door with water spray protection communicates to Zone 3-C. (Ref. 6.13 and 6.14) There is a 2-hour rated blockout above the door. (Ref. 6.8)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-I-1 9.5A-401 Revision 21 September 2013
- Lesser rated penetration seal to Zones 3-C and 3-I-2. (Ref. 6.12) West:
- 3-hour rated barrier separates this area from Zone 3-K-3 and 3-D-1. NC
- An open doorway, with security grate, communicates to Area 3-D-1. NC (Ref. 6.14)
- A 2-hour rated blockout panel communicates to Zone 3-K-3. (Ref. 6.8)
- Nonrated pipe penetrations penetrate into Area 3-D-1. (Ref. 6.14) Floor/Ceiling:
- 3-hour rated barriers: Floor: To areas 3-D-2, 3-D-3, 3-D-1, and Zone 3C. Ceiling: To Fire Area 4B and Zone 3L.
- A duct penetration without a fire damper communicates from the floor into Zone 3-C. (Ref. 6.14), however, this duct is protected by a 3-hour rated barrier in Fire Zone 3-C. This duct enclosure was installed to prevent a fire in Fire Zone 3-C from propagating into Fire Area 3-I-1.
- Lesser rated penetration seal to Area 3-CC. (Ref. 6.12) 2.0 COMBUSTIBLES 2.1 Floor Area: 900 ft2 2.2 In situ Combustible Materials
- Lube Oil
- Plastic
- Cable Insulation
- PVC 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-I-1 9.5A-402 Revision 21 September 2013 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection (partial). (Ref. 6.9) 3.2 Suppression
- Automatic wet pipe sprinkler system (partial). (Ref. 6.9)
- Closed head water spray system protecting 2 double doors in south wall and 1 door in east wall.
- Portable fire extinguishers.
- Hose stations. 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Chemical and Volume Control System Charging pumps 2-1, 2-2, and 2-3 and required ALOPs 2-1 and 2-2 may be lost due to a fire in this area. Charging pump 2-3 can be started locally to provide charging flow.
4.2 Residual Heat Removal System Control circuitry for RHR pumps 2-1 and 2-2 may be damaged by a fire in this area. Both RHR pumps 2-1 and 2-2 can be locally started to provide RHR flow. A fire in this area may affect the AC power cables and DC control cables for FCV-641A and FCV-641B. Prior to starting either RHR Pump 2-1 or 2-2, locally open its respective recirc valve (FCV-641A or FCV-641B) after opening its associated power supply breaker (52-2G-29 or 52-2H-15). 4.3 Safety Injection System SI valves 8803A and 8803B may be affected by a fire in this area. If these valves fail closed, the charging injection flowpath will be isolated. However, flowpaths through the regenerative heat exchanger and the RCP seals will remain available. Redundant valves 8801A and 8801B can be closed during pressure reduction. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-I-1 9.5A-403 Revision 21 September 2013
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3 hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Safe shutdown will not be adversely affected by the loss of the equipment in this area due to the availability of redundant equipment and/or manual actions.
- Smoke detection over charging pumps.
- Automatic wet pipe sprinkler protection over the pumps.
- Manual fire fighting equipment is available for use. The existing fire protection features provide a level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.2 Drawing No. 515567 6.3 SSER 31, April 1985 6.4 Calculation M-824, Combustible Loading 6.5 Drawing 065127, Fire protection Information Report, Unit 2 6.6 SSER 23, June 1984 6.7 NECS File: 131.95, FHARE 25, Nonrated Features in the Units 1 and 2 Centrifugal Charging Pump Rooms (CCP1 and CCP2) 6.8 NECS File: 131.95, FHARE 50, Plaster Block-out Panels in 3-Hour Barriers 6.9 NECS File: 131.95, FHARE 47, Partial Detection and Suppression Protection 6.10 Calculation 134-DC, Electrical Appendix R Analysis 6.11 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.12 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.13 NECS File: 131.95, FHARE 159, Unrated Doors Protected by Local Automatic Sprinklers 6.14 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-I-2 9.5A-404 Revision 21 September 2013 FIRE AREA 3-I-2 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This area is located at the south side of the Auxiliary Building at El. 73 ft. 1.2 Description This area houses the Unit 2 Centrifugal Charging Pump 2-3. 1.3 Boundaries South:
- 3-hour rated barrier separates this area from Zone 3-G and Area 3-D-2.
- Ventilation penetrations with 3-hour rated fire damper communicate to Area 3-D-2.
- A duct penetration with no fire damper penetrates to Zone 3-G. (Ref. 6.12) North:
- 3-hour rated barrier separates this area from Zone 3-C.
- A duct penetration with no fire damper penetrates to Zone 3-C. (Refs. 6.7 and 6.12) East:
- 3-hour rated barrier separates this area from Zone 3-G. An open doorway with security gate communicates to Zone 3-G. (Ref. 6.12)
West:
- 3-hour rated barrier separates this area from Area 3-I-1 and Zone 3-C.
- 3-hour rated fire door communicates to Area 3-I-1. There is a 2-hour rated blockout above the door. (Ref. 6.8)
- Lesser rated penetration seals to Area 3-I-1. (Ref. 6.11)
Floor/Ceiling: Floor: To Fire Zone 3-C and Area 3-D-2.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-I-2 9.5A-405 Revision 21 September 2013 Ceiling: To Fire Zones 3-L and 3-N.
- 3-hour rated barriers except for a duct penetration without a fire damper in the floor (to 3-C below) and ceiling (to 3-N above). (Ref. 6.12) 2.0 COMBUSTIBLES
2.1 Floor Area: 235 ft2 2.2 In situ Combustible Materials
- Polyethylene
- Oil
- PVC 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection 3.2 Suppression
- Automatic wet pipe system
- Portable fire extinguishers
- Fire hose stations DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-I-2 9.5A-406 Revision 21 September 2013 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Chemical and Volume Control System Charging pump 2-3 may be lost for a fire in this area. Redundant charging pumps 2-1 and 2-2 will remain available to provide charging flow.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3 hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Safe shutdown will not be adversely affected by the loss of the equipment in this area due to the availability of redundant equipment and/or manual actions.
- Smoke detection over charging pumps.
- Automatic wet pipe sprinkler protection over the pumps.
- Manual fire fighting equipment is available for use. The existing fire protection features provide a level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.2 Drawing No. 515567 6.3 SSER 31, April 1985 6.4 Calculation M-824, Combustible Loading 6.5 Drawing 065127, Fire protection Information Report, Unit 2 6.6 SSER 23, June 1984 6.7 NECS File: 131.95, FHARE 25, Nonrated Features in the Units 1 and 2 Centrifugal Charging Pump Rooms (CCP1 and CCP2) 6.8 NECS File: 131.95, FHARE 50, Plaster Block-out Panels in 3-Hour Barriers 6.9 Calculation 134-DC, Electrical Appendix R Analysis 6.10 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.11 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-I-2 9.5A-407 Revision 21 September 2013 6.12 NECS File: 131.95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-T-1 9.5A-408 Revision 21 September 2013 FIRE AREA 3-T-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location North end of the Unit 2 Fuel Handling Building adjacent to the auxiliary building, El. 100 ft. 1.2 Description This area adjoins Zones 32 and 3-U on the south; 3-A and 3-X on the north; 3-T-2 on the west; and below grade on the east. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. South:
- 3-hour barrier to below grade. NC
- 3-hour rated barrier separates this area from Zone 3-U except for a nonrated concrete shield wall. (Ref. 6.14)
- 3-hour rated barrier separates this area from Zone 32 except for a 1-1/2-hour rated double door in a 2-hour rated plaster barrier. (Refs. 6.8, 6.11 and 6.14)
- Lesser rated penetration seals to Fire Zone 32. (Ref. 6.12) North:
- 3-hour barrier to below grade. NC
- 3-hour rated barrier separates this area from Zone 3-A, except for a 2-hour rated blockout. (Refs. 6.8 and 6.11)
- Lesser rated penetration seals to Zones 3-A and 3-X. (Ref. 6.12)
- 3-hour rated barrier separates this area from Zone 3-X except for 2-hour rated blockout above a 1-1/2-hour rated double door. (Refs. 6.8, 6.11 and 6.14) East:
- 3-hour rated wall to below grade. NC West:
- A 1-hour rated barrier separates this area from Zone 3-T-2 with a 3-hour rated double door. (Ref. 6.13)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-T-1 9.5A-409 Revision 21 September 2013
- A 1-1/2-hour rated damper communicates to Zone 3-T-2. (Refs. 6.7 and 6.14)
- A duct penetration without a fire damper penetrates to Zone 3-T-2. (Ref. 6.14)
- Lesser rated penetration seals to Zone 3-T-2. (Ref. 6.12) Floor/Ceiling:
Floor: To Fire Zone 3-V-3.
Ceiling: To Fire Zone 3-W.
- A duct penetration without a fire damper penetrates to Zone 3-W above. (Ref. 6.14)
- An opening to a ventilation duct routed outside the fuel handling building at El. 140 ft.
2.0 COMBUSTIBLES
2.1 Floor Area: 710 ft2 2.2 In situ Combustible Materials
- Cable Insulation
- Clothing/Rags
- Oil
- Grease
- Polyethylene
- Plastic
- Wood (fir)
- Rubber
- Hydrogen line - this line has a guard pipe and there is an excess flow valve at the source to isolate the line in case of a H2 line break 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-T-1 9.5A-410 Revision 21 September 2013
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Area wide smoke detection 3.2 Suppression
- Area wide automatic wet pipe sprinklers
- Portable fire extinguishers
- Hose stations 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Auxiliary Feedwater AFW pump 2-1 may be affected in this area. AFW pumps 2-2 and 2-3 will remain available for safe shutdown. Manual valves FCV-436 and FCV-437 and and AFW Pump 2-1 suction valve (2-121) are located in Fire Area 3-T-1. A fire will not damage the normally closed (2-121 is normally open) manual valves. However, FCV-437 will need to be manually opened and 2-121 will need to be manually closed prior to CST inventory depletion 4.2 Makeup System Level for the condensate storage tank, LT-40 may be lost. Feedwater will be available from the raw water storage reservoir. 4.3 Safety Injection System A fire in this area may affect circuits associated with RWST Level Transmitter LT-920. There are no cables affected in this area that may result in diverting the RWST inventory. Therefore, loss of this instrument will not affect safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 3-T-1 9.5A-411 Revision 21 September 2013
5.0 CONCLUSION
The following fire protection features will adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3 hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Redundant safe shutdown functions are independent of this fire area.
- Low Fire Severity.
- Area-wide smoke detection and automatic suppression are provided.
- Manual fire fighting equipment is available. The existing fire protection features in this area provide an acceptable level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.2.
6.0 REFERENCES
6.1 Drawing No. 515577 6.2 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.3 Calculation M-624, Combustible Loading 6.4 Drawing 065127, Fire protection Information Report, Unit 2 6.5 SSER 31, April 1985 6.6 Deleted in Revision 13 6.7 NECS File: 131.95, FHARE 10, Undampered Ventilation Opening in the Unit 2 Auxiliary Feedwater Pump Rooms 6.8 NECS File: 131.95, FHARE 125, Lesser rated plaster blockouts and penetration seal configurations 6.9 Calculation 134-DC, Electrical Appendix R Analysis 6.10 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.11 NECS File: 131.95, FHARE 118, Appendix R Fire Area Plaster Barriers 6.12 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.13 PG&E Letter DCL-84-329 Dated 10/19/84 6.14 NECS File: 131.95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-B-1, 5-B-2, 5-B-3 9.5A-412 Revision 21 September 2013 FIRE AREAS 5-B-1, 5-B-2, 5-B-3 1.0 PHYSICAL CHARACTERISTICS
1.1 Location These three fire areas are located in the southwest part of the Unit 2 Auxiliary Building, El. 100 ft. 1.2 Description Fire areas 5-B-1, 5-B-2, and 5-B-3 contain the 480 V vital switchgear rooms (F, G, and H Buses, respectively). These areas are situated side-by-side with Fire Area 5-B-2 located in the center. Area 5-B-1 is west of 5-B-2 and Fire Area 5-B-3 is east of 5-B-2. Due to the similarities between these three areas, they have been combined into one section. 1.3 Boundaries 1.3.1 Fire Area 5-B-1 South:
- A 3-hour rated barrier separates this area from Area 3-CC. North:
- A 3-hour rated barrier with a nonrated seismic gap separates this area from Area 5-B-4. (Ref. 6.7)
- A 3-hour rated door communicates to Area 5-B-4.
- A protected duct penetration without a fire damper penetrates to Area 5-B-4. (Ref. 6.5)
- A duct penetration without a fire damper penetrates to Area 5-B-4. (Ref. 6.8)
East:
- A 3-hour rated barrier with a nonrated seismic gap separates this area from Area 5-B-2. (Ref. 6.7)
- A 3-hour rated door communicates to Area 5-B-2.
- A protected duct without a damper penetrates to Area 5-B-2. (Refs.6.5 and 6.6)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-B-1, 5-B-2, 5-B-3 9.5A-413 Revision 21 September 2013 West:
- A 3-hour rated barrier with a nonrated seismic gap separates this area from Area 5-B-4. (Ref. 6.7)
- A 3-hour rated door communicates to Area 5-B-4.
- 3 protected duct penetrations without fire dampers penetrate to Area 5-B-4. (Refs. 6.5 and 6.11)
Floor/Ceiling:
- 3-hour rated barrier: Floor: To Fire Areas 4-S and 4-B-1. Ceiling: To Fire Area 6-B-1.
1.3.2 Fire Area 5-B-2 South:
- A 3-hour rated barrier separates this area from Area 3-CC. North:
- A 3-hour rated barrier with a nonrated seismic gap separates this area from Area 5-B-4. (Ref. 6.7)
- Two 3-hour rated doors communicate to Area 5-B-4.
- A duct penetration with a 1-1/2-hour rated fire damper penetrates to Area 5-B-4. (Refs. 6.5 6.6, and 6.13)
East:
- A 3-hour rated barrier with a nonrated seismic gap separates this area from Area 5-B-3. (Ref. 6.7)
- A protected duct penetration without a damper penetrates to Area 5-B-3. (Ref. 6.5)
- A 3-hour rated door communicates to Area 5-B-3.
West:
- A 3-hour rated barrier with a nonrated seismic gap communicates to Area 5-B-1. (Ref. 6.7)
- A 3-hour rated door communicates to Area 5-B-1.
- A protected duct penetration without a damper penetrates to Area 5-B-1. (Ref. 6.5)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-B-1, 5-B-2, 5-B-3 9.5A-414 Revision 21 September 2013 Floor/Ceiling:
- 3-hour rated barrier: Floor: To Fire Areas 4-B and 4-B-1. Ceiling: To Fire Area 6-B-2.
1.3.3 Fire Area 5-B-3 South:
- A 3-hour rated barrier separates this area from Area 3-CC.
North:
- A 3-hour rated barrier with a nonrated seismic gap separates this area from Area 5-B-4. (Ref. 6.7)
- A 3-hour rated door communicates to Area 5-B-4.
- A duct penetration with a 1-1/2-hour rated fire damper penetrates to Area 5-B-4. (Refs. 6.5 and 6.13)
East:
- A 3-hour rated barrier with a nonrated seismic gap separates this area from Area 5-B-4. (Ref. 6.7)
- A 3-hour rated door communicates to Area 5-B-4.
West:
- A 3-hour rated barrier with a nonrated seismic gap separates this area from Area 5-B-2. (Ref. 6.7)
- A 3-hour rated door communicates to Area 5-B-2.
- A protected duct penetration without a damper penetrates to Area 5-B-2. (Ref. 6.5)
Floor/Ceiling:
- 3-hour rated barrier: Floor: To Fire Areas 4-B and 4-B-2. Ceiling: To Fire Area 6-B-3.
Protective Enclosure (for all three areas):
- 1-hour rated fire resistive covering is provided for HVAC ducts in the fire area. (Ref. 6.5)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-B-1, 5-B-2, 5-B-3 9.5A-415 Revision 21 September 2013 2.0 COMBUSTIBLES (typical for each area) 2.1 Floor Area: 444 ft2 2.2 In situ Combustible Materials
- Cable Insulation
- Plastic 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION (typical for each area) 3.1 Detection
- Smoke detection in each area. 3.2 Suppression
- CO2 hose stations
- Hose stations
- Portable fire extinguishers 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Fire Area 5-B-1 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-B-1, 5-B-2, 5-B-3 9.5A-416 Revision 21 September 2013 4.1.1 Auxiliary Feedwater AFW pump 2-3 may be lost due to a fire in this area. Redundant AFW pump 2-1 will be available to provide AFW flow to steam generators 2-3 and 2-4.
AFW valves LCV-113 and LCV-115 may be affected by a fire in this area. Redundant valves LCV-108 and LCV-109 will remain available to provide AFW flow to steam generators 2-3 and 2-4. 4.1.2 Chemical and Volume Control System CVCS valve 8105 may be affected by a fire in this area. Since the VCT and the RWST will be aligned to the charging pump suction, safe shutdown will not be affected if valve 8105 were to close in the event of a fire.
CVCS valve 8107 may be affected by a fire in this area. Redundant valves 8108, HCV-142, or 8145 and 8148 can be closed to isolate auxiliary spray during hot standby. Two other charging flowpaths can be used if 8107 spuriously closes and disables the regenerative heat exchanger charging flowpath. The PORVs will remain available for pressure reduction. Since valve 8107 has redundant components available, this valve's position will not affect safe shutdown.
Letdown orifice valves 8149A, 8149B and 8149C may be lost due to a fire in this area. Redundant valves LCV-459 and LCV-460 will be available to isolate letdown. Charging pump 2-1 and ALOP 2-1 may be lost due to a fire in this area. Redundant charging pumps 2-2, 2-3 and ALOP 2-2 will be available to provide charging flow.
Boric acid transfer pump 2-1 may be lost due to a fire in this area. Redundant boric acid pump 2-2 will be available for this function.
Volume control tank outlet valve LCV-112B may be affected by a fire in this area. If LCV-112B is lost then valve 8805B can be opened to provide water from the RWST to the charging pump suction. LCV-112C can be closed to isolate the volume control tank.
BAST 2-1 level indication from LT-106 may be affected by a fire in this area. Borated water will be available from the RWST. Therefore, BAST level indication is not required.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-B-1, 5-B-2, 5-B-3 9.5A-417 Revision 21 September 2013 4.1.3 Component Cooling Water CCW pump 2-1 and ALOP 2-1 may be lost due a fire in this area. Redundant CCW pumps and ALOPs 2-2 and 2-3 will be available to provide CCW.
CCW valve FCV-430 may be affected by a fire in this area. If FCV-430 is lost, then CCW heat exchanger 2-1 will be unavailable. However, redundant CCW heat exchanger 2-2 and valve FCV-431 will be available for CCW supply.
CCW valve FCV-750 may be affected by a fire in this area. Since seal injection will remain available, this will provide adequate cooling and FCV-750 will not be required. 4.1.4 Emergency Power A fire in this area may disable the diesel generator 2-1 backup control circuit. The normal control circuit may remain available.
A fire in this area may disable diesel generator 2-3. Diesel generators 2-1 and 2-2 will remain available. Breaker 52HF10 at SHF should be opened to preclude spurious operation of train "F" components.
A fire in this area may disable startup transformer 2-2. Onsite power will remain available from diesel generators 2-1 and 2-2.
All power supplies on the "F" bus may be lost. Redundant trains on the "G" and "H" buses will be available. A fire in this area may affect 480 V power to IY22. The 125 VDC power supply to the UPS will remain available.
A fire in this area may disable dc panel SD23 backup battery charger ED231. Normal battery charger ED232 will remain available. 4.1.5 Main Steam System The following steam generator level and pressure instrumentation may be lost due to a fire in this area: LT-516, LT-526, LT-529, LT-536, LT-539, LT-546, PT-514, PT-524, PT-534 and PT-544. Redundant instrumentation will be available for all four steam generators.
Steam generator 2-1 ten percent atmospheric dump valve PCV-19 may be affected by a fire in this area. Since this valve fails closed which is its desired position, safe shutdown can still be achieved. Redundant dump valves PCV-21 and PCV-22 will be available for cooldown purposes. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-B-1, 5-B-2, 5-B-3 9.5A-418 Revision 21 September 2013 Main Steam System valve FCV-38 may be affected by a fire in this area. This valve can be manually operated in the event of a fire to ensure that AFW PP 2-1 can provide auxiliary feedwater to steam generator 2-3. 4.1.6 Makeup System Condensate storage tank level indication LT-40 may be lost due to a fire in this area. Water from the raw water storage reservoir will be available through FCV-436 to provide auxiliary feedwater. Manual action can be performed to locally open this normally closed manual valve. 4.1.7 Reactor Coolant System Loss of LT-406, LT-459, NE-31, NE-51, PT-406, PT-403, TE-413A, TE-413B, TE-423A and TE-423B will not affect safe shutdown since redundant components are available that are independent of this fire area.
A fire in this area may affect PZR PORV PCV-474 and its block valve 8000A. Circuit damage to PCV-474 due to a fire in this area would cause the valve to fail closed which is the desired safe shutdown position. A redundant PORV will remain available for pressure reduction. 4.1.8 Safety Injection System SI pump 2-1 may spuriously operate due to a fire in this area. Local manual action may be required to defeat this spurious operation. Accumulator isolation valve 8808A may be lost due to a fire in this area. Manual action may be necessary to close valve 8808A.
Valves 8801A, 8803A and 8805A may be lost due to a fire in this area. Safe shutdown is not affected since redundant valves 8801B, 8803B and 8805B are available. 4.1.9 Auxiliary Saltwater System ASW pump 2-1 may be lost due to a fire in this area. Redundant ASW pump 2-2 will be available to provide ASW.
ASW valve FCV-602 may be lost due to a fire in this area. Redundant CCW heat exchanger inlet valve FCV-603 is used in place of FCV-602. Therefore, safe shutdown is not affected.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-B-1, 5-B-2, 5-B-3 9.5A-419 Revision 21 September 2013 4.10 HVAC HVAC equipment E-104, E-45, S-45, S-69 and FCV-5045 may be lost due to a fire in this area. Safe shutdown is not affected because E-104 and S-69 are not necessary for a fire and redundant HVAC equipment (S-46, E-46 and FCV-5046) will be available to provide HVAC support. 4.2 Fire Area 5-B-2 4.2.1 Auxiliary Feedwater AFW valves LCV-106, LCV-107, LCV-108 and LCV-109 may be affected by a fire in this area. Redundant valves LCV-110 and LCV-111 will remain available to regulate AFW flow to steam generators 2-1 and 2-2. 4.2.2 Component Cooling Water CCW pump and ALOP 2-2 may be lost due to a fire in this area. Redundant CCW pumps and ALOPs 2-1 and 2-3 will be available to provide CCW.
CCW valve FCV-431 may be affected by a fire in this area. Redundant valve FCV-430 will remain available to allow use of CCW heat exchanger 1-1.
A fire in this area may affect valve FCV-365. Since this valve fails in the desired open position, safe shutdown is not affected. A fire in this area may spuriously close valve FCV-356 and secure CCW to the RCP thermal barrier. The seal injection flowpath can also be affected in this fire area due to the fire induced spurious closure of FCV-128. The potential for a loss of all seal cooling can occur if the valves in these flowpaths spuriously close simultaneously. A manual action will be taken to open FCV-128 at the Hot Shutdown Panel. The position of FCV-356 will not affect safe shutdown. 4.2.3 Containment Spray A fire in this area may spuriously energize containment spray pump 2-1 and may spuriously open valve 9001A. Operator action can be taken to trip CS Pump 2-1.
Valve 9003A may be affected by a fire in this area. Manual action can be taken to close valve 9003A.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-B-1, 5-B-2, 5-B-3 9.5A-420 Revision 21 September 2013 4.2.4 Chemical and Volume Control System Charging pumps 2-2 and 2-3 and ALOP 2-2 may be lost due to a fire in this area. Redundant charging pump and ALOP 2-1 will be available to provide charging flow.
Boric acid transfer pump 2-2 may be lost for a fire in this area. Redundant boric acid transfer pump 2-1 will be available for this function.
CVCS valve 8106 may be affected by a fire in this area. Since the RWST will be aligned to the charging pump suction, valve 8106 is not necessary during a fire in this area.
CVCS valve 8108 may be affected by a fire in this area. Redundant valve 8107 can be shut to isolate auxiliary spray during hot standby. If 8108 spuriously closes, another charging flowpath can be used. The PORVs will remain available for pressure reduction. Therefore, this valve's position will not have an affect on safe shutdown.
CVCS valves 8104 and FCV-110A may be affected by a fire in this area. Safe shutdown is not affected since FCV-110A fails open and is still able to provide boric acid to the charging pump suction. Manual positioning of valve 8471 will be required if valve FCV-110A is used.
CVCS valves 8146, 8147 and 8148 may be affected by a fire in this area. Safe shutdown is not affected because redundant valves exist to isolate auxiliary spray, provide a charging flowpath and provide for pressure reduction. CVCS valve LCV-112C may be affected by a fire in this area. The running charging pump can be tripped from the control room to prevent cavitation. A pump can be started when the RWST supply is aligned and the VCT supply is isolated. Redundant valve 8805A remains available in order to provide water from the RWST to the charging pump suction. LCV-112B can be closed to isolate the volume control tank.
CVCS valves LCV-459 and LCV-460 may be lost due to a fire in this area. Redundant valves 8149A, 8149B and 8149C will remain available to provide letdown isolation. Therefore, safe shutdown is not affected.
A fire in this area may interrupt power to HCV-142. A fire in this area may also affect DC control cables which may cause HCV-142 and FCV-128 to spuriously close. Spurious closure of HCV-142 will not affect safe shutdown since redundant components exist to isolate auxiliary spray, to provide a charging flowpath, and to provide for pressure reduction. Spurious closure of FCV-128 will DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-B-1, 5-B-2, 5-B-3 9.5A-421 Revision 21 September 2013 isolate RCP seal injection. An operator action can be taken to fail FCV-128 after transferring control to the Hot Shutdown Panel. 4.2.5 Diesel Fuel Oil System Diesel fuel oil pump 0-2 may be lost due to a fire in this area. Redundant diesel fuel oil pump 0-1 remains available. Diesel fuel oil day tank valves LCV-85, LCV-86 and LCV-87 may be lost due to a fire in this area. Redundant valves LCV-88, LCV-89 and LCV-90 remain available. 4.2.6 Emergency Power A fire in this area may disable diesel generator 2-1. Diesel generators 2-2 and 2-3 will remain available for safe shutdown. If power is available to bus SPG, breaker 52HG10 at SHG should be opened to preclude spurious operation of train "G" components.
A fire in this area may disable the diesel generator 2-2 backup control circuit. The normal control circuit will remain available.
A fire in this area may disable startup transformer 2-2. Onsite power will remain available from diesel generators 2-2 and 2-3.
All power supplies on the "G" Bus may be lost due to a fire in this area. These power supplies are not necessary since redundant trains on the "F" and "H" Buses will be available.
A fire in this area may disable SD21 backup battery charger ED221. Normal battery charger ED21 will remain available. 4.2.7 Main Steam System The following instrumentation may be lost due to a fire in this area: LT-519, LT-549, PT-515, PT-525, PT-535 and PT-545. Since redundant trains will be available for each steam generator, safe shutdown will not be affected.
Valve PCV-21 may be affected by a fire in this area. Since this valve fails in its desired position safe shutdown is not affected. Redundant valves PCV-19 and PCV-20 will remain available for cooldown using steam generators 2-1 and 2-2.
Valves FCV-760 and FCV-761 may be lost due to a fire in this area. FCV-760 has redundant valves FCV-154 and FCV-248 while FCV-761 has redundant DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-B-1, 5-B-2, 5-B-3 9.5A-422 Revision 21 September 2013 valves FCV-151 and FCV-250 which will be available for isolation of steam generator blowdown. Therefore, safe shutdown is not affected.
Valve FCV-95 may be lost due to a fire in this area. AFW pump 2-2 will remain available to provide AFW to the steam generators.
Main steam isolation valves FCV-41, FCV-42 and bypass valve FCV-24 may be affected by a fire in this area. These valves can be manually closed during a fire. 4.2.8 Reactor Coolant System The following instrumentation may be lost due to a fire in this area: LT-460, NE-32, TE-433A, TE-433B, TE-443A and TE-443B. All of these components have redundant components that are available for safe shutdown.
Pressurizer PORV PCV-455C and blocking valve 8000B may be affected by a fire in this area. Since PCV-455C fails closed, safe shutdown is not affected. A redundant PORV will remain available for pressure reduction.
A fire in this area may prevent reactor coolant pumps 2-1, 2-2, 2-3, and 2-4 from being tripped. Safe shutdown is not affected if reactor coolant pumps continuously run.
Pressurizer heaters 2-3 and 2-4 may be affected by a fire in this area. Manual actions can be taken to de-energize heater group 2-4 and switch heater group 2-3 to the vital power source. Therefore, safe shutdown will not be affected. 4.2.9 Residual Heat Removal System RHR pump 2-1 and valve 8700A may be lost due to a fire in this area. Redundant RHR pump 2-2 and valve 8700B will be available to provide the RHR function.
RHR valve 8701 may be affected by a fire in this area. This valve is closed with its power removed during normal operations and will not spuriously operate. Also this valve can be manually opened for RHR operations. 4.2.10 Safety Injection System SI valves 8801B, 8803B and 8805B may be lost due to a fire in this area. Redundant valves 8801A, 8803A and 8805A remain available to provide the same functions. Also, the PORVs will be available for pressure reduction. Therefore, safe shutdown is not affected.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-B-1, 5-B-2, 5-B-3 9.5A-423 Revision 21 September 2013 Valve 8804A may be affected by afire in this area. This valve can be manually closed. Therefore, safe shutdown is not affected.
SI valves 8808B and 8808D will not be affected by a fire in this area. These valves can be manually closed. Therefore, safe shutdown is not affected.
A fire in this area may affect valve 8982A. Power to the valve is administratively removed by maintaining a toggle switch in the Control Room in the open position. The valve is normally closed, and spurious opening is not expected to occur. However, an operator action can be taken to open the power breaker to the valve to further preclude spurious operation. Safe shutdown will not be affected. 4.2.11 Auxiliary Saltwater System ASW pump 2-2 may be lost due to a fire in this area. Redundant pump 2-1 will be available to provide the ASW function.
ASW valve FCV-603 may be affected by a fire in this area. Redundant valve FCV-602 remains available, to provide ASW. Thus, no manual actions are required. 4.2.12 HVAC A fire in this area may affect E-102 and S-68. Since these two components are not necessary during a fire, safe shutdown is not affected. 4.3 Fire Area 5-B-3 4.3.1 Auxiliary Feedwater AFW pump 2-2 may be lost due to a fire in this area. Redundant pump 2-3 will be available to provide AFW.
A fire in this area may affect LCV-110 and LCV-111. Redundant valves LCV-113 and LCV-115 will remain available to provide AFW flow to steam generators 2-3 and 2-4. 4.3.2 Chemical and Volume Control System A fire in this area may result in the loss of boric acid storage tank level LT-102. Borated water will be available from the RWST. Therefore, BAST level indication will not be required.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-B-1, 5-B-2, 5-B-3 9.5A-424 Revision 21 September 2013 CVCS valve 8145 may be affected by a fire in this area. This valve will fail closed and does not affect safe shutdown. The PORVs are available, thus no manual actions are required. A fire in this area may affect valve FCV-110A. Safe shutdown is not affected since this valve fails open which is its desired position. Also, valve 8104 will remain available for boric acid transfer.
A fire in this area may affect circuits associated with letdown flow transmitter, FT-134. Letdown isolation valves (LCV-459, LCV-460, 8149A, 8149B and 8149C) are not affected in this area and will remain available to isolate letdown. Loss of this indication will not affect safe shutdown. 4.3.3 Component Cooling Water CCW pump and ALOP 2-3 may be lost due to a fire in this area. Redundant CCW pumps and ALOPs 2-1 and 2-2 will be available to provide CCW.
A fire in this area may spuriously close CCW return valves FCV-356 and FCV-357. Since seal injection will remain available, FCV-356 and FCV-357 will not be required open.
CCW supply valve FCV-355 may spuriously close during a fire in this area. FCV-355 can be manually operated for safe shutdown.
CCW supply valve FCV-364 may be affected by a fire in this area. Safe shutdown will not be affected since this valve fails open which is the desired position. 4.3.4 Containment Spray A fire in this area may affect containment spray pump 2-2 and valve 9001B. Operator action can be taken to trip CS Pump 2-2.
A fire in this area may spuriously open valve 9003B. This valve can be manually closed to ensure safe shutdown. 4.3.5 Diesel Fuel Oil System Diesel fuel oil pump 0-1 may be lost due to a fire in this area. Redundant diesel fuel oil pump 0-2 will remain available.
Diesel fuel oil day tank valves LCV-88, LCV-89 and LCV-90 may be lost due to a fire in this area. Redundant valves LCV-85, LCV-86 and LCV-87 remain available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-B-1, 5-B-2, 5-B-3 9.5A-425 Revision 21 September 2013 4.3.6 Emergency Power Diesel generator 2-2 may be lost due to a fire in this area. Diesel generators 2-1 and 2-3 will remain available for safe shutdown. Manual actions should be taken to prevent the spurious operation of "H" Bus components.
Control power for the diesel generator 2-3 backup control circuit may be lost due to a fire in this area. Power for the normal control circuit will remain available.
A fire in this area may disable startup transformer 2-2. Onsite power will remain available from diesel generators 2-1 and 2-3.
All power supplies on the "H" Bus may be lost due to fire in this area. Redundant trains "G" and "F" will remain available.
DC panel SD21 backup battery charger ED221 may be lost due to a fire in this area. Normal battery charger ED21 will remain available.
A fire in this area may disable dc panel SD22 backup battery charger ED221. Normal battery charger ED22 will remain available. 4.3.7 Main Steam System The following instrumentation may be lost due to a fire: LT-518, LT-528, LT-538, LT-548, PT-526 and PT-536. Safe shutdown is not affected since redundant trains of indication for all four steam generators are available. A fire in this area may interrupt power to PCV-20. A fire in this area may also affect cables that could cause the valve to spuriously operate. Manual action can be taken to isolate the air and fail the ADV closed. Redundant dump valves PCV-21 and PCV-22 will be available for cooldown using steam generators 2-3 and 2-4.
A fire in this area may spuriously close FCV-37. AFW pump 2-3 will remain available to provide auxiliary feedwater to the steam generators.
FCV-762 and FCV-763 may be lost due to a fire in this area. Redundant valves FCV-157 and FCV-246 for FCV-762 and FCV-160, and FCV-244 for FCV-763, will be available for isolation of steam generator blowdown. Therefore, safe shutdown is not affected.
Valves FCV-43 and FCV-44 may be affected by a fire in this area. These valves can be manually closed.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-B-1, 5-B-2, 5-B-3 9.5A-426 Revision 21 September 2013 4.3.8 Reactor Coolant System The following components may be lost due to a fire in this area: LT-461, NE-52 and PT-403. Since redundant trains will be available safe shutdown will not be affected.
PZR PORV PCV-456 and blocking valve 8000C may be affected by a fire in this area. Since PCV-456 fails closed safe shutdown is not affected. A redundant PORV will remain available for safe shutdown.
A fire in this area may spuriously start reactor coolant pumps 2-1, 2-2, 2-3 and 2-4. Safe shutdown is not affected if the RCPs continuously run. CCW to the thermal barrier heat exchanger or seal injection will remain available for RCP seal cooling.
Pressurizer heaters 2-1 and 2-2 may be affected by a fire in this area. Manual actions can be taken to de-energize heater group 2-1 and switch heater group 2-2 to the vital power supply. Therefore, safe shutdown is not affected. 4.3.9 Residual Heat Removal System RHR pump 2-2 and valves 8700B and FCV-641B may be affected by a fire in this area. Since RHR pump 2-1 and valves 8700A and FCV-641A remain available, safe shutdown is not affected.
Valve 8702 may be affected by a fire in this area. This valve is closed with its power removed during normal operations and will not spuriously open. Also, this valve can be manually opened for RHR operations. 4.3.10 Safety Injection System SI pump 2-2 may spuriously operate due to a fire in this area. Local manual action may be required to defeat this spurious operation.
Valve 8808C may be affected by a fire in this area. This valve can be manually closed to ensure safe shutdown.
A fire in this area may affect valve 8982B. Power to the valve is administratively removed by maintaining a toggle switch in the Control Room in the open position. The valve is normally closed, and spurious opening is not expected to occur. However, an operator action can be performed to open the power breaker to the valve to further preclude spurious operation. Therefore, safe shutdown is not affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-B-1, 5-B-2, 5-B-3 9.5A-427 Revision 21 September 2013 4.3.11 Auxiliary Saltwater System ASW valves FCV-495 and FCV-496 may be affected by a fire in this area. Valve FCV-601 will remain available to provide ASW system integrity. 4.3.12 HVAC A fire in this area may affect E-46, S-46, S-67 and FCV-5046. Since S-67 is not necessary and redundant components S-45, E-45 and FCV-5045 remain available, safe shutdown is not affected.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3 hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Automatic smoke detection is provided.
- Manual fire fighting equipment is available for use.
- The loss of safe shutdown functions in each fire area does not affect the redundant train.
The existing fire protection features provide an acceptable level of safety equivalent to that provided by Section III.G.2.
6.0 REFERENCES
6.1 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.2 Drawing No. 515569 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065127, Fire Protection Information Report, Unit 2 6.5 NECS File: 131.95, FHARE: 15, HVAC Duct Wrapped in Pyrocrete 6.6 NECS File: 131.95, FHARE: 80, Fire Dampers installed at Variance with Manufacturers Instructions 6.7 NECS File: 131.95, FHARE: 6, Seismic Gap At Concrete Block Walls 6.8 NECS File: 131.95, FHARE: 73, Undampered Ducts 6.9 Deleted in Revision 14. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 5-B-1, 5-B-2, 5-B-3 9.5A-428 Revision 21 September 2013 6.10 AR A0211784 AE 08, NES Fire Protection's Evaluation of Exposed Structural Steel Anchor Bolts 6.11 Calculation 134-DC, Electrical Appendix R Analysis 6.12 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.13 SSER 31, April 1985 6.14 NECS File: 131.95, FHARE 152, Evaluation of Fire Dampers in 480V Switchgear and Battery Rooms
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 5-B-4 9.5A-429 Revision 21 September 2013 FIRE AREA 5-B-4 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Southwest end of the Auxiliary Building, hot shutdown panel and nonvital 480V switchgear room area, El. 100 ft. 1.2 Description This area houses the hot shutdown panel and 480V switchgear. It occupies the southwest corner of the Auxiliary Building at El. 100 ft. A "No Storage" area sign is posted in the hot shutdown panel area. 1.3 Boundaries South:
- A 3-hour rated barrier separates this area from Areas 3-CC and 3-D-1.
- A 3-hour rated barrier with nonrated seismic gaps separates this area from Areas-5-B-1, 5-B-2, 5-B-3. (Ref. 6.14)
- Four 3-hour rated doors communicate into Areas 5-B-1, 5-B-2, 5-B-3 (one each to Areas 5-B-1 and 5-B-3, and two to 5-B-2).
- Two 1-1/2-hour rated fire dampers communicate to Areas 5-B-2, 5-B-3 (one damper into each area). (Refs. 6.13 and 6.23)
- A protected duct without a fire damper to Fire Area 5-B-1. (Refs. 6.7 and 6.23) North:
- A 3-hour rated barrier separates this area from Area 5-A-4.
- A 3-hour rated barrier with nonrated seismic gap seals separates this area from Zones S-5 and S-1. (Ref. 6.14)
- Two 3-hour rated doors communicate to Area 5-A-4.
- A duct penetration without a fire damper penetrates to Zone S-5. (Ref. 6.23) East:
- A duct penetration without a damper to Fire Area 5-B-1. (Refs. 6.8 and 6.23)
- A 3-hour rated barrier separates this area from Zones 3-X and S-2, and Area 5-B-1.
- Two protected duct penetrations without dampers to Area 5-B-1. (Refs. 6.7 and 6.23)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 5-B-4 9.5A-430 Revision 21 September 2013 West:
- Vent register with a 3-hour rated fire damper communicates with Zone S-1, the duct shaft. (Refs. 6.4, 6.11, and 6.22)
- A 3-hour rated barrier separates this area from Zone 19-A.
- A 3-hour rated barrier and door to Fire Area 5-B-3 and Zone S-1. Floor/Ceiling:
- 3-hour rated barriers: Floor: To Fire Areas 4-B and 4-B-2. Ceiling: To Fire Areas 6-B-1, 6-B-2, 6-B-3, 6-B-4, and 6-B-5
- Nonrated equipment hatch communicates to area 4-B below and Area 6-B-5 above. (Ref. 6.23)
- One duct penetrations to Area 6-B-5 without a fire damper. (Refs. 6.8 and 6.23) Protective
Enclosure:
- 1-hour rated fire resistive covering is provided for several HVAC ducts. (Refs. 6.7 and 6.13)
- Conduit K7438 is provided with a fire resistive wrap with an approximate fire rating of 3 hours, although a 1 hour fire barrier is committed. (Refs. 6.9 and 6.18) 2.0 COMBUSTIBLES 2.1 Floor Area: 2,622 ft2 2.2 In situ Combustible Materials
- Cable insulation
- Rubber
- Paper 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 5-B-4 9.5A-431 Revision 21 September 2013
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION 3.1 Detection
- Smoke detection in the area and inside hot shutdown panel. 3.2 Suppression
- CO2 hose stations
- Portable fire extinguishers 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Auxiliary Feedwater A fire in this area may prevent the operation from the hot shutdown panel of AFW pumps 2-2 and 2-3. Since AFW pumps 2-2 and 2-3 will remain operational from the control room, safe shutdown will not be affected.
Control of valves LCV-106, LCV-107, LCV-108 and LCV-109 from the hot shutdown panel may be affected by a fire in this area. Operation of valves LCV-106 and LCV-107 will remain available from the control room if FCV-95 is not affected by a fire in this area and AFW Pump 2-1 is utilized.
Valves LCV-110, LCV-111, LCV-113 and LCV-115 may be affected by a fire in this area. Manual actions can be taken to ensure operation of these valves when AFW Pumps 2-2 or 2-3 are utilized for safe shutdown.
4.2 Chemical and Volume Control System A fire in this area may prevent the operation of the following components from the hot shutdown panel: valve 8104, boric acid transfer pumps 2-1 and 2-2 and charging pumps 2-1 and 2-2. Since charging pumps 2-1 and 2-2, boric acid transfer pump 2-2 and valve 8104 will remain operational from the control room, safe shutdown will not be affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 5-B-4 9.5A-432 Revision 21 September 2013 Valves 8149A, 8149B and 8149C may be lost due to a fire in this area. Redundant valves LCV-459 and LCV-460 will remain available to isolate letdown.
Valves HCV-142 and FCV-128 may be affected by a fire in this area. These valves can be manually operated to provide auxiliary spray in order to ensure pressure reduction capabilities. Redundant charging flowpaths through the seal injection and charging injection flowpaths will be available.
Valve 8145 may be affected by a fire in this area. During hot standby, valves 8107 and 8108 can be used to isolate auxiliary spray, but during cold shutdown, valve 8148 will be available to allow the use of auxiliary spray. Since redundant components will be available, safe shutdown is not affected.
A fire in this area may affect the transmitter and circuits associated with charging pump header flow transmitter, FT-128, and pressure transmitter, PT-142. Both charging pumps are available in this fire area to provide charging flow. Loss of these instruments will not affect safe shutdown.
A fire in this area may affect circuits associated with letdown flow transmitter, FT-134. Letdown isolation valves LCV-459 and LCV-460 are not affected in this area and will remain available to isolate letdown. Loss of this instrument will not affect safe shutdown.
4.3 Component Cooling Water A fire in this area may prevent the operation of CCW pumps 2-1, 2-2 and 2-3 from the hot shutdown panel. However, operation these pumps will remain available from the control room. Therefore, safe shutdown will not be affected.
Valves FCV-355, FCV-430 and FCV-431 may be affected by a fire in this area. Valves FCV-355 and FCV-430 can be manually operated to ensure safe shutdown.
A fire in this area may affect valve FCV-356. The seal injection flow can also be affected in this area due to fire induced spurious closure of FCV-128. The potential for a loss of all RCP seal cooling can occur if the valves in these flowpaths spuriously close simultaneously. To provide CCW to the RCP thermal barrier heat exchanger, locally open FCV-356 after opening its power breaker.
A fire in this area may affect circuits associated with CCW flow transmitters for Header A (FT-68) and Header B (FT-65). All three CCW pumps will remain available in this area to provide CCW flow to either header. Therefore, loss of these instruments will not affect safe shutdown.
A fire in this area may affect circuits associated with the differential pressure transmitters for CCW Hx 2-1 (PT-5) and CCW Hx 2-2 (PT-6). All three CCW DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 5-B-4 9.5A-433 Revision 21 September 2013 pumps will remain available in this area to provide CCW flow to either header. Therefore, loss of these instruments will not affect safe shutdown.
A fire in this area may affect the circuits associated with the CCW flow transmitter on Header C (FT-69). This instrument is credited to indicate a loss of CCW flow. Loss of this indication will not affect flow to CCW Header C. Therefore, loss of this indicator will not affect safe shutdown. 4.4 Containment Spray A fire in this area may spuriously open valve 9001B. Since containment spray pump 2-2 will remain available, safe shutdown will not be affected with this valve open. 4.5 Diesel Fuel Oil System A fire in this area may affect the Unit 2 power circuits for diesel fuel oil transfer pumps 01 and 02. Offsite power is not affected in this area and would remain available for safe shutdown. However, if onsite power using the diesel generators is utilized, the circuits are protected by a fire barrier having an approximate rating of 3 hours, although 1 hour was committed. Operator action may be required to manually transfer the power supply from Unit 1 to Unit 2.
4.6 Emergency Power A fire in this area may disable diesel generator 2-3 backup control circuit. The normal control circuit will remain available. 4.7 Main Steam System A fire in this area may result in the loss of the following equipment: PT-514, PT-524, PT-534 and PT-544. Since two other trains of pressure indication for each steam generator will remain available, safe shutdown will not be affected.
A fire in this area may result in the loss of FCV-95. Since AFW pumps 2-2 and 2-3 will remain available to provide AFW, FCV-95 is not necessary for safe shutdown.
A fire in this area may affect valves PCV-19, PCV-20, PCV-21 and PCV-22. Operator action may be required to manually open each valve.
4.8 Makeup System Level for the condensate storage tank, LT-40 may be lost due to a fire in this area. Feedwater will be available from the raw water storage reservoir through valves FCV-436 and FCV-437. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 5-B-4 9.5A-434 Revision 21 September 2013 4.9 Reactor Coolant System A fire in this area may affect the following components: LT-459, LT-460, NE-51 and NE-52. Safe shutdown is not affected since redundant components will be available. Pressurizer PORVs PCV-455C, 456 and PCV-474 may be affected by a fire in this area. Since the block valves are available for PORV isolation and auxiliary spray remains available, safe shutdown will not be affected.
A fire in this area may cause reactor coolant pumps 2-1, 2-2, 2-3 and 2-4 to spuriously start. Safe shutdown is not affected if the RCPs continuously run. CCW to the thermal barrier heat exchanger or seal injection will remain available for RCP seal cooling.
Pressurizer heater groups 2-1, 2-2, 2-3 and 2-4 may be affected by a fire in this area. Since these heaters can be manually tripped, safe shutdown will not be affected.
4.10 Residual Heat Removal System RHR pump 2-2 may be lost due to a fire in this area. Redundant RHR pump 2-1 will remain available for safe shutdown.
4.11 Safety Injection System A fire in this area may spuriously open accumulator isolation valve 8808C. Manual action can be taken to close this valve.
Containment sump isolation valve 8982B may be affected by a fire in this area. Power to the valve is administratively removed by maintaining a toggle switch in the Control Room in the open position. The valve is normally closed, and spurious opening is not expected to occur. Therefore, safe shutdown is not affected.
4.12 Auxiliary Saltwater System A fire in this area may prevent the operation of ASW pumps 2-1 and 2-2 from the hot shutdown panel. However, safe shutdown will not be affected since the operation of ASW pump 2-1 and 2-2 from the control room will remain available.
Valves FCV-495 and FCV-496 may be lost due to a fire in this area. Valve FCV-601 will remain closed to provide ASW system integrity.
A fire in this area may spuriously close valves FCV-602 and FCV-603. A deviation was approved in this area for lack of automatic suppression and DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 5-B-4 9.5A-435 Revision 21 September 2013 inadequate separation of redundant valves. Since only ASW pump 2-1 may be available for a fire in this area, FCV-602 must be credited. Manual action can be taken to open valve FCV-602. 4.13 HVAC HVAC equipment E-102, E-45, E-46, S-45 and S-46 may be affected by a fire in this area. Redundant equipment E-104 is available for E-102. The other fans can be lost because portable fans can be used to provide HVAC. (Refs. 6.16 and 6.17)
5.0 CONCLUSION
This area does not meet the technical requirements of 10 CFR 50, Appendix R, Section III.G.3 because area-wide automatic suppression system is not provided.
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3 hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- The loss of safe shutdown functions in this area does not affect safe shutdown due to the availability of redundant functions and/or measures provided to preclude the effects of fire.
- Area wide smoke detection is provided.
- Manual fire fighting equipment is available. The existing fire protection features provide an acceptable level of safety equivalent to that achieved by compliance with Section III.G.2.
6.0 REFERENCES
6.1 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.2 Drawing No. 515569 6.3 DCN-DC2-EE-10913, provides isolator on RPM Tach-Pack 6.4 SSER 31, April 1985 6.5 Calculation M-824, Combustible Loading 6.6 Drawing 065127, Fire Protection Information Report, Unit 2 6.7 NECS File: 131.95, FHARE: 15, HVAC Duct Wrapped in Pyrocrete 6.8 NECS File: 131.95, FHARE: 73, Undampered Ducts DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 5-B-4 9.5A-436 Revision 21 September 2013 6.9 DCN DC2-EA-22612, Fireproof Conduit 6.10 DCN DC2-EE-12765, ASW Pump 2-1 Switch Control 6.11 Deleted in Revision 13 6.12 Appendix 3 for EP M-10 Unit 2 Fire Protection of Safe Shutdown Equipment 6.13 NECS File: 131.95, FHARE: 80, Fire Dampers Installed at Variance with Manufacturers Instructions 6.14 NECS File: 131.95, FHARE: 6, Seismic Gaps At Concrete Block Walls 6.15 Deleted in Revision 14. 6.16 Calculation M-911, Evaluation of Safe Shutdown Equipment During Loss of HVAC 6.17 Calculation M-912, HVAC Interactions for Safe Shutdown 6.18 PG&E Design Change Notice DC2-EA-050070, Unit 2 ThermoLag Replacement 6.19 Calculation 134-DC, Electrical Appendix R Analysis 6.20 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.21 NECS File: 131.95, FHARE 27, Undampered Duct Penetrations in Concrete Lined Shafts 6.22 NECS File: 131.95, FHARE 42, Fire Dampers Installation for Areas 5-A-4 and 5-B-4 6.23 NECS File: 131.95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-B-1, 6-B-2, 6-B-3 9.5A-437 Revision 21 September 2013 FIRE AREAS 6-B-1, 6-B-2, 6-B-3 1.0 PHYSICAL CHARACTERISTICS 1.1 Location Southwest side of the Unit 2 Auxiliary Building. Unit 2 battery, inverter, and dc switchgear rooms, El. 115 ft. 1.2 Description Fire Areas 6-B-1, 6-B-2, and 6-B-3 are separate fire areas, each containing redundant batteries, inverters, and dc switchgear, one train of which is required for safe shutdown. These fire areas are situated side by side, with Fire Area 6-B-2 located between Fire Area 6-B-1 to the west and Fire Area 6-B-3 to the east. Due to similarities between these three areas, they have been combined into one section.
Battery room ventilation is provided by a supply fan and an exhaust fan located in separate fire zones isolated by 25 ft of open space (Fire Zones 8-B-6 and 8-B-8). Either fan provides adequate flow to limit hydrogen concentration well below the explosive concentration. Control room annunciation is provided for loss of battery room ventilation. Additionally, control room annunciation is provided for dc overvoltage which could result in excessive hydrogen generation. Ventilation for the inverter and dc switchgear room is provided by two 100 percent supply fans which also supply ventilation for the 480V vital switchgear and are unrelated to the battery room ventilation. (Ref. 6.7)
The battery rooms are separated from the inverter and switchgear rooms. (Ref. 6.6)
1.3 Boundaries 1.3.1 Fire Area 6-B-1 South:
- 3-hour rated barrier separates this area from Area 3-CC. North:
- 3-hour rated barrier separates this area from Area 6-A-1.
- Unrated structural gap seal to Fire Area 6-A-1. (Ref. 6.14)
- A 3 hour door communicates to Area 6-A-1.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-B-1, 6-B-2, 6-B-3 9.5A-438 Revision 21 September 2013 East:
- 3-hour rated barrier separates this area from Area 6-B-2.
- A 3-hour rated door communicates to Area 6-B-2.
- Four protected ducts with no fire damper penetrate Area 6-B-2. Dampers are provided at the registers. (Refs. 6.5 and 6.10)
West:
- 3-hour rated barrier separates this area from Area 6-B-5.
- A 3-hour rated door communicates to Area 6-B-5.
- Three protected ducts with no fire damper penetrate Area 6-B-5 dampers are provided at the registers. (Refs.6.5 and 6.10)
Floor/Ceiling:
- 3-hour rated barriers: Floor: To Fire Areas 5-B-1 and 5-B-4. Ceiling: To Fire Area 7-B.
1.3.2 Fire Area 6-B-2 South:
- 3-hour rated barrier separates this area from Area 3-CC. North:
- 3-hour rated barrier separates this area from Area 6-A-2.
- Unrated structural gap seal to Fire Area 6-A-2. (Ref. 6.14)
- A 3-hour rated door communicates to Area 6-A-2. East:
- 3-hour rated barrier separates this area from Area 6-B-3.
- A 3-hour rated door communicates to Area 6-B-3.
- Four protected ducts with no fire damper penetrate Area 6-B-3. Dampers are provided at the registers. (Refs. 6.5 and 6.10)
West:
- 3-hour rated barrier separates this area from Areas 6-B-1.
- A 3-hour rated door communicates to Area 6-B-1.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-B-1, 6-B-2, 6-B-3 9.5A-439 Revision 21 September 2013
- Four protected ducts with no fire damper penetrate Areas 6-B-1. Dampers are provided at the registers. (Refs. 6.5 and 6.10)
Floor/Ceiling:
- 3-hour rated barriers: Floor: To Fire Areas 5-B-2 and 5-B-4. Ceiling: To Fire Area 7-B.
1.3.3 Fire Area 6-B-3 South:
- 3-hour rated barrier separates this area from Area 3-CC.
North:
- 3-hour rated barrier separates this area from Area 6-A-3.
- Unrated structural gap seal to Fire Area 6-A-3. (Ref. 6.14)
- A 3-hour rated door communicates to Area 6-A-3. East:
- 3-hour rated barrier separates this area from Area 6-B-4.
- A 3-hour rated door communicates to Area 6-B-4.
- Two protected ducts with no fire dampers penetrate Area 6-B-4. Dampers are provided at the registers. (Refs. 6.5 and 6.10) West:
- 3-hour rated barrier separates this area from Area 6-B-2.
- A 3-hour rated door communicates to Area 6-B-2.
- Four protected ducts with no fire damper penetrate Area 6-B-2. Dampers are provided at the registers. (Refs. 6.5 and 6.10)
Floor/Ceiling:
- 3-hour rated barriers: Floor: To Fire Areas 5-B-3 and 5-B-4. Ceiling: To Fire Area 7-B.
2.0 COMBUSTIBLES (typical for each area) 2.1 Floor Area: 672 ft2 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-B-1, 6-B-2, 6-B-3 9.5A-440 Revision 21 September 2013 2.2 In situ Combustible Materials
- Misc. combustibles
- Cable insulation
- Plastic
- Paper 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION (typical for each area) 3.1 Detection
- Smoke detection in the inverter, the dc switchgear rooms and the battery rooms. (Ref. 6.8) 3.2 Suppression
- CO2 hose stations
- Fire hose stations
- Portable fire extinguishers 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Fire Area 6-B-1 4.1.1 Auxiliary Feedwater DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-B-1, 6-B-2, 6-B-3 9.5A-441 Revision 21 September 2013 AFW pump 2-3 may be lost due to a fire in this area. Redundant AFW pump 2-2 will be available to provide AFW flow to steam generators 2-1 and 2-2.
Redundant AFW Pump 2-1 will be available after performing manual action to open steam supply valve FCV-38.
A fire in this area may affect AFW supply valves LCV-113 and LCV-115. Redundant valves LCV-110 and LCV-111 will remain available to provide AFW flow to steam generators 2-1 and 2-2 from AFW Pump 2-2. Steam generators 2-3 and 2-4 are credited for safe shutdown in this area. Valves LCV-108 and LCV-109 will remain available and a manual action to operate LCV-113 and LCV-115 can be performed to feed steam generators 2-3 and 2-4.
In addition, if FCV-38 is not affected by the fire and AFW Pp 2-1 is utilized, then LCV-106, LCV-107 will be available. 4.1.2 Chemical and Volume Control System Charging pump and ALOP 2-1 may be lost due to a fire in this area. Redundant charging pumps 2-2 and 2-3 and ALOP 2-2 will be available to provide charging flow.
Boric acid transfer pump 2-1 may be lost due to a fire in this area. Redundant boric acid transfer pump 2-2 will remain available.
Valve 8105 may be affected by a fire in this area. Safe shutdown will not be affected since the RWST can be made available to provide a charging suction flowpath.
A fire in this area may affect valve 8107. Valves 8108, HCV-142 or 8145 and 8148 may be shut to isolate auxiliary spray. Two other charging flowpaths are available if valve 8107 spuriously closes and blocks the charging flowpath through the regenerative heat exchanger. The pressurizer PORVs will remain available to provide pressure reduction capabilities. Since valve 8107 has redundant components, safe shutdown is not affected.
A fire in this area may spuriously open valves 8149A, 8149B, 8149C, LCV-459 or LCV-460. Manual operator action can be taken to fail 8149A, 8149B, and 8149C closed.
Valves 8146 and 8147 may fail open due to a fire in this area. This condition will not affect safe shutdown since the PORVs will remain available for pressure reduction.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-B-1, 6-B-2, 6-B-3 9.5A-442 Revision 21 September 2013 Valve LCV-112B may be affected by a fire in this area. If control of this valve is lost, the VCT can be isolated by closing valve LCV-112C. Valve 8805B can be opened to provide water to the charging pumps from the RWST.
A fire in this area may affect equipment and circuits associated with VCT level transmitter LT-112. This instrument is credited for diagnosis of failure of the VCT discharge valves LCV-112B or LCV-112C to automatically close. Therefore, loss of this instrument will not affect safe shutdown.
Boric acid storage tank 2-1 level, LT-106 may be lost due to a fire in this area. Borated water from the RWST will remain available. Therefore, BAST level indication is not required. 4.1.3 Component Cooling Water CCW pump and ALOP 2-1 may be lost due to a fire in this area. Redundant CCW pumps and ALOPs 2-2 and 2-3 will be available to provide CCW.
FCV-430 may be affected by a fire in this area. Valve FCV-431 will remain available to enable the use of redundant CCW heat exchanger 2-2.
A fire in this area may spuriously close FCV-750. Since RCP seal injection will remain available, adequate RCP seal cooling will be provided and FCV-750 will not be required open.
A fire in this area may affect circuits associated with CCW flow transmitters for Header A (FT-68) and Header C (FT-69). FT-65 will remain available to CCW Header B. CCW to header C will also remain available, and loss of FT-69 indication will not affect flow to the header.
A fire in this area may affect circuits associated with the differential pressure transmitters for CCW Hx 2-1 (PT-5). Flow through redundant CCW Hx 2-2 will remain available.
4.1.4 Emergency Power A fire in this area may disable the diesel generator 2-1 backup control circuit. Power for the normal control circuit will remain available.
A fire in this area may disable diesel generator 2-3. Diesel generators 2-1 and 2-2 will remain available for safe shutdown.
A fire in this area may disable startup transformer 2-2. Onsite power will remain available from diesel generators 2-1 and 2-2. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-B-1, 6-B-2, 6-B-3 9.5A-443 Revision 21 September 2013 Power supplies on the F bus may be lost due to a fire in this area. Redundant trains on the G and H buses will be available.
A fire in this area may affect the 480 V power supply to Uninterrupted Power Supply (UPS) IY22. The 125 Vdc backup power supply will remain available.
A fire in this area may disable dc panel SD23 backup battery charger ED231. Normal battery charger ED232 will remain available.
4.1.5 Main Steam System A fire in this area may affect the following instrumentation: LT-516, LT-526, LT-529, LT-536, LT-539, LT-546, PT-514, PT-524, PT-534 and PT-544. Safe shutdown is not affected since there are redundant trains of instrumentation for all four steam generators.
A fire in this area may fail valve PCV-19 to the desired, closed position for hot standby. Redundant dump valves PCV-20, PCV-21 and PCV-22 will remain available for cooldown.
A fire in this area may spuriously open FCV-248 and FCV-250. However, safe shutdown is not affected because valves FCV-761 and FCV-760 will remain available to isolate steam generator blowdown lines.
Valve FCV-25 may be spuriously opened by a fire in this area. This valve can be manually closed to ensure safe shutdown.
A fire in this area may spuriously close FCV-38. This valve can be manually opened to provide steam supply to AFW Pump 2-1.
4.1.6 Makeup System Condensate storage tank level indication, LT-40 may be lost due to a fire in this area. Water from the raw water storage reservoir will remain available through valve FCV-436 and FCV-437 in order to provide auxiliary feedwater. Operator action can be performed to locally open manual valve FCV-436 to provide raw water to AFW Pump 2-1 or locally open manual valve FCV-437 to provide raw water to AFW Pump 2-2.
4.1.7 Reactor Coolant System A fire in this area may result in the loss of the following components: LT-406, LT-459, NE-31, NE-51, PT-406, PT-403, TE-423A and TE-423B. Since redundant instrumentation exists, safe shutdown is not affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-B-1, 6-B-2, 6-B-3 9.5A-444 Revision 21 September 2013 Pressurizer PORV blocking valve 8000A may be affected by a fire in this area. Since pressurizer PORV PCV-474 will remain closed, the position of valve 8000A will not affect safe shutdown.
A fire in this area may prevent the tripping of the four reactor coolant pumps. Safe shutdown is not affected if the RCPs continuously run.
A fire in this area may spuriously energize pressurizer heater group 2-4. This heater group can be manually tripped to ensure safe shutdown.
4.1.8 Safety Injection System SI pump 2-1 may spuriously operate due to a fire in this area. Local manual action may be required to defeat this spurious operation. A fire in this area may result in the loss of the following valves: 8801A, 8803A and 8805A. Redundant valves 8801B, 8803B and 8805B will remain available to ensure safe shutdown.
Valve 8808A may be affected by a fire in this area. This valve can be manually operated to its safe shutdown position.
4.1.9 Auxiliary Saltwater System ASW pump 2-1 may be lost due to a fire in this area. The redundant ASW pump 2-2 will remain available.
Valve FCV-602 may be affected by a fire in this area. FCV-602 will be used with ASW pump 2-1. Since ASW pump 2-2 is used during a fire in this area, FCV-602 is not required.
4.1.10 HVAC HVAC equipment E-104, E-45, S-45, FCV-5045 and S-69 may be affected by a fire in this area. E-104 and S-69 will not be necessary during a fire in this area. S-45, E-45 and FCV-5045 have the following redundant components: S-46, E-46 and FCV-5046. Therefore, safe shutdown is not affected by a fire in this area.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-B-1, 6-B-2, 6-B-3 9.5A-445 Revision 21 September 2013 4.2 Fire Area 6-B-2 4.2.1 Auxiliary Feedwater A fire in this area may affect valves LCV-106, LCV-107, LCV-108 and LCV-109. Redundant valves LCV-110 and LCV-111 will remain available to provide AFW flow to steam generators 2-1 and 2-2.
4.2.2 Chemical and Volume Control System Valve 8106 may be affected by a fire in this area. Since the VCT or RWST will be aligned to the charging pump suction, safe shutdown will not be affected. A fire in this area may cause valve 8108 to spuriously operate. Valve 8107 can be shut to isolate auxiliary spray. If valve 8108 spuriously closes, one other charging flowpath is available. The PORVs will remain available for pressure reduction. Since valve 8108 has redundant components, safe shutdown is not affected.
Valve 8104 may be lost due to a fire in this area. FCV-110A and manual valve 8471 will remain available to provide boric acid to the charging pump suction.
A fire in this area may affect valves 8146, 8147 and 8148. Safe shutdown is not compromised because the PORVs will remain available for pressure reduction and other charging flowpaths exist.
Charging pumps 2-2 and 2-3 and ALOP 2-2 may be lost due to a fire in this area. Redundant charging pump and ALOP 2-1 will be available to provide charging flow.
Boric acid transfer pump 2-2 may be lost due to a fire in this area. Redundant boric acid transfer pump 2-1 will remain available.
Valves FCV-128 and HCV-142 may be affected by a fire in this area. Spurious closure of HCV-142 will not affect safe shutdown as redundant components exist to isolate auxiliary spray (8107), to provide a charging flowpath (charging injection), and to provide for pressure reduction (PORVs). Spurious closure of FCV-128 will result in isolation of seal injection flow. An operator action can be taken to fail FCV-128 after transferring control of the valve to the Hot Shutdown Panel.
Volume control tank outlet valve LCV-112C may be affected by a fire in this area. If LCV-112C spuriously closes then valve 8805A can be opened to provide water DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-B-1, 6-B-2, 6-B-3 9.5A-446 Revision 21 September 2013 from the RWST to the charging pump suction. Otherwise, the VCT may be isolated by closing LCV-112B.
Letdown isolation valves LCV-459 and LCV-460 may be affected by a fire in this area. These valves are desired closed for letdown isolation. This can be accomplished by closing valves 8149A, 8149B and 8149C. Therefore, safe shutdown is not affected.
Level indication for the boric acid storage tank 2-1, LT-106 may be lost due to a fire in this area. Borated water from the RWST will be available. Therefore, BAST level indication will not be required.
A fire in this area may affect the transmitter and circuits associated with charging pump header flow transmitter, FT-128, and pressure transmitter, PT-142. Both charging pumps are available in this fire area to provide charging flow. Loss of these instruments will not affect safe shutdown.
4.2.3 Component Cooling Water CCW pump and ALOP 2-2 may be lost due to a fire in this area. Redundant CCW pumps and ALOPs 2-1 and 2-3 will be available to provide CCW. Valve FCV-431 may be affected by a fire in this area. Redundant valve FCV-430 will remain available.
A fire in this area may fail open FCV-365, which is the desired position for safe shutdown. Redundant valve FCV-364 will be available and allow RHR HX 2-2 to be used.
A fire in this area may spuriously close valve FCV-356. This valve can be manually opened to ensure safe shutdown.
A fire in this area may affect circuits associated with CCW flow transmitters for Header B (FT-65) and Header C (FT-69). All three CCW pumps will remain available in this area to provide CCW flow to either header. Therefore, loss of these instruments will not affect safe shutdown.
The seal injection flowpath can also be affected in this fire area due to fire induced spurious closure of FCV-128. The potential for a loss of all RCP seal cooling can occur if the valves on these flowpaths spuriously close simultaneously. A manual action will be taken to fail FCV-128 open at the Hot Shutdown Panel to provide RCP seal injection.
A fire in this area may affect circuits associated with the differential pressure transmitters for CCW Hx 2-2 (PT-6). CCW Pp 2-1 will remain available to DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-B-1, 6-B-2, 6-B-3 9.5A-447 Revision 21 September 2013 provide flow to CCW Hx 2-1. Therefore, loss of this instrument will not affect safe shutdown.
4.2.4 Containment Spray A fire in this area may affect containment spray pump 2-1 and open 9001A. Manual operator action can be taken to trip CS Pump 2-1.
Valve 9003A may be spuriously opened due to a fire in this area. This valve can be manually closed in order to isolate containment spray.
4.2.5 Diesel Fuel Oil System Diesel fuel oil pump 0-2 may be lost due to a fire in this area. Redundant diesel fuel oil pump 0-1 remains available.
Valves LCV-85, LCV-86 and LCV-87 may be lost due to a fire in this area. However, safe shutdown is not affected because redundant valves LCV-88, LCV-89 and LCV-90 will remain available.
4.2.6 Emergency Power A fire in this area may disable diesel generator 2-1. Diesel generators 2-2 and 2-3 will remain available for safe shutdown.
A fire in this area may disable the diesel generator 2-2 backup control circuit. The normal control circuit will remain available.
A fire in this area may disable startup transformer 2-2. Onsite power will remain available from diesel generators 2-2 and 2-3.
All power supplies on the "G" bus may be lost due to a fire in this area. These power supplies are not necessary since redundant trains on the "F" and "H" buses will be available.
A fire in this area may affect backup power supply cables to ED231 and BAT22. No power losses will occur if these cables are lost.
4.2.7 Main Steam System The instrumentation that may be lost due to a fire in this area is as follows: LT-519, LT-549, PT-515, PT-525, PT-535 and PT-545. Since redundant instrumentation exists for each steam generator, safe shutdown will not be affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-B-1, 6-B-2, 6-B-3 9.5A-448 Revision 21 September 2013 A fire in this area may fail valve PCV-21 closed. A fire in this area could also affect cables that could cause the valve to spuriously open. Spurious operation of the valve can be mitigated by locally isolating air to PCV-21 to fail if closed. Redundant dump valves PCV-19, PCV-20 and PCV-22 will remain available for safe shutdown.
Valves FCV-760 and FCV-761 may be affected by a fire in this area. Redundant valves FCV-154 and FCV-248 for FCV-761 and FCV-151 and FCV-250 for FCV-760 remain available to isolate steam generator blowdown.
A fire in this area may affect valve FCV-95. AFW pump 2-2 will remain available to provide AFW flow to steam generators 2-1 and 2-2 if FCV-95 is unable to provide steam to AFW pump 2-1. Main steam isolation valves FCV-41, FCV-42 and bypass valve FCV-24 may be affected by a fire in this area. These valves can be manually operated to ensure safe shutdown.
4.2.8 Reactor Coolant System A fire in this area may result in the loss of the following equipment: LT-460, NE-32, TE-433A, TE-433B, TE-443A and TE-443B. Since redundant components exist, safe shutdown is not affected.
Valves PCV-455C and 8000B may be affected by a fire in this area. PCV-455C fails in the desired, closed position and redundant valves PCV-456 and 8000C will be available for pressure reduction. Therefore, safe shutdown is not affected.
A fire in this area may prevent the tripping of reactor coolant pumps 2-1, 2-2, 2-3 and 2-4. Since PCV-455A and PCV-455B can be shut to prevent uncontrolled pressure reduction, safe shutdown will not be affected. Seal injection will remain available for RCP seal cooling.
Pressurizer heaters groups 2-3 and 2-4 may be affected by a fire in this area. Manual actions can be taken to de-energize heater group 2-4 and switch heater group 2-3 to the vital power supply. Therefore, safe shutdown is not affected.
4.2.9 Residual Heat Removal System RHR pump 2-1, valve FCV-641A and valve 8700A may be lost due to a fire in this area. Redundant RHR pump 2-2 and valve FCV-641B will be available so safe shutdown will not be affected.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-B-1, 6-B-2, 6-B-3 9.5A-449 Revision 21 September 2013 Valve 8701 may be affected by a fire in this area. This valve is closed with its power removed during normal operations; therefore, it will remain closed. This valve can be manually opened for RHR operations.
4.2.10 Safety Injection System Valves 8801B, 8803B and 8805B may be lost due to a fire in this area. Safe shutdown will not be affected because redundant valves 8801A, 8803A and 8805A will remain available.
A fire in this area may spuriously open valve 8804A. This valve can be manually closed to ensure safe shutdown. Valves 8808B and 8808D may be affected by a fire in this area. These valves can be manually closed to ensure safe shutdown.
A fire in this area may affect valve 8982A. Power to the valve is administratively removed by maintaining a toggle switch in the Control Room in the open position. The valve is normally closed, and spurious opening is not expected to occur. However, an operator action can be taken to open the power breaker to further preclude spurious operation. If valve 8982A has opened after opening its respective power breaker, valve 8980 may be de-energized and manually closed. Therefore, safe shutdown is not affected.
4.2.11 Auxiliary Saltwater System ASW pump 2-2 may be lost due to a fire in this area. Redundant ASW pump 2-1 will be available to provide the ASW function.
Valve FCV-603 may be lost due to a fire in this area. Since redundant valve FCV-602 remains available, safe shutdown is not affected.
4.2.12 HVAC A fire in this area may affect E-102 and S-68. Since these components are not required to be operational following a fire, safe shutdown is not affected.
4.3 Fire Area 6-B-3 4.3.1 Auxiliary Feedwater AFW pump 2-2 may be lost for a fire in this area. Redundant AFW pump 2-3 will be available to provide AFW.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-B-1, 6-B-2, 6-B-3 9.5A-450 Revision 21 September 2013 Valves LCV-110 and LCV-111 may be affected by a fire in this area. Redundant valves LCV-113 and LCV-115 will remain available to provide AFW flow to steam generators 2-3 and 2-4.
4.3.2 Chemical and Volume Control System Level indication for boric acid storage tank 2-2 from LT-102 may be lost due to a fire in this area. Borated water from the RWST will remain available. Therefore, BAST level indication is not required.
Valve 8145 may be affected by a fire in this area. Since this valve fails in the desired closed position during hot standby and the PORVs will remain available, safe shutdown will not be affected. Valve FCV-110A may be affected by a fire in this area. Since this valve fails in the desired open position, safe shutdown is not affected.
A fire in this area may affect valves LCV-459 and LCV-460. Since redundant valves are available, safe shutdown is not affected.
A fire in this area may affect circuits associated with letdown flow transmitter, FT-134. Because letdown isolation valves 8149A, 8149B, and 8149C are not affected in this fire area and will remain available to isolate letdown, this diagnostic indication is not required.
4.3.3 Component Cooling Water CCW pump and ALOP 2-3 may be lost due to a fire in this area. Redundant pumps and ALOPs 2-1 and 2-2 are available to provide CCW.
CCW valve FCV-357 may be affected by a fire in this area. Since seal injection will remain available, FCV-357 will not be required open.
A fire in this area may spuriously close FCV-355. FCV-355 can be manually operated for safe shutdown.
FCV-364 will fail open due to a fire in this area, which is the desired position for safe shutdown. In addition, redundant RHR HX 1-1 will be available to provide this safe shutdown function. Redundant valve FCV-365 will remain available for safe shutdown.
A fire in this area may affect circuits associated with CCW flow transmitters for Header C (FT-69). CCW to Header C is not credited in this fire area. Therefore, loss of these instruments will not affect safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-B-1, 6-B-2, 6-B-3 9.5A-451 Revision 21 September 2013 4.3.4 Containment Spray Containment spray pump outlet valve 9001B may be affected by a fire in this area. CS Pump 2-2 is not affected in this area and will remain de-energized to isolate containment spray.
A fire in this area may spuriously open valve 9003B. This valve can be manually closed.
4.3.5 Diesel Fuel Oil System Diesel fuel oil pump 0-1 may be lost due to a fire in this area. The redundant diesel fuel oil pump 0-2 will remain available. Valves LCV-88, LCV-89 and LCV-90 may be lost due to a fire in this area. Redundant valves LCV-85, LCV-86 and LCV-87 will remain available.
4.3.6 Emergency Power A fire in this area may disable diesel generator 2-2. Diesel generator 2-1 and 2-3 will remain available for safe shutdown.
Diesel generator 2-3 backup control circuit may be lost due to a fire in this area. The normal control circuit will remain available.
All power supplies on the "H" Bus may be lost due to a fire in this area. Redundant power supplies on the "G" and "F" buses will remain available. A fire in this area may disable dc panel SD21 backup battery charger ED221. Normal battery charger ED21 will remain available.
A fire in this area may disable dc panel SD22 backup battery charger ED221. Normal battery charger ED22 will remain available.
A fire in this area may affect vital UPS IY23 and IY24 and vital instrument ac distribution panels PY23 and PY24. Redundant UPS IY21 and IY22, and corresponding panels PY21 and PY22, will remain available.
4.3.7 Main Steam System A fire in this area may result in the loss of the following components: LT-517, LT-518, LT-527, LT-528, LT-537, LT-538, LT-547, LT-548, PT-516, PT-526, PT-536 and PT-546. Since redundant trains of instrumentation exist for all four steam generators, safe shutdown is not affected.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-B-1, 6-B-2, 6-B-3 9.5A-452 Revision 21 September 2013 Valve PCV-20 may be affected by a fire in this area. This valve fails in the desired, closed position for hot standby. Redundant dump valves PCV-19 and PCV-21 will remain available for safe shutdown.
Valve PCV-22 may be affected by a fire in this area. Redundant dump valves PCV-19 and PCV-21 will remain available for safe shutdown.
A fire in this area may spuriously close FCV-37 and affect FCV-95. Safe shutdown will not be affected since AFW pump 2-3 will remain available to provide AFW to the steam generators.
Valves FCV-762 and FCV-763 may spuriously open due to a fire in this area. Valves FCV-157 and FCV-246 can be shut to provide steam generator blowdown in place of FCV-762 and FCV-160 and FCV-244 can perform the same function for FCV-763.
A fire in this area may affect FCV-43 and FCV-44. These valves can be manually shut to ensure safe shutdown.
4.3.8 Reactor Coolant System A fire in this area may affect LT-461, NE-52, TE-413A, TE-413B, PT-403 and PT-405. These instruments have redundant components: LT-459, LT-460, LT-406, NE-51, NE-31, NE-32, TE-423A, TE-423B, TE-433A, TE-433B, TE-443A, TE-443B and PT-406 available for safe shutdown.
A fire in this area may affect valve 8000C or cause PCV-456 to fail closed. PCV-456 is required closed during hot standby. PCV-455C will remain available for pressure reduction. Therefore, safe shutdown is not affected.
A fire in this area may prevent reactor coolant pumps 2-2 and 2-4 from being tripped. Safe shutdown is not affected if these RCPs continuously run. CCW to thermal barrier heat exchanger or seal injection will remain available for RCP seal cooling.
Pressurizer heater groups 2-1, 2-2, 2-3, and 2-4 may be lost due to a fire in this area. Manual actions can be taken to de-energize heater group 2-1 and switch heater group 2-3 to the vital power source. Therefore, safe shutdown is not affected.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-B-1, 6-B-2, 6-B-3 9.5A-453 Revision 21 September 2013 4.3.9 Residual Heat Removal System RHR pump 2-2, valve FCV-641B and outlet valve 8700B may be lost for a fire in this area. The redundant train (RHR PP 2-1 and valves 8700A and FCV-641A) will be available to provide the RHR function.
Valve 8702 may be affected by a fire in this area. This valve is closed with its power removed during normal operations; therefore it will remain closed. This valve can be manually opened for RHR operations.
4.3.10 Safety Injection System SI pump 2-2 may spuriously operate for a fire in this area. Local manual action may be required to defeat this spurious operation. Valve 8808C may be affected by a fire in this area. This valve can be manually closed to provide accumulator isolation.
A fire in this area may affect valve 8982B. Power to the valve is administratively removed by maintaining a toggle switch in the Control Room in the open position. The valve is normally closed, and spurious opening is not expected to occur. Therefore, safe shutdown is not affected.
A fire in this area may affect RWST Level Transmitter LT-920. Spurious operation of equipment that may divert the RWST inventory is not affected in this fire area. Therefore, loss of this instrument will not affect safe shutdown.
4.3.11 Auxiliary Saltwater System Valves FCV-495 and FCV-496 may be affected by a fire in this area. FCV-601 will remain closed to provide ASW system integrity.
4.3.12 HVAC One train of HVAC components (E-46, S-46, FCV-5046 and S-67) may be lost due to a fire in this area. S-67 is not required for a fire in this area. A redundant train of HVAC components (S-45, E-45 and FCV-5045) will remain available to provide the HVAC function.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown: DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 6-B-1, 6-B-2, 6-B-3 9.5A-454 Revision 21 September 2013
- Deviations to requirements for 3 hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Loss of safe shutdown functions in an area does not adversely affect safe shutdown.
- Automatic smoke detection in inverter and dc switchgear rooms.
- Manual fire fighting equipment is available for use. The existing fire protection feature provides an acceptable level of safety equivalent to that provided by Section III.G.
6.0 REFERENCES
6.1 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.2 Drawing No. 515570 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065127, Fire Protection Information Report, Unit 2 6.5 NECS File: 131.95, FHARE: 15, HVAC Ducts Wrapped with Pyrocrete 6.6 NECS File: 131.95, FHARE: 26, Non-rated Barriers 6.7 Response to Q.21 of PG&E letter dated November 13, 1978 6.8 DCN DCO-EE-35151, Provide Smoke Detection in Battery Rooms 6.9 DCN DC2-EE-16569 Rev. 0, Feeder Circuits for PT-406 6.10 NECS File: 131.95, FHARE: 80, Fire Dampers Installed at Variance with Manufacturers Instructions 6.11 AR A0211784 AE 08, NES Fire Protection's Evaluation of Exposed Structural Steel Anchor Bolts 6.12 Calculation 134-DC, Electrical Appendix R Analysis 6.13 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.14 NECS File: 131.95, FHARE 134, "Non-rated Structural Gap Seals in Fire Barriers" 6.15 NECS File: 131.95, FHARE 152, Evaluation of Fire Dampers in 480V Switchgear and Battery Rooms
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-B-4 9.5A-455 Revision 21 September 2013 FIRE AREA 6-B-4 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Southwest side of the Unit 2 Auxiliary Building, El. 115 ft.
1.2 Description Unit 2 reactor trip switchgear and rod programmer occupies this fire area.
1.3 Boundaries South:
- 3-hour rated barrier separates this area from Area 3-CC and Zone 3-AA. North:
- 3-hour rated barrier separates this area from Area 6-A-4 and Zone S-5.
- Unrated structural gap seal to Fire Area 6-A-4. (Ref. 6.11)
- A 3-hour rated door communicates to Area 6-A-4.
- A duct penetration with no fire damper penetrates to Zone S-5. (Ref. 6.5)
East:
- 3-hour rated barrier separates this area from Zones 3-AA, S-2, and S-5. West:
- 3-hour rated barrier separates this area from Area 6-B-3.
- A 3-hour rated door communicates to Area 6-B-3.
- Two ducts without fire dampers penetrate to Area 6-B-3. (Ducts are protected within 6-B-3 with dampers provided at the registers.) (Refs. 6.6 and 6.8)
Floor/Ceiling:
- 3-hour rated barriers separate this area from Area 5-B-4 below and Areas 7B and 7D above.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-B-4 9.5A-456 Revision 21 September 2013 2.0 COMBUSTIBLES 2.1 Floor Area: 1,222 ft2 2.2 In situ Combustible Materials
- Cable insulation
- Lube Oil
- Paper
- PVC
- Rubber
- Plastic
- Misc. combustibles 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection 3.2 Suppression
- CO2 hose stations
- Hose stations
- Portable fire extinguishers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-B-4 9.5A-457 Revision 21 September 2013 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Auxiliary Feedwater System Valves LCV-110 and LCV-111 may be affected by a fire in this area. These valves can be manually operated to ensure safe shutdown.
4.2 Chemical and Volume Control System A fire in this area may affect valves 8145 and 8148. Valves 8107, 8108 and HCV-142 will remain available to prevent uncontrolled pressure reduction and valve 8145 can be manually operated to provide auxiliary spray. A fire in this area may affect circuits associated with letdown flow transmitter, FT-134. Because letdown isolation valves LCV-459, LCV-460, 8149A, 8149B, and 8149C are not affected in this fire are and will remain available to isolate letdown, this diagnostic indication is not required. 4.3 Main Steam System A fire in this area may affect FCV-95, and prevent operation of AFW Pump 2-1. Redundant AFW Pump 2-2 will remain available to provide AFW flow to steam generators 2-1 and 2-2. 4.4 Reactor Coolant System A fire in this area may spuriously open the reactor vessel vent valves 8078A, 8078B, 8078C and 8078D. Valves 8078A and 8078B are in series, likewise for 8078C and 8078D. Manual operator action can be taken to fail the valves closed. Valves PCV-455C and PCV-456 may be lost due to a fire in this area. Redundant blocking valves 8000B and 8000C will remain available to isolate the PORV lines and prevent uncontrolled pressure reduction. RCS pressure indication, PT-405 may be lost due to a fire in this area. Redundant components PT-406 and PT-403 will remain available. Pressurizer heater groups 2-1 through 2-4 may be affected by a fire in this area. These heater groups can be manually de-energized to ensure safe shutdown. A fire in this area may result in the loss of the following components: TE-443A, TE-443B, TE-433A and TE-433B. Safe shutdown is not affected because redundant components exist. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-B-4 9.5A-458 Revision 21 September 2013 4.5 Residual Heat Removal System RHR pump 2-2 may be lost due to fire in this area. Redundant RHR pump 2-1 will remain available. 4.6 Safety Injection System A fire in this area may affect valve 8982B. Power to the valve is administratively removed by maintaining a toggle switch in the Control Room in the open position. The valve is normally closed, and spurious opening is not expected to occur. Therefore, safe shutdown is not affected. 4.7 HVAC S-46 and E-46 may be lost due to a fire in this area. Redundant components S-45 and E-45 will remain available to provide the HVAC function.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- The loss of safe shutdown functions located in this area will not affect safe shutdown capability.
- Automatic smoke detection is provided.
- Manual fire fighting equipment is provided.
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
The existing fire protection features provide an acceptable level of safety equivalent to that provided by Section III.G.2.
6.0 REFERENCES
6.1 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.2 Drawing No. 515570 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065127, Fire Protection Information Report, Unit 2 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-B-4 9.5A-459 Revision 21 September 2013 6.5 NECS File: 131.95, FHARE: 27, Undampered Duct Penetration in Concrete Lined Shafts 6.6 NECS File: 131.95, FHARE: 15, HVAC Duct Wrapped in Pyrocrete 6.7 Appendix 3 for GP M-10 Unit 2 Fire Protection of Safe Shutdown Equipment 6.8 NECS File: 131.95, FHARE: 80, Fire Dampers Installed at Variance with Manufacturer 6.9 Calculation 134-DC, Electrical Appendix R Analysis 6.10 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.11 NECS File: 131.95, FHARE 134, "Non-rated Structural Gap Seals in Fire Barriers" DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-B-5 9.5A-460 Revision 21 September 2013 FIRE AREA 6-B-5 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Southwest corner of the Auxiliary Building, El. 115 ft.
1.2 Description Unit 2 Electrical Area, 6-B-5 is just west of the "F" Bus battery inverter and dc switchgear room, Area 6-B-1. Raceway for safe shutdown functions are routed through this fire area. 1.3 Boundaries North:
- A 3-hour rated barrier to Fire Zone S-1.
- A 3-hour rated door communicates to Area 6-A-5 and is provided with a 2-hour rated blockout above the door. (Ref. 6.9)
South:
- 3-hour rated barrier separates this area from Fire Zone 19-A.
East:
- 3-hour rated barrier separates this area from Areas 6-A-1 and 6-B-1.
- A 3-hour rated door communicates to Area 6-B-1.
- Three protected ducts without fire dampers penetrate to Area 6-B-1. Dampers are provided at the registers. (Refs. 6.7, 6.12 and 6.17) West:
- 3-hour rated barrier separates this area from Zones 19-A, S-1, and 14-A.
- Two protected ducts without fire dampers penetrate to Zone 19-A. (Refs. 6.7, 6.12 and 6.17)
- A protected duct penetration without a fire damper penetrates to Zone S-1. (Refs. 6.7, 6.12 and 6.17)
- Proposed modification to install dampers. (Ref. 6.10)
- 3-hour rated door communicates to Zone S-1.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-B-5 9.5A-461 Revision 21 September 2013 Floor/Ceiling:
- 3-hour rated barrier: Floor: To Fire Area 5-B-4. Ceiling: To Fire Area 7-B.
- Two ducts with no fire damper penetrate to Area 5-B-4 below. (Refs. 6.8 and 6.17)
- Nonrated equipment hatches communicate to Area 5-B-4 below, and Zone 7-B above. (Ref. 6.17) The nonrated hatch to Zone 7-B contains HVAC duct penetrants. (Ref. 6.14 and 6.17)
- Two duct penetrations with 3-hour rated damper to 7B above.
Protective
Enclosure:
- 1-hour rated fire resistive covering for several HVAC ducts. (Refs. 6.7, 6.12 and 6.17) 2.0 COMBUSTIBLES
2.1 Floor Area: 724 ft2 2.2 In situ Combustible Materials
- Rubber
- Cable insulation
- Miscellaneous
- Paper
- Plastic 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-B-5 9.5A-462 Revision 21 September 2013 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection 3.2 Suppression
- CO2 hose stations
- Hose stations
- Portable fire extinguishers 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Chemical and Volume Control System Valves 8146 and 8147 may be affected by a fire in this area. These valves fail open, which provides a charging flowpath through the regenerative heat exchanger. Also the PORVs will remain available for pressure reduction. Therefore, safe shutdown can be achieved. Valves LCV-459 and LCV-460 may be affected by a fire in this area. Redundant valves 8149A, 8149B and 8149C will remain available to isolate letdown. 4.2 Component Cooling Water A fire in this area may affect valves FCV-355 and FCV-356, FCV-430 and FCV-431. Valves FCV-355, FCV-430 and FCV-431 can be manually operated to their safe shutdown position. A fire in this area may affect circuits associated with CCW flow transmitter for Header C (FT-69). CCW flow to Header C is not credited for safe shutdown in this area. Therefore, loss of this instrument will not affect safe shutdown. A fire in this area may affect circuits associated with the differential pressure transmitters for CCW Hx 2-1 (PT-5) and CCW Hx 2-2 (PT-6). CCW flow to either header, the heat exchanger discharge valves FCV-430 and FCV-431 will need to be manually aligned due to fire damage to their cables. Therefore, loss of these instruments will not affect safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-B-5 9.5A-463 Revision 21 September 2013 4.3 Containment Spray A fire in this area may spuriously open valve 9001B. Since CS pump 2-2 is not affected by a fire in this area, safe shutdown will not be affected. 4.4 Emergency Power A fire in this area may disable diesel generator 2-3 circuits. Offsite power is not affected in this area and would remain available. In addition, diesel generators 2 1 and 2-2 will remain available for safe shutdown. 4.5 Main Steam System A fire in this area may spuriously open FCV-248 and FCV-250. FCV-761 and FCV-760 will remain available to isolate steam generator blowdown. Therefore, safe shutdown is not affected. 4.6 Makeup System Condensate storage tank level indication may be lost due to a fire in this area. Water from the raw water storage reservoir will be available through FCV-436 and FCV-437. Operator action would be required to locally open normally closed manual valves prior to CST depletion. 4.7 Reactor Coolant System A fire in this area may affect source range flux monitor NE-51. Redundant indicators NE-31, NE-32, and NE-52 will remain available. Pressurizer heater group 2-4 may be affected by a fire in this area. This heater group can be manually de-energized to ensure safe shutdown. Control of all four reactor coolant pumps may be affected by a fire in this area. Safe shutdown is not affected if the RCPs continue to run. CCW to the thermal barrier heat exchanger or seal injection will remain available for RCP seal cooling. 4.8 Safety Injection System Accumulator isolation valve 8808C may be affected by a fire in this area. This valve can be manually closed to ensure safe shutdown. 4.9 Auxiliary Saltwater System Valves FCV-495 and FCV-496 may be lost due to a fire in this area. Redundant valve FCV-601 will remain closed to provide ASW system integrity. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-B-5 9.5A-464 Revision 21 September 2013 A fire in this area may spuriously close FCV-602 and FCV-603. These valves can be manually opened to ensure safe shutdown. A deviation was approved that credited the low combustible loading, automatic smoke detection, and the manual action. 4.10 HVAC A fire in this area in this area may affect E-45 and S-45. Redundant components S-46 and E-46 will remain available to provide the necessary HVAC support.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3 hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Loss of the safe shutdown functions in this area will not affect safe shutdown due to redundant equipment and/or measures taken to mitigate the effects of fire.
- Area wide smoke detection is provided in this area.
- Manual fire fighting equipment is available.
- Low fire severity.
The existing fire protection features provide an acceptable level of safety equivalent to that provided by Section III.G.2.
6.0 REFERENCES
6.1 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.2 Drawing No. 515570 6.3 DCN - DC2-EE-10913 provides isolators on RPM tach-packs 6.4 SSER 31, April 1985 6.5 Calculation M-824, Combustible Loading 6.6 Drawing 065127, Fire Protection Information Report, Unit 2 6.7 NECS File: 131.95, FHARE: 15, HVAC Ducts Wrapped in Pyrocrete 6.8 NECS File: 131.95, FHARE: 73, Undampered Ducts 6.9 NECS File: 131.95, FHARE: 118, Appendix R Fire Area Boundary Plaster Barriers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 6-B-5 9.5A-465 Revision 21 September 2013 6.10 Deleted in Revision 13 6.11 Appendix 3 for EP M-10 Unit 2 Fire Protection of Safe Shutdown Equipment 6.12 PG&E letter to NRC dated 12/6/84, Appendix R Deviation Request 6.13 Calculations M-911 and M-912 6.14 NECS File: 131.95, FHARE: 126, HVAC Ducts through Modified Unrated Hatch 6.15 Calculation 134-DC, Electrical Appendix R Analysis 6.16 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.17 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-B 9.5A-466 Revision 21 September 2013 FIRE AREA 7-B 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This area is located directly under the control room at El. 127 ft in the Auxiliary Building. 1.2 Description Fire Area 7-B, Unit 2 cable spreading room, is directly under the Unit 2 control room and south of the Unit 1 cable spreading room. No storage sign is posted at the west wall near the equipment hatch area. 1.3 Boundaries South:
- 3-hour rated barrier separates this area from Fire Zone 19-A and Area 3-CC.
North:
- 3-hour rated barrier separates this area from Area 7-A and Zone S-1. In addition, localized sections of structural steel for blockwalls were not provided with 3-hour rated fireproofing. (Ref. 6.21)
- Unrated structural gap seals to Fire Area 7-A. (Refs. 6.19 and 6.22).
- Two 3-hour rated doors communicate to Area 7-A.
- Lesser-rated Unistrut seals to Fire Area 7-A. (Refs. 6.20 and 6.22) East:
- 3-hour rated barrier separates this area from Area 7-D and Zones 3-AA, S-5.
- A non-rated duct penetrant to Zone S-5. (Refs. 6.15 and 6.22)
- Two 1-1/2-hour rated doors communicate to Area 7-D. (Refs. 6.8 and 6.22)
- A ventilation duct with a 3-hour rated fire damper communicates to Zone S-5. (Ref. 6.14)
West:
- 3-hour rated barrier separates this area from Fire Zones 19-A and S-1.
- A 1-1/2-hour rated fire damper communicates to Zone S-1. (Ref. 6.22)
- A 3-hour rated door communicates to Zone S-1.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-B 9.5A-467 Revision 21 September 2013 Floor/Ceiling:
- 3-hour rated barrier: Floor: To Fire Areas 6-B-5, 6-B-4, 6-B-3, 6-B-2, and 6-B-1. Ceiling: To Fire Zones 8C, 8-D, 8-F, and 8-H.
- Two ducts with 3-hour rated damper to 6-B-5 below.
- Nonrated equipment steel hatch with HVAC duct penetrants to Area 6-B-5 below. (Refs. 6.13 and 6.22)
- Unrated penetrations to Areas 8-C and 8-D above. (Ref. 6.18 and 6.22) 2.0 COMBUSTIBLES 2.1 Floor Area: 3,612 ft2 2.2 In situ Combustible Materials
- Cable Insulation
- Misc. combustible
- Plastics
- Polyethylene
- Resin
- Paper
- PVC
- Wood (fir) 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Moderate DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-B 9.5A-468 Revision 21 September 2013 3.0 FIRE PROTECTION 3.1 Detection
- Smoke detection.
- Heat detection.
3.2 Suppression
- Total flooding CO2 system actuated by heat detection (it also protects Area 7-D).
- Portable fire extinguishers.
- Hose stations.
4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Auxiliary Feedwater A fire in this area may affect Auxiliary Feedwater Supply valves LCV-106, 107, 108, 109, 110, 111, 113 and 115. Manual actions will enable valves LCV-106, 107, 108 and 109 to be controlled from the hot shutdown panel. Valves LCV-110, 111, 113 and 115 can be manually operated.
The ability to operate AFW pumps 2-2 and 2-3 from the control room may be lost due to a fire in this area. Manual actions can be taken to operate these pumps from the 4kV switchgear or the hot shutdown panel. (Ref. 6.10)
A fire in this area may affect FCV-37, FCV-38 and FCV-95. These valves are associated with AFW pump 2-1. AFW pump 2-1 is not necessary since AFW pumps 2-2 and 2-3 will remain available.
Condensate storage tank level indication, LT-40 may be affected by a fire in this area. Valves FCV-436 and FCV-437 can be manually opened in order to supply water from the raw water storage reservoir. 4.2 Chemical and Volume Control System A fire in this area may affect valves 8801A, 8801B, 8803A, and 8803B. RCS flow through the charging injection flow path can be secured by manual operation of (either 8801A or 8801B) and (either 8803A or 8803B). Prior to initiation of auxiliary spray, charging injection flow path will need to be isolated.
A fire in this area may affect valves 8107, 8108, 8145, 8148, FCV-128, 8146, 8147 and HCV-142. Operation of HCV-142 will remain available from the hot shutdown panel to isolate auxiliary spray flowpath. Charging flow to the RCS will DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-B 9.5A-469 Revision 21 September 2013 remain available through the seal injection flowpath. Repairs and operator action can be taken to use the auxiliary spray flow path and isolate diversion flowpaths for RCS pressure reduction. Valve 8145 can be operated from the dedicated shutdown panel.
A fire in this area may spuriously open 8166, 8167 and fail HCV-123 closed. Only one of these valves is required closed to provide excess letdown isolation. Since HCV-123 fails closed, safe shutdown is not affected.
A fire in this area may affect the ability to operate valves LCV-459, LCV-460, 8149A, 8149B and 8149C from the control room. Valves 8149A, 8149B, and 8149C can be operated from the hot shutdown panel.
The ability to operate charging pumps 2-1, 2-2 and 2-3 from the Control Room may be lost due to a fire in this area. Either charging pumps 2-1 and 2-2 can be started at the 4kV switchgear or the hot shutdown panel to provide charging flow. Manual action can be taken to isolate Charging Pump 2-3 by manual action at the 4kv switchgear SHG. (Ref. 6.10) A fire in this area may spuriously close valves 8105 and 8106. Since the charging pumps will be taking suction from the RWST, these valves are not required open.
A fire in this area may result in the loss of boric acid storage tank 2-2 and 2-1 level indication from LT-102 and LT-106, respectively. Borated water from the RWST will be available. Therefore, BAST level indication will not be required.
The ability to operate boric acid transfer pumps 2-1 and 2-2 from the Control Room may be lost due to a fire in this area. However, either pump can be operated from the hot shutdown panel to provide boric acid flow. The charging pumps will be available to provide RCS makeup and borated water from the RWST.
A fire in this area may fail HCV-104 and HCV-105 closed. Since these valves fail in the desired position, safe shutdown is not affected.
Valves FCV-110A and 8104 may be affected by a fire in this area. Manual actions can be taken to enable valve 8104 to be operated from the hot shutdown panel.
A fire in this area may spuriously open valves FCV-110B and FCV-111B. These valves can be manually closed to ensure safe shutdown.
A fire in this area may affect valves LCV-112B, LCV-112C, 8805A and 8805B. All of these valves can be manually operated to ensure safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-B 9.5A-470 Revision 21 September 2013 A fire in this area may affect charging pump header flow transmitter, FT-128, and pressure transmitter, PT-142. Alternative shutdown from the hot shutdown panel is credited in this area, and these instruments are not credited.
A fire in this area may affect letdown flow transmitter, FT-134. Alternative shutdown from the hot shutdown panel is credited in this area, and this flow transmitter is not required. Letdown is isolated at the hot shutdown panel.
A fire in this area may affect VCT level transmitter LT-112. Alternative shutdown from the hot shutdown panel is credited in this area, and this level transmitter is not required. 4.3 Component Cooling Water A fire in this area may cause FCV-356, FCV-357 and FCV-750 to spuriously close and fail to provide component cooling water to the reactor coolant pump thermal barriers if seal injection is not available. Control of HCV-142 to provide seal injection for RCP seal cooling will be available at the hot shutdown panel. Therefore, safe shutdown is not compromised.
The ability to operate CCW pumps 2-1, 2-2 and 2-3 from the Control Room may be lost due to a fire in this area. Manual actions will enable any of the CCW pumps to be started from the 4kV switchgear or the hot shutdown panel. (Ref. 6.10)
A fire in this area may affect valves FCV-430 and FCV-431. Either of these valves can be manually operated in order to provide a CCW flowpath.
Valves FCV-364 and FCV-365 may be affected by a fire in this area. Either valve can be manually opened in order to ensure RHR operation.
A fire in this area may spuriously close FCV-355. This valve can be manually opened and the RCPs can be tripped if seal injection is not available.
A fire in this area may affect CCW flow transmitters for Header A (FT-68), Header B (FT-65), and Header C (FT-69). These instruments are credited to indicate a loss of CCW flow. Availability of these instruments is not credited for safe shutdown.
A fire in this area may affect differential pressure transmitters for CCW Hx 2-1 (PT-5) and CCW Hx 2-2 (PT-6). These instruments are credited to indicate a loss of CCW flow. Availability of these instruments is not credited for safe shutdown.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-B 9.5A-471 Revision 21 September 2013 4.4 Containment Spray A fire in this area may spuriously start containment spray pumps 2-1 and 2-2 or may spuriously open the discharge valves 9001A and 9001B. Operator action can be taken to trip CS pumps 2-1 and 2-2. Therefore, safe shutdown will not be affected. 4.5 Emergency Power A fire in this area may disable remote control and auto transfer of diesel generator 2-1. The diesel can be manually started and loaded at the diesel generator local panel and at the 4kV switchgear room. (Ref. 6.11)
A fire in this area may disable remote control and auto transfer of diesel generator 2-2. The diesel can be manually started and loaded at the diesel generator local panel and at the 4kV switchgear room. (Ref. 6.11) A fire in this area may disable remote control and auto transfer of diesel generator 2-3. The diesel can be manually started and loaded at the diesel generator local panel and at the 4kV switchgear room. (Ref. 6.11)
A fire in this area may spuriously trip the 480 volt feeder breakers. These breakers can be manually closed. 4.6 Main Steam System A fire in this area may spuriously open the main steam isolation valves (FCV-41, 42, 43, and 44) and their bypasses (FCV-22, 23, 24, and 25). These valves can be manually closed.
A fire in this area may spuriously open the steam generator inboard isolation valves (FCV-760, 761, 762, and 763) and the outboard isolation valves (FCV-151, 154, 157, 160, 244, 246, 248, and 250). Operator action can be taken to close the valves and isolate SG blowdown.
Steam generator pressure indication in the control room and hot shutdown panel may be lost due to a fire in this area. Steam generator pressure for steam generators 2-1, 2-2, 2-3, 2-4 can be read off of PI-518, PI-528, PI-538 and PI-548, respectively.
A fire in this area may result in the loss of steam generator level instruments LT-517, 518, 519, 527, 528, 529, 537, 538, 539, 547, 548 and 549. Steam generator level indication will remain available from LT-516, 526, 536 and 546 at the dedicated shutdown panel.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-B 9.5A-472 Revision 21 September 2013 A fire in this area may prevent ten percent dump valves (PCV-19, 20, 21 and 22) from opening. These valves are required closed for hot standby and can be manually opened for cooldown. To mitigate spurious operation of these valves, control air is isolated and bled off to allow manual operation of the valve handwheel. 4.7 Reactor Coolant System Reactor coolant system pressure indication from PT-403 and PT-405 may be lost due to a fire in this area. This indication can be monitored using PT-406 at the dedicated shutdown panel.
A fire in this area may affect PORVs PCV-456, PCV-474 and PCV-455C and blocking valves 8000A, 8000B and 8000C. The above PORVs can be closed from the hot shutdown panel in order to prevent uncontrolled pressure reduction. Therefore, safe shutdown is not affected. Auxiliary spray is credited for RCS pressure reduction. If RCP seal cooling is not returned within 8 minutes, then Westinghouse recommends that seal injection and CCW to the thermal barrier heat exchangers be isolated and allow the RCP seals to cool through natural circulation. Seal injection could be isolated by closing manual valves 8382A and 8382B to the RCP seal injection filters 2-2 and 2-1 and closing RCP seal return filter inlet isolation valve 8396A (located in the filter gallery in Fire Zone 3-X). In addition, FCV-357 can be manually closed to isolate the RCP thermal barrier CCW return flowpath. With the seal injection flowpath isolated, RCS makeup would need to be directed through the charging injection flowpath by locally opening 8801A and 8803A using their handwheel after opening their power supply breakers.
A fire in this area may spuriously operate pressurizer heater groups 2-1, 2-2, 2-3 and 2-4. These heater groups can be manually de-energized to ensure safe shutdown.
A fire in this area may prevent reactor coolant pumps 2-1, 2-2, 2-3 and 2-4 from being secured. Manual actions at the 12kV switchgear may be necessary to secure the reactor coolant pumps.
A fire in this area may affect all RCP seal cooling sources (seal injection and CCW to the RCP Thermal Barrier Heat Exchanger). To prevent thermal shock of the RCP seals, seal injection and CCW to the RCP TBHX can be isolated by operation of valves 8382A, 8382B, 8396A and FCV-357. The charging injection flowpath will be credited for RCS makeup.
Source range monitors NE-31 and NE-32 may be lost due to a fire in this area. NE-51 and NE-52 will be available to provide source range indication at the hot shutdown panel. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-B 9.5A-473 Revision 21 September 2013 Pressurizer level indication from LT-459, LT-460 and LT-461 may be lost due to a fire in this area. LT-406 will remain available to provide level indication at the dedicated shutdown panel.
A fire in this area may affect reactor vessel head vent valves 8078A, 8078B, 8078C and 8078D. Operator action can be taken to fail the valves closed. Safe shutdown is not affected.
Hot and cold leg temperature instrumentation in the control room may be lost due to a fire in this area. TE-423A and TE-423B can be read at the dedicated shutdown panel. 4.8 Residual Heat Removal System Valves 8701 and 8702 are closed with their power removed during normal operations and will not spuriously open. Also, these valves can be manually opened for RHR operations. A fire in this area may spuriously close 8700A and 8700B. These valves can be manually operated to ensure safe shutdown.
RHR pumps 2-1 and 2-2 may be affected by a fire in this area. Either RHR pump may be started from the 4kV switchgear room to provide RHR flow.
A fire in this area may affect FCV-641A and FCV-641B or cause spurious operation of the valves. During the transition to cold shutdown conditions, prior to starting the RHR Pump, the respective recirc valve can be manually operated. 4.9 Safety Injection System A fire in this area may affect valves 8982A, 8982B, 9003A and 9003B may spuriously open due to a fire in this area. Power to 8982A and 8982B is administratively removed by maintaining a toggle switch in the Control Room in the open position. These valves are normally closed, and spurious opening is not expected to occur. However, an operator action can be taken to open the power breakers to further preclude spurious opening of 8982A and 8982B. Valves 9003A and 9003B can be manually operated in order to defeat any spurious signals.
Accumulator isolation valves 8808A, 8808B, 8808C and 8808D may be affected by a fire in this area. These valves can be manually closed which is the desired position for safe shutdown.
SI pumps 2-1 and 2-2 may spuriously operate due to a fire in this area. Local manual action may be required to defeat this spurious operation. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-B 9.5A-474 Revision 21 September 2013 A fire in this area may spuriously open valve 8804A. This valve can be manually closed to ensure safe shutdown.
A fire in this area may affect RWST Level Transmitter LT-920. Alternative shutdown capability is credited in this fire area, and this transmitter is not credited for safe shutdown. 4.10 Auxiliary Saltwater System The ability to operate ASW pumps 2-1 and 2-2 from the control room may be lost due to a fire in this area. Manual actions will enable both pumps to be operated from the hot shutdown panel or the 4kV switchgear.
A fire in this area may affect valves FCV-495 and FCV-496. ASW system integrity is unaffected by a fire in this area since FCV-601 will remain closed.
A fire in this area may spuriously close valves FCV-602 and FCV-603. These valves can be manually opened to ensure safe shutdown.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Smoke and heat detection are provided.
- Total flooding CO2 system is provided.
- No storage area near hatch. The fire protection features provided in this area provide an acceptable level of fire safety equivalent to that provided by Section III.G.
6.0 REFERENCES
6.1 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.2 Drawing No. 515572 6.3 DCN DC2-EE-12694 - provides isolators Contact on DG 6.4 DCN DC2-EE-12670 - provides disconnect switch at HSD panel 6.5 Calculation M-824, Combustible Loading DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 7-B 9.5A-475 Revision 21 September 2013 6.6 Drawing 065127, Fire Protection Information Report, Unit 2 6.7 SSER 31, April 1985 6.8 DCPP Unit 2 Report of 10 CFR 50, Appendix R Review (Rev. 0) 6.9 File 131.91 Memo from S. Lynch to P. Hypnar dated 12/08/83, Re: Current Transformer Protection 6.10 DCNs DC2-EE-48591, DC2-EE-48593, and DC2-EE-48594 Provide Transfer Switches at the 4kV Switchgear and Mode Selector Switches at the Hot Shutdown Panel 6.11 DCN DC1-EE-46132, Provides Local Control Capability for the Diesel Generators 6.12 DCN DC2-EE-48607, DG 2-2 Starting Circuit Power Supply Transfer Switch 6.13 NECS File: 131.95, FHARE: 126; HVAC Ducts through Modified Unrated Hatches 6.14 NECS File: 131.95, FHARE:80, Fire Dampers Installed at Variance with Manufacturer's Instructions 6.15 NECS File: 131.95, FHARE 139, HVAC Duct Without a Rated Seal in Appendix R Barrier 6.16 Calculation 134-DC, Electrical Appendix R Analysis 6.17 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.18 NECS File: 131.95, FHARE 140, Unrated Penetrations through Unit 2 Control Room Floor (Barrier 458) 6.19 NECS File: 131.95, FHARE 134, "Non-rated Structural Gap Seals in Fire Barriers" 6.20 NECS File: 131.95, FHARE 147, "Evaluation of Lesser Rated Unistrut Configurations in 128' Cable Spreading Room." 6.21 NECS File: 131.95, FHARE 104, "Fireproofing on Structural Steel for Block Walls." 6.22 NECS File: 131.95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area Wide Detection/Suppression DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 8-H 9.5A-476 Revision 21 September 2013 FIRE AREA 8-H 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This area is located in the southwest corner of the Unit 2 Auxiliary Building at El. 140 ft. 1.2 Description Area 8-H, Unit 2 Safeguards room, houses Unit 2 solid state protection cabinets. Automatic reactor trip, SIS, containment/isolation and other safeguard signals are generated from these cabinets. 1.3 Boundaries North:
- 1-hour rated barrier separates this area from Zone 8-F. (Ref. 6.6)
- A duct penetration with no fire damper. (Ref. 6.9) South:
- 3-hour rated barrier separates this area from Area 34.
East:
- 3-hour rated barrier separates this area from Zone 8-D.
- A 3-hour rated door communicates to Zone 8-D.
- A duct penetration with no fire damper (the duct is protected within 8-H.) with a 3-hour rated fire damper at the outlet of the protected duct work. (Ref. 6.8)
West:
- 3-hour rated barrier separates this area from Fire Zone 19-D (Turbine Building).
Floor/Ceiling:
- 3-hour rated barrier: Floor: To Fire Area 7-B. Ceiling: To outside
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 8-H 9.5A-477 Revision 21 September 2013 2.0 COMBUSTIBLES 2.1 Floor Area: 225 ft2 2.2 In situ Combustible Materials
- Cable insulation 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection 3.2 Suppression
- Portable fire extinguishers
- Hose stations 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Auxiliary Feedwater AFW pumps 2-2 and 2-3 may be lost due to a fire in this area. Redundant pump 2-1 will be available to provide AFW. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 8-H 9.5A-478 Revision 21 September 2013 4.2 Chemical and Volume Control System Valves 8107 and 8108 may be affected by a fire in this area. Redundant valves HCV-142 or 8145 and 8148 can be closed to isolate auxiliary spray. 8145 will also fail close if operator action is taken to close SG blowdown valves. RCP seal injection will remain available to provide a charging flowpath to the reactor. The PORVs will remain available for RCS pressure reduction. Since these valves have redundant components available, safe shutdown will not be affected. A fire in this area may result in the loss of 8149A, 8149B and 8149C. Redundant valves LCV-459 and LCV-460 will remain available to isolate letdown isolation. Valves LCV-112B, LCV-112C, 8805A and 8805B may be affected by a fire in this area. The running charging pumps can be tripped from the control room to prevent cavitation. A pump can be restarted after the RWST is aligned and the VCT is isolated. Since one pair of valves must be closed (i.e., LCV-112B, 112C) if the other pair is open (8805A, 8805B), safe shutdown is not affected since both pairs of valves can be manually positioned. 4.3 Component Cooling Water The ability to operate CCW pumps 2-1, 2-2 and 2-3 from the control room may be lost due to a fire in this area. Manual actions will enable these pumps to be operated from the hot shutdown panel or the 4kV switchgear. A fire in this area may spuriously close valves FCV-356, FCV-357 and FCV-750. Since seal injection will be available, these valves are not required open and their position will not affect safe shutdown. Valve FCV-355 may spuriously close due to a fire in this area. FCV-355 can be manually operated for safe shutdown. 4.4 Containment Spray A fire in this area may affect containment spray pumps 2-1 and 2-2 or valves 9001A and 9001B. Operator action can be taken to trip the CS pumps. Therefore, safe shutdown is not affected. 4.5 Emergency Power A fire in this area may disable the diesel generator 2-1 automatic transfer circuit. Manual control will remain available in the control room to transfer and load the diesel generator. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 8-H 9.5A-479 Revision 21 September 2013 A fire in this area may disable the diesel generator 2-2 automatic transfer circuit. Manual control will remain available in the control room to transfer and load the diesel generator. A fire in this area may disable the diesel generator 2-3 automatic transfer circuit. Manual control will remain available in the control room to transfer and load the diesel generator. 4.6 Main Steam System A fire in this area may affect valves FCV-151, 154, 157, 160, 244, 246, 248, 250, 760, 761, 762 and 763. Operator for action can be taken to fail the SGBD valves closed and isolate the flowpath. Therefore, safe shutdown is not affected. A fire in this area may affect valves FCV-41, 42, 43 and 44. These valves can be manually closed to ensure safe shutdown. A fire in this area may prevent the 10% dump valves PCV-19, PCV-20, PCV-21 and PCV-22 from opening. These valves are required closed while in hot standby and can be manually opened for decay heat removal. 4.7 Reactor Coolant System Operator action to close SGBD valves will also fail pressurizer PORV PCV-456 closed. Redundant valve PCV-455C will remain available to RCS pressure reduction. 4.8 Safety Injection System Valves 8801A, 8801B, 8803A and 8803B may be affected by a fire in this area. A charging flowpath to the reactor will remain available through RCP seal injection. Additionally the PORVs will remain available for pressure reduction. A fire in this area may prevent the operation of or cause the spurious operation of valves 8808A, 8808B, 8808C and 8808D. These valves can be manually closed to ensure safe shutdown. SI pumps 2-1 and 2-2 may spuriously operate due to a fire in this area. Local manual action can be taken to defeat this spurious operation. 4.9 Auxiliary Saltwater System The ability to operate ASW pumps 2-1 and 2-2 from the control room may be lost due to a fire in this area. Manual actions will enable both ASW pumps to be operated from the hot shutdown panel or the 4kV switchgear. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 8-H 9.5A-480 Revision 21 September 2013
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown: The safe shutdown functions located in this area are not required once the reactor is tripped.
- Smoke detection is provided.
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
The existing fire protection features provide a level of safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.2 Drawing No. 515571 6.3 SSER 23, April 1984 6.4 Calculation M-824, Combustible loading 6.5 Drawing 065127, Fire Protection Information Report, Unit 2 6.6 NECS File: 131.95, FHARE 75, 1-hour Rated Barrier 6.7 NECS File: 131.95, FHARE: 15, HVAC Ducts Wrapped in Pyrocrete 6.8 NECS File: 131.95, FHARE: 80, Fire Dampers Installed at Variance with Manufacturers Instructions 6.9 NECS File: 131.95, FHARE 129, Duct penetrations through common walls associated with fire zones 8-A, 8-D, 8-E, 8-F, 8-G, and 8-H 6.10 Calculation 134-DC, Electrical Appendix R Analysis 6.11 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 9 FIRE ZONES 9-A, 9-B, 9-C 9.5A-481 Revision 21 September 2013 FIRE AREA 9 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Unit 2 containment building El. 91 ft through 140 ft - Containment annulus area.
1.2 Description Fire Area 9 is divided into three fire zones:
- 9-A Containment penetration area
- 9-B Reactor coolant pump area
- 9-C Control rod drive area Fire Zone 9-A is the annular region within containment between El. 91 ft and the operating deck at El. 140 ft. The annular region is bounded by the containment wall and the shield wall separating 9-A from 9-B.
Fire Zone 9-B is a cylindrical shaped region in the central part of containment. It is separated from Zone 9-A by the shield wall and from 9-C by the concrete operating deck. Fire Zone 9-C is comprised of the reactor cavity and the area above the reactor from El. 140 ft and above. The outer wall of this zone is the containment wall. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. 1.3.1 Fire Zone 9-A
- 3-hour rated containment barrier (outer wall).
- A nonrated reinforced concrete shield wall separates this zone from Zone 9-B.
- Nonrated openings and steel grating to 9-C.
- A nonrated reinforced concrete shield ceiling separates this zone from 9-C.
- Containment penetrations consisting of 5 ft schedule 80 pipe sleeves are in the area. The electrical conductors pass through a steel header plate and are encased in fire retardant epoxy. The space between the header plates is pressurized with nitrogen.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 9 FIRE ZONES 9-A, 9-B, 9-C 9.5A-482 Revision 21 September 2013 l.3.2 Fire Zone 9-B
- A nonrated reinforced concrete shield wall separates this zone from Zone 9-A.
- Nonrated reinforced concrete operating deck separates this zone from Zone 9-C.
- Nonrated openings, hatches, piping and ventilation penetrations are present. 1.3.3 Fire Zone 9-C
- 3-hour rated containment wall. NC
- Nonrated reinforced concrete separates this zone from Zones 9-A and 9-B. There are also nonrated openings into 9-B.
- Nonrated equipment and personnel hatches communicate through the containment wall. (Ref. 6.9) 2.0 COMBUSTIBLES (for entire area) 2.1 Floor Area: 26,551 ft2 2.2 In situ Combustible Materials
- Oil (in RCPs Cranes, fan cooler motors)
- Grease (in valve operators, cranes, fan cooler motors)
- Cable
- Carbon Filters
- Neoprene
- Rubber
- PVC
- Plastic
- Hepa filters 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 9 FIRE ZONES 9-A, 9-B, 9-C 9.5A-483 Revision 21 September 2013
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Fire Zone 9-A 3.1.1 Detection
- Smoke detection 3.1.2 Suppression
- Hose stations 3.2 Fire Zone 9-B 3.2.1 Detection
- Smoke detection above each RCP.
3.2.2 Suppression
- Wet pipe automatic sprinklers over each RCP with remote annunciating flow alarm.
- Hose stations 3.3 Fire Zone 9-C 3.3.1 Detection
- Flame detection on operating deck.
3.3.2 Suppression
- Hose stations DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 9 FIRE ZONES 9-A, 9-B, 9-C 9.5A-484 Revision 21 September 2013 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Fire Zone 9-A 4.1.1 Chemical and Volume Control System Pressurizer auxiliary spray valves 8145 and 8148 may be affected by a fire in this area. Redundant valves 8107, 8108 or HCV-142 will remain available to prevent uncontrolled pressure reduction. A cold shutdown repair will allow manual initiation of auxiliary spray. (Ref. 6.10) In addition, the circuits associated with valves 8145 and 8148 are contained in dedicated conduits.
Valves 8146 and 8147 may be affected by a fire in this area. An available seal injection flowpath will provide the required charging function. These valves can be manually closed in order to initiate auxiliary spray following a fire inside containment. Valves 8149A, 8149B, 8149C, LCV-459 and LCV-460 may be affected by a fire in this area. Operator action can be taken to fail valves 8149A, 8149B and 8149C closed. Therefore, isolation of letdown will not be affected.
CVCS valves 8166, 8167 and HCV-123 may be affected by a fire in this area. To make sure HCV-123 fails closed, remove instrument power. Excess letdown will remain isolated and safe shutdown is not affected. 4.1.2 Main Steam System Main steam system valves FCV-760, FCV-761, FCV-762 and FCV-763 may be affected by a fire in this area. The following redundant valves will remain available to isolate steam generator blowdown lines: FCV-151, FCV-250, FCV-154, FCV-248, FCV-157, FCV-246, FCV-160 and FCV-244. Therefore, safe shutdown is not affected.
A fire in this area may affect steam generator level for all four loops. Only one steam generator is necessary for safe shutdown. Therefore, steam generator level indication for SG 2-4, from LT-547 will remain available because it has been provided with a 1-hour fire wrap. (Refs. 6.11 and 6.12) 4.1.3 Reactor Coolant System RCS valves 8000A, 8000B, 8000C and PZR PORVs PCV-455C, PCV-456 and PCV-474 may be affected by a fire in this area. Valves 8000A, 8000B and 8000C are required closed if the PZR PORVs are open during hot standby to prevent uncontrolled pressure reduction. Since PCV-455C, PCV-456 and PCV-DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 9 FIRE ZONES 9-A, 9-B, 9-C 9.5A-485 Revision 21 September 2013 457 fail closed and their circuits are located in dedicated conduits, and administrative controls are provided to ensure hot short sources are not possible, uncontrolled pressure reduction will not occur. A 1-hour fire wrap is provided on junction box BJX263 and K1986 and penetration boxes BTX12E, BTX19E and BTX26E to ensure the integrity of the circuits for the subject valves. Auxiliary spray remains available for depressurization.
RCS reactor vessel head vent valves 8078A, 8078B, 8078C and 8078D may be affected by a fire in this area. Operator action can be taken to fail the valves closed. Therefore, safe shutdown is not affected.
Pressurizer level transmitters LT-406, LT-459, LT-460 and LT-461 may be affected by a fire in this area. Only one of the four level transmitters is required for safe shutdown. Since the LT-406 circuitry is separated from the LT-459 circuitry by 20 ft with no intervening combustibles, either one of these level transmitters will be available for safe shutdown. Source range monitors NE-31, NE-32, NE-51 and NE-52 may be affected by a fire in this area. Since NE-31 and NE-32 are separated by more than 20 ft with no intervening combustibles, one of these channels will remain available to provide neutron flux indication in the event of a fire. Therefore, safe shutdown will not be affected.
RCS pressure transmitters PT-405 and PT-406 may be affected by a fire in this area. PT-403 will remain available to provide RCS pressure indication.
A fire in this area may fail PCV-455A and PCV-455B closed. Since these valves fail in the desired, closed position, safe shutdown is not affected. RCPs can also be tripped to mitigate spurious operation of the pressurizer spray valves.
Temperature indication on TE-413A, TE-413B, TE-423A, TE-423B, TE-433A, TE-433B, TE-443A and TE-443B may be affected by a fire. Due to the presence of 1-hour fire wraps, temperature indication on steam generator loops 3 and 4 will remain operational in the event of a fire. (Ref. 6.12) 4.1.4 Residual Heat Removal System RHR valves 8701 and 8702 may be affected by a fire in this area. These valves are normally closed with power removed and will not spuriously operate. These valves can be manually operated to their safe shutdown position.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 9 FIRE ZONES 9-A, 9-B, 9-C 9.5A-486 Revision 21 September 2013 4.1.5 Safety Injection System SI valves 8808A, 8808B, 8808C and 8808D may be affected by a fire in this area. These valves can be manually closed for RCS pressure reduction. 4.2 Fire Zone 9-B 4.2.1 Chemical and Volume Control System CVCS valves LCV-459 and LCV-460 may be affected by a fire in this area. Valves 8149A, 8149B, 8149C remain available to provide letdown isolation. 4.2.2 Main Steam System Main steam system valves FCV-760, FCV-761, FCV-762 and FCV-763 may be affected by a fire in this area. The following redundant valves will remain available to isolate steam generator blowdown lines: FCV-151, FCV-250, FCV-154, FCV-248, FCV-157, FCV-246, FCV-160 and FCV-244. Therefore, safe shutdown is not affected. 4.2.3 Reactor Coolant System RCS valves 8000A, 8000B, 8000C and PZR PORVs PCV-455C, PCV-456 and PCV-474 may be affected by a fire in this area. Valves 8000A, 8000B and 8000C are required closed if the PZR PORV are open during hot standby to prevent uncontrolled pressure reduction. Since PCV-455C, PCV-456 and PCV-474 fail closed in the event of a fire, uncontrolled pressure reduction will not occur. Auxiliary spray will remain available to provide pressure reduction capabilities. Therefore, safe shutdown is not affected.
The reactor vessel head vents 8078A, 8078B, 8078C and 8078D may be affected by a fire in this area. It would take two independent spurious signals to provide a path for the flow of reactor coolant which is not a credible scenario. If this were to occur, the charging pumps would be able to keep up with RCS inventory loss.
A fire in this zone may affect instrument sensing lines for LT-459, LT-460, LT-461, LT-406, and PT-406. This instrument is either shielded by the pressurizer vessel or protected by a heat shield. No electrical circuitry for this instrument exists in this fire zone. Therefore, safe shutdown is not affected.
Source range monitors NE-31, NE-32, NE-51 and NE-52 may be affected by a fire in this area. Since NE-31 and NE-32 are separated by more than 20 ft with DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 9 FIRE ZONES 9-A, 9-B, 9-C 9.5A-487 Revision 21 September 2013 no intervening combustibles, one of these channels will be available to provide neutron flux indication. Therefore, safe shutdown will not be affected. The following instrumentation for hot leg and cold leg temperatures: TE-413A, TE-413B, TE-423A, TE-423B, TE-433A, TE-433B, TE-443A and TE-433B may be affected by a fire in this area. TE-413A and TE-413B, and TE-423A and TE-423B, are separated by over 20 ft from TE-433A and TE-433B, and TE-4/43A and TE-443B, with no intervening combustibles. Therefore, safe shutdown will not be affected. 4.2.4 Residual Heat Removal System RHR valve 8702 may be affected by a fire in this area. 8702 is normally closed with its power removed during normal operations and will not spuriously operate. This valve can be manually operated to its safe shutdown position. 4.3 Fire Zone 9-C 4.3.1 Reactor Coolant System RCS valves 8000A, 8000B, 8000C and PZR PORVs PCV-455C, PCV-456 and PCV-474 may be affected by a fire in this area. Valves 8000A, 8000B and 8000C are required closed if the PZR PORV are open during hot standby to prevent uncontrolled pressure reduction. Since PCV-455C, PCV-456 and PCV-474 fail closed in the event of a fire, uncontrolled pressure reduction will not occur. Therefore, safe shutdown is not affected. Auxiliary spray will remain available for RCS pressure reduction.
Source range monitors NE-31, NE-32, NE-51 and NE-52 may be affected by a fire in this area. Since NE-31 and NE-32 are separated by more than 20 ft with no intervening combustibles, one of these channels will be available to provide neutron flux indication. Therefore, safe shutdown will not be affected. The reactor vessel head vents 8078A, 8078B, 8078C and 8078D may be affected by a fire in this area. Operator action can be taken to fail the valves closed. Therefore, safe shutdown is not affected.
5.0 CONCLUSION
S The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3 hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 9 FIRE ZONES 9-A, 9-B, 9-C 9.5A-488 Revision 21 September 2013
- Safe shutdown equipment utilized for safe plant shutdown are not adversely effected by a fire in this area due to spatial separation and barriers provided.
- Manual fire fighting equipment is provided for this area.
- Automatic wet pipe sprinklers are provided over each RCP.
- Smoke detection is provided for Zone 9-A and above each RCP in Zone 9-B.
- Flame detection is provided on the operating deck of Zone 9-C. A deviation from the requirements of 10 CFR 50, Appendix R, Section III.G.2 was requested in the report on 10 CFR 50, Appendix R Review because a noncombustible radiant energy shield between redundant shutdown divisions was not provided when separation was less than 20 ft. A 1-hour rated fire barrier was provided and SSER concluded that the modifications brought the area into compliance and that no deviation was required. An RCP lube oil collection system is provided for the RCPs in Zone 9-B. A deviation from the requirements of 10 CFR 50, Appendix R, Section III.O was requested because the oil holding tank's are not large enough to hold the contents of the entire lube oil system inventory for the four RCPs. The existing system is designed to hold the oil for one RCP plus some margin.
This deviation was granted in SSER 31.
6.0 REFERENCES
6.1 Drawing No. 515577 and 515578 6.2 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.3 DCN D2-EA-22612, provide 1-hour barrier for boxes and conduits 6.4 Calculation M-824, Combustible Loading 6.5 Drawing 065127, Fire protection Information Report, Unit 2 6.6 Deleted in Revision 13. 6.7 SSER 31, April 1985 6.8 Procedure EP-M10, Fire Protection of Safe Shutdown Equipment 6.9 NECS File: 131.95, FHARE: 94, Containment Personnel Airlock Doors 6.10 NECS File: 131.95, FHARE: 101, Separation of Pressurizer PORV and Auxiliary Spray Valve Circuits in the Containment Annular Area 6.11 NECS File: 131.95, FHARE: 105, Nonrated Mechanical Panels in Containment 6.12 DCP A-48568, Containment Fire Wrap Modifications 6.13 Calculation 134-DC, Electrical Appendix R Analysis 6.14 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 20 9.5A-489 Revision 21 September 2013 FIRE AREA 20 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Unit 2 southeast corner of the Turbine Building at El. 76 ft and 85 ft. 1.2 Description This area includes the 12kV switchgear room at El. 85 ft and the 12kV cable spreading room beneath, at El. 76 ft. The cable spreading room is accessed by open stairwells communicating between the two elevations of this area. 1.3 Boundaries North: 85' Elevation
- A 3-hour rated barrier to Fire Zone 19-A (TB-7). (Ref. 6.13)
- A 3-hour rated door to Fire Zone 19-A. 76' Elevation (Ref. 6.29)
- Unrated conduit penetration seals (Ref 6.28). South:
85' Elevation
- A 2-hour rated barrier to the exterior (Fire Area 29). (Refs. 6.8 and 6.24)
- A 2-hour rated barrier to Fire Zone S-7 (TB-13). (Ref. 21)
- A 3-hour rated roll up door to the exterior (Fire Area 29).
- Unrated penetration to the exterior (Fire Area 29). (Ref. 6.16)
- Unsealed Bus duct penetrations to Fire Area 29. (Ref. 6.6) 76' Elevation (Ref. 6.29)
- Unrated conduit penetration seals (Ref 6.28). East:
85' Elevation
- A 2-hour rated barrier to the exterior (Fire Area 29). (Ref. 6.24)
- A 3-hour rated roll up door in front of a 1-1/2 hour equivalent rated door to the exterior.
- A 3-hour rated roll up door over wall louvers to the exterior (Fire Area 29). (Refs. 6.8 and 6.17)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 20 9.5A-490 Revision 21 September 2013
- Unsealed Bus duct penetrations to Fire Area 29. (Ref. 6.6) 76' Elevation (Ref. 6.29)
- Unrated conduit penetration seals (Ref. 6.28). West:
85' Elevation
- A 3-hour rated barrier to Fire Area 22-C. (Ref. 6.24)
- A 2-hour rated barrier to Fire Zone S-7 (TB-13). (Ref. 6.21)
- Unrated small diameter penetration to Area 22C. (Ref. 6.16)
- A 3-hour rated door to Fire Area 22-C.
- A 3-hour rated roll-up door to Fire Area 22-C.
- A 3-hour rated fire damper to Fire Area 22-C.
- Lesser rated penetration seal to Fire Area 22-C. (Ref. 6.25) 76' Elevation (Ref. 6.29)
- Unrated conduit penetration seals (Ref. 6.28). Floor/Ceiling:
- 3-hour rated barriers with the following exception:
- A 2-hour rated enclosed stairwell with a nonrated ceiling and a 1-1/2-hour rated door communicates to Fire Zone 23-E (TB-7). (Ref. 6.10) - Lesser rated penetration seal to Fire Zone 23-E. (Ref. 6.25)
- Unprotected structural steel supporting the ceiling of the 85-ft elevation. (Ref. 6.9)
- A 3-hour rated concrete equipment plug to Fire Zone 23-B (TB-11) above, on unprotected steel supports with unsealed gaps. (Refs. 6.9 and 6.11)
Fire Resistive
Enclosures:
- Ten vertical conduit banks, routed to Fire Zone 23-A, 23-B and 23-C (Fire Areas TB-10, TB-11 and TB-12 respectively) are enclosed in this area on El. 85 ft, with a 2-hour rated fire barrier. Those on El. 76 ft are also protected either with the rated enclosure or by being located in embedded conduits.
(Refs. 6.11, 6.14, 6.15, 6.18, 6.19, 6.23, 6.26, and 6.27.)
- 3-hour fire resistive covering is provided for all the structural steel on El. 76 ft. (Refs. 6.1 and 6.9)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 20 9.5A-491 Revision 21 September 2013 2.0 COMBUSTIBLES 2.1 Floor Area: 4,095 ft2 (El. 76 ft), 6,160 ft2 (El. 85 ft) 2.2 In situ Combustible Materials
- Cable insulation
- PVC
- Fiberglass 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low (El. 76 ft)
- Low (El. 85 ft) 3.0 FIRE PROTECTION 3.1 Detection
- Smoke detection at both elevations. 3.2 Suppression
- Portable fire extinguishers.
- CO2 hose stations.
- Hose stations available in vicinity.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 20 9.5A-492 Revision 21 September 2013 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Auxiliary Feedwater System A fire in this area may affect AFW Pumps 2-2 and 2-3 and level control valves LCV-110, LCV-111, LCV-113, and LCV-115. Redundant AFW Pump 2-1 and LCV-106, LCV-107, LCV-108, and LCV-109 will remain available for safe shutdown. 4.2 Emergency Power A fire in this area may disable the diesel generator 2-2 automatic transfer circuit. Manual control will remain available in the control room to transfer and load the diesel generator.
The circuits associated with diesel generators 2-1 and 2-3 are protected with a 2-hour fire rated enclosure and will be available for safe shutdown. A fire in this area may disable startup transformer 2-2. Manual action may be credited to locally trip startup transformer breakers and manually start DG 2-1. Onsite power will remain available from diesel generators 2-1, 2-2 and 2-3. 4.3 Reactor Coolant System Control of reactor coolant pumps may be lost due to a fire in this area. Safe shutdown will not be affected if the RCPs continuously run. CCW to the thermal barrier heat exchanger or seal injection will remain available for RCP seal cooling. 4.4 Other Systems A fire in this area may affect safe shutdown equipment on Buses "F", "G" and "H". The banks are separated by a fire rated enclosure with a minimum fire rating of 2 hours in both the switchgear and cable spreading rooms. The unprotected panels and conduits at El. 76 ft have been evaluated and will not affect safe shutdown. (Refs. 6.5, 6.16, 6.17, 6.18, 6.20, 6.23, and 6.26)
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 20 9.5A-493 Revision 21 September 2013 adequate separation between redundant components to assure safe shutdown.
- Safe shutdown circuitry utilized in safe plant shutdown is not adversely affected due to the fire barriers provided (min. 2-hour enclosure on "F", "G" and "H" Buses) and the spatial separation provided. (Refs. 6.5, 6.14, 6.15, 6.18, 6.19, 6.20, and 6.23)
- Smoke detection provided in both elevations.
- Portable fire extinguishers and CO2 hose stations are available within the area and fire hose stations are nearby.
The existing fire protection features provide an acceptable level of safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 DCN DCI-EA-36409 Structural Steel Fire Rated Covering 6.2 Drawing Number 515573, 515574 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065127, Fire Protection Information Report, Unit 2 6.5 NECS File: 131.95, FHARE: 18, Conduits Not Enclosed in 2 Hour Enclosures 6.6 NECS File: 131.95, FHARE: 20, Unsealed Bus Duct Penetration 6.7 Not used 6.8 SSER 8, November 1978 6.9 PLC Report: Structural Steel Analysis for Diablo Canyon Rev. 2 (7/8/86) 6.10 NECS File: 131.95, FHARE: 4, Stairwell Nonrated Ceiling 6.11 NECS File: 131.95, FHARE: 14, Concrete Equipment Hatches 6.12 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.13 NECS File: 131.95, FHARE: 82 Dow Corning Penetration Seal Through Concrete Block Wall 6.14 NECS File: 131.95, FHARE: 45, 3-M Fire Wrap Repair of Pyrocrete Enclosures 6.15 PG&E Design Change Notice DC2-EA-050070, Unit 2 ThermoLag Replacement 6.16 NECS File: 131.95, FHARE 123, Unsealed penetrations with fusible link chain penetrants through fire barriers 6.17 Question 25, PG&E letter to NRC dated 8/3/78 6.18 "Fire Endurance Test of Pyrocrete Box Fire Protective Envelopes," Test Report by Omega Point Laboratories, October 18, 1996 6.19 PG&E Design Change Notice DC2-EC-050339, Unit 2, "Provide Pyrocrete Fire Barriers" DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 20 9.5A-494 Revision 21 September 2013 6.20 NECS File: 131.95, FHARE 138, Drain Holes in Pyrocrete Panels in Fire Area 10 and 20 6.21 NECS File: 131.95, FHARE 122. Staircase S-7 Fire Area Boundary 6.22 Calculation 134-DC, Electrical Appendix R Analysis 6.23 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.24 NECS File: 131.95, FHARE 133, Seismic/Construction Gaps in the 12kV Switchgear Rooms 6.25 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.26 NECS File: 131.95, FHARE 145, Pyrocrete Enclosure Thickness 6.27 PG&E Design Change AT-MM AR A0666894, Relocation of Drain Holes in Pyrocrete Panels 6.28 NECS File: 131.95, FHARE 151, Evaluation of Fire Area Boundaries for the 76' Elevation of Fire Areas 10 and 20. 6.29 NECS File: 131.95, FHARE 154, Removal of Below Grade 12-kV Cable Spreading Room Barriers from the Fire Protection Program DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 22-C 9.5A-495 Revision 21 September 2013 FIRE AREA 22-C 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Unit 2 Turbine Building, corridor outside diesel generator rooms, El. 85 ft.
1.2 Description Fire Area 22-C is the corridor at El. 85 ft in the Unit 2 Turbine Building that separates the diesel generator rooms; Zones 22-A-1 (TB-8), 22-B-1 (TB-9) and 22-C-1 from the 12-kV switchgear room (Area 20) and stairway Zone S-7 (TB-13). 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- A 3-hour rated barrier to Fire Zone 19-A (TB-7).
- A 3-hour rated double door to Fire Zone 19-A. South:
- A 3-hour rated barrier to the exterior (Fire Zone 29).
- A 3-hour rated double door to the exterior (Fire Area 29). East:
- A 3-hour rated barrier to Fire Area 20 and Fire Zone S-7 (TB-13). (Ref. 6.20)
- A 3-hour rated door to Fire Area 20.
- A 3-hour rated roll-up door to Fire Area 20.
- A duct penetration with a 3-hour rated fire damper to Area 20.
- A 1-1/2-hour rated door and non-rated seismic gaps to Fire Zone S-7 (TB-7). (Refs. 6.5 and 6.19)
- A lesser rated penetration seal to Area 20. (Ref. 6.23)
West:
- A 3-hour rated barrier to Fire Zones: (Ref. 6.22) - 22-A-1 (TB-8)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 22-C 9.5A-496 Revision 21 September 2013 - 22-B-1 (TB-9) - 22-C-1 (TB-17)
- 22-B-2 (TB-9)
- Unsealed penetration to Zone 22-A-1. (Ref. 6.21)
- Unrated small diameter penetrant to each Zone 22-A-1, 22-B-1, 22-C-1. (Ref. 6.16)
- Unsealed penetration to Zone 22-A-1. (Ref. 6.21)
- Unrated structural gap seal to Zone 22-C-1. (Ref. 6.22)
- A 3-hour rated roll-up door and personnel door to Zones 22-A-1 and 22-C-1.
- A 3-hour rated roll-up door to Zone 22-B-1.
- A 3-hour rated door to Zone 22-B-2.
Floor:
- Concrete on grade. NC Ceiling:
- 3-hour rated barrier to Fire Zones 23-A (TB-10) and 23-B (TB-11) and 23-C-1 (TB-13) above.
- A duct penetration without a fire damper to Fire Zone 23-C-1 (TB-3). (Refs. 6.5 and 6.10) 2.0 COMBUSTIBLES
2.1 Floor Area: 459 ft2 2.2 In situ Combustible Materials
- Cable insulation
- Clothing/Rags
- Rubber
- Plastic 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 22-C 9.5A-497 Revision 21 September 2013
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection None
3.2 Suppression
- Automatic wet pipe sprinklers with remote annunciation.
- Portable fire extinguishers
- Fire hose stations 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Emergency Power System A fire in this area may affect diesel fuel oil transfer pumps 0-1 and 0-2. The circuits for diesel fuel oil transfer pumps are enclosed in fire barriers. SSER 31 justifies this deviation. Offsite power will be available for safe shutdown in the event diesel fuel oil circuits are damaged by a fire. Therefore, safe shutdown is not affected. A fire in this area may affect day tank level control valves LCV-85, 86, 87, 88 and 89, and 90. The circuits for these valves are enclosed in fire barriers and the deviation mentioned above also applies to these valves. Offsite power will be available for safe shutdown in the event diesel fuel oil circuits are damaged by a fire. Diesel generator 2-1 circuits located in this area and the emergency stop switch are enclosed in fire barriers. Offsite power will be available for safe shutdown in the event diesel fuel oil circuits are damaged by a fire. The configuration in this area will provide an acceptable level of fire safety equivalent to that provided by Section III.G.2 of Appendix R. (Refs. 6.7, 6.11, 6.12, 6.14, 6.15, and 6.18) Diesel generator 2-2 circuits located in this area and the emergency stop switch are enclosed in fire barriers. The configuration in this area will provide an DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 22-C 9.5A-498 Revision 21 September 2013 acceptable level of fire safety equivalent to that provided by Section III.G.2 of Appendix R. Offsite power will be available for safe shutdown in the event diesel fuel oil circuits are damaged by a fire. (Refs. 6.7, 6.11, 6.12, 6.14, 6.15, and 6.18) All diesel generator 2-3 circuits located in this area are enclosed in a fire barrier. Offsite power will be available for safe shutdown in the event diesel fuel oil circuits are damaged by a fire. Therefore, diesel generator 2-3 will remain available for safe shutdown. (Refs. 6.13 and 6.15) The switches and circuits associated with the CO2 suppression system manual actuation system for the Unit 2 diesel generator room and circuits may be affected by a fire in this area. The cables for the switches are mineral insulated with a fire rating of 2 hours to preclude inadvertent actuation of the CO2 suppression system and automatic closure of the rollup door in the diesel generator room. Offsite power will be available for safe shutdown in the event diesel fuel oil circuits are damaged by a fire.
5.0 CONCLUSION
This area does not meet the requirements of 10 CFR 50, Appendix R, Section III.G.2, because of the lack of an area wide fire detection system.
- A deviation from 10 CFR 50, Appendix R, Section III.G.2 was requested, and granted in SSER 31.
The following features adequately mitigate the effects of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Isolators for diesel generator speed indication circuitry have been provided.
- An automatic wet pipe sprinkler system and manual fire fighting equipment is provided for this area.
- Although not required, fire barriers are provided for conduits containing diesel generator field circuits.
The existing fire protection for this area provides an acceptable level of safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 22-C 9.5A-499 Revision 21 September 2013
6.0 REFERENCES
6.1 Drawing Number 515573 6.2 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065127, Fire protection Information Report, Unit 2 6.5 SSER 31, April 1985 6.6 DCN DC2-EE-10913 - Provide Isolator 6.7 DCN DC2-EE-22613 - Provide 1 Hour barrier 6.8 Deleted 6.9 Architectural Drawing Number 502989 6.10 NECS File: 131.95, FHARE: 33, Undampered Ventilation Duct Penetrations 6.11 DCP A-48449, Provides 3-Hour Fire Rated Barrier for Unit 2 Diesel Generator Circuitry 6.12 DC2-EA-48386, Modify Thermo-Lag Fire Protection Enclosure for Diesel Generator Switch Boxes 6.13 DC2-EA-44405, Sixth Diesel Generator Design 6.14 NCR DCO-91-EN-N027 6.15 PG&E Design Change Notice DC2-EA-050070, Unit 2 ThermoLag Replacement 6.16 NECS File: 131.95, FHARE 123, Unsealed penetrations with fusible link chain penetrants through fire barriers 6.17 Calculation 134-DC, Electrical Appendix R Analysis 6.18 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.19 NECS File: 131.95, FHARE 122, Staircase S-7 and S Fire Area Boundary 6.20 NECS File: 131.95, FHARE 133, Seismic/Construction Gaps in the 12kV Switchgear Rooms 6.21 NECS File: 131.95, FHARE 103, Fire Barrier Configurations in the Emergency Diesel Generator Rooms 6.22 NECS File: 131.95, FHARE 30, Unrated Gaps in Appendix R Barriers in the Turbine Building 6.23 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 24-D 9.5A-500 Revision 21 September 2013 FIRE AREA 24-D 1.0 PHYSICAL CHARACTERISTICS
1.1 Location South end of Unit 2 Turbine Building at El. 119 ft between the 4kV switchgear room and the fan room for the 4kV switchgear and cable spreading rooms. 1.2 Description This is the excitation switchgear room at El. 119 ft. Duct work passes through this fire area. There is no safe shutdown equipment installed in this fire area. However, ventilation ducts providing cooling into safety-related 4kV switchgear required for safe shutdown passes through this area. 1.3 Boundaries North:
- A 3-hour rated barrier to Fire Zone 23-E (TB-7).
- Unrated structural gap seal to Fire Zone 23-E (TB-7). (Ref. 6.18) Note: Structural steel modifications for the block walls were deemed acceptable with no fireproofing. (Ref. 6.11)
- A 1-1/2-hour rated door to Fire Zone 23-E. (Ref. 6.8)
South:
- A 2-hour rated barrier to the exterior (Fire Area 29).
- A 2-hour rated barrier to Fire Zone S-7 (TB-13). (Ref. 6.14)
- A vent with a 1-1/2-hour rated fire damper to the exterior. East:
- A 3-hour rated barrier to Fire Zones 24-A (TB-10), 24-B (TB-11) and 24-C (TB-12).
- Unrated structural gap seals to Fire Zones 24-A (TB-10), 24-B (TB-11), and 24-C (TB-12). (Ref. 6.18)
- Three 1-1/2-hour rated doors, one to each of the following fire zones: 24-A (TB-10), 24-B (TB-11),and 24-C (TB-12) with pyrocrete blockouts above doors. (Ref. 6.21)
- Three 1-1/2 rated fire dampers, one to each of the following fire zones: 24-A (TB-10), 24-B (TB-11), and 24-C (TB-12).
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 24-D 9.5A-501 Revision 21 September 2013 West:
- A 2-hour rated barrier to Fire Zone 24-E (TB-13). (Ref. 6.17)
- Three duct penetrations without fire dampers to Fire Zone 24-E (TB-13). (Ref. 6.7)
- Lesser rated penetration seal to Fire Zone 24-E (TB-13). (Ref. 6.20)
- 2-hour rated barrier to Fire Zone S-7 (TB-13). (Ref. 6.14)
- A 1-1/2-hour rated door to Fire Zone S-7 (TB-13).
- A duct penetration without a damper to Fire Zone S-7 (TB-13). (Ref. 6.7) Ceiling:
- 3-hour rated barrier to Fire Zone 19-D. (Ref. 6.19)
- 3-hour rated equipment hatch penetrates to Zone 19-D. The hatch is supported by unprotected steel structures. (Refs. 6.6 and 6.10)
Floor:
- 3-hour rated barrier to Fire Zones 23-A (TB-10), 23-B (TB-11) and 23-C (TB-12).
- 3-hour rated equipment hatch penetrates to Fire Zone 23-B (TB-11). The hatch is supported by unprotected steel structures. (Refs. 6.6 and 6.10)
- A duct penetration without a damper to Zone 23-A (TB-10). (Refs. 6.7 and 6.13)
Protective
Enclosure:
- There is ductwork near the ceiling of this area which communicates from the east wall to the west wall and is provided with a 1-hour rated enclosure. (Ref. 6.5) - Two ducts from Zone 24-E
- One duct from Zone S-7 2.0 COMBUSTIBLES
2.1 Floor Area: 1,054 ft2 2.2 In situ Combustible Materials
- Cable insulation
- Rubber
- Paper
- PVC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 24-D 9.5A-502 Revision 21 September 2013 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection is provided.
3.2 Suppression
- CO2 hose station
- Fire hose station
- Portable fire extinguishers 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Emergency Power System A fire in this area may disable diesel generators 2-1, 2-2 and 2-3 automatic transfer circuit or may spuriously close the auxiliary transformer 22 circuit breakers. Offsite power is not affected in this area and will remain available for safe shutdown. In addition, manual action will enable the diesel to either be locally loaded or loaded from the control room. 4.2 HVAC HVAC fan S-68 may be lost due to a fire in this area. No action is required for loss of HVAC in the 4kV switchgear room. (Ref. 6.12) DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 24-D 9.5A-503 Revision 21 September 2013 Ducts for the three redundant 4kV switchgear rooms are located in this fire area. An alternate cooling air flow path is available through the associated cable spreading room for each switchgear room.
5.0 CONCLUSION
S
The following features adequately mitigate the consequences of the design basis fire and assure the ability to achieve safe shutdown.
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Manual fire fighting equipment is provided.
- Local smoke detection is provided.
- Loss of the safe shutdown circuitry in this area does not affect the ability to transfer to the emergency diesel generators.
This area meets the requirements of 10 CFR 50, Appendix R, Section III.G and no exemptions or deviations have been requested.
6.0 REFERENCES
6.1 Drawing Number 515575 6.2 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065127, Fire Protection Information Report, Unit 2 6.5 NECS File: 131.95, FHARE: 15, HVAC Ducts Wrapped with Pyrocrete 6.6 NECS File: 131.95, FHARE: 14, Concrete Equipment Hatches 6.7 NECS File: 131.95, FHARE: 33, Undampered Ventilation Duct Penetrations 6.8 NECS File: 131.95, FHARE: 70, Lesser Rated Door from 24-D to 23-E 6.9 NECS File: 131.95, FHARE: 118, Appendix R Fire Area Plaster Barriers 6.10 PLC Report: Structural Steel Analysis for Diablo Canyon (Rev. 2) (07/08/86) 6.11 NECS File: 131.95, FHARE: 106, Block Walls Modified in the 4kV Switchgear Area 6.12 Calculations, M-911 and M-912 6.13 NECS File: 131.95, FHARE: 136, Unrated HVAC Duct Penetrations 6.14 NECS File: 131.95, FHARE: 122, Staircase S-7, Fire Area Boundary 6.15 Calculation 134-DC, Electrical Appendix R Analysis DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 24-D 9.5A-504 Revision 21 September 2013 6.16 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.17 NECS File: 131.95, FHARE 118, Appendix R Fire Area Plaster Barriers. 6.18 NECS File: 131.95, FHARE 134, "Non-rated Structural Gap Seals in Fire Barriers" 6.19 NECS File: 131.95, FHARE 30, Unrated Gaps in Appendix R Barriers in the Turbine Building 6.20 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.21 DCN DC2-EA-24390, Provide 3-Hour Rated Double Doors and Plaster Block Out DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 29 9.5A-505 Revision 21 September 2013 FIRE AREA 29 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Yard area surrounding the Unit 2 Building including the main transformer area. 1.2 Description This fire area is the open yard area surrounding the Unit 2 power plant building at El. 85 ft. The fire area includes the transformer area located south of the containment, the fire area also includes the area south and south east of the Turbine Building. Three main transformers and a spare main transformer are a minimum of 50 ft from the Turbine Building. The two auxiliary transformers are approximately 30 ft away, and the startup transformer and its spare are about 15 ft away. Spilled oil will drain away from the turbine and containment buildings due to the pavement grade. The pipe chase outside containment is approximately 40 ft away from one of the nearest transformers. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North: Containment
- 3-hour rated barrier. NC Turbine building
- Non-rated wall to Fire Area 23-C-1, NC El. 104 ft
- 2-hour rated barrier except for doors and ventilation openings fitted with class "A" labeled devices to Fire Area 20. (Ref. 6.9)
- Nonrated walls and louvers to common exhaust plenum for diesel generator fire zones 22-A-2 (Fire Area TB-8), NC 22-B-2 (TB-9) NC and 22-C-2 NC at El. 85 ft and El. 104 ft. (Ref. 6.12).
- 2-hour rated gypsum board shaft type fire barrier interior walls at El. 107 ft and 119 ft. (Ref. 6.13)
- Unsealed bus duct penetrations to Fire Area 20. (Ref. 6.10)
- Unrated penetration to Fire Area 20. (Ref. 6.11)
- 2-hour rated barrier to Fire Zone S-7 (El. 85 ft, 104 ft, and 119 ft)
- Non-rated barrier with roll-up door to Fire Zone 19-A. NC (El. 85 ft)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 29 9.5A-506 Revision 21 September 2013
- Non-rated barrier with louvers to Fire Zone 19-A NC (El. 119 ft and 140 ft)
- Non-rated barrier and door to Fire Zone 19-A NC (El. 104 ft)
- 2-hour rated barrier with a duct penetration with 1-1/2-hour rated damper to Area 24-D (El. 119 ft)
South:
- Outside nonrated area East:
- Outside nonrated area West:
Turbine building
- Unsealed bus duct penetrations to Fire Area 20. (Ref. 6.10)
- 2-hour rated concrete barrier except for doors and ventilation openings fitted with class "A" labeled devices to Fire Area 20. (Ref. 6.9)
- Nonrated walls, roll up doors and louvers to Fire Zone 19-A NC (El. 85 ft, 104 ft, and 119 ft) Fire Area TB-7 and 19-D NC (El. 140 ft).
- Nonrated walls and louvers to Fire Zone 19-C NC (TB-7).
- 2-hour rated gypsum board shaft type fire barrier interior walls at El. 107 ft and 119 ft. (Ref. 6.13)
- A nonrated ISO phase bus penetrations and a louver with a fire damper to Fire Zone 23-E NC (El. 119 ft). 2.0 COMBUSTIBLES 2.1 Floor Area: 16,092 ft2 2.2 In situ Combustible Materials
- Transformer oil contained in the main transformer
- Cable
- Plastic 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 29 9.5A-507 Revision 21 September 2013
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- High 3.0 FIRE PROTECTION 3.1 Detection None 3.2 Suppression
- The three main transformers, two auxiliary transformers and the startup transformer are provided with automatic spray systems with remote annunciation.
- Hose station
- Yard hydrants with fully equipped hose houses
- Portable fire extinguishers 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Auxiliary Feedwater Control of AFW valves LCV-106, LCV-107, LCV-110 and LCV-111 from the control room and hot shutdown panel may be lost due to a fire in this area.
Valves LCV-108, LCV-109, LCV-113 and LCV-115 will be available to provide AFW supply to SGs 2-3 and 2-4. The main feedwater pumps are tripped in the control room. 4.2 Main Steam System Steam Generator Pressure instrumentation PT-514, PT-515, PT-516, PT-524, PT-525, and PT-526 may be lost due to a fire in this area. Steam generator pressure indication from PT-534, PT-535, PT-536, PT-544, PT-545 and PT-546 will remain available for steam generators SG 2-3 and SG 2-4.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 29 9.5A-508 Revision 21 September 2013 Valves FCV-24, FCV-25, FCV-41 and FCV-42 may be affected by a fire in this area. These valves have fusible links which, melt and cause them to fail closed. (Ref. 6.6) A fire in this area may affect 10 percent dump valves PCV-19 and PCV-20. These valves fail closed, which is the required position for safe shutdown. For spurious operation protection, fail PCV-19 and PCV-20 closed with actions in the fire area. Redundant valves PCV-21 and PCV-22 will remain available for cooldown. 4.3 Main Feedwater System A fire in this area may affect main feedwater valves FCV-1510, FCV-1520, FCV-510, and FCV-520. The main feedwater pumps can be tripped from the control room to stop feedwater flow through these valves. 4.4 Reactor Coolant System Source range monitor NE-51 may be lost due to a fire in this area. Redundant components NE-31, NE-32 and NE-52 will be available to provide necessary indications to the operator.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown.
- The redundant trains of safe shutdown functions located in this fire area are unaffected by fire in this area due to spatial separation and barriers provided.
- Automatic water spray systems operate to control a fire involving the transformer area.
- The grade of the transformer area is sloped to divert spilled oil away from the turbine and containment building.
- Many exposed walls of adjacent fire areas/zones are at least 2-hour rated with penetrations sealed commensurate with the hazard.
This area complies with the requirements of 10 CFR 50, Appendix R, Section III.G and no exemptions have been requested.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA 29 9.5A-509 Revision 21 September 2013
6.0 REFERENCES
6.1 Drawing Number 515573 6.2 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.3 Calculation Number M-671 - Fire Protection/Fire Barriers (Turbine building) 6.4 Calculation M-824, Combustible Loading Calculation 6.5 Drawing 065127, Fire Protection Information Report, Unit 2 6.6 Response to Q.31 of PG&E letter dated August 3, 1978 6.7 Calculation 134-DC, Electrical Appendix R Analysis 6.8 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.9 NECS File: 131.95, FHARE 133, Seismic/Construction Gaps in the 12kV Switchgear Rooms 6.10 NECS File: 131.95, FHARE 20, Unsealed Bus Duct Penetrations 6.11 NECS File: 131.95 FHARE 123, Unsealed Penetrations with Fusible Link Chain Penetrants Through Fire Barriers 6.12 SSER - 31 6.13 Question 27, PG&E Letter to NRC Dated 11/13/78 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 30-A-3, 30-A-4 9.5A-510 Revision 21 September 2013 FIRE AREAS 30-A-3 and 30-A-4 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Both fire areas are in the Intake Structure (El. -2 ft).
1.2 Description These areas consist of the ASW pump vaults inside the Intake Structure, surrounded by Fire Area IS-1 (Zone 30-A-5). 1.3 Boundaries 1.3.1 Fire Area 30-A-3 Northeast and Northwest:
- 3-hour rated wall and non-rated penetration seals to Fire Zone 30-A-5. (Ref. 6.7)
Southeast:
- 3-hour rated wall Fire Area 30-A-4. Southwest
- 3-hour rated wall with a nonrated steel watertight door to Fire Zone 30-A-5. (Ref. 6.11)
Ceiling:
- Penetrated by a ventilation stack without a fire damper. (Ref. 6.11)
- 3-hour rated concrete hatch to the exterior. (Ref. 6.8) 1.3.2 Fire Area 30-A-4 Northeast and Southeast:
- 3-hour rated wall and non-rated penetration seals to Fire Zone 30-A-5. (Ref. 6.7)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 30-A-3, 30-A-4 9.5A-511 Revision 21 September 2013 Northwest:
- 3-hour rated wall Fire Area 30-A-3. Southwest
- 3-hour rated wall with a nonrated steel watertight door to Fire Zone 30-A-5. (Ref. 6.11)
Ceiling:
- Penetrated by a ventilation stack without a fire damper. (Ref. 6.11)
- 3-hour rated concrete hatch to the exterior. (Ref. 6.8) 2.0 COMBUSTIBLES (typical for each fire area)
2.1 Floor Area: 126 ft2 2.2 In situ Combustible Materials
- Lubricating oil
- Rubber
- Cable Insulation
- PVC 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 30-A-3, 30-A-4 9.5A-512 Revision 21 September 2013 3.0 FIRE PROTECTION 3.1 Detection
- None
- Smoke detector outside of the entry to these areas in Fire Zone 30-A-5.
3.2 Suppression
- Portable fire extinguishers available in adjacent fire area. Hose stations in the vicinity.
4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Fire Area 30-A-3 4.1.1 Auxiliary Saltwater System ASW valve FCV-496 may be affected by a fire in this area. Redundant valves FCV-495 and FCV-601 will remain available to provide an ASW cooling flowpath and ASW system integrity. ASW pumps 2-1 and 2-2 may be lost due to a fire in this area. ASW pump 2-2 can be locally started to provide ASW flow. 4.1.2 HVAC HVAC fan E-104 may be lost affected by a fire in this area. Redundant HVAC fan E-102 will be available to provide necessary HVAC support. 4.2 Fire Area 30-A-4 4.2.1 Auxiliary Saltwater System ASW pumps 2-1 and 2-2 may be affected by a fire in this area. ASW pump 2-1 can be locally started to provide ASW flow. ASW valve FCV-495 may be affected by a fire in this area. Redundant valves FCV-496 and FCV-601 will remain available to provide an ASW cooling flowpath and ASW system integrity. 4.2.2 HVAC HVAC fan E-102 may be lost due to a fire in this area. Redundant HVAC fan E-104 will be available to provide necessary HVAC support. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS 30-A-3, 30-A-4 9.5A-513 Revision 21 September 2013
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown.
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Low Fire Severity.
- 3-hour rated walls except for nonrated steel watertight doors and non-rated penetration seals.
- Steel watertight doors would be able to confine smoke and hot gases to one side of the barrier. (Refs. 6.6 and 6.11)
- Smoke detection is available immediately outside the entrance of the areas.
- Manual fire protection equipment is available in the immediate vicinity. In these areas existing fire protection will provide an acceptable level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section IIIG.2.
6.0 REFERENCES
6.1 Drawing Number 515580 6.2 DCPP Unit 2 Review of 10/CFR/50, Appendix R (Rev. 2) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065127, Fire Protection Information Report, Unit 2 6.5 SSER 31, April 1985 6.6 Response to Q.7 of PG&E letter dated February 6, 1978 6.7 FHARE 114, Non-Rated Penetration Seals in the ASW Pump Room Barriers 6.8 FHARE 14, Concrete Equipment Hatches 6.9 Calculation 134-DC, Electrical Appendix R Analysis 6.10 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.11 NECS File: 131.95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-D-3 9.5A-514 Revision 21 September 2013 FIRE AREA AB-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This fire zone is in the Auxiliary Building at El. 54 ft, 64 ft and 73 ft on the south side adjacent to containment and is called the Unit 2 Boron Injection Tank (BIT) room. 1.2 Description Fire Zone 3-D-3 constitutes the corridor that separates the RHR pump rooms from each other at the 54-ft and 64-ft elevation. The Boron injection tank (which has been taken out of service) occupies this zone. Floor at 64 ft is metal grating. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. El. 54 ft North:
- 3-hour rated barrier to Fire Zone 3C. NC South:
- 3-hour rated barrier to containment. NC East:
- 3-hour rated barrier to Fire Area 3-D-2.
West:
- 3-hour rated barrier to Fire Area 3-D-1. Floor:
- 3-hour rated barrier to below grade. NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-D-3 9.5A-515 Revision 21 September 2013 El. 64 ft North:
- 3-hour rated barrier with an opening to Zone 3-C. NC South:
- 3-hour rated barrier to containment. NC East:
- 3-hour rated barrier to Fire Area 3-D-2.
- A 1-1/2-hour rated door to Fire Area 3-D-2. (Ref. 6.6)
- Two duct penetrations without fire dampers communicate to Fire Area 3-D-2. (Ref. 6.6)
- A 3 hour equivalent rated double door with a monorail cutout that has water spray protection communicates to Fire Area 3-D-2. (Refs. 6.9 and 6.14)
- A 2-hour plaster block-out panel communicates to Fire Area 3-D-2. (Ref. 6.9) West:
- 3-hour rated barrier to Fire Area 3-D-1.
- A 1-1/2-hour rated door to Fire Area 3-D-1. (Ref. 6.6)
- A duct penetration without a fire damper communicates to Fire Area 3-D-1. (Ref. 6.6)
- A 3-hour-equivalent rated double door with a monorail cutout that has water spray protection communicates to Fire Area 3-D-1. (Refs. 6.9 and 6.14)
- A 2-hour rated plaster block-out panel communicates to Fire Area 3-D-1. (Ref. 6.9)
Ceiling
- 3-hour rated to 3-I-1.
El. 73 ft South:
- 3-hour rated barrier to containment. NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-D-3 9.5A-516 Revision 21 September 2013 North:
- 3-hour rated barrier to Fire Areas 3-D-1, 3-D-2 and 3-I-1.
- Lesser rated penetrations to Fire Areas 3-D-1 and 3-D-2. (Ref. 6.12)
- 3-hour rated door to Fire Area 3-I-1.
- A duct penetration without damper to Fire Area 3-I-1. (Ref. 6.6)
East:
- 3-hour rated barrier to Fire Zone 3-G and below grade. NC
- Two duct penetrations without dampers to Fire Area 3-G. (Ref. 6.7)
West:
- 3-hour rated barrier to below grade. NC Ceiling:
- 3-hour rated to Fire Area 3-CC.
- Lesser rated penetrations to Fire Area 3-CC. (Ref. 6.12)
Floor:
- 3-hour rated barrier to Fire Areas 3-D-1 and 3-D-2. 2.0 COMBUSTIBLES
2.1 Floor Area: 583 ft2 2.2 In situ Combustible Materials
- Oil
- Grease
- Cable
- Plastic 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-D-3 9.5A-517 Revision 21 September 2013
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- None 3.2 Suppression
- Portable fire extinguishers
- Fire hose stations 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Residual Heat Removal System A fire in this area may affect AC control cables for RHR Pumps 2-1 and 2-2 recirculation valves, FCV-641A and FCV-641B Prior to starting either RHR Pump 2-1 or 2-2 from the control room, locally open its respective recirc valve (FCV-641A or FCV-641B) after opening its associated power supply breaker (52-2G-29 or 52-2H-15) located in SPG and SPH. 4.2 Safety Injection System SI valves 8803A and 8803B may be affected by a fire in this area. Alternate charging paths through the regenerative heat exchanger and the RCP seals will be available. Redundant valves 8801A and 8801B can be closed to isolate the charging injection flowpath if auxiliary spray is used for pressure reduction.
5.0 CONCLUSION
The following features will adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-D-3 9.5A-518 Revision 21 September 2013
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Portable fire extinguishers and fire hose stations are available.
- Low Fire Severity.
- Redundant safe shutdown functions are located outside this zone.
The existing fire protection provides an acceptable level of fire safety equivalent to that provided by Section III.G.2.
6.0 REFERENCES
6.1 Drawing 515566, 515567 6.2 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065127, Fire Protection Information Report, Unit 2 6.5 SSER 23, June 84 6.6 SSER 31, April 1985 6.7 NECS File: 131.95, FHARE: 67, Undampered Duct Penetrations 6.8 Deleted 6.9 NECS File: 131.95, FHARE 50, Plaster Block-out Panels in 3-Hour Barriers 6.10 Calculation 134-DC, Electrical Appendix R Analysis 6.11 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.12 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.13 PG&E Letter DCL-84-185 to NRC Dated 5/16/84 6.14 NECS File: 131.95, FHARE 159, Unrated Doors Protected by Local Automatic Sprinklers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-G 9.5A-519 Revision 21 September 2013 FIRE AREA AB-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Zone 3-G is located on the southeast side of the Auxiliary Building at El. 73 ft. 1.2 Description This fire zone contains the Unit 2 containment spray pumps 2-1 and 2-2, the spray additive tank and a nonvital motor control center. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- 3-hour rated barriers to Fire Areas 3-D-2 and 3-I-2
- 3-hour rated barrier to Fire Zone S-4.
- A nonrated barrier with openings to Fire Zone 3-C. NC
- A duct penetration without a damper to Fire Area 3-I-2. (Ref. 6.5) South:
- 3-hour rated barrier to Fire Zone S-4 and to below grade. NC East:
- 3-hour rated barrier to Fire Zone S-4 and to below grade. NC
- A nonrated barrier to Fire Zone 3-A. NC
- A nonrated door to Fire Zone 3-A. NC West:
- 3-hour rated barrier to areas 3-D-2, 3-I-2 and Zones 3-D-3, NC S-4.
- A 1-1/2-hour rated door to Fire Zone S-4.
- An open doorway with a security gate communicates to Fire Area 3-I-2. (Ref. 6.5)
- A duct penetration without a damper to Fire Area 3-I-2. (Ref. 6.5)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-G 9.5A-520 Revision 21 September 2013
- Two duct penetrations without dampers communicate with Fire Zone 3-D-3. NC (Ref. 6.6) Floor/Ceiling:
- 3-hour rated barrier to Fire Area 3-CC.
2.0 COMBUSTIBLES
2.1 Floor Area: 2,870 ft2 2.2 In situ Combustible Materials
- Cable
- Charcoal
- Clothing/Rags
- Miscellaneous
- Rubber
- Grease
- Lubricating oil 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-G 9.5A-521 Revision 21 September 2013 3.2 Suppression
- Portable fire extinguishers
- Fire hose station 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Chemical and Volume Control System Charging pump 2-3 may be lost due to a fire in this area. Charging pumps 2-1 and 2-2 will remain available to provide charging flow.
5.0 CONCLUSION
The following features will adequately mitigate the consequences of a design basis fire and assure the capability to achieve safe shutdown.
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Low Fire Severity.
- Smoke detection.
- Fire protection equipment is provided.
- Redundant safe shutdown functions are outside this zone.
The existing fire protection provides an acceptable level of fire safety equivalent to that provided by Section III.G.
6.0 REFERENCES
6.1 Drawing Number 515567 6.2 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev 2) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065127, Fire Protection Information Report, Unit 2 6.5 SSER 31, April 1985 6.6 NECS File: 131.95, FHARE: 67, Undampered Duct Penetrations 6.7 Calculation 134-DC, Electrical Appendix R Analysis 6.8 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONES 3-K-1, 3-K-2, 3-K-3 9.5A-522 Revision 21 September 2013 FIRE AREA AB-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location These zones are in the southwest corner of the 75-ft elevation of the Auxiliary Building. The zones are side by side with 3-K-2 between 3-K-1 on the west and 3-K-3 to the east. 1.2 Description These zones contain the component cooling water (CCW) pumps. Zone 3-K-1 contains CCW Pump 2-1. Zone 3-K-2 contains CCW Pump 2-2. Zone 3-K-3 contains CCW Pump 2-3. Zones 3-K-1 and 3-K-2 are similar in size, but Zone 3-K-3 is larger. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. 1.3.1 Fire Zone 3-K-1 North:
- Open to Fire Zone 3-C (See Note 1). (Ref. 6.3)
South:
- 3-hour rated barrier to below grade. NC East:
- 1-hour rated barrier to Fire Zone 3-K-2. (Ref. 6.6)
- A duct penetration without a damper to Fire Zone 3-K-2. (Ref. 6.3) West:
- 3-hour rated barrier to below grade. NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONES 3-K-1, 3-K-2, 3-K-3 9.5A-523 Revision 21 September 2013 Floor/Ceiling:
- 3-hour rated barriers: Floor: To Fire Zone 3-C. Ceiling: To Fire Area 4-B.
1.3.2 Fire Zone 3-K-2 North:
- Open to Fire Zone 3-C (See Note). (Ref. 6.3)
South:
- 3-hour rated barrier to below grade. NC East:
- 1-hour rated barrier to Fire Zone 3-K-3. (Ref. 6.6)
- Two duct penetrations without fire dampers communicate to Fire Zone 3-K-3. (Ref. 6.3)
West:
- 1-hour rated barrier to Fire Zone 3-K-1. (Ref. 6.6)
- A duct penetration without a fire damper communicates to Fire Zone 3-K-1. (Ref. 6.3)
Floor/Ceiling:
- Duct penetration with a 3-hour rated damper prevents communication to Fire Zone 3-C below.
- 3-hour rated barriers: Floor: To Fire Zone 3-C. Ceiling: To Fire Areas 4-B and 4-B-1.
1.3.3 Fire Zone 3-K-3 North:
- Open to Fire Zone 3-C (See Note 1). (Ref. 6.3)
- 3-hour rated barrier and door to Fire Area 3-I-1.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONES 3-K-1, 3-K-2, 3-K-3 9.5A-524 Revision 21 September 2013 South:
- 3-hour rated barrier to below grade. NC East:
- 3-hour rated barrier to below grade. NC
- 3-hour rated barrier to Fire Area 3-D-1.
- 3-hour rated barrier to Fire Area 3-I-1.
West:
- 3-hour rated barrier to below grade. NC
- 1-hour rated barrier to Fire Zone 3-K-2. (Ref. 6.6)
- Two duct penetrations without dampers communicate to Fire Zone 3-K-2. Floor/Ceiling:
- 3-hour rated barriers: Floor: To Fire Zone 3-C. Ceiling: To Fire Areas 4-B, 4-B-1, and 4-B-2.
(Note: For all three zones the openings North to 3-C are provided with an approximately 4-inch-high curb to prevent oil spillage from communicating between zones.)
- Lesser rated penetration seals to Fire Area 3-CC. (Ref. 6.11) 2.0 COMBUSTIBLES
2.1 Fire Zones 3-K-1 and 3-K-2 2.1.1 Floor Area: 405 ft2 2.1.2 In situ Combustible Materials
- Lubricating oil
- Cable insulation 2.1.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONES 3-K-1, 3-K-2, 3-K-3 9.5A-525 Revision 21 September 2013
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.1.4 Fire Severity
- Low (3-K-1)
- Low (3-K-2) 2.2 Fire Zone 3-K-3 2.2.1 Floor Area: 781 ft2 2.2.2 In situ Combustible Materials
- Lubricating oil
- Cable insulation
- Rubber 2.2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.2.4 Fire Severity
- Low DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONES 3-K-1, 3-K-2, 3-K-3 9.5A-526 Revision 21 September 2013 3.0 FIRE PROTECTION 3.1 Detection Zone 3-K-1: Smoke detection provided.
Zone 3-K-2: Smoke detection provided. Zone 3-K-3: Smoke detection provided. 3.2 Suppression Zone 3-K-1:
- Wet pipe automatic sprinkler system with remote annunciation.
- Fire hose stations.
- Portable fire extinguishers. Zone 3-K-2:
- Wet pipe automatic sprinkler system with remote annunciation.
- Fire hose stations.
- Portable fire extinguishers. Zone 3-K-3:
- Partial wet pipe automatic sprinkler system with remote annunciation is provided for the pump room and the pipe chase but not for the ante room.
- Fire hose station.
- Portable fire extinguishers.
4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Fire Zone 3-K-1 4.1.1 Component Cooling Water CCW pump 2-1 and ALOP 2-1 may be lost due to a fire in this area. Redundant CCW pumps 2-2 and 2-3 as well as ALOPs 2-2 and 2-3 will remain available to provide CCW. A deviation has been granted which justifies that even without full area detection and suppression, the existing configuration provides a level of fire safety that is equivalent to the criteria outlined in Section III.G.2 of 10 CFR 50, Appendix R. (Ref. 6.3) DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONES 3-K-1, 3-K-2, 3-K-3 9.5A-527 Revision 21 September 2013 4.2 Fire Zone 3-K-2 4.2.1 Chemical and Volume Control System Circuitry for charging pumps 2-1, 2-2 and 2-3 as well as ALOPs 2-1 and 2-2 may be damaged due to a fire in this area. Charging Pump 2-3 will remain available for safe shutdown. Charging pumps 2-1 and 2-2 can be tripped by opening their respective breaker control DC knife switch. 4.2.2 Component Cooling Water CCW pumps 2-1 and 2-2 and associated ALOPs may be lost due to a fire in this area. CCW pump 2-3 and ALOP 2-3 will remain available to provide CCW. A deviation has been granted which justifies that even without full area detection and suppression, the existing configuration provides a level of fire safety that is equivalent to the criteria outlined in Section III.G.2 of 10 CFR 50, Appendix R. (Ref. 6.3) 4.2.3 Residual Heat Removal System A fire in this area may affect an AC control cable for RHR Pp 2-1 recirc valve FCV-641A and result in loss of control of the valve. Redundant recirc valve FCV-641B will remain available for cold shutdown functions using RHR Pump 2-2. 4.2.4 Safety Injection System SI valves 8803A and 8803B may be affected by a fire in this area. Alternate charging paths through the regenerative heat exchanger or through the RCP seals will remain available. Redundant valves 8801A and 8801B can be closed to isolate the charging injection flowpath if auxiliary spray is used for pressure reduction. 4.3 Fire Zone 3-K-3 4.3.1 Chemical and Volume Control System Circuitry for charging pumps 2-1, 2-2 and ALOPs 2-1 and 2-2 may be affected by a fire in this area. Charging Pump 2-3 will remain available for safe shutdown. Charging pumps 2-1 and 2-2 can be tripped by opening their respective breaker control DC knife switch. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONES 3-K-1, 3-K-2, 3-K-3 9.5A-528 Revision 21 September 2013 4.3.2 Component Cooling Water CCW pump 2-3 and ALOP 2-3 may be lost due to a fire in this area. Redundant CCW pumps 2-1 and 2-2 and associated ALOPs will remain available to provide CCW. A deviation has been granted which justifies that even without full area detection and suppression, the existing configuration provides a level of fire safety that is equivalent to the criteria outlined in Section III.G.2 of 10 CFR 50, Appendix R. (Ref. 6.3) 4.3.3 Residual Heat Removal System A fire in this area may affect RHR Pump Recirc Valve FCV-641B and redundant recirculation valves, FCV-641A and FCV-641B. Prior to starting either RHR Pump 2-1 or 2-2 from the control room, locally open its respective recirc valve (FCV-641A or FCV-641B) after opening its associated power supply breaker (52-2G-29 or 52-2H-15) located in SPG and SPH. 4.3.4 Safety Injection System SI valves 8803A and 8803B may be affected by a fire in this area. Alternate charging paths through the regenerative heat exchanger or through the RCP seals will remain available. Redundant valves 8801A and 8801B can be closed to isolate the charging injection flowpath if auxiliary spray is used for pressure reduction.
5.0 CONCLUSION
The following feature will adequately mitigate consequences of a design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Smoke detection in each zone.
- Manual suppression equipment is available.
- Automatic sprinkler system.
- Low Fire Severity.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONES 3-K-1, 3-K-2, 3-K-3 9.5A-529 Revision 21 September 2013
- Dispersal of hot gases and smoke. The existing fire protection provides an acceptable level of fire safety equivalent to that provided by Section III.G.
6.0 REFERENCES
6.1 Drawing No. 515567 6.2 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.3 SSER 31, April 1985 6.4 Calculation M-824, Combustible Loading 6.5 Drawing 065127, Fire Protection Information Report, Unit 2 6.6 NECS File: 131.95, FHARE: 37, Rating of Barriers Between CCW Pump Rooms 6.7 SSER 23, June 1984 6.8 Appendix 3 For EP M-10 Unit 2 Fire Protection of Safe Shutdown Equipment 6.9 Calculation 134-DC, Electrical Appendix R Analysis 6.10 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.11 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-T-2 9.5A-530 Revision 21 September 2013 FIRE AREA AB-1 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Zone 3-T-2 is located in the south end of the Unit 2 Fuel Handling Building at El. 100 ft. This zone is adjacent to the southeast wall of the Auxiliary Building. 1.2 Description This zone contains AFW pump 2-2 and 2-3 and is actually in the Fuel Handling Building and is called the Unit 2 Auxiliary Feedwater Motor Driven Pump Room. 1.3 Boundaries North:
- 3-hour rated barrier to Fire Zone S-4.
South:
- 3-hour rated barrier to Fire Zone 3-U.
- A 1-1/2-hour rated double door to Fire Zone 3-U.
East:
- 1-hour rated barrier to Fire Zone 3-T-1. (Ref. 6.5)
- A 3-hour rated door to Fire Zone 3-T-1.
- A 1-1/2-hour rated fire damper to Fire Zone 3-T-1. (Ref. 6.5)
- A duct penetration without a damper to Fire Zone 3-T-1. (Ref. 6.2)
- Lesser rated penetration seals to Zone 3-T-1. (Ref. 6.10) West:
- 3-hour rated barrier to Fire Zone 3-CC.
- Lesser rated penetration seals to Fire Zone 3-CC. (Ref. 6.10)
- A 1-1/2-hour rated door to Fire Zone 3-CC. (Ref. 6.5) Floor/Ceiling:
- 3-hour rated barrier: Floor: To Fire Zone S-4. Ceiling: To Fire Zone 3-W.
- Ventilation opening communicates with Fire Zone 3-W above. (Ref. 6.6)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-T-2 9.5A-531 Revision 21 September 2013 2.0 COMBUSTIBLES 2.1 Floor Area: 400 ft2 2.2 In situ Combustible Materials
- Lubricants
- Cable insulation
- Clothing/Rags
- Wood (fir) 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detectors 3.2 Suppression
- Wet pipe automatic sprinkler system with remote annunciation.
- Portable fire extinguishers.
- Fire hose stations.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA AB-1 FIRE ZONE 3-T-2 9.5A-532 Revision 21 September 2013 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Auxiliary Feedwater AFW pumps 2-2 and 2-3 may be lost due to a fire in this area. AFW pump 2-1 will remain available to provide AFW.
5.0 CONCLUSION
The following features will adequately mitigate the consequences of a design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3 hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Portable fire extinguishers and hose stations.
- Redundant safe shutdown function located outside of this zone.
- Low Fire Severity.
- Automatic wet pipe sprinkler system.
- Smoke detection provided. The existing fire protection features provide a level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 Drawing No. 515569 6.2 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065127, Fire Protection Information Report, Unit 2 6.5 SSER 31, April 1985 6.6 NECS File: 131.95, FHARE 9, Ventilation Opening Above AFW Pump RM 6.7 NECS File: 131.95, FHARE 10, Undampered Ventilation Opening in the Unit 2 Auxiliary Feedwater Pump Rooms 6.8 Calculation 134-DC, Electrical Appendix R Analysis 6.9 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.10 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA FB-2 FIRE ZONE 32 9.5A-533 Revision 21 September 2013 FIRE AREA FB-2 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This zone is located at the east end of the Unit 2 Fuel Handling Building at El. 104 ft. 1.2 Description This zone consists of the Fuel Handling Building corridor.
1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- A 3-hour rated barrier to Fire Zone 3-W. NC
- A 3-hour fire rated barrier separates this zone from Zone 3-T-1 except for a 1-1/2-hour-equivalent rated double door in a 2-hour rated plaster barrier. (Refs. 6.8 and 6.12)
- Lesser rated penetration seals to Zone 3-T-1. (Ref. 6.13)
South:
- A 3-hour barrier to Zone 3-V-3. NC
- A duct penetration without a fire damper penetrates from Zones 3-V-2 NC and 3-V-3 NC. (Ref. 6.4)
- A 3-hour rated barrier separates this zone from Zone 3-V-2. NC
- A 3-hour rated barrier to Zone S-10.
- A 1-1/2 hour equivalent rated door to zone S-10. East:
- A 3-hour barrier to below grade NC and to Fire Area 3-T-1. West:
- A 3-hour rated barrier separates this zone from Zone 3-U. NC
- An opening communicates to Zone 3-U. (Ref. 6.7)
- A nonrated door communicates to Zone 3-V-2. NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA FB-2 FIRE ZONE 32 9.5A-534 Revision 21 September 2013
- A 3-hour rated barrier communicates to staircases S-10 and S-11.
- A 1-1/2 hour equivalent rated door communicates to staircase S-11.
- A 3-hour rated barrier separates this zone from Zone 3-W, NC 3-V-2 NC and 3-V-3. NC
- A duct penetration without a damper to Fire Zone 3-V-3. NC (Ref. 6.4) Floor:
- 3-hour rated barrier to 3-V-3. NC Ceiling:
- 3-hour rated barrier to 3-W NC and 3-V-4. NC
- A vent opening to 3-W. NC
- Two vent openings to 3-V-4. NC 2.0 COMBUSTIBLES
2.1 Floor Area: 2,089 ft2 2.2 In situ Combustible Materials
- Bulk Cable
- Lube Oil 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA FB-2 FIRE ZONE 32 9.5A-535 Revision 21 September 2013 3.0 FIRE PROTECTION 3.1 Detection
- None 3.2 Suppression
- Wet pipe sprinklers.
4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Make-up System Condensate storage tank level indication from LT-40 may be lost due to a fire in this area. Water from the raw water storage reservoir will remain available through FCV-436 an FCV-437. 4.2 Safety Injection System A fire in this area may affect RWST Level Transmitter LT-920. There are no cables affected in this area that may result in diverting the RWST inventory. Therefore, loss of this instrument will not affect safe shutdown.
5.0 CONCLUSION
The following features mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- A trained fire brigade is on-site at all times and is responsible for fire suppression responsibilities.
- Area wide fire suppression is provided. The existing fire protection for this area meets the requirements of 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 Drawing No. 515577. 6.2 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.3 Calculation M-824, Combustible Loading 6.4 FHARE 40, Undampered Ventilation Ducts 6.5 Deleted in Revision 14. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA FB-2 FIRE ZONE 32 9.5A-536 Revision 21 September 2013 6.6 Deleted 6.7 PG&E Letter to the NRC, Question No. 5, 11/13/78 6.8 NECS File: 131.95, FHARE 125, Lesser Rated Plaster Blockouts and Penetration Seal Configurations 6.9 Drawing 065127, Fire Protection Information Report, Unit 2 6.10 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.11 Calculation 134-DC, Electrical Appendix R Analysis 6.12 NECS File: 131.95, FHARE 118, Appendix R Fire Area Plaster Barriers 6.13 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 19-A 9.5A-537 Revision 21 September 2013 FIRE AREA TB-7 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Main condenser, feedwater, and condensate equipment area, Unit 2 Turbine Building, El. 85 ft through 119 ft. 1.2 Description This fire zone comprises the bulk of the Unit 2 Turbine Building at El. 85 ft, 104 ft, and 119 ft. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. 1.3.1 El. 85 ft North:
- 3-hour rated barriers separate this zone from Zones 14-A NC and 16, NC Areas 5-B-4 and 4-B.
- A 3-hour rated roll up door communicates to Zone 16. NC
- Two 1-1/2-hour rated double door communicates to Zone 16. NC
- A 3-hour rated door communicates to Zone 16. NC
- A duct penetration with a 3-hour rated fire damper to Area 19-E. NC
- A duct penetration without a fire damper penetrates to Area 19-E. NC (Ref. 6.11)
- A 1-1/2-hour rated door communicates to Zone 14-A. NC
- A 3-hour rated barrier to Fire Zone 19-E. NC (Ref. 6.22)
- A nonrated barrier to Fire Zone 19-C. NC South:
- 3-hour rated barriers separate this zone from Zones 22-C-1 and 22-C-2. (Ref. 6.20), and Areas 20, 22-C, and 19-E. NC (Refs. 6.12 and 6.22)
- A 3-hour rated double door communicates to Area 22-C and 19-C. NC
- A 3-hour rated door communicates to Area 20.
- A non-rated barrier with 3-hour rated double door to Zone 19-C.
- A non-rated barrier with rollup door to the exterior. NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 19-A 9.5A-538 Revision 21 September 2013 East:
- 3-hour rated barriers separate this zone from Zone 3-CC and Fire Area 4-B.
- 3-hour rated roll-up door to Area 4-B.
- Unrated small diameter penetration to Area 4-B. (Ref. 6.15)
- Nonrated barrier to Zone 19-C. NC
- A 3-hour rated barrier to Zone S-1.
- A 3-hour rated barrier with door to Zone 19-E. NC
- A penetration to Fire Area 3-CC. (Ref. 6.9)
- Lesser rated penetration seals to Fire Area 3-CC. (Ref. 6.21)
- 3-hour rated double doors communicate to Zone 19-C. NC
- Nonrated barrier separates this zone from part of the exterior. NC (Area 29).
- A 3-hour rated double door communicates to Zone 3-CC.
- 3-hour rated doors communicate to Zone 19-C. NC
- A ventilation penetration without a fire damper to Zone 19-C. NC
- Nonrated roll-up door communicates to Area 29. NC
- Four nonrated louvers to Area 29. NC
- Three 1-1/2-hour rated dampers to Zone 3-CC.
- A 3-hour rated barrier with a 3-hour and 1-1/2-hour double door to Fire Zone 16. NC West:
- Nonrated barriers separate this zone from the exterior (Area 29) NC Fire Zone 19-C, NC and the buttress area. NC
- Nonrated roll up door communicates to the buttress area. NC
- A nonhour rated roll-up door communicates to the exterior. NC (Area 29).
- A 3-hour rated barrier with 3-hour door to Zone 19-E. NC Floor: Reinforced concrete on grade. NC 1.3.2 El. 104 ft North:
- 3-hour rated barriers separate this zone from Zones 16 NC and 14-A NC and Areas 18, 5-B-4, and 6-B-5.
- An opening communicates to Zone 14-A.
- 3-hour rated door communicate to Area 18.
- Two 3-hour rated roll-up doors communicate to Zone 16. NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 19-A 9.5A-539 Revision 21 September 2013 South:
- 3-hour rated barriers separate this zone from Zones 24-E, NC 23-A, 23-E, NC 22-C-2 and Area 20.
- 3-hour rated barrier separates this zone from Zone 22-C-2. (Ref. 6.20)
- 3-hour rated doors communicate to Zones 24-E and 23-E. NC
- Nonrated barrier with door to the exterior. NC East:
- 3-hour rated barrier to Fire Area 18.
- 3-hour rated barriers separate this zone from Zone 3-CC.
- Nonrated barrier separates this zone from the exterior. NC
- Two nonrated louvers communicate to the exterior. NC
- A 3-hour rated door communicates to Zone 3-CC.
- Nonrated penetration seal between Zone 19-A NC and 3-CC. (Ref. 6.10) West:
- A nonrated barrier separates this zone from the exterior. NC
- Two nonrated doors communicate to the buttress area. NC 1.3.3 El. 119 ft North:
- 3-hour rated barriers separate this zone from Zones 14-A, NC 16 NC and 19-B NC and Areas 18, 6-B-5, and 7-B.
- Two 3-hour rated roll up doors communicate to Zone 16. NC
- A 3-hour rated double door communicates to Zone 16. NC
- 3-hour equivalent rated door communicate to Zone 19-B. NC
- A 3-hour rated fire damper to Zone 19-B. NC
- 3-hour rated fire damper to Area 18.
- Nonrated pipe penetration to Area 18. (Ref. 6.16)
- The non-rated gap assemblies in the fire barriers to Area 18 were deemed acceptable. (Ref. 6.19).
South:
- 3-hour rated barriers separate this zone from Zones 23-E, NC 24-E, S-6 and Fire Zone 25. (Ref. 6.20)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 19-A 9.5A-540 Revision 21 September 2013
- Nonrated isophase bus phase penetration communicates to Zone 23-E. NC
- 3-hour rated double doors communicate to Zones 25 and 24-E.
- Nonrated barrier and louver to the exterior. NC East:
- 3-hour rated barriers separate this Zone from Zone 3-CC, and Areas 6-B-5 and 7-B.
- Nonrated barriers separate this zone from the exterior (Area 29). NC
- A 3-hour equivalent rated door and blowout panels, both protected with a directional water spray system (Ref. 6.7 and 6.23) communicates to Area 3-CC.
- Three nonrated louvers to the exterior. NC
- Nonrated penetration for the main steam line penetration to Fire Area 3-CC. (Ref. 6.10)
- Two protected ducts without dampers to Fire Area 6-B-5. (Ref. 6.8)
- Duct penetration with 3-hour rated damper to Zone 19-B. NC West:
- 3-hour rated barrier to Fire Area 18.
- A nonrated barrier separates this zone from the exterior (Fire Area 29). NC
- Lesser rated penetration seals to Fire Area 19-A. NC (Ref. 6.21) Ceiling: 3-hour rated barrier to 19-D. NC 2.0 COMBUSTIBLES
2.1 Floor Area: 30,191 ft2 (El. 85 ft) 31,966 ft2 (El. 104 ft) 31,216 ft2 (El. 119 ft) 2.2 In situ Combustible Materials Elevation: 85 ft 104 ft 119 ft
- Cable
- Cable
- Cable
- Hydrogen
- Alcohol
- Rubber
- Acetylene
- Rubber
- Lube Oil
- Rubber
- Lube Oil
- Clothing/Rags
- Lube Oil
- Clothing/Rags
- Paper
- Clothing/Rags
- Paper
- Plastic
- Paper
- Plastic
- PVC
- Plastic
- PVC
- Wood (fir)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 19-A 9.5A-541 Revision 21 September 2013
- PVC
- Wood (fir)
- Miscellaneous (RP) 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low (El. 85 ft)
- Low (El. 104 ft)
- Low (El. 119 ft) 3.0 FIRE PROTECTION
3.1 Detection None
3.2 Suppression
- Automatic wet pipe sprinklers with remote annunciation area wide
- Deluge water spray systems for hydrogen seal oil unit and feedwater pump turbines
- Portable fire extinguishers
- Hose stations DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 19-A 9.5A-542 Revision 21 September 2013 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Auxiliary Feedwater A fire in this area may affect AFW pump 2-3. AFW pumps 2-1 and 2-2 will remain available.
A fire in this area may affect valves LCV-113 and LCV-115. Redundant valves LCV-106, LCV-107, LCV-108, and LCV-109 will remain available for AFW flow from AFW Pump 2-1, and LCV-110 and LCV-111 will remain available for AFW flow from AFW Pump 2-2. 4.2 Component Cooling Water CCW valves FCV-430 and FCV-431 may be affected by a fire in this area. FCV-431 can be manually operated to ensure safe shutdown. A fire in this area may affect the circuits associated with the CCW flow transmitter on Header C (FT-69). This instrument is credited to indicate a loss of CCW flow. Loss of this indication will not affect flow to CCW Header C. Therefore, loss of this indicator will not affect safe shutdown. 4.3 Emergency Power System A fire in this area may affect CO2 system manual action switches for the Unit 2 diesel generator rooms. Although a 3-hr enclosure and 2-hr cables are provided for the manual switches, the diesel generators are not credited for safe shutdown in this area. Offsite power is not affected in this area and will remain available for safe shutdown. A fire in this area may disable diesel generator 2-3. Offsite power is not affected in this area and will remain available for safe shutdown. In addition, diesel generators 2-1 and 2-2 will remain available for safe shutdown. 4.4 Auxiliary Saltwater System A fire in this area may spuriously close valves FCV-602 and FCV-603. FCV-603 can be manually opened to provide cooling to CCW heat exchanger 2-2. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 19-A 9.5A-543 Revision 21 September 2013 4.5 HVAC S-45 and E-45 may be lost due to a fire in this area. Redundant HVAC equipment S-46 and E-46 will be available to provide necessary HVAC support. 4.6 Containment Spray Containment spray pump 2-2 may spuriously operate due to a fire in this area. However, the corresponding discharge valve 9001B will not open. Therefore, the spurious containment spray pump operation has no impact on safe shutdown.
5.0 CONCLUSION
The following features adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Area wide automatic wet pipe sprinkler coverage.
- AFW trains 2-1 and 2-2 are independent of this zone and remain available.
- Isolators are provided to preclude the effects of hot shorts in the DG RPM indicator circuits.
- Substantial fire zone boundaries are provided to confine the fire to this zone.
- Manual fire fighting equipment is available. The existing fire protection features provide a level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.2 Drawing No. 515573, 515574, 525575 6.3 DCN DC2-EE-10913 - Provides Isolators on DG Tach-Pack 6.4 DCN DC2-EA-22612 - 3 Hour Fire Rated Barriers 6.5 Calculation M-824, Combustible Loading 6.6 Drawing 065127, Fire Protection Information Report, Unit 2 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 19-A 9.5A-544 Revision 21 September 2013 6.7 DCN DC2-EE-26465 - Provide Water Spray System in Blowout Area 6.8 SSER 31, April 1985 6.9 NECS File: 131.95, FHARE: 12, Winch Cable Penetrations for Post-LOCA Sampling Room Shield Wall 6.10 NECS File: 131.95, FHARE: 13, Unique Blockout Penetration Seal Through Barrier Between The Unit 2 Turbine/Containment Penetration Areas 6.11 NECS File: 131.95, FHARE: 58, Undampered Ventilation Duct Penetrations 6.12 NECS File: 131.95, FHARE: 82, Dow Corning Penetration Seal Through Concrete Block Wall 6.13 Deleted in Revision 14. 6.14 PG&E Design Change Notice DC2-EA-050070, Unit 2 ThermoLag Replacement 6.15 NECS File: 131.95, FHARE 123, Unsealed penetrations with fusible link chain penetrants through fire barriers 6.16 NECS File: 131.95, FHARE 131, Non-rated Pipe Penetrations in the Clean and Dirty Lube Oil Room and Unit 1 and Unit 2 Turbine Lube Oil Reservoir Rooms 6.17 Calculation 134-DC, Electrical Appendix R Analysis 6.18 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.19 NECS File: 131.95, FHARE 135, "Gaps in Appendix A Fire Rated Boundaries" 6.20 NECS File: 131.95, FHARE 30, Unrated Gaps in Appendix R Barriers in the Turbine Building 6.21 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.22 NECS File: 131.95, FHARE 120, CCW Heat Exchanger Rooms Fire Area Boundaries 6.23 NECS File: 131.95, FHARE 159, Unrated Doors Protected by Local Automatic Sprinklers. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 19-D 9.5A-545 Revision 21 September 2013 FIRE AREA TB-7 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Unit 2 Turbine Deck, El. 140 ft.
1.2 Description This fire zone comprises the Unit 2 Turbine Operating Deck at El. 140 ft.
1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- There is no boundary separating Fire Zone 19-D from 14-D.
South:
- A nonrated barrier separates this zone from Area 29. NC East:
- A nonrated barrier separates this zone from Area 34. NC
- A nonrated roll up door communicates to Area 34. NC
- A 3-hour rated barrier separates this zone from Area 8-H.
- A 3-hour rated barrier separates this zone from Area 8-F.
- A 3-hour rated barrier separates this zone from Area S-1.
- A 3-hour rated door communicates to Area S-1. West:
- A nonrated barrier separates this zone from Area 29. NC Floor:
- A 3-hour rated floor to Zones 19-A, NC 23-E, NC 24-E, 25, NC 19-B, NC 16, NC 17, NC 24-A, 24-B, 24-C, 24-D (Ref. 6.9), and 18.
- Ventilation exhaust openings with 3-hour rated fire dampers from Zones 24-A, 24-B, and 24-C.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 19-D 9.5A-546 Revision 21 September 2013
- A 3-hour rated equipment hatch penetrates to Fire Area 24-D. (Ref. 6.4)
- A 3-hour rated equipment hatch penetrates to Fire Zone 18. (Ref. 6.4)
- An open equipment hatch communicates to the 85-ft elevation of Zone 16. NC
- Open stairwells to Zones S-6, S-7, 19-A and 23-E.
- Unsealed blockout openings communicate to Zone 18. (Ref. 6.8)
- Nonrated vent and exhaust openings to Fire Zone 19-A. NC Ceiling:
- Nonrated ceiling to the exterior. NC
- An open ventilation exhaust vent along the center ridge of the roof. NC 2.0 COMBUSTIBLES
2.1 Floor Area: 52,547 ft2 2.2 In situ Combustible Materials
- Bulk Cable
- Hydrogen
- Alcohol
- Rubber
- Lube Oil
- Clothing/Rags
- Paper
- Plastic
- PVC
- Wood (Fir) 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 19-D 9.5A-547 Revision 21 September 2013 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Heat detection for Turbine Bearing No. 10 3.2 Suppression
- Water Deluge for all Turbine Bearings except No. 10
- Local CO2 System for Bearing No. 10
- Portable fire extinguishers
- Hose stations 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Emergency Power System A fire in this area may disable diesel generator 2-3. Offsite power is not affected in this fire area and will remain available for safe shutdown. In addition, diesel generators 2-1 and 2-2 will remain available for safe shutdown. 4.2 HVAC One train of HVAC equipment (E-45 and S-45) may be lost due to a fire in this area. A redundant train of HVAC components (E-46 and S-46) will remain available. 4.3 Containment Spray Containment spray pump 2-2 may spuriously operate due to a fire in this area. However, the corresponding discharge valve 9001B will not open. Therefore, the spurious containment spray pump operation has no impact on safe shutdown.
5.0 CONCLUSION
The following features mitigate the consequences of the design basis fire and ensure the capability to achieve safe shutdown:
- A trained fire brigade is on-site at all times and is responsible for fire suppression responsibilities.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 19-D 9.5A-548 Revision 21 September 2013
- Local (partial) fire detection is provided.
- Local (partial) fire suppression is provided.
- Manual fire suppression equipment is available.
- Redundant components are available or manual actions can be taken to achieve safe shutdown.
The existing fire protection for this area meets the level of safety required by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 Drawing No. 515576 6.2 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 1) 6.3 Calculation No. M-824, Combustible Loading 6.4 FHARE 14, Concrete Equipment Hatches 6.5 Drawing 065127, Fire Protection Information Report, Unit 2 6.6 Calculation 134-DC, Electrical Appendix R Analysis 6.7 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.8 NECS File: 131.95, FHARE 3, Valve Operator Shafts Through Barrier 6.9 NECS File: 131.95, FHARE 30, Unrated Gaps in Appendix R Barriers in the Turbine Building DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 19-E 9.5A-549 Revision 21 September 2013 FIRE AREA TB-7 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Zone 19-E is part of Fire Area TB-7 and is located in the northeast corner of the Unit 2 Turbine Building at El. 85 ft. (Ref. 6.12) 1.2 Description Fire Zone 19-E is the component cooling water (CCW) heat exchanger room. This area is completely separated from the rest of the Turbine Building by 3 hour barriers constructed of reinforced concrete walls, concrete block walls, and fire rated covering (on the Turbine Building side only). (Ref. 6.12) 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- 3-hour rated unidirectional fire barrier to Fire Zone 19-A (TB-7). NC (Ref. 6.12)
- 3-hour rated door to Fire Zone 19-A. NC South:
- 3-hour rated barrier to Fire Zone 19-A (TB-7). NC (Ref. 6.12) East:
- 3-hour rated barrier to Fire Area 4-B.
- 3-hour rated barrier to Fire Zone 19-A (TB-7). NC (Ref. 6.12)
- 3-hour rated fire damper to Fire Zone 19-A. NC
- A 2-hour rated fire barrier encloses a HVAC duct, without fire dampers, which passes from Fire Zone 19-A (TB-7) NC through the ceiling and through the east wall to Fire Area 4-B, and contains an unrated penetration seal. (Ref. 6.10)
West:
- 3-hour rated unidirectional pyrocrete barrier Fire Zone 19-A (TB-7). NC (Ref. 6.12)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 19-E 9.5A-550 Revision 21 September 2013
- 3-hour rated Fire Door to Fire Zone 19-A. NC
- 3-hour rated fire damper to Fire Zone 19-A. NC Floor/Ceiling:
- 3-hour rated barriers except for the following: A nonrated steel hatch that connects Fire Area 19-E to the 104-ft elevation of Fire Zone 19-A.
Protective
Enclosure:
- A reinforced concrete missile shield separates the redundant heat exchangers and extends approximately 2.5 ft beyond the ends and above the tops of the heat exchangers.
2.0 COMBUSTIBLES 2.1 Floor Area: 1,899 ft2 2.2 In situ Combustible Materials
- Cable insulation
- Plastics
- Oil
- Miscellaneous
- Rubber
- Clothing/Rags
- PVC
- Wood (fir) 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 19-E 9.5A-551 Revision 21 September 2013
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection is provided except under the alcove area (south side). (Ref. 6.8) 3.2 Suppression
- Automatic wet pipe sprinkler protection, with remote annunciation, is provided except under the alcove area (South side). (Ref. 6.8)
- Portable fire extinguishers
- Fire hose stations 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Component Cooling Water CCW valves FCV-430 and FCV-431 may be lost due to a fire in this area. Since one of these valves is normally open and would remain open in the event of a fire, CCW flow would still be available. A fire in this area may affect circuits associated with CCW flow transmitters for Header A (FT-68), Header B (FT-65), and Header C (FT-69). These instruments are credited to indicate a loss of CCW flow. Therefore, loss of these instruments will not affect safe shutdown. A fire in this area may affect differential pressure transmitters for CCW Hx 2-1 (PT-5) and CCW Hx 2-2 (PT-6). Loss of these instruments will not affect safe shutdown. 4.2 Auxiliary Saltwater System Valves FCV-602 and FCV-603 may be affected by a fire in this area. These valves can be manually opened to provide ASW to the CCW heat exchangers. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 19-E 9.5A-552 Revision 21 September 2013
5.0 CONCLUSION
This fire area does not meet the requirements of Appendix R, Section III.G.2.(c) in that a 1-hour enclosure is not provided around one train of redundant safe shutdown equipment. A deviation was requested and granted as stated in SSER 31.
The following fire protection features will adequately mitigate the consequences of the design basis fire and will assure the capability to achieve safe shutdown:
- Deviations to requirements for 3 hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Wet pipe automatic sprinkler system.
- Fire hose stations and portable fire extinguishers.
- Smoke detection is provided.
- Failure of ASW valve circuits could result in loss of ASW cooling to CCW heat exchangers but manual action can be taken to restore it.
- Failure of CCW valves circuits, due to fire, will result in the motor operated valves failing as is with one valve open and one valve closed, providing adequate CCW cooling for safe shutdown.
The fire protection in this area provides an acceptable level of fire safety equivalent to that provided by Section III.G.
6.0 REFERENCES
6.1 Drawing No. 515573 6.2 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065127, Fire Protection Information Report, Unit 2 6.5 SSER 31, April 1985 6.6 Not used 6.7 Memorandum from G.A. Tidrick/C.E. Ward to P.R. Hypnar dated May 3, 1983, Re: CCW system, files 140.061 and 131.91 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 19-E 9.5A-553 Revision 21 September 2013 6.8 NECS File: 131.95, FHARE: 51, Lack of Area Wide Detection and Suppression 6.9 Procedure: EP M-10 Emergency Procedure Fire Protection of Safe Shutdown Equipment 6.10 NECS File: 131.95, FHARE: 58, Undampered Ventilation Duct Penetrations 6.11 Not used 6.12 FHARE 120, CCW Heat Exchanger Room Boundary Walls 6.13 Calculation 134-DC, Electrical Appendix R Analysis 6.14 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 23-E 9.5A-554 Revision 21 September 2013 FIRE AREA TB-7 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Isophase bus duct, area Unit 2 Turbine Building, El. 104 ft.
1.2 Description This fire zone is part of Fire Area TB-7 and occupies the elevations from 104 ft through 140 ft. An enclosed stairwell on the north wall provides access to Area 20 below and a stair along the south wall provides access to Zone 24-A. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- 3-hour rated barrier separates this zone from Zone 19-A. NC
- A 3-hour rated door communicates to Zone 19-A. NC
- A nonrated isophase bus penetration communicates to Zone 19-A. NC
- 2-hour rated barrier separates Zone 23-E from Area 20 except for: - A 1-1/2-hour rated door communicates to Area 20.
- Nonrated ceiling slab for stairwell communicating to Area 20. (Ref. 6.5) - Lesser rated penetration seal from Zone 23-E to Area 20. (Ref. 6.14)
South:
- 3-hour rated barrier separates this zone from Zones 23-A, 24-A, and Area 24-D with the following exceptions:
- A 1-1/2-hour rated door communicates to Zone 23-A. - A 1-1/2-hour rated door communicates to Area 24-D. (Ref. 6.16) - A 1-1/2-hour rated door communicates to Zone 24-A. - Unrated structural gap seals to Fire Zones 23-A, 24-A, and 24-D. (Ref. 6.13) - Structural steel modifications for the block walls (at El. 119 ft) were deemed acceptable with no fireproofing. (Ref. 6.7)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 23-E 9.5A-555 Revision 21 September 2013 East:
- 2-hour rated (plaster) barrier separates this zone from Area 29. NC
- A nonrated isophase bus penetration communicates to Area 29. NC West:
- 2-hour rated barrier separates this zone from Zone 24-E, EL. 119 ft. (Ref. 6.11).
- Lesser rated penetration seals to Zone 24-E, EL. 119 ft. (Ref. 6.14)
- 2-hour rated barrier separates this zone from Zone 23-A. (Ref. 6.12)
- A 1-1/2-hour rated door communicates to Zone 23-A.
- A duct penetration without a fire damper penetrates to Zone 24-E. (Ref. 6.6)
Floor/Ceiling:
- 3-hour rated barrier separates this zone from Area 20 below.
- 3-hour rated barrier separates this zone from Zone 19-D NC above.
- Open vertical communication through the stairwell to Zone 19-D NC above. 2.0 COMBUSTIBLES 2.1 Floor Area: 1,920 ft2 2.2 In situ Combustible Materials
- Cable Insulation
- Rubber
- Plastic
- Wood (fir) 2.3 Transient Combustible Materials
- No storage area 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION 3.1 Detection
- None DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 23-E 9.5A-556 Revision 21 September 2013 3.2 Suppression
- CO2 hose station
- Portable fire extinguishers
- Fire hose stations 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Emergency System A fire in this area may disable the diesel generators 2-1, 2-2 and 2-3 automatic transfer circuits or may spuriously close the auxiliary transformer 2-2 circuit breaker. Offsite power is not affected in this area and will remain available for safe shutdown. In addition, manual actions can be taken to enable the diesels to be manually loaded or loaded from the control room.
5.0 CONCLUSION
The following features will adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Safe plant shutdown will not be adversely impacted if safe shutdown functions located in this zone are lost.
- Substantial zone boundary construction.
- Low fire severity.
- Manual fire fighting equipment is provided for this zone.
The existing fire protection features provide an acceptable level of safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.2 Drawing No. 515574, 515575 6.3 Calculation M-824, Combustible Loading DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-7 FIRE ZONE 23-E 9.5A-557 Revision 21 September 2013 6.4 Drawing 065127, Fire Protection Information Report, Unit 2 6.5 NECS File: 131.95, FHARE: 4, Stairwell Nonrated Ceiling 6.6 NECS File: 131.95, FHARE: 33, Undampered Ventilation Duct Penetrations 6.7 NECS File: 131.95, FHARE: 106, Block Walls Modified in the 4kV Switchgear Area 6.8 NECS File: 131.95, FHARE: 119, Plaster Barriers Credited for Appendix A to BTP (APCSB) 9.5-1 6.9 Calculation 134-DC, Electrical Appendix R Analysis 6.10 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.11 NECS File: 131.95, FHARE 118, Appendix R Fire Area Plaster Barriers 6.12 NECS File: 131.95, FHARE 119, Appendix A to BTP (APCSB) 9.5-1, Plaster Barriers 6.13 NECS File: 131.95, FHARE 134, "Non-rated Structural Gap Seals In Fire Barriers" 6.14 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.15 NECS File: 131.95, FHARE 50, Lesser Rated Plaster 6.16 NECS File: 131.95, FHARE 70, Lesser Rated Doors
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS TB-8, TB-9, TB-17 FIRE ZONES 22-A-1, 22-A-2, 22-B-1 22-B-2, 22-C-1, 22-C-2 9.5A-558 Revision 21 September 2013 FIRE AREAS TB-8, TB-9, TB-17 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Southwest corner of Unit 2 Turbine Building; consists of the diesel generator rooms (El. 85 ft) and the diesel generator air intakes (El. 85 ft and 107 ft). 1.2 Description Fire Areas TB-8, TB-9 and TB-17 and are divided into Fire Zones 22-A-1, 22-A-2, 22-B-1, 22-B-2, 22-C-1 and 22-C-2 to differentiate between the generator rooms and the ventilation intake and exhaust rooms. Fire Zones 22-A-1, 22-B-1 and 22-C-1 contain diesel generators 2-1, 2-2 and 2-3 respectively. These areas are located side by side with 22-C-1 (TB-17) on the north side of 22-A-1 (TB-8) and 22-B-1 (TB-9) on the south side of 22-A-1 (TB-8). Fire Zones 22-A-1, 22-B-1 and 22-C-1 are provided with curbs at all door openings to contain any oil leakage. Several 4-inch floor drains are provided underneath the day tanks in each diesel generator room. A common 4-inch pitched header, which is a minimum of 3-1/2-ft below the drain openings, connects the drains from each room with the turbine building sump. The diesel generator intake rooms (Fire Zones 22-A-2 (TB-8), 22-B-2 (TB-9) and 22-C-2 (TB-17)) communicate air between El. 85 ft, 107 ft, and the exterior (Fire Area 29) area. The area south of Zone 22-B-1 above El. 107 ft is separated by walls and Zones 22-A-2, 22-B-2 and 22-C-2, becomes an open common exhaust plenum below El. 107 ft. Due to the similarities of these three fire areas they are evaluated together.
1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS TB-8, TB-9, TB-17 FIRE ZONES 22-A-1, 22-A-2, 22-B-1 22-B-2, 22-C-1, 22-C-2 9.5A-559 Revision 21 September 2013 1.3.1 El. 85 ft 1.3.1.1 Fire Zones 22-A-1, 22-B-1, 22-C-1 North:
- 3-hour rated barrier from: - Zone 22-A-1 to Zone 22-C-1. (Ref. 6.13)
- Zone 22-B-1 to Zone 22-A-1. (Ref. 6.13) - Zone 22-C-1 to Zone 19-A.
South:
- 3-hour rated barrier from:
- Zone 22-A-1 to 22-B-1. (Ref. 6.13) - Zone 22-B-1 to 22-B-2. (Ref. 6.13) - Zone 22-C-1 to 22-A-1. (Ref. 6.13)
- A 3-hour rated door from Zone 22-B-1 to 22-B-2 East:
- 3-hour rated barriers to Area 22-C. (Ref. 6.13)
- A 3-hour rated roll-up door, one from each zone to Area 22-C.
- An unsealed penetration from Zone 22-A-1 to Area 22-C. (Ref. 6.13)
- Unrated small diameter penetrations one from each zone to Area 22-C. (Ref. 6.11)
- Unrated vertical gap seal from 22-C-1 to 22-C. (Ref. 6.16)
- A 3-hour rated door from Zone 22-A-1 to Area 22-C and from Zone 22-C-1 to Area 22-C.
- Unsealed Penetration from Zone 22-A-1 to Fire Area 22-C. (Ref. 6.8) West:
- 3-hour rated barrier
- Two 3-hour rated roll-up doors
- A drive shaft penetration DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS TB-8, TB-9, TB-17 FIRE ZONES 22-A-1, 22-A-2, 22-B-1 22-B-2, 22-C-1, 22-C-2 9.5A-560 Revision 21 September 2013 All of the above exist between each of the following: - Zone 22-A-1 to Zone 22-A-2
- Zone 22-B-1 to Zone 22-B-2 - Zone 22-C-1 to Zone 22-C-2
Floor/Ceiling:
- Floor: Reinforced concrete on grade. NC
- Ceiling: 3-hour rated except for Diesel Exhaust Stacks. (Ref. 6.8)
- Openings from Common Exhaust Plenum to Zones 22-A-2, 22-B-2 and 22-C-2 on El. 107 ft. (Ref. 6.8) 1.3.1.2 Fire Zones 22-A-2, 22-B-2, and 22-C-2 (Radiator Rooms)
North:
- 3-hour rated barrier from Zone 22-A-2 to Zone 22-C-2.
- 3-hour rated barrier from Zone 22-B-2 to Zone 22-A-2 and Zone 22-B-1. (Ref. 6.13)
- 3-hour rated barrier from Zone 22-C-2 to Zone 19-A. (Ref. 6.13)
- A 3-hour rated door from Zone 22-B-2 to Zone 22-A-2.
- A 3-hour rated door from Zone 22-A-2 to Zone 22-C-2. (Ref. 6.13)
- A 3-hour rated door from Zone 22-B-2 to Zone 22-B-1.
South:
- 3-hour rated barrier from Zone 22-A-2 to Zone 22-B-2. (Ref. 6.13)
- 3-hour rated barrier from Zone 22-C-2 to Zone 22-A-2. (Ref. 6.13)
- 3-hour rated door from Zone 22-A-2 to Zone 22-B-2.
- Nonrated barrier to the exterior (Area 29) NC from 22-B-2. (Ref. 6.18)
- 3-hour door to the radiator exhaust plenum.
- 3-hour rated door from Zone 22-C-2 to Zone 22-A-2.
East:
- 3-hour rated barrier.
- Two 3-hour rated roll up doors.
- A drive shaft penetration.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS TB-8, TB-9, TB-17 FIRE ZONES 22-A-1, 22-A-2, 22-B-1 22-B-2, 22-C-1, 22-C-2 9.5A-561 Revision 21 September 2013 All of the above exist between each of the following:
- Zone 22-A-2 to Zone 22-A-1 - Zone 22-B-2 to Zone 22-B-1 - Zone 22-C-2 to Zone 22-C-1
- A 3-hour rated barrier exists between 22-B-2 and 22-C. (Ref. 6.13)
- A 3-hour rated door from Zone 22-B-2 to 22-C.
West:
- Nonrated barrier to the exterior (Fire Area 29). (Ref. 6.18) NC Floor/Ceiling:
- Floor: Reinforced concrete on grade. NC 1.3.2 El. 104 ft Fire Areas 22-A-2, 22-B-2, and 22-C-2 North:
- 3-hour rated barrier from Zone 22-C-2 to Zone 24-E with non-rated features and Zone 19A. (Ref. 6.13)
- 3-hour rated barrier from Zone 22-A-2 to Zone 22-C-2. (Ref. 6.13)
- 5-inch deep cutout and a void in barrier from Zone 22-A-2 to Zone 22-C-2. (Ref. 6.13)
- A 3-hour rated door from Zone 22-C-2 to Zone 24-E.
- 3-hour rated barrier from Zone 22-B-2 to Zone 22-A-2. (Ref. 6.13)
- Lesser rated penetration seals form Zone 22-B-2 to Zone 22-A-2. (Ref. 6.17) South:
- Nonrated barriers to the exterior. (Ref. 6.18)
- A 3-hour rated barrier from Zone 22-A-2 to Zone 22-B-2. (Ref. 6.13)
- Lesser rated penetration seals form Zone 22-A-2 to Zone 22-B-2. (Ref. 6.17)
- A 3-hour rated barrier from Zone 22-C-2 to Zone 22-A-2. (Ref. 6.13)
- 5-inch deep cutout and a void in barrier from Zone 22-C-2 to Zone 22-A-2. (Ref. 6.13)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS TB-8, TB-9, TB-17 FIRE ZONES 22-A-1, 22-A-2, 22-B-1 22-B-2, 22-C-1, 22-C-2 9.5A-562 Revision 21 September 2013 East:
- 3-hour rated barrier from Zone 22-A-2 to Zone 22-C-2. (Ref. 6.13)
- Lesser rated penetration seals form Zone 22-A-2 to Zone 22-C-2. (Ref. 6.17)
- 3-hour rated barrier from Zone 22-B-2 to Zone 22-A-2. (Ref. 6.13)
- 3-hour rated barrier from Zone 22-C-2 to Zones 23-C-1, 23-A, and 23-B. (Ref. 6.13) West:
- 3-hour rated barrier from: - Zone 22-A-2 to Zone 22-B-2. (Ref. 6.13)
- Zone 22-B-2 to Zone 24-E. - Zone 22-C-2 to Zone 22-A-2. (Ref. 6.13)
Non Rated barriers to the exterior. (Refs. 6.8 and 6.18)
- Lesser rated penetration seals form Zone 22-A-2 to Zone 22-C-2. (Ref. 6.17)
- 3-hour rated doors from: E to 22-C-2 C-2 to 22-A-2 A-2 to 22-B-2
Floor/Ceiling:
- Floor: hour rated barriers to Zones 22-A-1, 22-B-1, and 22-C-1.
- Floor openings to 22-B-2. (Ref. 6.8)
- Ceiling: 3-hour rated barrier to Zone 25. (Ref. 6.13) 2.0 COMBUSTIBLES
2.1 Floor Area: 770 ft2 (22-A-1, 22-B-1, 22-C-1) 1383 ft2 (22-A-2) (Ref. 6.11) 1532 ft2 (22-B-2) (Ref. 6.11) 1658 ft2 (22-C-2) (Ref. 6.11) 2.2 In situ Combustible Materials
- Lube oil DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS TB-8, TB-9, TB-17 FIRE ZONES 22-A-1, 22-A-2, 22-B-1 22-B-2, 22-C-1, 22-C-2 9.5A-563 Revision 21 September 2013
- Diesel fuel
- Cable insulation
- Clothing/Rags
- Polyethylene
- Plastic
- Paper
- Rubber 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Moderate (22-A-1, 22-B-1, 22-C-1)
- Low (22-A-2, 22-B-2, 22-C-2) 3.0 FIRE PROTECTION
3.1 Detection
- Heat detection which: (1) Releases west doors (2) Releases east door (3) Activates CO2 system 3.2 Suppression
- Total flooding CO2
- Portable fire extinguishers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS TB-8, TB-9, TB-17 FIRE ZONES 22-A-1, 22-A-2, 22-B-1 22-B-2, 22-C-1, 22-C-2 9.5A-564 Revision 21 September 2013
- Fire hose stations 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Fire Zones 22-A-1 and 22-A-2 4.1.1 Diesel Fuel Oil System Diesel fuel oil pump 0-2 may be lost due to a fire in this area. Redundant pump 0-1 will remain available. Valves LCV-86 and LCV-89 may be lost due to a fire in this area. Day tank level control will be maintained by LCV-88 and LCV-90. In addition, offsite power is not affected in this area and will remain available for safe shutdown. 4.1.2 Emergency Power A fire in this area may disable diesel generator 2-1. Offsite power is not affected in this area and will remain available for safe shutdown. In addition, diesel generators 2-2 and 2-3 will remain available for safe shutdown. 4.2 Fire Zones 22-B-1 and 22-B-2 4.2.1 Diesel Fuel Oil System Diesel fuel oil pumps 0-1 and 0-2 may be affected by a fire in this area. Offsite power is not affected in this area and will remain available for safe shutdown. In addition,, diesel fuel oil transfer pump 0-1 will remain available for diesels 2-1 and 2-3 and diesel fuel oil pump 0-2 will remain available for diesels 2-1, 2-2 and 2-3. A fire in this area may result in the loss of LCV-85 and LCV-88. Offsite power is not affected in this area and will remain available for safe shutdown. In addition, day tank level control will be maintained by LCV-86 and LCV-87. 4.2.2 Emergency Power Diesel generator 2-2 may be lost due to a fire in this area. Offsite power is not affected in this area and will remain available for safe shutdown. In addition, diesel generators 2-1 and 2-3 will remain available for safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS TB-8, TB-9, TB-17 FIRE ZONES 22-A-1, 22-A-2, 22-B-1 22-B-2, 22-C-1, 22-C-2 9.5A-565 Revision 21 September 2013 4.3 Fire Zones 22-C-1 and 22-C-2 4.3.1 Diesel Fuel Oil System A fire in this area may disable diesel fuel oil pumps 0-1 and 0-2. Offsite power is not affected in this area and will remain available for safe shutdown. A fire in this area may disable day tank level control valves LCV-87 and LCV-90 for diesel generator 2-3. Offsite power is not affected in this area and will remain available for safe shutdown. In addition, redundant valves LCV-85, LCV-88, LCV-86, and LCV-89 will remain available to supply diesel to diesel generators 2-1 and 2-2. 4.3.2 Emergency Power Diesel generator 2-3 may be lost due to a fire in this area. Offsite power is not affected in this fire area and will remain available. In addition, diesel generators 2-1 and 2-2 will remain available for safe shutdown. 4.3.3 HVAC A fire in this area may cause one train of HVAC equipment to be lost (S-67). Loss of 4kV switchgear room HVAC S-67 will not affect safe shutdown.
5.0 CONCLUSION
The following fire protection features will adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- A total flooding CO2 suppression system is provided for the diesel generator rooms.
- Manual fire fighting equipment is available.
- Low fire severity.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREAS TB-8, TB-9, TB-17 FIRE ZONES 22-A-1, 22-A-2, 22-B-1 22-B-2, 22-C-1, 22-C-2 9.5A-566 Revision 21 September 2013
- The fire hazard is minimal in the ventilation intake and exhaust rooms. Smoke and hot gases would either be vented outside through the louvers in the exterior wall or confined within the area by the fire rated perimeter construction until the fire brigade arrives.
- The drainage system described in Section 1.2 does not contain fire traps. A commitment to provide fire traps was accepted by the NRC in SSER 8. This commitment was then withdrawn and the existing floor drainage system was justified and found to be acceptable.
The existing fire protection for the areas provides an acceptable level of safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 Drawing No. 515573 6.2 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065127, Fire Protection Information Report, Unit 2 6.5 SSER 23, June 1984 6.6 SSER 31, April 1985 6.7 Deleted 6.8 NECS File: 131.95, FHARE: 103, Fire Barrier Configurations in the Emergency Diesel Generator Rooms 6.9 DCP M-44405, Sixth Diesel Generator Design 6.10 Deleted 6.11 NECS File: 131.95, FHARE 123, Unsealed Penetrations with Fusible Link Chain Penetrants Through Fire Barriers 6.12 DCP H-50117, Diesel Generator Air Flow Improvement Modification, Units 1 and 2 6.13 NECS File: 131.95, FHARE 30, Unrated Gaps in Appendix R Barriers in the Turbine Building 6.14 Calculation 134-DC, Electrical Appendix R Analysis 6.15 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.16 NECS File: 131.95, FHARE 103, Fire Barrier Configurations in the Emergency Diesel Generator Rooms 6.17 NECS File: 131.95, FHARE 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.18 NECS File: 131 .95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-10 FIRE ZONES 23-A, 24-A 9.5A-567 Revision 21 September 2013 1.0 PHYSICAL CHARACTERISTICS 1.1 Location Fire Area TB-10 is in the southeast corner of the Unit 2 Turbine Building and consists of Fire Zone 23-A, at El. 107 ft, and Fire Zone 24-A, at El. 119 ft. 1.2 Description Fire Area TB-10 consists of the 4kV F Bus cable spreading room (at 107 ft), Fire Zone 23-A, and the 4kV F Bus switch gear room (at 119 ft), Fire Zone 24-A, in the Turbine Building. At least two of the three vitalities are required for safe shutdown. 1.3 Boundaries 1.3.1 Fire Zone 23-A (El. 107 ft) North:
- 3-hour rated barrier to Fire Zone 19-A.
- 2-hour rated barrier to Fire Zone 23-E (TB-7). (Ref. 6.14)
- A 1-1/2-hour rated door to Fire Zone 23-E.
South:
- 2-hour plaster barrier above 3-hour door to Zone 23-B. (Ref. 6.21)
- 2-hour rated barrier to Fire Zone 23-B (TB-11). (Ref. 6.5)
- Unrated structural gap seals to Fire Zone 23-B. (Ref. 6.18)
- Two 3-hour rated doors to Fire Zone 23-B.
- A 1-1/2-hour rated door to Fire Zone 23-B. (Ref. 6.22)
East:
- 2-hour rated barrier to Fire Zone 23-E. (Ref. 6.21)
- 2-hour rated barrier to the exterior (Area 29).
- 1-1/2-hour rated door to Fire Zone 23-E. West:
- 3-hour rated barrier to Fire Zones 24-E (Ref. 6.17) and 22-C-2. (Ref. 6.19)
- Lesser rated penetration seal to Fire Zone 24-E. (Ref. 6.20)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-10 FIRE ZONES 23-A, 24-A 9.5A-568 Revision 21 September 2013
- 1-hour rated unidirectional barrier to Fire Zone 24-E (TB-13) (above) (1-hour from Zone 23-A to Zone 24-E).
- A 1-1/2-hour rated door to Fire Area 24-E.
Floor/Ceiling:
Floor: To Fire Areas 20 and 22-C.
Ceiling: To Fire Area 24-D and Zones 24-A and 24-E.
- 3-hour rated concrete slab on unprotected steel. (Ref. 6.8)
- A ventilation duct without a fire damper communicates with Fire Area 24-D (above). (Refs. 6.9 and 6.13)
- A vent opening to Fire Zone 24-A above.
- A ventilation duct with a 3-hour rated fire damper communicates to Fire Zone 24-E (TB-13) (above). (Ref. 6.6) 1.3.2 Fire Zone 24-A (El. 119 ft)
North:
- 3-hour rated barrier to Fire Zone 23-E (TB-7).
- Unrated structural gap seals to Fire Zone 23-E (TB-7). (Ref. 6.18)
- A 1-1/2-hour rated door to Fire Zone 23-E.
South:
- 2-hour rated barrier to Fire Zone 24-B (TB-11). (Ref. 6.5)
- Unrated structural gap seals to Fire Zone 24-B (TB-11). (Ref. 6.18)
- A 1-1/2-hour rated door to Fire Zone 24-B.
East:
- 2-hour rated barrier to the exterior (Area 29). West:
- 3-hour rated barrier to Fire Area 24-D.
- Unrated structural gap seals to Fire Area 24-D. (Ref. 6.18)
- A 1-1/2-hour rated double door to Fire Area 24-D. (Ref. 6.10)
- 2-hour rated blockout around the door. (Ref. 6.10)
- A 1-1/2-hour rated damper to Fire Area 24-D. (Ref. 6.5)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-10 FIRE ZONES 23-A, 24-A 9.5A-569 Revision 21 September 2013 Floor:
- 3-hour rated concrete slab to Fire Zone 23-A.
- A vent opening to Fire Zone 23-A below.
Ceiling:
- A vent opening with a 3-hour rated fire damper to Zone 19-D (TB-7).
- 3-hour rated barrier to Fire Area 19-D. Protective
Enclosure:
- All corner gaps are sealed.
- Structural steel has fire resistive coverings. (Note: Some structural steel modifications for the block walls (at El. 119 ft) were deemed acceptable with no fireproofing. (Ref. 6.11))
2.0 COMBUSTIBLES
2.1 Fire Zone 23-A (Elevation 107 ft) 2.1.1 Floor Area: 1,463 ft2 2.1.2 In situ Combustible Materials
- Cable insulation
- Rubber
- Plastic 2.1.3 Transient Combustible Loading Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-10 FIRE ZONES 23-A, 24-A 9.5A-570 Revision 21 September 2013 2.1.4 Fire Severity
- Low 2.2 Fire Zone 24-A (El. 119 ft) 2.2.1 Floor Area: 855 ft2 2.2.2 In situ Combustible Materials
- Rubber
- Plastic 2.2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection is provided in Fire Zones 23-A and 24-A.
3.2 Suppression
- Portable fire extinguishers
- CO2 hose stations
- Fire hose stations DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-10 FIRE ZONES 23-A, 24-A 9.5A-571 Revision 21 September 2013 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Fire Zones 23-A and 24-A 4.1.1 Auxiliary Feedwater AFW pump 2-3 may be lost for a fire in this area. Redundant pump 2-1 will be available to provide AFW to steam generators 2-3 and 2-4.
AFW valves LCV-113 and LCV-115 may be affected by a fire in this area. Redundant valves LCV-108 and LCV-109 will remain available to provide AFW flow to steam generators 2-3 and 2-4 from AFW Pump 2-1. 4.1.2 Chemical and Volume Control System CVCS valve 8107 may be affected by a fire in this area. CVCS valves 8108, HCV-142, or 8145 and 8148 remain available to isolate auxiliary spray, two other charging flowpaths are available and the PORVs can be used for pressure reduction. Therefore, safe shutdown is not affected. Charging pump and ALOP 2-1 may be lost due to a fire in this area. Redundant charging pumps 2-2, 2-3 and ALOP 2-2 will remain available to provide charging flow. Boric acid transfer pump 2-1 may be lost due to a fire in this area. Redundant boric acid pump 2-2 will be available for this function. CVCS valve LCV-112B may be affected by a fire in this area. Valve 8805B remains available to provide water from the RWST to the charging pump suction. The VCT can be isolated by closing LCV-112C. A fire in this area may result in the loss of boric acid storage tank 2-1 level indication from LT-106. Borated water from the RWST will be available. Therefore, BAST level is not required. 4.1.3 Component Cooling Water CCW pump and ALOP 2-1 may be lost due to a fire in this area. CCW pumps and ALOPs 2-2 and 2-3 will remain available to provide CCW. CCW valve FCV-430 may be affected by a fire in this area making heat exchanger 2-1 unavailable for CCW cooling. Redundant valve FCV-431 will remain available making CCW heat exchanger 2-2 available. Thus no manual actions are required. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-10 FIRE ZONES 23-A, 24-A 9.5A-572 Revision 21 September 2013 4.1.4 Emergency Power The diesel generator 2-1 backup control circuit may be lost due to a fire in this area. The normal control circuit will remain available. Diesel generator 2-3 may be lost due to a fire in this area. Diesel generators 2-1 and 2-2 will remain available for safe shutdown. A fire in this area may disable startup transformer 2-2. Onsite power will remain available from diesel generators 2-1 and 2-2. All power supplies on the "F" Bus may be lost due to a fire in this area. Redundant power supplies from the "G" and "H" Buses will be available. A fire in this area may disable dc panel SD23 backup battery charger ED231. Normal battery charger ED232 will remain available. 4.1.5 Main Steam System A fire in this area may result in the loss of LT-516, LT-526, LT-529, LT-536, LT-539, LT-546, PT-514, PT-524, PT-534 and PT-544. Safe shutdown will not be affected since redundant instrumentation exists for all four steam generators. Main steam system valve PCV-19 may fail due to a fire in this area. Since this valve fails in its desired position, safe shutdown can still be achieved. A redundant dump valve will remain available for cooldown purposes. 4.1.6 Makeup System The level transmitter for the condensate storage tank, LT-40 may be lost due to a fire in this area. Feedwater will remain available through FCV-436 from the raw water storage reservoir. 4.1.7 Reactor Coolant System The following instrumentation may be lost due to a fire in this area: LT-406, LT-459, NE-31, NE-51, PT-406, PT-403, TE-413A, TE-413B, TE-423A, TE-423B. Redundant instrumentation will be available to provide necessary indications to the operator. RCS valve 8000A may be affected by a fire in this area. This valve fails "as is" (open). PCV-474 will remain closed to prevent uncontrolled pressure reduction through the PORV path. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-10 FIRE ZONES 23-A, 24-A 9.5A-573 Revision 21 September 2013 4.1.8 Safety Injection System SI valves 8801A, 8803A and 8805A may be lost due to a fire in this area. Valves 8801B and 8803B can be opened to provide a charging injection flow path in the event that 8801A and 8803A fail closed. Valve 8805B can be opened instead of valve 8805A to provide RWST water to the charging pumps. Since these valves have redundant components, safe shutdown is not affected. SI valve 8808A may be affected by a fire in this area. Valve 8808A can be manually closed in order to provide accumulator isolation during RCS pressure reduction. SI pump 2-1 may spuriously operate due to a fire in this area. Local manual action can be taken to defeat this spurious operation. 4.1.9 Auxiliary Saltwater System Circuitry for ASW pumps 2-1 and 2-2 may be damaged by a fire in this area. ASW pump 2-2 can be started locally to provide ASW flow. A fire in this area may affect valve FCV-602. This valve fails open which is the desired safe shutdown position. 4.1.10 HVAC HVAC equipment E-104, E-45, S-45, FCV-5045 and S-69 may be lost due to a fire in this area. E-104 and S-69 are not be necessary during a fire in this area. S-45, E-45 and FCV-5045 have redundant components S-46, E-46 and FCV-5046 that will remain available to provide necessary HVAC support to the 480 volt switchgear.
5.0 CONCLUSION
The consequences of a design basis fire will be mitigated by the following fire protection features and assure the ability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Smoke detection is provided in Fire Zones 23-A and 24-A.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-10 FIRE ZONES 23-A, 24-A 9.5A-574 Revision 21 September 2013
- Portable fire extinguishers, CO2 hose stations and fire hose stations are available.
- Redundant safe shutdown capability is located outside of this fire area.
In this fire area, existing fire protection features provide an acceptable level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 Drawing Nos. 515573, 515574, 515575, 515576 6.2 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065127, Fire Protection Information Report, Unit 2 6.5 SSER 8, November 1978 6.6 DCN DC2-EH-16047, Provide 3-hour rated Dampers to Area 24-E 6.7 Not used 6.8 PLC Report: Structural Steel Analysis for Diablo Canyon (Rev. 2) (7/8/86) 6.9 NECS File: 131.95, FHARE: 33, Undampered Ventilation Duct Penetrations 6.10 DCN DC2-EA-24390, Provide 3-hour rated Double Door and Plaster Blockout 6.11 NECS File: 131.95, FHARE: 106, Block Walls Modified in the 4kV Switchgear Area 6.12 AR A0211784 AE 08, NES Fire Protection's Evaluation of Exposed Structural Steel Anchor Bolts 6.13 NECS File: 131.95, FHARE: 136, Unrated HVAC Duct Penetrations 6.14 NECS File: 131.95, FHARE: 119, Plaster Barriers Credited for Appendix A to BTP (APCSB) 9.5-1 6.15 Calculation 134-DC, Electrical Appendix R Analysis 6.16 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.17 NECS File: 131.95, FHARE: 118, Appendix R Fire Area Plaster Barriers 6.18 NECS File: 131.95, FHARE: 134, "Non-rated Structural Gap Seals in Fire Barriers" 6.19 NECS File: 131.95, FHARE: 30, Unrated Gaps in Appendix R Barriers in the Turbine Building 6.20 NECS File: 131.95, FHARE: 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.21 NECS File: 131.95, FHARE: 50, Lesser Rated Plaster Barriers 6.22 Question 27, PG&E Letter to NRC Dated 11/13/78
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-11 FIRE ZONES 23-B, 24-B 9.5A-575 Revision 21 September 2013 FIRE AREA TB-11 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Area TB-11 is in the southeast corner of the Unit 2 Turbine Building and consists of Zones 23-B, and 24-B at El. 107 ft and 119 ft respectively. 1.2 Description Fire Zones 23-B and 24-B are in Fire Area TB-11 and contain the 4kV "G" Bus Cable Spreading Room at El. l04 ft and the 4kV "G" Bus switchgear room at El. 119 ft, respectively. At least two of the three vitalities are required for safe shutdown. 1.3 Boundaries 1.3.1 Fire Zone 23-B (El. 107 ft) North:
- 2-hour rated barrier separates this zone from Zone 23-A. (Refs. 6.6 and 6.16)
- Unrated structural gap seals to Fire Zone 23-A. (Ref. 6.14)
- A l-l/2-hour rated door communicates to Zone 23-A. (Ref. 6.16)
- One 3-hour rated doors communicate to Zone 23-A. South:
- 2-hour rated barrier separates this zone from Zone 23-C. (Refs. 6.6 and 6.16)
- Unrated structural gap seals to Fire Zone 23-C. (Ref. 6.14)
- One 3-hour rated door communicates to Zone 23-C.1
- Two 1-1/2-hour rated doors communicate to Zone 23-C. (Ref. 6.16) East:
- 2-hour rated barrier separates this zone from the exterior (Area 29). (Ref. 6.16)
West:
- 3-hour rated barrier separates this zone from Zones 22-C-2 and 23-C-1. (Ref. 6.15)
- 2-hour rated barrier to Fire Zone 23-C. (Ref. 6.16)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-11 FIRE ZONES 23-B, 24-B 9.5A-576 Revision 21 September 2013 Floor/Ceiling:
- 3-hour rated barrier separates this zone from Zones 24-B and 24-D above and Areas 20 and 22-C below.
- A ventilation opening without a fire damper communicates to Zone 24-B, above.
- A duct penetration with a 3-hour rated fire damper communicates with Fire Zone 24-E, above. (Ref. 6.3)
- 3-hour rated concrete hatches communicate through the floor and ceiling of this zone, on unprotected steel. (Ref. 6.8) 1.3.2 Fire Zone 24-B (El. 119 ft)
North:
- 2-hour rated barrier separates this zone from Zone 24-A. (Ref. 6.6)
- Unrated structural gap seals to Fire Zone 24-A. (Ref. 6.14)
- A 1-1/2-hour rated door communicates to Zone 24-A. South:
- 2-hour rated barrier separates this Zone from Zone 24-C. (Ref. 6.6)
- Unrated structural gap seals to Fire Zone 24-C. (Ref. 6.14)
- A 1-1/2-hour rated door communicates to Zone 24-C. East:
- 2-hour rated barrier separates this zone from the exterior (Area 29).
West:
- 3-hour rated barrier separates this zone from Area 24-D.
- Unrated structural gap seals to Fire Area 24-D. (Ref. 6.14)
- A ventilation duct with a 1-1/2-hour rated fire damper communicates to Area 24-D. (Ref. 6.6)
- A 1-1/2-hour rated double door communicates to Area 24-D. (Ref. 6.9)
- A 2-hour rated blockout around the door to Fire Area 24-D. (Ref. 6.9)
Floor/Ceiling:
- 3-hour rated barrier separates this zone from l9-D (above), and 23-B (below).
- A vent opening without a fire damper communicates to Zone 23-B.
- A vent opening with a 3-hour rated damper communicates to Zone 19-D.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-11 FIRE ZONES 23-B, 24-B 9.5A-577 Revision 21 September 2013 Protective
Enclosure:
- All corner gaps are sealed.
- Structural steel has a fire barrier coating.
(Note: Some structural steel modifications for the block walls (at El. 119 ft) were deemed acceptable with no fireproofing. (Ref. 6.10))
2.0 COMBUSTIBLES
2.1 Fire Zone 23-B 2.1.1 Floor Area: 1,473 ft2 2.1.2 In situ Combustible Materials
- Cable Insulation
- Rubber
- Plastic 2.1.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.1.4 Fire Severity
- Low 2.2 Fire Zone 24-B 2.2.1 Floor Area: 855 ft2 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-11 FIRE ZONES 23-B, 24-B 9.5A-578 Revision 21 September 2013 2.2.2 In situ Combustible Materials
- Cable insulation
- Rubber
- Plastic 2.2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection is provided in Zones 23-B and 24-B. 3.2 Suppression
- CO2 hose station
- Hose station
- Portable fire extinguisher DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-11 FIRE ZONES 23-B, 24-B 9.5A-579 Revision 21 September 2013 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Fire Zones 23-B and 24-B 4.1.1 Auxiliary Feedwater A fire in this area may affect LCV-106, LCV-107, LCV-108 and LCV-109. Redundant valves LCV-110 and LCV-111 will remain available to provide AFW flow to steam generators 2-1 and 2-2 from AFW Pump 2-2.
4.1.2 Chemical and Volume Control System Valve 8108 may be lost due to a fire in this area. Valve 8107 can be closed to isolate auxiliary spray, one other charging flowpath is available and the PORVs can be used for pressure reduction. Since this valve has redundant components, safe shutdown is not affected. A fire in this area may affect valve 8104. Safe shutdown is not affected because FCV-110A and manual valve 8471 will remain available to provide a boric acid flowpath to the charging pumps. Valves 8146, 8147 and 8148 may be affected by a fire in this area. Redundant valve 8107 will be available to isolate auxiliary spray. Alternate charging flow paths exist and the PORVs will be available for pressure reduction. Since redundant components are available, safe shutdown is not affected. Charging pumps 2-2 and 2-3 and ALOP 2-2 may be affected by a fire in this area. Redundant charging pump 2-1 and ALOP 2-1 will remain available for safe shutdown. Boric acid transfer pump 2-2 may be lost due to a fire in this area. Redundant boric acid transfer pump 2-1 will remain available. HCV-142 may be affected by a fire in this area. Since redundant components will be available, safe shutdown is not affected. A fire in this area may affect LCV-112C. Redundant valve 8805A will be available to provide water to the charging pump suction. The VCT may be isolated by a closure of LCV-112B. A fire in this area may affect valves LCV-459 and LCV-460. Redundant valves 8149A, 8149B, and 8149C will be available to isolate letdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-11 FIRE ZONES 23-B, 24-B 9.5A-580 Revision 21 September 2013 4.1.3 Component Cooling Water CCW pump and ALOP 2-2 may be lost due to a fire in this area. Redundant CCW pumps and ALOPs 2-1 and 2-3 will be available to provide CCW. A fire in this area may affect FCV-431. Redundant valve FCV-430 will enable the use of the other CCW train. Valve FCV-365 may be affected by a fire in this area. Since this valve fails in the desired, open position and redundant valve FCV-364 will remain available, safe shutdown is not affected. 4.1.4 Containment Spray A fire in this area may spuriously energize containment spray pump 2-1. However, the pump discharge valve, 9001A will remain closed and the pump will run on recirculation. 4.1.5 Diesel Fuel Oil System Diesel fuel oil pump 0-2 may be lost due to a fire in this area. Redundant diesel fuel oil pump 0-1 will remain available. A fire in this area may affect valves LCV-85, LCV-86 and LCV-87. Redundant valves LCV-88, LCV-89 and LCV-90 will provide day tank level control for all diesels. 4.1.6 Emergency Power Diesel generator 2-1 may be lost due to a fire in this area. Diesel generators 2-2 and 2-3 will remain available for safe shutdown. A fire in this area may disable the diesel generator 2-2 backup control circuit. The normal control circuit will remain available. A fire in this area may disable startup transformer 2-2. Onsite power will remain available from diesel generators 2-2 and 2-3. All power supplies on the "G" Bus may be lost due to a fire in this area. The redundant power supplies for "F" and "H" buses will be available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-11 FIRE ZONES 23-B, 24-B 9.5A-581 Revision 21 September 2013 4.1.7 Main Steam System A fire in this area may result in the loss of the following components: LT-519, LT-549, PT-515, PT-525, PT-535 and PT-545. Safe shutdown is not affected since redundant trains of instrumentation exist for all four steam generators. PCV-21 may be affected by a fire in this area. Since this valve fails in the desired closed position, safe shutdown is not affected. Redundant dump valves will remain available for cooldown purposes. A fire in this area may affect FCV-95. This valve is not necessary since two other AFW pumps 2-2 and 2-3 will remain available. Valves FCV-41 and FCV-42 may be affected by a fire in this area. These valves can be manually closed to ensure safe shutdown. 4.1.8 Reactor Coolant System A fire in this area may result in the loss of LT-460, NE-32, TE-433A, TE-433B, TE-443A and TE-443B. Redundant components for safe shutdown will be available. A fire in this area may affect valves 8000B and PCV-455C. 8000B fails "as is" (open) and PCV-455C fails closed. Since PCV-455C fails closed, uncontrolled pressure reduction will not occur. A redundant PORV is available for pressure reduction. Control of reactor coolant pumps 2-1, 2-2, 2-3 and 2-4 may be lost due to a fire in this area. Safe shutdown is not affected if the RCPs continuously run. Pressurizer heater groups 2-3 and 2-4 may be affected by a fire in this area. Manual actions can be taken to de-energize heater group 2-4 and switch heater group 2-3 to the vital power supply. Therefore, safe shutdown is not affected. 4.1.9 Residual Heat Removal System RHR pump 2-1 may be lost due to a fire in this area. Redundant pump 2-2 will be available to provide the RHR function. Valve 8701 may be affected by a fire in this area. This valve can be manually opened for RHR operations. A fire in this area may result in loss of control of FCV-641A. Since the redundant train is available (RHR Pp 2-2 and FCV-641B), this will not affect safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-11 FIRE ZONES 23-B, 24-B 9.5A-582 Revision 21 September 2013 4.1.10 Safety Injection System A fire in this area may result in the loss of valves 8801B, 8803B and 8805B. Redundant valves 8801A, 8803A and 8805A will remain available for safe shutdown. Valves 8808B and 8808D may be affected by a fire in this area. These valves can be manually closed to ensure safe shutdown. 4.1.11 Auxiliary Saltwater System Circuits for ASW pumps 2-1 and 2-2 may be damaged by a fire in this area. ASW pump 2-1 can be started locally to provide ASW flow. A fire in this area may affect valve FCV-603. Since this valve fails in the desired, open position, safe shutdown is not affected. 4.1.12 HVAC One train of required HVAC equipment, E-102 and S-68 may be lost due to a fire in this area. Neither of these components will be necessary because redundant HVAC equipment will be available to provide necessary HVAC support.
5.0 CONCLUSION
The following fire protection features mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Loss of the safe shutdown functions in these zones does not affect safe shutdown of the plant as the redundant train is located outside of the fire area will remain available.
- Smoke detection is provided in Zones 23-B and 24-B.
- Manual fire fighting equipment is available for use. In this fire area, existing fire protection features provide an acceptable level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III. G.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-11 FIRE ZONES 23-B, 24-B 9.5A-583 Revision 21 September 2013
6.0 REFERENCES
6.1 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.2 Drawing No. 515574, 515575, 6.3 DCN DC2-EA-l6047 Provides 3 Hr. Rated Damper 6.4 Drawing 065127, Fire Protection Information Report, Unit 2 6.5 Calculation M-824, Combustible Loading 6.6 SSER 8, November 1978 6.7 NECS File: 131.95, FHARE: 53, Undampered Duct Penetrations 6.8 PLC Report: Structural Steel Analysis for Diablo Canyon (Rev. 2) (7/8/86) 6.9 DCN DC2-EA-24390 Provide 3-hour rated double door and 2-hour rated plaster blockout 6.10 NECS File: 131.95, FHARE 106, Block Walls Modified in the 4kV Switchgear Area 6.11 AR A0211784 AE 08, NES Fire Protection's Evaluation of Exposed Structural Steel Anchor Bolts 6.12 Calculation 134-DC, Electrical Appendix R Analysis 6.13 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.14 NECS File: 131.95, FHARE: 134, "Non-rated Structural Gap Seals in Fire Barriers" 6.15 NECS File: 131.95, FHARE: 30, Unrated Gaps in Appendix R Barriers in the Turbine Building 6.16 Question 27, PG&E Letter to NRC Dated 11/13/78
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-12 FIRE ZONES 23-C, 24-C 9.5A-584 Revision 21 September 2013 FIRE AREA TB-12 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Area TB-12 is in the southeast corner of the Unit 2 Turbine Building and consists of Zones 23-C (4kV H Bus Cable Spreading Room) at El. 107 ft, and Zone 24-C (4kV H Bus Switchgear Room) at El. 119 ft. 1.2 Description Fire Zones 23-C and 24-C are in Fire Area TB-12 and contain the 4kV "H" Bus Cable Spreading Room at El. 107 ft and the 4kV "H" Bus Switchgear room at El. 119 ft respectively. At least two of the three vital divisions are required for safe shutdown. 1.3 Boundaries 1.3.1 Fire Zone 23-C (El. 107 ft) North:
- 2-hour rated barrier separates this zone from Zone 23-B. (Refs. 6.6 and 6.17)
- Unrated structural gap seals to Fire Zone 23-B. (Ref. 6.15)
- Two 1-1/2-hour rated doors communicating to Zone 23-B. (Ref. 6.17)
South:
- 2-hour rated barrier to the exterior (Area 29 and Fire Zone S-7).
- A 2-hour rated barrier separates this zone from Fire Zone S-7 (TB-13). (Ref. 6.7)
- Duct penetration with a 3-hour rated damper to the exterior (Area 29). (Ref. 6.17)
East:
- 2-hour rated barrier to the exterior (Area 29) and Zone 23-B. (Ref. 6.17)
West:
- 2-hour rated barrier separates this zone from Zones S-7 and 23-C-1. (Ref. 6.7)
- 2-hour rated barrier separates this zone from Fire Zone 23-C-1. (Ref. 6.8)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-12 FIRE ZONES 23-C, 24-C 9.5A-585 Revision 21 September 2013
- A 1-1/2-hour rated door communicates to Zone S-7.
- A duct penetration with a fire damper communicates to Zone S-7. (Ref. 6.3)
- Lesser rated penetration seals to Zone S-7 and 23-C-1. (Ref. 6.16) Floor/Ceiling:
Ceiling:
- 3-hour rated barrier
- A ventilation opening to Fire Zone 24-C, above Floor:
- 3-hour rated barrier on unprotected steel. (Ref. 6.9) 1.3.2. Fire Zone 24-C (El. 119 ft)
North:
- 2-hour rated barrier separates this zone from Zone 24-B.
- Unrated structural gap seals to Fire Zone 24-B. (Ref. 6.15)
- A 1-1/2-hour rated door communicates to Zone 24-B. (Ref. 6.6)
South:
- 2-hour rated barrier separates this zone from the exterior (Area 29). East:
- 2-hour rated barrier separates this zone from the exterior (Area 29).
West:
- 3-hour rated barrier separates this zone from Area 24-D.
- Unrated structural gap seals to Fire Area 24-D. (Ref. 6.15)
- A 1-1/2-hour rated double door communicates to Area 24-D. (Ref. 6.10)
- A ventilation duct with a 1-1/2-hour rated fire damper communicates to Area 24-D. (Ref. 6.6)
- A 2-hour rated blockout around the door. (Ref. 6.10)
Ceiling:
- 3-hour rated barrier to Fire Zone 19-D.
- A ventilation opening with a 3-hour rated damper to the main turbine deck.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-12 FIRE ZONES 23-C, 24-C 9.5A-586 Revision 21 September 2013 Floor:
- 3-hour rated barrier.
- A ventilation opening to Zone 23-C below.
Protective
Enclosure:
- All corner gaps are sealed.
- Structural steel has fire resistive coatings.
(Note: Some Structural steel modifications for the block walls (at El. 119 ft) were deemed acceptable with no fireproofing. (Ref. 6.11))
2.0 COMBUSTIBLES
2.1 Fire Zone 23-C 2.1.1 Floor Area: 1,224 ft2 2.1.2 In situ Combustible Materials
- Cable insulation
- Plastics 2.1.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.1.4 Fire Severity
- Low DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-12 FIRE ZONES 23-C, 24-C 9.5A-587 Revision 21 September 2013 2.2 Fire Zone 24-C 2.2.1 Floor Area: 958 ft2 2.2.2 In situ Combustible Materials
- Cable insulation
- Plastics
- Rubber 2.2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- 3.A.1 Zone 23-C Smoke detection for cable trays only
- 3.A.2 Zone 24-C Smoke detection area wide
- Smoke detection area wide 3.2 Suppression
- CO2 hose station
- Hose station
- Portable fire extinguisher DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-12 FIRE ZONES 23-C, 24-C 9.5A-588 Revision 21 September 2013 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Fire Zones 23-C and 24-C 4.1.1 Auxiliary Feedwater AFW pump 2-2 may be lost due to a fire in this area. Redundant AFW pumps 2-1 and 2-3 will be available to provide AFW.
A fire in this area may affect valves LCV-110 and LCV-111. Redundant valves LCV-106, LCV-107, LCV-108 and LCV-109 will remain available to provide AFW flow from AFW Pump 2-1, and LCV-113 and LCV-115 will remain available to provide AFW flow from AFW pump 2-3. 4.1.2 Chemical and Volume Control System Boric acid storage tank 2-2 level indication from LT-102 may be lost due to a fire in this area. Borated water from the RWST will remain available. Therefore, BAST level indication is not required. Pressurizer auxiliary spray valve 8145 may be affected by a fire in this area. This valve fails closed to isolate auxiliary spray during hot standby. The PORVs can be used for pressure reduction so valve 8145 will not be necessary. A fire in this area may affect valve FCV-110A. This valve fails in the desired, open position. Valve 8104 will remain available to provide boric acid transfer. 4.1.3 Component Cooling Water CCW pump 2-3 and ALOP 2-3 may be lost due to a fire in this area. Redundant pumps and ALOPs 2-1 and 2-2 will be available to provide CCW. A fire in this area may affect valve FCV-364. Since this valve fails in the desired, open position safe shutdown is not affected. 4.1.4 Containment Spray Containment spray pump 2-2 may spuriously operate due to a fire in this area. However, the corresponding discharge valve 9001B will not open. Therefore, the spurious containment spray pump operation has no impact on safe shutdown. 4.1.5 Diesel Fuel Oil System Diesel fuel oil pump 0-1 may be lost due to a fire in this area. The redundant diesel fuel oil pump 0-2 remains available. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-12 FIRE ZONES 23-C, 24-C 9.5A-589 Revision 21 September 2013 Valves LCV-88, LCV-89 and LCV-90 may be affected by a fire in this area. Redundant valves LCV-85, LCV-86 and LCV-87 will be available for day tank level control. 4.1.6 Emergency Power Diesel generator 2-2 may be lost due to a fire in this area. Diesel generators 2-1 and 2-3 will remain available for safe shutdown. A fire in this area may disable the diesel generator 2-3 backup control circuit. The normal control circuit will remain available. A fire in this area may disable startup transformer 2-2. Onsite power will remain available from diesel generators 2-1 and 2-3. All power supplies on the "H" Bus may lose power due to a fire in this area. Redundant power supplies on the "G" and "F" Buses will be available. A fire in this area may disable dc panel SD21 and SD22 backup battery charger ED221. Normal battery ED21 and ED22 will remain available. 4.1.7 Main Steam System A fire in this area may result in the loss of the following instrumentation: LT-518, LT-528, LT-538, LT-548, PT-526 and PT-536. Since redundant instrumentation exists for all four steam generators, safe shutdown is not affected. PCV-20 may be affected by a fire in this area. This valve fails in the desired, closed position, safe shutdown will not be affected. Redundant dump valves will remain available for cooldown purposes. A fire in this area may affect valves FCV-43 and FCV-44. These valves can be manually operated to ensure safe shutdown. 4.1.8 Reactor Coolant System A fire in this area may result in the loss of LT-461, NE-52 and PT-403. Safe shutdown will not be affected since redundant components will be available. A fire in this area may affect PZR PORV and blocking valve PCV-456 and 8000C. PCV-456 fails closed which prevents uncontrolled pressure reduction. Since redundant PORV PCV-455C will remain available for pressure reduction, safe shutdown will not be affected. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-12 FIRE ZONES 23-C, 24-C 9.5A-590 Revision 21 September 2013 Control of reactor coolant pumps 2-1, 2-2, 2-3 and 2-4 may be lost due to a fire in this area. Safe shutdown is not affected if the RCPs continuously run. Pressurizer heater groups 2-1 and 2-2 may be affected by a fire in this area. Manual actions can be taken to de-energize heater group 2-1 and switch heater group 2-2 to the vital power supply. Therefore, safe shutdown is not affected. 4.1.9 Residual Heat Removal System RHR pump 2-2 may be lost for a fire in this area. The redundant RHR pump 2-1 will be available to provide the RHR function. Valve 8702 may be affected by a fire in this area. This valve can be manually opened for RHR operations. A fire in this area may result in loss of control of FCV-641B. Since the redundant train is available (RHR Pp 2-1 and FCV-641A), this will not affect safe shutdown. 4.1.10 Safety Injection System SI pump 2-2 may spuriously operate due to a fire in this area. Local manual action may be required to defeat this spurious operation. Accumulator isolation valve 8808C may be affected by a fire in this area. This valve can be manually closed. 4.1.11 Auxiliary Saltwater System A fire in this area may affect valves FCV-495 and FCV-496. FCV-601 will remain closed to provide ASW system integrity. 4.1.12 HVAC A fire in this area may result in the loss of one train of HVAC components (E-46, S-46, FCV-5046 and S-67). S-67 is not necessary for a fire in this area. The HVAC function will be supplied by a redundant train of components (S-45, E-45 and FCV-5045).
5.0 CONCLUSION
The following fire protection features will adequately mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-12 FIRE ZONES 23-C, 24-C 9.5A-591 Revision 21 September 2013 references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Smoke detection is provided in Zone 23-C and 24-C.
- Manual fire fighting equipment is available for use.
- Loss of the safe shutdown functions in these zones does not affect safe shutdown of the plant as the redundant train is independent and remains available.
In this fire area, existing fire protection features provide an acceptable level of fire safety equivalent to that provided by l0 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 DCPP Unit 2 Review of l0 CFR 50, Appendix R (Rev. 2) 6.2 Drawing No. 515574, 5l5575 6.3 DCN DC2-EA-16047 - Provides 3 Hr. Rated Barrier 6.4 Drawing 065127, Fire Protection Information Report, Unit 2 6.5 Calculation M-824, Combustible Loading 6.6 SSER 8, November 1978 6.7 NECS File: 131.95, FHARE: 122: Staircase S-7, Fire Area Boundary 6.8 NECS File: 131.95, FHARE: 118, Appendix R Fire Area Plaster Barriers 6.9 PLC Report: Structural steel analysis for Diablo Canyon (Rev. 2) (7/8/86) 6.10 DCN DC2 - EA - 24390, Provide 3-hour rated double door and 2-hour rated plaster wall 6.11 NECS File: 131.95, FHARE: 106, Block Walls Modified in the 4kV Switchgear Area 6.12 AR A0211784 AE 08, NES Fire Protection's Evaluation of Exposed Structural Steel Anchor Bolts 6.13 Calculation 134-DC, Electrical Appendix R Analysis 6.14 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.15 NECS File: 131.95, FHARE: 134, "Non-rated Structural Gap Seals in Fire Barriers" 6.16 NECS File: 131.95, FHARE: 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.17 Question 27, PG&E Letter to NRC Dated 11/13/78 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-13 FIRE ZONE 23-C-1 9.5A-592 Revision 21 September 2013 FIRE AREA TB-13 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This zone is the corridor outside the 4kV cable spreading rooms at El. 107 ft at the south end of the Unit 2 Turbine Building. 1.2 Description Fire Zone 23-C-1 is the corridor between the Fire Zones 23-B and 23-C, and Stairway S-7 to the east and Fire Zone 22-C-2 on the west. The corridor contains "H" Bus safe shutdown circuitry. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
- 2-hour rated barrier to Fire Zone 23-B (TB-11).
- 3-hour rated door to Fire Zone 23-B. South:
- Nonrated barrier to the exterior (Area 29). NC East:
- 2-hour rated barrier to Fire Zones S-7, 23-B, and 23-C. (Ref. 6.10)
- 2-hour rated barrier to Fire Zone 23-C (TB-12). (Ref. 6.13)
- A duct penetration without a fire damper communicates to Fire Zone S-7 (TB-13). (Ref. 6.8)
- A 1-1/2-hour rated door to Fire Zone S-7 (TB-13).
- Lesser rated penetration seals to Fire Zones S-7 and 23-C. (Ref. 6.14)
- The south end of the east wall does not abut with the south wall. But the configuration is such that the rating is maintained to S-7.
West:
- 3-hour rated barrier to Fire Zone 22-C-2. (Ref. 6.9)
- A duct penetration without a fire damper communicates to Fire Zone 22-C-2.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-13 FIRE ZONE 23-C-1 9.5A-593 Revision 21 September 2013
- A nonrated penetration of structural steel to Zone 22-C-2 with sheet metal covers. (Ref. 6.9)
Floor/Ceiling:
- 3-hour barrier.
- Duct penetrations without a fire damper communicate from Fire Zone 24-E (above) to Fire Area 22-C below. (Ref. 6.8) 2.0 COMBUSTIBLES
2.1 Floor Area: 150 ft2 2.2 In situ Combustible Materials
- Bulk Cable
- Polyethylene
- Plastic
- Rubber 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection is provided.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-13 FIRE ZONE 23-C-1 9.5A-594 Revision 21 September 2013 3.2 Suppression
- CO2 hose stations and portable fire extinguishers are available in the vicinity. 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Diesel Fuel Oil System Diesel fuel oil pump 0-1 may be lost due to a fire in this area. Redundant diesel fuel oil pump 0-2 remains available.
4.2 Emergency Power A fire in this area may disable diesel generator 2-2. Offsite power is not affected in this area and will remain available for safe shutdown. In addition, diesel generators 2-1 and 2-3 will remain available for safe shutdown. 4.3 HVAC A fire in this area may affect one train of required HVAC equipment (S-67). S-67 is not necessary for a fire in this area.
5.0 CONCLUSION
The following fire protection features will mitigate the consequences of a design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- CO2 hose station and portable fire extinguishers are available in the vicinity.
- Redundant safe shutdown functions are located outside this fire zone.
- Low Fire Severity.
- Manual fire fighting equipment is available in adjacent area/zones. The existing fire protection for the area provides an acceptable level of safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-13 FIRE ZONE 23-C-1 9.5A-595 Revision 21 September 2013 6.1 Drawing Number 5l5574 6.2 Drawing Number 50l399 6.3 Drawing Number 06l882 6.4 DCPP Unit 2 Review of l0 CFR 50, Appendix R (Rev. 2) 6.5 Calculation M-824, Combustible Loading 6.6 Drawing 065127, Fire Protection Information Report, Unit 2 6.7 Deleted in Revision 13 6.8 NECS File: 131.95, FHARE: 33, Undampered Ventilation Duct Penetrations 6.9 NECS File: 131.95, FHARE: 30, Unrated Gaps in Appendix R Barriers in the Turbine Building 6.10 NECS File: 131.95, FHARE: 122, Staircase S-7 Fire Area Boundary 6.11 Calculation 134-DC, Electrical Appendix R Analysis 6.12 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.13 NECS File: 131.95, FHARE: 118, Appendix R Fire Area Plaster Barriers 6.14 NECS File: 131.95, FHARE: 109, Acceptance Criteria for Penetration Seals in Selected Barriers DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-13 FIRE ZONE 24-E 9.5A-596 Revision 21 September 2013 FIRE AREA TB-13 1.0 PHYSICAL CHARACTERISTICS
1.1 Location This fire zone is located at the south end of the Turbine Building at El. 107 ft and El. 119 ft (4-kV switchgear ventilation fan room). 1.2 Description This fire zone is an irregularly shaped area that incorporates two levels of the southwest end of the Turbine Building. On the l07-ft level the zone is the area above the ceiling of Fire Zones 22-A-1, 22-C-1, and 22-C-2. On the 119-ft level the zone is the 4kV switchgear ventilation fan room between Area 24-D and Zone 25 (TB-13). The air supply for these fans is from the El. 119 ft open ventilation hatch located in the northwest corner of the floor. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
El. 107 ft
- A 3-hour rated barrier to Zone 19-A (TB-7)
- A 3-hour rated door to Zone 19-A El. 119 ft
- 3-hour barrier to Fire Zone 19-A (TB-7)
- 3-hour rated double door to Fire Zone 19-A South:
El. 107 ft
- 3-hour rated barrier to Fire Zone 22-C-2 with nonrated features. (Ref. 6.14)
- A 3-hour rated single door to Fire Zone 22-C-2 DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-13 FIRE ZONE 24-E 9.5A-597 Revision 21 September 2013 El. 119 ft
- Nonrated barrier to Fire Zone 25 NC. Structural steel modifications for the block walls were deemed acceptable with no fireproofing. (Ref. 6.11)
- A 3-hour rated door to Fire Zone 25. NC East:
El. 107 ft
- A 2-hour rated barrier communicates to Fire Zones 23A (TB-10). (Refs. 6.12 and 6.17)
- 1-1/2-hour rated door to Fire Zone 23-A (TB-13) (Ref. 6.21)
- Lesser rate penetration seal to Fire Zone 23-A. (Ref. 6.18) El. 119 ft
- 2-hour rated barrier to Fire Area 24-D, and Zone 23-E (TB-7). (Refs. 6.12 and 6.17)
- A non-rated barrier to Fire Zone S-7 (TB-13) (Ref. 6.13)
- A duct penetration without fire damper to Zone 23-E. (Refs. 6.8 and 6.21)
- Lesser rate penetration seals to Fire Zones 24-D and 24-E. (Ref. 6.18)
- Three duct penetrations without fire dampers to Area 24-D. The ducts are provided with a 1-hour rated fire resistive covering in Area 24-D. (Refs. 6.5, 6.8 and 6.21) *
- 2-hour rated barrier to fire zone S-7 on mezzanine (El. 127 ft). (Ref. 6.13) West:
El. 107 ft
- 3-Hour rated barrier to Fire Zone 22-C-2.
El. 119 ft
- A nonrated barrier to Zone 25. NC
- A 1-1/2-hour rated door to Zone 25 NC at El. 127 ft above the mezzanine. (Ref. 6.21)
- The space between the mezzanine (Zone 25) and the exterior wall is wide open to provide air intake. (Ref. 6.21)
- The light fixtures in the hallway of Zone 25 are recessed in the ceiling without any fire barriers to Area 24-E.
- 2-hour rated barrier to Zone S-6. (Ref. 6.7)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-13 FIRE ZONE 24-E 9.5A-598 Revision 21 September 2013 Floor:
- 3-hour rated barrier except for: An open ventilation opening that connects El. 104 ft and 119 ft of Zone 24-E. Nonrated barrier between 24-E and 25 NC (El. 127 ft). (Ref. 6.6)
- A duct without a fire damper to Zone 23-C-1. (Refs. 6.8 and 6.21) - 2 dampered ducts to 4kV cable spreading rooms Fire Zones 23-A and 23-B.
Ceiling:
- 3-hour rated barrier to Zones 25 and 26 (El. 107 ft).
- 3-hour rated barrier to Zones 19-D (El. 119 ft). 2.0 COMBUSTIBLES
2.1 Floor Area: 1,211 ft2 (Ref. 6.12) 2.2 In situ Combustible Materials
- Clothing/Rags
- Rubber
- Cable
- Paper 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-13 FIRE ZONE 24-E 9.5A-599 Revision 21 September 2013 3.0 FIRE PROTECTION 3.1 Detection
- Smoke detection is provided throughout the 119-ft elevation. 3.2 Suppression
- A wet pipe automatic sprinkler (El. 119 ft) with remote annunciation.
- Portable fire extinguishers
- CO2 hose station
- Fire hose station 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Emergency Power System A fire in this area may disable circuits associated with diesel generator 2-3. Offsite power is not affected in this area and will remain available for safe shutdown. In addition, diesel generators 2-1 and 2-2 will remain available for safe shutdown. 4.2 HVAC A fire in this area may affect fans S-67, S-68 and S-69. The 4160 volt switchgear will not be affected by a loss of HVAC, therefore safe shutdown will not be affected. (Ref. 6.9)
5.0 CONCLUSION
The following fire protection features mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Low Fire Severity.
- Smoke detection is available at El. 119 ft.
- Automatic wet pipe sprinkler system at El. 119 ft.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-13 FIRE ZONE 24-E 9.5A-600 Revision 21 September 2013
- CO2 and fire hose stations.
- Portable fire extinguishers.
The existing fire protection provides an acceptable level of fire safety equivalent to that provided by Section III.G.2, because these fans are not required for safe shutdown.
6.0 REFERENCES
6.1 Drawing Numbers 515574, 515575 6.2 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065127, Fire Protection Information Report, Unit 2 6.5 NECS File: 131.95, FHARE: 15, HVAC Ducts Wrapped in Pyrocrete 102 6.6 NECS File: 131.95, FHARE: 44, Traveling Crew Quarters Wall 6.7 NECS File: 131.95, FHARE: 119, Plaster Barriers Credited for Appendix A to BTP (APCSB) 9.5-1 6.8 NECS File: 131.95, FHARE: 33, Undampered Ventilation Duct Penetrations 6.9 Calculations M-911 and M-912 6.10 Deleted in Revision 13 6.11 NECS File: 131.95, FHARE: 106, Block Walls Modified in the 4kV Switchgear Area 6.12 DCP H-50177, Diesel Generator Air Flow Improvement Modification, Units 1 and 2. 6.13 NECS File: 131.95: FHARE: 122, Staircase S-7 Fire Area Boundary 6.14 NECS File: 131.95, FHARE: 30, Unrated Gaps in Appendix R Barriers in the Turbine Building 6.15 Calculation 134-DC, Electrical Appendix R Analysis 6.16 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.17 NECS File: 131.95, FHARE: 118, Appendix R Fire Area Boundary Plaster Barriers 6.18 NECS File: 131.95, FHARE: 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.19 NECS File: 131.95, FHARE: 38, Undampered Ventilation Duct in a 1-Hour Barrier 6.20 NECS File: 131.95, FHARE: 60, Undampered Ventilation Ducts 6.21 NECS File: 131.95, FHARE 157, Unprotected Fire Rated Assemblies and Lack of Area-Wide Detection/Suppression. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-13 FIRE ZONE S-7 9.5A-601 Revision 21 September 2013 FIRE AREA TB-13 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fire Zone S-7 is a stairway, in the southern end of Unit 2 Turbine Building that goes from the 85-ft elevation up to the 140-ft main turbine deck. 1.2 Description This stairway is centered between the east and west sides of the Turbine Building. It runs from El. 85 ft to the turbine deck with access through fire rated doors at all elevations, except where it opens onto the turbine deck. 1.3 Boundaries El. 85 ft North:
- 2-hour rated barrier to Fire Area 20. (Ref. 6.8) South:
- 3-hour rated concrete barrier to the exterior East:
- 2-hour rated barrier to Fire Area 20 (Ref. 6.8)
West:
- 3-hour rated barrier to Fire Area 22-C
- A 1-1/2-hour rated door to Fire Area 22-C (Ref. 6.12)
- A nonrated seismic gap to Fire Area 22-C. (Ref. 6.8) El. 104 ft North:
- 2-hour rated barrier to Fire Zone 23-C (TB-12) (Ref. 6.8)
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-13 FIRE ZONE S-7 9.5A-602 Revision 21 September 2013 South:
- 2-hour rated barrier to the exterior shaft wall East:
- 2-hour rated barrier to Fire Zone 23-C (TB-12). (Ref. 6.8)
- A 1-1/2-hour rated door to Fire Zone 23-C.
- Duct penetration with a fire damper communicates to Fire Zone 23-C.
- Lesser rated penetration seals to Fire Zone 23-C. (Ref. 6.11) West:
- 2-hour rated barrier to Fire Zone 23-C-1 (TB-13) (Ref. 6.8)
- A 1-1/2-hour rated door to Fire Zone 23-C-1.
- A duct penetration without a fire damper communicates to Fire Zone 23-C-1. (Ref. 6.7)
- Lesser rated penetration seals to 23-C-1. (Ref. 6.11)
El. 119 ft North:
- 2-hour rated barrier to Fire Area 24-D. (Ref. 6.8) South:
- 2-hour rated barrier to the exterior.
East:
- 2-hour rated barrier to Fire Area 24-D. (Ref. 6.8)
- A 1-1/2-hour rated door to Fire Area 24-D.
- Duct penetration without a damper communicates to Fire Area 24-D. However, the ducting in Area 24-D is enclosed in a 1-hour rated enclosure. (Ref. 6.7)
- Lesser rated penetration seals to Fire Area 24-D. (Ref. 6.11) West:
- 2-hour rated barrier to Fire Zone 25
- Nonrated barrier to Fire Zone 24-E (TB-13). (Ref. 6.8)
- A 1-1/2-hour rated door to Fire Zone 25.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-13 FIRE ZONE S-7 9.5A-603 Revision 21 September 2013
- Duct penetration without a damper communicates to Fire Zone 24-E. (Ref. 6.7)
El. 140 ft The stairway is open to Fire Zone 19-D.
(Note: Electrical and mechanical penetrations are sealed at the barriers commensurate with the hazards to which they are exposed. The structural steel within the fire zone is unprotected.)
2.0 COMBUSTIBLES
2.1 Floor Area: 128 ft2 2.2 In situ Combustible Materials
- Cable Insulation
- Rubber
- Plastic 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection None DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-13 FIRE ZONE S-7 9.5A-604 Revision 21 September 2013 3.2 Suppression
- Manual suppression capability is available from other areas. 4.0 SAFE SHUTDOWN FUNCTIONS
4.1 Diesel Fuel Oil System Diesel fuel oil pump 0-1 may be lost due to a fire in this area. The redundant diesel fuel oil pump 0-2 will remain available. 4.2 Emergency Power A fire in this area may disable diesel generator 2-2. Offsite power is not affected in this area and will remain available for safe shutdown. In addition, diesel generators 2-1 and 2-3 will remain available for safe shutdown. 4.3 HVAC A fire in this area may result in the loss of one train of required HVAC equipment (S-67). S-67 is not necessary for a fire in this area.
5.0 CONCLUSION
The following features will mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- Deviations to requirements for 3-hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
- Manual suppression capability is provided in the adjacent zones.
- Substantial barriers, also electrical and mechanical penetrations sealed commensurate with barrier rating.
- Low fire severity.
The existing fire protection for the area provides an acceptable level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G. DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA TB-13 FIRE ZONE S-7 9.5A-605 Revision 21 September 2013
6.0 REFERENCES
6.1 Drawing Nos. 515573, 515574, 515575, 515576 6.2 Drawing No. 501399 6.3 Drawing Number 061882 6.4 DCPP Unit 2 Review of 10 CFR 50, Appendix R (Rev. 2) 6.5 Calculation M-824, Combustible Loading 6.6 Drawing 065127, Fire Protection Information Report, Unit 2 6.7 NECS File: 131.95, FHARE: 33, Undampered Ventilation Duct Penetrations 6.8 NECS File: 131.95, FHARE: 122, Staircase S-7 and S-6, Fire Area Boundary 6.9 Calculation 134-DC, Electrical Appendix R Analysis 6.10 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.11 NECS File: 131.95, FHARE: 109, Acceptance Criteria for Penetration Seals in Selected Barriers 6.12 SSER - 31
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA V-3 FIRE ZONE 3-V-3 9.5A-606 Revision 21 September 2013 FIRE AREA V-3 1.0 PHYSICAL CHARACTERISTICS
1.1 Location Fuel Handling Building El. 85 ft, 93 ft, 100 ft and 115 ft; Auxiliary Building main exhaust fan room No. 2, El. 115 ft; Auxiliary Building exhaust filter room, El. 100 ft; Auxiliary Building normal concrete exhaust duct, El. 93 ft; ad plenum, El. 85 ft. 1.2 Description This fire zone is located in the south end of the Unit 2 fuel handling building at El. 100 and 115 ft and includes a concrete exhaust air duct at El. 93 ft running from the Auxiliary Building to this zone. 1.3 Boundaries NOTE: NC designates a fire rated assembly that is not credited for compliance to 10 CFR 50 Appendix R or to Appendix A to BTP APCSB 9.5-1. North:
Three-hour rated barriers with the following exceptions: El. 85 ft:
- A 1-hour rated barrier with an undampered vent opening to Fire Zone 3-C. NC (Ref. 6.8)
- A 1-1/2-hour equivalent rated door communicating with Zone 3-L. NC
- A duct penetration without a damper to Fire Zone 3-A. NC (Ref. 6.9) El. 100 ft:
- Three nonrated doors communicating with Zone 3-V-2. NC
- A duct penetration without a fire damper penetrates zone 32. NC (Ref. 6.5) El. 115 ft:
- Five nonrated doors communicating with Zone 3-V-9. NC
- Two duct penetrations without fire dampers penetrate to Zone 3-V-9. NC DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA V-3 FIRE ZONE 3-V-3 9.5A-607 Revision 21 September 2013 South:
- 3-hour rated barriers. NC East:
- 3-hour rated barriers with the following exceptions. NC El. 100 ft A Duct penetration without a fire damper penetrates to Zone 32. NC (Ref. 6.5)
- Nonrated barrier to the exterior area at El. 115 ft. NC West:
- 3-hour rated barriers. NC
- Floor/Ceiling.
- Duct penetrations without fire dampers penetrate at 85-ft and 115-ft elevations.
2.0 COMBUSTIBLES
2.1 Floor Area: 1,150 ft2 2.2 In situ Combustible Materials
- Bulk Cable
- Foam Rubber
- Rubber
- Lube Oil
- Plastic 2.3 Transient Combustible Materials Transient combustible materials are strictly controlled in accordance with procedure OM8.ID4 and Engineering Calculation M-824. Below is a listing of reasonably expected transient combustible materials:
- Clothing/Rags
- Lubricants
- Miscellaneous Class A & B combustibles
- Solvents
- Wood DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA V-3 FIRE ZONE 3-V-3 9.5A-608 Revision 21 September 2013
- Plastic
- Paper 2.4 Fire Severity
- Low 3.0 FIRE PROTECTION
3.1 Detection
- Smoke detection at El. 115 ft 3.2 Suppression
- Portable fire extinguishers
- Hose stations 4.0 SAFE SHUTDOWN FUNCTIONS 4.1 Fire Zone 3-V-3 4.1.1 Auxiliary Feedwater AFW pumps 2-2 and 2-3 may be lost due to a fire in this area. Redundant AFW pump 2-1 will remain available.
5.0 CONCLUSION
The following fire protection features mitigate the consequences of the design basis fire and assure the capability to achieve safe shutdown:
- AFW pump 2-1 and associated components are independent of this fire zone and remain available for safe shutdown. (Ref. Section 4)
- Manual fire fighting equipment is available.
- Smoke detection provided in areas of combustible loading only (El. 115 ft).
- Deviations to requirements for 3 hour boundaries have been documented in the referenced Appendix R exemptions and engineering evaluations. These references verify that the subject boundaries are capable of maintaining adequate separation between redundant components to assure safe shutdown.
DCPP UNITS 1 & 2 FSAR UPDATE FIRE AREA V-3 FIRE ZONE 3-V-3 9.5A-609 Revision 21 September 2013 The existing fire protection features in this area provide an acceptable level of fire safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.
6.0 REFERENCES
6.1 Drawing Numbers 515577, 515578 6.2 DCPP Unit 2 Review of 10 CFR 50, Appendix R, Rev. 2 6.3 Calculation M-824, Combustible Loading 6.4 Drawing 065127, Fire Protection Information Report, Unit 2 6.5 NECS File: 131.95, FHARE: 40, Undampered Penetration Ducts 6.6 Calculation 134-DC, Electrical Appendix R Analysis 6.7 Calculation M-928, 10 CFR 50, Appendix R, Safe Shutdown Analysis 6.8 NECS File: 131.95, FHARE: 38, Undampered Ventilation Duct in a 1-Hour Barrier 6.9 NECS File: 131.95, FHARE: 60, Undampered Ventilation Ducts
DCPP UNITS 1 & 2 FSAR UPDATE
APPENDIX 9.5B REGULATORY COMPLIANCE SUMMARY DCPP UNITS 1 & 2 FSAR UPDATE 9.5B-1 Revision 15 September 2003 APPENDIX 9.5B DCPP REGULATORY COMPLIANCE SUMMARY A review of PG&E's compliance with Appendix A of NRC's Branch Technical Position (BTP) APCSB 9.5-1 was completed for the Diablo Canyon Power Plant (DCPP). PG&E's documents and correspondence on fire protection were reviewed to identify all commitments made regarding the applicable guidelines. Each commitment was evaluated to determine PG&E's compliance. The detailed results of this evaluation are documented in DCPP Commitment Closeout sheets for each guideline and commitment. Table B-1 summarizes the results of the evaluation.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 A. OVERALL REQUIREMENTS OF NUCLEAR PLANT FIRE PROTECTION PROGRAM Guideline Statement DCPP Compliance to Commitment 9.5B-2 Revision 15 September 2003 1. Personnel Responsibility for the overall fire protection program should be assigned to designated person in the upper level of management. This person should retain ultimate responsibility even though formulation and assurance of program implementation is delegated. Such delegation of authority should be to staff personnel prepared by training and experienced in fire protection and nuclear plant safety to provide a balanced approach in directing the fire protection programs for nuclear power plants. The qualification requirements for the fire protection engineer or consultant who will assist in the design and selection of equipment, inspect and test the completed physical aspects of the system, develop the fire protection program, and assist in the fire fighting training for the operating plant should be stated. Subsequently, the FSAR should discuss the training and the updating provisions such as fire drills provided for maintaining the competence of the station fire fighting and operating crew, including personnel responsible for maintaining and inspecting the fire protection equipment The fire protection staff should be responsible for: (a) Coordination of building layout and systems design with fire area requirements, including consideration of potential hazards associated with postulated design basis fires. (b) Design and maintenance of fire detection, suppression, and extinguishing systems. (c) Fire prevention activities. (d) Training and manual fire fighting activities of plant personnel and the fire brigade. Note: NFPA 6 - Recommendations for Organization of Industrial Fire Loss Prevention, contains useful guidance for organization and operation of the entire fire loss prevention program Responsibility for the overall fire protection program has been assigned to the President of PG&E. All fire protection staff and engineers satisfy the applicable qualification requirements. The responsibilities of the fire protection staff are described in administrative and fire fighting procedures. Appendix 9.5H details the organization, training, equipment, and implementing procedures related to the fire protection personnel. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 A. OVERALL REQUIREMENTS OF NUCLEAR PLANT FIRE PROTECTION PROGRAM Guideline Statement DCPP Compliance to Commitment 9.5B-3 Revision 15 September 2003 2. Design Bases The overall fire protection program should be based upon evaluation of potential fire hazards throughout the plant and the effect of postulated design basis fires relative to maintaining ability to perform safety shutdown functions and minimize radioactive releases to the environment. The overall fire protection program is based on the evaluation of potential fire hazards throughout the plant. The Appendix R Reports for DCPP Units 1 and 2 analyze the effect of a postulated design basis fire relative to safe shutdown functions and minimize radioactive releases to the environment. 3. Backup Total reliance should not be placed on a single automatic fire suppression system. Appropriate backup fire suppression capability should be provided. In areas of the plant where automatic fire suppression systems are employed, appropriate backup fire suppression capability is provided by installation of manual hose stations, portable fire extinguishers and portable fire pumps. Each backup method is surveilled as per procedure to ensure equipment availability so total reliance is not dependent upon a single automatic fire suppression system. 4. Single Failure Criterion A single failure in the fire suppression system should not impair both the primary and backup fire suppression capability. For example, redundant fire water pumps with the independent power supplies and controls should be provided. Postulated fires or fire protection system failures need not be considered concurrent with other plant accidents or the most severe natural phenomena. The effects of lightning strikes should be included in the overall plant fire protection program A single failure in the fire suppression system will not impair both the primary and backup suppression capability due to the nature of the primary and backup water supplies, the independence of power supplies for the associated pumps and valves, and the provision for portable backup fire pumps. Portions of the fire water system have been analyzed in regard to the design basis earthquake and are seismically qualified so that all hose-reels in safety-related areas of the plant will be available following a safe shutdown earthquake. The seismically qualified portion of the fire system can be readily isolated from the rest of the fire system. Other than those areas required to be available after the design basis earthquake, postulated fires or fire protection system failures are not considered concurrent with other plant accidents or the most severe natural phenomena. Lightning rods are installed at the high points of the containment, and lightning arrestors are installed on each of the phases of the main and DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 A. OVERALL REQUIREMENTS OF NUCLEAR PLANT FIRE PROTECTION PROGRAM Guideline Statement DCPP Compliance to Commitment 9.5B-4 Revision 15 September 2003 auxiliary transformers. The effects of lightning strikes are included in the overall plant fire protection program 5. Fire Suppression Systems Failure or inadvertent operation of the fire suppression systems should not incapacitate safety-related systems or components. Fire suppression systems that are pressurized during normal plant operation should meet the guidelines specified in BTP APSCB 3-1, "Protection Against Postulated Piping Failure in Fluid Systems Outside Containment." Failure or inadvertent operation of the fire suppression system has been evaluated in response to this guidance and NRC Information Notice 83-41. Failure due to seismic acceleration is not a concern, as determined in SSER No. 9 by the NRC. Fire suppression systems that are pressurized during normal plant operation meet the guidelines of APSCB 3-1. 6. Fuel Storage Areas The fire protection program (plans, personnel and equipment) for buildings storing new reactor fuel and for adjacent fire zones which could affect the fuel storage zone should be fully operational before fuel is received. Schedule for implementation of modifications, if any, will be established on a case-by-case basis. Amendment 51, in conjunction with the implementation of fire protection procedures, ensures that the fire protection program is fully operational in fire zones storing new reactor fuel and in adjacent fire zones. 7. Fuel Loading The fire protection program for an entire reactor unit should be fully operational prior to initial fuel loading in that reactor unit. Schedule for implementation of modifications, if any, will be established on a case-by-case basis. The fire protection program for Units 1 and 2 is fully operational and documented. The program was established prior to initial fuel loading. Schedule for implementation of modifications was established by 10 CFR 50.48(c). 8. Multiple Reactor Sites On multiple-reactor sites where there are operating reactors and construction of remaining units is being completed, the fire protection program should provide continuing evaluation and include additional fire barriers, fire protection capability, and administrative controls necessary to protect the operating units from construction fire hazards. The superintendent of the operating plant should have the lead responsibility for site fire protection. The fire protection program provided adequate protection for the operating unit from construction fire hazards, as assessed by audits and design change verifications. The Plant Manager had ultimate responsibility for site fire protection during construction DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 A. OVERALL REQUIREMENTS OF NUCLEAR PLANT FIRE PROTECTION PROGRAM Guideline Statement DCPP Compliance to Commitment 9.5B-5 Revision 15 September 2003 9. Simultaneous Fires Simultaneous fires in more than one reactor need not be postulated, where separation requirements are met. A fire involving more than one reactor unit need not be postulated except for facilities shared between units. For fire areas unique to only one unit, the Fire Hazards Analyses postulates a fire to occur in only one unit at a time. For fire areas in common facilities, the Fire Hazards Analyses present evaluations to ensure safe shutdown of both units. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 B. ADMINISTRATIVE PROCEDURES, CONTROLS AND FIRE BRIGADE Guideline Statement DCPP Compliance to Commitment 9.5B-6 Revision 15 September 2003 1. General Administrative Procedures Administrative procedures consistent with the need for maintaining the performance of the fire protection system and personnel in nuclear power plants should be provided. Guidance is contained in the following publications: NFPA 4 Organization for Fire Services NFPA 4A Organization for Fire Department NFPA 6 Industrial Fire Loss Prevention NFPA 7 Management of Fire Emergencies NFPA 8 Management Responsibility for Effects of Fire on Operations NFPA 27 Private Fire Brigades PG&E maintains performance of the DCPP Fire Protection Program and its personnel through effective administrative procedures guided by NFPA codes. The Fire Protection Program presents detailed information on the administrative procedures required to implement the fire protection program. 2. Bulk Storage of Combustibles Effective administrative measures should be implemented to prohibit bulk storage of combustible materials inside or adjacent to safety-related buildings or systems during operation or maintenance periods. Regulatory Guide (RG) 1.39, "Housekeeping Requirements for Water-Cooled Nuclear Power Plants," provides guidance on housekeeping, including the disposal of combustible materials. Administrative measures prohibiting bulk storage of combustible materials inside or adjacent to safety-related buildings or systems in operation have been established. DCPP follows the guidance presented in RG 1.39. Certain areas containing safe shutdown equipment disposal of combustible materials have been designated as posted "No Storage" areas to eliminate the possibility of an exposure fire from bulk storage of combustibles. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 B. ADMINISTRATIVE PROCEDURES, CONTROLS AND FIRE BRIGADE Guideline Statement DCPP Compliance to Commitment 9.5B-7 Revision 15 September 2003 3. Normal and Abnormal Conditions Normal and abnormal conditions or other anticipated operations such as modifications (e.g., breaking fire stops, impairment of fire detection and suppression systems) and refueling activities should be reviewed by appropriate levels of management and appropriate special actions and procedures such as fire watches or temporary fire barriers implemented to assure adequate fire protection and reactor safety. In particular: (a) Work involving ignition sources such as welding and flame cutting should be done under closely controlled conditions. Procedures governing such work should be reviewed and approved by persons trained and experienced in fire protection. Persons performing and directly assisting in such work should be trained and equipped to prevent and combat fires. If this is not possible, a person qualified in fire protection should directly monitor the work and function as a fire watch. (b) Leak testing, and similar procedures such as air flow determination, should use one of the commercially available aerosol techniques. Open flame or combustion generated smoke should not be permitted. (c) Use of combustible material, e.g., HEPA and charcoal filters, dry ion exchange resins or other combustible supplies, in safety-related systems or equipment should be permitted only when suitable fire retardant treated wood (scaffolding, lay noncombustible substitutes are not available. If wood must be used, only down blocks) should be permitted. Such materials should be allowed into safety-related areas only when they are to be used immediately. Their possible and probable use should be considered in the fire hazard analysis to determine the adequacy of the installed fire protection systems. Adequate fire protection and reactor safety at DCPP are maintained during normal and abnormal conditions or anticipated operations such as modifications and refueling activities by appropriate review by the DCPP Plant Staff Review Committee and the plant fire protection organization. Appropriate special actions are taken when needed as determined by these reviews. Work involving ignition sources at DCPP is controlled by Procedure IDAP OM8.ID1, Fire Loss Prevention and Administrative Procedure. (See Appendix 9.5H.) Persons trained and experienced in fire protection both review and implement these procedures. Qualified firewatches are provided when requirements of the ignition source control program cannot be met. PG&E ensures that neither open flame nor combustion generated smoke is used for leak testing through the above referenced administrative procedures. Testing is by commercial aerosol techniques, soap bubble test, or measurement of pressure change. The use of combustible materials at DCPP is strictly controlled through Administrative Procedure. (See Appendix 9.5H.) Combustible materials are used in safety-related systems only when suitable noncombustible substitutes are not available. The fire hazard analysis considers all in-situ combustibles to determine the adequacy of the installed fire protection systems. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 B. ADMINISTRATIVE PROCEDURES, CONTROLS AND FIRE BRIGADE Guideline Statement DCPP Compliance to Commitment 9.5B-8 Revision 15 September 2003 4. Self-sufficient Fire Fighting Capability Nuclear power plants are frequently located in remote areas, at some distances from public fire departments. Also, first response fire departments are often volunteer. Public fire department response should be considered in the overall fire protection program. However, the plant should be designed to be self-sufficient with respect to fire fighting activities and rely on the public response only for supplemental or backup capability. DCPP is self-sufficient with respect to fire fighting activities as described in the Administrative Procedure. (See Appendix 9.5H.) The San Luis Obispo County Fire Department provides a backup to primary fire brigade response to the power plant structures. 5. Fire Brigade Organization, Training, and Equipment The need for good organization, training, and equipping of fire brigades at nuclear power plant sites requires effective measures be implemented to assure proper discharge of these functions. The guidance in Regulatory Guide 1.101, "Emergency Planning for Nuclear Power Plants," should be followed as applicable. Organization, training, and equipment maintenance of the DCPP fire brigade is assured through an active Fire Protection Program and its supporting administrative and inspection procedures. The emergency plan established was developed to comply with the provisions of Appendix E to 10 CFR 50 and used the guidance contained in the "Guide to the Preparation of Emergency Plans for Production and Utilization Facilities." (a) Successful fire fighting requires testing and maintenance of the fire protection equipment emergency lighting and communication, as well as practice as brigades for the people who must utilize the equipment. A test plan that lists the individuals and their responsibilities in connection with routing tests and inspections of the fire detection and protection systems should be developed. The test plan should contain the types, frequency, and detailed procedures for testing. Procedures should also contain instructions on maintaining fire protection during those periods when the fire protection system is impaired or during periods of plant maintenance, e.g., fire watches or temporary hose connections to water systems. Procedures for testing and maintaining fire protection emergency lighting and communications systems are in effect. Administrative procedures describe the responsibilities for and disposition of the test and maintenance records resulting from the test procedures. Fire brigade members are trained in the use, testing, and maintenance of equipment. Abnormal operating conditions (such as may occur during maintenance periods) are reviewed and appropriate fire protection control measures are initiated. (b) Basic training is a necessary element in effective fire fighting operation. In order for a fire brigade to operate effectively, it must operate as a team. All members must know what their individual duties are. They must be familiar with the layout of the plant and equipment location and operation in order to permit effective fire fighting operations during times when a particular area is filled with smoke or is insufficiently lighted. Such training can only be accomplished by conducting drills several times a year (at DCPP Fire Brigade training occurs in accordance with the Fire Protection Program. A formal training program exists for fire brigade members. Formal training sessions are held at least quarterly, and individual training records are maintained in the plant files. Training sessions are supplemented by preplanned fire drills, conducted on a quarterly basis. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 B. ADMINISTRATIVE PROCEDURES, CONTROLS AND FIRE BRIGADE Guideline Statement DCPP Compliance to Commitment 9.5B-9 Revision 15 September 2003 least quarterly) so that all members of the fire brigade have had the opportunity to train as a team, testing itself in the major areas of the plant. The drills should include the simulated use of equipment in each area and should be preplanned and post-critiqued to establish the training objective of the drills and determine how well these objectives have been met. These drills should periodically (at least annually) include local fire department participation where possible. Such drills also permit supervising personnel to evaluate the effectiveness of communications within the fire brigade and with the on scene fire team leader, the reactor operator in the control room, and the offsite command post. (c) To have proper coverage during all phases of operation, members of each shift crew should be trained in fire protection. Training of the plant fire brigade should be coordinated with the local fire department so that responsibilities and duties are delineated in advance. This coordination should be part of the training course and implemented into the training of the local fire department staff. Local fire departments should be educated in the operational precautions when fighting fires on nuclear power plant sites. Local fire departments should be made aware of the need for radioactive protection of personnel and the special hazards associated with a nuclear power plant site. DCPP ensures proper fire protection coverage of the plant site through a 24-hour fire brigade supplied by shift personnel. Each brigade member satisfies the training requirements outlined in the Fire Protection Program which discusses plant and offsite fire department involvement. Local fire department members are trained in the special hazards and precautions associated with fires on nuclear power plant sites. (d) NFPA 17, "Private Fire Brigade" should be followed in organization, training, and fire drills. This standard also is applicable for the inspection and maintenance of fire fighting equipment. Among the standards referenced in this document, the following should be utilized: NFPA 194, "Standard for Screw Threads and Gaskets for Fire Hose Couplings," NFPA 196, Standard for Fire Hose," NFPA 197, "Training Standard on Initial Fire Attacks," NFPA 601, "Recommended Manual of Instructions and Duties for the Plant Watchman on Guard." NFPA booklets and pamphlets listed on pages 27-11 of Volume 8, 19/1-/2 are also applicable for good training references. In addition, courses in fire prevention and fire suppression which are recognized and/or sponsored by the fire protection industry should be utilized. Fire brigade organization, training, and fire drills are described in Appendix 9.5H. NFPA standards were used when organizing the fire brigade and developing the fire protection program implementing procedures. They will continue to be used when developing new or revising existing procedures. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 C. QUALITY ASSURANCE PROGRAM Guideline Statement DCPP Compliance to Commitment 9.5B-10 Revision 15 September 2003 Quality Assurance (QA) programs of applicants and contractors should be developed and implemented to assure that the requirements for design, procurement installation, and testing and administrative control for the fire protection program for safety-related areas as defined in this branch position are satisfied. The program should be under the management control of the QA organization. The QA program criteria that apply to the fire protection program should include the following: The QA Program, as described in Chapter 17 of the FSAR Update, assures that requirements for design, procurement, construction, testing, and related administrative activities for the Fire Protection (FP) Program for safety-related areas are satisfied. 1. Design Control and Procurement Document Control Measures should be established to assure that all design-related guidelines of the branch technical position are included in design and procurement documents and that deviations therefrom are controlled. Procedures ensure that all design-related guidelines of the branch technical position are included in the design and procurement documents and that deviations are controlled. 2. Instructions, Procedures, and Drawings Inspections, tests, administrative controls, fire drills, and training that govern the fire protection program should be prescribed by documented instructions, procedures, or drawings and should be accomplished in accordance with these documents. Procedures govern inspections, tests, administrative controls, fire drills, and training relating to the FP Program. 3. Control of Purchase Material, Equipment, and Services Measures should be established to assure that purchased material, equipment, and services conform to the procurement documents. Procedures address procurement and establish guidelines to assure that purchased material, equipment, and services conform to the procurement documents. 4. Inspection A program for independent inspection of activities affecting fire protection should be established and executed by, or for, the organization performing the activity to verify conformance with documented installation drawings and test procedures for accomplishing the activities. DCMs S-18 and T-13, and Appendix 9.5H provide a list of procedures that govern inspections, tests, administrative controls, fire drills, and training related to the FP Program. Following modifications, installation tests are initiated by procedures that govern the design change process. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 C. QUALITY ASSURANCE PROGRAM Guideline Statement DCPP Compliance to Commitment 9.5B-11 Revision 15 September 2003 5. Test and Test Control A test program should be established and implemented to assure that testing is performed and verified by inspection and audit to demonstrate conformance with design and system readiness requirements. The tests should be performed in accordance with written test procedures; test results should be properly evaluated and acted on. Test programs are laid out in detail in surveillance test procedures and are controlled by administrative procedures. The design change process mandates inspections following modifications. Procedures governing periodic inspections are laid out in the surveillance test procedures. Test results are documented evaluated, and their acceptability determined in accordance with these procedures. 6. Inspection, Test and Operating Status Measures should be established to provide for the identification of items that have satisfactorily passed required tests and inspections. Procedures establish measures to provide for the identification of items that have satisfactorily passed required tests and inspections. 7. Nonconforming Items Measures should be established to control items that do not conform to specified requirements to prevent inadvertent use or installation. The control of nonconforming items is governed by administrative procedures that mandate identification and reporting requirements to prevent inadvertent use or installation. 8. Corrective Action Measures should be established to assure that conditions adverse to fire protection, such as failures, malfunctions, deficiencies, deviations, defective components, uncontrolled combustible material, and nonconformance are promptly identified, reported, and corrected. Policies governing corrective measures relative to fire protection failures, malfunctions, deficiencies, deviations, defective components, uncontrolled combustible material, and nonconformances are addressed in administrative procedures. 9. Records Records should be prepared and maintained to furnish evidence that the criteria enumerated above are being met for activities affecting the fire protection program. Procedures provide for collection and retention of the records that are generated to verify the quality of the fire protection program. 10. Audits Audits should be conducted and documented to verify compliance with the fire protection program, including design and procurement documents; instructions; procedures and drawings, and inspection and test activities. Audits are conducted and documented to verify FP Program compliance. Procedures governing audits are presented in the administrative procedures manual. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 D. GENERAL GUIDELINES FOR PLANT PROTECTION Guideline Statement DCPP Compliance to Commitment 9.5B-12 Revision 15 September 2003 1. Building Design (a) Plant layouts should be arranged to: (1) Isolate safety-related systems from unacceptable fire hazards. (2) Separate redundant safety-related systems from each other so that both are not subject to damage from a single fire hazard. Alternatives: (A) Redundant safety-related systems that are subject to damage from a single fire hazard should be protected by a combination of fire retardant coatings and fire detection and suppression systems. (B) A separate system to perform the safety function should be provided. Plant layouts isolate safety-related systems from unacceptable fire hazards by (1) physical distance between potential hazards and safety-related equipment; (2) fire barriers; (3) administrative control over storage combustibles; and (4) detection and suppression systems. Redundant safety-related systems are separated according to the criteria of 10 CFR 50, Appendix R, Section III.G. Various exemptions to these requirements have been requested per 10 CFR 50.48 and are detailed in Appendix R Reports for Units 1 and 2. (b) In order to accomplish (a)(1) above, safety-related systems and fire hazards should be identified throughout the plant. Therefore, a detailed fire hazard analysis should be made. The fire hazards analysis should be reviewed and updated as necessary. A detailed fire hazard analysis identifies safety-related systems and fire hazards throughout the plant. This analysis is complete and updated as necessary. (c) For multiple reactor sites, cable spreading rooms should not be shared between reactors. Each cable spreading room should be separated from other areas of the plant by barriers(walls and floors) having a minimum fire resistance of three hours. Cabling for redundant safety divisions should be separated by walls having three-hour fire barriers. Units 1 and 2 use separate cable spreading rooms that are isolated from other areas of the plant by three-hour fire barriers except for the exemptions noted in the fire hazards analysis for these rooms (see Appendix 9.5A). Cabling for redundant safety divisions is not separated by three-hour fire walls. However, alternate safe shutdown capability independent of the cable spreading room has been provided. Therefore, a cable spreading room fire affecting redundant safety divisions would not adversely affect the ability to attain a safe shutdown. (d) Interior wall and structural components, thermal insulation materials and radiation shielding materials, and soundproofing should be noncombustible. Interior finishes should be noncombustible or listed by a nationally recognized testing laboratory, such as Factory Mutual or Underwriters' Laboratory, Inc., for flame spread, smoke and fuel contribution of 25 or less in its use configuration (ASTM E84 test, "Surface Burning Characteristics of Building Materials"). All interior wall and structural components, thermal insulation, radiation shielding materials, and soundproofing are noncombustible or have been evaluated to ensure that safe shutdown capability is not adversely impacted. The Fire Hazards Analysis (Appendix 9.5A) ensures that fire barriers can adequately contain postulated fire of the calculated severity. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 D. GENERAL GUIDELINES FOR PLANT PROTECTION Guideline Statement DCPP Compliance to Commitment 9.5B-13 Revision 15 September 2003 (e) Metal deck roof construction should be noncombustible (see the building materials directory of the Underwriters' Laboratory, Inc.) or listed as Class 1 by Factory Mutual System Approval Guide. Built-up metal roof construction is not utilized at DCPP. (f) Suspended ceilings and their supports should be of noncombustible construction. Concealed spaces should be devoid of combustibles. Suspended ceilings and supports are constructed of noncombustible materials, diffusers, and insulated pipe wraps in the control room. The fire hazards analysis (Appendix 9.5A) for the control room indicates that presence of this material does not present an unacceptable fire hazard. Concealed spaces above suspended ceilings are kept free of combustibles except for-fire area 4-A, counting and chemical laboratory, where redundant conduits containing cables essential to safe shutdown are located above the suspended ceiling. The laboratory ceiling has been replaced with a membrane fire-rated ceiling. The fire hazards analysis for fire area 4-A ensures that these combustibles do not adversely impact safe shutdown. (g) High voltage-high amperage transformers installed inside buildings containing safety-related systems should be of the dry type or insulated and cooled with noncombustible liquid. All high-amperage transformers installed inside buildings are of the dry type, as documented on drawings. (h) Buildings containing safety-related systems, having openings in exterior walls closer than 50 feet to flammable oil-filled transformers should be protected from the effects of a fire by: (1) Closing of the opening to have fire resistance equal to three hours. (2) Constructing a three-hour fire barrier between the transformers and the wall openings. (3) Closing the opening and providing the capability to maintain a water curtain in case of a fire. Buildings containing safety-related systems, having openings in exterior walls closer than 50 feet to flammable oil-filled transformers, are protected from the effect of a fire by two-hour rated barriers. The acceptability of this construction is evaluated in Appendix 9.5A. (i) Floor drains, sized to remove expected fire fighting water flow should be provided in those areas where fixed water fire suppression systems are installed. Drains should also be provided in other areas where hand hose lines may be used if such fire fighting water could cause unacceptable damage to equipment in the area. Equipment should be provided as required to contain water and direct it to floor drains. (See NFPA 92M, Floor drains (or other drainage means) of adequate capacity for anticipated fire water runoff are located in areas of the plant where sprinklers are located and in most areas where fire water hose reels would be used. Floor drains are not provided in some electrical areas. However, since automatic sprinklers are not located in these areas, any fire fighting involving use of water in these areas would be done with DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 D. GENERAL GUIDELINES FOR PLANT PROTECTION Guideline Statement DCPP Compliance to Commitment 9.5B-14 Revision 15 September 2003 "Waterproofing and Draining of Floors"). Drains in area containing combustible liquids should have provisions for preventing the spread of the fire throughout the drain system. Water drainage from areas which may contain radioactivity should be sampled and analyzed before discharge to the environment. hose reels by the fire brigade. If water was accumulating in a compartment, the fire brigade would open doors to allow runoff to stairwells or other areas. Furthermore, the quantity of water that might be expected to be used in an electrical area is not enough to cause flooding, even in a closed compartment. Flooding would not occur to such a level that safe shutdown equipment would be endangered. Equipment is mounted on pedestals, minimizing any adverse effects of water suppression systems. Building sumps and sump pumps have adequate capacity to handle anticipated fire water flows. Drain lines in areas containing significant amounts of combustible liquids are sized and sloped to minimize backflow into other areas and to prevent the spread of fire through the drain system. All drainage from areas that may contain radioactivity is processed through the liquid radwaste systems and automatically monitored prior to discharge. (j) Floors, walls, and ceilings enclosing separate fire areas should have minimum fire rating of three-hours. Penetration in these fire barriers, including conduits and piping, should be sealed or closed to provide a fire resistance rating at least equal to that of the fire barrier itself. Door openings should be protected with equivalent rated doors, frames, and hardware that have been tested and approved by a nationally recognized laboratory. Such doors should be normally closed and locked or alarmed with alarm and annunciation in the control room. Penetrations for ventilation systems should be protected by a standard "fire door damper" where required. (Refer to NFPA 80, "Fire Doors and Windows.") The fire hazard in each area should be evaluated to determine barrier requirements. If barrier fire resistance cannot be made adequate, fire detection and suppression should be provided, such as: (1) Water curtain in case of fire. (2) Flame retardant coatings. (3) Additional fire barriers. Floors walls, and ceilings enclosing separate fire areas are fire rated as appropriate for the local fire hazard. The adequacy of fire barriers in accordance with Appendix R is evaluated as part of the fire barrier penetration program. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 D. GENERAL GUIDELINES FOR PLANT PROTECTION Guideline Statement DCPP Compliance to Commitment 9.5B-15 Revision 15 September 2003 2. Control of Combustibles (a) Safety-related systems should be isolated from combustible materials. When this is not possible because of the nature of the safety system or the combustible material, special protection should be provided to prevent a fire from defeating the safety system function. Such protection may involve a combination of automatic fire suppression, and construction capable of withstanding and containing a fire that consumes all combustibles present. Examples of such combustible materials that may not be separable from the remainder of its system are: Safety-related systems are isolated and separated from combustible materials wherever possible. When this is not possible, special protection has been provided to prevent a fire from defeating the safety system functions. "Fire Hazard Analysis" in Appendix 9.5A and the "Report on 10 CFR 50, Appendix R Review" have shown that a single fire will not impair redundant safe shutdown system functions because (a) one train of redundant safe shutdown related equipment/components has been protected by rated fire-retardant materials; or (b) the affected components have been protected by automatic fire suppression; or both. (1) Emergency diesel generator fuel oil day Each emergency diesel generator room is enclosed by three-hour fire barriers, and automatic CO2 low-pressure flooding is furnished. Fire hazards analyses for the diesel generator rooms are presented in Appendix 9.5A. (2) Turbine-generator oil and hydraulic control fluid systems. The turbine building is separated from the rest of the plant by three-hour fire barriers. CO2 flooding is provided to the lube oil reservoir rooms, and sprinkler/spray systems provide fire suppression capabilities to various areas in the turbine building (see Appendix 9.5A). (3) Reactor coolant pump lube oil system. The reactor coolant pumps are provided with wet- pipe sprinkler systems. Reactor coolant pump oil collection system has also been provided to prevent a fire from defeating the safety system functions. Fire Hazards Analyses are presented in Appendix 9.5A and Appendix 9.5C. (b) Bulk gas storage (either compressed or cryogenic), should not be permitted inside structures housing safety-related equipment. Storage of flammable gas such as hydrogen, should be located outdoors or in separate detached buildings so that a fire or explosion will not adversely affect any safety-related systems or equipment. (Refer to NFPA 50A, "Gaseous Hydrogen Systems.") Care should be taken to locate high pressure gas storage containers with the long axis parallel to building walls. This will minimize the possibility of Bulk gas storage is not permitted inside structures housing safety-related equipment. A separate chemical and gaseous storage vault is provided for storage of hydrogen and nitrogen. The bulk CO2 storage tank is separated from any safety-related equipment in the turbine building. Bulk hydrogen and nitrogen storage tanks are located outside the turbine building, on the east side. Hydrogen and nitrogen bottles stored in the chemical and gaseous storage area in the laboratory or machine shop are oriented DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 D. GENERAL GUIDELINES FOR PLANT PROTECTION Guideline Statement DCPP Compliance to Commitment 9.5B-16 Revision 15 September 2003 wall penetration in the event of the container failure. Use of compressed gases (especially flammable and fuel gases) inside buildings should be controlled. (Refer to NFPA 6, "Industrial Fire Loss Prevention.") perpendicular to the fuel handling building. An analysis was performed to determine the consequences to safety-related equipment in the unlikely event of container failure. The analysis showed that no unacceptable damage would result from the missile hazard of a failed gas container. Therefore, the intent of this guideline is met. (c) The use of plastic materials should be minimized. In particular, halogenated plastics such as polyvinyl chloride (PVC) and neoprene should be used only when substitute noncombustible materials are not available. All plastic materials, including flame and fire retardant materials, will burn with an intensity and Btu production in a range similar to that of ordinary hydrocarbons. When burning they produce heavy smoke that obscures visibility and can plug air filters, especially charcoal and HEPA. The halogenated plastics also release free chlorine and hydrogen chloride when burning which are toxic to humans and corrosive to equipment. The use of plastics has been minimized. Within equipment, boards, panels, and devices, insulation is either fluorinated ethylene-propylene, cross-linked polyethylene, polyvinyl chloride (PVC) with an asbestos jacket (NEC Type TA), or PVC alone. The use of PVC has been kept to a minimum, and is used only where a manufacturer has standardized his production with this material. (d) Storage of flammable liquids should, as a minimum, comply with the requirements of NFPA 30, "Flammable and Combustible Liquids Code." Storage of flammable liquids meets the intent of NFPA 30, "Flammable and Combustible Liquids Code." 3. Electric Cable Construction, Cable Trays, and Cable Penetrations (a) Only noncombustible materials should be used for cable spreading rooms. Fire protection guidelines are incorporated into the design of the cable spreading rooms. Safety-related cables are routed in steel conduits. (b) See Section F.3 for fire protection guidelines for cable spreading rooms. Fire protection guidelines are incorporated into the design of the cable spreading rooms. Safety-related cables are routed in steel conduits. (c) Automatic water sprinkler systems should be provided for cable trays outside the cable spreading room. Cables should be designed to allow wetting down with deluge water without electrical faulting. Manual hose stations and portable hand extinguishers should be provided as backup. Safety-related equipment in the vicinity of such cable trays, that does not itself require water fire protection, but is subject to unacceptable damage from sprinkler water discharge, should be protected from sprinkler system operation or malfunction. When safety-related cables do not satisfy the provisions of RG 1.75, all exposed cables should be covered with an approved fire retardant coating Cable trays outside the cable spreading room are provided with automatic sprinkler systems or fire-resistive enclosures, or a separation analysis per 10 CFR 50 Appendix R has been performed and accepted by the NRC. The adequacy of cable tray protection is evaluated in Appendix 9.5A, Fire Hazards Analysis. Cables are designed to be wetted down without electrical faulting. Manual hose stations and hand extinguishers are provided as backup fire suppression. Operation or malfunction of sprinkler systems will not adversely impact safety-related equipment. Redundant field-run safety-related cables are routed in separate conduit DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 D. GENERAL GUIDELINES FOR PLANT PROTECTION Guideline Statement DCPP Compliance to Commitment 9.5B-17 Revision 15 September 2003 and automatic fire suppression system should be provided. and insulation and jacket material is fire retardant. Automatic fire suppression systems have been installed at DCPP. (d) Cable and cable tray penetration of fire barriers (vertical and horizontal) should be sealed to give protection at least equivalent to that fire barrier. The design of fire barriers for horizontal and vertical cable trays should, as a minimum, meet the requirements of ASTM E-119, "Fire Test of Building Construction and Materials," including the hose stream test. Cable tray penetrations are sealed to an equivalent fire resistance rating of the fire barrier itself. Fireproofing materials have met the requirements of ASTM E-119 tests. (e) Fire breaks should be provided as deemed necessary by the fire hazards analysis. Flame or flame retardant coatings may be used as a fire break for grouted electrical cables to limit spread of fire in cable ventings. (Possible cable derating owing to use of such coating materials must be considered during design.) Cable tray fire stops made of Dow Corning Q3-6548 silicone foam are installed at intervals of 4 feet on vertical trays and 10 feet on horizontal cable trays, and with 5 feet of cable tray crossings, either above or below the crossing. (Ref: Dwg 050029 DCP A-47854, DCP M-049476, FHAREs 101, 143) PG&E's Engineering Research staff conducted fire tests in 1975, which proved the cable tray fire stops prevented the spread of fire to the other side of the fire stop for both the horizontal and vertical trays. (f) Electric cable construction should as a minimum pass the current IEEE No. 383 flame test. (This does not imply that cables passing this test will not require additional fire protection.) For cable installation in operating plants and plants under construction that do not meet the IEEE 383 flame test requirements, all cables must be covered with an approved flame retardant coating and properly derated. Electrical cables at DCPP meet the intent of IEEE 383-1974 flame test requirements as stated in the referenced report. The following categories of cables installed in the power block after June 1, 1991 are exempt from the IEEE 383-1974 flame test requirements (
Reference:
ABB Impell Corporation Document No. 0170-219-001, Revision 2, PG&E Electrical Cable Acceptability Analysis): (1) Cables tested to the flame test requirements in UL 910, UL 1666 or UL 1581 (Vertical Tray Flame Test). The flame tests in these UL Standards meet or exceed the requirements of IEEE 383-1974 flame test using the ribbion gas burner. (2) Cables installed in non combustible totally closed enclosures such as conduits, terminal boxes, panels, cabinets etc. (g) To the extent practical, cable construction that does not give off corrosive gases while burning should be used. (Applicable to new cable installations.) Some PVC insulated cables are used in the plant. However, the small amount of PVC present does not produce significant hazards. To the extent practical, all new cable installations will utilize cables that do not give off corrosive gases when burned. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 D. GENERAL GUIDELINES FOR PLANT PROTECTION Guideline Statement DCPP Compliance to Commitment 9.5B-18 Revision 15 September 2003 (h) Cable trays, raceways, conduit, trenches, or culverts should be used only for cables. Miscellaneous storage should not be permitted nor should piping for flammable or combustible liquids or gases be installed in these areas. Installed equipment in cable tunnel or culverts need not be removed if they present no hazard to the cable runs as determined by the fire hazard analysis. Cable trays, raceways, and conduit are used exclusively for cables. Administrative controls exist to prevent storage in cable trays and raceways. (i) The design of cable tunnels, culverts, and spreading rooms should provide for automatic or manual smoke venting as required to facilitate manual fire fighting capability. Smoke venting capability is provided and is discussed in the referenced emergency procedures. (j) Cables in the control room should be kept to the minimum necessary for operation of the control room. All cables entering the control room should not be installed in floor trenches or culverts in the control room. Existing cabling installed in concealed floor and ceiling spaces should be protected by an automatic total flooding Halon system. All power and control cables entering the control room terminate there, and are considered necessary for control room operation. The cabling terminates at terminal blocks inside the control panels. No floor trenches or culverts exist in the control room. 4. Ventilation (a) The products of combustion that need to be removed from a specific fire area should be evaluated to determine how they can be controlled. Smoke and corrosive gases should generally be automatically discharged directly outside to a safe location. Smoke and gases containing radioactive materials should be monitored in the fire area to determine if release to the environment is within the permissible limits of the plant Technical Specifications (TS). The products of combustion which need to be removed from a specific fire area should be evaluated to determine how they will be controlled. The DCPP ventilation systems either supply fresh outside air to rooms or exhaust air from rooms into a closed duct system (or both for some rooms). The ventilation exhaust systems have been evaluated to determine the capability for removing smoke and products of combustion in the event of a fire. Ventilation exhaust capabilities, either manual or automatic, exist in all plant areas. Ventilation for manual fire fighting in areas with normal ventilation flow cutoff can be accomplished with portable blower-exhaust fans and by opening doors. These fans exhaust to the outside or to nearby operating ventilation exhaust ducts. If the normal ventilation system is used for heat and smoke venting, the heat and smoke would be discharged outside, not to other rooms. The ventilation system has been conservatively designed to provide adequate cooling for all equipment under all operating modes. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 D. GENERAL GUIDELINES FOR PLANT PROTECTION Guideline Statement DCPP Compliance to Commitment 9.5B-19 Revision 15 September 2003 Ventilation system discharges from areas containing radioactive materials are continuously monitored to determine whether releases are within the TS limits. (b) Any ventilation system designed to exhaust smoke or corrosive gases should be evaluated to ensure that inadvertent operation or single failures will not violate the controlled areas of the plant design. This requirement includes containment functions for protection of the public and maintaining habitability for operations personnel. Ventilation systems either supply fresh outside air to rooms or discharge air from rooms into a closed duct system (or both for some rooms). Single failures will not violate controlled areas or affect personnel habitability. Safety-related ventilation exhaust systems employ redundant components and subsystems where necessary to ensure reliable system operation. Inadvertent operation will not violate the controlled areas of the plant design. (c) The power supply and controls for mechanical ventilation systems should be run outside the fire area served by the system. Power supplies and controls for mechanical ventilation systems are run outside the fire area or zone served, to the extent practical. However, there are certain fire areas or zones in which redundant ventilation system components or circuitry could be affected by an unmitigated fire. (d) Fire suppression systems should be installed to protect charcoal filters in accordance with RG 1.52, "Design Testing and Maintenance Criteria for Atmospheric Cleanup Air Filtration." Charcoal filters are generally installed to meet the intent of RG 1.52. However, water spray systems have not been provided, since the maximum postulated radioactivity on the charcoal filters is below that required for auto-ignition of the filter. The degree of compliance with RG 1.52 is summarized in Table 9.4-2 of this FSAR Update. (e) The fresh air supply intakes to areas containing safety-related equipment or systems should be located remote from the exhaust air outlets and smoke vents of other fire areas to minimize the possibility of contaminating the intake air with the products of combustion. Fresh air intakes to areas containing safety-related equipment are located remote from exhaust air outlets to the extent practicable. The possibility of contaminating the intake air with products of combustion is extremely unlikely. The approximate distances between air supply intakes and the nearest exhaust air outlets for buildings and areas housing safety-related equipment are listed below: Intake-Exhaust Building or Area Approximate Distance Control room 50 feet Containment 150 feet Auxiliary building (including fuel handling area) 200 feet DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 D. GENERAL GUIDELINES FOR PLANT PROTECTION Guideline Statement DCPP Compliance to Commitment 9.5B-20 Revision 15 September 2003 Intake-Exhaust Building or Area Approximate Distance Diesel generator area 40 feet 4.16kV switchgear room 80 feet Turbine building (general) 150 feet Battery room area 25 feet (f) Stairwells should be designed to minimize smoke infiltration during a fire. Staircases should serve as escape routes and access routes for fire fighting. Fire exit routes should be clearly marked. Stairwells, elevators, and chutes should be enclosed in masonry towers with minimum fire rating of three-hours and automatic fire doors at least equal to the enclosure construction, each opening into the building. Elevators should not be used during fire emergencies. Stairwells are designed to minimize smoke infiltration. They are located to provide escape and access routes for fire fighting and are enclosed by two-hour fire walls with either "A" or B" labeled, normally closed fire doors. All exits are clearly marked. The ratings of various stairwells elevators, and chutes were analyzed and upgraded where necessary to meet the requirements of 10 CFR 50 Appendix R and as accepted by the NRC. Stairwell S-1 contains a nonrated access hatch to the ventilation shaft. Where stairwells or elevators cannot be enclosed in three-hour fire rated barrier with equivalent fire doors, escape and access routes should be established by pre-fire plan and practiced in drills by operating and fire brigade personnel. Pre-fire plans are established and in place. (g) Smoke and heat vents may be useful in specific areas such as cable spreading rooms and diesel fuel oil storage areas and Switchgear rooms. When natural-convection ventilation is used, a minimum ratio of 1 square foot of venting area per 200 square feet of floor area should be provided. If forced-convection ventilation is used, 300 CFI should be provided for every 200 square feet of floor area. See NFPA 204 for additional guidance on smoke control. The diesel fuel oil storage tanks are buried and do not require ventilation. PG&E uses forced ventilation to serve the cable spreading and switchgear rooms; however, fire dampers are used to assist fire extinguishment and reduce smoke propagation. Smoke removal plans subsequent to a fire are discussed in fire brigade training and fire fighting procedures. (h) Self-contained breathing apparatus, using full face positive pressure masks, approved by NIOSH (National Institute for Occupational Safety and Health - approval formerly given by the U.S. Bureau of Mines) should be provided for fire brigade, damage control, and control room personnel. Control room personnel may be furnished breathing air by a manifold system piped from a storage reservoir if practical. Service or operating life should be a minimum of one-half hour for the self-contained units. Self-contained breathing apparatus (SCBAs) are provided for fire brigade and control room personnel use at DCPP. Administrative controls exist to ensure their availability. At least two extra bottles are located onsite for those SCBAs that would be utilized by the Shift Fire Brigade and minimum control room compliment of operators. An onsite recharging system exists to permit quick and complete replenishment of exhausted supply air bottles. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 D. GENERAL GUIDELINES FOR PLANT PROTECTION Guideline Statement DCPP Compliance to Commitment 9.5B-21 Revision 15 September 2003 At least two extra air bottles should be located onsite for each self-contained breathing unit. In addition, an onsite six-hour supply of reserve air should be provided and arranged to permit quick and complete replenishment of exhaust supply air bottles as they are returned. If compressors are used as a source of breathing air, only units provided for breathing air should be used. Special care must be taken to locate the compressor in areas free of dust and contaminants. (i) Where total flooding gas extinguishing systems are used, area intake and exhaust ventilation dampers should close upon initiation of gas flow to maintain necessary gas concentration. (See NFPA 12, "Carbon Dioxide Systems," and 12A, "Halon 1303 Systems.") DCPP uses ventilation dampers to maintain the necessary gas concentration once the system has been actuated in a room protected by CO2 or Halon. 5. Lighting and Communication Lighting and two-way voice communication are vital to safe shutdown and emergency response in the event of fire. Suitable fixed and portable emergency lighting and communication devices should be provided to satisfy the following requirements: (a) Fixed emergency lighting should consist of sealed beam units with individual eight-hour minimum battery power supplies. PG&E installed emergency lighting system provides an acceptable margin of safety equivalent to that provided by the more conservative technical requirements of 10 CFR 50, Appendix R, Section III.J. (See Appendix 9.5D.) (b) Suitable sealed beam battery powered portable hand lights should be provided for emergency use. The need for portable hand lights to satisfy emergency use requirements in the event of a fire has been superseded by the more stringent regulations of 10 CFR 50, Appendix R, Section III.J. (c) Fixed emergency communication should use voice powered sets at preselected stations. Voice-powered communications systems are not used at DCPP. The primary communications system is a direct-dial company telephone network. A secondary communications system is the plant radio system, which includes various base stations, distributed portable units, and mobile units. The radio system is controlled and periodically tested through administrative means. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 D. GENERAL GUIDELINES FOR PLANT PROTECTION Guideline Statement DCPP Compliance to Commitment 9.5B-22 Revision 15 September 2003 (d) Fixed repeaters installed to permit use of portable radio communication units should be protected from exposure fire damage. The control room base station radio control consoles are powered from vital power and are afforded the protection of the control room. The remote shutdown panel for each unit is equipped with a base station radio control point and a plant telephone. Portable radios are available for communications with either the control room or the remote shutdown panel. Effective communications can be maintained while shutdown is occurring, either from the control room or the remote shutdown panel. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 E. FIRE DETECTION AND SUPPRESSION Guideline Statement DCPP Compliance to Commitment 9.5B-23 Revision 15 September 2003 1. Fire Detection System (a) Fire detection systems should as a minimum comply with NFPA 72D, "Standard for the Installation, Maintenance and Use of Proprietary Protection Signaling Systems". Deviations from the requirements of NFPA 72D should be identified and justified. An evaluation of the fire detection systems' compliance with NFPA 72D was performed. For all areas of noncompliance, engineering evaluations were provided to show that the intent of NFPA 72D was met, or modifications were made. A central supervising station is provided in the Control Room from which the control room operators can monitor the fire alarms for the DCPP site. The central supervising station provides an automatic and permanent visual recording of alarms and fire protection equipment initiation. FHARE 116, Testing and Maintenance of Ionization Smoke Detectors evaluates the frequency of performing sensitivity testing. (b) Fire detection system should give audible and visual alarm and annunciation in the control room. Local audible alarms should also sound at the location of the fire. The fire detection system gives audible and visual alarms in the control room. (c) Fire alarms should be distinctive and unique. They should not be capable of being confused with any other plant system alarms. The fire alarms outside the control room at DCPP are distinctive and unique. Site fire alarm characteristics are described in the Emergency Plan. The site fire alarm uses a combination of siren and horn signals. These measures ensure that alarms outside the control room are not confused with other plant system alarms. The site fire alarm is manually activated. (d) Fire detection and actuation systems should be connected to the plant emergency power supply. Fire detection and actuation systems are connected to the plant emergency power supply. 2. Fire Protection Water Supply Systems (a) An underground yard fire main loop should be installed to furnish anticipated fire water requirements. NFPA 24 - Standard for Outside Protection - gives necessary guidance for such installation. It references other design codes and standards developed by such organization as the American National Standards Institute (ANSI) and the American Water Works Association (AWWA). Lined steel or cast iron pipe should be used to reduce internal tuberculation. Such tuberculation deposits in a unlined pipe over a period of years can significantly reduce water flow through the A 12 inch underground yard fire main loop is installed to furnish anticipated firewater requirements. The water supply system is installed commensurate with the guidance of NFPA 24. Yard main piping was constructed using epoxy-lined asbestos cement. Repair and maintenance activities are performed in accordance with applicable NFPA guidelines. Means are available and procedures exist for treating and flushing portions of the fire main. The plant yard loop is sectionalized, and each plant feed line can be isolated without interrupting fire water DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 E. FIRE DETECTION AND SUPPRESSION Guideline Statement DCPP Compliance to Commitment 9.5B-24 Revision 15 September 2003 combination of increased friction and reduced pipe diameter. Means for treating and flushing the systems should be provided. Approved visually indicating sectional control valves, such as post indicator valves, should be provided to isolate portions of the main for maintenance or repair without shutting off the entire system. Visible location marking signs for underground valves is acceptable. Alternative valve position indicators should also be provided. For operating plants, fire main system piping that can be isolated from service or sanitary water system piping is acceptable. supply to the remainder of the plant. The fire main system piping is separate from service and sanitary water system piping. (b) A common yard fire main loop may serve multiunit nuclear power plant sites, if crossconnected between units. Sectional control valves should permit maintaining independence of the individual loop around each unit. For such installation, common water supplies may also be utilized. The water supply should be sized for the largest single expected flow. For multiple reactor sites with widely separate plants (approaching 1 mile or more), separate yard fire main loops should be used. Sectionalized systems are acceptable. A common yard fire main loop serves both Units 1 and 2, since the two units are in close proximity. The system uses sectional valves, which permit a common water supply to serve both units. A south site loop supplies water to the nonnuclear south site facilities. It may be cross-tied by opening valves FP-1214 and FU-4 to supplement the yard fire main loop. (c) If pumps are required to meet system pressure or flow requirements, a sufficient number of pumps should be provided so that 100 % capacity will be available with one pump inactive (e.g., three 50 % pumps or two 100 % pumps). The connection to the yard fire main loop from each fire pump should be widely separated, preferably located on opposite sides of the plant. Each pump should have its own driver with independent power supplies and control. At least one pump (if not powered from the emergency diesels) should be driven by nonelectrical means, preferably diesel engine. Pumps and drivers should be located in rooms separated from the remaining pumps and equipment by a minimum three-hour fire wall. Alarms indicating pump running, driver availability, or failure to start should be provided in the control room. Details of the fire pump installation should as a minimum conform to NFPA 20, "Standard for the Installation of Centrifugal Fire Pumps". The primary water supply for this system is a 5.0 million gallon reservoir, divided in two isolable compartments. This reservoir supplies and pressurizes the fire water system, and meets system pressure and flow requirements. As backup to the reservoir, two 1500 gpm fire pumps provide water from a 300,000 gallon fire water storage tank. These pumps would not normally be required to supply the fire main system. The pumps are powered from redundant 480 volt vital circuits and start automatically (in sequence) on low fire system pressure. Alarms indicating pump running and failure to start are provided in the control room. Fire pump installation meets the intent of NFPA 20. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 E. FIRE DETECTION AND SUPPRESSION Guideline Statement DCPP Compliance to Commitment 9.5B-25 Revision 15 September 2003 (d) Two separate reliable water supplies should be provided. If tanks are used, two 100 % (minimum of 300,000 gallons each) systems should be so interconnected that pumps can take suction from either or both. However, a leak in one tank or its piping should not cause both tanks to drain. The main plant fire water supply capacity should be capable of refilling either tank in a minimum of eight hours. Common tanks are permitted to fire and sanitary or service water storage. When this is done, however, minimum fire water storage requirements should be dedicated by means of a vertical standpipe for other water services. The fire protection water is supplied by two sources: (a) 5.0 million gallon gravity-feed raw water storage reservoir (b) 300,000 gallon water storage tank The power block outside yard loop is fed by the raw water reservoir. The 300,000-gallon seismically qualified fire water tank is located inside the transfer storage tank as a separate container. A flow path is available from the transfer tank, but a check valve prevents reverse flow. Refer to Section 9.5.1.2.1 for additional description. (e) The fire water supply (total capacity and flow rate) should be calculated on the basis of the largest expected flow rate for a period of two hours, but not less than 300,000 gallons. This flow rate should be based (conservatively) on 1,000 gpm for manual hose streams plus the greater of: (1) All sprinkler heads opened and flowing in the largest designed fire area. (2) The largest open head deluge system(s) operating. A fire water supply system flow test is performed once every three years to verify the ability of system piping to deliver the design flow rate of the largest required water suppression system identified in the PG&E Equipment Control Guidelines (see Chapter 16 of this FSAR Update) plus 500 gpm for hose. (f) Lakes or fresh water ponds of sufficient size may qualify as sole source of water for fire protection, but require at least two intakes to the pump supply. When a common water supply is permitted for fire protection and the ultimate heat sink, the following conditions should also be satisfied: (1) The additional fire protection water requirements are designed into the total storage capacity. (2) Failure of the fire protection system should not degrade the function of the ultimate heat sink. DCPP uses a common water supply of 5.0 million gallons for fire protection and plant make-up water. A separate 300,000 gallon tank may be used to service the fire protection system if necessary. The ultimate heat sink for DCPP is the ocean. (g) Outside manual hose installation should be sufficient to reach any location with an effective hose stream. To accomplish this, hydrants should be A fire hose system is provided that allows all outside areas to be reached by at least two hose streams. Each hose cabinet is equipped with DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 E. FIRE DETECTION AND SUPPRESSION Guideline Statement DCPP Compliance to Commitment 9.5B-26 Revision 15 September 2003 installed approximately every 250 feet on the yard main system. The lateral to each hydrant from the yard main should be controlled by a visually indicating or key operated (curb) valve. A hose house, equipped with hose and combination nozzle, and other auxiliary equipment recommended in NFPA 24, "Outside Protection," should be provided as needed but at least every 1,000 feet. Threads compatible with those used by local fire departments should be provided on all hydrants, hose couplings, and standpipe risers. 100 feet of 1-1/2 inch hose, a combination nozzle and spanner wrench. Threads are compatible with those used by local fire departments. The system meets the intent of NFPA 24. 3. Water Sprinklers and Hose Standpipe Systems (a) Each automatic sprinkler system and manual hose station standpipe should have an independent connection to the plant underground water main. Headers fed from each are permitted inside buildings to supply multiple sprinkler and standpipe systems. When provided, such headers are considered an extension of the yard main system. The header arrangement should be such that no single failure can impair both the primary and backup fire protection systems. Each sprinkler and standpipe system should be equipped with OS&Y (outside screw and yoke) gate valve, or other approved shutoff valve, and water flow alarm. Safety-related equipment that does not itself require sprinkler water fire protection, but is subject to unacceptable damage if wetted by sprinkler water discharge should be protected by water shields or baffles. The automatic sprinkler system and manual hose stations are supplied by a sectionalized underground fire main loop arranged such that no single failure could impair the entire fire protection system. See Section 9.5.1.2 for further details. Each sprinkler system and manual hose station standpipe is provided with an independent connection to the yard main. The turbine building contains an internal loop that acts as an extension of the yard main system. Each sprinkler system is equipped with an OS&Y gate valve or an approved shutoff valve, in addition to a flow alarm to alert the control room in the event of system actuation. Each standpipe system is not provided with a separate OS&Y; however, the sectionalizing valves ensure that single failure will not adversely impact the rest of the fire protection system. The Moderate Energy Line Break Program ensures that safety-related equipment susceptible to water damage is protected by water shields or baffles. (b) All valves in the fire water systems should be electrically supervised. The electrical supervision signal should indicate in the control room and other appropriate command locations in the plant. (See NFPA 26, "Supervision of Valves.") When electrical supervision of fire protection valves is not practical, an adequate management supervision program should be The sectionalizing fire loop main valves are electrically supervised at DCPP. An administrative program of locking, sealing, and inspecting valves is in place for those fire water supply valves that are impractical to supervise electrically. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 E. FIRE DETECTION AND SUPPRESSION Guideline Statement DCPP Compliance to Commitment 9.5B-27 Revision 15 September 2003 provided. Such a program should include locating valves open with strict key control; tamper proof seals; and periodic, visual check of all valves. (c) Automatic sprinkler systems should as a minimum conform to requirements of appropriate standards such a NFPA 13, "Standard for the Installation of Sprinkler Systems," and NFPA 15, "Standard for Water Spray Fixed Systems." DCPP automatic sprinkler systems are used in various areas of the plant and are installed commensurate with the requirements of NFPA 13. (d) Interior manual hose installation should be able to reach any location with at least one effective hose stream. To accomplish this, standpipes with hose connections equipped with a maximum of 75 feet of 1-1/2 inch woven jacket-lined fire hose and suitable nozzles should be provided in all buildings, including containment, on all floors and should be spaced at not more than 100 foot intervals. Individual standpipes should be at least 4 inch diameter for multiple hose connections and 2-1/2 inch diameter for single hose connections. These systems should follow the requirements of NFPA No. 14 for sizing, spacing, and pipe support requirements (NELPIA). Hose stations should be located outside entrances to normally unoccupied areas and inside normally occupied areas. Standpipes serving hose stations in areas housing safety-related equipment should have shutoff valves and pressure reducing devices (if applicable) outside the area. Hose stations are provided throughout DCPP at approximately 100 foot intervals and provided with 75 or 100 foot maximum hose length so that all locations within the plant can be reached with at least one effective hose stream. Fire hose standpipes are minimum 4 inch diameter for multiple hose connections and 2 inch for single hose connections. The standpipe systems were installed commensurate with the guidelines of NFPA 14. Access and occupancy requirements were considered in specifying hose reel locations. (e) The proper type of hose nozzles to be supplied to each area should be based on the fire hazard analysis. The usual combination spray/straight-stream nozzle may cause unacceptable mechanical damage (for example, the delicate electronic equipment in the control room) and be unsuitable. Electrically safe nozzles should be provided at locations where electrical equipment or cabling is located. Combination spray/straight stream nozzles are installed inside the buildings. Fire fighting procedures specify what equipment should be used to fight the various types of fires depending upon their location. Surveillance procedures assure on a periodic basis that this equipment is available for use. Fire brigade members are trained to use the appropriate equipment for the fire. (f) Certain fires such as those involving flammable liquids respond well to foam suppression. Consideration should be given to use of any of the available foams for such specialized protection application. These include the more common chemical and mechanical low expansion foams, high expansion foam and the relatively new aqueous film forming foam (AFFF). PG&E's fire protection staff evaluated the appropriate suppression systems to be used for the fire hazard. No foam suppression systems exist at DCPP. Total flooding CO2 systems or water spray systems are used where flammable liquid is considered a fire hazard. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 E. FIRE DETECTION AND SUPPRESSION Guideline Statement DCPP Compliance to Commitment 9.5B-28 Revision 15 September 2003 4. Halon Suppression Systems The use of Halon fire extinguishing agents should as a minimum comply with the requirements of NFPA 12A and 12B, "Halogenated Fire Extinguishing Agent Systems - Halon 1301 and Halon 1211." Only UL or FM approved agents should be used. In addition to the guidelines of NFPA 12A and 12B, preventative maintenance and testing of the systems, including check weighing of the Halon cylinders should be done at least quarterly. Particular consideration should also be given to: (a) Minimum required Halon concentration and soak time.
(b) Toxicity of Halon. (c) Toxicity and corrosive characteristics of thermal decomposition products of Halon. Halon suppression systems are not utilized at Diablo Canyon. 5. Carbon Dioxide Suppression Systems The use of carbon dioxide extinguishing systems should as a minimum comply with the requirements of NFPA 12, "Carbon Dioxide Extinguishing Systems." Particular consideration should also be given to: (a) Minimum required CO2 concentration and soak time. (b) Toxicity of CO2. (c) Possibility of secondary thermal shock (cooling) damage. (d) Offsetting requirements for venting during CO2 injection to prevent overpressurization versus sealing to prevent loss of agent. (e) Design requirements from overpressurization; and Carbon dioxide extinguishing systems at DCPP were installed commensurate with the guidelines of NFPA 12. The systems are periodically tested by surveillance procedures. Consideration has been given to the following design requirements: (a) The design concentrations of the low-pressure total flooding systems are: - Diesel generator = 35% - Lube oil reservoir room = 34% - Cable spreading room = 50% The high-pressure total flooding system provided for the circulation water pump has an extended discharge capability of 20 minutes at reduced flow rate.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 E. FIRE DETECTION AND SUPPRESSION Guideline Statement DCPP Compliance to Commitment 9.5B-29 Revision 15 September 2003 (f) Possibility and probability of CO2 systems being out-of-service because of personnel safety considerations. CO2 systems are disarmed whenever people are present in an area so protected. Areas entered frequently (even though duration time for any visit is short) have often been found with CO2 systems shut off. (b) Thirty-second time delay, before system actuation, is provided for evacuation of personnel. (c) Discharge nozzles are located away from equipment to minimize thermal shock damage. (d) Offsetting requirements for venting during CO2 injection are provided to prevent overpressurization. (e) Pressure plugs are provided in the CO2 piping to delay closure of discharge dampers and thus prevent overpressurization. (f) Each CO2 total flooding system is equipped with a total mechanical system disable. The disable is supplied for personnel safety during maintenance in the area. 6. Portable Extinguishers Fire extinguishers should be provided in accordance with guidelines of NFPA 10 and 10A, "Portable Fire Extinguishers, Installation, Maintenance and Use." Dry chemical extinguishers should be installed with due consideration given to cleanup problems after use and possible adverse effects on equipment installed in the area. Fire extinguishers are provided throughout DCPP commensurate with the requirements of NFPA 10 and 10A, and are inspected monthly. Maintenance on the fire extinguishers is performed on an annual basis. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 F. GUIDELINES FOR SPECIFIC PLANT AREAS Guideline Statement DCPP Compliance to Commitment 9.5B-30 Revision 15 September 2003 1. Primary and Secondary Containment (a) Normal Operation Fire protection requirements for the primary and secondary containment areas should be provided on the basis of specific identified hazards. For example: (1) Lubricating oil or hydraulic fluid systems for the primary coolant pumps (2) Cable tray arrangements and cable penetrations (3) Charcoal filters Fire suppression systems should be provided based on the fire hazards analysis. Fixed fire suppression capability should be provided for hazards that could jeopardize safe plant shutdown. Automatic sprinklers are preferred. An acceptable alternate is automatic gas (Halon or CO2) for hazards identified as requiring fixed suppression protection. An enclosure may be required to confine the agent if a gas system is used. Such enclosures should not adversely affect safe shutdown or other operating equipment in containment. Fire detection systems should alarm and annunciate in the control room. The type of detection used and the location of the detectors should be most suitable to the particular type of fire that could be expected from the identified hazard. A primary containment general area fire detection capability should be provided as backup for the above described hazard detection. To accomplish this, suitable smoke detection (e.g., visual observation, light scattering, and particle counting) should be installed in the air recirculating system ahead of any filters. Automatic fire suppression capability need not be provided in the primary containment atmospheres that are inerted during normal operation. However, Fire detection and suppression systems in containment are provided on the basis of specific identified hazards. Appendix 9.5C provides a description of fire protection features for the RCPs and evaluates its compliance with the requirements of 10 CFR 50, Appendix R, Section III.O. (See Appendix 9.5C.) An automatic wet pipe waterspray system is provided for each reactor coolant pump. Operation of the water spray system does not compromise integrity of the containment or other safety-related systems. Hose reel stations are provided in the containment cable penetration zone, and portable extinguishers are distributed outside the containment. Cable tray arrangements and cable penetrations are protected. Ionization smoke detectors are provided in the penetration areas. DCPP meets 10 CFR 50, Appendix R, Section III.G. separation criteria as demonstrated in the Fire Hazards Analysis (Appendix 9.5A). Fire protection provided for the charcoal filters is discussed in Section D.4(d) of this table. Fire detection capability is provided for the containment. Smoke detectors are provided for the reactor coolant pumps, and detectors are provided in the containment electrical penetration area. Additional detection capability is provided by flame detectors above the operating deck. The flame detectors are designed to detect a fire resulting from transient combustibles that could be introduced during refueling and maintenance outages. A flow alarm on the containment fire water line gives control room indication of RCP sprinkler system actuation. Fire detection systems annunciate in the control room. When maintenance or repair on the single fire protection line to the containment is being done, backup fire hoses can be brought into containment. In addition, portable fire extinguishing equipment is DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 F. GUIDELINES FOR SPECIFIC PLANT AREAS Guideline Statement DCPP Compliance to Commitment 9.5B-31 Revision 15 September 2003 special fire protection requirements during refueling and maintenance operations should be satisfied as provided below. Operation of the fire protection systems should not compromise integrity of the containment or the other safety-related systems. Fire protection activities in the containment areas should function in conjunction with total containment requirements such as control of contaminated liquid and gaseous release and ventilation. available. (b) Refueling and Maintenance Refueling and maintenance operations in containment may introduce additional hazards such as contamination control materials, decontamination supplies, wood planking, temporary wiring, welding, and flame cutting (with portable compressed fuel gas supply). Possible fires would not necessarily be in the vicinity of fixed detection and suppression systems. Management procedures and controls necessary to assure adequate fire protection are discussed in Section F.3(a) of this table. In addition, manual fire fighting capability should be permanently installed in containment. Standpipes with hose stations and portable fire extinguishers should be installed at strategic locations throughout containment for any required manual fire fighting operations. Equivalent protection from portable systems should be provided if it is impractical to install standpipes with hose stations. Adequate self-contained breathing apparatus should be provided near the containment entrances for fire fighting and damage control personnel. These units should be independent of any breathing apparatus or air supply systems provided for general plant activities. The use of combustible materials inside the containment during refueling and maintenance operations is discussed in Sections B.2 and B.3 of this table. In addition to administrative controls, portable fire extinguishers are installed at strategic locations throughout the containment. Standpipes with hose stations are provided as discussed in Appendix 9.5A. Self-contained breathing apparatus are provided near the control room and are available for use by fire fighting and damage control personnel as described in Section D.4(h) of this table. These units are intended for use in emergency situations. The control room is located in proximity to the containment access area. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 F. GUIDELINES FOR SPECIFIC PLANT AREAS Guideline Statement DCPP Compliance to Commitment 9.5B-32 Revision 15 September 2003 2. Control Room The control room is essential to the safe reactor operation. It must be protected against disabling fire damage and should be separated from other areas of the plant by floors, walls, and roofs having minimum fire resistance ratings of three hours. Control room cabinets and consoles are subject to damage from two distinct fire hazards: (a) Fire originating within a cabinet or console. (b) Exposure fire involving combustibles in the general room area. Manual fire fighting capability should be provided for both hazards. Hose stations and portable water and Halon extinguishers should be located in the control room to eliminate the need for operators to leave the control room. An additional hose piping shutoff valve and pressure reducing device should be installed outside the control room. Hose stations adjacent to the control room with portable extinguishers in the control room are acceptable. Nozzles that are compatible with the hazards and equipment in the control room should be provided for the manual hose station. The nozzles chosen should satisfy actual fire fighting needs, satisfy electrical safety and minimize physical damage to electrical equipment from hose stream impingement. Fire detection in the control room cabinets and consoles should be provided by smoke and heat detectors in each fire area. Alarm and annunciation should be provided in the control room. Fire alarms in other parts of the plant should also be alarmed and annunciated in the control room. Breathing apparatus for control room operators should be readily available. Control room floors, ceiling, supporting structures, and walls, including penetrations and doors, should be designed to a minimum fire rating of three hours. All penetration seals should be airtight. The control room ventilation intake should be provided with smoke detection capability to automatically alarm locally and isolate the control room ventilation The control room is constructed of noncombustible or fire-resistive materials with the exeption of the control consoles and room desk, which are constructed of fire retardant wood, and the floor, which is carpeted. The control room complex is separated from the rest of the plant by minimum three-hour fire barriers (with the exception of certain ventilation penetrations through the walls and special bulletproof, pressure- tight doors that are not labeled as fire rated). (See Appendix 9.5A) Extinguishers are located within the control room, and hose stations are located in adjacent rooms. Fog nozzles are used, designed to satisfy electrical safety requirements and minimize damage from hose stream impingement. Smoke detectors are provided in the control room cabinets and consoles containing redundant safe shutdown cabling. FHARE 93 evaluates acceptability of not installing smoke detectors in safety-related HVAC cabinets, POV1 and POV2 and nonsafety-related digital feedwater cabinets RODFW1 and RODFW2 for Units 1 and 2. Additionally, the control room is continuously occupied, and operators would normally detect fires, visually or by smell, before extensive damage occurred. Breathing apparatus for operators is readily available in the control room complex. The control room ventilation intake and exhaust are provided with smoke detectors that alarm in the control room. The control room ventilation system is not automatically isolated. However, the operator can isolate the system manually. He also has the option of operating the system on a once-through (no recirculation) basis, using all outside air. This mode would remove any smoke from the control room. Power and control cables entering the control room terminate there and are considered essential for control room operation. Cabling is not located in concealed floor and ceiling spaces. Drains are not provided, but safety-related equipment is mounted high enough above floor level that flooding is not feasible. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 F. GUIDELINES FOR SPECIFIC PLANT AREAS Guideline Statement DCPP Compliance to Commitment 9.5B-33 Revision 15 September 2003 system to protect operators by preventing smoke from entering the control room. Manually operated venting of the control room should be available so that operators have the option of venting for visibility. Manually operated ventilation systems are acceptable. Cables should not be located in concealed floor and ceiling spaces. All cables that enter the control room should terminate in the control room. That is, no cabling should be simply routed through the control room from one area to another. If such concealed spaces are used, however, they should have fixed automatic total flooding Halon protection. 3. Cable Spreading Room (a) The preferred acceptable (fire suppression) methods are: (1) Automatic water system such as closed head sprinklers, open head deluge, or open directional spray nozzles. Deluge and open spray systems should have provisions for manual operation at a remote station; however, there should also be provisions to preclude inadvertent operation. Location of sprinkler heads or spray nozzles should consider cable tray sizing and arrangements to assure wetting down with deluge water without electrical faulting. Open head deluge and open directional spray systems should be zoned so that a single failure will not deprive the entire area of automatic fire suppression capability. The use of foam is acceptable, provided it is of a type capable of being delivered by a sprinkler or deluge system, such as Aqueous Film Forming Foam (AFFF). (2) Manual hoses and portable extinguishers should be provided as backup. (3) Each cable spreading room of each unit should have divisional cable separation, and be separated from the other and the rest of the plant by a minimum three-hour rated fire wall. (Refer to NFPA 251 to ASTM E-119 for fire test resistance rating.) The cable spreading function is fulfilled by three rooms: (1) The 4.16kV cable spreading rooms are located in the turbine building (see Appendix 9.5A). They supply power for safety-related functions. This power is distributed in three isolated trains, separated from each other by two-hour fire barriers. Each compartment is constructed with two entrances at opposite ends. The 4.16kV switchgear and cable spreading areas are separated from the remainder of the turbine building by minimum two-hour rated fire barriers and from the outdoor transformers by two-hour fire barriers. The floor and ceiling slabs are two feet thick, and all electrical penetrations are sealed for a fire rating commensurate with the barrier rating. Fire-stopped cable trays are used in each compartment but are not stacked. All cables leaving this area are routed in steel conduit, and the redundant electrical divisions are separated by minimum two-hour barriers in the area adjacent to the 4.16kV cable spreading rooms. Fire suppression in this area is provided by manual CO2 hose stations, manual water hose stations, and portable extinguishers. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 F. GUIDELINES FOR SPECIFIC PLANT AREAS Guideline Statement DCPP Compliance to Commitment 9.5B-34 Revision 15 September 2003 (4) At least two remote and separate entrances are provided to the room for access by fire brigade personnel. (5) Aisle separation provided between tray stacks should be at least three feet wide and eight feet high. Detection is provided by ionization smoke detectors that alarm locally and in the control room. (2) The nonvital cable spreading room is located below the 12kV switchgear room (see Appendix 9.5A). It supplies power for nonsafety-related functions. Fire-stopped cable trays are used throughout. Fire suppression in this area is provided by manual CO2 hose stations, manual water hose stations, and portable extinguishers. Detection is provided by ionization smoke detectors that alarm locally and in the control room. (3) The auxiliary building cable spreading room (see Appendix 9.5A) is located just under the control room. It contains control cables (both safety-related and nonsafety-related) and the reactor protection racks. This room is enclosed on all sides, floor, and ceiling by three-hour rated fire barriers. Two entrances on opposite sides of the room are provided. All safety-related circuits are routed in steel conduits or are in trays located beneath the checker plate floor. All nonsafety-related circuits are routed in fire stopped cable trays. Nowhere do tray stacks exceed three high or two wide. Redundant protection sets are separated to the extent practical. The function of this area is backed up by a remote hot shutdown panel adjacent to the 480 volt switchgear room (see Appendix 9.5A). This panel is wired independent of the cable spreading room. Alternate shutdown capability, completely independent of the control room and cable spreading room, has been provided at DCPP. Fire suppression in this area is provided by a total flooding automatic CO2 system actuated by heat detection. This system may also be actuated manually. Manual water hose reels and portable extinguishers serve as a backup. Ionization smoke detectors are also provided that alarm locally and in the control room. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 F. GUIDELINES FOR SPECIFIC PLANT AREAS Guideline Statement DCPP Compliance to Commitment 9.5B-35 Revision 15 September 2003 (b) For cable spreading rooms that do not provide divisional cable separation of (a)(3) in addition to meeting (a)(1), (a)(2), (a)(4), and (a)(5) above, an auxiliary shutdown system with all cabling independent of the cable spreading room should be provided: (1) Divisional cable separation should meet the guidelines of Regulatory Guide 1.75, "Physical Independence of Electrical Systems." (2) All cabling should be covered with a suitable fire retardant coating. (3) As an alternate to (a) above, automatically initiated gas systems (Halon or CO2) may be used for primary fire suppression, provided a fixed water system is used as a backup. (4) Plants that cannot meet the guidelines of RG 1.75, in addition to meeting (1), (2), (4), and (5) above, an auxiliary shutdown system with all cabling independent of the cable spreading room should be provided. 4. Plant Computer Room Safety-related computer should be separated from other areas of the plant by barriers having a minimum three-hour fire resistant rating. Automatic fire detection should be provided to alarm and annunciate in the control room and alarm locally. Manual hose stations and portable water and Halon fire extinguishers should be provided. The computers used at DCPP do not serve safety-related functions. However, since they are housed adjacent to safety-related areas, detailed fire hazards analysis has been performed for the plant computer rooms (see Appendix 9.5A). Results of the fire hazards analysis show that the computer rooms do not constitute a significant fire hazard. Hose stations and portable extinguishers provide suppression capability in these areas, and smoke detectors are provided in the computer rooms and the exhaust air ducts from the computer rooms. 5. Switchgear Rooms Switchgear rooms should be separated from the remainder of the plant by minimum three-hour rated fire barriers to the extent practicable. Automatic fire detection should alarm and annunciate in the control room and alarm locally. Fire hose stations and portable extinguishers should be readily available. The switchgear rooms are separated from the remainder of the plant by two-hour or three-hour fire barriers. Each vital (safety-related) switchgear bus is located in its own room and separated from the other by two-hour fire barriers. An evaluation of the adequacy of these barriers is presented in Appendix 9.5A. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 F. GUIDELINES FOR SPECIFIC PLANT AREAS Guideline Statement DCPP Compliance to Commitment 9.5B-36 Revision 15 September 2003 Acceptable protection for cables that pass through the switchgear room is automatic water or gas suppression. Such automatic suppression must consider preventing unacceptable damage to electrical equipment and possible necessary containment of agent following discharge. All switchgear rooms are provided with ionization smoke detectors, which annunciate in the control room and locally. The switchgear areas are protected by manual CO2 hose stations. Hose reel stations and portable extinguishers are readily available. 6. Remote Safety-Related Panels The general area housing remote safety-related panels should be provided with automatic fire detectors that alarm locally and alarm and annunciate in the control room. Combustible materials should be controlled and limited to those required for operation. Portable extinguishers and manual hose stations should be provided. The area housing the remote safe shutdown panel is provided with ionization smoke detection that alarms in the control room. Minimizing combustible materials has been a primary design consideration at DCPP. Design and administrative control of combustibles are described in Section D.1 and Section B.2. All remote safety-related panels are within reach of hose stations and portable extinguishers. Smoke detectors are provided in the hot shutdown panels. Refer to Appendix 9.5A for the fire hazards of the hot shutdown remote control panel area (fire areas 5-A-4 and 5-B-4). 7. Station Battery Rooms Battery rooms should be protected against fire explosions. Battery rooms should be separated from each other and other areas of the plant by barriers having a minimum fire rating of three hours inclusive of all penetrations and openings. (See NFPA 69, "Standard on Explosion Prevention System.") Ventilation systems in the battery rooms should be capable of maintaining the hydrogen concentration well below 2 vol. % hydrogen concentration. Stand pipe and hose and portable extinguishers should be provided. Alternatives: (a) Provide a total fire rated barrier enclosure of the battery room complex that exceeds the fire load contained in the room. (b) Reduce the fire load to be within the fire barrier capability of 1-1/2 hours. (c) Provide a remote manual actuated sprinkler system in each room and provide the 1-1/2-hour fire barriers separation. The vital battery rooms are provided with three- hour rated fire barriers separating them from other areas of the plant. The adequacy of the nonvital battery room barriers is evaluated in Appendix 9.5A. Natural ventilation will maintain the hydrogen concentration below 2% volume. (Reference FHARE 132) Manual CO2 hose stations, fire water hose stations, and portable extinguishers are readily available to this area. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 F. GUIDELINES FOR SPECIFIC PLANT AREAS Guideline Statement DCPP Compliance to Commitment 9.5B-37 Revision 15 September 2003 8. Turbine Lubrication and Control Oil Storage and Use Areas A blank fire wall having a minimum resistance rating of three hours should separate all areas containing safety-related systems and equipment from the turbine oil system. When a blank wall is not present, open head deluge protection should be provided for the turbine oil hazards and automatic open head water curtain protection should be provided for wall openings. The turbine building contains the turbine lubrication and control oil system. The turbine building is separated from all other areas by three-hour fire barriers. The clean and dirty lube oil storage areas are contained in their own three-hour barriers. The lube oil reservoir area is protected by an automatic CO2 flooding system. The clean and dirty lube oil storage room is equipped with automatic wet-pipe sprinklers. The entire area is supplied with fire hose reels and portable extinguishers. Further discussion on these areas is found in Appendix 9.5A. 9. Diesel Generator Areas Diesel generators should be separated from each other and other areas of the plant by fire barriers having a minimum fire resistance rating of three hours. Automatic fire suppression such as AFFF foam, or sprinkler should be installed to combat any diesel generator or lubricating oil fires. Automatic fire detection should be provided to alarm and annunciate in the control room and alarm locally. Drainage for fire fighting water and means for local manual venting of smoke should be provided. Day tanks with total capacity up to 1,000 gallons are permitted in the diesel generator area under the following conditions: (a) The day tank is located in a separate enclosure, with a minimum fire resistance rating of three hours, including doors or penetrations. These enclosures should be capable of containing the entire contents of the day tanks. The enclosure should be ventilated to avoid accumulation of oil fumes. (b) The enclosure should be protected by automatic fire suppression systems such as AFFF or sprinklers. When day tanks cannot be separated from the diesel generator, one of the DCPP is designed with three diesel generators per unit. (see Appendix 9.5A). Each diesel is manufactured with a nominal 550 gallon capacity day tank as an integral part of the frame. Three-hour rated fire barriers are provided between the diesel generator compartments and the rest of the plant. Drainage is provided, sized to remove fire fighting water, and smoke venting can be achieved manually. Fire suppression is provided by an automatic total flooding CO2 system in each compartment This system alarms locally and annunciates in the control room. It can also be initiated locally or from the control room. Fire hose reels and portable extinguishers are readily available to each compartment. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 F. GUIDELINES FOR SPECIFIC PLANT AREAS Guideline Statement DCPP Compliance to Commitment 9.5B-38 Revision 15 September 2003 following should be provided for the diesel generator area: (a) Automatic open head deluge or open head spray nozzle system(s). (b) Automatic closed head sprinklers. (c) Automatic AFFF that is delivered by a sprinkler deluge or spray system. (d) Automatic gas system (Halon or CO2) may be used in lieu of foam or sprinklers to combat diesel generator and/or lubricating oil fires. 10. Diesel Fuel Oil Storage Areas Diesel fuel oil tanks with a capacity greater than 1,100 gallons should not be located inside the building containing safety-related equipment. They should be located at least 50 feet from any building containing safety-related equipment, or if located within 50 feet, they should be housed in a separate building with construction having a minimum fire resistance rating of three hours. Buried tanks are considered as meeting the three-hour resistance requirements. See NFPA 30, "Flammable and Combustible Liquids Code," for additional guidance. When located in a separate building, the tank should be protected by an automatic fire suppression system such as AFFF or sprinklers. Tanks, unless buried, should not be located directly above or below safety-related systems or equipment regardless of the fire rating of separating floors or ceilings. In operating plants where tanks are located directly above or below the diesel generators and cannot reasonable be moved, separating floors and main structural members should, as a minimum, have fire resistance rating of three hours. Floors should be liquid tight to prevent leaking of possible oil spills from one level to another. Drains should be provided to remove possible oil spills and fire fighting water to a safe location. One of the following acceptable methods of fire protection should also be provided: (a) Automatic open head deluge or open head spray nozzle system(s). The diesel fuel oil storage areas are located outside the turbine building, buried several feet below grade. A detailed description of the storage areas is provided in Appendix 9.5A. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 F. GUIDELINES FOR SPECIFIC PLANT AREAS Guideline Statement DCPP Compliance to Commitment 9.5B-39 Revision 15 September 2003 (b) Automatic closed head sprinklers. (c) Automatic AFFF that is delivered by a sprinkler system or spray system. 11. Safety-Related Pumps Pump houses and rooms housing safety-related pumps should be protected by automatic sprinkler protection unless a fire hazards analysis can demonstrate that a fire will not endanger other safety-related equipment required for safe plant shutdown. Early warning fire detection should be installed with alarm and annunciation locally and in the control room. Local hose stations and portable extinguishers should also be provided. Automatic sprinkler protection has been provided for the auxiliary feedwater pumps, the charging pumps, the component cooling water pumps, and the boric acid transfer pumps. Appendix 9.5A demonstrates that all other safe shutdown pumps will not endanger other safe shutdown equipment in the event of a fire. Areas containing pumps required for safe shutdown are provided with ionization smoke detection capabilities. Fire water hose reels and portable extinguishers are provided throughout the plant to serve as backup fire suppression. 12. New Fuel Area Hand and portable extinguishers should be located within this area. Also, local hose stations should be located outside but within hose reach of this area. Automatic fire detection should alarm and annunciate in the control room and alarm locally. Combustibles should be limited to a minimum in the new fuel area. The storage area should be provided with a drainage system to preclude accumulation of water. The storage configuration of new fuel should always be so maintained as to preclude criticality for any water density that might occur during fire water application. The new fuel storage area is located in a concrete vault and is not to be used for storage of combustible materials other than a plastic wrapper on new fuel. Portable extinguishers and fire hose reels are readily available to this vault. Two drains are provided and sized to prevent flooding in this area as a result of fire fighting. Ionization smoke detection is provided for this area. The fuel storage configuration is such that the water density ranges of fire fighting equipment will not allow criticality. (
Reference:
NRC Staff Response to the Testimony of Bridenbaugh, Hubbard, and Minor; February 18, 1976). 13. Spent Fuel Pool Area Protection for the spent fuel pool area should be provided by local hose stations and portable extinguishers. Automatic fire detection should be provided to alarm and annunciate in the control room and to alarm locally. The spent fuel pool area is provided with hose stations, portable extinguishers, and optical detection which alarms in the control room. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 F. GUIDELINES FOR SPECIFIC PLANT AREAS Guideline Statement DCPP Compliance to Commitment 9.5B-40 Revision 15 September 2003 14. Radwaste Building The radwaste building should be separated from other areas of the plant by fire barriers having at least three-hour ratings. Automatic sprinklers should be used in all areas where combustible materials are located. Automatic fire detection should be provided to annunciate and alarm in the control room and alarm locally. During a fire, the ventilation systems in these areas should be capable of being isolated. Water should drain to liquid radwaste building sumps. Acceptable alternative fire protection is automatic fire detection to alarm and annunciate in the control room, in addition to manual hose stations and portable extinguishers consisting of handheld and large wheeled units. The radwaste buildings are independent structures located approximately 100 feet east of the auxiliary building. Automatic wet pipe sprinkler systems are installed in the north and south buildings, where combustible materials are normally stored. The sprinkler systems alarm upon actuation. Annunciation of the alarm is in the building's main control room and at a local annunciator mounted outside the north storage building on the west wall. This fire protection arrangement was chosen in lieu of a fire detection system. Building drains for the north storage building are directed to the liquid radwaste system. The south storage building's dry active waste storage room has a 2-inch dike sloped to a sump that can contain the sprinkler water in the event of a fire. HVAC design and engineering are commensurate with the guidelines of NFPA 90A. 15. Decontamination Areas The decontamination areas should be protected by automatic sprinklers if flammable liquids are stored. Automatic fire detection should be provided to annunciate and alarm in the control room and alarm locally. The ventilation system should be capable of being isolated. Local hose stations and hand portable extinguishers should be provided as backup to the sprinkler system. Storage of flammable liquids at DCPP is controlled through administrative procedures. Flammable liquids are not stored in decontamination areas. The decontamination areas are located inside the fuel handling building, which is provided with hose stations and fire extinguishers. Detection is provided in the 140 ft elevation of fire zone 3-R, which opens to the decontamination areas below via a large equipment hatch. 16. Safety-Related Water Tanks Storage tanks that supply water for safe shutdown should be protected from the effects of fire. Local hose stations and portable extinguishers should be provided. Portable extinguishers should be located in nearby hose houses. Combustible materials should not be stored next to outdoor tanks. A minimum of 50 feet of separation should be provided between outdoor tanks and combustible materials where feasible. The refueling water storage tank and condensate storage tank are safety-related and required for safe plant shutdown. No combustible materials are stored in proximity to these tanks. Hose stations and fire hydrants from the yard main provide fire suppression capability. Portable extinguishers are located nearby. No fire hazards exist that could adversely affect the availability of these tanks. Additionally, these tanks have been encased in gunite as a part of seismic upgrading. A fire in the DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 F. GUIDELINES FOR SPECIFIC PLANT AREAS Guideline Statement DCPP Compliance to Commitment 9.5B-41 Revision 15 September 2003 vicinity of these tanks would not affect the tanks due to the insulating properties of the gunite. Approximately 12 feet separates these tanks from the common outside walls of the fuel building. 17. Cooling Towers Cooling towers should be of noncombustible construction or so located that a fire will not adversely affect any safety-related systems or equipment. Cooling towers should be of noncombustible construction when the basin are used for the ultimate heat sink or for the fire protection water supply. Not applicable. Cooling towers are not used at DCPP. 18. Miscellaneous Areas Miscellaneous areas such as records storage areas, shops, warehouses, and auxiliary boiler rooms should be so located that a fire or effects of a fire, including smoke, will not adversely affect any safety-related systems or equipment. Fuel oil tanks for auxiliary boilers should be buried or provided with dikes to contain the entire tank contents. A fire hazards analysis exists that documents the fire hazards that may threaten safe shutdown equipment. This analysis and the Appendix R Reports submitted to the NRC demonstrate that miscellaneous areas do not have an adverse impact on the ability of either unit to shut down in the event of a fire. A fuel oil tank for the auxiliary boilers is buried in the hillside, to the east and north of the fuel handling area. This tank is empty and has been abandoned in place. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 F. GUIDELINES FOR SPECIFIC PLANT AREAS Guideline Statement DCPP Compliance to Commitment 9.5B-42 Revision 15 September 2003 1. Welding and Cutting, Acetylene-Oxygen Fuel Gas Systems This equipment is used in various areas throughout the plant. Storage locations should be chosen to permit fire protection by automatic sprinkler systems. Local hose stations and portable equipment should be provided as backup. The requirements of NFPA 51 and 51B are applicable to these hazards. A permit system should be required to utilize this equipment. A complete welding and open flame permit system exists and is governed by the referenced administrative procedure. Oxygen and acetylene are stored in the hot shop and warehouse areas. Fuel gases are also used routinely in the machine shop area and hot shop. Fire hazards analyses of these areas considered the contribution of fuel gases to the overall combustible loading. Safety-related equipment is not present in any of these areas. The warehouse area and machine shop are protected by automatic sprinkler systems, with fire hoses and portable extinguishers providing backup. The hot shop is protected by hose reels and backed up by portable fire extinguishers. Permits are required whenever welding or cutting is done outside established shop areas (see Section B.3(a) of this table). 2. Storage Areas for Dry Ion Exchange Resins Dry ion exchange resins should not be stored near essential safety-related systems. Dry unused resins should be protected by automatic wet-pipe sprinkler installations. Detection by smoke and heat detectors should alarm and annunciate in the control room and alarm locally. Local hose stations and portable extinguishers should provide backup for these areas. Storage areas of dry resin should have curbs and drains. (Refer to NFPA 92M, "Waterproofing and Draining of Floors.") Dry ion exchange resins are stored in a sprinklered area of the main warehouse, which is located remote from the power block. Portable extinguishers are provided. 3. Hazardous Chemicals Hazardous chemicals should be stored and protected in accordance with the recommendations of NFPA 49, "Hazardous Chemicals Data." Chemicals storage areas should be well ventilated and protected against flooding conditions since some chemicals may react with water to produce ignition. Storage and protection arrangements are designed to meet the intent of NFPA-49. Storage facilities are located remote from the power block and are protected from flooding by a berm. DCPP UNITS 1 & 2 FSAR UPDATE TABLE B-1 COMPARISON OF DCPP TO APPENDIX A OF BTP APCSB 9.5-1 F. GUIDELINES FOR SPECIFIC PLANT AREAS Guideline Statement DCPP Compliance to Commitment 9.5B-43 Revision 15 September 2003 4. Materials Containing Radioactivity Materials that collect and contain radioactivity such as spent ion exchange resins, charcoal filters, and HEPA filters should be stored in closed metal tanks or containers that are located in areas free from ignition sources or combustibles. These materials should be protected from exposure to fires in adjacent areas as well. Consideration should be given to requirements for removal of isotropic decay heat from entrained radioactivity materials. Spent ion exchange resins are sluiced to the spent resin storage tanks in the auxiliary building. The resin is retained in a water solution in the tank. Storage in this manner eliminates the potential for combustion. Combustible loadings in this and adjacent areas are small, and no ignition sources are present. All filter housings are constructed of noncombustible materials (steel and concrete) and are located in areas that are relatively free from ignition sources and combustibles. Maximum postulated filter fission product loading is below that necessary to cause autoignition of charcoal filters. Fire hazards analysis of individual plant areas indicates that materials containing radioactivity are adequately protected from exposure to fire. DCPP UNITS 1 & 2 FSAR UPDATE
APPENDIX 9.5C REACTOR COOLANT PUMP OIL COLLECTION SYSTEM EVALUATION TO 10 CFR 50, APPENDIX R, SECTION III.O
DCPP UNITS 1 & 2 FSAR UPDATE 9.5C-1 Revision 15 September 2003 APPENDIX 9.5C REACTOR COOLANT PUMP OIL COLLECTION SYSTEM EVALUATION TO 10 CFR 50, APPENDIX R, SECTION III.O A. BACKGROUND In 1975, Pacific Gas and Electric Company (PG&E) provided a system to collect and contain a potential oil leak from the Westinghouse reactor coolant pump (RCP) motors. The four RCPs were considered as two sets, two RCPs per set. A separate oil collection system was provided for each set. Each collection system was designed to collect and contain a potential oil spill of up to 50 gallons. Automatic smoke detection and wet pipe automatic sprinkler systems were installed to provide active fire protection for each RCP. NRC review and acceptance of the fire protection provision for the RCPs is contained within Supplemental Safety Evaluation Report (SSER) No. 8. In March 1981, PG&E committed to provide a lube oil collection system consistent with the requirements of Appendix R, Section III.O. A review was made of the existing collection system and several modifications were made. The major modification involved replacing the two oil collection systems with one, and increasing the capacity of the collection tank to accommodate the entire lube oil inventory of one RCP motor. On July 15, 1983, a deviation from the requirements of Appendix R, Section III.O was requested for the RCP oil collection system on Unit 1. SSER 23 evaluated this request and approved the deviation. A similar deviation was requested for the Unit 2 RCP oil collection system on December 6, 1984, and approved in SSER 31 (which referenced SSER 23). The following discussion addresses the Unit 2 system (Fire Area 9, Fire Zones 9A, 9B, and 9C). The Unit 1 system is similar and will have the corresponding Unit 1 fire areas and zones (Fire Area 1 and Fire Zones 1A, 1B, and 1C). B. RCP AREA DESCRIPTION The RCPs are located in two areas within Fire Zone 9-B (fire area 9). Fire Zone 9- is separated from Fire Zone 9-A (containment penetration area) by a reinforced concrete shield wall which also serves as a support structure for the polar crane. Fire Zone 9-B is separated from Fire Zone 9-C (control rod drive area) by the elevation 140-foot floor slab and the reinforced concrete biological shield wall from elevation 140 feet to approximately 110 feet. The biological shield wall separates Zone 9-B into two areas (north and south) above elevation 110 feet. Each RCP is above this elevation, therefore, the biological shield serves as a DCPP UNITS 1 & 2 FSAR UPDATE 9.5C-2 Revision 15 September 2003 barrier between the north area, in which RCPs 2-1 and 2-2 are located, and the south area, in which RCPs 2-3 and 2-4 are located. The north and south areas communicate through open areas from approximately elevation 110 feet to the containment floor slab at elevation 91 feet and through open ventilation gratings above each RCP at elevation 140 feet. Each RCP is separated from the others by a minimum of approximately 45 feet. C. RCP OIL COLLECTION SYSTEM Each RCP is equipped with an oil collection system to collect and contain any reasonable oil leak. The oil collection system consists of a series of collection pans surrounding each pump draining to a lube oil collection tank. The collection pans surrounding each pump consist of 18-gauge sheet metal fastened to the platform grating at elevation 110 feet. Each pan has a minimum 1-7/8-inch rim and approximate collection area of 10 to 30 square feet. Each pan is connected to the adjacent pan by an overlapping joint and a mechanical fastener. All openings through and between the collection pans for conduit, pipes, etc., are surrounded by drip shields draining to the collection pans. A skirt is installed around the pump motor coupling to direct leaks on the outside of the motor casing (upper lube oil cooler, level instrumentation, etc.) to the collection pans below. The oil lift pump and piping is enclosed by a sheet metal shield. Spray from a potential oil lift pump leak would be confined to within the shield and the oil directed to the collection pans. Leaks internal to the motor casing are diverted to the collection pans below by a gutter inside the coupling area or collected above the main pump flange. The main pump flange is surrounded by a 2-inch rim with an overflow drain to the collection pans. All joints are caulked to prevent leakage. Each collection pan is equipped with a 1-1/2-inch drain pipe connected to a 2-inch drain line. The drain lines for each pump connect to a 2-inch common header and enter the containment annulus through penetrations in the shield wall. The common header drain line is routed to an oil collection tank located under the fuel transfer canal in the containment annulus at elevation 91 feet. The RCP oil collection tank has a 285-gallon capacity and is equipped with a valved drain, a 2-inch overflow, and a 2-inch vent. The vent is equipped with a flame arrester. The tank is designed to contain the oil inventory of one RCP motor with margin. Additionally, a closeout procedure for containment requires that the tank be verified empty after extended maintenance outage periods. DCPP UNITS 1 & 2 FSAR UPDATE 9.5C-3 Revision 15 September 2003 D. ACTIVE FIRE PROTECTION CAPABILITY D.1 Detection A smoke detector is provided between each RCP and the corresponding steam generator. The ventilation flowpath around the RCP was considered when the detectors were situated. Additional detectors are provided in the containment annulus in the exhaust air flowpath for Zone 9-B. These detectors annunciate in the continually manned control room. D.2 Suppression A wet-pipe automatic sprinkler system is provided for each RCP. The water flow alarm annunciates in the continually manned control room. The sprinkler system piping is designed such that a seismic event would not impact safety-related equipment due to system failure. Manual fire suppression capability, in the form of portable fire extinguishers and fire hose stations, is available for use in the RCP areas. Portable fire extinguishers are brought to the containment since they are not stored there during Modes 1 through 4. E. COMBUSTIBLES The combustible loading for the RCP areas is included in the discussion of Fire Area 9. F. DESCRIPTION OF DEVIATION F.1 Statement of Problem The above described RCP oil collection system is in compliance with Appendix R, Section III.O, and Item 2 of the NRC Staff Position Paper,(a) except for drainage of an overflow "to a safe location where the lube oil will not present an exposure fire hazard to or otherwise endanger safety related equipment." In the unlikely event of an overflow from a multiple RCP lube oil spill, RCP oil would be discharged from the RCP oil collection tank into the containment annulus floor trench at elevation 91 feet. (a) Presented in R. H. Vollmer's April 1, 1983, memorandum to D. G. Eisenhut concerning the oil collection system reactor coolant pumps, Florida Power and Light Company, St. Lucie 2, Docket No. 50-389, from J. Olshinski to D. G. Eisenhut. DCPP UNITS 1 & 2 FSAR UPDATE 9.5C-4 Revision 15 September 2003 F.2 Basis for Deviation Request (Unit 1) a. The RCP lube oil collection tank overflow pipe discharges downward to a recessed trench in the elevation 91 feet floor, along the outside of the shield wall. This trench is sloped so that an RCP lube oil overflow would flow to the containment drain sump. b. The overflow pipe of the oil collection tank has pickup from 3 inches above the tank bottom. Thus, in the remote likelihood of a multiple RCP motor lube oil spill and fire propagation to the oil collection tank, such a fire would not be extended to the oil discharges to the floor trench. c. The Westinghouse RCP CS VSS motor currently utilizes a high flash point lubricating oil (425F). The fire point of this oil is 520°F. Therefore, a high-energy ignition source would be necessary to sustain combustion in the unlikely event that a multiple RCP lube oil spill occurs and oil is discharged through the overflow pipe. An additional evaluation on the impact of the flash point temperature is included in FHARE 115. d. Because an oil-to-water heat exchanger serves each bearing assembly, and the heat exchanger discharge water and bearing temperatures are monitored and alarm in the continuously manned control room, it is not deemed credible for the RCP lube oil to reach temperatures within 50 percent of its flash point. e. There are various components and circuits necessary for safe shutdown in the vicinity of this floor trench. Power cable is routed in conduit. Other circuits are not considered to present a high-energy ignition source. F.3 Basis for Deviation Request (Unit 2) a. The RCP oil collection system, including the oil collection tank and overflow piping, has been designed to withstand the safe shutdown earthquake. b. The RCP lube oil collection tank overflow pipe discharges downward to a recessed trench in the floor at elevation 91 feet, along the outside of the shield wall. This trench is sloped so that any RCP lube oil overflow would flow to the containment drain sump. c. The inlet of the overflow pipe of the oil collection tank, located 3 inches above the tank bottom, will drain water off the bottom of the tank while containing the entire oil inventory of one RCP. The discharge is piped to the containment annulus trench such that splashing of the tank overflow in the trench is precluded. DCPP UNITS 1 & 2 FSAR UPDATE 9.5C-5 Revision 15 September 2003 d. The Westinghouse RCP motor currently utilizes a high flash point lubricating oil (425F). The fire point of this oil is 520°F. Therefore, a high-energy ignition source would be necessary to initiate combustion in the unlikely event that a multiple RCP lube oil spill (greater than 285 gallons) occurs and oil is discharged through the overflow pipe. An additional evaluation on the impact of the flash point temperature is included in FHARE 115. e. The lube oil flash point is sufficiently higher than any ignition sources in the vicinity of the tank overflow pipe or the anticipated flowpath of the overflowing oil. f. Because an oil-to-water heat exchanger serves each bearing assembly that maintains the oil temperature below 200°F, and since the heat exchanger discharge water and bearing temperature are monitored and alarm in the continuously manned control room, it is not deemed credible for the RCP lube oil to reach temperatures near its flash point. g. There are three safe shutdown functions located between 10 and 20 feet from the RCP oil collection tank: valves 8000C and PCV-456 for pressurizer pressure relief and LT-406 for pressurizer level measurement. A fire of 40 feet in diameter from the RCP oil spill collection tank would not jeopardize the safe shutdown of the plant. G. SAFETY EVALUATION The safety evaluation of the Units 1 and 2 RCP lube oil collection system, and the basis for acceptability of the deviation from Section III.O requirements, are documented in SSER 23. The concern with an unmitigated fire due to an overflow of lube oil from the collection system that could damage safety-related equipment in the vicinity was resolved based on the design of the collection system and the physical properties of the oil. The following are the technical bases for the safety evaluation: The overflow line for the lube oil collection tank discharges into a trench that is sloped to channel any potential oil spill to the containment drain sump. The oil has a high flash point temperature which would represent a significant hazard only if atomized or if the oil came in contact with a high-energy ignition source. The oil collection system is designed to withstand a safe shutdown earthquake. There are no ignition sources in the anticipated flow path of the overflowing oil. DCPP UNITS 1 & 2 FSAR UPDATE 9.5C-6 Revision 15 September 2003 Smoke detectors, if activated by a fire, would annunciate in the control room and the fire brigade would be summoned. Fire damage to safety-related circuits in the area would not affect the ability to achieve and maintain safe shutdown. DCPP UNITS 1 & 2 FSAR UPDATE
APPENDIX 9.5D EMERGENCY LIGHTING CAPABILITY EVALUATION TO 10 CFR 50, APPENDIX R, SECTION III.J DCPP UNITS 1 & 2 FSAR UPDATE 9.5D-1 Revision 16 June 2005 APPENDIX 9.5D EMERGENCY LIGHTING CAPABILITY EVALUATION TO 10 CFR 50, APPENDIX R, SECTION III.J A. EMERGENCY LIGHTING SYSTEM DESCRIPTION The emergency lighting system at the Diablo Canyon Power Plant (DCPP) consists of three independent systems: 1. Emergency AC Lighting System, 120 Vac The emergency ac lighting system is continuously energized. On loss of normal power supply to the vital G and H buses, the emergency diesel generators will start and pick up load in 10 seconds. The emergency ac lighting system will then be powered continuously by the emergency diesel generators. In the control room, the emergency ac lights are backed-up instantaneously by an independent uninterruptible power supply (UPS) with a four-hour rated battery. The UPS and battery are to bridge the power interruption during diesel starting and loading. The UPS and battery are not required for Appendix R and are rated QA Class N, Non Class IE, Design Class II, Non-Seismic. Tables 9.5D-1 and 9.5D-2 for Fire Area 8C are relying on the diesel-backed emergency ac lighting and BOLs to satisfy Appendix R requirements in the control room. In the pipe rack area, the emergency ac lights are powered from an UPS with an eight hour rated battery power supply. This UPS is located to ensure lighting is available in this area during all fire scenarios which require operator manual actions on the pipe rack. 2. Emergency DC Lighting System, 125 Vdc The 125 Vdc emergency lighting system is energized instantly upon loss of the emergency ac lighting system and is deenergized, after a 5-second time delay, on return of power supply to the emergency ac lighting system. These lights are powered from the nonvital station batteries and will provide sufficient emergency lighting for at least one hour. 3. Emergency Self-Contained Lighting, Battery Operated Lights (BOLs) with 8-Hour Battery Supply The emergency BOLs are located in various strategic areas of the plant which require lighting during safe shutdown. This lighting is either supplemental or additional to the emergency lighting system, so that adequate light would still be available should damage occur to either the DCPP UNITS 1 & 2 FSAR UPDATE 9.5D-2 Revision 16 June 2005 emergency lighting circuits or the normal lighting circuits serving a particular area. The emergency self-contained lights are energized upon failure of the associated ac lighting system (either normal or emergency lighting) and subsequently deenergized when the associated ac lighting system is returned to service. B. METHOD OF EVALUATION The review for compliance with 10 CFR 50, Section III.J, dealt with those fire zones or areas that may require the control room operator to take manual action at a remote location. This location may be either in an area where a fire is postulated or in an area unaffected by the single fire. In either case, emergency lighting is needed for access and egress routes to that remote location from the control room. Generally, it was assumed that if a fire were to occur, the emergency lighting circuit, including feeder circuit, that exists in the fire zone or area would be lost. Loss of lighting circuits that may affect lighting in other zones or areas was also taken into consideration. This approach ensures that lighting along the entire access and egress route is accounted for when needed. If no manual action is required of the plant operators for a fire in a particular zone or area, then the potential loss of emergency ac lights was not evaluated. (Safe shutdown can be achieved by the operators from, the main control room, where emergency lights exist.) An analysis of the effects of a fire was performed to demonstrate that adequate lighting for access and egress routes to safe shutdown components is provided. The results of this analysis are summarized in Section D. C. LEVEL OF ILLUMINATION FOR EMERGENCY LIGHTING A program was instituted to verify that plant emergency lighting provides sufficient levels of illumination to allow any needed operations of safe shutdown equipment, and to ensure that access and egress routes to such equipment will have adequate illumination for the traversal of these routes. D. SUMMARY The emergency lighting table matrix, in Table 9.5D-1 for Unit 1 and Table 9.5D-2 for Unit 2, identifies the type of emergency lighting credited in each fire area. The availability of each type of light is contingent upon lighting circuit routing and the specific fire scenario which requires access/egress through or operator action within the fire area specified. Specific details on 10 CFR 50 Appendix R emergency lighting including lighting units necessary for Appendix R, operator access/egress routes, operator manual actions which require emergency lighting, and availability of emergency lighting based upon power supply circuit routing are provided in design calculation 335-DC. The emergency lighting analysis and supporting documentation were reviewed by the NRC and determined to be DCPP UNITS 1 & 2 FSAR UPDATE 9.5D-3 Revision 16 June 2005 adequate for compliance with Section III.J of Appendix R to 10 CFR 50 (Ref. NRC letter to PG&E dated April 4, 1997, Chron. No. 232672). E. DESCRIPTION OF DEVIATION E.1 Statement of Problem Section III.J of Appendix R requires that "emergency lighting units with at least an 8-hour battery power supply be provided in all areas needed for operation of safe shutdown equipment and in access and egress routes thereto." J-9.5D(1) Because eight hour battery backed lighting units are not provided at all operator manual action locations and access/egress routes, the emergency lighting system at DCPP is not in strict compliance with Section III.J. This request for exemption from 10 CFR 50 Appendix R Section III.J was originally submitted in NRC docket 50-275 (Unit 1) and 50-323 (Unit 2) "Pacific Gas and Electric Company Review of 10 CFR 50 Appendix R Section III.G, III.J and III.O." Based on the NRC review of the above documents and clarifying description provided subsequently, the NRC staff approved the deviation to 10 CFR 50) Appendix R Section III.J in SSER 23 (Unit 1) and SSER 31 (Unit 2). E.2 Basis for Exemption (Unit 1) a. Three independent emergency lighting systems have been provided: ac lighting from the G and H buses of the emergency diesels, dc lighting for at least 1 hour from the nonvital station batteries, and BOLs with 8-hour battery packs in selected key locations throughout DCPP. b. Where manual operation of certain safe shutdown equipment is taken credit for, as discussed in Appendixº9.5G, the emergency lighting systems that provide for light along the access and egress routes to this equipment have been evaluated to ensure a reliable source of light is available. E.3 Basis for Exemption (Unit 2) a. Three independent emergency lighting systems have been provided: ac lighting from the G and H buses of the emergency diesels, dc lighting for at least 1 hour from the nonvital station batteries, and BOLs with 8-hour battery packs in selected key locations throughout DCPP. b. Where manual operation of certain safe shutdown equipment is taken credit for, the emergency lighting systems that provide for light along the access and egress routes to this equipment have been evaluated to ensure that a reliable source of light is available. DCPP UNITS 1 & 2 FSAR UPDATE 9.5D-4 Revision 16 June 2005 c. Fixed emergency lighting is provided at all operator manual locations, which require emergency lighting and in access/egress routes thereto. DCPP UNITS 1 & 2 FSAR UPDATE 9.5D-5 Revision 16 June 2005 TABLE 9.5D-1 Emergency Lighting Table Matrix (Unit 1) Fire Area Emergency Lighting Credited AC DC BOL 3AA X 3B3 X 3BB-85 X X 3BB-100 X X 3BB-115 X X 3C X 3H1 X 3L X X 3Q1 X X 3R X 3X X X 5A1 X 5A2 X X 5A3 X X 5A4 X X 6A1 X X X 6A2 X X 6A3 X X 6A5 X X 8C X X 10 X 11A1 X 11B1 X 11C1 X 11D X 12E X 13A X X 13B X X 13C X X 13D X 13E X X 14A X X X 14D X X 14E X X 28 UPS 34 X S1 X X S2 X X S3 X X Legend AC: Emergency AC Lighting, 120 Vac DC: Emergency DC Lighting, 125 Vdc BOL: Battery Operated Lights, 8-hour Battery Supply UPS: AC lighting with 8-hour battery backup power supply DCPP UNITS 1 & 2 FSAR UPDATE 9.5D-6 Revision 16 June 2005 TABLE 9.5D-2 Emergency Lighting Table Matrix (Unit 2) Fire Area Emergency Lighting Credited AC DC BOL 3AA X X X 3C X 3CC-85 X X 3CC-100 X X 3CC-115 X 3D3 X 3l1 X 3L X X 3T1 X 3X X X 4B X X 5B1 X X 5B2 X X 5B3 X X 5B4 X X 6B1 X X X 6B2 X X 6B3 X X 6B5 X 8C X X 19A X X X 19D X X 19E X 22A1 X 22B1 X 22B2 X 22C1 X 22C X 23E X X X 24A X X 24B X X 24C X X 24D X 29 UPS 34 X S1 X X S2 X X S4 X X S5 X S7 X X X Legend AC: Emergency AC Lighting, 120 Vac DC: Emergency DC Lighting, 125 Vdc BOL: Battery Operated Lights, 8-hour Battery Supply UPS: AC lighting with 8-hour battery backup power supply
DCPP UNITS 1 & 2 FSAR UPDATE
APPENDIX 9.5E 10 CFR 50, APPENDIX R, SECTION III.L ALTERNATIVE AND DEDICATED SHUTDOWN CAPABILITY DCPP UNITS 1 & 2 FSAR UPDATE 9.5E-1 Revision 15 September 2003 APPENDIX 9.5E 10 CFR 50, APPENDIX R, SECTION III.L ALTERNATIVE AND DEDICATED SHUTDOWN CAPABILITY As required by Section III.G.3 of 10 CFR 50, Appendix R, alternative shutdown capability and its associated circuits, independent of cables, systems or components in the area, room or zone under consideration, is provided: where the protection of systems whose function is required for hot shutdown does not satisfy the requirements of Section III.G.2. In addition, fire detection and a fixed fire suppression system must be installed in the area, room or zone under consideration.
Section III.L delineates the requirements for the alternative shutdown capability credited to meet Section III.G.3. The alternative shutdown capability is required to accommodate postfire conditions where offsite power is available and where offsite power is not available for 72 hours. The alternative shutdown capability provided for a specific fire area must be able to:
(a) achieve and maintain subcritical reactivity conditions in the reactor; (b) maintain reactor coolant inventory; (c) achieve and maintain hot standby conditions; (d) achieve cold shutdown conditions within 72 hours; and (e) maintain cold shutdown conditions, thereafter.
The performance goals for the shutdown function must be:
(a) The reactivity control function shall be capable of achieving and maintaining cold shutdown reactivity conditions. (b) The reactor coolant makeup function shall be capable of maintaining the reactor coolant level within the level indication in the pressurizer. (c) The reactor heat removal function shall be capable of achieving and maintaining decay heat removal. (d) The process monitoring function shall be capable of providing direct readings of the process variables necessary to perform and control the above functions.
DCPP UNITS 1 & 2 FSAR UPDATE 9.5E-2 Revision 15 September 2003 (e) The supporting functions shall be capable of providing the process cooling, lubrication, etc., necessary to permit the operation of the equipment used for safe shutdown functions. Alternative shutdown capability is credited for a fire in the control room (fire area 8-C) or the cable spreading rooms (fire area 7-A or 7-B). A deviation from Appendix R, Section III.G.3 for fire area 8-C was granted by the NRC for lack of area-wide fixed fire suppression system (Reference SSER No. 23). Postfire safe shutdown is carried out from outside the control room using control and monitoring functions provided at the remote hot shutdown panel (HSP), the dedicated shutdown panel (DSP), local indications, 4 kV and 480 V switchgears, local control panels, or locally at the valve.
Operating Procedures OP AP-8A and OP AP-8B implement the postfire safety shutdown capability. The repair actions credited involve manually aligning valves necessary to operate auxiliary spray for RCS depressurization. The repair actions are included in OP AP-8A and OP AP-8B.
The components and actions credited for the alternative shutdown capability are identified in the safe shutdown analysis section (Section 4.0 of Appendix 9.5A) for Fire Area 7-A for Unit 1 and Fire Area 7-B for Unit 2. The performance goals for the safe shutdown functions were achieved, and the requirements of Sections III.G.3 and III.L were achieved. DCPP UNITS 1 & 2 FSAR UPDATE
APPENDIX 9.5F FIRE BARRIER FIGURES
DCPP UNITS 1 & 2 FSAR UPDATE 9.5F-1 Revision 16 June 2005 APPENDIX 9.5F FIRE BARRIER FIGURES List of Figures: 9.5F-1(a) Fire Areas, Turbine Building Elevation 85 9.5F-2(a) Fire Areas, Turbine Building Elevation 104' 9.5F-3(a) Fire Areas, Turbine Building Elevation 119' 9.5F-4(a) Fire Areas, Turbine Building Elevation 140' 9.5F-5(a) Fire Areas, Auxiliary Building Elevation 54' and 64' 9.5F-6(a) Fire Areas, Auxiliary Building Elevation 75' 9.5F-7(a) Fire Areas, Auxiliary Building + Containment, Elevation 85' 9.5F-8(a) Fire Areas, Auxiliary Building + Containment + Fuel Handling Elevation 100' 9.5F-9(a) Fire Areas, Auxiliary Building + Containment + Fuel Handling Elevation 115' 9.5F-10(a) Fire Areas, Auxiliary Building + Containment + Fuel Handling Elevation 140' 9.5F-11(a) Fire Areas, Auxiliary Building Elevation 125'-8", 127'-4" and 163'-4" 9.5F-12(a) Fire Areas, Turbine Building Elevation 85' 9.5F-13(a) Fire Areas, Turbine Building Elevation 104' 9.5F-14(a) Fire Areas, Turbine Building Elevation 119' 9.5F-15(a) Fire Areas, Turbine Building Elevation 140' 9.5F-16(a) Fire Areas, Auxiliary Building + Containment + Fuel Handling Elevation 85' and 100' 9.5F-17(a) Fire Areas, Auxiliary Building + Containment + Fuel Handling Elevation 115' and 140' DCPP UNITS 1 & 2 FSAR UPDATE 9.5F-2 Revision 16 June 2005 9.5F-18(a) Fire Areas, Intake Structure 9.5F-19(a) Fire Areas, Buttress Area 9.5F-20 Deleted in Revision 4 9.5F-20A Buttress Area, Unit 1, Elevation 85' 9.5F-20B Buttress Area, Unit 1, Elevation 104' 9.5F-20C Buttress Area, Unit 2, Elevation 85' 9.5F-20D Buttress Area, Unit 2, Elevation 104' 9.5F-21 Fire Areas, Buttress Area 9.5F-22 Section A1-A1 9.5F-23 Section B1-B1 9.5F-24 Section C1-C1 9.5F-25 Section D1-1 9.5F-26 Section E-E 9.5F-27 Section F1-F1 9.5F-28 Section G-G 9.5F-29 Section A2-A2 9.5F-30 Section B2-B2 9.5F-31 Section C2-C2 9.5F-32 Sections D2-D2 and E2-E2 9.5F-33 Section F2-F2 (a) This figure corresponds to a controlled engineering drawing that is incorporated by reference into the FSAR Update. See Table 1.6-1 for the correlation between the FSAR Update Figure number and the corresponding controlled engineering drawing number. REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures.
FIGURES 9.5F-20A, B, C, AND D AND FIGURES 9.5F-21 THROUGH 9.5F-33 TO BE WITHHELD FROM PUBLIC PER 10 CFR 2.390 AND SECY-04-0191. DCPP UNITS 1 & 2 FSAR UPDATE
APPENDIX 9.5G EQUIPMENT REQUIRED FOR SAFE SHUTDOWN DCPP UNITS 1 & 2 FSAR UPDATE 9.5G-1 Revision 20 November 2011 APPENDIX 9.5G EQUIPMENT REQUIRED FOR SAFE SHUTDOWN Tables 9.5G-1 and 9.5G-2 for DCPP Units 1 and 2, respectively, list the minimum equipment required to bring the plant to a cold shutdown condition as defined by 10 CFR 50, Appendix R, Section III.G.
The "Redundancy/Comments" column is simplified and does not actually represent the component interrelationships needed to ensure safe shutdown. PG&E Engineering Calculation M-680 contains detailed component lists and logic diagrams which give component functions and interrelationships. For example, 1 of 2 ASW pumps and 1 of 2 ASW pump room exhaust fans are required for safe shutdown. The ASW pump that is credited following a postulated fire must also have its associated exhaust fan free from fire damage. These interrelationships are shown on the logic diagrams.
The ability to safely shutdown the plant following a fire in any fire area is evaluated using the safe shutdown logic diagrams, documented in PG&E Engineering Calculation M-928, and summarized in Section 4.0 of Appendix 9.5A of this FSAR Update.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-1 (UNIT 1) Sheet 1 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS
- 1. Emergency Power Supply a. Diesel generators 1-1, 1-2, 1-3 and associated equipment 2 of 3 diesel generators required; Offsite power (nonalternate shutdown areas only) b. Diesel fuel oil transfer pumps 1 of 2 pumps required c. Day tank level control valves required 1 of 2 LCVs per day tank LCV-85, LCV-88 LCV-86, LCV-89 LCV-87, LCV-90 d. Vital batteries 2 of 3 required e. Vital Battery chargers 2 of 5 required f. Vital ups 2 of 4 channels required g. 4kV Vital switchgear 2 of 3 required h. Vital DC distribution panels 2 of 3 required i. 480 V Vital switchgear 2 of 3 required j. Vital instrument ac distribution panels 2 of 4 panels required k. Fuel oil storage tanks TK 0-1 and TK 0-2 1 of 2 required l. Startup transformers 2 of 2 required m. 12kV Startup Bus 1 required 2. Auxiliary Feedwater System a. Auxiliary feedwater (AFW) pumps: turbine-driven AFW pump 1-1 and motor-driven AFW pumps 1-2 and 1-3 1 of 3 pumps required b. AFW pump turbine steam isolation valve: Applicable only to pump 1-1 FCV-95, FCV-152, FCV-15 Required for AFW pump 1-1 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-1 (UNIT 1) Sheet 2 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS FCV-37, FCV-38 Spurious operation only; 1 of 2 valves required for AFW pump 1-1 c. SG Aux Feedwater supply: Pump 1-1: LCV-106, LCV-107, LCV-108, and LCV-109 1 of 4 valves required for pump 1-1 Pump 1-2: LCV-110, LCV-111 1 of 2 valves required for Pump 1-2 Pump 1-3: LCV-113, LCV-115 1 of 2 valves required for Pump 1-3 d. Water supply and associated valves: 1) Condensate storage tank, or No valves required 2) Raw Water Storage Reservoir (RWSR) FCV-436, FCV-437 1 of 2 valves required for RWSR; manually operated for AFW supply, if required 3) RWSR system manual valves 0-1557, 0-280, 1-121, 1-159, 1-180 Manually align valves when transferring to RWSR 3. Residual Heat Removal System(a) a. Residual heat removal (RHR) pumps 1-1 and 1-2 1 of 2 pumps required b. RHR heat exchangers (HX) 1-1 and 1-2 1 of 2 HX required c. RHR valves: HCV-670, RHR HX Bypass Valve required HCV-637, HCV-638, RHR to cold leg loop 1 of 2 valves required 8726A, 8726B, RHR HX Bypass 1 of 2 valves required d. RHR heat sink: Component cooling water (CCW) system See Item 5 Auxiliary saltwater (ASW) system See Item 6 (a) Components of RHR system are required for COLD SHUTDOWN (credit is taken for manual alignment of the RHR System to ensure postfire safe shutdown capability).
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-1 (UNIT 1) Sheet 3 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS e. RHR valves 8701 and 8702, Loop 4 Recirculation to RHR 1 of 2 required to maintain reactor coolant pressure boundary during HOT STANDBY (HSB) Both valves can be manually opened for COLD SHUTDOWN (CSD); valves' power breakers are normally open at the motor control center f. 8707 RHR pumps suction relief valve Required for overpressure protection when RHR System is in service g. 8808A, 8808B, 8808C, 8808D Accumulator outlet valve to cold leg Valves required closed in transition from HSB to CSD Can be manually closed h. System components considered for spurious operation: FCV-641A, FCV-641B, RHR pump recirc Spurious Operation Only Valve 8703, Loops 1 & 2 RHR injection Spurious operation only; valve power breaker is normally open at the motor control center 8700A, 8700B, RHR Pump Suction Spurious Operation Only 8716A, 8716B, RHR HX return to loops Spurious Operation Only 8804B, RHR HX 1-2 to SI Pump Suction Spurious Operation Only 8809A, 8809B, Cold leg RHR injection Spurious Operation Only 4. Charging and Boration a. Centrifugal charging pumps 1-1 , 1-2, and 1-3 1 of 3 pumps required b. Charging pump (CCP1 and 2) cooling: CCW system See Item 5 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-1 (UNIT 1) Sheet 4 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS ASW system See Item 6 c. Centrifugal charging pump 1-1 and charging 1-2 auxiliary lube oil pumps. Only utilized to start pumps; can be bypassed d. Borated Water Source - Flowpath to Charging Pumps Either the RWST or BAST flowpath will provide adequate boration capability 1) Using boric acid storage tanks: Boric acid storage tanks 2 of 2 tanks (and manual crosstie valve 8476) required Boric acid transfer pumps 1 of 2 pumps required. Valve 8104 Manual valve 8471 and FCV-110A can be used as redundant flowpaths 8460A, 8460B, BA transfer pump discharge 1 of 2 required 2) Using refueling water storage tank: The VCT may initially be used for RCS makeup prior to alignment of RWST Valves 8805A, 8805B 1 of 2 valves required open LCV-112B, LCV-112C, VCT isolation 1 of 2 valves required closed e. Flowpath to RCS: 1 flowpath required FCV-128 Required for CCPs if using RCP seals or regenerative heat exchanger flowpath 1) Through the Regenerative Heat Exchanger: HCV-142, 8107, and 8108 Valves required for flowpath DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-1 (UNIT 1) Sheet 5 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS 8146, 8147 1 of 2 valves required open for charging; both valves required closed for auxiliary spray 8145, 8148 1 of 2 valves required for auxiliary spray (for RCS pressure reduction in the transition from HSB to CSD); spurious auxiliary spray is also considered 2) RCP Seal injection flowpath: 8121, RCP Seal Water Relief Valve Provides relief path if seal return is isolated 8384A, 8384B, 8396A (RCP seal injection filter isolation valves) Manually close valves to isolate seal injection and seal return 3) Charging injection flowpath: 8801A, 8801B 1 of 2 valves required 8803A, 8803B 1 of 2 valves required f. System components considered for spurious operation: 8166, 8167, HCV-123, excess letdown HX inlet isolation Spurious Operation Only 8149A, 8149B, 8149C, LCV-459, LCV-460 letdown isolation Spurious Operation Only 8105, 8106, Centrifugal charging pump recirculation line isolation Spurious Operation Only FCV-110B, FCV-111B, boric acid Blender outlet valves Spurious Operation Only HCV-104, HCV-105, boric acid transfer pump recirculation Spurious Operation Only DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-1 (UNIT 1) Sheet 6 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS
- g. Components considered for spurious operation 8804A, Charging pump suction header Spurious operation only Containment Spray Pumps 1-1 and 1-2 and associated discharge valves 9001A and 9001B Spurious operation only SI Pumps 1-1 and 1-2 Spurious operation only 9003A, 9003B, RHR Pumps to Containment Spray Ring Header Isolation Spurious operation only 8982A, 8982B, Containment Recirc Sump Isolation Spurious operation only; valves are normally closed/power removed FT-128, Charging header flow PT-142, Charging header pressure FT-134, Letdown Hx flow LT-112, VCT level LT-920, RWST level Diagnostic instruments to assist with spurious operation response 5. Component Cooling Water System a. CCW pumps 1-1, 1-2, and 1-3 1 of 3 pumps required b. CCW heat exchangers 1-1, 1-2 and surge tank 1-1 1 of 2 HX required; surge tank required c. CCW valves: FCV-430, FCV-431, CCW supply headers1 of 2 valves required FCV-364, FCV-365, RHR HX CCW Outlet 1 of 2 valves required for RHR system cooling; valves required for COLD SHUTDOWN; manual operation assumed in event of failure of remote control d. CCW pumps 1-1, 1-2, 1-3, auxiliary lube oil pumps Only required to start CCW pump; can be bypassed DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-1 (UNIT 1) Sheet 7 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS
- e. CCW heat sink: ASW system See Item 6 f. System components considered for spurious operation: FCV-355, FCV-356, FCV-357, FCV-750, CCW Header "C" and RCP thermal barrier HX valves Spurious Operation Only FT-65, FT-68, FT-79, CCW header flow PT-5, PT-6, CCW Hx Diff. Pressure Diagnostic instruments to assist with spurious operation response 6. Auxiliary Saltwater System a. Auxiliary saltwater (ASW) pumps 1-1, 1-2 1 of 2 pumps required b. ASW valves: FCV-602, FCV-603, ASW to CCW HX inlet loop 1 of 2 valves required c. ASW cross connect valves FCV-495, FCV-496 Evaluated for ASW boundary isolation d. System components considered for spurious operation:
FCV-601, ASW gates 1-8 and 1-9 Spurious Operation Only; power removed to ASW gates during normal operation 7. Main Steam System a. 10 percent atmospheric dump valves: PCV-19, PCV-20, PCV-21, PCV-22 1 of 4 valves required for cooldown; backup to 10 percent steam relief valves provided by main steam code safety valves b. Steam generator blowdown inboard isolation valves: FCV-760, FCV-761, FCV-762, FCV-763 Required to close to maintain water inventory for safe shutdown DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-1 (UNIT 1) Sheet 8 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS FCV-244 and FCV-160, FCV-246 and FCV-157, FCV-248 and FCV-154, FCV-250 and FCV-151 Required to close only if above steam generator blowdown FCVs fail to close c. FCV-41, FCV-42, FCV-43, FCV-44 All four MSIVs required to close to maintain steam generator water inventory d. System process line boundary valves considered for spurious operation: FCV-22, FCV-23, FCV-24, FCV-25 Spurious Operation Only 8. Instrumentation a. Steam generator level: SG 1-1: LT-516(a) , LT-517, LT-518, LT-519 SG 1-2: LT-526(a), LT-527, LT-528, LT-529 SG 1-3: LT-536(a), LT-537, LT-538, LT-539 SG 1-4: LT-546(a), LT-547, LT-548, LT-549 1 steam generator required for cooldown; 1 of 4 level transmitters required per steam generator b. Steam generator pressure: Loop 1: PT-514, PT-515, PT-516, PI-518 Loop 2: PT-524, PT-525, PT-526, PI-528 Loop 3: PT-534, PT-535, PT-536, PI-538 Loop 4: PT-544, PT-545, PT-546, PI-548 1 steam generator required for cooldown; 1 of 4 instruments required for that loop (a) Cold calibrated DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-1 (UNIT 1) Sheet 9 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS
- c. Reactor coolant system temperature: Loop 1: TE-413A, TE-413B Loop 2: TE-423A, TE-423B Loop 3: TE-433A, TE-433B Loop 4: TE-443A, TE-443B 1 loop required for cooldown; hot leg and cold leg temperature indication required for that loop d. Reactor coolant system pressure: PT-403, PT-405, PT-406 1 of 3 wide-range PTs required e. Pressurizer level: LT-459, LT-460, LT-461, LT-406(a) 1 of 4 required f. Source range flux monitors: NE-31, NE-32, NE-51, NE-52 1 of 4 required g. Boric Acid Storage Tank Level: LT-102, LT-106 1 of 2 required; tank level can be monitored locally if required h. Condensate Storage Tank Level: LT-40 AFW pump suction can be aligned to RWSR if CST inventory is depleted 9. Ventilation for Safe Shutdown Equipment a. 480 V switchgear room and inverter room supply and exhaust fans S-43, FCV-5045, S-44, FCV-5046, E-43, and E-44 (b) b. 4.16kV switchgear room supply fans S-67, S-68, S-69 Safe shutdown will not be adversely affected by loss of these fans c. ASW pump room exhaust fans E-101, E-103 1 of 2 required (a) Cold calibrated. Apply temperature correction to indicated level when using this transmitter in the hot condition. (b) Portable fans, powered by gas driven electric generators, can be used in the event that permanent ventilation fans are unavailable due to fire. These fans are to be used in accordance with post-fire safe shutdown procedure CP M-10. These fans can also be used in the unlikely event of a loss of control room ventilation.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-1 (UNIT 1) Sheet 10 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS 10. Reactor Coolant System a. Pressurizer power-operated relief valves PCV-455C, 474, 456 and block valves 8000A, B, and C Required to prevent LOCA due to stuck-open valve. PORV's PCV-455C and PCV-456 can also be used for RCS pressure reduction in the transition from HSB to CSD; backup for RCS overpressure protection is provided by pressurizer code safety valves b. System components considered for spurious actuation: PCV-455A, PCV-455B Spurious Operation Only 8078A, 8078B, 8078C, 8078D Spurious Operation Only c. Reactor Coolant Pumps Ability to trip RCPs is evaluated to prevent unacceptable RCP seal damage or spurious normal spray d. Pressurizer Heaters 1-1, 1-2, 1-3, and 1-4 All heater groups are evaluated for spurious operation; vital groups 1-2 and 1-3 are evaluated as an "operational convenience" to support safe shutdown DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-2 (UNIT 2) Sheet 1 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS
- 1. Emergency Power Supply a. Diesel generators 2-1, 2-2, 2-3 and associated equipment 2 of 3 diesel generators required; Offsite power (nonalternate shutdown areas only) b. Diesel fuel oil transfer pumps 0-1, 0-2 1 of 2 pumps required c. Day tank level control valves: 1 of 2 LCVs per day tank required LCV-85, LCV-88 LCV-86, LCV-89 LCV-87, LCV-90 d. Vital batteries 2 of 3 required e. Vital Battery chargers 2 of 5 required f. Vital ups 2 of 4 channels required g. 4kV Vital switchgear 2 of 3 required h. Vital DC distribution panels 2 of 3 required i. 480 V Vital switchgear 2 of 3 required j. Vital instrument ac distribution panels 2 of 4 panels required k. Fuel oil storage tanks TK 0-1 and TK 0-2 1 of 2 required
- l. Startup transformers 2 of 2 required
- m. 12kV Startup Bus 1 required 2. Auxiliary Feedwater System a. Auxiliary feedwater (AFW) pumps: turbine-driven AFW pump 2-1 and motor-driven AFW pumps 2-2 and 2-3 1 of 3 pumps required. b. AFW pump turbine steam isolation valve: Applicable only to AFW pump 2-1 FCV-95, FCV-152, FCV-15 Required for AFW pump 2-1 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-2 (UNIT 2) Sheet 2 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS FCV-37, FCV-38 Spurious operation only; 1 of 2 valves required for AFW pump 2-1 c. SG AUX Feedwater supply: Pump 2-1: LCV-106, LCV-107, LCV-108, and LCV-109 1 of 4 valves required for pump 2-1 Pump 2-2: LCV-110, LCV-111 1 of 2 valves required for pump 2-2 Pump 2-3: LCV-113, LCV-115 1 of 2 valves required for pump 2-3 d. Water supply and associated valves: 1) Condensate storage tank, or No valves required 2) Raw Water Storage Reservoir (RWSR) FCV-436, FCV-437 1 of 2 valves required to be manually operated for RWSR 3) RWSR system manual valves 0-1557, 0-280, 1-121, 1-159, 1-180 Manually align valves when transferring to RWSR 3. Residual Heat Removal System(a)
- a. Residual heat removal (RHR) pumps 2-1 and 2-2 1 of 2 pumps required b. RHR heat exchangers 2-1 and 2-2 1 of 2 HX required c. RHR valves: HCV-637, HCV-638, RHR to cold leg loop 1 of 2 valves required HCV-670, RHR HX Bypass Valve required 8726A, 8726B, RHR HX Bypass 1 of 2 valves required d. RHR heat sink: Component cooling water (CCW) system See Item 5 Auxiliary saltwater (ASW) system See Item 6 (a) Components of RHR system are required for COLD SHUTDOWN only (Credit is taken for manual alignment of the RHR system to ensure postfire safe shutdown capability).
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-2 (UNIT 2) Sheet 3 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS e. RHR valves 8701 and 8702, hot leg RHR suction 1 of 2 required to maintain reactor coolant pressure boundary during HSB; both valves can be manually opened for CSD; valve power breakers are normally open at the motor control center f. 8707, RHR pump suction relief valve Required for overpressure protection when RHR system is in service g. 8808A, 8808B, 8808C, 8808D Accumulator outlet valve to cold leg Valves required closed in transition from HSB to CSD; can be manually closed h. System components considered for spurious operation: FCV-641A, FCV-641B, RHR pump recirc Spurious Operation Only Valve 8703, loops 1 and 2 RHR injection Spurious Operation Only; valve power circuit is normally racked out at the motor control center 8700A, 8700B, RHR Pump Suction Spurious Operation Only 8716A, 8716B, RHR HX return to loops Spurious Operation Only 8804B, RHR HX 2-2 to SI Pump Suction Spurious Operation Only 8809A, 8809B, cold leg RHR injection Spurious Operation Only 4. Charging and Boration a. Centrifugal charging pumps 2-1, 2-2, and 2-3 1 of 3 pumps required b. Charging pump cooling: CCW system See Item 5 ASW system See Item 6 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-2 (UNIT 2) Sheet 4 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS
- c. Centrifugal charging pumps 2-1 and 2-2, auxiliary lube oil pumps Only utilized to start charging pumps; can be bypassed d. Borated water source to charging pumps Either the RWST or BAST flowpath will provide adequate boration capability 1) Using boric acid storage tanks: Boric acid storage tanks 2 of 2 tanks and manual cross-tie valve 8476 required Boric acid transfer pumps 1 of 2 pumps required Valve 8104 Manual valve 8471 and FCV-110A can be used as redundant flowpath 8460A, 8460B, BA transfer pump discharge 1 of 2 required OR 2) Using refueling water storage tank: The VCT may initially be used for RCS makeup prior to alignment of RWST Valves 8805A and 8805B 1 of 2 valves required open Valves LCV-112B and LCV-112C, VCT Isolation 1 of 2 valves required closed e. Flowpath to RCS: 1 flowpath required FCV-128 Required for CCPs if using RCP seals or regenerative heat exchanger flowpath 1) Regenerative heat exchanger flowpath: HCV-142, 8107, and 8108 Valves required for flowpath DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-2 (UNIT 2) Sheet 5 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS 8146, 8147 1 of 2 valves required open for charging; both valves required closed for auxiliary spray 8145, 8148 1 of 2 valves required for auxiliary spray (for RCS pressure reduction in transition from HSB to CSD);
spurious auxiliary spray is also considered 2) RCP seal injection flowpath: 8121, RCP Seal Water Relief Valve Provides relief path if seal return is isolated 8384A, 8384B, 8396A (RCP seal injection filter isolation valves) Manually close valves to isolate seal injection and seal return 3) Charging injection flowpath: 8801A, 8801B 1 of 2 valves required 8803A, 8803B 1 of 2 valves required f. System components considered for spurious operation: 8166, 8167, HCV-123, excess letdown HX inlet isolation Spurious Operation Only 8149A, 8149B, 8149C, LCV-459, LCV-460 letdown isolation Spurious Operation Only 8105, 8106, Centrifugal charging pump recirculation line isolation Spurious Operation Only FCV-110B, FCV-111B, boric acid blender outlet valves Spurious Operation Only HCV-104, HCV-105, boric acid transfer pump recirculation Spurious Operation Only 8804A, Charging pump suction header Spurious Operation Only DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-2 (UNIT 2) Sheet 6 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS Containment Spray Pumps 2-1 and 2-2 and associated discharge valves 9001A and 9001B Spurious Operation Only SI Pumps 2-1 and 2-2 Spurious Operation Only 9003A, 9003B, RHR Pumps to Containment Spray Ring Header Isolation Spurious Operation Only 8982A, 8982B, Containment Recirc Sump Isolation Spurious Operation Only; valves are normally closed with power removed FT-128, Charging header flow PT-142, Charging header pressure FT-134, Letdown Hx flow LT-112, VCT level LT-920, RWST level Diagnostic instruments to assist with spurious operation response 5. Component Cooling Water System a. CCW pumps 2-1, 2-2, and 2-3 1 of 3 pumps required b. CCW heat exchangers 2-1, 2-2, and surge tank 2-1 1 of 2 HX required Surge tank required c. CCW valves: FCV-430, FCV-431, CCW supply headers1 of 2 valves required FCV-364, FCV-365, RHR HX CCW outlet 1 of 2 valves required for RHR system cooling; valves required for COLD SHUTDOWN; manual operation assumed in event of failure of remote control
- d. CCW pumps 2-1, 2-2, 2-3, auxiliary lube oil pumps
Only required to start CCW pump; can be bypassed DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-2 (UNIT 2) Sheet 7 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS
- e. CCW heat sink: ASW system See Item 6 f. System components considered for spurious operation: FCV-355, FCV-356, FCV-357, FCV-750, CCW Header C and RCP thermal barrier HX valves. Spurious Operation Only FT-65, FT-68, FT-79, CCW header flow PT-5, PT-6, CCW Hx Diff. Pressure Diagnostic instruments to assist with spurious operation response 6. Auxiliary Saltwater System a. Auxiliary saltwater (ASW) pumps 2-1, 2-2 1 of 2 pumps required b. ASW valves: FCV-602, FCV-603, ASW to CCW HX inlet loop 1 of 2 valves required c. ASW cross connect valves FCV-495, FCV-496 Evaluated for ASW boundary isolation d. System components considered for spurious operation: ASW Gates 2-8 and 2-9, FCV-601 Spurious Operation Only; power removed to ASW gates during normal operation 7. Main Steam System a. 10 percent atmospheric dump valves PCV-19, PCV-20, PCV-21, PCV-22 1 of 4 valves required for cooldown; backup to 10 percent steam relief valves provided by main steam code safety valves DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-2 (UNIT 2) Sheet 8 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS
- b. Steam generator blowdown inboard isolation valves: FCV-760, FCV-761 FCV-762, and FCV-763 Required to close to maintain water inventory for safe shutdown FCV-244 and FCV-160, FCV-246 and FCV-157, FCV-248 and FCV-154, FCV-250 and FCV-151 Required to close only if above steam generator blowdown FCVs fail to close c. FCV-41, FCV-42, FCV-43, FCV-44 All four MSIVs required closed to maintain SG water inventory d. System component considered for spurious operation: FCV-22, FCV-23, FCV-24, FCV-25 Spurious Operation Only 8. Instrumentation a. Steam generator level SG 2-1: LT-516(a), LT-517, LT-518, LT-519 SG 2-2: LT-526(a), LT-527, LT-528, LT-529 SG 2-3: LT-536(a), LT-537, LT-538, LT-539 SG 2-4: LT-546(a), LT-547, LT-548, LT-549 1 steam generator required for; cooldown 1 of 4 level transmitters required per steam generator b. Steam generator pressure:
Loop 1: PT-514, PT-515, PT-516, PI-518 Loop 2: PT-524, PT-525, PT-526, PI-528 Loop 3: PT-534, PT-535, PT-536, PI-538 Loop 4: PT-544, PT-545, PT-546, PI-548 1 steam generator required for cooldown; 1 of4 instruments required for that loop (a) Cold calibrated. Apply temperature correction to indicated level when using these transmitters in the hot condition. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-2 (UNIT 2) Sheet 9 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS
- c. Reactor coolant system temperature:
Loop 1: TE-413A, TE-413B Loop 2: TE-423A, TE-423B Loop 3: TE-433A, TE-433B Loop 4: TE-443A, TE-443B 1 loop required for cooldown; hot leg and cold leg temperature indication required for that loop d. Reactor coolant system pressure: PT-403, PT-405, PT-406 1 of 3 wide-range PTs required e. Pressurizer level: LT-459, LT-460, LT-461, LT-406(a) 1 of 4 required f. Source range flux monitors: NE-31, NE-32, NE-51, NE-52 1 of 4 required g. Boric acid storage tank level: LT-102, LT-106 1 of 2 required tank level can be monitored locally if required h. Condensate storage tank level: LT-40 AFW pump suction can be aligned to RWSR if CST inventory is depleted 9. Ventilation for Safe Shutdown Equipment a. 480V switchgear room and inverter room supply and exhaust fans S-45, FCV-5045, S-46, FCV-5046, E-45, and E-46 (b) b. 4.16kV switchgear room supply fans S-67, S-68, S-69 Safe shutdown will not be adversely affected by loss of these fans c. ASW pump room exhaust fans E-102 and E-104 1 of 2 required (a) Cold Calibrated. Apply temperature correction to indicated level when using this transmitter in the hot condition. (b) Portable fans, powered by gas driven electric generators, can be used in the event that permanent ventilation fans are unavailable due to fire. These fans are to be used in accordance with post-fire safe shutdown procedure CP M-10. These fans can also be used in the unlikely event of a loss of control room ventilation. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 9.5G-2 (UNIT 2) Sheet 10 of 10 Revision 20 November 2011 SYSTEM AND ACTIVE COMPONENTS REDUNDANCY/COMMENTS 10. Reactor Coolant System a. Pressurizer power operated relief valves PCV-455C, 474, 456 and block valves 8000A, B, and C. Required to prevent LOCA due to stuck-open valve; PORVs PCV-455C and PCV-456 can be used for RCS pressure reduction in the transition from HSB to CSD; backup for RCS overpressure protection is provided by pressurize code safety valves b. System components considered spurious actuation: PCV-455A, PCV-455B Spurious Operation Only 8078A, 8078B, 8078C, 8078D Spurious Operation Only c. Reactor Coolant Pumps Ability to trip RCPs is evaluated to prevent unacceptable RCP seal damage or spurious normal spray d. Pressurizer Heaters 2-1, 2-2, 2-3 and 2-4 All heater groups for spurious operation; vital groups 2-2 and 2-3 evaluated as an "operational convenience" to support safe shutdown
DCPP UNITS 1 & 2 FSAR UPDATE
APPENDIX 9.5H INSPECTION AND TESTING REQUIREMENTS AND PROGRAM ADMINISTRATION DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-i Revision 21 September 2013 APPENDIX 9.5H INSPECTION AND TESTING REQUIREMENTS AND PROGRAM ADMINISTRATION TABLE OF CONTENTS Title Page SCOPE 9.5H-1 ORGANIZATION 9.5H-1
A. Administrative Responsibilities 9.5H-1 B. Fire Brigade Organization and Responsibilities 9.5H-3
SPECIAL CONSIDERATIONS 9.5H-5
A. License Requirements 9.5H-5 B. Notification of Insurance Carrier 9.5H-5 C. Fire Rated Assemblies 9.5H-5 D. Welding, Cutting, Grinding, and Brazing 9.5H-6 E. Combustible Materials in Safety-Related Areas 9.5H-6 F. Solvent Cleaning 9.5H-6
TRAINING 9.5H-7
A. All Plant Employees 9.5H-7 B. Fire Brigade Training 9.5H-7
FIRE EQUIPMENT INSPECTION AND MAINTENANCE 9.5H-9
IMPLEMENTING FIRE PROGRAM PROCEDURES 9.5H-9 FIRE PROTECTION OPERABILITY AND SURVEILLANCE REQUIREMENTS 9.5H-11
DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-1 Revision 21 September 2013 APPENDIX 9.5H INSPECTION AND TESTING REQUIREMENTS AND PROGRAM ADMINISTRATION SCOPE The purpose of the "Fire Protection Program" is to provide assurance through a defense-in-depth approach that a fire at the plant will not seriously endanger the safety of personnel, will not cause an unacceptable loss of property, will not prevent the performance of necessary safe shutdown functions and will not significantly increase the risk of radioactive releases to the environment. The "Fire Protection Program" consists of the utilization of fire resistive materials where feasible, fire detection and extinguishing systems and equipment, administrative controls and procedures and trained emergency response personnel." ORGANIZATION A. Administrative Responsibilities 1. The President of PG&E has overall responsibility for the fire protection program. Direct authority for implementing the program is delegated through the company line organization to the director in direct charge of the company facility. 2. The Senior Vice President, Chief Nuclear Officer, is responsible for implementing and maintaining in effect all provisions of the approved fire protection program for DCPP as required by the facility operating licenses. 3. The Site Vice President is responsible for overall safe operation of the plant and has control over onsite activities necessary for safe operation and maintenance of the plant including fire protection. 4. The Senior Director, Engineering Services and Projects, is responsible for:
- establishment of all technical and quality classification requirements for engineering and design of fire protection structures, systems, and components, including changes and modifications.
- maintenance of Chapter 9, Section 5.1 of the FSAR.
- assignment of qualified Fire Protection Engineers for review and acceptance of fire protection related design changes.
- maintenance of the technical bases for Fire Hazards Appendix R Evaluations (FHAREs)
DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-2 Revision 21 September 2013
- Initiating follow-up actions as necessary to correct identified deficiencies.
- Fire Protection matters with insurance company inspectors. 5. The Director - Quality Verification, is responsible for ensuring audits of the Fire Protection Program are conducted in accordance with license requirements.
- 6. The Station Director has the ultimate responsibility for the Diablo Canyon Fire Protection Program. The Station Director is responsible for:
- Implementation of the Fire Loss Prevention Program.
- The day-to-day coordination of the Fire Protection Program. 7. The Director - Operations Services is responsible for the implementation of the Plant Fire Brigade Program, including the training and administration of the Plant Fire Brigade as conducted by the Supervisor - Fire Protection. 8. The Supervisor - Fire Protection is responsible for:
- Ensuring the shift fire brigade complement is available for emergency response.
- The day to day coordination, management, and implementation of the Fire Brigade Program, including fire brigade training.
- Life Safety Program.
- Pre-fire planning.
- Site emergency responses for fires, hazardous materials, medical, and rescues.
- Plant interface with state and county fire codes, company departments for life/safety code compliance, regulators, and the California Department of Forestry and Fire.
- Monitoring fire prevention programs, including the control of ignition sources and adherence to Plant Administrative procedures. 9. Plant department heads and supervisors are required to ensure that the surveillance, testing and administrative fire protection procedures for which they are responsible are implemented and that their department personnel attend required fire protection and fire safety training.
DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-3 Revision 21 September 2013 10. The Shift Supervisor and Shift Foreman are responsible to monitor the operability of the plant fire protection system and to ensure that all appropriate compensatory measures have been implemented in accordance with the ECG for the systems or portions of systems which have been declared inoperable. The Shift Foreman is also responsible for the approval, extension or revocation of Weld Permits in the absence of a member of Fire Protection. 11. The Fire Brigade Leader is responsible to direct the fire fighting efforts at the scene of the fire and has the authority to order plant personnel to assist in fighting a fire. 12. Plant fire brigade members are required to participate in all aspects of the Fire Brigade Training Program and ensure all training requirements are kept current. They shall respond in a safe and timely fashion to all fire alarms and cooperate with offsite fire fighting agencies to extinguish site fires. 13. It is the responsibility of all plant employees to immediately report all fires, assist Fire brigade personnel as directed in a fire fighting effort, report all fire hazards to their supervisor, work safely and in such a manner as not to create a fire hazard and to be acquainted with the use and location of emergency equipment. B. Fire Brigade Organization and Responsibilities 1. There is one Fire Brigade on each shift providing continuous response capability. The Fire Brigade personnel may have no other fire emergency responsibilities that would prevent them from performing Fire Brigade duties. 1 Leader Fire Brigade Leader Qualified 4 Crew Members Fire Brigade Member Qualified
Note: The Fire Brigade Leader is a member of the Fire Brigade and has been specifically trained as a Fire Brigade Leader and designated as such by the Supervisor - Fire Protection. A qualified Nuclear Operator or Licensed Operator will accompany the Fire Brigade Leader in all emergency responses, unless the Nuclear Operator or Licensed Operator is the Fire Brigade Leader.
- 2. Site Emergency Coordinator's (SEC) responsibilities include:
- a. Dispatching the Fire Brigade to the scene of a fire emergency.
- b. Dispatching additional personnel to the scene of the fire as requested by the Fire Brigade Leader.
- c. Shutdown of fire affected or sensitive equipment.
DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-4 Revision 21 September 2013 d. Modifying ventilation as required by the fire emergency.
- e. De-energizing affected equipment.
- f. Requesting assistance from the San Luis Obispo County Fire Department/California Department of Forestry (CDF) if required.
- g. Notifying site Security in the event that outside assistance is required.
- h. Notifying the System Dispatcher if unit load is affected.
- i. Notifying persons required by plant emergency procedures.
- 3. The Fire Brigade Leader's responsibilities are:
- a. Command at the scene of the fire emergency.
- b. Safely coordinate the fire attack by the Fire Brigade and account for personnel.
- c. Establish a communication link between the scene of the fire emergency and the SEC.
- d. Advise the SEC of the need for assistance.
- e. During occasions when offsite professional fire fighting assistance is required the Brigade Leader is encouraged to rely heavily on the recommendations and expertise of these professionals. The ultimate responsibility and authority at the scene, however, remains that of the Brigade Leader.
- 4. All Fire Brigade member's responsibilities are:
- a. To participate in the training and drill exercises scheduled for the brigade.
- b. To respond in a safe and timely manner to all fire alarms.
- c. To assist offsite fire fighting personnel with extinguishment of onsite fires.
- d. To be particularly alert of fire hazards and take immediate action to get them corrected.
DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-5 Revision 21 September 2013 5. Fire Detection by plant personnel
- a. Reporting of fires takes precedence over fighting a fire. Only personnel who are trained in the use of fire fighting equipment may attempt to suppress a fire.
- b. Fires can be reported automatically by the fire alarm signal system or manually by plant personnel by calling the control room or using a radio to contact the control room. SPECIAL CONSIDERATIONS A. License Requirements Operating License Condition 2.C(4) and 2.C(5) for Units 1 and 2, respectively, require PG&E to maintain the approved Fire Protection Program. Changes can be made to the approved program without NRC approval provided the changes do not affect the ability to achieve and maintain safe shutdown requirements.
Certain portions of the fire protection system are required by the license to be operable. Prior to removing any portion(s) of the various fire protection systems from operation or upon discovering that a portion is inoperable, the Shift Supervisor or Shift Foreman shall be notified and a clearance request or other appropriate document submitted in accordance with the plant fire system impairment reporting system. Operability of fire protection systems are controlled by Equipment Control Guidelines (ECGs). Amendments 75 and 74 of the Unit 1 and Unit 2 Operating License, respectively, relocated the fire protection details of the DCPP Technical Specifications (TS) into this Appendix and into the administratively controlled ECGs (see Chapter 16 of this FSAR Update). As a result, this Appendix provides the basis for the administratively controlled fire protection plan ECGs. The list of ECGs is located in the section entitled "Fire Protection Operability And Surveillance Requirements" of this Appendix. Administrative Procedures provide guidance in the handling and documenting of impairments. B. Notification of Insurance Carrier The insurance carrier shall be informed of impairments to the fire system in accordance with the plant fire system impairment reporting system. The Insurance Department shall also be informed of fire incidents at the plant. C. Fire Rated Assemblies 1. Fire rated assemblies are defined as steel doors and their associated hardware, electrical and mechanical penetration seals, fire rated enclosures DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-6 Revision 21 September 2013 around safe shutdown circuits, credited cable tray fire stops, and ventilation dampers which provide the equivalent fire rating as the penetrated barrier (walls, floors, ceilings).
- 2. Fire Rated Assemblies governed by 10 CFR 50, Appendix R are controlled by ECG 18.7.1. Fire Rated Assemblies governed by BTP 9.5-1, Appendix A are controlled by 18.7.2. In accordance with ECG 18.7.1 and ECG 18.7.2, a fire watch is to be provided during the period the fire barrier is open or not functional, as required by the plant license and fire system impairment reporting system. 3. Temporary fire barrier penetration sealing material may be used until the permanent barriers have been installed and visually inspected to assure they are functional. However, this does not replace fire watch requirements. D. Welding, Cutting, Grinding, and Brazing Welding, cutting, grinding or brazing will be performed in accordance with the provisions of plant administrative procedures. E. Combustible Materials in Safety-Related Areas 1. Use of combustibles in safety-related areas is to be strictly controlled and is the responsibility of the area or work supervisor. Specific controls are delineated in plant procedures. 2. During refueling and maintenance operations, fire retardant and noncombustible materials should be used where practicable.
- 3. Smoking is strictly prohibited in the building and structures within the protected areas and in areas where "No Smoking" signs are posted. F. Solvent Cleaning 1. "No Smoking" signs shall be posted in the immediate area where solvent cleaning is performed and where other work involves open exposure of flammable liquid or gas.
- 2. Solvent cleaning with flammable liquids, when possible, should be done out of doors with maximum ventilation available and a portable fire extinguisher in the immediate area.
- 3. Safety solvents should be used in lieu of more flammable solvents where practicable.
DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-7 Revision 21 September 2013 TRAINING A. All Plant Employees Plant utility employees shall receive initial site specific fire protection training through General Employee Training or similar instruction delivery methods. This training shall include a discussion of the "Fire Protection Program," reporting of fires, fire prevention techniques and use of extinguishing agents. Special training programs for fire watch and other emergency response personnel shall be conducted as required prior to assignment to those positions. B. Fire Brigade Training The Supervisor - Fire Protection is responsible for the content of the Fire Brigade Training Program. All members are trained to a level of competency commensurate with the duties expected to be performed.
- 1. General
Federal and State Regulations require periodic training of Fire Brigade members. The training program utilizes classroom instruction, practice in fighting typical fires, and fire drills. Training is conducted on a continuing basis. Training sessions are designed such that all areas are completed every two years for Fire Brigade members.
- 2. Classroom Instructions The classroom instruction program includes:
- a. Identification of major fire hazards, locations of these hazards, and the type of fire with which each hazard is associated. b. Fire extinguishing agents best suited for controlling the fires, identification of the location of fire fighting equipment and familiarization with the plant layout including access and egress routes. c. The proper use of fire fighting equipment and the correct method of fighting the various types of fires which are likely to occur. d. Instruction in the Fire Protection Program including the direction and coordination of the fire fighting activities and individual responsibilities. e. The types of toxic characteristics of expected products of combustion from typical fires which can occur. f. The proper method for fighting fires in various plant locations including confined spaces.
DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-8 Revision 21 September 2013 g. Fire fighting procedures and strategies including recent changes. h. Plant modifications that have a significant impact on fire protection. i. Personnel rescue operations. j. The proper use of communication, lighting, ventilation and emergency breathing apparatus. k. The direction and the coordination of fire fighting activities (Fire Brigade Leaders only).
- 3. Fire Brigade Drills
- a. Fire Brigade drills are conducted quarterly for each Fire Brigade. b. The drills are conducted on the plant site in areas containing significant fire hazards where similar fires of that type, size and arrangement could reasonably occur. c. Drills are conducted so that each Fire Brigade member can participate. Each Brigade member should participate in at least one drill per year. d. At least one drill per year for each Fire brigade is performed on a back-shift. e. At least one drill per year for each Fire Brigade is unannounced. f. Drills will be observed by supervisory personnel to:
(1) Assess the effectiveness of the notification systems and times for the response of the Fire Brigade and their selection and use of equipment. (2) Assess the individual Fire Brigade member's knowledge of his responsibilities, conformance with established procedures and the use of fire fighting and other emergency equipment to the extent practicable. (3) Assess the Fire Brigade Leader's effectiveness in direction of the fire fighting effort. (4) Assess the overall effectiveness of the drill to determine if the training objectives are being met. DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-9 Revision 21 September 2013 g. Two drills per year shall involve a coordinated response involving the plant Fire Brigade and offsite fire protection agencies.
- 4. Practice Live fire training shall be conducted annually to provide experience in the skills and techniques of bringing fires under control and the use of fire fighting equipment and self-contained breathing apparatus under strenuous fire fighting conditions.
- 5. Minimum Physical Requirements A medical screening evaluation shall be performed annually for each fire Brigade member to identify potential cardiopulmonary deficiencies which may be aggravated by strenuous fire fighting activities. All members of the plant fire Brigade shall meet the medical screening acceptance criteria for respirator users.
- 6. Records and Evaluations Records of the training conducted, classroom instruction attendance and drill participation shall be entered in the DCPP Training Records Program.
Attendance and participation records shall be retained as a minimum for the duration of the individual's employment at DCPP. FIRE EQUIPMENT INSPECTION AND MAINTENANCE To meet the plant license, CAL-OSHA, and insurance carrier requirements, fire equipment for the plant is inspected and maintained on a routine basis. IMPLEMENTING FIRE PROGRAM PROCEDURES The nature of the Fire Protection Program is such that it may affect all plant personnel. As a result, implementing fire program procedures are included in several locations in the Plant Manual.
An informational listing of procedures related to the Fire Protection Program can be found in Design Criteria Memorandum S-18, "Fire Protection System," and T-13, "Appendix R Fire Protection." Some portions of the Plant Manual in which they are found are listed below.
Administrative Procedures Fire Loss Prevention Fire Brigade Training Welding, Cutting and Open Flame DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-10 Revision 21 September 2013 Storage and Handling of Combustible Materials Fire System Impairment Control of Flammable Materials Fire Watch and Welding Personnel Fire Protection Program Administration Operating Procedures Fire Water System Fire Supplement Water System Valve Checklist
Emergency Procedures Control Room Inaccessibility (Establishing Hot Standby and Cold Shutdown) Radiological Fire Non-radiological Fire Fire Protection of Safe Shutdown Equipment
Maintenance Procedures Fire Pump Disassembly, Repair & Reassembly Maintenance and Testing of Portable Fire Extinguishers
Surveillance Test Procedures Routine Shift Checks Fire and Smoke Detector Functional Test Fire Pump Performance Test Routine Surveillance of Fire Pumps Testing of Portable Long Term Cooling Pumps Emergency Lighting and Communication Test CO2 Fire System Operation (High and Low Pressure) Fire Water System Deluge System Functional Test Monthly Fire Valve Inspection Containment Fire Hose Reel and Hydrant Inspection Monthly Hose Reel Inspection Fire Hose Station Functional Test Monthly Fire Extinguisher Inspection Monthly CO2 Hose Reel and Deluge Valve Inspection Inspection of Fire Barrier Penetration Seals Fire Water System Flow Test Main Turbine Bearings, Main FW Pumps & H2 Seal Oil Deluge Fire Hose Gasket Replacement and Re-racking Fire Hose Operability and Hydrostatic Test (Outdoor and Indoor) Exercising Fire Water Sectionalizing Isolation and Supply Valves DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-11 Revision 21 September 2013 SG Loop Narrow Range Local Level Indicators PORV Emergency Close Switch at HSP RHR Pump Control Transfer Switch Centrifugal Charging Pump CCP3 Operability Manual Auxiliary Spray Valves FIRE PROTECTION OPERABILITY AND SURVEILLANCE REQUIREMENTS This section identifies the DCPP fire protection operability and surveillance requirements. These requirements were relocated from the TS by LAR 90-11 into ECGs. ECGs are also provided for equipment credited for Appendix R safe shutdown that are not covered by existing Technical Specifications. As such, this section provides the basis for the administratively controlled fire protection plan ECGs as stated in the License Requirements section of this Appendix. The ECGs associated with the Fire Protection Program and the bases are provided below:
ECG 18.1, "Fire Suppression Systems/Fire Suppression Water Systems" ECG 18.2, "Fire Hose Stations" ECG 18.4, "Spray and/or Sprinkler System" ECG 18.5, "CO2 System" BASIS: The operability (as defined in DCPP Technical Specifications) of the Fire Suppression Systems ensure that adequate fire suppression capability is available to confine and suppress fires occurring in any portion of the facility where safety-related equipment is located. The Fire Suppression System consists of the water system, spray and/or sprinklers, CO2, and firewater hose stations. The collective capability of the Fire Suppression System is adequate to minimize potential damage to safety-related equipment and is a major element in the facility Fire Protection Program. In the event that portions of the Fire Suppression Systems are inoperable, alternate fire fighting equipment is required to be made available in the affected areas until the inoperable equipment is restored to service. When the inoperable fire fighting equipment is intended for use as a backup means of fire suppression, a longer period of time is allowed to provide an alternate means of fire fighting than if the inoperable equipment is the primary means of fire suppression. The surveillance requirements provide assurance that the minimum operability requirements of the Fire Suppression Systems are met. DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-12 Revision 21 September 2013 In the event the Fire Suppression Water System becomes inoperable, prompt corrective measures must be taken since this system provides the major fire suppression capability of the plant. ECG 18.3, "Fire Detection Instrumentation" BASIS: The operability of the detection instrumentation ensures that adequate warning capability is available for prompt detection of fires. This capability is required in order to detect and locate fires in their early stages. Prompt detection of fires will reduce the potential for damage of safety-related equipment and is an integral element in the overall facility Fire Protection Program. In the event that a portion of the fire detection instrumentation is inoperable, the establishment of frequent fire patrols in the affected areas is required to provide detection capability until the inoperable instrumentation is restored to operability. Since the fire detectors installed in the plant are nonseismic, an inspection will be performed following a seismic event to detect any fires. ECG 18.7, "Fire Rated Assemblies" GENERAL BASIS: The functional integrity of the fire rated assemblies and associated penetration seals ensures that fires will be confined or adequately retarded from spreading to adjacent fire areas/zones or from affecting redundant safe shutdown circuits (10 CFR 50, Appendix R), and that safety-related equipment is protected from high fire hazards (BTP 9.5-1, Appendix A). This design feature minimizes the possibility of a single fire rapidly involving several fire areas/zones of the facility prior to detection and extinguishment. The fire rated assemblies and penetration seals are a passive element in the facility Fire Protection Program and are subject to periodic inspections. ECG 18.7.1, "10 CFR 50 APPENDIX R Fire Rated Assemblies" BASIS: Fire Rated Assemblies governed by 10 CFR 50, Appendix R are controlled by ECG 18.7.1. Appendix R fire rated assemblies are used to protect Safe Shutdown equipment from fire hazards. The fire rated assemblies, including fire rated enclosures, penetration seals, fire doors and fire dampers, are considered functional when the visually observed condition is the same as the as-designed configuration. For those fire rated DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-13 Revision 21 September 2013 assemblies that are not in the as-designed configuration, either the appropriate ECG action shall be performed until the fire rated assembly is returned to the as-designed configuration, or an evaluation is performed to show that the as-built configuration has not degraded the capability of the fire rated assembly to prevent the spread of fire from adversely affecting the ability to achieve and maintain safe shutdown conditions (i.e., FHARE). During periods of time when a fire rated assembly is not functional, either (1) a continuous fire watch is required to be maintained in the immediate vicinity of the affected barrier, or (2) the fire detectors or detection capability of the automatic fire suppression system on at least one side of the affected barrier must be verified operable and an hourly fire watch patrol established until the barrier is restored to functional status. Both the fire detectors and automatic fire suppression system provide detection and alarm capability in the control room for early warning of a fire, so that the operators can muster the Fire Brigade. A fire watch is considered continuous if the patrol can monitor the immediate area of the nonfunctional fire rated assembly at least once per 15 minutes or less. Because of existing administrative controls on storage of in-situ and transient combustible materials, hot work permits (ignition sources), and the existence of low combustible loading throughout DCPP and the widely dispersed locations of the combustible materials, it is not expected that a large uncontrolled fire will occur within 15 minutes. A fire watch monitoring the affected area at least once per 15 minutes will accomplish the intent of a continuous fire watch. For penetration seals, an alternate to either the continuous or roving fire watches, a temporary repair may be implemented. A size limitation of 16 square inches of the impaired sealant surface area for any individual gap or void is established based on available testing. An analysis of DCPP fire testing for the use of ceramic blanket and fiber to maintain a fire rated seal has been performed. This compensatory measure is only acceptable as a temporary repair due to the inability to maintain and control this configuration. Penetration seals repaired in accordance with this method shall be tracked and permanently repaired to the as-designed configuration.
For openings in non-combustible enclosures that form part of a fire barrier, an alternate administrative control may be implemented. Non-combustible enclosures are metal conduits, junction boxes, condulets, panels, etc., used for electric cable routing. These enclosures are considered part of fire rated assemblies when they are used in lieu of internal conduits seals (ICS). For open enclosures, the presence of personnel performing work or inspections may be used in lieu of a fire watch. While these individuals may or may not have the fire watch qualification (FIRE1), their presence will ensure that if a fire were to occur, it would be detected in its incipient stage. This administrative control is an alternative to either the continuous or roving fire watch specified in ECG-18.7.1 or ECG 18.7.2. DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-14 Revision 21 September 2013 For fire rated assemblies that do not have fire detection on at least one side of the assembly, use of the portable detection system as an alternate fire detection system is acceptable. Usage of the portable detection system in conjunction with an hourly firewatch does not reduce the effectiveness of existing fire protection capability. ECG 18.7.2, "NRC BRANCH TECHNICAL POSITION (BTP) 9.5-1 APPENDIX A Fire Rated Assemblies" BASIS: Fire Rated Assemblies governed by BTP 9.5-1, Appendix A are controlled by ECG 18.7.2. Appendix A fire rated assemblies include all walls, floor/ceilings, fire rated enclosures, fire doors, fire dampers, hatches, penetration seals (outside containment), and credited cable tray firestops which are used to protect safety related equipment from fire hazards. Appendix A fire rated assemblies are those fire rated assemblies that are not credited to separate redundant safe shutdown equipment and are not required to ensure safe shutdown capability is maintained, but are instead credited to protect safety related equipment from fire hazards. In the event that a fire rated assembly that is necessary for defense-in-depth or to protect safety related equipment from fire hazards becomes INOPERABLE, appropriate compensatory measures per ECG 18.7.2 must be taken while the assembly is being restored to operability or until an evaluation can be made demonstrating that other compensatory measures are not required. The functional integrity of the fire rated assemblies, including penetration seals, ensures that a fire will be confined to its area of origin. This will ensure flames and hot gasses are prevented from spreading to adjacent fire areas/zones, and that safety related equipment is protected from fire hazards (NRC Branch Technical Position (BTP) 9.5-1, Appendix A, "Overall Requirements of Nuclear Plant Fire Protection Program"). These design features minimize the possibility of a single fire rapidly involving several fire areas/zones of the facility prior to detection and extinguishment. Appendix A to BTP 9.5-1 provides the following guidance on "Building Design": Floors, walls, and ceilings enclosing separate fire areas should have minimum fire rating of three-hours. Penetrations in these fire barriers, including conduits and piping, should be sealed or closed to provide a fire resistance rating at least equal to that of the fire barrier itself. Door openings should be protected with equivalent rated doors, frames, and hardware that have been tested and approved by a nationally recognized laboratory. Such doors should be normally closed. DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-15 Revision 21 September 2013 Penetrations for ventilation systems should be protected by a standard "fire door damper" where required. Appendix A fire rated assemblies are used to protect safety related equipment from fire hazards, whereas, Appendix R fire rated assemblies are used to protect Safe Shutdown equipment from fire hazards. As a result, fire propagation across Appendix A fire barriers will not affect the ability to reach safe shutdown conditions. The ECG 18.7.2 ensures that the fire rating of these Appendix A barriers will be maintained. The fire rated assemblies, including walls, floors/ceilings, fire rated enclosures, penetration seals, fire doors, fire dampers, credited cable tray firestops, and hatches are considered functional when the observed condition is the same as the as-designed configuration. For those fire rated assemblies that are not in the as-designed configuration, either the appropriate ECG action shall be performed, until the fire rated assembly is returned to the as-designed configuration, or a documented evaluation of an impaired Appendix A fire rated assembly may be conducted. Because fire rated assemblies applicable to ECG 18.7.2 in and of themselves do not impact the ability to provide adequate separation of redundant trains of safe shutdown systems, impairment of ECG 18.7.2 barriers has limited impact on the ability to achieve and maintain safe shutdown in the event of a fire. However, an evaluation of an ECG 18.7.2 impairment may be completed to assess if an adequate level of defense-in-depth will continue to be provided within the affected fire area, and determine if other compensatory action is not required. The impairment shall still be corrected in a timely fashion. Accordingly, an ECG 18.7.2 Fire Rated Assembly Impairment Evaluation may be performed, considering: escape and access routes; location, quantity, and type of combustible material in the fire area; the presence of ignition sources and their likelihood of occurrence; the automatic fire suppression and fire detection capability in the fire area; the manual fire suppression capability in the fire area; cumulative effects with existing impairments; and the human error probability where applicable. The controls provided by ECG 18.7.2 are based upon maintaining the passive design features as evaluated and accepted by the NRC. The action statements are based upon temporary compensatory measures for degraded barrier features. Removal of a barrier or excessive degradations of a barrier must be evaluated for additional compensatory measures. ECG 4.2, "Steam Generator Level and Pressure Instruments (Appendix R)" BASIS: The local steam generator (SG) level and pressure instruments are electrically independent of the control room/cable spreading room. Therefore, the instruments are protected from the effects of a fire in these rooms that would require shutdown from outside the control room. LT-516, LT-526, LT-536, and LT-546 and their DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-16 Revision 21 September 2013 associated level indicators at the dedicated shutdown panel provide level indication outside of the control room for the SGs. PI-518, PI-528, PI-538, and PI-548 provide pressure indication outside of the control room for the SGs. ECG 7.1, "RCS Instrumentation (Appendix R)" BASIS: LT-406 (LI-406) and PT-406 (PI-406) provide indication of pressurizer level and RCS pressure at the Dedicated Shutdown Panel (DSP). Technical Specifications require indication of these parameters at the Hot Shutdown Panel (HSP); however, these instruments are also required at the DSP following a control room or cable spreading room fire and control room evacuation. ECG 7.2, "PORV Emergency Close Switch at the HSP (Appendix R)" BASIS: The 10 CFR 50 Appendix R safe shutdown analysis takes credit for the operability of PCV-455C or PCV-456 (or pressurizer auxiliary spray valves 8145 or 8148) to achieve cold shutdown in the event of a fire in the plant. In addition, spurious opening of any of the three PORVs due to fire in several fire areas must be either prevented or mitigated by an operator taking manual action to close a PORV using the emergency close switch at the HSP. ECG 8.1, "Centrifugal Charging Pump CCP3" BASIS: This ECG ensures the Units 1 and 2 Centrifugal Charging Pump CCP3 are available to pump at least 55 gpm at 5800 feet (2550 psid) of pump head to the RCS during plant conditions if the centrifugal charging pumps CCP1 and CCP2 were to become inoperable due to fire in the CCP area. In the event of a fire in the CCP rooms, a loss of power to the CCP1 and CCP2 pumps and a loss of control room start to the CCP3 could occur. However, the starting circuit of CCP3 can be bypassed at the switchgear, which is located in another fire area. Hence, CCP3 is not affected by a CCP area fire. The Fire Hazards Analysis concluded that safe shutdown will not be adversely affected by the loss of equipment in the CCP fire area due to the availability of redundant equipment and/or manual actions. The Fire Hazard Analysis also took credit for the following: A. Smoke detection over the charging pumps
B. Automatic wet-pipe sprinkler over the pumps
DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-17 Revision 21 September 2013 C. Manual fire fighting equipment NRC Safety Evaluation Report Supplement 23 found the above an acceptable method of meeting 10 CFR 50, Appendix R requirements. ECG 8.2, "Chemical and Volume Control System Valves (Appendix R)" BASIS: CVCS valves 8145, 8146, 8147 and 8148 are required for auxiliary spray. Auxiliary spray is a credited means of reducing RCS pressure in the transition from Hot Standby to Cold Shutdown for an Appendix R post-fire safe shutdown. The normal (8146) and alternate (8147) charging paths are credited paths for RCS makeup and boration for an Appendix R post-fire safe shutdown. ECG 10.1, "Residual Heat Removal Pump Transfer Switch at 4kV Switchgear (Appendix R)" BASIS: In the event of a fire in the control room/cable spreading room, the capability to start an RHR pump from the 4kV switchgear is required to shutdown the plant. The transfer switch is used to transfer the switchgear to local control and isolate the control room circuitry. ECG 37.1, "Hot Shutdown Panel (HSP) Neutron Flux Indicators (Appendix R)" BASIS: Source range flux indication at the HSP is provided by these instruments in the event of control room/cable spreading room fire and control room evacuation. NE-51 and NE-52 are also credited for post-fire availability for postulated fires outside of the control room or cable spreading room. For the ECGs related to Appendix R safe shutdown equipment, the Allowed Outage Time of 30 days and separate Condition entry are consistent with License Amendment Request 93-01, which requested changes to the Remote Shutdown TS in accordance with the Westinghouse Standard Technical Specifications (NUREG-1431). The Instrumentation section of the TS governs other Remote Shutdown instrumentation of the same importance as this instrumentation. Alternate Compensatory Measures In certain situations an alternate compensatory measure to a compensatory measure specified in a fire protection ECG may be more appropriate (NRC Regulatory Issue Summary 2005-07, "Compensatory Measures to Satisfy the Fire Protection Program Requirements"). For example, the compensatory measure required for a degraded fire DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-18 Revision 21 September 2013 barrier is typically an hourly fire watch, or, in the case of an inoperable spray or sprinkler system, is a continuous fire watch with backup fire suppression equipment. Fire watches may not be the most effective compensatory measure for degraded or inoperable fire protection features or post-fire safe-shutdown capability (see Information Notice 97-48, "Inadequate or Inappropriate Interim Fire Protection Compensatory Measures," dated July 9, 1997). A different compensatory measure or combination of measures (e.g., additional administrative controls, operator briefings, temporary procedures, interim shutdown strategies, operator manual actions, temporary fire barriers, temporary detection or suppression systems) may be implemented. A documented evaluation of the impact of the proposed alternate compensatory measure and its adequacy compared to the compensatory measure required by the ECG must be completed. The evaluation must demonstrate that the alternate compensatory measure would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire. Any alternate compensatory measure must maintain compliance with the General Design Criteria and 10 CFR 50.48(a), and must be retained as a record pursuant to 10 CFR 50.48(a). The evaluation of the alternate compensatory measure should incorporate risk insights regarding the location, quantity, and type of combustible material in the fire area; the presence of ignition sources and their likelihood of occurrence; the automatic fire suppression and fire detection capability in the fire area; the manual fire suppression capability in the fire area; and the human error probability where applicable. The following table provides a list of alternate compensatory measures that have been implemented and their corresponding LBIE evaluations: LBIE Description 2006-006 ECG 18.7 alternate compensatory measure implemented to address specific non-compliance concern in Fire Area 3-CC. The non-compliance involved inadequate separation of safe shutdown cables. The alternate compensatory measure consisted of additional combustible and hot work controls, a daily walkdown of the area, and fire brigade guidance. LBIE Screen Dated 09/05/06 AR A0676852 ECG 18.7 alternate compensatory measures implemented to address missing fire barriers required to comply with Appendix R Section III.G.2. The alternate compensatory measures are post-fire operator manual actions that have been demonstrated to be feasible and reliable in accordance with NRC Triennial Fire Protection Inspection Procedure, Attachment 71111.05TTP, issued 05/09/06. Note that this only applies to manual actions already identified and implemented by the approved Fire Protection Program. Implementation of manual actions not already identified by the approved Fire Protection Program would require a LBIE Section II evaluation. DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-19 Revision 21 September 2013 LBIE Description LBIE 2007-005 AR A0655791 ECG 18.7 alternate compensatory measures implemented to address missing fire barriers to protect cables associated with FCV-355, which are required to comply with Appendix R Section III.G.2 in Fire Areas 4B (U1 & U2), 5A3, 5A4, 6A3, 6A5, 8G, 5B3, 5B4, 6B3, 6B5 and 8H. The alternate compensatory measure credited operator action to locally open FCV-355 after tripping its power breaker. In addition, administrative controls were implemented to restrict the storage of transient combustible materials and use of hot work in the affected fire areas. LBIE Screen for OTSC to CP M-10 dated 1/10/08 AR A0715723 ECG 18.7 alternate compensatory measures implemented to address missing fire barriers to protect the auto transfer capability of the emergency diesel generators, which are required to comply with Appendix R Section III.G.2 in Fire Areas 10, TB-5/12B and 20. The alternate compensatory measure credited operator action to locally trip startup or auxiliary transformer breakers, and then to manually load the diesel generator to the respective bus either from the control room or locally at the 4kV switchgear. In addition, administrative controls were implemented to restrict the storage of transient combustible materials and use of hot work in the affected fire areas. LBIE 2008-05 LBIE-2008-06 AR A0717058 ECG 18.7 alternate compensatory measures implemented to address missing fire barriers to protect cables associated with FCV-128, which are required to comply with Appendix R Section III.G.2 in Fire Areas 5A2, 5A4, 6A2, 5B2, 5B4 and 6B2. The alternate compensatory measure credited operator action to either fail FCV-128 open at the hot shutdown panel or to secure CCW valve FCV-355 and/or FCV-356 to provide CCW to the RCP TBHX. In addition, administrative controls were implemented to restrict the storage of transient combustible materials and use of hot work in the affected fire areas. DCPP UNITS 1 & 2 FSAR UPDATE 9.5H-20 Revision 21 September 2013 LBIE Description LBIE 2008-05 LBIE 2008-06 AR A0724491 50038548 50521553 50521554 50521555 LBIE 2013-009 ECG 18.7 alternate compensatory measures implemented to address missing fire barriers to protect cables associated with safe shutdown equipment. The concerns were identified during the NFPA 805 transition project and involve fire damage to cables affecting multiple spurious operation of equipment in the following fire areas: CR-1, 34, 3BB (100-ft and 115-ft), 5A2, 5A3, 5A4, 6A1, 6A2, 6A3, 7A, 8G, TB-7/14A, TB-7/12E, 28, 3CC (100-ft and 115-ft), 5B2, 5B3, 5B4, 6B1, 6B2, 6B3, 7B, 8H, TB-7/23E, and 29. The alternate compensatory measure credited either an operator action or existing non-rated fire barriers. In addition, administrative controls were implemented to restrict the storage of transient combustible materials and use of hot work in the affected fire areas, in conjunction with a shift order. LBIE 2012-023 ECG 18.7 alternate compensatory measures implemented to address fire barriers that were not installed to an approved configuration. Specifically: The fire barrier between the Unit 1 isophase room, just South of the 4kV switchgear and cable spreading rooms, fire area TB-7/12-E and the Unit 1 transformer area, fire area 28. The fire barrier between the Unit 2 isophase room, just North of the 4kV switchgear and cable spreading rooms, fire area TB-7/23-E and the Unit 2 transformer area, fire area 29. The fire barriers between the Unit 1 and Unit 2 penetration area ceilings, fire areas 3-BB and 3-CC at elevation 115' and the exterior area above, fire area 34. The fire barrier between the floor of the control room ventilation equipment room, fire areas CR-1/8-B-3 and CR-1/8-B-4, and the adjacent areas below. DCPP UNITS 1 & 2 FSAR UPDATE i Revision 21 September 2013 Chapter 10 STEAM AND POWER CONVERSION SYSTEM CONTENTS
Section Title Page 10.1 SUMMARY DESCRIPTION 10.1-1
10.1.1 Reference Drawings 10.1-2
10.2 TURBINE-GENERATOR 10.2-1
10.2.1 Design Bases 10.2-1 10.2.1.1 Performance Requirements 10.2-1 10.2.1.2 Operating Characteristics 10.2-1 10.2.1.3 Functional Limitations 10.2-2 10.2.1.4 Design Codes 10.2-3
10.2.2 Description 10.2-3 10.2.2.1 Turbine 10.2-3 10.2.2.2 Lubrication 10.2-4 10.2.2.3 Cooling 10.2-4 10.2.2.4 Turbine Electrohydraulic Control System 10.2-5 10.2.2.5 Turbine Steam Flow Control 10.2-5 10.2.2.6 Overspeed Protection 10.2-6 10.2.2.7 Instrumentation 10.2-8
10.2.3 Turbine Missiles 10.2-9
10.2.4 Safety Evaluation 10.2-9 10.2.4.1 Trip System Operability 10.2-9 10.2.4.2 Protective Features 10.2-10 10.2.4.3 Radiological Evaluation 10.2-11
10.2.5 References 10.2-11
10.3 MAIN STEAM SYSTEM 10.3-1
10.3.1 Design Bases 10.3-1
10.3.2 Description 10.3-2
10.3.3 Safety Evaluation 10.3-3 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 10 Contents (Continued) ii Revision 21 September 2013 Section Title Page 10.3.4 Inspection and Testing Requirements 10.3-4 10.3.5 Water Chemistry 10.3-5 10.3.6 References 10.3-5 10.3.7 Reference Drawings 10.3-5 10.4 OTHER FEATURES OF STEAM AND POWER CONVERSION SYSTEM 10.4-1 10.4.1 Main Condenser 10.4-1 10.4.1.1 Design Bases 10.4-1 10.4.1.2 Equipment Description 10.4-1 10.4.1.3 Safety Evaluation 10.4-2 10.4.2 Main Condenser Evacuation System 10.4-2 10.4.2.1 Design Bases 10.4-2 10.4.2.2 Equipment Description 10.4-2 10.4.2.3 Safety Evaluation 10.4-3 10.4.3 Turbine Gland Sealing System 10.4-3 10.4.3.1 Design Bases 10.4-3 10.4.3.2 System Description 10.4-3 10.4.3.3 Safety Evaluation 10.4-4 10.4.4 Turbine Bypass System 10.4-4 10.4.4.1 Design Bases 10.4-4 10.4.4.2 System Description 10.4-4 10.4.4.3 Control 10.4-5 10.4.4.4 Safety Evaluation 10.4-6 10.4.4.5 Tests and Inspections 10.4-6 10.4.5 Circulating Water System 10.4-6 10.4.5.1 Design Bases 10.4-7 10.4.5.2 System Description 10.4-7 10.4.5.3 Safety Evaluation 10.4-8 10.4.5.4 Flooding 10.4-8 10.4.6 Condensate Polishing System 10.4-9 10.4.6.1 Design Bases 10.4-10 10.4.6.2 System Description 10.4-10 10.4.6.3 Safety Evaluation 10.4-10 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 10 Contents (Continued) iii Revision 21 September 2013 Section Title Page 10.4.7 Condensate and Feedwater System 10.4-10 10.4.7.1 Design Bases 10.4-11 10.4.7.2 System Description 10.4-11 10.4.7.3 Safety Evaluation 10.4-12 10.4.7.4 Flooding 10.4-13
10.4.8 Steam Generator Blowdown System 10.4-14 10.4.8.1 Design Bases 10.4-14 10.4.8.2 System Description 10.4-15 10.4.8.3 Safety Evaluation 10.4-16 10.4.8.4 Radiological and Environmental Effects 10.4-17 10.4.8.5 Inspection and Testing 10.4-17
10.4.9 Condensate and Feedwater Chemical Injection System 10.4-17 10.4.9.1 Design Bases 10.4-17 10.4.9.2 System Description 10.4-18 10.4.9.3 Safety Evaluation 10.4-19 10.4.9.4 Instrumentation Application 10.4-20 10.4.10 References 10.4-20 10.4.11 Reference Drawings 10.4-20
DCPP UNITS 1 & 2 FSAR UPDATE iv Revision 21 September 2013 Chapter 10 TABLES
Number Title 10.1-1 Steam Bypass and Relief Valves
10.1-2 Secondary System Operating Parameters at 100 percent Rated Power
10.3-1 Main Steam Line Valve Plant Startup Leakage Test Results
10.4-1 Main Condenser Performance Data
10.4-2 Deleted in Revision 11
DCPP UNITS 1 & 2 FSAR UPDATE v Revision 21 September 2013 Chapter 10 FIGURES Figure Title 10.1-1(a) Unit 2: Heat Balance Diagram - Maximum Calculated - Post LP Retrofit 10.1-2(a) Unit 2: Heat Balance Diagram - 100% RTO - Post LP Retrofit 10.1-3 Deleted in Revision 14
10.1-4 Deleted in Revision 14
10.1-5(a) Unit 1: Heat Balance Diagram - Maximum Calculated - Post LP Retrofit 10.1-6(a) Unit 1: Heat Balance Diagram - 100% RTO - Post LP Retrofit 10.2-1 Steam Generator Characteristic Pressure Curves
10.3-1 Deleted in Revision 16
10.3-2 Deleted in Revision 16
10.3-3 Deleted in Revision 16 10.3-4 Deleted in Revision 16 10.3-5 Deleted in Revision 16
10.3-6 Location of Steam Lines and Valves
10.4-1 Deleted in Revision 8
10.4-2 Revision of Steam Generator Feedwater Piping Steam Generators 1 and 4
10.4-3 Revision of Steam Generator Feedwater Piping Steam Generators 2 and 3
NOTE:
(a) This figure corresponds to a controlled engineering drawing that is incorporated by reference into the FSAR Update. See Table 1.6-1 for the correlation between the FSAR Update figure number and the corresponding controlled engineering drawing number.
DCPP UNITS 1 & 2 FSAR UPDATE 10.1-1 Revision 17 November 2006 Chapter 10 STEAM AND POWER CONVERSION SYSTEM This chapter provides information concerning the plant steam power conversion (heat utilization) system. The steam and power conversion system (SPCS) includes the turbine-generator, steam supply system, feedwater system, main condenser, and related subsystems. The auxiliary feedwater system is discussed in Chapter 6.
Descriptive information is provided to allow understanding of the system, with emphasis on those aspects of design and operation that affect the reactor and its safety features, or contribute to the control of radioactivity. The radiological aspects of normal system operation are summarized in this chapter and are presented in detail in Chapter 11. Design and quality code classifications applied to the steam and power conversion system are discussed in Chapter 3. 10.1 SUMMARY DESCRIPTION The SPCS is designed to convert the heat produced in the reactor to electrical energy. In each unit, reactor heat absorbed by the reactor coolant system (RCS) produces sufficient steam in four steam generators to supply the turbine-generator.
The SPCS is designed to operate on a closed, condensing cycle, with full flow condensate demineralization, and six stages of regenerative feedwater heating. Turbine exhaust steam is condensed in a single shell, surface-type condenser and returned to the steam generators through three stages of feedwater pumping. All three low-pressure turbine elements exhaust into a common condenser steam space. The arrangement of the equipment associated with the SPCS is shown in Figures 3.2-2, 3.2-3, 3.2-4, and 10.3-6.
The SPCS is designed to receive the heat absorbed by the RCS during normal power operation, as well as following an emergency shutdown of the turbine-generator from full load. Heat rejection under the latter condition is accomplished by steam bypass to the condenser and pressure relief to the atmosphere. Either the turbine bypass or the pressure relief system (without operation of safety valves) can dissipate the heat from the RCS following a turbine trip and a reactor trip. Trips, automatic control actions, and alarms are initiated by deviations of system variables from preset values. In every instance, automatic control functions are programmed so that appropriate corrective action is taken to protect the RCS (see Chapter 7).
The SPCS does not normally contain radioactivity. The vents and drains associated with the secondary cycle are arranged in a manner similar to those in a conventional fossil fuel generating station. However, the condenser air removal equipment will handle radioactive noncondensable gases during a steam generator primary-to-secondary tube leak. Means are provided to monitor (see Section 11.6) the DCPP UNITS 1 & 2 FSAR UPDATE 10.1-2 Revision 17 November 2006 discharge of radioactive material to the environment, to ensure that it is within the limits of 10 CFR 20 under normal operating conditions, or in the event of anticipated system malfunctions or accident conditions. Detection of these gases is described in Section 10.4.1 and in Chapter 7.
All SPCS equipment required for nuclear safety is classified as Design Class I, and the appropriate systems are sufficiently redundant to ensure maintenance of their safety functions. Specifically, the auxiliary feedwater system and portions of the main steam and main feedwater systems are required to perform various safety functions involving removal of decay heat and are classified as Design Class I. Safety functions relative to the auxiliary feedwater system are presented in Chapter 6.
Turbine heat balances at maximum calculated and full load conditions are shown, respectively, in Figures 10.1-1 and 10.1-2 for Unit 2, and Figures 10.1-5 and 10.1-6 for Unit 1. Typical operating parameters for the secondary system are listed in Table 10.1-2.
Tables 10.1-1 and 10.1-2 summarize important design and performance characteristics of equipment upon which the safety of the SPCS operation depends. The design performance characteristics and safety-related design features are described in the remainder of Chapter 10. The principal safety-related design features involve the main steam, main and auxiliary feedwater, turbine bypass, and steam generator blowdown systems. Safety-related design features of the auxiliary feedwater system are discussed in Chapter 6. 10.1.1 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures.
DCPP UNITS 1 & 2 FSAR UPDATE 10.2-1 Revision 21 September 2013 10.2 TURBINE-GENERATOR The basic function of the turbine-generator is to convert thermal energy initially to mechanical energy and finally to electrical energy. The turbine-generator receives saturated steam from the four steam generators through the main steam system. Steam is exhausted from the turbine-generator to the main condenser.
More detailed information, including design features and the safety evaluation of the turbine-generator and associated systems, is presented in the following sections. 10.2.1 DESIGN BASES The design bases for the turbine-generator include performance requirements, operating characteristics, functional limitations, and code requirements. 10.2.1.1 Performance Requirements The main turbine-generators and their auxiliary systems are designed for steam flow corresponding to 3,500 MWt and 3,580 MWt, which in turn correspond to the maximum calculated thermal performance data of the Units 1 and 2 nuclear steam supply systems (NSSS), respectively, at the original design ultimate expected thermal power. The Unit 2 turbine-generator has a higher power rating because of subsequent uprating of the Unit 2 NSSS. The intended mode of operation of both units is base loaded at levels limited to the lower licensed reactor levels of 3,411 MWt (see Table 15.1-1). 10.2.1.2 Operating Characteristics The steam generator characteristic pressure curves (Figure 10.2-1) are the bases for design of the turbine. The steam generator pressure curve shown in Figure 10.2-1 corresponds to the SG outlet pressure. The calculated curve is based on thermal design conditions with vessel Tavg of 577.6ºF and 10 percent steam generator tube plugging (Reference 1). The pressure at the turbine main steam valves does not exceed the pressure shown on the steam characteristic pressure curve for the corresponding turbine load. With a pressurized water reactor, it is recognized that the pressure at the turbine steam valves rises as the load on the turbine is reduced below rated load. During abnormal conditions at any given load, the pressure may exceed the pressure on the steam generator characteristic pressure curve by 30 percent on a momentary basis, but the total aggregate duration of such momentary swings above characteristic pressure over the whole turbine load range does not exceed a total of 12 hours per 12-month operating period.
The turbine inlet pressure is not directly controlled. A load index from the turbine first-stage pressure is compared to the reactor coolant Tavg; the control rods are then positioned accordingly.
DCPP UNITS 1 & 2 FSAR UPDATE 10.2-2 Revision 21 September 2013 10.2.1.3 Functional Limitations The plant is designed to sustain sudden large load decreases, as described in Section 5.2.1.5.1. This capability is provided by the use of controlled steam dump or bypass from the secondary system. This dump serves as a short-term artificial load, allowing the reactor to automatically cut back power without tripping. The reactor control system itself is not rapid enough to follow a sudden loss of load without allowing certain reactor plant variables (e.g., pressure and temperature) to exceed allowable operating limits. Therefore, a sufficiently large controlled steam dump, capable of simulating an external load on the reactor, is used to prevent the reactor from tripping.
The rates at which electrical load may be increased or decreased without tripping the reactor, including operation of the steam dump (bypass system), are as follows:
(1) Without steam bypass - If electrical load decrease does not exceed a step change of 10 percent, or a sustained ramp load decrease of 5 percent per minute, then the steam bypass will not operate. Steam bypass is not used to control load increases. (2) With steam bypass - If electrical load decrease does exceed a step change of 10 percent or a sustained ramp load decrease of 5 percent per minute, then a combination of steam dump banks 1, 2, and 3 of the turbine bypass system (Section 10.4.4.3) will operate. If the decrease is less than 50 percent, then a step change with control rods will account for a 10 percent load decrease, and the turbine bypass system will operate and control up to 40 percent of the remaining load decrease. (3) Electrical load increases are limited by the reactor control system to 5 percent full power per minute, or step changes of 10 percent of full power within the power range of 15 to 100 percent of full power.
For further explanation of the steam bypass and relief system, see Section 10.4.4. Steam bypass and relief valves are listed in Table 10.1-1. For electrical loading, see Chapter 8, Electric Power.
The functional limitations imposed by the design or operational characteristics of the turbine-generator are:
(1) Retrofitted with Alstom LP turbines, the units are suitable for continuous full load underfrequency operation down to 56.4 Hz. Operation below 56.4 Hz is limited to 10 seconds per event. There is no specific accumulated time limit for operation below 56.4 Hz. A trip within 0.5 seconds is required below 54.9 Hz.
(2) Under frequency set points and time delays are coordinated with PG&E's Under Frequency Load Shedding (UFLS) Program, per Utility Operations DCPP UNITS 1 & 2 FSAR UPDATE 10.2-3 Revision 21 September 2013 Standard UO S1426, which conservatively bounds turbine vendor requirements. (3) Load changes cause thermal stress in the turbine rotor, which persists as long as there are differences between the surface and interior temperatures of the rotor body. Operational procedures for changing load, that tend to ensure a maximum time period before the appearance of fatigue cracking, are required. Load changing recommendations are based on 10,000 cycles of general turbine operation. For example, the following load changes can be made instantaneously, without exceeding the 10,000-cycle recommendations: 0-10 percent, 10-33 percent, 20-53 percent, 30-78 percent, 40-85 percent, and 50-100 percent. (4) Operation at less than 5 percent rated load should be avoided; however, when necessary, auxiliary load may be carried indefinitely on the main generator following rejection of the main load, provided; (a) Low-pressure turbine exhaust hood spray is placed in service when hood temperature exceeds 175°F; and if hood temperature increases to 250°F for more than 15 minutes, the turbine is tripped (b) All supervisory instrument readings are within allowable alarm limits 10.2.1.4 Design Codes The turbine-generator and associated components are classified as Design Class II. Section 3.2 presents a discussion of design classifications and code requirements.
10.2.2 DESCRIPTION The Siemens-Westinghouse BB96 HP turbine is coupled to three Alstom ND56R LP turbines in a four-casing, tandem-compound, six-flow exhaust, 1800 rpm unit, with 57-inch last-stage blades. The ac generator is connected to the turbine shaft, and a brushless exciter is coupled to the generator. 10.2.2.1 Turbine The turbine consists of one double-flow, high-pressure element in tandem with three double-flow, low-pressure elements. Moisture separation and reheating of the steam are provided between the high-pressure and low pressure turbines by six horizontal axis, two-stage reheat cylindrical shell combined moisture separator-reheater assemblies. Three of these assemblies are located on each side of the low-pressure turbine elements.
Steam from the exhaust of the high-pressure turbine element enters one end of each moisture separator-reheater assembly, where internal manifolds in the lower section DCPP UNITS 1 & 2 FSAR UPDATE 10.2-4 Revision 21 September 2013 distribute the wet steam. The steam then flows through a moisture separator where the moisture is removed and the condensate drained to a drain tank from which it is pumped to the suction of the main feedwater pumps. The steam leaving the separator flows over two tube bundles where it is reheated in two stages. The reheated steam leaves through nozzles in the top of the assemblies and flows to the low pressure turbines through a stop valve and an intercept valve in each reheat steam line. Two moisture separator-reheater assemblies furnish steam to each of the three low-pressure turbine elements. The first stage tube bundle in the reheater is supplied with extraction steam from the high-pressure turbine, and the second-stage tube bundle is supplied from the main steam lines ahead of the high-pressure turbine. The supply steam condenses in the tubes; the condensate from the high-pressure tube bundle flows to the shell of the high-pressure feedwater heaters, while the condensate from the low-pressure tube bundle flows to the heater 2 drain tank.
A turbine shaft sealing system, using steam to seal the annular openings where the shaft penetrates the casings, prevents steam outleakage or air inleakage along the shaft. Turbine steam extraction connections are provided for six stages of feedwater heating. 10.2.2.2 Lubrication Turbine-generator bearings are lubricated by a conventional oil system. The volute type, centrifugal main oil pump is mounted on the turbine rotor and supplies all of the oil requirements for the lubrication system during normal operation. An ac motor-driven centrifugal pump supplies bearing oil for operating the turbine-generator on turning gear during coastdown after a trip, and during startup. A backup dc motor-driven bearing oil pump operates, in case of loss of ac power or if the ac pump fails to start, to lubricate the turbine-generator bearings during coastdown of the unit after tripout. Air-side and hydrogen-side ac motor-driven seal oil pumps are provided to supply oil to the generator hydrogen seal oil systems. An air side dc motor-driven seal oil backup pump operates in case of loss of ac power, to prevent leakage of the generator hydrogen. A lift pump is provided for bearings 3, 4, 5, 6, and 7 to lift the turbine rotor shaft off the journal bearing to reduce the starting load on the turning gear motor. Bearing 8 was retrofitted with an integral bearing lift system. 10.2.2.3 Cooling The cooling water requirements of the turbine-generator are met partially by the service cooling water system (Chapter 9), and partially by the main condensate and feedwater system (Section 10.4.7).
The following main turbine-generator heat exchangers are cooled by the service cooling water system:
(1) Turbine lubricating oil coolers DCPP UNITS 1 & 2 FSAR UPDATE 10.2-5 Revision 21 September 2013 (2) Generator hydrogen seal oil coolers (3) Exciter air-to-water heat exchangers (4) Electrohydraulic control fluid cooler (5) Main generator isophase bus duct cooler The following main turbine-generator heat exchangers are cooled by the main condensate and feedwater system: (1) Generator hydrogen coolers (2) Generator stator water coolers (3) Gland steam condenser 10.2.2.4 Turbine Electrohydraulic Control System The turbine is equipped with a digital electrohydraulic (DEH) control system that uses programmable triple modular redundant (TMR) digital controllers, dual redundant digital servo position controllers, input/output modules, and a high-pressure, fire-resistant, fluid supply system to operate the turbine control valves. By regulating the flow of steam through the turbine, the control system regulates turbine speed prior to the time that the generator is synchronized, and controls unit power output when the generator is connected to the Pacific Gas and Electric Company's (PG&E's) transmission system. The control system also provides overspeed protection. Retrofitted with Alstom LP turbines, the control system also provides low condenser vacuum and low bearing oil protection.
Unit electrical loading is completely under the control of the reactor operator except when automatic runbacks are in progress. No automatic offsite load dispatching is utilized. 10.2.2.5 Turbine Steam Flow Control The flow control of the main inlet steam is accomplished by four main stop valves in series with four governor control valves.
Each main stop valve operates in either a fully opened or fully closed position. The valve is opened when high-pressure fluid enters the hydraulic actuator cylinder and forces the piston to overcome spring closing pressure. It is closed immediately upon the dumping of main stop valve emergency trip fluid to provide quick closing independent of the electrical system. The valve may also be closed upon activation of the solenoid valve for periodic test of valve stem freedom. The purpose of the main DCPP UNITS 1 & 2 FSAR UPDATE 10.2-6 Revision 21 September 2013 stop valve, which is installed in the main steam line ahead of the governor control valve, is to provide an additional safety device to limit turbine overspeed.
Each governor control valve is of the single-seat, plug type design. The valve is opened when high pressure electrohydraulic (EH) fluid enters the actuator and overcomes the spring force of the valve as transmitted by the operating levers. During normal operation, control of the governor control valve is by a servo valve that regulates oil pressure in the actuator, based on information supplied from the DEH system controller. A linear variable differential transformer (LVDT) develops an analog signal proportional to the valve position, which is fed back to the controller to complete the control loop. The controller signal positions the control valves over a wide range of turbine speeds during startup and for load control after the unit is synchronized. The governor control valve is closed by reducing pressure on the dump valve. The dump valve can be activated by means of the emergency trip system, or by the auxiliary governor trip, to provide quick closing independent of the electrical system.
The flow control of steam to the low-pressure sections of the turbine is accomplished by six reheat stop valves in series with six interceptor valves.
Each reheat stop valve operates in either the fully opened or fully closed position. The valve is opened when high-pressure fluid enters the actuator hydraulic cylinder and forces the piston to overcome spring closing pressure. It is closed immediately upon dumping of main stop valve emergency trip fluid, on actuation of the emergency trip device. It may also be closed upon activation of the solenoid valve for periodic testing of valve stem freedom. The major function of the reheat stop valves is to shut off the flow of steam to the low-pressure turbines, when required. Each interceptor valve normally operates in a fully opened position. The valve is opened when high-pressure fluid is admitted through an orifice to the hydraulic cylinder operating piston. As the fluid pressure increases beneath the piston, it overcomes the force of the closing springs and opens the steam valve. It is quickly closed when the emergency trip fluid is released to drain. The purpose of this valve is to limit the flow of steam from the moisture separator-reheaters to the low-pressure turbines after a sudden load reduction. 10.2.2.6 Overspeed Protection The overspeed protection control (OPC) system controls turbine overspeed in the event of a partial or complete loss of load, or if the turbine reaches or exceeds 103 percent of rated speed. Turbine input power is a function of high-pressure turbine exhaust pressure; a pressure transducer provides high-pressure turbine exhaust pressure data. A three-phase watt transducer provides generated kW information. These quantities are compared; if they differ by a preset amount, protective logic is activated.
In the event that turbine shaft speed exceeds 103 percent of rated speed, overspeed protection is afforded through information (in rpm) supplied by three speed transducers DCPP UNITS 1 & 2 FSAR UPDATE 10.2-7 Revision 21 September 2013 to the OPC system. The signals from the transducers are validated against a high and low reference to determine when a transducer fails high or low. The turbine control system uses a median signal select logic to determine the controlling speed signal. A mechanical overspeed trip device is also provided that will automatically trip the unit at 111 percent of rated speed. The mechanism consists of a spring-loaded plunger located in the turbine shaft, which extends radially outward when 111 percent of rated speed is reached. When extended, the plunger contacts a lever, which in turn dumps control hydraulic fluid (autostop oil), causing all turbine steam inlet control and stop valves to close.
An electronic trip signal is generated by the DEH control system, at 111.5 percent of rated speed, as redundant overspeed protection. With the retrofitted Alstom LP turbines, this trip signal is used to energize two solenoid valves, either of which dumps autostop oil. This trip signal is set approximately 10 rpm higher than the mechanical overspeed device previously described.
Overspeed protection is necessary to preclude turbine rotor failure and associated turbine generated missiles. Refer to the discussion of turbine missiles in Section 10.2.3. 10.2.2.6.1 Partial Loss of Load A feature called close-intercept valve (CIV) was built into the original turbine control system to close the intercept valves. This CIV feature was designed to sense a load mismatch between high pressure exhaust pressure and generated power. CIV actuation would close the intercept valves for a preset time period. This feature was disabled on the original Westinghouse-supplied turbine control system and is not present in the new system. 10.2.2.6.2 Complete Loss of Load When a mismatch of high-pressure exhaust pressure and megawatts occurs, and the breaker opens, this condition is detected as a complete load loss. When the generator breaker opens, the load drop anticipation (LDA) is set, requesting OPC action.
All governor and interceptor valves are then rapidly closed. The LDA load loss circuit is inoperable below 22 percent of load, as measured by high-pressure exhaust pressure. 10.2.2.6.3 Overspeed Action OPC action also occurs when turbine speed is equal to, or greater than, 103 percent of rated speed. Governor and interceptor valves are closed until the speed drops below 103 percent.
The OPC system may be tested by using the OPC test function. If the breaker is open and the OPC test function is activated, a signal is generated; this signal indicates that DCPP UNITS 1 & 2 FSAR UPDATE 10.2-8 Revision 21 September 2013 the speed of the turbine is over 103 percent. The OPC system then closes the valves as though an actual overspeed condition had occurred. 10.2.2.6.4 Speed Channel System Three separate electromagnetic pickups input speed information to the turbine control system. These inputs are validated against a high and low reference to determine when a transducer fails high or low. The control system uses a median signal select logic to determine the controlling speed signal for turbine speed control, OPC, and redundant overspeed protection. 10.2.2.6.5 Automatic Runbacks and Programmed Ramps The turbine control system implements protective runbacks and programmed ramps (load reductions). The OTT and OPT protective runbacks are described in Section 7.7.2.4.2. The loss of main generator stator cooling protective runback is discussed in Section 10.2.4.2. Main turbine programmed ramps anticipating loss of steam flow are main feedwater pump trip and heater drip pump trip. A turbine runback anticipating a loss of heat sink is a trip of a circulating water pump. 10.2.2.7 Instrumentation Instrumentation is provided to continuously monitor and alarm the following turbine-generator parameters:
(1) Shaft vibration at main bearings (2) Shaft eccentricity (3) Shell expansion (4) Differential expansion between turbine shell and rotor (5) Turbine speed (6) Turbine metal temperatures (7) Bearing temperatures (8) Hydrogen gas and stator cooling water temperatures (9) Exhaust hood temperatures (10) Condenser vacuum
(11) Thrust bearing wear DCPP UNITS 1 & 2 FSAR UPDATE 10.2-9 Revision 21 September 2013 10.2.3 TURBINE MISSILES Tests and analyses regarding the potential generation and effects of missiles, caused by the turbine-generator accelerating to design overspeed, have been performed by both Siemens-Westinghouse Electric Corporation and Alstom. These tests and analyses are discussed in Chapter 3. Criteria for determining the turbine inspection scope and frequency required to prevent missile generation are also discussed in Chapter 3. 10.2.4 SAFETY EVALUATION The turbine-generator and associated steam handling equipment have received extensive mechanical, electrical, and radiological safety evaluations. Protective features regarding personnel and equipment safety are presented in this section. Safety features for reactor protection, in the event of a turbine-generator trip or sudden load reduction, are presented in Sections 10.3.3 and 10.4.4. 10.2.4.1 Trip System Operability The operability of the main turbine inlet valves and turbine trip system is verified by periodic functional tests. Operability of the trip system in the event of postulated accidents has also been reviewed. The trip system is protected from falling debris and will remain operational during and following postulated accidents for the following reasons:
(1) The siding and roofing of the turbine building are constructed to withstand design wind loads, which are in excess of the loads they would experience during an earthquake. Therefore, falling corrugated metal roofing or siding is not considered a credible event. (2) The main stop valves and the overspeed trip mechanism are located on the high-pressure turbine. Falling debris such as rivets and small scrap metal, would not damage the stop valve bodies, actuators, or trip mechanism in a manner that would prevent valve closure. (3) The reheat stop valves are located below the turbine deck. The turbine deck protects these valves from falling debris. (4) The intercept valves are located above each low-pressure turbine. Their operation is not necessary for stopping the main turbine on a turbine overspeed trip. (5) The EH fluid system piping, which supplies high-pressure oil to the main turbine steam inlet valves, runs both above and below the turbine deck.
Because most of the EH piping is either below the turbine deck or sheltered by the valve bodies and inlet piping, it is highly unlikely that said DCPP UNITS 1 & 2 FSAR UPDATE 10.2-10 Revision 21 September 2013 debris would impact the EH piping. In the extremely unlikely event that such debris were to impact the EH piping, the piping would have to be crimped completely shut to prevent the trip system from operating. This is not considered a credible event. A partially crimped line would not disable the trip system. A broken or punctured line would result in a loss of EH pressure resulting in HP stop valve and re-heat stop valve closure, thus stopping the main turbine. (6) Administrative operating requirements ensure that the turbine building crane is parked away from the steam inlet valves during turbine operation, to preclude damage to the valves from a postulated crane fall. 10.2.4.2 Protective Features Post Alstom LP turbine retrofit, the low vacuum mechanical trip feature has been removed and low vacuum trip is now provided through the DEH. The following other protective devices are independent of the electronic controller and, when initiated, will cause tripping of all turbine valves:
(1) Mechanical overspeed trip (see description in 10.2.2.6) (2) Low bearing oil pressure trip (this is provided by both the mechanical trip, independent of the electronic controller, as well as through the DEH). (3) Thrust bearing trip (4) Electrical solenoid trip, actuated by: (a) Safety injection system or steam generator high-high level (b) Generator loss of field (c) Reactor trip (d) Unit trip (e) Manual trip switches in control room (f) Turbine speed 111.5 percent or dc bus trip (DEH) (g) ATWS mitigation system actuation circuitry (5) Manual lever located at the turbine DCPP UNITS 1 & 2 FSAR UPDATE 10.2-11 Revision 21 September 2013 Each of the above tripping devices releases autostop oil. The oil release results in a decrease of autostop oil pressure that opens a diaphragm-operated trip valve in the EH high-pressure fluid system to release the pressure and close all steam valve actuators.
The generator is protected by a load runback feature on loss of cooling water to the generator stator. The runback is accomplished at a rate of approximately 40 percent load drop per minute by the turbine control system. If the generator runback fails to start in 45 seconds, the generator is additionally protected by a time delay trip, which results in a unit trip. Reverse power and antimotoring protection is also provided for the generator.
In addition to the devices described above, the turbine and steam system are protected by the following indicators and design features:
(1) Dropped reactor control rod signal light on the main control board (2) Isolation valve in each steam generator steam line (3) Check valve in each steam generator steam line (4) Safety valves in each steam generator steam line (5) Safety valves in the moisture separator-reheater inlet (cold reheat) piping (6) Extraction line nonreturn valves (7) Exhaust casing rupture diaphragms (8) Turbine steam and casing drains which open automatically at loads less than 20 percent 10.2.4.3 Radiological Evaluation Steam generated in the steam generators is not normally radioactive. However, in the event of primary-to-secondary system leakage due to a steam generator tube leak, it is possible for the main steam to become radioactively contaminated. A full discussion of the radiological aspects of primary-to-secondary leakage, including anticipated operating concentration of radioactive contaminants, means of detection of radioactive contamination, anticipated releases to the environment, and limiting conditions for operation, is included in Chapters 7 and 11. Detailed analyses of the radiological consequences of postulated steam plant accidents are presented in Chapter 15.
10.
2.5 REFERENCES
- 1. Delta 54 Replacement Steam Generator Thermal and Hydraulic Design Analysis Report for Diablo Canyon, WCAP-16573-P, August 2007.
DCPP UNITS 1 & 2 FSAR UPDATE 10.3-1 Revision 19 May 2010 10.3 MAIN STEAM SYSTEM The main steam system conveys the generated steam from the nuclear steam supply system to the turbine generator, turbine driven feedwater pumps, steam dump, reheaters, and via the auxiliary steam system, to the gland steam system and air ejectors. Main steam is also provided to the turbine driven auxiliary feedwater pump to ensure that steam generator water level is maintained in case of a station blackout. 10.3.1 DESIGN BASES The main steam system is designed so that a failure of a main steam line at any point along its length, or a malfunction of a valve installed therein, or any consequential damage, will not:
(1) Reduce the flow capacity of the auxiliary feedwater system (2) Render inoperable any engineered safety feature (i.e., controls, power or instrumentation cables, emergency core, or containment cooling piping) (3) Cause gross failure of any other steam or feedwater line valve (4) Initiate a loss-of-coolant accident (LOCA)
Each unit is designed so that a main steam line break inside the containment will not result in the containment pressure exceeding its design value. Furthermore, a steam line break between the exterior of the containment and the quick-acting isolation valve will not compromise the effectiveness of any containment barrier other than the broken steam line itself. Since the main steam isolation valves (MSIVs) are a secondary barrier that serve to back up the steam generator tubes, containment leaktight integrity will not be degraded as a result of a steam line break in this case. Further discussion of containment integrity for a steam line break is presented in Chapters 6 and 15.
The MSIVs, and the valves upstream of them and outside the containment, are designed and packed to have the capability of limiting gland leakage along the stem to no more than one cubic centimeter of water per hour per inch of stem diameter, when subjected to a hydrostatic test pressure of 1100 psig, or 0.03 scf of air per hour per inch of stem diameter with a differential pressure of 80 psi. They are designed to have the capability to limit the valve seat leakage rate to 0.1 scf per hour per inch of seat diameter, when subjected to a pneumatic pressure of 80 psig. Table 10.3-1 summarizes the potential leakages for valves located upstream of the steam line isolation valves, and lists the leak rates measured through these leak paths during initial plant startup testing.
Since the secondary system is a closed system inside containment whose integrity is not damaged by a LOCA, the offsite dose consequences via the leak paths identified in Table 10.3-1 are small when compared to the consequences from the containment DCPP UNITS 1 & 2 FSAR UPDATE 10.3-2 Revision 19 May 2010 atmosphere leakage assumed in the offsite dose analysis. Hence, pursuant to Table 6.2-39, there are no local leak rate limits for these leakage paths, and in accordance with 10 CFR 50, Appendix J, this leakage is not measured. See Section 5.5 for further discussion. The main steam lines, together with their supports and structures between each steam generator and its associated isolation valves (including the check valves), are Design Class I. Applicable design and quality code classifications are discussed in Chapter 3. The classification and applicable codes for the main steam system are identified in the DCPP Q-List (see Reference 8 of Section 3.2). 10.3.2 DESCRIPTION The arrangement of the equipment associated with the steam and power conversion system is shown in simplified form in Figures 3.2-2, 3.2-3, 3.2-4, and 10.3-6. Steam from the four steam generators is supplied to the turbine-generator unit. Steam enters the high-pressure turbine through four stop valves and four governing control valves. One stop valve and one control valve form a single assembly. After expanding through the high-pressure turbine, steam flows through the six moisture separators and two-stage reheaters to the three low-pressure turbine elements.
Saturated steam from the four steam generators passes through the containment wall in carbon steel pipes arranged to satisfy flexibility and Design Class I requirements. Each main steam line is anchored to the containment wall at the penetration. Steam flow restrictors are installed in each steam line inside the containment. The pressure drop at rated load between the steam generators and the turbine throttle is approximately 40 psi. Connections are provided in the four main steam lines, between the containment and the isolation valves, for spring-loaded safety valves and power-operated relief valves, and (in two of the four) steam lines to the auxiliary feed pump drive turbine, as shown in Figures 3.2-4 and 10.3-6.
The function of the MSIV is provided by a quick-acting isolation valve and a check valve installed in each main steam line. These valves are located outside of the containment structure and downstream of the safety valves. This design ensures that steam line isolation occurs for breaks either upstream or downstream of the valves. To permit inspection without disassembly, inspection ports for fiberoptic tubing are machined into each isolation valve body. The branch connection on two main steam lines for the auxiliary feed pump turbine is also provided with isolation valves and check valves. These check valves prevent reverse flow from an unfaulted steam generator in the event of a pipe break upstream of the check valves. Additional data on these valves are provided in Appendix 5.5A.
The MSIVs automatically close on high negative steam line pressure rate, low steam line pressure, or on a high-high containment pressure signal. The valves can be operated manually from the main control room. The MSIVs have remote-manual, air-DCPP UNITS 1 & 2 FSAR UPDATE 10.3-3 Revision 19 May 2010 operated bypass valves for the pressure equalization that is necessary to open the valves. The bypass valves are operated from the control room and automatically close on the same signals that automatically close the MSIVs. There are also manual bypass valves around those air-operated MSIV bypass valves on Main Steam Leads 2 and 3. These manual bypass valves can be used to drain condensate accumulated in piping upstream of the MSIVs upon a loss of instrument air supply prior to the startup of the auxiliary feedwater pump turbine. 10.3.3 SAFETY EVALUATION Main steam system safety concerns refer to the portions of the main steam lines that extend from the steam generators, penetrate the containment, and go up to and include the main steam isolation valves. Main steam system safety considerations are discussed in Sections 15.3.2 and 15.4.2. Safety provisions on the main steam lines include:
(1) The steam lines and the shell-sides of the steam generators are considered an extension of the containment boundary and, as such, are not to be damaged as a consequence of damage to the reactor coolant system. The steam generator shells and steam lines are, therefore, designed to be protected against reactor coolant system missiles. The reverse is also true in that the plant design is such that a steam line break will not cause damage to the reactor coolant system. (2) The measured steam flow has a functional Class II application. The flow signal is used by the Class II three-element feedwater controller and as a Class II load index signal for the main feedwater pumps. (3) The portion of the main steam system outlined above is also necessary to the safe shutdown of the plant and is classified as Design Class I. (4) Uncontrolled steam release as a result of a main steam line failure is limited to the contents of one steam generator, thus keeping the related effect upon the reactor core within the prescribed bounds. (The main steam line rupture event is discussed in detail in Sections 6.2.1, 15.3.2, and 15.4.2.) This results in the need for isolation valves and check valves, as well as special design considerations for the main steam lines themselves. These considerations are necessary to ensure that damage to a portion of one steam line does not result in damage to the corresponding portion of the other steam lines or the other steam generators. They are covered in detail in the main steam line break discussion (see Chapter 15). Each MSIV is opened by air and closes when either of the solenoid valves in its vent line are energized, releasing the air. In the event of a fire at the nearby main transformer bank, solenoid valve wiring could conceivably be DCPP UNITS 1 & 2 FSAR UPDATE 10.3-4 Revision 19 May 2010 burned, shorted, or opened, thus preventing solenoid energization and MSIV closure. To ensure MSIV closure in this event, a valve with a thermal fuse (automatic sprinkler type) has been installed in the vent lines of MSIV 41 and MSIV 42 on Units 1 and 2.
Other safety provisions include:
(1) The steam generator safety valves (2) The steam generator power-operated relief valves (3) The steam supply to the turbine driven auxiliary feedwater pump The steam supply to the auxiliary feedwater pump turbine is safety-related because of the engineered safety requirements of the auxiliary feedwater system. The steam supply lines from two of the four steam generators are interconnected upstream of the steam line stop valve to provide both redundancy and balanced steam flow. Both isolation and check valves in series in each of these lines provide the required valve redundancy that acts to prevent reverse flow. (4) The flow restrictors Each replacement steam generator has a flow restrictor located in the steam outlet nozzle to limit the steam blowdown from the steam generators in the event of a main steam line rupture. The flow restrictor consists of seven 6.03-inch ID venturi nozzles. Each main steam line also includes a 16-inch diameter flow restrictor that acts to limit the maximum flow and the resulting thrust forces created by a steam line break. The flow restrictors are discussed in more detail in Section 5.5.4. 10.3.4 INSPECTION AND TESTING REQUIREMENTS The piping from the steam generator, up to and including the main steam line isolation valves, is equipped with removable insulation for inservice inspection of welds. The tests and inspections that apply to the main steam line isolation valves are in accordance with the DCPP Technical Specifications (Reference 1). Main steam line isolation valves are tested periodically to verify their ability to close within the required time.
Preoperational and startup testing requirements applicable to the main steam system are discussed in Chapter 14.
Since the major components of the steam and power conversion system are accessible during normal power operation, leakage from the valves located upstream of the MSIVs is monitored by routine visual inspection by the operators. Since the secondary system DCPP UNITS 1 & 2 FSAR UPDATE 10.3-5 Revision 19 May 2010 upstream of the MSIVs forms a closed system inside containment, the amount of post-LOCA containment atmosphere that can leak to the environment via the main steam line containment penetrations is small compared to the amount assumed to leak to the environment in the offsite dose analysis. For this reason, there are no design leak rate requirements imposed on the leakage paths identified in Table 10.3-1, and no local leak rate testing is performed on these penetrations pursuant to Table 6.2-39, in accordance with 10 CFR 50, Appendix J. 10.3.5 WATER CHEMISTRY All volatile chemistry is used in the main steam, feedwater, and condensate systems to provide improved corrosion protection and control. Steam generator blowdown for chemistry control is discussed in Section 10.4.8. The main steam sampling system is discussed in Section 9.3. Chemical treatment of the secondary system water for corrosion control is discussed in Section 10.4.9.
The control measures exercised over the secondary water chemistry for the purpose of inhibiting steam generator tube degradation consist of a program encompassing: (a) scheduled sampling and analyses of fluid systems for the critical control parameters, (b) recording, reviewing, and management of data, (c) identification of process sampling points, (d) guidance for corrective actions for off-point chemistry, (e) identification of the authority responsible for the interpretation of data, and (f) the sequence and timing of administrative events required to initiate corrective action.
Additional control measures for secondary water chemistry come from the turbine manufacturer. The program includes the monitoring of main steam purity. 10.
3.6 REFERENCES
- 1. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended. 10.3.7 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures.
DCPP UNITS 1 & 2 FSAR UPDATE 10.4-1 Revision 21 September 2013 10.4 OTHER FEATURES OF STEAM AND POWER CONVERSION SYSTEM Principal design features and subsystems of the DCPP steam and power conversion system are described and evaluated in this section. 10.4.1 MAIN CONDENSER The main condenser provides a heat sink and collection volume for steam and condensate discharged from the main turbine, feedwater pump turbines, turbine bypass system, feedwater heater drains, and other miscellaneous flows, drains, and vents. 10.4.1.1 Design Bases The main condenser is designed to condense full load steam and maintain a nominal absolute pressure of 1.71 inches of mercury. Sufficient surface (618,000 square feet) is provided to condense steam generator relief system steam (up to 40 percent of maximum calculated capability flow), following a load reduction, or under controlled startup conditions, or from residual and decay heat at shutdown.
The condenser hotwells are sized to provide adequate storage of water (138,000 gallons) to allow for the water lost to the atmosphere and "shrinkage" on a 50 percent load reduction. The condensate leaving the hotwells is deaerated to 0.005 cc/liter dissolved oxygen level.
During operation, air is removed from the condenser by steam jet air ejectors and discharged to the plant vent. The discharged air is continuously monitored for radioactivity. No control functions are associated with this radiation monitor. During startup, the condenser is evacuated by a wet-type rotary vacuum pump which discharges air to the atmosphere.
The main condenser is provided with a means of detecting saltwater leakage and is classified as Design Class II. 10.4.1.2 Equipment Description The main condensing surface is mounted beneath the low-pressure turbine elements in two shells with interconnected steam spaces. The tubes are arranged parallel to the turbine shaft. The performance data for both the Units 1 and 2 condensers are summarized in Table 10.4-1.
The following materials are used in the condenser:
(1) Shell and tube supports - carbon steel, ASTM A285, Grade C (2) Tubesheets 10 copper nickel, ASTM B171 (with corrosion-resistant coating on the saltwater side)
DCPP UNITS 1 & 2 FSAR UPDATE 10.4-2 Revision 21 September 2013 (3) Water boxes - carbon steel, ASTM A285, Grade C, lined with corrosion resistant coating on the saltwater side (4) Tubes - titanium 10.4.1.3 Safety Evaluation The condenser will condense up to 40 percent of the full load main steam flow during a load reduction, startup, or shutdown. The steam generator relief system, described in Section 10.4.4, protects the NSSS from overpressure if the condenser is not available or if the steam flow exceeds the capacity of the condenser. The secondary system is normally not radioactive. However, in the event of primary-to-secondary leakage through leaking steam generator tubes, it is possible for the main steam to become radioactively contaminated. A discussion of the assumed leakage rates, treatment methods, and calculated activity levels is included in Section 11.1.6, and an inventory of radionuclides in the condenser for an assumed leak rate is shown in Table 11.1-27. 10.4.2 MAIN CONDENSER EVACUATION SYSTEM The main condenser evacuation system (MCES) removes noncondensable gases from the main condenser during plant startup, cooldown, and normal operation. The system has no safety-related function and is classified as Design Class II. 10.4.2.1 Design Bases The MCES consists of a wet-type rotary vacuum pump and steam jet air ejectors. The vacuum pump is common to both units and is used to draw an initial vacuum in the condensers of either unit. The steam jet air ejectors are used after the initial pumpdown and are designed to maintain a nominal absolute pressure of 1-1/2 inches of mercury. 10.4.2.2 Equipment Description The wet-type rotary vacuum pump has a capacity of approximately 7000 cubic feet per minute, and will pump the condensers of either unit down to a nominal absolute pressure of 1-1/2 inches of mercury in approximately 1 hour.
The steam jet air ejector system consists of two stages of steam jets mounted on a combined inter-after surface condenser. The air ejector system is designed to remove 360 pounds per hour of air saturated with water vapor at 71.5°F, and a suction pressure of 1 inch of mercury absolute pressure when supplied with steam at 85 psig. The first stage consists of eight 25 percent capacity jets and the second stage consists of twin 100 percent capacity jets.
DCPP UNITS 1 & 2 FSAR UPDATE 10.4-3 Revision 21 September 2013 10.4.2.3 Safety Evaluation The MCES has no safety-related function. Air is discharged from the vacuum pump through a local vent. Since the condenser vacuum would be drawn before opening the MSIVs, there is no possibility of radioactive materials being drawn into the condenser during vacuum pump operation. Noncondensables vented from the steam jet air ejectors while the plant is at power operation are discharged through the plant vent that is continuously monitored for radioactivity. Further discussion of releases due to steam generator leakage and the radiation monitoring of the plant vent is given in Sections 11.1.6 and 11.4. 10.4.3 TURBINE GLAND SEALING SYSTEM The turbine gland sealing system provides shaft sealing for the main and feedwater pump turbines. 10.4.3.1 Design Bases The turbine gland sealing system is designed to prevent the leakage of air into, or steam out of, the turbines along the turbine shaft. The system has no safety-related functions and is classified as Design Class II. 10.4.3.2 System Description The turbine glands are of the labyrinth type. When the unit is being started, and partially during normal operation, steam is supplied to the gland header from the main steam line to seal the high-pressure and low-pressure turbine glands. The auxiliary boiler also can be used to supply sealing steam during startup. When the turbine is operating under load, the steam pressure inside the high-pressure turbine increases and steam leaks outward toward the rotor ends. The leakage from the high-pressure glands partially supplies the steam requirements for the low-pressure glands, while the remainder is furnished by the main steam gland regulator. Adequate steam pressure is maintained in the gland area at all times to prevent the leakage of air into, or steam out of, the turbine along the turbine shaft.
At normal operating conditions, the exhaust from the gland seals is approximately 3000 pounds per hour of air saturated with water vapor at 150°F. The gland steam condenser maintains a pressure slightly below atmosphere in the gland leak-off system to prevent the escape of steam from the glands. The air and noncondensable gases from the turbine gland seal condenser are exhausted to the plant vent, which is continuously monitored.
In the event that the gland steam becomes contaminated, it will be detected by radiation detectors located in the plant vent (monitors PVNR and PVRNR). The turbine building is not monitored for leakage from the glands. Details of the radiological evaluation of the system are included in Chapter 11. DCPP UNITS 1 & 2 FSAR UPDATE 10.4-4 Revision 21 September 2013 10.4.3.3 Safety Evaluation The turbine gland sealing system has no safety-related function. In the event of steam generator leakage and continued plant operation, the gland sealing system prevents the release of radioactive steam to the turbine building. If gland seals are lost due to a malfunction of the system, a small amount of steam could be released depending on the type of equipment malfunction. Upon the loss of gland sealing steam, the turbine would be tripped to prevent seal or rotor damage. A turbine trip would prevent additional radioactive steam from entering the turbine. 10.4.4 TURBINE BYPASS SYSTEM The turbine bypass system (TBS) bypasses main steam directly to the main condenser and atmosphere, depending on the required capacity, during the emergency condition caused by a sudden load reduction by the turbine-generator or turbine trip, and during plant startup and shutdown. 10.4.4.1 Design Bases The TBS is designed with a capacity to bypass a range of approximately 66 to 79 percent of the full load steam flow over the range of full load operating conditions to the main condenser and the atmosphere combined. Valve banks 1, 2, and 3 from Section 10.4.4.3 are credited in determining this capacity. The steam dump capacity to the main condenser alone (banks 1 and 2 from Section 10.4.4.3) has a range of approximately 35 to 41 percent of the full load steam flow over the range of full load operating conditions. The system thus provides an artificial load on the reactor coolant system during the emergency condition of a sudden load reduction by the turbine-generator or a turbine trip.
The capacity of the TBS, combined with the 10 percent step-load-change characteristics of the reactor, provides the capability of accepting a sudden load reduction of up to 50 percent, without reactor trip or operation of the spring-loaded safety valves or power operated relief valves.
Banks 1, 2, and 3 from Section 10.4.4.3 of the turbine bypass piping and valves are classified as Design Class II because they are not required for safe shutdown, as discussed in Section 10.4.4.4. Applicable codes and standards for piping, valves, and fittings are discussed in Section 3.2. 10.4.4.2 System Description Each unit is provided with a power relief system capable of passing between 35 and 41 percent of full load main steam flow directly to the condenser, depending on the full load operating conditions. The main steam lines also have power-operated relief valves that were originally sized to pass 45 percent of maximum calculated capability main steam flow to the atmosphere to assist in accommodating a full load rejection. Due to the DCPP UNITS 1 & 2 FSAR UPDATE 10.4-5 Revision 21 September 2013 Tavg and Tfeed Ranges Program, the capacity of these valves now varies based on the full load operating conditions. Bank 4 of the atmospheric steam dump valves (ADVs), from Section 10.4.4.3, are set at a lower pressure than the spring-loaded safety valves. The total amount of steam released to the atmosphere during a loss of generator external load (while maintaining auxiliary load) will be less than 2.5 equivalent full power minutes of feedwater flow, or 637,000 pounds of steam for Unit 1 and 650,000 pounds of steam for Unit 2. There is a power-operated relief valve in each main steam line with approximately 10 percent relief capacity upstream of the isolation valve, and also nine power-operated relief valves for approximately 35 percent relief capacity downstream (see Figure 3.2-4). The exact capacity of these relief valves depend on the full load operating conditions. 10.4.4.3 Control During normal operating transients for which the plant is designed, the TBS system is automatically regulated by the reactor coolant temperature control system to maintain the programmed coolant temperature.
When a transient results in a plant trip, the operator transfers bypass control to the pressure control mode and regulates the system to maintain no-load steam pressure. Lower pressures can be maintained automatically by adjustment of the pressure setpoint. During a plant cooldown, the bypass system is manually controlled to achieve the required cooling rate. This is accomplished by manual adjustment of the pressure setpoint in the control room and requires a minimum operation of four bypass valves to the condenser. There are 12 power relief valves that take steam from the dump header (connected to all main steam lines). The valves discharge into spray distribution headers in the condenser. Four of the valves are used during cooldown.
The valve banks are opened in the following sequence:
(1) Cooldown valves (4 of 12 turbine bypass valves) (2) Bypass valves (remaining 8 of 12 turbine bypass valves) NOTE: Plant capability is provided to use all 12 bypass valves for cooldown during Mode 3 after boration to cold shutdown conditions. (3) Atmospheric relief valves (9 valves downstream of isolation valves) (4) Atmospheric relief valves (4 valves upstream of isolation valves)
DCPP UNITS 1 & 2 FSAR UPDATE 10.4-6 Revision 21 September 2013 10.4.4.4 Safety Evaluation The TBS system is not essential to the safe operation of the plant; it is required to give the plant flexibility of operation and a controlled cooldown. The steam generator safety valves provide relieving capacity during a period when all valves are out of service.
With the exception of the steam generator safety valves and Bank 4 of the atmospheric dump valves, no part of the bypass system has a safety requirement.
Failure of the turbine bypass valves, the atmospheric relief valves downstream of the main steam isolation valves, or any pipe downstream of the MSIVs could result in a rapid cooldown and pressurization of the steam generator until the isolation valves close on high negative steam line pressure rate or low steam line pressure signals. The transients and radiological consequences associated with such a failure would not be as severe as the double-ended severance of a main steam line, as discussed in Chapter 15. Failure of any component (or pipe) downstream of the isolation valve could not cause overpressurization of a steam generator because of the location of the spring-loaded safety valves upstream of the isolation valves. The TBS has been analyzed for potential effects of piping rupture on nearby safety-related equipment. Details of this analysis are presented in Section 3.6.4. 10.4.4.5 Tests and Inspections Local test facilities for the bypass flow control valves are not provided. The steam bypass and relief valves are not a safety item and are tested at reactor low power levels. Each steam generator 10 percent atmospheric dump valve line, associated block valve, and associated remote manual controls, including the backup air bottles, will be demonstrated operable as required by the Technical Specifications and at least once per 31 days by verifying that the steam generator 10 percent ADV block valves are open. In addition, remote manual controls and backup air bottles will be used to verify that all steam generator 10 percent ADVs will operate at least once each 24 months. This frequency interval is subject to SR 3.0.2 of the Technical Specifications.
Should evidence indicate that radioactivity is being released as a result of leakage through these valves during the postaccident recovery period, action such as tightening packing will be taken to eliminate the source. 10.4.5 CIRCULATING WATER SYSTEM The circulating water system provides the heat sink required for removal of waste heat in the power plant's thermal cycle. The system has the principal function of removing heat by absorbing this energy in the main condenser.
DCPP UNITS 1 & 2 FSAR UPDATE 10.4-7 Revision 21 September 2013 10.4.5.1 Design Bases The circulating water system is designed to provide cooling water necessary to condense the steam entering the main condenser. The system also serves the intake coolers, condensate cooler, service cooling water heat exchangers. The design temperature rise in the circulating water system at full load operation is 18°F. The design flow per unit is nominally 867,000 gpm.
The circulating water system is classified as Design Class II. 10.4.5.2 System Description Condenser circulating water is seawater from the Pacific Ocean. The ocean water level normally varies between zero and +6 feet mean lower low water (MLLW) datum. Mean sea level (MSL) zero is equivalent to +2.6 feet MLLW.
A curtain wall at the front of the intake structure limits the amount of floating debris entering the intake structure. Bar racks near the front of the intake structure intercept large submerged debris. The bar racks have 3/8-inch thick bars at 3-3/8 inch centers. Traveling screens intercept all material larger than the screen mesh opening (3/8 inch clear square openings).
The total flow in each unit's circulating water system is nominally 867,000 gpm, which is pumped by two circulating water pumps per unit through two circulating water conduits per unit to the condenser inlet water boxes. Each pump has a discharge isolation valve and bypass line around the valve. Approximately 4000 gpm of the circulating water flow is used per unit to cool the service water heat exchangers and 1000 gpm to cool the pump motor cooling water.
At the intake structure, each circulating water system consists of two circulating water pumps with motors cooled by an air-to-water heat exchanger. The cooling water is provided from the fire water system via a small demineralizer.
The chlorination system provides chemical treatment of the circulating water to control macro and micro fouling in the intake tunnels, piping, and the condenser tubes. The system is used as needed.
The chlorination system, which is shown as part of Figure 3.2-17, provides an oxidizing biocide to the suction of the circulating water pumps for control of macro and micro fouling. Liquid sodium hypochlorite and a supplemental chemical are stored in tanks at the intake structure (common to both units). Adequate valving is provided for isolating any of the tanks from the system. Each tank is within a containment tank sized to contain the entire contents of the storage tank. When chlorination is required (based on a time schedule), the chemicals are injected via metering pumps and injected into the intake structure. Concentrations of chlorine in the circulation water system outfall are DCPP UNITS 1 & 2 FSAR UPDATE 10.4-8 Revision 21 September 2013 discussed in detail in Reference 1 and the National Pollutant Discharge Elimination System permit. 10.4.5.3 Safety Evaluation The circulating water pumps are not required for safety of the units. Dependable pump operation is necessary, however, for reliable operation of electric generating plants and provisions to ensure their operation are incorporated in the design. 10.4.5.4 Flooding Due to the low operating pressure of the circulating water system, the probability of a line, expansion joint, or waterbox failure is very low. The differential head across the circulating water pumps at shutoff is a nominal 160 feet. At high tide, the pump discharge head at shutoff would be 163.4 feet, measured at elevation zero, MSL datum. However, provisions exist in the design of the circulating water system that prevent the circulating water pumps from operating at shutoff head.
The design of the inlet and outlet of the circulating water to the condenser consists of several components. The circulating water flows through the embedded supply conduit, the inlet transition spool piece, the inlet expansion joint, and inlet condenser water box prior to entering the condenser tubes. Similarly, upon exiting the tubes, the circulating water passes through the outlet waterbox, expansion joint, transition spool piece, and embedded discharge conduit prior to being discharged to the ocean. The transition spool pieces, expansion joints, and condenser (including waterboxes) are located in the turbine building. The discharge gates are located in the embedded discharge conduit in the yard. The design pressure of the rubber expansion joints on the inlet and outlet of the condenser (located at an elevation of 85 feet) is 81 feet.
Thus, if a circulating water pump were to pump against closed discharge gates, the pressure on the expansion joint (the pump discharge head minus the static elevation head) would be less than the design pressure. The design pressure of the transition inlet and outlet spool pieces (located at an elevation of 81 feet) is 58 feet. Similarly, the design pressure of the condenser water boxes (located at an elevation of 85 feet) is 58 feet. To prevent operating the circulating water pump and system in a configuration that could result in overpressurizing the transition spool pieces and waterboxes, mechanical stops on the condenser discharge gate operators and structural stops on the gate guide tracks inhibit the complete closing of the discharge gates. Dynamic water hammer pressures will not occur due to inadvertent closing of the water gates because the motor operators close the gates at a rate of only 15 inches per minute. These measures make circulating water system overpressurization a highly improbable event.
DCPP UNITS 1 & 2 FSAR UPDATE 10.4-9 Revision 21 September 2013 Inlet spool pieces and water boxes are constructed of ductile carbon steel, and their catastrophic failure, such that significant seawater could flood the turbine building, is not a credible assumption. The cast iron outlet spool piece was hydrotested to 1.5 times the maximum attainable circulating water system pressure.
A flooding analysis was performed based on the failure of an operator to properly secure a condenser waterbox manway cover. In order to obtain a conservative flooding rate for this scenario, waterbox manhole cover failure was assumed to be coincident with an operating error in which both circulating water pumps were running and both discharge gates were closed to the stops. In this event, approximately 43,000 gpm or 5,700 cfm of water could be expected to flow from a lower inlet waterbox manhole (the manholes with the greatest incident head of water). This flow would fill the sump and equipment pit storage areas below elevation 85 feet in 15 minutes, if the building drains are assumed to be functioning, and in 10 minutes, if the drains are not functioning. During this time, alarms would be given for turbine building sump high level and for water in the condenser pit. It may be assumed that the condensate pumps, being flooded, would have tripped, giving dramatic indication of an irregular condition.
In order to provide additional time for operators to react to this flooding casualty, a fire door was installed between the main condensers and the corridor to the emergency diesel generator rooms in order to minimize the amount of water that could enter the compartments. The door is locked closed and monitored through the security system. This door will allow at least 12 more minutes (assuming no flow of water from the building) for the postulated manhole failure flow after sumps and pits are flooded, during which corrective action (tripping the circulating water pump involved or opening doors to the outside of the building, or both) may be taken before availability of the emergency generators could be jeopardized. Subsequent to the fire door installation, a float switch system was mounted on the walls of the condenser pit. This instrumentation system eliminated the need for operator action in order to protect safety-related equipment from any type of circulating water system leakage. The system will automatically trip the circulating water pumps if water fills the condenser pit thereby assuring that the turbine building can not be flooded by a circulating water system leak. The system employs two out of three logic for a high degree of reliability and it provides a high condenser pit level alarm indication in the control room. 10.4.6 CONDENSATE POLISHING SYSTEM The condensate polishing system removes both dissolved and suspended corrosion products and impurities from the condensate. The system is important to maintaining secondary water chemistry and minimizes the buildup of sludge in the steam generators, but has no safety-related function.
DCPP UNITS 1 & 2 FSAR UPDATE 10.4-10 Revision 21 September 2013 10.4.6.1 Design Bases The condensate polishing system is designed to polish the full condensate flow during startup and normal plant operation. During startup, the system allows recirculation of condensate at approximately 5500 gpm through the condensate polishing demineralizers and feedwater heaters, returning it to the main condenser. This design provision allows a more complete cleanup of secondary water prior to system startup. The vessels are designed to Section VIII of the ASME code. The system piping is designed to ANSI B31.1. 10.4.6.2 System Description The condensate polishing system is comprised of seven mixed bed demineralizers. Either six or seven demineralizers are in service processing the full condensate flow (approximately 21,000 gpm) depending on whether any one of the demineralizers is in the regeneration mode or not. The demineralizer in the regeneration mode is taken out of service and is regenerated externally in order to minimize the possibility of introducing regenerant chemicals in the condensate and feedwater system. The external regeneration process for one demineralizer normally takes about 12 to 16 hours.
Components of the condensate polishing system, including demineralizers, regenerators, and associated equipment, are located in the turbine building buttresses. The system is capable of either automatic or manual operation, and can be bypassed if necessary.
10.4.6.3 Safety Evaluation The condensate polishing system has no safety-related function and is classified as Design Class II. Although located within the Design Class I buttresses, the system and component supports, including enclosures, do not compromise the Design Class I seismic requirement of the turbine building buttress structure.
Personnel safety provisions include smoke detectors and portable fire extinguishers in compartments where potential for fire exists. Eyewashes and a safety shower are also provided in the chemical storage and chemical feed pump areas. 10.4.7 CONDENSATE AND FEEDWATER SYSTEM The condensate and feedwater system, shown in Figures 3.2-2 and 3.2-3, receives condensate from the condenser hotwells and delivers it to the steam generator at the required pressure and temperature. In the steam generator, the condensate removes heat from the reactor coolant and is converted into steam.
DCPP UNITS 1 & 2 FSAR UPDATE 10.4-11 Revision 21 September 2013 10.4.7.1 Design Bases The condensate and feedwater system is primarily a Design Class II system except for a part of the feedwater system that supplies heated water to the steam generators. The steam generator feedwater pumps are designed for maximum calculated load operating conditions (see Figures 10.1-5 and 10.1-1, for DCPP Units 1 and 2, respectively), and are capable of supplying the required feedwater flow to the steam generators under transient load reduction conditions. The condensate pumps and condensate booster pumps provide adequate suction pressure to the feedwater pumps under load transient conditions. During a main turbine control system load drop anticipate transient or a loss of feedwater pump load reduction, the standby condensate pump / condensate booster pump set will start, the stator coil and cooling water flow for valve FCV-31 will open, and hotwell rejection valve LCV-12 will close to provide adequate suction to the feedwater pumps.
The criteria for feedwater line isolation valve closure are discussed in Section 6.2. The pressure-retaining components, or compartments of components, conform to the following codes as minimum design criteria:
(1) System pressure vessels and feedwater heaters - ASME Boiler and Pressure Vessel Code, Section VIII (2) System valves, fittings, and piping - ANSI Code for Pressure Piping B31.1 and B31.7 where applicable. The feed lines from the isolation valves to the steam generators are covered by the ASME Boiler and Pressure Vessel Code, Section I 10.4.7.2 System Description The main condensate and feedwater system is of the closed type, with deaeration accomplished in the condenser. Condensate is pumped through the generator hydrogen coolers and stator coolers, the gland steam condenser, and the air ejector condensers to the suction of the condensate booster pumps, which pump the condensate though the condensate polishing system and five stages of low-pressure feedwater heaters to the feedwater pumps. The water discharged from the feedwater pumps flows through the single stage of high pressure heaters into the steam generators. All feedwater heaters are horizontal, one-third-size units (three in parallel),
except heater 6 drain cooler, which is a single full-size straight tubed heat exchanger.
Three half capacity, three-stage, vertical, can-type, centrifugal, motor driven condensate pumps are provided with separate hotwell suction lines and a common discharge manifold. Three condensate booster pumps are provided. These are half capacity, horizontal, split case, centrifugal, motor driven pumps with common suction and discharge manifolds. Two half capacity, high speed turbine driven feedwater pumps are provided, with common suction and discharge manifolds. All pumps are equipped with minimum flow protective devices. DCPP UNITS 1 & 2 FSAR UPDATE 10.4-12 Revision 21 September 2013 Feedwater flows to the steam generators through four lines penetrating the containment, one line for each steam generator. Flow regulating valves, isolation valves, bypass regulating valves, and a check valve are installed in each line outside the containment.
A feedwater pump control system controls the speed of the turbine-driven feedwater pumps to achieve a programmed pressure differential between the feedwater header leaving the number 1 feedwater heaters and the main steam common header. The programmed pressure differential varies as a function of unit load. Feedwater header-steam-header differential pressure indication is also provided in the control room.
Each feedwater flow regulator is positioned by its own three-element control system (see Chapter 7). All main feedwater piping downstream from the final feedwater check valve and motor-operated isolation valve (inclusive) is designed to meet Design Class I requirements. Warmup lines are provided on the discharge of the feedwater pumps to circulate heated feedwater back through an idle feedwater pump to keep it warm and ready for service.
Drains from feedwater heaters 1 and 2 flow to the heater 2 drain tank with the flashed steam from the drain tank vented to heater 2. The heater 2 drain pump takes suction from the heater 2 drain tank and discharges to the feedwater pump suction manifold. Drains from the four lower pressure heaters cascade to the heater 6 drain cooler and then to the main condenser. 10.4.7.3 Safety Evaluation The main condensate and feedwater system does not have to operate to ensure safe shutdown of the NSSS. The auxiliary feedwater system, described in Section 6.5, provides adequate feedwater to the steam generators from the condensate storage tank in the event of a loss of main feedwater. The reactor transient and radiological consequences of a main feedwater line break are discussed in Section 15.4.2. The rupture of a main feedwater line is one of the principal breaks considered in the analysis of dynamic effects of pipe breaks outside the containment. Additional barriers and restraints have been added, as required, to protect safety systems from a feedwater line rupture, or protect the feedwater line from another line rupture. In the event leakage develops from one of the feedwater heaters, that heater can be isolated and repaired while the generating unit remains on line. Since the secondary side is normally not radioactive, most leakage through valve seals will not present any radiological problems. The consequences of having the secondary side of the plant radioactive due to steam generator leakage are discussed in Chapters 11 and 15.
The Design Class I portion of the feedwater system is physically located well above ground elevation and is not susceptible to failure by flooding from other ruptured systems. The active components in the main feedwater system required to operate in the event of a design basis accident are the check valves upstream of the auxiliary DCPP UNITS 1 & 2 FSAR UPDATE 10.4-13 Revision 21 September 2013 feedwater nozzles on the main feedwater lines, the main feedwater motor-operated isolation valves, and the main feedwater control and bypass control valves.
Feedwater is introduced into the steam generators through a feedwater nozzle located in the upper shell. The nozzle does not require a flow-limiting device because the feedring itself provides this function. The nozzle contains a welded thermal liner that minimizes the impact of rapid feedwater temperature transients on the nozzle. The feedwater distribution ring is welded to the feedwater nozzle to minimize the potential for draining the ring. The feedring is located above the elevation of the feed nozzle to minimize the time required to fill the feed nozzle during a cold water addition transient. The feedwater is discharged through spray nozzles installed on the top of the ring. These features reduce the thermal fatigue loading on the feedwater nozzle, eliminate steady-state thermal stratification in the feedwater nozzle and feedwater piping elbow at the feedwater nozzle entrance, and minimize the potential for bubble- collapse water hammer in the feedwater distribution ring. The feedwater piping elbow at the feedwater nozzle entrance also contains an elbow thermal liner that minimizes the effects of thermal stratification on the elbow-to-nozzle weld and the weld of the feedwater inlet thermal sleeve to feedwater nozzle.
The steam generator feedring is fabricated from alloy steel with a significant chromium content to provide enhanced erosion/corrosion resistance characteristics. The feedring has spray nozzles that are spaced around the feedring circumference to distribute the feedwater into the upper shell recirculating water pool. The spray nozzle perforations also act to prevent loose parts ingress from the feedwater system.
Also, following a review of the experience with water hammer at other plants in that portion of the feedwater piping inside the containment (the Design Class I portion at Diablo Canyon), this piping has been modified as shown in Figures 10.4-2 and 10.4-3 to minimize the possibility of a damaging water hammer. 10.4.7.4 Flooding A postulated failure of the condensate or feedwater Design Class II piping in the turbine building would result in approximately 19,800 cubic feet of the water being released to the turbine building floor, if the entire contents of the hotwell and heater drain tank were discharged. Maloperation of the condensate or feedwater system due to a broken pipe would be detected by feedwater heater temperature transients or pump trips due to runout overcurrent. In addition, level switches, which alarm in the control room, are installed in the turbine building sump and in the condenser pit closest to the diesel generators of each unit to alert the operator to the flooding condition. Spillage from most broken pipes could be detected and isolated before significant flooding occurred.
Adverse environmental conditions created by flashing water from broken pipes are not expected, due to the large building volume. Environmental effects due to high energy pipe ruptures outside the containment are more fully evaluated and discussed in Section 3.6.4. DCPP UNITS 1 & 2 FSAR UPDATE 10.4-14 Revision 21 September 2013 In the event that the entire contents of the hotwell and heater drain tanks are discharged to the turbine building, the operability of Design Class I equipment (diesel generator and component cooling water heat exchangers) in the building is not endangered. The volume of water that would be discharged is within the capacity of the turbine building drain system. This system includes one 18-inch drain line from the turbine building sump of each unit to the circulating water system discharge canal (see Figure 3.2-27). If this drain were clogged, the water flow would begin to fill the turbine building sumps and equipment pits below 85 feet (see Figures 1.2-16 and 1.2-20). However, the capacity (58,000 cubic feet) below this elevation is more than three times the potential flooding volume. Water would not accumulate to a level that would endanger the operability of the diesel generators since the area of the passageway through which water may enter the room is one-half the drain area on the west side of the rooms. Because of their elevation above the turbine building floor, the component cooling water heat exchangers are not susceptible to flooding damage.
These provisions also protect safety-related equipment from flooding damage caused by the failure of other Design Class II piping or components located in the turbine building.
The Design Class I equipment in the auxiliary building is not endangered by turbine building flooding. The area of the auxiliary building housing Design Class I equipment is separated from the turbine building by 70 feet of doors and passageways. If water does enter the auxiliary building, it will drain to the building pipe tunnel, which has a capacity of approximately 345,000 gallons. The auxiliary building drain system is completely separate from the turbine building system so back flow through the drain system is not possible. 10.4.8 STEAM GENERATOR BLOWDOWN SYSTEM The steam generator blowdown system is used in conjunction with the condensate and feedwater chemical injection system and the condensate polishing system to maintain steam generator water chemistry within the plant-specific limits.
The steam generator blowdown system for each unit is composed of two processing paths. One path discharges blowdown flow via the steam generator blowdown tank to the circulating water discharge tunnel. The other path recycles blowdown flow to the main condenser via the blowdown treatment system and/or the blowdown treatment bypass line. The recycle path can discharge a portion of blowdown flow to the discharge tunnel. Blowdown flow for each unit can be directed to either blowdown path alone, or to both paths simultaneously. 10.4.8.1 Design Bases The blowdown tank process path and the blowdown treatment portion of the recycle process path are designed for 150 gpm of water from four steam generators on a continuous basis. The blowdown treatment bypass portion of the recycle path, including DCPP UNITS 1 & 2 FSAR UPDATE 10.4-15 Revision 21 September 2013 the flash tank, is designed for 1 percent of main steaming rate at 100 percent plant load from four steam generators on a continuous basis. These continuous flow ratings may be exceeded during plant startup and other plant evolutions based on engineering evaluation.
During plant operation, steam generator shell-side water concentrates suspended and dissolved solids that are brought in by the feedwater. Water must be blown down to maintain water chemistry as specified in plant procedures.
The steam generator blowdown system is classified as Design Class II downstream of the containment isolation valves. 10.4.8.1.1 On-Line Monitoring The blowdown system is continuously monitored for radioactivity. The sampling system parallels the blowdown flow from each steam generator. Continuous sampling and monitoring for radioactivity is accomplished with a single composite sample taken from the four steam generator sample lines and passed through a radiation monitor. Sampling and monitoring of nonradioactive solids is accomplished by continuous conductivity measurements and grab sample analysis. 10.4.8.1.2 Isolation Criterion The criterion used for isolation of the blowdown system is based on the concentration of activity in the blowdown. When the sampling system radiation monitor detects a preset activity level, the steam generator blowdown isolation valves and the blowdown tank effluent valve close. The isolation system has been designed so that the blowdown tank effluent valve closes before any significant radioactive liquid reaches the effluent isolation valve. Upon detection of activity, plant personnel may process the blowdown via the blowdown treatment system as directed by the Chemistry Section. 10.4.8.1.3 Design Codes The system valves, fittings, and piping from the steam generators up to and including the first manually operated gate valves outside of the containment are designed to ASME Boiler and Pressure Vessel Code, Section I, ANSI B31.7 criteria from the manual gate valve to the pneumatic-operated flow control valve, and to ANSI B31.1 downstream of these control valves, including the blowdown treatment system. The tanks, heat exchangers, filters, and demineralizers in the blowdown system and blowdown treatment system are designed to Section VIII of the ASME Boiler and Pressure Vessel Code. 10.4.8.2 System Description Blowdown flow in the discharge path is processed via the steam generator blowdown tank; approximately 35 percent of the blowdown flow flashes to steam inside the tank DCPP UNITS 1 & 2 FSAR UPDATE 10.4-16 Revision 21 September 2013 and is vented to the atmosphere. The remaining liquid, approximately 65 percent of the blowdown flow, is discharged by gravity to the condenser circulating water discharge.
Blowdown flow in the recycle path may be processed by the blowdown treatment system or the blowdown treatment bypass line. This treatment system reduces the temperature and pressure of the water. The treatment system may also demineralize and recycle the blowdown water to the condensate system. In the treatment system, blowdown enters a flash tank where it is reduced in pressure. Flashed water vapor is vented from the tank through a pressure control valve to either a feedwater heater to improve cycle thermal efficiency or to the main condenser. The blowdown liquid then passes through a heat exchanger where the temperature is further reduced to approximately 110°F. The liquid may then enter a prefilter and demineralizer before being recycled to the main condenser. If required, a portion of the flash tank liquid flowing out of the heat exchangers can be routed to the plant outfall via the blowdown overboard drain line to improve the secondary water chemistry.
Blowdown water first passes through a prefilter and is then directed through one of two 60 cubic foot mixed bed demineralizers. The demineralizer removes both radioactive and nonradioactive ionic impurities. Upon exhaustion, the resin will be replaced or the demineralizer will be regenerated. The liquid is then recycled to the main condenser. The blowdown treatment bypass line routes the depressurized, undemineralized blowdown directly to the condenser.
A piping and instrumentation schematic for the steam generator blowdown system is shown in Figure 3.2-4. 10.4.8.3 Safety Evaluation The blowdown system's effect on plant safety is minimal, since neither the blowdown function nor the treatment function is required continuously. Either function may be interrupted temporarily to replace failed components. Neither function is required to operate following a LOCA.
Ruptured components or failed-open valves could cause unplanned blowdown of secondary steam. Since blowdown piping in this system is 6 inches or smaller, such pipe break accidents fall within the category of minor secondary system pipe breaks. Consequences of this type of accident are detailed in Sections 15.2.14 and 15.3.2. The probability of radiation leakage is small since the system is normally nonradioactive. If, however, a failure of a blowdown pipe occurs while steam generator leakage is also taking place, the consequences are within the limits described in Section 15.3.2 for minor secondary system pipe breaks.
The blowdown treatment system is shown schematically in Figure 3.2-4. All filter and demineralizer components are located in the auxiliary building, from which leakage is processed through the liquid radwaste system. An automatically controlled isolation valve provides shutoff of the blowdown discharge path to the plant outfall if significant DCPP UNITS 1 & 2 FSAR UPDATE 10.4-17 Revision 21 September 2013 activity is detected. In any case, the results of failure are bounded by those of the pipe break referred to above. 10.4.8.4 Radiological and Environmental Effects The evaluation of radiological and environmental effects is treated in Section 11.2. 10.4.8.5 Inspection and Testing The steam generator blowdown system is operated continuously during plant operation, thereby demonstrating system operability without the special inspections or testing required for standby systems. Equipment evaluations and inspections are performed periodically on the blowdown systems. 10.4.9 CONDENSATE AND FEEDWATER CHEMICAL INJECTION SYSTEM Chemical feed equipment is provided for chemical additions to the discharge of the condensate polishing system, to the main feedwater pumps' suction header, and to the discharge of the auxiliary feed pumps (see Figure 3.2-3 for the location of the injection points). The chemicals are injected into the condensate and feedwater system to prevent corrosion in the feedwater system and the steam generators. The condensate and feedwater chemical injection system has no safety function and is classified as Design Class II. 10.4.9.1 Design Bases The condensate and feedwater chemical injection system is designed to provide the following chemical additions to the condensate and feedwater systems:
(1) Ethanolamine to the discharge line of each demineralizer in the condensate polishing system or to the condensate pumps' discharge header when the condensate polisher system is out of service, as required, to control the pH of the feedwater and steam generator water. (2) Hydrazine, or a mixture of hydrazine and carbohydrazide, to the main feedwater pump suction piping to scavenge oxygen from the feedwater to an undetectable level with a residual of hydrazine at the inlet to the steam generators. Because of the similarity with hydrazine and carbohydrazide being bounded, from a safety and environmental perspective, by hydrazine, the mixture will be handled as if it were hydrazine. (3) Ethanolamine and hydrazine, or other chemicals as specified by chemistry procedures, to the auxiliary feed pumps discharge to control the chemistry in the steam generators when the auxiliary feed pumps are used to supply water to steam generators.
DCPP UNITS 1 & 2 FSAR UPDATE 10.4-18 Revision 21 September 2013 (4) Boric acid solution to the main feedwater pump suction piping to reduce denting of tubes in the steam generator. (5) Other chemicals as specified by chemistry procedures. The system provides the capability to condition the water in the steam generator during wet lay-up, hydrotesting, and other times when the main feedwater system is not in operation. 10.4.9.2 System Description Three sets of chemical feed pumps are available in each unit. The first set consists of 3 high-capacity chemical feed pumps used to inject chemicals at a feed rate of 2 to 26 gph. Individual pumps are dedicated to ethanolamine and hydrazine/carbohydrazine injection, with the third pump on standby for either service. The high-capacity pumps are simplex, metering, reciprocating, hydraulic, diaphragm type pumps that are not used under normal operating conditions.
During normal operation, a second chemical injection feed system in each unit is used to inject concentrated ethanolamine and hydrazine solutions.
The condensate hydrazine and ethanolamine feed system for each unit consists of a 250-gallon stainless steel hydrazine day tank with two chemical feed pumps, one in operation and one standby, and a 250-gallon stainless steel ethanolamine day tank with two chemical feed pumps, one in operation and one standby. Bulk 35 percent (by weight) hydrazine is stored in liquibins provided by the chemical supplier and is pumped by a 1-gpm transfer pump to the hydrazine day tank. A 6,000 gallon closed vertical pressure vessel, with a fume scrubber and two positive displacement, gear type transfer pumps, stores and supplies the ethanolamine hydroxide chemical (85 percent aqueous solution of ethanolamine) for both units. The concentrated solution is pumped as needed to the ethanolamine day tank. The four chemical feed pumps are simplex, metering, reciprocating, hydraulic, diaphragm type pumps. Pump output is controlled by changing the length of the piston stroke. The piston stroke length is manually controlled with a micrometer knob located on the feed pump. The desired ethanolamine and hydrazine concentration in the condensate can be controlled by manually adjusting the pump stroke. The water is monitored for conductivity and dissolved oxygen at the condensate pump discharge. Conductivity and dissolved oxygen, plus pH and hydrazine concentration, are also monitored at the final feedwater header before branching to the four steam generators.
A third chemical feed system is available, but not normally used. It is similar to the 2nd chemical system described above, except the hydrazine day tank is 200 gallons, the ethanolamine day tank is 300 gallons, and the 4 chemical feed pumps are duplex pumps. Condensate from the condensate pump discharge header can be used to dilute the hydrazine and ethanolamine in the respective chemical day tank.
DCPP UNITS 1 & 2 FSAR UPDATE 10.4-19 Revision 21 September 2013 The auxiliary feed pump chemical feed system for each unit consists of a 500 gallon stainless steel tank, a 300 gallon stainless steel tank, and five chemical feed pumps that are piped so that the fifth pump is used as a shared spare. The five chemical feed pumps are each 2-20 gallons per hour capacity pumps similar to the high-capacity condensate hydrazine and ethanolamine chemical feed system pumps. The pump stroke and hence chemical feed rate will be manually controlled. The chemical feed pumps pump into the discharge side of the auxiliary feed pumps. An injection line runs to the discharge of each of the three auxiliary feed pumps.
The secondary boric acid system consists of two boric acid mix/feed tanks (each tank having a capacity of 1325 gallons), three 50 percent feed pumps (each pump having a capacity of 60 gallons per hour), and a screw feeder for loading the boric acid to the mix/feed tanks. Also provided are two tank mixers (mechanical agitators) for ensuring a complete and thorough mixing of the boric acid solution in the tanks. The pumping injection flow rate will be manually controlled, primarily based on the boric acid concentration in the steam generator blowdown. 10.4.9.3 Safety Evaluation The condensate and feedwater chemical injection systems are designed to provide adequate amounts of conditioning chemicals to the secondary system, as required, for the prevention of corrosion in the condensate and feedwater systems and the steam generators.
The ethanolamine/hydrazine injection pumps and supply tanks for the condensate system are located in the turbine building west buttress and the turbine building. The concentrations in the ethanolamine and hydrazine supply tanks can be up to 85 percent and 35 percent, respectively. The tanks are vented to the outside of the building. There are no engineered safety features in the vicinity that would be damaged or rendered inaccessible by a ruptured supply tank.
The bulk ethanolamine storage tank, its fume scrubber, and its two transfer pumps are located in the turbine building west buttress, which houses the condensate polishers. Toppling of this vertical tank is not expected to damage the nearby safety-related diesel fuel oil lines which are inside an adequately covered recessed pipe trench. Any accidental chemical spill, which is harmless to the steel pipes, would be confined within the trench and be prevented from reaching the diesel generator room by firestops. The auxiliary feed pump chemical injection system supply tanks are located in the auxiliary building over a ventilation opening at the 115 foot elevation floor. The auxiliary feed pumps served are located below on the 100-foot elevation floor. A ruptured supply tank could cause 300 or 500 gallons of solution to fall partially on one of the motor-driven auxiliary feed pumps, Number 1-3. The motor has a drip-proof enclosure and the centerline of the pump motor unit is 2 feet-6 inches above the 100-foot floor elevation. The area is drained by two 4 inch floor drains. The floor area in the vicinity of the auxiliary feed pumps is in excess of 1000 square feet so that 500 gallons would cause less than 1 inch of depth on the floor. Motor-driven Auxiliary Feed Pump 1-3 could DCPP UNITS 1 & 2 FSAR UPDATE 10.4-20 Revision 21 September 2013 possibly be put out of service, due to water in the motor, by this accident; however, the second motor-driven pump and the turbine-driven pump would still be available.
The boric acid mix/feed tanks are located in the turbine building at the 85-foot elevation (ground level). The boric acid feed pumps are also located at this elevation. The floor area at this elevation (ground level) is large enough so that a ruptured feed tank would cause only a negligible depth of water on the floor, even though up to 1100 gallons of solution could be released. The only safety related component that could be affected by water is the diesel generator fire protection controls for Unit 1 only. These controls are wall mounted in a splash-proof box. In addition, the feed tanks are constrained to prevent any lateral movement or overturning and resist a seismic event. There are no other engineered safety features in the vicinity that would be damaged or rendered inaccessible by a ruptured feed tank. The feed tanks are purged with nitrogen and vented to the building. 10.4.9.4 Instrumentation Application The rate of feed of the chemical injection pumps into the main condensate and feedwater systems is proportioned to feedwater flow with manual adjustment of rate of chemical injection to rate of feedwater flow. The main condensate and feedwater supply tanks are equipped with level gauge glasses. The auxiliary feedwater supply tanks are equipped with low level alarm switches in addition to level gauge glasses. The chemical feed pump motors will alarm on overcurrent.
The pumping injection flow rate for the boric acid injection system will be manually controlled based on the boric acid concentration in the steam generator blowdown. The feed tanks are equipped with level indicators and the feed pumps include thermal overload protection. 10.4.10 REFERENCES 1. Final Environmental Statement for Diablo Canyon Power Plant, U.S. Nuclear Regulatory Commission, Washington, D.C., May 1973. 10.4.11 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures. DCPP UNITS 1 & 2 FSAR UPDATE Revision 13 April 2000 TABLE 10.1-1 STEAM BYPASS AND RELIEF VALVES Design Class(a) Relieves to Pressure Mode Pressure(b) Capacity 10% Main Steam Power-operated Valves (10%): I Atmosphere Operating 790 psia 327,255 lb/hr Maximum 1,179 psia 495,949 lb/hr
Turbine Bypass Valves (40%): II Condenser Operating 790 psia 527,099 lb/hr Maximum 1,165 psia 789,875 lb/hr
Power-operated Steam Relief Valves (35%): II Atmosphere Operating 790 psia 612,014 lb/hr Maximum 1,165 psia 917,123 lb/hr
Main Steam Spring-loaded Safety Valves: Design Class Relieves to Set Pressure At 3% Accumulation Valve Full Open Orifice Size (inches) I Atmosphere 1,065 psig 803,790 lb/hr 867,431 lb/hr 4.515 I Atmosphere 1,078 psig 813,471 lb/hr 877,875 lb/hr 4.515 I Atmosphere 1,090 psig 822,408 lb/hr 887,516 lb/hr 4.515 I Atmosphere 1,103 psig 832,090 lb/hr 897,960 lb/hr 4.515 I Atmosphere 1,115 psig 841,027 lb/hr 907,601 lb/hr 4.515 (a) PG&E Design Class; see Table 3.2-1 (b) Ref.: DCMs M-46 (U-1) and M-71 (U-2) 10% pressure values from envelopes of lines 227 and 228, which have the highest accident pressure 35% pressure values from envelope of line 590, which supplies the PORVs 40% pressure values from envelope of line 587 supplying the valves DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 10.1-2 SECONDARY SYSTEM OPERATING PARAMETERS AT 100 PERCENT RATED POWER Mass of water in one steam generator, lb 102,600 Mass of steam in one steam generator, lb 6,900 Secondary side operating temperature, °F 522 Steam generator blowdown tank capacity, ft3 641 Air ejector flowrate - rated, scfm 25
- expected average, scfm 2.5
Total mass of water in secondary system, lb 2,800,000 Total mass of steam in secondary system, lb 60,000
DCPP UNITS 1 & 2 FSAR UPDATE Revision 12 September 1998 TABLE 10.3-1 MAIN STEAM LINE VALVE PLANT STARTUP LEAKAGE TEST RESULTS Valve Type and Leakage Path Quantity Leakage per Valve Leakage to atmosphere through seat of 6-inch safety valves(a) 20 10 bubbles/min Leakage to atmosphere through seat of 8-inch power-operated relief valves 4 24 cc/hr Leakage to auxiliary feed pump turbine through seat of 4-inch isolation valves 2 6 cc/hr Leakage to atmosphere through stems of gate valves in series with power-operated relief valves(b) 4 12 cc/hr Leakage to atmosphere through stems of main steam isolation valves(c) 4 4 cc/hr Leakage to atmosphere through stems of globe valves bypassing the main steam isolation valves 4 negligible (a) Tested in accordance with API Standard 527. Test made after popping with nitrogen and then pressure reduced to 92 percent of nitrogen popping pressure. (b) Tested seat at 1500 psig for 3 minutes. Result shown is maximum of all valves tested - hydro test. (c) Requirement: leakage per valve shall not exceed 2 cc of water per hour when subjected to hydrostatic pressure of 1100 psig, or 0.06 scfh of air with a differential pressure of 80 psi. There are two valves per valve assembly. These are purchase specifications, not operational test requirements. DCPP UNITS 1 & 2 FSAR UPDATE Revision 17 November 2006 TABLE 10.4-1 MAIN CONDENSER PERFORMANCE DATA The condenser for each unit has two shells. The data given below are based on the full load heat balance. Characteristics Unit 1 Shell Unit 2 Shell Total heat load, Btu/hr(c) 8.19 x 109 8.19 x 109 Absolute pressure in condensing zone, in. Hg (with 56.5°F circulating water temperature at inlet to condenser) 1.71 1.71 Circulating water flow, gpm(d) 862,000 862,000 Average velocity in tube, ft/sec 6.8 6.8 Effective surface area, ft2 (e) 618,150 618,150 Cleanliness factor, % (a) 85 85 Tube outside diameter, in. 1 1
Tube BWG 22 22
Tube overall length, ft 40 ft 9 in. 40 ft 9 in.
Tube effective length, ft 40.56 40.56
Number of tubes 58,216 58,216 Total condensate stored at maximum operating level (82 ft-6 in.), cu ft 18,880(b) 18,880(b) (a) This is the percent of clean tube heat transfer coefficient used in the design of the condenser. (b) There is a single hotwell for each unit. (c) The Units 1 and 2 condensers were originally rated for a nominal heat load of 7.6x109 Btu/hr. The post Alstom LP Turbine Retrofit heat loads based upon the Alstom supplied "Full Load" heat balance diagrams for Units 1 and 2 are bounded by the Westinghouse approximated value shown in the table. Refer to Figures 10.1-6 and 10.1-2 for the full load heat balances, Units 1 and 2, respectively. (d) This is a nominal value based on pump design documents and impacts on flow due to varying tidal conditions. (e) Vendor supplied value. It is considered a nominal value.
FIGURE 10.2-1 STEAM GENERATOR CHARACTERISTIC PRESSURE CURVES UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008 Revision 11 November 1996 FIGURE 10.3-6 LOCATION OF STEAM LINES AND VALVES UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 10.4-2 REVISION OF STEAM GENERATOR FEEDWATER PIPING STEAM GENERATORS 1 AND 4 UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996FIGURE 10.4-3 REVISION OF STEAM GENERATOR FEEDWATER PIPING STEAM GENERATORS 2 AND 3 UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE DCPP UNITS 1 & 2 FSAR UPDATE i Revision 21 September 2013 Chapter 11 RADIOACTIVE WASTE MANAGEMENT CONTENTS Section Title Page 11 RADIOACTIVE WASTE MANAGEMENT 11-1
11.1 SOURCE TERMS 11.1-1
11.1.1 Basic Physical Data and Constants 11.1-2
11.1.2 Determination of Activity Inventories in Reactor Core 11.1-2
11.1.3 Determination of Inventories in Fuel Rod Gaps 11.1-3
11.1.4 Determination of Primary Coolant Activities 11.1-3
11.1.5 Determination of Tritium Activities in Primary Coolant 11.1-4 11.1.5.1 Ternary Fissions - Cladding Diffusion 11.1-4 11.1.5.2 Tritium Produced from Boron Reactions 11.1-4 11.1.5.3 Tritium Produced from Lithium Reactions 11.1-4 11.1.5.4 Control Rod Sources 11.1-5 11.1.5.5 Tritium Production from Deuterium Reactions 11.1-5 11.1.5.6 Total Tritium Sources in Coolant 11.1-5 11.1.6 Determination of Secondary System Activities 11.1-5
11.1.7 References 11.1-6
11.2 LIQUID WASTE SYSTEM 11.2-1
11.2.1 Design Objectives 11.2-1
11.2.2 System Description 11.2-2 11.2.2.1 General 11.2-2 11.2.2.2 Equipment Drain or Closed Drain Subsystem 11.2-2 11.2.2.3 Floor Drains and Open Drain Subsystem 11.2-6 11.2.2.4 Chemical Drain Subsystem 11.2-9 11.2.2.5 Laundry and Hot Shower, and Laundry/Distillate Subsystem 11.2-9 11.2.2.6 Demineralizer Regenerant Subsystem 11.2-9
11.2.3 Liquid Radwaste System Operation 11.2-10
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 11 CONTENTS (Continued) Section Title Page ii Revision 21 September 2013 11.2.3.1 Liquid Radwaste Processing Sub System 11.2-10 11.2.3.2 Liquid Radwaste Discharge Sub System 11.2-10
11.2.4 System Design 11.2-10
11.2.5 Performance Data 11.2-11
11.2.6 Plant Releases 11.2-11 11.2.6.1 Current Operational Releases 11.2-11 11.2.6.2 Pre-operational Estimated Release Evaluation 11.2-11 11.2.7 Release Points 11.2-15 11.2.7.1 Turbine Building Drain System 11.2-15 11.2.7.2 Steam Generator Blowdown System 11.2-16 11.2.7.3 Condensate Demineralizer Regenerant Solution 11.2-17 11.2.7.4 Typical Volumes Released 11.2-17
11.2.8 Dilution Factors 11.2-18 11.2.8.1 Current Operational Doses 11.2-18 11.2.8.2 Pre-operational Dose Factors 11.2-18
11.2.9 Calculated Doses 11.2-19 11.2.9.1 Current Operation Doses 11.2-19 11.2.9.2 Pre-Operation Estimated Doses 11.2-19
11.2.10 References 11.2-20
11.3 GASEOUS WASTE SYSTEM 11.3-1
11.3.1 Design Objectives 11.3-1
11.3.2 System Description 11.3-2
11.3.3 Gaseous Radwaste System Operation 11.3-3
11.3.4 System Design 11.3-4
11.3.5 Performance Tests 11.3-4
11.3.6 Plant Releases 11.3-5 11.3.6.1 Current Operational Releases 11.3-5 11.3.6.2 Pre-operational Estimated Release Evaluation 11.3-5 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 11 CONTENTS (Continued) Section Title Page iii Revision 21 September 2013 11.3.7 Dilution Factors 11.3-8 11.3.7.1 Current Operational Dilution Factors 11.3-8 11.3.7.2 Pre-operational Dilution Factors 11.3-8
11.3.8 Doses 11.3-8 11.3.8.1 Current Operational Doses 11.3-8 11.3.8.2 Pre-operational Doses 11.3-9
11.3.9 References 11.3-9 11.4 PROCESS AND EFFLUENT RADIOLOGICAL MONITORING SYSTEM 11.4-1
11.4.1 Design Objectives 11.4-1
11.4.2 Continuous Monitoring 11.4-1 11.4.2.1 General Description 11.4-1 11.4.2.2 Process Radiation Monitoring System 11.4-3 11.4.2.3 Area Radiation Monitoring System 11.4-12
11.4.3 Sampling 11.4-14 11.4.3.1 Basis for Selection of Sample Locations 11.4-14 11.4.3.2 Expected Composition and Concentration 11.4-14 11.4.3.3 Quantity to be Measured 11.4-14 11.4.3.4 Sampling Frequency and Procedures 11.4-14 11.4.3.5 Analytical Procedures and Sensitivity 11.4-15 11.4.3.6 Influence of Results on Plant Operations 11.4-15
11.4.4 Calibration and Maintenance 11.4-15 11.4.4.1 Alarm Setpoints 11.4-15 11.4.4.2 Definitions 11.4-15 11.4.4.3 Calibration Procedure 11.4-16 11.4.4.4 Test Frequencies 11.4-16 11.4.4.5 System Summary 11.4-16
11.4.5 References 11.4-16
11.5 SOLID WASTE SYSTEM 11.5-1
11.5.1 Function 11.5-1
11.5.2 Design Objectives 11.5-1 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 11 CONTENTS (Continued) Section Title Page iv Revision 21 September 2013 11.5.3 System Inputs 11.5-1 11.5.4 Components 11.5-1 11.5.4.1 Spent Resins Processing System 11.5-2 11.5.4.2 Spent Filter/Ion Exchange Media Processing System 11.5-2 11.5.4.3 Spent Filter Cartridge Processing System 11.5-2 11.5.4.4 Mobile Radwaste Processing System 11.5-3 11.5.4.5 Dry Active Waste Processing System 11.5-3 11.5.4.6 Mixed Waste 11.5-4 11.5.4.7 Component Failures and System Malfunctions 11.5-4 11.5.5 Packaging 11.5-5
11.5.6 Storage Facilities 11.5-5
11.5.7 Shipment 11.5-6
11.5.8 References 11.5-6
11.5.9 Reference Drawings 11.5-6
11.6 OFFSITE RADIOLOGICAL MONITORING PROGRAM 11.6-1
11.6.1 Expected Background 11.6-1
11.6.2 Critical Pathways 11.6-1
11.6.3 Sampling Media, Location and Frequency 11.6-2 11.6.3.1 Marine Samples 11.6-2 11.6.3.2 Terrestrial Samples 11.6-2
11.6.4 Analytical Sensitivity 11.6-3 11.6.4.1 Types of Analyses 11.6-3 11.6.4.2 Measuring Equipment 11.6-3 11.6.4.3 Sample Detection Sensitivity 11.6-3
11.6.5 Data Analysis and Presentation 11.6-4
11.6.6 Program Statistical Sensitivity 11.6-4
11.6.7 References 11.6-5
DCPP UNITS 1 & 2 FSAR UPDATE v Revision 21 September 2013 Chapter 11 TABLES Table Title 11.1-1 Library of Physical Data for Isotopes
11.1-2 Basic Assumptions for Core and Coolant Inventories for Design Basis Case 11.1-3 Basic Assumptions for Core and Coolant Inventories for Normal Operation Case 11.1-4 Core Activity Inventories for Design Basis Case (Curies)
11.1-5 Core Activity Inventories for Normal Operation Case (Curies)
11.1-6 Basic Assumptions for Fuel Rod Gap Activities
11.1-7 Activity in Fuel Rod Gaps
11.1-8 Input Constants for Coolant Activities for Design Basis Case
11.1-9 Input Constants for Coolant Activities for Normal Operation Case 11.1-10 Basic Data for Corrosion Product Activities 11.1-11 Primary Coolant Activities for Design Basis Case
11.1-12 Primary Coolant Activities for Normal Operation Case
11.1-13 Reactor Coolant Nitrogen-16 Activity
11.1-14 Deposited Corrosion Product Activity in Steam Generator
11.1-15 Demineralizer and Evaporator Decontamination Factors
11.1-16 Production and Removals in Primary Coolant for Design Basis Case
11.1-17 Production and Removals in Primary Coolant for Normal Operation Case 11.1-18 Basic Assumptions for Pressurizer Activities
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 11 TABLES (Continued) Table Title vi Revision 21 September 2013 11.1-19 Activity in Pressurizer for Design Basis Case 11.1-20 Activity in Pressurizer for Normal Operation Case
11.1-21 Basic Assumptions for Tritium Activity in Primary Coolant
11.1-22 Tritium Activities in Primary Coolant
11.1-23 Steam System Operating Conditions Assumed for Activity Analysis for Normal Operation Case 11.1-24 Additional Secondary System Operating Parameters
11.1-25 Steam Generator Partition Factors
11.1-26 Total Additions and Removals of Activity in Each Steam Generator for Normal Operation Case (Curies) 11.1-27 Equilibrium Activities and Concentrations in Each Steam Generator for Normal Operation Case 11.1-28 Total Additions and Removals of Activity in the Condenser for Normal Operation Case (Curies) 11.1-29 Equilibrium Activities and Concentrations in the Condenser for Normal Operation Case 11.1-30 Total Additions and Removals of Activity in the Condenser Vapor Space for Normal Operation Case (Curies) 11.1-31 Equilibrium Activities and Concentrations in the Condenser Vapor Space for Normal Operation Case 11.2-1 Assumptions Used for Input Waste Streams and Activity Calculations
11.2-2 Assumptions for Calculations of Activity Released from CVCS
11.2-3 Activity Concentration Spectrum I Through V for Input Waste Sources, Design Basis Case 11.2-4 Activity Concentration Spectrum I Through V for Input Waste Sources, Normal Operation Case DCPP UNITS 1 & 2 FSAR UPDATE Chapter 11 TABLES (Continued) Table Title vii Revision 21 September 2013 11.2-5 Annual Flow and Isotopic Spectra for Liquid Waste Inputs 11.2-6 Isotopic Flows Through CVC System, Design Basis Case
11.2-7 Isotopic Flows Through CVC System, Normal Operation Case
11.2-8 Annual Flow and Activity Concentration of Process Streams for Design Basis Case 11.2-9 Annual Flow and Activity Concentration of Process Streams for Normal Operation Case 11.2-10 Equipment Design Summary Data - Liquid Radwaste System
11.2-11 Parameters Used in Tritium Analysis for Plant Water Sources
11.2-12 Deleted in Revision 1
11.2-13 Calculated and Assumed Holdup Times for Liquid Waste System Tanks 11.2-14 Estimated Annual Activity Release for Design Basis Case (One unit)
11.2-15 Estimated Annual Activity Release for Normal Operation Case (One unit) 11.2-16 Annual Flow and Activity Concentration of Process Streams for Steam Generator Blowdown Treatment System 11.2-17 Summary of Estimated Liquid Waste System Annual Waste Volumes for Units 1 and 2 11.2-18 Estimated Annual Liquid Effluent Release for Normal Operation Case with Anticipated Operational Occurrences 11.2-19 Basic Assumptions for Liquid Pathways Exposures
11.2-20 Bioaccumulation Factors
11.2-21 Effluent Concentrations After Initial Dilution: Design Basis Case
11.2-22 Effluent Concentrations After Initial Dilution: Normal Operation Case DCPP UNITS 1 & 2 FSAR UPDATE Chapter 11 TABLES (Continued) Table Title viii Revision 21 September 2013 11.2-23 Effluent Concentrations After Initial Dilution: Normal Operation with Anticipated Operational Occurrences 11.2-24 Doses Resulting from Radioactive Releases in Liquid Wastes: Design Basis Case (mrem/yr) 11.2-25 Doses Resulting from Radioactive Releases in Liquid Wastes: Normal Operation Case (mrem/yr) 11.2-26 Doses Resulting from Radioactive Releases in Liquid Wastes: Anticipated Operational Occurrences (mrem/yr) 11.3-1 Equipment Design and Operating Parameters for Gaseous Radwaste System Units 1 and 2 11.3-2 Gaseous Waste System Release: Design Basis Case (Curies)
11.3-3 Gaseous Waste System Release: Normal Operation Case (Curies)
11.3-4 Annual Gaseous Radwaste Flows
11.3-5 Maximum Activity in Gas Decay Tank: Design Basis Case
11.3-6 Maximum Activity in Gas Decay Tank: Normal Operation Case
11.3-7 Activity in Volume Control Tank: Design Basis Case
11.3-8 Activity in Volume Control Tank: Normal Operation Case
11.3-9 Gaseous Releases due to Cold Shutdown and Startups
11.3-10 Distances in Miles From DCPP Unit 1 Reactor Centerline to the Nearest Milk Cow, Meat Animal, Milk Goat, Residence, Vegetable Garden, and Site Boundary 11.3-11 Estimates of Relative Concentration (/Q) at Locations Specified in Table 11.3-10 11.3-12 Estimates of Deposition (/Q) at Locations Specified in Table 11.3-10 11.3-13 Annual Average Atmosphere Activity Concentrations at Site Boundary for Design Basis Case DCPP UNITS 1 & 2 FSAR UPDATE Chapter 11 TABLES (Continued) Table Title ix Revision 21 September 2013 11.3-14 Annual Average Atmospheric Activity Concentrations at Site Boundary for Normal Operation Case 11.3-15 Offsite Doses for NW Sector at Distance 0.5 Mi: Design Basis Case
11.3-16 Offsite Doses for NW Sector at Distance 3.6 Mi: Design Basis Case
11.3-17 Offsite Doses for NNW Sector at Distance 0.5 Mi: Design Basis Case
11.3-18 Offsite Doses for NNW Sector at Distance 1.5 Mi: Design Basis Case 11.3-19 Offsite Doses for NNW Sector at Distance 3.6 Mi: Design Basis Case
11.3-20 Offsite Doses for N Sector at Distance 0.5 Mi: Design Basis Case
11.3-21 Offsite Doses for NNE Sector at Distance 0.5 Mi: Design Basis Case
11.3-22 Offsite Doses for NE Sector at Distance 0.5 Mi: Design Basis Case
11.3-23 Offsite Doses for ENE Sector at Distance 0.7 Mi: Design Basis Case
11.3-24 Offsite Doses for ENE Sector at Distance 4.5 Mi: Design Basis Case
11.3-25 Offsite Doses for E Sector at Distance 1.0 Mi: Design Basis Case
11.3-26 Offsite Doses for ESE Sector at Distance 1.0 Mi: Design Basis Case
11.3-27 Offsite Doses for ESE Sector at Distance 3.7 Mi: Design Basis Case
11.3-28 Offsite Doses for SE Sector at Distance 1.1 Mi: Design Basis Case
11.3-29 Offsite Doses for SE Sector at Distance 3.7 Mi: Design Basis Case
11.3-30 Offsite Doses for NW Sector at Distance 0.5 Mi: Normal Operation Case 11.3-31 Offsite Doses for NW Sector at Distance 3.6 Mi: Normal Operation Case 11.3-32 Offsite Doses for NNW Sector at Distance 0.5 Mi: Normal Operation Case DCPP UNITS 1 & 2 FSAR UPDATE Chapter 11 TABLES (Continued) Table Title x Revision 21 September 2013 11.3-33 Offsite Doses for NNW Sector at Distance 1.5 Mi: Normal Operation Case 11.3-34 Offsite Doses for NNW Sector at Distance 3.6 Mi: Normal Operation Case 11.3-35 Offsite Doses for N Sector at Distance 0.5 Mi: Normal Operation Case 11.3-36 Offsite Doses for NNE Sector at Distance 0.5 Mi: Normal Operation Case 11.3-37 Offsite Doses for NE Sector at Distance 0.5 Mi: Normal Operation Case 11.3-38 Offsite Doses for ENE Sector at Distance 0.7 Mi: Normal Operation Case 11.3-39 Offsite Doses for ENE Sector at Distance 4.5 Mi: Normal Operation Case 11.3-40 Offsite Doses for E Sector at Distance 1 Mi: Normal Operation Case
11.3-41 Offsite Doses for ESE Sector at Distance 1 Mi: Normal Operation Case 11.3-42 Offsite Doses for ESE Sector at Distance 3.7 Mi: Normal Operation Case 11.3-43 Offsite Doses for SE Sector at Distance 1.1 Mi: Normal Operation Case 11.3-44 Offsite Doses for SE Sector at Distance 3.7 Mi: Normal Operation Case 11.4-1 Radiation Monitors and Readouts
11.4-2 Deleted in Revision 10
11.4-3 Radiation Monitor-Valve Control Operations
11.5-1 Solid Radwaste System Input Volumes DCPP UNITS 1 & 2 FSAR UPDATE Chapter 11 TABLES (Continued) Table Title xi Revision 21 September 2013 11.5-2 Activity in Radwaste System Demineralizers: Normal Operation Cases (Curies/Year) 11.5-3 Deleted in Revision 6
11.5-4 Activity Collected in Radwaste Filter Cartridges at Time of Replacement: Design Basis Case/Normal Operation Case 11.5-5 Summary of Radwaste Materials Shipment 11.6-1 Radiological Environmental Monitoring Program 11.6-2 Deleted in Revision 1
11.6-3 Deleted in Revision 11
11.6-4 Environmental Radiological Monitoring Program Summary
11.6-5 Deleted in Revision 1
11.6-6 Deleted in Revision 1
11.6-7 Deleted in Revision 1
11.6-8 Deleted in Revision 1
11.6-9 Deleted in Revision 1
11.6-10 Deleted in Revision 11
11.6-11 Maximum Values for the Lower Limits of Detection (LLD)
11.6-12 Deleted in Revision 11
11.6-13 Estimated Relative Concentration
11.6-14 Estimated Depositions
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 11 FIGURES Figure Title xii Revision 21 September 2013 11.1-1 R. E. Ginna Plant Tritium Sources - Measured and Predicted 11.2-1 Deleted in Revision 18
11.2-2 Liquid Waste Process Flow Diagram: Design Basis
11.2-3 Liquid Waste Process Flow Diagram: Normal Operation
11.2-4 Blowdown System Flow Diagram - Discharge Mode
11.2-5 Blowdown System Flow Diagram Recycle Path
11.2-6 Tritium Concentration in Water Versus Time
11.2-7 Tritium Airborne Concentration in Fuel Handling Area Versus Time
11.2-8 Tritium Airborne Concentration in Containment Versus Time 11.2-9 Site Plot Plan - Radwaste Discharge 11.3-1 Deleted in Revision 1
11.3-2 Deleted in Revision 1
11.3-3 Deleted in Revision 1
11.3-4 Gaseous Waste Systems' Release Points
11.4-1 Radiation Monitoring System
11.5-1 Solid Radwaste System
11.5-2 Deleted in Revision 3
11.5-3 Spent Resin Flow Diagram
11.5-4 Location of Onsite Storage Facility
11.5-5(a) Solid Radwaste Storage Building DCPP UNITS 1 & 2 FSAR UPDATE Chapter 11 FIGURES (Continued) Figure Title xiii Revision 21 September 2013 11.5-5A Deleted in Revision 11 11.5-6 Chemical and Volume Control System Displaying Filters
11.5-7 Spent Fuel Pool Displaying Filters
11.5-8 Liquid Radwaste System Displaying Filters
11.5-9 System for Capturing Expended Filter Cartridges
11.5-10 Cover of Filter Vessel
11.5-11 Spent Resin Storage Area
11.5-12 Load Out Station
11.6-1 Deleted in Revision 11 11.6-2 Deleted in Revision 11 11.6-3 Deleted in Revision 4
11.6-4 Deleted in Revision 11
11.6-5 Deleted in Revision 11
NOTE:
(a) This figure corresponds to a controlled engineering drawing that is incorporated by reference into the FSAR Update. See Table 1.6-1 for the correlation between the FSAR Update figure number and the corresponding controlled engineering drawing number.
DCPP UNITS 1 & 2 FSAR UPDATE 11-1 Revision 19 May 2010 Chapter 11 RADIOACTIVE WASTE MANAGEMENT
The purpose of this chapter is to provide a complete description and state the design objectives of the radioactive waste systems to demonstrate compliance with the general provisions of 10 CFR 20 and 10 CFR 50. Performance evaluation of the radioactive waste treatment systems is described. This chapter is divided into the following sections:
11.1 Source Terms 11.2 Liquid Waste System 11.3 Gaseous Waste System 11.4 Process and Effluent Radiological Monitoring System 11.5 Solid Waste System 11.6 Offsite Radiological Monitoring Program
In the sections on liquid and gaseous waste systems, all significant release pathways of radioactive liquids and gases are identified and discussed, including those not directly associated with waste treatment systems; for example, blowdown system releases and steam leakage.
A pre-operation evaluation of the liquid and gaseous radwaste systems was performed to demonstrate the system's ability to maintain releases within regulations. To carry out an activity analysis of the plant that covers different combinations of basic operating parameters, two cases were selected: a Design Basis Case and a case identified as "Normal Operation," which includes anticipated operational occurrences, and is hereinafter referred to as the Normal Operation Case. These cases do not represent the typical results of actual plant operation, and the operational basis and resulting values are not license limits. For the Design Basis Case, the plant was assumed to have been operated for a full year at full thermal power of 3568 Mwt with a capacity factor of 80 percent and a fuel defect level of 1 percent. The radwaste systems were assumed to be in operation as designed, and primary system leakage was assumed to be negligible. The complete set of other assumptions associated with this case are listed in Table 11.1-2 and discussed in detail in the following sections.
For the Normal Operation Case the plant was assumed to have been operated for a full year at full power with a capacity factor of 80 percent and a fuel defect level of 0.12 percent. Coincident with this condition, it was assumed that there existed primary system leakage of 100 pounds per day to the secondary system, 1 percent of primary coolant noble gas inventory and 0.001 percent of primary coolant iodine inventory to the containment, and 160 pounds per day to the auxiliary building. These assumptions are DCPP UNITS 1 & 2 FSAR UPDATE 11-2 Revision 19 May 2010 in agreement with those provided in the NRC Report NUREG-0017 for normal operation of a pressurized water reactor (PWR) (see Reference 9 of Section 11.1). The complete set of assumptions for this case is also discussed in the following sections. As a result of the analyses of these cases, the following conclusions can be drawn.
Diablo Canyon Power Plant (DCPP) Units 1 and 2 can be operated under normal conditions, including the consideration of anticipated operational occurrences in conformance with:
(1) The general provisions of 10 CFR 20 and 10 CFR 50 (2) The dose limits established in 10 CFR 20 for the release of radioactive materials (3) The radiation dose limits specified in Appendix I to 10 CFR 50 The radioactive waste release values provided in this chapter are nominal values. Actual release values are reported to the NRC in the DCPP Annual Radioactive Effluent Release Report.
DCPP UNITS 1 & 2 FSAR UPDATE 11.1-1 Revision 19 May 2010 11.1 SOURCE TERMS This section describes the routine (or operational) source term and the pre- operational evaluation of source term for the Design Basis Case and the Normal Operation Case. Routine source term: The operational source term in the reactor coolant system and supporting systems are monitored on a routine basis in accordance with plant Technical Specifications and plant approved procedures. The information is readily available to site personnel for evaluating source term and trends. The Station policy is to operate the plant with zero fuel defects to achieve a low source term in the primary coolant. The plant operating philosophy is to maintain leakage from the primary system well below Technical Specification limits. This operating philosophy is fundamental to minimizing the input of radioactive material into the liquid radwaste (LRW) and gaseous radwaste (GRW) systems, and therefore minimize activity that may be released from the station. There have been periods when a fuel leak develops and the RCS Dose Equivalent Iodine (DEI) has been near the Technical Specification value of 1.0 Ci/cc for periods of time. The station has demonstrated that the LRW and GRW systems operating per station procedures has maintained plant releases at a fraction of Technical Specification and 10 CFR 20 limits. Routine operating reactor coolant system DEI is normally only a fraction of the Technical Specification value of 1.0 Ci/cc. The routine operating source term is much lower than the cases described below. Tritium is produced as part of the fission process of the reactor and its production is a direct function of power produced and capacity factor. Tritium being an isotope of water is not removed in the treatment systems. Given that tritium has a 12.5 year half life, essentially all the tritium produced is released from the plant via the LRW system or through evaporation via the plant vent. Pre Operation source term evaluations: The preoperational evaluation of radioactive materials produced and stored in the reactor system is reported and discussed in this section. These sources have been computed for two basic sets of plant operating conditions: the Design Basis Case and the Normal Operation Case.
DCPP UNITS 1 & 2 FSAR UPDATE 11.1-2 Revision 19 May 2010 The complete isotopic source terms are presented in tabular form along with the basic assumptions used in the computations. The activities and concentrations were calculated with the EMERALD NORMAL (Reference 8) digital computer program. A detailed discussion of the physical data and assumptions used is contained in the following paragraphs: 11.1.1 BASIC PHYSICAL DATA AND CONSTANTS The values of isotopic physical data used in the radiological effects analyses are listed in Table 11.1-1. The values of half-lives and fission yields were taken from the Meek and Rider report (Reference 1) and from Tobias (Reference 10) and are in general agreement with those in TID-14844 (Reference 2) and ORNL-2127 (Reference 3). The values for average beta energies are those provided in Perkins and King (Reference 4) and the average gamma energies are taken from Tobias. The values of decay constants were calculated from the half-lives with the standard formula. The fission yields were modified to account for plutonium buildup by using the values for uranium and plutonium fissioned during an equilibrium core cycle as follows: Yield (U + Pu) = [Fissions (U) x Yield (U)] + [Fissions (Pu) x Yield (Pu)] Fissions (U + Pu) The number of fissions per megawatt-second is taken to be 3.15 x 1016, which agrees well with the value of 3.2 x 1016 used in Reference 2. 11.1.2 DETERMINATION OF ACTIVITY INVENTORIES IN REACTOR CORE The EMERALD NORMAL program was run for 11 months with zero initial activities, and the result was decayed one month. The resulting core activities (assuming one-third of the core was replaced at refueling) were then set equal to the initial activities and the process repeated. Taking one-third of the activities after the first cycle, plus one-third of the activities after the second cycle, gives an approximation to the initial activities for an equilibrium core cycle. The core inventories for the year's operating cycle were then computed using an 80 percent capacity factor to ensure a realistic inventory of Kr-85. The power level and other basic assumptions are provided in Tables 11.1-2, and 11.1-3. The resulting core inventories are listed in Tables 11.1-4 and 11.1-5. These calculated core inventories are in general agreement with those tabulated in TID-14844, with those listed in the USNRC Reactor Safety Study (WASH-1400) (Reference 12), and with those listed in the Diablo Canyon Preliminary Safety Analysis Report (Reference 5).
Actual operating configuration is 21 months of operation, with a mixture of fuel with enrichments up to 5 percent, with maximum analyzed burnup of 50,000 MWD/MTU. The EMERALD NORMAL 12-month cycle core inventory results in higher calculated doses. Therefore, it bounds the actual operating configuration. DCPP UNITS 1 & 2 FSAR UPDATE 11.1-3 Revision 19 May 2010 11.1.3 DETERMINATION OF INVENTORIES IN FUEL ROD GAPS The computed gap activities are based on buildup in the fuel from the fission process and diffusion to the fuel rod gap at rates dependent on the operating temperature. For this analysis, the fuel pellets were divided into five concentric rings, each with a release rate dependent on the mean fuel temperature within that ring. The diffusing isotope is assumed present in the gas gap when it has diffused to the boundary of the outer ring. The core temperature distribution used in this analysis, based on hot channel factors of FH = 1.70 and Fq = 2.82, is presented in Table 11.1-6. The diffusion coefficient, D', for Xe and Kr in UO2, varies with temperature in accordance with the following expression:
)16731T1(REexp'D'D)1673(T (11.1-1) where:
E = activation energy )1673('D = diffusion coefficient at 1673°K = 1 x 10-11 sec-1 T = temperature in °K R = gas constant This expression is valid for temperatures above 1100°C. Below this temperature, fission gas release occurs mainly by two temperature independent phenomena, recoil and knock-out, and is predicted by using D' at 100°C. The value used for D' (1673°K), based on data at burnups greater than 1019 fission/cc, is used to account for possible fission gas release by other mechanisms and pellet cracking during irradiation.
The diffusion coefficients for iodine isotopes are assumed to be the same as those for Xe and Kr (References 6 and 7).
The resulting fractions of core activity present in the fuel rod gaps are listed in Table 11.1-7, along with the total inventories of activity in the gaps. 11.1.4 DETERMINATION OF PRIMARY COOLANT ACTIVITIES The basic data and assumptions used in calculating the coolant concentrations for the Design Basis Case and the Normal Operation Case are provided in Tables 11.1-2, 11.1-3, 11.1-8, 11.1-9, and 11.1-10. The coolant concentrations and activities, listed in Tables 11.1-11, 11.1-12, and 11.1-13, are provided for the operating temperature. The activities of corrosion products deposited in the steam generator are provided in Table 11.1-14. The total amounts of activity produced and removed from the coolant during the operating period are provided in Tables 11.1-16 and 11.1-17. All models and equations, including parent-daughter production, purification terms, boron feed-bleed terms, and coolant leakage terms are provided in detail in Reference 8, and are DCPP UNITS 1 & 2 FSAR UPDATE 11.1-4 Revision 19 May 2010 generally consistent with those provided in NUREG-0017 (Reference 9). The demineralizer decontamination factors assumed are listed in Table 11.1-15. The basic assumptions and data used in calculating the activities on the pressurizer are listed in Table 11.1-18, and the calculated activities for the two cases are provided in Tables 11.1-19 and 11.1-20. 11.1.5 DETERMINATION OF TRITIUM ACTIVITIES IN PRIMARY COOLANT Tritium atoms are generated in the fuel at a rate of approximately 8 x 10-5 atoms per fission, or 1.05 x 10-2 curies/MWt/day. Any boron bearing control rods in the core are a potential source of tritium.
A direct source of tritium is the reaction of neutrons with dissolved boron in the reactor coolant. Boron is used in the reactor coolant for reactivity control. Neutron reactions with lithium are also a direct source of tritium. Lithium hydroxide is used for pH control.
Figure 11.1-1 shows calculated versus measured tritium production in the reactor coolant for the R. E. Ginna plant. A 10 percent release from the fuel rods was assumed for the calculation. 11.1.5.1 Ternary Fissions - Cladding Diffusion With zirconium alloy cladding, approximately 10 percent of the tritium produced in the fuel will diffuse through the cladding into the coolant (Reference 11). 11.1.5.2 Tritium Produced from Boron Reactions The neutron reactions with boron that result in the production of tritium are: B10 (n, 2 ) T B10 (n, ) Li7 (n, n ) T B11 (n, T) Be9 B10 (n, d) Be9* (n, ) Li6 (n, )T Of the above reactions, only the first two contribute significantly to the tritium production. The B11 (n, T) Be9 reaction has a threshold of 14 MeV and a cross section of 5 mb. Since the neutrons produced at this energy result in a flux of less than 109 n/cm2-sec, the tritium produced from this reaction is negligible. The B10 (n,d) reaction may be neglected since Be9* has been found to be unstable. 11.1.5.3 Tritium Produced from Lithium Reactions The neutron reactions with lithium resulting in the production of tritium are: Li7 (n, n ) T Li6 (n, ) T DCPP UNITS 1 & 2 FSAR UPDATE 11.1-5 Revision 19 May 2010 Lithium hydroxide is used for pH adjustment of the reactor coolant. Lithium concentrations may reach a value of 6.0 ppm at the beginning-of-cycle. During normal plant operations the lithium is maintained within an operational band per plant procedure. At the end-of-cycle, the lithium concentrations may decrease to 0.0 ppm. This is accomplished by the addition of Li7 OH and by a cation demineralizer included in the chemical and volume control system. This demineralizer will remove any excess of lithium such as could be produced in the B10 (n, ) Li7 reaction. The Li6 (n,) T reaction is controlled by limiting the Li6 impurity in the Li7 OH used in the reactor coolant and by lithiating the demineralizers with 99.9 atom percent Li7. 11.1.5.4 Control Rod Sources In a fixed burnable poison rod, there are two primary sources of tritium generation: the B10 (n, 2 ) T and the B10 (n, ) Li7 (n, n ) T reactions. Unlike the coolant, where the Li7 level is controlled, there is a buildup of Li7 in the burnable poison rods. The burnable poison rods are required during the first year of operation only. During this time, the tritium production is 72 curies/pound B10. The control rod materials used at DCPP are Ag-In-Cd; there are no tritium sources in these materials. 11.1.5.5 Tritium Production from Deuterium Reactions Since the fraction of naturally occurring deuterium in water is less than 0.0015, the tritium produced from this reaction is negligible (less than 1 curie per year). 11.1.5.6 Total Tritium Sources in Coolant A summary of the sources of tritium in the reactor coolant system are listed in Table 11.1-22, and all basic data and assumptions used are provided in Table 11.1-21. The calculated total tritium produced in the reactor plant, 1640 curies/year, agrees fairly well with the NUREG-0017 value of 0.4 Ci/MWt/year, which gives 1427 curies/year, the difference being conservative. 11.1.6 DETERMINATION OF SECONDARY SYSTEM ACTIVITIES In order to estimate the potential plant releases as a result of secondary system leakage or discharges, during periods when significant activity exists in the steam system, the steam system activity levels have been determined. As discussed earlier, the range of possible combinations of plant operating conditions has been represented by making an activity analysis on the basis of 0.12 percent fuel defects, coincident with a leakage of 100 pounds per day to the secondary system. The projected plant releases for this condition are based on the assumption that these conditions persist throughout the full year. The steam system operating conditions assumed for the activity analysis are listed in Tables 11.1-23, 11.1-24, and 11.1-25, and the results of the analysis are DCPP UNITS 1 & 2 FSAR UPDATE 11.1-6 Revision 19 May 2010 provided in Tables 11.1-26 through 11.1-31. The equations and models for the activity balances and transport calculations are detailed in Reference 8, and they are generally consistent with those provided in NUREG-0017. 11.
1.7 REFERENCES
- 1. M.E. Meek and B.F. Rider, Summary of Fission Product Yields for U-235, U-238, Pu-239, and Pu-241 at Thermal, Fission Spectrum, and 14 MeV Neutron Energies, Report Number APED-5398, March 1, 1968.
- 2. J.J. DiNunno, et al, Calculation of Distance Factors for Power and Test Reactor Sites, AEC Report Number TID-14844, March 23, 1962.
- 3. J.O. Blomeke and M.F. Todd, Uranium-235 Fission - Product Production as a Function of Thermal Neutron Flux, Irradiation Time, and Decay Time, AEC Report ORNL-2127, August 19, 1957.
- 4. J.F. Perkins, and R.W. King, "Energy Release from the Decay of Fission Products," Nuclear Science and Engineering, 1958.
- 5. Preliminary Safety Analysis Report, Nuclear Units Number 1 & 2, Diablo Canyon Site, Pacific Gas and Electric Company.
- 6. D.F. Toner and J.S. Scott, "Fission Product Release From UO2," Nuclear Safety, Vol. 3, No. 2, December, 1961. 7. J. Belle, Uranium Dioxide: Properties and Nuclear Applications, Naval Reactor, DRD of USAEC, 1961.
- 8. S.G. Gillespie and W.K. Brunot, EMERALD NORMAL - A Program for the Calculation of Activity Releases and Doses from Normal Operation of a Pressurized Water Plant, Program Description and User's Manual, Pacific Gas and Electric Company, Revision 1, December 1974.
- 9. NUREG-0017, Calculation of Releases of Radioactive Materials in Liquid and Gaseous Effluents from Pressurized Water Reactors, USNRC, (PWR-GALE Code), May 1976.
- 10. A. Tobias, Data from the Calculation of Gamma Radiation Spectra and Beta Heating from Fission Products, (Revision 2), RD/B/M2453, Central Electricity Generating Board, England, October 1972.
- 11. WCAP 8253, Source Term Data for Westinghouse Pressurized Water Reactors, May 1974.
DCPP UNITS 1 & 2 FSAR UPDATE 11.1-7 Revision 19 May 2010 12. Reactor Safety Study (WASH-1400), An Assessment of Accident Risks in U.S. Commercial Nuclear Power Plants, Appendix VI, U.S. Nuclear Regulatory Commission, October 1975. DCPP UNITS 1 & 2 FSAR UPDATE 11.2-1 Revision 20 November 2011 11.2 LIQUID WASTE SYSTEM The liquid radwaste system (LRS) collects and processes the radioactive liquid wastes generated from the primary side of the plant during operation. The LRS reduces the activity of these liquid wastes to levels acceptable for discharge to the environment. The system is designed to minimize dose to plant personnel and the general public in accordance with NRC regulations. Presented in this section are design objectives, equipment and operational descriptions, process flow diagrams, and radiological evaluation of the liquid waste system.
Three other major liquid waste streams that may potentially be radiologically contaminated are included in this chapter, although they are not technically part of the LRS. 11.2.1 DESIGN OBJECTIVES The design objectives of the liquid waste system are to:
(1) Collect radioactive liquid wastes generated by the primary side of the plant (2) Provide sufficient liquid wastes surge and processing capacity so that operation and availability of the plant is not limited (3) Reduce the volume of radioactive waste that must be shipped off site for disposal (4) Process liquid wastes for discharge to the environment to meet the limits specified in 10 CFR 20 and the guidelines in Appendix I to 10 CFR 50 (as low as is reasonably achievable (ALARA)) (5) Maintain safe operating conditions and system integrity throughout all anticipated operating conditions (6) Ensure that dose to the public is maintained below the dose limits specified in 10 CFR 20, Appendix I to 10 CFR 50 and 40 CFR 190 (7) Provide adequate drainage during normal operation and postulated flooding conditions following equipment failure as described in Section 9.3.3 DCPP UNITS 1 & 2 FSAR UPDATE 11.2-2 Revision 20 November 2011 11.2.2 SYSTEM DESCRIPTION 11.2.2.1 General Units 1 and 2 share a common LRS, except for equipment located inside containment.
A detailed piping and instrumentation schematic of the LRS is shown in Figure 3.2-19. The common waste system consists of the following five collection subsystems:
(1) Equipment drain subsystem
(2) Floor drain subsystem (3) Chemical drain subsystem (4) Laundry and hot shower and laundry/distillate subsystem (5) Demineralizer regenerant subsystem These five collection subsystems are described in the following sections.
The floor drain, chemical drain, laundry/distillate, laundry and hot shower, and demineralizer regenerant subsystems generally collect low activity level liquid wastes. The equipment drain subsystem collects liquids with variable activity levels. The demineralizer regenerant subsystem is used as backup for the floor drain and equipment drain subsystem. Following treatment, effluents from the LRS are released to the environment at either of the units' circulating water system discharge structures via the auxiliary saltwater system (see Figure 11.2-9). The waste liquid releases are diluted in the auxiliary saltwater system and main circulating water system flows. Releases require positive operator action, are continuously monitored, and are automatically isolated in the event of a high radiation alarm or a power failure. 11.2.2.1.1 Chemical and Volume Control System A major source of radioactive waste liquids is the reactor coolant system (RCS). The bulk of these wastes are processed and retained within the chemical and volume control system (CVCS), with a portion being routed to the LRS. A piping and instrumentation schematic of the CVCS is shown in Figure 3.2-8. A complete description of the CVCS is included in Section 9.3. 11.2.2.2 Equipment Drain or Closed Drain Subsystem The closed drain system is so called because drains from equipment are connected directly to the drainage system. Closed drain wastes are not exposed to the DCPP UNITS 1 & 2 FSAR UPDATE 11.2-3 Revision 20 November 2011 atmosphere until they reach their destination. Inside containment closed drain wastes flow to the reactor coolant drain tank. Sources include the following:
(1) Reactor coolant loop drains (2) Pressurizer relief tank (3) Reactor coolant pumps secondary seals (4) Excess letdown line (during startup) (5) Accumulators (6) Refueling canal (7) Reactor coolant pumps seal water inlet line drain (8) Reactor flange leakoff (9) Excess letdown heat exchanger (10) Regenerative heat exchanger outlet line drain When the reactor coolant drain tank reaches a preset liquid level, the wastes are automatically pumped to the liquid holdup tanks for processing in the CVCS. The pumps may also be manually started prior to reaching the preset level. The wastes may also be pumped to the equipment drain receiver tanks or the refueling water storage tanks when required. An integrating flow meter on the reactor coolant drain pump discharge reads out on the auxiliary building control board, and reactor coolant drain tank high and low level alarms to the main annunciator are provided.
Closed drainage from equipment in the auxiliary building is collected in the miscellaneous equipment drain tank. Sources include the following:
(1) Chemical and volume control system (a) Deborating demineralizer drain
(b) Mixed bed demineralizer drain
(c) Evaporator condensate demineralizer drain (abandoned in place) (d) Cation bed demineralizer drain (e) Evaporator feed ion exchanger drains DCPP UNITS 1 & 2 FSAR UPDATE 11.2-4 Revision 20 November 2011 (f) Reactor coolant filter (g) Seal water heat exchanger (tube side) and filter (h) Volume control tank drain and sample line drain (i) Charging pumps, header, bypass, and seal injection filter (j) Letdown heat exchanger (tube side) (k) Gas stripper feed pumps drain (l) Liquid holdup tanks recirculation pumps, line, and relief valve discharge (m) Boric acid preheater drain (abandoned in place) (n) Boric acid evaporator (abandoned in place) (o) Boric acid evaporator condensate filters (abandoned in place) (p) Concentrates holding tanks and pump 0-2 (abandoned in place) (q) Boric acid evaporator condenser relief valve (2) Safety injection system (SIS) (a) Containment recirculation water chamber (b) Safety injection pumps seal and drip pocket drain (c) Various valve steam leakoffs (3) Residual heat removal (RHR) system (a) RHR heat exchanger tube side drains (b) RHR pump and line drain (c) Various valve steam leakoffs (4) NSSS sampling system (a) NSSS sampling sink drain (b) NSSS sample line drain DCPP UNITS 1 & 2 FSAR UPDATE 11.2-5 Revision 20 November 2011 (c) Volume control tank sample line drain (5) Containment spray system (a) Containment spray line drain (b) Containment spray pumps (6) Spent fuel pool cooling system (a) Spent fuel pool resin trap filter (b) Spent fuel pool filter (c) Spent fuel pool pumps (d) Refueling water purification filter (e) Spent fuel pool skimmer filter, pump, strainer, and drain (f) Spent fuel pool heat exchanger (g) Spent fuel pool demineralizer drain (7) Component cooling water system (CCWS) (a) Waste gas compressor seal water coolers (8) Liquid radwaste system (a) Equipment drain receivers overflow and pumps (b) Processed waste receivers (formally the waste concentrator condensate tank (WCCT)) overflow and pumps (c) Spent resin motive water pumps (d) Spent resin storage tanks (9) Gaseous radwaste system (a) Gas decay tanks drain (b) Waste gas compressor moisture separator DCPP UNITS 1 & 2 FSAR UPDATE 11.2-6 Revision 20 November 2011 (c) Gaseous radwaste vent header drain (10) Turbine steam supply system (a) Steam generator blowdown tank (11) Gland steam sealing system Note: Normally the following drains go to the miscellaneous condensate return tank and turbine building sump. They can be routed to the MEDT if elevated levels of radioactivity are present. (a) Gland steam condenser drains (b) Steam jet air ejector When the miscellaneous equipment drain tank reaches a preset liquid level, the wastes are automatically pumped to the equipment drain receiver tanks. A high level alarm function is provided.
Closed drain wastes being transferred to the equipment drain receiver tanks are routed to one of the two tanks. When that tank reaches its high level setpoint, incoming flow is automatically diverted to the second equipment drain receiver tank. The filled tanks are normally recirculated, sampled, and analyzed before further batch processing. A high and low level alarm function is provided for each tank.
11.2.2.3 Floor Drains and Open Drain Subsystem The open drain system drains potentially contaminated areas in the containment buildings and the auxiliary building with equipment that does not normally handle reactor coolant. The piping systems and trenches used in this system permit exposure of the contents to the atmosphere.
Inside containment floor drain wastes are collected in the containment sumps and the reactor cavity sump. Sources include the following:
(1) Reactor coolant pump seal No. 3 leakoff
(2) Excess letdown heat exchanger shell relief and drain (3) Reactor coolant pump thermal barrier relief
(4) Reactor coolant pump upper bearing cooling relief (5) Containment fan cooler drip pans and coils DCPP UNITS 1 & 2 FSAR UPDATE 11.2-7 Revision 20 November 2011 (6) Reactor vessel support cooler relief (7) Reactor coolant pump lube oil spill collection tanks Integrating flow meters in the discharge lines from the reactor cavity sumps and containment sumps are provided to detect leakage from in-containment sources.
Potentially contaminated auxiliary building floor drain wastes are collected in the auxiliary building sump. The uncontaminated floor drains from the auxiliary building drain to other discharge pathways such as the sanitary drainage system, outside, etc.
Sources for the auxiliary building sump include the following:
(1) Chemical and volume control system (a) Charging pump base drains (b) Boric acid tanks, filters, and transfer pump drains (c) Boric acid evaporator Unit 1 concentrates pumps (abandoned in place) (d) Boric acid distillate pump drains (abandoned in place) (e) Boric acid concentrates filters (abandoned in place) (f) Boric acid reserve tanks and transfer pumps' drain (g) Chemical mixing tank (h) Batching tank (i) Concentrate holding tank pump 0-1 (abandoned in place) (2) NSSS sampling system (a) Sample sinks (1-2 and 2-2) (3) Containment spray system (a) Spray additive tank (4) Spent fuel pool cooling system (a) Spent fuel pool sump DCPP UNITS 1 & 2 FSAR UPDATE 11.2-8 Revision 20 November 2011 (5) Component cooling water system (a) Component cooling water surge tank relief (b) RHR heat exchanger shell side drains (6) Liquid radwaste system (a) Floor drain receivers and pumps (b) Chemical drain tank overflow (c) Laundry and hot shower tanks overflow (d) Spent resin loadout area (e) Spent resin transfer filters (f) Laundry/distillate tanks and pumps drain and tank overflow (7) Ventilation system (a) Plant vent drains (8) Auxiliary steam system (a) Auxiliary steam hydrazine feed unit (b) Package boiler blowdown tempering tank (c) Auxiliary steam drain receiver and pumps (9) Elevation 140 ft. roof drains discharge to LRS only if contamination is detected The RHR compartments spills collect in the RHR sumps that are normally discharged to the floor drain receivers.
When a sump has filled to a preset level, the wastes are automatically pumped to one of two floor drain receiver tanks. When a tank has reached its high level setpoint, sump flow will automatically be diverted to the second floor drain receiver tank. The filled tank is normally recirculated, sampled, and analyzed before further batch processing. A high level alarm function is provided for each sump. A high level and low level alarm function is provided for each floor drain receiver tank.
DCPP UNITS 1 & 2 FSAR UPDATE 11.2-9 Revision 20 November 2011 11.2.2.4 Chemical Drain Subsystem Chemical wastes are generated due to routine chemical and radiochemical sampling and analyses. Chemical wastes from both units drain by gravity to a divided chemical drain tank. The filled section is recirculated, sampled, and analyzed before discharge. 11.2.2.5 Laundry and Hot Shower, and Laundry/Distillate Subsystem Laundry, hot shower and treated CVCS liquids are generally very low in activity. The laundry and hot shower wastes are generated by laundering contaminated protective clothing and by personnel decontamination. CVCS liquid holdup tank (LHUT) water is routed to the liquid radwaste system when reuse in the reactor cavity or spent fuel pool is not possible. The hot shower wastes flow by gravity to one of the laundry and hot shower tanks. When one of the laundry and hot shower tanks is filled, the flow is manually diverted to the second tank. The filled tank is recirculated, sampled, and analyzed before further batch processing or discharge. The laundry waste will normally drain to one of the laundry/distillate tanks for discharge. Treated LHUT water may be drained to one of the laundry/distillate tanks or to one of the demineralizer regenerant receiver tanks for further treatment by the liquid radwaste system. When one of the laundry/distillate tanks is filled, the flow is manually diverted to the second tank. The filled tank is recirculated, sampled, and analyzed before further batch processing or discharge. 11.2.2.6 Demineralizer Regenerant Subsystem The demineralizer regenerant subsystem consists of two 15,000 gallon demineralizer regenerant receivers (arranged in parallel) located adjacent to the equipment drain receivers in the auxiliary building. Originally, it was intended that regeneration wastes from the steam generator blowdown treatment system, deborating demineralizers, or evaporator distillate demineralizers were to be routed to these tanks, and neutralized by concentrated sulfuric acid or sodium hydroxide. The steam generator blowdown regeneration system never operated and changes in California EPA regulations halted neutralization of other regenerants in the demineralizer regenerant receivers.
The demineralizer regenerant receivers collect equipment or floor drain liquid and function as surge capacity for these systems. In addition, treated LHUT liquid can be drained to the demineralizer regenerant receivers for additional processing.
DCPP UNITS 1 & 2 FSAR UPDATE 11.2-10 Revision 20 November 2011 11.2.3 LIQUID RADWASTE SYSTEM OPERATION The LRS is operated on a batch basis. When a floor drain receiver, equipment drain receiver, chemical drain, laundry/distillate tank, laundry and hot shower tank, or demineralizer regenerant receiver is filled, it is isolated to prevent accumulation of additional contaminated waste. Control interlocks prevent tanks from being simultaneously filled and discharged. The tanks are normally recirculated, sampled, and analyzed to determine if additional treatment is required. Batches of equipment and floor drains are normally processed to reduce radioactivity concentrations prior to discharge. 11.2.3.1 Liquid Radwaste Processing Sub System Batches requiring further treatment are processed through the radwaste media filters, ion exchangers, filters and/or mobile liquid process system. The radwaste media filters and ion exchangers are normally operated in series. Both in-door and out-door locations are provided for mobile liquid process systems. Mobile liquid process systems may be used to augment LRS in-plant components. Treated liquid is collected in the Processed Waste Receivers. In addition, treated LHUT liquid can be routed to the Processed Waste Receivers. These batches are then sampled and analyzed prior to discharge. 11.2.3.2 Liquid Radwaste Discharge Sub System Batches that contain sufficiently low quantities of radioactivity to meet discharge limits are treated by filtration and discharged to the outfall of the circulating water via the auxiliary saltwater discharge. Circulating water flow is verified prior to initiating a release. Written operating procedures govern the mechanics of discharging liquid radwaste to the unrestricted area (Reference 8).
As part of the procedures, records of plant water inventories, circulating water flow rates, and radwaste batch analysis data sheets are kept to ensure that the discharges are maintained below the applicable regulations. 11.2.4 SYSTEM DESIGN The systems that handle radioactive or potentially radioactive liquid wastes, as designed, comply with the intent of GDC 60 and 64 of Appendix A to 10 CFR 50.
The components of the LRS are listed in Table 11.2-10. A similar listing for the CVCS is provided in Table 9.3-6. Included are equipment size or capacity, applicable flowrate, material of construction, and design temperature and pressure.
DCPP UNITS 1 & 2 FSAR UPDATE 11.2-11 Revision 20 November 2011 Applicable codes and standards for process equipment used in the liquid waste system are presented in the DCPP Q-List (see Reference 8 of Section 3.2). Equivalent data for the CVCS are shown in Table 9.3-5.
The seismic and quality group classifications for these components and associated piping are also provided in the DCPP Q-List 9 (see Reference 8 of Section 3.2). Radiological monitoring is discussed in detail in Section 11.4.
The routing of all piping is strictly controlled by the design engineers and is specified on the piping drawings. Consequently, there are field-fabricated lines, but no field-routed lines. Lines that are field-fabricated have the following characteristics: (a) the lines are routed to minimize operator dose, all deviations from the specified routing require prior approval of the piping engineer, and as-built drawings are made showing final dimensions, (b) the sizes, schedules, materials, and code classes are specified on the piping drawings, (c) the field-fabricated piping is similar to shop-fabricated piping in design, quality assurance procedures, and inspection, (d) pipe hanger placement is not specified on piping drawings, but a maximum spacing between hangers is specified as a design standard, and (e) a design review is conducted in accordance with the quality assurance procedures described in Chapter 17 in the same manner as for shop-fabricated piping. 11.2.5 PERFORMANCE DATA LRW process equipment is evaluated for it's effectiveness in removing radioactivity on a batch basis. Approved Plant procedures govern concentrations of activity that must be processed and limits the activity in any individual batch prior to release. When the process equipment removal efficiency no longer produces water to meet these requirements, the filters, media or ion exchange resin is replaced. 11.2.6 PLANT RELEASES 11.2.6.1 Current Operational Releases The actual releases from the plant site are summarized in the Annual Radiological Effluents report to the NRC. The report summarizes the liquid, gaseous and solid radwaste that is released from the site for the past year and provides the calculated dose to the public, which is calculated using the site dose calculating manual. Releases from DCPP have routinely demonstrated compliance within the general provisions of, and dose limits established in, 10 CFR 20 and 10 CFR 50. 11.2.6.2 Pre-Operational Estimated Release Evaluation The following information provides historical perspective demonstrating that DCPP's anticipated operation would result in releases within applicable regulations. This information does not necessarily reflect current operating conditions or practices.
DCPP UNITS 1 & 2 FSAR UPDATE 11.2-12 Revision 20 November 2011 The estimated releases based on the original design were calculated with the EMERALD-NORMAL computer program, supplemented by hand calculations. Two process flow diagrams of the LRS are presented to depict the modes of operation for the two cases used for radiation release analysis: the Design Basis Case, and the Normal Operation Case. The flow diagram for the Design Base Case, Figure 11.2-2, shows the waste stream sources and processing route of liquid waste for the assumptions of this case. The numbered waste input streams have their annual flow and isotopic spectra listed in Table 11.2-5. The numbered process streams are listed in Table 11.2-8, along with flows and isotopic concentrations. The flow diagram for the Normal Operation Case is shown in Figure 11.2-3. Flows and isotopic parameters for this case are listed in Tables 11.2-5 and 11.2-9.
The detailed assumptions used in calculation of estimated activity release from the LRS are listed in Table 11.2-1. Tables 11.2-3 and 11.2-4 list the activity concentration spectrum for the input sources. A tabulation of the estimated annual release by isotope is provided in Tables 11.2-14 and 11.2-15 for the two cases.
For the Normal Operation Case with anticipated operational occurrences, as defined in RG 1.112 (Reference 7), an additional release of 0.15 Ci/yr per reactor with the same isotopic makeup as in Table 11.2-15 is assumed. This annual release is provided in Table 11.2-18 for one unit. Since an average of 2 days holdup time is available upstream of both the boric acid and waste treatment systems, no additional release, assuming the systems are out of service, is postulated.
The detailed assumptions used in the calculation of estimated activity release from the CVCS to the LRS are listed in Table 11.2-2. A tabulation of the isotopic flows through the system components is provided in Tables 11.2-6 and 11.2-7, and the estimated annual releases to the LRS are provided in Tables 11.2-8 and 11.2-9 for the Design Basis and Normal Operation Cases.
For purposes of estimating annual average plant radionuclide releases, approximately two-thirds of the boric acid evaporator distillate produced is assumed to be recycled to the primary water storage tank, and the rest routed to the liquid waste system. This release (350,000 gallons/year for each unit) is primarily for tritium control purposes. A list of assumed decay times for system tanks is provided in Table 11.2-13. Demineralizer decontamination factors are listed in Table 11.1-15.
During conditions corresponding to the Design Basis Case, which assumes a 1 percent fuel defect level with negligible primary system leakage, the floor drain wastes will have an approximate activity level of 0.0015 mCi/cc. These wastes are normally filtered and released to the main condenser circulating water discharge canal.
During conditions corresponding to the Normal Operation Case, which assumes a 0.12 percent fuel defect level with primary system leakage, the activity level of the floor DCPP UNITS 1 & 2 FSAR UPDATE 11.2-13 Revision 20 November 2011 drain wastes is approximately 0.1 mCi/cc. Under this operating condition, the wastes will be processed through the filters and/or ion exchangers. The chemical drain wastes will have an approximate activity level of 9 x 10-4 µCi/cc during conditions corresponding to the Design Basis Case. During conditions corresponding to the Normal Operation Case, the wastes will be approximately 1 x 10-4 µCi/cc. During conditions corresponding to the assumptions of Design Basis Case, the approximate activity level in the processed effluent from the equipment drain receiver tanks is 0.007 µCi/cc. The activity level of the processed effluent is 0.002 µCi/cc during conditions corresponding to the Normal Operation Case. The steam generator blowdown system is depicted on two process flow diagrams that show the two paths of operation of the system and the assumptions used in the radiation release analyses. Figure 11.2-4 shows the discharge path with blowdown directed to the blowdown tank and the circulating water discharge structure. Figure 11.2-5 shows the recycle path with blowdown directed to the blowdown treatment system. For the Design Basis Case, it is assumed that the blowdown is processed via the discharge path because this case assumes no primary-to-secondary leakage and no activity is present in the secondary system. For the Normal Operation Case, it is assumed that the blowdown is processed only via the recycle path and the discharge path is isolated since the assumptions for this case result in significant levels of activity in the secondary system. Table 11.2-16 shows the total annual volumetric flows for one unit and the activity concentrations corresponding to the alphabetically labeled process streams in these two figures for the Normal Operation Case.
The estimated annual activity releases from the turbine building sump for one unit are listed in Tables 11.2-14 and 11.2-15 for the Design Basis Case and the Normal Operations Case, respectively. Table 11.2-17 lists the total annual estimated volumes released from the liquid waste system for two units for both cases and includes the turbine building sump discharge. The tritium concentration in the RCS is controlled by bleeding coolant from the RCS to the LRS via the CVCS (see Section 9.3.4). Other losses from the RCS are through radioactive decay and mixing of the primary coolant with refueling cavity water during refueling. The calculation of the tritium concentration in the various plant water sources is based on the following assumptions:
(1) Tritium activity in the RCS is provided in Table 11.1-22 for the anticipated operational occurrences case. (2) The total volume of water released from the RCS for the analysis of the Design Basis Case and the anticipated operational occurrences case is 350,000 gallons per year per unit.
DCPP UNITS 1 & 2 FSAR UPDATE 11.2-14 Revision 20 November 2011 (3) The temperature of the spent fuel pool is constant at 100°F throughout the life of the plant except during refueling when the temperature rises to 125°F. The air above the spent fuel pool is 80°F at 70 percent relative humidity. (4) The water temperature of the refueling canal, when filled with borated water from the refueling water storage tank, is 125°F. The air above the refueling canal is 80°F at 70 percent relative humidity. Mixing with 15 percent of the water from the spent fuel pool occurs during each refueling period. (5) During refueling, the containment purge fans are in continuous operation. (6) No water is lost from the spent fuel pool or refueling water storage tank, except through evaporation. (7) Evaporation from the spent fuel pool is calculated by the equation (Reference 3): )pp(WV425.00.95AVawa+= (11.2-1) where: V = loss rate from the water volume, lbm/hr A = exposed area of the water volume, ft2 W = latent heat of vaporization of the water, Btu/lbm Va = velocity of the air across the surface of the water, ft/min pw = vapor pressure of the water, in. of Hg pa = vapor pressure of the water in air, in. of Hg The important parameters for evaluating tritium losses and distribution in the plant are provided in Table 11.2-11.
The resulting tritium concentrations in various plant areas are shown in Figures 11.2-6 through 11.2-8. It should be noted that the tritium concentrations plotted in these figures are yearly averages or, in the case of airborne concentrations during refueling, are averages during the refueling periods, based on a 1 year fuel cycle with 11 months operation and 1 month refueling. The tritium management procedures are designed to ensure that tritium airborne concentrations in all normally occupied plant areas are significantly below levels required to ensure compliance with 10 CFR 20, Subparts C and D. The restriction of primary coolant tritium concentration by releasing demineralized water from the RCS is intended to reduce in-plant personnel radiation dose.
DCPP UNITS 1 & 2 FSAR UPDATE 11.2-15 Revision 20 November 2011 The above analysis was performed to demonstrate that DCPP "normal operation" radiological effluents meet the criteria of 10 CFR 50, Appendix I. This analysis is conservative and bounds DCPP current operation. The analysis was performed prior to plant operation and will be modified only if a design change or operational change rendered it nonconservative. 11.2.7 RELEASE POINTS The four major release pathways are as follows:
(a) from the LRS to the discharge structure via either the Unit 1 or Unit 2 auxiliary saltwater discharge lines (Figures 11.2-2, 11.2-3, and 11.2-9); (b) from the Unit 1 or Unit 2 steam generator blowdown: (1) via the steam generator blowdown tanks to the discharge structure via the respective unit's discharge conduit (Figures 11.2-4 and 11.2-9); (2) via diversion from the steam generator blowdown recycle line to the main condenser. (c) from the turbine building sump to the discharge structure via either the Unit 1 or Unit 2 turbine-generator building sump discharge line (Figure 11.2-5). (d) from the condensate demineralizer regenerant system via either the high conductivity tank or the low conductivity tank.
Other minor discharge pathways may exist. Those identified pathways, monitored radiologically, are included in the offsite dose calculation manual and/or implementing procedures. The LRS is described in Section 11.2.2. The other three main discharge pathways are described in Sections 11.2.7.1 through 11.2.7.3 below. 11.2.7.1 Turbine Building Drain System The concentration of radioactivity in the turbine building drains is expected to be low, even in the event of significant primary-to-secondary steam generator leakage. The radiation level and flow of liquid from the turbine building drains are monitored at the oily water separator to verify that there are no unaccounted for or unexpected releases from the turbine building drains. If significant radioactivity is detected coming from the turbine building drains, the discharge can be routed to the LRS for treatment. The monitoring system is in conformance with Regulatory Guide 1.21 (Reference 9) and General Design Criterion (GDC) 4 of Appendix A to 10 CFR 50. DCPP UNITS 1 & 2 FSAR UPDATE 11.2-16 Revision 20 November 2011 Turbine building sump wastes are normally released to the environment via each unit's circulating water discharge structure (see Figure 11.2-9). A detailed piping and instrumentation schematic of the turbine building sump systems is shown in Figure 3.2-27. 11.2.7.2 Steam Generator Blowdown System The steam generator blowdown system for each unit provides two processing paths. One path discharges blowdown flow to the environment via the steam generator blowdown tank and the circulating water discharge tunnel. The other path recycles blowdown flow to the main condenser via the blowdown treatment system and/or the blowdown treatment bypass line. The recycle path can discharge a portion of blowdown flow to the discharge tunnel. Blowdown flow for each unit can be directed to either blowdown path alone, or to both paths simultaneously.
During plant operation, steam generator water collects suspended and dissolved solids that are brought in by the feedwater. Water must be blown down from the steam generators to maintain low solids concentration for efficient operation (Reference 1).
The blowdown flow maybe directed to either or both the discharge and recycle paths for a total blowdown flow of approximately 400 gpm per unit to maintain water chemistry and low solids concentration. If activity is detected at preset levels in the blowdown system, the blowdown will be automatically isolated from the discharge path and blowdown flow will be limited to the recycle path at up to 150 gpm per unit. A record of the activity level of the blowdown discharged to the circulating water canal and steam generator blowdown tank vent will be maintained. Appropriate flow measurement instruments on the steam generator blowdown tank inlets and liquid discharge will indicate and record all releases. The quantity of activity released to the atmosphere and circulating water canal can thus be directly determined.
The steam generator blowdown system in the recycle path may normally be used for water recovery by processing blowdown, upon exiting the flash tank, directly to the condenser via the blowdown bypass line and/or by processing blowdown through a flash tank, heat exchanger, prefilter, and demineralizer. In the treatment system processing path, blowdown is reduced in pressure and temperature within the flash tank and heat exchanger. A mixed bed demineralizer with prefilter is used to reduce any solids concentration and any activity in the blowdown. Two demineralizers can be operated in parallel or series service with a system flow capability of 20 to 150 gpm. The mixed bed resin is in the hydrogen and hydroxide form. The effluent from the demineralizer is high quality water equivalent to condensate makeup. The treated blowdown enters a resin trap filter before being recycled to the main condenser.
Upon ion exchange exhaustion (indicated by increased effluent conductivity), the mixed bed demineralizer resin is replaced with new resin. DCPP UNITS 1 & 2 FSAR UPDATE 11.2-17 Revision 20 November 2011 A description of the design bases, on-line monitoring, isolation criteria, design codes, system description, safety evaluation, inspection, and testing of the steam generator blowdown system is provided in Section 10.4.8. 11.2.7.3 Condensate Demineralizer Regenerant Solution The condensate demineralizer regenerant solution is the waste created from regenerating anion and cation resin used to clean water in the condenser. The resin is regenerated with sulfuric acid and sodium hydroxide. The high conductivity tank (HCT) normally receives the initial rinse water that may contain most of the acid, caustic and contaminants removed from the resin. The low conductivity tank (LCT) normally receives cleaner water used as a final rinse of the resin. The concentration of radioactivity in the condensate demineralizer regenerant solution is expected to be low.
The HCT is discharged as a discreet batch. The tank pH is adjusted within an acceptable range consistent with NPDES and other state requirements. The tank is then recirculated, sampled and analyzed prior to issuing a discharge permit.
The LCT is normally discharged as a discreet batch. The tank is recirculated, sampled and analyzed prior to issuing a discharge permit. In some cases, the LCT is allowed to discharge as a continuous discharge for a period of time. In this configuration, more than one sample is taken during the discharge period to ensure that the discharge remains within limits. 11.2.7.4 Typical Volumes Released These are not limiting volumes but are an approximation of routine plant discharge volumes. Volumes can change as defined in the site procedures as long as 10 CFR 20, and 10 CFR 50, Appendix I criteria are maintained. Typical LRS Annual Release Volumes: Source UFSAR Section Nominal Quantity (gallons) Equipment Drains 11.2.2.2 400,000 to 500,000 Floor Drains 11.2.2.3 200,000 to 400,000 Treated CVCS 11.2.2.1.1; Table 11.2-1 #27 470,000 to 750,000 Laundry & Hot Shower Drains 11.2.2.5 50,000 to 250,000 Chemical Drains 11.2.2.4 13,000 to 30,000 Sub Total 1.1 M to 1.9 M DCPP UNITS 1 & 2 FSAR UPDATE 11.2-18 Revision 20 November 2011 Typical Plant Annual Release Volumes: Pathways Nominal Quantity (gallons) LRS 1.1 M to 1.9 M U-1 SGBD 30M U-2 SGBD 30M Turbine Bldg Sump 15M U-1 Condensate Demineralizer Regenerant Tanks 5M U-2 Condensate Demineralizer Regenerant Tanks 5M Only trace amounts of activity are in the pathways that are not LRS. 11.2.8 DILUTION FACTORS 11.2.8.1 Current Operational Doses The condenser cooling water and the auxiliary saltwater system of Units 1 and 2 are used for dilution of released liquid wastes. The dilution flow available per unit is 876,000 gallons per minute. (See Chapter 10 for a description of the circulating water system and Chapter 9 for the auxiliary saltwater system.) 11.2.8.2 Pre-Operational Dose Factors The pre-operational estimated activity concentrations listed in Tables 11.2-21 through 11.2-23 are for one unit's turbine building wastes and liquid waste system diluted with one unit's annual circulating water flow. It should be noted that this method of calculation yields a maximum annual average concentration within the circulating water discharge structure.
For the calculation of all internal and external doses from liquid effluent releases, a dilution factor of 5 was used from the point of release to the organism or dose point. This value was taken from Table A-1 of RG 1.109 (Reference 5) as a conservative estimate of the dilution at the edge of the initial mixing zone for a high-velocity surface discharge. This factor is considered very conservative; experimental dye studies (Reference 2) have determined that the average dilution factor for fish, invertebrate, and sediment exposure to liquid effluents is 100. The dilution factor of 5 was confirmed by the NRC staff in the Final Environmental Statement for Diablo Canyon Units 1 and 2 (Reference 4).
DCPP UNITS 1 & 2 FSAR UPDATE 11.2-19 Revision 20 November 2011 11.2.9 CACULATED DOSES 11.2.9.1 Current Operation Doses Current operation doses are calculated in accordance with the offsite dose calculation manual contained in site approved procedures in accordance with 10 CFR 20 and appropriate NRC Regulatory Guides.
All liquid wastes are discharged to saline waters, which are not used as a source of drinking water or irrigation water. Thus, the only significant pathways to man from this source are through food chains involving marine organisms. Liquid releases have been examined for the possible effects on man and on aquatic organisms. For man, the pathways considered are the intake of aquatic foods that were grown within the radiological influence of the plant. 11.2.9.2 Pre-Operation Estimated Doses Pre-operational radiation dose calculations are presented in Tables 11.2-24 through 11.2-26 for the Design Basis Case, the Normal Operation Case, and the Normal Operation Case with anticipated operational occurrences. These tables list the doses from one unit. The dose via water pathways was calculated with the EMERALD NORMAL program, which uses liquid dose models and assumptions based on RG 1.109.
Pre-operational calculations included direct exposures through contact with water by swimming or by exposures in shoreline areas where minute quantities of radioactivity may be deposited. The usage factor for fish and invertebrate consumption and sediment exposure time were taken from RG 1.109, as were the bioaccumulation factors for fish, invertebrates, and plants. The complete set of bioaccumulation factors used is listed in Table 11.2-20. A list of effluent concentrations after dilution is provided in Tables 11.2-21 through 11.2-23.
The individual doses from fish consumption were based on rockfish caught and eaten by a sport fisherman, with a 1-day delay between the time of catch and consumption. The individual doses from invertebrate consumption were based on abalone, caught noncommercially and eaten with a 1-day delay between the time of catch and consumption. The possible doses from swimming or boating were based on the exposure periods listed in RG 1.109. A summary of the dose assumptions for liquid pathways exposures is provided in Table 11.2-19.
On the basis of the calculated estimates of radiation dose presented in Tables 11.2-24 through 11.2-26, it was concluded that under normal conditions, including the consideration of anticipated operational occurrences, the potential dose from liquid DCPP UNITS 1 & 2 FSAR UPDATE 11.2-20 Revision 20 November 2011 effluents from DCPP Units 1 and 2 would be well within the dose limits specified in 10 CFR 50, Appendix I. 11.2.10 REFERENCES 1. A.B. Sisson, et al., Evaluation for Removal of Radionuclides from PWR Steam Generator Blowdowns, International Water Conference, November 2, 1971.
- 2. Preliminary Safety Analysis Report, Nuclear Unit Number 2, Diablo Canyon Site, Pacific Gas and Electric Company, Docket Number 50-323.
- 3. Handbook of Fan Engineering, 6th Ed., Buffalo Forge Company.
- 4. Diablo Canyon Final Environmental Statement, U.S. Atomic Energy Commission, May 1973, Docket Numbers 50-275 and 50-323.
- 5. Regulatory Guide 1.109, Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10 CFR Part 50, Appendix I, USNRC, March 1976.
- 6. EMERALD-NORMAL, a Program for the Calculation of Activity Releases and Potential Doses from the Normal Operation of a Pressurized Water Reactor Plant, Revision 2, Pacific Gas and Electric Company, July 1976.
- 7. Regulatory Guide 1.112, Calculation of Releases of Radioactive Materials in Gaseous and Liquid Effluents from Light-Water Cooled Power Reactors, USNRC, April 1976.
- 8. DCPP Plant Procedures.
- 9. Regulatory Guide 1.21, Measuring, Evaluating, and Reporting Radioactivity in Solid Wastes and Releases of Radioactive Materials in Liquid and Gaseous Effluents from Light-water-cooled Nuclear Power Plants, USNRC, December 1971.
DCPP UNITS 1 & 2 FSAR UPDATE 11.3-1 Revision 20 November 2011 11.3 GASEOUS WASTE SYSTEM The gaseous radwaste system (GRS) provides controlled handling and disposal of gaseous wastes generated during plant operation. The system is designed to minimize dose to plant personnel and the general public in accordance with NRC regulations. In this section, the GRS is described. The following sections include the design objectives, equipment design, operational descriptions, process flow diagrams. 11.3.1 DESIGN OBJECTIVES The GRS system is designed to collect, store, monitor, and release plant waste gas streams that may contain radioactive noble gases, iodine, and radioactive particulate material. The GRS collects gaseous wastes with potentially high levels of radioactive isotopes and hydrogen, but low levels of oxygen, and is designed to meet the following objectives:
(1) Provide the capacity to collect and store the radioactive gaseous wastes (2) Provide sufficient capacity and storage to process and store in a shielded area, the volume of gaseous effluents directly from the RCS (3) Provide cover gas for the liquid holdup tanks (4) Provide a means of sampling gaseous effluents (5) Ensure that releases of radioactive gaseous wastes are kept as low as is reasonably achievable (ALARA) (6) Maintain the release of radioactive gases below limits specified by 10 CFR 20 (7) Ensure that dose to the public is maintained below the dose limits specified in Appendix I to 10 CFR 50 In addition to the release planned from the GRS, other releases of radioactive gases from the plant are possible under some operating conditions; for example, in periods during which primary coolant system leakage occurs. These additional pathways that can, under some plant operating conditions, release radioactive gases are: (1) Containment purge (2) Auxiliary building ventilation (3) Fuel handling area ventilation (4) Main condenser air ejector DCPP UNITS 1 & 2 FSAR UPDATE 11.3-2 Revision 20 November 2011 (5) Gland steam condenser (6) Steam generator blowdown system (7) Power relief valves (8) Main steam and reheat relief valves
(9) Solid radwaste storage building ventilation
(10) Laundry facility ventilation These release pathways are described in Chapters 9, 10, and 11.
Most waste gas releases are routed to the plant vent, with the exception of any power relief valves, main steam relief valves, reheat valves, solid radwaste storage facility, radwaste storage building/laundry facility exhaust, chemical laboratories exhaust, turbine building exhaust, and any miscellaneous steam leakage. Locations of the release points in the plant are shown in Figure 11.3-4. The design exit velocity at the plant vent is 17 m/sec during normal plant operation.
Tritium is also released via the plant vent system mainly due to evaporation from the spent fuel pool. 11.3.2 SYSTEM DESCRIPTION The GRS is designed to process radioactive gases consisting primarily of nitrogen and hydrogen with low levels of oxygen. The gases are collected by the vent header system from various primary and auxiliary systems. Radioactive or potentially radioactive gaseous wastes result from collection of excess cover gas in the liquid holdup tanks, degasification in the volume control tank, and cover gas displaced in the pressurizer relief tank and reactor coolant drain tank. A piping schematic for the GRS is shown in Figure 3.2-24.
Each unit has a vent header network and surge tank. Gases collected by the vent header system are routed to a surge tank equipped with a safety relief valve to prevent overpressurization.
Each unit's surge tank feeds that unit's waste gas compressor and/or a shared spare compressor through a pressure control valve set to maintain constant compressor suction pressure. The system is designed such that the shared spare compressor will automatically start if the pressure in the surge tank rises above 3 psig. An oxygen monitor on the moisture separator discharge limits the concentration of oxygen that can be fed to the gas decay tanks. The monitor actuates an alarm at 2 percent 02 concentration and trips the compressors at 4 percent. DCPP UNITS 1 & 2 FSAR UPDATE 11.3-3 Revision 20 November 2011 The compressor discharge is routed into a network of valves feeding the gas decay tanks. Based on downstream conditions and operator selection, the system controls the positioning of these valves. One tank will be filling, with one tank on standby, and one tank being used for cover gas. The system will automatically switch to the standby tank when the fill tank reaches 100 psig. Should this fail to happen, the system will alarm when the tank reaches 105 psig. Each decay tank is located in an individual shielded vault and is equipped with a safety relief valve that discharges to the plant vent.
The gas decay tanks are provided for the holdup of radioactive gases prior to release to the environment. The design provides the capability to hold gases for a minimum of 45 days. This is not a requirement to holdup gases for that period of time. The holdup time required is that which would result in releases that are in compliance with release rate and dose limits. Each gas decay tank may be operated as a cover gas supply for the liquid holdup tanks. Normal coolant letdown then displaces the gases back into the GRS. This process effectively increases the volume of storage available for gaseous holdup.
Each gas decay tank is equipped with a flow control valve connected to the plant vent. The discharge of each valve is routed into a common flow control valve that provides redundant means of isolation and requires manual operation by the control system to ensure no inadvertent venting may take place. Downstream of the common flow control valve is a radiation monitor that controls a downstream control valve. If the activity in the discharging waste gas exceeds its upper limit, the control valve closes, terminating the release. The final processing of waste gas prior to release to the atmosphere is by a high-efficiency particulate air (HEPA) filter located just downstream of the radiation control valve and just upstream of the plant vent. The sampling system associated with the GRS is used to monitor the hydrogen and oxygen content of the gases in the system and to collect grab samples for oxygen concentration analysis. Thirteen sample points exist in this system including all influent sources and each of the gas decay tanks. These sample points may be monitored continuously, or intermittently as required, or grab samples may be taken from manual sample taps. The gas analyzer is equipped with a sample tap for taking bottled samples to undergo radiological testing. 11.3.3 GASEOUS RADWASTE SYSTEM OPERATION The GRS will handle gaseous discharge from the various sources. The volume of gases will originate from displaced cover gas in the liquid holdup tanks. The gaseous flow is discharged to the vent header and routed to the surge tank. The suction pressure to the normally operating compressor is maintained at approximately 0.5 psig via a pressure regulator on the surge tank outlet. During normal operation, the waste gas compressor starts and stops based on surge tank pressure. to maintain 1.1 psig to 2.0 psig in the surge tank. If a control malfunction occurs causing the compressor to continuously operate, a recycle valve would open returning gases from the moisture DCPP UNITS 1 & 2 FSAR UPDATE 11.3-4 Revision 20 November 2011 separator at 0.9 psig pressure in the surge tank. This supplies gases back to the compressor suction preventing evacuation of the compressor suction piping. In addition, if the liquid holdup tank header pressure is at or below the setpoints drops below 0.75 psig, a recycle valve from the gas decay tanks would open to maintain the cover gases in the liquid holdup tanks. A shared Unit 1 and 2 spare compressor will start on a high surge tank pressure of 3 psig. The waste gas compressor discharges into a gas decay tank through a series of automatic valves. When the decay tank is filled to 100 psig, the inlet valve to the filled tank closes and the inlet valve to a standby tank opens. Should this fail to happen, a high pressure alarm sounds at 105 psig. The remaining tank is now positioned as the standby tank with the filled tank isolated for decay and release.
The gases in the decay tanks are periodically checked for buildup of hydrogen and oxygen. The gas analyzer checks for oxygen in the range 0-2 percent (+/-0.1 percent) and for hydrogen over three ranges: 0-5 percent (+/-0.1 percent), 0-50 percent (+/-1 percent), and 0-100 percent (+/-2 percent). The analyzer is set to provide an alarm if the oxygen concentration reaches 2 percent and the hydrogen reaches 3.5 percent. Additionally, the gases directed into the decay tanks being filled during waste gas compressor operation are continuously monitored for oxygen content via oxygen analyzer CEL 75 and 76, which alarms at 2 percent oxygen concentration. However, hydrogen concentration in the system is not monitored as its concentration is assumed at all times to be 4 percent (the flammability limit for hydrogen is 6 percent oxygen concentration) or more by volume for all plant operating modes. In this manner, the potential for explosive hydrogen/oxygen mixtures will be mitigated. The capability exists for diluting the gas with nitrogen (Figure 3.2-24) using pneumatically operated valves controlled from the auxiliary building control panel. A grab sample will be taken for isotopic analyses from the gas decay tanks and waste gas sources as required by the plant Technical Specifications (Reference 6). 11.3.4 SYSTEM DESIGN The systems that handle radioactive or potentially radioactive gaseous waste are designed to comply with the intent of GDC 60 and 64 of Appendix A to 10 CFR 50. The GRS, including the gas analyzer package, is designed and fabricated as Design Class II. The equipment and piping code classification are listed in the DCPP Q-List (see Reference 8 of Section 3.2). The design and operating parameters for the GRS equipment are shown in Table 11.3-1. 11.3.5 PERFORMANCE TESTS All GRS radiation and chemical monitors used in system evaluation are functionally tested and calibrated periodically to ensure the accuracy of measurements. The types of radiation monitors and locations are contained in Section 11.4.
DCPP UNITS 1 & 2 FSAR UPDATE 11.3-5 Revision 20 November 2011 Measurements are made on a continuous basis and records maintained of the quantity of radioactive gases released. Comparison of results provides a check on the continuing performance of the waste gas systems. This approach proves effective in documenting deficiencies and their corrections. The routine radiation-monitoring program also detects leakage from the GRS by detecting minute changes in the activity of air in the areas occupied by the system. Appropriate means are used to locate and correct any increase in leakage. 11.3.6 PLANT RELEASES 11.3.6.1 Current Operational Releases The actual gaseous releases are performed in accordance with approved plant procedures. The plant vent pathway is continuously monitored for noble gases, particulates and iodines.
The containment atmosphere is sampled and evaluated prior to release via the plant vent pathway during power operations. During periods of maintenance and refueling outages most releases continue via the plant vent pathway. However the containment equipment hatch may be open at times during maintenance resulting in direct communication between the containment and the outside air. If flow out of the containment equipment hatch is detected, containment air is evaluated per plant approved procedures to ensure a significant release via the equipment hatch is accounted for. 11.3.6.2 Pre-Operational Estimated Release Evaluation The following information provides historical perspective demonstrating that DCPP's anticipated operation would result in releases within applicable regulations. This information does not necessarily reflect current operating conditions or practices.
The potential release pathways for radioactive gases have been described in previous paragraphs. Table 11.3-2 lists the estimated annual releases for the Design Basis Case, and Table 11.3-3 lists the estimated annual releases for the Normal Operation Case. The assessments of total curies released via each of the various pathways are discussed below. All release calculations were performed using the EMERALD-NORMAL (Reference 1) computer code.
Table 11.3-4 lists the estimated annual gaseous radwaste flows. Tables 11.3-5 through 11.3-8 list the estimated activities in the gas decay tanks and the volume control tank for the Design Basis and Normal Operation Cases.
For the release from venting of the gas decay tanks, it was assumed that the full volume of primary coolant is degassed twice a year, and the quantities of radioactive gases released are listed in Table 11.3-2 for the Design Basis Case and in Table 11.3-3 for the Normal Operation Case. DCPP UNITS 1 & 2 FSAR UPDATE 11.3-6 Revision 20 November 2011 Containment venting releases are based on an assumed leakage of 1 percent of the primary coolant noble gas inventory and 0.001 percent of the primary coolant iodine inventory per day to the containment. It was assumed that the containment air is purged 24 times a year, and that the containment air is first circulated through the charcoal filters (described in Section 9.4.5) if the plant has been operating with significant primary coolant leakage to the containment. This recirculation is assumed to reduce the airborne iodine content by 98 percent, based on a filter decontamination factor (DF) of 10 for iodine, a circulation flowrate of 24,000 cfm for 16 hours, a containment free volume of 2.6 x 106 cubic feet, and a mixing efficiency of 70 percent. The resulting releases of iodine and noble gases for the Normal Operation Case are provided in Table 11.3-3.
In the event of leakage of primary coolant to the auxiliary building, the auxiliary building ventilation system can become a release pathway. In the calculation of release via this pathway, in the Normal Operation Case, it has been assumed that primary coolant leakage is 160 pounds per day, with a partition factor of 1 for noble gases and 0.0075 for iodine, with no iodine filtration in the ventilation system. The calculated releases via this pathway are provided in Table 11.3-3.
Because of the cleanup of the spent fuel pool water, the very large iodine removal capability of the water, the long decay times for noble gases and iodines in fuel rods handled in the pool, low fuel temperatures, and opportunity for prior release of gases in the containment, the amounts of iodine and noble gases released from the spent fuel pool to the environment under normal conditions are small. In the calculation of the release via this pathway, it was assumed that one-third of a core of spent fuel with 100 hours decay is placed in the spent fuel pool at the beginning of an operating cycle. Radionuclides diffuse through defects in fuel elements when cold at a rate 105 less than at normal core operating temperature. A partition factor of 0.001 is assumed for iodine and 1 for noble gases in the pool. The fuel handling area ventilation charcoal filter system is assumed to be 90 percent efficient for iodine removal. The calculated releases via this pathway are provided in Table 11.3-3.
Releases from the waste concentrator condenser vent will be negligible, and small amounts of gas that are released via this mechanism are included in the analysis by conservatively assuming that they are vented to the atmosphere before entering the GRS.
During periods when primary-to-secondary leakage exists, some release of noble gases and iodine will occur via the main condenser air ejector. To calculate these releases, it was assumed that all noble gases are transferred directly to the condenser vapor space, where they are released through the ejector after some decay. The parameters used in the calculation are provided in Tables 11.1-23, 11.1-24, and 11.1-25. These assumptions are consistent with those provided in NUREG-0017. Five percent of the iodine leakage from the primary to the secondary system is assumed to be in volatile form and to behave in a manner similar to a noble gas at steam generator operating DCPP UNITS 1 & 2 FSAR UPDATE 11.3-7 Revision 20 November 2011 temperatures. A partition factor of 0.15 is assumed for volatile iodine in the condenser, and zero for nonvolatile iodine, so the iodine release from this pathway is entirely in volatile form. The activity releases via this pathway are provided in Table 11.3-3.
A small potential source of activity release exists from the gland steam condenser. Because of the small steam flowrate used, however, both the noble gas and the iodine release rates via this mechanism will be negligible compared with the air ejector releases, and this mechanism has not been calculated separately.
The steam generator blowdown tank vent was not considered to be a significant source of iodine release for the purposes of the offsite dose calculations since the blowdown tank was not expected to be used during periods when significant activity is present in the blowdown.
Significant release via the power relief valves and main steam and reheat relief valves is not expected under normal operating conditions.
A small potential source of gaseous activity release exists from the laundry/radwaste storage building and solid radwaste storage facility ventilation systems. However, because of the degassed nature of contaminated materials that enter these facilities, noble gas release rate via these pathways will be negligible compared with other listed pathways, and therefore have not been included. Similarly, since iodine will not be gaseous, iodine releases via these pathways have not been included.
As a result of normal secondary system steam and water leakage, some iodines and noble gases will escape to the environment if significant activity exists in the secondary system. For the Normal Operation Case, a water leakage of 5 gpm was assumed, along with a steam leakage of 1700 lb/hr. The releases via this pathway are also listed in Table 11.3-3.
During plant startup after a cold shutdown, small quantities of radioactive gases may be released from the vacuum pumps (when the condenser is pumped down) and from the cover gas of the liquid holdup tanks. Gases from the liquid holdup tanks are processed by the GRS, but the discharge from the condenser is vented directly to the atmosphere. Calculations were performed to evaluate the contribution to the total annual air dose at the site boundary in the NW sector of gases released from the condenser during startup. The results of these calculations are listed in Table 11.3-9. Additional assumptions used in the calculations are:
(1) Initial secondary system activity equal to equilibrium levels with 0.12 percent fuel defects and 100 pounds per day primary-to-secondary leakage (Normal Operation Case). (2) An "equivalent downtime" is used that is equal to a step change from full power to cold shutdown, a 24-hour down-time, and a step change back to full power.
DCPP UNITS 1 & 2 FSAR UPDATE 11.3-8 Revision 20 November 2011 (3) During shutdown, all noble gases are assumed to accumulate in the condenser vapor space; an effective partition factor of 0.15 is assumed for iodine between the secondary system water and the condenser vapor space for volatile iodine species, and zero for nonvolatile iodine. (4) All airborne condenser activity is immediately released to the environment on startup. All iodine released is assumed to be volatile, and therefore not to be absorbed into food pathways. The critical dose point is considered to be the site boundary in the NW sector. This analysis was performed to demonstrate that DCPP "normal operation" radiological effluents meet the criteria of 10 CFR 50, Appendix I. This analysis is conservative and bounds DCPP current operation. This analysis was performed prior to plant operation and would be modified only if a design change or operational change rendered it nonconservative. 11.3.7 DILUTION FACTORS 11.3.7.1 Current Operational Dilution Factors The meteorological program is discussed in detail in Section 2.3. All current plant releases are calculated with average /Q values using 5-year historical meteorological conditions. 11.3.7.2 Pre-Operational Dilution Factors The pre-operational evaluation values of dilution factor (/Q) used in the calculation of annual average offsite radiation dose are provided in Table 11.3-11 for the locations specified in Table 11.3-10. The values of deposition rate (D/Q) used in the calculation of annual average offsite radiation dose are provided in Table 11.3-12 for the locations specified in Table 11.3-10. The D/Q values were derived from Figure 7 of RG 1.111 (Reference 3) for a ground level release.
The resulting pre-operational evaluation maximum offsite annual average atmospheric activity concentrations in each onshore sector are provided in Table 11.3-13 for the Design Basis Case and in Table 11.3-14 for the Normal Operation Case. 11.3.8 DOSES 11.3.8.1 Current Operational Doses Doses for current operation are calculated in accordance with the site dose calculation manual contained in site approved procedures in accordance with 10 CFR 20 and appropriate NRC Regulatory Guides.
DCPP UNITS 1 & 2 FSAR UPDATE 11.3-9 Revision 20 November 2011 11.3.8.2 Pre-Operational Doses Pre-operational dose calculations were performed at the critical distances for each age group and existing dose pathways in each onshore sector within 5 miles of Unit 1. The critical distances assumed in each sector are provided in Table 11.3-10. The milk cow and milk goat food pathways were not identified within 5 miles of the plant and were therefore not considered.
The models used to calculate the offsite radiation doses are those discussed in RG 1.109 (Reference 4) for a ground level release. The standard usage factors provided in RG 1.109 were used, as well as the standard decay times, transfer factors, and dose conversion factors. Since a ground level release was assumed, the gamma total body and air doses were calculated using the semi-infinite cloud model described in RG 1.109, which gives generally conservative results.
The results of the offsite dose calculations are presented in Tables 11.3-15 through 11.3-29 for the Design Base Case, and in Tables 11.3-30 through 11.3-44 for the Normal Operation Case. Actual results obtained from the environmental radiological monitoring program are discussed in Section 11.6. On the basis of the calculated estimates of radiation dose presented in Tables 11.3-15 through 11.3-44 and the results of the radiological monitoring program, it can be concluded that, under normal conditions, including consideration of anticipated operational occurrences, the potential dose from gaseous effluents from DCPP Units 1 and 2 will be well within the dose limits provided in Appendix I to 10 CFR 50. 11.
3.9 REFERENCES
- 1. S.G. Gillespie and W.K. Brunot, EMERALD-NORMAL - A Program for the Calculation of Activity Releases and Doses from Normal Operation of a Pressurized Water Plant, Revision 1, Pacific Gas and Electric Company, December 1974.
- 2. NUREG-0017, Calculation of Releases of Radioactive Materials in Liquid and Gaseous Effluents from Pressurized Water Reactors (PWR-GALE code), USNRC, May 1976.
- 3. Regulatory Guide 1.111, Methods for Estimating Atmospheric Transport and Dispersion of Gaseous Effluents in Routine Releases from Light Water-Cooled Reactors, USNRC, March 1976.
- 4. Regulatory Guide 1.109, Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10 CFR Part 50, Appendix I, USNRC, March 1976.
- 5. DCPP Plant Procedures.
DCPP UNITS 1 & 2 FSAR UPDATE 11.3-10 Revision 20 November 2011 6. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix to License Nos. DPR-80 and DPR-82, as amended. DCPP UNITS 1 & 2 FSAR UPDATE 11.4-1 Revision 19 May 2010 11.4 PROCESS AND EFFLUENT RADIOLOGICAL MONITORING SYSTEM 11.4.1 DESIGN OBJECTIVES The radiological monitoring system is designed to provide radioactivity measurements, records alarms, and/or automatic line isolation in order to control and/or process, the release of radioactive fluids in compliance with applicable regulations. It monitors process and effluent streams wherever a potential release of radioactivity exists during all modes of plant operation.
The design objectives for the radiation monitoring system are to:
(1) Warn of any radiation health hazard to operating personnel (2) Warn of leakage from process systems containing radioactive fluids (3) Monitor amount of activity released in effluents (4) Isolate or divert lines containing liquid and gaseous activity when activity levels reach a preset limit (5) Record the radioactivity present at various plant locations In the event of an accident, the process and effluent radiological monitoring system, in conjunction with the area radiation monitoring system, will provide information on the concentration and dispersion of radioactivity throughout the plant, thereby enabling operating personnel to evaluate the severity and mitigate the consequences of an accident.
11.4.2 CONTINUOUS MONITORING 11.4.2.1 General Description The components(a) of the radiation monitoring system are designed for operation in the following ranges of conditions:
(1) Temperature - An ambient temperature range of 40° to 120°F. (2) Humidity - 0 to 95 percent relative humidity. (a) The only components of this system that are exposed to a wider range of conditions are located in the containment. This includes detectors and associated local alarm and indication equipment for the area-type monitoring channels there. Some of these, namely the low level-normal ops monitors are not expected to operate following a major loss-of-coolant accident. Postaccident high-range gamma monitors are used for postaccident situations.
DCPP UNITS 1 & 2 FSAR UPDATE 11.4-2 Revision 19 May 2010 (3) Pressure - Components in the auxiliary building and control room are designed for normal atmospheric pressure. Area monitoring system components inside the containment are designed to withstand containment test pressure. (4) Radiation - Process and area radiation monitors are of a nonsaturating design so that they will register full-scale if exposed to radiation levels up to 100 times full-scale indication. (5) Radiation monitoring equipment is designed and located such that radiation damage to electrical insulation and other materials will not affect their usefulness over the life of the plant. (6) The radiation monitoring system is designed such that it can be checked, tested, and recalibrated as required. Most of the control room radiation monitoring system equipment used for normal operation and anticipated operational occurrences are centralized in cabinets. A data logger is provided in the radiation monitoring system cabinets in the control room. Each monitoring channel is sequentially recorded. Equipment used solely for postaccident monitoring is located in additional cabinets in the control room. The digital radiation monitoring system equipment is located in a six-bay cabinet while the control room air supply and pressurization system is in the room control monitor rack (RCRM). Sliding channel drawers are normally used for rapid replacement of units, assemblies, and entire channels. It is possible to completely remove the various chassis from the cabinet after disconnecting the cable connectors from the rear of these units. Detector output is usually measured in either counts per minute (cpm), milliroentgens per hour (mR/hr), or roentgens per hour (R/hr) and microcuries per cubic centimeter (Ci/cc). Each channel has a minimum range of three decades. Radiation monitors are listed in Tables 5.2-16 and 11.4-1. The iodine monitors are isotopic I-131 monitors and read in cpm, microcuries (Ci), or microcuries per second (Ci/sec). The radiation monitoring system is divided into the following subsystems:
(1) The process radiation monitoring system that monitors radiation levels in various plant and component effluent streams (2) The area monitoring system that monitors radioactivity in various areas within the plant The locations of all detectors with respect to plant equipment for Unit 1 are listed in Table 11.4-1. Unit 2 detectors are in corresponding locations. Piping sequence and locations of process detectors are found in appropriate piping schematics, shown as figures in Section 3.2.
DCPP UNITS 1 & 2 FSAR UPDATE 11.4-3 Revision 19 May 2010 11.4.2.2 Process Radiation Monitoring System 11.4.2.2.1 Description This system, as illustrated in Figure 11.4-1, consists of multiple channels that monitor radiation levels in various plant operating systems. The output from each channel detector except the digital radiation monitor is transmitted to the radiation monitoring system cabinets where the radiation level is indicated on a meter and recorded by a multipoint recorder. Except for air particulate/iodine/noble gas monitors in the Technical Support Center (TSC) and the adjacent laboratory, the gas decay tank cubicles, and the steam generator blowdown overboard monitor, the radiation monitoring system cabinets for most process radiation monitors are located in the control room. The radiation monitoring system cabinets for the TSC and the adjacent laboratory are located in the computation center. High-radiation level alarms are indicated on the radiation monitoring system cabinets with annunciation at one of two main annunciators. Except for the monitors in the TSC, the adjacent laboratory and some supplementary monitors, the main annunciator for process monitors is at the control board in the control room.
The control board annunciator provides several windows that alarm for input channels (process or area) detecting high radiation. The main annunciator for the TSC and the adjacent laboratory is in the TSC panel HVAC annunciator in the computation center. Four windows are provided for this annunciator, one each for high-radiation alarms from:
(1) TSC area monitors (2) Laboratory area monitor (3) TSC air particulate/iodine/noble gas monitors (4) Laboratory air particulate/iodine/noble gas monitors Verification of which channel has alarmed is done at the radiation monitoring system cabinets serving that annunciator (see Figure 11.4-1).
A tabulation of the process radiation monitoring channels is found in Table 11.4-1. The minimum sensitivity is based on a Co-60 background level of 2 mR/hr.
A typical channel contains a completely integrated modular assembly that includes the following:
(1) Log Level Amplifier Accepts detector pulses, performs a log integration (converts total pulse rate to a logarithmic analog signal), and amplifies the resulting output for suitable indicating and recording.
DCPP UNITS 1 & 2 FSAR UPDATE 11.4-4 Revision 19 May 2010 (2) Power Supplies Furnishes electrical power for the circuits, relays, alarm lights, and detectors. (3) Test-Calibration Circuitry Provides a precalibrated pulse signal to test channel electronics and a solenoid-operated radiation check source to verify channel operation. A common annunciator on the main control board indicates when a channel is in the test mode. (4) Radiation Level Meter Provides a dual scale calibrated logarithmically from 101 to 104, and 101 to 106 counts per minute. The wide-range level signal is also recorded by the recorder. (5) Indicating Lights Indicate high-radiation alarms, tests, and circuit failures. A number of annunciator windows on the main control board is actuated either on high radiation signal from the channels or from any channel failure, and another window is lit when channels are placed in the test mode. However, the digital radiation monitoring system and a few other monitors do not have this "test" alarm feature. (6) Bistable Circuits Two bistable circuits are provided: one to alarm on high radiation (actuation point may be set at any level within the range of the instruments), and one to alarm on loss of signal (circuit failure). (7) Check Source A remotely operated long half-life radiation check source or electronic check source is furnished for each channel. The check source simulates the radiation being monitored. The check source deflection is sufficient to cause an upscale indication. The main steam line radiation monitors and the control room pressurization system radiation monitors have a fixed "keep alive" source mounted directly on the detector. It is used only to keep the channel out of a low fail condition. The process radiation monitoring system consists of the radiation monitoring channels described in Items 1 through 28 below. (The prefix numbers, where used with channel DCPP UNITS 1 & 2 FSAR UPDATE 11.4-5 Revision 19 May 2010 identification, indicate monitors associated with Unit 1 or Unit 2; 0 indicates a shared monitor or no unit designation.)
The sample lines for the air particulate and gaseous radiation monitors (containment, RHR heat exchanger compartment exhaust, control room, TSC, laboratories, and plant vent) are designed and installed in accordance with the recommendations of Reference 2.
The flow in each of the sample lines (1-inch diameter, typically) is turbulent. Particle deposition due to gravity and Brownian diffusion are assumed to be small since the horizontal runs of the sample lines are short and the sample velocity is high. Long-radius bends are used for all sample lines, including the inlet lines to the monitors, to preclude deposition due to extreme turns. Isokinetic probes are used wherever the sample is taken from a moving airstream. Deposition in the basically vertical sample line runs are assumed to be largely due to turbulent deposition and is analyzed in the description for each of the air particulate monitors.
(1) Containment - Air Particulate Monitor (1-R-11 and 2-R-11) This monitor is provided to measure air particulate gamma radioactivity in the containment. The sampler for this channel takes a continuous air sample from the containment atmosphere. The inlet line from inside the containment is routed through the containment penetration to the monitor, which is located adjacent to the penetration. The sample is monitored by a scintillation counter-filter paper detector assembly. The particulate matter is collected on the filter paper's constantly moving surface and is viewed by a photomultiplier-scintillation crystal combination.
The sample is returned to the containment after it passes through the series-connected gas monitor.
The pulse signal is transmitted to the radiation monitoring system cabinets in the control room. Lead shielding is provided to reduce the background level to where it does not interfere with the detector's sensitivity. (2) Containment - Radioactive Gas Monitor (1-R-12 and 2-R-12) This monitor is provided to measure gaseous beta-gamma radioactivity in the containment. The detector consists of a gamma sensitive Geiger-Mueller (GM) tube mounted in the monitor container. DCPP UNITS 1 & 2 FSAR UPDATE 11.4-6 Revision 19 May 2010 This channel takes a continuous air sample from the containment atmosphere that passes through the air particulate monitor (1-R-11, 2-R-11), and then through the gas monitor assembly. The sample is circulated in a fixed volume where it is monitored by a radiation detector. The sample is then returned to the containment. Its output is transmitted to the radiation monitoring system cabinets in the control room. (3) Residual Heat Removal Heat Exchanger Compartment Exhaust Duct Air Particulate Detector Monitor (1-R-13 and 2-R-13) This monitor is provided to measure air particulate gamma radioactivity in the RHR heat exchanger compartments' exhaust ducts to detect a leaking recirculation loop component in the event of a loss-of-coolant accident (LOCA). It operates in the same manner as the containment air particulate monitor. The sampler for this channel takes a continuous common air sample from the exhaust ducts of both RHR compartments. An isokinetic probe is installed in each RHR compartment exhaust duct. The monitor is located in proximity to the sample points. The sample is monitored by a scintillation counter-filter paper detector assembly. The sample is then returned to the exhaust ducts. Ducts may be sampled individually by use of a selector switch at the console. High radiation is annunciated at the main control board. (4) Plant Noble Gas Vent Monitor (1-R-14, 2-R-14) (1-R-14R, 2-R-14R) Each channel consists of a pressurized three liter volume monitored by a beta scintillation detector. RM-14 is part of the normal range (NR) skid. RM-14R is part of the redundant normal range (RNR) skid. Local indication for these channels is provided by the Local Radiation Processors (LRPs) mounted on their respective skids. Remote indication for these channels is provided by the Radiation Display Units (RDUs) for their respective skids. The RDUs are mounted in the radiation monitoring system panels in the control room.
(5) Condenser Air Ejector Gas Monitor (1-R-15, 1-R-15R, 2-R-15, 2-R-15R) These channels monitor the discharge from the air ejector exhaust header of the condensers. Gaseous radiation is indicative of a primary-to-secondary system leak. The gas discharge is routed to the plant vent. High radiation is annunciated at the main control board.
DCPP UNITS 1 & 2 FSAR UPDATE 11.4-7 Revision 19 May 2010 (6) Component Cooling Liquid Monitors (1-R-17A, 2-R-17A, 1-R-17B, 2-R-17B) These channels continuously monitor the component cooling water (CCW) system for radiation indicative of a leak of reactor coolant from the reactor coolant system (RCS) and/or the RHR loop to the CCW. Each channel employs an off-line detector using a bypass line from CCW pump discharge to suction. Due to the discharge piping configuration, however, only one monitor is sampling flow representative of the bulk system when only one CCW heat exchanger is in service. A high-radiation-level signal initiates closure of the valve located in the component cooling surge tank vent line to prevent gaseous radiation release. Adequate lead shielding is provided to reduce the effect of background radiation so that it does not interfere with the detector's sensitivity. (7) Liquid Radwaste Effluent Monitor (O-R-18) This channel continuously monitors discharges from the liquid radwaste system (LRS). Automatic valve closure is initiated to prevent further release after a high radiation level is indicated and alarmed, and flow is diverted to the equipment drain receiver tanks. Scintillation counters located in in-line samplers monitor these effluent discharges. An alarm function is provided on the main control board and the auxiliary building control board. Adequate lead shielding is provided to reduce the effect of background radiation so that it does not interfere with the detector's sensitivity. In addition, samples from the LRS batches are analyzed in the laboratory. (8) Steam Generator Blowdown Sample Monitor (1-R-19, 2-R-19) This channel monitors the liquid phase of the secondary side of the steam generator for radioactivity (which would indicate a primary-to-secondary system leak) providing backup information to that of the condenser air removal gas monitor. Blowdown samples from each of the four steam generators are combined in a common header and the common sample is continuously monitored by a scintillation counter in an in-line sampler assembly. Adequate lead shielding is provided to reduce the effect of background radiation so that it does not interfere with the detector's sensitivity. High activity alarm indications are displayed locally and at the radiation monitoring system cabinets, with annunciation at the control board in the control room. If a high activity alarm occurs, isolation valves in the blowdown and sample lines acting with the valve in the line from the blowdown tank to DCPP UNITS 1 & 2 FSAR UPDATE 11.4-8 Revision 19 May 2010 the discharge structure will close and the blowdown tank liquid effluent will be diverted to the equipment drain receiver tank. Subsequent identification of the leaking steam generator would then be made by manual override of sample line isolation and drawing separate samples from each steam generator for analysis. (9) Gas Decay Tank Discharge Gas Monitor (1-R-22, 2-R-22) This channel monitors the gaseous discharge from the gas decay tanks. The detector consists of a Geiger-Mueller tube inserted into an in-line fixed volume container that includes adequate shielding to reduce the background radiation low enough not to interfere with the detector's sensitivity. This channel will alarm on the main control board and auxiliary building control board and close the gas decay tanks discharge valve on a high radiation level signal. (10) Plant Vent Particulate Monitors (1-R-28, 2-R-28)(1-R-28R, 2-R-28R) Each channel consists of a fixed particulate filter monitored by a beta scintillation detector. RM-28 is part of the NR skid. RM-28R is part of the RNR skid. The sample for each skid is isokinetically drawn from the plant vent stack. Local indication for these channels is provided by the LRPs mounted on their respective skids. Remote indication for these channels is provided by the RDUs for their respective skids. The RDUs are mounted in the radiation monitoring system panels in the control room. (11) Plant Vent Iodine Monitors (1-R-24, 2-R-24)(1-R-24R, 2-R-24R) Each channel consists of a charcoal cartridge filter monitored by a gamma scintillation detector. Iodine is discriminated using a single channel analyzer. RM-24 is part of the NR skid. RM-24R is part of the RNR skid. The sample for each skid is isokinetically drawn from the plant vent stack. Local indication for these channels is provided by the LRPs mounted on their respective skids. Remote indication for these channels is provided by the RDUs for their respective skids. The RDUs are mounted in the radiation monitoring system panels in the control room. (12) Steam Generator Blowdown Tank Liquid Effluent Monitor (1-R-23, 2-R-23) This channel is provided to continuously measure liquid effluent from the blowdown tank. The channel employs a scintillation counter located in an off-line sample chamber. Adequate shielding is employed to reduce effects of background radiation. The count rate is handled in the same manner as for the basic radiation monitoring system. Output is recorded in conjunction with, and parallel to, DCPP UNITS 1 & 2 FSAR UPDATE 11.4-9 Revision 19 May 2010 the recorded outputs of the flow elements related to the blowdown tank inputs and effluents at a local panel specifically provided for that function. Output is also recorded at the data logger in the radiation monitoring system cabinets in the control room. Alarms are provided on the main control board for high and low radiation (instrument failure). A high-radiation signal isolates the blowdown discharge, and diverts blowdown tank liquid effluent to the equipment drain receiver tank. (13) High-Range Plant Vent Gas Monitor (1-R-29, 2-R-29) Postaccident Monitor This monitor measures high-range gross gamma radioactivity in the plant vent. The detector consists of a shielded ion chamber contiguous to the plant vent and mounted on an adjacent support structure. A control room readout, with an associated recording device, is provided on the postaccident monitoring (PAM) panel. Also provided on this panel are the high and low (instrument failure) radiation alarms. The high and fail radiation alarms are also provided on the main control board. The high alarm also alarms in the State of California Office of Emergency Services in Sacramento. (14) Containment Purge Exhaust Monitors (1-R-44A, 2-R-44A)(1-R-44B, 2-R-44B) Each channel consists of a beta scintillation detector mounted to the side of the Containment Purge Exhaust (CPE) duct. The detectors are mounted diametrically opposed on the 48-in CPE duct. Their location is on the downstream of the CPE fan, E-3. Local indication for each channel is provided by the wall mounted LRPs associated with each detector. Remote indication for each channels is provided by the RDUs. The RDUs are mounted in the radiation monitoring system panels in the control room. These monitors provide an engineered safety feature actuation signal to close the CVI valves in the case of high radioactivity exhausting the containment. (15) Extended Range Noble Gas Monitor (1-R-87, 2-R-87) The extended range (ER) channel, RM-87, uses a beta scintillation detector operated in the current mode. The ER noble gas detector is less sensitive and the volume of the detection chamber is smaller than those of the NR noble gas channel. The ER chamber is not pressurized. The sample is isokinetically drawn off the plant vent stack at approximately 1/20th the rate of the sample for the NR and RNR skids. The chamber is downstream of two identical trains of particulate and iodine roughing DCPP UNITS 1 & 2 FSAR UPDATE 11.4-10 Revision 19 May 2010 filters/grab samplers. Alternating between the trains allows removing a grab sample while continuing to monitor the stack. The grab samplers are to be used for assessing post accident releases of particulates and Iodine using laboratory instruments. All of this equipment is mounted on the ER skid. Local indication for RM-87 is provided on the LRP for the NR Skid. Remote indication for RM-87 is provided on the RDU for the NR skid. The RDU is mounted in the radiation monitoring system panels in the control room. Indication for RM-87 is on the same indicating channel used for RM-14. (16) TSC Air Supply Radioactive Particulate Monitor (O-R-66) This monitor is provided to measure air particulate gamma radioactivity in the ventilation air supply to the TSC. The isokinetic flow sampler for this channel takes a continuous air sample from the TSC ventilation air supply duct. (17) TSC Air Supply Noble Gas Monitor (O-R-67) This monitor is provided to measure the noble gas activity in the ventilation air supply to the TSC. The same isokinetic flow as described in item (16) above is used for the analysis. (18) TSC Air Supply Iodine Radiation Monitor (O-R-82) This monitor is provided to measure the iodine activity in the ventilation air supply to the TSC. The same isokinetic flow as described in item (16) above is used for the analysis. (19) Laboratory Adjacent to the TSC Radioactive Particulate Monitor (O-R-68) This monitor is provided to measure air particulate gamma radioactivity in the laboratory. The sample is drawn directly from the room. (20) Laboratory Adjacent to the TSC Noble Gas Monitor (O-R-69) This monitor is provided to measure the noble gas activity in the laboratory. The sample is drawn directly from the room. (21) Laboratory Adjacent to the TSC Iodine Radiation Monitor (O-R-83) This monitor is provided to measure the iodine activity in the laboratory. The sample is drawn directly from the room. DCPP UNITS 1 & 2 FSAR UPDATE 11.4-11 Revision 19 May 2010 (22) Radwaste Storage Building Ventilation Exhaust Air Particulate Samplers (0-RX-55, 0-RX-56) These samplers consist of in-line particulate filter assemblies, which provide the capability to sample and subsequently assess (via laboratory analysis), the concentrations of radioactive material present in the exhaust from the radwaste storage building. RX-55 samples the exhaust from the solid radwaste (old) storage building, and RX-56 samples the exhaust from the laundry/respirator cleaning facility and radwaste (new) storage building prior to the discharge of these effluent points to the environment. (23) Oily Water Separator Effluent Monitor (O-R-3) This channel continuously monitors the turbine building sump retention tank discharge into the oily water separator. (24) Condensate Demineralizer Waste Regenerant Discharge Monitoring The contents of the condensate demineralizer regenerant waste tanks will be processed and periodically sampled prior to release, in accordance with plant procedure. (25) Main Steam Line Activity Monitors (1-R-71 through 1-R-74 and 2-R-71 through 2-R-74) These monitors consist of gamma-sensitive Geiger-Mueller tubes and are provided to continuously monitor the main steam lines. The detectors are located next to each main steam line and measure the steam activity from the line's shine. (26) Gas Decay Tank Cubicle Radiation Monitors (1-R-41, 1-R-42, 1-R-43, 2-R-41, 2-R-42, 2-R-43) These monitors are for detecting noble gas activity in the gas decay tanks. The detectors are located in compartments adjacent to the decay tanks and provide indication on the auxiliary building control board.
(27) Solid Radwaste Inspection Station Radiation Monitors (0-R-84, 0-R-85) These radiation monitors are provided to permit the assessment of the contact (R-84) and one-meter (R-85) radiation dose rates being given off from material containers being prepared for storage and shipment as solid radioactive waste. The detectors are located at the decontamination/inspection station in the solid radwaste storage area.
DCPP UNITS 1 & 2 FSAR UPDATE 11.4-12 Revision 19 May 2010 11.4.2.2.2 Design Evaluation An evaluation of instrumentation function relative to monitoring and controlling releases of radioactivity from various plant systems is discussed below.
(1) Fuel Handling Inside Containment For activity releases inside containment, the air particulate and gas monitors RE-11 and RE-12 will alarm in the control room. The air exhausted from the containment through the containment purge and exhaust lines is monitored by RM-44A and RM-44B. In the event that the pre-determined high alarm setpoint levels are exceeded, these radiation monitoring channels will initiate a signal that would cause the closure of the CVI valves and mitigate the consequences of the accident. (2) Liquid and Gas Wastes For ruptures or leaks in the waste processing system, plant area monitors and the vent stack monitor will alarm on an increase in radiation over a preset level. For cases where leaks are involved, the operator may control activity release by system isolation. For more severe postulated accident cases, such as rupture of waste tanks, activity release is not controlled. The environmental consequences of the postulated accidents are not based on instrument action. For inadvertent releases relative to violation of administrative procedures, monitors provide alarms and the means for limiting radioactive releases. The gas decay tank discharge monitor will close the flow control valve in the waste decay tanks discharge line when the radiation level in the line exceeds a preset level.
Where liquid waste releases are involved, the liquid radwaste discharge monitor trips shut a valve in the discharge line when the radioactivity in the discharge line exceeds a preset level and redirects the flow to the equipment drain receiver tanks. For steam generator blowdown releases, the blowdown effluent monitor and the blowdown sample monitor isolate the blowdown discharge and will divert the blowdown tank liquid effluent to the equipment drain receiver tanks. 11.4.2.3 Area Radiation Monitoring System 11.4.2.3.1 Description This system consists of multiple channels that monitor radiation levels in various areas of the plant. The system has low-range monitors for normal operation and high-range monitors for postaccident conditions. These monitors and their locations are listed in Table 11.4-1. DCPP UNITS 1 & 2 FSAR UPDATE 11.4-13 Revision 19 May 2010 The selection and location of the monitoring areas are based on multiple considerations, including occupancy status of various plant zones, potential for increase in background activity levels due to operations carried out in a particular location, and desirability of surveillance of infrequently visited areas.
A typical channel of the area radiation monitoring system consists of a fixed-position, gamma-sensitive Geiger-Mueller tube detector. The detector count rate is amplified, and its log count rate is displayed by the readout in the radiation monitoring system cabinets. The radiation level is indicated locally at the detector and at the radiation monitoring system cabinets and it is also recorded. Except for the area monitors in the TSC and the adjacent laboratory, the radiation monitoring system cabinets are located in the control room. The radiation monitoring system cabinet for the area monitors in the TSC and laboratory is located in the TSC computation center. High-radiation alarms are displayed on one of two main annunciators, on the radiation monitoring system cabinets, and at the detector location. The control room annunciator provides several windows that alarm for process or area channels detecting high radiation, except for the monitors in the TSC and laboratory. The main annunciator for high radiation detected by the TSC and laboratory area monitors is the TSC HVAC annunciator located in the computation center. A separate window is provided on this annunciator for the TSC area monitors and for the laboratory area monitor. Verification of which channel has alarmed is done at the radiation monitoring system cabinets. Each channel contains a completely integrated modular assembly (see the description of the process radiation monitoring system in Section 11.4.2.2.).
The log level amplifier module amplifies the radiation level signal for indication and recording. The module also provides controls for actuation of the channel check source. A meter is mounted on the front of each readout module and is scaled to read logarithmically from 1.0 x 10-1 to 1.0 x 104 mR/hr. The exceptions are the control room ventilation intake monitor, which has a range of 1.0 x 10-2 to 1.0 x 103 mR/hr, the pressurization intake monitor, which has a range of 1.0 x 10-2 mR/hr to 1.0 x 104 mR/hr, and the area monitor for the PV monitoring skid and the HRSS postaccident sampling room, which has a range of 1.0 x 10-1 to 1.0 x 107 mR/hr. A local meter, scaled logarithmically from 1.0 x 10-2 to 1.0 x 104 mR/hr, is mounted at the detector assembly. Two mutually redundant high-range containment monitors RE-30 and RE-31 are provided for each unit, each consisting of a detector mounted inside the containment liner to mitigate the effects of local hot spots and to obtain the best "view" of the containment free volume. The units are powered from separate instrument power channels.
Each detector is a hermetically sealed, stacked, parallel plate, three-terminal guarded ionization chamber, operated in the saturated mode. The detector and its special cable are environmentally qualified to IEEE 323-1974.
DCPP UNITS 1 & 2 FSAR UPDATE 11.4-14 Revision 19 May 2010 Each readout has a range of 1 to 107 R/hr and has high alarm, failure alarm, logarithmic scale recorder, and electronic system and detector checks. 11.4.2.3.2 Design Evaluation Radiation detection instruments are located in areas of the plant that house equipment containing or processing radioactive materials. These instruments continually detect, compute, and record operating radiation levels. If the radiation level should rise above the setpoint listed for each channel (see Table 11.4-1), an alarm is initiated in a control room.
Local annunciation is provided at the detector to indicate high radiation levels to personnel in the area. The monitoring system is operated in conjunction with regular and special radiation surveys and with chemical and radiochemical analyses performed by the plant staff. Adequate information and warning is thereby provided for the continued safe operation of the plant and assurance that personnel dose does not exceed 10 CFR 20 limits. 11.4.3 SAMPLING 11.4.3.1 Basis for Selection of Sample Locations Locations for periodic sampling are based on the following:
(1) Sampling of process fluids that contain radioactivity (2) Sampling of process fluids not normally radioactive that may become radioactively contaminated due to some component failure 11.4.3.2 Expected Composition and Concentration Because of the diversity of sources of sampled fluids, the activity levels are expected to range from negligible to the reactor coolant concentrations provided in Section 11.1.
Concentrated liquid samples may have higher than normal RCS specific activities. 11.4.3.3 Quantity to Be Measured Samples expected to contain radioactivity are analyzed periodically as specified in the radiological monitoring and controls procedures and the chemical analysis procedures of the Plant Manual. 11.4.3.4 Sampling Frequency and Procedures Sampling frequency varies according to the sample being analyzed and previous activity level of the sample. The sampling frequency for effluents is specified in the radiological and monitoring procedures of the Plant Manual. The sampling frequency DCPP UNITS 1 & 2 FSAR UPDATE 11.4-15 Revision 19 May 2010 for non-effluent samples is specified in the chemical analysis procedures of the Plant Manual. 11.4.3.5 Analytical Procedures and Sensitivity Analytical procedures are in accordance with the Plant Chemistry Manual. The required sensitivities are specified in the radiological and monitoring procedures of the Plant Manual.
Equipment used for radiation analysis is located near the primary chemical laboratory and the laboratory near the TSC. 11.4.3.6 Influence of Results on Plant Operations The Technical Specifications lists the appropriate radioactive contamination limits on the pertinent systems, as well as the required actions if the limits are exceeded. 11.4.4 CALIBRATION AND MAINTENANCE 11.4.4.1 Alarm Setpoints The alarm/trip setpoints for radioactive liquid and gaseous effluent radiation monitors (as defined in Technical Specifications) are determined in accordance with the methodology and parameters in the offsite dose calculation procedure. The alarm/trip setpoints for all other process and area radiation monitors are established by administrative procedures and controlled in Vol. 9B, Table T-IIC-2, "I&C RMS Data Book for Radiation Monitoring and Allied System Data," and are based on protection of public health and safety, plant personnel health and safety, and maintaining efficient plant operation.
Table 11.4-3 lists those monitors that affect valve control operations, together with their effect. 11.4.4.2 Definitions Radiation Monitor Channel Functional Test - Injection of a simulated signal into the channel as close to the sensor as practicable to verify operability including alarm and/or trip functions.
Radiation Monitor Channel Source Check - The qualitative assessment of channel response when the channel sensor is exposed to a radiological source.
Other definitions are listed in Section 1 of Reference 1.
DCPP UNITS 1 & 2 FSAR UPDATE 11.4-16 Revision 19 May 2010 11.4.4.3 Calibration Procedure Area and process monitors were initially calibrated by their original manufacturer. Response curves for each detector were provided with the instrument. These curves essentially relate detector performance to the energy spectrum that the detector would see in operation. 11.4.4.3.1 Area Monitors Based upon the requirements of the plant Technical Specifications, traceable radioactive sources are used to calibrate the area monitors. The monitors are also functionally checked periodically in accordance with the plant Technical Specifications. 11.4.4.3.2 Process Monitors For the process monitors the, detectors are calibrated with traceable radioactive sources on the frequency defined in the plant Technical Specifications or Equipment Control Guidelines (ECGs) (see Chapter 16). Further, the detector response is correlated to the results of analysis of the process stream with calibrated counting room equipment. 11.4.4.4 Test Frequencies Calibration and functional checks of the process and area monitors are performed at frequencies that are in accordance with the plant Technical Specifications and Equipment Control Guidelines. 11.4.4.5 System Summary It is concluded that the administrative controls imposed on the operator, combined with the radiation monitoring system design, provide a high degree of assurance against accidental release of radioactivity to the environment. 11.
4.5 REFERENCES
- 1. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
- 2. ANSI N13.1-1969, American National Standard Guide to Sampling Airborne Radioactive Materials in Nuclear Facilities.
DCPP UNITS 1 & 2 FSAR UPDATE 11.5-1 Revision 21 September 2013 11.5 SOLID WASTE SYSTEM 11.5.1 FUNCTION The solid radwaste system (SRS) is designed to process, package, and store the radioactive wastes generated by plant operations until they are shipped offsite for permanent disposal at a licensed burial facility. Figure 11.5-1 is a flow diagram of the SRS. 11.5.2 DESIGN OBJECTIVES The design objectives of the SRS are:
(1) To provide a means for collecting and processing the plant's radioactive waste streams in accordance with both regulatory and burial site criteria without limiting the functionality of the plant (2) To maintain any potential radiation dose to plant personnel and the environment, as a result of the operation of the SRS, as low as is reasonably achievable (ALARA), within the dose limits of 10 CFR 20 (3) To package the plant's solid radioactive wastes in conformance with the requirements of 10 CFR 71 11.5.3 SYSTEM INPUTS The SRS collects the following inputs for processing, packaging, and disposal: (1) Spent filter/ion exchange media (2) Spent ion exchange resin (3) Spent filter cartridges (4) Miscellaneous dry active wastes (i.e., contaminated paper, rags, clothing, tools, etc.)
The SRS input from each of the plant radioactive waste streams is presented in Table 11.5-1. Tables 11.5-2 and 11.5-4 list the activities of the spent ion exchange resins, the spent filter media, and the spent cartridge filters for both the normal and design basis cases. 11.5.4 COMPONENTS The SRS has five major subsystems: the spent filter/ion exchange media processing system, the spent resin processing system, the spent filter cartridge processing system, DCPP UNITS 1 & 2 FSAR UPDATE 11.5-2 Revision 21 September 2013 the mobile radwaste processing system (MRPS), and the dry active waste processing system. The function of each of these subsystems is described in the following paragraphs. 11.5.4.1 Spent Resins Processing System The system for transferring spent resins from any of the ion exchangers to the spent resin storage tanks (SRSTs) consists of four separate headers connected to four eductors and discharge systems that permit the transfer of resin from any of the 30 ion exchanger units to either of two SRSTs. Pressurized air is used to transfer resin from either SRST to the loadout station (LS) to which the MRPS container is connected. Pressurized air can also be used to transfer resin from one SRST to the other. Two SRST eductors are provided to transfer resin from one SRST to the other. Figure 11.5-3 is a flow diagram of the spent resin processing system.
The general layout of the system is shown in Figure 11.5-11. The SRSTs are located in shielded cells. All of the valves, instruments, and the discharge eductor are located in a separately shielded area (valve gallery) adjacent to the SRST cells. The spent resin LS is located on the east outside wall of the auxiliary building.
A spent resin sampling system allows for the collection of grab samples as resins enter the SRSTs or while the spent resins are being transferred out of the SRSTs to the MRPS.
All of the equipment associated with this system is considered potentially highly radioactive. None of the equipment, which is located behind shielding, will be approached either for operation or maintenance except under the direction of plant radiation protection personnel under the special work permit rules of the plant. 11.5.4.2 Spent Filter/Ion Exchange Media Processing System Pressurized air is used to transfer exhausted media from either of the two radwaste media filters to the LS to which the MRPS container is connected. 11.5.4.3 Spent Filter Cartridge Processing System This system is designed to remove and handle spent filter cartridges generated in the filters of the chemical and volume control system (CVCS), spent fuel storage system, and liquid radwaste system. The radioactively contaminated spent filter cartridges can be removed from the filter housing or vessels with the operator remaining behind shielding. The spent cartridges are transferred to storage or to the MRPS in shielded transfer casks.
It is assumed that the whole change-out procedure takes 1 hour. This includes loading clean filter cartridges. Half an hour can be spent with the operator protected from DCPP UNITS 1 & 2 FSAR UPDATE 11.5-3 Revision 21 September 2013 radioactive spent cartridges by the transfer cask. For the remaining time, the operator is protected from the filter cartridges by concrete, steel, and/or lead shields.
Figures 11.5-6 through 11.5-8 show the location of filters in the system.
Figures 11.5-9 and 11.5-10 display the system for capturing the filters using the grappling hook, cask, pulley, and mirrors. 11.5.4.4 Mobile Radwaste Processing System The MRPS is a skid-mounted mobile radwaste dewatering/solidification system. The MRPS for media and resin is located on a concrete pad as shown in Figure 11.5-12 and in Bay 2 of the Solid Radwaste facility for filters. This space will accommodate the spillage of resins via concrete sloped to a drain within the area.
The MRPS is operated on a batch basis to solidify concentrates, to dewater or solidify spent ion exchange or filtration media, and to encapsulate spent cartridge filters. Slurries from the media filter vessels are sluiced out to the MRPS and dewatered or solidified. Spent resin slurries are sluiced to the MRPS (see Section 11.5.5) from the spent resin storage tank and dewatered or solidified. Filter cartridges are transferred to the MRPS container in a shielded spent filter transfer cask, if required. Waste concentrates, ion exchange media, filtration media, and cartridge filters will be dewatered or solidified in accordance with the process control program detailed in the Plant Procedures Manual.
Normally, containers are dewatered or solidified in processing shields. The containers are stored in the shields until shipment. The containers are transferred by mobile cranes into the shipping casks. Containers may be dewatered and/or solidified while in casks on the trailers by which they will be shipped. When processing is finished in shipping casks, the containers are shipped immediately so that no in-plant handling is required.
Complete waste solidification or absence of free liquid prior to shipment are ensured by the implementation of a process control program consistent with the recommendations of NUREG-0472 (Reference 1). For medium and high activity waste, level sensors monitor the levels in the waste containers and provide alarm signals to alert the MRPS operator to take action to prevent filling beyond preset levels. Low activity waste level may be monitored by sight by the MRPS operator. Potential waste container overflows are contained by the curbed processing pad, then flow into a sump that will return the spill to the radwaste system. 11.5.4.5 Dry Active Waste Processing System Potentially radioactive dry wastes are collected at appropriate locations throughout the plant, as dictated by the volume of the wastes generated during operation or maintenance. The wastes are then segregated, processed, and packaged. DCPP UNITS 1 & 2 FSAR UPDATE 11.5-4 Revision 21 September 2013 Compressible dry active wastes may be processed by compaction in either a drum or box compactor. During compaction, the airflow in the vicinity of the compactor is directed by the compactor exhaust fan through a high-efficiency particulate filter before it is discharged.
Large or highly radioactive components and equipment that have been contaminated during reactor operation and that are not amenable to compaction are handled either by qualified plant personnel or by outside contractors specializing in radioactive materials handling, and the components and equipment are packaged in shipping containers of an appropriate size and design. 11.5.4.6 Mixed Waste Mixed waste is liquid or solid waste that is both hazardous and radioactive. Mixed waste is segregated and accumulated in drums in Bay 6 of the Solid Radwaste Storage Facility (SRSF). Filled drums of mixed waste are placed in storage in Bay 5 of the SRSF. 11.5.4.7 Component Failures and System Malfunctions Analyses have been performed to evaluate potential dose to operating personnel should the solid radwaste systems malfunction or components fail. The components and systems considered most likely to fail are discussed below.
During the transfer of spent resin to the SRSTs, a failure of the motive water pump could result in lines becoming clogged with resin. The lines may be cleaned out by starting up the second motive water pump and using the normal operating procedure. The CVCS resin transfer piping system includes cleanout flanges, which can be used if the lines cannot be cleaned by using the normal procedure. The cleanout flanges are located in areas that are shielded from the main resin transfer lines, and minimize the dose to operating personnel during a cleanout operation.
During the transfer of spent resin from a demineralizer to an SRST, failure of a pneumatically operated valve on the outlet of the demineralizer would require special operator action. The valves have reach-rods extending through the shield wall, permitting manual operation of the valve. After flushing the demineralizer completely and allowing sufficient time for decay of any residual activity, the operating personnel would perform the required repair on the valve. A maximum dose of 800 mR is estimated to occur in the repair of a valve on a CVCS mixed bed demineralizer.
As a backup in the event the pneumatically operated tank outlet valve fails during transfer of spent resin from one of the SRSTs, the valve can be controlled by manual operators extending through a second shield wall to the operating area. DCPP UNITS 1 & 2 FSAR UPDATE 11.5-5 Revision 21 September 2013 11.5.5 PACKAGING Disposable mild steel liners are used for packaging dewatered, solidified or encapsulated wastes. The typical liner sizes may range from 80 to 300 cubic feet. High Integrity Containers (HIC) are also used for packaging dewatered or encapsulated wastes. The typical HIC sizes may range from 75 to 200 cubic feet. Wet solid waste may be packaged for further off-site treatment, on-site storage or off-site disposal. Dry active wastes may be packaged for further off-site treatment, on-site storage or off-site disposal. For on-site storage and direct disposal, 55-gallon steel drums or 4 x 4 x 6 foot steel boxes will typically be used. Drums and boxes classified as IP1 and IP2 containers will be utilized as applicable. 11.5.6 STORAGE FACILITIES Onsite storage for packaged wastes will be provided by the solid radwaste storage facility (SRSF) or by the radwaste storage building (RSB). These buildings are located east of the auxiliary building, as shown in Figure 11.5-4.
The SRSF provides a storage area for metal boxes, drums, and shielded filters. The SRSF can hold 580 drums or 65 boxes and 60 drums. The arrangement of the rooms in the SRSF is shown in Figure 11.5-5. A forklift is used for moving the containers into and within the storage area. Concrete walls provide shielding between the various vaults in the SRSF. Encapsulation or dewatering of filters may occur in the SRSF. Segregation and compaction of dry active waste is also performed in the SRSF. The RSB provides storage areas for 180 liners or HICs and compacted dry active waste in 4 x 4 x 6 foot boxes or 55-gallon drums. The liner storage vaults are sized to accommodate 80 ft3 containers stacked 3 wide by 2 high. An overhead crane assembly is used for moving liners or HICs to their respective storage areas in the RSB. A shielded cask rail car is used to transport liners or HICs from the load-out area to the storage vaults. Encapsulation of filters and dewatering of resin may occur in the shielded cask rail car in the RSB truck bay. A liner-inspection/decontamination station is also provided for preparing containers for storage or shipping.
The compacted dry active waste storage area (DAW vault) is sized to accommodate 522 boxes at 93 ft3 each, totaling 48,456 ft3 of storage. Drums can also be stored in this facility. A fork lift is used for moving the containers into and within the DAW vault.
The old steam generators (OSGs) and old reactor vessel head assemblies (ORVHAs) were removed from DCPP Units 1 and 2 during the steam generator and reactor vessel head replacement projects. These ten large components are temporarily stored in the OSG Storage Facility (OSGSF) specifically constructed for this purpose. The OSGSF meets the radwaste storage requirements for temporary storage of the OSGs and DCPP UNITS 1 & 2 FSAR UPDATE 11.5-6 Revision 21 September 2013 ORVHAs until site decommissioning. The OSGSF is designed to be used as a non-occupied mausoleum for the temporary storage of the OSGs and ORVHAs. No other radwaste storage is permitted within this facility. 11.5.7 SHIPMENT The shipment of prepacked solid waste from the plant site to burial locations is contracted to firms licensed to transport radioactive material in accordance with applicable Department of Transportation regulations. All shipping containers and transportation casks are in conformance with 49 CFR 171 to 49 CFR 178 and 10 CFR 71, as applicable. Table 11.5-5 summarizes the expected quantities to be shipped. 11.
5.8 REFERENCES
- 1. NUREG-0472, Radiological Effluent Technical Specifications for PWRs, Rev. 3, USNRC, March 1979. 11.5.9 REFERENCE DRAWINGS Figures representing controlled engineering drawings are incorporated by reference and are identified in Table 1.6-1. The contents of the drawings are controlled by DCPP procedures.
DCPP UNITS 1 & 2 FSAR UPDATE 11.6-1 Revision 19 May 2010 11.6 OFFSITE RADIOLOGICAL MONITORING PROGRAM The environmental radiation monitoring program was developed to comply with the requirements of the State of California Department of Health Services, Radiological Health Section, and the NRC.
The monitoring program required by the DCPP Technical Specifications (Reference 6) includes monitoring, sampling, analysis, and reporting, including performance of a Land Use Census and participation in an Interlaboratory Comparison Program. 11.6.1 EXPECTED BACKGROUND The 1984 results of the preoperational monitoring program are shown in Table 11.6-4 and Reference 1. Table 11.6-4 summarizes measurements of external dose with thermoluminescent dosimeters (TLDs), gross beta, gamma isotopic, and I-131 activities in air samples and gamma isotopic and I-131 and/or tritium activities (as appropriate for particular samples) in marine and terrestrial samples. There are no known local man-made sources of radioactivity in the vicinity of DCPP; therefore, the variations shown in these tables are considered to be either natural variations or fallout from weapons testing. Gamma isotopic analyses were made of all marine and terrestrial samples. Only a few showed measurable activities above background. The results of all samples with detected activity during the preoperational period January 1, 1981, through March 31, 1984, are included in the Preoperational Environmental Report (Reference 8).
The data, presented on an annual basis, show local differences in activity as well as seasonal variations. Terrestrial variations may be attributable to such factors as variation in the spatial distribution of radionuclides in the soil, the amount of rainfall, TLD locations in valleys as contrasted to hillsides, and secondary sources of airborne dust from such activities as construction or farming.
These data and those for previous years serve as a baseline during plant operation. 11.6.2 CRITICAL PATHWAYS Based on the expected radiological releases from Units 1 and 2 (Section 11.2 and 11.3), and the tabulated estimates of dose, none of the releases is expected to significantly increase the total dose to man relative to natural background. Calculations show which principal pathways for atmospheric releases will give the maximum doses. All doses through aquatic releases are expected to be negligible.
The levels of radiation in environmental samples are expected to be very low and, for many isotopes, below the minimum detectable level, using the best techniques available today. For this reason, dose analyses are performed based principally on plant effluent data, with secondary analyses based on environmental data.
DCPP UNITS 1 & 2 FSAR UPDATE 11.6-2 Revision 19 May 2010 For airborne releases, the Offsite Dose Calculations Procedure (ODCP) is used with measured local meteorological data, measured release data of the gases and particulates, plus local demographic data, to estimate individual dose.
From the gamma dosimeter stations for the direct radiation measurements, in general, the offsite stations are used to serve as reference points for natural background and manmade environmental radiation that is not associated with plant operations. Onsite and fenceline stations are used to measure dose from the plant. Therefore, direct radiation dose above background is obtained and compared to calculated doses.
For radiological releases to the ocean, the ODCP is used in conjunction with effluent data to estimate dose from the consumption of aquatic foods grown within the radiological influence of the plant.
Radiological reconcentration data for species in the vicinity of Diablo Cove are obtained from RG 1.109 (Reference 7).
Aquatic food intake is based on the parameters provided in Reference 7 via the ODCP.
Consideration is also given to any group that has unusually high per capita consumption. 11.6.3 SAMPLING MEDIA, LOCATION AND FREQUENCY 11.6.3.1 Marine Samples The types of marine samples, the frequency of collection, and the sampling location are shown in Table 11.6-1. These samples were selected to represent various food products. 11.6.3.2 Terrestrial Samples Possible dose to man could result from atmospheric immersion and inhalation, and consumption of radionuclides deposited as particulates from the gaseous effluent of DCPP. To monitor the above pathways, various types of terrestrial samples are collected and analyzed. Air samples using particulate filters and iodine cartridges are taken continuously at a minimum of four sample locations. The sites were selected to provide data at downwind locations, major population centers, and areas that are not influenced by plant operations. It should be noted that 8 of 16 sectors surrounding DCPP are located over water, therefore the 5 air sampling stations recommended by the Branch Technical Position for Radiological Environmental Monitoring Program (Revision 1, 1979) were reduced to 4 air sampling stations.
Gamma dosimetry measurements are made at environmental monitoring stations using TLDs. The TLDs were selected because of their sensitivity and the ease of readout.
DCPP UNITS 1 & 2 FSAR UPDATE 11.6-3 Revision 19 May 2010 Drinking water samples are collected from the Raw Water Reservoirs. Surface water samples are collected from the plant outfall. Samples of various foodstuffs produced in the area are also collected when available.
The terrestrial sampling frequency reflects the areas that are most sensitive to changes in radioactive levels and in dose measurements. Thus, the airborne sampling is weekly, the TLD measurements are quarterly, and the terrestrial foods measurements are monthly or in season. 11.6.4 ANALYTICAL SENSITIVITY 11.6.4.1 Types of Analyses The types of radiological analyses performed on each sample are presented in Table 11.6-1. The offsite radiological program emphasizes analyses for those radionuclides expected to be present in the DCPP effluent and those that will be the major contributors to dose to the public.
The effluent from DCPP is expected to contain radionuclides whose identity and activity can be determined by gamma spectrometry. Thus, all samples are placed in a fixed geometry and analyzed by gamma spectrometry. Other analysis techniques can be utilized as deemed necessary. 11.6.4.2 Measuring Equipment The equipment presently in use for the radiological monitoring program typically includes, but is not limited to:
(1) Gas-flow proportional counter for gross beta analyses (2) High purity intrinsic germanium detectors (or equivalent) (3) Thermoluminescent dosimeters for external dose measurements (4) Beta-gamma coincidence spectrometer (5) Liquid scintillation spectrometer 11.6.4.3 Sample Detection Sensitivity The ability to accurately determine the radioactivity in a sample is a function of many variables including the following: (a) sample size, (b) self-absorption in the sample, (c) detector counting efficiency, (d) counting time background count rate, (e) half-life of the isotope, (f) loss of radionuclides in sample preparation, and (g) ability to distinguish between isotopes with similar gamma emission energies. Consistent results are DCPP UNITS 1 & 2 FSAR UPDATE 11.6-4 Revision 19 May 2010 obtained by standardizing procedures that maintain as many of the above variables constant as practicable.
11.6.5 DATA ANALYSIS AND PRESENTATION The data acquired from the environmental monitoring program falls into the categories of:
(1) Information on the distribution of radioactivity in lower trophic levels in the physical environs of DCPP (2) Information on external radiation in the vicinity of DCPP (3) Information on radionuclides in foodstuffs that may result in a dose to man In examining the distribution of radionuclides in the environment and lower trophic levels, comparisons are made to the preoperational data to determine if there are any biological or physical compartments in nature that are accumulating radioactivity.
Similarly, external radioactivity measurements during plant operation are compared with the average and range of data obtained in the preoperational program.
If radionuclides due to plant effluents are found in foodstuffs, estimates of radiation dose are made that utilize the best estimates of food consumption. These dose calculations are compared with those based on plant emission data with the appropriate meteorological and aquatic dispersion models as discussed in Section 11.6.2. The data from the offsite monitoring program are reported annually. The reports include the basic data on sampling locations, organism collected, counting data, gross activity levels, identification of gamma emitting isotopes, and the associated counting errors. Tables 11.6-13 and 11.6-14 tabulate estimated concentrations and depositions based on the monitoring program. 11.6.6 PROGRAM STATISTICAL SENSITIVITY The activity in environmental samples is expected to be low after dilution and dispersion of radionuclides released by the power plant. For many isotopes, the radioactivity will be below the lower limits of detection (LLD) that are listed in Table 11.6-11. Doses calculated from environmental measurements at the LLD will demonstrate doses below 5 millirem per year. With dose estimated from effluent data as shown in Sections 11.2 and 11.3, much lower dose levels can be estimated even though large errors may be introduced in the dispersion modeling. Thus, doses estimated using effluent data will provide a more detailed definition of the dose increments due to the operation of DCPP than will dose estimates calculated from the environmental measurements.
Counting errors for effluent data and errors associated with the calculational models will be used to determine the overall sensitivity of estimated dose. Where dose calculations DCPP UNITS 1 & 2 FSAR UPDATE 11.6-5 Revision 19 May 2010 are based on environmental data, errors in the environmental sample analysis will be included in the overall program sensitivity analysis. 11.
6.7 REFERENCES
- 1. 1984 Annual Environmental Radiological Report, Diablo Canyon Power Plant, Pacific Gas and Electric Company, San Ramon, CA, Report 411-85.123, 1985.
- 2. Deleted in Revision 1.
- 3. Deleted in Revision 1.
- 4. Deleted in Revision 1.
- 5. Deleted in Revision 1.
- 6. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
- 7. Regulatory Guide 1.109, Revision 1, Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10 CFR Part 50, Appendix I, USNRC, October 1977.
- 8. Preoperational Radiological Environmental Report, Diablo Canyon Power Plant, Pacific Gas and Electric Company, San Ramon, CA, Report 411-84.530, 1985.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-1 LIBRARY OF PHYSICAL DATA FOR ISOTOPES Number Nuclide Half-life, Yield Beta Energy, Gamma Energy, Decay Const., hours Fract MeV/Dis MeV/Dis hr-1 1 H-3 0.108E 06 0.800E-04 0.00620 0.0 0.642E-05 2 Cr-51 0.667E 03 0.0 0.00055 0.02900 0.104E-02 3 Mn-54 0.727E 04 0.0 0.00590 0.83500 0.953E-04 4 Fe-55 0.648E 02 0.0 0.0 0.00600 0.107E-01 5 Co-58 0.171E 04 0.0 0.03100 0.98100 0.405E-03 6 Fe-59 0.108E 04 0.0 0.12900 1.17000 0.642E-03 7 Co-60 0.461E 05 0.0 0.10400 2.49000 0.150E-04 8 Kr-83M 0.186E 01 0.470E-02 0.03900 0.00050 0.373E 00 9 Kr-85M 0.440E 01 0.103E-01 0.25200 0.16000 0.157E 00 10 Kr-85 0.941E 05 0.0 0.22100 0.00200 0.736E-05 11 Kr-87 0.127E 01 0.194E-01 1.34000 0.76400 0.546E 00 12 Kr-88 0.277E 01 0.279E-01 0.37200 2.03000 0.250E 00 13 Sr-89 0.123E 04 0.369E-01 0.55600 0.0 0.563E-03 14 Sr-90 0.245E 06 0.455E-01 0.16900 0.0 0.283E-05 15 Y-90 0.639E 02 0.0 0.91200 0.0 0.208E-01 16 Sr-91 0.972E 01 0.461E-01 0.62400 0.84000 0.713E-01 17 Y-91 0.147E 04 0.120E-02 0.59300 0.00400 0.471E-03 18 Sr-92 0.270E 01 0.453E-01 0.21400 1.29000 0.257E 00 19 Y-92 0.360E 01 0.390E-02 1.39000 0.48500 0.192E 00 20 Zr-95 0.157E 04 0.585E-01 0.11100 0.73900 0.441E-03 21 Nb-95 0.841E 03 0.136E-02 0.04500 0.76000 0.824E-03 22 Mo-99 0.680E 02 0.607E-01 0.40500 0.12600 0.102E-01 23 I-131 0.193E 03 0.319E-01 0.18300 0.39200 0.359E-02 24 Te-132 0.779E 02 0.464E-01 0.06100 0.23100 0.890E-02 25 I-132 0.240E 01 0.530E-03 0.48500 2.28000 0.289E 00 26 I-133 0.210E 02 0.620E-01 0.49300 0.62400 0.330E-01 27 Xe-133M 0.552E 02 0.0 0.20700 0.02100 0.126E-01 28 Xe-133 0.127E 03 0.0 0.15500 0.04500 0.546E-02 29 Cs-134 0.180E 05 0.410E-04 0.16800 1.57000 0.385E-04 30 I-134 0.866E 00 0.764E-01 0.94100 2.58000 0.800E 00 31 I-135 0.670E 01 0.600E-01 0.31600 1.56000 0.103E 00 32 Xe-135M 0.260E 00 0.0 0.10400 0.42100 0.267E 01 33 Xe-135 0.920E 01 0.313E-02 0.30400 0.26200 0.753E-01 34 Cs-136 0.312E 03 0.377E-03 0.11900 2.21000 0.222E-02 35 Cs-137 0.236E 06 0.633E-01 0.17300 0.56200 0.294E-05 36 Xe-138 0.233E 00 0.558E-01 0.5900 1.28000 0.297E 01 37 Ba-140 0.307E 03 0.596E-01 0.27400 0.21200 0.226E-02 38 La-140 0.401E 02 0.103E-02 0.43900 2.31000 0.173E-01 39 Ce-144 0.685E 04 0.485E-01 0.09300 0.01600 0.101E-03 40 Pr-144 0.292E 00 0.0 1.20000 0.06400 0.237E 01
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-2 BASIC ASSUMPTIONS FOR CORE AND COOLANT INVENTORIES FOR DESIGN BASIS CASE Reactor core thermal power, mw 3568.0 Duration of cycle, hr 8760.0 Capacity factor during period 0.800 Number of fissions per megawatt-second 0.315E17 Total mass of uranium in core, lb 1.97E5 Total mass of plutonium in core, lb 6.05E2 Reload uranium enrichment, percent 3.18 Reload mass of fissile plutonium, lb 0.0 Primary-to-secondary leakrate, gpm 0.0 Primary coolant leakage to containment, gpm 0.0 Primary coolant leakage to auxiliary building, gpm 0.0 Fraction of fuel with defective cladding 0.01 Weight of water in primary system, lb 5.66E5 Volume of water in primary system, gal. 9.40E4 Letdown flowrate, gpm 75.0 Capacity factor of primary cation demineralizer 0.1 Average shim bleed flowrate, gpm 1.0 Fraction of shim bleed flow discharged to environment 0.667
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-3 BASIC ASSUMPTIONS FOR CORE AND COOLANT INVENTORIES FOR NORMAL OPERATION CASE Reactor core thermal power, mw 3568.0 Duration of cycle, hr 8760.0 Capacity factor during period 0.800 Number of fissions per megawatt-second 0.315E17 Total mass of uranium in core, lb 1.97E5 Total mass of plutonium in core, lb 6.05E2 Reload uranium enrichment, percent 3.18 Reload mass of fissile plutonium, lb 0.0 Primary-to-secondary leakrate, gpm 0.0115 Primary coolant leakage to containment, gpm 0.0385 Primary coolant leakage to auxiliary building, gpm 0.0184 Fraction of fuel with defective cladding 0.0012 Weight of water in primary system, lb 5.66E5 Volume of water in primary system, gal. 9.40E4 Letdown flowrate, gpm 75.0 Capacity factor of primary cation demineralizer 0.1 Average shim bleed flowrate, gpm 1.0 Fraction of shim bleed flow discharged to environment 0.667
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-4 CORE ACTIVITY INVENTORIES FOR DESIGN BASIS CASE (CURIES)
Nuclide Initial Act. Produced Decayed Lkge to Coolt. Inventory Equil Inven. Curies/Megawatt Cr-51 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Mn-54 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Fe-55 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Co-58 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Fe-59 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Co-60 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Kr-83M 0.0 0.4660E 11 0.4658E 11 0.2340E 06 0.1428E 08 0.1428E 08 0.4001E 04 Kr-85M 0.0 0.4317E 11 0.4314E 11 0.5127E 06 0.3129E 08 0.3129E 08 0.8769E 04 Kr-85 0.4007E 06 0.4639E 06 0.3932E 05 0.1249E 05 0.8128E 06 0.5461E 07 0.2278E 03 Kr-87 0.0 0.2817E 12 0.2816E 12 0.9662E 06 0.5893E 08 0.5893E 08 0.1652E 05 Kr-88 0.0 0.1857E 12 0.1856E 12 0.1389E 07 0.8475E 08 0.8475E 08 0.2375E 05 Sr-89 0.4946E 06 0.5532E 09 0.4910E 09 0.2510E 03 0.1116E 09 0.1121E 09 0.3129E 05 Sr-90 0.3073E 07 0.3425E 07 0.1173E 06 0.1194E 02 0.6380E 07 0.1382E 09 0.1786E 04 Y-90 0.3073E 07 0.4497E 09 0.4464E 09 0.1897E 01 0.6346E 07 0.1382E 09 0.1779E 04 Sr-91 0.4745E-14 0.8746E 11 0.8732E 11 0.3527E 03 0.1400E 09 0.1400E 09 0.3925E 05 Y-91 0.6767E 08 0.5924E 09 0.5177E 09 0.5060E 02 0.1424E 09 0.1437E 09 0.3992E 05 Sr-92 0.0 0.3094E 12 0.3093E 12 0.3470E 03 0.1376E 09 0.1376E 09 0.3857E 05 Y-92 0.0 0.2519E 12 0.2518E 12 0.6027E 02 0.1495E 09 0.1495E 09 0.4189E 05 Zr-95 0.8460E 08 0.6871E 09 0.5960E 09 0.6221E 02 0.1758E 09 0.1777E 09 0.4926E 05 Nb-95 0.1083E 09 0.1142E 10 0.1073E 10 0.6000E 02 0.1777E 09 0.1818E 09 0.4981E 05 Mo-99 0.8000E 05 0.1646E 11 0.1628E 11 0.9199E 05 0.1844E 09 0.1844E 09 0.5168E 05 I-131 0.4937E 07 0.3048E 10 0.2956E 10 0.3082E 06 0.9689E 08 0.9689E 08 0.2715E 05 Te-132 0.1553E 06 0.1098E 11 0.1084E 11 0.3510E 05 0.1409E 09 0.1409E 09 0.3950E 05 I-132 0.1602E 06 0.3560E 12 0.3559E 12 0.4614E 06 0.1426E 09 0.1426E 09 0.3995E 05 I-133 0.6024E-02 0.5444E 11 0.5425E 11 0.6155E 06 0.1883E 09 0.1883E 09 0.5278E 05 Xe-133M 0.1593E 04 0.4954E 09 0.4908E 09 0.7318E 05 0.4519E 07 0.4519E 07 0.1267E 04 Xe-133 0.3309E 07 0.8969E 10 0.8780E 10 0.3012E 07 0.1882E 09 0.1882E 09 0.5276E 05 Cs-134 0.1460E 01 0.3605E 07 0.1284E 07 0.1248E 05 0.3116E 07 0.3116E 07 0.8734E 03 I-134 0.0 0.1627E 13 0.1627E 13 0.7610E 06 0.2321E 09 0.2321E 09 0.6504E 05 I-135 0.0 0.1651E 12 0.1650E 12 0.5971E 06 0.1823E 09 0.1823E 09 0.5108E 05 Xe-135M 0.0 0.6164E 12 0.6163E 12 0.4329E 06 0.2643E 08 0.2643E 08 0.7407E 04 Xe-135 0.9747E-15 0.1264E 12 0.1838E 11 0.4567E 06 0.2789E 08 0.2789E 08 0.7816E 04 Cs-136 0.1542E 06 0.7228E 08 0.2129E 08 0.3588E 04 0.1145E 07 0.1145E 07 0.3209E 03 Cs-137 0.4430E 07 0.4946E 07 0.1753E 06 0.2235E 05 0.9173E 07 0.1658E 09 0.2571E 04 Xe-138 0.0 0.4416E 13 0.4416E 13 0.2779E 07 0.1695E 09 0.1695E 09 0.4751E 05 Ba-140 0.2375E 08 0.3580E 10 0.3423E 10 0.4367E 03 0.1810E 09 0.1610E 09 0.5074E 05 La-140 0.2732E 08 0.2668E 11 0.2652E 11 0.7071E 02 0.1642E 09 0.1842E 09 0.5162E 05 Ce-144 0.6129E 08 0.1306E 09 0.7999E 08 0.3644E 02 0.1119E 09 0.1473E 09 0.3135E 05 Pr-144 0.6127E 08 0.1877E 13 0.1876E 13 0.3643E 02 0.1119E 09 0.1473E 09 0.3135E 05
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-5 CORE ACTIVITY INVENTORIES FOR NORMAL OPERATION CASE (CURIES) Nuclide Initial Act. Produced Decayed Lkge to Coolt. Inventory Equil Inven. Curies/Megawatt Cr-51 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Mn-54 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Fe-55 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Co-58 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Fe-59 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Co-60 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Kr-83M 0.0 0.4660E 11 0.4658E 11 0.2809E 05 0.1428E 08 0.1428E 08 0.4001E 04 Kr-85M 0.0 0.4317E 11 0.4314E 11 0.6152E 05 0.3129E 08 0.3129E 08 0.8769E 04 Kr-85 0.4007E 06 0.4639E 06 0.3963E 05 0.1511E 04 0.8235E 06 0.6932E 07 0.2308E 03 Kr-87 0.0 0.2817E 12 0.2816E 12 0.1159E 06 0.5893E 08 0.5893E 08 0.1652E 05 Kr-88 0.0 0.1857E 12 0.1857E 12 0.1667E 06 0.8475E 08 0.8475E 08 0.2375E 05 Sr-89 0.4946E 08 0.5532E 09 0.4910E 09 0.3012E 02 0.1116E 09 0.1121E 09 0.3129E 05 Sr-90 0.3073E 07 0.3425E 07 0.1173E 06 0.1433E 01 0.6380E 07 0.1382E 09 0.1788E 04 Y-90 0.3073E 07 0.4497E 09 0.4465E 09 0.2276E 00 0.6346E 07 0.1382E 09 0.1779E 04 Sr-91 0.4745E-14 0.8746E 11 0.8732E 11 0.4233E 02 0.1400E 09 0.1400E 09 0.3925E 05 Y-91 0.6767E08 0.5924E 09 0.5177E 09 0.6072E 01 0.1424E 09 0.1437E 09 0.3992E 05 Sr-92 0.0 0.3094E 12 0.3093E 12 0.4164E 02 0.1376E 09 0.1376E 09 0.3857E 05 Y-92 0.0 0.2519E 12 0.2518E 12 0.7232E 01 0.1495E 09 0.1495E 09 0.4189E 05 Zr-95 0.8460E 08 0.6871E 09 0.5960E 09 0.7466E 01 0.1758E 09 0.1777E 09 0.4926E 05 Nb-95 0.1083E 09 0.1142E 10 0.1073E 10 0.7200E 01 0.1777E 09 0.1818E 09 0.4981E 05 Mo-99 0.8000E 05 0.1646E 11 0.1628E 11 0.1104E 05 0.1844E 09 0.1844E 09 0.5168E 05 I-131 0.4937E 07 0.3048E 10 0.2956E 10 0.3699E 05 0.9690E 08 0.9690E 08 0.2716E 05 Te-132 0.1553E 06 0.1098E 11 0.1084E 11 0.4212E 04 0.1409E 09 0.1409E 09 0.3950E 05 I-132 0.1602E 06 0.3560E 12 0.3559E 12 0.5537E 05 0.1426E 09 0.1426E 09 0.3995E 05 I-133 0.6024E 02 0.5444E 11 0.5425E 11 0.7387E 05 0.1883E 09 0.1883E 09 0.5278E 05 Xe-133M 0.1593E 04 0.4954E 09 0.4908E 09 0.8783E 04 0.4520E 07 0.4520E 07 0.1267E 04 Xe-133 0.3309E 07 0.8969E 10 0.8784E 10 0.3616E 06 0.1883E 09 0.1883E 09 0.5278E 05 Cs-134 0.1460E 01 0.3605E 07 0.1298E 07 0.1514E 04 0.3121E 07 0.3121E 07 0.8749E 03 I-134 0.0 0.1627E 13 0.1627E 13 0.9132E 05 0.2321E 09 0.2321E 09 0.6504E 05 I-135 0.0 0.1651E 12 0.1650E 12 0.7165E 05 0.1823E 09 0.1823E 09 0.5108E 05 Xe-135M 0.0 0.6164E 12 0.6163E 12 0.5195E 05 0.2643E 08 0.2643E 08 0.7407E 04 Xe-135 0.9747E-15 0.1264E 12 0.1838E 11 0.5481E 05 0.2789E 08 0.2789E 08 0.7816E 04 Cs-136 0.1542E 06 0.2228E 08 0.2129E 08 0.4307E 03 0.1145E 07 0.1145E 07 0.3210E 03 Cs-137 0.4430E 07 0.4946E 07 0.1755E 06 0.2686E 04 0.9197E 07 0.1887E 09 0.2578E 04 Xe-138 0.0 0.4416E 13 0.4416E 13 0.3335E 06 0.1695E 09 0.1695E 09 0.4751E 05 Ba-140 0.2375E 08 0.3580E 10 0.3423E 10 0.5240E 02 0.1810E 09 0.1810E 09 0.5074E 05 La-140 0.2732E 08 0.2668E 11 0.2652E 11 0.8486E 01 0.1842E 09 0.1842E 09 0.5162E 05 Ce-144 0.6129E 08 0.1306E 09 0.7999E 08 0.4372E 01 0.1119E 09 0.1473E 09 0.3135E 05 Pr-144 0.6127E 08 0.1877E 13 0.1876E 13 0.4372E 01 0.1119E 09 0.1473E 09 0.3135E 05
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-6 BASIC ASSUMPTIONS FOR FUEL ROD GAP INVENTORIES Percent of Core Fuel Within Given Fuel Temperature Temperature Range(a) Power, MWt Range, °F 0.0 0.1961 >3400 0.1 3.1373 3400 - 3200 0.3 10.3922 3200 - 3000 0.7 25.1 3000 - 2800 1.6 58.333 2800 - 2600 2.9 104.61 2600 - 2400 4.3 152.55 2400 - 2200 5.9 211.275 2200 - 2000 84.1 2999.02 <2000 (a) Based on hot channel factors of FH = 1.70 and Fq = 2.82. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-7 ACTIVITY IN FUEL ROD GAPS Nuclide Pellet Release Fraction Gap Inventory, Ci Kr-83M 0.000824 0.118E 05 Kr-85M 0.001240 0.388E 05 Kr-85 0.167000 0.138E 06 Kr-87 0.000668 0.394E 05 Kr-88 0.000998 0.846E 05 I-131 0.008220 0.797E 06 I-132 0.000901 0.128E 06 I-133 0.002710 0.510E 06 Xe-133M 0.004370 0.198E 05 Xe-133 0.006670 0.126E 07 I-134 0.000557 0.129E 06 I-135 0.001540 0.281E 06 Xe-135M 0.000303 0.801E 04 Xe-135 0.001800 0.502E 05 Xe-138 0.000316 0.536E 05 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-8 INPUT CONSTANTS FOR COOLANT ACTIVITIES FOR DESIGN BASIS CASE Fuel to Coolant, Fuel Escape Rate, Pur. Rate, P-S Leak Rate, Prim-Cont Lk Rate, Prim-Aux Lk Rate Nuclide Ci/hr sec-1 hr-1 hr-1 hr-1 hr-1 H-3 0.0 0.0 0.5897E-03 0.0 0.0 0.0 Cr-51 0.3010E-01 0.0 0.6034E-01 0.0 0.0 0.0 Mn-54 0.4820E-02 0.0 0.6034E-01 0.0 0.0 0.0 Fe-55 0.2890E-01 0.0 0.6034E-01 0.0 0.0 0.0 Co-58 0.2500E 00 0.0 0.6034E-01 0.0 0.0 0.0 Fe-59 0.1570E-01 0.0 0.6034E-01 0.0 0.0 0.0 Co-60 0.3090E-01 0.0 0.6034E-01 0.0 0.0 0.0 Kr-83M 0.3340E 02 0.6500E-07 0.8840E-03 0.0 0.0 0.0 Kr-85M 0.7316E 02 0.6500E-07 0.8840E-03 0.0 0.0 0.0 Kr-85 0.1426E 01 0.6500E-07 0.8840E-03 0.0 0.0 0.0 Kr-87 0.1379E 03 0.6500E-07 0.8840E-03 0.0 0.0 0.0 Kr-88 0.1982E 03 0.6500E-07 0.8840E-03 0.0 0.0 0.0 Sr-89 0.3582E-01 0.1000E-10 0.6034E-01 0.0 0.0 0.0 Sr-90 0.1704E-02 0.1000E-10 0.6034E-01 0.0 0.0 0.0 Y-90 0.2707E-03 0.1600E-11 0.8840E-03 0.0 0.0 0.0 Sr-91 0.5033E-01 0.1000E-10 0.6034E-01 0.0 0.0 0.0 Y-91 0.7220E-02 0.1600E-11 0.8840E-03 0.0 0.0 0.0 Sr-92 0.4952E-01 0.1000E-10 0.6034E-01 0.0 0.0 0.0 Y-92 0.8600E-02 0.1600E-11 0.8840E-03 0.0 0.0 0.0 Zr-95 0.8878E-02 0.1600E-11 0.6034E-01 0.0 0.0 0.0 Nb-95 0.8562E-02 0.1600E-11 0.6034E-01 0.0 0.0 0.0 Mo-99 0.1313E 02 0.2000E-08 0.8840E-03 0.0 0.0 0.0 I-131 0.4398E 02 0.1300E-07 0.5976E-01 0.0 0.0 0.0 Te-132 0.5009E 01 0.1000E-08 0.5976E-01 0.0 0.0 0.0 I-132 0.6584E 02 0.1300E-07 0.5976E-01 0.0 0.0 0.0 I-133 0.8783E 02 0.1300E-07 0.5576E-01 0.0 0.0 0.0 Xe-133M 0.1044E 02 0.6500E-07 0.8840E-03 0.0 0.0 0.0 Xe-133 0.4298E 03 0.6500E-07 0.8840E-03 0.0 0.0 0.0 Cs-134 0.1781E 01 0.1300E-07 0.3637E-01 0.0 0.0 0.0 I-134 0.1086E 03 0.1300E-07 0.5976E-01 0.0 0.0 0.0 I-135 0.8520E 02 0.1300E-07 0.5976E-01 0.0 0.0 0.0 Xe-135M 0.6177E 02 0.6500E-07 0.8840E-03 0.0 0.0 0.0 Xe-135 0.6517E 02 0.6500E-07 0.8840E-03 0.0 0.0 0.0 Cs-136 0.5120E 00 0.1300E-07 0.3637E-01 0.0 0.0 0.0 Cs-137 0.3189E 01 0.1300E-07 0.3637E-01 0.0 0.0 0.0 Xe-138 0.3988E 03 0.6500E-07 0.8840E-01 0.0 0.0 0.0 Ba-140 0.8231E-01 0.1000E-10 0.6034E-01 0.0 0.0 0.0 La-140 0.1009E-01 0.1000E-11 0.6034E-01 0.0 0.0 0.0 Ce-144 0.5199E-02 0.1600E-11 0.6034E-01 0.0 0.0 0.0 Pr-144 0.5199E-02 0.1600E-11 0.6034E-01 0.0 0.0 0.0
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-9 INPUT CONSTANTS FOR COOLANT ACTIVITIES FOR NORMAL OPERATION CASE Fuel to Coolant, Fuel Escape Rate, Pur. Rate, P-S Leak Rate, Prim-Cont Lk Rate, Prim-Aux Lk Rate Nuclide Ci/hr sec-1 hr-1 hr-1 hr-1 hr-1 H-3 0.0 0.0 0.5897E-03 0.7340E-05 0.2457E-04 0.1174E-04 Cr-51 0.3010E-01 0.0 0.6034E-01 0.7340E-05 0.2457E-04 0.1174E-04 Mn-54 0.4820E-02 0.0 0.6034E-01 0.7340E-05 0.2457E-04 0.1174E-04 Fe-55 0.2890E-01 0.0 0.6034E-01 0.7340E-05 0.2457E-04 0.1174E-04 Co-58 0.2500E 00 0.0 0.6034E-01 0.7340E-05 0.2457E-04 0.1174E-04 Fe-59 0.1570E-01 0.0 0.6034E-01 0.7340E-05 0.2457E-04 0.1174E-04 Co-60 0.3090E-01 0.0 0.6034E-01 0.7340E-05 0.2457E-04 0.1174E-04 Kr-83M 0.4008E 01 0.6500E-07 0.8840E-03 0.7340E-05 0.4167E-03 0.1174E-04 Kr-85M 0.8779E 01 0.6500E-07 0.8840E-03 0.7340E-05 0.4167E-03 0.1174E-04 Kr-85 0.1725E 00 0.6500E-07 0.8840E-03 0.73403-05 0.4167E-03 0.1174E-04 Kr-87 0.1854E 02 0.6500E-07 0.8840E-03 0.7340E-05 0.4167E-03 0.1174E-04 Kr-88 0.2379E 02 0.6500E-07 0.8840E-03 0.7340E-05 0.4167E-03 0.1174E-04 Sr-89 0.4298E-02 0.1000E-10 0.6034E-01 0.7340E-05 0.2457E-04 0.1174E-04 Sr-90 0.2045E-03 0.1000E-10 0.6034E-01 0.7340E-05 0.2457E-04 0.1174E-04 Y-90 0.3248E-04 0.1600E-11 0.8840E-03 0.7340E-05 0.2457E-04 0.1174E-04 Sr-91 0.6040E-02 0.1000E-10 0.6034E-01 0.7340E-05 0.2457E-04 0.1174E-04 Y-91 0.8664E-03 0.1600E-11 0.8840E-03 0.7340E-05 0.2457E-04 0.1174E-04 Sr-92 0.5942E-02 0.1000E-10 0.6034E-01 0.7340E-05 0.2457E-04 0.1174E-04 Y-92 0.1032E-02 0.1600E-11 0.8840E-03 0.7340E-05 0.2457E-04 0.1174E-04 Zr-95 0.1065E-02 0.1600E-11 0.6034E-01 0.7340E-05 0.2457E-04 0.1174E-04 Mb-95 0.1027E-02 0.1600E-11 0.6034E-01 0.7340E-05 0.2457E-04 0.1174E-04 Mb-99 0.1575E 01 0.2000E-08 0.8840E-03 0.7340E-05 0.2457E-04 0.1174E-04 I-131 0.5278E 01 0.1300E-07 0.5976E-01 0.7340E-05 0.2457E-04 0.1174E-04 Te-132 0.6011E 00 0.1000E-08 0.5976E-01 0.7340E-05 0.2457E-04 0.1174E-04 I-132 0.7901E 01 0.1300E-07 0.5976E-01 0.7340E-05 0.2457E-04 0.1174E-04 I-133 0.1054E 02 0.1300E-07 0.5976E-01 0.7340E-05 0.2457E-04 0.1174E-04 Me-133M 0.1253E 01 0.6500E-07 0.8840E-03 0.7340E-05 0.4167E-03 0.1174E-04 Mn-133 0.5160E 02 0.6500E-07 0.8840E-03 0.7340E-05 0.4167E-03 0.1174E-04 Cs-134 0.2161E 00 0.1300E-07 0.3637E-01 0.7340E-05 0.2457E-04 0.1174E-04 I-134 0.1303E 02 0.1300E-07 0.5976E-01 0.7340E-05 0.2457E-04 0.1174E-04 I-135 0.1022E 02 0.1300E-07 0.5976E-01 0.7340E-05 0.2457E-04 0.1174E-04 Xe-135M 0.7412E 01 0.6500E-07 0.8840E-03 0.7340E-05 0.4167E-03 0.1174E-04 Xe-135 0.7821E 01 0.6500E-07 0.8840E-03 0.7340E-05 0.4167E-03 0.1174E-04 Cs-136 0.6145E-01 0.1300E-07 0.3637E-01 0.7340E-05 0.2457E-04 0.1174E-04 Cs-137 0.3832E 00 0.1300E-07 0.3637E-01 0.7340E-05 0.2457E-04 0.1174E-04 Xe-138 0.4759E 02 0.6500E-07 0.8840E-03 0.7340E-05 0.4167E-03 0.1174E-04 Ba-140 0.7477E-02 0.1000E-10 0.6034E-01 0.7340E-05 0.2457E-04 0.1174E-04 La-140 0.1211E-02 0.1600E-11 0.6034E 01 0.73403-05 0.2457E-04 0.1174E-04 Ce-144 0.6239E-03 0.1600E-11 0.6034E-01 0.7340E-05 0.2457E-04 0.1174E-04 Pr-144 0.6239E-03 0.1600E-11 0.6034E-01 0.7340E-05 0.2457E-04 0.1174E-04
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-10 BASIC DATA FOR CORROSION PRODUCT ACTIVITIES Core Wetted Areas, Effective, in2 Zirconium 9.42 x 106 Stainless steel 6.09 x 105 Inconel 1.01 x 106 Out-of-core Wetted Area, Inconel, in2 2.74 x 107 Coolant velocity, ft/sec Core 15.0 Steam generator 18.6 Nominal Base Metal Release Rates, mg/dm2-mo Zirconium 0.0 Stainless steel 0.5 Inconel 1.0 Coolant Crud Level, ppm 0.1 Permanent Crud Film, Nominal, mg/dm2 Incore 50 Out-of-core 50 Transient Crud Layer, Nominal, mg/dm2 Incore 50 Out-of-core 50 Total mass of metal in contact with primary coolant, lb 2.2 x 106 DCPP UNITS 1 & 2 FSAR UPDATE Revision 13 April 2000 TABLE 11.1-11 PRIMARY COOLANT ACTIVITIES FOR DESIGN BASIS CASE Nuclide Concentration, µCi/cc Activity, Ci H-3 0.7934E 00 0.2823E 03 Cr-51 0.1378E-02 0.4904E 00 Mn-54 0.2241E-03 0.7976E-01 Fe-55 0.1143E-02 0.4069E 00 Co-58 0.2600E-01 0.9250E-01 Fe-59 0.7236E-03 0.2575E 00 Co-60 0.1439E-02 0.5120E 00 Kr-83M 0.2513E 00 0.8943E 02 Kr-85M 0.1298E 01 0.4619E 03 Kr-85 0.4166E 01 0.1482E 04 Kr-87 0.7089E 00 0.2522E 03 Kr-88 0.2219E 01 0.7895E 03 Sr-89 0.1653E-02 0.5881E 00 Sr-90 0.7937E-04 0.2824E-01 Y-90 0.1382E-03 0.4919E-01 Sr-91 0.1075E-02 0.3824E 00 Y-91 0.1534E-01 0.5460E 01 Sr-92 0.4390E-03 0.1562E 00 Y-92 0.5619E-03 0.2000E 00 Zr-95 0.4105E-03 0.1461E 00 Nb-95 0.3989E-03 0.1420E 00 Mo-99 0.3331E 01 0.1185E 04 I-131 0.1951E 01 0.6941E 03 Te-132 0.2050E 00 0.7296E 02 I-132 0.7008E 00 0.2494E 03 I-133 0.2661E 01 0.9469E 03 Xe-133M 0.2243E 01 0.7983E 03 Xe-133 0.1947E 03 0.6927E 05 Cs-134 0.1375E 00 0.4893E 02 I-134 0.3549E 00 0.1263E 03 I-135 0.1467E 01 0.5221E 03 Xe-135M 0.2778E 00 0.9884E 02 Xe-135 0.3918E 01 0.1394E 04 Cs-136 0.3729E-01 0.1327E 02 Cs-137 0.2464E 00 0.8767E 02 Xe-138 0.3746E 00 0.1333E 03 Ba-140 0.2798E-02 0.9955E 00 La-140 0.9882E-03 0.3516E 00 Ce-144 0.2418E-03 0.8602E-01 Pr-144 0.2418E-03 0.8603E-01 Zn-65 0.8000E-02 0.2846E-01 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-12 PRIMARY COOLANT ACTIVITIES FOR NORMAL OPERATION CASE
Nuclide Concentration, µCi/cc Activity, Ci H-3 0.7377E 00 0.2625E 03 Cr-51 0.1377E-02 0.4901E 00 Mn-54 0.2240E-03 0.7970E-01 Fe-55 0.1143E-02 0.4066E 00 Co-58 0.1156E-01 0.4113E 01 Fe-59 0.7230E-03 0.2573E 00 Co-60 0.1438E-02 0.5116E 00 Kr-83M 0.3012E-01 0.1072E 02 Kr-85M 0.1553E 00 0.5528E 02 Kr-85 0.3579E 00 0.1273E 03 Kr-87 0.8500E-01 0.3025E 02 Kr-88 0.2658E 00 0.9458E 02 Sr-89 0.1982E-03 0.7052E-01 Sr-90 0.9517E-05 0.3387E-02 Y-90 0.1652E-04 0.5879E-02 Sr-91 0.1289E-03 0.4587E-01 Y-91 0.1784E-02 0.6347E 00 Sr-92 0.5267E-04 0.1874E-01 Y-92 0.6741E-04 0.2399E-01 Zr-95 0.4922E-04 0.1752E-01 Nb-95 0.4784E-04 0.1702E-01 Mo-99 0.3981E 00 0.1417E 03 I-131 0.2340E 00 0.8325E 02 Te-132 0.2459E-01 0.8749E 01 I-132 0.8408E-01 0.2992E 02 I-133 0.3192E 00 0.1136E 03 Xe-133M 0.2608E 00 0.9280E 02 Xe-133 0.2186E 02 0.7778E 04 Cs-134 0.1666E-01 0.5929E 01 I-134 0.4258E-01 0.1515E 02 I-135 0.1760E 00 0.6263E 02 Xe-135M 0.3332E-01 0.1186E 02 Xe-135 0.4674E 00 0.1663E 03 Cs-136 0.4470E-02 0.1591E 01 Cs-137 0.2958E-01 0.1052E 02 Xe-138 0.4495E-01 0.1599E 02 Ba-140 0.3355E-03 0.1194E 00 La-140 0.1185E-03 0.4215E-01 Ce-144 0.2899E-04 0.1032E-01 Pr-144 0.2899E-04 0.1032E-01 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-13 REACTOR COOLANT NITROGEN-16 ACTIVITY Location Activity, µCi/cc Core outlet 87
Reactor outlet nozzle 71
Steam generator inlet 67
Steam generator outlet 45
Reactor coolant pump inlet 43
Reactor coolant pump outlet 42
Reactor inlet nozzle 40
Core inlet 33 DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 11.1-14 DEPOSITED CORROSION PRODUCT ACTIVITY IN STEAM GENERATOR Concentration, µCi/cm2 Operating Time, months Isotope 0 6 12 24 36 Mn-54 1.0 x 10-5 0.15 0.60 1.5 2.0 Mn-56 1.0 x 10-5 3.3 3.3 3.3 3.3 Co-58 1.0 x 10-2 4.5 10.2 11.0 11.0 Fe-59 1.0 x 10-4 1.4 3.0 3.0 3.0 Co-60 1.0 x 10-3 0.20 0.80 2.0 3.5
DCPP UNITS 1 & 2 FSAR UPDATE Revision 20 November 2011 TABLE 11.1-15 DEMINERALIZER AND EVAPORATOR DECONTAMINATION FACTORS Nuclide Primary Mxd Bed Primary Cation Letdown Mxd Bed Letdown Cation Letdown Anion BA Evap Feed Ion Exchangers(b) Waste Mxd. Beds(a) H-3 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 Cr-51 1.000E 01 1.000E 02 1.000E 02 1.000E 02 1.000E 00 1.000E 03 1.000E 03 Mn-54 1.000E 01 1.000E 02 1.000E 02 1.000E 02 1.000E 00 1.000E 03 1.000E 03 Fe-55 1.000E 01 1.000E 02 1.000E 02 1.000E 02 1.000E 00 1.000E 03 1.000E 03 Co-58 1.000E 01 1.000E 02 1.000E 02 1.000E 02 1.000E 00 1.000E 03 1.000E 03 Fe-59 1.000E 01 1.000E 02 1.000E 02 1.000E 02 1.000E 00 1.000E 03 1.000E 03 Co-60 1.000E 01 1.000E 02 1.000E 02 1.000E 02 1.000E 00 1.000E 03 1.000E 03 Kr-83M 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 Kr-85M 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 Kr-85 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 Kr-87 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 Kr-88 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 Sr-89 1.000E 01 1.000E 02 1.000E 02 1.000E 02 1.000E 00 1.000E 03 1.000E 03 Sr-90 1.000E 01 1.000E 02 1.000E 02 1.000E 02 1.000E 00 1.000E 03 1.000E 03 Y-90 1.000E 00 1.000E 00 1.000E 01 1.000E 00 1.000E 00 1.000E 03 1.000E 03 Sr-91 1.000E 01 1.000E 02 1.000E 02 1.000E 02 1.000E 00 1.000E 03 1.000E 03 Y-91 1.000E 00 1.000E 00 1.000E 01 1.000E 00 1.000E 00 1.000E 03 1.000E 03 Sr-92 1.000E 01 1.000E 02 1.000E 02 1.000E 02 1.000E 00 1.000E 03 1.000E 03 Y-92 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 03 1.000E 03 Zr-95 1.000E 01 1.000E 02 1.000E 02 1.000E 02 1.000E 00 1.000E 03 1.000E 03 Nb-95 1.000E 01 1.000E 02 1.000E 02 1.000E 02 1.000E 00 1.000E 03 1.000E 03 Mo-99 1.000E 00 1.000E 00 1.000E 02 1.000E 00 1.000E 00 1.000E 03 1.000E 03 I-131 1.000E 01 1.000E 00 1.000E 02 1.000E 00 1.000E 02 1.000E 02 1.000E 03 Te-132 1.000E 01 1.000E 00 1.000E 02 1.000E 00 1.000E 02 1.000E 03 1.000E 03 I-132 1.000E 01 1.000E 00 1.000E 02 1.000E 00 1.000E 02 1.000E 02 1.000E 03 I-133 1.000E 01 1.000E 00 1.000E 02 1.000E 00 1.000E 02 1.000E 02 1.000E 03 Xe-133M 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 Xe-133 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 Cs-134 2.000E 00 1.000E 01 2.000E 00 1.000E 01 1.000E 00 1.000E 03 2.000E 01 I-134 1.000E 01 1.000E 00 1.000E 02 1.000E 00 1.000E 02 1.000E 02 1.000E 03 I-135 1.000E 01 1.000E 00 1.000E 02 1.000E 00 1.000E 02 1.000E 02 1.000E 03 Xe-135M 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 Xe-135 1.000E 00 1.000E00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 Cs-136 2.000E 00 1.000E 01 2.000E 00 1.000E 01 1.000E 00 1.000E 03 2.000E 01 Cs-137 2.000E 00 1.000E 01 2.000E 00 1.000E 01 1.000E 00 1.000E 03 2.000E 01 Xe-138 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 1.000E 00 Ba-140 1.000E 01 1.000E 02 1.000E 02 1.000E 02 1.000E 00 1.000E 03 1.000E 03 La-140 1.000E 01 1.000E 02 1.000E 02 1.000E 02 1.000E 00 1.000E 03 1.000E 03 Ce-144 1.000E 01 1.000E 02 1.000E 02 1.000E 02 1.000E 00 1.000E 03 1.000E 03 Pr-144 1.000E 01 1.000E 02 1.000E 02 1.000E 02 1.000E 00 1.000E 03 1.000E 03 (a) Two waste mixed beds in series. (b) Boric Acid Evaporator has been abandoned in place. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-16 PRODUCTION AND REMOVALS IN PRIMARY COOLANT FOR DESIGN BASIS CASE Nuclide Produced, Ci Decayed, Ci Cleaned Up, Ci Lked to Sec, Ci Lked to Cont, Ci Lked to Aux, Ci H-3 0.1642E 04 0.1463E 02 0.1345E 04 0.0 0.0 0.0 Cr-51 0.2637E 03 0.4455E 01 0.2070E 03 0.0 0.0 0.0 Mn-54 0.4222E 02 0.6647E-01 0.3366E 02 0.0 0.0 0.0 Fe-55 0.2532E 03 0.3805E 02 0.1718E 03 0.0 0.0 0.0 Co-58 0.2190E 04 0.1458E 02 0.1737E 04 0.0 0.0 0.0 Fe-59 0.1375E 03 0.1445E 01 0.1087E 03 0.0 0.0 0.0 Co-60 0.2707E 03 0.6729E-01 0.2161E 03 0.0 0.0 0.0 Kr-83M 0.2926E 06 0.2916E 06 0.5535E 03 0.0 0.0 0.0 Kr-85M 0.6409E 06 0.6359E 06 0.2855E 04 0.0 0.0 0.0 Kr-85 0.1250E 05 0.6654E 02 0.7987E 04 0.0 0.0 0.0 Kr-87 0.1208E 07 0.1205E 07 0.1562E 04 0.0 0.0 0.0 Kr-88 0.1736E 07 0.1728E 07 0.4885E 04 0.0 0.0 0.0 Sr-89 0.3138E 03 0.2897E 01 0.2482E 03 0.0 0.0 0.0 Sr-90 0.1493E 02 0.6984E-03 0.1192E 02 0.0 0.0 0.0 Y-90 0.5049E 01 0.4623E 01 0.3015E 00 0.0 0.0 0.0 Sr-91 0.4409E 03 0.2386E 03 0.1615E 03 0.0 0.0 0.0 Y-91 0.6483E 02 0.2065E 02 0.3098E 02 0.0 0.0 0.0 Sr-92 0.4338E 03 0.3511E 03 0.6602E 02 0.0 0.0 0.0 Y-92 0.3386E 03 0.3369E 03 0.1238E 01 0.0 0.0 0.0 Zr-95 0.7777E 02 0.5637E 00 0.6165E 02 0.0 0.0 0.0 Nb-95 0.7605E 02 0.1023E 01 0.5991E 02 0.0 0.0 0.0 Mo-99 0.1150E 06 0.1047E 06 0.7267E 04 0.0 0.0 0.0 I-131 0.3852E 06 0.2179E 05 0.2902E 06 0.0 0.0 0.0 Te-132 0.4388E 05 0.5676E 04 0.3050E 05 0.0 0.0 0.0 I-132 0.7610E 06 0.6303E 06 0.1044E 06 0.0 0.0 0.0 I-133 0.7694E 06 0.2734E 06 0.3961E 06 0.0 0.0 0.0 Xe-133M 0.9896E 05 0.8554E 05 0.4819E 04 0.0 0.0 0.0 Xe-133 0.3935E 07 0.3131E 07 0.4059E 06 0.0 0.0 0.0 Cs-134 0.1560E 05 0.1645E 02 0.1243E 05 0.0 0.0 0.0 I-134 0.9513E 06 0.8851E 06 0.5288E 05 0.0 0.0 0.0 I-135 0.7464E 06 0.4727E 06 0.2185E 06 0.0 0.0 0.0 Xe-135M 0.5840E 07 0.2304E 07 0.6113E 03 0.0 0.0 0.0 Xe-135 0.1519E 07 0.9150E 06 0.8591E 04 0.0 0.0 0.0 Cs-136 0.4485E 04 0.2574E 03 0.3372E 04 0.0 0.0 0.0 Cs-137 0.2793E 05 0.2248E 01 0.2227E 05 0.0 0.0 0.0 Xe-138 0.3474E 07 0.3473E 07 0.8258E 03 0.0 0.0 0.0 Ba-140 0.5458E 03 0.1965E 02 0.4202E 03 0.0 0.0 0.0 La-140 0.2388E 03 0.5309E 02 0.1483E 03 0.0 0.0 0.0 Ce-144 0.4554E 02 0.7609E-01 0.3631E 02 0.0 0.0 0.0 Pr-144 0.1831E 04 0.1785E 04 0.3631E 02 0.0 0.0 0.0
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-17 PRODUCTION AND REMOVALS IN PRIMARY COOLANT FOR NORMAL OPERATION CASE Nuclide Produced, Ci Decayed, Ci Cleaned Up, Ci Lked to Sec, Ci Lked to Cont, Ci Lked to Aux, Ci H-3 0.1642E 04 0.1384E 02 0.1271E 04 0.1583E 02 0.5299E 02 0.2532E 02 Cr-51 0.2637E 03 0.4452E 01 0.2068E 03 0.2516E-01 0.8424E-01 0.4026E-01 Mn-54 0.4222E 02 0.6643E-01 0.3364E 02 0.4092E-02 0.1370E-01 0.6547E-02 Fe-55 0.2532E 03 0.3803E 02 0.1717E 03 0.2088E-01 0.6991E-01 0.3341E-01 Co-58 0.2190E 04 0.1457E 02 0.1736E 04 0.2112E 00 0.7070E 00 0.3379E 00 Fe-59 0.1375E 03 0.1443E 01 0.1086E 03 0.1321E-01 0.4423E-01 0.2114E-01 Co-60 0.2707E 03 0.6725E-01 0.2159E 03 0.2627E-01 0.8794E-01 0.4203E-01 Kr-83M 0.3511E 05 0.3495E 05 0.6634E 02 0.5509E 00 0.3127E 02 0.8814E 00 Kr-85M 0.7691E 05 0.7610E 05 0.3417E 03 0.2837E 01 0.1611E 03 0.4540E 01 Kr-85 0.1512E 04 0.6269E 01 0.7526E 03 0.6249E 01 0.3547E 03 0.9998E 01 Kr-87 0.1449E 06 0.1445E 06 0.1873E 03 0.1555E 01 0.8826E 02 0.2488E 01 Kr-88 0.2084E 06 0.2070E 06 0.5852E 03 0.4859E 01 0.2758E 03 0.7774E 01 Sr-89 0.3765E 02 0.3474E 00 0.2976E 02 0.3621E-02 0.1212E-01 0.5794E-02 Sr-90 0.1791E 01 0.8376E-04 0.1429E 01 0.1739E-03 0.5821E-03 0.2782E-03 Y-90 0.6057E 00 0.5525E 00 0.3603E-01 0.2992E-03 0.1002E-02 0.4787E-03 Sr-91 0.5291E 02 0.2862E 02 0.1938E 02 0.2357E-02 0.7892E-02 0.3772E-02 Y-91 0.7779E 01 0.2407E 01 0.3611E 01 0.2999E-01 0.1004E 00 0.4798E-01 Sr-92 0.5205E 02 0.4212E 02 0.7922E 01 0.9637E-03 0.3226E-02 0.1542E-02 Y-92 0.4063E 02 0.4041E 02 0.1485E 00 0.1233E-02 0.4127E-02 0.1973E-02 Zr-95 0.9332E 01 0.6760E-01 0.7392E 01 0.8993E-03 0.3011E-02 0.1439E-02 Nb-95 0.9126E 01 0.1226E 00 0.7184E 01 0.8740E-03 0.2926E-02 0.1398E-02 Mo-99 0.1380E 05 0.1252E 05 0.8687E 03 0.7213E 01 0.2415E 02 0.1154E 02 I-131 0.4623E 05 0.2614E 04 0.3480E 05 0.4275E 01 0.1431E 02 0.6840E 01 Te-132 0.5285E 04 0.6807E 03 0.3658E 04 0.4493E 00 0.1504E 01 0.7189E 00 I-132 0.9131E 05 0.7562E 05 0.1252E 05 0.1538E 01 0.5148E 01 0.2461E 01 I-133 0.9233E 05 0.3279E 05 0.4751E 05 0.5835E 01 0.1954E 02 0.9336E 01 Xe-133M 0.1188E 05 0.9952E 04 0.5607E 03 0.4655E 01 0.2643E 03 0.7448E 01 Xe-133 0.4722E 06 0.3629E 06 0.4574E 05 0.3798E 03 0.2156E 05 0.6077E 03 Cs-134 0.1093E 04 0.1993E 01 0.1506E 04 0.3040E 00 0.1018E 01 0.4865E 00 I-134 0.1142E 06 0.1062E 06 0.6345E 04 0.7793E 00 0.2609E 01 0.1247E 01 I-135 0.8958E 05 0.5671E 05 0.2621E 05 0.3220E 01 0.1078E 02 0.5152E 01 Xe-135M 0.7006E 06 0.2764E 06 0.7333E 02 0.6089E 00 0.3456E 02 0.9742E 00 Xe-135 0.1823E 06 0.1092E 06 0.1025E 04 0.8511E 01 0.4831E 03 0.1362E 02 Cs-136 0.5383E 03 0.3086E 02 0.4042E 03 0.8158E-01 0.2731E 00 0.1305E 00 Cs-137 0.3357E 04 0.2699E 00 0.2674E 04 0.5397E 00 0.1807E 01 0.8635E 00 Xe-138 0.4168E 06 0.4167E 06 0.9908E 02 0.8227E 00 0.4670E 02 0.1316E 01 Ba-140 0.6550E 02 0.2356E 01 0.5038E 02 0.6130E-02 0.2052E-01 0.9807E-02 La-140 0.2865E 02 0.6365E 01 0.1778E 02 0.2163E-02 0.7241E-02 0.3461E-02 Ce-144 0.5465E 01 0.9124E-02 0.4354E 01 0.5296E-03 0.1773E-02 0.8474E-03 Pr-144 0.2195E 03 0.2141E 03 0.4354E 01 0.5297E-03 0.1773E-02 0.8474E-03
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-18 BASIC ASSUMPTIONS FOR PRESSURIZER ACTIVITIES Pressurizer liquid volume, gal. 8080 Pressurizer vapor volume, gal. 5400 Flowrate, gpm 1 Stripping fraction for noble gases 1 Stripping fraction for other isotopes 0.0 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-19 ACTIVITY IN PRESSURIZER FOR DESIGN BASIS CASE Liquid Phase Steam Phase Nuclide Activity, Ci Concent, µCi/cc Nuclide Activity, Ci Concent µCi/cc H-3 0.224E 02 0.731E 00 Kr- 83M 0.510E-01 0.250E-02 Cr-51 0.369E-01 0.121E-02 Kr- 85M 0.623E 00 0.305E-01 Mn-54 0.676E-02 0.221E-03 Kr- 85 0.186E 04 0.913E 02 Fe-55 0.143E-01 0.468E-03 Kr- 87 0.983E-01 0.482E-02 Co-58 0.335E 00 0.109E-01 Kr- 88 0.671E 00 0.329E-01 Fe-59 0.203E-01 0.665E-03 Xe-133M 0.135E 02 0.664E 00 Co-60 0.438E-01 0.143E-02 Xe-133 0.258E 04 0.127E 03 Kr-83M 0.0 0.0 Xe-135M 0.443E 00 0.217E-01 Kr-85M 0.0 0.0 Xe-135 0.693E 01 0.340E 00 Kr-85 0.0 0.0 Xe-138 0.954E 02 0.468E-03 Kr-87 0.0 0.0 Kr-88 0.0 0.0 Sr-89 0.469E-01 0.153E-02 Sr-90 0.242E-02 0.792E-04 Y-90 0.314E-02 0.103E-03 Sr-91 0.310E-02 0.101E-03 Y-91 0.404E 00 0.132E-01 Pressurizer Deposited Activity Sr-92 0.377E-03 0.123E-04 Y-92 0.100E-02 0.327E-04 Nuclide Activity, µCi/c2 Zr-95 0.118E-01 0.387E-03 Nb-95 0.121E-01 0.397E-03 Cr-51 9.80E-02 Mo-99 0.425E 02 0.139E 01 Mn-54 1.50E-01 I-131 0.401E 02 0.131E 01 Mn-56 2.20E-02 Te-132 0.285E 01 0.931E-01 Co-58 3.80E 00 I-132 0.331E 01 0.108E 00 Co-60 1.60E-01 I-133 0.149E 02 0.488E 00 Fe-59 1.40E-01 Xe-133M 0.0 0.0 Xe-133 0.0 0.0 Cs-134 0.417E 01 0.136E 00 I-134 0.998E-01 0.326E-02 I-135 0.300E 01 0.982E-01 Xe-135M 0.0 0.0 Xe-135 0.0 0.0 Cs-136 0.875E 00 0.286E-01 Cs-137 0.751E 01 0.246E 00 Xe-138 0.0 0.0 Ba-140 0.655E-01 0.214E-02 La-140 0.549E-01 0.179E-02 Ce-144 0.728E-02 0.238E-03 Pr-144 0.728E-02 0.238E-03
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-20 ACTIVITY IN PRESSURIZER FOR NORMAL OPERATION CASE Liquid Phase Steam Phase Nuclide Activity, Ci Concent, µCi/cc Nuclide Activity, Ci Concent µCi/cc H-3 0.211E 02 0.691E 00 Kr- 83M 0.612E-02 0.300E-03 Cr-51 0.349E-01 0.121E-02 Kr- 85M 0.745E-01 0.365E-02 Mn-54 0.675E-02 0.221E-03 Kr- 85 0.175E 03 0.860E 01 Fe-55 0.143E-01 0.468E-03 Kr- 87 0.118E-01 0.578E-03 Co-58 0.335E 00 0.109E-01 Kr- 88 0.803E-01 0.394E-02 Fe-59 0.203E-01 0.664E-03 Xe-133M 0.158E-01 0.773E-01 Co-60 0.438E-01 0.143E-02 Xe-133 0.291E 03 0.143E 02 Kr-83M 0.0 0.0 Xe-135M 0.532E-01 0.261E-02 Kr-85M 0.0 0.0 Xe-135 0.829E 00 0.406E-01 Kr-85 0.0 0.0 Xe-138 0.114E-02 0.561E-04 Kr-87 0.0 0.0 Kr-88 0.0 0.0 Sr-89 0.562E-02 0.184E-03 Sr-90 0.290E-03 0.950E-05 Y-90 0.376E-03 0.123E-04 Sr-91 0.272E-03 0.121E-04 Y-91 0.471E-01 0.154E-02 Pressurizer Deposited Activity Sr-92 0.453E-04 0.148E-05 Y-92 0.120E-03 0.393E-05 Nuclide Activity mCi/c2 Zr-95 0.142E-02 0.464E-04 Nb-95 0.146E-02 0.476E-04 Cr-51 9.80E-02 Mo-99 0.508E 01 0.166E 00 Mn-54 1.50E-01 I-131 0.481E 01 0.157E 00 Mn-56 2.20E-02 Te-132 0.342E 00 0.112E-01 Co-58 3.80E 00 I-132 0.397E 00 0.130E-01 Co-60 1.60E-01 I-133 0.179E 01 0.586E-01 Fe-59 1.40E-01 Xe-133M 0.0 0.0 Xe-133 0.0 0.0 Cs-134 0.505E 00 0.165E-01 I-134 0.120E-01 0.391E-03 I-135 0.360E 00 0.118E-01 Xe-135M 0.0 0.0 Xe-135 0.0 0.0 Cs-136 0.105E 00 0.343E-02 Cs-137 0.901E 00 0.295E-01 Xe-138 0.0 0.0 Ba-140 0.785E-02 0.257E-03 La-140 0.658E-02 0.215E-03 Ce-144 0.873E-03 0.285E-04 Pr-144 0.873E-03 0.285E-04 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-21 BASIC ASSUMPTIONS FOR TRITIUM ACTIVITY IN PRIMARY COOLANT 1. Core Thermal Power 3568 MWt
- 2. Plant Load Factor 0.8
- 3. Core Volume 1153 ft3
- 4. Core Volume Fractions
- a. UO2 0.3052 b. Zr + SS 0.1000
- c. H2O 0.5948
- 5. Initial Reactor Coolant Boron Level
- a. Initial cycle 840 ppm
- b. Equilibrium cycle 1200 ppm
- 6. Reactor Coolant Volume 12,560 ft3
- 7. Reactor Coolant Transport Times
- a. Incore 0.77 sec
- b. Out-of-core 10.87 sec
- 8. Reactor Coolant Peak Lithium Level (99% pure Li7) 2.2 ppm
- 9. Core Average Neutron Fluxes, n/cm2-sec a. E > 6 MeV 2.91 x 1012 b. E > 5 MeV 7.90 x 1012 c. 3 MeV E 6 MeV 2.26 x 1013 d. 1 MeV E 5 MeV 5.31 x 1013 e. E < 0.625 eV 2.26 x 1013
- 10. Neutron Reaction Cross Sections a. B10 (n, 2) T: (1 MeV E 5 MeV) = 31.6 mb (spectrum weighted) (E > 5 MeV) = 75 mb b. Li7 (n, n V) T: (3 MeV E 6 MeV) = 39.1 mb (spectrum weighted) (E > 6 MeV) = 400 mb 11. Fraction of Ternary Tritium Diffusing Through Zirconium Cladding
- a. Design value 0.30
- b. Expected value 0.01 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-22 TRITIUM ACTIVITY IN PRIMARY COOLANT Tritium Source Core Activity, Ci Coolant Activity, Ci Total Produced in Coolant, Ci Cycle = 8760 Hours
Ternary fissions 0.196E05 0.121E03 1092.76
Burnable poison rods 0.0 0.0 0.0
Control rods 0.0 0.0 0.0
Boron shim control 0.0 0.270E02 442.40
Lithium-7 reaction 0.0 0.100E01 9.05
Lithium-6 reaction 0.0 0.105E02 94.97
Deuterium reaction 0.0 0.294E00 2.66
Total 0.196E05 0.160E03 1641.84
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-23 STEAM SYSTEM OPERATING CONDITIONS ASSUMED FOR ACTIVITY ANALYSIS FOR NORMAL OPERATION CASE Parameter Value Steam Gen. 1 Steam Gen. 2 Steam Gen. 3 Steam Gen. 4 Steam flowrate to condenser from unit (lb/hr) 3804300.0 3804300.0 3804300.0 3804300.0 Feedwater flowrate to unit (lb/hr) 3804725.0 3804725.0 3804725.0 3804725.0 Blowdown flowrate from unit (lb/hr) 17647.5 17647.5 17647.5 17647.5 Steam venting flowrate from unit (lb/hr) 0.0 0.0 0.0 0.0 Total weight of steam vented from unit during period-lb 0.0 0.0 0.0 0.0 Weight of water in unit (lb) 81500.0 81500.0 81500.0 81500.0 Volume of water in unit (ft3) 1680.4 1680.4 1680.4 1680.4 Density of water in unit (lb/ft3) 48.5 48.5 48.5 48.5 Fraction of primary to secondary leakage to this unit 0.25 0.25 0.25 0.25 Leakage flowrate to this unit (computed) (gal./min) 0.0029 0.0029 0.0029 0.0029 Total gallons of prim. cool. leaked into unit in period 1208.8 1208.8 1208.8 1208.8 Total steam flowrate of condenser (lb/hr) 15217200.0 Total condensate flowrate from condenser (lb/hr) 15221402.0 Weight of water in condenser (lb) 1700000.0 Volume of water in condenser (ft3) 27243.58 Density of water in condenser (lb/ft3) 62.39 Total primary to secondary leak rate (gal./min) 0.0115 Water leakage rate from secondary system (gal./min) 5.0 Steam leakage rate from secondary system (lb/hr) 1700.0 Flowrate of water to blowdown cleanup system (lb/hr) 51763.78 Capacity factor of blowdown cleanup system 1.0 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-24 ADDITIONAL SECONDARY SYSTEM OPERATING PARAMETERS Mass of water in one steam generator, lb 81,500 Mass of steam in one steam generator, lb 7,200 Secondary side operating temperature, °F 519 Steam generator blowdown tank capacity, ft3 641 Air ejector flowrate - rated, scfm 25
- expected average, scfm 2.5 Total mass of water in secondary system, lb 1,000,000 (minus condenser)
Total mass of steam in secondary system, lb 61,200
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-25 STEAM GENERATOR PARTITION FACTORS(a) Nuclide St.Gen.1 St.Gen.2 St.Gen.3 St.Gen.4 H-3 1.0000 1.0000 1.0000 1.0000 Cr-51 0.0007 0.0007 0.0007 0.0007 Mn-54 0.0007 0.0007 0.0007 0.0007 Fe-55 0.0007 0.0007 0.0007 0.0007 Co-58 0.0007 0.0007 0.0007 0.0007 Fe-59 0.0007 0.0007 0.0007 0.0007 Co-60 0.0007 0.0007 0.0007 0.0007 Kr-83M 1.0000 1.0000 1.0000 1.0000 Kr-85M 1.0000 1.0000 1.0000 1.0000 Kr-85 1.0000 1.0000 1.0000 1.0000 Kr-87 1.0000 1.0000 1.0000 1.0000 Kr-88 1.0000 1.0000 1.0000 1.0000 Sr-89 0.0007 0.0007 0.0007 0.0007 Sr-90 0.0007 0.0007 0.0007 0.0007 Y-90 0.0007 0.0007 0.0007 0.0007 Sr-91 0.0007 0.0007 0.0007 0.0007 Y-91 0.0007 0.0007 0.0007 0.0007 Sr-92 0.0007 0.0007 0.0007 0.0007 Y-92 0.0007 0.0007 0.0007 0.0007 Zr-95 0.0007 0.0007 0.0007 0.0007 Nb-95 0.0007 0.0007 0.0007 0.0007 Mo-99 0.0007 0.0007 0.0007 0.0007 I-131 0.0065 0.0065 0.0065 0.0065 Te-132 0.0007 0.0007 0.0007 0.0007 I-132 0.0065 0.0065 0.0065 0.0065 I-133 0.0065 0.0065 0.0065 0.0065 Xe-133M 1.0000 1.0000 1.0000 1.0000 Xe-133 1.0000 1.0000 1.0000 1.0000 Cs-134 0.0007 0.0007 0.0007 0.0007 I-134 0.0065 0.0065 0.0065 0.0065 I-135 0.0065 0.0065 0.0065 0.0065 Xe-135M 1.0000 1.0000 1.0000 1.0000 Xe-135 1.0000 1.0000 1.0000 1.0000 Cs-136 0.0007 0.0007 0.0007 0.0007 Cs-137 0.0007 0.0007 0.0007 0.0007 Xe-138 1.0000 1.0000 1.0000 1.0000 Ba-140 0.0007 0.0007 0.0007 0.0007 La-140 0.0007 0.0007 0.0007 0.0007 Ce-144 0.0007 0.0007 0.0007 0.0007 Pr-144 0.0007 0.0007 0.0007 0.0007
(a) Iodine partition factors are for nonvolatile species only and include partitioning in moisture separators. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-26 TOTAL ADDITIONS AND REMOVALS OF ACTIVITY IN EACH STEAM GENERATOR FOR NORMAL OPERATION CASE (CURIES) Nuclide Leakage in From Feedwater To Main Stm To Blowdown Vented Decayed Leaked H-3 0.3007E 01 0.6511E 04 0.6513E 04 0.0 0.0 0.8954E-03 0.7276E 00 Cr-51 0.5976E-02 0.5983E-03 0.8659E-03 0.5681E-02 0.0 0.2753E-04 0.9674E-07 Mn-54 0.9719E-03 0.9793E-04 0.1414E-03 0.9280E-03 0.0 0.4126E-06 0.1580E-07 Fe-55 0.4960E-02 0.4651E-03 0.6877E-03 0.4512E-02 0.0 0.2251E-03 0.7683E-07 Co-58 0.5015E-01 0.5043E-02 0.7288E-02 0.4782E-01 0.0 0.9040E-04 0.8142E-04 Fe-59 0.3137E-02 0.3150E-03 0.4554E-03 0.2988E-02 0.0 0.8944E-05 0.5088E-07 Co-60 0.6239E-02 0.6290E-03 0.9083E-03 0.5959E-02 0.0 0.4179E-06 0.1015E-06 Sr-89 0.8600E-03 0.8638E-04 0.1249E-03 0.8193E-03 0.0 0.2153E-05 0.1395E-07 Sr-90 0.4130E-04 0.4164E-05 0.6013E-05 0.3945E-04 0.0 0.5205E-09 0.6717E-09 Y-90 0.7106E-04 0.1159E-04 0.1160E-04 0.6919E-04 0.0 0.3850E-05 0.1296E-08 Sr-91 0.5599E-03 0.3580E-04 0.6114E-04 0.4011E-03 0.0 0.1334E-03 0.6831E-08 Y-91 0.7122E-02 0.1191E-02 0.1191E-02 0.7105E-02 0.0 0.1719E-04 0.1331E-06 Sr-92 0.2289E-03 0.4779E-05 0.1516E-04 0.9944E-04 0.0 0.1191E-03 0.1693E-08 Y-92 0.2928E-03 0.3159E-04 0.3218E-04 0.1919E-03 0.0 0.1896E-03 0.3595E-08 Zr-95 0.2136E-03 0.2147E-04 0.3103E-04 0.2036E-03 0.0 0.4192E-06 0.3467E-08 Nb-95 0.2076E-03 0.3162E-04 0.3163E-04 0.2075E-03 0.0 0.7978E-06 0.3534E-08 Mo-99 0.1713E 01 0.1612E 00 0.2381E 00 0.1562E 01 0.0 0.7425E-01 0.2660E-04 I-131 0.1015E 01 0.1372E 01 0.1418E 01 0.9519E 00 0.0 0.1678E-01 0.1584E-03 Te-132 0.1067E 00 0.1013E-01 0.1492E-01 0.9786E-01 0.0 0.4061E-02 0.1666E-05 I-132 0.3652E 00 0.2914E 00 0.3006E 00 0.2018E 00 0.0 0.2861E 00 0.3358E-04 I-133 0.1386E 01 0.1620E 01 0.1689E 01 0.1133E 01 0.0 0.1837E 00 0.1887E-03 Cs-134 0.7721E-01 0.2177E-01 0.2178E-01 0.7217E-01 0.0 0.2567E-04 0.2433E-05 I-134 0.1851E 00 0.4043E-01 0.5234E-01 0.3513E-01 0.0 0.1380E 00 0.5847E-05 I-135 0.7647E 00 0.6716E 00 0.7138E 00 0.4791E 00 0.0 0.2433E 00 0.7974E-04 Cs-136 0.1938E-01 0.4603E-02 0.5473E-02 0.1813E-01 0.0 0.3720E-03 0.6114E-06 Cs-137 0.1282E 00 0.3120E-01 0.3695E-01 0.1224E 00 0.0 0.3320E-05 0.4128E-05 Ba-140 0.1456E-02 0.1445E-03 0.2097E-03 0.1976E-02 0.0 0.1449E-04 0.2343E-07 La-140 0.5137E-03 0.8819E-04 0.8811E-04 0.5781E-03 0.0 0.4660E-04 0.9843E-08 Ce-144 0.1258E-03 0.1267E-04 0.1831E-04 0.1201E-03 0.0 0.5668E-07 0.2045E-08 Pr-144 0.1258E-03 0.1717E-04 0.1836E 04 0.1205E-03 0.0 0.1334E-02 0.2051E-08 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-27 EQUILIBRIUM ACTIVITIES AND CONCENTRATIONS IN EACH STEAM GENERATOR FOR NORMAL OPERATION CASE Nuclide Activity, Ci Concentration, µCi/cc H-3 0.1991E-01 0.4184E-03 Cr-51 0.3782E-05 0.7947E-07 Mn-54 0.6177E-06 0.1298E-07 Fe-55 0.3003E-05 0.6312E-07 Co-58 0.3183E-04 0.6689E-06 Fe-59 0.1989E-05 0.4180E-07 Co-60 0.3967E-05 0.8336E-07 Sr-89 0.5454E-06 0.1146E-07 Sr-90 0.2626E-07 0.5518E-09 Y-90 0.4584E-07 0.9633E-09 Sr-91 0.2670E-06 0.5611E-08 Y-91 0.4683E-05 0.9842E-07 Sr-92 0.6619E-07 0.1391E-08 Y-92 0.1331E-06 0.2797E-08 Zr-95 0.1355E-06 0.2848E-08 Nb-95 0.1381E-06 0.2903E-08 Mo-99 0.1030E-02 0.2164E-04 I-131 0.6670E-03 0.1402E-04 Te-132 0.6514E-04 0.1369E-05 I-132 0.1414E-03 0.2971E-05 I-133 0.7942E-03 0.1669E-04 Cs-134 0.9512E-04 0.1999E-05 I-134 0.2462E-04 0.5173E-06 I-135 0.3357E-03 0.7055E-05 Cs-136 0.2390E-04 0.5023E-06 Cs-137 0.1614E-03 0.3391E-05 Ba-140 0.9160E-06 0.1925E-07 La-140 0.3848E-06 0.8087E-08 Ce-144 0.7994E-07 0.1680E-08 Pr-144 0.8019E-07 0.1685E-08
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-28 TOTAL ADDITIONS AND REMOVALS OF ACTIVITY IN THE CONDENSER FOR NORMAL OPERATION CASE (CURIES) Nuclide From Mainsteam To Feedwater Decayed Water Leakage H-3 0.2605E-05 0.2605E 05 0.1867E-01 0.4283E 01 Cr-51 0.3464E-02 0.2394E-02 0.2777E-06 0.3935E-06 Mn-54 0.5658E-03 0.3918E-03 0.4171E-08 0.6442E-07 Fe-55 0.2751E-02 0.1861E-02 0.2223E-05 0.3060E-06 Co-58 0.2915E-01 0.2017E-01 0.9131E-06 0.3317E-05 Fe-59 0.1822E-02 0.1260E-02 0.9030E-07 0.2072E-06 Co-60 0.3633E-02 0.2516E-02 0.4225E-08 0.4137E-06 Sr-89 0.4995E-03 0.3456E-03 0.2174E-07 0.5682E-07 Sr-90 0.2405E-04 0.1666E-04 0.5262E-11 0.2739E-08 Y-90 0.4640E-04 0.4636E-04 0.5615E-07 0.7622E-08 Sr-91 0.2446E-03 0.1432E-03 0.1140E-05 0.2355E-07 Y-91 0.4765E-02 0.4764E-02 0.2508E-06 0.7833E-04 Sr-92 0.6063E-04 0.1912E-04 0.5481E-06 0.3144E-08 Y-92 0.1287E-03 0.1264E-03 0.2717E-05 0.2078E-07 Zr-95 0.1241E-03 0.8590E-04 0.4235E-08 0.1412E-07 Nb-95 0.1265E-03 0.1265E-03 0.1164E-07 0.2080E-07 Mo-99 0.9523E 00 0.6449E 00 0.7340E-03 0.1060E-03 I-131 0.5673E 01 0.5488E 01 0.2201E-02 0.9023E-03 Te-132 0.5967E-01 0.4052E-01 0.4026E-04 0.6663E-05 I-132 0.1202E 01 0.1166E 01 0.3760E-01 0.1917E-03 I-133 0.6755E 01 0.6482E 01 0.2389E-01 0.1066E-02 Cs-134 0.8715E-01 0.8711E-01 0.3746E-06 0.1432E-04 I-134 0.2094E 00 0.1618E 00 0.1446E-01 0.2660E-04 I-135 0.2855E 01 0.2687E 01 0.3104E-01 0.4418E-03 Cs-136 0.2189E-01 0.1842E-01 0.4569E-05 0.3028E-05 Cs-137 0.1478E 00 0.1248E 00 0.4094E-07 0.2052E-04 Ba-140 0.8390E-03 0.5782E-03 0.1458E-06 0.9507E-07 La-140 0.3524E-03 0.3528E-03 0.4610E-06 0.5801E-07 Ce-144 0.7322E-04 0.5070E-04 0.5729E-09 0.8337E-08 Pr-144 0.7345E-04 0.6860E-04 0.1020E-04 0.1129E-07 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-29 EQUILIBRIUM ACTIVITIES AND CONCENTRATIONS IN THE CONDENSER FOR NORMAL OPERATION CASE Nuclide Activity, Ci Concentration, µCi/cc H-3 0.4151E 00 0.5381E-03 Cr-51 0.3815E-07 0.4945E-10 Mn-54 0.6244E-08 0.8093E-11 Fe-55 0.2966E-07 0.3844E-10 Co-58 0.3215E-06 0.4168E-09 Fe-59 0.2008E-07 0.2603E-10 Co-60 0.4010E-07 0.5198E-10 Sr-89 0.5507E-08 0.7139E-11 Sr-90 0.2655E-09 0.3441E-12 Y-90 0.6685E-09 0.8665E-12 Sr-91 0.2282E-08 0.2959E-11 Y-91 0.6835E-07 0.8859E-10 Sr-92 0.3047E-09 0.3950E-12 Y-92 0.1908E-08 0.2473E-11 Zr-95 0.1369E-08 0.1774E-11 Nb-95 0.2016E-08 0.2613E-11 Mo-99 0.1013E-04 0.1314E-07 I-131 0.8746E-04 0.1134E-06 Te-132 0.6458E-06 0.8372E-09 I-132 0.1858E-04 0.2409E-07 I-133 0.1033E-03 0.1339E-06 Cs-134 0.1388E-05 0.1800E-08 I-134 0.2578E-05 0.3342E-08 I-135 0.4282E-04 0.5550E-07 Cs-136 0.2935E-06 0.3805E-09 Cs-137 0.1989E-05 0.2579E-08 Ba-140 0.9215E-08 0.1195E-10 La-140 0.5623E-08 0.7289E-11 Ce-144 0.8081E-09 0.1047E-11 Pr-144 0.1094E-08 0.1419E-11
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-30 TOTAL ADDITIONS AND REMOVALS OF ACTIVITY IN THE CONDENSER VAPOR SPACE FOR NORMAL OPERATION CASE Inleak Rate, Tot. Inleakage, Vent Rate, Vent Rate, Tot. Vented, Decayed, Nuclide Ci/hr Ci hr-1 Ci/hr Ci Ci Kr-83 0.7861E-04 0.5509E 00 0.1650E 00 0.2413E-04 0.1690E 00 0.3817E 00 Kr-85M 0.4049E-03 0.2837E 01 0.1650E 00 0.2071E-03 0.1451E 01 0.1385E 01 Kr-85 0.7133E-03 0.6249E 01 0.1650E 00 0.7133E-03 0.6244E 01 0.2787E-03 Kr-87 0.2219E-03 0.1555E 01 0.1650E 00 0.5151E-04 0.3610E 00 0.1194E 01 Kr-88 0.6933E-03 0.4859E 01 0.1650E 00 0.2755E-03 0.1930E 01 0.2927E 01 I-131 0.4575E-05 0.3206E-01 0.1650E 00 0.4477E-05 0.3136E-01 0.6824E-03 I-132 0.1646E-05 0.1153E-01 0.1650E 00 0.5985E-06 0.4193E-02 0.7338E-02 I-133 0.6245E-05 0.4376E-01 0.1650E 00 0.5204E-05 0.3645E-01 0.7290E-02 Xe-133M 0.6653E-03 0.4662E 01 0.1650E 00 0.6182E-03 0.4330E 01 0.3294E 00 Xe-133 0.5421E-01 0.3799E 03 0.1650E 00 0.5248E-01 0.3675E 03 0.1215E 02 I-134 0.8341E-06 0.5845E-02 0.1650E 00 0.1426E-06 0.9991E-03 0.4845E-02 I-135 0.3446E-05 0.2415E-01 0.1650E 00 0.2118E-05 0.1484E-01 0.9301E-02 Xe-135M 0.6224E-03 0.4362E 01 0.1650E 00 0.3628E-04 0.2543E 00 0.4107E 01 Xe-135 0.1304E-02 0.9136E 01 0.1650E 00 0.8951E-03 0.6270E 01 0.2862E 01 Xe-138 0.1174E-03 0.8227E 00 0.1650E 00 0.6170E-05 0.4324E-01 0.7794E 00 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.1-31 EQUILIBRIUM ACTIVITIES AND CONCENTRATIONS IN THE CONDENSER VAPOR SPACE FOR NORMAL OPERATION CASE
Nuclide Activity, Ci Concentration, mCi/cc Kr-83M 0.1462E-03 0.5164E-07 Kr-85M 0.1255E-02 0.4434E-06 Kr-85 0.4323E-02 0.1527E-05 Kr-87 0.3122E-03 0.1103E-06 Kr-88 0.1670E-02 0.5897E-06 I-131 0.2697E-04 0.9524E-08 I-132 0.3618E-05 0.1278E-08 I-133 0.3141E-04 0.1109E-07 Xe-133M 0.3746E-02 0.1323E-05 Xe-133 0.3180E 00 0.1123E-03 I-134 0.8637E-06 0.3050E-09 I-135 0.1281E-04 0.4522E-08 Xe-135M 0.2194E-03 0.7747E-07 Xe-135 0.5419E-02 0.1914E-05 Xe-138 0.3740E-04 0.1321E-07 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-1 Sheet 1 of 2 Revision 11 November 1996 ASSUMPTIONS USED FOR INPUT WASTE STREAMS AND ACTIVITY CALCULATIONS BASED ON ORIGINAL SYSTEM DESIGN
- 1. Each stream of liquid waste input is categorized by one of the following isotopic concentration spectra, which are shown for the two analyses cases in Tables 11.2-3 and 11.2-4:
Spectrum I - Degassed primary coolant Spectrum II - Degassed primary coolant with 48 hours of decay Spectrum III - 1.0% of degassed primary coolant with 48 hours of decay Spectrum IV - 0.01% of degassed primary coolant with 48 hours of decay Spectrum V - 0.001% of primary coolant with 48 hours of decay; principally component cooling water.
- 2. Heat exchangers are periodically drained producing 25 gallons/inch inlet piping/year for the Design Basis Case and 1.5 times the above for the Normal Operation Case.
- 3. Pumps are periodically drained producing 10 gallons/inch suction/year for the Design Basis Case and 1.5 times the above for the Normal Operation Case.
- 4. Pump baseplate leakage of 0.10 gallons/day for the Design Basis Case and 1.5 times the above for the Normal Operation Case
- 5. Tanks are periodically drained producing 100 gallons/5 feet diameter/year for the Design Basis Case and 1.5 times the above for the Normal Operation Case.
- 6. Filter cartridge replacement three times per year, producing 15 gallons/replacement for the Design Basis Case and 1.5 times the above volume for the Normal Operation Case.
- 7. Sampling produces 4 gallons/sample (2 gallons/sample to laboratory drain and 2 gallons/sample due to line purging, 7 samples/day/unit).
- 8. Valve stem leakage of 10 cc/day for the Design Basis Case and 1.5 times the above for the Normal Operation Case.
- 9. No waste from relief valve discharges for the Design Basis Case and 50 gallons/year for the Normal Operation Case.
- 10. Laundry waste of 3 washloads per week producing 210 gallons/washload for the CDesign Basis Case and 1.5 times the above volume for the Normal Operation Case.
- 11. Personnel decontamination showers of 4 showers/day producing 5 gallons/shower for the Design Basis Case and 1.5 times the above volume for the Normal Operation Case.
- 12. Personnel handwashes of 25 per day producing 0.5 gallons/wash for the Design Basis Case and 1.5 times the above volume for the Normal Operation Case.
- 13. Periodic system piping drains of 200 gallons/year/system/unit for the Design Basis Case and 1.5 times the above volume for the Normal Operation Case.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-1 Sheet 2 of 2 Revision 11 November 1996 14. Containment fan cooler drains of 1,000 gallons/year/unit for the Design Basis Case and 1.5 times the above volume for the Normal Operation Case.
- 15. Each reactor coolant pump 3 seal leaks 100 cc/hour for the Design Basis Case and the Normal Operation Case.
- 16. Spent resin loadout area washdown of 200 gallons/year for the Design Basis Case and 1.5 times the above for the Normal Operation Case.
- 17. Demineralizer overflow produces 500 gallons/backwash and resin replacement of one demineralizer per set annually for the Design Basis Case and the Normal Operation Case.
- 18. Reactor coolant drain tank wastes are processed through the CVCS for the Design Basis Case and 500 gallons/year/unit to the liquid waste system for the Normal Operation Case.
- 19. Miscellaneous floor drain leakage of 5,000 gallons/year for the Design Basis Case and 1.5 times the above volume for the Normal Operation Case.
- 20. Miscellaneous leakage of 160 pounds/day/unit of Spectrum I wastes to the auxiliary building for the Normal Operation Case.
- 21. Miscellaneous leakage of 40 gallons/day/unit of Spectrum I wastes to the containment building for the Normal Operation Case.
- 22. RHR pump leakage of 0.25 gallons/pump for the Normal Operation Case.
- 23. Waste will be allowed 48 hours of decay before processing from the chemical drain, laundry and hot shower, miscellaneous equipment drain, and reactor coolant drain tanks. (This includes fill time and discharge time.)
- 24. Waste will be allowed 336 hours of decay in the floor drain receiver and equipment drain receiver tanks before processing. (This includes one-half of the fill time plus one-half of the discharge time.)
- 25. Waste will be allowed 24 hours of decay in the waste condensate tank before processing.
- 26. No decay credit is taken for sumps.
- 27. For tritium control, 350,000 gallons/unit will be discharged annually.
- 28. Primary-to-secondary steam generator leakage of 100 lb/day of primary coolant for the Normal Operation Case.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 20 November 2011 TABLE 11.2-2 ASSUMPTIONS FOR CALCULATIONS OF ACTIVITY RELEASED FROM CVCS BASED ON ORIGINAL SYSTEM DESIGN Average Shim Bleed Flowrate, gpm 1.0 Capacity of Liquid Holdup Tank, gal. 83000 DFs for CVC Demineralizers (Given in Table 11.1-15) DF for Boric Acid Evaporator (a) - iodine 102 - other nuclides 103 Capacity of Monitor Tank, gal. 25000 Fraction of Boric Acid Evaporator Distillate Recycled (a) 0.333 (a) Boric Acid Evaporator has been abandoned in place
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-3 Sheet 1 of 2 Revision 11 November 1996 ACTIVITY CONCENTRATION SPECTRUM I THROUGH V FOR INPUT WASTE SOURCES, DESIGN BASIS CASE (µCi/cc)(a) Nuclide Spectrum I Spectrum II Spectrum III Spectrum IV Spectrum V H-3 0.11E+01 0.11E+01 0.11E-01 0.11E-03 0.11E-04 Cr-51 0.19E-02 0.19E-02 0.19E-04 0.19E-06 0.19E-07 Mn-54 0.31E-03 0.30E-03 0.30E-05 0.30E-07 0.30E-08 Fe-55 0.15E-02 0.92E-03 0.92E-05 0.92E-07 0.92E-08 Co-58 0.17E-01 0.16E-01 0.16E-03 0.16E-05 0.16E-06 Fe-59 0.10E-02 0.97E-03 0.97E-05 0.97E-07 0.97E-08 Co-60 0.19E-02 0.19E-02 0.19E-04 0.19E-06 0.19E-07 Kr-83M 0.35E+00 0.0 0.0 0.0 0.0 Kr-85M 0.18E+01 0.0 0.0 0.0 0.0 Kr-85 0.58E+01 0.0 0.0 0.0 0.0 Kr-87 0.99E+00 0.0 0.0 0.0 0.0 Kr-88 0.31E+01 0.0 0.0 0.0 0.0 Sr-89 0.24E-02 0.23E-02 0.23E-04 0.23E-06 0.23E-07 Sr-90 0.11E-03 0.11E-03 0.11E-05 0.11E-07 0.11E-08 Y-90 0.19E-04 0.16E-04 0.16E-06 0.16E-08 0.16E-09 Sr-91 0.15E-02 0.50E-04 0.50E-06 0.50E-08 0.50E-09 Y-91 0.21E-02 0.20E-02 0.20E-04 0.20E-06 0.20E-07 Sr-92 0.61E-03 0.27E-08 0.27E-10 0.27E-12 0.27E-13 Y-92 0.78E-04 0.25E-07 0.25E-09 0.25E-11 0.25E-12 Zr-95 0.57E-03 0.56E-03 0.56E-05 0.56E-07 0.56E-08 Nb-95 0.56E-03 0.56E-03 0.56E-05 0.56E-07 0.56E-08 Mo-99 0.46E-01 0.28E-01 0.28E-03 0.28E-05 0.28E-06 I-131 0.28E+01 0.23E+01 0.23E-01 0.23E-03 0.23E-04 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-3 Sheet 2 of 2 Revision 11 November 1996 Nuclide Spectrum I Spectrum II Spectrum III Spectrum IV Spectrum V Te-132 0.29E+00 0.19E+00 0.19E-02 0.19E-04 0.19E-05 I-132 0.97E+00 0.20E+00 0.20E-02 0.20E-04 0.20E-05 I-133 0.38E+01 0.77E+00 0.77E-02 0.77E-04 0.77E-05 Xe-133M 0.31E+01 0.0 0.0 0.0 0.0 Xe-133 0.20E+03 0.0 0.0 0.0 0.0 Cs-134 0.19E+00 0.19E+00 0.19E-02 0.19E-04 0.19E-05 I-134 0.49E+00 0.10E-16 0.10E-18 0.10E-20 0.10E-21 I-135 0.21E+01 0.15E-01 0.15E-03 0.15E-05 0.15E-06 Xe-135M 0.39E+00 0.0 0.0 0.0 0.0 Xe-135 0.54E+01 0.0 0.0 0.0 0.0 Cs-136 0.51E-01 0.46E-01 0.46E-03 0.46E-05 0.46E-06 Cs-137 0.35E+00 0.35E+00 0.35E-02 0.35E-04 0.35E-05 Xe-138 0.51E+00 0.0 0.0 0.0 0.0 Ba-140 0.39E-02 0.35E-02 0.35E-04 0.35E-06 0.35E-07 La-140 0.14E-02 0.27E-02 0.27E-04 0.27E-06 0.27E-07 Ce-144 0.33E-03 0.33E-03 0.33E-05 0.33E-07 0.33E-08 Pr-144 0.33E-03 0.33E-03 0.33E-05 0.33E-07 0.33E-08 (a) A plateout decontamination factor of 10 for yttrium and 100 for molybdenum is assumed for all waste streams.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-4 Sheet 1 of 2 Revision 11 November 1996 ACTIVITY CONCENTRATION SPECTRUM I THROUGH V FOR INPUT WASTE SOURCES, DESIGN BASIS CASE (µCi/cc)(a) Nuclide Spectrum I Spectrum II Spectrum III Spectrum IV Spectrum V H-3 0.11E+01 0.10E+01 0.10E-01 0.10E-03 0.10E-04 Cr-51 0.19E-02 0.19E-02 0.19E-04 0.19E-06 0.19E-07 Mn-54 0.31E-03 0.30E-03 0.30E-05 0.30E-07 0.30E-08 Fe-55 0.15E-02 0.92E-03 0.92E-05 0.92E-07 0.92E-08 Co-58 0.17E-01 0.16E-01 0.16E-03 0.16E-05 0.16E-06 Fe-59 0.10E-02 0.97E-03 0.97E-05 0.97E-07 0.97E-08 Co-60 0.19E-02 0.19E-02 0.19E-04 0.19E-06 0.19E-07 Kr-83M 0.42E-01 0.0 0.0 0.0 0.0 Kr-85M 0.22E+00 0.0 0.0 0.0 0.0 Kr-85 0.67E+00 0.0 0.0 0.0 0.0 Kr-87 0.12E+00 0.0 0.0 0.0 0.0 Kr-88 0.38E+00 0.0 0.0 0.0 0.0 Sr-89 0.28E-03 0.27E-03 0.27E-05 0.27E-07 0.23E-08 Sr-90 0.13E-04 0.13E-04 0.13E-06 0.13E-08 0.13E-09 Y-90 0.24E-05 0.19E-05 0.19E-07 0.19E-09 0.19E-10 Sr-91 0.18E-03 0.59E-07 0.59E-07 0.59E-09 0.59E-10 Y-91 0.25E-03 0.24E-03 0.24E-05 0.24E-07 0.24E-08 Sr-92 0.74E-04 0.33E-09 0.33E-11 0.33E-13 0.33E-14 Y-92 0.93E-05 0.30E-08 0.30E-10 0.30E-12 0.30E-13 Zr-95 0.68E-04 0.67E-04 0.67E-06 0.67E-08 0.67E-09 Nb-95 0.67E-04 0.67E-04 0.67E-06 0.67E-08 0.67E-09 Mo-99 0.56E-02 0.34E-02 0.34E-04 0.34E-06 0.34E-07 I-131 0.32E+00 0.27E+00 0.27E-02 0.27E-04 0.27E-05 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-4 Sheet 2 of 2 Revision 11 November 1996 Nuclide Spectrum I Spectrum II Spectrum III Spectrum IV Spectrum V Te-132 0.35E-01 0.23E+01 0.23E-03 0.23E-05 0.23E-06 I-132 0.12E+00 0.23E+01 0.23E-03 0.23E-05 0.23E-06 I-133 0.44E+00 0.91E+01 0.91E-03 0.91E-05 0.91E-06 Xe-133M 0.38E+00 0.0 0.0 0.0 0.0 Xe-133 0.32E+02 0.0 0.0 0.0 0.0 Cs-134 0.24E+01 0.24E+01 0.24E-03 0.24E-05 0.24E-06 I-134 0.60E+01 0.12E-17 0.12E-19 0.12E-21 0.12E-22 I-135 0.25E+00 0.17E-02 0.17E-04 0.17E-06 0.17E-07 Xe-135M 0.46E+01 0.0 0.0 0.0 0.0 Xe-135 0.65E+00 0.0 0.0 0.0 0.0 Cs-136 0.63E-02 0.56E-02 0.56E-04 0.56E-06 0.56E-07 Cs-137 0.42E+01 0.42E+01 0.42E-03 0.42E-05 0.42E-06 Xe-138 0.63E+01 0.0 0.0 0.0 0.0 Ba-140 0.47E-03 0.42E-03 0.42E-05 0.42E-07 0.42E-08 La-140 0.17E-03 0.32E-03 0.32E-05 0.32E-07 0.32E-08 Ce-144 0.40E-04 0.40E-04 0.40E-06 0.40E-08 0.40E-09 Pr-144 0.40E-04 0.40E-04 0.40E-06 0.40E-08 0.40E-09 (a) A plateout decontamination factor of 10 for yttrium and 100 for molybdenum is assumed for all waste streams.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-5 Sheet 1 of 4 ANNUAL FLOW AND ISOTOPIC SPECTRA FOR LIQUID WASTE INPUTS THIS TABLE APPLIES TO THE ESTIMATED RELEASES AND RADIOLOGICAL CONSEQUENCES CALCULATED, BASED ON ORIGINAL DESIGN (SEE FIGURES 11.2-2 and 11.2-3) Design Normal Basis Operation Stream Case Case Concentration Number(a) Stream Identification Flow(b) Flow(b) Spectrum Revision 20 November 2011 1A Safety injection tank drain 80 120 IV 1B Safety injection tank drain 80 120 IV 2A Safety injection system piping drains 200 300 IV 2B Safety injection system piping drains 200 300 IV 3A Spray additive tank relief and drain 140 260 III 3B Spray additive tank relief and drain 140 260 II 4A Containment spray pump drains 200 300 II 4B Containment spray pump drains 200 300 III 5A Component cooling water (CCW) surge tank relief valve 0 50 V 5B CCW surge tank relief valve 0 50 V 6A RHR heat exchanger (CCW) drain 600 900 V 6B RHR heat exchanger (CCW) drain 600 900 V 7A Waste gas compressor seal cooler relief valve (CCW) 0 100 V 7B Waste gas compressor seal cooler relief valve (CCW) 0 50 V 8A Sample sink drains 2,920 4,380 IV 8B Sample sink drains 2,920 4,380 IV (c) Chemical drain tank drain and overflow - - - (c) Laundry and hot shower tank drain and overflow - - - (c) Radwaste filter drains - - - (c) Floor drain receiver tank drain and overflow - - - 9 Spent resin loadout area drain 200 300 IV 10A Charging pump (CCP1) baseplate drain 135 165 III 10B Charging pump (CCP2) baseplate drain 135 165 III 11A Chemical mixing tank drain 20 30 IV 11B Chemical mixing tank drain 20 30 IV 12A (f) Boric acid and concentrates filter drain 90 135 IV 12B (f) Boric acid and concentrates filter drain 90 135 IV 13 (f) Concentrates holding tank drain and overflow 120 180 IV 14 (f) Concentrates holding tank pump drains 20 30 IV 15A Boric acid tank drain and overflow 400 600 IV 15B Boric acid tank drain and overflow 400 600 IV 16 Batching tank drain and overflow 100 150 IV
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-5 Sheet 2 of 4 Design Normal Basis Operation Stream Case Case Concentration Number(a) Stream Identification Flow(b) Flow(b) Spectrum Revision 20 November 2011 17A (f) Boric acid evaporator heat exchanger drains 300 450 IV 17B (f) Boric acid evaporator heat exchanger drains 300 450 IV 18A (f) Boric acid evaporator pump drains 80 120 IV 18B (f) Boric acid evaporator pump drains 80 120 IV 19A Monitor tank drain and overflow 800 1,200 IV 19B Monitor tank drain and overflow 800 1,200 IV 20 Miscellaneous leakage (Units 1 and 2) 14,600 I 21 Miscellaneous floor drains (Units 1 and 2) 5,000 7,500 IV 22A Containment fan cooler drain 1,000 1,500 IV 22B Containment fan cooler drain 1,000 1,500 IV 23A Reactor coolant pump labyrinth seal relief valve (CCW) 0 50 V 23B Reactor coolant pump labyrinth seal relief valve (CCW) 0 50 V 24A Reactor coolant pump thermal barrier relief (CCW) - 50 V 24B Reactor coolant pump thermal - barrier relief (CCW) - 50 V 25A Biological shield plate relief (CCW) - 50 V 25B Biological shield plate relief (CCW) 50 V 26A Reactor coolant pump upper and lower bearing relief (CCW) - 50 V 06B Reactor coolant pump upper and lower bearing relief (CCW) - 50 V 27A Reactor vessel support coolers relief (CCW) - 50 V 27B Reactor vessel support coolers relief (CCW) - 50 V 28A Reactor coolant pump No. 3 seal 925 1,400 III 28B Reactor coolant pump No. 3 seal 925 1,400 III 29A Excess letdown heat exchanger relief (CCW) - 50 V 29B Excess letdown heat exchanger relief (CCW) - 50 V 30A Miscellaneous equipment leakages - 11,700 I 30B Miscellaneous equipment leakages - 11,700 I 31A Reactor coolant drain tank relief valve - 50 II 31B Reactor coolant drain tank relief valve - 50 II 33A Miscellaneous pump leakage 70 10 III 33B Miscellaneous pump leakage 70 110 III 34 Laboratory drains 10,220 15,330 IV 35 Laundry drains 32,760 49,140 V 36 Personnel decontamination 11,860 16,340 V DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-5 Sheet 3 of 4 Design Normal Basis Operation Stream Case Case Concentration Number(a) Stream Identification Flow(b) Flow(b) Spectrum Revision 20 November 2011 37A CVCS valve leakoffs 6 9 II 37B CVCS valve leakoffs 6 9 II 38A Letdown heat exchanger tube side drain 75 110 II 38B Letdown heat exchanger tube side drain 75 110 II 39A Volume control tank drain 150 225 II 39B Volume control tank drain 150 225 II 40A Charging pump (CCP1) drains 140 210 II 40B Charging pump (CCP2) drains 140 210 II 41A Reactor coolant filter 45 60 II 41B Reactor coolant filter 45 60 II 42A Seal water injection filter 90 135 II 42B Seal water injection filter 90 135 II 43A Seal water filter 45 60 II 43B Seal water filter 45 60 II 44A Ion exchange filter 45 60 IV 44B Ion exchange filter 45 60 IV 45A Liquid holdup tank drain 1,050 1,575 II 45B Liquid holdup tank drain 700 1,050 II 46A CVCS miscellaneous piping drains 200 300 II 46B CVCS miscellaneous piping drains 200 300 II 47A RHR heat exchanger drain 700 1,050 II 47B RHR heat exchanger drain 700 1,050 II 48A RHR pump drain 280 420 II 48B RHR pump drain 280 420 II 49A RHR piping drains 200 300 II 49B RHR piping drains 200 300 II 50A Spent fuel pit cooling system piping drains 200 300 III 50B Spent fuel pit cooling system piping drains 200 300 III 51A Spent fuel pit cooling system filter drains 225 340 III 51B Spent fuel pit cooling system filter drains 225 340 III 52A Containment sump pump discharge piping drain 200 300 III 52B Containment sump pump discharge piping drain 200 300 III (c) Equipment drain receiver tank drain and overflow - - - (c) Equipment drain receiver tank pump drain - - - (c) Waste Concentrator Condensate tank drain and overflow - - - (c) Waste Concentrator Condensate tank pump drain - - - DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-5 Sheet 4 of 4 Design Normal Basis Operation Stream Case Case Concentration Number(a) Stream Identification Flow(b) Flow(b) Spectrum Revision 20 November 2011 (c) Radwaste concentrator heat exchanger drains - - - (c) Radwaste concentrator pump drains - - - (c) Waste concentrates tank drain and overflow - - - 53 Spent resin motive water pump drains 60 90 III 54A Waste gas moisture separator drain 40 60 III 54B Waste gas moisture separator drain 20 30 III 55A Waste gas decay tank drain 420 630 III 55B Waste gas decay tank drain 420 630 III 56A Waste gas compressor inlet piping drain 200 300 III 56B Waste gas compressor inlet piping drain 200 300 III 57A Sample sink drains 2,190 3,290 III 57B Sample sink drains 2,190 3,290 III 58A CVCS demineralizer overflow 5,500 5,500 III 58B CVCS demineralizer overflow 5,500 5,500 III 59A Steam generator blowdown tank drain (d) (d) (d) 59B Steam generator blowdown tank drain (d) (d) (d) (c) Spent resin tank overflow - - - 60A Waste regenerant tank discharge - 121,700 (e) 60B Waste regenerant tank discharge - 121,700 (e) (a) The letters "A" and "B" on the stream numbers refer to Units 1 and 2 inputs, respectively.
(b) Annual estimated flow in gallons per year.
(c) These streams are intra-system leakages and are not counted as input.
(d) The steam generator blowdown tank will have significant activity only when significant primary to secondary leakage occurs. (e) Calculated from secondary system activity concentrations and blowdown flowrate.
(f) Equipment is abandoned in place and no longer in use.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-6 Sheet 1 of 2 Revision 20 November 2011 ISOTOPIC FLOWS THROUGH CVC SYSTEM, DESIGN BASIS CASE Liquid Holdup Tank BA Evap Feed Ion Exchangers Monitor Tank Inflow, Outflow, Inflow, Liq Outflow, Inflow, To Wst Cond Tank, Nuclide Ci/hr Ci/hr Ci/hr Ci/hr Ci/hr Ci/hr H-3 0.230E-00 0.229E-00 0.229E-00 0.223E-00 0.223E-00 0.149E-00 Cr-51 0.318E-05 0.188E-05 0.188E-09 0.188E-12 0.188E-12 0.124E-12 Mn-54 0.517E-06 0.492E-06 0.492E-10 0.492E-13 0.492E-13 0.328E-13 Fe-55 0.264E-05 0.120E-07 0.120E-11 0.120E-14 0.120E-14 0.705E-15 Co-58 0.267E-04 0.217E-04 0.217E-08 0.217E-11 0.217E-11 0.144E-11 Fe-59 0.167E-05 0.121E-05 0.121E-09 0.121E-12 0.121E-12 0.799E-13 Co-60 0.332E-05 0.329E-05 0.329E-09 0.329E-12 0.329E-12 0.219E-12 Kr-83 0.211E-01 0.0 0.0 0.0 0.0 0.0 Kr-85M 0.109E-00 0.365E-35 0.365E-35 0.0 0.0 0.0 Kr-85 0.243E-00 0.242E-00 0.242E-00 0.0 0.0 0.0 Kr-87 0.594E-01 0.0 0.0 0.0 0.0 0.0 Kr-88 0.186E-00 0.323E-55 0.323E-55 0.0 0.0 0.0 Sr-89 0.381E-05 0.287E-05 0.287E-09 0.287E-12 0.287E-12 0.190E-12 Sr-90 0.183E-06 0.183E-06 0.183E-10 0.183E-13 0.183E-13 0.122E-13 Y-90 0.344E-04 0.327E-06 0.327E-06 0.327E-09 0.327E-09 0.192E-10 Sr-91 0.248E-05 0.615E-21 0.615E-25 0.615E-28 0.615E-28 0.174E-28 Y-91 0.354E-02 0.279E-02 0.279E-02 0.279E-05 0.279E-05 0.185E-06 Sr-92 0.101E-05 0.669E-62 0.669E-66 0.669E-69 0.669E-69 0.205E-70 Y-92 0.141E-03 0.106E-45 0.106E-45 0.106E-48 0.106E-48 0.700E-51 Zr-95 0.946E-06 0.757E-06 0.757E-10 0.757E-13 0.757E-13 0.502E-13 Nb-95 0.919E-06 0.893E-06 0.893E-10 0.893E-13 0.893E-13 0.595E-13 Mo-99 0.830E-00 0.488E-02 0.488E-02 0.488E-05 0.488E-05 0.288E-07 I-131 0.490E-01 0.802E-02 0.802E-04 0.802E-06 0.802E-08 0.513E-08 Te-132 0.515E-02 0.582E-04 0.582E-06 0.582E-09 0.582E-11 0.349E-11 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-6 Sheet 2 of 2 Revision 20 November 2011 Liquid Holdup Tank BA Evap Feed Ion Exchangers Monitor Tank Inflow, Outflow, Inflow, Liq Outflow, Inflow, To Wst Cond Tank, Nuclide Ci/hr Ci/hr Ci/hr Ci/hr Ci/hr Ci/hr I-132 0.176E-01 0.600E-04 0.600E-06 0.600E-08 0.600E-10 0.472E-11 I-133 0.669E-01 0.400E-08 0.400E-10 0.400E-12 0.400E-14 0.180E-14 Xe-133M 0.183E-00 0.329E-03 0.329E-03 0.0 0.0 0.0 Xe-133 0.154E-02 0.997E-00 0.997E-00 0.0 0.0 0.0 Cs-134 0.908E-02 0.890E-02 0.445E-03 0.445E-06 0.445E-06 0.297E-06 I-134 0.893E-02 0.0 0.0 0.0 0.0 0.0 I-135 0.369E-01 0.846E-24 0.846E-26 0.846E-28 0.846E-30 0.163E-30 Xe-135M 0.233E-01 0.128E-24 0.128E-24 0.0 0.0 0.0 Xe-135 0.327E-00 0.139E-16 0.139E-16 0.0 0.0 0.0 Cs-136 0.246E-02 0.804E-03 0.402E-04 0.402E-07 0.402E-07 0.261E-07 Cs-137 0.163E-01 0.162E-01 0.812E-03 0.812E-06 0.812E-06 0.542E-06 Xe-138 0.314E-01 0.0 0.0 0.0 0.0 0.0 Ba-140 0.645E-05 0.207E-05 0.207E-09 0.207E-12 0.207E-12 0.134E-12 La-140 0.228E-05 0.238E-05 0.238E-09 0.238E-12 0.238E-12 0.154E-12 Ce-144 0.557E-06 0.529E-06 0.529E-10 0.529E-13 0.529E-13 0.353E-13 Pr-144 0.557E-06 0.529E-06 0.529E-10 0.529E-13 0.529E-13 0.353E-13 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-7 Sheet 1 of 2 Revision 20 November 2011 ISOTOPIC FLOWS THROUGH CVC SYSTEM, NORMAL OPERATION CASE Liquid Holdup Tank BA Evap Feed Ion Exchangers Monitor Tank Inflow, Outflow, Inflow, Liq Outflow, Inflow, To Wst Cond Tank, Nuclide Ci/hr Ci/hr Ci/hr Ci/hr Ci/hr Ci/hr H-3 0.218E 00 0.217E 00 0.217E 00 0.211E 00 0.211E 00 0.140E 00 Cr-51 0.317E-05 0.188E-05 0.188E-09 0.188E-12 0.188E-12 0.124E-12 Mn-54 0.516E-06 0.492E-06 0.492E-10 0.492E-13 0.492E-13 0.328E-13 Fe-55 0.263E-05 0.120E-07 0.120E-11 0.120E-14 0.120E-14 0.705E-15 Co-58 0.266E-04 0.217E-04 0.217E-08 0.217E-11 0.217E-11 0.144E-11 Fe-59 0.167E-05 0.121E-05 0.121E-09 0.121E-12 0.121E-12 0.790E-13 Co-60 0.331E-05 0.329E-05 0.329E-09 0.329E-12 0.329E-12 0.219E-12 Kr-83M 0.252E-02 0.0 0.0 0.0 0.0 0.0 Kr-85M 0.130E-01 0.436E-36 0.436E-36 0.0 0.0 0.0 Kr-85 0.229E-01 0.228E-01 0.228E-01 0.0 0.0 0.0 Kr-87 0.713E-02 0.0 0.0 0.0 0.0 0.0 Kr-88 0.223E-01 0.386E-56 0.386E-56 0.0 0.0 0.0 Sr-89 0.457E-06 0.344E-06 0.344E-10 0.344E-13 0.344E-13 0.228E-13 Sr-90 0.219E-07 0.219E-07 0.219E-11 0.219E-14 0.219E-14 0.146E-14 Y-90 0.411E-05 0.392E-07 0.392E-07 0.392E-10 0.392E-10 0.230E-11 Sr-91 0.297E-06 0.737E-22 0.737E-26 0.737E-29 0.737E-29 0.209E-29 Y-91 0.412E-03 0.325E-03 0.325E-03 0.325E-06 0.325E-06 0.216E-07 Sr-92 0.122E-06 0.803E-63 0.803E-67 0.803E-70 0.803E-70 0.246E-71 Y-92 0.169E-04 0.127E-46 0.127E-46 0.127E-49 0.127E-49 0.840E-52 Zr-95 0.113E-06 0.908E-07 0.908E-11 0.908E-14 0.908E-14 0.602E-14 Nb-95 0.110E-06 0.107E-06 0.107E-10 0.107E-13 0.107E-13 0.713E-14 M0-99 0.992E-01 0.583E-03 0.583E-03 0.583E-06 0.583E-06 0.344E-08 I-131 0.588E-02 0.962E-03 0.962E-05 0.962E-07 0.962E-09 0.615E-09 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-7 Sheet 2 of 2 Revision 20 November 2011 Liquid Holdup Tank BA Evap Feed Ion Exchangers Monitor Tank Inflow, Outflow, Inflow, Liq Outflow, Inflow, To Wst Cond Tank, Nuclide Ci/hr Ci/hr Ci/hr Ci/hr Ci/hr Ci/hr Te-132 0.618E-03 0.698E-05 0.698E-07 0.698E-10 0.698E-12 0.418E-12 I-132 0.211E-02 0.720E-05 0.720E-07 0.720E-09 0.720E-11 0.567E-12 I-133 0.802E-02 0.480E-09 0.480E-11 0.480E-13 0.480E-15 0.215E-15 Xe-133M 0.213E-01 0.383E-04 0.383E-04 0.0 0.0 0.0 Xe-133 0.174E 01 0.112E 00 0.112E 00 0.0 0.0 0.0 Cs-134 0.110E-02 0.108E-02 0.539E-04 0.539E-07 0.539E-07 0.360E-07 I-134 0.107E-02 0.0 0.0 0.0 0.0 0.0 I-135 0.443E-02 0.101E-24 0.101E-26 0.101E-28 0.101E-30 0.196E-31 Xe-135M 0.279E-02 0.153E-25 0.153E-25 0.0 0.0 0.0 Xe-135 0.390E-01 0.166E-17 0.166E-17 0.0 0.0 0.0 Cs-136 0.295E-03 0.964E-04 0.482E-05 0.482E-08 0.482E-08 0.313E-08 Cs-137 0.195E-02 0.195E-02 0.975E-04 0.975E-07 0.975E-07 0.650E-07 Xe-138 0.377E-02 0.0 0.0 0.0 0.0 0.0 Ba-140 0.773E-06 0.248E-06 0.248E-10 0.248E-13 0.248E-13 0.161E-13 La-140 0.273E-06 0.285E-06 0.285E-10 0.285E-13 0.285E-13 0.185E-13 Ce-144 0.668E-07 0.635E-07 0.835E-11 0.635E-14 0.635E-14 0.423E-14 Pr-144 0.668E-07 0.635E-07 0.635E-11 0.635E-14 0.635E-14 0.423E-14 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-8 Sheet 1 of 5 Revision 11 November 1996 ANNUAL FLOW AND ACTIVITY CONCENTRATION OF PROCESS STREAMS FOR DESIGN BASIS CASE Stream Number(a) 1 2 3 4 5 Annual Flow, gal./yr 3850 17370 0.0 140 44620 Nuclide Concentration, µCi/cc H-3 0.533E-02 0.697E-03 0.0 0.110E-01 0.110E-04 Cr-51 0.899E-05 0.118E-05 0.0 0.185E-04 0.176E-07 Mn-54 0.148E-05 0.193E-06 0.0 0.304E-05 0.303E-08 Fe-55 0.444E-04 0.581E-06 0.0 0.915E-05 0.548E-08 Co-58 0.795E-04 0.104E-04 0.0 0.164E-03 0.160E-06 Fe-59 0.471E-05 0.616E-06 0.0 0.970E-05 0.941E-08 Co-60 0.945E-05 0.124E-05 0.0 0.194E-04 0.194E-07 Sr-89 0.112E-04 0.146E-05 0.0 0.230E-04 0.224E-07 Sr-90 0.533E-06 0.697E-07 0.0 0.110E-05 0.110E-08 Y-90 0.778E-07 0.102E-07 0.0 0.160E-06 0.541E-09 Sr-91 0.242E-06 0.317E-07 0.0 0.499E-06 0.163E-10 Y-91 0.991E-05 0.130E-05 0.0 0.204E-04 0.199E-07 Sr-92 0.133E-10 0.173E-11 0.0 0.273E-10 0.122E-18 Y-92 0.119E-09 0.156E-10 0.0 0.245E-09 0.314E-16 Zr-95 0.271E-05 0.354E-06 0.0 0.558E-05 0.546E-08 Nb-95 0.270E-05 0.353E-06 0.0 0.556E-05 0.556E-08 M0-99 0.137E-03 0.179E-04 0.0 0.281E-03 0.172E-06 I-131 0.114E-01 0.149E-02 0.0 0.234E-01 0.197E-04 Te-132 0.925E-03 0.121E-03 0.0 0.190E-02 0.124E-05 I-132 0.954E-03 0.125E-03 0.0 0.197E-02 0.128E-05 I-133 0.374E-02 0.489E-03 0.0 0.770E-02 0.158E-05 Cs-134 0.943E-03 0.123E-03 0.0 0.194E-02 0.194E-05 I-134 0.492E-19 0.643E-20 0.0 0.101E-18 0.211E-38 I-135 0.707E-04 0.924E-05 0.0 0.146E-03 0.102E-08 Cs-136 0.225E-03 0.294E-04 0.0 0.462E-03 0.416E-06 Cs-137 0.169E-02 0.221E-03 0.0 0.347E-02 0.347E-05 Ba-140 0.170E-04 0.222E-05 0.0 0.349E-04 0.313E-07 La-140 0.129E-04 0.169E-05 0.0 0.266E-04 0.301E-07 Ce-144 0.161E-05 0.211E-06 0.0 0.332E-05 0.330E-08 Pr-144 0.161E-05 0.211E-06 0.0 0.332E-05 0.330E-08 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-8 Sheet 2 of 5 Revision 11 November 1996 Stream Number(a) 6 7 8 9 10 Annual Flow, gal./yr 10220 21360 76200 0.0 12690 Nuclide Concentration, µCi/cc H-3 0.110E-03 0.160E-02 0.469E-03 0.0 0.491E+00 Cr-51 0.176E-06 0.190E-05 0.567E-06 0.0 0.029E-03 Mn-54 0.303E-07 0.430E-06 0.126E-06 0.0 0.136E-03 Fe-55 0.548E-07 0.367E-07 0.208E-07 0.0 0.414E-03 Co-58 0.160E-05 0.208E-04 0.614E-05 0.0 0.733E-02 Fe-59 0.941E-07 0.114E-05 0.338E-06 0.0 0.435E-03 Co-60 0.194E-06 0.282E-05 0.828E-06 0.0 0.871E-03 Sr-89 0.224E-06 0.277E-05 0.821E-06 0.0 0.103E-02 Sr-90 0.110E-07 0.160E-06 0.469E-07 0.0 0.492E-04 Y-90 0.541E-08 0.156E-06 0.449E-07 0.0 0.720E-05 Sr-91 0.163E-09 0.287E-17 0.314E-10 0.0 0.328E-04 Y-91 0.199E-06 0.254E-05 0.750E-06 0.0 0.913E-03 Sr-92 0.122E-17 0.0 0.235E-16 0.0 0.434E-05 Y-92 0.314E-15 0.0 0.605E-16 0.0 0.563E-06 Zr-95 0.546E-07 0.701E-06 0.207E-06 0.0 0.250E-03 Nb-95 0.556E-07 0.797E-06 0.234E-06 0.0 0.249E-03 Mo-99 0.172E-05 0.134E-05 0.707E-06 0.0 0.127E-01 I-131 0.197E-03 0.102E-02 0.324E-03 0.0 0.105E+01 Te-132 0.124E-04 0.140E-04 0.631E-05 0.0 0.860E-01 I-132 0.128E-04 0.144E-04 0.651E-05 0.0 0.935E-01 I-133 0.158E-04 0.172E-07 0.305E-05 0.0 0.366E+00 Cs-134 0.194E-04 0.279E-03 0.821E-04 0.0 0.870E-01 I-134 0.211E-37 0.0 0.406E-38 0.0 0.345E-02 I-135 0.102E-07 0.171E-19 0.196E-08 0.0 0.212E-01 Cs-136 0.416E-05 0.319E-04 0.976E-05 0.0 0.207E-01 Cs-137 0.347E-04 0.506E-03 0.149E-03 0.0 0.156E+00 Ba-140 0.313E-06 0.238E-05 0.729E-06 0.0 0.157E-02 La-140 0.301E-06 0.274E-05 0.825E-06 0.0 0.118E-02 Ce-144 0.330E-07 0.468E-06 0.137E-06 0.0 0.149E-03 Pr-144 0.330E-07 0.468E-06 0.137E-06 0.0 0.149E-03 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-8 Sheet 3 of 5 Revision 11 November 1996 Stream Number(a) 58A&B 59A&B 60A&B 11 12 Annual Flow, gal./yr 11000 0.0 0.0 23990 0.0
Nuclide Concentration, µCi/cc H-3 0.110E-01 0.0 0.0 0.264E+00 0.0 Cr-51 0.185E-04 0.0 0.0 0.315E-03 0.0 Mn-54 0.304E-05 0.0 0.0 0.712E-04 0.0 Fe-55 0.915E-05 0.0 0.0 0.614E-05 0.0 Co-58 0.164E-03 0.0 0.0 0.345E-02 0.0 Fe-59 0.970E-05 0.0 0.0 0.189E-03 0.0 Co-60 0.194E-04 0.0 0.0 0.467E-03 0.0 Sr-89 0.230E-04 0.0 0.0 0.460E-03 0.0 Sr-90 0.110E-05 0.0 0.0 0.265E-04 0.0 Y-90 0.160E-06 0.0 0.0 0.259E-04 0.0 Sr-91 0.499E-06 0.0 0.0 0.694E-15 0.0 Y-91 0.204E-04 0.0 0.0 0.420E-03 0.0 Sr-92 0.273E-10 0.0 0.0 0.0 0.0 Y-92 0.245E-09 0.0 0.0 0.0 0.0 Zr-95 0.558E-05 0.0 0.0 0.116E-03 0.0 Nb-95 0.556E-05 0.0 0.0 0.132E-03 0.0 Mo-99 0.281E-03 0.0 0.0 0.223E-03 0.0 I-131 0.234E-01 0.0 0.0 0.170E+00 0.0 Te-132 0.190E-02 0.0 0.0 0.233E-02 0.0 I-132 0.197E-02 0.0 0.0 0.241E-02 0.0 I-133 0.770E-02 0.0 0.0 0.301E-05 0.0 Cs-134 0.194E-02 0.0 0.0 0.463E-01 0.0 I-134 0.101E-18 0.0 0.0 0.0 0.0 I-135 0.146E-03 0.0 0.0 0.910E-17 0.0 Cs-136 0.462E-03 0.0 0.0 0.530E-02 0.0 Cs-137 0.347E-02 0.0 0.0 0.838E-01 0.0 Ba-140 0.349E-04 0.0 0.0 0.396E-03 0.0 La-140 0.266E-04 0.0 0.0 0.454E-03 0.0 Ce-144 0.332E-05 0.0 0.0 0.775E-04 0.0 Pr-144 0.332E-05 0.0 0.0 0.775E-04 0.0
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-8 Sheet 4 of 5 Revision 11 November 1996 Stream Number(a) 13 14 15 16 17 Annual Flow, gal./yr 0.0 23990 700,000 723,990 800,190 Nuclide Concentration, µCi/cc H-3 0.0 0.264E+00 0.101E+01 0.985E-00 0.891E+00 Cr-51 0.0 0.315E-06 0.806E-12 0.104E-07 0.634E-07 Mn-54 0.0 0.712E-07 0.217E-12 0.236E-08 0.141E-07 Fe-55 0.0 0.614E-08 0.468E-14 0.203E-09 0.216E-08 Co-58 0.0 0.345E-05 0.957E-11 0.114E-06 0.688E-06 Fe-59 0.0 0.189E-06 0.503E-12 0.626E-08 0.379E-07 Co-60 0.0 0.467E-06 0.146E-11 0.155E-07 0.929E-07 Sr-89 0.0 0.460E-06 0.126E-11 0.152E-07 0.919E-07 Sr-90 0.0 0.265E-07 0.806E-13 0.878E-09 0.526E-08 Y-90 0.0 0.259E-07 0.126E-09 0.980E-09 0.516E-08 Sr-91 0.0 0.694E-18 0.116E-27 0.0 0.299E-11 Y-91 0.0 0.420E-06 0.121E-05 0.118E-05 0.114E-05 Sr-92 0.0 0.0 0.136E-69 0.0 0.224E-17 Y-92 0.0 0.0 0.463E-50 0.0 0.576E-17 Zr-95 0.0 0.116E-06 0.332E-12 0.384E-08 0.232E-07 Nb-95 0.0 0.132E-06 0.393E-12 0.437E-08 0.262E-07 Mo-99 0.0 0.223E-06 0.191E-06 0.192E-06 0.241E-06 I-131 0.0 0.170E-03 0.337E-07 0.567E-05 0.360E-04 Te-132 0.0 0.233E-05 0.232E-10 0.772E-07 0.673E-06 I-132 0.0 0.241E-05 0.312E-10 0.799E-07 0.690E-06 I-133 0.0 0.301E-08 0.121E-13 0.997E-10 0.291E-06 Cs-134 0.0 0.232E-02 0.196E-05 0.788E-04 0.791E-04 I-134 0.0 0.0 0.0 0.0 0.0 I-135 0.0 0.910E-20 0.187E-09 0.0 0.187E-09 Cs-136 0.0 0.265E-03 0.171E-05 0.898E-05 0.903E-05 Cs-137 0.0 0.419E-02 0.357E-05 0.142E-03 0.143E-03 Ba-140 0.0 0.396E-06 0.906E-12 0.131E-07 0.183E-07 La-140 0.0 0.454E-06 0.101E-11 0.150E-07 0.921E-07 Ce-144 0.0 0.775E-07 0.232E-12 0.257E-08 0.154E-07 Pr-144 0.0 0.776E-07 0.232E-12 0.257E-08 0.154E-07
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-8 Sheet 5 of 5 Revision 11 November 1996 Stream Number(a) 18 19 Annual Flow, gal./yr 800,190 (See Section 11.2.7.) Nuclide Concentration, µCi/cc H-3 0.891E+00 0.774E-06 Cr-51 0.634E-07 0.551E-13 Mn-54 0.141E-07 0.123E-13 Fe-55 0.216E-08 0.188E-14 Co-58 0.688E-06 0.598E-12 Fe-59 0.379E-07 0.329E-13 Co-60 0.929E-07 0.807E-13 Sr-89 0.919E-07 0.799E-13 Sr-90 0.526E-08 0.457E-14 Y-90 0.516E-08 0.448E-14 Sr-91 0.299E-11 0.260E-17 Y-91 0.114E-05 0.991E-12 Sr-92 0.224E-19 0.195E-23 Y-92 0.576E-17 0.501E-23 Zr-95 0.232E-07 0.202E-13 Nb-95 0.262E-07 0.228E-13 Mo-99 0.241E-06 0.209E-12 I-131 0.360E-04 0.313E-10 Te-132 0.673E-06 0.585E-12 I-132 0.690E-06 0.600E-12 I-133 0.291E-06 0.253E-12 Cs-134 0.791E-04 0.687E-10 I-134 0.0 0.0 I-135 0.187E-09 0.164E-15 Cs-136 0.903E-05 0.785E-11 Cs-137 0.143E-03 0.124E-09 Ba-140 0.813E-07 0.706E-13 La-140 0.921E-07 0.800E-13 Ce-144 0.154E-07 0.134E-13 Pr-144 0.154E-07 0.134E-13 (a) See Figure 11.2-2 for waste stream number identification.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-9 Sheet 1 of 5 Revision 11 November 1996 ANNUAL FLOW AND ACTIVITY CONCENTRATION OF PROCESS STREAMS FOR NORMAL OPERATION CASE Stream Number(a) 1 2 3 4 5 Annual Flow, gal./yr 29800 37530 100 220 65480
Nuclide Concentration, µCi/cc H-3 0.009E+00 0.307E+00 0.103E+01 0.103E-01 0.103E-04 Cr-51 0.153E-02 0.582E-03 0.185E-02 0.185E-04 0.176E-07 Mn-54 0.240E-03 0.914E-04 0.304E-03 0.304E-05 0.303E-08 Fe-55 0.120E-02 0.457E-03 0.915E-03 0.915E-05 0.548E-08 Co-58 0.131E-01 0.499E-02 0.164E-01 0.164E-03 0.160E-06 Fe-59 0.787E-03 0.299E-03 0.970E-03 0.970E-05 0.941E-08 Co-60 0.153E-02 0.582E-03 0.194E-02 0.194E-04 0.194E-07 Sr-89 0.219E-03 0.831E-04 0.271E-03 0.271E-05 0.263E-08 Sr-90 0.104E-04 0.395E-05 0.132E-04 0.132E-06 0.132E-09 Y-90 0.186E-05 0.706E-06 0.194E-05 0.194E-07 0.651E-10 Sr-91 0.142E-03 0.539E-04 0.590E-05 0.590E-07 0.193E-11 Y-91 0.197E-03 0.748E-04 0.245E-03 0.245E-05 0.239E-08 Sr-92 0.578E-04 0.220E-04 0.329E-09 0.329E-11 0.147E-19 Y-92 0.731E-05 0.278E-05 0.295E-08 0.295E-10 0.378E-17 Zr-95 0.535E-04 0.204E-04 0.667E-04 0.667E-06 0.653E-09 Nb-95 0.525E-04 0.199E-04 0.667E-04 0.667E-06 0.667E-09 Mo-99 0.437E-02 0.166E-02 0.341E-02 0.341E-04 0.209E-07 I-131 0.251E+00 0.955E-01 0.269E+00 0.269E-02 0.226E-05 Te-132 0.273E-01 0.104E-01 0.227E-01 0.227E-03 0.148E-06 I-132 0.917E-01 0.349E-01 0.234E-01 0.234E-03 0.153E-06 I-133 0.349E+00 0.133E+00 0.913E-01 0.913E-01 0.187E-06 Cs-134 0.186E-01 0.706E-02 0.236E-01 0.236E-03 0.235E-06 I-134 0.469E-01 0.178E-01 0.124E-17 0.124E-19 0.259E-39 I-135 0.196E+00 0.747E-01 0.175E-02 0.175E-04 0.122E-09 Cs-136 0.492E-02 0.187E-02 0.562E-02 0.562E-04 0.505E-07 Cs-137 0.328E-01 0.125E-01 0.417E-01 0.417E-03 0.417E-06 Ba-140 0.372E-03 0.141E-03 0.424E-03 0.424E-05 0.381E-08 La-140 0.131E-03 0.499E-04 0.323E-03 0.323E-05 0.366E-08 Ce-144 0.317E-04 0.120E-04 0.401E-04 0.401E-06 0.399E-09 Pr-144 0.317E-04 0.120E-04 0.401E-04 0.401E-04 0.399E-09 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-9 Sheet 2 of 5 Revision 11 November 1996 Stream Number(a) 6 7 8 9 10 Annual Flow, gal./yr 15330 67650 80100 1000 19000
Nuclide Concentration, µCi/cc H-3 0.103E-03 0.527E+00 0.278E-04 0.103E-01 0.459E+00 Cr-51 0.176E-06 0.705E-03 0.477E-07 0.195E-02 0.828E-03 Mn-54 0.303E-07 0.152E-03 0.820E-08 0.306E-03 0.136E-03 Fe-55 0.548E-07 0.216E-04 0.148E-07 0.153E-02 0.413E-03 Co-58 0.160E-05 0.748E-02 0.434E-06 0.167E-01 0.731E-02 Fe-59 0.941E-07 0.414E-03 0.255E-07 0.100E-02 0.434E-03 Co-60 0.194E-06 0.994E-03 0.526E-07 0.195E-02 0.869E-03 Sr-89 0.263E-07 0.118E-03 0.713E-08 0.278E-03 0.121E-03 Sr-90 0.132E-08 0.678E-05 0.357E-09 0.132E-04 0.590E-05 Y-90 0.651E-09 0.663E-05 0.176E-09 0.236E-05 0.869E-06 Sr-91 0.193E-10 0.365E-14 0.521E-11 0.181E-03 0.374E-05 Y-91 0.239E-07 0.110E-03 0.648E-08 0.250E-03 0.109E-03 Sr-92 0.147E-18 0.0 0.397E-19 0.737E-04 0.465E-06 Y-92 0.378E-16 0.0 0.102E-16 0.931E-05 0.601E-07 Zr-95 0.653E-08 0.302E-04 0.177E-08 0.681E-04 0.298E-04 Nb-95 0.667E-08 0.338E-04 0.181E-08 0.667E-04 0.298E-04 Mo-99 0.209E-06 0.929E-04 0.566E-07 0.556E-02 0.154E-02 I-131 0.226E-04 0.491E-01 0.613E-05 0.320E+00 0.121E+00 Te-132 0.148E-05 0.897E-03 0.400E-06 0.347E-01 0.102E-01 I-132 0.153E-05 0.926E-03 0.413E-06 0.117E+00 0.110E-01 I-133 0.187E-05 0.348E-05 0.507E-06 0.445E+00 0.430E-01 Cs-134 0.235E-05 0.120E-01 0.637E-06 0.236E-01 0.105E-01 I-134 0.259E-38 0.0 0.701E-39 0.598E-01 0.377E-03 I-135 0.122E-08 0.103E-15 0.330E-09 0.250E+00 0.235E-02 Cs-136 0.505E-06 0.152E-02 0.137E-06 0.625E-02 0.252E-02 Cs-137 0.417E-05 0.214E-01 0.113E-05 0.417E-01 0.186E-01 Ba-140 0.381E-07 0.114E-03 0.103E-07 0.473E-03 0.190E-03 La-140 0.366E-07 0.130E-03 0.991E-08 0.167E-03 0.143E-03 Ce-144 0.399E-08 0.200E-04 0.108E-08 0.403E-04 0.179E-04 Pr-144 0.399E-08 0.200E-04 0.108E-08 0.403E-04 0.179E-04 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-9 Sheet 3 of 5 Revision 11 November 1996 Stream Number(a) 58A&B 59A&B 60A&B 11 12 Annual Flow, gal./yr 11000 300 0 98650 0
Nuclide Concentration, µCi/cc H-3 0.1832-01 0.0 0.0 0.461E+00 0.0 Cr-51 0.185E-04 0.0 0.0 0.469E-03 0.0 Mn-54 0.304E-05 0.0 0.0 0.130E-03 0.0 Fe-55 0.915E-05 0.0 0.0 0.305E-05 0.0 Co-58 0.164E-05 0.0 0.0 0.587E-02 0.0 Fe-59 0.970E-05 0.0 0.0 0.305E-03 0.0 Co-60 0.194E-04 0.0 0.0 0.867E-03 0.0 Sr-89 0.271E-05 0.0 0.0 0.889E-04 0.0 Sr-90 0.132E-06 0.0 0.0 0.593E-05 0.0 Y-90 0.194E-07 0.0 0.0 0.590E-05 0.0 Sr-91 0.590E-07 0.0 0.0 0.101E-15 0.1 Y-91 0.245E-05 0.0 0.0 0.849E-04 0.0 Sr-92 0.329E-11 0.0 0.0 0.0 0.0 Y-92 0.295E-10 0.0 0.0 0.0 0.0 Zr-95 0.667E-06 0.0 0.0 0.234E-04 0.0 Nb-95 0.667E-06 0.0 0.0 0.286E-04 0.0 Mo-99 0.341E-04 0.0 0.0 0.137E-04 0.0 I-131 0.269E-02 0.0 0.0 0.181E-01 0.0 Te-132 0.227E-03 0.0 0.0 0.149E-03 0.0 I-132 0.234E-03 0.0 0.0 0.154E-03 0.0 I-133 0.913E-03 0.0 0.0 0.197E-06 0.0 Cs-134 0.236E-03 0.0 0.0 0.104E-01 0.0 I-134 0.124E-19 0.0 0.0 0.0 0.0 I-135 0.175E-04 0.0 0.0 0.241E-17 0.0 Cs-136 0.562E-04 0.0 0.0 0.758E-03 0.0 Cs-137 0.417E-03 0.0 0.0 0.187E-01 0.0 Ba-140 0.424E-05 0.0 0.0 0.561E-04 0.0 La-140 0.323E-05 0.0 0.0 0.645E-04 0.0 Ce-144 0.401E-06 0.0 0.0 0.170E-04 0.0 Pr-144 0.401E-06 0.0 0.0 0.170E-04 0.0
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-9 Sheet 4 of 5 Revision 11 November 1996 Stream Number(a) 13 14 15 16 17 Annual Flow, gal./yr 0 98650 7000000 798650 878950
Nuclide Concentration, µCi/cc H-3 0.0 0.461E+00 0.906E+00 0.851E+00 0.773E+00 Cr-51 0.0 0.469E-06 0.806-12 0.579E-07 0.570E-07 Mn-54 0.0 0.130E-06 0.217E-12 0.161E-07 0.154E-07 Fe-55 0.0 0.305E-08 0.468E-14 0.377E-09 0.169E-08 Co-58 0.0 0.587E-05 0.957E-11 0.725E-06 0.698E-06 Fe-59 0.0 0.305E-06 0.503E-12 0.377E-07 0.366E-07 Co-60 0.0 0.867E-06 0.146E-11 0.107E-06 0.102E-06 Sr-89 0.0 0.889E-07 0.151E-12 0.110E-07 0.106E-07 Sr-90 0.0 0.593E-08 0.957E-14 0.732E-09 0.698E-09 Y-90 0.0 0.590E-08 0.151E-10 0.742E-09 0.690E-09 Sr-91 0.0 0.101E-18 0.136E-28 0.125E-19 0.475E-12 Y-91 0.0 0.849E-07 0.141E-06 0.134E-06 0.122E-06 Sr-92 0.0 0.0 0.161E-70 0.0 0.0 Y-92 0.0 0.0 0.554E-51 0.0 0.0 Zr-95 0.0 0.234E-07 0.398E-13 0.289E-08 0.279E-08 Nb-95 0.0 0.286E-07 0.473E-13 0.353E-09 0.337E-09 Mo-99 0.0 0.137E-07 0.227E-07 0.216E-07 0.248E-07 I-131 0.0 0.181E-04 0.408E-08 0.224E-05 0.259E-05 Te-132 0.0 0.149E-06 0.277E-11 0.184E-07 0.532E-07 I-132 0.0 0.154E-06 0.373E-11 0.190E-07 0.549E-07 I-133 0.0 0.197E-09 0.141E-14 0.235E-10 0.462E-07 Cs-134 0.0 0.520E-03 0.237E-06 0.644E-04 0.586E-04 I-134 0.0 0.0 0.0 0.0 0.0 I-135 0.0 0.241E-20 0.131E-30 0.0 0.301E-10 Cs-136 0.0 0.379E-04 0.206E-07 0.470E-05 0.428E-05 Cs-137 0.0 0.935E-03 0.428E-06 0.116E-03 0.106E-03 Ba-140 0.0 0.561E-07 0.106E-12 0.693E-08 0.724E-08 La-140 0.0 0.654E-07 0.121E-12 0.797E-08 0.815E-08 Ce-144 0.0 0.170E-07 0.282E-13 0.210E-08 0.201E-08 Pr-144 0.0 0.170E-07 0.282E-13 0.210E-08 0.201E-08
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-9 Sheet 5 of 5 Revision 11 November 1996 Stream Number(a) 18 19 Annual Flow, gal./yr 878750 (See Section 11.2.7.)
Nuclide Concentration, µCi/cc H-3 0.773E+00 0.738E-06 Cr-51 0.570E-07 0.543E-13 Mn-54 0.154E-07 0.147E-13 Fe-55 0.169E-08 0.161E-14 Co-58 0.698E-06 0.666E-12 Fe-59 0.366E-07 0.349E-13 Co-60 0.102E-06 0.973E-13 Sr-89 0.106E-07 0.101E-13 Sr-90 0.698E-09 0.635E-15 Y-90 0.690E-09 0.658E-15 Sr-91 0.475E-12 0.453E-18 Y-91 0.122E-06 0.116E-12 Sr-92 0.0 0.0 Y-92 0.0 0.0 Zr-95 0.279E-08 0.266E-14 Nb-95 0.337E-09 0.306E-15 Mo-99 0.248E-07 0.237E-13 I-131 0.259E-05 0.247E-12 Te-132 0.532E-07 0.508E-13 I-132 0.549E-07 0.524E-13 I-133 0.462E-07 0.441E-13 Cs-134 0.586E-04 0.559E-10 I-134 0.0 0.0 I-135 0.301E-10 0.287E-16 Cs-136 0.428E-05 0.408E-11 Cs-137 0.106E-03 0.101E-09 Ba-140 0.724E-08 0.691E-14 La-140 0.815E-08 0.778E-14 Ce-144 0.201E-08 0.192E-14 Pr-144 0.201E-08 0.192E-14 (a) See Figure 11.2-3 for waste stream number identification.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-10 Sheet 1 of 3 Revision 19 May 2010 EQUIPMENT DESIGN SUMMARY DATA LIQUID RADWASTE SYSTEM Volume Pressure, Temperature, Tank Quantity Type gal psig °F Material Reactor coolant drain 1(f) Horiz 400 25 267 SS Laundry and hot shower 2(a) Vert 1,000 5 300 CS Chemical drain 1(a) Horiz 1,000 0 150 SS Aux. Building sump 1(a) - 7,300 0 120 SS Misc. equip. drain 1(a) - 5,500 0 180 SS Processed waste receiver 2(a) Vert 15,000 0 180 SS Floor drain receiver 2(a) Vert 15,000 0 180 SS Equipment drain receiver 2(a) Vert 15,000 0 180 SS Demineralizer regenerant receiver 2(a) Vert 15,000 0 180 (b) Laundry/distillate 2(a) Vert 25,000 0 150 SS Containment structure sump 1(f) NA 700 0 140 (g) Reactor cavity sump 1(f) NA 300 0 140 (g) RHR pump room sump 1(f) NA 500 0 180 (g) DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-10 Sheet 2 of 3 Revision 19 May 2010 Flow, Head, Pressure, Temp, Pump Qty. Type gpm ft psig °F Mtl.(d) Reactor coolant drain tank 2(f) Vert Cent. 150 170 150 300 SS Chemical drain 1(a) Horiz Cent.(c) 20 122 150 180 SS Laundry and hot shower drain 2(a) Vert Cent.(c) 20 122 150 180 CS Misc. equip. drain tank 2(a) Horiz Cent.(c) 50 45 150 180 CS(h) Floor drain receiver 2(a) Vert. Cent.(c) 50 300 150 180 SS Equipment drain receiver 2(a) Vert Cent.(c) 50 300 150 180 SS Processed waste receiver 2(a) Vert Cent.(c) 50 122 150 180 SS Containment structure sump 4(f) Vert Cent.(c) 50 45 150 140 CI(h) Demineralizer regenerant receiver 2(a) Vert Cent.(c) 50 300 150 180 SS Reactor cavity sump 2(f) Horiz Cent.(e) 30 75 150 140 SS RHR pump room sumps 4(f) Vert Cent 50 40 150 180 CI(h) . Aux. Building sump 2(a) Horiz Cent.(e) 50 45 150 180 CI(h) Laundry/distillate 2(a) Horiz Cent. 150 200 150 115 SS DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-10 Sheet 3 of 3 Revision 19 May 2010 Miscellaneous Quantity Capacity Type Radwaste filters 5(a) 50 gpm Cartridge Media filters 2(a) 50 gpm Media bed Ion exchangers 2(a) 50 gpm Bead resin Spent Resin Transfer Filters 2(a) 120 gpm Cartridge (a) Equipment common to Units 1 and 2 (b) Carbon steel with a neoprene lining (c) Mechanical seal provided (d) Wetted surfaces only (e) Deep well jet pump (f) Per unit (g) Concrete (h) Cast iron Ni Resist Type D2
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.2-11 PARAMETERS USED IN TRITIUM ANALYSIS FOR PLANT WATER SOURCES Parameter Value Primary system volume, gal. 94,000 Volume of water in primary water storage tank, gal. 200,000 Volume of water in refueling water storage tank, gal. 450,000 Volume of water in spent fuel pool, gal. 442,000 Percent of mixing of spent fuel pool water with refueling canal during refueling 15 Evaporative loss from spent fuel pool during operation, gal./day 500 Evaporative loss from spent fuel pool during refueling, gal./day 1,360 Evaporative loss from refueling canal during refueling, gal./day 485
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.2-13 CALCULATED AND ASSUMED HOLDUP TIMES FOR LIQUID WASTE SYSTEM TANKS Fill Release Assumed Decay Capacity, Time, Time, Time, Tank Qty. gal. Days Days Days Hours Liquid holdup 5(a) 83,000 46.1 3.07 21.0 504.0 Monitor 2 25,000 0.93 0.093 0.5 12.0 Waste Condensate 1 15,000 2.23 0.56 1.0 24.0 Reactor coolant drain 1 400 116.8 7.4E-4 2.0 48.0 Laundry and hot shower 2(a) 1,000 3.6 0.03 2.0 48.0 Chemical drain 1(a) 1,000 7.6 0.014 2.0 48.0 Miscellaneous equipment drain 1(a) 20,000 123.0 0.3 2.0 48.0 Equipment drain receiver 1 15,000 42.5 0.56 14.0 336.0 Floor drain receiver 1 15,000 33.7 0.08 14.0 336.0 Waste regenerant 1 15,000 - - 18.0 432.0 (a) Equipment common to both units.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.2-14 ESTIMATED ANNUAL ACTIVITY RELEASE FOR DESIGN BASIS CASE (ONE UNIT) Turbine Bldg Condensate Polishing Radwaste System, Sump, System, One Unit Total, Nuclide Ci/yr Ci/yr Ci/yr Ci/yr H-3 0.135E+04 0.0 0.0 0.135E+04 Cr-51 0.960E-04 0.0 0.0 0.960E-04 Mn-54 0.213E-04 0.0 0.0 0.213E-04 Fe-55 0.327E-05 0.0 0.0 0.327E-05 Co-58 0.104E-02 0.0 0.0 0.104E-02 Fe-59 0.574E-04 0.0 0.0 0.574E-04 Co-60 0.141E-03 0.0 0.0 0.141E-03 Sr-89 0.139E-03 0.0 0.0 0.139E-03 Sr-90 0.797E-03 0.0 0.0 0.797E-03 Y-90 0.781E-05 0.0 0.0 0.781E-05 Sr-91 0.453E-08 0.0 0.0 0.453E-08 Y-91 0.173E-02 0.0 0.0 0.173E-02 Sr-92 0.339E-14 0.0 0.0 0.339E-14 Y-92 0.872E-14 0.0 0.0 0.872E-14 Zr-95 0.351E-04 0.0 0.0 0.351E-04 Mb-95 0.397E-04 0.0 0.0 0.397E-04 Mo-99 0.365E-03 0.0 0.0 0.365E-03 I-131 0.545E-01 0.0 0.0 0.545E-01 Te-132 0.102E-02 0.0 0.0 0.102E-02 I-132 0.104E-02 0.0 0.0 0.104E-02 I-133 0.441E-03 0.0 0.0 0.441E-03 Cs-134 0.120E-02 0.0 0.0 0.120E-02 I-134 0.0 0.0 0.0 0.0 I-135 0.284E-06 0.0 0.0 0.284E-06 Cs-136 0.137E-01 0.0 0.0 0.137E-01 Cs-137 0.216E+00 0.0 0.0 0.216E+00 Ba-140 0.123E-03 0.0 0.0 0.123E-03 La-140 0.139E-03 0.0 0.0 0.139E-03 Ce-144 0.233E-04 0.0 0.0 0.233E-04 Pr-144 0.233E-04 0.0 0.0 0.233E-04
Total (excluding H-3) 0.411E+00 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.2-15 ESTIMATED ANNUAL ACTIVITY RELEASE FOR NORMAL OPERATION CASE (ONE UNIT) Turbine Bldg Condensate Polishing Radwaste System, Sump, System(a), One Unit Total, Nuclide Curies/yr Curies/yr Curies/yr Curies/yr H-3 0.129E+04 0.430E+01 0.0 0.129E+04 Cr-51 0.948E-04 0.390E-06 0.106E-02 0.126E-02 Mn-54 0.256E-04 0.645E-07 0.246E-03 0.297E-03 Fe-55 0.281E-05 0.302E-06 0.120E-03 0.788E-03 Co-58 0.116E-02 0.334E-05 0.113E-01 0.136E-01 Fe-59 0.609E-04 0.207E-06 0.644E-03 0.771E-03 Co-60 0.170E-03 0.414E-06 0.163E-02 0.197E-02 Sr-89 0.176E-04 0.565E-07 0.183E-03 0.220E-03 Sr-90 0.111E-05 0.271E-08 0.108E-04 0.130E-04 Y-90 0.115E-05 0.764E-08 0.751E-05 0.948E-05 Sr-91 0.790E-09 0.239E-07 0.607E-07 0.934E-07 Y-91 0.203E-03 0.780E-06 0.232E-02 0.276E-02 Sr-92 0.0 0.310E-08 0.0 0.339E-08 Y-92 0.0 0.207E-07 0.0 0.226E-07 Zr-95 0.464E-05 0.143E-07 0.473E-04 0.568E-04 Nb-95 0.530E-06 0.207E-07 0.720E-04 0.794E-04 Mo-99 0.412E-04 0.103E-03 0.356E-01 0.391E-01 I-131 0.431E-02 0.895E-03 0.114E+01 0.125E+01 Te-132 0.885E-04 0.668E-05 0.288E-02 0.325E-02 I-132 0.913E-04 0.191E-03 0.0 0.309E-03 I-133 0.768E-04 0.103E-02 0.371E-01 0.418E-01 Cs-134 0.975E-03 0.143E-04 0.310E-01 0.141E+00 I-134 0.0 0.263E-04 0.0 0.288E-04 I-135 0.501E-07 0.446E-03 0.162E-03 0.488E-03 Cs-136 0.712E-02 0.302E-05 0.312E-02 0.112E-01 Cs-137 0.176E-00 0.207E-04 0.452E-01 0.242E+00 Ba-140 0.120E-04 0.955E-07 0.174E-04 0.323E-04 La-140 0.136E-04 0.501E-07 0.403E-04 0.114E-03 Ce-144 0.334E-05 0.796E-08 0.317E-04 0.383E-04 Pr-144 0.334E-05 0.111E-07 0.317E-04 0.383E-04
Total (excluding H-3) 0.160E+01 (a) Resin regenerant discharge.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-16 Sheet 1 of 2 Revision 11 November 1996 ANNUAL FLOW AND ACTIVITY CONCENTRATION OF PROCESS STREAMS FOR STEAM GENERATOR BLOWDOWN SYSTEM FOR NORMAL OPERATION CASE BASED ON ORIGINAL SYSTEM DESIGN
Stream Number A B C D E
Annual Flow, gal./yr 76,300,000 0.0 42,865,000 42,865,000 0.0
Nuclide Concentration, µCi/cc H-3 0.420E-03 0.0 0.303E-03 0.303E-03 0.0 Cr-51 0.790E-07 0.0 0.102E-06 0.102E-08 0.0 Mn-54 0.130E-07 0.0 0.168E-07 0.168E-09 0.0 Fe-55 0.630E-07 0.0 0.013E-07 0.813E-09 0.0 Co-58 0.670E-06 0.0 0.864E-06 0.864E-08 0.0 Fe-59 0.420E-07 0.0 0.542E-07 0.542E-07 0.0 Co-60 0.830E-07 0.0 0.107E-06 0.107E-08 0.0 Sr-89 0.110E-07 0.0 0.142E-07 0.142E-09 0.0 Sr-90 0.550E-09 0.0 0.709E-09 0.709E-11 0.0 Y-90 0.960E-09 0.0 0.124E-08 0.124E-08 0.0 Sr-91 0.560E-08 0.0 0.722E-08 0.722E-10 0.0 Y-91 0.980E-07 0.0 0.126E-06 0.126E-06 0.0 Sr-92 0.140E-08 0.0 0.181E-08 0.181E-10 0.0 Y-92 0.280E-08 0.0 0.361E-08 0.361E-08 0.0 Zr-95 0.280E-08 0.0 0.361E-08 0.361E-10 0.0 Nb-95 0.290E-08 0.0 0.374E-08 0.374E-10 0.0 Mo-99 0.220E-04 0.0 0.284E-04 0.284E-04 0.0 I-131 0.140E-04 0.0 0.172E-04 0.172E-06 0.0 Te-132 0.140E-05 0.0 0.181E-05 0.181E-07 0.0 I-132 0.300E-05 0.0 0.368E-05 0.368E-07 0.0 I-133 0.170E-04 0.0 0.208E-04 0.208E-06 0.0 Cs-134 0.200E-05 0.0 0.258E-05 0.129E-05 0.0 I-134 0.520E-06 0.0 0.637E-06 0.637E-08 0.0 I-135 0.710E-05 0.0 0.870E-05 0.870E-07 0.0 Cs-136 0.500E-06 0.0 0.645E-06 0.322E-06 0.0 Cs-137 0.340E-05 0.0 0.439E-05 0.219E-05 0.0 Ba-140 0.190E-07 0.0 0.245E-07 0.245E-09 0.0 La-140 0.810E-08 0.0 0.104E-07 0.104E-09 0.0 Ce-144 0.170E-08 0.0 0.219E-08 0.219E-10 0.0 Pr-144 0.170E-08 0.0 0.219E-08 0.219E-10 0.0
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-16 Sheet 2 of 2 Revision 11 November 1996 Stream Number F G H I
Annual Flow, gal./yr 0.0 42,865,000 0.0 2,600,00
Nuclide Concentration, µCi/cc H-3 0.0 0.303E-03 0.0 0.540E-03 Cr-51 0.0 0.102E-08 0.0 0.490E-10 Mn-54 0.0 0.168E-09 0.0 0.810E-11 Fe-55 0.0 0.813E-09 0.0 0.380E-10 Co-58 0.0 0.864E-08 0.0 0.420E-09 Fe-59 0.0 0.542E-09 0.0 0.260E-10 Co-60 0.0 0.107E-08 0.0 0.520E-10 Sr-89 0.0 0.142E-09 0.0 0.710E-11 Sr-90 0.0 0.709E-11 0.0 0.340E-12 Y-90 0.0 0.124E-08 0.0 0.870E-12 Sr-91 0.0 0.722E-10 0.0 0.300E-11 Y-91 0.0 0.126E-06 0.0 0.890E-10 Sr-92 0.0 0.181E-10 0.0 0.390E-12 Y-92 0.0 0.361E-08 0.0 0.250E-11 Zr-95 0.0 0.361E-10 0.0 0.180E-11 Nb-95 0.0 0.374E-10 0.0 0.260E-11 Mo-99 0.0 0.284E-04 0.0 0.130E-07 I-131 0.0 0.172E-06 0.0 0.110E-06 Te-132 0.0 0.101E-07 0.0 0.840E-09 I-132 0.0 0.368E-07 0.0 0.240E-07 I-133 0.0 0.208E-06 0.0 0.130E-06 Cs-134 0.0 0.129E-05 0.0 0.180E-08 I-134 0.0 0.637E-08 0.0 0.330E-08 I-135 0.0 0.870E-07 0.0 0.560E-07 Cs-136 0.0 0.322E-06 0.0 0.380E-09 Cs-137 0.0 0.219E-05 0.0 0.260E-08 Ba-140 0.0 0.245E-09 0.0 0.120E-10 La-140 0.0 0.104E-09 0.0 0.730E-11 Ce-144 0.0 0.219E-10 0.0 0.100E-11 Pr-144 0.0 0.219E-10 0.0 0.140E-11
(a) See Figures 11.2-4 and 11.2-5 for stream number identification. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.2-17 SUMMARY OF ESTIMATED LIQUID WASTE SYSTEM ANNUAL WASTE VOLUMES FOR UNITS 1 AND 2 Total Annual Total Annual Volume, Gallons Volume, Gallons Stream (Design Basis (Normal Number(a) Case) Operation Case) Laundry, showers, handwashers 5 44,620 65,480 Chemical laboratory drains 6 10,220 15,330 Floor drain subsystem 7 21,360 -(b) Equipment drain subsystem 11 23,990 98,650 Steam generator blowdown F & H - -(c) treatment system CPS regenerant wastes - - 2,360,000 Turbine-generator building sump 1 - 5,200,000 CVCS (tritium control) 15 700,000 700,000 Total plant discharge for two units 800,190 8,439,460
(a) See Figures 11.2-2, 11.2-3, and 11.2-5.
(b) Floor drain volume included in equipment drain volume (stream 11) for treatment in normal operation case. (c) Analysis assumed no resin regeneration for steam generator blowdown treatment system.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.2-18 ESTIMATED ANNUAL LIQUID EFFLUENT RELEASE FOR NORMAL OPERATION CASE WITH ANTICIPATED OPERATIONAL OCCURRENCES (ONE UNIT) Nuclide Release, curies H-3 1.29 E+03 Cr-51 1.26 E-03 Mn-54 2.97 E-04 Fe-55 7.88 E-04 Co-58 1.36 E-02 Fe-59 7.71 E-04 Co-60 1.97 E-03 Sr-89 2.20 E-04 Sr-90 1.30 E-05 Y-90 9.48 E-06 Sr-91 9.34 E-08 Y-91 2.76 E-03 Sr-92 3.39 E-09 Y-92 2.26 E-08 Zr-95 5.68 E-05 Nb-95 7.94 E-05 Mo-99 3.91 E-02 I-131 1.25 E00 Te-132 3.25 E-03 I-132 3.09 E-04 I-133 4.18 E-02 Cs-134 1.44 E-01 I-134 2.88 E-05 I-135 4.88 E-04 Cs-136 1.12 E-02 Cs-137 2.42 E-01 Ba-140 3.23 E-05 La-140 1.14 E-04 Ce-144 3.83 E-05 Pr-144 3.83 E-05
Total (excluding H-3) 1.75 E00 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.2-19 BASIC ASSUMPTIONS FOR LIQUID PATHWAYS EXPOSURES Plant dilution flow 876000 gpm Length of plant cycle 8760.00 hr Biological and Environmental Parameters Receiving body of water Pacific Ocean Receiving water type Ocean
Dilution factor from discharge to swimming water 5.0E 00 Dilution factor from discharge to drinking water 5.0E 00 Dilution factor from discharge to fish 5.0E 00 Dilution factor from discharge to invertebrates 5.0E 00 Dilution factor from discharge to aquatic plants 5.0E 00
Decay time from environment to water = 5.0E-01 Fish = 1.0E 00 Invertebrates = 1.0E 00 Aquatic Plants = 1.0E 00 Consumption by Man, days
Decay time from discharge to sediment, days = 1.00E 00 Accumulation time for sediment activity, days = 1.10E 04
Food Consumption Rates, kg/yr Exposure Time Hours/Year Age Group Water Fish Invertebrates Aquatic Plants Swimming Shore
Adult 0.0 2.10E 01 5.00E 00 0.0 5.20E 01 1.20E 01 Teenager 0.0 1.60E 01 3.80E 00 0.0 5.20E 01 6.70E 01 Child 0.0 6.90E 00 1.70E 00 0.0 2.90E 01 1.40E 01 Infant 0.0 0.0 0.0 0.0 0.0 0.0
DCPP UNITS 1 & 2 FSAR UPDATE Revision 12 September 1998 TABLE 11.2-20 BIOACCUMULATION FACTORS Nuclide Fish Inverteb. Aq. Plants H-3 9.00E-01 9.30E-01 9.30E-01 Cr-51 4.00E 02 2.00E 03 2.00E 03 Mn-54 5.50E 02 4.00E 02 5.50E 03 Fe-55 3.00E 03 2.00E 04 7.30E 02 Co-58 1.00E 02 1.00E 03 1.00E 03 Fe-59 3.00E 03 2.00E 04 7.30E 02 Co-60 1.00E 02 1.00E 03 1.00E 03 Sr-89 2.00E 00 2.00E 01 1.00E 01 Sr-90 2.00E 00 2.00E 01 1.00E 01 Y-90 2.50E 01 1.00E 03 5.00E 03 Sr-91 2.00E 00 2.00E 01 1.00E 01 Y-91 2.50E 01 1.00E 03 5.00E 03 Sr-92 2.00E 00 2.00E 01 1.00E 01 Y-92 2.50E 01 1.00E 03 5.00E 03 Zr-95 2.00E 02 8.00E 01 1.00E 03 Nb-95 3.00E 04 1.00E 02 5.00E 02 Mo-99 1.00E 01 1.00E 01 1.00E 01 I-131 1.00E 01 5.00E 01 1.00E 03 Te-132 1.00E 01 1.00E 02 1.00E 03 I-132 1.00E 01 5.00E 01 1.00E 03 I-133 1.00E 01 5.00E 01 1.00E 03 Cs-134 4.00E 01 2.50E 01 5.00E 01 I-134 1.00E 01 5.00E 01 1.00E 03 I-135 1.00E 01 5.00E 01 1.00E 03 Cs-136 4.00E 01 2.50E 01 5.00E 01 Cs-137 4.00E 01 2.50E 01 5.00E 01 Ba-140 1.00E 01 1.00E 02 5.00E 02 La-140 2.50E 01 1.00E 03 5.00E 03 Ce-144 1.00E 01 6.00E 02 6.00E 02 Pr-144 2.50E 01 1.00E 03 5.00E 03 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-21 Sheet 1 of 2 Revision 11 November 1996 EFFLUENT CONCENTRATIONS AFTER INITIAL DILUTION: DESIGN BASIS CASE Nuclide Release Rate(a), Ci/yr Average Yearly Concentration in Discharge, µCi/cc H-3 1.35E+03 7.75E-07 Cr-51 9.60E-05 5.51E-14 Mn-54 2.13E-05 1.22E-14 Fe-55 3.27E-06 1.88E-15 Co-58 1.04E-03 5.97E-13 Fe-59 5.74E-05 3.29E-14 Co-60 1.41E-04 8.09E-14 Sr-89 1.39E-04 7.98E-14 Sr-90 7.97E-06 4.57E-15 Y-90 7.81E-06 4.48E-15 Sr-91 4.53E-09 2.60E-18 Y-91 1.73E-03 9.93E-13 Sr-92 3.39E-15 1.95E-24 Y-92 8.72E-15 5.00E-24 Zr-95 3.51E-05 2.01E-14 Nb-95 3.97E-05 2.28E-14 Mo-99 3.65E-04 2.09E-13 I-131 5.45E-02 3.13E-1 Te-132 1.02E-03 5.85E-13 I-132 1.09E-03 5.97E-13 I-133 4.41E-04 2.53E-13
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-21 Sheet 2 of 2 Revision 11 November 1996 Nuclide Release Rate(a), Ci/yr Average Yearly Concentration in Discharge, µCi/cc Cs-134 1.20E-01 6.89E-11 I-134 0.0 0.0 I-135 2.84E-07 1.63E-16 Cs-136 1.37E-02 7.86E-12 Cs-137 2.16E-01 1.24E-10 Ba-140 1.23E-04 7.06E-14 La-140 1.39E-04 7.98E-14 Ce-144 2.33E-05 1.34E-14 Pr-144 2.33E-05 1.34E-14
Totals 1.35E+03 7.75E-07 Totals excluding H-3 4.11E-01 2.36E-10 (a) One unit
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.2-22 EFFLUENT CONCENTRATIONS AFTER INITIAL DILUTION: NORMAL OPERATION CASE
Nuclide Release Rate(a), Ci/yr Average Yearly Concentration in Discharge, µCi/cc H-3 1.29E+03 7.42E-07 Cr-51 1.16E-03 6.66E-13 Mn-54 2.72E-04 1.56E-13 Fe-55 1.23E-04 7.06E-14 Co-58 1.25E-02 7.17E-12 Fe-59 7.05E-04 4.05E-13 Co-60 1.80E-03 1.13E-12 Sr-89 2.01E-04 1.15E-13 Sr-90 1.19E-05 6.83E-15 Y-90 8.67E-06 4.97E-15 Sr-91 8.54E-08 4.90E-17 Y-91 2.52E-03 1.45E-12 Sr-92 0.31E-08 1.78E-18 Y-92 0.21E-07 1.20E-17 Zr-95 5.20E-05 2.98E-14 Nb-95 7.26E-05 4.17E-14 Mo-99 3.57E-02 2.05E-11 I-131 1.15E-00 6.60E-10 I-132 2.82E-04 1.62E-13 I-133 3.82E-02 2.19E-11 Cs-134 1.29E-01 7.40E-11 I-134 0.26E-04 1.49E-14 I-135 6.08E-04 3.49E-13 Cs-136 1.02E-02 5.85E-12 Cs-137 2.21E-01 1.27E-10 Ba-140 2.95E-05 1.69E-14 La-140 1.04E-04 5.97E-14 Ce-144 3.51E-05 2.01E-14 Pr-144 3.51E-05 2.01E-14
Totals 1.29E+03 7.42E-07 Totals excluding H-3 1.60E+00 9.24E-10
(a) One unit
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.2-23 EFFLUENT CONCENTRATIONS AFTER INITIAL DILUTION: NORMAL OPERATION WITH ANTICIPATED OPERATIONAL OCCURRENCES
Nuclide Release Rate(a), Ci/yr Average Yearly Concentration in Discharge, µCi/cc H-3 1.29E+03 7.42E-07 Cr-51 1.26E-03 7.23E-13 Mn-54 2.99E-04 1.70E-13 Fe-55 7.88E-04 4.52E-13 Co-58 1.36E-02 7.80E-12 Fe-59 7.71E-04 4.42E-13 Co-60 1.97E-03 1.13E-12 Sr-89 2.20E-04 1.26E-13 Sr-90 1.30E-05 7.46E-15 Y-90 9.48E-06 5.44E-15 Sr-91 9.34E-08 5.36E-17 Y-91 2.76E-03 1.58E-12 Sr-92 3.39E-09 1.95E-18 Y-92 2.26E-08 1.30E-17 Zr-95 5.68E-05 3.26E-14 Nb-95 7.94E-05 4.56E-14 Mo-99 3.91E-02 2.24E-11 I-131 1.25E+00 7.17E-10 Te-132 3.25E-03 1.86E-12 I-132 3.09E-04 1.77E-13 I-133 4.18E-02 2.40E-10 Cs-134 1.41E-01 8.09E-11 I-134 2.88E-05 1.65E-14 I-135 4.88E-04 2.80E-13 Cs-136 1.12E-02 6.43E-12 Cs-137 2.42E-01 1.39E-10 Ba-140 3.23E-05 1.85E-14 La-140 1.14E-04 6.54E-14 Ce-144 3.83E-05 2.20E-14 Pr-144 3.83E-05 2.20E-14
Totals 1.29E+03 7.43E-07 Totals excluding H-3 1.75E+00 2.64E-03
(a) One unit
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-24 Sheet 1 of 2 Revision 11 November 1996 DOSES RESULTING FROM RADIOACTIVE RELEASES IN LIQUID WASTES: DESIGN BASIS CASE (mrem/yr) Age Group = Adult
Exposure Pathway Whole Body Skin Bone GI Tract Thyroid Lung Kidney Liver Drinking water 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Consumption of fish 7.22E-3 0.0 2.39E-3 4.30E-4 2.56E-3 7.51E-4 1.66E-3 4.33E-3 Consumption of invertebrates 5.17E-4 0.0 3.65E-4 2.09E-4 2.76E-3 1.43E-4 2.90E-4 6.89E-4 Consumption of aquatic plants 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Exposure to contaminated sediment 4.18E-4 4.87E-4 0.0 0.0 0.0 0.0 0.0 0.0 Swimming in water 4.67E-6 5.39E-5 0.0 0.0 0.0 0.0 0.0 0.0
Total 4.16E-4 5.41E-4 2.76E-3 6.39E-4 5.31E-3 8.94E-4 1.95E-3 5.02E-3
Age Group = Teenager
Drinking water 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Consumption of fish 1.89E-3 0.0 2.53E-3 3.27E-4 2.34E-3 7.63E-4 1.62E-3 4.38E-3 Consumption of invertebrates 3.12E-4 0.0 3.85E-4 1.61E-4 2.56E-3 1.38E-4 2.77E-4 6.87E-4 Consumption of aquatic plants 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Exposure to contaminated sediment 2.33E-3 2.72E-3 0.0 0.0 0.0 0.0 0.0 0.0 Swimming in water 4.67E-6 5.39E-5 0.0 0.0 0.0 0.0 0.0 0.0
Total 4.54E-3 2.77E-3 2.91E-3 4.88E-4 4.89E-3 9.01E-4 1.90E-3 5.06E-3
Age Group = Child
Drinking water 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Consumption of fish 8.42E-4 0.0 3.14E-3 2.30E-4 2.37E-3 6.11E-4 1.37E-3 3.83E-3 Consumption of invertebrates 1.58E-4 0.0 4.96E-4 9.23E-5 2.72E-3 1.15E-4 2.43E-4 6.22E-4 Consumption of aquatic plants 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Exposure to contaminated sediment 4.87E-4 5.68E-4 0.0 0.0 0.0 0.0 0.0 0.0 Swimming in water 2.60E-6 3.01E-5 0.0 0.0 0.0 0.0 0.0 0.0
Total 1.49E-3 5.98E-4 3.64E-3 3.22E-4 5.09E-3 7.27E-4 1.61E-3 4.45E-3
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-24 Sheet 2 of 2 Revision 11 November 1996 Age Group = Infant Exposure Pathway Whole Body Skin Bone GI Tract Thyroid Lung Kidney Liver Drinking water 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Consumption of fish 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Consumption of invertebrates 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Consumption to aquatic plants 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Exposure to contaminated sediment 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Swimming in water 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Total 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-25 Sheet 1 of 2 Revision 11 November 1996 DOSES RESULTING FROM RADIOACTIVE RELEASES IN LIQUID WASTES: NORMAL OPERATION CASE (mrem/yr) Age Group = Adult
Exposure Pathway Whole Body Skin Bone GI Tract Thyroid Lung Kidney Liver Drinking water 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Consumption of fish 3.49E-3 0.0 2.61E-3 8.36E-4 4.77E-2 7.74E-4 1.94E-3 4.77E-3 Consumption of invertebrates 6.74E-4 0.0 5.48E-4 7.66E-4 5.65E-2 1.72E-4 5.79E-4 1.11E-3 Consumption of aquatic plants 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Exposure to contaminated sediment 4.36E-4 5.09E-4 0.0 0.0 0.0 0.0 0.0 0.0 Swimming in water 1.03E-5 5.88E-5 0.0 0.0 0.0 0.0 0.0 0.0
Total 4.56E-3 5.68E-4 3.16E-3 1.60E-3 1.04E-1 9.46E-4 2.52E-3 5.88E-3
Age Group = Teenager
Drinking water 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Consumption of fish 2.06E-3 0.0 2.76E-3 5.83E-4 4.45E-2 7.96E-4 1.92E-3 4.75E-3 Consumption of invertebrates 4.61E-4 0.0 5.78E-4 5.05E-4 5.26E-2 1.73E-4 5.81E-4 9.82E-4 Consumption of aquatic plants 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Exposure to contaminated sediment 2.44E-3 2.84E-3 0.0 0.0 0.0 0.0 0.0 0.0 Swimming in water 1.03E-5 5.88E-5 0.0 0.0 0.0 0.0 0.0 0.0
Total 4.97E-3 2.90E-3 3.34E-3 1.09E-3 9.71E-2 9.69E-4 2.50E-3 5.73E-3
Age Group = Child Drinking water 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Consumption of fish 9.64E-4 0.0 3.43E-3 3.19E-4 4.59E-2 6.37E-4 1.636-3 4.16E-3 Consumption of invertebrates 3.07E-4 0.0 7.49E-4 2.23E-4 5.63E-2 1.45E-4 5.17E-4 8.95E-4 Consumption of aquatic plants 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Exposure to contaminated sediment 5.09E-4 5.94E-4 0.0 0.0 0.0 0.0 0.0 0.0 Swimming in water 5.74E-6 3.28E-5 0.0 0.0 0.0 0.0 0.0 0.0
Total 1.79E-3 6.27E-4 4.18E-3 5.42E-4 1.02E-1 7.82E-4 2.15E-3 5.05E-3 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-25 Sheet 2 of 2 Revision 11 November 1996 Age Group = Infant Exposure Pathway Whole Body Skin Bone GI Tract Thyroid Lung Kidney Liver Drinking water 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Consumption of fish 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Consumption of invertebrates 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Consumption of aquatic plants 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Exposure to contaminated sediment 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Swimming in water 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Total 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-26 Sheet 1 of 2 Revision 11 November 1996 DOSES RESULTING FROM RADIOACTIVE RELEASES IN LIQUID WASTES: NORMAL OPERATIONAL WITH ANTICIPATED OPERATIONAL OCCURRENCES (mrem/yr) Age Group = Adult
Exposure Pathway Whole Body Skin Bone GI Tract Thyroid Lung Kidney Liver Drinking water 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Consumption of fish 3.74E-3 0.0 2.86E-3 8.86E-4 5.20E-2 8.20E-4 2.10E-3 5.20E-3 Consumption of invertebrates 7.32E-4 0.0 6.00E-4 8.30E-4 6.16E-2 1.82E-4 6.26E-4 1.21E-3 Consumption of aquatic plants 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Exposure to contaminated sediment 4.78E-4 5.58E-4 0.0 0.0 0.0 0.0 0.0 0.0 Swimming in water 1.13E-5 5.99E-5 0.0 0.0 0.0 0.0 0.0 0.0
Total 4.96E-3 6.18E-4 3.46E-3 1.72E-3 1.14E-1 1.00E-1 2.73E-3 6.41E-3
Age Group = Teenager
Drinking water 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Consumption of fish 2.23E-3 0.0 3.02E-3 6.17E-4 4.85E-2 8.51E-4 2.08E-3 5.18E-3 Consumption of invertebrates 4.99E-4 0.0 6.32E-4 5.47E-4 5.74E-2 1.85E-4 6.31E-4 1.07E-3 Consumption of aquatic plants 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Exposure to contaminated sediment 2.67E-3 3.11E-3 0.0 0.0 0.0 0.0 0.0 0.0 Swimming in water 1.13E-5 5.99E-5 0.0 0.0 0.0 0.0 0.0 0.0
Total 5.41E-3 3.17E-3 3.66E-3 1.16E-3 1.06E-1 1.04E-3 2.71E-3 6.25E-3
Age Group = Child Drinking water 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Consumption of fish 1.04E-3 0.0 3.76E-3 3.32E-4 5.01E-2 6.80E-4 1.77E-3 4.54E-3 Consumption of invertebrates 3.31E-4 0.0 8.19E-4 2.40E-4 6.15E-2 1.54E-4 5.61E-4 9.75E-4 Consumption of aquatic plants 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Exposure to containment sediment 5.58E-4 6.51E-4 0.0 0.0 0.0 0.0 0.0 0.0 Swimming in water 6.28E-6 3.34E-5 0.0 0.0 0.0 0.0 0.0 0.0
Total 1.95E-3 6.84E-4 4.58E-3 5.71E-4 1.12E-1 8.34E-4 2.33E-4 5.51E-3 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.2-26 Sheet 2 of 2 Revision 11 November 1996 Age Group = Infant Exposure Pathway Whole Body Skin Bone GI Tract Thyroid Lung Kidney Liver Drinking water 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Consumption of fish 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Consumption of invertebrates 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Consumption of aquatic plants 0.0 -- 0.0 0.0 0.0 0.0 0.0 0.0 Exposure to contaminated sediment 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Swimming in water 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Total 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.3-1 Sheet 1 of 2 Revision 12 September 1998 EQUIPMENT DESIGN AND OPERATING PARAMETERS FOR GASEOUS RADWASTE SYSTEM, UNITS 1 AND 2 1. Waste Gas Compressor Number used: 3; 1 each unit, 1 shared Type: horizontal, centrifugal compressor Temperature: 70°F - 130°F Inlet pressure: 0.5 psig - 2.0 psig Capacity: 40 cfm at inlet pressure 2.0 psig and discharge pressure 110 psig Cooling water rate: 42.5 gpm Driver: 25 hp 2. Surge Tank Number used: 2; 1 each unit Type: horizontal Size: 18' x 1' Volume: 14 ft3 Design pressure: 405 psig/Design temperature: 650°F Operating maximum pressure: 10 psig Material: ASTM A106 Carbon Steel (PG&E pipe specification K2) 3. Gas Decay Tank Number used: 6; 3 each unit Type: vertical Size: 13' x 8' Volume: 705 ft3 Design temperature: 150°F
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.3-1 Sheet 2 of 2 Revision 12 September 1998 3. Gas Decay Tank (continued) Design pressure: 150 psig Operating maximum pressure: 105 psig Material: SA285C, carbon steel Design as per ASME Boiler and Pressure Vessel Code, Section III, Class C 4. Waste Gas Analyzer Number used: 2; 1 each unit Oxygen analyzer: Range: 0-5% (+/-2% of full range) Alarm: 2% oxygen Hydrogen analyzer: Range: 0-5% (+/-2% of full range) 0-50% (+/-2% of full range) 0-100% (+/-2% of full range) Alarm: 3.5% hydrogen Sample channel: 16 5. Discharge filter Number used: 2; 1 each unit Type: HEPA filter Size: 8" x 8" x 5-7/8" Efficiency: 99.97% on 0.3 micron particles Capacity: 55 cfm at 1" water gauge differential DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-2 GASEOUS WASTE SYSTEM RELEASE: DESIGN BASIS CASE (CURIES) Gas Decay Steam Condenser Auxiliary Spent Secondary Tank Containment System Offgas Building Fuel Pool System Water Total Nuclide Venting Venting Leakage Venting Venting Release Leakage Release Kr- 83M 0.0 0.0 0.0 0.0 0.0 0.197E-19 --- 0.197E-19 Kr- 85M 0.0 0.0 0.0 0.0 0.0 0.224E-09 --- 0.224E-09 Kr- 85 0.505E 04 0.0 0.0 0.0 0.0 0.538E-01 --- 0.505E 04 Kr- 87 0.0 0.0 0.0 0.0 0.0 0.169E-26 --- 0.169E-26 Kr- 88 0.0 0.0 0.0 0.0 0.0 0.360E-13 --- 0.360E-13 Xe-133M 0.210E-02 0.0 0.0 0.0 0.0 0.127E-02 --- 0.337E-02 Xe-133 0.411E 03 0.0 0.0 0.0 0.0 0.189E 00 --- 0.411E 03 Xe-135M 0.482E-46 0.0 0.0 0.0 0.0 0.668E-07 --- 0.668E-07 Xe-135 0.262E-31 0.0 0.0 0.0 0.0 0.276E-06 --- 0.276E-04 Xe-138 0.0 0.0 0.0 0.0 0.0 0.0 --- 0.0
I -131 --- 0.0 0.0 0.0 0.0 0.112E-04 0.0 0.112E-04 I -132 --- 0.0 0.0 0.0 0.0 0.167E-05 0.0 0.167E-05 I -133 --- 0.0 0.0 0.0 0.0 0.194E-06 0.0 0.194E-06 I -134 --- 0.0 0.0 0.0 0.0 0.310E-08 0.0 0.310E-08 I -135 --- 0.0 0.0 0.0 0.0 0.177E-07 0.0 0.177E-07 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.3-3 Sheet 1 of 2 Revision 11 November 1996 GASEOUS WASTE SYSTEM RELEASE: NORMAL OPERATION CASE (CURIES) Gas Decay Condenser Auxiliary Spent Steam Secondary Tank Containment Offgas Building Fuel Pool System System Water Total Nuclide Venting Venting Venting Venting Release Leakage Leakage Release Kr - 83 0.0 0.287E 00 0.169E 00 0.110E-01 0.236E-20 0.615E-04 --- 0.156E 01 Kr - 85M 0.0 0.350E 01 0.145E-01 0.567E 01 0.269E-10 0.317E-03 --- 0.106E 02 Kr - 85 0.439E 03 0.443E 03 0.624E 01 0.100E 02 0.654E-02 0.558E-03 --- 0.898E 03 Kr - 87 0.0 0.554E 00 0.361E 00 0.311E 01 0.203E-27 0.174E-03 --- 0/402E 01 Kr - 88 0.0 0.378E 01 0.193E 01 0.972E 01 0.432E-14 0.543E-03 --- 0.154E 02 Xe - 133M 0.244E-03 0.721E 02 0.433E 01 0.931E 01 0.152E-03 0.521E-03 --- 0.858E 02 Xe - 133 0.434E 02 0.118E 05 0.367E 03 0.760E 03 0.227E-01 0.424E-01 --- 0.129E 05 Xe - 135M 0.577E-47 0.920E 00 0.254E 00 0.122E 01 0.001E-08 0.486E-03 --- 0.239E 01 Xe - 135 0.313E-32 0.280E 02 0.626E-01 0.170E 02 0.331E-05 0.102E-02 --- 0.513E 02 Xe - 138 0.0 0.530E-01 0.432E-01 0.165E 01 0.0 0.919E-04 --- 0.174E 01 I - 131 --- 0.336E-01 0.312E-01 0.637E-01 0.859E-05 0.630E-03 0.897E-06 0.129E 00 I - 132 --- 0.188E 00 0.418E-02 0.230E-01 0.752E-06 0.134E-03 0.191E-06 0.215E 00 I - 133 --- 0.685E-02 0.363E-01 0.872E-01 0.165E-06 0.751E-03 0.106E-05 0.131E 00 I - 134 --- 0.378E-04 0.999E-03 0.117E-01 0.310E-08 0.234E-04 0.266E-07 0.127E-01 I - 135 --- 0.121E-02 0.148E-01 0.482E-01 0.177E-07 0.318E-03 0.441E-06 0.645E-01 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.3-3 Sheet 2 of 2 Revision 11 November 1996 Total Nuclide Release H - 3 0.33E 03 Cr - 51 0.0 Mn - 54 0.44E-01 Fe - 55 0.0 Co - 58 0.15E-00 Fe - 59 0.15E-01 Co - 60 0.68E-01 Sr - 89 0.33E-02 Sr - 90 0.56E-03 Y - 90 0.0 Sr - 91 0.0 Y - 91 0.0 Sr - 92 0.0 Y - 92 0.0 Zr - 95 0.0 Nb - 95 0.0 Mo - 99 0.0 Te - 132 0.0 Cs - 134 0.44E-01 Cs - 136 0.0 Cs - 137 0.75E-01 Ba - 140 0.0 La - 140 0.0 Ce - 144 0.0 Pr - 144 0.0 C - 14 0.80E 01 DCPP UNITS 1 & 2 FSAR UPDATE Revision 20 November 2011 TABLE 11.3-4 ANNUAL GASEOUS RADWASTE FLOWS (Standard Cubic Feet Per Year) Source Flow Liquid holdup tanks: Displaced 60,300 Recycled 15,300 45,000 Volume control tank 19,000 Boric acid gas stripper(b) 7,400 Reactor coolant drain tank 250 Pressurizer relief tank 350 Nitrogen added to gas decay tanks 28,000 Total annual discharge 100,000(a)
(a) Assumes: 1. Two cold shutdowns per year
- 2. Base loaded plant operation
- 3. Hydrogen controlled to less than 4%
(b) Equipment is abandoned in place and no longer in use.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-5 MAXIMUM ACTIVITY IN GAS DECAY TANK: DESIGN BASIS CASE Nuclide Activity, Ci Concentration, µCi/cc Kr-83M 0.894E 02 0.421E 01 Kr-85M 0.462E 03 0.217E 02 Kr-85 0.160E 04 0.754E 02 Kr-87 0.252E 03 0.119E 02 Kr-88 0.790E 03 0.372E 02 Xe-133M 0.798E 03 0.376E 02 Xe-133 0.693E 05 0.326E 04 Xe-135M 0.988E 02 0.465E 01 Xe-135 0.139E 04 0.656E 02 Xe-138 0.133E 03 0.628E 01 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-6 MAXIMUM ACTIVITY IN GAS DECAY TANK: NORMAL OPERATION CASE Nuclide Activity, Ci Concentration, µCi/cc Kr-83M 0.107E 02 0.505E 00 Kr-85M 0.553E 02 0.260E 01 Kr-85 0.130E 03 0.612E 01 Kr-87 0.302E 02 0.142E 01 Kr-88 0.946E 02 0.445E 01 Xe-133M 0.928E 02 0.437E 01 Xe-133 0.778E 04 0.366E 03 Xe-135M 0.119E 02 0.558E 00 Xe-135 0.166E 03 0.783E 01 Xe-138 0.160E 02 0.753E 00
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-7 ACTIVITY IN VOLUME CONTROL TANK: DESIGN BASIS CASE Liquid Phase Vapor Phase Nuclide Activity, Ci Concentration, µCi/cc Activity, Ci Concentration, µCi/cc Total Act, Ci H - 3 0.497E 01 0.732E 00 0.0 0.0 0.497E 01 Cr- 51 0.935E-02 0.138E-02 0.0 0.0 0.935E-02 Mn- 54 0.152E-02 0.224E-03 0.0 0.0 0.152E-02 Fe- 55 0.773E-02 0.114E-02 0.0 0.0 0.773E-02 Co- 58 0.785E-01 0.115E-01 0.0 0.0 0.785E-01 Fe- 59 0.491E-02 0.722E-03 0.0 0.0 0.491E-02 Co- 60 0.976E-02 0.144E-02 0.0 0.0 0.976E-02 Kr- 83M 0.0 0.0 0.495E 00 0.109E 00 0.495E 00 Kr- 85M 0.0 0.0 0.276E 01 0.609E 00 0.276E 01 Kr- 85 0.0 0.0 0.657E 01 0.145E 01 0.657E 01 Kr- 87 0.0 0.0 0.132E 01 0.291E 00 0.132E 01 Kr- 88 0.0 0.0 0.456E 01 0.101E 01 0.456E 01 Sr- 89 0.112E-01 0.165E-02 0.0 0.0 0.112E-01 Sr- 90 0.538E-03 0.792E-04 0.0 0.0 0.538E-03 Y - 90 0.928E-03 0.137E-03 0.0 0.0 0.928E-03 Sr- 91 0.710E-02 0.104E-02 0.0 0.0 0.710E-02 Y - 91 0.955E-01 0.140E-01 0.0 0.0 0.955E-01 Sr- 92 0.271E-02 0.398E-03 0.0 0.0 0.271E-02 Y - 92 0.374E-02 0.550E-03 0.0 0.0 0.374E-02 Zr- 95 0.278E-02 0.410E-03 0.0 0.0 0.278E-02 Nb- 95 0.271E-02 0.398E-03 0.0 0.0 0.271E-02 Mo- 99 0.223E 02 0.328E 01 0.0 0.0 0.223E 02 I -131 0.132E 02 0.194E 01 0.0 0.0 0.132E 02 Te-132 0.139E 01 0.204E 00 0.0 0.0 0.139E 01 I -132 0.441E 01 0.649E 00 0.0 0.0 0.441E 01 I -133 0.178E 02 0.262E 01 0.0 0.0 0.178E 02 Xe-133M 0.213E-02 0.314E-03 0.493E 01 0.109E 01 0.493E 01 Xe-133 0.378E-01 0.556E-02 0.416E 03 0.919E 02 0.416E 03 Cs-134 0.932E 00 0.137E 00 0.0 0.0 0.932E 00 I -134 0.183E 01 0.269E 00 0.0 0.0 0.183E 01 I -135 0.957E 01 0.141E 01 0.0 0.0 0.957E 01 Xe-135M 0.715E 00 0.105E 00 0.304E 00 0.672E-01 0.102E 01 Xe-135 0.260E 00 0.382E-01 0.858E 01 0.189E 01 0.884E 01 Cs-136 0.252E 00 0.371E 01 0.0 0.0 0.252E 00 Cs-137 0.167E 01 0.246E 00 0.0 0.0 0.167E 01 Xe-138 0.0 0.0 0.388E 00 0.857E-01 0.388E 00 Ba-140 0.190E-01 0.279E-02 0.0 0.0 0.190E-01 La-140 0.678E-02 0.998E-03 0.0 0.0 0.678E-02 Ce-144 0.164E-02 0.241E-03 0.0 0.0 0.164E-02 Pr-144 0.164E-02 0.241E-03 0.0 0.0 0.164E-02
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-8 ACTIVITY IN VOLUME CONTROL TANK: NORMAL OPERATION CASE Liquid Phase Vapor Phase Nuclide Activity, Ci Concentration, µCi/cc Activity, Ci Concentration, µCi/cc Total Act, Ci H - 3 0.470E 01 0.692E 00 0.0 0.0 0.470E 01 CR- 51 0.934E-02 0.137E-02 0.0 0.0 0.934E-02 Mn- 54 0.152E-02 0.224E-03 0.0 0.0 0.152E-02 Fe- 55 0.772E-02 0.114E-02 0.0 0.0 0.772E-02 Co- 58 0.784E-01 0.115E-01 0.0 0.0 0.784E-01 Fe- 59 0.490E-02 0.772E-03 0.0 0.0 0.490E-02 Co- 60 0.975E-02 0.144E-02 0.0 0.0 0.975E-02 Kr- 83M 0.0 0.0 0.594E-01 0.131E-01 0.594E-01 Kr- 85M 0.0 0.0 0.330E 00 0.729E-01 0.330E 00 Kr- 85 0.0 0.0 0.619E 00 0.137E 00 0.619E 00 Kr- 87 0.0 0.0 0.158E 00 0.349E-01 0.158E 00 Kr- 88 0.0 0.0 0.547E 00 0.121E 00 0.547E 00 Sr- 89 0.134E-02 0.198E-03 0.0 0.0 0.134E-02 Sr- 90 0.646E-04 0.950E-05 0.0 0.0 0.646E-04 Y - 90 0.111E-03 0.163E-04 0.0 0.0 0.111E-03 Sr- 91 0.851E-03 0.125E-03 0.0 0.0 0.851E-03 Y - 91 0.111E-01 0.164E-02 0.0 0.0 0.111E-01 Sr- 92 0.325E-03 0.478E-04 0.0 0.0 0.325E-03 Y - 92 0.448E-03 0.660E-04 0.0 0.0 0.448E-03 Zr- 95 0.334E-03 0.491E-04 0.0 0.0 0.334E-03 Nb- 95 0.325E-03 0.477E-04 0.0 0.0 0.325E-03 Mo- 99 0.267E 01 0.392E 00 0.0 0.0 0.267E 01 I -131 0.158E 01 0.233E 00 0.0 0.0 0.158E 01 Te-132 0.166E 00 0.245E-01 0.0 0.0 0.166E 00 I -132 0.529E 00 0.779E-01 0.0 0.0 0.529E 00 I -133 0.214E 01 0.315E 00 0.0 0.0 0.214E 01 Xe-133M 0.256E-03 0.376E-04 0.573E 00 0.127E 00 0.574E 00 Xe-133 0.453E-02 0.667E-03 0.469E 02 0.104E 02 0.469E 02 Cs-134 0.113E 00 0.166E-01 0.0 0.0 0.113E 00 I -134 0.219E 00 0.323E-01 0.0 0.0 0.219E 00 I -135 0.115E 01 0.169E 00 0.0 0.0 0.115E 01 Xe-135M 0.858E-01 0.126E-01 0.365E-01 0.806E-02 0.122E 00 Xe-135 0.311E-01 0.458E-02 0.102E 01 0.226E 00 0.105E 01 Cs-136 0.303E-01 0.445E-02 0.0 0.0 0.303E-01 Cs-137 0.200E 00 0.295E-01 0.0 0.0 0.200E 00 Xe-138 0.00 0.0 0.466E-01 0.103E-01 0.446E-01 Ba-140 0.227E-02 0.335E-03 0.0 0.0 0.227E-02 La-140 0.813E-03 0.120E-03 0.0 0.0 0.813E-03 Ce-144 0.197E-03 0.289E-04 0.0 0.0 0.197E-03 Pr-144 0.197E-03 0.289E-04 0.0 0.0 0.197E-03
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-9 GASEOUS RELEASES DUE TO COLD SHUTDOWN AND STARTUPS (Released from Condenser)
Nuclide Released, Ci Fraction of Total Annual Release Kr-83m 1.89E-8 1.21E-8 Kr-85m 2.91E-5 2.75E-6 Kr-85 4.32E-3 4.75E-6 Kr-87 6.36E-10 1.58E-10 Kr-88 4.14E-6 2.69E-7 I-131(a) 4.32E-5 3.32E-4 I-132(a) 7.69E-9 2.79E-7 I-133(a) 2.51E-5 1.90E-4 Xe-133m 2.80E-3 3.29E-5 Xe-133 2.80E-1 2.17E-5 I-134(a) 7.34E-15 5.73E-13 I-135(a) 1.98E-6 3.06E-5 Xe-135m 1.89E-5 1.20E-5 Xe-135 1.20E-3 2.63E-5 Xe-138 0.0 0.0
Totals 2.89E-1 6.54E-4 (a) Volatile form only.
Notes: Beta air dose at 0.5 miles NW of plant = 1.55E-5 mrem/yr Gamma air dose at 0.5 miles NW of plant = 5.12E-6 mrem/yr DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-10 DISTANCES IN MILES FROM DCPP UNIT 1 REACTOR CENTERLINE TO THE NEAREST MILK COW, MEAT ANIMAL, MILK GOAT, RESIDENCE, VEGETABLE GARDEN, AND SITE BOUNDARY 22-1/2° Radial Sectors(a) Nearest NW NNW N NNE NE ENE E ESE SE Milk cow None(b) None None None None None None None None Meat animal 0.5 0.5 0.5 0.5 0.5 0.7 1.0 1.0 1.1
Milk goat None None None None None None None None None Residence None 1.5 None None None 4.5 None None None Vegetable garden 3.6 3.6 None None None None None 3.7 3.7
Site boundary 0.5 0.5 0.5 0.5 0.5 0.7 1.0 1.0 1.1
(a) Sectors not shown contain no land beyond the site boundary, other than islets not used for the purposes indicated in this table. (b) None within 5 miles, typical of other places where "None" is used.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-11 ESTIMATES OF RELATIVE CONCENTRATION (/Q)(a) AT LOCATIONS SPECIFIED IN TABLE 11.3-10
22-1/2° Radial Sectors Nearest NW NNW N NNE NE ENE E ESE SE Milk cow None None None None None None None None None
Meat animal 1.58X10-6 8.67X10-7 4.93X10-7 2.44X10-7 1.62X10-7 9.18X10-8 1.07X10-7 5.20X10-7 1.32X10-6 Milk goat None None None None None None None None None
Residence None 3.30X10-7 None None None 1.40X10-8 None None None Vegetable garden 1.50X10-7 1.50X10-7 None None None None None 1.00X10-7 1.00X10-7 Site boundary 1.58X10-6 8.67X10-7 4.93X10-7 2.44X10-7 1.62X10-7 9.18X10-8 1.07X10-7 5.20X10-7 1.32X10-6 (a) In units of seconds per cubic meter.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-12 ESTIMATES OF DEPOSITION (/Q)(a) AT LOCATIONS SPECIFIED IN TABLE 11.3-10 22-1/2° Radial Sectors Nearest NW NNW N NNE NE ENE E ESE SE Milk cow None None None None None None None None None
Meat animal 2.54X10-8 1.33X10-8 5.50X10-9 3.27X10-9 4.13X10-9 1.77X10-9 1.65X10-9 8.47X10-9 2.90X10-8 Milk goat None None None None None None None None None
Residence None 2.08X10-9 None None None 6.49X10-11 None None None Vegetable garden 8.13X10-10 4.27X10-10 None None None None None 7.91X10-10 3.20X10-9 Site boundary 2.54X10-8 1.33X10-8 5.50X10-9 3.27X10-9 4.13X10-9 1.77X10-9 1.65X10-9 8.47X10-9 2.90X10-8 (a) In units of meters-2, includes sector width and frequency of winds in each sector.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.3-13 Sheet 1 of 2 Revision 11 November 1996 ANNUAL AVERAGE ATMOSPHERIC ACTIVITY CONCENTRATIONS AT SITE BOUNDARY FOR DESIGN BASIS CASE (µCi/cc) Sector Nuclide NW NNW N NNE NE ENE E ESE SE I-135 7.633E-22 4.189E-22 2.382E-22 1.179E-22 7.826E-23 4.277E-23 4.806E-23 2.336E-22 5.864E-22 H-3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Cr-51 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Mn-54 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Fe-55 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Co-58 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Fe-59 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Co-60 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Kr-83M 9.868E-34 5.415E-34 3.079E-34 1.524E-34 1.012E-34 5.734E-35 6.683E-35 3.248E-34 8.245E-34 Kr-85M 1.121E-23 6.153E-24 3.499E-24 1.732E-24 1.150E-24 6.515E-25 7.594E-25 3.691E-24 9.369E-24 Kr-85 2.528E-10 1.387E-10 7.887E-11 3.903E-11 2.592E-11 1.469E-11 1.712E-11 8.318E-11 2.112E-10 Kr-87 8.455E-41 4.639E-41 2.638E-41 1.306E-41 8.669E-42 4.912E-42 5.726E-42 2.783E-41 7.063E-41 Kr-88 1.805E-27 9.905E-28 5.632E-28 2.788E-28 1.851E-28 1.049E-28 1.222E-28 5.941E-28 1.508E-27 Sr-89 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Sr-90 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Y-90 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Sr-91 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Y-91 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Sr-92 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Y-92 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Zr-95 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Nb-95 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Mo-99 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-131 4.819E-19 2.644E-19 1.504E-19 7.442E-20 4.941E-20 2.700E-20 3.034E-20 1.474E-19 3.702E-19 Te-132 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-132 7.214E-20 3.959E-20 2.251E-20 1.114E-20 7.397E-21 4.042E-21 4.542E-21 2.207E-20 5.542E-20 I-133 8.355E-21 4.585E-21 2.607E-21 1.290E-21 8.567E-22 4.681E-22 5.260E-22 2.556E-21 6.419E-21 Xe-133M 1.688E-16 9.265E-17 5.268E-17 2.607E-17 1.731E-17 9.810E-10 1.143E-17 5.557E-17 1.411E-16 Xe-133 2.058E-11 1.129E-11 6.420E-12 3.178E-12 2.110E-12 1.196E-12 1.393E-12 6.772E-12 1.719E-11 Cs-134 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-134 1.336E-22 7.332E-23 4.169E-23 2.064E-23 1.370E-23 7.486E-24 8.413E-24 4.088E-23 1.027E-22 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.3-13 Sheet 2 of 2 Revision 11 November 1996 Sector Nuclide NW NNW N NNE NE ENE E ESE SE Xe-135M 3.345E-21 1.835E-21 1.044E-21 5.165E-22 3.429E-22 1.943E-22 2.265E-22 1.101E-21 2.794E-21 Xe-135 1.382E-18 7.582E-19 4.311E-19 2.134E-19 1.417E-19 8.028E-20 9.357E-20 4.547E-19 1.154E-18 Cs-136 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Cs-137 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Xe-138 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Ba-140 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 La-140 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Ce-144 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Pr-144 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 C-14 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.3-14 Sheet 1 of 2 Revision 11 November 1996 ANNUAL AVERAGE ATMOSPHERIC ACTIVITY CONCENTRATIONS AT SITE BOUNDARY FOR NORMAL OPERATION CASE (µCi/cc) Sector Nuclide NW NNW N NNE NE ENE E ESE SE H-3 1.401E-11 7.687E-12 4.371E-12 2.163E-12 1.436E-12 7.848E-13 8.820E-13 4.286E-12 1.076E-11 Cr-51 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Mn-54 1.918-15 1.053E-15 5.985E-14 2.967E-16 1.967E-16 1.075E-16 1.208E-16 5.869E-16 1.474E-15 Fe-55 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Co-58 4.466E-15 3.548E-15 2.017E-15 9.985E-16 6.629E-16 3.622E-16 4.071E-16 1.978E-15 4.967E-15 Fe-59 6.466E-16 3.548E-16 2.017E-16 9.985E-17 6.629E-17 3.622E-17 4.071E-17 1.978E-16 4.967E-16 Co-60 2.931E-15 1.608E-5 9.146E-16 4.526E-16 3.005E-16 1.642E-16 1.845E-16 8.968E-16 2.252E-15 Kr-83M 7.805E-14 4.283E-14 2.435E-14 1.205E-14 8.002E-15 4.535E-15 5.286E-15 2.569E-14 6.521E-14 Kr-85M 5.323E-13 2.921E-13 1.661E-13 8.221E-14 5.458E-14 3.093E-14 3.605E-14 1.752E-13 4.447E-13 Kr-85 4.558E-11 2.501E-11 1.422E-11 7.039E-12 4.674E-12 2.648E-12 3.087E-12 1.500E-11 3.808E-11 Kr-87 2.016E-13 1.104E-13 6.290E-14 3.113E-14 2.067E-14 1.171E-14 1.365E-14 6.635E-14 1.684E-13 Kr-88 7.725E-13 4.239E-13 2.410E-13 1.193E-13 7.921E-14 4.488E-14 5.232E-14 2.542E-13 6.454E-13 Sr-89 1.422E-16 7.805E-17 4.438E-17 2.197E-17 1.458E-17 7.969E-18 8.955E-10 4.352E-17 1.093E-16 Sr-90 2.414E-17 1.325E-17 7.532E-18 3.720E-18 2.475E-18 1.352E-18 1.520E-18 7.386E-18 1.854E-17 Y-90 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Sr-91 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Y-91 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Sr-92 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Y-92 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Zr-95 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Nb-95 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Mo-99 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-131 5.601E-15 3.073E-15 1.748E-15 8.649E-16 5.742E-16 3.138E-16 3.526E-16 1.714E-15 4.303E-15 Te-132 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-132 1.190E-15 6.529E-16 3.712E-16 1.837E-16 1.220E-16 6.666E-17 7.491E-17 3.640E-14 9.141E-16 I-133 5.673E-15 3.113E-15 1.770E-15 8.761E-16 5.816E-16 3.178E-16 3.572E-17 1.736E-15 4.358E-15 Xe-133M 4.259E-12 2.337E-12 1.329E-12 6.577E-13 4.367E-13 2.475E-13 2.884E-13 1.402E-12 3.558E-12 Xe-133 6.468E-10 3.549E-10 2.018E-10 9.989E-11 6.632E-11 3.758E-11 4.381E-11 2.129E-10 5.404E-10 Cs-134 1.918E-15 1.053E-15 5.985E-16 2.962E-16 1.967E-16 1.075E-16 1.208E-16 5.869E-16 1.474E-15 I-134 5.496E-16 3.016E-16 1.715E-16 8.487E-17 5.635E-17 3.079E-17 3.460E-17 1.682E-16 4.222E-16 I-135 2.787E-15 1.529E-15 8.697E-16 4.304E-16 2.858E-16 1.562E-16 1.755E-16 8.528E-16 2.141E-15 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.3-14 Sheet 2 of 2 Revision 11 November 1996 Sector Nuclide NW NNW N NNE NE ENE E ESE SE Xe-135M 7.857E-14 4.311E-14 2.452E-14 1.213E-14 8.056E-15 4.565E-15 5.321E-15 2.586E-14 6.564E-14 Xe-135 2.287E-12 1.255E-12 7.135E-13 3.532E-13 2.345E-13 1.329E-13 1.549E-13 7.526E-13 1.911E-12 Cs-136 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Cs-137 3.254E-15 1.786E-15 1.015E-15 5.026E-16 3.337E-16 1.823E-16 2.049E-16 9.957E-16 2.500E-15 Xe-138 8.728E-14 4.789E-14 2.723E-14 1.348E-14 8.948E-15 5.071E-15 5.910E-15 2.872E-14 7.291E-14 Ba-140 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 La-140 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Ce-144 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Pr-144 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 C-14 3.448E-13 1.892E-13 1.076E-13 5.325E-14 3.536E-14 1.932E-14 2.171E-14 1.055E-13 2.649E-13
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-15 OFFSITE DOSES FOR NW SECTOR AT DISTANCE 0.5 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) DESIGN BASIS CASE Dose Adult Teen Child Infant Ingestion bone 4.406E-08 3.486E-08 6.434E-08 0.0 Ingestion liver 6.312E-08 4.925E-08 6.592E-08 0.0 Ingestion whole body 3.611E-08 2.935E-08 4.974E-08 0.0 Ingestion thyroid 2.065E-05 1.421E-05 2.143E-05 0.0 Ingestion kidney 1.080E-07 6.383E-08 4.026E-08 0.0 Ingestion lung 0.0 0.0 0.0 0.0 Ingestion GI 1.663E-08 9.324E-09 5.645E-09 0.0
Total bone 4.406E-08 3.486E-08 6.434E-08 0.0 Total liver 6.312E-08 4.925E-08 6.592E-08 0.0 Total whole body 3.611E-08 2.935E-08 4.974E-08 0.0 Total thyroid 2.065E-05 1.421E-05 2.143E-05 0.0 Total kidney 1.080E-07 6.383E-08 4.026E-08 0.0 Total lung 0.0 0.0 0.0 0.0 Total GI 1.663E-08 9.324E-09 5.645E-09 0.0
Gamma air 5.145E-01 5.145E-01 5.145E-01 5.145E-01 Beta air 1.161E-02 1.161E-02 1.161E-02 1.161E-02
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-16 OFFSITE DOSES FOR NW SECTOR AT DISTANCE 3.6 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) DESIGN BASIS CASE Dose Adult Teen Child Infant Ingestion bone 5.578E-10 9.049E-10 2.186E-09 0.0 Ingestion liver 7.992E-10 1.279E-09 2.289E-09 0.0 Ingestion whole body 4.573E-10 7.619E-10 1.690E-09 0.0 Ingestion thyroid 2.615E-07 3.688E-07 7.281E-07 0.0 Ingestion kidney 1.368E-09 1.657E-09 1.368E-09 0.0 Ingestion lung 0.0 0.0 0.0 0.0 Ingestion GI 2.105E-10 2.421E-10 1.918E-10 0.0
Total bone 5.578E-10 9.049E-10 2.186E-09 0.0 Total liver 7.992E-10 1.279E-09 2.239E-09 0.0 Total whole body 4.573E-10 7.619E-10 1.690E-09 0.0 Total thyroid 2.615E-07 3.688E-07 7.281E-07 0.0 Total kidney 1.368E-09 1.657E-09 1.368E-09 0.0 Total lung 0.0 0.0 0.0 0.0 Total GI 2.105E-10 2.421E-10 1.918E-10 0.0
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-17 OFFSITE DOSES FOR NNW SECTOR AT DISTANCE 0.5 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) DESIGN BASIS CASE Dose Adult Teen Child Infant Ingestion bone 2.312E-08 1.829E-08 3.377E-08 0.0 Ingestion liver 3.313E-08 2.585E-08 3.460E-08 0.0 Ingestion whole body 1.895E-08 1.540E-08 2.610E-08 0.0 Ingestion thyroid 1.084E-05 7.455E-06 1.125E-05 0.0 Ingestion kidney 5.669E-08 3.350E-08 2.113E-08 0.0 Ingestion lung 0.0 0.0 0.0 0.0 Ingestion GI 8.726E-09 4.894E-09 2.962E-09 0.0
Total bone 2.312E-08 1.829E-08 3.377E-08 0.0 Total liver 3.313E-08 2.585E-08 3.460E-08 0.0 Total whole body 1.895E-08 1.540E-08 2.610E-08 0.0 Total thyroid 1.084E-05 7.455E-06 1.125E-05 0.0 Total kidney 5.669E-08 3.350E-08 2.113E-08 0.0 Total lung 0.0 0.0 0.0 0.0 Total GI 8.726E-09 4.894E-09 2.962E-09 0.0
Gamma air 2.823E-01 2.823E-01 2.823E-01 2.823E-01 Beta air 6.371E-03 6.371E-03 6.371E-03 6.371E-03 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-18 OFFSITE DOSES FOR NNW SECTOR AT DISTANCE 1.5 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) DESIGN BASIS CASE Dose Adult Teen Child Infant Inhalation bone 2.077E-09 1.937E-09 2.985E-09 4.420E-09 Inhalation liver 2.971E-09 2.732E-09 3.047E-09 5.218E-09 Inhalation whole body 1.687E-09 1.617E-09 2.294E-09 3.049E-09 Inhalation thyroid 9.794E-07 7.988E-07 1.009E-06 1.722E-06 Inhalation kidney 5.094E-09 3.559E-09 1.884E-09 1.326E-09 Inhalation lung 0.0 0.0 0.0 0.0 Inhalation GI 5.289E-10 3.526E-10 1.810E-10 1.360E-10
External whole body 1.692E-03 1.692E-03 1.692E-03 1.692E-03
External skin 7.394E-02 7.394E-02 7.394E-02 7.394E-02
Total bone 1.692E-03 1.692E-03 1.692E-03 1.692E-03 Total liver 1.692E-03 1.692E-03 1.692E-03 1.692E-03 Total whole body 1.692E-03 1.692E-03 1.692E-03 1.692E-03 Total thyroid 1.693E-03 1.693E-03 1.693E-03 1.694E-03 Total kidney 1.692E-03 1.692E-03 1.692E-03 1.692E-03 Total lung 1.692E-03 1.692E-03 1.692E-03 1.692E-03 Total GI 1.692E-03 1.692E-03 1.692E-03 1.692E-03 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-19 OFFSITE DOSES FOR NNW SECTOR AT DISTANCE 3.6 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) DESIGN BASIS CASE Dose Adult Teen Child Infant Ingestion bone 2.926E-10 4.746E-10 1.146E-09 0.0 Ingestion liver 4.192E-10 6.706E-10 1.175E-09 0.0 Ingestion whole body 2.398E-10 3.996E-10 8.862E-10 0.0 Ingestion thyroid 1.371E-07 1.934E-07 3.819E-07 0.0 Ingestion kidney 7.174E-10 8.692E-10 7.174E-10 0.0 Ingestion lung 0.0 0.0 0.0 0.0 Ingestion GI 1.104E-10 1.270E-10 1.006E-10 0.0
Total bone 2.926E-10 4.746E-10 1.146E-09 0.0 Total liver 4.192E-10 6.706E-10 1.175E-09 0.0 Total whole body 2.398E-10 3.996E-10 8.862E-10 0.0 Total thyroid 1.371E-07 1.934E-07 3.819E-07 0.0 Total kidney 7.174E-10 8.692E-10 7.174E-10 0.0 Total lung 0.0 0.0 0.0 0.0 Total GI 1.104E-10 1.270E-10 1.006E-10 0.0
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-20 OFFSITE DOSES FOR N SECTOR AT DISTANCE 0.5 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) DESIGN BASIS CASE Dose Adult Teen Child Infant Ingestion bone 9.551E-09 7.557E-09 1.395E-08 0.0 Ingestion liver 1.368E-08 1.068E-08 1.429E-08 0.0 Ingestion whole body 7.829E-09 6.363E-09 1.078E-08 0.0 Ingestion thyroid 4.477E-06 3.080E-06 4.647E-06 0.0 Ingestion kidney 2.342E-08 1.384E-08 8.729E-09 0.0 Ingestion lung 0.0 0.0 0.0 0.0 Ingestion GI 3.605E-09 2.022E-09 1.224E-09 0.0
Total bone 9.551E-09 7.557E-09 1.395E-08 0.0 Total liver 1.368E-08 1.068E-08 1.429E-08 0.0 Total whole body 7.829E-09 6.363E-09 1.078E-08 0.0 Total thyroid 4.477E-06 3.080E-06 4.647E-06 0.0 Total kidney 2.342E-08 1.384E-08 8.729E-09 0.0 Total lung 0.0 0.0 0.0 0.0 Total GI 3.605E-09 2.022E-09 1.224E-09 0.0
Gamma air 1.605E-01 1.605E-01 1.605E-01 1.605E-01 Beta air 3.623E-03 3.623E-03 3.623E-03 3.623E-03
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-21 OFFSITE DOSES FOR NNE SECTOR AT DISTANCE 0.5 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) DESIGN BASIS CASE Dose Adult Teen Child Infant Ingestion bone 5.688E-09 4.500E-09 8.306E-09 0.0 Ingestion liver 8.148E-09 6.358E-09 8.510E-09 0.0 Ingestion whole body 4.662E-09 3.789E-09 6.421E-09 0.0 Ingestion thyroid 2.666E-06 1.834E-06 2.767E-06 0.0 Ingestion kidney 1.395E-08 8.240E-09 5.198E-09 0.0 Ingestion lung 0.0 0.0 0.0 0.0 Ingestion GI 2.146E-09 1.204E-09 7.287E-10 0.0
Total bone 5.688E-09 4.500E-09 8.306E-09 0.0 Total liver 8.148E-09 6.358E-09 8.510E-09 0.0 Total whole body 4.662E-09 3.789E-09 6.421E-09 0.0 Total thyroid 2.666E-06 1.834E-06 2.767E-06 0.0 Total kidney 1.395E-08 8.240E-09 5.198E-09 0.0 Total lung 0.0 0.0 0.0 0.0 Total GI 2.146E-09 1.204E-09 7.287E-10 0.0
Gamma air 7.945E-02 7.945E-02 7.945E-02 7.945E-02 Beta air 1.793E-03 1.793E-03 1.793E-03 1.793E-03 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-22 OFFSITE DOSES FOR NE SECTOR AT DISTANCE 0.5 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) DESIGN BASIS CASE Dose Adult Teen Child Infant Ingestion bone 7.178E-09 5.679E-09 1.048E-08 0.0 Ingestion liver 1.028E-08 8.024E-09 1.074E-08 0.0 Ingestion whole body 5.884E-09 4.782E-09 8.104E-09 0.0 Ingestion thyroid 3.365E-06 2.315E-06 3.492E-06 0.0 Ingestion kidney 1.760E-08 1.040E-08 6.560E-09 0.0 Ingestion lung 0.0 0.0 0.0 0.0 Ingestion GI 2.709E-09 1.519E-09 9.197E-10 0.0
Total bone 7.178E-09 5.679E-09 1.048E-08 0.0 Total liver 1.028E-08 8.024E-09 1.074E-08 0.0 Total whole body 5.884E-09 4.782E-09 8.104E-09 0.0 Total thyroid 3.365E-06 2.315E-06 3.492E-06 0.0 Total kidney 1.760E-08 1.040E-08 6.560E-09 0.0 Total lung 0.0 0.0 0.0 0.0 Total GI 2.709E-09 1.519E-09 9.197E-10 0.0
Gamma air 5.275E-02 5.275E-02 5.275E-02 5.275E-02 Beta air 1.190E-03 1.190E-03 1.190E-03 1.190E-03
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-23 OFFSITE DOSES FOR ENE SECTOR AT DISTANCE 0.7 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) DESIGN BASIS CASE Dose Adult Teen Child Infant Ingestion bone 3.068E-09 2.427E-09 4.481E-09 0.0 Ingestion liver 4.395E-09 3.430E-09 4.591E-09 0.0 Ingestion whole body 2.515E-09 2.044E-09 3.464E-09 0.0 Ingestion thyroid 1.438E-06 9.892E-07 1.493E-06 0.0 Ingestion kidney 7.522E-09 4.445E-09 2.804E-09 0.0 Ingestion lung 0.0 0.0 0.0 0.0 Ingestion GI 1.158E-09 6.493E-10 3.931E-10 0.0
Total bone 3.068E-09 2.427E-09 4.481E-09 0.0 Total liver 4.395E-09 3.430E-09 4.591E-09 0.0 Total whole body 2.515E-09 2.044E-09 3.464E-09 0.0 Total thyroid 1.438E-06 9.892E-07 1.493E-06 0.0 Total kidney 7.522E-09 4.445E-09 2.804E-09 0.0 Total lung 0.0 0.0 0.0 0.0 Total GI 1.158E-09 6.493E-10 3.931E-10 0.0
Gamma air 2.989E-02 2.989E-02 2.989E-02 2.989E-02 Beta air 6.746E-04 6.746E-04 6.746E-04 6.746E-04
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-24 OFFSITE DOSES FOR ENE SECTOR AT DISTANCE 4.5 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) DESIGN BASIS CASE Dose Adult Teen Child Infant Inhalation bone 7.466E-11 6.962E-11 1.073E-10 1.589E-10 Inhalation liver 1.068E-10 9.819E-11 1.095E-10 1.876E-10 Inhalation whole body 6.065E-11 5.813E-11 8.247E-11 1.096E-10 Inhalation thyroid 3.521E-08 2.872E-08 3.628E-08 6.191E-08 Inhalation kidney 1.831E-10 1.279E-10 6.772E-11 4.766E-11 Inhalation lung 0.0 0.0 0.0 0.0 Inhalation GI 1.901E-11 1.267E-11 6.505E-12 4.890E-12
External whole body 7.179E-05 7.179E-05 7.179E-05 7.179E-05
External skin 3.137E-03 3.137E-03 3.137E-03 3.137E-03
Total bone 7.179E-05 7.179E-05 7.179E-05 7.179E-05 Total liver 7.179E-05 7.179E-05 7.179E-05 7.179E-05 Total whole body 7.179E-05 7.179E-05 7.179E-05 7.179E-05 Total thyroid 7.183E-05 7.182E-05 7.183E-05 7.185E-05 Total kidney 7.179E-05 7.179E-05 7.179E-05 7.179E-05 Total lung 7.179E-05 7.179E-05 7.179E-05 7.179E-05 Total GI 7.179E-05 7.179E-05 7.179E-05 7.179E-05
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-25 OFFSITE DOSES FOR E SECTOR AT DISTANCE 1.0 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) DESIGN BASIS CASE Dose Adult Teen Child Infant Ingestion bone 2.867E-09 2.268E-09 4.186E-09 0.0 Ingestion liver 4.107E-09 3.204E-09 4.289E-09 0.0 Ingestion whole body 2.350E-09 1.910E-09 3.236E-09 0.0 Ingestion thyroid 1.344E-06 9.243E-07 1.395E-06 0.0 Ingestion kidney 7.028E-09 4.153E-09 2.620E-09 0.0 Ingestion lung 0.0 0.0 0.0 0.0 Ingestion GI 1.082E-09 6.067E-10 3.673E-10 0.0
Total bone 2.867E-09 2.268E-09 4.186E-09 0.0 Total liver 4.107E-09 3.204E-09 4.289E-09 0.0 Total whole body 2.350E-09 1.910E-09 3.236E-09 0.0 Total thyroid 1.344E-06 9.243E-07 1.395E-06 0.0 Total kidney 7.028E-09 4.153E-09 2.620E-09 0.0 Total lung 0.0 0.0 0.0 0.0 Total GI 1.082E-09 6.067E-10 3.673E-10 0.0
Gamma air 3.484E-02 3.484E-02 3.484E-02 3.484E-02 Beta air 7.863E-04 7.863E-04 7.863E-04 7.863E-04
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-26 OFFSITE DOSES FOR ESE SECTOR AT DISTANCE 1.0 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) DESIGN BASIS CASE Dose Adult Teen Child Infant Ingestion bone 1.472E-08 1.165E-08 2.150E-08 0.0 Ingestion liver 2.109E-08 1.646E-08 2.203E-08 0.0 Ingestion whole body 1.207E-08 9.807E-09 1.662E-08 0.0 Ingestion thyroid 6.900E-06 4.746E-06 7.162E-06 0.0 Ingestion kidney 3.609E-08 2.133E-08 1.345E-08 0.0 Ingestion lung 0.0 0.0 0.0 0.0 Ingestion GI 5.555E-09 3.116E-09 1.886E-09 0.0
Total bone 1.472E-08 1.165E-08 2.150E-08 0.0 Total liver 2.109E-08 1.646E-08 2.203E-08 0.0 Total whole body 1.207E-08 9.807E-09 1.662E-08 0.0 Total thyroid 6.900E-06 4.746E-06 7.162E-06 0.0 Total kidney 3.609E-08 2.133E-08 1.345E-08 0.0 Total lung 0.0 0.0 0.0 0.0 Total GI 5.555E-09 3.116E-09 1.886E-09 0.0
Gamma air 1.693E-01 1.693E-01 1.693E-01 1.693E-01 Beta air 3.821E-03 3.821E-03 3.821E-03 3.821E-03
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-27 OFFSITE DOSES FOR ESE SECTOR AT DISTANCE 3.7 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) DESIGN BASIS CASE Dose Adult Teen Child Infant Ingestion bone 5.431E-10 8.810E-10 2.128E-09 0.0 Ingestion liver 7.781E-10 1.245E-09 2.180E-09 0.0 Ingestion whole body 4.452E-10 7.418E-10 1.645E-09 0.0 Ingestion thyroid 2.546E-07 3.590E-07 7.089E-07 0.0 Ingestion kidney 1.332E-09 1.613E-09 1.332E-09 0.0 Ingestion lung 0.0 0.0 0.0 0.0 Ingestion GI 2.050E-10 2.357E-10 1.867E-10 0.0
Total bone 5.431E-10 8.810E-10 2.128E-09 0.0 Total liver 7.781E-10 1.245E-09 2.180E-09 0.0 Total whole body 4.452E-10 7.418E-10 1.645E-09 0.0 Total thyroid 2.546E-07 3.590E-07 7.089E-07 0.0 Total kidney 1.332E-09 1.613E-09 1.332E-09 0.0 Total lung 0.0 0.0 0.0 0.0 Total GI 2.050E-10 2.357E-10 1.867E-10 0.0
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-28 OFFSITE DOSES FOR SE SECTOR AT DISTANCE 1.1 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) DESIGN BASIS CASE Dose Adult Teen Child Infant Ingestion bone 5.046E-08 3.992E-08 7.369E-08 0.0 Ingestion liver 7.229E-08 5.641E-08 7.550E-08 0.0 Ingestion whole body 4.136E-08 3.361E-08 5.696E-08 0.0 Ingestion thyroid 2.365E-05 1.627E-05 2.455E-05 0.0 Ingestion kidney 1.237E-07 7.311E-08 4.611E-08 0.0 Ingestion lung 0.0 0.0 0.0 0.0 Ingestion GI 1.904E-08 1.068E-08 6.465E-09 0.0
Total bone 5.046E-08 3.992E-08 7.369E-08 0.0 Total liver 7.229E-08 5.641E-08 7.550E-08 0.0 Total whole body 4.136E-08 3.361E-08 5.696E-08 0.0 Total thyroid 2.365E-05 1.627E-05 2.455E-05 0.0 Total kidney 1.237E-07 7.311E-08 4.611E-08 0.0 Total lung 0.0 0.0 0.0 0.0 Total GI 1.904E-08 1.068E-08 6.465E-09 0.0
Gamma air 4.298E-01 4.298E-01 4.298E-01 4.298E-01 Beta air 9.700E-03 9.700E-03 9.700E-03 9.700E-03
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-29 OFFSITE DOSES FOR SE SECTOR AT DISTANCE 3.7 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) DESIGN BASIS CASE Dose Adult Teen Child Infant Ingestion bone 2.200E-09 3.569E-09 8.620E-09 0.0 Ingestion liver 3.152E-09 5.043E-09 8.832E-09 0.0 Ingestion whole body 1.803E-09 3.005E-09 6.664E-09 0.0 Ingestion thyroid 1.031E-06 1.454E-06 2.872E-06 0.0 Ingestion kidney 5.394E-09 6.535E-09 5.394E-09 0.0 Ingestion lung 0.0 0.0 0.0 0.0 Ingestion GI 8.303E-10 9.547E-10 7.563E-10 0.0
Total bone 2.200E-09 3.569E-09 8.620E-09 0.0 Total liver 3.152E-09 5.043E-09 8.832E-09 0.0 Total whole body 1.803E-09 3.005E-09 6.664E-09 0.0 Total thyroid 1.031E-06 1.454E-06 2.872E-06 0.0 Total kidney 5.394E-09 6.535E-09 5.394E-09 0.0 Total lung 0.0 0.0 0.0 0.0 Total GI 8.303E-10 9.547E-10 7.563E-10 0.0
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-30 OFFSITE DOSES FOR NW SECTOR AT DISTANCE 0.5 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) NORMAL OPERATION CASE Dose Adult Teen Child Infant Ingestion bone 6.470E-02 5.040E-02 8.703E-02 0.0 Ingestion liver 1.065E-01 8.164E-02 1.019E-01 0.0 Ingestion whole body 8.301E-02 4.040E-02 3.180E-02 0.0 Ingestion thyroid 2.400E-01 1.651E-01 2.491E-01 0.0 Ingestion kidney 3.293E-02 1.946E-02 1.227E-02 0.0 Ingestion lung 1.215E-02 1.041E-02 1.146E-02 0.0 Ingestion GI 1.136E-01 5.889E-02 3.272E-02 0.0
Total bone 6.470E-02 5.040E-02 8.703E-02 0.0 Total liver 1.065E-01 8.164E-02 1.019E-01 0.0 Total whole body 8.301E-02 4.040E-02 3.180E-02 0.0 Total thyroid 2.400E-01 1.651E-01 2.491E-01 0.0 Total kidney 3.293E-02 1.946E-02 1.227E-02 0.0 Total lung 1.215E-02 1.041E-02 1.146E-02 0.0 Total GI 1.136E-01 5.889E-02 3.272E-02 0.0
Gamma air 7.859E-01 7.859E-01 7.859E-01 7.859E-01 Beta air 2.496E-01 2.496E-01 2.496E-01 2.496E-01
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-31 OFFSITE DOSES FOR NW SECTOR AT DISTANCE 3.6 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) NORMAL OPERATION CASE Dose Adult Teen Child Infant Ingestion bone 3.185E-02 5.189E-02 1.052E-01 0.0 Ingestion liver 3.432E-02 5.455E-02 9.099E-02 0.0 Ingestion whole body 2.788E-02 2.742E-02 2.522E-02 0.0 Ingestion thyroid 3.039E-03 4.286E-03 8.463E-03 0.0 Ingestion kidney 1.127E-02 1.365E-02 1.127E-02 0.0 Ingestion lung 3.721E-02 1.365E-02 1.127E-02 0.0 Ingestion GI 1.088E-02 1.168E-02 8.568E-03 0.0
Total bone 3.185E-02 5.189E-02 1.052E-01 0.0 Total liver 3.432E-02 5.455E-02 9.099E-02 0.0 Total whole body 2.788E-02 2.742E-02 2.522E-02 0.0 Total thyroid 3.039E-03 4.286E-03 8.463E-03 0.0 Total kidney 1.127E-02 1.365E-02 1.127E-02 0.0 Total lung 3.721E-03 6.847E-03 1.030E-02 0.0 Total GI 1.088E-02 1.168E-02 8.568E-03 0.0
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-32 OFFSITE DOSES FOR NNW SECTOR AT DISTANCE 0.5 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) NORMAL OPERATION CASE Dose Adult Teen Child Infant Ingestion bone 3.396E-02 2.645E-02 4.568E-02 0.0 Ingestion liver 5.590E-02 4.285E-02 5.346E-02 0.0 Ingestion whole body 4.357E-02 2.120E-02 1.669E-02 0.0 Ingestion thyroid 1.260E-01 8.665E-02 1.307E-01 0.0 Ingestion kidney 1.728E-02 1.021E-02 6.442E-03 0.0 Ingestion lung 6.378E-03 5.463E-03 6.017E-03 0.0 Ingestion GI 5.964E-02 3.091E-02 1.717E-02 0.0
Total bone 3.396E-02 2.645E-02 4.568E-02 0.0 Total liver 5.590E-02 4.285E-02 5.346E-02 0.0 Total whole body 4.357E-02 2.120E-02 1.669E-02 0.0 Total thyroid 1.260E-01 8.665E-02 1.307E-01 0.0 Total kidney 1.728E-02 1.021E-02 6.442E-03 0.0 Total lung 6.378E-03 5.463E-03 6.017E-03 0.0 Total GI 5.964E-02 3.091E-02 1.717E-02 0.0
Gamma air 4.312E-01 4.312E-01 4.312E-01 4.312E-01 Beta air 1.370E-01 1.370E-01 1.370E-01 1.370E-01
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-33 OFFSITE DOSES FOR NNW SECTOR AT DISTANCE 1.5 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) NORMAL OPERATION CASE Dose Adult Teen Child Infant Inhalation bone 1.892E-03 1.164E-03 1.037E-03 1.221E-03 Inhalation liver 6.453E-03 4.281E-03 3.282E-03 3.440E-03 Inhalation whole body 3.269E-03 1.809E-03 1.646E-03 1.686E-03 Inhalation thyroid 1.736E-02 1.368E-02 1.719E-02 2.823E-02 Inhalation kidney 3.043E-03 2.126E-03 1.125E-03 7.919E-04 Inhalation lung 7.415E-03 6.104E-03 5.589E-03 7.540E-03 Inhalation GI 3.073E-03 1.751E-03 1.594E-03 1.630E-03
External whole body 2.043E-01 2.043E-01 2.043E-01 2.043E-01
External skin 2.950E-01 2.950E-01 2.950E-01 2.950E-01
Total bone 2.062E-01 2.054E-01 2.053E-01 2.055E-01 Total liver 2.107E-01 2.085E-01 2.075E-01 2.077E-01 Total whole body 2.075E-01 2.061E-01 2.059E-01 2.059E-01 Total thyroid 2.216E-01 2.179E-01 2.214E-01 2.325E-01 Total kidney 2.073E-01 2.064E-01 2.054E-01 2.050E-01 Total lung 2.117E-01 2.104E-01 2.098E-01 2.118E-01 Total GI 2.073E-01 2.060E-01 2.059E-01 2.059E-01
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-34 OFFSITE DOSES FOR NNW SECTOR AT DISTANCE 3.6 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) NORMAL OPERATION CASE Dose Adult Teen Child Infant Ingestion bone 1.672E-02 2.723E-02 5.521E-02 0.0 Ingestion liver 1.801E-02 2.863E-02 4.776E-02 0.0 Ingestion whole body 1.463E-02 1.439E-02 1.324E-02 0.0 Ingestion thyroid 1.594E-03 2.248E-03 4.439E-03 0.0 Ingestion kidney 5.915E-03 7.166E-03 5.915E-03 0.0 Ingestion lung 1.953E-03 3.594E-03 5.404E-03 0.0 Ingestion GI 5.711E-03 6.131E-03 4.497E-03 0.0
Total bone 1.672E-02 2.723E-02 5.521E-02 0.0 Total liver 1.801E-02 2.863E-02 4.776E-02 0.0 Total whole body 1.463E-02 1.439E-02 1.324E-02 0.0 Total thyroid 1.594E-03 2.248E-03 4.439E-03 0.0 Total kidney 5.915E-03 7.166E-03 5.915E-03 0.0 Total lung 1.953E-03 3.594E-03 5.404E-03 0.0 Total GI 5.711E-03 6.131E-03 4.497E-03 0.0
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-35 OFFSITE DOSES FOR N SECTOR AT DISTANCE 0.5 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) NORMAL OPERATION CASE Dose Adult Teen Child Infant Ingestion bone 1.403E-02 1.093E-02 1.887E-02 0.0 Ingestion liver 2.309E-02 1.770E-02 2.209E-02 0.0 Ingestion whole body 1.800E-02 8.761E-03 6.895E-03 0.0 Ingestion thyroid 5.204E-02 3.580E-02 5.401E-02 0.0 Ingestion kidney 7.140E-03 4.219E-03 2.661E-03 0.0 Ingestion lung 2.635E-03 2.257E-03 2.486E-03 0.0 Ingestion GI 2.464E-02 1.277E-02 7.096E-03 0.0 Total bone 1.403E-02 1.093E-02 1.887E-02 0.0 Total liver 2.309E-02 1.770E-02 2.209E-02 0.0 Total whole body 1.800E-02 8.761E-03 6.895E-03 0.0 Total thyroid 5.204E-02 3.580E-02 5.401E-02 0.0 Total kidney 7.140E-03 4.219E-03 2.661E-03 0.0 Total lung 2.635E-03 2.257E-03 2.486E-03 0.0 Total GI 2.464E-02 1.277E-02 7.096E-03 0.0
Gamma air 2.452E-01 2.452E-01 2.452E-01 2.452E-01 Beta air 7.789E-02 7.789E-02 7.789E-02 7.789E-02 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-36 OFFSITE DOSES FOR NNE SECTOR AT DISTANCE 0.5 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) NORMAL OPERATION CASE Dose Adult Teen Child Infant Ingestion bone 8.356E-03 6.509E-03 1.124E-02 0.0 Ingestion liver 1.375E-02 1.054E-02 1.315E-02 0.0 Ingestion whole body 1.072E-02 5.217E-03 4.106E-03 0.0 Ingestion thyroid 3.099E-02 2.131E-02 3.216E-02 0.0 Ingestion kidney 4.252E-03 2.513E-03 1.585E-03 0.0 Ingestion lung 1.569E-03 1.344E-03 1.481E-03 0.0 Ingestion GI 1.468E-02 7.605E-03 4.226E-03 0.0
Total bone 8.356E-03 6.509E-03 1.124E-02 0.0 Total liver 1.375E-02 1.054E-02 1.315E-02 0.0 Total whole body 1.072E-02 5.217E-03 4.106E-03 0.0 Total thyroid 3.099E-02 2.131E-02 3.216E-02 0.0 Total kidney 4.252E-03 2.513E-03 1.585E-03 0.0 Total lung 1.569E-03 1.344E-03 1.481E-03 0.0 Total GI 1.468E-02 7.605E-03 4.226E-03 0.0
Gamma air 1.214E-01 1.214E-01 1.214E-01 1.214E-01 Beta air 3.855E-02 3.855E-02 3.855E-02 3.855E-02
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-37 OFFSITE DOSES FOR NE SECTOR AT DISTANCE 0.5 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) NORMAL OPERATION CASE Dose Adult Teen Child Infant Ingestion bone 1.055E-02 8.215E-03 1.418E-02 0.0 Ingestion liver 1.736E-02 1.331E-02 1.660E-02 0.0 Ingestion whole body 1.353E-02 6.585E-03 5.182E-03 0.0 Ingestion thyroid 3.911E-02 2.690E-02 4.059E-02 0.0 Ingestion kidney 5.367E-03 3.171E-03 2.000E-03 0.0 Ingestion lung 1.980E-03 1.696E-03 1.868E-03 0.0 Ingestion GI 1.852E-02 9.598E-03 5.333E-03 0.0
Total bone 1.055E-02 8.215E-03 1.418E-02 0.0 Total liver 1.736E-02 1.331E-02 1.660E-02 0.0 Total whole body 1.353E-02 6.585E-03 5.182E-03 0.0 Total thyroid 3.911E-02 2.690E-02 4.059E-02 0.0 Total kidney 5.367E-03 3.171E-03 2.000E-03 0.0 Total lung 1.980E-03 1.696E-03 1.868E-03 0.0 Total GI 1.852E-02 9.598E-03 5.333E-03 0.0
Gamma air 8.058E-02 8.058E-02 8.058E-02 8.058E-02 Beta air 2.559E-02 2.559E-02 2.559E-02 2.559E-02
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-38 OFFSITE DOSES FOR ENE SECTOR AT DISTANCE 0.7 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) NORMAL OPERATION CASE Dose Adult Teen Child Infant Ingestion bone 4.508E-03 3.512E-03 6.064E-03 0.0 Ingestion liver 7.420E-03 5.688E-03 7.097E-03 0.0 Ingestion whole body 5.784E-03 2.815E-03 2.215E-03 0.0 Ingestion thyroid 1.671E-02 1.150E-02 1.735E-02 0.0 Ingestion kidney 2.294E-03 1.356E-03 8.551E-04 0.0 Ingestion lung 8.467E-04 7.252E-04 7.988E-04 0.0 Ingestion GI 7.918E-03 4.103E-03 2.280E-03 0.0
Total bone 4.508E-03 3.512E-03 6.064E-03 0.0 Total liver 7.420E-03 5.688E-03 7.097E-03 0.0 Total whole body 5.784E-03 2.815E-03 2.215E-03 0.0 Total thyroid 1.671E-02 1.150E-02 1.735E-02 0.0 Total kidney 2.294E-03 1.356E-03 8.551E-04 0.0 Total lung 8.467E-04 7.252E-04 7.988E-04 0.0 Total GI 7.918E-03 4.103E-03 2.280E-03 0.0
Gamma air 4.566E-02 4.566E-02 4.566E-02 4.566E-02 Beta air 1.450E-02 1.450E-02 1.450E-02 1.450E-02
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-39 OFFSITE DOSES FOR ENE SECTOR AT DISTANCE 4.5 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) NORMAL OPERATION CASE Dose Adult Teen Child Infant Inhalation bone 6.802E-05 4.186E-05 3.728E-05 4.388E-05 Inhalation liver 2.320E-04 1.539E-04 1.180E-04 1.236E-04 Inhalation whole body 1.175E-04 6.502E-05 5.915E-05 6.060E-05 Inhalation thyroid 6.241E-04 4.919E-04 6.180E-04 1.015E-03 Inhalation kidney 1.094E-04 7.641E-05 4.045E-05 2.847E-05 Inhalation lung 2.665E-04 2.194E-04 2.009E-04 2.710E-04 Inhalation GI 1.105E-04 6.296E-05 5.729E-05 5.859E-05
External whole body 6.780E-03 6.780E-03 6.780E-03 6.780E-03
External skin 1.031E-02 1.031E-02 1.031E-02 1.031E-02
Total bone 6.848E-03 6.822E-03 6.817E-03 6.824E-03 Total liver 7.012E-03 6.934E-03 6.898E-03 6.903E-03 Total whole body 6.897E-03 6.845E-03 6.839E-03 6.840E-03 Total thyroid 7.404E-03 7.272E-03 7.398E-03 7.795E-03 Total kidney 6.889E-03 6.856E-03 6.820E-03 6.808E-03 Total lung 7.046E-03 6.999E-03 6.981E-03 7.051E-03 Total GI 6.890E-03 6.843E-03 6.837E-03 6.838E-03
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-40 OFFSITE DOSES FOR E SECTOR AT DISTANCE 1 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) NORMAL OPERATION CASE Dose Adult Teen Child Infant Ingestion bone 4.214E-03 3.283E-03 5.668E-03 0.0 Ingestion liver 6.936E-03 5.317E-03 6.634E-03 0.0 Ingestion whole body 5.406E-03 2.631E-03 2.071E-03 0.0 Ingestion thyroid 1.562E-02 1.074E-02 1.621E-02 0.0 Ingestion kidney 2.144E-03 1.267E-03 7.993E-04 0.0 Ingestion lung 7.914E-04 6.779E-04 7.467E-04 0.0 Ingestion GI 7.401E-03 3.835E-03 2.131E-03 0.0
Total bone 4.214E-03 3.283E-03 5.668E-03 0.0 Total liver 6.936E-03 5.317E-03 6.634E-03 0.0 Total whole body 5.406E-03 2.631E-03 2.071E-03 0.0 Total thyroid 1.562E-02 1.074E-02 1.621E-02 0.0 Total kidney 2.144E-03 1.267E-03 7.993E-04 0.0 Total lung 7.914E-04 6.779E-04 7.467E-04 0.0 Total GI 7.401E-03 3.835E-03 2.131E-03 0.0
Gamma air 5.322E-02 5.322E-02 5.322E-02 5.322E-02 Beta air 1.690E-02 1.690E-02 1.690E-02 1.690E-02
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-41 OFFSITE DOSES FOR ESE SECTOR AT DISTANCE 1 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) NORMAL OPERATION CASE Dose Adult Teen Child Infant Ingestion bone 2.163E-02 1.685E-02 2.909E-02 0.0 Ingestion liver 3.560E-02 2.729E-02 3.404E-02 0.0 Ingestion whole body 2.775E-02 1.350E-02 1.063E-02 0.0 Ingestion thyroid 8.020E-02 5.517E-02 8.324E-02 0.0 Ingestion kidney 1.101E-02 6.503E-03 4.102E-03 0.0 Ingestion lung 4.061E-03 3.479E-03 3.832E-03 0.0 Ingestion GI 3.798E-02 1.968E-02 1.094E-02 0.0
Total bone 2.163E-02 1.685E-02 2.909E-02 0.0 Total liver 3.560E-02 2.729E-02 3.404E-02 0.0 Total whole body 2.775E-02 1.350E-02 1.063E-02 0.0 Total thyroid 8.020E-02 5.517E-02 8.324E-02 0.0 Total kidney 1.101E-02 6.503E-03 4.102E-03 0.0 Total lung 4.061E-03 3.479E-03 3.832E-03 0.0 Total GI 3.798E-02 1.968E-02 1.094E-02 0.0
Gamma air 2.586E-01 2.586E-01 2.586E-01 2.586E-01 Beta air 8.215E-02 8.215E-02 8.215E-02 8.215E-02
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-42 OFFSITE DOSES FOR ESE SECTOR AT DISTANCE 3.7 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) NORMAL OPERATION CASE Dose Adult Teen Child Infant Ingestion bone 3.101E-02 5.052E-02 1.024E-01 0.0 Ingestion liver 3.341E-02 5.311E-02 8.859E-02 0.0 Ingestion whole body 2.714E-02 2.669E-02 2.456E-02 0.0 Ingestion thyroid 2.959E-03 4.173E-03 8.239E-03 0.0 Ingestion kidney 1.097E-02 1.329E-02 1.097E-02 0.0 Ingestion lung 3.623E-03 6.667E-03 1.003E-02 0.0 Ingestion GI 1.059E-02 1.137E-02 8.341E-03 0.0
Total bone 3.101E-02 5.052E-02 1.024E-01 0.0 Total liver 3.341E-02 5.311E-02 8.859E-02 0.0 Total whole body 2.714E-02 2.669E-02 2.456E-02 0.0 Total thyroid 2.959E-03 4.173E-03 8.239E-03 0.0 Total kidney 1.097E-02 1.329E-02 1.097E-02 0.0 Total lung 3.623E-03 6.667E-03 1.003E-02 0.0 Total GI 1.059E-02 1.137E-02 8.341E-03 0.0
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-43 OFFSITE DOSES FOR SE SECTOR AT DISTANCE 1.1 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) NORMAL OPERATION CASE Dose Adult Teen Child Infant Ingestion bone 7.411E-02 5.773E-02 9.968E-02 0.0 Ingestion liver 1.220E-01 9.351E-02 1.167E-01 0.0 Ingestion whole body 9.508E-02 4.627E-02 3.642E-02 0.0 Ingestion thyroid 2.749E-01 1.891E-01 2.853E-01 0.0 Ingestion kidney 3.771E-02 2.229E-02 1.406E-02 0.0 Ingestion lung 1.392E-02 1.192E-02 1.313E-02 0.0 Ingestion GI 1.302E-01 6.745E-02 3.748E-02 0.0
Total bone 7.411E-02 5.773E-02 9.968E-02 0.0 Total liver 1.220E-01 9.351E-02 1.167E-01 0.0 Total whole body 9.508E-02 4.627E-02 3.642E-02 0.0 Total thyroid 2.749E-01 1.891E-01 2.853E-01 0.0 Total kidney 3.771E-02 2.229E-02 1.406E-02 0.0 Total lung 1.392E-02 1.192E-02 1.313E-02 0.0 Total GI 1.302E-01 6.745E-02 3.748E-02 0.0
Gamma air 6.566E-01 6.566E-01 6.566E-01 6.566E-01 Beta air 2.085E-01 2.085E-01 2.085E-01 2.085E-01
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.3-44 OFFSITE DOSES FOR SE SECTOR AT DISTANCE 3.7 MI (MREM/YEAR - AIR DOSES IN MRAD/YEAR) NORMAL OPERATION CASE Dose Adult Teen Child Infant Ingestion bone 1.255E-01 2.044E-01 4.144E-01 0.0 Ingestion liver 1.352E-01 2.149E-01 3.584E-01 0.0 Ingestion whole body 1.098E-01 1.080E-01 9.935E-02 0.0 Ingestion thyroid 1.199E-02 1.690E-02 3.338E-02 0.0 Ingestion kidney 4.439E-02 5.378E-02 4.439E-02 0.0 Ingestion lung 1.466E-02 2.697E-02 4.056E-02 0.0 Ingestion GI 4.286E-02 4.602E-02 3.375E-02 0.0
Total bone 1.255E-01 2.044E-01 4.144E-01 0.0 Total liver 1.352E-01 2.149E-01 3.584E-01 0.0 Total whole body 1.098E-01 1.080E-01 9.935E-02 0.0 Total thyroid 1.199E-02 1.690E-02 3.338E-02 0.0 Total kidney 4.439E-02 5.378E-02 4.439E-02 0.0 Total lung 1.466E-02 2.697E-02 4.056E-02 0.0 Total GI 4.286E-02 4.602E-02 3.375E-02 0.0
DCPP UNITS 1 & 2 FSAR UPDATE Table 11.4-1 Sheet 1 of 6 RADIATION MONITORS AND READOUTS Revision 18 October 2008 RMS RMS Detector Unit(e) Readout(s) Channel Description Elevation Range Type Location No. Indication Location Recorder Location R -1 Control room area monitor 140 ft 0.1 to E4 mR/hr GM NE area rad rack behind main control panel 0 0 RI-1 RM-1 Local RNRMA RR-1 RNRMA R -2 Containment area monitor 140 ft 0.1 to E4 mR/hr GM West containment wall at personnel hatch 1 1 2 2 RI-2 RM-2 RI-2 RM-2 Local RNRMA Local RNRMC RR-2 RR-2 RNRMA RNRMC R -3 Oily water separator effluent monitor 85 ft 10 to E6 cpm Gamma Scint. Oily water separator room 0 RM-3 RNRMA RR-3 RNRMA R -4 Centrifugal charging pump CCP3 (room #2) monitor 73 ft 0.1 to E4 mR/hr GM SE corner at charging pump 1-3, pump outside of SE corner (N-wall at charging pump 2-3) 1 1 2 2 RI-4 RM-4 RI-4 RM-4 Local RNRMA Local RNRMC RR-4 RR-4 RNRMA RNRMC R -6 NSSS sampling room area monitor 100 ft 0.1 to E4 mR/hr GM SW corner on U-1 (NW corner on U-2) 1 1 2 2 RI-6 RM-6 RI-6 RM-6 Local RNRMA Local RNRMC RR-6 RR-6 RNRMA RNRMC R -7 Incore seal table monitor - area monitor 115 ft 0.1 to E4 mR/hr GM South hatch at upper internals laydown area on U-1 (North on U-2) 1 1 2 2 RI-7 RM-7 RI-7 RM-7 Local RNRMA Local RNRMC RR-7 RR-7 RNRMA RNRMC R -10 Auxiliary bldg control board area monitor 85 ft 0.1 to E4 mR/hr GM South wall 0 0 RI-10 RM-10 Local RNRMA RR-10 RNRMA R -11 Containment air particulate monitor 100 ft 10 to E6 cpm Gamma Scint. Area GE 1 2 RM -11 RM -11 RNRMB RNRMD RR-11 RR-11 RNRMA RNRMC R -12 Containment air radioactive gas monitor 100 ft 10 to E6 cpm GM Area GE 1 2 RM -12 RM -12 RNRMB RNRMD RR-12 RR-12 RNRMA RNRMC R -13 RHR exhaust duct air particulate monitor 100 ft 10 to E6 cpm Gamma Scint Wall in north corridor at RHR ht exchg.area - area K for U-1 (South for U-2) 1 2 RM -13 RM -13 RNRMB RNRMD RR-13 RR-13 RNRMA RNRMC DCPP UNITS 1 & 2 FSAR UPDATE Table 11.4-1 Sheet 2 of 6 Revision 18 October 2008 RMS RMS Detector Unit(e) Readout(s) Channel Description Elevation Range Type Location No. Indication Location Recorder Location R -14 and R-14R Plant vent radioactive gas monitors 85ft 10 to 5E6 cpm Beta Scint Plant vent at NE wall/ penetration room - area L for U-1 (SE for U-2) 1 1 2 2 RM-14 RM-14R RM-14 RM-14R RNRMS3 RNRMS4 RNRMS3 RNRMS4 EARS(f) EARS(f) EARS(f) EARS(f) TSC TSC TSC TSC R -15 and R-15R Steam jet air ejector radioactive gas dischg. monitors 104ft 10 to 5E6 cpm Beta Scint. Turb. Bldg., Area C on wall at Col. line 10 between Col. lines C&D for U-1 (line 26 for U-2) 1 1 2 2 RM-15 RM-15R RM-15 RM-15R RNRMS4 RNRMS4 RNRMS4 RNRMS4 EARS(f) EARS(f) EARS(f) EARS(f) TSC TSC TSC TSC R -17A and R -17B CCW discharge header effluent monitors 73 ft 10 to E6 cpm Gamma Scint. Outside east door on wall at component cooling pump room 1 1 2 2 RM -17A RM -17B RM -17A RM -17B RNRMB RNRMB RNRMD RNRMD RR-17A RR-17B RR-17A RR-17B RNRME RNRME RNRMC RNRMC R -18 Liquid radwaste discharge line effluent monitor 55 ft 10 to E6 cpm Gamma Scint. Pipe tunnel from radwaste (north corridor) 0 RM -18 RNRME RR-18 RNRME R -19 Steam generator blowdown sample effluent monitor 100 ft 10 to E6 cpm Gamma Scint. SE side of containment structure/penetration room - area GE for U-1 (NE for U-2) 1 1 2 2 RI-19 RM -19A RI-19 RM -19A SGSP RNRMB SGSP RNRMD RR-19 RR-19 RNRME RNRMC R -22 Gas decay tank radioactive gas discharge monitor 55 ft 10 to E6 cpm GM Pipe tunnel 1 2 RM-22 RM-22 RNRME RNRMC RR-22 RR-22 RNRME RNRMC R -23 Steam generator blowdown tank effluent to out-fall monitor 100 ft 1 to E6 cpm Gamma Scint. Area GE 1 1 2 2 RI-23 Scint. PM205 PM205 RR-23 RR-23A RR-23 RR-23A PM205 RNRME PM205 RNRMC R -24 and R-24R Plant vent iodine monitor 85ft 10 to 5E6 cpm Gamma Scint. Plant vent at area L 1 1 2 2 RM-24 RM-24R RM-24 RM-24R RNRMS3 RNRMS4 RNRMS3 RNRMS4 EARS(f) EARS(f) EARS(f) EARS(f) TSC TSC TSC TSC R -25 Main control room air intake monitor 160 ft 0.01 to E3 mR/hr Gamma Scint. Auxiliary bldg. control room air intake 1 2 RI-25 RI-25 RCRM RCRM - - R -26 Main control room air intake monitor 160 ft 0.01 to E3 mR/hr Gamma Scint. Auxiliary bldg. control room air intake 1 2 RI-26 RI-26 RCRM RCRM - - DCPP UNITS 1 & 2 FSAR UPDATE Table 11.4-1 Sheet 3 of 6 Revision 18 October 2008 RMS RMS Detector Unit(e) Readout(s) Channel Description Elevation Range Type Location No. Indication Location Recorder Location R -28 and R-28R Plant vent air particulate monitors 85ft 10 to E6 cpm Beta Scint. Plant vent at NE wall to containment structure/penetration room - area L, for U-1 (SE for U-2) 1 1 2 2 RM-28 RM-28R RI-28 RI-28R RNRMS3 RNRMS4 RNRMS3 RNRMS4 EARS(f) EARS(f) EARS(f) EARS(f) TSC TSC TSC TSC R -29 Plant vent high radiation gross gamma monitor 155 ft 0.1 to E7 mR/hr ION Plant vent on platform on NW side of duct for U-1 (SW for U-2) 1 2 RI-29 RI-29A RI-29 PAM-2 Local PAM-2 RR-29 RR-29 PAM-2 PAM-2 R -30 Containment high range area radiation monitor - 1 140 ft 1 to E7 R/hr ION East stairway 1 2 RI-30 RI-30 PAM-2 PAM-2 RR-30 RR-30 PAM-1 PAM-1 R -31 Containment high range area radiation monitor - 2 140 ft 1 to E7 R/hr ION West stairway 1 2 RI-31 RI-31 PAM-2 PAM-2 RR-31 RR-31 PAM-1 PAM-1 R -34 Area Monitor for Plant Vent Monitoring Skid 85ft 0.1 to E7 mR/hr ION Plant vent at NE wall penetration room - Area L for U-1 (SE for U-2) 1 1 2 2 RC-22 RI-34 RC-22 RI-34 Local Local Local Local RR-34 RR-34 PAM-2 PAM-2 R-41 Gas decay tank cubicle radiation monitor (1-1, 2-1) 64 ft 1 to E4 mR/hr ION Gas decay tank 1 1 2 RI-41 RI-41 ABCP ABCP - - - 2 R-42 Gas decay tank cubicle radiation monitor (1-2, 2-2) 64 ft 1to E4 mR/hr ION Gas decay tank 2 1 2 RI-42 RI-42 ABCP ABCP - - R-43 Gas decay tank cubicle radiation monitor (1-3, 2-3) 64 ft 1 to E4 mR/hr ION Gas decay tank 3 1 2 RI-43 RI-43 ABCP ABCP - - R-44A and R-44B Containment Purge Exhaust 100 ft 10 to 5E6 cpm Beta Scint. Area L 1 1 2 2 RM-44A RM-44B RM-44A RM-44B RNRMS1 RNRMS2 RNRMS1 RNRMS2 EARS(f) EARS(f) EARS(f) EARS(f) TSC TSC TSC TSC R -48 HRSS (Sentry) post-accident sampling room 85 ft 0.1 to E7 mR/hr ION HRSS 1 2 RI-48 RI-48 POPLSI POPLSI - - DCPP UNITS 1 & 2 FSAR UPDATE Table 11.4-1 Sheet 4 of 6 Revision 18 October 2008 RMS RMS Detector Unit(e) Readout(s) Channel Description Elevation Range Type Location No. Indication Location Recorder Location R -51 Control room pressurization system ventilation intake air monitor 140ft 0.01 to E4 mR/hr GM NW corner of turbine building 1 RI-51 RCRM - - R -52 Control room pressurization system ventilation intake air monitor 140 ft 0.01 to E4 mR/hr GM NW corner of turbine building 1 RI-52 RCRM - - R -53 Control room pressurization system ventilation intake air monitor 140ft 0.01 to E4 mR/hr GM SW corner of turbine building 2 RI-53 RCRM - - R -54 Control room pressurization system ventilation intake air monitor 140 ft 0.01 to E4 mR/hr GM SW corner of turbine building 2 RI-54 RCRM - - R -58 Spent Fuel Pool Area Monitor 140 ft 0.1 to E4 mR/hr GM West wall column line 111 and 251 1 1 2 2 RI-58 RI-58A RI-58 RI-58A Local PAM-2 Local PAM-2 RR-58 RR-58 RNRMA RNRMC R -59 New Fuel Storage Area Monitor 140 ft 0.1 to E4 mR/hr GM West wall column line 153 and 203 1 1 2 2 RI-59 RI-59A RI-59 RI-59A Local PAM-2 Local PAM-2 RR-59 RR-59 RNRMA RNRMC R -60 TSC-Office Area Radiation Monitor 104 ft 0.1 to E4 mR/hr GM East wall at exit door 0 RI-60 Local RR-60 Local R -61 TSC-Operations/RMS Area Monitor 104 ft 0.1 to E4 mR/hr GM South wall at doorway 0 RI-61 Local RR-61 Local R -62 TSC-Computations Center Area Monitor 104 ft 0.1 to E4 mR/hr GM South wall at doorway 0 RI-62 Local RR-62 Local R -63 TSC-NRC Office Area Monitor 104 ft 0.1 to E4 mR/hr GM North wall at doorway 0 RI-63 Local RR-63 Local R -64 TSC-HVAC Equipment room area monitor 104 ft 0.1 to E4 mR/hr GM East wall at midpoint 0 RI-64 Local RR-64 Local R -65 TSC-laboratory area monitor 104 ft 0.1 to E4 mR/hr GM North wall at midpoint 0 RI-65 Local RR-65 Local DCPP UNITS 1 & 2 FSAR UPDATE Table 11.4-1 Sheet 5 of 6 Revision 18 October 2008 RMS RMS Detector Unit(e) Readout(s) Channel Description Elevation Range Type Location No. Indication Location Recorder Location R -66 TSC-air particulate monitor 104 ft 10 to E6 cpm Beta Scint. TSC-HVAC equipment room 0 RI-66 Local RR-66 Local R -67 TSC-noble gas monitor 104 ft 10 to E6 cpm Beta Scint. TSC-HVAC equipment room 0 RI-67 Local RR-67 Local R -68 TSC-laboratory air particulate monitor 104 ft 10 to E6 cpm Beta Scint. TSC-HVAC equipment room 0 RI-68 Local RR-68 Local R -69 TSC-laboratory noble gas monitor 104 ft 10 to E6 cpm Beta Scint. TSC-HVAC equipment room 0 RI-69 Local RR-69 Local R -71 Main steam line noble gas radiation monitor (lead 1) 130 ft 10 to E6 cpm GM Outside NW side of containment - area FW for U-1 (SW for U-2) 1 2 RI-71 RI-71 RNGFFD RNGFFD RR-71 RR-71 RNRME RNRMC R-72 Main steam line noble gas radiation monitor (lead 2) 130 ft 10 to E6 cpm GM Outside NW side of containment - area FW for U-1 (SW for U-2) 1 2 RI-72 RI-72 RNGFFD RNGFFD RR-72 RR-72 RNRME RNRMC R-73 Main steam line noble gas radiation monitor (lead 3) 130 ft 10 to E6 cpm GM Outside containment area GW 1 2 RI-73 RI-73 RNGFFD RNGFFD RR-73 RR-73 RNRME RNRMC R-74 Main steam line noble gas radiation monitor (lead 4) 130 ft 10 to E6 cpm GM Outside containment area GW 1 2 RI-74 RI-74 RNGFFD RNGFFD RR-74 RR-74 RNRME RNRMC R-82 TSC-iodine monitor 104 ft 10 to E6 cpm Gamma Scint. TSC-HVAC equipment room 0 RI-82 Local RR-82 RMPTSC R-83 TSC-laboratory iodine monitor 104 ft 10 to E6 cpm Gamma Scint. TSC-HVAC equipment room 0 RI-83 Local RR-83 RMPTSC R-84 Contact inspection station radiation monitor 115 ft 0.1 to E3 R/hr ION Chamber Solid radwaste storage area 0 RM-84 Local - - R-85 One-meter inspection station radiation monitor 115 ft 0.1 to E3 R/hr ION Chamber Solid radwaste storage area 0 RM-85 Local - - R-87 Plant vent extended range radioactive gas monitors 85 ft 10-4 to 105 µCi/cc Beta Scint. Plant vent at NE walls/penetration room - area L for U-1 (SE for U-2) 1 2 RM-14 RM-14 RNRMS3 RNRMS3 EARS(f) EARS(f) TSC TSC DCPP UNITS 1 & 2 FSAR UPDATE Table 11.4-1 Sheet 6 of 6 Revision 18 October 2008 RMS RMS Detector Unit(e) Readout(s) Channel Description Elevation Range Type Location No. Indication Location Recorder Location R-90 R/W Storage 115 ft 0.1 to E4 mR/hr GM R/W Storage Truck Bay 0 RI-90A RI-90B Local Mechanical RM Control RM - - R-92 Laundry facility 132 ft 10 to E5 cpm GM Laundry RM 0 - - RR-92 Local RF-87A and RF-87B Particulate and iodine grab sampling assembly (Post Accident) 85 ft Plant vent at NE wall/penetration room - area L for U-1 (SE for U-2) 1 2 - - - - - - - - RX-55 Laundry and Radwaste Facility Exhaust Sampler 115 ft Ventilation room Old Radwaste Building 0 RX-56 Radwaste Storage and Laundry Facility Exhaust Sampler 142 ft Mezzanine Area New Radwaste Building 0 (a) Deleted in Revision 4 (b) Deleted in Revision 9 (c) Deleted in Revision 11 (d) Post-LOCA sampling control panel (e) Units designation: 0 = 1 monitor common to both Units 1 = Unit 1 monitor 2 = Unit 2 monitor (f) EARS shall be used as recording method as necessary until the Central Radiation Processor is installed
Symbol Location 1 ABCP Auxiliary building control panel, elevation 85 ft 11 RNRMA Radiation monitor rack A, control room 2 ABRV Auxiliary building roof vent access area 12 RNRMB Radiation monitor rack B, control room 3 RNGFFD Main steam line radiation monitor rack, control room 13 RNRMC Radiation Monitor rack C, control room 4 HRSS Sentry high radiation sampling room 14 RNRMD Radiation Monitor rack D, control room 5 PAM-1 Post accident monitor panel 1, control room 15 RNRME Radiation monitor rack E, control room 6 PAM-2 Post accident monitor panel 2, control room 16 SGSP Steam generation sample panel 7 POPLSI Post-LOCA sampling control panel 17 RMPTSC Radiation monitor panel, TSC 8 PM197 Panel 197, access area of auxiliary building 9 PM205 Mechanical panel 205, auxiliary building 10 RCRM Rack control room monitor - Unit 2 side control room[P-11.4(1)]
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.4-3 RADIATION MONITOR - VALVE CONTROL OPERATIONS Radiation Element Affected Valves Effect RE-17A and RE-17B SV225, RCV16 Close CCW surge tank vent.
RE-18 SV233, RCV18, FCV477 Liquid radwaste control valves: Close liquid radwaste over-board and open liquid radwaste equipment drain receiver dump. RE-23 SV237, FCV160, SV238, FCV157, SV239, FCV154, SV240, FCV151, SV242, FCV498, SV241, FCV499 (a) High radiation (1) close steam generators 1 to 4 blowdown tank inlet and sample, (2) close steam generator blowdown tank outlet, (3) close blowdown tank outlet to discharge tunnel and open blowdown tank outlet to equipment drain receiver; (b) Power loss to RE (1) close steam generators 1 to 4 blowdown tank inlet and sample, (2) close steam generator blowdown tank outlet, (3) close blowdown tank outlet to discharge tunnel and open blowdown tank outlet to equipment drain receiver. RE-19 SV237, FCV160, SV238, FCV157, SV239, FCV154, SV240, FCV151, SV242, FCV498, SV241, FCV499 High radiation (1) close steam generators 1 to 4 blowdown tank inlet and sample, (2) close steam generator blowdown tank outlet, (3) close blowdown tank outlet to discharge tunnel and open blowdown tank outlet to equipment drain receiver. RE-51, RE-52, RE-53, and RE-54 - Initiate control room pressurization system. RE-44A and RE-44B Trains A and B containment vent isolation valves Closure.
RE-22 SV218, RCV17 Gaseous radwaste vent closure.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.5-1 SOLID RADWASTE SYSTEM INPUT VOLUMES
Source Design Basis Volume Normal Operation Volume Bases Boric acid waste 11,700 gal/yr 23,190 gal/yr EPRI NP-3370 concentrates
Spent ion exchange resin 1,600 ft3/yr 1,600 ft3/yr EPRI NP-3370 Expended filtration/ion 400 ft3/yr 400 ft3/yr 12 beds/yr exchange media Spent filter cartridges 240/yr 240/yr EPRI NP-3370 (requiring encapsulation)
Dry active waste 210 boxes 180 boxes EPRI NP-3370, EPRI NP-2900 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.5-2 Sheet 1 of 2 Revision 11 November 1996 ACTIVITY IN RADWASTE SYSTEM DEMINERALIZERS NORMAL OPERATION CASE (CURIES/YEAR)
Primary Primary Letdown Letdown Letdown Spent Fuel Nuclide Mxd Bed Demin Cation Demin Mxd Bed Demin Cation Demin Anion Demin Pool Demin H-3 0.0 0.0 0.0 0.0 0.0 0.0 Cr-51 0.281E 02 0.309E-00 0.179E-02 0.179E-04 0.0 0.119E-04 Mn-54 0.282E 02 0.310E-00 0.289E-02 0.289E-04 0.0 0.693E-04 Fe-55 0.227E 01 0.249E-01 0.111E-05 0.111E-07 0.0 0.856E-13 Co-58 0.587E 03 0.646E 01 0.515E-01 0.515E-03 0.0 0.863E-03 Fe-59 0.238E 02 0.262E 00 0.185E-02 0.185E-04 0.0 0.225E-04 Co-60 0.250E 03 0.275E 01 0.267E-01 0.267E-03 0.0 0.983E-04 Sr-89 0.740E 01 0.814E-01 0.600E-03 0.600E-05 0.0 0.190E-04 Sr-90 0.175E 01 0.192E-01 0.188E-03 0.188E-05 0.0 0.113E-04 Y-90 0.173E 01 0.190E-01 0.186E-03 0.186E-05 0.0 0.112E-04 Sr-91 0.384E-01 0.422E-03 0.102E-20 0.102E-22 0.0 0.976E-10 Y-91 0.377E-01 0.415E-03 0.101E-20 0.101E-22 0.0 0.960E-10 Sr-92 0.436E-02 0.479E-04 0.310E-62 0.310E-64 0.0 0.934E-12 Y-92 0.436E-02 0.479E-04 0.310E-62 0.310E-64 0.0 0.934E-12 Zr-95 0.231E 01 0.255E-01 0.199E-03 0.199E-05 0.0 0.248E-04 Nb-95 0.349E 01 0.384E-01 0.323E-03 0.323E-05 0.0 0.391E-04 Mo-99 0.0 0.0 0.0 0.0 0.0 0.0 I-131 0.138E 04 0.0 0.265E 00 0.0 0.265E-04 0.216E-02 Te-132 0.586E 02 0.0 0.776E-03 0.0 0.776E-08 0.472E-04 I-132 0.648E 02 0.0 0.801E-03 0.0 0.102E-07 0.487E-04 I-133 0.205E-03 0.0 0.144E-07 0.0 0.144E-11 0.165E-05 Cs-134 0.146E 04 0.131E 03 0.401E 01 0.361E 01 0.0 0.817E-02 I-134 0.113E 01 0.0 0.0 0.0 0.0 0.730E-10 I-135 0.361E 02 0.0 0.971E-24 0.0 0.971E-28 0.225E-07 Cs-136 0.237E 02 0.213E 01 0.217E-01 0.195E-01 0.0 0.119E-04 Cs-137 0.301E 04 0.271E 03 0.843E 01 0.759E 01 0.0 0.255E-01 Ba-140 0.315E 01 0.346E-01 0.109E-03 0.109E-05 0.0 0.422E-05 La-140 0.330E 01 0.362E-01 0.125E-03 0.125E-05 0.0 0.476E-05 Ce-144 0.357E 01 0.393E-01 0.365E-03 0.365E-05 0.0 0.159E-04 Pr-144 0.357E-01 0.393E-01 0.365E-03 0.365E-05 0.0 0.159E-04 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.5-2 Sheet 2 of 2 Revision 11 November 1996 Primary Primary Letdown Letdown Letdown Spent Fuel
Nuclide Mxd Bed Demin Cation Demin Mxd Bed Demin Cation Demin Anion Demin Pool Demin H-3 0.0 0.0 0.0 0.0 0.0 0.0 Cr-51 0.281E 02 0.309E-00 0.179E-02 0.179E-04 0.0 0.119E-04 Mn-54 0.282E 02 0.310E-00 0.289E-02 0.289E-04 0.0 0.693E-04 Fe-55 0.227E 01 0.249E-01 0.111E-05 0.111E-07 0.0 0.856E-13 Co-58 0.588E 03 0.646E 01 0.516E-01 0.516E-03 0.0 0.863E-03 Fe-59 0.238E 02 0.262E 00 0.185E-02 0.185E-04 0.0 0.225E-04 Co-60 0.250E 03 0.275E 01 0.267E-01 0.267E-03 0.0 0.983E-04 Sr-89 0.617E 02 6.679E 00 0.500E-02 0.500E-04 0.0 0.566E-04 Sr-90 0.146E 02 0.160E 00 0.156E-02 0.156E-04 0.0 0.684E-04 Y-90 0.144E 02 0.158E 00 0.155E-02 0.155E-04 0.0 0.677E-04 Sr-91 0.320E 00 0.352E-02 0.853E-20 0.853E-22 0.0 0.980E-10 Y-91 0.315E 00 0.346E-02 0.840E-20 0.840E-22 0.0 0.964E-10 Sr-92 0.363E-01 0.399E-03 0.258E-61 0.258E-63 0.0 0.934E-12 Y-92 0.363E-01 0.399E-03 0.258E-61 0.258E-63 0.0 0.934E-12 Zr-95 0.193E 02 0.212E 00 0.166E-02 0.166E-04 0.0 0.401E-04 Nb-95 0.291E 02 0.320E 00 0.270E-02 0.270E-04 0.0 0.672E-04 Mo-99 0.0 0.0 0.0 0.0 0.0 0.0 I-131 0.115E 05 0.0 0.221E 01 0.0 0.221E-03 0.280E-02 Te-132 0.489E 03 0.0 0.647E-02 0.0 0.647E-07 0.525E-04 I-132 0.540E 03 0.0 0.668E-02 0.0 0.853E-07 0.543E-04 I-133 0.171E 04 0.0 0.120E-06 0.0 0.120E-10 0.194E-05 Cs-134 0.120E 05 0.108E 04 0.331E 02 0.298E 02 0.0 0.345E-01 I-134 0.941E 01 0.0 0.0 0.0 0.0 0.730E-10 I-135 0.301E 03 0.0 0.809E-23 0.0 0.809E-27 0.225E-07 Cs-136 0.197E 03 0.178E 02 0.181E 00 0.163E 00 0.0 0.336E-04 Cs-137 0.251E 05 0.226E 04 0.702E 02 0.632E 02 0.0 0.131E 00 Ba-140 0.263E 02 0.289E 00 0.906E-03 0.906E-05 0.0 0.713E-05 La-140 0.275E 02 0.302E 00 0.104E-02 0.104E-04 0.0 0.792E-05 Ce-144 0.298E 02 0.327E 00 0.305E-02 0.305E-04 0.0 0.868E-04 Pr-144 0.289E 02 0.327E 00 0.305E-02 0.305E-04 0.0 0.869E-04
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.5-4 ACTIVITY COLLECTED IN RADWASTE FILTER CARTRIDGES AT TIME OF REPLACEMENT(a) (CURIES) DESIGN BASIS CASE RCC Letdown(b) Radwaste(c) Nuclide Primary Loop Ion Exchge Concentrates Condensate 0-1 0-2 0-3 H-3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Cr-51 0.148E 00 0.429E-07 0.214E-07 0.214E-10 0.418E-05 0.731E-03 0.212E-05 Mn-54 0.669E-01 0.312E-07 0.156E-07 0.156E-10 0.268E-05 0.475E-03 0.136E-05 Fe-55 0.125E-01 0.280E-10 0.140E-10 0.140E-13 0.165E-07 0.153E-05 0.833E-08 Co-58 0.232E 01 0.925E-06 0.462E-06 0.462E-09 0.827E-04 0.146E-01 0.421E-04 Fe-59 0.112E 00 0.396E-07 0.198E-07 0.198E-10 0.365E-05 0.643E-03 0.186E-05 Co-60 0.481E 00 0.234E-06 0.117E-06 0.117E-09 0.198E-04 0.352E-02 0.101E-04 NORMAL OPERATION CASE RCC Letdown(b) Radwaste(c) Nuclide Primary Loop Ion Exchge Concentrates Condensate 0-1 0-2 0-3 H-3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Cr-51 0.148E 00 0.428E-07 0.214E-07 0.214E-10 0.372E-06 0.446E-02 0.441E-06 Mn-54 0.669E-01 0.312E-07 0.156E-07 0.156E-10 0.184E-06 0.356E-02 0.301E-06 Fe-55 0.125E-01 0.280E-10 0.140E-10 0.140E-13 0.125E-07 0.313E-05 0.637E-08 Co-58 0.232E 01 0.924E-06 0.462E-06 0.462E-09 0.620E-05 0.102E 00 0.904E-05 Fe-59 0.112E 00 0.396E-07 0.198E-07 0.198E-10 0.292E-06 0.427E-02 0.393E-06 Co-60 0.481E 00 0.234E-06 0.117E-06 0.117E-09 0.134E-05 0.269E-01 0.225E-05
(a) Three cartridge replacements per cycle.
(b) As Designated on Figure 11.5-6. (c) As Designated on Figure 11.5-8.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 11.5-5 SUMMARY OF RADWASTE MATERIALS SHIPMENT Quantity Quantity Possible per Shipments Shipment Material per Year Shipment per Year Method Packaged wastes Solidified liquid concentrates 0 ft3 100 ft3 0 truck Class B/C Resins 160 ft3 80 ft3 2 truck Class A Resin 400 ft3 200 ft3 2 truck Spent filter cartridges 240 100 2 truck
Filtration/ion exchange media 60 ft3 200 ft3 1/2 truck Dry active wastes 50 boxes 10 boxes 5 truck
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.6-1 Sheet 1 of 2 RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM Revision 12 September 1998 Exposure Pathway Number of Samplesand Sampling and Type and/or Sample Sample Locations Collection Frequency of Analysis
- 1. Airborne
Radioiodine and particulates 4 stations Continuous sampler operation with sample collection weekly, or more frequently if required by dust loading Radioiodine canister. I-131 analysis weekly.
Particulate sampler. Analyze for gross beta radioactivity 24 hours following filter change. Perform gamma isotopic analysis on each sample when gross beta activity is > 10 times the yearly mean of control samples. Perform gamma isotopic analysis on composite (by location) quarterly.
- 2. Direct radiation 30 stations, 2 phosphors at each location Quarterly Gamma dose. Quarterly. 3. Waterborne
- a. Drinking 1 station Monthly grab sample I-131 analysis, gamma isotopic analysis monthly, and tritium analysis quarterly.
- b. Surface 1 station Monthly grab sample Gamma isotopic analysis monthly. Tritium analysis quarterly.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.6-1 Sheet 2 of 2 Revision 12 September 1998 Exposure Pathway Number of Samples and Sampling and Type and/or Sample Sample Locations Collection Frequency of Analysis
- 4. Ingestion
- a. Milk Samples from milking animals in three locations within 5 km distance having the highest dose potential. If there are none, then one sample from milking animals in each of three areas from 5 to 8 km distant where doses are calculated to be greater than 1 mrem per yr. One sample from milking animals at a control location 15 to 30 km distant and in the least prevalent wind direction. Semimonthly when animals are on pasture; monthly at other times Gamma isotopic and I-131 analysis. b. Fish and Invertebrates >2 stations Sample in season, or semi-annually if they are not seasonal Gamma isotopic analysis on edible portions.
- c. Food products > 2 stations (if available) Monthly during growing season portion (if available) Gamma isotopic analysis on edible.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.6-4 Sheet 1 of 5 ENVIRONMENTAL RADIOLOGICAL MONITORING PROGRAM SUMMARY (PREOPERATIONAL RESULTS) Revision 18 October 2008 Medium or Pathway Type and Total Lower Limit All Control Sampled Number of of Location Locations Number of (Unit of Analyses Detection(a) Name, Distance(d) Mean(1)(b) Mean(1)(b) Reportable Measurement) Performed (LLD) and Direction Range(b) Range(b) Occurrences Seawater, Tritium (12) - - None detected - 0 (pCi. L-1) Gamma Isotopic (36) - - None detected - 0 54Mn None detected 59Fe 3.79x102(c) None detected 58Co None detected 60Co None detected 65Zn None detected 95Zr None detected 95Nb None detected 131I None detected 134Cs None detected 137Cs None detected 140Ba 2.14x103(c) None detected 140La 6.09x102(c) None detected Surface water Tritium (12) - - None detected - 0 (pCi. L-1) Gross Beta (12) - Sta. 5S2, 2.94(12/12) - 0 0.6 mi, 65° 2.24-3.58
Gamma Isotopic - 0 54Mn None detected 59Fe None detected 58Co None detected 60Co None detected 65Zn None detected DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.6-4 Sheet 2 of 5 Revision 18 October 2008 Medium or Pathway Type and Total Lower Limit All Control Sampled Number of of Location Locations Number of (Unit of Analyses Detection(a) Name, Distance(d) Mean(1)(b) Mean(1)(b) Reportable Measurement) Performed (LLD) and Direction Range(b) Range(b) Occurrences 95Zr None detected 95Nb None detected 131I None detected 134Cs None detected 137Cs None detected 140Ba 1.35x102(c) None detected 140La 3.48x101(c) None detected Drinking water Tritium (12) - None detected - 0 (pCi. L-1) Gross Beta (12) Sta. D W1, 2.4 (8/12) - 0 0.0 mi, 2.24-4.09 in plant
131-Iodine (12) None detected - 0
Gamma Isotopic (12) - 0 54Mn None detected 59Fe None detected 58Co None detected 60Co None detected 65Zn None detected 95Zr None detected 95Nb None detected 131I None detected 134Cs None detected 137Cs None detected 140Ba None detected 140La None detected DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.6-4 Sheet 3 of 5 Revision 18 October 2008 Medium or Pathway Type and Total Lower Limit All Control Sampled Number of of Location Locations Number of (Unit of Analyses Detection(a) Name, Distance(d) Mean(1)(b) Mean(1)(b) Reportable Measurement) Performed (LLD) and Direction Range(b) Range(b) Occurrences Outfall Tritium (18) - None detected - 0 (pCi. L-1) Gamma Isotopic (18) None detected 54Mn None detected 59Fe None detected 58Co None detected 60Co None detected 65Zn None detected 95Zr None detected 95Nb None detected 131I None detected 134Cs None detected 137Cs None detected 140Ba 2.74x103(c) None detected 140La 8.35x102(c) None detected Airborne 131I (507) - None detected 0.108 (3/211) 0 (pCi. m-3) 0.0137-0.159 Gross Beta - 0.012(296/296) 0.010(211/211)
(507) 0.004-0.033 0.005-0.033
Gamma Isotopic (507) - - 0 134Cs None detected None detected 137Cs None detected None detected
Fish and Gamma Isotopic - - 0 seafood (79) (pCi. kg-1) 54Mn 1.46x102 None detected None detected DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.6-4 Sheet 4 of 5 Revision 18 October 2008 Medium or Pathway Type and Total Lower Limit All Control Sampled Number of of Location Locations Number of (Unit of Analyses Detection(a) Name, Distance(d) Mean(1)(b) Mean(1)(b) Reportable Measurement) Performed (LLD) and Direction Range(b) Range(b) Occurrences 59Fe 5.19x102 None detected None detected 58Co 1.74x102 None detected None detected 60Co 2.02x102 None detected None detected 65Zn - None detected None detected 134Cs 1.50x102 None detected None detected 137Cs 1.46x102 None detected 16.4 (5/57) Milk 131I (30) - None detected None detected 0 (pCi. L-1) Gamma Isotopic (30) - 0 134Cs None detected None detected 137Cs None detected None detected 140Ba None detected None detected 140La None detected None detected
Food Gamma - - 0 products Isotopic (36) (pCi. kg-1) 131I 6.65x101 None detected None detected 134Cs None detected None detected 137Cs None detected None detected DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.6-4 Sheet 5 of 5 Revision 18 October 2008 Medium or Pathway Type and Total Lower Limit All Control Sampled Number of of Location Locations Number of (Unit of Analyses Detection(a) Name, Distance(d) Mean(1)(b) Mean(1)(b) Reportable Measurement) Performed (LLD) and Direction Range(b) Range(b) Occurrences Direct TLD Packets 1 mR/mo(e) Sta. 3S1(f) 77.2(313/313) Sta. 2F2 and 0 radiation (335) 0.4 mi, 23° 49.6-106.9 4D1 (mR) mR/yr 62.0(22/22) 67.8-66.2 mR/yr 8.9 (11/11(f) 7.9-10.1 mR/mo (106.9 mR/yr) (a) Unless specified, all required LLDs were met. (b) Mean and range based upon detectable measurements only. Fraction of detectable measurements at specified locations is indicated in parentheses (1); e.g., (10/12) means 10 samples out of 12 collected showed activity. (c) A priori LLD not met due to elapse time between collection and count dates, short half-life of nuclide involved, and equipment failure. Value listed is worst case. (d) Only one station location for this sample type; therefore, no control or indicator stations are listed. (e) Sensitivity of TLD system. (f) Indicator location with Highest Annual Mean. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.6-11 Sheet 1 of 2 Revision 12 September 1998 MAXIMUM VALUES FOR THE LOWER LIMITS OF DETECTION (LLD) Airborne Food Particulate Fish Products Sediment Water or Gases (pCi/kg, Milk (pCi/kg, (pCi/kg, Analysis (pCi/l) (pCi/m3) wet) (pCi/l) wet) dry) Gross beta 4 0.01 H-3 2000* Mn-54 15 130 Fe-59 30 260 Co-58, 60 15 130 Zn-65 30 260 Zr- Nb -95 15 I-131 1** 0.07 1 60 Cs-134 15 0.05 130 15 60 150 Cs-137 18 0.06 150 18 80 180 Ba- La -140 15 15
- For surface water samples, a value of 3000 pCi/l may be used.
- If no drinking water pathway exists, a value of 15 pCi/l may be used.
Table Notation The LLD is defined, for purposes of these specifications, as the smallest concentration of radioactive material in a sample that will yield a net count, above system background, that will be detected with 95 percent probability with only 5 percent probability of falsely concluding that a blank observation represents a "real" signal. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 11.6-11 Sheet 2 of 2 Revision 12 September 1998 For a particular measurement system (which may include radiochemical separation): t)(Yexp22.2VEbS4.66LLDxxx= where:
LLD is "a priori" the lower limit of detection as defined above (as pCi per unit mass or volume)
Sb is the standard deviation of the background counting rate or of the counting rate of a blank sample as appropriate (as counts per minute) E is the counting efficiency (as counts per transformation)
V is the sample size (in units of mass or volume)
2.22 is the number of transformations per minute per picocurie
Y is the fractional radiochemical yield (when applicable) is the radioactive decay constant for the particular radionuclide t is the elapsed time between sample collection (or end of the sample collection period) and time of counting The value of Sb used in the calculation of the LLD for a detection system will be based on the actual observed variance of the background counting rate or of the counting rate of the blank samples (as appropriate) rather than on an unverified theoretically predicted variance. In calculating the LLD for a radionuclide determined by gamma ray spectrometry, the background will include the typical contributions of other radionuclides normally present in the samples (e.g., potassium-40 in milk samples). Analyses will be performed in such a manner that the stated LLDs will be achieved under routine conditions. Occasionally, background fluctuations, unavoidably small sample sizes, the presence of interfering nuclides, or other uncontrollable circumstances may render these LLDs unachievable. In such cases, the contributing factors will be identified and described in the Annual Environmental Radiological Operating Report.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.6-13 ESTIMATED RELATIVE CONCENTRATIONS )/(Q(a) 22-1/2° Radial Sectors Nearest NW NNW N NNE NE ENE E ESE SE Milk cow None None None None None None None None None
Meat animal N/A N/A N/A N/A N/A N/A N/A N/A N/A
Milk goat None None None None None None None None None
Residence 1.53X10-7 4.16X10-7 None 3.89X10-8 2.00X10-8 3.64X10-8 5.89X10-8 7.07X10-7(b) None Vegetable garden None None None None None None None None None Site boundary 3.44X10-6 2.70X10-6 1.51X10-6 8.25X10-7 1.62X10-7 9.18X10-8 1.07X10-7 5.20X10-7 1.32X10-6 (a) In units of seconds per cubic meter. (b) Vegetable farm has workers with residence occupancy factor of 1/2 for inhalation and group plane pathway.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 11.6-14 ESTIMATED DEPOSITIONS (/Q)(a) 22-1/2° Radial Sectors Nearest NW NNW N NNE NE ENE E ESE SE Milk cow None 1.21X10-10 6.52X10-11 4.09X10-11 4.48X10-11 6.13X10-11 1.13X10-10 3.79X10-10 Meat animal 1.50X10-8 6.71X10-9 3.47X10-9 2.18X10-9 1.43X10-9 1.64X10-9 1.67X10-9 5.53X10-9 3.55X10-8 Milk goat None None None None None None None None None
Residence 3.83X10-10 8.15X10-10 None 8.75X10-11 4.00X10-11 7.85X10-11 1.41X10-10 4.77X10-9 None Vegetable garden None None None None None None 1.41X10-10 4.77X10-9 None Site boundary 1.50X10-8 6.81X10-9 3.47X10-9 2.18X10-9 1.43X10-9 1.64X10-9 1.67X10-9 5.53X10-9 3.55X10-8 (a) In units of meters-2, includes sector width and frequency of winds in each sector.
FIGURE 11.2-2 LIQUID WASTE PROCESS FLOW DIAGRAM DESIGN BASIS CASE UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 20 November 2011 FIGURE 11.2-3 LIQUID WASTE PROCESS FLOW DIAGRAM NORMAL OPERATIONS CASE UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 20 November 2011
Revision 18 October 2008 FSAR UPDATEUNITS 1 AND 2 DIABLO CANYON SITE FIGURE 11.4-1 Sheet 1 of 2 RADIATION MONITORING SYSTEM Revision 18 October 2008 FSAR UPDATEUNITS 1 AND 2 DIABLO CANYON SITE FIGURE 11.4-1 Sheet 2 of 2 RADIATION MONITORING SYSTEM
FIGURE 11.5-3 SPENT RESIN FLOW DIAGRAM UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 20 November 2011
FIGURE 11.5-6 CHEMICAL AND VOLUME CONTROL SYSTEM DISPLAYING FILTERS UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 20 November 2011
DCPP UNITS 1 & 2 FSAR UPDATE i Revision 21 September 2013 Chapter 12 RADIATION PROTECTION CONTENTS Section Title Page 12.1 SHIELDING 12.1-1
12.1.1 Design Objectives 12.1-1
12.1.2 Design Description 12.1-2 12.1.2.1 Shielding Locations and Basic Configurations 12.1-2 12.1.2.2 General Shielding Design Criteria and Features 12.1-2 12.1.2.3 Containment Shielding Design 12.1-4 12.1.2.4 Fuel Handling Area Shielding Design 12.1-6 12.1.2.5 Auxiliary Building Shielding Design 12.1-6 12.1.2.6 Control Room Shielding Design 12.1-7 12.1.2.7 Technical Support Center Shielding Design 12.1-7 12.1.2.8 Postaccident Sampling Compartment 12.1-7 12.1.2.9 Old Steam Generator Storage Facility 12.1-8
12.1.3 Source Terms 12.1-8
12.1.4 Area Monitoring 12.1-9 12.1.5 Operating Procedures 12.1-9
12.1.6 Estimates of Exposure 12.1-10 12.1.6.1 Calculated Exposure Estimates 12.1-11 12.1.6.2 Exposure Estimates Based on Operating Plant Experience 12.1-11 12.1.6.3 Exposure Estimates for Diablo Canyon 12.1-11
12.1.7 References 12.1-12
12.2 VENTILATION 12.2-1
12.2.1 Design Objectives 12.2-1
12.2.2 Design Description 12.2-1 12.2.2.1 Containment Ventilation Systems 12.2-2 12.2.2.2 Control Room Ventilation System 12.2-2 12.2.2.3 Auxiliary Building Ventilation System 12.2-3
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 12 CONTENTS (Continued) Section Title Page ii Revision 21 September 2013 12.2.2.4 Fuel Handling Area Ventilation System 12.2-4 12.2.2.5 Turbine Building Ventilation 12.2-4 12.2.2.6 Technical Support Center Ventilation 12.2-4 12.2.2.7 Postaccident Sampling Compartment Ventilation 12.2-4
12.2.3 Source Terms 12.2-5 12.2.3.1 Auxiliary Building Source Terms 12.2-5 12.2.3.2 Fuel Handling Area Source Term 12.2-7 12.2.3.3 Containment Source Term 12.2-7 12.2.3.4 Turbine Building Source Term 12.2-8 12.2.3.5 Control Room Source Term 12.2-8 12.2.3.6 Technical Support Center Source Term 12.2-9
12.2.4 Airborne Radioactivity Monitoring 12.2-9 12.2.4.1 Process and Area Monitoring Systems 12.2-9 12.2.4.2 Routine Grab Sampling Program 12.2-9 12.2.4.3 Continuous Air Monitors 12.2-10
12.2.5 Operating Procedures 12.2-10
12.2.6 Estimates of Inhalation Doses 12.2-10
12.3 HEALTH PHYSICS PROGRAM 12.3-1
12.3.1 Program Objectives 12.3-1
12.3.2 Facilities and Equipment 12.3-1
12.3.3 Personnel Dosimetry 12.3-4
DCPP UNITS 1 & 2 FSAR UPDATE iii Revision 21 September 2013 Chapter 12 TABLES Table Title 12.1-1 Plant Zone Classifications
12.1-2 Principal Auxiliary Building Shielding
12.1-3 Maximum Activity in Liquid Holdup Tank
12.1-4 Maximum Activity in RCS Charging Pump
12.1-5 Maximum Activity in Waste Evaporator
12.1-6 Maximum Activity in Boric Acid Evaporator
12.1-7 Maximum Activity in Spent Fuel Pool
12.1-8 Maximum Activity in Monitor Tank and Waste Condensate Tank
12.1-9 Maximum Activity in Spent Resin Tank
12.1-10 Maximum Activity in Waste Concentrates Tank 12.1-11 Maximum Activity in Radwaste System Drain Tanks 12.1-12 Maximum Activity in Primary Water Storage Tank
12.1-13 Maximum Activity in Refueling Water Storage Tank
12.1-14 Radiation Exposure Rates from External Storage Tanks
12.1-15 Calculated Annual Man-rem Exposure of Plant Personnel
12.2-1 Design Values for Containment Ventilation System
12.2-2 Design Values for Control Room Ventilation System
12.2-3 Design Values for Auxiliary Building Ventilation System
12.2-4 Design Values for Fuel Handling Area Ventilation System
12.2-5 Estimated Airborne Activity Concentrations in Auxiliary Building Work Areas for Normal Operation DCPP UNITS 1 & 2 FSAR UPDATE Chapter 12 TABLES (Continued) Table Title iv Revision 21 September 2013 12.2-6 Estimated Airborne Activity Concentrations in Letdown Heat Exchanger Compartment for Normal Operation 12.2-7 Estimated Airborne Activity Concentrations in Volume Control Tank Compartment for Normal Operation 12.2-8 Estimated Airborne Activity Concentrations in Charging Pump Compartment for Normal Operation 12.2-9 Estimated Airborne Activity Concentrations in Gas Decay Tank Compartment for Normal Operation 12.2-10 Estimated Activity Concentrations in Spent Fuel Pool for Anticipated Operational Occurrences Case 12.2-11 Estimated Airborne Activity Concentrations in Fuel Handling Areas for Normal Operation 12.2-12 Estimated Airborne Activity Concentrations in Containment for Normal Operation
12.2-13 Estimated Airborne Activity Concentrations in Turbine Building for Normal Operation
12.2-14 Estimated Airborne Activity Concentrations at Control Room Intake for Normal Operation 12.2-15 Estimated Airborne Activity Concentrations in Control Room for Normal Operation
12.2-16 Deleted in Revision 19
12.2-17 Estimated Occupancy Factors for Plant Areas
12.2-18 Estimated Inhalation and Immersion Doses for Plant Areas
12.3-1 Health Physics Portable Instrumentation
12.3-2 Health Physics Air Sampling Instrumentation
12.3-3 Respirators Approved for Use at Diablo Canyon Power Plant for Protection Against Radioactive Materials DCPP UNITS 1 & 2 FSAR UPDATE v Revision 21 September 2013 Chapter 12 FIGURES Figure Title 12.1-1 Radiation Zone Map, Containment & Auxiliary Buildings, Plan at Elev. 60 and 64 ft 12.1-2 Radiation Zone Map, Containment & Auxiliary Buildings, Plan at Elev. 73 ft 12.1-3 Radiation Zone Map, Containment & Auxiliary Buildings, Plan at Elev. 85 ft 12.1-4 Radiation Zone Map, Containment & Auxiliary Buildings, Plan at Elev. 91 and 100 ft 12.1-5 Radiation Zone Map, Containment & Auxiliary Buildings, Plan at Elev. 115 ft 12.1-6 Radiation Zone Map, Containment & Auxiliary Buildings, Plan at Elev. 140 ft 12.1-7 Radiation Zone Map, Turbine Building, Plan at Elev. 85 ft 12.1-8 Radiation Zone Map, Turbine Building, Plan at Elev. 104 ft 12.1-9 Radiation Zone Map, Turbine Building, Plan at Elev. 119 ft
12.1-10 Radiation Zone Map, Turbine Building, Plan at Elev. 140 ft
12.1-11 Radiation Zone Map, Solid Radwaste Storage Facility
12.1-12 Radiation Zone Map, Radwaste Storage Building
DCPP UNITS 1 & 2 FSAR UPDATE 12.1-1 Revision 21 September 2013 Chapter 12 RADIATION PROTECTION
The purpose of this chapter is to demonstrate that both external and internal radiation dose resulting from operation of the Diablo Canyon Power Plant (DCPP) will be kept as low as is reasonably achievable (ALARA) and within applicable limits. 12.1 SHIELDING This section describes the radiation shielding objectives and design configuration, identifies and characterizes source terms, summarizes important features of the area radiation monitoring system, describes those operating procedures that ensure external dose is kept ALARA, and gives estimates of dose to operating personnel and persons proximate to the DCPP site boundary. 12.1.1 DESIGN OBJECTIVES The overall design objectives for shielding during normal operation, maintenance, and refueling, including anticipated operational occurrences, are:
(1) To protect all onsite personnel from external radiation dose to the extent that doses are maintained within the limits specified in 10 CFR 20 and are ALARA (2) To ensure that the maximum continuous occupancy external dose delivered to any point on the site boundary is consistent with the guidelines provided in Appendix I to 10 CFR 50 regarding the dose from plant effluents, and 40 CFR 190 for total dose to individuals in the general public (3) To provide sufficient access and occupancy time to various locations within the plant to allow personnel to conduct routine operation, refueling, and maintenance activities without exceeding the dose limits specified in 10 CFR 20 (4) To reduce potential neutron activation of equipment and mitigate the possibility of radiation-induced material damage In addition, the shielding is designed to provide adequate protection under all postulated accident conditions, including a loss of primary coolant, to achieve the following objectives: (1) To permit plant personnel to effect an orderly recovery from an accident condition DCPP UNITS 1 & 2 FSAR UPDATE 12.1-2 Revision 21 September 2013 (2) To ensure that the direct radiation from plant structures is sufficiently low so that the total dose at the site boundary from both direct radiation and effluents is within the limits specified in 10 CFR 100 for all postulated accident conditions (3) To permit continued operation of the other unit on the site in the unlikely event that a design basis accident occurs at one unit A postaccident radiation shielding design review for DCPP, as required by NUREG 0737 (Reference 7), was performed and is reported in Reference 1.
12.1.2 DESIGN DESCRIPTION This section discusses the specific design criteria for individual shielding systems required to achieve the overall objectives and describes the actual shielding design. 12.1.2.1 Shielding Locations and Basic Configurations Figure 1.2-1 shows a plot plan of the site and indicates the location of roads, major plant buildings, and switchyards. It should be noted that the plant site is not served by railroad facilities. Figure 1.2-2 presents a detail of the plant layout and shows the location of outside tanks that could house potentially radioactive materials.
Figures 1.2-4 through 1.2-9 provide scaled plan views of Unit 1 buildings that contain process equipment for treatment of radioactive fluids, and indicate locations and basic configurations of the shielding provided. Figures 1.2-10 through 1.2-12 show similar views of Unit 2 structures. Corresponding sectional views of Unit 1 structures including shielding are shown in Figures 1.2-21 through 1.2-26. Comparable sectional views of Unit 2 structures are shown in Figures 1.2-28 through 1.2-30. Units 1 and 2 are similar with respect to shielding design. 12.1.2.2 General Shielding Design Criteria and Features One of the principal design objectives for plant shielding is to reduce the expected radiation levels within plant structures to values that will allow plant personnel to gain access to normal work areas and remain there for sufficient time to perform required routine work without exceeding normal occupational dose limits. To implement this objective, plant areas capable of personnel occupancy are classified into one of five zones on the basis of expected frequency and duration of occupancy during routine operation, refueling, and maintenance(1). A maximum design dose rate criterion is defined for each zone; it is consistent with the previously stated overall shielding design objectives. Plant shielding is designed to ensure that radiation dose rates in all plant areas are below the classified zone limits. (1) Radiation zone maps show general zones. Background details may not be accurate. DCPP UNITS 1 & 2 FSAR UPDATE 12.1-3 Revision 21 September 2013 The radiation zone criteria are summarized in Table 12.1-1. The specific zoning for all plant areas during normal operation in Unit 1 is shown in Figures 12.1-1 through 12.1-12. Radiation zones for Unit 2 are similar to those for Unit 1.
Typical Zone 0 areas are the turbine building and turbine plant service areas, the control room, and the TSC. Typical Zone I areas are the auxiliary building work stations and corridors and the outer surfaces of the containment and auxiliary building. Zone II areas include the surface of the refueling water during refueling (except during movement of a fuel assembly) and the operating deck of the containment during reactor shutdown. Areas designated Zone III include the sampling room and reactor containment penetration areas, including ventilation, steam line, and electrical penetrations. Typical Zone IV areas are within the regions adjacent to the reactor coolant system (RCS) at power operation and the demineralizer and volume control tank spaces. The postaccident radiation levels within the plant structures are discussed in Reference 1.
The radiologically controlled areas (RCAs) within plant structures (Zones I, II, III, and IV) are separated by barriers from the uncontrolled areas (Zone 0) to avoid inadvertent entry of unauthorized personnel. Entrance into the radiologically controlled areas is normally made from a single access control station at the +85 foot elevation of the auxiliary building and is under procedural control. An auxiliary access control, located on the 140 ft elevation, may be utilized to provide more efficient access into the RCA, including containment buildings. Other access control stations may be temporarily established to support plant operations on an ad hoc basis. Within the radiologically control areas, all areas are appropriately marked and/or barricaded in accordance with 10 CFR 20 and other applicable regulations. Areas designated Zone IV, such as the room containing the equipment and floor drain receiver tanks and the waste concentrator tanks, are accessible to plant personnel only at infrequent intervals, for limited periods of time, and then under strict radiological control. The dry active waste and resin liner storage areas in the radwaste storage building are also designated as Zone IV.
Care has been taken to ensure that radiologically controlled area zones that are normally relatively low dose rate areas (i.e., Zones I and II) are not likely to be subjected to unexpected increases in dose rate due to the rapid introduction of radioactive materials into nearby process piping or other means. The routing of all plant piping is strictly controlled. Pipes that carry radioactive materials are routed in radiologically controlled access areas properly zoned for that level of activity.
Shielding is arranged to protect personnel from direct gamma radiation that could otherwise stream through piping penetrations. Reach rods are provided where necessary to permit the operator to remain behind shielding while operating valves. For the radwaste storage building, exposure of site workers is minimized through the use of concrete shielding around the stored material, remote handling of high activity liners, and controlled access to the storage building.
DCPP UNITS 1 & 2 FSAR UPDATE 12.1-4 Revision 21 September 2013 12.1.2.3 Containment Shielding Design Containment shielding is divided into four categories according to functions: primary shield, secondary shield, fuel handling shield, and accident shield. Each of these is discussed below. 12.1.2.3.1 Primary Shield The primary shield consists of the core baffle, water annuli, barrel-thermal shield (all of which are within the reactor vessel), the reactor vessel wall, and a concrete structure surrounding the reactor vessel.
The primary shield (or parts thereof) performs the following functions:
(1) Reduces the energy-dependent neutron flux incident on the reactor vessel to prevent material property changes that might unduly restrict operation of the plant (2) Attenuates reactor core neutron flux to prevent excessive activation of plant components and structures outside the primary shield (3) Limits the gamma flux in both the reactor vessel and primary shield concrete to avoid large temperature gradients and/or dehydration of the concrete (4) Reduces the radiation levels from reactor sources so that limited access is possible to certain areas within the reactor containment building during full power operation (5) Reduces the residual radiation from the core to levels that will permit access to the region between the primary and secondary shields at a reasonable time after shutdown The concrete structure immediately surrounding the reactor vessel extends up from the base of the containment and is an integral part of the main structural concrete support for the reactor vessel. It extends upward to join the concrete cavity over the reactor.
The reactor cavity, which is approximately rectangular in shape, extends upward to the operating floor. A steel shield plate is provided where each of the eight reactor coolant pipes penetrates the primary shield.
The primary concrete shield is air-cooled to prevent overheating and dehydration from the heat generated by radiation absorption in the concrete. Eight "windows" are provided in the primary shield for insertion of the out-of-core nuclear instrumentation. Cooling for this instrumentation is also provided by air.
DCPP UNITS 1 & 2 FSAR UPDATE 12.1-5 Revision 21 September 2013 12.1.2.3.2 Secondary Shield The secondary shield surrounds the primary shield and the reactor coolant loops and consists of the annular polar crane support wall, the concrete operating floor over the primary coolant loops, and the shell of the containment structure. The shell of the containment structure also serves as the accident shield.
The main function of the secondary shielding is to attenuate the radiation originating in the reactor and reactor coolant. Although the interior of the containment is a Zone IV area during full power operation, the secondary shielding is designed to reduce radiation levels to a point where limited access to certain areas within the containment is possible. The areas where limited accessibility is intended include the operating floor at elevation +140 feet and the annular areas between the crane wall and the containment shell on elevations +91 and +115 feet. The radiation levels in these areas are generally < 15 mR/hr. The secondary shield will also limit the full power dose rate outside the containment building to < 1 mrem/hr. 12.1.2.3.3 Fuel Handling Shield The reactor cavity, flooded during refueling operations, provides a temporary water shield above the components being withdrawn from the reactor vessel. The water height during movement of fuel assemblies is at least 23 feet above the reactor vessel flange. This height ensures that a minimum of 8 feet of water will be above the top of a withdrawn fuel assembly (about 9 feet of water above the active fuel). With upper internals in place, the water height during the unlatching of control rods is 23 feet above the fuel assemblies (12 feet above the reactor vessel flange). The fuel handling shield is designed to facilitate the removal and transfer of spent fuel assemblies and control rod clusters from the reactor vessel to the spent fuel pool. It is designed to attenuate direct radiation from spent fuel and control rod clusters to < 2.5 mR/hr at the refueling cavity water surface except during movement of a fuel assembly and as noted below.
The fuel handling shield also provides attenuation of radiation from the reactor vessel internals. During removal of the upper internals package, the control rod drive lead screws and top hat assemblies must be raised above the water surface producing temporary radiation levels in excess of 1 R/hr. In the stored position, the very top of the lead screws extend from the surface producing localized dose rates to operators in the immediate area of less than 100 mrem/hr. The general area dose rate at the side of the pool is less than 5 mrem/hr near the upper internals.
The refueling canal is a passageway connected to the reactor cavity and extending to the inside surface of the reactor containment. The canal is formed by two concrete walls that extend upward to the same height as the reactor cavity. During refueling, the canal is flooded with borated water to the same height as the reactor cavity.
DCPP UNITS 1 & 2 FSAR UPDATE 12.1-6 Revision 21 September 2013 The spent fuel assemblies and control rod clusters are remotely removed from the reactor containment through the horizontal spent fuel transfer tube and placed in the spent fuel pool. Concrete shielding and barriers protect personnel from radiation during the time a spent fuel assembly is being transferred from the containment to the spent fuel pool. 12.1.2.3.4 Accident Shield The accident shield consists of the reinforced concrete cylindrical containment shell that is capped by a hemispherical reinforced concrete dome. This shielding includes supplemental shielding in front of the containment penetrations.
The equipment access hatch is shielded by a solid concrete block shadow shield. The main function of the accident shield is to reduce radiation levels outside the containment building to an acceptable level following a design basis accident (DBA). 12.1.2.4 Fuel Handling Area Shielding Design Spent fuel is stored in the spent fuel pool located in the fuel handling area. This area is located in the auxiliary building adjacent to the containment. The basic shield configuration for the Unit 1 spent fuel pool is shown in plan views in Figure 1.2-5 and in sectional views in Figures 1.2-23 and 1.2-24.
Water is used to provide shielding over the spent fuel assemblies so visual observation of fuel handling operations can be realized. The depth of the pool provides a submergence for the top of a fuel assembly of at least 8 feet during normal fuel handling operations and 23 feet submergence while fuel is stored in the fuel racks. Pool water level is indicated, and any water removed from the pool must be pumped out since there are no gravity drains. The shielding for the fuel handling area restricts the dose rate to 5 mrem/hr in normally occupied areas. Dose rates at the surface of the spent fuel pool will normally be 10 mrem/hr. During transfer of a spent fuel assembly, the minimum water level above the active fuel will be about 9 feet. With a peak fuel assembly (1.55 times full power level) being transferred, the maximum calculated dose rate at the surface of the pool is 50 mrem/hr. However, dose rates to the operator on the refueling platform will be less than 20 mrem/hr. The calculated doses exclude any contribution to dose rate from radioactivity contained in the spent fuel pool water. For additional information on the spent fuel pool water, see Section 9.1.3.2. 12.1.2.5 Auxiliary Building Shielding Design The purpose of the shielding in the auxiliary building is to protect personnel working near various system components in the chemical and volume control system (CVCS), DCPP UNITS 1 & 2 FSAR UPDATE 12.1-7 Revision 21 September 2013 the residual heat removal system, the waste disposal system, the sampling system, and the auxiliary coolant systems. The general layout of the shielding in the auxiliary building is shown on plan views of Figures 1.2-4 through 1.2-9. Sectional views are included in Figures 1.2-21 through 1.2-23, 1.2-25, and 1.2-26.
The shielding provided for the auxiliary building is designed to limit the dose rate during normal operation to less than 1 mR/hr in normally occupied areas, and at or below 2.5 mR/hr in areas requiring periodic occupancy. In addition, the auxiliary building shielding is designed to provide limited access to areas within the building during the long-term recirculation phase following a loss-of-coolant accident (LOCA).
The auxiliary building shielding consists of concrete walls around equipment and piping that contain significant quantities of activity. Each equipment compartment is individually shielded so that compartments may be entered without having to shut down and/or decontaminate the adjacent system. In some cases, such as the tube withdrawal spaces for the abandoned boric acid and waste evaporators (shown in Figure 1.2-7), removable concrete block walls are provided to allow personnel access to equipment during maintenance periods. The shield material provided throughout the auxiliary building is regular concrete except for some of the shielding around the reactor coolant filter, which is high-density concrete. The principal auxiliary building shielding provided is tabulated in Table 12.1-2. 12.1.2.6 Control Room Shielding Design The control room shield consists of the concrete walls and roof of the control room. A plan view of the control room is shown in Figure 1.2-4, and sectional views are shown in Figures 1.2-25 and 1.2-26. Normal radiation levels in the control room are less than 0.5 mR/hr. The limiting case for shielding design is post-DBA conditions. The control room shielding is designed to limit the integrated doses under postaccident conditions to 2.5 rem to the whole body, which is well below the value of 5 rem specified in 10 CFR 50, General Design Criterion (GDC) 19. 12.1.2.7 Technical Support Center Shielding Design The Technical Support Center is designed to be habitable throughout the course of a DBA. Concrete shielding in the walls, roof, and floor is designed to limit the integrated doses under postaccident conditions to 2.5 rem to the whole body, consistent with the criterion for the control room. 12.1.2.8 Postaccident Sampling Compartment The sampling compartment is shielded from external sources by concrete walls and concrete support columns. Personnel should be able to perform necessary DCPP UNITS 1 & 2 FSAR UPDATE 12.1-8 Revision 21 September 2013 postaccident sampling operations without experiencing a radiation dose exceeding the limits specified in NUREG-0737. 12.1.2.9 Old Steam Generator Storage Facility The old steam generators (OSGs) and old reactor vessel head assemblies (ORVHAs) were removed from DCPP Units 1 and 2 during the steam generator and reactor vessel head replacement projects. These ten large components are temporarily stored in the OSG Storage Facility (OSGSF) specifically constructed for this purpose. The OSGSF meets the radwaste storage requirements for temporary storage of the OSGs and ORVHAs until site decommissioning. The radiological design of the OSGSF meets the radiation shielding requirements of 40 CFR 190, 10 CFR 20, and the DCPP License. The building is designed to have a maximum contact dose rate of 0.2 mR/hr on the exterior wall surface. This value is less than and is bounded by the 0.5 mR/hr radiation dose rate limitation requirement stated in Table 12.1-1 for the Plant Occupancy Zone in which the OSGSF is located (Zone 0 - Unlimited Access). The building design also provides locking access control entrance doors and concrete labyrinths designed to provide shielding. 12.1.3 SOURCE TERMS The normal full power sources utilized for shielding and dose calculations are based on operation for 1 year at a core thermal power of 3568 MWt with an 85 percent capacity factor. The source terms were calculated using the EMERALD-NORMAL (Reference 2) computer code, which is described in detail in Section 15.5.8, and the source terms are assumed to be the maximum that would occur under either the design basis case or the normal operation case (including anticipated operational occurrences); both of these conditions are defined in Chapter 11. The isotopic source terms applicable to dose calculations are listed in the tables in Section 11.1 and Tables 12.1-3 through 12.1-13.
Actual operating configuration is 21 months of operation, with a mixture of fuel with enrichments up to 5 percent, with maximum analyzed burnup of 50,000 MWD/MTU. The EMERALD NORMAL 12-month cycle core inventory results in higher calculated doses. Therefore, it bounds the actual operating configuration.
To review the adequacy of shielding thickness for the shielded compartments, the computer code ISOSHLD (Reference 3) was used. ISOSHLD performs gamma ray shielding calculations for isotopic sources in a wide variety of source and shield configurations. Attenuation calculations are performed by point kernel integration, with attenuation and buildup factors provided for shields with an effective atomic number of from 4 to 82. Section 15.5.9 provides a more detailed description of the code. For these shielding calculations, source and shield configurations were approximated by cylindrical or slab geometry, and the radiation exposure rates were calculated, using ISOSHLD, at all locations outside the shielded compartments where exposure to plant personnel is possible. DCPP UNITS 1 & 2 FSAR UPDATE 12.1-9 Revision 21 September 2013 In addition, radiation dose rates were calculated for the storage tanks outside the auxiliary building, i.e., the primary water storage tank and the refueling water storage tank. Exposure rates were calculated, using ISOSHLD, immediately outside the tanks and at the site boundary (800 meters).
The results of these calculations are shown in Table 12.1-14. The calculations are for direct gamma exposure only; at distances such as 800 meters, the contribution from air-scattered gamma rays can increase the total dose rate by as much as a factor of 2 (Reference 4). The calculated exposure rates at the site boundary are small enough that any contribution from air-scattered gamma rays will still produce a negligible result. 12.1.4 AREA MONITORING The plant's area radiation monitoring system is described in detail in Section 11.4. A brief summary of the important features of this system follows.
The area radiation monitoring system consists of fixed detectors mounted at the locations listed in Table 11.4-1.
The area radiation monitoring system is not required for safe shutdown of the plant. The principal purpose of the system is to alert personnel of increasing radiation levels in the monitored areas. Upon receipt of an alarm, the normal procedure is for operations personnel to investigate the cause and then take any action that is warranted. In general, the area radiation monitors have no automatic functions other than their alarm function. The exceptions to this are the instruments in the spent fuel and new fuel storage areas that automatically transfer the fuel handling area ventilation system to the charcoal filter mode (see Section 9.4.4) and sound an alarm in the hot shop area. 12.1.5 OPERATING PROCEDURES The operating procedures that ensure external exposures will be kept ALARA can be grouped into three broad categories:
(1) Routine surveillance of the dose rate at various plant locations (2) Preplanning and procedural control of radiation work (3) Analysis of dose actually received Each of these is discussed below: (1) During the initial startup test program, a series of neutron and gamma dose rate measurements were performed to verify that there are no defects or inadequacies in the shielding that might hinder normal operation and/or maintenance activities. In addition, a comprehensive program of routine gamma dose rate measurements is an integral part of DCPP UNITS 1 & 2 FSAR UPDATE 12.1-10 Revision 21 September 2013 the plant radiation protection program. This information is used to identify areas where special measures may be required to avoid unnecessary radiation exposure, to assist in the preplanning of work, and to help identify equipment malfunctions that lead to increased dose rates.
Radiation areas are appropriately posted and/or barricaded in accordance with the requirements of 10 CFR 20 or the plant Technical Specifications (Reference 6). (2) Under the provisions of the plant Radiation Protection Program, all radiation work is carried out under a radiation work permit. These work permits are instruction sheets intended to ensure that appropriate precautions will be taken during the performance of all radiation work. As such, they specify protective clothing requirements, monitoring requirements, dosimetry requirements, expected radiation conditions, and any special measures required to control the dose received by personnel. Such special measures might include limiting the stay time in an area, erection of temporary shielding, use of remote handling tools, or other techniques appropriate to the specific situations. Personnel are instructed in radiation protection in accordance with specific procedures established in Volume I of the Plant Manual. (3) Self-reading dosimeters, coupled with the results of the thermoluminescent dosimeters (TLDs) or film badges, are routinely checked by radiation protection personnel to verify that each individual's exposure, as shown on the individual's permanent record, is within expected values. If a person's exposure appears to be higher than estimated, radiation protection personnel investigate and initiate corrective action. Radiation workers are responsible for remaining cognizant of their current exposure status. 12.1.6 ESTIMATES OF EXPOSURE An assessment of the expected radiation dose to individuals as a result of DCPP operations results in the following general conclusions:
(1) The annual man-rem external exposure in offsite locations resulting from direct shine from plant structures containing radioactive materials is extremely small. For example, the annual continuous occupancy dose at a distance of 800 meters contributed by direct shine from the containment has been calculated to be approximately 1.5 mR using the conservative assumption that the dose rate on its exterior surface is the maximum design value of 1 mr/hr. (2) The man-rem exposure to the general public is, for all practical purposes, the result of airborne and liquid releases from the radioactive waste disposal system. Although this exposure is expected to be very low, DCPP UNITS 1 & 2 FSAR UPDATE 12.1-11 Revision 21 September 2013 numerical estimates have been made and are presented in Sections 11.2.9 and 11.3.9 for liquid and gaseous releases, respectively. (3) Estimates of personnel exposures have been obtained from surveys of exposure at other operating plants and from calculations based on anticipated occupancy times for various job classifications in various areas within the plant. The calculated exposures compare reasonably well with those experienced at other plants. 12.1.6.1 Calculated Exposure Estimates The annual exposure to plant personnel for normal operation of the two units is calculated to be about 50 man-rem. (This information is historical documentation and does not reflect current operating exposures.) This value is derived from anticipated occupancy times for various job classifications in various areas within the plant. The dose rates assigned to the various areas are based on normal plant operation assuming approximately 0.2 percent fuel defects. Table 12.1-15 presents a summary of the calculated values of man-rem exposure on the basis of occupancy factors listed in Table 12.2-17 and dose rates in various areas.
Experience at other pressurized water reactors has shown that normal operational activities generally account for only part of a plant's total exposure. Hence, the total estimated annual dose with both units operating, and including special maintenance and refueling activities, is about 400 man-rem. (This information is historical documentation and does not reflect current operating exposures.)
12.1.6.2 Exposure Estimates Based on Operating Plant Experience Reference 5 reports that for 1981 the annual average collective dose from a pressurized water reactor was 652 man-rems. 12.1.6.3 Exposure Estimates for Diablo Canyon Based on the above described exposure estimates from both analytical predictions and records of exposures at actual operating plants, it is believed that 200 man-rem per year per unit represents a reasonable estimate of the maximum total exposure to be expected for performance of all normal operations, testing, and maintenance at DCPP. The exposure for two-unit operation should be somewhat less than double the value for operation of one unit, since certain facilities, such as the radwaste treatment system, are common to both units. (This information is historical documentation and does not reflect current operating exposures.)
The regulations of 10 CFR 20 limit the Total Effect Dose Equivalent (TEDE) to 5 rem per year. Pacific Gas and Electric Company limits TEDE to 5 rem per year with guidelines for maintaining doses at levels below this value.
DCPP UNITS 1 & 2 FSAR UPDATE 12.1-12 Revision 21 September 2013 If operating experience reveals areas where exposure problems exist, appropriate changes will be made in plant shielding, source strengths, locations, or operating practices as required to maintain personnel doses ALARA. 12.
1.7 REFERENCES
- 1. Diablo Canyon Units 1 and 2 Radiation Shielding Review, Rev. 3, June 1984.
- 2. S. G. Gillespie and W. K. Brunot, EMERALD NORMAL - A program for the Calculation of Activity Releases and Doses from Normal Operation of a Pressurized Water Plant, Program Description and User's Manual, Pacific Gas and Electric Company, March 1973.
- 3. R. L. Engel, et al, ISOSHLD - A Computer Code for the General Purpose Isotope Shielding Analysis, BNWL-236, UC-34, Physics, Pacific Northwest Laboratory, Richland, Washington, June 1966. 4. Reactor Handbook, Second Edition, Volume III, Part B, Oak Ridge National Laboratory, 1962.
- 5. Occupational Radiation Exposure at Commercial Nuclear Power Reactors 1981, NUREG-0713, Vol. 3, Nov. 1982.
- 6. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
- 7. NUREG 0737, Clarification of TMI Plan Requirements, USNRC, November 1980.
DCPP UNITS 1 & 2 FSAR UPDATE 12.2-1 Revision 19 May 2010 12.2 VENTILATION The ventilation systems at DCPP are designed to provide a suitable environment for personnel and equipment during normal plant operation, including anticipated operational occurrences. Parts of the ventilation system also perform safety-related functions such as cooling of engineered safety feature (ESF) motors, postaccident containment heat removal, and ensure postaccident control room and Technical Support Center habitability. These are described in detail in Section 9.4. The portions of the ventilation systems designed to remove radioactive materials from the ventilation flows prior to release to the atmosphere are described below, together with the assumptions made to calculate airborne activity concentrations. 12.2.1 DESIGN OBJECTIVES The overall design objectives of the ventilation systems from the standpoint of control of airborne radioactive materials are to:
(1) Maintain airborne radioactive material concentrations in normal work areas in the auxiliary building and fuel handling area within the values provided in 10 CFR 20.1-20.601 (2) Operate in conjunction with other gaseous waste disposal equipment to ensure that the dose from concentrations of airborne radioactive materials in unrestricted areas beyond the site boundary are within the limits specified in Appendix I to 10 CFR 50 (3) Provide the ability to maintain and/or reduce the airborne radioactive material concentrations in normally unoccupied areas within the plant structure to levels that will allow periodic access as required for nonroutine work (4) Ensure that the dose restrictions of 10 CFR 100 are satisfied following a DBA (5) Ensure that the control room and Technical Support Center remain habitable following a DBA in accordance with the requirements of 10 CFR 50 and GDC 19. 12.2.2 DESIGN DESCRIPTION The following paragraphs present brief descriptions of the ventilation systems for each of the major plant structures. The descriptions include building volumes, flowrates, and filter characteristics used when estimating airborne activity concentrations in the various plant areas. As noted, more complete design descriptions of the ventilation systems can be found in Section 9.4.
DCPP UNITS 1 & 2 FSAR UPDATE 12.2-2 Revision 19 May 2010 12.2.2.1 Containment Ventilation Systems The systems provided for ventilation of the atmosphere inside the containment, including design criteria, are discussed in detail in Sections 6.2.3 and 9.4 and include:
(1) Containment purge supply and exhaust system (2) Containment fan coolers (3) Iodine removal units The containment purge system includes a single supply fan and a single exhaust fan.
Supply air is drawn from the atmosphere through a roughing filter. The purge exhaust fan draws air from the main ventilation header in the containment and exhausts it to the plant vent, from which it is released to atmosphere at the top of the containment. The purge exhaust air is not filtered. This system is not in continuous operation during power operation, but is provided for use on a periodic basis as required prior to personnel entry.
Five fan cooler units are provided in the containment. The principal purpose of these units is to recirculate and cool the containment atmosphere during normal operation and following a DBA.
Each containment building is provided with two iodine removal units consisting of a recirculation fan complete with roughing filter, HEPA filter, and charcoal filter on the fan suction. These units are operated as required during normal operation to control airborne iodine and particulate concentrations in the containment atmosphere. Parameters used for the containment airborne activity concentration analysis are presented in Table 12.2-12. 12.2.2.2 Control Room Ventilation System A detailed description of the control room ventilation system, including design criteria, is provided in Section 9.4.1. Briefly, it consists of the equipment necessary to provide the following modes of operation:
(1) Mode 1 - 73 percent of the control room air is recirculated, 27 percent of the air is outside makeup, and 100 percent of the air is passed through roughing filters. (2) Mode 2 - 100 percent of the air is outside makeup, passed through roughing filters, and is used to purge smoke from the control room in the event of a fire.
DCPP UNITS 1 & 2 FSAR UPDATE 12.2-3 Revision 19 May 2010 (3) Mode 3 - control room is isolated from outside air. 100 percent of air is recirculated with 27 percent passing through HEPA and charcoal filters. Mode 3 operation is manually initiated on human detection, i.e., odor/smell by control room operators. (4) Mode 4 - used in the event of airborne radioactivity and the requirement of long-term occupancy of the control room. This mode isolates and pressurizes the control room and mechanical equipment room through the HEPA and charcoal filters with outside air to reduce local infiltration. The Mode 3 recirculation train operates concurrently. The design of the control room ventilation system ensures that the control room will remain habitable during postaccident operation in accordance with the requirements of 10 CFR 50, Appendix A, Criterion 19.
Parameters used for the analysis are presented in Table 12.2-2. 12.2.2.3 Auxiliary Building Ventilation System The auxiliary building ventilation system is described in detail in Section 9.4.2. Briefly, the system for each unit contains two full-capacity supply fans that draw air from the atmosphere just above the auxiliary building and then discharge it to the occupied areas of the building and to the ESF pump compartments whenever they are in operation. Two full-capacity exhaust fans draw air from various locations throughout the building and discharge it to the plant vent, where it is released at the top of the containment. Under normal circumstances, the exhaust air is passed through a roughing filter and HEPA filter prior to entering the vent. Under accident conditions (as indicated by a safety injection signal), the air exhausted from the ESF pump compartments is passed through a charcoal filter in addition to the roughing and HEPA filters. Exhaust air from other portions of the building will continue to be passed through roughing and HEPA filters only. If only one supply/exhaust fan set is available under accident conditions, exhaust air from areas other than the safety feature pump compartments will be isolated.
In all modes of operation, the ventilation flow patterns are designed so that the air flows from areas of lower potential contamination to areas of higher potential contamination. The system is balanced so that the building is normally under a slight negative pressure.
Parameters used for the analysis are presented in Table 12.2-3.
DCPP UNITS 1 & 2 FSAR UPDATE 12.2-4 Revision 19 May 2010 12.2.2.4 Fuel Handling Area Ventilation System The fuel handling area ventilation system, including design criteria, is described in detail in Section 9.4.4. Two full-capacity supply fans discharge into duct work in the corridors and equipment compartments below the spent fuel pool floor. Three full-capacity exhaust fans are provided. They collect air from along one side of the pool, just above the surface. In this manner, the air provides a sweeping action over the surface of the pool. During normal operation, one nonvital exhaust fan is in operation and the air is passed through a roughing and HEPA filter before being discharged to the plant vent. Under accident conditions, as sensed by high radiation on the area radiation monitors in the vicinity, one of two vital exhaust fans are placed in operation and the exhaust flow is passed through a charcoal filter in addition to the roughing and HEPA filters.
Parameters used for the airborne activity concentration analysis are given in Table 12.2-4. 12.2.2.5 Turbine Building Ventilation Ventilation in the turbine building is provided by a number of cabinet fans mounted on the exterior wall of the building. These fans draw air from the surrounding atmosphere into the building through roughing filters. The air is discharged from the roof of the building without treatment. This system, described in Section 9.4.3, is intended only to provide personnel comfort since the potential for introduction of airborne radioactivity into the turbine building is very low. It should be noted in this regard that the condenser air ejector discharge, which could be a point of release of radioactive materials in the event of steam generator tube leakage, is piped to the plant vent. The volume of the turbine building served by the cabinet fans is 2.46 x 106 cubic feet (one unit). The ventilation flowrate is 420,000 cfm. 12.2.2.6 Technical Support Center Ventilation The TSC is provided with its own ventilation system in which air supplied from the control room pressurization system is passed through HEPA and charcoal filters. The redundant Class I control room pressurization fans supply air to the TSC which can be maintained at a positive pressure of about 1/8-inch H20. Self-contained air conditioning units are also provided for the offices, the operations center, and the laboratory areas. A detailed description of the system is provided in Section 9.4.11. 12.2.2.7 Postaccident Sampling Compartment Ventilation One of two 100-percent capacity, redundant, pressurization fans will deliver 1000 cfm of charcoal-filtered outside air to the complex. One of two 100-percent capacity, redundant exhaust fans will discharge 700 cfm of charcoal-filtered air to the atmosphere. The differential of 1000 cfm delivered air and 700 cfm discharged air maintains a positive pressure in the complex. DCPP UNITS 1 & 2 FSAR UPDATE 12.2-5 Revision 19 May 2010 12.2.3 SOURCE TERMS The following sections describe the source terms used to estimate the airborne radioactivity levels for normal operation in areas within plant structures, including each building in the reactor facility. 12.2.3.1 Auxiliary Building Source Terms The auxiliary building ventilation system has been designed to prevent the transport of airborne radioactive materials into normal work areas. For example, equipment representing potential sources is located in compartments off the main corridors, with the ventilation flow directed from the corridors to the compartments and then to the plant vent. As a result, the occurrence of a situation wherein an equipment leak would introduce radioactive materials into the air of a normally occupied area is minimized. However, for purposes of estimating the maximum air activity concentrations that could occur in normally occupied operating spaces of the auxiliary building, the following source terms were assumed:
(1) Two-unit leakage of 20 gpd per unit of primary coolant at 0.2 percent fuel defects uniformly distributed in the auxiliary building main corridors (volume = 370,000 cubic feet) with a ventilation exhaust flow of 75,000 cfm (2) Partition factors of 0.005 for iodines, 1 for noble gases, and 0.26 for tritium as tritiated water (HTO). No credit is taken for condensation of HTO or plateout of iodines.
The results of this analysis are presented in Table 12.2-5.
Certain individual rooms within the auxiliary building contain reactor auxiliary equipment that can potentially generate the maximum airborne activity concentrations expected at any time during normal operating conditions. These areas are the CVCS letdown heat exchanger room, the volume control tank room, the charging pump rooms, and the gas decay tank rooms. Occasional entry may be required into these areas during the course of normal operations for maintenance or repair purposes. Access to these areas will be under strict procedural control at all times. Thorough radiation surveys will be conducted prior to access to these spaces so that necessary controls can be prescribed to limit personnel exposure. It should be emphasized that the airborne activity concentrations calculated for these rooms are the maximum that could occur in spaces where access is strictly controlled, and do not reflect the anticipated concentrations in areas of normal occupancy.
DCPP UNITS 1 & 2 FSAR UPDATE 12.2-6 Revision 19 May 2010 The source term for the CVCS letdown heat exchanger room is based on the following assumptions:
(1) CVCS leakage of 1 gpd of hot primary coolant at 0.2 percent fuel defects occurs upstream of the letdown heat exchanger (2) The volume of the compartment is taken to be 6500 cubic feet with a ventilation flowrate of 1200 cfm (3) Partition factors of 0.10 for iodines, 1 for noble gases, and 0.35 for tritium as HTO are assumed The source term for the volume control tank room is based on the following assumptions: (1) CVCS leakage of 10 gpd of cold primary coolant at 0.2 percent fuel defects occurs upstream of the tank (2) The room volume is taken to be 2140 cubic feet with a ventilation flowrate of 600 cfm (3) Partition factors are assumed to be 0.001 for iodines, 1 for noble gases, and 0.01 for tritium as HTO The source term for the charging pump compartment is based on the following assumptions: (1) CVCS leakage of 10 gpd of cold primary coolant at 0.2 percent fuel defects occurs upstream of the pump (2) The compartment volume is taken to be 3900 cubic feet with a ventilation flowrate of 400 cfm (3) Partition factors of 0.001 for iodines, 1 for noble gases, and 0.01 for tritium as HTO are assumed The source term for the gas decay tank compartment is based on the following assumptions: (1) Gas decay tank leakage of 0.01 scfm is assumed with tank activity inventory as shown in Table 11.3-5 (2) The compartment volume is taken to be 3490 cubic feet with a ventilation flowrate of 40 cfm (3) A partition factor of 1 is assumed for noble gases at the leakage point DCPP UNITS 1 & 2 FSAR UPDATE 12.2-7 Revision 19 May 2010 The resulting maximum airborne activity concentrations in these spaces during normal operation are summarized in Tables 12.2-6 through 12.2-9. (Note that the actual ventilation flowrates for the above rooms are higher than the assumed values used for the source term analysis. The higher flowrates would result in lower airborne activity concentrations in these spaces and would be enveloped by the values shown in Tables 12.2-6 through 12.2-9.)
12.2.3.2 Fuel Handling Area Source Term Airborne activity in the fuel handling area is produced primarily from tritium evaporation and iodine and noble gas partitioning from the spent fuel pool. The evaporation of tritium is discussed in Section 11.2.2, and the calculated airborne tritium concentrations above the spent fuel pool as a function of plant operating time are shown in Figure 11.2-7. The iodine and noble gas releases from the spent fuel pool are based on the following assumptions:
(1) Fuel handling area volume of 4700 cubic feet with a ventilation flowrate of 35,750 cfm (2) Partition factors of 0.001 for iodines and 1 for noble gases (3) Spent fuel pool activity concentrations and production rates are listed in Table 12.2-10 The resulting airborne activity concentrations during normal operation in the fuel handling areas are summarized in Table 12.2-11. 12.2.3.3 Containment Source Term The source term for containment airborne activity during normal operation is based on the following assumptions: (1) Leakage of 240 lb/day of primary coolant at 0.2 percent fuel defects (2) Partition factors of 0.10 for iodines, 1 for noble gases, and 0.35 for tritium as HTO at the leakage point (3) Ninety days of activity accumulation. No credit taken for plateout, containment leakage, cleanup recirculation unit operation, or other activity removal except natural decay The resulting airborne activity concentrations are listed in Table 12.2-12.
DCPP UNITS 1 & 2 FSAR UPDATE 12.2-8 Revision 19 May 2010 12.2.3.4 Turbine Building Source Term The source term for the turbine building is based on the following assumptions:
(1) Two-unit main steam leakage of 1700 lb/hr per unit and condenser water leakage of 5 gpm per unit into the turbine building based on 20 gpd per unit of primary-to-secondary system leakage of primary coolant with 0.2 percent fuel defects (2) Partition factors of 1 for noble gases, iodines, and tritium for steam leakage at the point of leakage (3) Partition factors of 0.001 for iodines and 0.01 for tritium as HTO for condenser water leakage (4) Turbine building volume of 10.25 x 106 cubic feet with a ventilation flowrate of 840,000 cfm (two units)
The resulting airborne activity concentrations during normal operation are listed in Table 12.2-13. 12.2.3.5 Control Room Source Term The source term for the control room is assumed to result from the total plant gaseous waste releases as indicated in Table 11.3-3. The airborne activity concentration at the control room intake is calculated using an assumed annual average /Q of 1.78 x 10-4 sec/m3, and the total gaseous release from both units. The source term for the control room itself is calculated using the following assumptions:
(1) Intake airborne activity concentrations as provided in Table 12.2-14 (2) Control room Mode 1 operation with intake and exhaust flowrates assumed to be 4200 cfm. The control room volume is taken as 125,000 cubic feet (3) No credit is taken for filtration or other removal of activity from the incoming air The resulting control room airborne activity concentrations for normal operation are presented in Table 12.2-15.
DCPP UNITS 1 & 2 FSAR UPDATE 12.2-9 Revision 19 May 2010 12.2.3.6 Technical Support Center Source Term The TSC airborne activity concentrations for normal operation are expected to be similar to those in the control room. 12.2.4 AIRBORNE RADIOACTIVITY MONITORING The instruments and methods used for airborne radioactivity monitoring include certain channels in the process monitoring system, the plant area monitoring system, continuous air monitors (CAMs), and portable low volume air samplers. 12.2.4.1 Process and Area Monitoring Systems The process and area monitoring systems (including particulate collection) as well as instruments designed to continue functioning during off-normal events and emergencies are described in detail in Section 11.4. The monitors, with their readout locations, are also listed in Table 11.4-1. Based on operational data, permanently installed air particulate and gas monitors (APGMs) may be correlated against air samples collected in close proximity to the sample collection point. After more than two decades of plant operations, experience has shown that the vast majority of such samples are statistically indistinguishable from background, making such correlations at these levels of little value. When taken, however, these grab samples are gross counted and analyzed for isotopic and quantification as appropriate. The response of the APGMs during the period of grab sampling may be correlated to the total Ci/cc measured in the grab sample and this correlation may be used to develop the instrument response in counts per minute (CPM) versus concentration in Ci/cc. The effect of ambient background is taken into account. Correlation frequencies may be established that are appropriate for the specific instrument involved based on considerations such as likely variation in isotopic mixture, history of the instrument in terms of calibration shift, use of the instrument for quantitative work, and the potential for a statistically significant measured value above background resulting from licensed material. 12.2.4.2 Grab Sampling Program The grab sampling program consists of collection of air moisture for tritium analysis and air for noble gas particulate and halogen analysis. The location and frequency of the samples are determined based on the potential for a statistically significant measured value above background resulting from licensed material. Some samples may be scheduled on a periodic basis. Samples for particulate and halogen activities are collected on fixed filters backed up by a triethylenediamine (TEDA)-impregnated charcoal or a silver zeolite cartridge. Air is passed through these sample collectors using a constant flowrate pump. The filters and charcoal cartridges are changed out for laboratory analysis. DCPP UNITS 1 & 2 FSAR UPDATE 12.2-10 Revision 19 May 2010 12.2.4.2.1 Tritium and Noble Gas Analyses Collection of air moisture for tritium analysis and air for noble gas analysis may be performed during certain activities such as flood up of the reactor cavity and subsequent fuel movement. DCPP radiation control procedures define the scope, procedure, and frequency of these analyses. 12.2.4.3 Continuous Air Monitors Portable CAMs may be used at selected locations as part of the airborne radioactivity surveillance program. Use of the CAMs is based on the potential for airborne as a result of plant conditions or work activities. 12.2.5 OPERATING PROCEDURES The grab air sampling program and the use of portable CAMS are described in DCPP procedures. 12.2.6 ESTIMATES OF INHALATION DOSES The calculations of in-plant inhalation and immersion doses to plant operating and maintenance personnel are based on the estimated airborne concentrations for plant areas presented in Tables 12.2-5 through 12.2-15 and on the estimated occupancy factors for these areas presented in Table 12.2-17. The dose to plant personnel also depends on engineering controls to minimize airborne concentrations, on the type of respiratory protection equipment, if any, being worn, and on other administrative procedures such as purging of contaminated areas, limiting occupancy, etc. Note: These calculations are historical in nature and were completed prior to the 1994 new 10 CFR 20. At that time the concept of maximum permissible concentration (MPC) based on a presumed chronic uptake and resultant body burdens over the years was dropped and replaced by the concept of the derived concentration (DAC) based on annual dose limits and the assumption of acute rather than chronic exposures. Although prior to 1994 compliance was demonstrated by the number of MPC hours accumulated in a week, the tables in the FSAR reflect doses that are very conservatively calculated and far higher than what has historically been encountered during more than 2 decades of operation. These doses are still bounding and the MPC values will not be replaced with DACs. The newer values and definitions are currently contained in 10CFR20 and included in plant procedures as appropriate. Respiratory protective equipment may be used to limit dose from iodine, and particulates in accordance with 10 CFR 20 requirements. Tritium dose may be limited by either respiratory protection and protective suits to reduce the effective concentration DCPP UNITS 1 & 2 FSAR UPDATE 12.2-11 Revision 19 May 2010 below the 10 CFR 20 level, or by limiting personnel occupancy in areas of high concentration.
The estimated inhalation and immersion doses to plant personnel for normal full power operation are presented in Table 12.2-18 in units of person-rem/year.
It should be noted that the calculated doses to plant personnel in Table 12.2-18 are conservative estimates and, in view of the strict administrative controls over personnel dose due to the conservative assumptions used in the calculation of the source terms listed in Section 12.2.3, are much higher than would be expected under normal operating conditions. In particular, the assumptions for primary coolant leakage to the auxiliary building are extremely conservative, since continuous leakage of 20 gpd into the corridors and into three compartments simultaneously is assumed, giving a total leakage rate twice that of the anticipated operational occurrences case.
It is expected that personnel inhalation dose will be low and essentially negligible in comparison to external dose. The inhalation doses at offsite locations are the result of releases of gaseous waste. These doses are referred to in Section 11.3.
DCPP UNITS 1 & 2 FSAR UPDATE 12.3-1 Revision 20 November 2011 12.3 HEALTH PHYSICS PROGRAM This section describes the objectives, facilities and equipment, and dosimetry methods and procedures related to radiation protection of personnel at the Diablo Canyon Power Plant (DCPP). 12.3.1 PROGRAM OBJECTIVES The plant operating organization is described in Section 13.1.2 and illustrated in Figure 13.1-2. The Radiation Protection Manager is responsible for administering, coordinating, planning, and scheduling all radiation protection activities at the plant. The Chemistry and Environmental Operations Manager is responsible for administrating, coordinating, planning and scheduling all chemistry, radiochemistry, and environmental activities at the plant.
The principal objectives of the Radiation Protection Program are to:
(1) Establish programs to help minimize the radiation dose to personnel consistent with the objective of operation of the plant in a safe, reliable, and efficient manner (2) Ensure compliance with all applicable regulations and PG&E policies pertaining to radiation protection and release of radioactive materials The Radiation Protection Program for the plant is carried out in accordance with PG&E's program directives. The program directives are statements of the policy covering each aspect of the Radiation Protection Program and are based on appropriate NRC regulations. The program directives are implemented by various interdepartmental and department level administrative procedures and working level procedures contained in the Plant Manual. All personnel whose work involves the potential for exposure to radiation or radioactive materials receive training, commensurate with their risk, in radiation safety based on these documents.
12.3.2 FACILITIES AND EQUIPMENT The principal radiation protection facilities for the plant are discussed below.
(1) Access Control Entrance and exit from the main radiologically controlled areas of the plant are normally made through a central access control point on the 85-foot elevation. This area is used for administratively processing personnel in and out of the radiologically controlled area, as well as providing a final contamination control point between the radiologically controlled area and the rest of the plant. An auxiliary access control, located on the 140 ft elevation, may be utilized to provide more efficient DCPP UNITS 1 & 2 FSAR UPDATE 12.3-2 Revision 20 November 2011 access into the RCA, including containment buildings. Other access control stations may be temporarily established to support plant operations on an ad hoc basis. The access controls on the 85 ft and 140 ft elevations include provisions for logging personnel in and out of the radiologically controlled areas on radiation work permits. There is a portal monitor located at the exit of these access controls to serve as a final contamination monitor for personnel exiting the radiologically controlled area. The 85 ft access control area has a decontamination facility that drains into the liquid radwaste system. (2) Radiochemical Laboratory and Counting Room These facilities are used for plant chemistry and radiochemistry programs as well as for processing samples for radiation protection analyses.
These facilities include detectors tied into a gamma spectroscopy system. Other counters and detectors are available and are used for gross alpha and beta counting and for tritium analyses. (3) Calibration Facility A calibration facility is provided for onsite calibration of most of the portable radiation monitoring instrumentation and some of the process monitors. The calibration facility is equipped with an irradiator for routine calibration of gamma-sensitive dose rate instruments. The irradiator is designed so that instruments can be accurately positioned for reproducible dose rates. The irradiator is traceable to the National Institute for Standards and Technology (NIST). Another irradiator is used for calibration of the TLDs and the self-reading dosimeters. The irradiator is traceable to the NIST. Other irradiators, traceable to the NIST may also be used for calibration activities at DCPP. Calibration of instruments is performed using controlled vendor manuals or approved procedures. In addition to the sources located in the calibration facility, additional sources mounted in standardized geometry fixtures are used for the calibration of process radiation monitoring instruments. These sources are stored in the calibration facility or shielded safes near the chemistry laboratory. Instruments that cannot be properly calibrated using the available facilities at DCPP are returned to the manufacturer or other appropriate contractors for calibration. DCPP UNITS 1 & 2 FSAR UPDATE 12.3-3 Revision 20 November 2011 (4) First Aid Room A medical facility with extensive emergency treatment capability is located in Building 102. The facility is staffed with trained emergency medical personnel. The facility serves as a general first aid area for minor injuries and an interim treatment area for seriously injured personnel until they can be transported to an offsite hospital or care facility. The medical facility has the capability of responding to injured persons who are also radiologically contaminated. (5) Laboratory A laboratory adjacent to the TSC may be used for counting in-plant samples if the normal counting room facilities become unusable following a postulated accident. The laboratory is equipped with a gamma spectroscopy system. (6) Laundry Facility An onsite laundry facility is provided for on-site cleaning and monitoring of protective clothing and respirators. An offsite laundry service is also used and may be used exclusively. The introduction of single-use protective clothing may significantly reduce or eliminate the need for onsite or offsite laundry services. The laundry facility is located above the solid radwaste storage facility. The major categories of radiation protection equipment are described below. (1) Portable radiation survey instruments for alpha, beta, and gamma radiation detection and dose rate instruments for measuring beta, gamma, and neutron dose rates are listed in Table 12.3-1. Some of the dose rate instruments are extended-range instruments to provide emergency monitoring capability. (2) Air sampling equipment and continuous air monitors are listed in Table 12.3-2. This equipment is described further in Section 12.2.4. (3) Respiratory protection equipment available for routine and emergency use is listed in Table 12.3-3. (4) Protective clothing is available for the plant in sufficient quantities to accommodate normal operation, refueling outages, and the initial stages of recovery from a major emergency (1 to 2 weeks). (5) Several types of emergency, evacuation, and decontamination kits are available at the plant site and at key offsite locations. The contents of the DCPP UNITS 1 & 2 FSAR UPDATE 12.3-4 Revision 20 November 2011 kits vary according to their intended use and include some or all of the following: (a) Portable radiation monitoring instruments (b) Air sampling equipment - some with batteries (c) Environmental sampling and labeling equipment (d) Protective clothing and respiratory protection equipment (e) Portable radio communication equipment (f) Decontamination supplies (g) Procedures, maps, area drawings, etc. 12.3.3 PERSONNEL DOSIMETRY The official and permanent record of accumulated external radiation dose received by individuals is obtained from interpretation of the TLDs. All individuals who are required to be monitored by 10 CFR 20 are issued beta-gamma TLDs and are required to wear them in a radiologically controlled area. Most TLDs are processed on site. Film badges or other TLDs may be supplied by a contractor and utilized as a backup to the TLDs owned by PG&E. Dosimetry badges are changed on a routine basis, although the TLD of any individual may be processed at any time to determine the individual's dose status. Extremity or neutron dosimetry, as well as additional TLDs or film badges, are available and are issued as required.
Personnel working in the radiologically controlled areas are provided with a means of estimating their accumulated external dose. Ordinarily, this is accomplished with the use of self-reading dosimeters. Dose estimates are updated daily, or more frequently when conditions warrant. These estimates are replaced by official dose records when the TLDs are analyzed. Information regarding an individual's dose is available so that personnel may keep themselves informed of their current dose status. Reports giving official personnel dose information are available to supervisors. These reports serve as a tool for the supervisor in making future job assignments. Individuals are closely monitored and may be restricted from further radiation work if their dose estimate reaches the administrative guideline, which is set below the dose limits established by 10 CFR 20.
The control of internal exposure to radioactive material will be supplemented by a routine bioassay program consisting of whole body counting. Whole body counting is normally performed onsite. Urinalysis performed by an outside contractor may be used on a non-routine confirmatory basis as required. The frequency of sampling depends on the person's potential dose to airborne hazards. DCPP UNITS 1 & 2 FSAR UPDATE 12.3-5 Revision 20 November 2011 Although engineering controls are normally used to control airborne radioactivity, use of respiratory protection equipment, control of access, limitation of exposure times, or other controls may be required to help maintain personnel exposure as low as is reasonably achievable.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.1-1 PLANT ZONE CLASSIFICATIONS Design Maximum Zone Condition of Occupancy Dose Rate, mrem/hr(a) O Unlimited access - areas that do not require controlled access for radio-logical reasons and can be occupied by plant personnel or visitors on an unlimited time basis 0.5 I Normal access - areas to which access is controlled for radiological reasons, but which require, or would permit, con-tinuous occupancy by radiation workers during normal working hours 1.0 II Controlled access requiring periodic occupancy 2.5 III Controlled access requiring short-term occupancy 15 IV Controlled access requiring infrequent occupancy > 15
(a) Basis: Full power operation of both Units with 1 percent failed fuel.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 20 November 2011 TABLE 12.1-2 PRINCIPAL AUXILIARY BUILDING SHIELDING Shielding Thickness, ft-in. Walls Component N(a) S(a) E(a) W(a) Floor Ceiling Demineralizers 4-0(b) 1-0 4-0 3-0 3-0 2-6 Charging pump 2-0 2-0(b) 2-6(b) 2-6 2-0 2-0 Liquid holdup tanks 2-6(b) 2-6 Ground 2-6(b) Ground 2-0 Spent resin tanks 3-4 3-4 3-10 3-10(b) 3-0 4-0 Volume control tank 3-0(b) 2-6(b) 3-0(b) 3-0 2-6 2-0 Reactor coolant filter 2-6 2-6 2-0 2-0 2-0 2-0 Gas stripper (on boric acid evaporator) (c) 2-0 3-0(b) 3-0(b) 3-0(b) 2-0 3-0 Gas decay tanks 4-0(b) 4-0 4-0 3-0 Ground 5-0 Gas compressors 2-0(b) 2-0 3-0 2-0(b) Ground 5-0 Waste concentrators 3-0(b) 3-0(b) 2-0(b) 2-0(b) 2-0 2-0
(a) Refer to orientation of Unit 1 equipment for directions.
(b) Dimensions identified with (b) are the thicknesses separating the component from potentially occupied areas, and are the limiting thickness from the standpoint of dose rate to personnel. (c) Equipment is abandoned in place and no longer in service. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.1-3 MAXIMUM ACTIVITY IN LIQUID HOLDUP TANK Activity, Concentration, Nuclide Curies Ci/cc Cr-51 0.202E 00 0.713E-03 Mn-54 0.167E 00 0.589E-03 Mn-56 0.213E 01 0.752E-02 Co-58 0.537E 01 0.190E-01 Fe-59 0.223E 00 0.787E-03 Co-60 0.169E 00 0.597E-03 Sr-89 0.543E 00 0.192E-02 Sr-90 0.259E-01 0.916E-04 Sr-91 0.274E 00 0.969E-03 Sr-92 0.510E-01 0.180E-03 Y-90 0.315E-01 0.111E-03 Y-91 0.106E 01 0.375E-02 Y-92 0.159E 00 0.563E-03 Zr-95 0.693E 00 0.245E-02 Nb-95 0.687E 00 0.242E-02 Mo-99 0.144E 03 0.509E 00 Te-132 0.518E 02 0.183E 00 Cs-134 0.402E 02 0.142E 00 Cs-136 0.153E 01 0.539E-02 Cs-137 0.623E 02 0.220E-00 Ba-140 0.750E 00 0.265E-02 La-140 0.289E 00 0.102E-02 Ce-144 0.688E-01 0.243E-03 Pr-144 0.688E-01 0.243E-03 I-131 0.492E 03 0.174E 01 I-132 0.944E 02 0.333E 00 I-133 0.707E 03 0.250E 01 I-134 0.418E 01 0.147E-01 I-135 0.281E 03 0.994E 00 Kr-83M 0.163E 02 0.574E-01 Kr-85 0.175E 04 0.617E 01 Kr-85M 0.223E 03 0.789E 00 Kr-87 0.273E 02 0.965E-01 Kr-88 0.260E 03 0.920E 00 Xe-133 0.510E 05 0.180E 03 Xe-133M 0.575E 03 0.203E 01 Xe-135 0.188E 04 0.664E 01 Xe-135M 0.877E-03 0.310E-05 Xe-138 0.747E-03 0.264E-05 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.1-4 MAXIMUM ACTIVITY IN RCS CHARGING PUMP Concentrations, Nuclide Ci/cc Cr-51 0.7160E-03 Mn-54 0.5890E-03 Mn-56 0.2210E-01 Co-58 0.1900E-01 Fe-59 0.7890E-03 Co-60 0.5970E-03 Sr-89 0.1922E-02 Sr-90 0.9162E-04 Sr-91 0.1289E-02 Sr-92 0.5030E-03 Y-90 0.1121E-03 Y-91 0.3755E-02 Y-92 0.6316E-03 Zr-95 0.2450E-02 Nb-95 0.2424E-02 Mo-99 0.5301E 00 Te-132 0.1895E 00 Cs-134 0.1420E 00 Cs-136 0.5440E-02 Cs-137 0.2201E-00 Ba-140 0.2673E-02 La-140 0.9010E-03 Ce-144 0.2430E-03 Pr-144 0.2430E-03 I-131 0.1761E 01 I-132 0.6456E 00 I-133 0.2851E 01 I-134 0.3620E 01 I-135 0.1503E 00 Kr-83M 0.2547E 00 Kr-85 0.6158E 01 Kr-85M 0.1481E 01 Kr-87 0.8558E 00 Kr-88 0.2502E 01 Xe-133 0.1839E 03 Xe-133M 0.2135E 01 Xe-135 0.8441E 01 Xe-135M 0.1322E 00 Xe-138 0.3875E 00 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.1-5 MAXIMUM ACTIVITY IN WASTE EVAPORATOR Activity, Concentration, Nuclide Curies Ci/cc Cr-51 0.360E-08 0.211E-08 Mn-54 0.123E-04 0.723E-05 Mn-56 0.0 0.0 Co-58 0.256E-04 0.150E-04 Fe-59 0.132E-06 0.777E-07 Co-60 0.254E-04 0.149E-04 Sr-89 0.129E-05 0.756E-06 Sr-90 0.871E-05 0.511E-05 Sr-91 0.0 0.0 Sr-92 0.0 0.0 Y-90 0.871E-05 0.511E-05 Y-91 0.572E-05 0.336E-05 Y-92 0.0 0.0 Zr-95 0.482E-05 0.283E-05 Nb-95 0.102E-04 0.599E-05 Mo-99 0.0 0.0 Te-132 0.0 0.0 Cs-134 0.980E-02 0.575E-02 Cs-136 0.160E-11 0.940E-12 Cs-137 0.208E-01 0.122E-01 Ba-140 0.569E-12 0.334E-12 La-140 0.655E-12 0.384E-12 Ce-144 0.966E-05 0.567E-05 Pr-144 0.966E-05 0.567E-05 I-131 0.290E-14 0.170E-14 I-132 0.144E-35 0.848E-36 I-133 0.0 0.0 I-134 0.0 0.0 I-135 0.0 0.0 DCPP UNITS 1 & 2 FSAR UPDATE Revision 20 November 2011 TABLE 12.1-6 MAXIMUM ACTIVITY IN BORIC ACID EVAPORATOR (b) Gaseous Activity (In Gas Stripper Condenser) Activity in Activity in Isotope Feedwater, µCi/cc Condenser, µCi/cc Kr-83m 5.7E-02 1.2E+00 Kr-85 6.2E+00 1.3E+02 Kr-85m 7.9E-01 1.7E+01 Kr-87 9.6E-02 2.0E+00 Kr-88 9.2E-01 1.9E+01 Xe-133 1.8E+02 3.8E+03 Xe-133m 2.0E+00 4.3E+01 Xe-135 6.6E+00 1.4E+02 Xe-135m 3.1E-06 6.5E-05 Xe-138 2.6E-06 5.5E-05 Liquid Activity (In Concentrates Holding Tank) (b) Activity in(a) Activity in Isotope Feedwater, µCi/cc Condenser, µCi/cc I-131 1.7E-02 2.8E-02 I-132 3.3E-03 2.8E-03 I-133 2.5E-02 3.1E-02 I-134 1.5E-04 0.0 I-135 9.9E-03 6.0E-02 Mo-99 5.1E-03 7.8E-02 Cs-134 7.1E-03 1.2E-01 Cs-137 1.1E-02 1.2E-01
(a) Isotopes with small activity are not listed.
(b) Equipment is abandoned in place and no longer in service. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.1-7 MAXIMUM ACTIVITY IN SPENT FUEL POOL(a) Activity, Concentration, Nuclide Curies Ci/cc Cr-51 9.59E-04 6.98E-08 Mn-54 8.46E-04 6.15E-08 Mn-56 1.18E-10 8.58E-15 Co-58 2.66E-02 1.94E-06 Fe-59 1.09E-03 7.92E-08 Co-60 8.59E-04 6.25E-08 Kr-83M 0.0 0.0 Kr-85M 0.0 0.0 Kr-85 0.0 0.0 Kr-87 0.0 0.0 Kr-88 0.0 0.0 Sr-89 2.96E-03 2.15E-07 Sr-90 1.47E-04 1.07E-08 Y-90 2.36E-04 1.72E-08 Sr-91 1.58E-05 1.15E-09 Y-91 9.03E-03 6.57E-07 Sr-92 1.74E-06 1.26E-10 Y-92 6.85E-07 4.99E-11 Zr-95 3.81E-03 2.77E-07 Nb-95 3.89E-03 2.83E-07 Mo-99 6.33E-01 4.61E-05 I-131 3.37E 00 2.46E-04 Te-132 2.48E-01 1.80E-05 I-132 2.57E-01 1.87E-05 I-133 6.62E-01 4.82E-05 X-133M 0.0 0.0 X-133 0.0 0.0 Cs-134 2.23E-01 1.62E-05 I-134 1.28E-03 9.29E-08 I-135 7.25E-03 5.28E-07 Xe-135M 0.0 0.0 Xe-135 0.0 0.0 Cs-136 9.55E-03 6.95E-07 Cs-137 4.60E-01 3.35E-05 Xe-138 0.0 0.0 Ba-140 3.63E-03 2.64E-07 La-140 3.19E-03 2.32E-07 Ce-144 3.87E-04 2.82E-08 Pr-144 3.87E-04 2.82E-08 (a) Basis: Primary coolant with 1 percent fuel defects, three days decay, and purification by the CVCS demineralizers, at a flowrate of 120 gpm, is dispersed in the refueling water. A 15 percent mixing of the spent fuel pool with the refueling water is assumed. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.1-8 MAXIMUM ACTIVITY IN MONITOR TANK AND WASTE CONDENSATE TANK Monitor Tank Waste Condensate Tank Activity, Concentration, Activity, Concentration, Nuclide Curies Ci/cc Curies Ci/cc H-3 0.200E 02 0.211E 00 0.120E 02 0.211E 00 Cr-51 0.665E-07 0.703E-09 0.399E-07 0.703E-09 Mn-54 0.556E-07 0.588E-09 0.334E-07 0.588E-09 Mn-56 0.192E-07 0.203E-09 0.115E-07 0.203E-09 Co-58 0.179E-05 0.189E-07 0.107E-05 0.189E-07 Fe-59 0.738E-07 0.780E-09 0.443E-07 0.780E-09 Co-60 0.565E-07 0.597E-09 0.339E-07 0.597E-09 Sr-89 0.200E-06 0.211E-08 0.120E-06 0.211E-08 Sr-90 0.963E-08 0.102E-09 0.578E-08 0.102E-09 Sr-91 0.371E-07 0.392E-09 0.222E-07 0.392E-09 Sr-92 0.559E-09 0.590E-11 0.335E-09 0.590E-11 Y-90 0.962E-05 0.102E-06 0.577E-05 0.102E-06 Y-91 0.353E-03 0.373E-05 0.212E-03 0.373E-05 Y-92 0.329E-05 0.348E-07 0.198E-05 0.348E-07 Zr-95 0.255E-06 0.270E-08 0.153E-06 0.270E-08 Nb-95 0.255E-06 0.269E-08 0.153E-06 0.269E-08 Mo-99 0.420E-04 0.444E-06 0.252E-04 0.444E-06 Te-132 0.154E-04 0.162E-06 0.922E-05 0.162E-06 Cs-134 0.552E-02 0.584E-04 0.331E-02 0.584E-04 Cs-136 0.269E-03 0.284E-05 0.161E-03 0.284E-05 Cs-137 0.114E-01 0.120E-03 0.682E-02 0.120E-03 Ba-140 0.269E-06 0.284E-08 0.161E-06 0.284E-08 La-140 0.144E-06 0.152E-08 0.865E-07 0.152E-06 Ce-144 0.255E-07 0.269E-09 0.153E-07 0.269E-09 Pr-144 0.255E-07 0.269E-09 0.153E-07 0.269E-09 I-131 0.157E-02 0.165E-04 0.939E-03 0.165E-04 I-132 0.220E-04 0.233E-06 0.132E-04 0.233E-06 I-133 0.152E-02 0.161E-04 0.912E-03 0.161E-04 I-134 0.307E-09 0.325E-11 0.184E-09 0.325E-11 I-135 0.235E-03 0.248E-05 0.141E-03 0.248E-05 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.1-9 MAXIMUM ACTIVITY IN SPENT RESIN TANK Activity, Nuclide Curies Cr-51 5.95E-01 Mn-54 1.40E 00 Mn-56 3.28E-01 Co-58 2.36E 01 Fe-59 7.92E-01 Co-60 1.72E 00 Sr-89 2.06E 00 Sr-90 2.75E-01 Y-90 2.81E-01 Sr-91 2.48E-01 Y-91 3.03E 00 Sr-92 3.83E-02 Y-92 4.49E-02 Zr-95 2.94E 00 Nb-95 3.73E 00 Mo-99 1.61E 02 I-131 6.29E 02 Te-132 5.89E 01 I-132 8.82E 01 I-133 6.52E 02 Cs-134 8.94E 00 I-134 2.76E 03 I-135 1.95E 02 Cs-136 3.52E 00 Cs-137 6.41E 02 Ba-140 1.77E 00 La-140 1.22E 00 Ce-144 5.38E-01 Pr-144 5.38E-01 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.1-10 MAXIMUM ACTIVITY IN WASTE CONCENTRATES TANK Activity, Concentration, Nuclide Curies Ci/cc H-3 0.216E 00 0.570E-01 Cr-51 0.719E-03 0.190E-03 Mn-54 0.627E-03 0.166E-03 Mn-56 0.222E-06 0.586E-07 Co-58 0.198E-01 0.524E-02 Fe-59 0.812E-03 0.214E-03 Co-60 0.638E-03 0.169E-03 Kr-83M 0.0 0.0 Kr-85M 0.0 0.0 Kr-85 0.0 0.0 Kr-87 0.0 0.0 Kr-88 0.0 0.0 Sr-89 0.551E-03 0.145E-03 Sr-90 0.272E-04 0.718E-05 Y-90 0.171E-04 0.453E-05 Sr-91 0.668E-05 0.176E-05 Y-91 0.121E-03 0.320E-04 Sr-92 0.194E-08 0.513E-09 Y-92 0.178E-05 0.470E-06 Zr-95 0.708E-03 0.187E-03 Nb-95 0.720E-03 0.190E-03 Mo-99 0.711E-01 0.188E-01 I-131 0.378E 00 0.999E-01 Te-132 0.295E-01 0.780E-02 I-132 0.313E-01 0.828E-02 I-133 0.109E 00 0.289E-01 Xe-133M 0.0 0.0 Xe-133 0.0 0.0 Cs-134 0.303E-01 0.802E-02 I-134 0.636E-13 0.168E-13 I-135 0.157E-02 0.414E-03 Xe-135M 0.0 0.0 Xe-135 0.0 0.0 Cs-136 0.138E-02 0.364E-03 Cs-137 0.643E-01 0.170E-01 Xe-138 0.0 0.0 Ba-140 0.689E-03 0.182E-02 La-140 0.582E-03 0.154E-03 Ce-144 0.717E-04 0.189E-04 Pr-144 0.717E-04 0.189E-04 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 12.1-11 Sheet 1 of 2 Revision 11 November 1996 MAXIMUM ACTIVITY IN RADWASTE SYSTEM DRAIN TANKS Equipment Drain Floor Drain Receiver Tank Receiver Tank Concentration, Concentration, Nuclide Ci/cc Ci/cc H-3 0.74E 01 0.23E-02 Cr-51 0.26E-03 0.79E-05 Mn-54 0.22E-03 0.66E-05 Mn-56 0.81E-02 0.10E-04 Co-58 0.70E-02 0.21E-03 Fe-59 0.29E-03 0.88E-03 Co-60 0.22E-03 0.68E-03 Sr-89 0.20E-03 0.59E-05 Sr-90 0.94E-05 0.29E-06 Y-90 0.27E-05 0.14E-06 Sr-91 0.12E-03 0.64E-06 Y-91 0.41E-04 0.13E-05 Sr-92 0.47E-04 0.59E-07 Y-92 0.47E-04 0.14E-05 Zr-95 0.25E-03 0.76E-05 Nb-95 0.25E-03 0.76E-05 Mo-99 0.45E-01 0.10E-02 I-131 0.16E 00 0.45E-02 Te-132 0.17E-01 0.41E-03 I-132 0.59E-01 0.59E-03 I-133 0.26E 00 0.32E-02 Cs-134 0.10E-01 0.32E-03 I-134 0.33E-01 0.40E-04 I-135 0.14E 00 0.41E-03 Cs-136 0.54E-03 0.16E-04 Cs-137 0.22E-01 0.68E-03 Ba-140 0.27E-03 0.78E-05 La-140 0.97E-03 0.51E-05 Ce-144 0.25E-04 0.76E-06 Pr-144 0.25E-04 0.76E-06 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 12.1-11 Sheet 2 of 2 Revision 11 November 1996 Chemical Drain Laundry and Hot Tank Shower Tank Concentration, Concentration, Nuclide Ci/cc Ci/cc H-3 0.22E-04 0.22E-05 Cr-51 0.68E-07 0.68E-08 Mn-54 0.59E-07 0.59E-08 Mn-56 0.53E-11 0.53E-12 Co-58 0.19E-05 0.19E-06 Fe-59 0.77E-07 0.77E-08 Co-60 0.60E-07 0.60E-08 Sr-89 0.21E-06 0.21E-07 Sr-90 0.10E-07 0.10E-08 Sr-91 0.44E-08 0.44E-09 Sr-92 0.23E-12 0.23E-13 Y-90 0.11E-07 0.11E-08 Y-91 0.37E-06 0.37E-07 Y-92 0.51E-07 0.51E-08 Zr-95 0.27E-06 0.27E-07 Nb-95 0.27E-06 0.27E-07 Mo-99 0.33E-04 0.33E-05 Te-132 0.12E-04 0.12E-05 Cs-134 0.12E-04 0.12E-05 Cs-136 0.53E-06 0.53E-07 Cs-137 0.24E-04 0.24E-05 Ba-140 0.27E-06 0.27E-07 La-140 0.21E-06 0.21E-07 Ce-144 0.27E-07 0.27E-08 Pr-144 0.27E-07 0.27E-08 I-131 0.15E-03 0.15E-04 I-132 0.19E-04 0.19E-05 I-133 0.58E-04 0.58E-05 I-134 0.75E-21 0.75E-22 I-135 0.10E-05 0.10E-06 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.1-12 MAXIMUM ACTIVITY IN PRIMARY WATER STORAGE TANK Activity, Concentration, Nuclide Curies Ci/cc Cr-51 2.27E-10 3.00E-13 Mn-54 9.21E-10 1.22E-13 Mn-56 0.0 0.0 Co-58 1.47E-07 1.95E-10 Fe-59 4.16E-10 5.49E-13 Co-60 1.18E-09 1.56E-12 Sr-89 1.27E-09 1.67E-12 Sr-90 2.09E-10 2.76E-13 Y-90 1.70E-08 2.25E-11 Sr-91 8.05E-23 1.06E-25 Y-91 2.56E-04 3.39E-07 Sr-92 0.0 0.0 Y-92 3.26E-37 4.30E-40 Zr-95 1.97E-09 2.60E-12 Nb-95 2.96E-09 3.91E-12 Mo-99 6.50E-08 8.58E-11 I-131 7.49E-05 9.89E-08 Te-132 5.01E-08 6.62E-11 I-132 5.18E-08 6.84E-11 I-133 3.55E-10 4.69E-13 Cs-134 5.35E-03 7.07E-06 I-134 0.0 0.0 I-135 5.83E-22 7.71E-25 Cs-136 3.11E-10 2.12E-08 Cs-137 3.58E-10 1.63E-05 Ba-140 4.14E-10 4.11E-13 La-140 4.14E-10 4.72E-13 Ce-144 1.60E-05 5.47E-13 Pr-144 1.23E-02 5.47E-13 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.1-13 MAXIMUM ACTIVITY IN REFUELING WATER STORAGE TANK Activity, Concentration, Nuclide Curies Ci/cc Cr-51 4.19E-07 2.03E-10 Mn-54 6.80E-07 3.30E-10 Mn-56 0.0 0.0 Co-58 1.75E-05 8.51E-09 Fe-59 6.14E-07 2.98E-10 Co-60 7.28E-07 3.53E-10 Sr-89 4.63E-06 2.25E-09 Sr-90 1.01E-06 4.92E-10 Y-90 6.39E-07 3.11E-10 Sr-91 3.31E-12 1.61E-15 Y-91 6.38E-06 3.10E-09 Sr-92 2.29E-21 1.11E-24 Y-92 3.15E-18 1.53E-21 Zr-95 7.22E-06 3.51E-09 Nb-95 1.06E-05 5.17E-09 Mo-99 9.36E-06 4.55E-09 I-131 4.93E-04 2.39E-07 Te-132 4.87E-06 2.36E-09 I-132 8.47E-06 4.12E-09 I-133 9.20E-07 4.47E-10 Cs-134 8.51E-03 4.13E-06 I-134 0.0 0.0 I-135 9.10E-11 4.42E-14 Cs-136 6.52E-05 3.17E-08 Cs-137 1.54E-02 7.45E-06 Ba-140 1.42E-06 6.91E-10 La-140 1.32E-06 6.41E-10 Ce-144 1.74E-06 8.43E-10 Pr-144 1.74E-06 8.43E-10 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.1-14 RADIATION EXPOSURE RATES FROM EXTERNAL STORAGE TANKS Maximum Dose Rate Maximum Dose Rate Tank at Tank Surface, mR/hr at 800 meters, mR/hr(a) Primary water storage 5.52 E-03 6.47 E-10 tank
Refueling water storage 3.18 E-03 7.25 E-10 tank
(a) Direct gamma radiation only (see Section 12.1).
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 12.1-15 Sheet 1 of 2 Revision 12 September 1998 CALCULATED ANNUAL MAN-REM EXPOSURE OF PLANT PERSONNEL(a) 3Due to Normal Operation (This information is historical documentation and does not reflect current operating exposures) Chemical and Radia- Electrical and Expected tion Protection Control Mechanical Maint. Dose Operators(b) Technicians(c) Technicians(d) Personnel(e) Rate man-hr/ man-rem/ man-hr/ man-rem/ man-hr/ man-rem/ man-hr/ man-rem/ Area Zone r/hr wk wk wk wk wk wk wk wk
- 1. Control Room 0 1.0x10-4 2000 0.20 10 0.001 300 0.03 0.3 0.0
- 2. Turbine Building 0 1.0x10-4 700 0.07 10 0.001 1000 0.10 3000 0.30 3. Outside 0 2.0x10-5 150 0.003 50 0.001 100 0.002 2 0.0
- 4. Aux Bldg Corridors I 1.0x10-4 700 0.07 2200 0.22 500 0.05 2600 0.26
- 5. Fuel Handling Area II 2.5x10-4 2 0.0005 8 0.002 120 0.03 320 0.08
- 6. Primary Sample Room III 1.5x10-2 2 0.03 3 0.05 1.00 0.02 6 0.09
- 7. Containment IV 1.5x10-1 0.5 0.08 2 0.25 2 0.3 0.3 0.05
- 8. Volume Control Tank Compartment IV 5 0.03 0.15 0.2 1.00 0 0 0.2 1.0 9. Charging Pumps IV 2x10-1 0.60 0.12 0.5 0.10 3 0.6 7.0 1.35
- 10. Letdown HX IV 1.5 0.03 0.05 0.20 0.30 0 0.00 0.30 0.50
- 11. Gas Decay Tanks IV 0.5 0.04 0.02 0.30 0.15 0 0.00 0.30 0.15
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 12.1-15 Sheet 2 of 2 Revision 12 September 1998 Chemical and Radia- Electrical and Expected tion Protection Control Mechanical Maint. Dose Operators(b) Technicians(c) Technicians(d) Personnel(e) Rate man-hr/ man-rem/ man-hr/ man-rem/ man-hr/ man-rem/ man-hr/ man-rem/ Area Zone r/hr wk wk wk wk wk wk wk wk Total Man-rem/wk 0.81 2.08 1.132 3.78
Total Man-rem/yr 42.00 108.00 59.00 197.00 52 wk/yr PLANT ANNUAL TOTAL DUE TO NORMAL OPERATION (including 32 man-rems for supervisors): 406 man-rems(f) (a) Average work week for all personnel-40 hours. (b) Two-unit shift crew of 22 people, continuous coverage, 3696 man-hours/week. (c) 60 chemical and radiation protection technicians, 2400 man-hours/week. (d) 60 control technicians, 2400 man-hours/week. (e) 149 man crew, 5960 man-hours/week. (f) Special maintenance and refueling activities are expected to add another 400 man-rems for a total of 800 man-rems per year.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 12 September 1998 TABLE 12.2-1 DESIGN VALUES FOR CONTAINMENT VENTILATION SYSTEM Containment Free Air Volume, ft3 2.6 x 106 Purge Supply Fan Flow Rate, cfm 50,000 Purge Exhaust Fan Flow Rate, cfm 55,000 Fan Cooler Flow Rate, cfm/Fan Cooler Unit Normal operation 110,000 Postaccident 47,000 Iodine Removal Fan Flow Rate, cfm/fan 12,000 HEPA Filter Efficiency for 0.3 m DOP Particles, % 99.97 Charcoal Filter Efficiency, %(a) Elemental iodine 99 Methyl iodide 85 (a) Radioactive elemental iodine and radioactive iodide as methyl iodide, respectively. (Efficiency rates are for filters as originally specified. Replacement filters shall comply with the requirements of Regulatory Guide 1.52 and ANSI N509.) DCPP UNITS 1 & 2 FSAR UPDATE Revision 12 September 1998 TABLE 12.2-2 DESIGN VALUES FOR CONTROL ROOM VENTILATION SYSTEM Total Room Volume(a), Unit 1 plus Unit 2, ft3 170,000 Supply Fan Rating, cfm/fan 7,800 Minimum number of operable fans 1/Unit Recirculation Flowrate Under Accident Conditions, cfm 2,100 HEPA Filter Efficiency for 0.3 m Particles DOP, % 99.97 Charcoal Filter Efficiency, %(b) Elemental iodine 99 Methyl iodide 85
(a) Includes all areas served by control room ventilation, including control room, computer room, record storage room, control room kitchen, foreman's office, safeguards and HVAC equipment room. (b) Radioactive elemental iodine and radioactive iodide as methyl iodide, respectively. (Efficiency rates are for filters as originally specified. Replacement filters shall comply with the requirements of Regulatory Guide 1.52 and ANSI N509.) DCPP UNITS 1 & 2 FSAR UPDATE Revision 13 April 2000 TABLE 12.2-3 DESIGN VALUES FOR AUXILIARY BUILDING VENTILATION SYSTEM Auxiliary Building Volume, Unit 1 plus Unit 2, ft3 1,312,000 Supply Fan Rating, cfm/fan 67,500 Exhaust Fan Rating, cfm/fan 73,500 HEPA Filter Efficiency for 0.3 m Particles DOP, % 99.97 Charcoal Filter Efficiency, %(a) Elemental iodine 99 Methyl iodide 85 (a) Radioactive elemental iodine and radioactive iodide as methyl iodide, respectively. (Efficiency rates are for filters as originally specified. Replacement filters shall comply with the requirements of Regulatory Guide 1.52 and ANSI N509.) DCPP UNITS 1 & 2 FSAR UPDATE Revision 13 April 2000 TABLE 12.2-4 DESIGN VALUES FOR FUEL HANDLING AREA VENTILATION SYSTEM Fuel Handling Building Volume, Each Unit, ft3 525,000 Supply Fan Rating, cfm/fan 23,300 Exhaust Fan Rating, cfm/fan 35,750 HEPA Filter Efficiency for 0.3 m Particles DOP, % 99.97 Charcoal Filter Efficiency, %(a) Elemental iodine 99 Methyl iodide 85 (a) Radioactive elemental iodine and radioactive iodide as methyl iodide, respectively. (Efficiency rates are for filters as originally specified. Replacement filters shall comply with the requirements of Regulatory Guide 1.52 and ANSI N509.) DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.2-5 ESTIMATED AIRBORNE ACTIVITY CONCENTRATIONS IN AUXILIARY BUILDING WORK AREAS FOR NORMAL OPERATION Concentration MPC Air-10 CFR 20 Nuclide Ci/cc Ci/cc H-3 4.22E-09 5.00E-06 Cr-51 0.0 2.00E-06 Mn-54 0.0 4.00E-08 Mn-56 0.0 5.00E-07 Co-58 0.0 5.00E-08 Fe-59 0.0 5.00E-08 Co-60 0.0 9.00E-09 Kr-83M 4.02E-09 1.00E-06 Kr-85M 2.37E-08 6.00E-06 Kr-85 5.81E-08 1.00E-05 Kr-87 1.33E-08 1.00E-06 Kr-88 3.98E-08 1.00E-06 Sr-89 0.0 1.00E-08 Sr-90 0.0 1.00E-09 Y-90 0.0 1.00E-07 Sr-91 0.0 1.00E-07 Y-91 0.0 3.00E-08 Sr-92 0.0 3.00E-07 Y-92 0.0 3.00E-07 Zr-95 0.0 3.00E-08 Nb-95 0.0 1.00E-07 Mo-99 0.0 2.00E-07 I-131 1.43E-10 9.00E-09 Te-132 0.0 2.00E-07 I-132 5.13E-11 2.00E-07 I-133 2.31E-10 3.00E-08 Xe-133M 3.53E-08 1.00E-05 Xe-133 2.83E-06 1.00E-05 Cs-134 0.0 1.00E-08 I-134 2.76E-11 5.00E-07 I-135 1.21E-10 1.00E-07 Xe-135M 7.09E-09 1.00E-06 Xe-135 5.34E-08 4.00E-06 Cs-136 0.0 2.00E-07 Cs-137 0.0 1.00E-08 Xe-138 5.07E-09 1.00E-06 Ba-140 0.0 4.00E-08 La-140 0.7 4.00E-08 Ce-144 0.0 6.00E-09 Pr-144 0.0 1.00E-06 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.2-6 ESTIMATED AIRBORNE ACTIVITY CONCENTRATIONS IN LETDOWN HEAT EXCHANGER COMPARTMENT FOR NORMAL OPERATION Concentration MPC Air-10 CFR 20 Nuclide Ci/cc Ci/cc H-3 8.96E-09 5.00E-06 Cr-51 0.0 2.00E-06 Mn-54 0.0 4.00E-08 Mn-56 0.0 5.00E-07 Co-58 0.0 5.00E-08 Fe-59 0.0 5.00E-08 Co-60 0.0 9.00E-09 Kr-83M 6.30E-09 1.00E-06 Kr-85M 3.72E-08 6.00E-06 Kr-85 9.16E-08 1.00E-05 Kr-87 2.08E-08 1.00E-06 Kr-88 6.27E-08 1.00E-06 Sr-89 0.0 3.00E-08 Sr-90 0.0 1.00E-09 Y-90 0.0 1.00E-07 Sr-91 0.0 3.00E-07 Y-91 0.0 3.00E-08 Sr-92 0.0 3.00E-07 Y-92 0.0 3.00E-07 Zr-95 0.0 3.00E-08 Nb-95 0.0 1.00E-07 Mo-99 0.0 2.00E-07 I-131 4.49E-09 9.00E-09 Te-132 0.0 2.00E-07 I-132 1.61E-09 2.00E-07 I-133 7.27E-09 3.00E-08 Xe-133M 5.58E-08 1.00E-05 Xe-133 4.45E-06 1.00E-05 Cs-134 0.0 1.00E-08 I-134 8.63E-10 5.00E-07 I-135 3.80E-09 1.00E-07 Xe-135M 1.17E-08 1.00E-06 Xe-135 8.42E-08 4.00E-06 Cs-136 0.0 2.00E-07 Cs-137 0.0 1.00E-08 Xe-138 7.84E-09 1.00E-06 Ba-140 0.0 4.00E-08 La-140 0.0 1.00E-07 Ce-144 0.0 6.00E-09 Pr-144 0.0 1.00E-06 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.2-7 ESTIMATED AIRBORNE ACTIVITY CONCENTRATIONS IN VOLUME CONTROL TANK COMPARTMENT FOR NORMAL OPERATION Concentration MPC Air-10 CFR 20 Nuclide Ci/cc Ci/cc H-3 5.11E-09 5.00E-06 Cr-51 0.0 2.00E-06 Mn-54 0.0 4.00E-08 Mn-56 0.0 5.00E-07 Co-58 0.0 5.00E-08 Fe-59 0.0 5.00E-08 Co-60 0.0 9.00E-09 Kr-83M 1.28E-07 1.00E-06 Kr-85M 7.50E-07 6.00E-06 Kr-85 1.84E-06 1.00E-05 Kr-87 4.24E-07 1.00E-06 Kr-88 1.27E-06 1.00E-06 Sr-89 0.0 3.00E-08 Sr-90 0.0 1.00E-09 Y-90 0.0 1.00E-07 Sr-91 0.0 3.00E-07 Y-91 0.0 3.00E-08 Sr-92 0.0 3.00E-07 Y-92 0.0 3.00E-07 Zr-95 0.0 3.00E-08 Nb-95 0.0 1.00E-07 Mo-99 0.0 2.00E-07 I-131 9.02E-10 9.00E-09 Te-132 0.0 2.00E-07 I-132 3.26E-10 2.00E-07 I-133 1.46E-09 3.00E-08 Xe-133M 1.12E-06 1.00E-05 Xe-133 8.94E-05 1.00E-05 Cs-134 0.0 1.00E-08 I-134 1.77E-10 5.00E-07 I-135 7.66E-10 1.00E-07 Xe-135M 2.35E-07 1.00E-06 Xe-135 1.69E-06 4.00E-06 Cs-136 0.0 2.00E-07 Cs-137 0.0 1.00E-08 Xe-138 1.69E-07 1.00E-06 Ba-140 0.0 4.00E-08 La-140 0.0 1.00E-07 Ce-144 0.0 6.00E-09 Pr-144 0.0 1.00E-06 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.2-8 ESTIMATED AIRBORNE ACTIVITY CONCENTRATIONS IN CHARGING PUMP COMPARTMENT FOR NORMAL OPERATION Concentration MPC Air-10 CFR 20 Nuclide Ci/cc Ci/cc H-3 7.64E-09 5.00E-06 Cr-51 0.0 2.00E-06 Mn-54 0.0 4.00E-08 Mn-56 0.0 5.00E-07 Co-58 0.0 5.00E-08 Fe-59 0.0 5.00E-08 Co-60 0.0 9.00E-09 Kr-83M 1.84E-07 1.00E-06 Kr-85M 1.10E-06 6.00E-06 Kr-85 2.75E-06 1.00E-05 Kr-87 6.00E-07 1.00E-06 Kr-88 1.85E-06 1.00E-06 Sr-89 0.0 3.00E-08 Sr-90 0.0 1.00E-09 Y-90 0.0 1.00E-07 Sr-91 0.0 3.00E-07 Y-91 0.0 3.00E-08 Sr-92 0.0 3.00E-07 Y-92 0.0 3.00E-07 Zr-95 0.0 3.00E-08 Nb-95 0.0 1.00E-07 Mo-99 0.0 2.00E-07 I-131 1.35E-09 9.00E-09 Te-132 0.0 2.00E-07 I-132 4.73E-10 2.00E-07 I-133 2.18E-09 3.00E-08 Xe-133M 1.67E-06 1.00E-05 Xe-133 1.34E-04 1.00E-05 Cs-134 0.0 1.00E-08 I-134 2.46E-10 5.00E-07 I-135 1.13E-09 1.00E-07 Xe-135M 2.84E-07 1.00E-06 Xe-135 2.51E-06 4.00E-06 Cs-136 0.0 2.00E-07 Cs-137 0.0 1.00E-08 Xe-138 2.01E-07 1.00E-06 Ba-140 0.0 4.00E-08 La-140 0.0 1.00E-07 Ce-144 0.0 6.00E-09 Pr-144 0.0 1.00E-06 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.2-9 ESTIMATED AIRBORNE ACTIVITY CONCENTRATIONS IN GAS DECAY TANK COMPARTMENT FOR NORMAL OPERATION Concentration MPC Air-10 CFR 20 Nuclide Ci/cc Ci/cc H-3 0.0 5.00E-06 Cr-51 0.0 2.00E-06 Mn-54 0.0 4.00E-08 Mn-56 0.0 5.00E-07 Co-58 0.0 5.00E-08 Fe-59 0.0 5.00E-08 Co-60 0.0 9.00E-09 Kr-83M 3.29E-08 1.00E-06 Kr-85M 4.67E-07 6.00E-06 Kr-85 3.19E-04 1.00E-05 Kr-87 7.36E-08 1.00E-06 Kr-88 4.91E-07 1.00E-06 Sr-89 0.0 3.00E-08 Sr-90 0.0 1.00E-09 Y-90 0.0 1.00E-07 Sr-91 0.0 3.00E-07 Y-91 0.0 3.00E-08 Sr-92 0.0 3.00E-07 Y-92 0.0 3.00E-07 Zr-95 0.0 3.00E-08 Nb-95 0.0 1.00E-07 Mo-99 0.0 2.00E-07 I-131 0.0 9.00E-09 Te-132 0.0 2.00E-07 I-132 0.0 2.00E-07 I-133 0.0 3.00E-08 Xe-133M 8.90E-06 1.00E-05 Xe-133 1.68E-03 1.00E-05 Cs-134 0.0 1.00E-08 I-134 0.0 5.00E-07 I-135 0.0 1.00E-07 Xe-135M 7.30E-09 1.00E-06 Xe-135 2.15E-06 4.00E-06 Cs-136 0.0 2.00E-07 Cs-137 0.0 1.00E-08 Xe-138 4.64E-09 1.00E-06 Ba-140 0.0 4.00E-08 La-140 0.0 1.00E-07 Ce-144 0.0 6.00E-09 Pr-144 0.0 1.00E-06 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.2-10 ESTIMATED ACTIVITY CONCENTRATIONS IN SPENT FUEL POOL FOR ANTICIPATED OPERATIONAL OCCURRENCES CASE Rate Activity MPC Air-10 CFR 20 Nuclide mCi/cc Curies mCi/cc Cr-51 0.0 0.0 0.0 Mn-54 0.0 0.0 0.0 Mn-56 0.0 0.0 0.0 Co-58 0.0 0.0 0.0 Fe-59 0.0 0.0 0.0 Co-60 0.0 0.0 0.0 Kr-83M 0.622E-24 0.0 0.0 Kr-85M 0.806E-14 0.0 0.0 Kr-85 0.169E-05 0.0 0.0 Kr-87 0.621E-31 0.0 0.0 Kr-88 0.129E-17 0.0 0.0 Sr-89 0.821E-08 0.587E-06 0.351E-09 Sr-90 0.242E-08 0.180E-06 0.108E-09 Y-90 0.388E-09 0.216E-06 0.129E-09 Sr-91 0.679E-13 0.801E-12 0.479E-15 Y-91 0.196E-08 0.762E-05 0.456E-08 Sr-92 0.153E-21 0.567E-21 0.339E-24 Y-92 0.822E-19 0.427E-18 0.255E-21 Zr-95 0.135E-07 0.975E-06 0.583E-09 Nb-95 0.211E-07 0.154E-05 0.918E-09 Mo-99 0.454E-07 0.445E-05 0.266E-08 I-131 0.765E-06 0.449E-04 0.268E-07 Te-132 0.208E-07 0.931E-06 0.557E-09 I-132 0.279E-06 0.181E-05 0.108E-08 I-133 0.101E-07 0.218E-06 0.130E-09 Xe-133M 0.404E-07 0.0 0.0 Xe-133 0.574E-05 0.0 0.0 Cs-134 0.323E-05 0.473E-03 0.282E-06 I-134 0.0 0.0 0.0 I-135 0.260E-11 0.222E-10 0.133E-13 Xe-135M 0.365E-11 0.0 0.0 Ye-135 0.803E-09 0.0 0.0 Cs-136 0.293E-08 0.325E-06 0.194E-09 Cs-137 0.347E-05 0.511E-03 0.305E-06 Xe-138 0.0 0.0 0.0 Ba-140 0.232E-08 0.148E-06 0.882E-10 La-140 0.425E-09 0.969E-07 0.579E-10 Ce-144 0.393E-08 0.290E-06 0.174E-09 Pr-144 0.393E-08 0.290E-06 0.174E-09 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.2-11 ESTIMATED AIRBORNE ACTIVITY CONCENTRATIONS IN FUEL HANDLING AREAS FOR NORMAL OPERATION Concentration MPC Air-10 CFR 20 Nuclide Ci/cc Ci/cc H-3 1.18E-08 5.00E-06 Cr-51 0.0 2.00E-06 Mn-54 0.0 4.00E-08 Mn-56 0.0 5.00E-07 Co-58 0.0 5.00E-08 Fe-59 0.0 5.00E-08 Co-60 0.0 9.00E-09 Kr-83M 3.96E-29 1.00E-06 Kr-85M 5.23E-20 6.00E-06 Kr-85 1.15E-11 1.00E-05 Kr-87 3.88E-36 1.00E-06 Kr-88 8.28E-24 1.00E-06 Sr-89 0.0 3.00E-08 Sr-90 0.0 1.00E-09 Y-90 0.0 1.00E-07 Sr-91 0.0 3.00E-07 Y-91 0.0 3.00E-08 Sr-92 0.0 3.00E-07 Y-92 0.0 3.00E-07 Zr-95 0.0 3.00E-08 Nb-95 0.0 1.00E-07 Mo-99 0.0 2.00E-07 I-131 2.01E-16 9.00E-09 Te-132 0.0 2.00E-07 I-132 7.16E-17 2.00E-07 I-133 2.66E-18 3.00E-08 Xe-133M 2.66E-13 1.00E-05 Xe-133 3.79E-11 1.00E-05 Cs-134 0.0 1.00E-08 I-134 0.0 5.00E-07 I-135 6.79E-22 1.00E-07 Xe-135M 2.54E-17 1.00E-06 Xe-135 5.24E-15 4.00E-06 Cs-136 0.0 2.00E-07 Cs-137 0.0 1.00E-08 Xe-138 0.0 1.00E-06 Ba-140 0.0 4.00E-08 La-140 0.0 1.00E-07 Ce-144 0.0 6.00E-09 Pr-144 0.0 1.00E-06 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.2-12 ESTIMATED AIRBORNE ACTIVITY CONCENTRATIONS IN CONTAINMENT FOR NORMAL OPERATION Concentration MPC Air-10 CFR 20 Nuclide Ci/cc Ci/cc H-3 1.63E-05 5.00E-06 Cr-51 0.0 2.00E-06 Mn-54 0.0 4.00E-08 Mn-56 0.0 5.00E-07 Co-58 0.0 5.00E-08 Fe-59 0.0 5.00E-08 Co-60 0.0 9.00E-09 Kr-83M 1.46E-08 1.00E-06 Kr-85M 2.00E-07 6.00E-06 Kr-85 1.66E-04 1.00E-05 Yr-87 3.33E-08 1.00E-06 Kr-88 2.13E-07 1.00E-06 Sr-89 0.0 3.00E-08 Sr-90 0.0 1.00E-09 Y-90 0.0 1.00E-07 Sr-91 0.0 3.00E-07 Y-91 0.0 3.00E-08 Sr-92 0.0 3.00E-07 Y-92 0.0 3.00E-07 Zr-95 0.0 3.00E-08 Nb-95 0.0 1.00E-07 Mo-99 0.0 2.00E-07 I-131 1.04E-06 9.00E-09 Te-132 0.0 2.00E-07 I-132 4.79E-09 2.00E-07 I-133 1.84E-07 3.00E-08 Xe-133M 3.87E-06 1.00E-05 Xe-133 6.87E-04 1.00E-05 Cs-134 0.0 1.00E-08 I-134 9.67E-10 5.00E-07 I-135 3.10E-08 1.00E-07 Xe-135M 3.53E-08 1.00E-06 Xe-135 1.00E-06 4.00E-06 Cs-136 0.0 2.00E-07 Cs-137 0.0 1.00E-08 Xe-138 2.79E-09 1.00E-06 Ba-140 0.0 4.00E-08 La-140 0.0 1.00E-07 Ce-144 0.0 6.00E-09 Pr-144 0.0 1.00E-06 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.2-13 ESTIMATED AIRBORNE ACTIVITY CONCENTRATIONS IN TURBINE BUILDING FOR NORMAL OPERATION Concentration MPC Air-10 CFR 20 Nuclide Ci/cc Ci/cc H-3 1.79E-10 5.00E-06 Cr-51 0.0 2.00E-06 Mn-54 0.0 4.00E-08 Mn-56 0.0 5.00E-07 Co-58 0.0 5.00E-08 Fe-59 0.0 5.00E-08 Co-60 0.0 9.00E-09 Kr-83M 2.81E-14 1.00E-06 Kr-85M 1.66E-13 6.00E-06 Kr-85 4.08E-13 1.00E-05 Kr-87 9.23E-14 1.00E-06 Kr-88 2.79E-13 1.00E-06 Sr-89 0.0 3.00E-08 Sr-90 0.0 1.00E-09 Y-90 0.0 1.00E-07 Sr-91 0.0 3.00E-07 Y-91 0.0 3.00E-08 Sr-92 0.0 3.00E-07 Y-92 0.0 3.00E-07 Zr-95 0.0 3.00E-08 Nb-95 0.0 1.00E-07 Co-99 0.0 2.00E-07 I-131 5.14E-13 9.00E-09 Te-132 0.0 2.00E-07 I-132 2.33E-14 2.00E-07 I-133 8.84E-14 3.00E-08 Xe-133M 2.49E-13 1.00E-05 Xe-133 2.00E-11 1.00E-05 Cs-134 0.0 1.00E-08 I-134 4.50E-16 5.00E-07 I-135 1.49E-14 1.00E-07 Xe-135M 3.91E-13 1.00E-06 Xe-135 4.19E-13 4.00E-06 Cs-136 0.0 2.00E-07 Cs-137 0.0 1.00E-08 Xe-138 3.43E-14 1.00E-06 Ba-140 0.0 4.00E-08 La-140 0.0 1.00E-07 Ce-144 0.0 6.00E-09 Pr-144 0.0 1.00E-06 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.2-14 ESTIMATED AIRBORNE ACTIVITY CONCENTRATIONS AT CONTROL ROOM INTAKE FOR NORMAL OPERATION Concentration MPC Air-10 CFR 20 Nuclide Ci/cc Ci/cc H-3 1.42 E-10 5.00 E-06 Kr-83M 3.19 E-11 1.00 E-06 Kr-85M 2.07 E-10 6.00 E-06 Kr-85 1.95 E-08 1.00 E-05 Kr-87 1.02 E-10 1.00 E-06 Kr-88 3.30 E-10 1.00 E-06 I-131 6.60 E-13 9.00 E-09 I-132 1.42 E-13 2.00 E-07 I-133 8.92 E-13 3.00 E-08 Xe-133M 3.82 E-10 1.00 E-05 Xe-133 3.68 E-08 1.00 E-05 I-134 3.84 E-14 5.00 E-07 I-135 3.68 E-13 1.00 E-07 Xe-135M 7.37 E-11 1.00 E-06 Xe-135 5.29 E-10 4.00 E-06 Xe-138 4.15 E-11 1.00 E-06 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 12.2-15 ESTIMATED AIRBORNE ACTIVITY CONCENTRATIONS IN CONTROL ROOM FOR NORMAL OPERATION Concentration MPC Air-10 CFR 20 Nuclide Ci/cc Ci/cc H-3 3.41E-10 5.00E-06 Cr-51 0.0 2.00E-06 Mn-54 0.0 4.00E-08 Mn-56 0.0 5.00E-07 Co-58 0.0 5.00E-08 Fe-59 0.0 5.00E-08 Co-60 0.0 9.00E-09 Kr-83M 2.77E-11 1.00E-06 Kr-85M 1.93E-10 6.00E-06 Kr-85 1.96E-08 1.00E-05 Kr-87 8.35E-11 1.00E-06 Kr-88 2.98E-10 1.00E-06 Sr-89 0.0 3.00E-08 Sr-90 0.0 1.00E-09 Y-90 0.0 1.00E-07 Sr-91 0.0 3.00E-07 Y-91 0.0 3.00E-08 Sr-92 0.0 3.00E-07 Y-92 0.0 3.00E-07 Zr-95 0.0 3.00E-08 Nb-95 0.0 1.00E-07 Mo-99 0.0 2.00E-07 I-131 6.58E-13 9.00E-09 Te-132 0.0 2.00E-07 I-132 1.28E-13 2.00E-07 I-133 8.79E-13 3.00E-08 Xe-133M 3.78E-10 1.00E-05 Xe-133 3.67E-08 1.00E-05 Cs-134 0.0 1.00E-08 I-134 2.89E-14 5.00E-07 I-135 3.53E-13 1.00E-07 Xe-135M 3.54E-11 1.00E-06 Xe-135 5.13E-10 4.00E-06 Cs-136 0.0 2.00E-07 Cs-137 0.0 1.00E-08 Xe-138 1.87E-11 1.00E-06 Ba-140 0.0 4.00E-08 La-140 0.0 1.00E-07 Ce-144 0.0 6.00E-09 Pr-144 0.0 1.00E-06 DCPP UNITS 1 & 2 FSAR UPDATE Revision 15 September 2003 TABLE 12.2-17 ESTIMATED OCCUPANCY FACTORS FOR PLANT AREAS (Hours per 7-day Week) Chemical and Elect. and Radiation Mechanical Protection Control Maintenance Area Operators(a) Technicians(b) Technicians(c) Personnel(d) Control room 2000 10 300 0.3 Turbine building 700 10 1000 3000 Outside 150 50 100 2 Auxiliary building 700 2200 500 2600 corridors Fuel handling area 2 8 120 320 Primary sampling room 2 3 1 6 Containment 0.5 2 2 0.3 Volume control tank 0.03 0.2 - 0.2 compartment Charging pump compartment 0.6 0.5 3 7 Letdown heat exchanger 0.03 0.2 - 0.3 compartment Gas decay tank 0.04 0.3 - 0.3 compartment Offices 141 116 374 24 Total 3,696 2,400 2,400 5,960 _____________________ (a) Operators - 22 men for 2 units x 168 hr/week = 3,696 man-hr/week. (b) Chemical and radiation protection technicians - 60 men for 2 units x 40 hr/week = 2,400 man-hr/week. (c) Control technicians - 60 men for 2 units x 40 hr/week - 2,400 man-hr/week. (d) Maintenance personnel - electrical and mechanical - 149 men for 2 units x 40 hr/week = 5,960 man-hr/week. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 12.2-18 Sheet 1 of 3 Revision 11 November 1996 ESTIMATED INHALATION AND IMMERSION DOSES FOR PLANT AREAS Plant Personnel Exposures (Man-rem/yr)(a) Chemical and Radiation Electrical and Protection Control Mechanical Main-Area Dose Operators Technicians Technicians tenance Personnel Total
- 1. Control room Inhalation 1.69 E-01 6.02 E-04 1.76 E-02 2.58 E-05 1.88 E-01 thyroid Inhalation 2.56 E-01 9.03 E-04 2.68 E-02 3.86 E-05 2.83 E-01 whole body(b) Immersion 1.03 E+00 3.68 E-03 1.08 E-01 1.58 E-04 1.14 E+00 (beta and gamma)
- 2. Turbine building Inhalation 3.64 E-02 2.50 E-04 4.85 E-02 1.48 E-01 2.33 E-01 thyroid Inhalation 4.95 E-02 3.40 E-04 6.61 E-02 2.01 E-01 3.17 E-01 whole body(b) Immersion 2.11 E-04 1.45 E-06 2.82 E-04 8.63 E-04 1.36 E-03 (beta and gamma)
- 3. Auxiliary building Inhalation 1.46 E+01 4.52 E+01 1.08 E+01 5.27 E+01 7.59 E+01 corridors (includes thyroid primary sampling Inhalation 1.16 E+01 3.62 E+00 8.69 E-01 4.19 E+00 9.84 E+00 room) whole body(b) Immersion 2.22 E+01 6.88 E+01 1.65 E+01 7.99 E+01 1.88 E+02 (beta and gamma)
- 4. Fuel handling Inhalation 3.30 E-08 1.89 E-07 2.55 E-06 6.55 E-06 9.32 E-06 area thyroid Inhalation 7.85 E-03 4.50 E-02 6.05 E-01 1.56 E+00 2.22 E+00 whole body(b) Immersion 6.01 E-06 3.43 E-05 4.62 E-04 1.19 E-03 1.69 E-03 (beta and gamma)
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 12.2-18 Sheet 2 of 3 Revision 11 November 1996 Chemical and Radiation Electrical and Protection Control Mechanical Main-Area Dose Operators Technicians Technicians tenance Personnel Total
- 5. Containment Inhalation 5.86 E-03(e) 1.69 E-02(e) 2.53 E-02(e) 3.06 E-03(e) 5.11 E-02(e) thyroid Inhalation 3.60 E-02(f) 1.04 E-01(f) 1.55 E-01(f) 1.86 E-02(f) 3.13 E-01(f) whole body(b) Immersion 4.03 E+00 1.16 E+01 1.73 E+01 2.08 E+00 3.50 E+01 (beta and gamma)
- 6. Volume control Inhalation 4.24 E-04 2.52 E-03 0.0 2.11 E-03 5.05 E-03 tank compartment thyroid Inhalation 6.48 E-05 3.84 E-04 0.0 3.22 E-04 7.71 E-04 whole body(b) Immersion 3.22 E-02 1.91 E-01 0.0 1.60 E-01 3.84 E-01 (beta and gamma)
- 7. Charging pump Inhalation 1.14 E-02(d) .5 E-03(d) 6.27 E-03(d) 1.26 E-01(d) 1.53 E-01(d) compartment thyroid Inhalation 1.74 E-03 1.45 E-03 9.57 E-03 1.93 E-02 2.35 E-02 whole body(b) Immersion 8.65 E-01 7.2 E-01 4.75 E-01 9.5 E+00 5.28 E+02 (beta and gamma)
- 8. Letdown heat Inhalation 2.09 E-04(c) 1.14 E-03(c) 0.0 1.91 E-03(c) 3.26 E-03(c) exchanger thyroid compartment Inhalation 1.02 E-04 5.96 E-04 0.0 9.93 E-04 1.69 E-03 whole body(b) Immersion 1.62 E-04 8.84 E-03 0.0 1.47 E-02 2.37 E-02 (beta and gamma)
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 12.2-18 Sheet 3 of 3 Revision 11 November 1996 Chemical and Radiation Electrical and Protection Control Mechanical Main-Area Dose Operators Technicians Technicians tenance Personnel Total
- 9. Gas decay tank Inhalation 0.0 0.0 0.0 0.0 0.0 compartment thyroid Inhalation 0.0 0.0 0.0 0.0 0.0 whole body(b) Immersion 5.12 E-01 4.8 E+00 0.0 4.8 E+00 1.01 E+01 (beta and gamma)
Total for All Inhalation 1.49 E+01 4.52 E+01 1.1 E+01 5.3 E+01 1.24 E+02 Areas thyroid Inhalation 1.53 E+00 3.77 E+00 1.72 E+00 5.99 E+00 1.30 E+01 whole body(b) Immersion 2.47 E+02 8.62 E+01 3.44 E+01 9.65 E+01 4.64 E+02 (beta and gamma)
(a) Basis: 50 weeks/year. (b) From tritium inhalation and absorption through skin. (c) Includes use of a respirator with a protection factor of 100. (d) Includes use of a respirator with a protection factor of 10. (e) Includes use of a respirator with a protection factor of 10,000. (f) Includes use of a protective suit, hood, and respirator with a total protection from tritium factor of 100.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 12.3-1 Sheet 1 of 3 Revision 16 June 2005 HEALTH PHYSICS PORTABLE INSTRUMENTATION Item Nominal Detector Radiation No. Instrument Identification Quantity Type Measured Range Dose Rate Meters
- 1. High Range 2 GM g 1 R/hr - 10 Kr/hr
- 2. Low Range 5 GM g Dose Rate:
Bkg to 3000 mR/hr
- 3. Dose Rate Meter 30 Ion chamber b, g 0-5,000 mR/hr
- 4. Condenser R-meter 1 Ion chamber G 0-0.25, 0-2.5, 0-25 R
Self-Reading Pocket Ion Chambers
- 1. Direct Reading Pocket Dosimeters 250 Ion chamber G 0-200 mR
- 2. Direct Reading Pocket Dosimeters 50 Ion chamber g 0-1R and 0-2R
- 3. Direct Reading Pocket Dosimeters 60 Ion chamber g 0-5 R
- 4. Direct Reading Pocket Dosimeters 5 Ion chamber g 0-50R
- 5. Direct Reading Pocket Dosimeters 5 Ion chamber g 0-100 R
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 12.3-1 Sheet 2 of 3 Revision 16 June 2005 Item Nominal Detector Radiation No. Instrument Identification Quantity Type Measured Range Count Rate Meters
- 1. Count Rate Meter 5 GM 500,000 cpm
- 2. Count Rate Meter 10 - 70,000 cpm
- 3. Pulse Rate Meter 3 - 500,000 cpm
- 4. Count Rate Meter 40 - 50,000 cpm
Count Rate Meter Probes And Detectors
- 1. Hand Probe 30 GM b, g -
- 2. Shielded Hand Probe 10 GM b, g -
- 3. Alpha Scintillation Probe 1 ZnS(Ag) Alpha -
- 4. Gamma Scintillation Probe 2 NaI(TI) g -
Scintillation Monitors
- 1. Rad Portal Monitor 4 Scintil. b, g 0-9999 cpm
- 2. Portable Gamma Monitor 2 Scintil. g 0.1 to 1000 mR/hr DCPP UNITS 1 & 2 FSAR UPDATE TABLE 12.3-1 Sheet 3 of 3 Revision 16 June 2005 Item Nominal Detector Radiation No. Instrument Identification Quantity Type Measured Range Neutron Proportional Counters
- 1. Portable Rem Counter 1 BF3 n, thermal 0-5000 mrem/hr to fast
Solid-State Dosimeters
- 1. Personal Electronic Dosimeters 500 Si b, g 0-9999 mR
Miscellaneous
- 1. Self-reading Dosimeter Charger 4 - - -
- 2. Scaler with Ratemeter 1 - - Scaler, 106- 1 counts: Ratemeter, 0-500, 0-5K, 0-50K, 0-500K cpm
- 3. Extendable Probe Dose Rate 10 GM b, g 0-1000 R/hr Meter A variety of portable instrumentation is available for radiological monitoring. The general equipment types are summarized in this table. It should be noted that this list is intended only to be illustrative of what may be in use. Quantities and types of specific equipment may vary from time to time as conditions change, new products appear on the market, etc.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 12.3-2 HEALTH PHYSICS AIR SAMPLING INSTRUMENTATION Item Nominal Detector Radiation No. Instrument Identification Quantity Type Measured Range 1. Personnel Air Sampler 6 - 4 liters/min 2. Portable Air Samplers 10 - 2 cfm 3. Continuous Air Monitor 6 Sealed Gas - Proportional Beta ~ 0.3-4 cfm Single Channel Particulate / Iodine or Particulate Noble Gas NOTE: A variety of air sampling equipment is available for radiological monitoring. The general equipment types are summarized in this table. It should be noted that this list is intended only to be illustrative of what may be in use. Quantities and types of specific equipment may vary from time to time as conditions change, new products appear on the market, etc. DCPP UNITS 1 & 2 FSAR UPDATE Revision 16 June 2005 TABLE 12.3-3 RESPIRATORS APPROVED FOR USE AT DIABLO CANYON POWER PLANT FOR PROTECTION AGAINST RADIOACTIVE MATERIALS Nominal Type of Respirator Quantity Air purifying, full facepiece, various sizes 100 Powered air purifying respirator (PAPR) 5 Airline respirator, constant flow 20 Self-contained breathing 108 NOTE: A variety of respirators are available for use. The general types are summarized in this table. It should be noted that this list is intended only to be illustrative of what may be in use. Quantities and types of specific equipment may vary from time to time as conditions change, new products appear on the market, etc.
FIGURES 12.1-1 THROUGH 12.1-12 TO BE WITHHELD FROM PUBLIC PER 10 CFR 2.390 AND SECY-04-0191. DCPP UNITS 1 & 2 FSAR UPDATE Chapter 13 CONDUCT OF OPERATIONS CONTENTS Section Title Page i Revision 21 September 2013 13.1 ORGANIZATIONAL STRUCTURE 13.1-1 13.1.1 Corporate Organization 13.1-1 13.1.1.1 Corporate Functions, Responsibilities, and Authorities 13.1-1 13.1.1.2 Corporate Staffing and Organizational Relationships 13.1-2 13.1.1.3 Interrelationship with Contractors and Suppliers 13.1-3 13.1.1.4 Technical Staff 13.1-3
13.1.2 Operating Organization 13.1-3 13.1.2.1 Plant Organization 13.1-3 13.1.2.2 Personnel Functions, Responsibilities, and Authorities 13.1-5 13.1.2.3 Shift Crew Composition 13.1-14
13.1.3 Qualification Requirements for Nuclear Plant Personnel 13.1-15 13.1.3.1 Minimum Qualification Requirements 13.1-15 13.1.3.2 Qualifications of Plant Personnel 13.1-16 13.1.4 References 13.1-16
13.2 TRAINING PROGRAM 13.2-1
13.2.1 Initial Program Description 13.2-1 13.2.1.1 Program Content 13.2-1 13.2.1.2 Coordination with Preoperational Tests and Fuel Loading 13.2-2 13.2.1.3 Practical Reactor Operation 13.2-3 13.2.1.4 Reactor Simulator Training 13.2-3 13.2.1.5 Previous Nuclear Training 13.2-3 13.2.1.6 Other Scheduled Training 13.2-3 13.2.1.7 Training Programs for Nonlicensed Personnel 13.2-3 13.2.1.8 General Employee Training Program 13.2-4 13.2.1.9 Responsible Individual 13.2-4
13.2.2 Licensed Operator Continuing (Requalification) Training Program 13.2-5
13.2.3 Replacement Training 13.2-5 13.2.3.1 Licensed Operator and Senior Operator Training Program 13.2-5 13.2.3.2 Shift Technical Advisor Training Program 13.2-5 13.2.3.3 Non-Licensed Operator Training Program 13.2-6 DCPP UNITS 1 & 2 FSAR UPDATE Chapter 13 CONTENTS (Continued) Section Title Page ii Revision 21 September 2013 13.2.4 Records 13.2-6 13.3 EMERGENCY PLANNING 13.3-1
13.3.1 References 13.3-1
13.4 REVIEW AND AUDIT 13.4-1
13.4.1 Review and Audit - Construction Phase 13.4-1
13.4.2 Review and Audit - Operation Phase 13.4-1 13.4.2.1 Plant Staff Review Committee 13.4-1 13.4.2.2 Independent Review and Audit Program 13.4-1 13.4.2.3 Management Oversight Groups 13.4-1
13.5 PLANT PROCEDURES AND PROGRAMS 13.5-1
13.5.1 Procedures 13.5-1 13.5.2 Programs 13.5-1 13.5.2.1 Process Control Program 13.5-1 13.5.2.2 Radiation Protection Program 13.5-2 13.5.2.3 In-Plant Radiation Monitoring 13.5-2 13.5.2.4 Backup Method for Determining Subcooling Margin 13.5-2 13.5.2.5 Containment Polar and Turbine Building Cranes 13.5-2 13.5.2.6 Motor-Operated Valve Testing and Surveillance Program 13.5-2
13.5.3 References 13.5-3
13.6 PLANT RECORDS 13.6-1
13.7 PHYSICAL SECURITY 13.7-1
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 13 TABLES Table Title iii Revision 21 September 2013 13.2-1 Summary of Activities Employed in Training Programs for Persons in the Initial Diablo Canyon Operating Organization (Historical as submitted in November 1978) 13.2-2 Training Summary for Individuals in the Initial Diablo Canyon Operating Organization (Historical)
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 13 FIGURES Figure Title iv Revision 21 September 2013 13.1-1A Site Organization 13.1-1B Services Organization
13.1-1C Operating Organization
13.1-2 Deleted in Revision 18
13.1-3 Effective Shift Organization - Either or Both Units Fueled and Above 200°F Primary System Temperature 13.1-4 Minimum Shift Organization - Both Units Defueled or Primary System Temperature at or Below 200°F 13.1-5 Operations Organization if Manager Does Not Hold SRO License
13.1-6 Operations Organization if Manager Holds SRO License 13.2-1 Initial Schedule of Planned Nuclear Training (Historical)
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 13 APPENDICES Appendix Title v Revision 21 September 2013 13.1A Deleted in Revision 17 13.1B Deleted in Revision 12
DCPP UNITS 1 & 2 FSAR UPDATE 13.1-1 Revision 21 September 2013 Chapter 13 CONDUCT OF OPERATIONS Pacific Gas and Electric Company (PG&E) became involved in the operation of nuclear power plants in 1957 after many years of successfully operating its fossil-fueled power plants. In the operation of Humboldt Bay Power Plant (HBPP), Unit 3, and Diablo Canyon Power Plant (DCPP), Units 1 and 2, PG&E has demonstrated its dedication as a competent and safety-oriented operating organization. PG&E is also committed to continually developing and enhancing the organization responsible for operation of its power plants to meet expanded technical and regulatory requirements. In keeping with this commitment, PG&E has made significant changes since commencement of operations in its nuclear organization and operating policies to strengthen PG&E's capability to operate its nuclear power plants safely and reliably for all operating conditions. 13.1 ORGANIZATIONAL STRUCTURE 13.1.1 CORPORATE ORGANIZATION PG&E's organizational structure is shown in Figure 17.1-1. The manner in which the various PG&E departments function in performing the design, operation, and quality assurance of DCPP is described in succeeding sections. Chapter 17 provides further discussion of the utility organization. 13.1.1.1 Corporate Functions, Responsibilities, and Authorities The Board of Directors of PG&E Corporation oversees the governance of PG&E.
The Chairman, CEO, and President, PG&E Corporation, is accountable to the Board of Directors and establishes the corporate policies, goals, and objectives related to all of PG&E's activities and operations. Reporting to the Chairman, CEO, and President, PG&E Corporation, is the President, PG&E. The President, PG&E, is a member of the Board of Directors and is responsible for and directs the planning, distribution, and development of all the Company's energy resources and nuclear power generation. These functions include such activities as planning and development, engineering, construction, and fossil and nuclear power plant operations. Reporting to the President and Chief Executive Officer, PG&E, is the Senior Vice President, Energy Supply, the Senior Vice President, Safety and Shared Services, and the Executive Vice President - Electric Operations. The Executive Vice President - Electric Operations, through the Director - Applied Technology Services, is responsible for providing, upon request: (1) technical investigations, tests, analyses, examinations, and calibration services in support of Diablo Canyon and Humboldt Bay Power Plants; (2) developing, evaluating, qualifying, DCPP UNITS 1 & 2 FSAR UPDATE 13.1-2 Revision 21 September 2013 testing, and improving welding, brazing, and heat-treating procedures required by the company; and (3) providing evaluation support of these procedures.
The Senior Vice President, Safety and Shared Services, through the Support Services Supervisor - Engineering Records Unit, is responsible for providing document services support for Diablo Canyon and Humboldt Bay Power Plants. These services include indexing, preparing, and duplicating microfiche for the drawing control system; storing the master microfiche and drawings that cannot be microfilmed; and scanning and indexing drawings when requested by Nuclear Generation. They also provide remote storage of master microfilm reels for the records management system (RMS) and storage of vendor manuals. The Senior Vice President, Safety and Shared Services, through the Manager - Nuclear Supply Chain, is responsible for the administration, coordination, planning, and operation of warehousing and material procurement in support of DCPP construction and operations, as well as for contract services.
The Senior Vice President, Energy Supply, is responsible for the safe and efficient operation of utility owned generation. Reporting to the Senior Vice President, Energy Supply is the Senior Vice President, Chief Nuclear Officer. The Senior Vice President, Chief Nuclear Officer, is responsible for the safe and efficient operation of PG&E's nuclear power plants. The Senior Vice President, Chief Nuclear Officer, is the corporate officer specified by the DCPP Technical Specifications, Section 5, who shall have corporate responsibility for overall plant nuclear safety and shall take any measures needed to ensure acceptable performance of the staff in operating, maintaining, and providing technical support to the plant to ensure nuclear safety. Reporting to the Senior Vice President, Chief Nuclear Officer, is the Site Vice President; Senior Director, Engineering and Projects; Director, Quality Verification; Director, Humboldt Bay Nuclear; Director, Strategic Projects; Director, Station Support; and DCPP Employee Concerns Program supervisor. The Site Vice President is responsible for overall safe operation of the plant and has control over onsite activities necessary for safe operation and maintenance of the plant. Reporting to the Site Vice President is the Station Director; and the Director, Security Services. 13.1.1.2 Corporate Staffing and Organizational Relationships Current operations of PG&E are organized under and responsible to the Chairman of the Board. Reporting directly to the Chairman of the Board is the Chairman, Chief Executive Officer, and President, PG&E Corporation.
Reporting directly to the Chairman, CEO, and President, PG&E Corporation is the President, PG&E.
DCPP UNITS 1 & 2 FSAR UPDATE 13.1-3 Revision 21 September 2013 Reporting to the President, PG&E, is the Senior Vice President, Energy Supply; the Senior Vice President, Safety and Shared Services; and the Executive Vice President - Electrical Operations. Reporting to the Senior Vice President, Chief Nuclear Officer, is the Site Vice President; the Senior Director, Engineering and Projects; the Director, Quality Verification; the Director, Humboldt Bay Nuclear; the Director, Strategic Projects; the Director, Station Support and the DCPP Employee Concerns Program Supervisor. Reporting to the Site Vice President is the Station Director and the Director, Security Services. 13.1.1.3 Interrelationship With Contractors And Suppliers The working interrelationships and organizational interfaces between PG&E, Westinghouse (the nuclear steam supply system (NSSS) manufacturer) and other suppliers and contractors are described in Chapter 1. 13.1.1.4 Technical Staff Nuclear Generation may call upon a variety of other PG&E departments, as well as outside consultants, to assist in the technical support of nuclear power plant operations as shown in Figure 17.1-1.
PG&E's overall technical capability is such that most technical support functions for nuclear power plants are handled within the PG&E organization. Outside consultants are available to provide technical support in all technical areas for plant operations and are used to assist on special problems as required. Consultant personnel interface with PG&E specialists in a variety of technical, engineering, and design areas. 13.1.2 OPERATING ORGANIZATION 13.1.2.1 Plant Organization Overall responsibility for the operation of Diablo Canyon is assigned to the Senior Vice President, Chief Nuclear Officer. The division of responsibilities is as follows: (1) Senior Vice President, Chief Nuclear Officer (a) Site Vice President
(b) Senior Director, Engineering and Projects (c) Employee Concerns Program Supervisor
(d) Director, Quality Verification DCPP UNITS 1 & 2 FSAR UPDATE 13.1-4 Revision 21 September 2013 (e) Director, Strategic Projects (f) Director, Station Support (2) Site Vice President (a) Station Director (b) Director, Security Services Security Services Cyber Security Supervisor
(3) Senior Director, Engineering and Projects (a) Director, Engineering Services Mechanical Systems Engineering Technical Support Engineering Instrumentation, Controls, and Electrical Systems Engineering Design Engineering Project Engineering (b) Nuclear Fuels Management
(c) Director, Geosciences (d) Director, Nuclear Projects (e) Regulatory Services (4) Director, Strategic Projects Project Services Project managers for various special projects Construction (5) Director, Station Support (a) Director, Site Services Procedure and Document Services Emergency Planning Performance Improvement (b) Director, Learning Services (c) Director, Compliance, Alliance, and Risk DCPP UNITS 1 & 2 FSAR UPDATE 13.1-5 Revision 21 September 2013 (6) Station Director (a) Director, Operations Services Operations Operations Performance Operations Planning Chemistry and Environmental Operations (b) Director, Nuclear Work Management Daily Work Control Outage Management Outage Services Planning (c) Director, Maintenance Services Electrical Instrumentation and Controls Maintenance Team Mechanical (d) Manager, Radiation Protection The organizational charts for positions described in this section are provided in Figures 13.1-1A and C. 13.1.2.2 Personnel Functions, Responsibilities, and Authorities
13.1.2.2.1 Senior Vice President, Chief Nuclear Officer The Senior Vice President, Chief Nuclear Officer, is responsible for the safe and efficient operation of PG&E's nuclear power plants, quality verification, and the employee concerns program.
The site organizational chart for positions described in this section are provided in Figure 13.1-1A. 13.1.2.2.1.1 Site Vice President The Site Vice President is responsible for overall safe operation of the plant and has control over onsite activities necessary for safe operation and maintenance of the plant. 13.1.2.2.1.2 Senior Director, Engineering and Projects The Senior Director, Engineering and Projects, is responsible for configuration control; design bases defense and management; providing engineering support for plant operations; managing technical programs related to system and component health and long-term planning; replacement parts design; design drafting; engineering support of DCPP UNITS 1 & 2 FSAR UPDATE 13.1-6 Revision 21 September 2013 emergent work; predictive monitoring of equipment performance; nuclear fuel configuration management; preventive maintenance management; plant transient analysis design bases defense and management; complying with regulatory requirements pertaining to SSCs; geotechnical services; and strategic projects. In addition, this position is specifically charged with development, evaluation, qualification, testing, and improvement of nondestructive examination procedures required by PG&E and for evaluation of these types of procedures that are used at DCPP by other organizations.
Reporting to the Senior Director, Engineering and Projects, is the Director, Engineering Services; the Director, Geosciences; the Director, Nuclear Projects; the Manager, Regulatory Services and the Manager, Nuclear Fuels Purchasing. 13.1.2.2.1.2.1 Director, Geosciences The Director, Geosciences, is responsible for providing seismic, geologic, and geotechnical services for the safe and reliable operation of company facilities. Of particular importance to DCPP and Humboldt Bay Power Plant are the department capabilities and expertise in the following areas: site characterization, earthquake activity interpretations, seismic hazard analyses, ground motion studies, post-earthquake inspections, seismic risk evaluations, seismic instrumentation, geotechnical exploration, slope stability evaluations, and soil and rock testing. 13.1.2.2.1.2.2 Director, Engineering Services The Director, Engineering Services, is responsible for providing day-to-day engineering support for plant operations and for performance of modifications to the plant. Reporting to the Director, Engineering Services, are the Manager, Mechanical Engineering; Manager, Technical Support Engineering; Manager, Design Engineering; Manager, Projects Engineering, and the Manager, Instrumentation, Controls, and Electrical Engineering. 13.1.2.2.1.2.3 Director, Nuclear Projects The Director, Nuclear Projects is responsible for the response to Fukushima, Seismic studies and the License Renewal project. 13.1.2.2.1.2.4 Manager, Nuclear Fuels Purchasing The Manager, Nuclear Fuels Purchasing, is responsible for developing, directing, and administering the company-wide nuclear fuel procurement strategy, inventory policy, and fuel contract management program in support of plant operations. DCPP UNITS 1 & 2 FSAR UPDATE 13.1-7 Revision 21 September 2013 13.1.2.2.1.2.5 Manager, Regulatory Services The Manager, Regulatory Services, is responsible for NRC regulatory submittals; the license amendment process; the reportability process; the technical specification bases and final safety analysis report update processes; the commitment management process; and coordinating interactions with the NRC inspectors. 13.1.2.2.1.3 Director, Quality Verification The Director, Quality Verification, is responsible for management of the Quality Assurance (QA) Program and for assuring that the QA Program is implemented and complied with by all involved organizations, both internal and external to PG&E. Refer to Section 17.1 for additional responsibilities. The Director, QV, is responsible for independent review and oversight of operations, corrective action, plant support, engineering, procurement, and maintenance activities performed by or for DCPP. These responsibilities are described in Chapter 17. 13.1.2.2.1.4 Director, Strategic Projects The Director, Strategic Projects is responsible for project management services for Diablo Canyon, including management of all strategic projects. Reporting to the Director, Strategic Projects is the Manager, Project Services and project managers for various special projects identified by DCPP management, and the Manager, Construction Management. 13.1.2.2.1.4.1 Manager, Project Services The Manager, Project Services, is responsible for implementation of capital and expense projects at Diablo Canyon. These projects would be considered as "typical" utility commitments for equipment reliability and component improvements. 13.1.2.2.1.4.2 Manager, Construction Management The Manager, Construction Management, is responsible for administering, coordinating, planning, and scheduling all construction maintenance activities at the plant. This position provides direction, assistance, and guidance to onsite contractor and facilities maintenance. 13.1.2.2.1.5 Director, Station Support The Director, Station Support is responsible for training and site services, which includes emergency planning and performance improvement. DCPP UNITS 1 & 2 FSAR UPDATE 13.1-8 Revision 21 September 2013 13.1.2.2.1.5.1 Director, Site Services The Director, Site Services, provides direct supervision over performance improvement; emergency planning, and procedure and document services. Reporting to the Director, Site Services, is the Manager, Procedure and Document Services; the Manager, Performance Improvement; and the Manager, Emergency Planning. The Manager, Specialized Applications Group - Generation, is matrixed to the Director, Site Services, and reports to Information Systems Technology Services. 13.1.2.2.1.5.1.1 Manager, Procedure and Document Services The Manager, Procedure and Document Services, is responsible for the control and distribution of all controlled drawings and implementation of the record management program and DCPP's procedure program. This position is also responsible for the overall coordination of DCPP's procedure program and for providing various procedure related services. 13.1.2.2.1.5.1.2 Manager, Specialized Applications Group - Generation The Manager, Specialized Applications Group - Generation, is responsible for overall coordination of software lifecycle management activities conducted within Nuclear Generation-Information Systems, including administration of the software program inventory. 13.1.2.2.1.5.1.3 Manager, Emergency Planning The Manager, Emergency Planning, is responsible for the development, coordination, and implementation of all emergency planning activities, including providing the plant interface with the corporate emergency planning activities; and for the development, coordination, and implementation of emergency planning at the site. 13.1.2.2.1.5.1.4 Manager, Performance Improvement The Manager, Performance Improvement, is responsible for the overall management of the performance improvement program; for providing oversight to ensure trends adverse to quality are identified, and for Identifying key performance indicators to be used in assessing the overall health of the performance improvement process. 13.1.2.2.1.5.2 Director, Learning Services The Director, Learning Services, is responsible for the overall implementation, maintenance, monitoring, and evaluation of nuclear generation activities associated with personnel training and qualifications and for obtaining and maintaining accreditation for training programs specifically identified by INPO. DCPP UNITS 1 & 2 FSAR UPDATE 13.1-9 Revision 21 September 2013 13.1.2.2.1.5.3 Director, Compliance, Alliance, and Risk The Director, Compliance, Alliance, and Risk, is responsible for the integrated business plan and the continuous improvement process. The Manager, Nuclear Supply Chain, is matrixed to the Director, Compliance, Alliance, and Risk, and reports directly to the Director, Generation Supply Chain. The Manager, Business Planning, is matrixed to the Director, Compliance, Alliance, and Risk, and reports directly to Business Finance. 13.1.2.2.1.5.3.1 Manager, Nuclear Supply Chain The Manager, Nuclear Supply Chain, is responsible for administering, coordinating, planning, and operation of warehousing and procurement of materials in support of plant operations and construction, as well as for contract services. This position is responsible for the functions within the materials procurement group including: the procurement specialist group, warehousing operations, and materials coordination. 13.1.2.2.1.6 Employee Concerns Program Supervisor The Supervisor, Employee Concerns Program is responsible for management of a program, independent of line management, for company and contractor employees to raise concerns dealing with harassment, intimidation, retaliation or discrimination without fear of retaliation. 13.1.2.2.2 Site Vice President Organization 13.1.2.2.2.1 Station Director The Station Director is responsible within those limits established by the plant operating licenses and the policy of the Senior Vice President, Chief Nuclear Officer, for the development and implementation of those programs, procedures, and instructions required for the operation of DCPP. The Station Director, has been delegated the necessary authority to approve and direct development and implementation of these programs, procedures, and instructions. The Station Director is the plant manager specified in the DCPP Technical Specifications, Section 5. 13.1.2.2.2.2 Director, Security Services The Director, Security Services, is responsible for implementation of the Security Program that includes the Security Plan. Reporting to the Director, Security Services, is Manager, Security Services and the Supervisor, Cyber Security. 13.1.2.2.2.2.1 Managers, Security Services The Managers, Security Services, are responsible for developing, planning, and coordinating all activities associated with the plant security program. DCPP UNITS 1 & 2 FSAR UPDATE 13.1-10 Revision 21 September 2013 13.1.2.2.2.2.2 Supervisor, Cyber Security The Supervisor, Cyber Security is the single point of contact for DCPP Cyber Security Program. 13.1.2.2.3 Operating Organization Responsibilities The plant operating organization authorized for two-unit operation is shown in Figure 13.1-1C. 13.1.2.2.3.1 Functions, Responsibilities, and Authorities The functions, responsibilities, and authorities of key supervisor positions in the DCPP operating organization are summarized briefly in the following paragraphs. Each organization that supports DCPP documents and maintains current a written description of its internal organization. This documentation describes the business unit or department's structure, levels of authority, lines of communication, and assignments of responsibility. Such documentation takes the form of organization charts supported by written job descriptions or other narrative material in sufficient detail that the duties and authority of each individual whose work affects quality is clear. Interfaces between organizations are described in administrative procedures or other documents controlled in accordance with the appropriate requirements of Section 17.6. 13.1.2.2.3.2 Station Director The Station Director is responsible for operations, maintenance, and nuclear work management. The Station Director is the plant manager specified in the DCPP Technical Specifications, Section 5. 13.1.2.2.3.2.1 Director, Operations Services The Director, Operations Services, exercises direct supervision over operations activities. The Director, Operations Services, reports to the Station Director. Reporting to the Director, Operations Services, is the Manager, Operations; the Manager, Operations Planning; the Manager, Operations Performance; and the Manager, Chemistry and Environmental Operations. 13.1.2.2.3.2.1.1 Manager, Operations The Manager, Operations, is the operations manager specified in the DCPP Technical Specifications, Section 5. He is the responsible Manager for ensuring that appropriate operating procedures are available and that operating personnel are familiar with the procedures. In carrying out these responsibilities, he provides direct supervision to the Operations Superintendent (if the Manager, Operations, does not hold a Senior Reactor Operator (SRO) license for Diablo Canyon), the Operations Dayshift Supervisor, the technical assistants, and the operations engineers. DCPP UNITS 1 & 2 FSAR UPDATE 13.1-11 Revision 21 September 2013 During high workload periods (such as outages), the Director, Operations Services, may choose to appoint an additional operations manager in order to better fulfill the responsibilities listed above. In such cases, the division of responsibilities will be clearly identified, and establishment of that position will be communicated to all appropriate organizations. 13.1.2.2.3.2.1.1.1 Operations Superintendent If the operations manager does not hold an SRO license for Diablo Canyon, the Operations Superintendent shall hold an SRO license for Diablo Canyon. The Operations Superintendent shall be responsible for providing operating instructions to the Shift Foremen and Shift Managers as indicated in Figure 13.1-5. The Operations Superintendent satisfies the operations middle manager position specified in the Technical Specifications and shall meet the requirements of ANSI 3.1-1993, Sections 4.2.2 and 4.3. This position is not intended to be filled using rotational personnel.
If the operations manager holds an SRO license for Diablo Canyon, the Operations Superintendent position is not required to be staffed as indicated in Figure 13.1-6. 13.1.2.2.3.2.1.1.2 Shift Manager The Shift Manager is responsible for overall supervision of the operation of the facility. He provides direct supervision to the Shift Foremen, and, in the absence of higher supervision, is in full charge of the plant. In the event of an operating emergency, the Shift Manager is authorized to take any actions he deems necessary.
13.1.2.2.3.2.1.1.3 Shift Foreman The Shift Foreman is responsible for providing direct supervision of the plant operators, the work they perform, and for providing administrative support in this area. The Shift Foreman has command and control responsibility for the control room for his assigned unit.
The Shift Foreman may also be assisted by a work control shift foreman. The work control shift foreman is an optionally manned position, whose function is described in the appropriate administrative procedure. 13.1.2.2.3.2.1.1.4 Shift Technical Advisor The shift technical advisor (STA) function will normally be assigned to one of the SRO licensed operators on crew. The STA function may be assigned to an STA-qualified individual supplementing the crew.
The STA provides technical and analytical support to the operating shift crew to ensure safe operation of the plant. DCPP UNITS 1 & 2 FSAR UPDATE 13.1-12 Revision 21 September 2013 During transient and emergency events, the STA qualified individual is responsible for applying their background to the analysis and response to the event and advising the rest of the crew, as applicable, on actions to terminate or mitigate the consequences of such events. 13.1.2.2.3.2.1.2 Manager, Operations Planning The Operations Planning Manager is responsible for outage and daily work control planning and clearance preparation. 13.1.2.2.3.2.1.3 Manager, Operations Performance The Operations Performance Manager is responsible for the Industrial Fire Group, oversight of Operations Training programs, and the Operations administrative support. 13.1.2.2.3.2.1.4 Manager, Chemistry and Environmental Operations The Manager, Chemistry and Environmental Operations, is responsible for administering, coordinating, planning, and scheduling all chemistry activities at the plant. He is also responsible for coordinating DCPP environmental activities and for developing and managing programs to achieve and maintain compliance with all environmental regulations and requirements. 13.1.2.2.3.2.2 Manager, Radiation Protection The Manager, Radiation Protection, is responsible for administering, coordinating, planning, and scheduling all radiation protection activities at the plant. The Manager, Radiation Protection, is the radiation protection manager specified in the DCPP Technical Specifications, Section 5. While the manager reports directly to the Station Director, he has direct access to the Site Vice President, and the Senior Vice President, Chief Nuclear Officer on matters concerning radiation protection and support. 13.1.2.2.3.2.3 Director, Nuclear Work Management The Director, Nuclear Work Management, is responsible for the management of DCPP unit outages including planning, organizing, staffing, directing, and controlling the preparation of outages. The Director, Nuclear Work Management, is also responsible for the daily work control process and organization. 13.1.2.2.3.2.3.1 Manager, Daily Work Control The Manager, Work Control, is responsible for outage and maintenance-critical scheduling, and is responsible to ensure that all maintenance, refueling, and modification activities are coordinated between the various maintenance organizations and that proper interfaces and detailed plans exist for the timely and safe performance of all plant activities. DCPP UNITS 1 & 2 FSAR UPDATE 13.1-13 Revision 21 September 2013 13.1.2.3.2.3.2 Manager, Outage Management The Manager, Outage is responsible for outage and scheduling (including refueling, maintenance, and unplanned outages), and is responsible to ensure that all outage maintenance and modification activities are coordinated between the various maintenance organizations and that proper interfaces and detailed plans exist for the timely and safe performance of all plant activities. 13.1.2.2.3.2.3.3 Manager, Outage Services The Manager, Outage Services is responsible outage strategies and outage-related business planning, as well as refueling outage safety plan development and outage work window planning. 13.1.2.2.3.2.3.4 Manager, Planning The Manager, Planning, is responsible for planning work instructions for all maintenance activities at the plant. This position provides direction, assistance, and guidance to maintenance planning personnel in preventive and corrective maintenance techniques and programs. 13.1.2.2.3.2.4 Director, Maintenance Services The Director, Maintenance Services, exercises direct supervision over maintenance. Reporting to the director is the Manager, Electrical Maintenance; the Manager, Instrumentation and Controls Maintenance; the Manager, Mechanical Maintenance; and the Manager, Maintenance Support. 13.1.2.2.3.2.4.1 Manager, Electrical Maintenance The Manager, Electrical Maintenance, is responsible for administering, coordinating, planning, and scheduling all electrical maintenance activities at the plant. This position provides direction, assistance, and guidance to electrical maintenance personnel in preventive and corrective maintenance techniques and programs. 13.1.2.2.3.2.4.2 Manager, Instrumentation and Controls Maintenance The Manager, Instrumentation and Controls (I&C) Maintenance, is responsible for administering, coordinating, planning, and scheduling all I&C maintenance activities at the plant. This position provides direction, assistance, and guidance to I&C maintenance personnel in preventive and corrective maintenance techniques and programs. 13.1.2.2.3.2.4.3 Manager, Maintenance Support The Manager, Maintenance Support, is responsible for administering, coordinating, planning, and scheduling all multi-disciplined team activities at the plant. This position DCPP UNITS 1 & 2 FSAR UPDATE 13.1-14 Revision 21 September 2013 provides direction, assistance, and guidance to operations support team personnel in preventive and corrective maintenance techniques and programs. 13.1.2.2.3.2.4.4 Manager, Mechanical Maintenance The Manager, Mechanical Maintenance, is responsible for administering, coordinating, planning, and scheduling all mechanical maintenance activities at the plant. This position provides direction, assistance, and guidance to mechanical maintenance personnel in preventive and corrective maintenance techniques and programs. 13.1.2.3 Shift Crew Composition With either or both units fueled and above 200°F in primary system temperature, a minimum shift organization is composed of:
- one Shift Manager and one Shift Foreman, each with a Senior Operator License.
- three Licensed Operators, at least one will be assigned to each unit.
- three Auxiliary Operators, at least one will be assigned to each unit.
- one Shift Technical Advisor, an individual who provides technical support to the unit operations shift crew in the areas of thermal hydraulics, reactor engineering, and plant analysis with regard to safe operation of the unit.
This position will be manned unless there is a crew member with an SRO license who meets the qualifications specified by the Commission Policy Statement on Engineering Expertise on Shift.
- one Chemical and Radiation Protection Technician. This organization is shown in Figure 13.1-3. With both units defueled or both units at or below 200°F in primary system temperature, the minimum shift crew complement is reduced to:
- one Shift Foreman.
- no Senior Licensed Operator. However, at least one licensed Senior Operator or licensed Senior Operator limited to fuel handling will be present during core alterations on either unit who has no other concurrent responsibilities.
- two licensed operators, at least one will be assigned to each unit.
- three auxiliary operators, at least one will be assigned to each unit.
DCPP UNITS 1 & 2 FSAR UPDATE 13.1-15 Revision 21 September 2013
- one chemical and radiation protection technician. This organization is shown in Figure 13.1-4.
The shift crew composition may be one less than the above minimum requirements, 10 CFR 50.54(m)(2)(i), and the Technical Specifications for a period of time not to exceed two hours in order to accommodate unexpected absence of on duty shift crew members provided immediate action is taken to restore the shift crew composition to within the above minimum requirements. This provision does not permit any shift crew position to be unmanned upon shift change due to an oncoming shift crewman being late or absent.
The establishment of the shift organization is based on consideration of PG&E's power plant staffing philosophy, the evaluation of the operating practices of U.S. pressurized water reactor plants, PG&E's experience with HBPP and large (up to 750 MWe) fossil-fuel units, and the expanded technical and operational regulatory requirements of nuclear power operation.
This shift organization provides effective manpower to cover the operating contingencies that can reasonably be expected to occur during normal operation of the plant. An organization of this size is also effective to monitor operation of engineered safety systems in the event of any plant accidents. The shift organization includes sufficient personnel to perform those operations required to implement the required portions of the Emergency Plan.
The shift chemical and radiation protection technician performs the chemistry sampling and analysis radiation monitoring, and other chemistry and radiation protection functions normally encountered during both normal and nonroutine operations. In addition, all licensed operators are trained in chemistry and radiation protection as part of their operator license training. 13.1.3 QUALIFICATION REQUIREMENTS FOR NUCLEAR PLANT PERSONNEL 13.1.3.1 Minimum Qualification Requirements PG&E is using Regulatory Guide 1.8 (ANSI/ANS 3.1-1978) as the basis for establishing minimum qualification requirements for comparable management, supervisory, and technical positions in the plant organization. One exception is that the Manager, Radiation Protection, shall meet or exceed the qualification requirements of Regulatory Guide 1.8, Revision 2, April 1987 for the Radiation Protection Manager. A second exception is that the operations manager shall meet or exceed the minimum qualifications as specified in Technical Specification 5.2.2.e. A third exception is that the licensed Reactor Operators and SROs shall meet or exceed the minimum qualifications of ANSI/ANS 3.1-1993 (Reference 6) as endorsed by Regulatory Guide 1.8, Revision 3, May 2000 (Reference 7) with the exceptions clarified in the current DCPP UNITS 1 & 2 FSAR UPDATE 13.1-16 Revision 21 September 2013 revision to NUREG-1021 (Reference 8), Section ES-202. Other exceptions are summarized in Table 17.1-1.
The minimum qualification processes for physical force personnel (operators, instrument technicians, maintenance personnel, and chemical and radiation protection technicians) are defined by the Institute of Nuclear Power Operation (INPO) accreditation criteria (Reference 5). PG&E has received, and will maintain, INPO accreditation of the training and qualification programs for physical force personnel. 13.1.3.2 Qualifications of Plant Personnel PG&E has addressed NUREG-0660 (Reference 1), NUREG-0731 (Reference 2), and Regulatory Guide 1.8 (Reference 3) (ANSI/ANS-3.1-1978, Standard for Qualification and Training of Personnel of Nuclear Power Plants) as the basis for establishing minimum educational background and experience requirements for all management, supervisory, and professional personnel.
The key management, supervisory, and technical positions in the plant organization are filled by individuals who have been actively engaged in the nuclear power field. Qualification forms for personnel holding the key positions in the plant operating organization are maintained on file at the plant. 13.
1.4 REFERENCES
- 1. NUREG-0660, NRC Action Plan Developed as a Result of the TMI-2 Accident, Task I.B.1
- 2. NUREG-0731, Guidelines for Utility Management Structure and Technical Resources
- 3. Regulatory Guide 1.8, Personnel Selection and Training, USNRC February 1979
- 4. Regulatory Guide 1.33, Quality Assurance Program Requirements (Operation), USNRC February 1978
- 5. ACAD 00-001, Revision 0, The Process for Accreditation of Training in the Nuclear Power Industry, January 2000
- 6. ANSI/ANS 3.1, American National Standard for Selection, Qualification, and Training of Personnel for Nuclear Power Plants, April 1993
- 7. Regulatory Guide 1.8, Qualification and Training of Personnel for Nuclear Power Plants, Revision 3, May 2000
- 8. NUREG-1021, Operator Licensing Examination Standards for Power Reactors DCPP UNITS 1 & 2 FSAR UPDATE 13.2-1 Revision 21 September 2013 13.2 TRAINING PROGRAM 13.2.1 INITIAL PROGRAM DESCRIPTION The experience obtained by PG&E since 1956 in training personnel for operation and maintenance of nuclear power plants has enabled it to clearly define the training requirements for each position in the plant organization and to evaluate the various means of obtaining this training. Based on this experience, PG&E chose to utilize a combination of formal classroom training and on-the-job experience with operating nuclear plants to achieve its training goals. A brief summary of each of the initial training activities is given in Table 13.2-1. The extent to which each individual participated in these activities was determined based on the person's position in the plant organization and his previous experience. A training summary for the initial operating organization is presented in Table 13.2-2.
Tables 13.2-1 and 13.2-2 summarize the initial plant training program and are historical in nature. 13.2.1.1 Program Content The training programs described in Sections 13.2.1.1.1, 13.2.1.1.2, 13.2.1.2, 13.2.1.3, 13.2.1.4, 13.2.1.5, and 13.2.1.6 were for the initial plant personnel and are retained herein for historical value. Starting with Section 13.2.1.7, the present and ongoing plant training programs are described. 13.2.1.1.1 Training for Initial Plant Supervisorial Personnel The training programs for the initial appointees to supervisory positions in the Diablo Canyon operating organization are summarized in Table 13.2-2.
The first formal involvement by a member of the plant staff in the Diablo Canyon project occurred in early 1968, when the Power Plant Engineer was assigned to PG&E's General Office for approximately 2 months to assist in the preparation of the preliminary safety analysis report (PSAR) for Unit 1. In the spring of 1969, both the Power Plant Engineer and the Supervisor of Operations were engaged in similar work on the Unit 2 PSAR for approximately 6 months, and they also assisted in the conceptual design of several plant systems. These two individuals were then assigned to the R. E. Ginna plant in the latter part of 1969 to participate in the startup testing program. Since that time, other key plant supervisory personnel have been sent to various pressurized water reactor (PWR) plants that were in operation or in the startup testing program. The majority of these assignments took place in the period from 1970 to 1972.
In July 1970, the second major step in the early supervisory training activities occurred with the organization of the Diablo Canyon Task Force at Humboldt Bay. This was the first time that the majority of the supervisory staff was assembled as a group. Initially, the Task Force consisted of 14 individuals on a full- or part-time basis. During the DCPP UNITS 1 & 2 FSAR UPDATE 13.2-2 Revision 21 September 2013 period that the group was at Humboldt Bay, work was begun on the various Task Force assignments, including preparation of training material, operating manuals, licensing material and technical specifications, and performing an operational review of the plant design.
In August 1971, the Task Force was transferred to the site, along with several supervisors who had not previously been on the Task Force, in order to obtain maximum participation of plant staff personnel in onsite activities, including observation of equipment installation and review and comment on the system and equipment preoperational and startup test procedures prepared by the General Construction Department.
The second basic phase of the training program began with the arrival onsite of selected plant operators about 5 years before the initial anticipated core loading. At that time, the formal nuclear training courses required to prepare individuals for the operator license examinations began. These courses were conducted by members of the plant supervisory staff. Depending on a particular individual's experience and qualifications, supervisors were either instructors or participants as appropriate during different portions of this program. In most cases, the supervisors participating in these courses had completed similar training at the Humboldt Bay Power Plant.
In addition to participation in the formal training programs, the supervisors were actively engaged in preoperational testing and checkout of systems and equipment, hot functional testing, initial loading and low level testing, and in the power escalation program leading to commercial operation, as those activities took place.
13.2.1.1.2 Training for Plant Physical Force Personnel All physical force personnel were trained in radiation protection, quality assurance, and security procedures and practices to an extent commensurate with their duties. In addition, the chemical and radiation protection technicians and control technicians participated in the nuclear technology and plant design seminars. The chemical and radiation protection technicians were also trained in chemical and radiochemical techniques.
The first physical force personnel assigned to the site were the control technicians, three of whom arrived in late 1971. They were placed on loan to the General Construction instrument staff and participated in the installation and checkout of plant equipment. An apprentice control technician was transferred to the site in December 1972 and was also placed on loan to General Construction. 13.2.1.2 Coordination with Preoperational Tests and Fuel Loading The schedule of formal nuclear training designed to prepare candidates for NRC Operator and Senior Operator License examinations is shown in Figure 13.2-1 in relation to the schedule for preoperational testing and initial fuel loading. DCPP UNITS 1 & 2 FSAR UPDATE 13.2-3 Revision 21 September 2013 13.2.1.3 Practical Reactor Operation The senior control operators and control operators for Unit 1 were assigned to the site about five years before the initial anticipated core loading and began formal training at that time. The remaining operators were assigned as the preoperational testing work load dictated. All operators received extensive on-the-job training in the operation of plant controls during the preoperational and startup testing programs. Other physical force personnel were assigned to the site as dictated by the work load and in time to complete any training required prior to work assignment. 13.2.1.4 Reactor Simulator Training The simulator training program for the "Cold" license candidates is described in Table 13.2-1, Section 16, Simulator Training. 13.2.1.5 Previous Nuclear Training The majority of the initial supervisory personnel had several years of nuclear power plant experience at Humboldt Bay Power Plant or at other nuclear facilities. Thus, the initial training for this group was largely concentrated in two major areas: (a) becoming familiar with the differences between the PWR and boiling water reactor (BWR) concepts, and (b) study of the design and operation of the Diablo Canyon plant itself. 13.2.1.6 Other Scheduled Training Plant personnel were required to participate in a program of lectures, demonstrations, written assignments, and drills designed to familiarize them with fire protection procedures, security procedures, medical and first aid techniques, radiation protection principles, their actions in the event of a plant emergency, and other topics. The extent of the training that a particular individual received was dependent on the responsibilities of his or her position on the plant staff. 13.2.1.7 Training Programs for Nonlicensed Personnel Each individual on the plant staff receives training to some degree depending on the scope of their job duties and responsibilities. This training falls into three general categories: (a) standard PG&E training programs, (b) general employee training programs related to working at Diablo Canyon, and (c) training programs specific to job-related departmental duties.
All personnel receive general employee training as discussed in Section 13.2.1.8.
Each onsite NPG department has defined a training program directed toward the technical skills needed for job-related duties. These training programs are described in the Plant Manual.
DCPP UNITS 1 & 2 FSAR UPDATE 13.2-4 Revision 21 September 2013 13.2.1.8 General Employee Training Program Training programs involving industrial safety, first aid, fire protection, security, emergency planning, radiation protection, quality control, and other general topics are conducted for onsite personnel to supplement specific job-related technical training programs.
General training for all onsite personnel is given in the following areas:
(1) General description of plant and facilities (2) General site rules (3) Radiological health and safety program (4) Site emergency plans (5) Industrial safety program (including medical emergency response notification, and general fire protection) (6) Security program (7) Quality assurance/orientation (8) Fitness for Duty (9) Hazardous Materials The extent of training in the above topics varies from one person to another commensurate with factors such as the duties and responsibilities of the person's job, areas of the plant to be accessed, whether the access is to be escorted or unescorted, duration of the access, and prior experience.
13.2.1.9 Responsible Individual The Senior Vice President, Chief Nuclear Officer has overall responsibility for the entire training effort for plant personnel. He is responsible for ensuring that necessary training programs are established, implemented, documented, and audited.
The Director, Learning Services, reports to the Director, Station Support, and is responsible within the Nuclear Generation organization for conducting the majority of plant training. The director is also responsible for training coordination so that resources are used effectively and the training program content reflects the actual needs of the various departments and workers and satisfies current NRC and industry standards.
Within Learning Services, there are functional groups reporting to the Director, Learning Services, that conduct operator, technical, maintenance, engineering, and general employee training. There is also an ongoing training development and administration effort.
DCPP UNITS 1 & 2 FSAR UPDATE 13.2-5 Revision 21 September 2013 13.2.2 LICENSED OPERATOR CONTINUING (REQUALIFICATION) TRAINING PROGRAM The Diablo Canyon Licensed Operator Continuing Training Program was accredited by INPO in March 1986. This program is maintained in accordance with the standards specified in the accreditation criteria and is evaluated for accreditation renewal every four years.
On May 26, 1987, the NRC revised 10 CFR 55 regarding training and qualifications of licensed operators. As a result of this issuance, DCPP revised its Continuing Training Program to meet the requirements of 10 CFR 55 utilizing a Systems Approach to Training methodology. In accordance with Generic Letter 87-07, PG&E submitted a response on April 28, 1988, to inform the NRC that the DCPP Continuing Training Program would be following a Systems Approach to Training methodology.
PG&E will comply with the functional requirements identified in the American National Standard Institute/American Nuclear Society (ANSI/ANS) 3.5-2009, "Nuclear Power Plant Simulators for Use in Operator Training and Examination." Personnel qualifications will be in accordance with the requirements specified in Chapter 17, Table 17.1-1. 13.2.3 REPLACEMENT TRAINING 13.2.3.1 Licensed Operator and Senior Operator Training Program The Diablo Canyon Licensed Operator and Senior Licensed Operator Training Program was accredited by INPO in March 1986. These programs are maintained in accordance with the standards specified in the accreditation criteria and are evaluated for accreditation renewal every four years.
On May 26, 1987, the NRC revised 10 CFR 55 regarding training and qualifications of licensed operators. As a result of this issuance, DCPP revised the Licensed Operator and Senior Licensed Operator Training Programs to meet the requirements of 10 CFR 55 utilizing a Systems Approach to Training methodology.
In accordance with Generic Letter 87-07, PG&E submitted a response on April 28, 1988, to inform the NRC that the DCPP Licensed Operator and Senior Licensed Operator Training Program would be following a Systems Approach to Training methodology. 13.2.3.2 Shift Technical Advisor Training Program The Diablo Canyon Shift Technical Advisor (STA) Training Program was accredited by INPO in March 1986. This program is maintained in accordance with the standards DCPP UNITS 1 & 2 FSAR UPDATE 13.2-6 Revision 21 September 2013 specified in the accreditation criteria and is evaluated for accreditation renewal every four years. 13.2.3.3 Non-Licensed Operator Training Program The Diablo Canyon Non-Licensed Operator Training Program was accredited by INPO in March 1986. This program is maintained in accordance with the standards specified in the accreditation criteria and is evaluated for accreditation renewal every four years. 13.2.4 RECORDS Training record files are maintained for all personnel. The files are maintained in accordance with Plant Manual procedures that state that the files shall contain records of qualifications, experience, training, and retraining for each member of the plant organization. Audits of the various plant training programs and records are conducted by the quality verification organization.
DCPP UNITS 1 & 2 FSAR UPDATE 13.3-1 Revision 11 November 1996 13.3 EMERGENCY PLANNING A comprehensive Emergency Plan has been developed for Diablo Canyon as required by Section 50.47(b) and Appendix E to 10 CFR 50. It serves several purposes including:
(1) Establishing the emergency duties and responsibilities of the various members of the plant staff at or near the site (2) Informing all affected agencies (including members of the plant staff) of the interfaces that have been established between the plant staff and participating PG&E and non-PG&E support groups (3) Providing a convenient means for gathering together, by way of appendices to the Emergency Plan, the plans of the various participating offsite agencies such that plant staff personnel are made aware of the basic responsibilities and capabilities of these agencies (4) Providing an overview of the facilities, equipment, and procedures utilized by the plant staff in the emergency in order to inform and assist those offsite agencies who must coordinate their activities with those of the plant staff (5) Providing training and exercising of emergency plans for both licensee employees and other support groups' personnel (6) Fulfilling licensing requirements of the NRC The DCPP Emergency Plan has been developed in accordance with the guidance of NUREG-0654/FEMA-REP-1(1) and has been placed on the docket of each unit. 13.
3.1 REFERENCES
- 1. NUREG-0654/FEMA-REP-1, Revision 1, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, November 1980.
DCPP UNITS 1 & 2 FSAR UPDATE 13.4-1 Revision 20 November 2011 13.4 REVIEW AND AUDIT 13.4.1 REVIEW AND AUDIT - CONSTRUCTION PHASE The independent review and audit of construction activities was incorporated into the Quality Assurance Program during design, construction, and preoperational testing as prescribed by the Quality Assurance program as described in Chapter 17 of the FSAR Update. 13.4.2 REVIEW AND AUDIT - OPERATION PHASE Review and audit during the operation phase is accomplished by senior members of the plant staff, independent review and audit groups, and management oversight groups as discussed below. In addition, the quality verification (QV) organization independently audits operation phase activities in accordance with FSAR Update, Chapter 17. 13.4.2.1 Plant Staff Review Committee A PSRC has been established at the plant site to advise the Station Director on all matters related to nuclear safety. The PSRC's functions and responsibilities are detailed in Section 17.2 of this FSAR Update. 13.4.2.2 Independent Review and Audit Program A program of independent review and audit of nuclear plant operations has been in effect since the initial operation of HBPP, Unit 3 in 1963. This program, which was applied to the preoperational testing, startup testing, and operation of DCPP, has been reviewed and appropriately modified so that it conforms to the requirements and recommendations of ANSI N18.7-1976, Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants.
This program satisfies the requirements of Sections 4.3 and 4.5 of ANSI 18.7-1976. The independent review and audit program functions and responsibilities are detailed in Section 17.2 of this FSAR Update. 13.4.2.3 Management Oversight Groups As a means for corporate management to be involved in nuclear plant safety considerations and to ensure that these considerations are effectively applied to plant operation, management oversight groups have been established.
DCPP UNITS 1 & 2 FSAR UPDATE 13.5-1 Revision 21 September 2013 13.5 PLANT PROCEDURES AND PROGRAMS 13.5.1 PROCEDURES Safety-related activities involving the design, operation, maintenance, and testing of plant systems and equipment are carried out in accordance with written policies and detailed written procedures. These policies and procedures, as well as others involving plant activities not related to safety, are incorporated into a Diablo Canyon Plant Manual. Because of its physical size and diversity of topics, this manual has been divided into multiple volumes. Except as noted in FSAR Update Table 17.1-1, these policies and procedures implement the requirements of the NRC Regulatory Guide 1.33, Revision 2, Quality Assurance Program Requirements (Operations) (Reference 1) and the requirements and recommendations of ANSI N18.7-1976, Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants. Emergency operating procedures meet the requirements of Supplement 1 to NUREG-0737, Requirements for Emergency Response Capability (Reference 2).
The review, change, and approval process for these procedures is described in Section 17.5. 13.5.2 PROGRAMS 13.5.2.1 Process Control Program The Process Control Program (PCP) contains the current formulas, sampling, analyses, tests, and determinations to be made to ensure that processing and packaging of solid radioactive wastes based on demonstrated processing of actual or simulated wet solid wastes will be accomplished in such a way as to ensure compliance with 10 CFR Parts 20, 61, and 71 and Federal and State regulations, burial ground requirements, and other requirements governing the disposal of solid radioactive waste.
Changes to the PCP are documented and records of review for changes made to the PCP are retained. The documentation contains:
- sufficient information to support the change together with the appropriate analyses or evaluations justifying the change(s), and
- a determination that the change will maintain the overall conformance of the solidified waste product to existing requirements of Federal, State, or other applicable regulations.
PCP changes become effective after review and approval by the Station Director.
DCPP UNITS 1 & 2 FSAR UPDATE 13.5-2 Revision 21 September 2013 13.5.2.2 Radiation Protection Program Procedures for personnel radiation protection are prepared consistent with the requirements of 10 CFR 20 and are approved, maintained, and adhered to for all operations involving personnel radiation exposure. 13.5.2.3 In-Plant Radiation Monitoring A program, which will ensure the capability to accurately determine the airborne iodine concentration in vital areas under accident conditions is established, implemented, and maintained. The program includes:
- Personnel training
- Procedures for monitoring
- Provisions for maintenance of sampling and analysis equipment 13.5.2.4 Backup Method for Determining Subcooling Margin A program, which will ensure the capability to accurately monitor the Reactor Coolant System subcooling margin is established, implemented, and maintained. The program includes the following:
- Personnel training
- Procedures for monitoring 13.5.2.5 Containment Polar and Turbine Building Cranes A program is established, implemented, and maintained to ensure that: (1) the parked location of the containment polar cranes precludes jet impingement from a postulated pipe rupture, and (2) the operation of the turbine building cranes is consistent with the restrictions associated with the current Hosgri seismic analysis of the turbine building.
This program includes the following:
- Personnel training
- Procedures for the containment polar and turbine building cranes operation The procedures will control the operation of the containment polar cranes in jet impingement zones.
13.5.2.6 Motor-Operated Valve Testing and Surveillance Program A program is established to comply with Generic Letter 89-10, "Safety-Related Motor-Operated Valve Testing and Surveillance" and its supplements and Generic Letter 96-05, "Periodic Verification of Motor-Operated Valves."
DCPP UNITS 1 & 2 FSAR UPDATE 13.5-3 Revision 21 September 2013 13.
5.3 REFERENCES
- 1. Regulatory Guide 1.33, Rev. 2, Quality Assurance Program Requirements (Operational), USNRC, February 1978.
- 2. NUREG-0737, Supplement 1, Requirements for Emergency Response Capability, December 1982.
- 3. NRC Letter to PG&E, dated May 28, 1999, granting License Amendment 135, Units 1 and 2.
- 4. PG&E letter DCL-94-262, dated November 28, 1994, "Closure Response to NRC Generic Letter 89-10" and all supporting PG&E letters.
- 5. PG&E Letter DCL 99-031, dated March 25, 1999, "Response to Request for Additional Information Regarding NRC Generic Letter 96-05, Periodic Verification for Motor Operated Valves" and all supporting PG&E letters.
DCPP UNITS 1 & 2 FSAR UPDATE 13.6-1 Revision 11 November 1996 13.6 PLANT RECORDS Plant records are maintained in accordance with established PG&E practices. The records management program is discussed in Chapter 17.
DCPP UNITS 1 & 2 FSAR UPDATE 13.7-1 Revision 20 November 2011 13.7 PHYSICAL SECURITY The Security Plans for DCPP have been developed as required by 10 CFR 73 and DPR-80 and DPR-82 License Condition E. The Security Plans include the following: (1) The Physical Security Plan (PSP), including the following appendices: (a) Appendix A: Glossary of Security Plan terms (b) Appendix B: Training and Qualification Plan (per 10 CFR 73, Appendix B) (c) Appendix C: Safeguards Contingency Plan (per 10 CFR 73, Appendix C) (d) Appendix D: Independent Spent Fuel Installation Security Program (per 10 CFR 73.51) (2) The Cyber Security Plan (CSP). The PSP establishes and maintains a physical protection system and security organization on site for the purpose of protecting against radiological sabotage and preventing the theft of special nuclear material. Portions of the information contained in the PSP are considered to be "Safeguards Information" as defined in 10 CFR 73.2 and must therefore be protected against public disclosure and disseminated on a "need-to-know" basis as required by 10 CFR 73.21. The CSP is the program implemented to prevent damage to, unauthorized access to, and allow restoration of computers, electronic communications systems, electronic communication services, wire communication, and electronic communication, including information contained therein, to ensure its availability, integrity, authentication, confidentiality, and non-repudiation. In control systems, this would include unauthorized access that could affect operation of plant structures, systems, or components. The CSP contains information that has been designated "Security-Related Information - Withhold under 10 CFR 2.390." The PSP has been approved by the NRC and is implemented at the DCPP site. The implementation of the CSP, including the key intermediate milestone dates and the full implementation date, will be in accordance with the implementation schedule submitted to the NRC in PG&E Letter DCL-11-040, dated April 4, 2011, and approved by the NRC Staff with License Amendments (LA) 210 (DPR-80) and LA 212 (DPR-82). All changes to the Security Plans require evaluation per 10 CFR 50.54(p) to determine if prior NRC review and approval via 10 CFR 50.90, the License Amendment process, is required. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 13.2-1 Sheet 1 of 5 Revision 11 November 1996 SUMMARY OF ACTIVITIES EMPLOYED IN TRAINING PROGRAMS FOR PERSONS IN THE INITIAL DIABLO CANYON OPERATING ORGANIZATION (HISTORICAL AS SUBMITTED IN NOVEMBER 1978) 1. Humboldt Bay Experience Many of the key individuals in the initial plant organization were members of the Humboldt Bay staff before they transferred to Diablo Canyon Power Plant and have extensive nuclear experience in their areas of responsibility. Certain other individuals, who were not members of the Humboldt Bay staff, have been assigned there for appropriate periods to participate in operations involving their areas of responsibility.
- 2. PWR Experience Key individuals were assigned to an operating PWR (or one in the process of preoperational and/or startup testing) to observe and/or participate in operations involving their areas of responsibility. The plants involved included R. E. Ginna, H. B. Robinson, Connecticut Yankee, Point Beach, and San Onofre. Assignments ranged from 3 weeks to 7 months, with most lasting approximately 1 month.
- 3. Participation in the Diablo Canyon Task Force This group consists of selected technical and operating supervisory personnel and is responsible for the preparation of training material, operating manuals, licensing material and Technical Specifications, test procedures, and for performing an operational review of the plant design.
- 4. Design Lecture Series This 4-week course was conducted in March 1971 at the Westinghouse Atomic Power Division in Pittsburgh, Pennsylvania. Fifteen supervisors on the plant staff and one member of the Department of Steam Generation attended this course. The trainees were given a series of lectures covering the function, design description, control and instrumentation, normal and abnormal operation, and maintenance of all principal components of the Diablo Canyon Units 1 and 2 nuclear steam supply systems. These lectures were given by Westinghouse design engineers who were closely associated with the design of the plant. The lectures were supplemented by study of written information on pressurized water reactor technology provided by Westinghouse and trips to Westinghouse manufacturing facilities where trainees were afforded an opportunity to witness actual fabrication of components.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 13.2-1 Sheet 2 of 5 Revision 11 November 1996 5. Nuclear Technology Course This course is taught by members of the plant staff and utilizes PG&E's Introduction To Nuclear Power training manual as a text. The purpose of this course is to provide a general background in the field of nuclear power plant technology. The major topics that are included in the course are:
- a. Basic mathematics
- b. Basic atomic and nuclear physics
- c. Introduction to nuclear reactors and nuclear power plant cycles
- d. Light water reactor physics
- e. Heat transfer considerations in light water reactors
- f. Operating characteristics of light water reactors
- g. Nuclear instrumentation h Chemical, radiochemical, and waste disposal considerations in light water reactor operation i. Reactor safeguards.
These topics are treated in sufficient depth to prepare an individual for applicable portions of the Senior Operator License examination. The complete course, which is intended for license candidates, takes about 4 weeks and covers each of these topics in detail. Abbreviated versions of the course covering subjects directly related to their duties and responsibilities are given to other personnel as appropriate.
- 6. Radiation Protection Training Course This course is taught by members of the plant staff and utilizes PG&E's Radiation Protection Training Manual, Radiation Control Standards And Procedures, and other appropriate material as texts. The standards are a compilation of technical statements of policy covering each aspect of a nuclear power plant's radiation protection program and are based on the requirements of 10 CFR 20 and other applicable regulations. The procedures provide practical information regarding the implementation of the standards and are based on adaptations to nuclear power plant requirements of procedures and practices widely used throughout the atomic energy industry.
The Training Manual is a general work that covers theory and other background material. The major topics covered in this course include: a. Basic radiation physics and biology
- b. Sources of radioactivity in nuclear power plants
- c. Radiation protection instrumentation
- d. Fundamentals of shielding
- e. Personnel exposure limits DCPP UNITS 1 & 2 FSAR UPDATE TABLE 13.2-1 Sheet 3 of 5 Revision 11 November 1996 f. Protective clothing and equipment g. Control and transfer of radioactive materials
- h. Decontamination practices
- i. Radiation monitoring techniques
- j. Control of access
- k. Records and reporting requirements.
The complete course for radiation and process monitors requires about 4 weeks. A similar course designed for NRC license examination candidates required about 1 week. Personnel in other classifications receive shorter courses covering those subjects directly related to their duties and responsibilities.
- 7. Plant Design and Operation Seminars This seminar course is conducted by supervisory personnel on the plant staff and covers the design, description, and operation of each plant system plus related topics such as the Technical Specifications and the Site Emergency Plan. The course is primarily designed for operators and is expected to last about 8 weeks. As appropriate, personnel in other classifications will receive shorter courses covering systems and equipment related to their areas of responsibility.
- 8. NRC Operator and Senior Operator License Examination Seminars These seminars are conducted by supervisory personnel on the plant staff for the benefit of license examination candidates. They consist of a review of appropriate items in activities 5, 6, and 7 above plus discussions of additional topics required to cover the items listed in 10 CFR 55.21-23. The length of this program will be determined following an evaluation of the needs of the individuals involved, but based on Humboldt Bay experience, it is expected to last about 4 weeks. 9. P-250 and P-2000 Computer Maintenance Courses These courses, lasting a total of 16 weeks, were conducted in the fall of 1970 by Westinghouse Computer and Instrument Division personnel and were designed to provide comprehensive coverage of the construction, operation, repair, and maintenance of the P-250 and P-2000 computers. The course attended by Diablo Canyon personnel was held at PG&E's Pittsburg Power Plant where a P-250 computer was available for use by the students.
- 10. Instrument and Control Course This is a 12-week course intended for instrument maintenance supervisors and technicians and is conducted by instructors from the Nuclear Instrumentation and Control DCPP UNITS 1 & 2 FSAR UPDATE TABLE 13.2-1 Sheet 4 of 5 Revision 11 November 1996 Department of Westinghouse at the department headquarters in Baltimore, Maryland. The general subjects covered include the design, maintenance, and testing of the solid-state rod control system, flux mapping system, nuclear instrumentation system, radiation monitoring system, and solid-state protection system. The course combines both formal classroom lectures on systems and modules and practical bench work with the equipment.
Diablo Canyon personnel attended this course beginning in January 1972.
- 11. Process Controls Course This 2-week course was conducted at the Portland General Electric Trojan site in June 1972 by Westinghouse Computer and Instrument Division personnel. The course material included lectures on both systems and modules for the various process control systems (feedwater control, steam dump, pressurizer level and pressure). In addition, the various modules were available for bench work by the students.
- 12. Refresher Course in Radiological Engineering This 3-week course was conducted in 1972 by personnel from the health physics staff of the General Electric Company Vallecitos Nuclear Center. It was designed to provide graduate-level refresher training in radiological engineering topics such as internal and external radiation dosimetry, radiation biology, atmospheric diffusion modules, instrumentation, and environmental pathways. It consisted primarily of formal classroom lectures.
- 13. Chemistry and Radiochemistry Seminars These seminars are conducted by supervisory personnel on the plant staff for training of radiation and process monitors, and will take about 4 months. The subject matter for these seminars will include such topics as basic chemistry, laboratory techniques, radiochemical methods, and theory and use of counting room equipment. A variety of texts will be employed, including PG&E procedures manuals, vendors' instruction manuals, and standard chemistry and radiochemistry texts. In addition, the classroom work will be supplemented by actual laboratory training as appropriate.
- 14. Nondestructive Testing School This 3-week course is presented at the site by instructors from General Dynamics/Convair. The class consists of both formal lectures and practical demonstrations, and persons completing it and successfully passing the examinations are qualified as ASNT Level II inspectors for radiography, ultrasonic testing, magnetic particle testing, and liquid penetrant testing.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 13.2-1 Sheet 5 of 5 Revision 11 November 1996 15. Operational Core Analysis Training This 3-week course is presented in Pittsburgh, Pennsylvania, by Westinghouse and is intended for nuclear engineers. It discusses the theory and operation of the operational core analysis computer codes that will be used to monitor core thermal-hydraulic performance and fuel depletion.
- 16. Simulator Training Candidates for "Cold" NRC licenses will attend a 14-day training program at the Westinghouse reactor simulator at Zion, Illinois.
The course has been established so that the typical day is divided approximately equally into classroom work and "hands-on" simulator time. Emphasis during the first week will be on taking the trainee through a simulated operational cycle from a cold shutdown through plant heatup/reactor startup/turbine-generator startup/power operation/plant shutdown/and plant cooldown. This first cycle will stress familiarization with control board and plant operation under normal operating conditions. The second week's training will be a repeat of the training received the first week, but at an accelerated pace and will incorporate the maximum number of minor and major malfunction situations in the time allotted. The trainee will learn to identify specific malfunctions, analyze the hazards involved, and effect proper corrective actions. The second week will also incorporate simulation and evaluation of normal and abnormal plant transients and the required operator action to effect recovery from transient and accident situations. A refresher simulator training course of seven days duration will be provided shortly before initial loading.
- 17. In-place Filter Testing Workshop This 5-day workshop is conducted by the Harvard School of Public Health in Boston, Massachusetts. The subject matter deals with subjects of theory, design, and testing of HEPA and activated charcoal air filtration systems. About half of the time is devoted to classroom lectures and the other half consists of laboratory work using DOP generators and detection equipment and other filter testing devices. The Power Plant Engineer attended this course in September 1971.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 13.2-2 Sheet 1 of 2 Revision 11 November 1996 TRAINING SUMMARY FOR INDIVIDUALS IN THE INITIAL DIABLO CANYON OPERATING ORGANIZATION (HISTORICAL) Humblt. Dsgn. Rad. Plant Oper. Proc. Rad. AEC Bay PWR Task Lect. Nuclr. Prot. Dsgn. Lic. Comp. I & C Ctrls. Engr. Chem. NDT Core Anal. Simul. Position - Name License Exper. Exper. Force(a) Series Tech. Course Semr. Revw. Maint. Course Course Refr. Semrs. Sch. Code Trng. Trng. Plant Superint. Cold SOL,OP 3 y 2 m July 1970 P OP OP OP OP - - - - - - - - P Supv. of Operations Cold SOL 3 y 6 m July 1970 P I I I I - - - - - - - - P Power Plant Engr. Cold SOL,OP 8 y 7 m July 1970 P I I I I - - - P - - - - P Supv. of Maint. - 9 y 1 m Aug. 1971 P OP OP OP - - - - - - P - - - Relief Shift Supv. Cold SOL 8 y 1 m July 1970 P OP OP I I - - - - - - - - P Shift Foreman Cold SOL 6 y 1 m Oct. 1970 P P P I,P I,P - - - - - - - - P Cold SOL 9 y 1 m July 1970 P P P I,P I,P - - - - - - - - P Cold SOL 9 y 1 m Feb. 1972 - P P I,P I,P - - - - - - - - P Cold SOL 10 m 1 m May 1972 - P P I,P I,P - - - - - - - - P Cold SOL 11 y 1 m - P P P I,P I,P - - - - - - - - P Cold SOL 1 y 1 m Aug. 1971 P P P I,P I,P - - - - - - - - P Hot SOL - - - - P P P P - - - - - - - - - Nuclear Engineers Cold SOL,OP 2 y 3 m(b) Aug. 1970 P I,OP I,OP I,OP OP - - - - - P - - - Cold SOL,OP 1 m 1 m(b) Jan. 1971 - I,OP I,OP I,OP OP - - - - - - - - P Hot SOL,OP 1 y 1 m Dec. 1970 P I,OP I,OP I,OP OP - - - - - - (c) - - Hot SOL,OP - - - OP P OP OP - - - - - - - - - Hot SOL,OP - - - OP P OP OP - - - - - - - - - Hot SOL,OP - - - OP P OP OP - - - - - - - - - Chem. & Rad. Prot. Engr. - 5 y 1 m July 1970 - OP I I,OP I - - - P I - - - - 3 y 3 w Nov. 1972 P OP I I,OP I - - - P I - - - - Instrument Engr. - 8 y 2 m July 1970 P OP OP I,OP - - P - - - - - - - Inst. & Contrls. Supv. - 1 m - July 1970 - OP OP I - P P P - - - - - - DCPP UNITS 1 & 2 FSAR UPDATE TABLE 13.2-2 Sheet 2 of 2 Revision 11 November 1996 Humblt. Dsgn. Rad. Plant Oper. Proc. Rad. AEC Bay PWR Task Lect. Nuclr. Prot. Dsgn. Lic. Comp. I & C Ctrls. Engr. Chem. NDT Core Anal. Simul. Position - Name License Exper. Exper. Force(a) Series Tech. Course Semr. Revw. Maint. Course Course Refr. Semrs. Sch. Code Trng. Trng. Q/A Coordinator - 7 y - Aug. 1970 P OP I I,P I - - - - - - - - - Maintenance Engr. - - - - - OP P OP - - - - - - - - - - Mechanical Foreman - - - - - OP P OP - - - - - - - - - - Electrical Foreman - - - - - OP P OP - - - - - - - - - - Operators Hot L(h) (d) - - - P P P P - - - - - - - - (i) Control Technicians - (e) - - - OP P OP - (f) (g) - - - - - - - Rad. & Proc. Monitrs. - OP - - - P P OP - - - - - P - - - - Maint. Phys. Forces - - - - - - P - - - - - - - - - - - Clerical - - - - - - P - - - - - - - - - - - Key: y = years, m = months, w = weeks, P = participant, I = Instructor, OP = Optional Participation depends on work load and individual needs, SOL = Senior Operator License, L = Operator License (a) Date given is date at which participation in Task Force project began. Task Force work largely complete by March 1973. (b) Not including experience gained while not a PG&E employee. (c) A second individual from the Steam Generation Department will also attend. (d) It is expected that approximately 1/3 of the successful bidders will have had prior experience at Humboldt Bay. There are no plans to send others to Humboldt Bay. (e) Two of the successful bidders have had several years of experience at Humboldt Bay. The other two have had approximately one month. (f) Two only. A third individual has had computer experience in his previous assignment at a conventional plant. The fourth is receiving training as part of apprenticeship program. (g) Three only. Fourth is in training as apprentice and will receive on-the-job experience prior to startup. (h) For Assistant Control Operator and above. (i) Three Senior Control Operators with prior Operator Licenses at Humboldt Bay.
President Site Vice President Director and Plant Manager Humboldt Bay Nuclear Director Site Services Director Station Support Director Quality Verification Revision 21 September 2013FIGURE 13.1-1A SITE ORGANIZATION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Director Learning Services Station Director Director Compliance, Alliance, and Risk Manager Special Applications Group Managers Security Services Manager Emergency Planning Manager Performance Improvement Manager Procedure & Document Services Senior Vice President Energy Supply Supervisor Cyber Security Manager Business Finance Manager Nuclear Supply Chain Director Security Services Senior Vice President Chief Nuclear Officer Director Engineering Services Manager Technical Support Manager I&C and Electrical Systems Manager Design Engineering Manager Project Engineering Manager Mechanical Systems Senior Director Engineering and Projects Director Geosciences Manager Nuclear Fuels Manager Regulatory Services Director Nuclear Projects Employee Concerns Program Supervisor Director Strategic Projects Project Managers Project Services Project Managers Special Projects Manager Construction
Intentionally Left Blank
Revision 18 October 2008FIGURE 13.1-1B SERVICES ORGANIZATION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE
Senior Vice President, Chief Nuclear Officer Site Vice President Manager Electrical Director Nuclear Work Management Director Operations Services Manager Outage Management Manager I&C Manager Maintenance Team Manager Mechanical Manager Chemistry & Environmental Manager Outage Services Manager Operations Manager Daily Work Control Manager Radiation Protection Director Maintenance Services Station Director Revision 21 September 2013 FIGURE 13.1-1C OPERATING ORGANIZATION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Manager Planning Manager Operations Performance Manager Operations Planning
EFFECTIVE SHIFT OPERATING ORGANIZATION
- SOL requirement may be fulfilled by any SOL individual. Not all Senior Control Operators have SOLs.
- Refer to FSAR Update, Section 13.1.2.3 SHIFT MANAGER *SOL SHIFT FOREMAN *SOL CHEMICAL & RADIATION PROTECTION TECHNICIAN ** 3 LICENSED OPERATORS SHIFT TECHNICAL ADVISOR DIABLO CANYON WATCH COMMANDER ** 3 AUXILIARY OPERATORS CONTRACT SECURITY FORCE PG&E SECURITY FORCE LEGEND: SOL NRC SENIOR OPERATOR LICENSE REQUIRED Revision 20 November 2011FIGURE 13.1-3 EFFECTIVE SHIFT ORGANIZATION EITHER OR BOTH UNITS FUELED AND ABOVE 200°F PRIMARY SYSTEM TEMPERATURE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE
MINIMUM SHIFT OPERATING ORGANIZATION
- Refer to FSAR Update, Section 13.1.2.3 SHIFT FOREMAN *SOL CHEMICAL & RADIATION PROTECTION TECHNICIAN
- 2 LICENSED OPERATORS DIABLO CANYON WATCH COMMANDER
- 3 AUXILIARY OPERATORS CONTRACT SECURITY FORCE PG&E SECURITY FORCE LEGEND:
SOL NRC SENIOR OPERATOR LICENSE REQUIRED Revision 20 November 2011FIGURE 13.1-4 MINIMUM SHIFT ORGANIZATION BOTH UNITS DEFUELED OR PRIMARY SYSTEM TEMPERATURE AT OR BELOW 200°FUNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Director Operations Services Manager Manager Manager Operations Shift Manager Operations Planning Operations Performance
SFM - Shift Foreman Crew C Shift Manager Crew B Shift Manager Crew A Shift Manager Crew D Shift Manager Crew E Unit 1 SFM Unit 2 SFM Unit 1 SFM Unit 2 SFM Unit 1 SFM Unit 2 SFM Unit 1 SFM Unit 2 SFM Unit 1 SFM Unit 2 SFM Revision 19May2010FIGURE 13.1-5 OPERATIONS ORGANIZATION IF MANAGER DOES NOT HOLD SRO LICENSE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Operations Superintendent Director Operations Services
SFM - Shift Foreman Shift Manager Crew C Shift Manager Crew B Shift Manager Crew A Shift Manager Crew D Shift Manager Crew E Unit 1 SFM Unit 2 SFM Unit 1 SFM Unit 2 SFM Unit 1 SFM Unit 2 SFM Unit 1 SFM Unit 2 SFM Unit 1 SFM Unit 2 SFM Revision 19 May2010FIGURE 13.1-6 OPERATIONS ORGANIZATION IF MANAGER HOLDS SRO LICENSE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Manager Operations Manager Operations Planning Manager Operations Performance
DCPP UNITS 1 & 2 FSAR UPDATE i Revision 21 September 2013 Chapter 14 INITIAL TESTS AND OPERATION CONTENTS Section Title Page 14.1 TEST PROGRAM 14.1-1
14.1.1 Administrative Procedures -- Testing 14.1-2 14.1.1.1 Organizational Responsibilities 14.1-2 14.1.1.2 Preparation of Procedures 14.1-2 14.1.1.3 Reviewing and Approving Procedures 14.1-3 14.1.1.4 Conducting Tests 14.1-3 14.1.1.5 Evaluating and Approving Results 14.1-3 14.1.1.6 Documentation 14.1-3 14.1.1.7 Personnel Qualifications 14.1-4 14.1.1.8 Additional Qualifications 14.1-5
14.1.2 Administrative Procedures -- Modifications 14.1-5
14.1.3 Test Objectives and Procedures 14.1-6 14.1.3.1 Preoperational Testing 14.1-6 14.1.3.2 Startup Testing 14.1-7 14.1.4 Fuel Loading and Initial Operation 14.1-7 14.1.4.1 Fuel Loading 14.1-7 14.1.4.2 Postloading Tests 14.1-9 14.1.4.3 Initial Criticality 14.1-9 14.1.4.4 Low Power Testing 14.1-10 14.1.4.5 Power Level Escalation 14.1-10
14.1.5 Administrative Procedures -- System Operation 14.1-11 14.1.5.1 Operating Procedures 14.1-11 14.1.5.2 Safety Precautions 14.1-11
14.1.6 References 14.1-11
14.2 AUGMENTATION OF APPLICANT'S STAFF FOR INITIAL TESTS AND OPERATION 14.2-1
14.2.1 Organizational Functions, Responsibilities, and Authorities 14.2-1
14.2.2 Interrelationships and Interfaces 14.2-1
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 14 CONTENTS (continued) Section Title Page ii Revision 21 September 2013 14.2.3 Key Personnel Functions, Responsibilities, and Authorities 14.2-2 14.2.3.1 Station Construction Department 14.2-2 14.2.3.2 Operating Department 14.2-3 14.2.3.3 Westinghouse 14.2-3
14.2.4 Personnel Qualifications 14.2-6
14.2.5 References 14.2-6
14.3 POSTCOMMERCIAL OPERATIONAL TEST PROGRAM 14.3-1
DCPP UNITS 1 & 2 FSAR UPDATE iii Revision 21 September 2013 Chapter 14 TABLES Table Title 14.1-1 Preoperational Testing Summary
14.1-2 Fuel Loading and Initial Startup Testing Summary
DCPP UNITS 1 & 2 FSAR UPDATE iv Revision 21 September 2013 Chapter 14 FIGURES Figure Title 14.1-1 Chronological Sequence of Startup Testing
DCPP UNITS 1 & 2 FSAR UPDATE 14.1-1 Revision 15 September 2003 Chapter 14 INITIAL TESTS AND OPERATION Sections 14.1 and 14.2 are historical in nature; they reflect the preoperational and initial startup test program through the start of commercial operation. Section 14.3 addresses the postcommercial operational test program. 14.1 TEST PROGRAM The preoperational and initial startup program for the Pacific Gas and Electric Company's (PG&E's) Diablo Canyon Power Plant (DCPP) will demonstrate that:
(1) The plant is ready to operate in a manner that, with reasonable assurance, will not endanger the safety of the public. (2) The procedures for operating the plant safely have been tested and demonstrated. (3) The operating organization is knowledgeable about the plant and the procedures and is fully prepared to operate the plant safely.
The program is designed to demonstrate that structures, components, and systems meet the appropriate design criteria and otherwise operate satisfactorily. The program includes construction tests, preoperational or functional tests, initial fuel loading, and startup tests. The program will culminate in the operation of the plant at maximum guaranteed load.
The discussion of tests in this chapter generally excludes construction tests and otherwise includes only testing associated with safety-related requirements. Testing excluded from this discussion is administered in a manner consistent with the program described in this chapter.
Construction tests include hydrostatic testing, system cleaning, valve leakage tests, control valve operations, electrical continuity checks, electrical performance tests, and control instrument alignment. Construction tests are usually conducted as the components and systems are completed to ensure readiness for preoperational testing.
Preoperational tests demonstrate, insofar as possible prior to loading nuclear fuel, that those plant structures, components, and systems related to safety have been properly installed and operate according to design requirements. Preoperational tests that cannot be completed prior to fuel loading because the necessary test conditions do not exist will be completed when conditions are suitable for testing. DCPP UNITS 1 & 2 FSAR UPDATE 14.1-2 Revision 15 September 2003 Preoperational testing of a system begins whenever construction is sufficiently advanced to indicate the test may be completed. This phase of testing began in 1973 and has been integrated with other construction activities.
Startup tests demonstrate that the plant will perform satisfactorily in normal operation and that, with reasonable assurance, the plant is capable of withstanding the transients analyzed in this Final Safety Analysis Report (FSAR). 14.1.1 ADMINISTRATIVE PROCEDURES -- TESTING 14.1.1.1 Organizational Responsibilities The overall responsibility for the preoperational testing and startup program is assigned to the Lead Startup Engineer.
The Lead Startup Engineer directs other Station Construction Department personnel in preparing and conducting the testing program with technical assistance from the Engineering Department, Nuclear Plant Operations (NPO), the nuclear steam supply system (NSSS) vendor, and other equipment suppliers as appropriate. The plant operating organization performs all operations during the testing program. The Assistant Plant Manager/Plant Superintendent will designate a Startup Coordinator who will be responsible for startup operational activities. In some cases there will be procedures, administratively controlled by the NPO Department, which will be included in the Preoperational and Startup Test Program. Their inclusion will occur when they satisfy the requirements and objectives of a test that would normally be prepared at the direction of the Lead Startup Engineer. 14.1.1.2 Preparation of Procedures Test procedures are prepared under the direction of the Lead Startup Engineer for all preoperational and startup tests. Each procedure consists of the test purpose and description, references, prerequisites, initial conditions, instructions (including acceptance criteria), and data and calculation sheets as required. The status of all preoperational and startup tests is maintained in a Startup Status Report.
The sources of information for writing the test procedures include approved drawings, specifications, technical literature, system functional descriptions, similar completed tests from other pressurized water reactor nuclear power plants, manufacturers' testing recommendations, plant operating procedures, general operating orders and instructions, and any other design or technical information available.
Test instructions are established using design and technical information and include acceptance criteria established from the functional requirements specified in the appropriate sections of this FSAR or from documents approved by the Engineering Department. Space for documenting test results is also included.
DCPP UNITS 1 & 2 FSAR UPDATE 14.1-3 Revision 15 September 2003 14.1.1.3 Reviewing and Approving Procedures The Lead Startup Engineer is responsible for the preparation of each test procedure and will request review of tests by the Assistant Plant Manager/Plant Superintendent and others as considered appropriate. The Assistant Plant Manager/Plant Superintendent is responsible for obtaining comments from NPO. The Lead Startup Engineer and the Assistant Plant Manager/Plant Superintendent will indicate their review is complete by signing off the test cover sheet.
The Plant Staff Review Committee (PSRC) will review approved procedures, prior to their conduct, for units with an operating license. 14.1.1.4 Conducting Tests The Lead Startup Engineer is responsible for conducting all preoperational and startup tests and assigns the responsibility for conducting individual tests to a Startup Engineer who, in turn, verifies that all the necessary conditions are established. The Lead Startup Engineer requests the plant Startup Coordinator to perform the operations step-by-step, following the sequence specified in the test procedure. During and subsequent to preoperational testing, power plant operating personnel will operate all switches, breakers, and valves for controlling energized equipment under the direct supervision of the Shift Foreman in accordance with the startup program, and/or at the request of the Startup Engineer. 14.1.1.5 Evaluating and Approving Results The Startup Engineer and the Assistant Plant Manager/Plant Superintendent's representatives make an evaluation of the test results. If the results satisfy the acceptance criteria, they sign off the test as completed. The completed test procedure is reviewed by both the Lead Startup Engineer and the Assistant Plant Manager/Plant Superintendent and is signed to indicate approval of the completed test.
The results of preoperational tests of safety-related systems will undergo plant staff review prior to receipt of an operating license. Subsequent to the receipt of an operating license, the results of all completed preoperational and startup tests will be reviewed by the PSRC. 14.1.1.6 Documentation Completed procedures and related data and test sheets will be properly identified, indexed, and retained for the plant's permanent files. The Lead Startup Engineer is responsible for the distribution of all completed test procedures. Distribution will be made as individual preoperational and startup test procedures are completed.
DCPP UNITS 1 & 2 FSAR UPDATE 14.1-4 Revision 15 September 2003 14.1.1.7 Personnel Qualifications Since 1958, Station Construction Department management has selected personnel to direct the startup of eleven fossil-fueled, eight geothermal, and one nuclear-fueled steam-electric generating units. Only in the latter case was the responsibility shared and authority subordinated to direction from the NSSS supplier. The timely startup and exceptionally trouble-free performance of these units in operation demonstrates management's ability to select qualified personnel and the success of the system.
Personnel assigned to DCPP startup have been selected to meet the anticipated needs of startup service and transfer of operations to the Nuclear Power Generation Department of the units that will provide additional trouble-free generating capacity for PG&E. Their selection is based on personal backgrounds requiring minimum supplementary technical education or field experience. The Lead Startup Engineer is responsible for requesting, and the Manager of Station Construction is responsible for providing, any additional training to ensure that members of the startup organization have the abilities to satisfy management objectives and the following: 14.1.1.7.1 Lead Startup Engineer The Lead Startup Engineer shall have a minimum of 10 years of power plant experience. Graduation in an engineering discipline shall count for 2 of these years, and a minimum of 3 years of power plant startup experience is required. Of the remaining 5 years, a maximum of 2 may be fulfilled by academic or field training in nuclear subjects. The Lead Startup Engineer shall be familiar with the design and performance of all the DCPP systems. 14.1.1.7.2 Startup Engineer Startup Engineers shall have a minimum of 6 years of power plant experience. Graduation in an engineering discipline shall count for 2 of these years, and a minimum of 1 year of power plant startup experience is required. Of the remaining 3 years, a maximum of 1 year may be fulfilled by academic or field training in nuclear subjects. Startup Engineers shall be familiar with the design and performance objectives of the DCPP systems. 14.1.1.7.3 Assistant Startup Engineer Assistant Startup Engineers shall have a minimum of 4 years of power plant experience. Graduation in an engineering discipline shall count for 2 of these years, and a minimum of 1 year of power plant startup experience is required. Assistant Startup Engineers shall be familiar with the design and performance objectives of assigned DCPP systems.
DCPP UNITS 1 & 2 FSAR UPDATE 14.1-5 Revision 15 September 2003 14.1.1.7.4 Startup Engineer Trainee Startup Engineer Trainees shall, as a minimum, have either a degree in an engineering discipline or 2 years of power plant experience. Experience needed to fulfill the requirements for other positions within the Startup Department shall be gained by on-the-job training that includes preparation of preoperational and startup procedures and personal participation in the execution of preoperational tests of DCPP systems under the supervision of a Startup Engineer. Startup Engineer Trainees shall be familiar with the design and performance objectives of assigned DCPP systems. 14.1.1.8 Additional Qualifications In addition, appointees to any of the above assignments may have additional qualifications that will allow them to fill the following positions: 14.1.1.8.1 Nuclear Advisor Nuclear advisors shall have a minimum of a bachelor's degree in engineering or in physical science and 2 of years experience in such areas as reactor physics, core measurements, core heat transfer, and core physics testing programs. One year of experience may be fulfilled by academic training beyond the bachelor's degree program on a one-for-one time basis. 14.1.1.8.2 Chemistry Advisor Chemistry advisors shall have a minimum of a bachelor's degree in engineering or in physical science, and 1 year of experience in water or wastewater treatment. 14.1.2 ADMINISTRATIVE PROCEDURES -- MODIFICATIONS Test procedure inadequacies discovered at any time are corrected using written changes. All test procedure changes are reviewed and approved according to the administrative procedure for the original test procedure before final acceptance of the test by the Plant Superintendent. If the test results do not satisfy the acceptance criteria, or are otherwise contrary to the expected results, the Lead Startup Engineer is responsible for documenting the problem and acts as coordinator between General Construction and the Engineering Departments in resolving such problems, including any necessary system modifications. Resulting test changes shall be handled as described above. Any required retesting shall be handled according to the administrative procedure for conducting the original test. All test procedure changes for units with an operating license require PSRC review within the time frame established by the Technical Specifications(1). Temporary system modifications required for testing are documented in the procedures and, following completion of testing, restoration to normal conditions is made and documented. DCPP UNITS 1 & 2 FSAR UPDATE 14.1-6 Revision 15 September 2003 14.1.3 TEST OBJECTIVES AND PROCEDURES 14.1.3.1 Preoperational Testing The testing program performed prior to fuel loading ensures that performance of equipment and systems is in accordance with design criteria. The program includes tests, adjustments, calibrations, and system operations necessary to ensure that initial fuel loading, initial criticality, and subsequent power operation can be safely undertaken. As installation of individual components and systems is completed, each is tested according to approved written procedures. The tests are designed to verify, as nearly as possible, the performance of the components and/or systems under conditions expected to be experienced during plant operation. The prerequisites for these tests include written confirmation that construction activities are complete.
During system tests for which normal plant conditions do not exist and cannot be simulated, the systems are operationally tested to the maximum extent possible. The remainder of the tests are performed when conditions are suitable for testing. Abnormal plant conditions are simulated during testing, when required, and when such conditions do not endanger personnel or equipment.
Evaluations of test results are made to verify that components and systems are performing satisfactorily and, if not, to provide a basis for recommending corrective action.
Where required, simulated signals or inputs are used to verify the full operating range of a system and to calibrate and align the system and instruments at these conditions. Later, systems that are used during normal operation are verified and calibrated under actual operating conditions. Systems that are not used during normal plant operation, but must be in a state of readiness to perform safety-related functions, are checked under all modes and test conditions prior to plant startup. Examples of these systems are the reactor trip system and engineered safety features system logic. Correct operation and setpoints are verified during this testing.
Testing performed during preoperational testing will be completed before fuel loading. In some cases, it will be necessary to defer certain preoperational tests until after fuel loading. These include tests to be performed on the complete rod control system, rod position indication, and complete incore movable detector system. These tests have been identified in Table 14.1-2, Fuel Loading and Initial Startup Testing Summary. Prior to the performance of hot testing following core loading, prerequisite cold testing will have been performed. An example of these tests is the cold rod drop time measurement test. In any event, the surveillance requirements of the Technical Specifications will be met as required for each mode transition.
DCPP UNITS 1 & 2 FSAR UPDATE 14.1-7 Revision 15 September 2003 14.1.3.2 Startup Testing After satisfactory completion of final precritical tests, nuclear operation of the reactor begins. This final phase of startup and testing includes initial criticality, low power testing, and power level escalation. The purpose of these tests is to establish the operational characteristics of the plant and the core, to acquire data for the determination of setpoints, to establish administrative controls during reactor operations, and to ensure that operation is within license requirements. A brief description of the test program is presented in the following sections. Table 14.1-2 summarizes the tests that will be performed from fuel load through plant operation at rated power, and Figure 14.1-1 shows the sequence in which these tests are performed. 14.1.4 FUEL LOADING AND INITIAL OPERATIONS 14.1.4.1 Fuel Loading The overall responsibility and direction for initial fuel loading is exercised by PG&E personnel. Fuel loading begins when all prerequisite system tests and operations have been satisfactorily completed, an operating license has been obtained from the U. S. Nuclear Regulatory Commission, and a review by the plant staff has determined that the requirements in the Technical Specifications have been met.
Access to the containment will be controlled by written procedure during fuel loading. Fuel handling tools and equipment shall have been checked out and dry runs conducted in the use and operation of equipment. The reactor vessel and associated components will be in a state of readiness to receive fuel. Water level will be maintained above the bottom of the nozzles and recirculation maintained to ensure a uniform boron concentration. Boron concentration can be increased via the recirculation system.
The as-loaded core configuration is specified as part of the core design studies conducted well in advance of fuel loading. The core is assembled in the reactor vessel that is already filled with water containing enough dissolved boric acid to maintain an effective multiplication factor of 0.95, or less, or a boron concentration greater than 2000 ppm. For initial core loading, the 2000 ppm minimum is limiting and results in an effective multiplication factor of less than 0.90. The refueling cavity is partially filled with borated water during initial fuel loading to provide lubrication for the fuel handling equipment. Coolant chemistry conditions are prescribed in the fuel loading procedure and verified periodically by chemical analysis of moderator samples prior to and during fuel loading operations.
Fuel loading instrumentation shall consist of at least two source range monitors. Normally, two permanently installed excore source range neutron channels and three temporary incore source range neutron channels will be available. The permanent channels, when responding, are monitored in the control room by licensed operators. The temporary channels installed inside the containment structure are monitored by knowledgeable test personnel who, in turn, communicate with the senior licensed DCPP UNITS 1 & 2 FSAR UPDATE 14.1-8 Revision 15 September 2003 operator in charge of fuel loading. At least one channel is equipped with an audible count rate indicator audible in the control room and loading area. Both permanent channels have the capability of displaying the neutron count rate on strip chart recorders. The temporary channels indicate on count rate meters with a minimum of one channel recorded on a strip chart recorder. Minimum count rates attributable to neutrons generated in the core are required on at least two of the five (i.e., three temporary and two permanent) available neutron source range channels at all times following installation of the primary sources and the first ten fuel assemblies to continue fuel loading.
Two neutron sources are inserted into the core at locations and sequence specified in the fuel loading program to ensure a neutron population that produces a minimum of 1/2-count/sec for adequate monitoring of the core.
Fuel assemblies, together with inserted components (rod cluster control assemblies (RCCAs), burnable poison rods, source spider, or thimble plugging devices), are placed in the reactor vessel one at a time according to an approved sequence to provide reliable core monitoring that minimizes the possibility of core mechanical damage. The fuel loading procedure includes a tabular check sheet that prescribes the movements of each fuel assembly and its specified inserted components from its initial position in the fuel racks to its final position in the core. Checks are made of component serial numbers and types to guard against possible inadvertent exchanges or substitutions of components, and two reactor core fuel assembly tag boards are maintained throughout the core loading operation.
An initial increment of ten fuel assemblies, the first of which contains an active neutron source, is the minimum source-fuel increment that permits subsequent meaningful inverse count rate monitoring. This initial increment is determined by calculation and previous experience to be markedly subcritical keff 0.90) under the required conditions of loading.
Each subsequent fuel loading increment is accompanied by detailed neutron count rate monitoring to determine that the just-loaded increment does not excessively increase the count rate and that the extrapolated inverse count rate ratio is not decreasing for unexplained reasons. The results of each loading step are evaluated according to written procedures before the next prescribed step is started.
Criteria for safe loading require that loading operations stop immediately if:
(1) An unanticipated increase in the neutron count rate by a factor of two occurs on all operating nuclear channels during any single loading step (excludes anticipated changes due to source/detector geometry) (2) The neutron count rate on any individual nuclear channel unexpectedly increases by a factor of three during any single loading step (excludes anticipated changes due to source/detector geometry)
DCPP UNITS 1 & 2 FSAR UPDATE 14.1-9 Revision 15 September 2003 A "high count rate" alarm in the containment and the control room is coupled to the source range channels with a setpoint equal to or less than five times the current count rate. This alarm automatically alerts the fuel loading crew to an indication of high count rate and requires an immediate stop of all operations until the situation is evaluated. If it is immediately determined that no hazards to personnel exist, preselected personnel may remain in the containment to evaluate the cause and determine future action.
Fuel loading procedures specify alignment of fluid systems to prevent inadvertent dilution of the boron concentration in the reactor coolant, restrict the movement of fuel to preclude the possibility of mechanical damage, prescribe the conditions under which loading can proceed, identify chains of responsibility and authority, provide for continuous and complete fuel and core component accountability, and establish procedures to be observed in case of emergency. 14.1.4.2 Postloading Tests Upon completion of fuel loading, the reactor upper internals and the pressure vessel head are installed and additional testing is performed prior to initial criticality. The final pressure tests are conducted after filling and venting of the reactor coolant system (RCS) is completed. The purpose of this phase of the program is to prepare the system for nuclear operation and to establish that design requirements necessary for operation are achieved.
Mechanical and electrical tests are performed on the RCCA drive mechanisms. A complete operational check of the RCCA drive mechanisms and the RCCA position indicator systems is performed. Tests are performed on the reactor trip circuits to verify manual trip operation and actual RCCA drop times are measured for each assembly. Whenever the RCCA drive mechanisms are being tested, the boron concentration in the RCS is such that criticality cannot be achieved with all RCCAs fully withdrawn. A complete functional electrical and mechanical check is made of the incore nuclear flux mapping system at operating temperature and pressure. 14.1.4.3 Initial Criticality Initial criticality is established by sequentially withdrawing the shutdown and control groups of control rod assemblies from the core, leaving the last withdrawn control group inserted far enough in the core to provide effective control when criticality is achieved. Then the heavily borated reactor coolant is diluted until criticality is achieved. Successive stages of control rod assembly group withdrawal and of boron concentration reduction are monitored by observing changes in neutron count rate. Periodically, samples of the primary coolant boron concentration are obtained and analyzed.
The inverse count rate ratio is used as an indication of the nearness and rate of approach to criticality of the core during RCCA group withdrawal and during reactor coolant boron dilution. The rate of approach is reduced as the reactor approaches extrapolated criticality to ensure that effective control is maintained at all times. Written DCPP UNITS 1 & 2 FSAR UPDATE 14.1-10 Revision 15 September 2003 procedures specify alignment of fluid systems, control the rate at which the approach to criticality may proceed, and predict initial values of core conditions under which criticality is expected. 14.1.4.4 Low Power Testing A prescribed program of reactor physics measurements is undertaken to verify that the basic static and kinetic characteristics of the core are as expected and that the values of the kinetic coefficients assumed in the safety analysis are conservative.
The measurements are made at low power and at or near operating temperature and pressure. The measurements include verification of calculated control rod assembly group reactivity worths, isothermal temperature coefficient under various core conditions, differential boron concentration reactivity worth, and critical boron concentrations all as functions of control rod assembly group configuration. In addition, measurements of the power distribution are made. Concurrent tests are conducted on the instrumentation including the source and intermediate-range nuclear channels.
Written procedures specify the sequence of testing and the conditions under which each test is to be performed. This ensures both safety of operation and the relevancy and consistency of the results obtained. If significant deviations from design predictions exist, unacceptable behavior is revealed, or apparent anomalies develop, the testing is suspended while the situation is reviewed by PG&E to determine whether a question of safety is involved; the deviation is resolved prior to resumption of testing. 14.1.4.5 Power Level Escalation When the operating characteristics of the plant have been verified by low power testing, a program of power level escalation in successive stages brings the unit to its full licensed power level. Reactor and unit operational characteristics are closely examined at each power level plateau and the relevance of the safety analysis is verified before escalation to the next programmed level.
Measurements are made to determine the relative power distribution in the core as functions of power level.
Secondary system heat balances ensure that the various indications of power level are consistent and provide a base for calibration of power range neutron channels. The ability of the reactor control system to respond effectively to signals from reactor plant and steam plant instrumentation under a variety of conditions encountered in normal operations is verified.
At prescribed power levels, the dynamic response characteristics of the reactor plant and steam plant are evaluated. The responses of system components are measured for design step and ramp changes in load, 50 percent reduction of load at design rate and normal recovery, net load rejection, and turbine trip. DCPP UNITS 1 & 2 FSAR UPDATE 14.1-11 Revision 15 September 2003 Adequacy of radiation shielding is verified by gamma and neutron radiation surveys inside the containment and throughout the plant site at specified power levels. Periodic sampling of reactor coolant is performed to verify the chemical and radiochemical analysis of the reactor plant systems.
The functional performance requirements in some instances are described by specific quantitative acceptance criteria that are addressed in other sections of the FSAR. In other cases, acceptance standards may specify that a system or component perform a given action sequence. In either case, the detailed procedures or the referenced documents used in performing the test include specific acceptance criteria against which actual performance is measured. Plant conditions for each of the tests are listed in the test procedure.
When completed, this program provides assurance that plant performance is in accordance with the safety requirements established in the FSAR. The listing of the tests in Tables 14.1-1 and 14.1-2 includes specific identification of the objectives of each particular test that is required. Figure 14.1-1 gives a graphic presentation of the chronological sequence of startup testing. 14.1.5 ADMINISTRATIVE PROCEDURES -- SYSTEM OPERATION 14.1.5.1 Operating Procedures Normal and emergency operation of all plant systems and/or major pieces of equipment are carried out in accordance with written procedures prepared by plant personnel and approved by the Plant Manager or his representative. These procedures are incorporated into the test program by the Lead Startup Engineer as appropriate. Where the prerequisite conditions for an operating procedure cannot be met during the test program, the procedure is demonstrated, under conditions simulating, as nearly as possible, the prerequisite conditions. The Assistant Plant Manager/Plant Superintendent reviews each startup test procedure to ensure that the operations specified in the test procedure are consistent with the normal and emergency operating procedures. 14.1.5.2 Safety Precautions The measurements and operations during low power escalation testing are similar to normal unit operations at power and normal safety precautions are observed. Those tests that require special operating conditions are accomplished using test procedures that prescribe necessary limitations and precautions. 14.
1.6 REFERENCES
- 1. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
DCPP UNITS 1 & 2 FSAR UPDATE 14.2-1 Revision 15 September 2003 14.2 AUGMENTATION OF APPLICANT'S STAFF FOR INITIAL TESTS AND OPERATION The startup group, under the direction of the Lead Startup Engineer, is responsible for conducting the preoperational and startup testing programs. As such, the startup group may be considered the augmenting organization for the normal plant operating staff during the testing period. The NSSS supplier will furnish technical advice to the startup group during the initial testing period. In addition, the plant technical staff will augment the startup group during the initial test program. This augmentation will include shift supervision and shift staff engineer support. 14.2.1 ORGANIZATIONAL FUNCTIONS, RESPONSIBILITIES, AND AUTHORITIES PG&E's organizational structure is shown in Figure 17.1-1. The Vice President-General Construction is responsible for construction of DCPP Units 1 and 2. This responsibility extends until the plant is running and released for operation, and includes the startup and acceptance of equipment.
The Nuclear Power Generation organizational structure is described in Chapter 13.
The plant operating organization, also described in Chapter 13, is responsible for the safety of operating personnel and the general public, for providing the necessary operating personnel for the power plant, for the training of those personnel, and for the direction and supervision of their work during the startup of new facilities. All activities that could affect the operation of the plant are done under the cognizance of licensed personnel as required by the Technical Specifications(1). Technical advice furnished by Westinghouse Electric Corporation (Westinghouse), the NSSS designer and manufacturer, is advisory in nature since only PG&E's Operating Department plant staff will be licensed to direct or control plant operation. 14.2.2 INTERRELATIONSHIPS AND INTERFACES The Lead Startup Engineer functions as the principal contact between the construction and operating organizations for startup activities.
The Startup Coordinator functions as the Assistant Plant Manager/Plant Superintendent's representative for startup operational activities.
The working interrelationship between the Lead Startup Engineer and the Startup Coordinator is described in Section 14.2.3.
Westinghouse will provide technical advice on site to PG&E during installation, startup, testing, and initial operation of the NSSS. This will provide additional assurance that the NSSS is installed, started, tested, and operated in conformance with the design intent. Westinghouse personnel assigned to the site will provide technical advice and will DCPP UNITS 1 & 2 FSAR UPDATE 14.2-2 Revision 15 September 2003 provide technical liaison with the Westinghouse home office to promptly resolve problems within the Westinghouse scope of responsibility. 14.2.3 KEY PERSONNEL FUNCTIONS, RESPONSIBILITIES, AND AUTHORITIES 14.2.3.1 Station Construction Department The Station Construction Department designates a Lead Startup Engineer who reports to the DCPP Senior Site Representative.
The Lead Startup Engineer is responsible for:
(1) Preparing the preoperational and startup testing programs and schedules; approval of these programs will be by the Lead Startup Engineer's signature (2) Obtaining and preparing system test and acceptance criteria (3) Providing necessary written test procedures (4) Incorporating operating orders, procedures, and instructions prepared by the Assistant Plant Manager/Plant Superintendent into the test program (5) Obtaining comments on test procedures from the Assistant Plant Manager/Plant Superintendent (6) Arranging for startup personnel necessary to conduct the program and ensuring the adequacy of their preparation (7) Ensuring that all prerequisites for performing tests are satisfactorily completed (8) Directing individual preoperational and startup tests (9) Verifying that each preoperational or startup test is satisfactorily completed (10) Releasing accepted systems to the Assistant Plant Manager/Plant Superintendent (11) Participating as a member in plant staff review committee meetings during preoperational and startup testing (12) Obtaining technical advice from Westinghouse as necessary DCPP UNITS 1 & 2 FSAR UPDATE 14.2-3 Revision 15 September 2003 (13) Obtaining technical advice from PG&E's Engineering Department as necessary 14.2.3.2 Operating Department The Plant Manager is responsible for serving as chairman of the Plant Staff Review Committee meetings as discussed in Chapter 13.
The Assistant Plant Manager/Plant Superintendent is responsible for:
(1) Reviewing the schedules and test procedures developed by the Lead Startup Engineer and approving the overall startup schedule (2) Preparing equipment operating orders, procedures, and instructions in accordance with standard PG&E operating practices for inclusion in the testing program (3) Verifying that operating personnel are qualified to perform the operations required by the test program. Qualification of operating personnel is discussed in Chapter 13 (4) Supervising operation of controls of all components and systems during the test programs as requested by the Lead Startup Engineer and in accordance with the startup program (5) Witnessing tests on apparatus and equipment and making recommendations on test results (6) Determining that plant components and systems meet operating requirements as to safety, reliability, and economy of operation (7) Accepting independent auxiliary equipment and systems for operation as needed after satisfactory performance has been demonstrated The Assistant Plant Manager/Plant Superintendent designates an individual as Startup Coordinator, and that individual is responsible for startup operational activities under the Assistant Plant Manager/Plant Superintendent. For DCPP Units 1 and 2, the Operations Manager has been designated as Startup Coordinator.
14.2.3.3 Westinghouse Early in construction, Westinghouse provided a site manager to represent Westinghouse at the site.
The site technical advice that will be provided for startup testing will be dependent upon the test being performed, the level of testing activity at any specific time, and requests DCPP UNITS 1 & 2 FSAR UPDATE 14.2-4 Revision 15 September 2003 by PG&E. Consequently, the personnel levels, categories, and schedules will be established by the site manager based on anticipated activities during each phase of the startup schedule. Westinghouse representatives will work in conjunction with the DCPP startup organization. A Westinghouse systems engineer will be assigned to the site for hot functional testing and other major systems testing activities. Supporting this engineer will be several field service engineers normally assigned on site during plant construction. These engineers will be augmented by specialists from the Westinghouse home office as required for adequate observation of the specific test being performed. The specialists will provide specific technical advice for specific tests.
A typical schedule for Westinghouse specialists follows:
(1) Reactor Coolant System Hydrotest - three specialists (a) Reactor Coolant Pump Specialist Scheduled to be on site 2 days prior to the hydrotest and for an approximate duration of 1 week or until satisfactory completion of the activity (b) Chemist Scheduled to be on site 2 days prior to the hydrotest and for an approximate duration of 1 week or until satisfactory completion of the activity (c) Quality Assurance of Internals Inspector Scheduled to be on site 2 weeks prior to the hydrotest and for an approximate duration of 2 weeks or until satisfactory completion of the activity (2) Hot Functional Test - three specialists (a) Reactor Coolant Pump Specialist Scheduled to be on site 2 weeks prior to the hot functional test and for an approximate duration of 2 weeks or until satisfactory completion of the activity (b) Chemist Scheduled to be on site 2 days prior to the hot functional test and for an approximate duration of 1 week or until satisfactory completion of the activity DCPP UNITS 1 & 2 FSAR UPDATE 14.2-5 Revision 15 September 2003 (c) Quality Assurance of Internals Inspector Scheduled to be on site during the post-hot functional period and for an approximate duration of 1 week or until satisfactory completion of the activity (3) Core Loading - three specialists (a) Physicist Scheduled to be on site 2 days prior to core loading and for an approximate duration of 1 week or until satisfactory completion of the activity (b) Chemist Scheduled to be on site 2 days prior to core loading and for an approximate duration of 1 week or until satisfactory completion of the activity (c) Fuel Handling Specialist Scheduled to be on site 1 week prior to core loading and for an approximate duration of 2 weeks or until satisfactory completion of the activity (4) Plant Startup - four specialists (a) Nuclear Test Engineer Scheduled to be on site 1 week prior to startup and for an approximate duration of 8 weeks or until satisfactory completion of the activity (b) Chemist Scheduled to be on site 2 days prior to startup and for an approximate duration of 1 week or until satisfactory completion of the activity (c) Transient Analyst Scheduled to be on site prior to completion of each activity DCPP UNITS 1 & 2 FSAR UPDATE 14.2-6 Revision 15 September 2003 (d) Reactivity Computer Instrumentation Specialist Scheduled to be on site 1 day prior to startup and for an approximate duration of 2 weeks or until satisfactory completion of the activity 14.2.4 PERSONNEL QUALIFICATIONS A resume for the Startup Coordinator (Operations Manager) is in the appendix to Chapter 13.
Qualifications of Westinghouse personnel providing technical advice include sufficient personal maturity, work experience, education, and specialized training to satisfy Westinghouse of their competence to adequately perform tasks assigned by the Westinghouse site manager. Due to the fluid nature of plant startup schedules, the individuals who will perform these assignments cannot be identified until specific milestones (i.e., hot functional, etc.) have actually occurred. Timing will be the principal factor in determining individual availability. Trainees and personnel with limited work experience are not used in positions of significant responsibility. Experience in the startup of nuclear power plants has indicated that the qualification of Westinghouse personnel assigned has been fully acceptable. 14.
2.5 REFERENCES
- 1. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
DCPP UNITS 1 & 2 FSAR UPDATE 14.3-1 Revision 17 November 2006 14.3 POSTCOMMERCIAL OPERATIONAL TEST PROGRAM This section describes the program for testing modifications to DCPP systems per approved design changes. The program ensures design changes are reviewed for postmodification operational testing requirements and that all operational tests are developed and performed prior to returning affected equipment to service.
The engineering director has overall responsibility for postmodification testing.
The scope of a modification is evaluated against plant safety features, industry codes, regulatory requirements, etc. From this evaluation, the scope of required testing is determined. Temporary test procedures are prepared when existing plant procedures will not adequately test the modification. Procedures used for performance of operational testing of design changes are reviewed and approved by appropriate DCPP management. Operational testing ensures a modification will function in accordance with the design basis by simulating normal and transient conditions when practical.
DCPP defines testing based on work category. Post modification testing (PMT) consists of maintenance verification testing (MVT), operability verification testing (OVT), and design verification testing (DVT). These tests may consist of functional tests, dry-run tests, dynamic tests, and inspections. Qualified personnel review and evaluate the test results for acceptability prior to releasing the equipment for service.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 14.1-1 Sheet 1 of 8 Revision 18 October 2008 PREOPERATIONAL TESTING SUMMARY System Tests Test Objectives
- 1. Electrical Systems 1.1 Vital bus (4.16 kV, 480 V, 120 Vac) 1. To demonstrate full plant load capability and interchangeability of all alternate power sources.
- 2. To verify automatic transfer of buses with and without offsite power available. 3. To verify the 4.16 kV and 480 Vac vital bus load start logic.
1.2 Vital 125 Vdc system 1. To verify proper operation in normal and emergency conditions of batteries, battery chargers, 125 Vdc switchgear, and distribution panels.
- 2. To verify battery capacities.
1.3 Communications systems 1. To verify that the site evacuation signal can be heard from any location at the site.
- 2. To verify that the fire alarm signal can be heard from any location in the plant. 3. To verify that communications stations for fuel loading are functional.
1.4 Emergency lighting 1. To verify adequacy for operator transit from point to point. 2. Diesel Engine Generator Units 1. To verify the start signal setpoints and logic.
- 2. To verify the capability of the diesel engine generator units to supply power to vital equipment for plant cooldown during emergency conditions, such as loss of offsite power coincident with loss of turbine generator.
- 3. To verify that redundant features of the system function according to the design intent.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 14.1-1 Sheet 2 of 8 Revision 18 October 2008 System Tests Test Objectives
- 2. (Continued) 4. To verify that the diesel fuel oil transfer pump will supply fuel oil from the diesel fuel oil storage tank to the diesel engine fuel oil day tank.
- 3. Fire Protection Systems 1. To verify that the fire pumps will supply water from the fire water tank to selected stations within the DCPP and that the automatic start features operate as designed.
- 2. To verify that the low-pressure CO2 system functions properly and that CO2 is delivered to appropriate fire protection stations.
- 3. To verify that the Halon system functions properly and that Halon is dispersed in the solid-state protection system room in acceptable concentrations.
- 4. Ventilation Systems 1. To verify the operation of the containment fan coolers and dampers according to design and to measure heat removal capability during hot functional testing.
- 2. To verify that the auxiliary and fuel handling building exhaust and supply fans and the control room air conditioning units and their associated dampers, valves, and filters operate according to design.
- 3. To verify the logic for postaccident condition initiation of containment pressure reduction. 4. To verify the closure of containment purge supply and exhaust ducts and the pressure relief duct from a high radioactivity in containment signal.
- 5. Instrumentation and Control Systems 5.1 Process instrumentation 1. Applicable alarm and control set- points are checked for conformance with design values. 5.2 Nuclear instrumentation 1. Prior to core loading, nuclear instruments will have been aligned and source range detector response to neutron source checked.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 14.1-1 Sheet 3 of 8 Revision 18 October 2008 System Tests Test Objectives 5.2 (Continued) 2. All required channels will be checked to verify operability within the required Technical Specifications interval. 5.3 Automatic reactor power control systems tests 1. The system alignment is verified at preoperational conditions to demonstrate the response of the system to simulated inputs. These tests are performed to verify that the systems will operate satisfactorily at power.
- 2. At power, the alignment of the system is verified by programmed step changes and under actual test transient conditions.
5.4 Engineered safety features (ESF) 1. To verify ESF, setpoints, logic, and response times. 2. To verify response of ESF equipment to a safety injection signal with and without offsite power available. 5.5 Reactor protection system 1. To test redundancy, coincidence, independence, and safe failure on loss of power to process instrumentation and reactor protection equipment.
- 2. To verify reactor protection time response meets design requirements. 3. To test automatic and manual reactor trip setpoints, logic, and reactor trip breakers.
5.6 Radiation monitoring systems 1. To calibrate against known standards and verify the operability and alarm setpoints of all process monitors (air particulate monitors, gas monitors, and liquid monitors) located in the plant.
- 6. System Functional Tests 6.1 Reactor coolant system (RCS) 1. To verify the integrity and leaktightness of the RCS and auxiliary primary systems at the specified test pressure and temperature. 2. To verify the capability of the pressurizer relief tank to function according to design.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 14.1-1 Sheet 4 of 8 Revision 18 October 2008 System Tests Test Objectives 6.1 (Continued) 3. To verify proper operation of the nuclear steam supply system and auxiliary systems local and remote indicators, alarms, recorders, and controllers for pressure, temperature, flow, and level. 4. To verify resistance temperature detector (RTD) bypass loop flow and correct functional operation of control and indicating equipment and the detectors.
- 5. To establish baseline data for inservice inspections and verify integrity of the system.
6.2 Chemical and volume control system (CVCS) 1. To verify that the design charging, letdown, and excess letdown flowrates are attainable. 2. To verify that the reactor coolant purification equipment operates according to design parameters.
- 3. To verify charging pump (CCP1 and 2) performance and response to a safety injection signal when the RCS is depressurized.
- 4. To verify ability to control RCS water volume.
- 5. To verify the ability to control chemical shim concentration.
- 6. To verify the design seal water flowrates to each reactor coolant pump. 7. To verify that pumps, filters, tanks, and heat tracing used for batching, storage, and transfer of 12% boric acid function satisfactorily as a system.
- 8. To verify gas stripper and boric acid evaporator operation meets design requirements.
- 9. To verify chemical addition and sampling features function according to design. 10. To verify operating capability of process instrumentation and controls under normal conditions.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 14.1-1 Sheet 5 of 8 Revision 18 October 2008 System Tests Test Objectives 6.3 Safety injection system 1. To verify the safety injection pump and accumulator performance and response to a safety injection signal when the RCS is depressurized.
- 2. Test the systems to ensure capability of meeting design objectives.
6.4 Containment spray system 1. To verify the containment spray pump performance and response to a containment spray signal. 2. Verify that the system can be tested to verify functional performance. 6.5 Residual heat removal system (RHRS) 1. To verify the RHR pump performance and response to a safety injection signal when the RCS is depressurized.
- 2. To verify the system is capable of supplying emergency core cooling in the recirculation mode. 3. To verify system capability for supplying cooling water during core loading.
- 4. To verify the capability for plant cooldown assuming failure of a single active component. 6.6 Component cooling water system (CCWS) 1. To verify normal system operation according to the system description and design requirements. 2. To verify the capability for plant cooldown assuming failure of a single active component.
6.7 Makeup water system 1. To verify the makeup water transfer pumps will transfer water from the condensate storage tank to the fire system, and to the CCW system surge tank.
- 2. To verify the primary water makeup pumps will supply water from the primary water storage tank to the CCW system surge tank, to the boric acid blender, and to the chemical mixing tank in the CVCS system.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 14.1-1 Sheet 6 of 8 Revision 18 October 2008 System Tests Test Objectives 6.8 Auxiliary saltwater system (ASWS) 1. To verify normal system operation according to system description and design requirements.
- 2. To verify the capability for plant cooldown assuming failure of a single active component. 6.9 Liquid radwaste system 1. To verify that liquids can be collected in the reactor coolant drain tank and transferred to other tanks per design.
- 2. To verify waste processing according to the system description (includes waste concentrator, waste concentrator pumps, and liquid radwaste filter and tanks).
- 3. To verify that liquid radwaste releases can be controlled and excessive releases can be prevented.
- 4. To verify proper operation of primary system leak detection features and to verify proper operation of miscellaneous equipment drain tank pumps, equipment drain receivers, and pumps. 6.10 Gaseous radwaste system 1. To verify the collection and processing of gaseous radwaste is according to the system description. 6.11 Auxiliary feedwater system 1. To verify the turbine- and motor-driven auxiliary feedwater pumps deliver feedwater from the condensate storage tank to the steam generators at design flowrate and pressure and otherwise perform according to design in response to ESF signals. 6.12 Condensate, feedwater, and main steam 1. To check proper operation and indication of feedwater control and main steam line isolation valves for the appropriate actuation signals. 6.13 Hydrogen and nitrogen systems 1. To verify valve operability, regulating and reducing station performance, and the ability to supply the appropriate gas to interconnecting systems as required.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 14.1-1 Sheet 7 of 8 Revision 18 October 2008 System Tests Test Objectives
- 7. Hot Functional Tests The intent of planned testing shall include but not be limited to the following: 1. To check RCS heatup and cooldown procedures. 2. To demonstrate satisfactory performance of components and systems that are exposed to RCS temperature. 3. To verify to the extent possible proper operation of instrumentation, controllers, and alarms. 4. To provide design operating conditions for testing the following auxiliary systems: a. CVCS
- b. Sampling system
- c. CCWS d. RHRS e. ASWS
- 5. To verify that water can be charged by the CVCS at rated flow against normal reactor coolant pressure.
- 6. To check letdown design flowrate for each operating mode.
- 7. To check operation of the excess letdown and seal water flowpaths.
- 8. To check steam generator instrumentation and control systems. 9. To verify the ability to cool down the plant using the steam generators.
- 10. To check thermal expansion and restraint of RCS components and piping. 11. To perform isothermal calibration of RTDs and incore thermocouples.
- 12. To operationally test the RHRS.
- 13. To check pressurizer level and pressure instrumentation and control systems.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 14.1-1 Sheet 8 of 8 Revision 18 October 2008 System Tests Test Objectives
- 7. (Continued) 14. To check RCS instrumentation and control systems.
- 15. To verify the ability of the auxiliary feedwater system to feed the steam generators. 16. To verify that steam generator blowdown operates according to design.
- 17. To verify the capability of emergency process control from a location remote to the control room. 18. To verify correct plant response to a safety injection signal under hot operating conditions.
Verify system alignments, automatic transfer of electrical systems, and automatic sequential start of ESF equipment.
- 19. Following hot functional testing, the reactor internals are removed and inspected for signs of excessive vibration. 8. Relief and Safety Valve Tests 1. To verify setpoints of the relief and safety valves.
- 9. Containment Building 1. To conduct structural integrity and integrated leakrate tests. 2. To verify proper operation and leaktightness of air locks.
- 3. To verify closure of all containment isolation valves for the appropriate signals.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 14.1-2 Sheet 1 of 6 Revision 15 September 2003 FUEL LOADING AND INITIAL STARTUP TESTING SUMMARY Tests Objectives
- 1. Startup Program Master Document 1. To define the sequence of tests and activities from preparation for fuel load through fuel loading, low power testing, and power ascension.
- 2. To establish hold points for administrative control over proceeding into significant areas of testing or power plateaus. 2. Fuel Loading Program 2.1 Fuel loading prerequisites and periodic checkoffs 1. To establish and maintain the prerequisite conditions for fuel loading. 2.2 Initial fuel loading 1. To specify the sequence of operation for fuel loading.
- 3. Precritical Test Program 3.1 Incore movable detectors 1. To verify correct functional operation of control and indicating equipment.
3.2 Rod drive mechanism timing 1. To verify the proper timing for rod drive mechanism control equipment. 2. To operationally check each control rod drive mechanism with a control rod attached. 3.3 Incore thermocouple-loop RTD cross calibration 1. To check and compare incore thermocouple readings with RCS RTD readings and calibrate the system if required. 3.4 Pressurizer spray and heater capacity and continuous spray flow setting 1. To establish the continuous spray flowrate. 2. To verify the pressure control capability using spray flow and heaters. 3.5 RTD bypass loop flow 1. To establish and verify acceptable flowrates. measurement DCPP UNITS 1 & 2 FSAR UPDATE TABLE 14.1-2 Sheet 2 of 6 Revision 15 September 2003 Tests Objectives 3.6 Rod drop time measurement 1. To determine the drop time of each control rod for selected conditions. 3.7 Rod position indication 1. To demonstrate satisfactory system performance of indication and alarm functions. 2. To demonstrate that control rods operate over their entire length of travel. 3.8 Rod control system operational test 1. To demonstrate that the rod control system performs its required control and indication functions to verify availability for use just prior to criticality. 3.9 RCS flow measurement 1. To verify adequacy of RCS flow.
3.10 RCS flow coastdown 1. To verify the rate of change of reactor coolant flow subsequent to selective reactor coolant pump trips.
- 4. Initial Criticality and Low Power Physics Program 4.1 Initial criticality 1. To bring the reactor critical for the first time.
- 2. To compare the measured critical boron concentration with the expected critical boron concentration. 3. To establish upper limit of flux level for zero power physics measurements.
4.2 Nuclear design checks 1. To verify the boron endpoint concentration, the isothermal temperature coefficient of reactivity, and zero power flux distribution for various rod configurations. 4.3 Rod and boron reactivity worth measurements 1. To verify design values of bank differential and integral worths during boron addition and dilution. 4.4 Rod cluster control assembly (RCCA) pseudo-ejection 1. To verify that the RCCA reactivity worth assumed in the accident analysis is conservative. 4.5 Minimum shutdown verification 1. To verify the reactivity worth of the shutdown banks. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 14.1-2 Sheet 3 of 6 Revision 15 September 2003 Tests Objectives 4.5 (Continued) 2. To measure the critical boron concentration with all shutdown and control banks inserted, less the most reactive rod assembly. 4.6 Conduct special test program (Unit 1 only) consisting of the following tests: a) Natural circulation 1. Provide supplementary technical information and operator training. (Tests a through g.) b) Natural circulation with loss of pressurizer heaters 2. Determine capability of CVCS charging and letdown to cooldown the RCS. (Test f.) c) Natural circulation at reduced pressure 3. Demonstrate ability to control RCS and steam generator parameters. (Test g.) (d) Natural circulation with simulated loss of offsite ac power (e) Effect of steam generator isolation on natural circulation (f) Cooldown capability of the charging and letdown system (g) Simulated loss of all onsite and offsite ac power 5 Power Ascension Program 5.1 Thermal power measurements 1. To ascertain level of thermal power for establishment of plateaus for testing activities.
- 2. To provide thermal power information for use in other tests. 5.2 Radiation surveys and shielding effectiveness 1. To obtain background information to establish access restrictions .
- 2. To verify shielding adequacy.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 14.1-2 Sheet 4 of 6 Revision 15 September 2003 Tests Objectives 5.3 Operational alignment of nuclear instrumentation systems (NIS) 1. To make necessary adjustments to the NIS as a function of reactor thermal power 5.4 Operational alignment of RCS temperature instrumentation at power 1. To make necessary adjustments to the Tavg and T channels as a function of reactor thermal power 5.5 Calibration of steam and feedwater flow instrumentation at power 1. To calibrate steam and feedwater flow instrumentation as a function values determined from test instrumentation. 5.6 Turbine overspeed trip test 1. To test the main turbine electrical and mechanical overspeed trip mechanisms. 5.7 Incore power distribution 1. To verify that nuclear design predicted power distributions are valid for normal rod patterns and configurations. 5.8 Effluents and effluents monitoring 1. To verify level of radwaste releases. 5.9 Chemical and radiochemical 1. To demonstrate ability to control RCS analysis water chemistry.
5.10 Control systems checkout 1. To demonstrate proper operation of the: a. RCS
- b. Steam generator level control system
- c. Steam dump control system
- d. Turbine control system.
5.11 Control rod pseudo-ejection and above bank position measurements 1. To verify response of the excore detectors to a rod in above bank position. 2. To verify the effects of a rod out of position and a pseudo-ejected rod upon neutron flux and hot channel factors. 5.12 Static rod drop and RCCA below bank position measurements (Unit 1 only) 1. To verify the response of excore detectors to a rod in below bank position. 2. To verify that a single control rod assembly inserted fully or part way below the control bank results in acceptable hot channel factors. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 14.1-2 Sheet 5 of 6 Revision 15 September 2003 Tests Objectives 5.13 Rod group drop and plant trip 1. To verify functioning of negative rate trip circuitry in the excore detector system.
- 2. To verify control systems performance as evidenced by plant parameter variations within acceptable limits. 5.14 Plant shutdown from outside the control room 1. To verify shutdown capability from backup control stations 5.15 Load swing tests 1. To verify control systems performance as evidenced by plant parameter variations within acceptable limits.
- 2. To verify plant response to load changes.
5.16 Doppler power reactivity coefficient measurement 1. To verify nuclear design prediction of the Doppler-only power coefficient. 5.17 Incore-excore detector calibration 1. To form a relationship between incore and excore neutron detector signals for generated axial offsets 5.18 Large load reduction tests 1. To verify ability of plant to sustain large load reductions as evidenced by parameters remaining within acceptable limits. 5.19 Steam generator moisture carryover 1. To verify that actual steam generator moisture carryover is equal to or less than design value. 5.20 Nuclear steam supply system acceptance test 1. To operate the plant at or near 100% power for 100 hours to verify plant capability at sustained load. 5.21 Net load trip tests 1. To verify plant response to loss of plant load at the 50% and 100% power plateaus for Unit 1 and the 50% power plateau for Unit 2.
- 2. To verify control systems performance as evidenced by plant parameter variations within acceptable limits.
5.22 Plant trip tests 1. To verify plant response to turbine generator trips at 50% and 100% power plateaus.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 14.1-2 Sheet 6 of 6 Revision 15 September 2003 Tests Objectives 5.22 (Continued) 2. To verify control systems performance as evidenced by plant parameter variations within acceptable limits.
- 3. To verify automatic transfer to offsite standby power. 5.23 Natural circulation boron mixing cooldown test (Unit 1 only) 1. To verify ability to add and mix 12% boric acid, cooldown to RHR via natural circulation and continue cooldown to cold shutdown conditions .
DCPP UNITS 1 & 2 FSAR UPDATE i Revision 21 September 2013 CHAPTER 15 ACCIDENT ANALYSES CONTENTS Section Title Page ACCIDENT ANALYSIS 15-1
15.1 CONDITION I - NORMAL OPERATION AND OPERATIONAL TRANSIENTS 15.1-1
15.1.1 Optimization of Control Systems 15.1-2
15.1.2 Initial Power Conditions Assumed in Accident Analyses 15.1-2 15.1.2.1 Power Rating 15.1-3 15.1.2.2 Initial Conditions 15.1-3 15.1.2.3 Power Distribution 15.1-4
15.1.3 Trip Points and Time Delays to Trip Assumed in Accident Analyses 15.1-5
15.1.4 Calorimetric Errors - Power Range Neutron Flux 15.1-6 15.1.5 Rod Cluster Control Assembly Insertion Characteristics 15.1-6 15.1.6 Reactivity Coefficients 15.1-7
15.1.7 Fission Product Inventories 15.1-7
15.1.8 Residual Decay Heat 15.1-7 15.1.8.1 Fission Product Decay 15.1-8 15.1.8.2 Decay of U-238 Capture Products 15.1-8 15.1.8.3 Residual Fissions 15.1-9 15.1.8.4 Distribution of Decay Heat Following Loss-of-Coolant Accident 15.1-9
15.1.9 Computer Codes Utilized 15.1-10 15.1.9.1 FACTRAN 15.1-10 15.1.9.2 LOFTRAN 15.1-11 15.1.9.3 PHOENIX-P 15.1-11 15.1.9.4 ANC 15.1-11 15.1.9.5 TWINKLE 15.1-12 15.1.9.6 THINC 15.1-12 15.1.9.7 RETRAN-02 15.1-12 DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 CONTENTS (Continued) Section Title Page ii Revision 21 September 2013 15.1.9.8 RETRAN-02W 15.1-13 15.1.10 References 15.1-13
15.2 CONDITION II - FAULTS OF MODERATE FREQUENCY 15.2-1
15.2.1 Uncontrolled Rod Cluster Control Assembly Bank Withdrawal from a Subcritical Condition 15.2-2 15.2.1.1 Identification of Causes and Accident Description 15.2-2 15.2.1.2 Analysis of Effects and Consequences 15.2-4 15.2.1.3 Results 15.2-5 15.2.1.4 Conclusions 15.2-5
15.2.2 Uncontrolled Rod Cluster Control Assembly Bank Withdrawal at Power 15.2-5 15.2.2.1 Identification of Causes and Accident Description 15.2-5 15.2.2.2 Analysis of Effects and Consequences 15.2-7 15.2.2.3 Results 15.2-8 15.2.2.4 Conclusions 15.2-10
15.2.3 Rod Cluster Control Assembly Misoperation 15.2-10 15.2.3.1 Identification of Causes and Accident Description 15.2-10 15.2.3.2 Analysis of Effects and Consequences 15.2-12 15.2.3.3 Results 15.2-13 15.2.3.4 Conclusions 15.2-14
15.2.4 Uncontrolled Boron Dilution 15.2-15 15.2.4.1 Identification of Causes and Accident Description 15.2-15 15.2.4.2 Analysis of Effects and Consequences 15.2-16 15.2.4.3 Conclusions 15.2-17
15.2.5 Partial Loss of Forced Reactor Coolant Flow 15.2-18 15.2.5.1 Identification of Causes and Accident Description 15.2-18 15.2.5.2 Analysis of Effects and Consequences 15.2-19 15.2.5.3 Results 15.2-20 15.2.5.4 Conclusions 15.2-20
15.2.6 Startup of an Inactive Reactor Coolant Loop 15.2-20 15.2.6.1 Identification of Causes and Accident Description 15.2-20 15.2.6.2 Analysis of Effects and Consequences 15.2-21 15.2.6.3 Results 15.2-22 15.2.6.4 Conclusions 15.2-22 DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 CONTENTS (Continued) Section Title Page iii Revision 21 September 2013 15.2.7 Loss of External Electrical Load and/or Turbine Trip 15.2-22 15.2.7.1 Identification of Causes and Accident Description 15.2-22 15.2.7.2 Analysis of Effects and Consequences 15.2-23 15.2.7.3 Results 15.2-26 15.2.7.4 Conclusions 15.2-27
15.2.8 Loss of Normal Feedwater 15.2-27 15.2.8.1 Identification of Causes and Accident Description 15.2-27 15.2.8.2 Analysis of Effects and Consequences 15.2-29 15.2.8.3 Results 15.2-30 15.2.8.4 Conclusions 15.2-30 15.2.9 Loss of Offsite Power to the Station Auxiliaries 15.2-31 15.2.9.1 Identification of Causes and Accident Description 15.2-31 15.2.9.2 Analysis of Effects and Consequences 15.2-31 15.2.9.3 Results 15.2-32 15.2.9.4 Conclusions 15.2-32
15.2.10 Excessive Heat Removal Due to Feedwater System Malfunctions 15.2-32 15.2.10.1 Identification of Causes and Accident Description 15.2-32 15.2.10.2 Analysis of Effects and Consequences 15.2-33 15.2.10.3 Results 15.2-34 15.2.10.4 Conclusions 15.2-34
15.2.11 Sudden Feedwater Temperature Reduction 15.2-34 15.2.11.1 Identification of Causes and Accident Description 15.2-35 15.2.11.2 Analysis of Effects and Consequences 15.2-35 15.2.11.3 Results 15.2-36 15.2.11.4 Conclusions 15.2-36
15.2.12 Excessive Load Increase Incident 15.2-36 15.2.12.1 Identification of Causes and Accident Description 15.2-36 15.2.12.2 Analysis of Effects and Consequences 15.2-37 15.2.12.3 Results 15.2-38 15.2.12.4 Conclusions 15.2-39
15.2.13 Accidental Depressurization of the Reactor Coolant System 15.2-39 15.2.13.1 Identification of Causes and Accident Description 15.2-39 15.2.13.2 Analysis of Effects and Consequences 15.2-39 15.2.13.3 Results 15.2-40 15.2.13.4 Conclusions 15.2-40 DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 CONTENTS (Continued) Section Title Page iv Revision 21 September 2013 15.2.14 Accidental Depressurization of the Main Steam System 15.2-40 15.2.14.1 Identification of Causes and Accident Description 15.2-40 15.2.14.2 Analysis of Effects and Consequences 15.2-41
15.2.15 Spurious Operation of the Safety Injection System at Power 15.2-41 15.2.15.1 Spurious Safety Injection (SSI) DNBR Analysis 15.2-41 15.2.15.2 Spurious Safety Injection (SSI) Pressurizer Overfill Analysis 15.2-44
15.2.16 References 15.2-49 15.3 CONDITION III - INFREQUENT FAULTS 15.3-1 15.3.1 Loss of Reactor Coolant from Small Ruptured Pipes or from Cracks in Large Pipes that Actuate Emergency Core Cooling System 15.3-2 15.3.1.1 Acceptance Criteria 15.3-2 15.3.1.2 Identification of Causes and Accident Description 15.3-2 15.3.1.3 Analysis of Effects and Consequences 15.3-3 15.3.1.4 Results 15.3-4 15.3.1.5 Conclusions 15.3-6
15.3.2 Minor Secondary System Pipe Breaks 15.3-7 15.3.2.1 Acceptance Criteria 15.3-7 15.3.2.2 Identification of Causes and Accident Description 15.3-7 15.3.2.3 Analysis of Effects and Consequences 15.3-7 15.3.2.4 Conclusions 15.3-7
15.3.3 Inadvertent Loading of a Fuel Assembly into an Improper Position 15.3-8 15.3.3.1 Acceptance Criteria 15.3-8 15.3.3.2 Identification of Causes and Accident Description 15.3-8 15.3.3.3 Analysis of Effects and Consequences 15.3-8 15.3.3.4 Results 15.3-9 15.3.3.5 Conclusions 15.3-9
15.3.4 Complete Loss of Forced Reactor Coolant Flow 15.3-10 15.3.4.1 Acceptance Criteria 15.3-10 15.3.4.2 Identification of Causes and Accident Description 15.3-10 15.3.4.3 Analysis of Effects and Consequences 15.3-11 15.3.4.4 Results 15.3-12 15.3.4.5 Conclusions 15.3-12
DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 CONTENTS (Continued) Section Title Page v Revision 21 September 2013 15.3.5 Single Rod Cluster Control Assembly Withdrawal at Full Power 15.3-12 15.3.5.1 Acceptance Criteria 15.3-12 15.3.5.2 Identification of Causes and Accident Description 15.3-12 15.3.5.3 Analysis of Effects and Consequences 15.3-13 15.3.5.4 Results 15.3-13 15.3.5.5 Conclusions 15.3-14
15.3.6 References 15.3-14 15.4 CONDITION IV - LIMITING FAULTS 15.4-1 15.4.1 Major Reactor Coolant System Pipe Ruptures (LOCA) 15.4-2 15.4.1.1 Acceptance Criteria 15.4-2 15.4.1.2 Background of Best Estimate Large Break LOCA 15.4-3 15.4.1.3 WCOBRA/TRAC Thermal-hydraulic Computer Code 15.4-4 15.4.1.4 Thermal Analysis 15.4-6 15.4.1.4A Unit 1 Best Estimate Large Break LOCA Evaluation Model 15.4-10 15.4.1.5A Unit 1 Containment Backpressure 15.4-13 15.4.1.6A Unit 1 Reference Transient Description 15.4-13 15.4.1.7A Unit 1 Sensitivity Studies 15.4-14 15.4.1.8A Unit 1Additional Evaluations 15.4-16 15.4.1.9A Unit 1 10 CFR 50.46 Results 15.4-16 15.4.1.10A Unit 1 Plant Operating Range 15.4-17 15.4.1.4B Unit 2 Best Estimate Large Break LOCA Evaluation Model 15.4-18 15.4.1.5B Unit 2 Containment Backpressure 15.4-19 15.4.1.6B Unit 2 Confirmatory Studies 15.4-20 15.4.1.7B Unit 2 Uncertainty Evaluation 15.4-20 15.4.1.8B Unit 2 Limiting PCT Transient Description 15.4-21 15.4.1.9B Unit 2 10 CFR 50.46 Requirements 15.4-21 15.4.1.10B Unit 2 Plant Operating Range 15.4-22 15.4.1.11 Conclusions (Common) 15.4-22
15.4.2 Major Secondary System Pipe Rupture 15.4-23 15.4.2.1 Rupture of a Main Steam Line at Hot Zero Power 15.4-24 15.4.2.2 Major Rupture of a Main Feedwater Pipe 15.4-30 15.4.2.3 Rupture of a Main Steam Line at Full Power 15.4-35
15.4.3 Steam Generator Tube Rupture (SGTR) 15.4-39 15.4.3.1 Acceptance Criteria 15.4-39 15.4.3.2 Identification of Causes and Accident Description 15.4-39 15.4.3.3 Analysis of Effects and Consequences 15.4-43 DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 CONTENTS (Continued) Section Title Page vi Revision 21 September 2013 15.4.3.4 Conclusions 15.4-49 15.4.4 Single Reactor Coolant Pump Locked Rotor 15.4-50 15.4.4.1 Identification of Causes and Accident Description 15.4-50 15.4.4.2 Analysis of Effects and Consequences 15.4-50 15.4.4.3 Results 15.4-52 15.4.4.4 Conclusions 15.4-52
15.4.5 Fuel Handling Accident 15.4-53 15.4.5.1 Acceptance Criteria 15.4-53 15.4.5.2 Identification of Causes and Accident Description 15.4-53 15.4.5.3 Results 15.4-56 15.4.5.4 Conclusions 15.4-57
15.4.6 Rupture of a Control Rod Drive Mechanism Housing (Rod Cluster Control Assembly Ejection) 15.4-58 15.4.6.1 Acceptance Criteria 15.4-58 15.4.6.2 Identification of Causes and Accident Description 15.4-58 15.4.6.3 Analysis of Effects and Consequences 15.4-61 15.4.6.4 Results 15.4-64 15.4.6.5 Conclusions 15.4-65
15.4.7 Rupture of a Waste Gas Decay Tank 15.4-66 15.4.7.1 Identification of Causes and Accident Description 15.4-66 15.4.7.2 Conclusions 15.4-67
15.4.8 Rupture of a Liquid Holdup Tank 15.4-67 15.4.8.1 Identification of Causes and Accident Description 15.4-67 15.4.8.2 Conclusions 15.4-68
15.4.9 Rupture of Volume Control Tank 15.4-68 15.4.9.1 Identification of Causes and Accident Description 15.4-68 15.4.9.2 Conclusions 15.4-68
15.4.10 References 15.4-69
15.5 ENVIRONMENTAL CONSEQUENCES OF PLANT ACCIDENTS 15.5-1
15.5.1 Approach to Analyses of Radiological Effects of Accidents 15.5-2
15.5.2 Activity Inventories in the Plant Prior to Accidents 15.5-3 DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 CONTENTS (Continued) Section Title Page vii Revision 21 September 2013 15.5.3 Effects of Plutonium Inventory on Potential Accident Doses 15.5-5 15.5.4 Postaccident Meteorological Conditions 15.5-5
15.5.5 Rates of Isotope Inhalation 15.5-12
15.5.6 Population Distribution 15.5-12
15.5.7 Description of the EMERALD (Revision 1) Program 15.5-12 15.5.8 Description of the EMERALD-NORMAL Program 15.5-13 15.5.9 Description of the ISOSHLD Program 15.5-13
15.5.10 Environmental Consequences of Condition II Faults 15.5-14
15.5.11 Environmental Consequences of a Small LOCA - No Fuel Damage 15.5-15 15.5.11.1 Environmental Consequences of a Small LOCA - with Fuel Damage 15.5-16
15.5.12 Environmental Consequences of Minor Secondary System Pipe Breaks 15.5-17
15.5.13 Environmental Consequences of Inadvertent Loading of a Fuel Assembly into an Improper Position 15.5-18
15.5.14 Environmental Consequences of Complete Loss of Forced Reactor Coolant Flow 15.5-18
15.5.15 Environmental Consequences of an Underfrequency Accident 15.5-18
15.5.16 Environmental Consequences of a Single Rod Cluster Control Assembly Withdrawal at Full Power 15.5-19
15.5.17 Environmental Consequences of Major Rupture of Primary Coolant Pipes 15.5-19 15.5.17.1 Basic Events and Release Fractions 15.5-19 15.5.17.2 Spray System Iodine Removal Rates 15.5-20 15.5.17.3 Offsite Exposures from Containment Leakage 15.5-21 15.5.17.4 Containment Leakage Exposure Sensitivity Study 15.5-22 15.5.17.5 Delay of Containment Spray Initiation 15.5-23 DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 CONTENTS (Continued) Section Title Page viii Revision 21 September 2013 15.5.17.6 Offsite Exposures from Containment Shine 15.5-25 15.5.17.7 Offsite Population Exposures from Containment Leakage 15.5-25 15.5.17.8 Offsite Exposures from Post-LOCA Recirculation Loop Leakage in the Auxiliary Building 15.5-25 15.5.17.9 Offsite Exposures from Controlled Postaccident Containment Venting 15.5-33 15.5.17.10 Postaccident Control Room Exposures 15.5-35 15.5.17.11 Summary and Conclusions 15.5-38
15.5.18 Environmental Consequences of a Major Steam Pipe Rupture 15.5-38 15.5.18.1 Radiological Assessment for Accident-Induced Leakage 15.5-39 15.5.19 Environmental Consequences of a Major Rupture of a Main Feedwater Pipe 15.5-43
15.5.20 Environmental Consequences of a Steam Generator Tube Rupture (SGTR) 15.5-44 15.5.20.1 Offsite Exposures 15.5-44 15.5.20.2 Control Room Exposures 15.5-48
15.5.21 Environmental Consequences of a Locked Rotor Accident 15.5-50
15.5.22 Environmental Consequences of a Fuel Handling Accident 15.5-53 15.5.22.1 Fuel Handling Accident in the Fuel Handling Area 15.5-53 15.5.22.2 Fuel Handling Accident Inside Containment 15.5-55 15.5.22.3 Conclusion, Fuel Handling Accidents 15.5-57
15.5.23 Environmental Consequences of a Rod Ejection Accident 15.5-57
15.5.24 Environmental Consequences of a Rupture of a Waste Gas Decay Tank 15.5-59
15.5.25 Environmental Consequences of a Rupture of a Liquid Holdup Tank 15.5-60
15.5.26 Environmental Consequences of a Rupture of a Volume Control Tank 15.5-60
15.5.27 Summary of Analyses of Environmental Consequences of Potential Plant Accidents 15.5-61
15.5.28 References 15.5-62 DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 TABLES Table Title ix Revision 21 September 2013 15.1-1 Nuclear Steam Supply System Power Ratings 15.1-2 Trip Points and Time Delays to Trip Assumed in Accident Analyses
15.1-3 Deleted in Revision 10
15.1-4 Summary of Initial Conditions and Computer Codes Used
15.2-1 Time Sequence of Events for Condition II Events 15.2-2 Deleted in Revision 6 15.3-1 Time Sequence of Events - Small Break LOCA
15.3-2 Fuel Cladding Results - Small Break LOCA
15.3-3 Time Sequence of Events for Condition III Events
15.4-A Deleted in Revision 12
15.4-B Deleted in Revision 12
15.4.1-1A Unit 1 Best Estimate Large Break LOCA Time Sequence of Events
15.4.1-1B Unit 2 Best Estimate Large Break Sequence of Events for Limiting PCT Case
15.4.1-2A Unit 1 Best Estimate Large Break LOCA Analysis Results
15.4.1-2B Unit 2 Best Estimate Large Break LOCA Analysis Results
15.4.1-3A Unit 1 Key Best Estimate Large Break LOCA Parameters and Reference Transient Assumptions 15.4.1-3B Unit 2 Key Best Estimate Large Break LOCA Parameters and Initial Transient Assumptions 15.4.1-4A Unit 1 Sample of Best Estimate Sensitivity Analysis Results
15.4.1-4B Unit 2 Results From Confirmatory Studies DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 TABLES (Continued) Table Title x Revision 21 September 2013 15.4.1-5A Unit 1 Containment Back Pressure Analysis Input Parameters Used for Best Estimate LOCA Analysis 15.4.1-5B Unit 2 Containment Back Pressure Analysis Input Parameters Used for Best Estimate LBLOCA Analysis
15.4-6 Deleted in Revision 18
15.4-7 Deleted in Revision 18 15.4.1-7A Unit 1 Plant Operating Range Allowed by the Best-Estimate Large Break LOCA Analysis 15.4.1-7B Unit 2 Plant Operating Range Allowed by the Best-Estimate Large Break LOCA Analysis 15.4-8 Time Sequence of Events for Major Secondary System Pipe Ruptures
15.4-8A Deleted in Revision 19
15.4-9 Deleted in Revision 19
15.4-10 Summary of Results for Locked Rotor Transient
15.4-11 Typical Parameters Used in the VANTAGE 5 Reload Analysis of the Rod Cluster Control Assembly Ejection Accident 15.4-12 Operator Action Times for Design Basis SGTR Analysis
15.4-13 Deleted in Revision 20
15.4-13A Timed Sequence of Events - SGTR MTO Analysis
15.4-13B Timed Sequence of Events - SGTR Dose Analysis 15.4-14 Mass Release Results - SGTR Dose Analysis
15.4-14A Deleted in Revision 19
15.5-1 Reactor Coolant Fission and Corrosion Product Activities During Steady State Operation and Plant Shutdown Operation DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 TABLES (Continued) Table Title xi Revision 21 September 2013 15.5-2 Results of Study of Effects of Plutonium on Accident Doses 15.5-3 Design Basis Postaccident Atmospheric Dilution Factors
15.5-4 Expected Postaccident Atmospheric Dilution Factors
15.5-5 Atmospheric Dilution Factors
15.5-6 Assumed Onsite Atmospheric Dilution Factors for the Control Room 15.5-7 Breathing Rates Assumed in Analysis 15.5-8 Population Distribution
15.5-9 Summary of Offsite Doses from Loss of Electrical Load
15.5-10 Summary of Offsite Doses from a Small Loss-of-Coolant Accident
15.5-11 Summary of Offsite Doses from an Underfrequency Accident
15.5-12 Summary of Offsite Doses from a Single Rod Cluster Control Assembly Withdrawal
15.5-13 Calculated Activity Releases from LOCA - Expected Case
15.5-14 Calculated Activity Releases from LOCA - Design Basis Case
15.5-15 Thyroid Dose, 2-hour, Containment Leakage, Expected Case
15.5-16 Thyroid Dose, 2-hour, Containment Leakage, Design Basis Case
15.5-17 Thyroid Dose, 30-day, Containment Leakage, Expected Case
15.5-18 Thyroid Dose, 30-day, Containment Leakage, Design Basis Case
15.5-19 Whole Body Dose, 2-hour, Containment Leakage, Expected Case
15.5-20 Whole Body Dose, 2-hour, Containment Leakage, Design Basis Case
15.5-21 Whole Body Dose, 30-day, Containment Leakage, Expected Case
15.5-22 Whole Body Dose, 30-day, Containment Leakage, Design Basis Case DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 TABLES (Continued) Table Title xii Revision 21 September 2013 15.5-23 Summary of Exposure from Containment Leakage 15.5-24 Assumptions Used to Calculate Offsite Exposures from Post-LOCA Circulation Loop Leakage in the Auxiliary Building 15.5-25 Offsite Exposures from Post-LOCA Circulation Loop Leakage in the Auxiliary Building
15.5-26 Percentage Occurrence of Wind Direction and Calm Winds Expressed as Percentage of Total Hourly Observations Within Each Season at the Site (250-ft Level) 15.5-27 Diablo Canyon Power Plant Site Probability of Persistence Offshore Wind Direction Sectors (250-ft Level) 15.5-28 Assumptions Used to Calculate Onshore Controlled Containment Venting
15.5-29 Onshore Controlled Containment Venting Exposures
15.5-30 Atmospheric Dispersion Factors for Onshore Controlled Containment Venting (Stability Category D) 15.5-31 Control Room Infiltration Assumed for Radiological Exposure Calculations
15.5-32 Assumptions Used to Calculate Postaccident Control Room Radiological Exposures 15.5-33 Estimated Postaccident Exposure to Control Room Personnel
15.5-34 Steam Releases Following a Major Steam Line Break
15.5-35 Deleted in Revision 16
15.5-36 Deleted in Revision 16
15.5-37 Deleted in Revision 7
15.5-38 Deleted in Revision 7
15.5-39 Deleted in Revision 7
15.5-40 Long-term Activity Release Fractions for Fuel Failure Accidents DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 TABLES (Continued) Table Title xiii Revision 21 September 2013 15.5-41 Activity Releases Following a Locked Rotor Accident 15.5-42 Summary of Offsite Doses from a Locked Rotor Accident
15.5-43 Deleted in Revision 16
15.5-44 Composite Source Term for Fuel Handling Accident in the Fuel Handling Building 15.5-45 Assumptions for Fuel Handling Accident in the Fuel Handling Area 15.5-46 Deleted in Revision 16
15.5-47 Summary of Doses from Fuel Handling Accident in the Fuel Handling Area
15.5-48 Design Inputs and Assumptions for Fuel Handling Accident Inside Containment 15.5-49 Activity Releases from Fuel Handling Accident Inside Containment (LOPAR Fuel) 15.5-50 Summary of Offsite Doses from Fuel Handling Accident Inside Containment 15.5-51 Activity Releases Following A Rod Ejection Accident
15.5-52 Summary of Offsite Doses from a Rod Ejection Accident
15.5-53 Summary of Offsite Doses from a Rupture of a Gas Decay Tank
15.5-54 Deleted in Revision 11
15.5-55 Deleted in Revision 11
15.5-56 Summary of Offsite Doses from Rupture of a Liquid Holdup Tank
15.5-57 Summary of Offsite Doses from Rupture of a Volume Control Tank
15.5-58 Deleted in Revision 16
15.5-59 Deleted in Revision 16
DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 TABLES (Continued) Table Title xiv Revision 21 September 2013 15.5-60 Deleted in Revision 16 15.5-61 Offsite Doses from Post-LOCA Containment Leakage
15.5-62 Offsite Doses from Post-LOCA Large RHR Pump Seal Leakage
15.5-63 Post-LOCA Doses with Margin Recirculation Loop Leakage
15.5-64 Parameters Used in Evaluating Radiological Consequences For SGTR Analysis 15.5-65 Iodine Specific Activities in the Primary and Secondary Coolant - SGTR Analysis 15.5-66 Iodine Spike Appearance Rates - SGTR Analysis
15.5-67 Noble Gas Specific Activities in the Reactor Coolant Based on 1% Fuel Defects - SGTR Analysis 15.5-68 Atmospheric Dispersion Factors and Breathing Rates - SGTR Analysis
15.5-69 Thyroid Dose Conversion Factors and Whole Body Dose Conversion Factors - SGTR Analysis 15.5-70 Average Gamma and Beta Energy for Noble Gases - SGTR Analysis
15.5-71 Offsite Radiation Doses from SGTR Accident
15.5-72 Control Room Parameters Used in Evaluating Radiological Consequences for SGTR Analysis 15.5-73 Deleted in Revision 16
15.5-74 Control Room Radiation Doses from Airborne Activity in SGTR Accident
15.5-75 Summary of Post-LOCA Doses from Various Pathways (DF of 100)
DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES Figure Title xv Revision 21 September 2013 15.1-1 Illustration of Overpower and Overtemperature T Protection 15.1-2 Rod Position Versus Time on Reactor Trip
15.1-3 Normalized RCCA Reactivity Worth Versus Percent Insertion
15.1-4 Normalized RCCA Bank Reactivity Worth Versus Time After Trip
15.1-5 Doppler Power Coefficient Used in Accident Analysis
15.1-6 Residual Decay Heat 15.1-7 1979 ANS Decay Heat Curve
15.1-8 Fuel Rod Cross Section
15.2-1 Deleted in Revision 6
15.2-2 Deleted in Revision 6
15.2-3 Deleted in Revision 6
15.2-4 Deleted in Revision 6
15.2-5 Deleted in Revision 6
15.2-6 Deleted in Revision 3
15.2-7 Deleted in Revision 3
15.2-8 Deleted in Revision 3
15.2-9 Deleted in Revision 3
15.2-10 Deleted in Revision 3
15.2-11 Deleted in Revision 6
15.2-12 Deleted in Revision 6
15.2-13 Deleted in Revision 6
DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xvi Revision 21 September 2013 15.2-14 Deleted in Revision 6 15.2-15 Deleted in Revision 6
15.2-16 Deleted in Revision 6
15.2-17 Deleted in Revision 6
15.2-18 Deleted in Revision 6 15.2-19 Deleted in Revision 6 15.2-20 Deleted in Revision 3
15.2-21 Deleted in Revision 3
15.2-22 Deleted in Revision 3
15.2-23 Deleted in Revision 3
15.2-24 Deleted in Revision 3
15.2-25 Deleted in Revision 3
15.2-26 Deleted in Revision 3
15.2-27 Deleted in Revision 3
15.2-28 Deleted in Revision 3
15.2-29 Deleted in Revision 6
15.2-30 Deleted in Revision 6
15.2-31 Deleted in Revision 6
15.2-32 Deleted in Revision 6
15.2-33 Deleted in Revision 6
15.2-34 Deleted in Revision 6
DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xvii Revision 21 September 2013 15.2-35 Deleted in Revision 6 15.2-36 Deleted in Revision 6
15.2-37 Deleted in Revision 6
15.2-38 Deleted in Revision 3
15.2-39 Deleted in Revision 3 15.2-40 Deleted in Revision 3 15.2-41 Deleted in Revision 6
15.2-42 Deleted in Revision 6
15.2-43 Deleted in Revision 6
15.2-44 Deleted in Revision 6
15.2-45 Deleted in Revision 6
15.2-46 Deleted in Revision 6
15.2-47 Deleted in Revision 3
15.2-48 Deleted in Revision 6
15.2-49 Deleted in Revision 6
15.2-50 Deleted in Revision 6
15.2-51 Deleted in Revision 6
15.2-52 Deleted in Revision 6
15.2-53 Deleted in Revision 6
15.2-54 Deleted in Revision 6
15.2-55 Deleted in Revision 6
DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xviii Revision 21 September 2013 15.2-56 Deleted in Revision 6 15.2-57 Deleted in Revision 6
15.2-58 Deleted in Revision 6
15.2-59 Deleted in Revision 6
15.2-60 Deleted in Revision 6 15.2-61 Deleted in Revision 6 15.2-62 Deleted in Revision 6
15.2-63 Deleted in Revision 6
15.2-64 Deleted in Revision 6
15.2-65 Deleted in Revision 6
15.2-66 Deleted in Revision 6
15.2-67 Deleted in Revision 6
15.2-68 Deleted in Revision 6
15.2-69 Deleted in Revision 6
15.2-70 Deleted in Revision 6
15.2-71 Deleted in Revision 6
15.2.1-1 Uncontrolled Rod Withdrawal from a Subcritical Condition - Neutron Flux Versus Time 15.2.1-2 Uncontrolled Rod Withdrawal from a Subcritical Condition - Thermal Flux Versus Time 15.2.1-3 Uncontrolled Rod Withdrawal from a Subcritical Condition - Temperature Versus Time, Reactivity Insertion Rate 75 x 10-5K/sec DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xix Revision 21 September 2013 15.2.2-1 Rod Withdrawal at Power - Minimum Feedback, 75 pcm/sec Insertion Rate - Pressurizer Pressure and Neutron Flux Versus Time 15.2.2-2 Rod Withdrawal at Power - Minimum Feedback, 75 pcm/sec Insertion Rate - DNBR and Tavg Versus Time 15.2.2-3 Rod Withdrawal at Power - Minimum Feedback, 3 pcm/sec Insertion Rate - Pressurizer Pressure and Neutron Flux Versus Time 15.2.2-4 Rod Withdrawal at Power - Minimum Feedback, 3 pcm/sec Insertion Rate - DNBR and Tavg Versus Time 15.2.2-5 Rod Withdrawal at Power - Reactivity Insertion Rate vs. DNBR for 100% Power Cases 15.2.2-6 Rod Withdrawal at Power - Reactivity Insertion Rate vs. DNBR for 60% Power Cases 15.2.2-7 Rod Withdrawal at Power - Reactivity Insertion Rate vs. DNBR for 10% Power Cases 15.2.3-1 Transient Response to Dropped Rod Cluster Control Assembly, Nuclear Power and Core Heat Flux Versus Time 15.2.3-2 Transient Response to Dropped Rod Cluster Control Assembly, Average Coolant Temperature and Pressurizer Pressure Versus Time 15.2.4-1 Variation in Reactivity Insertion Rate with Initial Boron Concentration for a Dilution Rate of 262 gpm 15.2.5-1 All Loops Operating, Two Loops Coasting Down - Core Flow Versus Time
15.2.5-2 All Loops Operating, Two Loops Coasting Down - Failed Loop Flow Versus Time 15.2.5-3 All Loops Operating, Two Loops Coasting Down - Heat Flux Versus Time
15.2.5-4 All Loops Operating, Two Loops Coasting Down - Nuclear Power Versus Time 15.2.5-5 All Loops Operating, Two Loops Coasting Down, DNBR Versus Time
DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xx Revision 21 September 2013 15.2.6-1 Nuclear Power Transient During Startup of an Inactive Loop 15.2.6-2 Average and Hot Channel Heat Flux Transients During Startup of an Inactive Loop 15.2.6-3 Core Flow During Startup of an Inactive Loop
15.2.6-4 Pressurizer Pressure Transient and Core Average Temperature Transient During Startup of an Inactive Loop 15.2.6-5 DNBR Transient During Startup of an Inactive Loop 15.2.7-1 Loss of Load With Pressurizer Spray and Power Operated Relief Valve for DNB Concern at Beginning of Life - DNBR and Nuclear Power Versus Time 15.2.7-2 Loss of Load With Pressurizer Spray and Power Operated Relief Valve for DNB Concern at Beginning of Life - Average Core Temperature and Pressurizer Water Volume Versus Time 15.2.7-3 Loss of Load With Pressurizer Spray and Power Operated Relief Valve for DNB Concern at End of Life - DNBR, Steam Temperature, Pressurizer Pressure, and Nuclear Power Versus Time 15.2.7-4 Loss of Load With Pressurizer Spray and Power Operated Relief Valve for DNB Concern at End of Life - Average Core Temperature and Pressurizer Water Volume Versus Time 15.2.7-5 Deleted in Revision 16
15.2.7-6 Deleted in Revision 16
15.2.7-7 Deleted in Revision 16
15.2.7-8 Deleted in Revision 16
15.2.7-9 Loss of Load Without Pressurizer Spray and Power Operated Relief Valves for Overpressure Concern at Beginning of Life - Reactor Power, Pressurizer Pressure, and Lower Plenum Pressure Versus Time DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xxi Revision 21 September 2013 15.2.7-10 Loss of Load With Pressurizer Spray and Power Operated Relief Valves for Overpressure Concern at Beginning of Life - Steam Generator Steam and Water Pressure Versus Time 15.2.7-11 Loss of Load With Pressurizer Spray and Power Operated Relief Valves for Overpressure Concern at Beginning of Life - Reactor Power, Pressurizer Pressure, and Lower Plenum Pressure Versus Time 15.2.7-12 Loss of Load With Pressurizer Spray and Power Operated Relief Valves for Overpressure Concern at Beginning of Life - Steam Generator Steam and Water Pressure Versus Time 15.2.8A-1 Deleted in Revision 19
15.2.8-1 Loss of Normal Feedwater - RCS Temperatures and Steam Generator Mass Transients 15.2.8A-2 Deleted in Revision 19
15.2.8-2 Loss of Normal Feedwater - Pressurizer Water Volume and Pressurizer Pressure Transients 15.2.8A-3 Deleted in Revision 19
15.2.8-3 Loss of Normal Feedwater - Nuclear Power and Steam Generator Pressure Transients 15.2.10A-1 Deleted in Revision 19
15.2.10-1 Feedwater Control Valve Malfunction - Full Power, Manual Rod Control, Nuclear Power and Core Heat Flux Transients 15.2.10A-2 Deleted in Revision 19
15.2.10-2 Feedwater Control Valve Malfunction - Full Power, Manual Rod Control, Pressurizer Pressure and Faulted Loop Delta-T Transients 15.2.10-3 Feedwater Control Valve Malfunction - Full Power, Manual Rod Control, Core Average Temperature and DNBR Transients 15.2.11-1 Excessive Load Increase Without Control Action at Beginning of Life, (MTC), Minimum Feedback, T and Tavg as a Function of Time DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xxii Revision 21 September 2013 15.2.11-2 Excessive Load Increase Without Control Action at Beginning of Life, (MTC), Minimum Feedback, DNBR, Nuclear Power and Pressurizer Pressure as a Function of Time 15.2.11-3 Excessive Load Increase Without Control Action at End of Life, (MTC), Maximum Feedback, T and Tavg as a Function of Time 15.2.11-4 Excessive Load Increase Without Control Action at End of Life, (MTC), Maximum Feedback, DNBR, Nuclear Power and Pressurizer Pressure as a Function of Time 15.2.11-5 Excessive Load Increase With Reactor Control at Beginning of Life, (MTC), Minimum Feedback, T and Tavg as a Function of Time 15.2.11-6 Excessive Load Increase With Reactor Control at Beginning of Life, (MTC), Minimum Feedback, DNBR, Nuclear Power and Pressurizer Pressure as a Function of Time 15.2.11-7 Excessive Load Increase With Reactor Control at End of Life, (MTC), Maximum Feedback, T and Tavg as a Function of Time 15.2.11-8 Excessive Load Increase With Reactor Control at End of Life, (MTC), Maximum Feedback, DNBR, Nuclear Power and Pressurizer Pressure as a Function of Time 15.2.12-1 Nuclear Power and DNBR Transients for Accidental Depressurization of the Reactor Coolant System 15.2.12-2 Pressurizer Pressure and Core Average Temperature Transients for Accidental Depressurization of the Reactor Coolant System 15.2.13-1 Deleted in Revision 17.
15.2.13-2 Deleted in Revision 17.
15.2.13-3 Deleted in Revision 17.
15.2.14-1 Deleted in Revision 16.
15.2.14-2 Deleted in Revision 16. DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xxiii Revision 21 September 2013 15.2.15-1 Spurious Actuation of Safety Injection System at Power DNBR Analysis - Pressurizer Water Volume and Pressurizer Pressure Versus Time 15.2.15-2 Spurious Actuation of Safety Injection System at Power DNBR Analysis - Nuclear Power, Steam Flow, and Core Water Temperature Versus Time 15.2.15-3 SSI Pressurizer Overfill Analysis - Typical Pressurizer Pressure Response 15.2.15-4 SSI Pressurizer Overfill Analysis - Typical Pressurizer Liquid Volume Response 15.2.15-5 SSI Pressurizer Overfill Analysis - Typical RCS Average Temperature Response 15.3-1 Safety Injection Flowrate for Small Break LOCA 15.3-2 RCS Depressurization 4-inch Cold Leg Break
15.3-3 Core Mixture Elevation 4-inch Cold Leg Break
15.3-4 Cladding Temperature Transient 4-inch Cold Leg Break
15.3-5 Deleted in Revision 13.
15.3-6 Deleted in Revision 13.
15.3-7 Deleted in Revision 13.
15.3-8 LOCA Core Power Transient
15.3-9 RCS Depressurization 3-inch Cold Leg Break
15.3-10 Deleted in Revision 13.
15.3-11 Core Mixture Elevation 3-inch Cold Leg Break
15.3-12 Deleted in Revision 13.
15.3-13 Clad Temperature Transient 3 inch Cold Leg Break
15.3-14 Deleted in Revision 13. DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xxiv Revision 21 September 2013 15.3-14a Deleted in Revision 13. 15.3-14b Deleted in Revision 13.
15.3-14c Deleted in Revision 13.
15.3-14d Deleted in Revision 13.
15.3-14e Deleted in Revision 13. 15.3-14f Deleted in Revision 13. 15.3-15 Interchange Between Region 1 and Region 3 Assembly
15.3-16 Interchange Between Region 1 and Region 2 Assembly - Burnable Poison Rods Being Retained by the Region 2 Assembly 15.3-17 Interchange Between Region 1 and Region 2 Assembly - Burnable Poison Rods Being Transferred to the Region 1 Assembly 15.3-18 Enrichment Error - A Region 2 Assembly Loaded into the Core Central Position 15.3-19 Loading a Region 2 Assembly into a Region 1 Position Near Core Periphery 15.3-20 Deleted in Revision 3
15.3-21 Deleted in Revision 3
15.3-22 Deleted in Revision 3
15.3-23 Deleted in Revision 3
15.3-24 Deleted in Revision 3
15.3-25 Deleted in Revision 3
15.3-26 Deleted in Revision 6
15.3-27 Deleted in Revision 6
DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xxv Revision 21 September 2013 15.3-28 Deleted in Revision 6 15.3-29 Deleted in Revision 6
15.3-30 Deleted in Revision 6
15.3-31 Deleted in Revision 6
15.3-32 Deleted in Revision 6 15.3-33 Top Core Node Vapor Temperature 3-inch Cold Leg Break 15.3-34 Rod Film Coefficient 3-inch Cold Leg Break
15.3-35 Hot Spot Fluid Temperature 3 inch Cold Leg Break
15.3-36 Break Mass Flow 3-inch Cold Leg Break
15.3-37 RCS Depressurization 2-inch Cold Leg Break 15.3-38 Core Mixture Elevation 2-inch Cold Leg Break
15-3-39 Cladding Temperature Transient 2-inch Cold Leg Break
15-3-40 RCS Depressurization 6-inch Cold Leg Break
15-3-41 Core Mixture Elevation 6-inch Cold Leg Break
15.3.4-1 All Loops Operating, All Loops Coasting Down - Flow Coastdown Versus Time 15.3.4-2 All Loops Operating, All Loops Coasting Down - Heat Flux Versus Time
15.3.4-3 All Loops Operating, All Loops Coasting Down - Nuclear Power Versus Time 15.3.4-4 All Loops Operating, All Loops Coasting Down - DNBR Versus Time
15.4.1-1A Unit 1 Reference Transient PCT and PCT Location
15.4.1-1B Unit 2 Limiting PCT Case and PCT Location
DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xxvi Revision 21 September 2013 15.4.1-2A Unit 1 Reference Transient Vessel Side Break Flow 15.4.1-2B Unit 2 Limiting PCT Case Vessel Side Break Flow
15.4.1-3A Unit 1 Reference Transient Loop Side Break Flow
15.4.1-3B Unit 2 Limiting PCT Case Loop Side Break Flow
15.4.1-4A Unit 1 Reference Transient Broken and Intact Loop Pump Void Fraction 15.4.1-4B Unit 2 Limiting PCT Case Broken and Intact Loop Pump Void Fraction 15.4.1-5A Unit 1 Reference Transient Hot Assembly/Top of Core Vapor Flow
15.4.1-5B Unit 2 Limiting PCT Case Hot Assembly/Top of Core Vapor Flow
15.4.1-6A Unit 1 Reference Transient Pressurizer Pressure
15.4.1-6B Unit 2 Limiting PCT Case Pressurizer Pressure
15.4.1-7A Unit 1 Reference Transient Lower Plenum Collapsed Liquid Level
15.4.1-7B Unit 2 Limiting PCT Case Lower Plenum Collapsed Liquid Level
15.4.1-8A Unit 1 Reference Transient Vessel Water Mass
15.4-1-8B Unit 2 Limiting PCT Case Vessel Fluid Mass
15.4.1-9A Unit 1 Reference Transient Loop 1 Accumulator Flow
15.4.1-9B Unit 2 Limiting PCT Case Loop 1 Accumulator Flow
15.4.1-10A Unit 1 Reference Transient Loop 1 Safety Injection Flow
15.4.1-10B Unit 2 Limiting PCT Case Loop 1 Safety Injection Flow
15.4.1-11A Unit 1 Reference Transient Core Average Channel Collapsed Liquid Level
15.4.1-11B Unit 2 Limiting PCT Case Core Average Channel Collapsed Liquid Level
15.4.1-12A Unit 1 Reference Transient Loop 1 Downcomer Collapsed Liquid Level
DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xxvii Revision 21 September 2013 15.4.1-12B Unit 2 Limiting PCT Case Loop 1 Downcomer Collapsed Liquid Level 15.4.1-13A Unit 1 Total ECCS Flow (3 Lines Injecting)
15.4.1-13B Unit 2 Total ECCS Flow (3 Lines Injecting)
15.4.1-14A Unit 1 Reference Transient Pressure Transient
15.4.1-14B Unit 2 Lower Bound COCO Containment Pressure Transient 15.4.1-15A Unit 1 Axial Power Distribution Limits 15.4.1-15B Unit 2 Axial Power Distribution Limits
15.4-2 Deleted in Revision 18
15.4-3 Deleted in Revision 18
15.4-4 Deleted in Revision 18
15.4-5 Deleted in Revision 18
15.4-5A Deleted in Revision 12
15.4-5B Deleted in Revision 12
15.4-6 Deleted in Revision 18
15.4-7 Deleted in Revision 18
15.4-8 Deleted in Revision 18
15.4-9 Deleted in Revision 18
15.4-9A Deleted in Revision 12
15.4-9B Deleted in Revision 12
15.4-10 Deleted in Revision 18
15.4-11 Deleted in Revision 18
DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xxviii Revision 21 September 2013 15.4-12 Deleted in Revision 18 15.4-13 Deleted in Revision 18
15.4-13A Deleted in Revision 12
15.4-13B Deleted in Revision 12
15.4-14 Deleted in Revision 18 15.4-15 Deleted in Revision 18 15.4-16 Deleted in Revision 12
15.4-17 Deleted in Revision 12
15.4-17A Deleted in Revision 12
15.4-18 Deleted in Revision 12
15.4-19 Deleted in Revision 12
15.4-20 Deleted in Revision 12
15.4-21 Deleted in Revision 12
15.4-21A Deleted in Revision 12
15.4-22 Deleted in Revision 12
15.4-23 Deleted in Revision 12
15.4-24 Deleted in Revision 12
15.4-25 Deleted in Revision 12
15.4-25A Deleted in Revision 12
15.4-26 Deleted in Revision 12
15.4-27 Deleted in Revision 12
DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xxix Revision 21 September 2013 15.4-28 Deleted in Revision 12 15.4-29 Deleted in Revision 12
15.4-29A Deleted in Revision 12
15.4-29B Deleted in Revision 12
15.4-30 Deleted in Revision 12 15.4-31 Deleted in Revision 12 15.4-32 Deleted in Revision 12
15.4-33 Deleted in Revision 12
15.4-33A Deleted in Revision 12
15.4-33B Deleted in Revision 12
15.4-34 Deleted in Revision 12
15.4-35 Deleted in Revision 12
15.4-36 Deleted in Revision 12
15.4-37 Deleted in Revision 12
15.4-37A Deleted in Revision 12
15.4-38 Deleted in Revision 12
15.4-39 Deleted in Revision 12
15.4-40 Deleted in Revision 12
15.4-41 Deleted in Revision 12
15.4-41A Deleted in Revision 12
15.4-42 Deleted in Revision 12
DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xxx Revision 21 September 2013 15.4-43 Deleted in Revision 12 15.4-44 Deleted in Revision 12
15.4-45 Deleted in Revision 12
15.4-45A Deleted in Revision 12
15.4-46 Deleted in Revision 12 15.4-47 Deleted in Revision 12 15.4-48 Deleted in Revision 12
15.4-49 Deleted in Revision 12
15.4-49A Deleted in Revision 12
15.4-50 Deleted in Revision 12
15.4-51 Deleted in Revision 12
15.4-51A Deleted in Revision 12
15.4-52 Deleted in Revision 12
15.4-53 Deleted in Revision 12
15.4-53A Deleted in Revision 12
15.4-54 Deleted in Revision 12
15.4-55 Deleted in Revision 12
15.4-56 Deleted in Revision 12
15.4-57 Deleted in Revision 12
15.4-57A Deleted in Revision 12
15.4-58 Deleted in Revision 12
DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xxxi Revision 21 September 2013 15.4-59 Deleted in Revision 12 15.4-59A Deleted in Revision 12
15.4-60 Deleted in Revision 12
15.4-61 Deleted in Revision 12
15.4-61A Deleted in Revision 12 15.4-62 Deleted in Revision 12 15.4-63 Deleted in Revision 6
15.4-64 Deleted in Revision 6
15.4-65 Deleted in Revision 6
15.4-66 Deleted in Revision 6
15.4-67 Deleted in Revision 6
15.4-68 Deleted in Revision 6
15.4-69 Deleted in Revision 6
15.4-70 Deleted in Revision 6
15.4-71 Deleted in Revision 6
15.4-72 Deleted in Revision 6
15.4-73 Deleted in Revision 6
15.4-74 Deleted in Revision 6
15.4-75 Deleted in Revision 2
15.4-75a Deleted in Revision 3
15.4-75b Deleted in Revision 3
DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xxxii Revision 21 September 2013 15.4-75c Deleted in Revision 3 15.4-75d Deleted in Revision 3
15.4-75e Deleted in Revision 3
15.4-75f Deleted in Revision 3
15.4-75g Deleted in Revision 3 15.4-75h Deleted in Revision 3 15.4-75i Deleted in Revision 6
15.4-75j Deleted in Revision 6
15.4-75k Deleted in Revision 6
15.4-75l Deleted in Revision 6
15.4-75m Deleted in Revision 6
15.4-75n Deleted in Revision 6
15.4-75o Deleted in Revision 6
15.4-75p Deleted in Revision 6
15.4-76 Deleted in Revision 7
15.4-77 Deleted in Revision 7
15.4-78 Deleted in Revision 3
15.4-79 Deleted in Revision 3
15.4-80 Deleted in Revision 3
15.4-81 Deleted in Revision 3
15.4-82 Deleted in Revision 3
DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xxxiii Revision 21 September 2013 15.4-83 Deleted in Revision 3 15.4-84 Deleted in Revision 3
15.4-85 Deleted in Revision 3
15.4-86 Deleted in Revision 3
15.4-87 Deleted in Revision 3 15.4-88 Deleted in Revision 3 15.4-89 Deleted in Revision 6
15.4-90 Deleted in Revision 6
15.4-91 Deleted in Revision 6
15.4-92 Deleted in Revision 6
15.4-93 Deleted in Revision 6
15.4-94 Deleted in Revision 6
15.4-95 Deleted in Revision 6
15.4-96 Deleted in Revision 6
15.4-97 Deleted in Revision 6
15.4-98 Deleted in Revision 6
15.4-99 Deleted in Revision 16
15.4-100 Deleted in Revision 16
15.4-101 Deleted in Revision 16
15.4-102 Deleted in Revision 16
15.4-103 Deleted in Revision 16
DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xxxiv Revision 21 September 2013 15.4-104 Deleted In Revision 16 15.4-105 Deleted in Revision 16
15.4-106 Deleted in Revision 16
15.4-107 Deleted in Revision 16
15.4-108 Deleted in Revision 16 15.4-109 Deleted in Revision 16 15.4.2A-1 Deleted in Revision 19
15.4.2-1 Rupture of a Main Steam Line - Variation of Reactivity with Power at Constant Core Average Temperature 15.4.2A-2 Deleted in Revision 19
15.4.2-2 Rupture of a Main Steam Line - Variation of Keff with Core Average Temperature 15.4.2A-3 Deleted in Revision 19
15.4.2-3 Rupture of a Main Steam Line - Safety Injection Curve
15.4.2A-4A Deleted in Revision 19
15.4.2A-4B Deleted in Revision 19
15.4.2A-4C Deleted in Revision 19
15.4.2A-4D Deleted in Revision 19
15.4.2-4 Rupture of a Main Steam Line with Offsite Power Available - Core Heat Flux and Steam Flow Transients 15.4.2A-5 Deleted in Revision 19
15.4.2-5 Rupture of a Main Steam Line with Offsite Power Available - Loop Average Temperature and reactor Coolant Pressure Transients DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xxxv Revision 21 September 2013 15.4.2-6 Rupture of a Main Steam Line with Offsite Power Available - Reactivity and Core Boron Transients 15.4.2A-7 Deleted in Revision 19
15.4.2-7 Rupture of a Main Steam Line without Offsite Power Available - Core Heat Flux and Steam Flow Transients 15.4.2A-8 Deleted in Revision 19 15.4.2-8 Rupture of a Main Steam Line without Offsite Power Available - Loop Average Temperature and Reactor Coolant Pressure Transients 15.4.2A-9 Deleted in Revision 19
15.4.2-9 Rupture of a Main Steam Line without Offsite Power Available - Reactivity and Core Boron Transients 15.4.2A-10 Deleted in Revision 19
15.4.2-10 Main Feedline Rupture with Offsite Power Available - Nuclear Power and Core Heat Flux Transients 15.4.2A-11 Deleted in Revision 19
15.4.2-11 Main Feedline Rupture with Offsite Power Available - Pressurizer Pressure and Core Water Volume Transients 15.4.2A-12 Deleted in Revision 19
15.4.2-12 Main Feedline Rupture with Offsite Power Available - Reactor Coolant Temperature Transients for the Faulted and Intact Loops 15.4.2A-13 Deleted in Revision 19
15.4.2-13 Main Feedline Rupture with Offsite Power Available - Steam Generator Pressure and Total mass Transients 15.4.2A-14 Deleted in Revision 19
15.4.2-14 Main Feedline Rupture without Offsite Power Available - Nuclear Power and Core Heat Flux Transients DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xxxvi Revision 21 September 2013 15.4.2A-15 Deleted in Revision 19 15.4.2-15 Main Feedline Rupture without Offsite Power Available - Pressurizer Pressure and Water Volume Transients 15.4.2A-16 Deleted in Revision 19
15.4.2-16 Main Feedline Rupture without Offsite Power Available - Reactor Coolant Temperature Transients for the Faulted and Intact Loops 15.4.2A-17 Deleted in Revision 19 15.4.2-17 Main Feedline Rupture without Offsite Power Available - Steam Generator Pressure and Total Mass Transients 15.4.2A-18 Deleted in Revision 19 15.4.2-18 Main Steam Line Rupture at Full Power, 0.49 ft2 Break - Nuclear Power and Core Heat Flux Transients 15.4.2-19 Main Steam Line Rupture at Full Power, 0.49 ft2 Break - Pressurizer Pressure and Water Volume Transients 15.4.2-20 Main Steam Line Rupture at Full Power, 0.49 ft2 Break - Reactor Vessel Inlet Temperature and Loop Average Temperature Transients 15.4.2-21 Main Steam Line Rupture at Full Power, 0.49 ft2 Break - Total Steam Flow and Steam Pressure Transients 15.4.3A-1 Deleted in Revision 19
15.4.3-1 Deleted in Revision 20
15.4.3-1A Pressurizer Level - SGTR MTO Analysis
15.4.3-1B Pressurizer Level - SGTR Dose Analysis
15.4.3A-2 Deleted in Revision 19
15.4.3-2 Deleted in Revision 20
15.4.3-2A Pressurizer Pressure - SGTR MTO Analysis DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xxxvii Revision 21 September 2013 15.4.3-2B Pressurizer Pressure - SGTR Dose Analysis 15.4.3A-3 Deleted in Revision 19
15.4.3-3 Deleted in Revision 20
15.4.3-3A Secondary Pressure - SGTR MTO Analysis
15.4.3-3B Secondary Pressure - SGTR Dose Analysis 15.4.3A-4 Deleted in Revision 19 15.4.3-4 Deleted in Revision 20
15.4.3-4A Intact Loop Hot and Cold Leg RCS Temperatures - SGTR MTO Analysis
15.4.3-4B Intact Loop Hot and Cold Leg RCS Temperatures - SGTR Dose Analysis
15.4.3A-5 Deleted in Revision 19
15.4.3-5 Deleted in Revision 20
15.4.3-5B Ruptured Loop Hot and Cold Leg RCS Temperatures - SGTR Dose Analysis 15.4.3A-6 Deleted in Revision 19
15.4.3-6 Deleted in Revision 20
15.4.3-6A Primary to Secondary Break Flow Rate - SGTR MTO Analysis
15.4.3-6B Primary to Secondary Break Flow Rate - SGTR Dose Analysis
15.4.3A-7 Deleted in Revision 19
15.4.3-7A Ruptured SG Water Volume - SGTR Margin-to-Overfill Analysis
15.4.3-7B Ruptured SG Water Volume - SGTR Dose Analysis
15.4.3A-8 Deleted in Revision 19
15.4.3-8 Deleted in Revision 20 DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xxxviii Revision 21 September 2013 15.4.3-8A Ruptured Steam Generator Water Mass - SGTR MTO Analysis 15.4.3-8B Ruptured Steam Generator Water Mass - SGTR Dose Analysis
15.4.3A-9 Deleted in Revision 19
15.4.3-9 Ruptured SG Mass Release Rate to the Atmosphere - SGTR Dose Analysis 15.4.3A-10 Deleted in Revision 19 15.4.3-10 Intact SGs Mass Release Rate to the Atmosphere - SGTR Dose Analysis
15.4.3A-11 Deleted in Revision 19
15.4.3-11 Total Flashed Break Flow - SGTR Dose Analysis
15.4.4-1 All Loops Operating, One Locked Rotor - Pressure Versus Time
15.4.4-2 All Loops Operating, One Locked Rotor - Clad Temperature Versus Time
15.4.4-3 All Loops Operating, One Locked Rotor - Flow Coastdown Versus Time
15.4.4-4 All Loops Operating, One Locked Rotor - Heat Flux Versus Time
15.4.4-5 All Loops Operating, One Locked Rotor - Nuclear Power Versus Time
15.4.6-1 Nuclear Power Transient, BOL HZP, Rod Ejection Accident
15.4.6-2 Hot Spot Fuel and Clad Temperature Versus Time BOL, HZP, Rod Ejection Accident
15.4.6-3 Nuclear Power Transient, EOL, HFP, Rod Ejection Accident
15.4.6-4 Hot Spot Fuel and Clad Temperatures Versus Time, EOL, HZP, Rod Ejection Accident
15.5-1 Ratio of Short-Term Release Concentration to Continuous Release Concentration Versus Release Duration 15.5-2 Thyroid Dose at 800 Meters Versus Weight of Steam Dumped to Atmosphere (Design Basis Case Assumptions) DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xxxix Revision 21 September 2013 15.5-3 Thyroid Dose at 10,000 Meters Versus Weight of Steam Dumped to Atmosphere (Design Basis Case Assumptions) 15.5-4 Thyroid Dose at 10,000 Meters Versus Weight of Steam Dumped to Atmosphere (Expected Case Assumptions) 15.5-5 Thyroid Dose at 800 Meters Versus Weight of Steam Dumped to Atmosphere (Expected Case Assumptions) 15.5-6 Thyroid Exposures for 15% Nonremovable Iodine 15.5-7 DBA Two-hour 800-meter Thyroid Exposures Versus Spray Removal Constant and Percent Nonremovable Iodine 15.5-8 DBA Thirty-hour 800-meter Thyroid Exposures Versus Spray Removal Constant and Percent Nonremovable Iodine 15.5-9 Containment Recirculation Sump Activity Pathway to the Atmosphere for Small Leak Case 15.5-10 Containment Recirculation Sump Activity Pathway to the Atmosphere for Large Leak Case 15.5-11 Equilibrium Elemental Iodine Partition and Decontamination Factors for the Expected Case - Large Circulation Loop Leakage in the Auxiliary Building 15.5-12 Equilibrium Elemental Iodine Partition and Decontamination Factors for the DBA Case - Large Circulation Loop Leakage in the Auxiliary Building 15.5-13 Deleted in Revision 7
15.5-14 Potential Radiation Exposures as a Result of Accidents Involving Failure of Fuel Cladding (Design Basis Case Assumptions) 15.5-15 Potential Radiation Exposures as a Result of Accidents Involving Failure of Fuel Cladding (Expected Case Assumptions) 15.5-16 Incremental Long-term Doses from Accidents Involving Failure of Fuel Cladding 15.5-17 Deleted in Revision 16 DCPP UNITS 1 & 2 FSAR UPDATE CHAPTER 15 FIGURES (Continued) Figure Title xl Revision 21 September 2013 15.5-18 Deleted in Revision 16 15.5-19 Deleted in Revision 19
15.5-20 Deleted in Revision 16
15.5-21 Deleted in Revision 16
15.5-22 Deleted in Revision 16
DCPP UNITS 1 & 2 FSAR UPDATE 15-1 Revision 20 November 2011 Chapter 15 ACCIDENT ANALYSES Since 1970, the ANS classification of plant conditions has been used to divide plant conditions into four categories in accordance with anticipated frequency of occurrence and potential radiological consequences to the public. The four categories are as follows: (1) Condition I: Normal Operation and Operational Transients (2) Condition II: Faults of Moderate Frequency (3) Condition III: Infrequent Faults (4) Condition IV: Limiting Faults The basic principle applied in relating design requirements to each of the conditions is that the most frequent occurrences must yield little or no radiological risk to the public, and those extreme situations having the potential for the greatest risk to the public shall be those least likely to occur. Where applicable, reactor trip system and engineered safety features functioning is assumed, to the extent allowed by considerations such as the single failure criterion, in fulfilling this principle. In the evaluation of the radiological consequences associated with initiation of a spectrum of accident conditions, numerous assumptions must be postulated. In many instances these assumptions are a product of extremely conservative judgments. This is due to the fact that many physical phenomena, in particular fission product transport under accident conditions, are not understood to the extent that accurate predictions can be made. Therefore, the set of assumptions postulated would predominantly determine the accident classification. The specific accident sequences analyzed in this chapter include those required by Revision 1 of Regulatory Guide 1.70, Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants, and others considered significant for the Diablo Canyon Power Plant (DCPP). Because the DCPP design differs from other plants, some of the accidents identified in Table 15-1 of Regulatory Guide 1.70, Revision 1, are not applicable to this plant; some comments on these items are as follows: (Item 10) - There are no pressure regulators or regulating instruments in the Westinghouse pressurized water reactor (PWR) design whose failure could cause heat removal greater than heat generation. (Item 11) - Reactor coolant flow controller is not a feature of the Westinghouse PWR design. Treatment of the performance of the reactivity controller in a number of accident conditions is offered in this chapter. DCPP UNITS 1 & 2 FSAR UPDATE 15-2 Revision 20 November 2011 (Item 12) - The reactor coolant system (RCS) components whose failure could cause a Condition III or Condition IV loss-of-coolant accident (LOCA) are Design Class I components, that is, they are designed to withstand consequences of the safe shutdown earthquake (SSE) which is equivalent to the double design earthquake (DDE) occurrence. In addition, the analyses of the design LOCA includes the assumption of unavailability of offsite power. (Item 22) - No instrument lines from the RCS boundary in the DCPP design penetrate the containment(a) . (Item 24) - The analysis of the consequences of such small spills and leaks is included within the cases evaluated in Chapter 11, and larger leaks and spills are analyzed in Section 15.5. (Item 25) - The radiological consequences of this event are analyzed in Chapter 11, for the case of "Anticipated Operational Occurrences." (Item 26) - Habitability of the control room following accident conditions is discussed in Chapter 6, and potential radiological exposures are reported in Section 15.5. In addition, Chapter 7 contains an analysis showing that the plant can be brought to, and maintained in, the hot shutdown condition from outside the control room. (Item 27) - Overpressurization of the residual heat removal system (RHRS) is considered extremely unlikely. PG&E reviewed possible RHRS overpressure scenarios and qualified the system for all credible high pressure transients in DCPP design change package N-049118. (Item 28) - This event is covered by the analyses of Section 15.2.7. (Item 29) - Same as Item 28 above. (Item 30) - Malfunctions of auxiliary saltwater system and component cooling water system (CCWS) are discussed in Chapter 9, Sections 9.2.7 and 9.2.2 respectively. (Item 31) - There are no significant safety-related consequences of this event. (Item 33) - The effects of turbine trip on the RCS are presented in Section 15.2.7. (Item 34) - Malfunctions of this system are discussed in Section 9.3.2. (Item 35) - The radiological effects of this event are not significant for PWR plants. Minor leakages are within the scope of the analysis cases presented in Chapter 11. (a) For definition of the RCS boundary, refer to the 1972 issue of ANS N18.2, Nuclear Safety Criteria for the Design of Stationary PWR Plants. DCPP UNITS 1 & 2 FSAR UPDATE 15.1-1 Revision 20 November 2011 15.1 CONDITION I - NORMAL OPERATION AND OPERATIONAL TRANSIENTS Condition I occurrences are those that are expected frequently or regularly in the course of power operation, refueling, maintenance, or maneuvering of the plant. As such, Condition I occurrences are accommodated with margin between any plant parameter and the value of that parameter which would require either automatic or manual protective action. Inasmuch as Condition I occurrences occur frequently or regularly, they must be considered from the point of view of affecting the consequences of fault conditions (Conditions II, III, and IV). In this regard, analysis of each fault condition is generally based on a conservative set of initial conditions corresponding to the most adverse set of conditions that can occur during Condition I operation.
A typical list of Condition I events is shown below:
(1) Steady state and shutdown operations Mode 1 - Power operation (> 5% of rated thermal power) Mode 2 - Startup (keff 0.99, 5% of rated thermal power) Mode 3 - Hot standby (keff < 0.99, Tavg 350°F) Mode 4 - Hot shutdown (subcritical, residual heat removal system in operation, keff < 0.99, 200°F < Tavg < 350°F) Mode 5 - Cold shutdown (subcritical, residual heat removal system in operation, keff < 0.99, Tavg 200°F) Mode 6 - Refueling (keff 0.95, Tavg 140°F) (2) Operation with permissible deviations Various deviations that may occur during continued operation as permitted by the plant Technical Specifications (Reference 1) must be considered in conjunction with other operational modes. These include: (a) Operation with components or systems out of service (b) Leakage from fuel with cladding defects (c) Activity in the reactor coolant 1. Fission products 2. Corrosion products 3. Tritium DCPP UNITS 1 & 2 FSAR UPDATE 15.1-2 Revision 20 November 2011 (d) Operation with steam generator leaks up to the maximum allowed by the Technical Specifications (3) Operational transients (a) Plant heatup and cooldown (up to 100°F/hour for the reactor coolant system (RCS); 200°F/hour for the pressurizer) (b) Step load changes (up to +/- 10 percent) (c) Ramp load changes (up to 5 percent per minute) (d) Load reduction up to and including a 50 percent load reduction from full power 15.1.1 OPTIMIZATION OF CONTROL SYSTEMS Prior to initial startup, a setpoint study (Reference 2) was performed in order to simulate performance of the reactor control and protection systems. Emphasis was placed on the development of a control system that will automatically maintain prescribed conditions in the plant even under the most conservative set of reactivity parameters with respect to both system stability and transient performance.
For each mode of plant operation, a group of optimum controller setpoints is determined. In areas where the resultant setpoints are different, compromises based on the optimum overall performance are made and verified. A consistent set of control system parameters is derived satisfying plant operational requirements throughout the core life and for power levels between 15 and 100 percent. The study comprises an analysis of the following control systems: rod cluster assembly control, steam dump, steam generator level, pressurizer pressure, and pressurizer level.
Since initial startup, setpoints and control system components have been maintained to optimize performance. When changes are made, the accident analyses are reviewed and revised as necessary. The impact of maintaining pressurizer level 22 percent and 90 percent in Modes 3, 4, and 5 has been evaluated as acceptable because there is no adverse impact on any accident analyses (Reference 28). 15.1.2 INITIAL POWER CONDITIONS ASSUMED IN ACCIDENT ANALYSES Reactor power-related initial conditions assumed in the accident analyses presented in this chapter are described in this section.
DCPP UNITS 1 & 2 FSAR UPDATE 15.1-3 Revision 20 November 2011 15.1.2.1 Power Rating Table 15.1-1 lists the principal power rating values that are assumed in analyses performed in this section. Two ratings are given:
(1) The guaranteed nuclear steam supply system (NSSS) thermal power output. This power output includes the thermal power generated by the reactor coolant pumps. (2) The engineered safety features (ESF) design rating. The Westinghouse-supplied ESFs are designed for a thermal power higher than the guaranteed value in order not to preclude realization of future potential power capability. This higher thermal power value is designated as the ESF design rating. This power output includes the thermal power generated by the reactor coolant pumps.
Where initial power operating conditions are assumed in accident analyses, the guaranteed NSSS thermal power output (plus allowance for errors in steady state power determination for some accidents) is assumed. Where demonstration of the adequacy of the ESF is concerned, the ESF design rating plus allowance for error is assumed. The thermal power values for each transient analyzed are given in Table 15.1-4. 15.1.2.2 Initial Conditions For most accidents, which are DNB limited, nominal values of initial conditions are assumed. The allowances on power, temperature, and pressure are determined on a statistical basis and are included in the limit DNBR, as described in Reference 3. This procedure is known as the "Improved Thermal Design Procedure" (ITDP) and these accidents utilize the WRB-1 and WRB-2 DNB correlations (References 4 and 5). ITDP allowances may be more restrictive than non-ITDP allowances. The initial conditions for other key parameters are selected in such a manner to maximize the impact on DNBR. Minimum measured flow is used in all ITDP transients. The allowances on power, temperature, pressure, and flow that were evaluated for their effect on the ITDP analyses for a 24-month fuel cycle are reported in Reference 22. These allowances are conservatively applicable for shorter fuel cycle lengths.
For accident evaluations that are not DNB limited, or for which the Improved Thermal Design Procedure is not employed, the initial conditions are obtained by adding maximum steady state errors to rated values. The following steady state errors are considered:
(1) Core power +/-2% allowance calorimetric error (2) Average RCS +/-4.7°F allowance for deadband and measurement error temperature DCPP UNITS 1 & 2 FSAR UPDATE 15.1-4 Revision 20 November 2011 (3) Pressurizer pressure +/-38 psi or +/-60 psi allowance for steady state fluctuations and measurement error (see Note) Note: Pressurizer pressure uncertainty is +/-38 psi in analyses performed prior to 1993; however, NSAL 92-005 (Reference 17) indicates +/-60 psi is a conservative value for future analyses. Reference 18 evaluates the acceptability of existing analyses, which use +/-38 psi.
For some accident evaluations, an additional allowance has been conservatively added to the measurement error for the average RCS temperatures to account for steam generator fouling.
Units 1 and 2 are expected to operate at a Reactor Coolant System vessel average temperature (Tavg) of approximately 569 ºF following steam generator replacement. To support startup following completion of steam generator replacement, a design change has been implemented that provides analyses and evaluations to support operation over a Tavg range from 565 ºF to 577.3/577.6 ºF (Unit 1/Unit 2). 15.1.2.3 Power Distribution The transient response of the reactor system is dependent on the initial power distribution. The nuclear design of the reactor core minimizes adverse power distribution through the placement of fuel assemblies, control rods, and by operation instructions. The power distribution may be characterized by the radial peaking factor FH and the total peaking factor Fq. The peaking factor limits are given in the Technical Specifications. For transients that may be DNB-limited, the radial peaking factor is of importance. The radial peaking factor increases with decreasing power level due to rod insertion. This increase in FH is included in the core limits illustrated in Figure 15.1-1. All transients that may be DNB limited are assumed to begin with a FH consistent with the initial power level defined in the Technical Specifications. The axial power shape used in the DNB calculation is discussed in Section 4.4.3. For transients that may be overpower-limited, the total peaking factor Fq is of importance. The value of Fq may increase with decreasing power level so that the full power hot spot heat flux is not exceeded, i.e., Fq x Power = design hot spot heat flux. All transients that may be overpower-limited are assumed to begin with a value of Fq consistent with the initial power level as defined in the Technical Specifications. The value of peak kW/ft can be directly related to fuel temperature as illustrated in Figures 4.4-1 and 4.4-2. For transients that are slow with respect to the fuel rod thermal time constant (approximately 5 seconds), the fuel temperatures are illustrated in DCPP UNITS 1 & 2 FSAR UPDATE 15.1-5 Revision 20 November 2011 Figures 4.4-1 and 4.4-2. For transients that are fast with respect to the fuel rod thermal time constant, (for example, rod ejection), a detailed heat transfer calculation is made. 15.1.3 TRIP POINTS AND TIME DELAYS TO TRIP ASSUMED IN ACCIDENT ANALYSES A reactor trip signal acts to open two trip breakers connected in series feeding power to the control rod drive mechanisms. The loss of power to the mechanism coils causes the mechanism to release the rod cluster control assemblies (RCCAs), which then fall by gravity into the core. There are various instrumentation delays associated with each trip function, including delays in signal actuation, in opening the trip breakers, and in the release of the rods by the mechanisms. The total delay to trip is defined as the time delay from the time that trip conditions are reached to the time the rods are free and begin to fall. Limiting trip setpoints assumed in accident analyses and the time delay assumed for each trip function are given in Table 15.1-2. Reference is made in that table to the overtemperature and overpower T trip shown in Figure 15.1-1. This figure presents the allowable reactor coolant loop average temperature and T for the design flow and the NSSS Design Thermal Power distribution as a function of primary coolant pressure. The boundaries of operation defined by the Overpower T trip and the Overtemperature T trip are represented as "protection lines" on this diagram. The protection lines are drawn to include all adverse instrumentation and setpoint errors so that under nominal conditions trip would occur well within the area bounded by these lines. The utility of this diagram is in the fact that the limit imposed by any given DNBR can be represented as a line. The DNB lines represent the locus of conditions for which the DNBR equals the safety analysis limit values (1.68 and 1.71 for V-5 thimble cell and typical cells, respectively) for ITDP accidents. All points below and to the left of a DNB line for a given pressure have a DNBR greater than the limit values. The diagram shows that DNB is prevented for all cases if the area enclosed with the maximum protection lines is not traversed by the applicable DNBR line at any point. The current fuel cycles for the Diablo Canyon Units only use the Vantage 5 (V-5) fuel assembly type. However, the safety analyses performed in support of the introduction of V-5 fuel also considered the presence of the Standard type fuel assemblies during the previous transition cycles. The DNBR values and transient results presented in the FSAR Update continue to reflect the Standard fuel type, since it is limiting with respect to DNB margin in comparison to the V-5 fuel type.
The area of permissible operation (power, pressure and temperature) is bounded by the combination of reactor trips: high pressurizer pressure (fixed setpoint); low pressurizer pressure (fixed setpoint); overpower and overtemperature T (variable setpoints); and by a line defining conditions at which the steam generator safety valves open.
The limit values, which were used as the DNBR limits for all accidents analyzed with the Improved Thermal Design Procedure are conservative compared to the actual design DNBR values required to meet the DNB design basis.
DCPP UNITS 1 & 2 FSAR UPDATE 15.1-6 Revision 20 November 2011 The difference between the limiting trip point assumed for the analysis and the normal trip point represents an allowance for instrumentation channel error and setpoint error. During startup tests, it is demonstrated that actual instrument errors and time delays are equal to or less than the assumed values.
Accident analyses that assume the steam generator low-low water level to initiate protection functions may be affected by the trip time delay (TTD) (Reference 19) that was developed to reduce the incidence of unnecessary feedwater related reactor trips.
The TTD imposes calculated time delays on the steam generator low-low water level reactor trip and auxiliary feedwater actuation. The values of these time delays are based on, (a) the highest power level observed subsequent to the time the low-low level setpoint is reached, and (b) the number of steam generators in which the low-low level setpoint is reached. The TTD delays the reactor trip and auxiliary feedwater actuation in order to provide time for corrective action by the operator or for natural stabilization of shrink/swell water level transients. The TTD is primarily designed for low power or startup operations, and is only active below 50 percent Rated Thermal Power. DCPP uses only the TTD associated with low-low level in more than one steam generator. 15.1.4 CALORIMETRIC ERRORS - POWER RANGE NEUTRON FLUX The calorimetric error is the error assumed in the determination of core thermal power as obtained from secondary plant measurements. The total ion chamber current (sum of the top and bottom sections) is calibrated (set equal) to this measured power on a periodic basis. The secondary power is obtained from measurement of feedwater flow, feedwater inlet temperature to the steam generators, and steam pressure. High-accuracy instrumentation is provided for these measurements with accuracy tolerances much tighter than those that would be required to control feedwater flow. 15.1.5 ROD CLUSTER CONTROL ASSEMBLY INSERTION CHARACTERISTICS The negative reactivity insertion following a reactor trip is a function of the acceleration of the RCCA and the variation in rod worth as a function of rod position.
With respect to accident analyses, the critical parameter is the time of insertion up to the dashpot entry or approximately 85 percent of the rod cluster travel. For accident analyses, the insertion time to dashpot entry is conservatively taken as 2.7 seconds. The RCCA position versus time assumed in accident analyses is shown in Figure 15.1-2.
Figure 15.1-3 shows the fraction of total negative reactivity insertion for a core where the axial distribution is skewed to the lower region of the core. This curve is used as input to all point kinetics core models used in transient analyses.
There is inherent conservatism in the use of this curve in that it is based on a skewed axial power distribution that would exist relatively infrequently. For cases other than DCPP UNITS 1 & 2 FSAR UPDATE 15.1-7 Revision 20 November 2011 those associated with xenon oscillations, significant negative reactivity would have been inserted due to the more favorable axial power distribution existing prior to trip.
The normalized RCCA negative reactivity insertion versus time is shown in Figure 15.1-4. The curve shown in this figure was obtained from Figures 15.1-2 and 15.1-3. A total negative reactivity insertion following a trip of 4 percent k is assumed in the transient analyses except where specifically noted otherwise. This assumption is conservative with respect to the calculated trip reactivity worth available as shown in Tables 4.3-2 and 4.3-3.
The normalized RCCA negative reactivity insertion versus time curve for an axial power distribution skewed to the bottom (Figure 15.1-4) is used in transient analyses.
Where special analyses require the use of three-dimensional or axial one-dimensional core models, the negative reactivity insertion resulting from reactor trip is calculated directly by the reactor kinetic code and is not separable from other reactivity feedback effects. In this case, the RCCA position versus time of Figure 15.1-2 is used as code input. 15.1.6 REACTIVITY COEFFICIENTS The transient response of the reactor coolant system is dependent on reactivity feedback effects, in particular the moderator temperature coefficient and the Doppler power coefficient. These reactivity coefficients and their values are discussed in detail in Chapter 4.
In the analysis of certain events, conservatism requires the use of large reactivity coefficient values, whereas in the analysis of other events, conservatism requires the use of small reactivity coefficient values. Some analyses, such as loss of reactor coolant from cracks or ruptures in the RCS, do not depend on reactivity feedback effects. The values used are given in Table 15.1-4; reference is made in that table to Figure 15.1-5 that shows the upper and lower Doppler power coefficients, as a function of power, used in the transient analysis. The justification for use of conservatively large versus small reactivity coefficient values is discussed on an event-by-event basis. 15.1.7 FISSION PRODUCT INVENTORIES The fission product inventories existing in the core and fuel rod gaps are described in Section 15.5.2. The description of the models used for calculating fuel gap activities is included in Section 15.5.2. 15.1.8 RESIDUAL DECAY HEAT Residual heat in a subcritical core consists of:
(1) Fission product decay energy DCPP UNITS 1 & 2 FSAR UPDATE 15.1-8 Revision 20 November 2011 (2) Decay of neutron capture products (3) Residual fissions due to the effect of delayed neutrons These constituents are discussed separately in the following paragraphs.
15.1.8.1 Fission Product Decay For short times (<103 seconds) after shutdown, data on yields of short-half-life isotopes is sparse. Very little experimental data is available for the gamma ray contributions and even less for the beta ray contribution. Several authors have compiled the available data into a conservative estimate of fission product decay energy for short times after shutdown, notably Shure (Reference 6), Dudziak (Reference 7), and Teage (Reference 8). Of these three selections, Shure's curve is the highest and it is based on the data of Stehn and Clancy (Reference 9) and Obenshain and Foderaro (Reference 10). The fission product contribution to decay heat that has been assumed in the small break LOCA (SBLOCA) accident analyses is the curve of Shure increased by 20 percent for conservatism. The decay heat curve used for the Best Estimate large break LOCA (LBLOCA) analysis is based on the 1979 ANS decay heat curve as described in Section 8 of Reference 23. This curve with the 20 percent factor included is shown in Figure 15.1-6. For the non-LOCA analyses the 1979 ANS decay heat curve is used (Reference 11). Figure 15.1-7 presents this curve as a function of time after shutdown. 15.1.8.2 Decay of U-238 Capture Products Betas and gammas from the decay of U-239 (23.5-minute half-life) and Np-239 (2.35-day half-life) contribute significantly to the heat generation after shutdown. The cross sections for production of these isotopes and their decay schemes are relatively well known. For long irradiation times their contribution can be written as: watts/wattteMeV200)(1c)E(EP/P11101++= (15.1-1) watts/wattte)tet(eMeV200)(1c)E(EP/P2122122202+++= (15.1-2) where:
P1/P0 is the energy from U-239 decay P2/P0 is the energy from Np-239 decay t is the time after shutdown (seconds) c(1+) is the ratio of U-238 captures to total fissions = 0.6 (1 + 0.2) DCPP UNITS 1 & 2 FSAR UPDATE 15.1-9 Revision 20 November 2011 1 = the decay constant of U-239 = 4.91 x 10-4 per second 2 = the decay constant of Np-239 decay = 3.41 x 10-6 per second E1 = total -ray energy from U-239 decay = 0.06 MeV E2 = total -ray energy from Np-239 decay = 0.30 MeV E1 = total -ray energy from U-239 decay = 1/3(a) x 1.18 MeV E2 = total -ray energy from Np-239 decay = 1/3(a) x 0.43 MeV For the SBLOCA, based on conservative modeling of the ratio of U-238 captures to total fissions, heavy element decay heat is calculated without applying further uncertainty correction (Reference 24). For the Best Estimate LOCA analysis, the heat from the radioactive decay of U-239 and Np-239 is calculated as described in Section 8 of Reference 23. The decay of other isotopes, produced by neutron reactions other than fission, is neglected. For the non-LOCA analysis, the decay of U-238 capture products is included as an integral part of the 1979 decay heat curve presented as Figure 15.1-7. 15.1.8.3 Residual Fissions The time dependence of residual fission power after shutdown depends on core properties throughout a transient under consideration. Core average conditions are more conservative for the calculation of reactivity and power level than actual local conditions as they would exist in hot areas of the core. Thus, unless otherwise stated in the text, static power shapes have been assumed in the analysis and these are factored by the time behavior of core average fission power calculated by a point kinetics model calculation with six delayed neutron groups.
For the purpose of illustration, only one delayed neutron group calculation, with a constant shutdown reactivity of -4 percent k is shown in Figure 15.1-6. 15.1.8.4 Distribution of Decay Heat Following Loss-of-Coolant Accident During an SBLOCA the core is rapidly shut down by void formation or RCCA insertion, or both, and long-term shutdown is assured by the borated ECCS water. A large fraction of the heat generation to be considered comes from fission product decay gamma rays. This heat is not distributed in the same manner as steady state fission power. Local peaking effects that are important for the neutron dependent part of the heat generation do not apply to the gamma ray source contribution. The steady state factor of 97.4 percent that represents the fraction of heat generated within the cladding and pellet drops to 95 percent for the hot rod in a LOCA.
For example, 1/2 second after the rupture about 30 percent of the heat generated in the fuel rods is from gamma ray absorption. The gamma power shape is less peaked than the steady state fission power shape, reducing the energy deposited in the hot rod at the expense of adjacent colder rods. A conservative estimate of this effect is a reduction of 10 percent of the gamma ray contribution or 3 percent of the total. Since (a) Two-thirds of the potential -energy is assumed to escape by the accompanying neutrinos. DCPP UNITS 1 & 2 FSAR UPDATE 15.1-10 Revision 20 November 2011 the water density is considerably reduced at this time, an average of 98 percent of the available heat is deposited in the fuel rods, the remaining 2 percent being absorbed by water, thimbles, sleeves, and grids. The net effect is a factor of 0.95, rather than 0.974, to be applied to the heat production in the hot rod.
For the Best Estimate LOCA analysis, the energy deposition modeling is performed as described in Section 8 of Reference 23. 15.1.9 COMPUTER CODES UTILIZED Summaries of some of the principal computer codes used in transient analyses are given below. Other codes, in particular, very specialized codes in which the modeling has been developed to simulate one given accident, such as the NOTRUMP code used in the analysis of the RCS pipe rupture (Section 15.4), and which consequently have a direct bearing on the analysis of the accident itself, are summarized in their respective accident analyses sections. The codes used in the analyses of each transient are listed in Table 15.1-4. 15.1.9.1 FACTRAN FACTRAN (Reference 12) calculates the transient temperature distribution in a cross section of a metalclad UO2 fuel rod (see Figure 15.1-8) and the transient heat flux at the surface of the cladding using as input the nuclear power and the time-dependent coolant parameters (pressure, flow, temperature, and density).
The code uses a fuel model that exhibits the following features simultaneously: (1) A sufficiently large number of finite difference radial space increments to handle fast transients such as rod ejection accidents (2) Material properties that are functions of temperature and a sophisticated fuel-to-cladding gap heat transfer calculation (3) The necessary calculations to handle post-DNB transients: film boiling heat transfer correlations, zirconium-water reaction, and partial melting of the materials The gap heat transfer coefficient is calculated according to an elastic pellet model. The thermal expansion of the pellet is calculated as the sum of the radial (one-dimensional) expansions of the rings. Each ring is assumed to expand freely. The cladding diameter is calculated based on thermal expansion and internal and external pressures. If the outside radius of the expanded pellet is smaller than the inside radius of the expanded cladding, there is no fuel-cladding contact and the gap conductance is calculated on the basis of the thermal conductivity of the gas contained in the gap. If the pellet outside radius so calculated is larger than the cladding inside radius (negative gap), the pellet and the cladding are pictured as exerting upon each other a pressure DCPP UNITS 1 & 2 FSAR UPDATE 15.1-11 Revision 20 November 2011 sufficient to reduce the gap to zero by elastic deformation of both. This contact pressure determines the heat transfer coefficient.
FACTRAN is further discussed in Reference 12. 15.1.9.2 LOFTRAN The LOFTRAN (Reference 13) program is used for studies of transient response of a PWR system to specified perturbations in process parameters. LOFTRAN simulates a multiloop system by a lumped parameter single-loop model containing reactor vessel, hot and cold leg piping, steam generator (tube and shell-sides), and the pressurizer. The pressurizer heaters, spray, relief and safety valves are also considered in the program. Point model neutron kinetics, and reactivity effects of the moderator, fuel, boron, and rods are included. The secondary side of the steam generator utilizes a homogeneous, saturated mixture for the thermal transients and a water level correlation for indication and control. The reactor protection system is simulated to include reactor trips on neutron flux, overpower and overtemperature reactor coolant T, high and low pressure, low flow, and high pressurizer level. Control systems are also simulated including rod control, steam dump, feedwater control, and pressurizer pressure control. The safety injection system (SIS), including the accumulators, is also modeled.
LOFTRAN is a versatile program that is suited to both accident evaluation and control studies as well as parameter sizing. LOFTRAN also has the capability of calculating the transient value of DNB based on the input from the core limits illustrated in Figure 15.1-1. The core limits represent the minimum value of DNBR as calculated for a typical or thimble cell. LOFTRAN is further discussed in Reference 13. 15.1.9.3 PHOENIX- P The PHOENIX-P (Reference 25) computer code is a two-dimensional, multi-group, transport based lattice code and is capable of providing all necessary data for PWR analysis. Being a dimensional lattice code, PHOENIX-P does not rely on pre-determined spatial/spectral interaction assumptions for heterogeneous fuel lattice, hence, it will provide a more accurate multi-group flux solution than versions of LEOPARD (Reference 14), which was used previously. The PHOENIX-P computer code is approved by the NRC as the lattice code for generating macroscopic and microscopic few group cross sections for PWR analysis.
The PHOENIX-P computer code is described in more details in Section 4.3.3. 15.1.9.4 ANC With the advent of VANTAGE 5 fuel and axial features such as axial blankets and part length burnable absorbers, the three dimensional nodal codes ANC (Advanced Nodal Code) (Reference 26) has replaced the previous two group X-Y TURTLE (Reference 15) code. The three dimensional nature of the nodal codes provides both DCPP UNITS 1 & 2 FSAR UPDATE 15.1-12 Revision 20 November 2011 the radial and axial power distributions, and also determines the critical boron concentrations and power distributions. The moderator coefficient is evaluated by varying the inlet temperature in the same calculations used for power distribution and reactivity predictions.
Axial calculations are used to determine differential control rod worth curves (reactivity versus rod insertion) and axial power shapes during steady state and transient xenon conditions. Group constants are obtained from three-dimensional nodal calculations homogenized by flux volume weighting.
The ANC computer code is described in more detail in Section 4.3.3. 15.1.9.5 TWINKLE The TWINKLE (Reference 16) program is a multidimensional spatial neutron kinetics code, which was patterned after steady state codes presently used for reactor core design. The code uses an implicit finite-difference method to solve the two-group transient neutron diffusion equations in one-, two-, and three-dimensions. The code uses six delayed neutron groups and contains a detailed multiregion fuel-cladding-coolant heat transfer model for calculating pointwise Doppler and moderator feedback effects. The code handles up to 2000 spatial points and performs its own steady state initialization. Aside from basic cross section data and thermal-hydraulic parameters, the code accepts as input basic driving functions such as inlet temperature, pressure, flow, boron concentration, control rod motion, and others. Various edits provide channelwise power, axial offset, enthalpy, volumetric surge, pointwise power, fuel temperatures, and so on. The TWINKLE code is used to predict the kinetic behavior of a reactor for transients that cause a major perturbation in the spatial neutron flux distribution.
TWINKLE is further described in Reference 16. 15.1.9.6 THINC The THINC code is described in Section 4.4.3. 15.1.9.7 RETRAN-02 The RETRAN-02 program is used to perform the best-estimate thermal-hydraulic analysis of operational and accident transients for light water reactor systems. The program is constructed with a highly flexible modeling technique that provides the RETRAN-02 program the capability to model the actual performance of the plant systems and equipment.
DCPP UNITS 1 & 2 FSAR UPDATE 15.1-13 Revision 20 November 2011 The main features of the RETRAN-02 program are: (1) A one-dimensional, homogeneous equilibrium mixture thermal-hydraulic model for the reactor cooling system (2) A point neutron kinetics model for the reactor core (3) Special auxiliary or component models (such as non-equilibrium pressurizer temperature transport delay) (4) Control system models (5) A consistent steady state initialization technique The RETRAN-02 program is further discussed in Reference 21. 15.1.9.8 RETRAN-02W The RETRAN-02W program is the Westinghouse version of the RETRAN-02 program (see Reference 27). RETRAN-02W is used to determine plant transient response to selected accidents, as described in Sections 15.2 and 15.4. 15.1.10 REFERENCES
- 1. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended. 2. M. Ko, Setpoint Study for PG&E Diablo Canyon Units 1 and 2, WCAP 8320, June 1974.
- 3. H. Chelemer, et al., Improved Thermal Design Procedure, WCAP-8567-P-A (Proprietary) and WCAP-8568-NP-A (Non-Proprietary), February 1989.
- 4. F. E. Motley, et al., New Westinghouse Correlation WRB-1 for Predicting Critical Heat Flux in Rod Bundles with Mixing Vane Grids, WCAP-8762-P-A and WCAP-8763-A, July 1984.
- 5. S. L. Davidson, and W. R. Kramer; (Ed.) Reference Core Report VANTAGE 5 Fuel Assembly, WCAP-10444-P-A (Proprietary) and WCAP-10445-NP-A (Non-Proprietary), Appendix A.2.0, September 1985.
- 6. K. Shure, Fission Product Decay Energy in Bettis Technical Review, WAPD-BT-24, December 1961, pp. 1-17.
DCPP UNITS 1 & 2 FSAR UPDATE 15.1-14 Revision 20 November 2011 7. K. Shure and D. J. Dudziak, "Calculating Energy Released by Fission Products," Trans. Am. Nucl. Soc. 4 (1) 30, 1961.
- 8. U.K.A.E.A. Decay Heat Standard.
- 9. J. R. Stehn and E. F. Clancy, "Fission-Product Radioactivity and Heat Generation," Proceedings of the Second United Nations International Conference on the Peaceful Uses of Atomic Energy, Geneva, 1958, Volume 13, United Nations, Geneva, 1958, pp. 49-54.
- 10. F. E. Obenshain and A. H. Foderaro, Energy from Fission Product Decay, WAPD-P-652, 1955.
- 11. ANSI/ANS-5.1-1979, Decay Heat Power In Light Water Reactors, August 29, 1979. 12. H. G. Hargrove, FACTRAN, a Fortran IV Code for Thermal Transients in a UO2 Fuel Rod, WCAP-7908-A, December 1989.
- 13. T. W. T. Burnett et al, LOFTRAN Code Description, WCAP-7907-A, April 1984.
- 14. R. F. Barry, LEOPARD, a Spectrum Dependent Non-Spatial Depletion Code for the IBM-7904, WCAP-3269-26, September 1963.
- 15. R. F. Altomare and S. Barry, The TURTLE 24.0 Diffusion Depletion Code, WCAP-7213, June 1968, (Westinghouse NES Proprietary); WCAP-7758, September 1971.
- 16. D. H. Risher, Jr. and R. F. Barry, TWINKLE - A Multi-Dimensional Neutron Kinetics Computer Code, WCAP-7979P-A, January 1975.
- 17. Diablo Canyon Pressurizer Pressure Controller Uncertainty, Westinghouse Nuclear Safety Advisory Letter (NSAL) 92-005, September 22, 1992.
- 18. PG&E Nuclear Plant, Diablo Canyon Units 1 and 2, Pressurizer Pressure Control System Uncertainty Safety Assessment, Westinghouse Letter PGE-93-659, November 18, 1993.
- 19. S. Miranda, et al., Steam Generator Low Water Level Protection System Modifications to Reduce Feedwater Related Trips, WCAP-11325-P-A, Rev. 1, February 1988.
- 20. Deleted in Revision 13.
DCPP UNITS 1 & 2 FSAR UPDATE 15.1-15 Revision 20 November 2011 21. RETRAN-02 -- A Program for Transient Thermal-Hydraulic Analysis of Complex Fluid Flow Systems, Volume 1: Theory and Numerics, (Revision 5), EPRI NP-1850-CCM-A, March 1992.
- 22. Westinghouse Improved Thermal Design Procedure Instrument Uncertainty Methodology, Diablo Canyon Units 1 and 2, 24-Month Fuel Cycle Evaluation, WCAP-11594, Revision 2, January 1997.
- 23. S. M. Bajorek, et al., Code Qualification Document for Best Estimate LOCA Analysis, Volume I: Models and Correlations, WCAP-12945-P-A, Volume I, Revision 2, 1998.
- 24. NUREG-0800, Standard Review Plan, Branch Technical Position ASB 9-2, Residual Decay Energy for Light-Water Reactors for Long Term Cooling, July 1981.
- 25. T. Q. Nguyen, et. al., Qualification of the PHOENIX-P/ANC Nuclear Design System for Pressurized Water Reactor Cores, WCAP-11596-P-A, June 1988.
- 26. S. L. Davidson, (Ed), et al., ANC: Westinghouse Advanced Nodal Computer Code, WCAP-10965-P-A, September 1986.
- 27. RETRAN-02 Modeling and Qualification for Westinghouse Non-LOCA Safety Analyses, WCAP-14882-P-A (Proprietary), April 1999, and WCAP-15234-A (Non-Proprietary), May 1999. 28. Westinghouse Letter PGE-10-53, "Transmittal of LBIE to Address the Increase in Pressurizer Level in Modes 3, 4, & 5, September 23, 2010.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-1 Revision 21 September 2013 15.2 CONDITION II - FAULTS OF MODERATE FREQUENCY These faults result at worst in reactor shutdown with the plant being capable of returning to operation. By definition, these faults (or events) do not propagate to cause a more serious fault, i.e., a Condition III or IV fault. In addition, Condition II events are not expected to result in fuel rod failures or reactor coolant system (RCS) overpressurization. For the purposes of this report the following faults have been grouped into these categories:
(1) Uncontrolled rod cluster control assembly (RCCA) bank withdrawal from a subcritical condition (2) Uncontrolled RCCA bank withdrawal at power (3) RCCA misoperation (4) Uncontrolled boron dilution (5) Partial loss of forced reactor coolant flow (6) Startup of an inactive reactor coolant loop (7) Loss of external electrical load and/or turbine trip (8) Loss of normal feedwater (9) Loss of offsite power and main generator power to the station auxiliaries (10) Excessive heat removal due to feedwater system malfunctions (11) Sudden feedwater temperature reduction (12) Excessive load increase (13) Accidental RCS depressurization (14) Accidental main steam system depressurization (15) Spurious operation of safety injection system (SIS) at power Each of these faults of moderate frequency are analyzed in this section. In general, each analysis includes an identification of causes and description of the accident, an analysis of effects and consequences, a presentation of results, and relevant conclusions.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-2 Revision 21 September 2013 An evaluation of the reliability of the reactor protection system actuation following initiation of Condition II events has been completed and is presented in Reference 1 for the relay protection logic. Standard reliability engineering techniques were used to assess the likelihood of the trip failure due to random component failures. Common-mode failures were also qualitatively investigated. It was concluded from the evaluation that the likelihood of no trip following initiation of Condition II events is extremely small (2 x 10-7 derived for random component failures). The reliability of the solid-state protection system has also been evaluated using the same methods. The calculated reliability is of the same order of magnitude as that obtained for the relay protection logic.
Hence, because of the high reliability of the protection system, no special provision is included in the design to cope with the consequences of Condition II events without trip.
The time sequence of events during each Condition II fault is shown in Table 15.2-1. 15.2.1 UNCONTROLLED ROD CLUSTER CONTROL ASSEMBLY BANK WITHDRAWAL FROM A SUBCRITICAL CONDITION 15.2.1.1 Identification of Causes and Accident Description An RCCA withdrawal accident is defined as an uncontrolled increase in reactivity in the reactor core caused by withdrawal of RCCAs resulting in a power excursion. Such a transient could be caused by a malfunction of the reactor control or control rod drive systems. This could occur with the reactor at either subcritical, hot zero power, or at power. The at-power case is discussed in Section 15.2.2. Although the reactor is normally brought to power from a subcritical condition by means of RCCA withdrawal, initial startup procedures with a clean core call for boron dilution. The maximum rate of reactivity increase in the case of boron dilution is less than that assumed in this analysis (see Section 15.2.4).
The RCCA drive mechanisms are wired into preselected bank configurations that are not altered during core reactor life. These circuits prevent the assemblies from being withdrawn in other than their respective banks. Power supplied to the banks is controlled so that no more than two banks can be withdrawn at the same time. The RCCA drive mechanisms are of the magnetic latch type and coil actuation is sequenced to provide variable speed travel. The maximum reactivity insertion rate analyzed in the detailed plant analysis is that occurring with the simultaneous withdrawal of the two control banks having the maximum combined worth at maximum speed.
The neutron flux response to a continuous reactivity insertion is characterized by a very fast rise terminated by the reactivity feedback effect of the negative Doppler coefficient. This self-limitation of the power burst is of primary importance since it limits the power to a tolerable level during the delay time for protection action. Should a continuous RCCA DCPP UNITS 1 & 2 FSAR UPDATE 15.2-3 Revision 21 September 2013 withdrawal accident occur, the transient will be terminated by the following automatic features of the reactor protection system. 15.2.1.1.1 Source Range High Neutron Flux Reactor Trip The source range high neutron flux reactor trip is actuated when either of two independent source range channels indicates a neutron flux level above a preselected manually adjustable setpoint. This trip function may be manually bypassed when either intermediate range flux channel indicates a flux level above a specified level. It is automatically reinstated when both intermediate range channels indicate a flux level below a specified level. 15.2.1.1.2 Intermediate Range High Neutron Flux Reactor Trip The intermediate range high neutron flux reactor trip is actuated when either of two independent intermediate range channels indicates a flux level above a preselected manually adjustable setpoint. This trip function may be manually bypassed when two of the four power range channels give readings above approximately 10 percent of full power and is automatically reinstated when three of the four channels indicate a power below this value. 15.2.1.1.3 Power Range High Neutron Flux Reactor Trip (Low Setting) The power range high neutron flux trip (low setting) is actuated when two-out-of-four power range channels indicate a power level above approximately 25 percent of full power. This trip function may be manually bypassed when two of the four power range channels indicate a power level above approximately 10 percent of full power and is automatically reinstated when three of the four channels indicate a power level below this value. 15.2.1.1.4 Power Range High Neutron Flux Reactor Trip (High Setting) The power range high neutron flux reactor trip (high setting) is actuated when two-out-of-four power range channels indicate a power level above a preset setpoint. This trip function is always active. In addition, control rod stops on high intermediate range flux level (one-of-two) and high power range flux level (one-out-of-four) serve to discontinue rod withdrawal and prevent the need to actuate the intermediate range flux level trip and the power range flux level trip, respectively. 15.2.1.1.5 High Neutron Flux Rate Trip The high neutron flux rate trip is actuated when the rate of change in power exceeds the positive or negative setpoint in two-out-of-four power range channels. This function is always active. The negative flux rate trip (NFRT) only applies to Unit 1.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-4 Revision 21 September 2013 15.2.1.2 Analysis of Effects and Consequences This transient is analyzed by three digital computer codes. The TWINKLE (Reference 2) code is used to calculate the reactivity transient and hence the nuclear power transient. The FACTRAN (Reference 3) code is then used to calculate the thermal heat flux transient based on the nuclear power transient calculated by the TWINKLE code. FACTRAN also calculates the fuel, cladding, and coolant temperatures. A detailed thermal and hydraulic computer code, THINC (Reference 9) is used to determine if DNB occurs.
In order to give conservative results for a startup accident, the following assumptions are made concerning the initial reactor conditions:
(1) Since the magnitude of the power peak reached during the initial part of the transient for any given rate of reactivity insertion is strongly dependent on the Doppler coefficient, conservative values (low absolute magnitude) as a function of power are used. See Section 15.1.6 and Table 15.1-4. (2) Contribution of the moderator reactivity coefficient is negligible during the initial part of the transient because the heat transfer time between the fuel and the moderator is much longer than the neutron flux response time.
However, after the initial neutron flux peak, the succeeding rate of power increase is affected by the moderator reactivity coefficient. The conservative value, given in Table 15.1-4, is used in the analysis to yield the maximum peak heat flux. (3) The reactor is assumed to be at hot zero power. This assumption is more conservative than that of a lower initial system temperature. The higher initial system temperature yields a larger fuel-water heat transfer coefficient, larger specific heats, and a less negative (smaller absolute magnitude) Doppler coefficient, all of which tend to reduce the Doppler feedback effect thereby increasing the neutron flux peak. The initial effective multiplication factor is assumed to be 1 since this results in maximum neutron flux peaking. (4) Reactor trip is assumed to be initiated by power range high neutron flux (low setting). The most adverse combination of instrument and setpoint errors, as well as delays for trip signal actuation and RCCA release, is taken into account. A 10 percent increase is assumed for the power range flux trip setpoint, raising it from the nominal value of 25 to 35 percent. Previous results, however, show that the rise in neutron flux is so rapid that the effect of errors in the trip setpoint on the actual time at which the rods are released is negligible. In addition, the reactor trip insertion characteristic is based on the assumption that the highest worth RCCA is stuck in its fully withdrawn position. See Section 15.1.5 for RCCA insertion characteristics. DCPP UNITS 1 & 2 FSAR UPDATE 15.2-5 Revision 21 September 2013 (5) The maximum positive reactivity insertion rate assumed is greater than that for the simultaneous withdrawal of the combination of the two control banks having the greatest combined worth at maximum speed (45 inches/minute). Control rod drive mechanism design is discussed in Section 4.2.3. (6) The initial power level was assumed to be below the power level expected for any shutdown condition. The combination of highest reactivity insertion rate and lowest initial power produces the highest peak heat flux. 15.2.1.3 Results Figures 15.2.1-1 through 15.2.1-3 show the transient behavior for the indicated reactivity insertion rate with the accident terminated by reactor trip at 35 percent nominal power. This insertion rate is greater than that for the two highest worth control banks, both assumed to be in their highest incremental worth region.
Figure 15.2.1-1 shows the neutron flux transient. The neutron flux overshoots the full power nominal value but this occurs for only a very short time period. Hence, the energy release and the fuel temperature increase are relatively small. The thermal flux response, of interest for departure from nucleate boiling (DNB) considerations, is shown in Figure 15.2.1-2. The beneficial effect on the inherent thermal lag in the fuel is evidenced by a peak heat flux less than the full power nominal value. The DNBR remains above the applicable safety analysis limit value at all times.
Figure 15.2.1-3 shows the response of the average fuel, cladding, and coolant temperatures at the hot spot. 15.2.1.4 Conclusions In the event of an RCCA withdrawal accident from the subcritical condition, the core and the RCS are not adversely affected since the combination of thermal power and the coolant temperature result in a DNBR above the limiting value. 15.2.2 UNCONTROLLED ROD CLUSTER CONTROL ASSEMBLY BANK WITHDRAWAL AT POWER 15.2.2.1 Identification of Causes and Accident Description Uncontrolled RCCA bank withdrawal at power results in an increase in the core heat flux. Since the heat extraction from the steam generator lags behind the core power generation until the steam generator pressure reaches the relief or safety valve setpoint, there is a net increase in the reactor coolant temperature. Unless terminated by manual or automatic action, the power mismatch and resultant coolant temperature rise would eventually result in DNB, an RCS overpressure condition, or the pressurizer filled with liquid. Therefore, the reactor protection system is designed to terminate any such DCPP UNITS 1 & 2 FSAR UPDATE 15.2-6 Revision 21 September 2013 transient before the DNBR falls below the safety analysis limit values, the RCS pressure exceeds 110 percent of the design value, or the pressurizer becomes filled with liquid.
The automatic features of the reactor protection system that ensure these limits are not exceeded following the postulated accident include the following:
(1) The power range neutron flux instrumentation actuates a reactor trip if two-out-of-four channels exceed a high flux or a positive flux rate high setpoint. (2) The reactor trip is actuated if any two-out-of-four T channels exceed an overtemperature T setpoint. This setpoint is automatically varied with axial power imbalance, coolant temperature, and pressure to protect against DNB. (3) The reactor trip is actuated if any two-out-of-four T channels exceed an overpower T setpoint. (4) A high pressurizer pressure reactor trip actuated from any two-out-of-four pressure channels that are set at a fixed point. This set pressure is less than the set pressure for the pressurizer safety valves. (5) A high pressurizer water level reactor trip actuated from any two-out-of-three level channels that are set at a fixed point.
In addition to the above listed reactor trips, there are the following RCCA withdrawal blocks:
(1) High neutron flux (one-out-of-four) (2) Overpower T (two-out-of-four) (3) Overtemperature T (two-out-of-four)
Reference 18 documents that the generic and conservatively bounding evaluations have been performed to ensure that the RCS overpressure and the pressurizer overfill conditions are not a concern for this event. One evaluation demonstrates that the positive flux rate trip provides adequate protection to ensure that the most limiting RCCA withdrawal event with respect to RCS pressure does not result in the peak RCS pressure exceeding 110 percent of the design limit. The positive flux rate trip setpoint and response time that are credited for this evaluation are listed in Table 15.1-2. Another evaluation demonstrates that the pressurizer water level high trip prevents a pressurizer overfill condition for those RCCA withdrawal events that are very slow and do not generate any other automatic protection signal. The pressurizer water level high trip response time is listed as N/A with the note indicating that the evaluation results are extremely insensitive to the assumed response time. DCPP UNITS 1 & 2 FSAR UPDATE 15.2-7 Revision 21 September 2013 The generic evaluations of Reference 18 establish that the RCS overpressure and pressurizer overfill criteria are much less limiting, and only the minimum DNBR analysis is described in detail within this section. The manner in which the combination of overpower and overtemperature T trips provide fuel cladding protection over the full range of RCS conditions is described in Chapter 7. This includes a plot (also shown as Figure 15.1-1) presenting allowable reactor coolant loop average temperature and T for the design power distribution and flow as a function of primary coolant pressure. The boundaries of operation defined by the overpower T trip and the overtemperature T are represented as protection lines on this diagram. The protection lines are drawn to include all adverse instrumentation and setpoint errors so that under nominal conditions trip would occur well within the area bounded by these lines. The utility of this diagram is in the fact that the limit imposed by any given DNBR can be represented as a line. The DNB lines represent the locus of conditions for which the DNBR equals the safety analysis limit values. All points below and to the left of a DNB line for a given pressure have a DNBR greater than the limit. The diagram shows that DNB is prevented for all cases if the area enclosed with the maximum protection lines is not traversed by the applicable DNBR line at any point.
The area of permissible operation (power, pressure, and temperature) is bounded by the combination of reactor trips: high neutron flux (fixed setpoint); high-pressure (fixed setpoint); low-pressure (fixed setpoint); overpower and overtemperature T (variable setpoints). 15.2.2.2 Analysis of Effects and Consequences This transient is analyzed by the LOFTRAN (Reference 4) code. This code simulates the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generator, and steam generator safety valves. The code computes pertinent plant variables including temperatures, pressures, and power level. The core limits as illustrated in Figure 15.1-1 are used as input to LOFTRAN to determine the minimum DNBR during the transient.
This accident is analyzed with the Improved Thermal Design Procedure as described in Reference 5. In order to obtain conservative results, the following assumptions are made:
(1) Initial conditions of nominal core power and reactor coolant average temperatures (including 2.5°F for steam generator fouling) and nominal reactor coolant pressure, are assumed. Uncertainties in initial conditions are included in the limit DNBR as described in Reference 5. (2) Reactivity Coefficients - two cases are analyzed: (a) Minimum reactivity feedback. A positive moderator coefficient of reactivity of +5 pcm/°F is assumed. A variable Doppler power DCPP UNITS 1 & 2 FSAR UPDATE 15.2-8 Revision 21 September 2013 coefficient with core power is used in the analysis. A conservatively small (in absolute magnitude) value is assumed. (b) Maximum reactivity feedback. A conservatively large positive moderator density coefficient and a large (in absolute magnitude) negative Doppler power coefficient are assumed. (3) The reactor trip on high neutron flux is assumed to be actuated at a conservative value of 118 percent of nominal full power. The T trips include all adverse instrumentation and setpoint errors, while the delays for the trip signal actuation are assumed at their maximum values. (4) The RCCA trip insertion characteristic is based on the assumption that the highest worth assembly is stuck in its fully withdrawn position. (5) The maximum positive reactivity insertion rate is greater than that which would be obtained from the simultaneous withdrawal of the two control rod banks having the maximum combined worth at maximum speed.
The effect of RCCA movement on the axial core power distribution is accounted for by causing a decrease in overtemperature T trip setpoint proportional to a decrease in margin to DNB. 15.2.2.3 Results Figures 15.2.2-1 and 15.2.2-2 show the response of neutron flux, pressure, average coolant temperature, and DNBR due to a rapid RCCA withdrawal starting from full power. Reactor trip on high neutron flux occurs shortly after the start of the accident. Since this is rapid with respect to the thermal time constants of the plant, small changes in Tavg and pressure result and a large margin to DNB is maintained. The response of neutron flux, pressure, average coolant temperature, and DNBR for a slow control rod assembly withdrawal from full power is shown in Figures 15.2.2-3 and 15.2.2-4. Reactor trip on overtemperature T occurs after a longer period and the rise in temperature and pressure is consequently larger than for rapid RCCA withdrawal. Again, the minimum DNBR is never less than the safety analysis limit values.
Figure 15.2.2-5 shows the minimum DNBR as a function of reactivity insertion rate from initial full power operation for the minimum and for the maximum reactivity feedbacks. It can be seen that two reactor trip channels provide protection over the whole range of reactivity insertion rates. These are the high neutron flux and overtemperature T trip channels. The minimum DNBR is never less than the safety analysis limit values.
Figures 15.2.2-6 and 15.2.2-7 show the minimum DNBR as a function of reactivity insertion rate for RCCA withdrawal incidents starting at 60 and 10 percent power, respectively. The results are similar to the 100 percent power case, except that as the DCPP UNITS 1 & 2 FSAR UPDATE 15.2-9 Revision 21 September 2013 initial power is decreased, the range over which the overtemperature T trip is effective is increased. In neither case does the DNBR fall below the safety analysis limit values.
The shape of the curves of minimum DNB ratio versus reactivity insertion rate in the reference figures is due both to reactor core and coolant system transient response and to protection system action in initiating a reactor trip. Referring to Figure 15.2.2-7, for example, it is noted that:
(1) For reactivity insertion rates above 30 pcm/sec reactor trip is initiated by the high neutron flux trip for the minimum reactivity feedback cases. The neutron flux level in the core rises rapidly for these insertion rates while core heat flux and coolant system temperature lag behind due to the thermal capacity of the fuel and coolant system fluid. Thus, the reactor is tripped prior to significant increase in heat flux or water temperature with resultant high minimum DNB ratios during the transient. As reactivity insertion rate decreases, core heat flux and coolant temperatures can remain more nearly in equilibrium with the neutron flux. Minimum DNBR during the transient thus decreases with decreasing insertion rate. (2) The Overtemperature T reactor trip circuit initiates a reactor trip when measured coolant loop T exceeds a setpoint based on measured RCS average temperature and pressure. It is important to note that the average temperature contribution to the circuit is lead-lag compensated in order to decrease the effect of the thermal capacity of the RCS in response to power increase. (3) For reactivity insertion rate below 30 pcm/sec the Overtemperature T trip terminates the transient. For reactivity insertion rates between 30 pcm/sec and 7 pcm/sec the effectiveness of the Overtemperature T trip increases (in terms of increased minimum DNBR) due to the fact that with lower insertion rates the power increase rate is slower, the rate of rise of average coolant temperature is slower and the system lags and delays become less significant. (4) For reactivity insertion rates less than 7 pcm/sec, the rise in the reactor coolant temperature is sufficiently high so that the steam generator safety valve setpoint is reached prior to trip. Opening of these valves, which act as an additional heat load on the RCS, sharply decreases the rate of increase of RCS average temperature. This decrease in rate of increase of the average RCS temperature during the transient is accentuated by the lead-lag compensation causing the Overtemperature T trip setpoint to be reached later with a resulting lower minimum DNBR.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-10 Revision 21 September 2013 Figures 15.2.2-5, 15.2.2-6, and 15.2.2-7 illustrate minimum DNBRs calculated for minimum and maximum reactivity feedback.
Since the RCCA withdrawal at power incident is an overpower transient, the fuel temperatures rise during the transient until after reactor trip occurs. For high reactivity insertion rates, the overpower transient is fast with respect to the fuel rod thermal time constant, and the core heat flux lags behind the neutron flux response. Due to this lag, the peak core heat flux does not exceed 118 percent of its nominal value (i.e., the high neutron flux trip setpoint assumed in the analysis). Taking into account the effect of the RCCA withdrawal on the axial core power distribution, the peak fuel centerline temperature will still remain below the fuel melting temperature.
For slow reactivity insertion rates, the core heat flux remains more nearly in equilibrium with the neutron flux. The overpower transient is terminated by the Overtemperature T reactor trip before a DNB condition is reached. The peak heat flux again is maintained below 118 percent of its nominal value. Taking into account the effect of the RCCA withdrawal on the axial core power distribution, the peak fuel centerline temperature will remain below the fuel melting temperature.
Since DNB does not occur at any time during the RCCA withdrawal at power transient, the ability of the primary coolant to remove heat from the fuel rod is not reduced. Thus, the fuel cladding temperature does not rise significantly above its initial value during the transient.
The calculated sequence of events for this accident is shown in Table 15.2-1. With the reactor tripped, the plant eventually returns to a stable condition. The plant may subsequently be cooled down further by following normal plant shutdown procedures. 15.2.2.4 Conclusions The high neutron flux and overtemperature T trip channels provide adequate protection over the entire range of possible reactivity insertion rates; i.e., the minimum value of DNBR is always larger than the safety analysis limit values. 15.2.3 ROD CLUSTER CONTROL ASSEMBLY MISOPERATION This section discusses RCCA misoperation that can result either from system malfunction or operator error. 15.2.3.1 Identification of Causes and Accident Description RCCA misalignment accidents include:
(1) One or more dropped RCCAs within the same group (2) A dropped RCCA bank DCPP UNITS 1 & 2 FSAR UPDATE 15.2-11 Revision 21 September 2013 (3) Statically misaligned RCCA Each RCCA has a position indicator channel that displays the position of the assembly.
The displays of assembly positions are grouped for the operator's convenience. Fully inserted assemblies are further indicated by a rod at bottom signal, which actuates a local alarm and a control room annunciator. Group demand position is also indicated.
RCCAs are always moved in preselected banks, and the banks are always moved in the same preselected sequence. Each bank of RCCAs is divided into two groups. The rods comprising a group operate in parallel through multiplexing thyristors. The two groups in a bank move sequentially such that the first group is always within one step of the second group in the bank. A definite schedule of actuation (or deactuation of the stationary gripper, movable gripper, and lift coils of a mechanism) is required to withdraw the RCCA attached to the mechanism. Since the stationary gripper, movable gripper, and lift coils associated with the four RCCAs of a rod group are driven in parallel, any single failure that would cause rod withdrawal would affect a minimum of one group. Mechanical failures are in the direction of insertion, or immobility.
A dropped RCCA, or RCCA bank, is detected by:
(1) A sudden drop in the core power level as seen by the nuclear instrumentation system (2) Asymmetric power distribution as seen on out-of-core neutron detectors or core-exit thermocouples (3) Rod at bottom signal (4) Rod deviation alarm (5) Rod position indication Misaligned RCCAs are detected by: (1) Asymmetric power distribution as seen on out-of-core neutron detectors or core-exit thermocouples (2) Rod deviation alarm (3) Rod position indicators The deviation alarm alerts the operator whenever an individual rod position signal deviates from the other rods in the bank by a preset limit.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-12 Revision 21 September 2013 During time intervals when the Rod Position Deviation Monitor is inoperable: (1) Each rod position indicator is determined to be operable by verifying that the Demand Position Indication System and the Digital Rod Position Indication System agree within 12 steps at least once per four hours. During time intervals when the rod insertion limit monitor is inoperable, the individual rod positions are verified to be within insertion limits at least once per four hours.
If one or more rod position indicator channels should be out of service, detailed operating instructions are followed to ensure the alignment of the nonindicated RCCAs. The operator is also required to take action as required by the Technical Specifications (TS). 15.2.3.2 Analysis of Effects and Consequences Method of Analysis (1) One or More Dropped RCCAs from the Same Group For evaluation of the dropped RCCA event, the transient system response is calculated using the LOFTRAN code. The code simulates the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generator, and steam generator safety valves. The code computes pertinent plant variables including temperatures, pressures, and power level. Statepoints are calculated and nuclear models are used to obtain a hot channel factor consistent with the primary system conditions and reactor power. By incorporating the primary conditions from the transient and the hot channel factor from the nuclear analysis, the DNB design basis is shown to be met using the THINC code. The transient response, nuclear peaking factor analysis, and DNB design basis confirmation are performed in accordance with the methodology described in Reference 10. (2) Dropped RCCA Bank A dropped RCCA bank results in a symmetric power change in the core. As discussed in Reference 10, assumptions made for the dropped RCCA(s) analysis provide a bounding analysis for the dropped RCCA bank. (3) Statically Misaligned RCCA Steady state power distributions are analyzed using the computer codes as described in Table 4.1-2. The peaking factors are then used as input to DCPP UNITS 1 & 2 FSAR UPDATE 15.2-13 Revision 21 September 2013 the THINC code to calculate the DNBR. The analysis examines the case of the worst rod withdrawn from control bank D inserted at the insertion limit with the reactor initially at full power. The analysis assumes this incident to occur at beginning of life or the time in core life which this results in the minimum value of moderator temperature coefficient. This assumption maximizes the power rise and minimizes the tendency of increased moderator temperature to flatten the power distribution. 15.2.3.3 Results (1) One or More Dropped RCCAs Single or multiple dropped RCCAs within the same group result in a negative reactivity insertion. The core is not adversely affected during this period since power is decreasing rapidly. Power may be reestablished either by reactivity feedback or control bank withdrawal. Following a dropped rod event in manual rod control, the plant will establish a new equilibrium condition. The equilibrium process without control system interaction is monotonic, thus removing power overshoot as a concern and establishing the automatic rod control mode of operation as the limiting case. For a dropped RCCA event in the automatic rod control mode, the rod control system detects the drop in power and initiates control bank withdrawal. Power overshoot may occur due to this action by the automatic rod controller after which the control system will insert the control bank to restore nominal power. Figures 15.2.3-1 and 15.2.3-2 show a typical transient response to a dropped RCCA(s) in automatic control. Uncertainties in the initial conditions are included in the DNB evaluation as described in Reference 10. In all cases, the minimum DNBR remains above the safety analysis limit value.
Following plant stabilization, the operator may manually retrieve the RCCA(s) by following approved operating procedures. (2) Dropped RCCA Bank A dropped RCCA bank typically results in a reactivity insertion of greater than 500 pcm. The core is not adversely affected during this period since power is decreasing rapidly. The one or more dropped RCCA(s) transient will proceed as described in the previous section, except the return to power will be less due to the greater worth of the entire bank. The power transient for a dropped RCCA bank is symmetric. Following plant stabilization, normal procedures are followed. DCPP UNITS 1 & 2 FSAR UPDATE 15.2-14 Revision 21 September 2013 (3) Statically Misaligned RCCA The most severe misalignment situations with respect to DNBR at significant power levels arise from cases in which one RCCA is fully inserted, or where Bank D is fully inserted with one RCCA fully withdrawn. Multiple independent alarms, including a bank insertion limit alarm, alert the operator well before the postulated conditions are approached. The bank can be inserted to its insertion limit with any one assembly fully withdrawn without the DNBR falling below the limit value. The insertion limits in the TS may vary from time to time depending on a number of limiting criteria. The full power insertion limits on control bank D must be chosen to be above that position which meets the minimum DNBR and peaking factor limits. The full power insertion limits is usually dictated by other criteria. Detailed results will vary from cycle to cycle depending on fuel arrangements. For this RCCA misalignment, with Bank D inserted to its full power insertion limit and one RCCA fully withdrawn, DNBR does not fall below the safety analysis limit value. This case is analyzed assuming the initial reactor power, pressure, and RCS temperatures are at their nominal values but with the increased radial peaking factor associated with the misaligned RCCA. For RCCA misalignments with one RCCA fully inserted, the DNBR does not fall below the limit value. This case is analyzed assuming the initial reactor power, pressure, and RCS temperatures are at their nominal values, but with the increased radial peaking factor associated with the misaligned RCCA. DNB does not occur for the RCCA misalignment incident and thus the ability of the primary coolant to remove heat from the fuel rod is not reduced. The peak fuel temperature corresponds to a linear heat generation rate based on the radial peaking factor penalty associated with the misaligned RCCA and the design axial power distribution. The resulting linear heat generation is well below that which would cause fuel melting.
Following the identification of an RCCA group misalignment condition by the operator, the operator is required to take action as required by the plant TS and operating instructions. 15.2.3.4 Conclusions For all cases of dropped RCCAs or dropped banks, the DNBR remains greater than the safety analysis limit value, therefore, the DNB design criterion is met. DCPP UNITS 1 & 2 FSAR UPDATE 15.2-15 Revision 21 September 2013 For all cases of any RCCA inserted, or Bank D inserted to its rod insertion limits with any single RCCA in that bank fully withdrawn (static misalignment), the DNBR remains greater than the safety analysis limit value. 15.2.4 UNCONTROLLED BORON DILUTION 15.2.4.1 Identification of Causes and Accident Description Reactivity can be added to the core by feeding unborated water into the RCS via the reactor makeup portion of the chemical and volume control system (CVCS). Boron dilution is a manual operation under strict administrative controls with procedures calling for a limit on the rate and duration of dilution. A boric acid blend system is provided to permit the operator to match the boron concentration of reactor coolant makeup water to that in the RCS during normal makeup injection. The CVCS is designed to limit, even under various postulated failure modes, the potential rate of dilution to a value, which after indication through alarms and instrumentation, provides the operator with sufficient time to correct the situation in a safe and orderly manner.
The opening of the primary water makeup control valves provides makeup to the RCS that can dilute the reactor coolant. Inadvertent dilution from this source can be readily terminated by closing the control valve. In order for makeup water to be added to the RCS at pressure, at least one charging pump must be running in addition to a primary makeup water pump.
The rate of addition of unborated makeup water to the RCS when it is not at pressure is limited by the capacity of the primary water supply pumps. The maximum addition rate in this case is 300 gpm, which is based on the capacity of one operable primary water supply pump.
The boric acid from the boric acid tank is blended with primary grade water in the blender and the composition is determined by the preset flowrates of boric acid and primary grade water on the control board. In order to dilute, two separate operations are required:
(1) The operator must select from the automatic makeup mode to the dilute mode (2) The operator must select start to initiate system start Omitting either step would prevent dilution.
Information on the status of the reactor coolant makeup is continuously available to the operator. Lights are provided on the control board to indicate the operating condition of the pumps in the CVCS. Alarms are actuated to warn the operator if boric acid or demineralized water flowrates deviate from preset values as a result of system malfunction. DCPP UNITS 1 & 2 FSAR UPDATE 15.2-16 Revision 21 September 2013 15.2.4.2 Analysis of Effects and Consequences 15.2.4.2.1 Method of Analysis To cover all phases of the plant operation, boron dilution during refueling, startup, and power operation is considered in this analysis. Table 15.2-1 contains the time sequence of events for this accident. 15.2.4.2.2 Dilution During Refueling During refueling the following conditions exist:
(1) One residual heat removal (RHR) pump is operating to ensure continuous mixing in the reactor vessel. (2) The seal injection water supply to the reactor coolant pumps is typically isolated for the purpose of performing RCP maintenance. (3) Boric acid supply to the suction of the charging pumps is available for the addition of boric acid to the RCS. Alternatively, boric acid supply may be lined up to the suction of the safety injection pumps when all the reactor vessel head bolts are fully detensioned. (4) The boron concentration in the refueling water is 2000 ppm, corresponding to a shutdown margin of at least 5 percent k with all RCCAs in; periodic sampling ensures that this concentration is maintained. (5) Neutron sources are installed in the core and the source range detectors outside the reactor vessel are active and provide an audible count rate.
During initial core loading, BF3 detectors are installed inside the reactor vessel and are connected to instrumentation giving audible count rates to provide direct monitoring of the core. A minimum water volume in the RCS of 5717 cubic feet is considered. This corresponds to the volume necessary to fill the reactor vessel above the nozzles to ensure mixing via the RHR loop. A maximum dilution flow of 300 gpm and uniform mixing are assumed.
The operator has prompt and definite indication of any boron dilution from the audible count rate instrumentation. High count rate is alarmed in the control room. Count rate will increase with the subcritical multiplication factor during boron dilution.
If a safety injection pump is used for boration, it is aligned to take suction from the RWST and discharge to the cold legs of the RCS, and the boundary valves from the DCPP UNITS 1 & 2 FSAR UPDATE 15.2-17 Revision 21 September 2013 CVCS to the SIS are closed. These requirements ensure no new dilution flowpaths are introduced when using the SIS boration flowpath. 15.2.4.2.3 Dilution During Startup The RCS is filled with borated water from the refueling water storage tank (RWST) prior to startup. This is modeled as 2000 ppm boron, which is conservative. DCPP TS limit the RWST to a minimum of 2300 ppm boron.
Core monitoring is by external BF3 detectors. Mixing of the reactor coolant is accomplished by operation of the reactor coolant pumps. High source range flux level and all reactor trip alarms are effective. In the analysis, a maximum dilution flow of 300 gpm limited by the capacity of the two primary water makeup pumps is considered. The volume of the reactor coolant is approximately 9153 cubic feet, which is the active volume of the RCS excluding the pressurizer. 15.2.4.2.4 Dilution at Power With the unit at power and the RCS at pressure, the dilution rate is limited by the capacity of the charging pumps. The effective reactivity addition rate for the reactor at full power and for a boron dilution flow of 262 gpm is shown as a function of RCS boron concentration in Figure 15.2.4-1. This figure includes the effect of increasing boron worth with dilution. The reactivity rate used in the following evaluation is 1.752 x 10-5 k/sec based on a conservatively high value for the expected boron concentration (1600 ppm) at power. 15.2.4.3 Conclusions For dilution during refueling and startup, the analysis assumes the following. As noted above, DCPP TS now require 2300 ppm boron. The numbers below are conservative.
At the beginning of the core life, equilibrium cycle core, the boron concentration must be reduced from 2000 ppm to approximately 1600 ppm before the reactor will go critical. This takes 32 minutes. This is ample time for the operator to recognize a high count rate signal and isolate the reactor makeup water source by closing valves and stopping the primary water supply pumps.
During startup, the minimum time required to reduce the reactor coolant boron concentration to 1600 ppm, where the reactor would go critical with all RCCAs in, is 38 minutes. Once again, this should be more than adequate time for the operator to recognize the high count rate signal and terminate the dilution flow.
For dilution during full power operation:
(1) With the reactor in automatic control at full power, the power and temperature increase from boron dilution results in the insertion of the DCPP UNITS 1 & 2 FSAR UPDATE 15.2-18 Revision 21 September 2013 RCCAs and a decrease in shutdown margin. Continuation of dilution and RCCA insertion would cause the assemblies to reach the minimum limit of the rod insertion monitor in approximately 4.7 minutes, assuming the RCCAs to be initially at a position providing the maximum operational maneuvering band consistent with maintaining a minimum control band incremental rod worth. Before reaching this point, however, two alarms would be actuated to warn the operator of the accident condition. The first of these, the low insertion limit alarm, alerts the operator to initiate normal boration. The other, the low-low insertion limit alarm, alerts the operator to follow emergency boration procedures. The low alarm is set sufficiently above the low-low alarm to allow normal boration without the need for emergency procedures. If dilution continues after reaching the low-low alarm, it takes approximately 15.0 minutes after the low-low alarm before the total shutdown margin (assuming 1.6 percent) is lost due to dilution. Therefore, adequate time is available following the alarms for the operator to determine the cause, isolate the primary grade water source, and initiate boration. (2) With the reactor in manual control and if no operator action is taken, the power and temperature rise will cause the reactor to reach the high neutron flux or overtemperature T trip setpoint. The boron dilution accident in this case is essentially identical to a RCCA withdrawal accident at power. The maximum reactivity insertion rate for boron dilution is shown in Figure 15.2.4-1 and is seen to be within the range of insertion rates analyzed for a RCCA withdrawal accident. There is ample time available (approximately 14.5 minutes) after a reactor trip for the operator to determine the cause of dilution, isolate the primary grade water sources, and initiate reboration before the reactor can return to criticality assuming a 1.6 percent shutdown margin at the beginning of dilution. 15.2.5 PARTIAL LOSS OF FORCED REACTOR COOLANT FLOW 15.2.5.1 Identification of Causes and Accident Description A partial loss of coolant flow accident can result from a mechanical or electrical failure in a reactor coolant pump, or from a fault in the power supply to the pump. If the reactor is at power at the time of the accident, the immediate effect of loss of coolant flow is a rapid increase in the coolant temperature. This increase could result in DNB with subsequent fuel damage if the reactor is not tripped promptly.
The necessary protection against a partial loss of coolant flow accident is provided by the low primary coolant flow reactor trip that is actuated by two-out-of-three low flow signals in any reactor coolant loop. Above approximately 35 percent power (Permissive 8), low flow in any loop will actuate a reactor trip. Between approximately DCPP UNITS 1 & 2 FSAR UPDATE 15.2-19 Revision 21 September 2013 10 percent power (Permissive 7) and the power level corresponding to Permissive 8 low flow in any two loops will actuate a reactor trip. Reactor trip on low flow is blocked below Permissive 7.
A reactor trip signal from the pump breaker position is provided as a backup to the low flow signal. When operating above Permissive 7, a breaker open signal from any two pumps will actuate a reactor trip. Reactor trip on reactor coolant pump breakers open signal is blocked below Permissive 7.
Normal power for the pumps is supplied through buses connected through transformers to the generator. Two pump buses each supply power to two pumps. When a generator trip occurs, the pumps are automatically transferred to a bus supplied from external power lines, and the pumps will continue to supply coolant flow to the core. Following any turbine trip where there are no electrical or mechanical faults that require immediate tripping of the generator from the network, the generator remains connected to the network for approximately 30 seconds. The reactor coolant pumps remain connected to the generator thus ensuring full flow for approximately 30 seconds after the reactor trip before any transfer is made. 15.2.5.2 Analysis of Effects and Consequences 15.2.5.2.1 Method of Analysis The following case has been analyzed:
(1) All loops operating, two loops coasting down. This transient is analyzed by three digital computer codes. First the LOFTRAN code is used to calculate the loop and core flow during the transient. The LOFTRAN code is also used to calculate the time of reactor trip, based on the calculated flows and the nuclear power transient following reactor trip. The FACTRAN code is then used to calculate the heat flux transient based on the nuclear power and flow from LOFTRAN.
Finally, the THINC code is used to calculate the minimum DNBR during the transient based on the heat flux from FACTRAN and the flow from LOFTRAN. The DNBR transient presented represents the minimum of the typical and thimble cells for Standard and VANTAGE 5 fuel. 15.2.5.2.2 Initial Conditions The assumed initial operating conditions are the most adverse with respect to the margin to DNB, i.e., nominal steady state power level, nominal steady state pressure, and nominal steady state coolant average temperature (with 2.5°F for steam generator fouling). See Section 15.1.2 for an explanation of initial conditions. The accident is analyzed using the Improved Thermal Design Procedure as described in Reference 5.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-20 Revision 21 September 2013 15.2.5.2.3 Reactivity Coefficients A conservatively large absolute value of the Doppler-only power coefficient is used (see Table 15.1-4). The total integrated Doppler reactivity from 0 to 100 percent power is assumed to be -0.016 k. The most positive moderator temperature coefficient (+5 pcm/°F) is assumed since this results in the maximum hot spot heat flux during the initial part of the transient when the minimum DNBR is reached. 15.2.5.2.4 Flow Coastdown The flow coastdown analysis is based on a momentum balance around each reactor coolant loop and across the reactor core. This momentum balance is combined with the continuity equation, a pump momentum balance, and the pump characteristics and is based on high estimates of system pressure losses. 15.2.5.3 Results The calculated sequence of events is shown in Table 15.2-1. Figures 15.2.5-1 through 15.2.5-4 show the core flow coastdown, the loop flow coastdown, the heat flux coastdown, and the nuclear power coastdown. The minimum DNBR is not less then the safety analysis limit value. A plot of DNBR vs. time is given in Figure 15.2.5-5 for the most limiting typical or thimble cell for Standard and VANTAGE 5 fuel. 15.2.5.4 Conclusions The analysis shows that the DNBR will not decrease below the safety analysis limiting values at any time during the transient. Thus no core safety limit is violated. 15.2.6 STARTUP OF AN INACTIVE REACTOR COOLANT LOOP In accordance with the TS, DCPP operation during startup and power operation with less than four loops is not permitted. This analysis is presented for completeness. 15.2.6.1 Identification of Causes and Accident Description If a plant is operating with one pump out of service, there is reverse flow through the loop due to the pressure difference across the reactor vessel. The cold leg temperature in an inactive loop is identical to the cold leg temperature of the active loops (the reactor core inlet temperature). If the reactor is operated at power, and assuming the secondary side of the steam generator in the inactive loop is not isolated, there is a temperature drop across the steam generator in the inactive loop and, with the reverse flow, the hot leg temperature of the inactive loop is lower than the reactor core inlet temperature.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-21 Revision 21 September 2013 Starting of an idle reactor coolant pump without bringing the inactive loop hot leg temperature close to the core inlet temperature would result in the injection of cold water into the core, which causes a rapid reactivity insertion and subsequent power increase.
This event is classified as an ANS Condition II incident (an incident of moderate frequency) as defined at the beginning of this chapter.
Should the startup of an inactive reactor coolant pump at an incorrect temperature occur, the transient will be terminated automatically by a reactor trip on low coolant loop flow when the power range neutron flux (two-out-of-four channels) exceeds the P-8 setpoint, which has been previously reset for three-loop operation. 15.2.6.2 Analysis of Effects and Consequences This transient is analyzed by three digital computer codes. The LOFTRAN Code (Reference 4) is used to calculate the loop and core flow, nuclear power and core pressure and temperature transients following the startup of an idle pump. FACTRAN (Reference 3) is used to calculate the core heat flux transient based on core flow and nuclear power from LOFTRAN. The THINC Code (Reference 9) is then used to calculate the DNBR during the transient based on system conditions (pressure, temperature, and flow) calculated by LOFTRAN and heat flux as calculated by FACTRAN.
In order to obtain conservative results for the startup of an inactive pump accident, the following assumptions are made: (1) Initial conditions of maximum core power and reactor coolant average temperatures and minimum reactor coolant pressure resulting in minimum initial margin to DNB. A 25 percent maximum steady state power level including appropriate allowances for calibration and instrument errors is assumed, however DCPP is not allowed to be at power with an inactive loop. The high initial power gives the greatest temperature difference between the core inlet temperature and the inactive loop hot leg temperature. (2) Following the start of the idle pump, the inactive loop flow reverses and accelerates to its nominal full flow value. (3) A conservatively large (absolute value) negative moderator coefficient associated with the end of life. (4) A conservatively low (absolute value) negative Doppler power coefficient is used. DCPP UNITS 1 & 2 FSAR UPDATE 15.2-22 Revision 21 September 2013 (5) The initial reactor coolant loop flows are at the appropriate values for one pump out of service. (6) The reactor trip is assumed to occur on low coolant flow when the power range neutron flux exceeds the P-8 setpoint, which has been reset for N-1 loop operation. The P-8 setpoint is conservatively assumed to be 84 percent of rated power, which corresponds to the nominal N-1 loop operation setpoint plus 9 percent for nuclear instrumentation errors. 15.2.6.3 Results The results following the startup of an idle pump with the above listed assumptions are shown in Figures 15.2.6-1 through 15.2.6-5. As shown in these curves, during the first part of the transient, the increase in core flow with cooler water results in an increase in nuclear power and a decrease in core average temperature. The minimum DNBR during the transient is considerably greater than the safety analysis limit values.
Reactivity addition for the inactive loop startup accident is due to the decrease in core water temperature. During the transient, this decrease is due both to a) the increase in reactor coolant flow, and b) as the inactive loop flow reverses, to the colder water entering the core from the hot leg side (colder temperature side prior to the start of the transient) of the steam generator in the inactive loop. Thus, the reactivity insertion rate for this transient changes with time. The resultant core nuclear power transient, computed with consideration of both moderator and Doppler reactivity feedback effects, is shown in Figure 15.2.6-1. The calculated sequence of events for this accident is shown in Table 15.2-1. The transient results illustrated in Figures 15.2.6-1 through 15.2.6-5 indicate that a stabilized plant condition, with the reactor tripped, is approached rapidly. Plant cooldown may subsequently be achieved by following normal shutdown procedures. 15.2.6.4 Conclusions The transient results show that the core is not adversely affected. There is considerable margin to the safety analysis DNBR limit values; thus, no fuel or cladding damage is predicted. 15.2.7 LOSS OF EXTERNAL ELECTRICAL LOAD AND/OR TURBINE TRIP 15.2.7.1 Identification of Causes and Accident Description A major load loss on the plant can result from either a loss of external electrical load or from a turbine trip. For either case, offsite power is available for the continued operation of plant components such as the reactor coolant pumps. The case of loss of offsite power is analyzed in Section 15.2.9.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-23 Revision 21 September 2013 For a turbine trip, the reactor would be tripped directly (unless it is below the P-9 setpoint) from a signal derived from the turbine autostop oil pressure and turbine stop valves. The automatic steam dump system accommodates the excess steam generation. Reactor coolant temperatures and pressure do not significantly increase if the steam dump system and pressurizer pressure control system are functioning properly. If the turbine condenser were not available, the excess steam generation would be dumped to the atmosphere. Additionally, main feedwater flow would be lost if the turbine condenser were not available. For this situation, steam generator level would be maintained by the auxiliary feedwater system.
For a loss of external electrical load without subsequent turbine trip, no direct reactor trip signal would be generated. A continued steam load of approximately 5 percent would exist after total loss of external electrical load because of the electrical demand of plant auxiliaries.
In the event the steam dump valves fail to open following a large loss of load, the steam generator safety valves may lift and the reactor may be tripped by the high pressurizer pressure signal, the high pressurizer water level signal, or the overtemperature T signal. The steam generator shell-side pressure and reactor coolant temperatures will increase rapidly. The pressurizer safety valves and steam generator safety valves are, however, sized to protect the RCS and steam generator against overpressure for all load losses without assuming the operation of the steam dump system, pressurizer spray, pressurizer power-operated relief valves, automatic RCCA control, or direct reactor trip on turbine trip.
The steam generator safety valve capacity is sized to remove the steam flow at the engineered safeguards design rating (105 percent of steam flow at rated power) from the steam generator without exceeding 110 percent of the steam system design pressure. The pressurizer safety valve capacity is sized based on a complete loss of heat sink with the plant initially operating at the maximum calculated turbine load along with operation of the steam generator safety valves. The pressurizer safety valves are then able to maintain the RCS pressure within 110 percent of the RCS design pressure without direct or immediate reactor trip action.
A more complete discussion of overpressure protection can be found in Reference 8. 15.2.7.2 Analysis of Effects and Consequences In this analysis, the behavior of the unit is evaluated for a complete loss of steam load from full power without a direct reactor trip. This is done to show the adequacy of the pressure-relieving devices and to demonstrate core protection margins. The reactor is not tripped until conditions in the RCS result in a trip. The turbine is assumed to trip without actuating all the turbine stop valve limit switches. This assumption delays reactor trip until conditions in the RCS result in a trip due to other signals. Thus, the analysis assumes a worst case transient. In addition, no credit is taken for steam dump. Main feedwater flow is terminated at the time of turbine trip, with no credit taken for DCPP UNITS 1 & 2 FSAR UPDATE 15.2-24 Revision 21 September 2013 auxiliary feedwater (except for long-term recovery) to mitigate the consequences of the transient.
Total loss-of-load transients are analyzed for DNB and overpressure concerns. The LOFTRAN computer program (see Section 15.1) is used by Westinghouse to analyze the total loss of load transients for the DNB concern. The RETRAN-02 computer program (see Section 15.1) is used by DCPP to analyze the transients for the overpressure concern. Both programs simulate the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generator, and steam generator safety valves. The programs compute pertinent variables, including temperatures, pressures, and power level.
Major assumptions are summarized below:
(1) Initial Operating Conditions The initial reactor power, RCS pressure, and RCS temperatures are assumed at their nominal values consistent with steady state full power operation. (2) Moderator and Doppler Coefficients of Reactivity The turbine trip is analyzed with both maximum and minimum reactivity feedback. The maximum feedback (EOL) cases assume a large negative moderator temperature coefficient and the most negative Doppler power coefficient. The minimum feedback (BOL) cases assume a minimum moderator temperature coefficient and the least negative Doppler coefficient. (3) Reactor Control From the standpoint of the maximum pressures attained, it is conservative to assume that the reactor is in manual control. If the reactor were in automatic control, the control rod banks would move prior to trip and reduce the severity of the transient. (4) Steam Release No credit is taken for the operation of the steam dump system or steam generator power-operated relief valves. The steam generator pressure rises to the safety valve setpoint where steam release through safety valves limits secondary steam pressure at the setpoint value.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-25 Revision 21 September 2013 (5) Pressurizer Spray and Power-Operated Relief Valves For the DNB concern, two cases for both BOL and EOL are analyzed using the LOFTRAN computer program. For the overpressure concern, since the total loss of load transients result in higher peak RCS and steam generator pressures at BOL, the same two cases are analyzed using the RETRAN-02 computer program for BOL only. (a) Full credit is taken for the effect of pressurizer spray and power-operated relief valves in reducing or limiting the coolant pressure. Safety valves are also available. (b) No credit is taken for the effect of pressurizer spray and power-operated relief valves in reducing or limiting the coolant pressure. Safety valves are operable. (6) Feedwater Flow Main feedwater flow to the steam generators is assumed to be lost at the time of turbine trip. No credit is taken for auxiliary feedwater flow since a stabilized plant condition will be reached before auxiliary feedwater initiation is normally assumed to occur; however, the auxiliary feedwater pumps would be expected to start on a trip of the main feedwater pumps. The auxiliary feedwater flow would remove core decay heat following plant stabilization. The following assumptions are used in the RETRAN-02 analysis for the overpressure concern only.
(7) To enhance the main steam line safety valve model, the individual nominal setpoint, plus 3 percent tolerance for each safety valve, is modeled in the analysis. In other words, the main steam safety valves start to open when the steam pressure reaches their nominal setpoints plus 3 percent. Then, the main steam safety valves are assumed to linearly open with the pressure, until fully open at the 3 percent pressure accumulation (3 percent above the initial opening pressure). (8) The presence of a water loop seal delays the opening of the pressurizer safety valve. The loop seal water starts to leak out from the safety valve when the safety valve setpoint is reached. However, no pressure is relieved from the pressurizer until the loop seal water is completely purged, after which the safety valve pops full open in less than 0.1 second. The loop seal water purge time of 1.272 seconds was used in the analysis. All pressurizer safety valves have been converted to a steam-seat design and condensate in the loop is now continuously drained back to the pressurizer, thereby eliminating the water loop seal. Even though DCPP UNITS 1 & 2 FSAR UPDATE 15.2-26 Revision 21 September 2013 the water loop seal has been eliminated, the resulting benefit is not credited in the analysis. (9) The initial pressurizer pressure of 2176.9 psig is used in the analysis, which includes a 58.1 psi pressurizer pressure control uncertainty. (10) It is conservative to maximize the reactor power. Therefore, the reactor trip due to high neutron flux is not credited in the analysis.
Reactor trip is actuated by the first reactor protection system trip setpoint reached with no credit taken for the direct reactor trip on the turbine trip. 15.2.7.3 Results The transient responses for a total loss of load from full power operation are shown for four cases DNB concern is evaluated at BOL and EOL with pressure control and overpressure concern is evaluated at BOL with and without pressure control. Refer to Figures 15.2.7-1 through 15.2.7-4 and Figures 15.2.7-9 through 15.2.7-12.
Figures 15.2.7-1 and 15.2.7-2 show the transient responses for the total loss of steam load at BOL, for the DNB concern, assuming full credit for the pressurizer spray and pressurizer power-operated relief valves. No credit is taken for the steam dump. The reactor is tripped by the high pressurizer pressure trip channel. The minimum DNBR is well above the limit value.
Figures 15.2.7-3 and 15.2.7-4 show the responses for the total loss of load at EOL, for the DNB concern, assuming a large (absolute value) negative moderator temperature coefficient. All other plant parameters are the same as in the above case. As a result of the maximum reactivity feed at EOL, no reactor protection system trip setpoint is reached. Because main feedwater is assumed to be lost, the reactor is tripped by the low-low steam generator water level trip channel. The DNBR increases throughout the transient and never drops below its initial value. The pressurizer safety valves are not actuated in these transients.
Figures 15.2.7-9 and 15.2.7-10 show the transient responses for the total loss of load at BOL for the overpressure concern. No credit is taken for the pressurizer spray, pressurizer power-operated relief valves, or steam dump. The pressurizer and main steam safety valves are modeled as described in assumptions 7 and 8. The initial pressurizer pressure includes the pressurizer pressure control uncertainty to maximize the peak pressure. The reactor is tripped on the high pressurizer pressure signal. This case results in the highest RCS peak pressure among all cases. The peak RCS pressure is below 110 percent of the design value.
Figures 15.2.7-11 and 15.2.7-12 show the transient responses for the total loss of load at BOL for the overpressure concern, assuming full credit for the pressurizer spray and the pressurizer power-operated relief valves. No credit is taken for the steam dump. DCPP UNITS 1 & 2 FSAR UPDATE 15.2-27 Revision 21 September 2013 The models for the pressurizer and main steam safety valves and the initial pressurizer pressure are the same as those used in the above case. The reactor trip due to high neutron flux is not credited in order to maximize the peak steam generator pressure. The reactor is tripped on the high pressurizer pressure signal. This case results in the highest steam generator peak pressure among all cases. The peak steam generator pressure is below 110 percent of the design value.
Reference 8 presents additional results for a complete loss of heat sink including loss of main feedwater. This report shows the overpressure protection that is afforded by the pressurizer and steam generator safety valves.
Technical Specification 3.7.1 establishes reduced plant operating power limits for off normal conditions when one or more MSSVs are inoperable to ensure a loss of load event does not result in overpressurization of the steam generators. When two or more MSSVs are inoperable per steam generator loop, the reduced power limits are established using a conservative energy balance algorithm established in the Westinghouse Nuclear Safety Advisory Letter NSAL-94-001 as documented in Reference 21. To evaluate off normal plant operation with a single inoperable MSSV on one or more steam generator loops, an additional spectrum of loss of load analyses are performed as documented in Reference 22. These analyses use the RETRAN-02W code to analyze the BOL loss of load overpressure case as discussed in this section and which represents the limiting case for challenging the steam generator peak pressure limit. These analysis results, as summarized in the Technical Specification Bases 3.7.1, credit the overtemperature T reactor trip to demonstrate that the specified reduced operating power limit ensures that the available relief capacity with one inoperable MSSV per loop maintains the peak steam generator pressure below 110 percent of the design value. 15.2.7.4 Conclusions Results of the analyses, including those in Reference 8, show that the plant design is such that a total loss of external electrical load without a direct or immediate reactor trip presents no hazard to the integrity of the RCS or the main steam system. Pressure-relieving devices incorporated in the two systems are adequate to limit the maximum pressures to within the design limits.
The integrity of the core is maintained by operation of the reactor protection system; i.e., the DNBR will be maintained above the safety analysis limit values. Thus, no core safety limit will be violated. 15.2.8 LOSS OF NORMAL FEEDWATER 15.2.8.1 Identification of Causes and Accident Description A loss of normal feedwater (from pump failures, valve malfunctions, or loss of offsite ac power) results in a reduction in capability of the secondary system to remove the DCPP UNITS 1 & 2 FSAR UPDATE 15.2-28 Revision 21 September 2013 heat generated in the reactor core. If the reactor were not tripped during this accident, core damage would possibly occur from a sudden loss of heat sink. If an alternative supply of feedwater were not supplied to the plant, residual heat following reactor trip would heat the primary system water to the point where water relief from the pressurizer would occur. Significant loss of water from the RCS could conceivably lead to core damage. Since the plant is tripped well before the steam generator heat transfer capability is reduced, the primary system conditions never approach a DNB condition.
The following provide the necessary protection against a loss of normal feedwater:
(1) Reactor trip on low-low water level in any steam generator (2) Two motor-driven auxiliary feedwater (AFW) pumps that are started on: (a) Low-low level in any steam generator (b) Trip of both main feedwater pumps (c) Any safety injection signal (d) Loss of offsite power (automatic transfer to diesel generators) (e) Manual actuation (3) One turbine-driven auxiliary feedwater pump that is started on: (a) Low-low level in any two steam generators (b) Undervoltage on both reactor coolant pump buses (c) Manual actuation The motor-driven AFW pumps are connected to vital buses and are supplied by the diesels if a loss of offsite power occurs. The turbine-driven pump utilizes steam from the secondary system and exhausts it to the atmosphere. The controls are designed to start both types of pumps within 1 minute even if a loss of all ac power occurs simultaneously with loss of normal feedwater. The AFW pumps take suction from the condensate storage tank for delivery to the steam generators. Instrumentation is provided in the motor-driven pump discharge to sense low pump discharge pressure indicative of a depressurized steam generator. If low pump discharge pressure should occur, control valves automatically throttle down to prevent pump runout. This automatic action ensures that the required flow is maintained. However, no such instrumentation is provided for the turbine-driven pump and remote-manual action by the plant operator is required to terminate its flow to a depressurized steam generator.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-29 Revision 21 September 2013 The analysis shows that following a loss of normal feedwater, the AFW system is capable of removing the stored and residual heat thus preventing either overpressurization of the RCS or liquid relief through the pressurizer power operated relief valves or safety valves. 15.2.8.2 Analysis of Effects and Consequences A detailed analysis using the RETRAN-02W code (Reference 19) is performed in order to determine the plant transient following a loss of normal feedwater. The code describes the plant neutron kinetics, RCS including factors that influence the natural circulation, pressurizer, steam generators, and feedwater system, and compute pertinent variables, including the pressurizer pressure, pressurizer water level, and reactor coolant average temperature.
Major assumptions are:
(1) Reactor trip occurs on steam generator low-low level at 8 percent of narrow range span. (2) The plant is initially operating at 102 percent of the nuclear steam supply system (NSSS) rating, including a conservatively large RCP heat of 20 MWt. (3) Conservative core residual heat generation based on long-term operation at the initial power level preceding the trip is assumed. The ANSI/ANS-5.1-1979 + 2 was used for calculation of residual decay heat levels. (4) The auxiliary feedwater system is actuated by the low-low steam generator water level signal. (5) The limiting single failure in the auxiliary feedwater system occurs (turbine-driven pump failure). The auxiliary feedwater system is assumed to supply a total of 600 gpm to all four SGs from the motor-driven pumps. (6) The pressurizer sprays and heaters are assumed operable. This maximizes the peak transient pressurizer water volume. Sensitivity analyses determined that it is conservative to assume that the PORVs are inoperable (Reference 20). (7) Secondary system steam relief is achieved through the self-actuated safety valves. The main steam safety valves are assumed to begin to lift 3 percent above the set pressure with a 5 psi accumulation to full open.
Note that steam relief will, in fact, be through the power-operated relief valves or condenser dump valves for most cases of loss of normal feedwater. However, for the sake of analysis these have been assumed unavailable. DCPP UNITS 1 & 2 FSAR UPDATE 15.2-30 Revision 21 September 2013 (8) The initial reactor coolant average temperature is 5.5°F lower than the nominal value. The initial pressurizer pressure is 60 psi above the nominal value. (9) The minimum SGTP of 0 percent was assumed. (10) The initial feedwater temperature is assumed to be 435°F. 15.2.8.3 Results Figures 15.2.8-1 through 15.2.8-3 show plant parameters following a loss of normal feedwater at the conditions associated with Unit 2, which were determined to be limiting. Figure 15.2.8-2 shows the pressurizer pressure as a function of time.
Following the reactor and turbine trip from full load, the water level in the steam generators will fall due to the reduction of steam generator void fraction and because steam flow through the safety valves continues to dissipate the stored and generated heat. One minute following the initiation of the low-low level trip, the motor-driven AFW pumps are automatically started, reducing the rate of water level decrease.
The capacity of the motor-driven AFW pumps combined with the available secondary inventory is capable of dissipating the core residual heat without liquid water relief from the RCS relief or safety valves.
From Figure 15.2.8-2 it can be seen that at no time is there liquid relief from the pressurizer. If the AFW delivered is greater than that of two motor-driven pumps, the initial reactor power is less than 102 percent of the NSSS rating, or the steam generator water level in one or more steam generators is above the low-low level trip point at the time of trip, then the results for this transient will be less limiting.
The calculated sequence of events for this accident is listed in Table 15.2-1. As shown in Figures 15.2.8-1 through 15.2.8-3, the plant approaches a stabilized condition following reactor trip and AFW initiation. Plant procedures may be followed to further cool down the plant. 15.2.8.4 Conclusions Results of the analysis show that a loss of normal feedwater does not adversely affect the core, the RCS, or the steam system, since the AFW capacity is such that the reactor coolant liquid is not relieved from the pressurizer relief or safety valves.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-31 Revision 21 September 2013 15.2.9 LOSS OF OFFSITE POWER TO THE STATION AUXILIARIES 15.2.9.1 Identification of Causes and Accident Description During a complete loss of offsite power and a turbine trip there will be loss of power to the plant auxiliaries, i.e., the reactor coolant pumps, condensate pumps, etc.
The events following a loss of ac power with turbine and reactor trip are described in the sequence listed below:
(1) Plant vital instruments are supplied by emergency power sources. (2) As the steam system pressure rises following the trip, the steam system power-operated relief valves are automatically opened to the atmosphere.
Steam dump to the condenser is assumed not to be available. If the power-operated relief valves are not available, the steam generator self-actuated safety valves may lift to dissipate the sensible heat of the fuel and coolant plus the residual heat produced in the reactor. (3) As the no-load temperature is approached, the steam system power-operated relief valves (or the self-actuated safety valves, if the power-operated relief valves are not available) are used to dissipate the residual heat and to maintain the plant at the hot standby condition. (4) The emergency diesel generators started on loss of voltage on the plant emergency buses begin to supply plant vital loads. The AFW system is started automatically as discussed in the loss of normal feedwater analysis. The steam-driven auxiliary feedwater pump utilizes steam from the secondary system and exhausts to the atmosphere. The motor-driven AFW pumps are supplied by power from the diesel generators. The pumps take suction directly from the condensate storage tank for delivery to the steam generators.
Upon the loss of power to the reactor coolant pumps, coolant flow necessary for core cooling and the removal of residual heat is maintained by natural circulation in the reactor coolant loops. 15.2.9.2 Analysis of Effects and Consequences A detailed analysis using the RETRAN-02W code (Reference 19) is performed in order to determine the plant transient following loss of offsite power. The code describes the plant neutron kinetics, RCS including factors that influence the natural circulation, pressurizer, steam generators, and feedwater system, and computes pertinent variables, including the pressurizer pressure, pressurizer water level, and reactor coolant average temperature.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-32 Revision 21 September 2013 Major assumptions differing from those in a loss of normal feedwater are: (1) No credit is taken for immediate response of control rod drive mechanisms caused by a loss of offsite power. (2) RCP coastdown to natural circulation conditions is assumed after reactor trip (i.e., rod motion), which is more limiting for long-term heat removal capability. (3) The initial feedwater temperature is assumed to be 425°F. (4) A nominal reactor coolant pump heat input of 14 MWt. 15.2.9.3 Results The time sequence of events for the accident at the conditions associated with Unit 2, which were determined to be limiting, is given in Table 15.2-1. This event is bounded by the complete-loss-of-flow analysis (Section 15.3.4), in terms of minimum DNBR. Therefore, this event is not analyzed for DNB concerns, but rather, for the long-term heat removal capability. After the reactor trip, stored and residual heat must be removed to prevent damage to either the RCS or the core. The RETRAN-02W code results show that the natural circulation flow available is sufficient to provide adequate core decay heat removal following reactor trip and RCP coastdown. 15.2.9.4 Conclusions Results of the analysis show that, for the loss of offsite power to the station auxiliaries event, all safety criteria are met. Since the DNBR remains above the safety analysis limit, the core is not adversely affected. AFW capacity is sufficient to prevent liquid relief through the pressurizer relief and safety valves; this assures that the RCS is not overpressurized.
Analysis of the natural circulation capability of the RCS demonstrates that sufficient long-term heat removal capability exists following reactor coolant pump coastdown to prevent fuel or cladding damage.
15.2.10 EXCESSIVE HEAT REMOVAL DUE TO FEEDWATER SYSTEM MALFUNCTIONS 15.2.10.1 Identification of Causes and Accident Description Reductions in feedwater temperature or excessive feedwater additions are means of increasing core power above full power. Such transients are attenuated by the thermal capacity of the secondary plant and of the RCS. The overpower-overtemperature DCPP UNITS 1 & 2 FSAR UPDATE 15.2-33 Revision 21 September 2013 protection (neutron high flux, overtemperature T, and overpower T trips) prevent any power increase that could lead to a DNBR that is less than the DNBR limit.
One example of excessive feedwater flow would be a full opening of a feedwater control valve due to a feedwater control system malfunction or an operator error. At power, this excess flow causes a greater load demand on the RCS due to increased subcooling in the steam generator. With the plant at no-load conditions the addition of cold feedwater may cause a decrease in RCS temperature and thus a reactivity insertion due to the effects of the negative moderator coefficient of reactivity. Continuous excessive feedwater addition is prevented by the steam generator high-high level trip. 15.2.10.2 Analysis of Effects and Consequences The excessive heat removal due to a feedwater system malfunction transient is analyzed with the RETRAN-02W code. This code simulates a multiloop system, neutron kinetics, the pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generator, and steam generator safety valves. The code computes pertinent plant variables including temperatures, pressures, and power level.
The system is analyzed to evaluate plant behavior in the event of a feedwater system malfunction.
Excessive feedwater addition due to a control system malfunction or operator error that allows a feedwater control valve to open fully is considered. Two conditions are evaluated as follows:
(1) Accidental opening of one feedwater control valve with the reactor just critical at zero load conditions assuming a conservatively large moderator density coefficient characteristic of EOL conditions. (2) Accidental opening of one feedwater control valve at full power (with automatic and manual rod control). In the case of an accidental full opening of one feedwater control valve with the reactor at zero power, a feedwater flow increase of less than 150 percent of the nominal full power flow has been shown to be less limiting than an equivalent feedwater flow increase event from full power conditions. Since the feedwater flow can increase up to 100 percent of the full power flow at zero power conditions, the feedwater flow increase event at zero power is bounded by the full power event, and has not been explicitly analyzed.
The reactivity insertion rate following a feedwater system malfunction is calculated with the following assumptions:
(1) For the feedwater control valve accident at full power, one feedwater control valve is assumed to malfunction resulting in a step increase to 250 percent of nominal feedwater flow to one steam generator.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-34 Revision 21 September 2013 (2) Coincident with the feedwater flow increase in the faulted loop, the feedwater temperature in all loops decreases approximately 23°F from the minimal full power value. This accounts for the effect of the feedwater passing through the heaters at a higher velocity. (3) The initial water level in all the steam generators is at a conservatively low level. (4) No credit is taken for the heat capacity of the RCS and steam generator thick metal in attenuating the resulting plant cooldown. (5) The feedwater flow resulting from a fully open control valve is terminated by the steam generator high-high level signal that closes all feedwater control valves, closes all feedwater bypass valves, trips the main feedwater pumps, and shuts the motor-operated feedwater isolation valves. 15.2.10.3 Results The full power case (EOL, with manual rod control) gives the largest reactivity feedback and results in the greatest power increase. A turbine trip and reactor trip is actuated when the steam generator level reaches the high-high level setpoint.
Transient results (see Figures 15.2.10-1 through 15.2.10-3) show the core heat flux, pressurizer pressure, core Tavg, and DNBR, as well as the increase in nuclear power and loop T associated with the increased thermal load on the reactor. Steam generator level rises until the feedwater is terminated as a result of the high-high steam generator level trip. The DNBR does not drop below the limit safety analysis DNBR. 15.2.10.4 Conclusions An excessive feedwater addition at no-load conditions is bounded by the analysis at full power. The DNBRs encountered for excessive feedwater addition at power are well above the safety analysis limit DNBR values. 15.2.11 SUDDEN FEEDWATER TEMPERATURE REDUCTION A concern was raised during the Unit 1 power ascension test program that an inadvertent actuation of the load transient bypass relay (LTBR) might initiate a transient that exceeds analyzed reactor operating limits. An evaluation performed showed that since the expected feedwater temperature decrease due to inadvertent actuation of the LTBR was significantly less than that of the net load trip, the consequences and events of inadvertent actuation of the LTBR were bounded by the feedwater temperature decrease event.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-35 Revision 21 September 2013 The automatic load transient bypass (LTB) feature has been eliminated for Units 1 and 2. Control of the feedwater heater bypass valve has been changed to manual only. 15.2.11.1 Identification of Causes and Accident Description A reduction in feedwater temperature may be caused by an inadvertent manual opening of the feedwater bypass valve. This would divert flow around the low pressure feedwater heaters. A consequent maximum 70°F reduction in feedwater temperature to the steam generators would occur.
Feedwater temperature may also be reduced during a load rejection trip. The feedwater transient data taken from a 100 percent net load trip test with LTB active showed that a maximum feedwater temperature decrease of 230°F occurred over a 400-second time period. The temperature decrease without LTB is significantly less.
Reductions in temperature of feedwater entering the steam generators, if not accompanied by a corresponding reduction in steam flow, would result in an increase in core power and create a greater load demand on the RCS. The net effect on the RCS of a reduction in reactor coolant temperature is similar to the effect of increasing secondary steam flow. Such transients are attenuated by the thermal capacity of the secondary plant and of the RCS. The high neutron flux trip, overtemperature T trip, and overpower T trip act to prevent any power increase that could lead to a DNBR less than the limit value. The reactor may reach a new equilibrium condition at a power level corresponding to the new steam generator T. A small temperature reduction results in only a small increase in reactor power and does not result in a reactor trip. A larger temperature reduction produces a larger increase in reactor power and may cause a power/temperature mismatch and a reactor trip. 15.2.11.2 Analysis of Effects and Consequences 15.2.11.2.1 Temperature Drops Less than 73°F The protection available to mitigate the consequences of a decrease in feedwater temperature is the same as that for an excessive increase in steam flow event, as discussed in Section 15.2.12. A step load increase of 10 percent from full load was analyzed, and the minimum DNBR for this event was found to be above the safety analysis limit values.
The increase in heat load resulting from a 10 percent increase in load is equivalent to a 73°F drop in feedwater temperature at the steam generator inlet. Thus a feedwater temperature transient that results in a feedwater temperature drop of 73°F or less at the steam generator inlets is less severe than the excessive load increase incident presented in Section 15.2.12 and as such does not exceed any safety limits.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-36 Revision 21 September 2013 15.2.11.2.2 Temperature Drops Greater than 73°F To address feedwater temperature reductions that exceed 73°F, analyses were performed assuming instantaneous temperature drops of 175°F and 250°F at the steam generator, with corresponding steam load reductions of 50 percent and 100 percent, respectively. The maximum temperature drop of 250°F was chosen to bound the temperature decrease of 230°F experienced during the net load trip test when the LTBR was actuated in response to a load reduction. In this test, feedwater temperature dropped approximately 230°F over a time period of 400 seconds, which is significantly less severe than the instantaneous drop of 250°F assumed in the analysis. Since LTB has been eliminated, the feedwater temperature drop will be significantly less and is bounded by the instantaneous drop of 250°F assumed in the analysis. 15.2.11.3 Results Both a 175°F feedwater temperature reduction concurrent with a 50 percent load reduction and a 250°F feedwater temperature reduction concurrent with a full (100 percent) load reduction were analyzed. The analysis shows that the cooldown effects of the large feedwater reduction are more than counteracted by the reduced heat removal resulting from the turbine load reduction, such that the transient causes a heatup of the RCS. As a result, the core power decreases and the DNBR increases during the transient. These cases do not challenge core thermal limits. 15.2.11.4 Conclusions All safety criteria are met for credible scenarios of sudden feedwater temperature reduction. Instantaneous feedwater temperature reductions up to 73°F result in an RCS cooldown that is bounded by the analysis of an excessive load increase incident presented in Section 15.2.12. This bounds the maximum feedwater temperature decrease of 70°F that could result from the inadvertent opening of a feedwater heater bypass valve. For feedwater temperature reductions during a load reduction transient, analyses conclude that these cases result in a net RCS heatup and core power decrease, with no significant challenge to the core thermal limits. 15.2.12 EXCESSIVE LOAD INCREASE INCIDENT 15.2.12.1 Identification of Causes and Accident Description An excessive load increase incident is defined as a rapid increase in the steam flow that causes a power mismatch between the reactor core power and the steam generator load demand. The reactor control system is designed to accommodate a 10 percent step-load increase or a 5 percent per minute ramp load increase in the range of 15 to 100 percent of full power. Any loading rate in excess of these values may cause a reactor trip actuated by the reactor protection system.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-37 Revision 21 September 2013 This accident could result from either an administrative violation such as excessive loading by the operator or an equipment malfunction in the steam dump control or turbine speed control.
During power operation, steam dump to the condenser is controlled by reactor coolant condition signals; i.e., high reactor coolant temperature indicates a need for steam dump. A single controller malfunction does not cause steam dump; an interlock is provided that blocks the opening of the valves unless a large turbine load decrease or a turbine trip has occurred.
Protection against an excessive load increase accident is provided by the following reactor protection system signals:
(1) Overpower T (2) Overtemperature T (3) Power range high neutron flux 15.2.12.2 Analysis of Effects and Consequences This accident is analyzed using the LOFTRAN code. The code simulates the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generator, and steam generator safety valves. The code computes pertinent plant variables including temperatures, pressures, and power level.
Four cases are analyzed to demonstrate the plant behavior following a 10 percent step load increase from rated load. These cases are as follows:
(1) Reactor control in manual with BOL minimum moderator reactivity feedback (2) Reactor control in manual with EOL maximum moderator reactivity feedback (3) Reactor control in automatic with BOL minimum moderator reactivity feedback (4) Reactor control in automatic with EOL maximum moderator reactivity feedback For the BOL minimum moderator feedback cases, the core has the least negative moderator temperature coefficient of reactivity and the least negative Doppler only power coefficient curve; therefore the least inherent transient response capability. For the EOL maximum moderator feedback cases, the moderator temperature coefficient of reactivity has its highest absolute value and the most negative Doppler only power DCPP UNITS 1 & 2 FSAR UPDATE 15.2-38 Revision 21 September 2013 coefficient curve. This results in the largest amount of reactivity feedback due to changes in coolant temperature.
A conservative limit on the turbine valve opening is assumed, and all cases are studied without credit being taken for pressurizer heaters.
This accident is analyzed with the improved thermal design procedure as described in Reference 5. Initial reactor power, RCS pressure and temperature are assumed to be at their nominal values. Uncertainties in initial conditions are included in the limit DNBR as described in Reference 5.
Plant characteristics and initial conditions are further discussed in Section 15.1.
Normal reactor control systems and engineered safety systems are not required to function. The reactor protection system is assumed to be operable; however, reactor trip is not encountered for most cases due to the error allowances assumed in the setpoints. No single active failure will prevent the reactor protection system from performing its intended function.
The cases, which assume automatic rod control, are analyzed to ensure that the worst case is presented. The automatic function is not required. 15.2.12.3 Results The calculated sequence of events for the excessive load increase incident is shown in Table 15.2-1. Figures 15.2.11-1 through 15.2.11-4 illustrate the transient with the reactor in the manual control mode. As expected, for the BOL minimum moderator feedback case, there is a slight power increase, and the average core temperature shows a large decrease. This results in a DNBR, which increases above its initial value. For the EOL maximum moderator feedback manually controlled case, there is a much larger increase in reactor power due to the moderator feedback. A reduction in DNBR is experienced but DNBR remains above the limit value.
Figures 15.2.11-5 through 15.2.11-8 illustrate the transient assuming the reactor is in the automatic control mode. Both the BOL minimum and EOL maximum moderator feedback cases show that core power increases, thereby reducing the rate of decrease in coolant average temperature and pressurizer pressure. For both of these cases, the minimum DNBR remains above the limit value.
For all cases, the plant rapidly reaches a stabilized condition at the higher power level. Normal plant operating procedures would then be followed to reduce power.
The excessive load increase incident is an overpower transient for which the fuel temperatures will rise. Reactor trip does not occur for any of the cases analyzed, and DCPP UNITS 1 & 2 FSAR UPDATE 15.2-39 Revision 21 September 2013 the plant reaches a new equilibrium condition at a higher power level corresponding to the increase in steam flow.
Since DNB does not occur at any time during the excessive load increase transients, the ability of the primary coolant to remove heat from the fuel rod is not reduced. Thus, the fuel cladding temperature does not rise significantly above its initial value during the transient. 15.2.12.4 Conclusions The analysis presented above shows that for a 10 percent step load increase, the DNBR remains above the safety analysis limit values, thereby precluding fuel or cladding damage. The plant reaches a stabilized condition rapidly, following the load increase. 15.2.13 ACCIDENTAL DEPRESSURIZATION OF THE REACTOR COOLANT SYSTEM 15.2.13.1 Identification of Causes and Accident Description An accidental depressurization of the RCS could occur as a result of an inadvertent opening of a pressurizer relief or safety valve. Since a safety valve is sized to relieve approximately twice the steam flowrate of a relief valve, and will therefore allow a much more rapid depressurization upon opening, the most severe core conditions resulting from an accidental depressurization of the RCS are associated with an inadvertent opening of a pressurizer safety valve. Initially, the event results in a rapidly decreasing RCS pressure, which could reach the hot leg saturation pressure if a reactor trip does not occur. The pressure continues to decrease throughout the transient. The effect of the pressure decrease is to decrease the neutron flux via the moderator density feedback, but the reactor control system (if in the automatic mode) functions to maintain the power and average coolant temperature essentially constant until the reactor trip occurs. Pressurizer level increases initially due to expansion caused by depressurization and then decreases following reactor trip.
The reactor will be tripped by the following reactor protection system signals:
(1) Pressurizer low pressure (2) Overtemperature T 15.2.13.2 Analysis of Effects and Consequences The accidental depressurization transient is analyzed with the LOFTRAN code. The code simulates the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generator, and steam generator safety valves. The code computes pertinent plant variables including temperatures, pressures, and power DCPP UNITS 1 & 2 FSAR UPDATE 15.2-40 Revision 21 September 2013 level. This accident is analyzed with the Improved Thermal Design Procedure as described in Reference 5.
In calculating the DNBR the following conservative assumptions are made:
(1) Plant characteristics and initial conditions are discussed in Section 15.1. Uncertainties and initial conditions are included in the limit DNBR as described in Reference 5.
(2) A positive moderator temperature coefficient of reactivity for (+ 7 pcm/°F) BOL operation in order to provide a conservatively high amount of positive reactivity feedback due to changes in moderator temperature. The spatial effect of voids due to local or subcooled boiling is not considered in the analysis with respect to reactivity feedback or core power shape. These voids would tend to flatten the core power distribution. (3) A low (absolute value) Doppler coefficient of reactivity such that the resultant amount of negative feedback is conservatively low in order to maximize any power increase due to moderator reactivity feedback. 15.2.13.3 Results Figure 15.2.12-1 illustrates the flux transient following the RCS depressurization accident. The flux increases until the time reactor trip occurs on overtemperature T, thus resulting in a rapid decrease in the nuclear flux. The time of reactor trip is shown in Table 15.2-1. The pressure decay transient following the accident is given in Figure 15.2.12-2. The resulting DNBR never goes below the safety analysis limit value as shown in Figure 15.2.12-1. 15.2.13.4 Conclusions The pressurizer low pressure and the overtemperature T reactor protection system signals provide adequate protection against this accident, and the minimum DNBR remains in excess of the safety analysis limit value. 15.2.14 ACCIDENTAL DEPRESSURIZATION OF THE MAIN STEAM SYSTEM 15.2.14.1 Identification of Causes and Accident Description The most severe core conditions resulting from an accidental depressurization of the main steam system are associated with an inadvertent opening of a single steam dump, relief, or safety valve. The analyses, assuming a rupture of a main steam pipe, are discussed in Section 15.4.
The steam released as a consequence of this accident results in an initial increase in steam flow that decreases during the accident as the steam pressure falls. The energy removal from the RCS causes a reduction of coolant temperature and pressure. In the DCPP UNITS 1 & 2 FSAR UPDATE 15.2-41 Revision 21 September 2013 presence of a negative moderator temperature coefficient, the cooldown results in a reduction of core shutdown margin.
The analysis is performed to demonstrate that the following criterion is satisfied: Assuming a stuck RCCA and a single failure in the engineered safety features (ESF) the limit DNBR value will be met after reactor trip for a steam release equivalent to the spurious opening, with failure to close, of the largest of any single steam dump, relief, or safety valve.
The following systems provide the necessary mitigation of an accidental depressurization of the main steam system.
(1) SIS actuation from any of the following: (a) Two-out-of-four low pressurizer pressure signals
(b) Two-out-of-three low steam line pressure signals on any one loop (2) The overpower reactor trips (neutron flux and T) and the reactor trip occurring in conjunction with receipt of the safety injection signal. (3) Redundant isolation of the main feedwater lines: Sustained high feedwater flow would cause additional cooldown. Therefore, a safety injection signal will rapidly close all feedwater control valves, trip the main feedwater pumps, and close the backup feedwater isolation valves. 15.2.14.2 Analysis of Effects and Consequences Due to the size of the break and the assumed initial conditions, an Accidental Depressurization of the Main Steam System event is bounded by the Main Steam Line Rupture accident analyzed in Section 15.4.2.1. As such, no explicit analysis is performed for the Accidental Depressurization of the Main Steam System. All applicable acceptance criteria are shown to be met via the results and conclusions in Section 15.4.2.1. 15.2.15 SPURIOUS OPERATION OF THE SAFETY INJECTION SYSTEM AT POWER 15.2.15.1 Spurious Safety Injection (SSI) DNBR Analysis 15.2.15.1.1 Identification of Causes and Accident Description Spurious SIS operation at power could be caused by operator error or a false electrical actuating signal. A spurious signal may originate from any of the safety injection actuation channels as described in Section 15.4.2.1.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-42 Revision 21 September 2013 Following the actuation signal, the suction of the coolant charging pumps is diverted from the volume control tank to the RWST. The charging injection valves between the charging pumps and the injection header open automatically. The charging pumps then pump RWST water through the header and injection line and into the cold legs of each loop. The safety injection pumps also start automatically but provide no flow when the RCS is at normal pressure. The passive injection system and the low-head system also provide no flow at normal RCS pressure.
The analyses of the potential for DNB, loss of fuel integrity, and excessive cooldown are presented in the discussions herein.
An SIS signal normally results in a reactor trip followed by a turbine trip. However, it cannot be assumed that any single fault that actuates the SIS will also produce a reactor trip. Therefore, two different courses of events are considered. Case A: Trip occurs at the same time spurious injection starts.
Case B: The reactor protection system produces a trip later in the transient. For Case A, the operator should determine if the spurious signal was transient or steady state in nature, i.e., an occasional occurrence or a definite fault. The operator will determine this by following approved procedures. In the transient case, the operator would stop the safety injection and bring the plant to the hot shutdown condition. If the SIS must be disabled for repair, boration should continue and the plant brought to cold shutdown. In the event of pressurizer overfill, PORV operation will provide an isolable path to relieve the excess RCS fluid. The evaluation of possible pressurizer overfill is contained in the next section. For Case B, the reactor protection system does not produce an immediate trip and the reactor experiences a negative reactivity excursion causing a decrease in the reactor power. The power unbalance causes a drop in Tavg and consequent coolant shrinkage, and pressurizer pressure and level drop. Load will decrease due to the effect of reduced steam pressure on load if the electrohydraulic governor fully opens the turbine throttle valve. If automatic rod control is used, these effects will be lessened until the rods have moved out of the core. The transient is eventually terminated by the reactor protection system low-pressure trip or by manual trip.
The time to trip is affected by initial operating conditions including core burnup history that affects initial boron concentration, rate of change of boron concentration, and Doppler and moderator coefficients.
Recovery from this incident for Case B is in the same manner as for Case A. The only difference is the lower Tavg and pressure associated with the power imbalance during this transient. The time at which reactor trip occurs is of no concern for this accident. At lighter loads coolant contraction will be slower resulting in a longer time to trip.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-43 Revision 21 September 2013 15.2.15.1.2 Analysis of Effects and Consequences The spurious operation of the SIS is analyzed for DNBR with the LOFTRAN program. The code simulates the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generator, steam generator safety valves, and the effect of the SIS. The program computes pertinent plant variables including temperatures, pressures, and power level.
Because of the power and temperature reduction during the transient, operating conditions do not approach the core limits. Analyses of several cases show that the results are relatively independent of time to trip.
A typical transient is considered representing conditions at BOL. Results at EOL are similar except that moderator feedback effects result in a slower transient.
The assumptions are:
(1) Initial Operating Conditions The initial reactor power and RCS temperatures are assumed at their maximum values consistent with steady state full power operation including allowances for calibration and instrument errors. (2) Moderator and Doppler Coefficients of Reactivity A positive BOL moderator temperature coefficient was used. A low absolute value Doppler power coefficient was assumed. (3) Reactor Control The reactor was assumed to be in manual control. (4) Pressurizer Heaters Pressurizer heaters were assumed to be inoperative in order to increase the rate of pressure drop. (5) Boron Injection At time zero, two charging pumps (CCP1 and CCP2) begin injection and pump borated water through the SIS and into the cold leg of each loop.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-44 Revision 21 September 2013 (6) Turbine Load Turbine load was assumed constant until the electrohydraulic governor drives the throttle valve wide open. Then turbine load drops as steam pressure drops.
(7) Reactor Trip Reactor trip was initiated by low pressure. The trip was conservatively assumed to be delayed until the pressure reached 1860 psia. 15.2.15.1.3 Results The transient response for the minimum feedback case is shown in Figures 15.2.15-1 through 15.2.15-2. Nuclear power starts decreasing immediately due to boron injection, but steam flow does not decrease until 25 seconds into the transient when the turbine throttle valve goes wide open. The mismatch between load and nuclear power causes Tavg, pressurizer water level, and pressurizer pressure to drop. The low-pressure trip setpoint is reached at 23 seconds and rods start moving into the core at 25 seconds.
After trip, pressures and temperatures slowly rise since the turbine is tripped and the reactor is producing some power due to delayed neutron fissions and decay heat. 15.2.15.1.4 Conclusions Results of the DNBR analysis show that spurious safety injection with or without immediate reactor trip presents no hazard to the integrity of the RCS. DNBR is never less than the initial value. Thus, there will be no cladding damage and no release of fission products to the RCS.
If the reactor does not trip immediately, the low-pressure reactor trip will be actuated. This trips the turbine and prevents excess cooldown thereby expediting recovery from the incident. 15.2.15.2 Spurious Safety Injection (SSI) Pressurizer Overfill Analysis 15.2.15.2.1 Identification of Causes and Accident Description The causes and accident description are essentially identical for the SSI DNBR analysis discussed in Section 15.2.15.1 and the SSI pressurizer overfill evaluation in this section. The pressurizer overfill cases model the long term plant response and the operator actions taken to terminate the event before the liquid relief capability of the PSV is challenged. The operator recovery actions for SSI mitigation at power are provided in the plant emergency operating procedures (EOPs). These operator actions, including making a pressurizer PORV available, stopping all but one centrifugal charging pump DCPP UNITS 1 & 2 FSAR UPDATE 15.2-45 Revision 21 September 2013 (CCP1 or CCP2), throttling the charging flow, and establishing RCS letdown flow, are discussed below.
(a) Make Pressurizer PORV Available One of the first recovery actions that the EOPs describe is to verify a pressurizer PORV is available for pressure relief. The operator is directed to open an associated isolation valve as necessary to make a PORV available. The pressurizer overfill evaluation assumes that the operator makes a PORV available within 11 minutes of the initiation of the event. (b) Stop All But One CCP (CCP1 or CCP2) The EOPs provide direction, that in the event of a reactor trip or safety injection, the non-safety related centrifugal charging pump CCP3 is not needed and is secured. The pressurizer overfill evaluation conservatively assumes that CCP3 is operating when the SSI event occurs, since this maximizes the pressurizer fill rate. The operators stop the CCP3 within 9 minutes of the event initiation. Once the operators have identified that the SI is unnecessary, the EOPs direct the operators to stop all but one CCP (CCP1 or CCP2), and throttle the CCP (CCP1 or CCP2) flow as necessary to minimize the potential for pressurizer overfill while maintaining adequate RCP seal injection flow. The operators are assumed to stop all but one CCP (CCP1 or CCP2) within 14 minutes, and require one additional minute to throttle the charging flow. (c) Restore Instrument Air and Establish RCS Letdown The SI signal causes a Phase A containment isolation and a loss of instrument air to containment. In order to establish RCS letdown and terminate the SSI event, the EOPs direct the operators to restore instrument air to containment. The operators are assumed to restore instrument air to containment within 21 minutes of the event. The EOPs then direct the operators through a series of steps, which allow them to establish RCS letdown and stabilize the pressurizer level. The operators are able to establish RCS letdown and terminate the SSI event within 26 minutes.
There are three different cases evaluated to bound the potential impact of the plant control systems operation on the SSI event and the potential for pressurizer overfill.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-46 Revision 21 September 2013 Case 1 Case 1 assumes that the pressurizer pressure control system malfunctions such that the sprays, backup heaters, and proportional heaters all remain on during the event. Both Class 1 PORVs are unavailable. Case 1 establishes the maximum time available for the operators to open a pressurizer PORV block valve and make a PORV available, before the liquid relief capability of the PSV is challenged. The PSV capability is defined as a maximum of 3 openings under liquid relief conditions with the liquid temperature remaining greater than 613°F as established in Reference 16. Case 2 Case 2 assumes that the pressurizer pressure control system malfunctions such that the sprays, backup heaters, and proportional heaters all remain on during the event. This case causes the earliest filling of the pressurizer and the earliest initiation of liquid relief through the pressurizer PORV. This case evaluates that the minimum capacity of the backup nitrogen accumulators is adequate to allow termination of the SSI event without challenging the liquid relief capability of the PSV. Case 3 Case 3 assumes there is a loss of instrument air such that the pressurizer sprays are not operable. The pressurizer heaters remain on during the event. This case causes the earliest pressure increase to the PORV lift setpoint. The analyses of Cases 2 and 3 establish the bounding conditions for evaluating the potential impact of the pressurizer control systems on the time at which the pressurizer fills and the relative number of steam relief and liquid relief PORV cycles which occur during an SSI event. 15.2.15.2.2 Analysis of Effects and Consequences The SSI event is analyzed for pressurizer overfill conditions with the RETRAN program as documented in Reference 16. The code simulates the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generator, steam generator safety valves, and the effect of the SSI. The program computes pertinent plant variables including temperatures, pressures, and power level.
The assumptions are:
(1) Initial Operating Conditions The initial pressurizer pressure is assumed to be at 2,190 psia, which is 60 psi lower than the nominal value. The pressurizer pressure control system is also assumed to control to a reduced setpoint of 2,190 psia when it is operable. This lower RCS pressure results in increased ECCS injection flow during the transient and maximizes the challenges to the PSVs and PORVs.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-47 Revision 21 September 2013 The initial RCS Tavg is assumed to be at the minimum pressurizer program level corresponding to 560°F, which bounds the maximum RCS temperature uncertainty of 5°F. This conservatively maximizes the initial RCS mass, and minimizes the RCS volumetric shrinkage after the reactor trip. For this initial Tavg, the corresponding programmed initial pressurizer level is 51.2 percent, which bounds the pressurizer level uncertainty of 6.1 percent. (2) Pressurizer Heaters Both the backup and proportional pressurizer heaters are assumed to remain on even after the normal control setpoint is reached to conservatively maximize the pressurizer liquid volume and decrease the time to fill the pressurizer with liquid. (3) Reactor Trip / Turbine Load The reactor trip occurs coincident with the SI actuation, which results in an immediate turbine trip. There is no credit for heat removal from the steam dump system to the condenser or atmosphere. Only the main steam safety valves are assumed to be operable, with a 3 percent setpoint drift and 3 percent accumulation. Main feedwater is lost coincident with the reactor/turbine trip. One MDAFW pump delivers the minimum flow of 410 gpm to two steam generators. The AFW fluid temperature is a maximum value of 100°F. The minimum heat transfer from the primary coolant loop to the secondary system leads to a conservatively early pressurizer fill condition and challenge to the pressurizer overfill condition. (4) Moderator and Doppler Coefficients of Reactivity Similar to the DNBR analysis, the pressurizer overfill analysis assumes a positive BOL moderator temperature coefficient and low absolute value Doppler power coefficient. Since the reactor trip occurs immediately for the pressurizer overfill case, these reactivity coefficients have a negligible impact on the results.
(5) Reactor Decay Heat Conservative core residual heat generation is assumed based on long-term operation at the initial power level preceding the trip. The 1973 decay heat ANSI + 2 was used for calculation of residual decay heat levels.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-48 Revision 21 September 2013 (6) Pressurizer PORVs The pressurizer PORV lift setpoint is assumed to be a minimum of 2,298 psia. The pressurizer PORV delay and stroke time are minimized. The PORV opens with a delay time of 0.589 seconds and a stroke time of 0.416 seconds, and closes with a delay time of 0.825 seconds and a stroke time of 0.819 seconds. The PORV valve area is assumed to increase/decrease linearly as the valve strokes open and closed. These assumptions conservatively maximize the number of PORV open cycles during the SSI event. The backup nitrogen accumulators can provide for more than 100 PORV cycles. (7) ECCS Injection Flow Two trains of ECCS pumps are assumed to provide the maximum injection flow versus RCS pressure. The RWST fluid temperature is assumed to be 35°F to maximize the ECCS fluid density. 15.2.15.2.3 Results The sequence of events for the 3 pressurizer overfill cases is listed in Table 15.2.-1. Typical transient responses are shown in Figures 15.2.15-3 through 15.2.15-5.
Case 1 The spurious safety injection signal occurs at one second. This generates a concurrent reactor trip signal from full power conditions followed by a turbine trip signal one second later. The pressurizer pressure and pressurizer level initially decrease as the RCS power and temperature reduce from full power conditions to hot no load conditions. The initiation of the ECCS injection flow halts the post trip pressure decrease and then rapidly increases the pressure until the pressurizer spray valves open enough to maintain the pressurizer pressure relatively constant. The pressurizer level continues to increase due to ECCS injection flow and pressurizer spray flow until the pressurizer fills. The water solid RCS then experiences a rapid pressure increase to the pressurizer safety valve lift setpoint. The Case 1 analysis evaluation is considered complete when the fourth liquid relief of the PSV begins at 748 seconds. This establishes the minimum time available for the operators to unblock a pressurizer PORV to prevent challenging the liquid relief capability of the PSV.
Case 2 The first part of each SSI case is essentially identical as the plant experiences the spurious safety injection, reactor trip, and turbine trip from full power conditions. The plant response for Case 2 is identical to Case 1 including up to the time that the pressurizer becomes water solid. For Case 2, the RCS pressure increases only to the pressurizer PORV lift setpoint where it is maintained relatively constant as the PORV DCPP UNITS 1 & 2 FSAR UPDATE 15.2-49 Revision 21 September 2013 continues to cycle and relieve liquid. As the operator actions decrease the ECCS injection flow, the PORV begins cycling less frequently. By the time the SSI event is terminated at 30 minutes, the PORV has cycled a total of 45 times. Case 3 In Case 3, the pressurizer sprays are not available such that after the reactor trip the RCS pressure continues increasing to the pressurizer PORV lift setpoint. The pressurizer PORV continues to cycle and relieve steam as the pressurizer level increases due to the ECCS injection flow. Without the pressurizer sprays, the RCS pressure is maintained near the PORV setpoint such that the pressurizer fills later than Case 1. Once the pressurizer becomes water solid, the PORV begins relieving liquid. The PORV generates less of a setpoint undershoot while relieving liquid. As a result, the PORV cycles at a slightly faster rate than when relieving steam. Similar to Case 2, the PORV begins cycling less frequently as the operator actions decrease the ECCS injection flow. By the time the SSI event is terminated at 30 minutes, the PORV has cycled a total of 88 times. 15.2.15.2.4 Conclusions Case 1 establishes that for the limiting SSI event, the operators have a minimum time of about 748 seconds or 12.5 minutes to make a pressurizer PORV available to prevent challenging the PSV liquid relief capability. These results conservatively bound the 11 minutes assumed for the operators to manually unblock a pressurizer PORV. Cases 2 and 3 establish that with the worst-case control system operation, the operators have adequate time to terminate an SSI event prior to exceeding the capacity of pressurizer PORV cycles provided by the backup nitrogen accumulators. The mitigation function of the Class I PORVs ensures that the SSI event can be terminated prior to challenging the PSV liquid relief capability. 15.2.16 REFERENCES 1. W. C. Gangloff, An Evaluation of Anticipated Operational Transients in Westinghouse Pressurized Water Reactors, WCAP-7486, May 1971.
- 2. D. H. Risher, Jr. and R. F. Barry, TWINKLE-A Multi-Dimensional Neutron Kinetics Computer Code, WCAP-7979-P-A (Proprietary) and WCAP-8028-A (Non-Proprietary), January 1975.
- 3. H. G. Hargrove, FACTRAN, A Fortran IV Code for Thermal Transients in UO2 Fuel Rod, WCAP-7908-A, December 1989.
- 4. T. W. T. Burnett, et al., LOFTRAN Code Description, WCAP-7907-A, April 1984.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-50 Revision 21 September 2013 5. H. Chelemer, et al., Improved Thermal Design Procedure, WCAP-8567-P-A (Proprietary) and WCAP-8568-A (Non-Proprietary), February 1989.
- 6. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR-82, as amended.
- 7. H. Chelemer, et al., Subchannel Thermal Analysis of Rod Bundle Cores, WCAP-7015, Revision 1, January 1969.
- 8. K. Cooper, et al., Overpressure Protection for Westinghouse Pressurized Water Reactor, WCAP-7769, Rev. 1, June 1972.
- 9. J. S. Shefcheck, Application of the THINC Program to PWR Design, WCAP-7359-L, August 1969 (Proprietary), and WCAP-7838, January 1972.
- 10. R. L. Haessler, et al., Methodology for the Analysis of the Dropped Rod Event, WCAP-11394 (Proprietary) and WCAP-11395 (Non-Proprietary), April 1987.
- 11. Deleted in Revision 16.
- 12. Deleted in Revision 16.
- 13. Deleted in Revision 16.
- 14. Deleted in Revision 18.
- 15. Deleted in Revision 18.
- 16. Westinghouse letter PGE-98-503, Diablo Canyon Units 1 & 2 Inadvertent ECCS Actuation at Power Analysis - PSV Operability Issue, January 13, 1998.
- 17. Westinghouse Letter NSAL-02-11, Reactor Protection System Response Time Requirements, July 29, 2002
- 18. Westinghouse Letter PGE-02-072, Diablo Canyon Units 1 & 2 Evaluation of Reactor Trip Functions for Uncontrolled RCCA Withdrawal at Power, December 13, 2002.
- 19. RETRAN-02 Modeling and Qualification for Westinghouse Non-LOCA Safety Analyses, WCAP-14882-P-A (Proprietary), April 1999, and WCAP-15234-A (Non-Proprietary), May 1999.
- 20. Westinghouse Letter NSAL-07-10, Loss-of-Normal Feedwater/Loss-of-Offsite AC Power Analysis PORV Modeling Assumptions, November 7, 2007.
DCPP UNITS 1 & 2 FSAR UPDATE 15.2-51 Revision 21 September 2013 21. PG&E Design Calculation N-115, Reduced Power Levels for a Number of MSSVs Inoperable, March 14, 1994. 22. Westinghouse Letter PGE-10-43, Diablo Canyon Units 1 & 2 Loss of Load / Turbine Trip Analysis with One Inoperable MSSV per Steam Generator, September 2, 2010. DCPP UNITS 1 & 2 FSAR UPDATE 15.3-1 Revision 21 September 2013 15.3 CONDITION III - INFREQUENT FAULTS By definition, Condition III occurrences are faults that may occur very infrequently during the life of the plant. They will be accompanied with the failure of only a small fraction of the fuel rods although sufficient fuel damage might occur to preclude resumption of operation for a considerable outage time. The release of radioactivity will not be sufficient to interrupt or restrict public use of those areas beyond the exclusion radius. A Condition III fault will not, by itself, generate a Condition IV fault or result in a consequential loss of function of the reactor coolant system (RCS) or containment barriers. For the purposes of this report the following faults have been grouped into this category:
(1) Loss of reactor coolant, from small ruptured pipes or from cracks in large pipes, that actuates the emergency core cooling system (ECCS). (2) Minor secondary system pipe breaks. (3) Inadvertent loading of a fuel assembly into an improper position. (4) Complete loss of forced reactor coolant flow. (5) Single rod cluster control assembly (RCCA) withdrawal at full power.
Each of these infrequent faults is analyzed in this section. In general, each analysis includes acceptance criteria, an identification of causes and description of the accident, an analysis of effects and consequences, a presentation of results, and relevant conclusions. The time sequences of events during four Condition III faults of type (1) above, small- break loss-of-coolant accident (SBLOCA), are shown in Table 15.3-1. Westinghouse has determined that the amount of fuel damage during a SBLOCA can be much higher than the small amount previously assumed, and that credit for automatic initiation of the Containment Spray System (CSS) cannot be assumed. Based on this, the radiological consequences of a SBLOCA have been analyzed assuming a bounding 100 percent rod burst with no credit for the CSS. The dose analysis for this bounding SBLOCA is added in Section 15.5.11.1. Based on the results of the new analysis, the SBLOCA does not fall within the explicit definition of a Condition III fault, since it is assumed that it can be accomplished with the failure of more than "only a small fraction of the fuel rods," and the release of radioactivity may be "sufficient to interrupt or restrict public use of those areas beyond the exclusion radius." SBLOCA remains a fault that may occur very infrequently during the life of the plant. Dose consequences per the new analysis are below 10 CFR Part 100 applicable guidelines and limits and are bounded by the large break loss-of-coolant-accident (LBLOCA), and therefore are acceptable. DCPP UNITS 1 & 2 FSAR UPDATE 15.3-2 Revision 21 September 2013 15.3.1 LOSS OF REACTOR COOLANT FROM SMALL RUPTURED PIPES OR FROM CRACKS IN LARGE PIPES THAT ACTUATES EMERGENCY CORE COOLING SYSTEM 15.3.1.1 Acceptance Criteria 15.3.1.1.1 10 CFR Part 50, Section 50.46, Acceptance Criteria for Emergency Core Cooling Systems for Light-Water Nuclear Power Reactors (1) Peak cladding temperature. The calculated maximum fuel element cladding temperature shall not exceed 2200°F. (2) Maximum cladding oxidation. The calculated total oxidation of the cladding shall nowhere exceed 0.17 times the total cladding thickness before oxidation. (3) Maximum hydrogen generation. The calculated total amount of hydrogen generated from the chemical reaction of the cladding with water or steam shall not exceed 0.01 times the hypothetical amount that would be generated if all of the metal in the cladding cylinders surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react. This reduces the potential for explosive hydrogen/oxygen mixtures inside containment. (4) Coolable geometry. Calculated changes in core geometry shall be such that the core remains amenable to cooling. (5) Long-term cooling. After any calculated successful initial operation of the ECCS, the calculated core temperature shall be maintained at an acceptably low value and decay heat shall be removed for the extended period of time required by the long-lived radioactivity remaining in the core. 15.3.1.1.2 Radiological Criteria The radiological consequences of a SBLOCA are within the applicable guidelines and limits specified in 10 CFR Part 100 detailed in Section 15.5.11. 15.3.1.2 Identification of Causes and Accident Description A LOCA is defined as a rupture of the RCS piping or of any line connected to the system. This includes small pipe breaks, typically a 3/8-inch diameter opening (0.11 square inch), up to and including a break size of 1.0 square foot that results in flow that is greater than the makeup flow rate from either CCP1 or CCP2 (see Section 6.3.3.2.2). See Section 3.6 for a more detailed description of the LOCA boundary limits. The coolant that would be released to the containment contains fission products.
DCPP UNITS 1 & 2 FSAR UPDATE 15.3-3 Revision 21 September 2013 The maximum break size for which the normal makeup system can maintain the pressurizer level is obtained by comparing the calculated flow from the RCS through the postulated break against the charging system flow capability when aligned for maximum charging at normal RCS pressure. Should a larger break occur, depressurization of the RCS causes fluid to flow to the RCS from the pressurizer resulting in a pressure and level decrease in the pressurizer. Reactor trip occurs when the pressurizer low-pressure trip setpoint is reached. The safety injection system (SIS) is actuated when the appropriate pressurizer low-pressure setpoint is reached. Reactor trip and SIS actuation are also initiated by a high containment pressure signal. The consequences of the accident are limited in two ways:
(1) Reactor trip and borated water injection complement void formation in causing rapid reduction of nuclear power to a residual level corresponding to the delayed fission and fission product decay (2) Injection of borated water ensures sufficient flooding of the core to prevent excessive cladding temperatures Before the break occurs, the plant is in an equilibrium condition; i.e., the heat generated in the core is being removed via the secondary system. During blowdown, heat from decay, hot internals, and the vessel continues to be transferred to the RCS. The heat transfer between the RCS and the secondary system may be in either direction depending on the relative temperatures. In the case of continued heat addition to the secondary system, system pressure increases and steam dump may occur. Makeup to the secondary side is automatically provided by the auxiliary feedwater (AFW) pumps. The safety injection signal stops normal feedwater flow by closing the main feedwater line isolation valves and initiates emergency feedwater flow by starting AFW pumps.
The secondary flow aids in the reduction of RCS pressure. When the RCS depressurizes to below approximately 600 psia, the accumulators begin to inject water into the reactor coolant loops. The reactor coolant pumps are assumed to be tripped at the beginning of the accident and the effects of pump coastdown are included in the blowdown analyses. 15.3.1.3 Analysis of Effects and Consequences For loss-of-coolant accidents due to small breaks less than 1 square foot, the NOTRUMP (Reference 12) computer code is used to calculate the transient depressurization of the RCS as well as to describe the mass and enthalpy of flow through the break. The NOTRUMP computer code is a one-dimensional general network code with a number of features. Among these features are the calculation of thermal nonequilibrium in all fluid volumes, flow regime-dependent drift flux calculations with counter-current flooding limitations, mixture level tracking logic in multiple-stacked fluid nodes, and regime-dependent heat transfer correlations. The NOTRUMP SBLOCA emergency core cooling system (ECCS) evaluation model was developed to DCPP UNITS 1 & 2 FSAR UPDATE 15.3-4 Revision 21 September 2013 determine the RCS response to design basis SBLOCAs and to address the NRC concerns expressed in NUREG-0611, "Generic Evaluation of Feedwater Transients and Small Break Loss-of-Coolant Accidents in Westinghouse-Designed Operating Plants."
In NOTRUMP, the RCS is nodalized into volumes interconnected by flowpaths. The broken loop is modeled explicitly, with the intact loops lumped into a second loop. The transient behavior of the system is determined from the governing conservation equations of mass, energy, and momentum applied throughout the system. A detailed description of the NOTRUMP code is provided in References 12 and 13.
The use of NOTRUMP in the analysis involves, among other things, the representation of the reactor core as heated control volumes with the associated bubble rise model to permit a transient mixture height calculation. The multinode capability of the program enables an explicit and detailed spatial representation of various system components. In particular, it enables a proper calculation of the behavior of the loop seal during a loss-of-coolant transient.
Safety injection flowrate to the RCS as a function of the system pressure is used as part of the input. The SIS was assumed to be delivering water to the RCS 27 seconds after the generation of a safety injection signal.
For the analysis, the SIS delivery considers pumped injection flow that is depicted in Figure 15.3-1 as a function of RCS pressure. This figure represents injection flow from the SIS pumps based on performance curves degraded 5 percent from the design head. The 27-second delay includes time required for diesel startup and loading of the safety injection pumps onto the emergency buses. The effect of residual heat removal (RHR) pump flow is not considered here since their shutoff head is lower than RCS pressure during the time portion of the transient considered here. Also, minimum safeguards ECCS capability and operability have been assumed in these analyses.
Peak cladding temperature analyses are performed with the LOCTA IV (Reference 4) code that determines the RCS pressure, fuel rod power history, steam flow past the uncovered part to the core, and mixture height history. 15.3.1.4 Results 15.3.1.4.1 Reactor Coolant System Pipe Breaks This section presents the results of a spectrum of small break sizes analyzed. The small break analysis was performed at 102 percent of the Rated Core Power (3411 MWt), a Total Peaking Factor (FQT) of 2.70, a Thermal Design Flow of 87,700 / 88,500 gpm/loop (Unit 1 / Unit 2) and a steam generator tube plugging level of 10 percent. For Unit 1, the small-break analysis was performed for the Replacement Steam Generator (RSG). For Unit 2, the small break analysis was performed for the upflow core barrel/baffle configuration, upper head temperature reduction and RSG. DCPP UNITS 1 & 2 FSAR UPDATE 15.3-5 Revision 21 September 2013 The limiting small break size was shown to be a 3-inch diameter break in the cold leg. In the analysis of this limiting break, an RCS Tavg window of 577.3 / 577.6°F, +5°F, -4°F (Unit 1 / Unit 2) was considered. The high Tavg cases were shown to be more limiting than the Low Tavg cases and therefore are the subject of the remaining discussion. The time sequence of events and the fuel cladding results for the breaks analyzed are shown in Tables 15.3-1 and 15.3-2.
During the earlier part of the small break transient, the effect of the break flow is not strong enough to overcome the flow maintained by the reactor coolant pumps through the core as they are coasting down following reactor trip. Therefore, upward flow through the core is maintained. The resultant heat transfer cools the fuel rods and cladding to very near the coolant temperature as long as the core remains covered by a two-phase mixture. This effect is evident in the accompanying figures.
The depressurization transients for the limiting 3-inch breaks are shown in Figure 15.3-9. The extent to which the core is uncovered for these breaks is presented in Figure 15.3-11. The maximum hot spot cladding temperature reached during the transient, including the effects of fuel densification as described in Reference 3, is 1391 / 1288°F (Unit 1 / Unit 2). The peak cladding temperature transients for the 3-inch breaks are shown in Figure 15.3-13. The top core node vapor temperatures for the 3-inch breaks are shown in Figure 15.3-33. When the mixture level drops below the top of the core, the top core node vapor temperature increases as the steam superheats along the exposed portion of the fuel. The rod film coefficients for this phase of the transients are given in Figure 15.3-34. The hot spot fluid temperatures are shown in Figure 15.3-35 and the break mass flows are shown in Figure 15.3-36. The core power (dimensionless) transient following the accident (relative to reactor scram time) is shown in Figure 15.3-8. The reactor shutdown time (4.7 sec) is equal to the reactor trip signal processing time (2.0 seconds) plus 2.7 seconds for complete rod insertion. During this rod insertion period, the reactor is conservatively assumed to operate at 102 percent rated power. The small break analyses considered 17x17 Vantage 5 fuel with IFMs, ZIRLO cladding, and an axial blanket. Fully enriched annular pellets, as part of an axial blanket core design, were modeled explicitly in this analysis. The results when modeling the enriched annular pellets were not significantly different than the results from solid pellet modeling.
Several figures are also presented for the additional break sizes analyzed. Figures 15.3-37, 15.3-2, and 15.3-40 present the RCS pressure transient for the 2-, 4-, and 6-inch breaks, respectively. Figures 15.3-38, 15.3-3, and 15.3-41 present the core mixture height plots for 2-, 4-, and 6-inch breaks, respectively. The peak cladding temperature transients for the 2-inch breaks are shown in Figure 15.3-39. The peak cladding temperature transients for the 4-inch breaks are shown in Figure 15.3-4. These results are not available for the 6-inch break because the core did not uncover for this transient.
DCPP UNITS 1 & 2 FSAR UPDATE 15.3-6 Revision 21 September 2013 The small break analysis was performed with the Westinghouse ECCS Small Break Evaluation Model (References 12 and 4) approved for this use by the Nuclear Regulatory Commission in May 1985. An approved cold leg SI condensation model, COSI (Reference 26), was utilized as part of the Evaluation Model. 15.3.1.5 Conclusions The analysis demonstrates that the acceptance criteria are met as follows: 15.3.1.5.1 10 CFR Part 50, Section 50.46, Acceptance Criteria for Emergency Core Cooling Systems for Light-Water Nuclear Power Reactors (1) Peak cladding temperature. The calculated maximum fuel element cladding temperature does not exceed 2200°F, as shown in Table 15.3-2. (2) Maximum cladding oxidation. The calculated total oxidation of the cladding nowhere exceeds 0.17 times the total cladding thickness before oxidation, as shown in Table 15.3-2. (3) Maximum hydrogen generation. Table 15.3-2 shows that the average cladding oxidation is less than 0.01 times the cladding thickness. Thus the calculated total amount of hydrogen generated from the chemical reaction of the cladding with water or steam does not exceed 0.01 times the hypothetical amount that would be generated if all of the metal in the cladding cylinders surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react. (4) & (5) Coolable Geometry and Long Term Cooling. The results associated with the SBLOCA analysis performed with the NOTRUMP Evaluation Model explicitly demonstrate compliance with Criteria 1 through 3. Because of the fuel rod burst and blockage models used in the LOCTA code, and modeling of the cold leg recirculation phase in NOTRUMP, SBLOCA analysis results also support the coolable geometry and long term cooling criteria. Since Criteria 1 through 3 are explicitly met, Criteria 4 and 5 are met as well. The SBLOCA phenomena and results are therefore in compliance with 10 CFR 50.46 acceptance criteria. 15.3.1.5.2 Radiological The radiological consequences of a SBLOCA are within the applicable guidelines and limits specified in 10 CFR Part 100 detailed in Section 15.5.11. DCPP UNITS 1 & 2 FSAR UPDATE 15.3-7 Revision 21 September 2013 15.3.2 MINOR SECONDARY SYSTEM PIPE BREAKS 15.3.2.1 Acceptance Criteria (1) The minimum departure from nucleate boiling ratio (DNBR) does not go below the safety analysis limit (see Section 15.4.2.1.1 and 15.4.2.3.1) at any time during the transient to ensure that the core remains geometrically intact with no loss of core cooling capability. (2) Any activity release must be such that the calculated doses at the site boundary are a small fraction of the applicable guidelines and limits specified in 10 CFR Part 100 as detailed in Section 15.5.12. 15.3.2.2 Identification of Causes and Accident Description Included in this grouping are ruptures of secondary system lines which would result in steam release rates equivalent to a 6-inch diameter break or smaller.
15.3.2.3 Analysis of Effects and Consequences Minor secondary system pipe breaks must not result in more than the failure of only a small fraction of the fuel elements in the reactor. Since the results of analysis presented in Section 15.4.2 for a major secondary system pipe rupture also meet these criteria, separate analyses for minor secondary system pipe breaks is not required.
The analyses of the more probable accidental opening of a secondary system steam dump, relief, or safety valve is presented in Section 15.2.14. These analyses are illustrative of a pipe break equivalent in size to a single valve opening. 15.3.2.4 Conclusions The analysis demonstrates that the acceptance criteria are met as follows: (1) The analysis presented in Section 15.4.2 demonstrates that the consequences of a minor secondary system pipe break are acceptable because a DNBR of less than the design basis values does not occur even for a more critical major secondary system pipe break. (2) Section 15.5.12 demonstrates the potential radiological exposures to the public following a minor secondary system pipe rupture per the applicable guidelines and limits specified in 10 CFR Part 100 are met. DCPP UNITS 1 & 2 FSAR UPDATE 15.3-8 Revision 21 September 2013 15.3.3 INADVERTENT LOADING OF A FUEL ASSEMBLY INTO AN IMPROPER POSITION 15.3.3.1 Acceptance Criteria (1) In the event of a fuel loading error not identified until normal operation, the offsite dose consequences should be a small fraction of the applicable guidelines and limits specified in 10 CFR Part 100 as detailed in Section 15.5.1. 15.3.3.2 Identification of Causes and Accident Description Fuel and core loading errors such as inadvertently loading one or more fuel assemblies into improper positions, loading a fuel rod during manufacture with one or more pellets of the wrong enrichment, or loading a full fuel assembly during manufacture with pellets of the wrong enrichment will lead to increased heat fluxes if the error results in placing fuel in core positions calling for fuel of lesser enrichment. The inadvertent loading of one or more fuel assemblies requiring burnable poison rods into a new core without burnable poison rods is also included among possible core loading errors.
Any error in enrichment, beyond the normal manufacturing tolerances, can cause power shapes that are more peaked than those calculated with the correct enrichments. The incore system of movable neutron flux detectors that is used to verify power shapes at the start of life is capable of revealing any assembly enrichment error or loading error that causes power shapes to be peaked in excess of the design value. To reduce the probability of core loading errors, each fuel assembly is marked with an identification number and loaded in accordance with a core loading diagram. For each core loading, the identification number is checked to ensure proper core configuration. The power distortion due to any combination of misplaced fuel assemblies would significantly raise peaking factors and would be readily observable with movable incore neutron flux detectors. In addition to the flux detectors, thermocouples are located at the outlet of about one-third of the fuel assemblies in the core. There is a high probability that these thermocouples would also indicate any abnormally high coolant enthalpy rise. Incore flux measurements are taken during the startup subsequent to every refueling operation. A more detailed discussion of the flux detection capabilities may be found in Section 4.3.2.2. 15.3.3.3 Analysis of Effects and Consequences Steady state power distributions in the x-y plane of the core are calculated with the TURTLE code (see Section 1.6.1, item 49 and Section 4.3.2.8.5), based on macroscopic cross sections calculated by the LEOPARD code (see Section 1.6.1, item 48 and Section 4.3.3.2). A discrete representation is used wherein each individual fuel rod is described by a mesh interval. The power distributions in the x-y plane for a correctly loaded core assembly are given in Chapter 4 based on enrichments given in that section. DCPP UNITS 1 & 2 FSAR UPDATE 15.3-9 Revision 21 September 2013 For each core loading error case analyzed, the percent deviations from detector readings for a normally loaded core are shown at all incore detector locations (see Figures 15.3-15 through 15.3-19). 15.3.3.4 Results The following core loading error cases have been analyzed:
(1) Case A The case in which a Region 1 assembly is interchanged with a Region 3 assembly. The particular case considered was the interchange of two adjacent assemblies near the periphery of the core (see Figure 15.3-15). (2) Case B The case in which a Region 1 assembly is interchanged with a neighboring Region 2 fuel assembly. Two analyses have been performed for this case (see Figures 15.3-16 and 15.3-17). In Case B-1, the interchange is assumed to take place with the burnable poison rods transferred with the Region 2 assembly mistakenly loaded into Region 1. In Case B-2, the interchange is assumed to take place closer to core center and with burnable poison rods located in the correct Region 2 position but in a Region 1 assembly mistakenly loaded into the Region 2 position. (3) Case C Enrichment error: the case in which a Region 2 fuel assembly is loaded in the core central position (see Figure 15.3-18). (4) Case D The case in which a Region 2 fuel assembly instead of a Region 1 assembly is loaded near the core periphery (see Figure 15.3-19). 15.3.3.5 Conclusions In the event that a single rod or pellet has a higher enrichment than the nominal value, the consequences in terms of reduced DNBR and increased fuel and cladding temperatures will be limited to the incorrectly loaded rod or rods.
DCPP UNITS 1 & 2 FSAR UPDATE 15.3-10 Revision 21 September 2013 Fuel assembly loading errors are prevented by administrative procedures implemented during core loading. In the unlikely event that a loading error occurs, analyses in this section confirm that resulting power distribution effects will either be readily detected by the incore movable detector system or will cause a sufficiently small perturbation to be acceptable within the uncertainties allowed between nominal and design power shapes.
The analysis demonstrates the acceptance criterion is met as follows: (1) No events leading to environmental radiological consequences are expected as a result of loading errors (see Section 15.5.13). 15.3.4 COMPLETE LOSS OF FORCED REACTOR COOLANT FLOW 15.3.4.1 Acceptance Criteria (1) Maintain the minimum DNBR greater than the safety analysis limit for fuel (see Section 4.4.2.1). 15.3.4.2 Identification of Causes and Accident Description A complete loss of forced reactor coolant flow may result from a simultaneous loss of electrical supplies to all reactor coolant pumps. If the reactor is at power at the time of the accident, the immediate effect of loss of coolant flow is a rapid increase in the coolant temperature. This increase could result in departure from nucleate boiling (DNB) with subsequent fuel damage if the reactor were not tripped promptly. The following reactor trips provide necessary protection against a loss of coolant flow accident:
(1) Undervoltage or underfrequency on reactor coolant pump power supply buses (primary protection) (2) Low reactor coolant loop flow (backup to undervoltage and underfrequency trips) (3) Pump circuit breaker opening (backup to low flow)
The reactor trip on reactor coolant pump bus undervoltage is provided to protect against conditions that can cause a loss of voltage to all reactor coolant pumps, i.e., loss of offsite power. This function is blocked below approximately 10 percent power (Permissive 7).
The reactor trip on reactor coolant pump underfrequency is provided to trip the reactor for an underfrequency condition, resulting from frequency disturbances on the major power grid. Underfrequency also opens the reactor coolant pump breakers that disengage the reactor coolant pumps from the power grid so that the pumps flywheel kinetic energy is available for full coastdown. DCPP UNITS 1 & 2 FSAR UPDATE 15.3-11 Revision 21 September 2013 The reactor trip on low primary coolant loop flow is provided to protect against loss-of-flow conditions that affect only one reactor coolant loop. It also serves as a backup to the undervoltage and underfrequency trips. This function is generated by two-out-of-three low-flow signals per reactor coolant loop. Above approximately 35 percent power (Permissive 8), low flow in any loop will actuate a reactor trip. Between approximately 10 and 35 percent power (Permissive 7 and Permissive 8), low-flow in any two loops will actuate a reactor trip. A reactor trip from opened pump breakers is provided as a backup to the low-flow signals. Above Permissive 7 a breaker open signal from any 2 of 4 pumps will actuate a reactor trip. Reactor trip on reactor coolant pump breakers open is blocked below Permissive 7.
Normal power for the reactor coolant pumps is supplied through buses from a transformer connected to the generator. Two pumps are on each bus. When a generator trip occurs, the buses are automatically transferred to a transformer supplied from external power lines, and the pumps will continue to supply coolant flow to the core. Following any turbine trip, where there are no electrical or mechanical faults which require immediate tripping of the generator from the network, the generator remains connected to the network for approximately 30 seconds. The reactor coolant pumps remain connected to the generator thus ensuring full flow for 30 seconds after the reactor trip before any transfer is made. 15.3.4.3 Analysis of Effects and Consequences This transient is analyzed by three digital computer codes. First the LOFTRAN (Reference 8) code is used to calculate the loop and core flow during the transient. The LOFTRAN code is also used to calculate the nuclear power transient. The FACTRAN (Reference 9) code is then used to calculate the heat flux transient based on the nuclear power and flow from LOFTRAN. Finally, the THINC (see Section 1.6.1, item 28 and Section 4.4.3) code is used to calculate the minimum DNBR during the transient based on the heat flux from FACTRAN and flow from LOFTRAN. The transients presented represent the minimum of the typical and thimble cells.
The following cases have been analyzed: (1) Four of four loops coasting down (undervoltage). (2) Reactor coolant pumps power supply frequency decay at a maximum constant 3 Hz/sec rate (underfrequency). The method of analysis and the assumptions made regarding initial operating conditions and reactivity coefficients are identical to those discussed in Section 15.2, except that following the loss of supply to all pumps at power, a reactor trip is actuated by either bus undervoltage or bus underfrequency.
DCPP UNITS 1 & 2 FSAR UPDATE 15.3-12 Revision 21 September 2013 15.3.4.4 Results The calculated sequence of events is shown in Table 15.3-3. Figures 15.3.4-1 through 15.3.4-3 show the flow coastdown, the heat flux coastdown, and the nuclear power coastdown for the limiting complete loss of flow event, the four-loop coastdown. The reactor is assumed to trip on the bus undervoltage signal, as this trip actuation is more DNBR limiting for the DCPP analysis than the transient initiated from underfrequency reactor trip. A plot of DNBR versus time is given in Figure 15.3.4-4. This plot represents the limiting cell for the four-loop coastdown. 15.3.4.5 Conclusions The safety analysis results described in Section 15.3.4.4 have demonstrated that for the complete loss of forced reactor coolant flow, the minimum DNBR is above the safety analysis limit values of 1.71/1.68 (typical cell/thimble cell) during the transient; therefore, no core safety limit is violated. 15.3.5 SINGLE ROD CLUSTER CONTROL ASSEMBLY WITHDRAWAL AT FULL POWER 15.3.5.1 Acceptance Criteria (1) No more than 5 percent of the fuel rods experience a DNBR less than the limit value. 15.3.5.2 Identification of Causes and Accident Description By design, no single electrical or mechanical failure in the rod control system could cause the accidental withdrawal of a single RCCA from the inserted bank at full power operation. The operator could deliberately withdraw a single RCCA in the control bank; this feature is necessary in order to retrieve an assembly should one be accidentally dropped. In the extremely unlikely event of simultaneous electrical failures that could result in single RCCA withdrawal, rod deviation and control rod urgent failure may be displayed on the plant annunciator, and the rod position indicators would indicate the relative positions of the assemblies in the bank. The urgent failure alarm also inhibits automatic rod motion in the group in which it occurs. Withdrawal of a single RCCA by operator action, whether deliberate or by a combination of errors, would result in activation of the same alarm and the same visual indications.
Each bank of RCCAs in the system is divided into two groups of four mechanisms each (except Group 2 of Bank D which consists of five mechanisms). The rods comprising a group operate in parallel through multiplexing thyristors. The two groups in a bank move sequentially such that the first group is always within one step of the second group in the bank. A definite schedule of actuation and deactuation of the stationary gripper, movable gripper, and lift coils of a mechanism is required to withdraw the RCCA attached to the mechanism. Since the four stationary grippers, movable DCPP UNITS 1 & 2 FSAR UPDATE 15.3-13 Revision 21 September 2013 grippers, and lift coils associated with the four RCCAs of a rod group are driven in parallel, any single failure that would cause rod withdrawal would affect a minimum of one group, or four RCCAs. Mechanical failures are either in the direction of insertion or immobility.
In the unlikely event of multiple failures that result in continuous withdrawal of a single RCCA, it is not possible, in all cases, to provide assurance of automatic reactor trip so that core safety limits are not violated. Withdrawal of a single RCCA results in both positive reactivity insertion tending to increase core power, and an increase in local power density in the core area covered by the RCCA. 15.3.5.3 Analysis of Effects and Consequences Power distributions within the core are calculated by the ANC code based on macroscopic cross sections generated by PHOENIX-P (see Section 4.4.3). The peaking factors calculated by ANC (see Section 4.4.3) are then used by THINC (see Section 1.6.1, item 28 and Section 4.4.3) to calculate the minimum DNBR for the event. The plant was analyzed for the case of the worst rod withdrawn from Control Bank D inserted at the insertion limit, with the reactor initially at full power. 15.3.5.4 Results Two cases have been considered as follows:
(1) If the reactor is in the automatic control mode, withdrawal of a single RCCA will result in the immobility of the other RCCAs in the controlling bank. The transient will then proceed in the same manner as Case 2 described below. For such cases as above, a trip will ultimately ensue, although not sufficiently fast in all cases to prevent a minimum DNBR in the core of less than the safety limit. (2) If the reactor is in the manual control mode, continuous withdrawal of a single RCCA results in both an increase in core power and coolant temperature, and an increase in the local hot channel factor in the area of the failed RCCA. In terms of the overall system response, this case is similar to those presented in Section 15.2; however, the increased local power peaking in the area of the withdrawn RCCA results in lower minimum DNBR than for the withdrawn bank cases. Depending on initial bank insertion and location of the withdrawn RCCA, automatic reactor trip may not occur sufficiently fast to prevent the minimum core DNBR from falling below the safety limit value. Evaluation of this case at the power and coolant condition at which overtemperature T trip would be expected to trip the plant shows that an upper limit for the number of rods with a DNBR less than the safety limit value is 5 percent.
DCPP UNITS 1 & 2 FSAR UPDATE 15.3-14 Revision 21 September 2013 15.3.5.5 Conclusions The analysis demonstrates the acceptance criterion is met as follows: (1) For the case of one RCCA fully withdrawn, with the reactor in either the automatic or manual control mode and initially operating at full power with Bank D at the insertion limit, an upper bound of the number of fuel rods experiencing DNBR less than the safety analysis limit DNBR is 5 percent or less of the total fuel rods in the core. For both cases discussed, the indicators and alarms mentioned would function to alert the operator to the malfunction before any DNB could occur. For Case 2 discussed above, the insertion limit alarms (low and low-low alarms) would also serve in this regard. 15.
3.6 REFERENCES
- 1. Deleted in Revision 3.
- 2. Deleted in Revision 3.
- 3. J. M. Hellman, Fuel Densification Experimental Results and Model for Reactor Application, WCAP-8219, October 1973.
- 4. F. M. Bordelon, et al, LOCTA-IV Program: Loss-of-Coolant Transient Analysis, WCAP-8305 June 1974 5. Deleted in Revision 15.
- 6. Deleted in Revision 15.
- 7. Deleted in Revision 3.
- 8. T. W. T. Burnett, et al., LOFTRAN Code Description, WCAP-7907-A, April 1984.
- 9. H. G. Hargrove, FACTRAN, A Fortran-IV Code for Thermal Transients in UO2 Fuel Rods, WCAP-7908-A, December 1989.
- 10. Deleted in Revision 21.
- 11. Deleted in Revision 6.
- 12. P. E. Meyer, NOTRUMP, A Nodal Transient Small Break and General Network Code, WCAP-10079-P-A, August 1985.
DCPP UNITS 1 & 2 FSAR UPDATE 15.3-15 Revision 21 September 2013 13. H. Lee, S. D. Rupprecht, W. D. Tauche, W. R. Schwarz, Westinghouse Small Break ECCS Evaluation Model Using the NOTRUMP Code, WCAP-10054-P-A, August 1985.
- 14. Deleted in Revision 13.
- 15. Deleted in Revision 13.
- 16. Deleted in Revision 13.
- 17. Deleted in Revision 12.
- 18. Deleted in Revision 12.
- 19. Deleted in Revision 12.
- 20. Deleted in Revision 13.
- 21. Deleted in Revision 12.
- 22. Deleted in Revision 12.
- 23. Deleted in Revision 13.
- 24. Deleted in Revision 13.
- 25. Deleted in Revision 13.
- 26. Thompson, C. M., et al., Addendum to the Westinghouse Small Break LOCA Evaluation Model Using the NOTRUMP Code: Safety Injection Into the Broken Loop and the COSI Condensation Model, WCAP-10054-P-A, Addendum 2, Rev. 1, (proprietary), October 1995.
- 27. T. Q. Nguyen, et al., Qualification of the PHOENIX-P/ANC Nuclear Design System for Pressurized Water Reactor Cores, WCAP-11596-P-A, June 1988.
- 28. S. L. Davidson, (Ed), et al., ANC: Westinghouse Advanced Nodal Computer Code, WCAP-10965-P-A, September 1986.
DCPP UNITS 1 & 2 FSAR UPDATE 15.4-1 Revision 21 September 2013 15.4 CONDITION IV - LIMITING FAULTS Condition IV occurrences are faults that are not expected to take place, but are postulated because their consequences would include the potential for the release of significant amounts of radioactive material. These are the most drastic occurrences that must be designed against and represent limiting design cases. Condition IV faults shall not cause a fission product release to the environment resulting in an undue risk to public health and safety in excess of guideline values of 10 CFR Part 100. A single Condition IV fault shall not cause a consequential loss of required functions of systems needed to cope with the fault including those of the emergency core cooling system (ECCS) and the containment. For the purposes of this report the following faults have been classified in this category:
(1) Major rupture of pipes containing reactor coolant up to and including double-ended rupture of the largest pipe in the reactor coolant system (RCS), i.e., loss-of-coolant-accident (LOCA) (2) Major secondary system pipe ruptures (3) Steam generator tube rupture (4) Single reactor coolant pump (RCP) locked rotor (5) Fuel handling accident (6) Rupture of a control rod mechanism housing (rod cluster control assembly (RCCA) ejection) (7) Rupture of a gas decay tank (8) Rupture of a liquid holdup tank (9) Rupture of a volume control tank Each of these nine limiting faults is analyzed in this section. In general, each analysis includes acceptance criteria, an identification of causes and description of the accident, an analysis of effects and consequences, a presentation of results, and relevant conclusions.
The analyses of thyroid and whole body doses, resulting from events leading to fission product release, are presented in Section 15.5. The fission product inventories that form a basis for these calculations are presented in Chapter 11 and Section 15.5. Also included is a discussion of system interdependency contributing to limiting fission product leakages from the containment following a Condition IV occurrence.
DCPP UNITS 1 & 2 FSAR UPDATE 15.4-2 Revision 21 September 2013 The large break LOCA analysis contained in Section 15.4.1 has been revised to incorporate separate Best Estimate LOCA analyses for Units 1 and 2. The general discussion of the Best Estimate LOCA transient in Sections 15.4.1.2, 15.4.1.3, and 15.4.1.4 are applicable to Units 1 and 2. However, the statistical treatment methodologies are slightly different for Units 1 and 2. Statistical treatment methodologies for Units 1 and 2 are discussed in Sections 15.4.1.4A and 15.4.1.4B respectively. 15.4.1 MAJOR REACTOR COOLANT SYSTEM PIPE RUPTURES (LOCA) 15.4.1.1 Acceptance Criteria 15.4.1.1.1 10 CFR Part 50, Section 50.46, Acceptance Criteria for Emergency Core Cooling Systems for Light-Water Nuclear Power Reactors It must be demonstrated that there is a high level of probability that the limits set forth in 10 CFR 50.46 are met. The acceptance criteria are listed below: (1) Peak cladding temperature. The calculated maximum fuel element cladding temperature shall not exceed 2200 °F. (2) Maximum cladding oxidation. The calculated total oxidation of the cladding shall nowhere exceed 0.17 times the total cladding thickness before oxidation. (3) Maximum hydrogen generation. The calculated total amount of hydrogen generated from the chemical reaction of the cladding with water or steam shall not exceed 0.01 times the hypothetical amount that would be generated if all of the metal in the cladding cylinders surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react. (4) Coolable geometry. Calculated changes in core geometry shall be such that the core remains amenable to cooling. (5) Long-term cooling. After any calculated successful initial operation of the ECCS, the calculated core temperature shall be maintained at an acceptably low value and decay heat shall be removed for the extended period of time required by the long-lived radioactivity remaining in the core. 15.4.1.1.2 Radiological Criteria (1) The resulting potential exposures to individual members of the public and to the general population shall be lower than the applicable guidelines and limits specified in 10 CFR Part 100. DCPP UNITS 1 & 2 FSAR UPDATE 15.4-3 Revision 21 September 2013 15.4.1.2 Background of Best Estimate Large Break LOCA The analysis performed to comply with the requirements of 10 CFR 50.46 (Reference 1), and Revisions to the Acceptance Criteria (Reference 54) is presented in this section. In 1988, the NRC Staff amended the requirements of 10 CFR 50.46 and Appendix K, "ECCS Evaluation Models," to permit the use of a realistic evaluation model to analyze the performance of the ECCS during a hypothetical LOCA. This decision was based on an improved understanding of LOCA thermal-hydraulic phenomena gained by extensive research programs. Under the amended rules, best estimate thermal-hydraulic models may be used in place of models with Appendix K features. The rule change also requires, as part of the LOCA analysis, an assessment of the uncertainty of the best estimate calculations. It further requires that this analysis uncertainty be included when comparing the results of the calculations to the prescribed acceptance criteria of 10 CFR 50.46. Further guidance for the use of best estimate codes is provided in Regulatory Guide 1.157 (Reference 55). A LOCA evaluation methodology for three- and four-loop PWR plants based on the revised 10 CFR 50.46 rules was developed by Westinghouse with the support of EPRI and Consolidated Edison and has been approved by the NRC. The methodology is documented in WCAP-12945, "Code Qualification Document (CQD) for Best Estimate LOCA Analysis" (Reference 56). The time sequence of events during a nominal large double-ended cold leg guillotine (DECLG) break LOCA is shown in Tables 15.41-1A and 15.4.1-1B. The results of the large break LOCA analysis are shown in Tables 15.4.1-2A and 15.4.1-2B and show compliance with the acceptance criteria. The analytical techniques used for the large break LOCA analysis are in compliance with 10 CFR 50.46 (Reference 1) as amended in Reference 54, and are described in Reference 56. Due to the significant differences between the Unit 1 and Unit 2 reactor vessel internals, plant-specific vessel models were developed and evaluated. The significant differences between the units are summarized below: Unit 1 Unit 2 "Top Hat"-Upper Support Plate Flat Upper Support Plate Domed Lower Support Plate Flat Lower Support Plate Thermal Shield Neutron Pads Diffuser Plate No Diffuser Plate An analysis of each unit was performed and a comparison determined that the Unit 1 vessel model resulted in more limiting PCT values. As a result, the Best Estimate base Large Break LOCA analysis (Reference 60) results were based on Unit 1 and were considered bounding for both Unit 1 and Unit 2. Recently, the Unit 1 Best Estimate LOCA was reanalyzed for Unit 1 using the approved reanalysis methodology established in Reference 56. In the process of performing the Unit 1 reanalysis DCPP UNITS 1 & 2 FSAR UPDATE 15.4-4 Revision 21 September 2013 (Reference 67), it was determined that the Unit 1 vessel model no longer consistently resulted in the limiting PCTs, and could not be considered bounding for Unit 2. Therefore, the reanalysis methodology (Reference 56) was only applied to Unit 1, and a new and separate Best Estimate Large Break LOCA analysis was performed for Unit 2 using an updated and slightly different methodology as described in Reference 69. Both Unit 1 and Unit 2 use the base Best Estimate Large Break LOCA analysis methodology and computer code as described in Reference 60 and described in Section 15.4.1.3, which is applicable to Units 1 and 2. Separate subsequent subsections describe the Unit 1 reanalysis methodology (Reference 67), the Unit 2 analysis methodology (Reference 69), and the respective results. 15.4.1.3 WCOBRA/TRAC Thermal-hydraulic Computer Code The thermal-hydraulic computer code that was reviewed and approved for the calculation of fluid and thermal conditions in the PWR during a large break LOCA is WCOBRA/TRAC, Version Mod 7A, Revision 1 (Reference 56). A detailed assessment of the computer code WCOBRA/TRAC was made through comparisons to experimental data. These assessments were used to develop quantitative estimates of the code's ability to predict key physical phenomena in the PWR large break LOCA. Slightly different revisions to this computer code were used for the Unit 1 reanalysis and the separate Unit 2 analysis as described in later sections. WCOBRA/TRAC combines two-fluid, three-field, multi-dimensional fluid equations used in the vessel with one-dimensional drift-flux equations used in the loops to allow a complete and detailed simulation of a PWR. This best estimate computer code contains the following features: (1) Ability to model transient three-dimensional flows in different geometries inside the vessel (2) Ability to model thermal and mechanical non-equilibrium between phases (3) Ability to mechanistically represent interfacial heat, mass, and momentum transfer in different flow regimes (4) Ability to represent important reactor components such as fuel rods, steam generators, reactor coolant pumps, etc. The two-fluid formulation uses a separate set of conservation equations and constitutive relations for each phase. The effects of one phase on another are accounted for by interfacial friction and heat and mass transfer interaction terms in the equations. The conservation equations have the same form for each phase; only the constitutive relations and physical properties differ. Dividing the liquid phase into two fields is a convenient and physically accurate way of handling flows where the liquid can appear in both film and droplet form. The droplet field permits more accurate modeling of DCPP UNITS 1 & 2 FSAR UPDATE 15.4-5 Revision 21 September 2013 thermal-hydraulic phenomena, such as entrainment, de-entrainment, fallback, liquid pooling, and flooding. WCOBRA/TRAC also features a two-phase, one-dimensional hydrodynamics formulation. In this model, the effect of phase slip is modeled indirectly via a constitutive relationship that provides the phase relative velocity as a function of fluid conditions. Separate mass and energy conservation equations exist for the two-phase mixture and for the vapor. The reactor vessel is modeled with the three-dimensional, three field model, while the loop, major loop components, and safety injection points are modeled with the one-dimensional model. All geometries modeled using the three-dimensional model are represented as a matrix of cells. The number of mesh cells used depends on the degree of detail required to resolve the flow field, the phenomena being modeled, and practical restrictions such as computing costs and core storage limitations. The equations for the flow field in the three-dimensional model are solved using a staggered difference scheme on the Eulerian mesh. The velocities are obtained at mesh cell faces, and the state variables (e.g., pressure, density, enthalpy, and phasic volume fractions) are obtained at the cell center. This cell is the control volume for the scalar continuity and energy equations. The momentum equations are solved on a staggered mesh with the momentum cell centered on the scalar cell face. The basic building block for the mesh is the channel, a vertical stack of single mesh cells. Several channels can be connected together by gaps to model a region of the reactor vessel. Regions that occupy the same level form a section of the vessel. Vessel sections are connected axially to complete the vessel mesh by specifying channel connections between sections. Heat transfer surfaces and solid structures that interact significantly with the fluid can be modeled with rods and unheated conductors. One-dimensional components are connected to the vessel. The basic scheme used also employs the staggered mesh cell. Special purpose components exist to model specific components such as the steam generator and pump. A typical calculation using WCOBRA/TRAC begins with the establishment of a steady-state, initial condition with all loops intact. The input parameters and initial conditions for this steady-state calculation are discussed in the next section. Following the establishment of an acceptable steady-state condition, the transient calculation is initiated by introducing a break into one of the loops. The evolution of the transient through blowdown, refill, and reflood proceeds continuously, using the same computer code (WCOBRA/TRAC) and the same modeling assumptions. Containment pressure is modeled with the BREAK component using a time dependent pressure table. Containment pressure is calculated using the COCO code (Reference 61) and mass and energy releases from the WCOBRA/TRAC calculation. DCPP UNITS 1 & 2 FSAR UPDATE 15.4-6 Revision 21 September 2013 15.4.1.4 Thermal Analysis 15.4.1.4.1 Westinghouse Performance Criteria for ECCS The reactor is designed to withstand thermal effects caused by a LOCA including the double-ended severance of the largest RCS pipe. The reactor core and internals together with the ECCS are designed so that the reactor can be safely shut down and the essential heat transfer geometry of the core preserved following the accident.
The ECCS, even when operating during the injection mode with the most severe single active failure, is designed to meet the acceptance criteria of 10 CFR 50.46. 15.4.1.4.2 Sequence of Events and Systems Operations The sequence of events following a nominal large DECLG break LOCA is presented in Tables 15.4.1-1A and 15.4.1-1B for Units 1 and 2, respectively. Should a major break occur, depressurization of the RCS results in a pressure decrease in the pressurizer. The reactor trip signal subsequently occurs when the pressurizer low pressure trip setpoint is reached. A safety injection signal is generated when the appropriate setpoint is reached. These countermeasures will limit the consequences of the accident in two ways:
(1) Reactor trip and borated water injection complement void formation in causing rapid reduction of power to a residual level corresponding to fission product decay heat. No credit is taken during the LOCA transient for negative reactivity due to the boron concentration of the injection water. However, an average RCS/sump mixed boron concentration is calculated to ensure that the post-LOCA core remains subcritical. In addition, the insertion of control rods to shut down the reactor is not assumed in the large break analysis. (2) Injection of borated water provides the fluid medium for heat transfer from the core and prevents excessive cladding temperatures.
For the present Westinghouse PWR design, the limiting single failure assumed for a large break LOCA is the loss of one train of ECCS pumps (one charging pump (CCP1 or CCP2), one high-head safety injection (SI) pump, and one residual heat removal pump). One ECCS train delivers flow through the injection lines to each loop, with the least resistant branch injection line spilling to containment backpressure (Figures 15.4.1-14A and 15.4.1-14B and Tables 15.4.1-7A and 15.4.1-7B). All emergency diesel generators (EDGs) are assumed to start in the modeling of the containment fan coolers and spray pumps. Modeling full operation of the containment heat removal system is required by Branch Technical Position CSB 6-1, and is a conservative assumption for the large break LOCA analysis.
DCPP UNITS 1 & 2 FSAR UPDATE 15.4-7 Revision 21 September 2013 15.4.1.4.3 Description of a Large Break LOCA Transient Before the break occurs, the RCS is assumed to be operating normally at full power in an equilibrium condition, i.e., the heat generated in the core is being removed via the secondary system. A large DECLG break is assumed to open almost instantaneously in one of the main RCS pipes. Calculations have demonstrated that the most severe transient results occur for a DECLG break between the pump and the reactor vessel. The large break LOCA transient can be divided into convenient time periods in which specific phenomena occur, such as various hot assembly heatup and cooldown transients. For a typical large break, the blowdown period can be divided into the critical heat flux (CHF) phase, the upward core flow phase, and the downward core flow phase. These are followed by the refill, reflood, and long-term cooling periods. Specific important transient phenomena and heat transfer regimes are discussed below, with the transient results shown in Figures 15.4.1-1A to 15.4.1-12A for Unit 1 and Figures 15.4.1-1B to 15.4.1-12B for Unit 2. (1) Critical Heat Flux (CHF) Phase Immediately following the cold leg rupture, the break discharge rate is subcooled and high. The regions of the RCS with the highest initial temperatures (core, upper plenum, upper head, and hot legs) begin to flash to steam, the core flow reverses, and the fuel rods begin to go through departure from nucleate boiling (DNB). The fuel cladding rapidly heats up while the core power shuts down due to voiding in the core. This phase is terminated when the water in the lower plenum and downcomer begins to flash. The mixture swells and intact loop pumps, still rotating in single-phase liquid, push this two-phase mixture into the core. (2) Upward Core Flow Phase Heat transfer is improved as the two-phase mixture is pushed into the core. This phase may be enhanced if the pumps are not degraded, or if the break discharge rate is low due to saturated fluid conditions at the break. If pump degradation is high or the break flow is large, the cooling effect due to upward flow may not be significant. Figures 15.4.1-4A and 15.4.1-4B show the void fraction for one intact loop pump and the broken loop pump for Units 1 and 2, respectively. The figures show that the intact loop remains in single-phase liquid flow for several seconds, resulting in enhanced upward core flow cooling. This phase ends as the lower plenum mass is depleted, the loop flow becomes two-phase, and the pump head degrades. DCPP UNITS 1 & 2 FSAR UPDATE 15.4-8 Revision 21 September 2013 (3) Downward Core Flow Phase The loop flow is pushed into the vessel by the intact loop pumps and decreases as the pump flow becomes two-phase. The break flow begins to dominate and pulls flow down through the core, up the downcomer to the broken loop cold leg, and out the break. While liquid and entrained liquid flow provide core cooling, the top of core vapor flow, as shown in Figures 15.4.1-5A and 15.4.1-5B for Units 1 and 2, respectively, best illustrate this phase of core cooling. Once the system has depressurized to the accumulator pressure, the accumulators begin to inject cold borated water into the intact cold legs. During this period, due to steam upflow in the downcomer, a portion of the injected ECCS water is calculated to be bypassed around the downcomer and out the break. As the system pressure continues to fall, the break flow, and consequently the downward core flow, are reduced. The core begins to heat up as the system pressure approaches the containment pressure and the vessel begins to fill with ECCS water. (4) Refill Period As the refill period begins, the core begins a period of heatup and the vessel begins to fill with ECCS water. This period is characterized by a rapid increase in cladding temperatures at all elevations due to the lack of liquid and steam flow in the core region. This period continues until the lower plenum is filled and the bottom of the core begins to reflood and entrainment begins. (5) Reflood Period During the early reflood phase, the accumulators begin to empty and nitrogen enters the system. This forces water into the core, which then boils, causing system repressurization, and the lower core region begins to quench. During this time, core cooling may increase due to vapor generation and liquid entrainment. During the reflood period, the core flow is oscillatory as cold water periodically rewets and quenches the hot fuel cladding, which generates steam and causes system repressurization. The steam and entrained water must pass through the vessel upper plenum, the hot legs, the steam generators, and the reactor coolant pumps before it is vented out the break. This flow path resistance is overcome by the downcomer water elevation head, which provides the gravity driven reflood force. From the later stage of blowdown to the beginning of reflood, the accumulators rapidly discharge borated cooling water into the RCS, filling the lower plenum and contributing to the filling of the downcomer. The pumped ECCS water aids in the filling of the downcomer and subsequently supplies water to maintain a full downcomer and complete the reflood period. As the quench front progresses up the DCPP UNITS 1 & 2 FSAR UPDATE 15.4-9 Revision 21 September 2013 core, the PCT location moves higher into the top core region. As the vessel continues to fill, the PCT location is cooled and the early reflood period is terminated. A second cladding heatup transient may occur due to boiling in the downcomer. The mixing of ECCS water with hot water and steam from the core, in addition to the continued heat transfer from the hot vessel and vessel metal, reduces the subcooling of ECCS water in the lower plenum and downcomer. The saturation temperature is dictated by the containment pressure. If the liquid temperature in the downcomer reaches saturation, subsequent heat transfer from the vessel and other structures will cause boiling and level swell in the downcomer. The downcomer liquid will spill out of the broken cold leg and reduce the driving head, which can reduce the reflood rate, causing a late reflood heatup at the upper core elevations. Figures 15.4.1-12A and 15.4.1-12B show only a slight reduction in downcomer level which indicates that a late reflood heatup does not occur for either Unit. However, the Unit 1 reanalysis methodology (Reference 67) still requires that both the early and late reflood PCT periods be considered, while the Unit 2 updated analysis methodology (Reference 69) has eliminated the need to evaluate the late reflood period for PCT. For the Unit 1 reanalysis, the first reflood peak is considered to be the maximum PCT, which occurs after the beginning of reflood, and before the beginning of gravity driven reflood. In Unit 1 Figure 15.4.1-1A, this corresponds to the maximum PCT between about 35 and 50 seconds after the break. The second reflood peak is then considered to be the maximum PCT, which occurs after the beginning of gravity driven reflood. This terminology for first and second reflood PCTs is only used in the further discussions of the Unit 1 Best Estimate LBLOCA reanalysis. Continued operation of the ECCS pumps supplies water during the long-term cooling period. Core temperatures have been reduced to long-term steady state levels associated with dissipation of residual heat generation. When low level is reached in the refueling water storage tank (RWST), switchover to the recirculation phase is initiated. The residual heat removal (RHR) pumps are tripped, and the operator manually aligns the charging (CCP1 or CCP2) and safety injection (SI) pumps to the RHR pump discharge. Once the alignment is completed, all ECCS pumps recirculate containment recirculation sump water. The containment spray pumps continue to draw suction from the RWST until the low-low level is reached, at which time the containment spray pumps are tripped. If two RHR pumps are running, the containment spray valves can be aligned so that an RHR pump can be utilized to deliver recirculation water to the containment spray ring headers and spray nozzles for continued containment spray system post-accident operation.
Approximately 7.0 hours after initiation of the LOCA, the ECCS is realigned to supply water to the RCS hot legs in order to control the boric acid concentration in the reactor DCPP UNITS 1 & 2 FSAR UPDATE 15.4-10 Revision 21 September 2013 vessel. Long-term cooling also includes long-term criticality control. To achieve long-term criticality control, a mixed-mean sump boron concentration is determined and verified against core design margins to ensure core subcriticality, without credit for RCCA insertion. A mixed-mean sump boron concentration is calculated based on minimum volumes for boron sources and maximum volumes for dilution sources. The calculated mixed-mean sump boron concentration is verified against available core design margins on a cycle-specific basis. 15.4.1.4A Unit 1 Best Estimate Large Break LOCA Evaluation Model The thermal-hydraulic computer code that was reviewed and approved for the calculation of fluid and thermal conditions in the PWR during a large break LOCA is WCOBRA/TRAC, Version MOD7A Rev. 1 (Reference 56). Modeling of the PWR introduces additional uncertainties that are identified and quantified for the plant-specific Unit 1 analysis (Reference 60). The final step of the best estimate analysis methodology is to combine all the uncertainties related to the code and plant parameters, and estimate the PCT at 95 percent probability. The steps taken to derive the PCT uncertainty estimate are summarized below (1) Plant Model Development In this step, a WCOBRA/TRAC model of the plant is developed. A high level of noding detail is used in order to provide an accurate simulation of the transient. However, specific guidelines are followed to ensure that the model is consistent with models used in the code validation. This results in a high level of consistency among plant models, except for specific areas dictated by hardware differences, such as in the upper plenum of the reactor vessel or the ECCS injection configuration. (2) Determination of Plant Operating Conditions In this step, the expected or desired operating range of the plant to which the analysis applies is established. The parameters considered are based on a "key LOCA parameters" list that was developed as part of the methodology. A set of these parameters, at mostly nominal values, is chosen for input as initial conditions to the plant model. A transient is run utilizing these parameters and is known as the "initial transient." Next, several confirmatory runs are made, which vary a subset of the key LOCA parameters over their expected operating range in one-at-a-time sensitivities. The most limiting input conditions, based on these confirmatory runs, are then combined into a single transient, which is then called the "reference transient." DCPP UNITS 1 & 2 FSAR UPDATE 15.4-11 Revision 21 September 2013 (3) PWR Sensitivity Calculations A series of PWR transients is performed in which the initial fluid conditions and boundary conditions are ranged around the nominal condition used in the reference transient. The results of these calculations for DCPP form the basis for the determination of the initial condition bias and uncertainty discussed in Section 6 of Reference 60. Next, a series of transients is performed that vary the power distribution, taking into account all possible power distributions during normal plant operation. The results of these calculations for DCPP form the basis for the determination of the power distribution bias and uncertainty discussed in Section 7 of Reference 60. Finally, a series of transients is performed that vary parameters that affect the overall system response ("global" parameters) and local fuel rod response ("local" parameters). The results of these calculations for DCPP form the basis for the determination of the model bias and uncertainty discussed in Section 8 of Reference 60. (4) Response Surface Calculations Regression analyses are performed to derive PCT response surfaces from the results of the power distribution run matrix and the global model run matrix. The results of the initial conditions run matrix are used to generate a PCT uncertainty distribution. (5) Uncertainty Evaluation The total PCT uncertainty from the initial conditions, power distribution, and model calculations is derived using the approved methodology (Reference 56). The uncertainty calculations assume certain plant operating ranges that may be varied depending on the results obtained. These uncertainties are then combined to determine the initial estimate of the total PCT uncertainty distribution for the DECLG and split breaks. The results of these initial estimates of the total PCT uncertainty are compared to determine the limiting break type. If the split break is limiting, an additional set of split transients is performed that vary overall system response ("global" parameters) and local fuel rod response ("local" parameters). Finally, an additional series of runs is made to quantify the bias and uncertainty due to assuming that the above three uncertainty categories are independent. The final PCT uncertainty distribution is then calculated for the limiting break type, and the 95th percentile PCT is determined. DCPP UNITS 1 & 2 FSAR UPDATE 15.4-12 Revision 21 September 2013 (6) Plant Operating Range The plant operating range over which the uncertainty evaluation applies is defined. Depending on the results obtained in the above uncertainty evaluation, this range may be the desired range established in step 2, or may be narrower for some parameters to gain additional margin. There are three major uncertainty categories or elements:
(1) Initial condition bias and uncertainty (2) Power distribution bias and uncertainty (3) Model bias and uncertainty Conceptually, these elements may be assumed to affect the reference transient PCT as shown below.
PCTi = PCTREFi + PCTICi + PCTPDi + PCTMODi (15.4.1-1)
- where, PCTREFi = Reference transient PCT: The reference transient PCT is calculated using WCOBRA/TRAC at the nominal conditions identified in Table 15.4.1-3A, for blowdown (i=1), first reflood (i=2), and second reflood (i=3). PCTICi = Initial condition bias and uncertainty: This bias is the difference between the reference transient PCT, which assumes several nominal or average initial conditions, and the average PCT taking into account all possible values of the initial conditions. This bias takes into account plant variations that have a relatively small effect on PCT. The elements that make up this bias and its uncertainty are plant specific. PCTPDi = Power distribution bias and uncertainty: This bias is the difference between the reference transient PCT, which assumes a nominal power distribution, and the average PCT taking into account all possible power distributions during normal plant operation.
Elements that contribute to the uncertainty of this bias are calculational uncertainties, and variations due to transient operation of the reactor. PCTMODi = Model bias and uncertainty: This component accounts for uncertainties in the ability of the WCOBRA/TRAC code to accurately predict important phenomena that affect the overall system DCPP UNITS 1 & 2 FSAR UPDATE 15.4-13 Revision 21 September 2013 response ("global" parameters) and the local fuel rod response ("local" parameters). The code and model bias is the difference between the reference transient PCT, which assumes nominal values for the global and local parameters, and the average PCT taking into account all possible values of global and local parameters. The separability of the uncertainty components in the manner described above is an approximation since the parameters in each element may be affected by parameters in other elements. The bias and uncertainty associated with this assumption are quantified as part of the overall uncertainty methodology and included in the final estimates of the 95-percentile PCT ( PCT95%). The application of the reanalysis methodology to Unit 1 first determines a new reference transient PCT. The bias and uncertainty associated with the initial conditions, power distributions, and models are assumed to remain unchanged. This assumption is assessed to determine that the fundamental LOCA transient characteristics remain unchanged from the new reference transient to that of the original analysis. If applicable, the uncertainty in applying the reanalysis methodology is determined when the superposition assumption is requantified (i.e., the assumption that the major uncertainty elements are independent), and the new bias and new uncertainty is calculated. 15.4.1.5A Unit 1 Containment Backpressure A conservatively bounding minimum containment back pressure (Figure 15.4.1-14A) is calculated using the methods and assumptions described in Reference 2, Appendix A. Containment back pressure is calculated using the COCO code (Reference 61) and mass and energy releases from the WCOBRA/TRAC calculation. Input parameters used for the Unit 1 containment backpressure calculation are presented in Table 15.4.1-5A. This minimum containment back pressure is modeled using a time dependent pressure table as a boundary condition for the Best Estimate Large Break LOCA analysis. 15.4.1.6A Unit 1 Reference Transient Description A series of WCOBRA/TRAC calculations is performed to determine the PCT effect of variations in key LOCA parameters. An initial transient calculation is performed in which several parameters are set at their assumed bounding (most limiting) values in order to calculate a conservative PCT response to a large break LOCA. The results of these confirmatory runs, as well as the limiting plant determination runs, are incorporated into a final calculation that is referred to as the reference transient. The Unit 1 reference transient models a DECLG break that assumed the conditions listed in Table 15.4.1-3A and includes the Loss of Offsite Power (LOOP) assumption that was shown to produce more limiting PCT results than the offsite power available assumption. The reference transient calculation was performed with several parameters set at their bounding DCPP UNITS 1 & 2 FSAR UPDATE 15.4-14 Revision 21 September 2013 values in order to calculate a relatively high PCT. Single parameter variation studies based on the reference transient were performed to assess which parameters have a significant effect on the PCT results. The results of these studies are presented in Section 15.4.1.7A. The reference transient is the basis for the uncertainty calculations necessary to establish the Unit 1 PCT95%. 15.4.1.7A Unit 1 Sensitivity Studies A large number of single parameter sensitivity calculations of key LOCA parameters was performed to determine the PCT effect on the LBLOCA transient. These calculations are required as part of the approved Best Estimate LOCA methodology (Reference 56) to develop data for use in the uncertainty evaluation. For each sensitivity study, a comparison between the reference transient results and the sensitivity transient results was made. These single parameter sensitivity calculations were determined to remain applicable for the Unit 1 reanalysis methodology, as applied (Reference 67). The results of a small sample of these sensitivity studies performed for the original analysis (Reference 60) are summarized in Table 15.4.1-4A. The results of the entire array of sensitivity studies are included in Reference 60. The Unit 1 reanalysis is documented in Reference 67. The conclusions of the confirmatory cases were determined to remain the same (i.e., limiting direction of conservatism). 15.4.1.7A.1 Unit 1 Initial Condition Sensitivity Studies Several calculations were performed to evaluate the PCT effect of changes in the initial conditions on the LBLOCA transient. These calculations modeled single parameter variations in key initial plant conditions over the expected ranges of operation, including TAVG, RCS pressure, and ECCS temperatures, pressures, and volumes. The results of these studies are presented in Section 6 of Reference 60.
The results of these sensitivity studies were used to develop uncertainty distributions for the blowdown, first, and second reflood peaks. The uncertainty distributions resulting from the initial conditions, PCTICi, are used in the overall PCT uncertainty evaluation to determine the final estimate of PCT95%. 15.4.1.7A.2 Unit 1 Power Distribution Sensitivity Studies Several calculations were performed to evaluate the PCT effect of changes in power distributions on the LBLOCA transient. The approved methodology was used to develop a run matrix of peak linear heat rate relative to the core average, maximum relative rod power, relative power in the bottom third of the core, and relative power in the middle third of the core, as the power distribution parameters to be considered. These calculations modeled single parameter variations as well as multiple parameter variations. The results of these studies indicate that power distributions with peak DCPP UNITS 1 & 2 FSAR UPDATE 15.4-15 Revision 21 September 2013 powers skewed to the top of the core produced the most limiting PCTs. These results are presented in Section 7 of Reference 60.
The results of these sensitivity studies were used to develop response surfaces, which are used to predict the PCT due to changes in power distributions for the blowdown, first, and second reflood peaks. The uncertainty distributions resulting from the power distributions, PCTPDi, are used in the overall PCT uncertainty evaluation to determine the final estimate of PCT95%. 15.4.1.7A.3 Unit 1 Global Model Sensitivity Studies Several calculations were performed to evaluate the PCT effect of changes in global models on the LBLOCA transient. Reference 56 provides a run matrix of break discharge coefficient, broken cold leg resistance, and condensation rate as the global models to be considered for the double-ended guillotine break. These calculations modeled single parameter variations as well as multiple parameter variations. The limiting split break size was also identified using the approved methodology (Reference 56). These results are presented in Section 8 of Reference 60. The results of these sensitivity studies were used to develop response surfaces, which are used to predict the PCT due to changes in global models for the DECLG blowdown, first, and second reflood peaks. The uncertainty distribution resulting from the global models, PCTMODi, is used in the overall PCT uncertainty evaluation to determine the final estimate of PCT95%. These single parameter sensitivity calculations were determined to remain applicable for the Unit 1 reanalysis methodology, as applied (Reference 67). 15.4.1.7A.4 Unit 1 Overall PCT Uncertainty Evaluation and Results The equation used to initially estimate the 95 percentile PCT (PCTi of Equation 15.4.1-1) was presented in Section 15.4.1.4A. Each of the uncertainty elements (PCTICi, PCTPDi, PCTMODi) is considered to be independent of each other. Each element includes a correction or bias, which is added to PCTREFi to move it closer to the expected, or average, PCT. The bias from each element has an uncertainty associated with the methods used to derive the bias.
Each bias component of the uncertainty elements is considered a random variable, whose uncertainty distribution is obtained directly, or is obtained from the uncertainty of the parameters of which the bias is a function. Since PCTi is the sum of these biases, it also becomes a random variable. Separate initial PCT frequency distributions are constructed as follows for the DECLG break and the limiting split break:
(1) Generate a random value of each uncertainty element (PCTIC, PCTPD, PCTMOD)
DCPP UNITS 1 & 2 FSAR UPDATE 15.4-16 Revision 21 September 2013 (2) Calculate the resulting PCT using Equation 15.4.1-1 (3) Repeat the process many times to generate a histogram of PCTs The results of this assessment showed the DECLG break to be the limiting break type.
A final verification step is performed to quantify the bias and uncertainty resulting from the superposition assumption (i.e., the assumption that the major uncertainty elements are independent). Several additional WCOBRA/TRAC calculations are performed in which variations in parameters from each of the three uncertainty elements are modeled for the DECLG break. These predictions are compared to the predictions based on Equation 15.4.1-1, and additional biases and uncertainties are applied where appropriate.
The superposition assumption verification step was performed for the Unit 1 reanalysis (Reference 67). These calculations resulted in an adjustment of the bias and uncertainty that is required for the reanalysis methodology.
The estimate of the PCT at 95 percent probability is determined by finding that PCT below which 95 percent of the calculated PCTs reside. This estimate is the licensing basis PCT, under the revised ECCS rule (10 CFR 50.46). The results of the Best Estimate LBLOCA analysis are presented in Table 15.4.1-2A. The difference between the 95 percentile PCT and the average PCT increases with each subsequent PCT period, due to propagation of uncertainties. 15.4.1.8A Unit 1 Additional Evaluations Zircaloy Clad Fuel: An evaluation of Zircaloy clad fuel has shown that the Zircaloy clad fuel is bounded by the results of ZIRLO clad fuel analysis.
IFBA Fuel: An evaluation of IFBA fuel has shown that the IFBA fuel is bounded by the results of the non-IFBA fuel analysis. TAVG Coastdown: An end-of-cycle, full power TAVG coastdown at 565°F evaluation was performed and concluded that there would be no adverse effect on the Best Estimate LBLOCA analysis as a TAVG window between 565°F and 577.3°F was explicitly modeled in the Best Estimate LBLOCA analysis. These evaluations have been shown to continue to apply for the Unit 1 reanalysis (Reference 67). 15.4.1.9A Unit 1 10 CFR 50.46 Results It must be demonstrated that there is a high level of probability that the limits set forth in 10 CFR 50.46 are met. The demonstration that these limits are met is as follows:
DCPP UNITS 1 & 2 FSAR UPDATE 15.4-17 Revision 21 September 2013 (1) There is a high level of probability that the PCT shall not exceed 2200°F. The 95th percentile PCT results presented in Table 15.4.1-2A indicate that this regulatory limit has been met. (2) The local maximum oxidation (LMO) calculated in the original BELOCA analysis results (Reference 60) is based on a limiting PCT transient that is in excess of the Unit 1 reanalysis 95 percentile PCT and remains bounding for Unit 1. Based on this original conservative PCT transient, a LMO of 11 percent was calculated, which meets the 10 CFR 50.46 acceptance criterion (b)(2), i.e., "Local Maximum Oxidation of the cladding less than 17 percent," remains bounding for Unit 1, and is presented as an upper bound in Table 15.4.1-2A. (3) The maximum core wide oxidation (CWO) determined in the original BELOCA analysis results (Reference 60) was based on limiting fuel temperatures that exceed those in the Unit 1 reanalysis and remain bounding for Unit 1. Based on these original conservative fuel temperatures, the total amount of hydrogen generated (i.e., CWO) , is 0.0089 times (0.89 percent) the maximum theoretical amount, which meets the 10 CFR 50.46 acceptance criterion (b)(3), i.e., "Core-Wide Oxidation less than 1 percent," remains bounding for Unit 1, and is presented as an upper bound in Table 15.4.1-2A. (4) Criterion (b)(4) has historically been satisfied by adherence to criteria (b)(1) and (b)(2), and by assuring that fuel deformation due to combined LOCA and seismic loads is specifically addressed. The approved methodology (Reference 56) specifies that effects of LOCA and seismic loads on core geometry do not need to be considered unless grid crushing extends beyond the assemblies in the low-power channel as defined in the DCPP WCOBRA/TRAC model. This situation has not been calculated to occur for DCPP Unit 1. Therefore, acceptance criterion (b)(4) is satisfied. (5) The approved Westinghouse position on criterion (b)(5) is that this requirement is satisfied if a coolable geometry is maintained, and the core remains subcritical following the LOCA (Reference 56). This position is independent from and unaffected by the use of best-estimate LOCA methodology. 15.4.1.10A Unit 1 Plant Operating Range The expected PCT and associated uncertainty presented above for Unit 1 are valid for a range of plant operating conditions. Many parameters in the reference transient calculation are at nominal values. The range of variation of the operating parameters has been accounted for in the estimated PCT uncertainty. Table 15.4.1-7A summarizes the operating ranges for Unit 1. Note that Figure 15.4.1-15A illustrates the axial power distribution limits that were analyzed and are verified on a cycle-specific basis. DCPP UNITS 1 & 2 FSAR UPDATE 15.4-18 Revision 21 September 2013 Table 15.4.1-5A summarizes the LBLOCA containment data used for calculating containment back pressure. If plant operation is maintained within the plant operating ranges presented in Table 15.4.1-7A, the LOCA analyses presented in this section are considered to be valid. 15.4.1.4B Unit 2 Best Estimate Large Break LOCA Evaluation Model The thermal-hydraulic computer code, which was reviewed and approved for the calculation of fluid and thermal conditions in a PWR during a large break LOCA, is WCOBRA/TRAC Version MOD7A, Rev. 1 (Reference 56). Westinghouse has since developed an alternative uncertainty methodology called ASTRUM, which stands for Automated Statistical Treatment of Uncertainty Method (Reference 69). This method is still based on the "Code Qualification Document" (CQD) methodology (Reference 56). The ASTRUM methodology replaces the response surface technique with a statistical sampling method where the uncertainty parameters are simultaneously sampled for each case. The ASTRUM methodology has received NRC approval for referencing in licensing calculations (SER appended to Reference 69). The WCOBRA/TRAC MOD7A, Revision 6, is an evolution of Revision 1 that includes logic to facilitate the automation aspects of ASTRUM, user conveniences, and error corrections. WCOBRA/TRAC MOD7A, Revision 6, is documented in Reference 69.
A detailed assessment of the computer code WCOBRA/TRAC was made through comparisons with experimental data. These assessments were used to develop quantitative estimates of the code's ability to predict key physical phenomena in a PWR large break LOCA. Modeling of a PWR introduces additional uncertainties that are identified and quantified in the plant-specific analysis. The final step in application of the best-estimate methodology for Unit 2, in which all uncertainties of the LOCA parameters are accounted for to estimate a PCT, local maximum oxidation (LMO), and core-wide oxidation (CWO) at 95-percent probability, is described below.
(1) Plant Model Development In this step, a WCOBRA/TRAC model of the plant is developed. A high level of noding detail is used in order to provide an accurate simulation of the transient. However, specific guidelines are followed to ensure that the model is consistent with models used in the code validation. This results in a high level of consistency among plant models, except for specific areas dictated by hardware differences, such as in the upper plenum of the reactor vessel or the ECCS injection configuration. (2) Determination of Plant Operating Conditions In this step, the expected or desired operating range of the plant to which the analysis applies is established. The parameters considered are based DCPP UNITS 1 & 2 FSAR UPDATE 15.4-19 Revision 21 September 2013 on a "key LOCA parameters" list that was developed as part of the methodology. A set of these parameters, at mostly nominal values, is chosen for input as initial conditions to the plant model. A transient is run utilizing these parameters and is known as the "initial transient." Next, several confirmatory runs are made, which vary a subset of the key LOCA parameters over their expected operating range in one-at-a-time sensitivities. Because certain parameters are not included in the uncertainty analysis, these parameters are set at their bounding condition.
This analysis is commonly referred to as the confirmatory analysis. The most limiting input conditions, based on these confirmatory runs, are then combined into the model that will represent the limiting state for the plant, which is the starting point for the assessment of uncertainties.
(3) Assessment of Uncertainty The ASTRUM methodology is based on order statistics. The technical basis of the order statistics is described in Section 11 of Reference 69.
The determination of the PCT uncertainty, LMO uncertainty, and CWO uncertainty relies on a statistical sampling technique. According to the statistical theory, 124 WCOBRA/TRAC calculations are necessary to assess against the three 10 CFR 50.46 criteria (PCT, LMO, CWO). The uncertainty contributors are sampled randomly from their respective distributions for each of the WCOBRA/TRAC calculations. The list of uncertainty parameters, which are randomly sampled for each time in the cycle, break type (split or double-ended guillotine), and break size for the split break are also sampled as uncertainty contributors within the ASTRUM methodology. Results from the 124 calculations are tallied by ranking the PCT from highest to lowest. A similar procedure is repeated for LMO and CWO. The highest rank of PCT, LMO, and CWO will bound 95 percent of their respective populations with 95-percent confidence level.
(4) Plant Operating Range The plant operating range over which the uncertainty evaluation applies is defined. Depending on the results obtained in the above uncertainty evaluation, this range may be the desired range or may be narrower for some parameters to gain additional margin.
15.4.1.5B Unit 2 Containment Backpressure A conservatively bounding minimum containment back pressure (Figure 15.4.1-14B) is calculated using the methods and assumptions described in Reference 2, Appendix A. Containment back pressure is calculated using the COCO code (Reference 61), the input parameters presented in Table 15.4.1-5B, mass and energy releases from the DCPP UNITS 1 & 2 FSAR UPDATE 15.4-20 Revision 21 September 2013 WCOBRA/TRAC calculation, and the structural heat sinks presented in Table 15.4.1-5A. Input parameters used for the Unit 2 containment backpressure calculation are presented in Table 15.4.1-5B. This minimum containment back pressure is modeled using a time dependent pressure table as a boundary condition for the Best Estimate Large Break LOCA analysis. 15.4.1.6B Unit 2 Confirmatory Studies A few confirmatory studies were performed to establish the limiting conditions for the uncertainty evaluation. In the confirmatory studies performed, key LOCA parameters are varied over a range and the impact on the peak cladding temperature is assessed.
The results for the confirmatory studies are summarized in Table 15.4.1-4B. In summary, the limiting conditions for the plant at the time the design basis accident is postulated to occur are reflected in the final reference transient. These limiting conditions are:
(1) Loss of offsite power (2) High RCS average temperature (3) High steam generator tube plugging of 15 percent (4) High average power fraction in the assemblies on the core periphery (fraction of power in outer assemblies = 0.8) 15.4.1.7B Unit 2 Uncertainty Evaluation The ASTRUM methodology (Reference 69) differs from the previously approved Westinghouse Best-Estimate methodology (Reference 56) primarily in the statistical technique used to make a singular probabilistic statement with regard to the conformance of the system under analysis to the regulatory requirement of 10 CFR 50.46.
The ASTRUM methodology applies a non-parametric statistical technique to generate output e.g., PCT, LMO, and CWO from a combination of WCOBRA/TRAC and HOTSPOT (Reference 68) calculations. These calculations are performed by applying a direct, random Monte Carlo sampling to generate the input for the WCOBRA/TRAC and HOTSPOT computer codes.
This approach allows the formulation of a simple singular statement of uncertainty in the form of a tolerance interval for the numerical acceptance criteria of 10 CFR 50.46. Based on the non-parametric statistical approach, the number of Monte Carlo runs is only a function of the tolerance interval and associated confidence level required to meet the desired level of safety.
DCPP UNITS 1 & 2 FSAR UPDATE 15.4-21 Revision 21 September 2013 15.4.1.8B Unit 2 Limiting PCT Transient Description The DCPP Unit 2 PCT-limiting transient is a DECLG break which analyzes conditions that fall within those listed in Table 15.4.1-7B. The sequence of events following is presented in Table 15.4.1-1B. The PCT-limiting case was chosen to show a conservative representation of the response to a large break LOCA. 15.4.1.9B Unit 2 10 CFR 50.46 Results It must be demonstrated that there is a high level of probability that the limits set forth in 10 CFR 50.46 are met. The demonstration that these limits are met is as follows:
(1) Because the resulting PCT for the limiting case is 1872 °F, which represents a bounding estimate of the 95th percentile PCT at the 95-percent confidence level, the analysis confirms that 10 CFR 50.46 acceptance criterion (b)(1), i.e., "Peak Cladding Temperature less than 2200 °F", is met. The results are shown in Table 15.4.1-2B. (2) Because the resulting local maximum oxidation (LMO) for the limiting case is 1.64 percent, which represents a bounding estimate of the 95th percentile LMO at the 95-percent confidence level, the analysis confirms that 10 CFR 50.46 acceptance criterion (b)(2), i.e., "Local Maximum Oxidation of the cladding less than 17 percent," is met. The results are shown in Table 15.4.1-2B. (3) The limiting hot fuel assembly rod has a calculated maximum oxidation of 0.17 percent. Because this is the hottest fuel rod within the core, the calculated maximum oxidation for any other fuel rod would be less than this value. For the low power peripheral fuel assemblies, the calculated oxidation would be significantly less than this maximum value. The core wide oxidation (CWO) is essentially the sum of all calculated maximum oxidation values for all of the fuel rods within the core. Therefore, a detailed CWO calculation is not needed because the calculated sum will always be less than 0.17 percent. Because the resulting CWO is conservatively assumed to be 0.17 percent, which represents a bounding estimate of the 95th percentile CWO at the 95-percent confidence level, the analysis confirms that 10 CFR 50.46 acceptance criterion (b)(3), i.e.,
"Core-Wide Oxidation less than 1 percent," is met. The results are shown in Table 15.4.1-2B. (4) Criterion (b)(4) has historically been satisfied by adherence to criteria (b)(1) and (b)(2), and by assuring that fuel deformation due to combined LOCA and seismic loads is specifically addressed. The approved methodology (Reference 56) specifies that effects of LOCA and seismic loads on core geometry do not need to be considered unless grid crushing extends beyond the assemblies in the low-power channel as defined in the DCPP UNITS 1 & 2 FSAR UPDATE 15.4-22 Revision 21 September 2013 DCPP WCOBRA/TRAC model. This situation has not been calculated to occur for DCPP Unit 2. Therefore, acceptance criterion (b)(4) is satisfied. (5) The approved Westinghouse position on Criterion (b)(5) is that this requirement is satisfied if a coolable geometry is maintained, and the core remains subcritical following the LOCA (Reference 56). This position is independent from and unaffected by the use of best-estimate LOCA methodology. 15.4.1.10B Unit 2 Plant Operating Range The accepted PCT and its uncertainty developed previously are valid for a range of Unit 2 plant operating conditions. The range of variation of the operating parameters has been accounted for in the uncertainty evaluation. Table 15.4.1-7B summarizes the operating ranges for DCPP Unit 2 as defined for the proposed operating conditions, which are supported by the Best-Estimate LBLOCA analysis. Table 15.4.1-5B summarizes the LBLOCA containment data used for calculating containment back pressure. It should be noted that other non-LBLOCA analyses may not support these ranges. If operation is maintained within these ranges, the LBLOCA results developed in this report using WCOBRA/TRAC are considered to be valid. Note that some of these parameters vary over their range during normal operation (accumulator temperature) and other ranges are fixed for a given operational condition (Tavg). 15.4.1.11 Conclusions (Common) 15.4.1.11.1 10 CFR 50.46 Acceptance Criteria It must be demonstrated that there is a high level of probability that the limits set forth in 10 CFR 50.46 are met. The demonstration that these limits are met is as follows: (1) The limiting PCT corresponds to a bounding estimate of the 95th percentile PCT at the 95-percent confidence level such that the analysis confirms that 10 CFR 50.46 acceptance criterion (b)(1), i.e., "Peak Cladding Temperature less than 2200 ºF", is demonstrated. (2) 10 CFR 50.46 acceptance criterion (b)(2), requires that the maximum calculated reduction in fuel cladding thickness at any location in the core due to the zirconium and water (Zr-H2O) reaction shall be less than 17 percent of the original cladding thickness. Because the Zr-H2O reaction essentially oxidizes the fuel cladding and generates hydrogen as a by-product, the reduction in cladding thickness is evaluated based on the amount of H2 generated (i.e., oxidation) at a given core location. The BELOCA methodology calculates the local maximum oxidation (LMO), which corresponds to a bounding estimate of the 95th percentile LMO at the 95-percent confidence level such that the analysis confirms that the DCPP UNITS 1 & 2 FSAR UPDATE 15.4-23 Revision 21 September 2013 10 CFR 50.46 acceptance criterion (b)(2), i.e., "Local Maximum Oxidation of the Cladding Less than 17 percent," is demonstrated. (3) 10 CFR 50.46 acceptance criterion (b)(3) requires that the total quantity of fuel cladding oxidized due to the Zr-H2O reaction shall be less than 1 percent, which is verified by ensuring the total calculated amount of H2 generated is less than 1 percent of the theoretical maximum possible if all of the fuel cladding in the core was oxidized. The BELOCA methodology calculates the limiting core wide oxidation (CWO) which corresponds to a bounding estimate of the 95th percentile CWO at the 95-percent confidence level such that the analysis confirms that 10 CFR 50.46 acceptance criterion (b)(3), i.e., "Core-Wide Oxidation Less than 1 percent," is demonstrated. (4) 10 CFR 50.46 acceptance criterion (b)(4) requires that the calculated changes in core geometry are such that the core remains amenable to cooling. This criterion has historically been satisfied by adherence to criteria (b)(1) and (b)(2), and by assuring that fuel deformation due to combined LOCA and seismic loads is specifically addressed. The approved methodology (Reference 56) specifies that effects of LOCA and seismic loads on core geometry do not need to be considered unless fuel grid crushing extends beyond the assemblies representing the low-power channel. (5) 10 CFR 50.46 acceptance criterion (b)(5) requires that long-term core cooling be provided following the successful initial operation of the ECCS. The approved Westinghouse position on this criterion is that this requirement is satisfied if a coolable geometry is maintained, and the core remains subcritical following the LOCA (Reference 56). This position is independent from and unaffected by the use of best-estimate LOCA methodology. 15.4.1.11.2 Radiological Section 15.5.17.11 concludes that the resulting potential exposures have been found to be lower than the applicable guidelines and limits specified in 10 CFR Part 100. 15.4.2 MAJOR SECONDARY SYSTEM PIPE RUPTURE Three major secondary system pipe ruptures are analyzed in this section: rupture of a main steam line at hot zero power, rupture of a main feedwater pipe, and rupture of a main steam line at power. The time sequence of events for each of these events is provided in Table 15.4-8.
DCPP UNITS 1 & 2 FSAR UPDATE 15.4-24 Revision 21 September 2013 15.4.2.1 Rupture of a Main Steam Line at Hot Zero Power 15.4.2.1.1 Acceptance Criteria The following limiting criteria are applicable for a main steam line rupture at hot zero power: 15.4.2.1.1.1 Fuel Damage Criteria Any fuel damage calculated to occur must be of sufficiently limited extent that the core will remain in place and intact with no loss of core cooling capability. This is conservatively demonstrated by meeting the following criteria: (1) DNB will not occur on the lead rod with at least a 95 percent probability at a 95 percent confidence level. The minimum DNBR must not go below the applicable limit value of 1.45 at any time during the transient. 15.4.2.1.1.2 Radiological Criteria (1) The resulting potential exposures to individual members of the public and to the general population shall be lower than the applicable guidelines and limits specified in 10 CFR Part 100. 15.4.2.1.2 Identification of Causes and Accident Description The steam release from a rupture of a main steam pipe would result in an initial increase in steam flow that decreases during the accident as the steam pressure falls. The energy removal from the RCS causes a reduction of coolant temperature and pressure. In the presence of a negative moderator temperature coefficient, the cooldown results in a positive reactivity insertion and subsequent reduction of core shutdown margin. If the most reactive RCCA is assumed stuck in its fully withdrawn position after reactor trip, there is an increased possibility that the core will become critical and return to power. A return to power following a steam pipe rupture is a potential problem mainly because of the high power peaking factors that exist assuming the most reactive RCCA to be stuck in its fully withdrawn position. The core is ultimately shut down by the boric acid injection delivered by the SIS and accumulators.
In order to allow for routine plant heatups and cooldowns, plant procedures allow the SIS to be blocked per permissive P-11, provided that the RCS boron concentration is maintained at a value greater than or equal to the cold shutdown margin requirement. As discussed in Reference 63, this additional shutdown margin ensures that there would be no return to power for a steam pipe rupture such that the analysis of a rupture of a steam line at hot zero power remains bounding.
The analysis of a main steam pipe rupture is performed to demonstrate that the following criteria are satisfied:
DCPP UNITS 1 & 2 FSAR UPDATE 15.4-25 Revision 21 September 2013 (1) Assuming a stuck RCCA, with or without offsite power, and assuming a single failure in the engineered safety features (ESF) there is no consequential damage to the primary system and the core remains in place and intact. (2) Energy release to containment from the worst steam pipe break does not cause failure of the containment structure (see Appendix 6.2D). Although DNB and possible cladding perforation following a steam pipe rupture are not necessarily unacceptable, the following analysis, in fact, shows that the DNB design basis is met for any rupture assuming the most reactive assembly stuck in its fully withdrawn position.
The following functions provide protection for a steam line rupture:
(1) SIS actuation from any of the following: (a) Two-out-of-four low pressurizer pressure signals (b) Two-out-of-three low steam line pressure signals in any one loop (c) Two-out-of-three high containment pressure signals (2) The overpower reactor trips (neutron flux and T) and the reactor trip occurring in conjunction with receipt of the safety injection signal. (3) Redundant isolation of the main feedwater lines: sustained high feedwater flow would cause additional cooldown. Therefore, a safety injection signal will rapidly close all feedwater control valves, trip the main feedwater pumps, and close the feedwater isolation valves that backup the control valves. (4) Closure of the fast acting main steam line isolation valves on: (See Figure 7.2-1 and the Technical Specifications (Reference 30)) (a) Two-out-of-three low steam line pressure signals in any one loop (b) Two-out-of-four high-high containment pressure (c) Two-out-of-three high negative steam line pressure rate signals in any one loop (used only during cooldown and heatup operations)
The fast-acting isolation valves are provided in each main steam line and will fully close within 10 seconds of a large steam line break. For breaks downstream of the isolation valves, closure of all valves would completely terminate the blowdown. For any break, in any location, no more than one steam generator would blow down even if one of the DCPP UNITS 1 & 2 FSAR UPDATE 15.4-26 Revision 21 September 2013 isolation valves fails to close. A description of steam line isolation is included in Chapter 10.
The effective throat area of the integral flow restrictors in the steam generators is 1.388 ft2, which is considerably smaller than the area of the main steam pipe. These restrictors serve to limit the maximum steam flow for any break at any location. 15.4.2.1.3 Analysis of Effects and Consequences The analysis of the steam pipe rupture has been performed to determine:
(1) The plant transient conditions, including core heat flux and RCS temperature and pressure resulting from the cooldown following the steam line break. The RETRAN-02W code (Reference 70) has been used. (2) The thermal and hydraulic behavior of the core following a steam line break. A detailed thermal and hydraulic digital-computer code, THINC (See Section 1.6.1, item 28 and Section 4.4.3), has been used to determine if DNB occurs for the core conditions computed in (1) above.
The following conditions were assumed to exist at the time of a main steam line break accident.
(1) End of life (EOL) shutdown margin at no-load, equilibrium xenon conditions, and the most reactive assembly stuck in its fully withdrawn position: Operation of the control rod banks during core burnup is restricted in such a way that addition of positive reactivity in a steam line break accident will not lead to a more adverse condition than the case analyzed. (2) The negative moderator coefficient corresponds to the EOL rodded core with the most reactive rod in the fully withdrawn position. The variation of the coefficient with temperature and pressure has been included. The keff versus temperature at 1050 psia corresponding to the negative moderator temperature coefficient, plus the Doppler temperature effect used is shown in Figure 15.4.2-2. The effect of power generation in the core on overall reactivity is shown in Figure 15.4.2-1. The core properties associated with the sector nearest the affected steam generator and those associated with the remaining sector were conservatively combined to obtain average core properties for reactivity feedback calculations. To verify the conservatism of this method, the reactivity as well as the power distribution was checked with the advanced nodal code core model (see Section 4.3.3.3). These core analyses considered the Doppler reactivity from the high fuel temperature near the DCPP UNITS 1 & 2 FSAR UPDATE 15.4-27 Revision 21 September 2013 stuck RCCA, moderator feedback from the high water enthalpy near the stuck RCCA, power redistribution and non-uniform core inlet temperature effects. For cases in which steam generation occurs in the high flux regions of the core, the effect of void formation was also included. It was confirmed that the reactivity feedback model employed in the RETRAN-02W kinetics analysis was consistent with the core analysis and the overall analysis is conservative. (3) The modeling of the SIS in RETRAN-02W is described in Reference 70. The minimum boric acid solution concentration of 2300 ppm in the RWST is assumed. The SIS piping downstream of the RWST isolation valves is assumed to contain no boron (0 ppm), which delays the delivery of boron to the reactor coolant loops from the RWST water. With this conservative assumption, the SIS and accumulators combine to limit the return to power. Cases were examined for both minimum and maximum SIS flow rates. For the minimum SIS flow rate cases the most restrictive single failure in the SIS is considered. The SIS flow assumed conservatively corresponds to that delivered by only one high-head charging pump delivering full flow to the cold leg header. The charging pump (CCP1 or CCP2) is assumed to begin providing flow to the RCS at 25 seconds after receipt of the SI signal for the case in which offsite power is assumed available, and at 35 seconds for the case where offsite power is not available; the additional 10-second delay is assumed to start the diesels and load the necessary safety injection equipment onto them. For the maximum SIS flow rate cases, a flow profile was assumed that bounds the maximum flow from two high-head charging pumps (CCP1 and CCP2) plus two intermediate-head SI pumps plus the non-safety-related CVCS charging pump (CCP3). A 2-second signal delay was assumed. For this analysis, it was determined that the maximum SIS flow rate assumption is conservative for the more limiting case with offsite power available, due to the effect of higher SIS flow on the timing of cold leg accumulator actuation. The cold leg accumulators provide an additional source of borated water to the core when the RCS pressure decreases below the actuation setpoint. The minimum accumulator boron concentration of 2200 ppm is assumed, along with a conservatively low actuation setpoint of 577.2 psia. Actuation of the accumulators causes a significant influx of boron, which rapidly shuts down the reactor. Assuming the maximum SIS flow rate slows down the rate of the RCS pressure decrease and thus delays the accumulator actuation. If the most reactive RCCA is assumed stuck in its fully withdrawn position after a reactor trip, there is an increased possibility that the core will become critical and DCPP UNITS 1 & 2 FSAR UPDATE 15.4-28 Revision 21 September 2013 return to power. A return to power following a steam pipe rupture is a potential problem mainly because of the high power peaking factors that would exist assuming the most-reactive RCCA to be stuck in its fully withdrawn position. Therefore, the limiting case presented herein conservatively assumes a maximum SIS flow rate. (4) Because the steam generators are equipped with integral flow restrictors with a 1.388 ft2 throat area, any rupture with a break greater than this size, regardless of the location, would have the same effect on the reactor as a 1.388 ft2 break. The following two cases have been considered in determining the core power and RCS transients: (a) Complete severance of a pipe with the plant initially at no-load conditions and with offsite power available. Full reactor coolant flow is maintained. (b) Complete severance of a pipe with the plant initially at no-load conditions and with offsite power unavailable. Loss of offsite power results in reactor coolant pump coastdown. (5) Power peaking factors corresponding to one stuck RCCA and non-uniform core inlet coolant temperatures are determined at EOL. The coldest core inlet temperatures are assumed to occur in the sector with the stuck rod.
The power peaking factors account for the effect of the local void in the region of the stuck control assembly during the return to power phase following the steam line break. This void in conjunction with the large negative moderator coefficient partially offsets the effect of the stuck assembly. The power peaking factors depend on the core power, operating history, temperature, pressure, and flow. All the cases above assume initial hot shutdown conditions at time zero, because this represents the most limiting initial condition. Should the reactor be just critical or operating at power at the time of a steam line break, the reactor will be tripped by the normal overpower protection system when power level reaches a trip point. Following a trip at power the RCS contains more stored energy than at no-load, the average coolant temperature is higher than at no-load, and there is appreciable energy stored in the fuel. Thus, the additional stored energy is removed via the cooldown caused by the steam line break before the no-load conditions of RCS temperature and shutdown margin assumed in the analyses are reached. After the additional stored energy has been removed, the cooldown and reactivity insertions proceed in the same manner as in the analysis, which assumes no-load condition at time zero. DCPP UNITS 1 & 2 FSAR UPDATE 15.4-29 Revision 21 September 2013 However, because the initial steam generator water inventory is greatest at no-load, the magnitude and duration of the RCS cooldown are less for steam line breaks occurring at power. (6) In computing the steam flow during a steam line break, the Moody Curve (Reference 16) for fl/D = 0 is used. (7) Perfect moisture separation in the steam generator is assumed. This assumption leads to conservative results because, in fact, considerable water would be discharged. Water carryover would reduce the magnitude of the temperature decrease in the core. (8) To maximize the primary-to-secondary heat transfer rate, 0 percent steam generator tube plugging is assumed. (9) All main and auxiliary feedwater pumps are assumed to be operating at full capacity when the rupture occurs. This assumption maximizes the cooldown. A conservatively high auxiliary feedwater flow rate of 1700 gpm at a minimum temperature of 60ºF is assumed to be delivered to the affected steam generator. Main feedwater is isolated 64 seconds following the SI signal by closure of the main feedwater isolation valves. No credit is taken for the faster-closing main feedwater control valves. Auxiliary feedwater continues for the duration of the transient. (10) The effect of heat transferred from thick metal in the reactor coolant system and the steam generators is not included in the cases analyzed. The heat transferred from these sources would be a net benefit because it would slow the cooldown of the RCS. 15.4.2.1.4 Results The double-ended rupture of a main steam line at zero power was analyzed for both Units 1 and 2; however, only the results from the slightly more limiting Unit 1 cases are presented. Unit 2 results are similar. The time sequence of events, both with and without offsite power available for Unit 1, are presented in Table 15.4-8.
Figures 15.4.2-4 through 15.4.2-6 show the plant response following a main steam pipe rupture. Offsite power is assumed to be available such that full reactor coolant flow exists. The transient shown assumes an uncontrolled steam release from only one steam generator.
Figures 15.4.2-7 through 15.4.2-9 show the plant response for the case with a loss of offsite power. This assumption results in a coastdown of the reactor coolant pumps. In this case, the core power increases at a slower rate and reaches a lower peak value than in the case with offsite power available. The ability of the emptying steam generator to extract heat from the RCS is reduced by the decreased flow in the RCS. DCPP UNITS 1 & 2 FSAR UPDATE 15.4-30 Revision 21 September 2013 It should be noted that following a steam line break only one steam generator blows down completely. Thus, the remaining steam generators are still available for dissipation of decay heat after the initial transient is over. In the case with loss of offsite power, this heat would be removed to the atmosphere via the main steam safety valves. 15.4.2.1.5 Conclusions The analysis demonstrates the acceptance criteria are met as follows: 15.4.2.1.5.1 Fuel Limits Based on the results of the analysis, the core will remain in place and intact with no loss of core cooling capability. A DNB analysis was performed for the limiting steam line break case with offsite power available as described above. The analysis demonstrated that the minimum DNBR remains well above the limit value of 1.45. Therefore, the DNB design basis is met for the steam line break event initiated from zero power. 15.4.2.1.5.2 Radiological Section 15.5.18 concludes that potential exposures from major steam line ruptures will be well below the guideline levels specified in 10 CFR Part 100. 15.4.2.2 Major Rupture of a Main Feedwater Pipe 15.4.2.2.1 Acceptance Criteria The following limiting criteria are applicable for a main feedwater pipe rupture: 15.4.2.2.1.1 Fuel Damage Criteria Any fuel damage calculated to occur must be of sufficiently limited extent that the core will remain in place and intact with no loss of core cooling capability. This is conservatively demonstrated by meeting the following criteria: (1) With respect to fuel damage due to "dryout" where the water level in the vessel drops below the top of the core, criterion that no bulk boiling occurs in the primary coolant system prior to event "turnaround" is applied. Turnaround is defined as the point when the heat removal capability of the steam generators, being fed by auxiliary feedwater (AFW), exceeds NSSS heat generation. DCPP UNITS 1 & 2 FSAR UPDATE 15.4-31 Revision 21 September 2013 15.4.2.2.1.2 Maximum RCS and Main Steam System Pressure Requirements: The maximum pressure in the RCS and main steam system should be maintained below 110 percent of the design value, 2748.5 psia and 1208.5 psia, respectively. 15.4.2.2.1.3 Radiological Criteria The resulting potential exposures to individual members of the public and to the general population shall be lower than the applicable guidelines and limits specified in 10 CFR Part 100. 15.4.2.2.2 Identification of Causes and Accident Description A major feedwater line rupture is defined as a break in a feedwater pipe large enough to prevent the addition of sufficient feedwater to the steam generators to maintain shell-side fluid inventory in the steam generators. If the break is postulated in a feedline between the check valve and the steam generator, fluid from the steam generator may also be discharged through the break. Further, a break in this location could preclude the subsequent addition of AFW to the affected steam generator. (A break upstream of the feedline check valve would affect the nuclear steam supply system (NSSS) only as a loss of feedwater. This case is covered by the evaluation in Section 15.2.8).
Depending on the size of the break and the plant operating conditions at the time of the break, the break could cause either an RCS cooldown (by excessive energy discharge through the break), or an RCS heatup. Potential RCS cooldown resulting from a secondary pipe rupture is evaluated in Section 15.4.2.1. Therefore, only the RCS heatup effects are evaluated for a feedline rupture. A feedline rupture reduces the ability to remove heat generated by the core from the RCS for the following reasons:
(1) Feedwater to the steam generators is reduced. Since feedwater is subcooled, its loss may cause reactor coolant temperatures to increase prior to reactor trip (2) Liquid in the steam generator may be discharged through the break, and would then not be available for decay heat removal after trip (3) The break may be large enough to prevent the addition of any main feedwater after trip The following provide the necessary protection against a main feedwater line rupture: (1) A reactor trip on any of the following conditions: (a) High pressurizer pressure DCPP UNITS 1 & 2 FSAR UPDATE 15.4-32 Revision 21 September 2013 (b) Overtemperature T (c) Low-low steam generator water level in any steam generator (d) Safety injection signals from any of the following:
- Low steam line pressure
- High containment pressure (Refer to Chapter 7 for a description of the actuation system.) (2) An AFW system to provide an assured source of feedwater to the steam generators for decay heat removal (Refer to Chapter 6 for a description of the AFW system.) 15.4.2.2.3 Analysis of Effects and Consequences The feedline break transient is analyzed using the RETRAN-02W computer code described in Reference 70. The RETRAN-02W model simulates the reactor coolant system, neutron kinetics, pressurizer, pressurizer relief and safety valves, pressurizer heaters, pressurizer spray, steam generators, feedwater system, and main steam safety valves. The code computes pertinent plant variables including steam generator mass, pressurizer water volume, reactor coolant average temperature, reactor coolant system pressure, and steam generator pressure. The feedline rupture analysis methodology is not intended to minimize the predicted time to pressurizer overfill, as this scenario is evaluated in Section 15.2.15. Pressurizer overfill concerns during feedline rupture were generically dispositioned by Westinghouse (Reference 64) and determined not to require evaluation since operator action is credited to preclude water relief by the PSVs.
Major assumptions are:
(1) The plant is initially operating at 102 percent of the NSSS rating, including a conservatively large RCP heat of 20 MWt for the case with offsite power available and a nominal (minimum guaranteed) RCP heat of 14 MWt for the case without offsite power available. These assumptions maximize the primary side heat that must be removed for each case. (2) Initial reactor coolant average temperature is 5.0°F above the nominal value, and the initial pressurizer pressure is 60 psi above its nominal value. (3) The initial pressurizer level is set to the nominal full power programmed level plus an uncertainty of +5.7 percent span for Diablo Canyon Units 1 and 2, resulting in an initial pressurizer level of 66.4 percent span and 66.8 DCPP UNITS 1 & 2 FSAR UPDATE 15.4-33 Revision 21 September 2013 percent span, respectively. Initial steam generator water level is at 75 percent narrow range span (NRS) in the faulted steam generator, and at 55 percent NRS in the intact steam generators. (4) No credit is taken for the pressurizer power-operated relief valves or pressurizer spray. (5) No credit is taken for the high pressurizer pressure reactor trip. (6) Main feed to all steam generators is assumed to stop at the time the break occurs (all main feedwater spills out through the break). (7) The break discharge quality is calculated by RETRAN-02W as a function of pressure and temperature. (8) Reactor trip is assumed to be initiated when the low-low level trip setpoint in the ruptured steam generator is reached. A low-low level setpoint of 0 percent NRS is assumed. (9) A double-ended break area of 0.5184 ft2 is assumed. A break area of 0.5184 ft2 corresponds to the flow area of the reducer leading to the feedring, and is the largest effective area of flow out of the steam generators for the feedline break event. This minimizes the steam generator fluid inventory available for removal of long-term decay heat and stored energy following reactor trip, and thereby maximizes the resultant heatup of the reactor coolant. (10) No credit is taken for heat energy deposited in RCS metal during the RCS heatup. (11) No credit is taken for charging or letdown. (12) The steam generator heat transfer correlation for the steam generator tubes is automatically adjusted by RETRAN-02W as the shell-side inventory decreases. (13) Conservative core residual heat generation based on the 1979 ANS 5.1 (Reference 32) decay heat standard plus uncertainty was used for calculation of residual decay heat levels. (14) The AFW is assumed to be initiated 10 minutes after the trip with a feed rate of 390 gpm DCPP UNITS 1 & 2 FSAR UPDATE 15.4-34 Revision 21 September 2013 15.4.2.2.4 Results Analyses were performed for both Units 1 and 2 separately; the most limiting case with offsite power and the corresponding case without offsite power are presented.
Results for two feedline break cases are presented. Results for a case in which offsite power is assumed to be available are presented in Section 15.4.2.2.4.1. Results for a case in which offsite power is assumed to be lost following reactor trip are presented in Section 15.4.2.2.4.2. The calculated sequence of events for both cases is listed in Table 15.4-8. 15.4.2.2.4.1 Feedline Rupture with Offsite Power Available The system response following a feedwater line rupture, assuming offsite power is available, is presented in Figures 15.4.2-10 through 15.4.2-13. Results presented in Figures 15.4.2-11 and 15.4.2-13 show that pressures in the RCS and main steam system remain below 110 percent of the design pressures, 2748.5 psia and 1208.5 psia, respectively. Pressurizer pressure decreases after reactor trip on low-low steam generator water level due to the reduction of heat input. Following this initial decrease, pressurizer pressure increases to the pressurizer safety valve setpoint. This increase in pressure is the result of coolant expansion caused by the reduction in heat transfer capability in the steam generators. Figure 15.4.2-11 indicates a pressurizer water volume equivalent to a water-solid condition; however, this is not an acceptance criteria for the analysis. Pressurizer overfill does not require specific evaluation for feedline rupture. At approximately 5900 seconds, decay heat generation decreases to a level such that the total RCS heat generation (decay heat plus pump heat) is less than auxiliary feedwater heat removal capability, and RCS pressure and temperature begin to decrease.
The results show that the core remains covered at all times and that no boiling occurs in the reactor coolant loops. 15.4.2.2.4.2 Feedline Rupture with Offsite Power Unavailable The system response following a feedwater line rupture without offsite power available is similar to the case with offsite power available. However, as a result of the loss of offsite power (assumed to occur at reactor trip), the reactor coolant pumps coast down. This results in a reduction in total RCS heat generation by the amount produced by pump operation.
The reduction in total RCS heat generation produces a milder transient than in the case where offsite power is available. Results presented in Figures 15.4.2-14 through 15.4.2-17 show that pressure in the RCS and main steam system remain below 110 percent of the design pressures, 2748.5 psia and 1208.5 psia, respectively. Pressurizer pressure decreases after reactor trip on low-low steam generator water level due to the reduction of heat input. Following this initial decrease, pressurizer DCPP UNITS 1 & 2 FSAR UPDATE 15.4-35 Revision 21 September 2013 pressure increases to a peak pressure of 2426 psia at 106 seconds. This increase in pressure is the result of coolant expansion caused by the reduction in heat transfer capability in the steam generators. Figure 15.4.2-15 shows that the water volume in the pressurizer increases in response to the heatup, but does not fill the pressurizer. At approximately 2200 seconds, decay heat generation decreases to a level less than the auxiliary feedwater heat removal capability, and RCS temperature begins to decrease. The results show that the core remains covered at all times and that no boiling occurs in the reactor coolant loops. 15.4.2.2.5 Conclusions Results of the analysis show that for the postulated feedline rupture, the assumed AFW system capacity is adequate to remove decay heat, to prevent overpressurizing the RCS, and to prevent uncovering the reactor core. The analysis documents that the acceptance criteria for a postulated feedline rupture are met as follows: 15.4.2.2.5.1 Fuel Damage Any fuel damage calculated to occur is of sufficiently limited extent that the core will remain in place and intact with no loss of core cooling capability. This is conservatively demonstrated by Figures 15.4.2-12 and 15.4.2-16 that show no bulk boiling occurs in the primary coolant system prior to event "turnaround". 15.4.2.2.5.2 Maximum RCS and Main Steam System Pressure As shown in Figures 15.4.2-11 and 15.4.2-13, the maximum pressure in the RCS and main steam system is maintained below 110 percent of the design value, 2748.5 psia and 1208.5 psia, respectively. 15.4.2.2.5.3 Radiological Section 15.5.19 concludes that potential exposures from major feedwater line ruptures will be well below the guideline levels specified in 10 CFR Part 100, and that the occurrence of such ruptures would not result in undue risk to the public. 15.4.2.3 Rupture of a Main Steam Line at Full Power 15.4.2.3.1 Acceptance Criteria The following limiting criteria are applicable for a main steam line rupture at full power: 15.4.2.3.1.1 Fuel Damage Criteria Any fuel damage calculated to occur must be of sufficiently limited extent that the core will remain in place and intact with no loss of core cooling capability. This is conservatively demonstrated by meeting the following criteria: DCPP UNITS 1 & 2 FSAR UPDATE 15.4-36 Revision 21 September 2013 (1) DNB will not occur on the lead rod with at least a 95 percent probability at a 95 percent confidence level. The minimum DNBR must not go below the DNBR Safety Analysis Limit of 1.68/1.71 (see Section 4.4.1.1.2) at any time during the transient. (2) The peak linear heat generation rate will not exceed a 22 kW/ft (Section 4.4.1.2 and Figure 4.4-2) which would cause fuel centerline melt. 15.4.2.3.1.2 Radiological Criteria The resulting potential exposures to individual members of the public and to the general population shall be lower than the applicable guidelines and limits specified in 10 CFR Part 100. 15.4.2.3.2 Identification of Causes and Accident Description A rupture in the main steam system piping from an at-power condition creates an increased steam load, which extracts an increased amount of heat from the reactor coolant system via the steam generators. This results in a reduction in reactor coolant system temperature and pressure. In the presence of a strong negative moderator temperature coefficient, typical of end-of-cycle conditions, the colder core inlet coolant temperature causes the core power to increase from its initial level due to the positive reactivity insertion. The power approaches a level equal to the total steam flow. Depending on the break size, a reactor trip may occur due to overpower conditions or as a result of a steam line break protection function actuation.
The steam system piping failure accident analysis, described in Section 15.4.2.1, is performed assuming a hot zero power initial condition with the control rods inserted in the core, except for the most reactive rod, which remains fully withdrawn out of the core. This condition could occur while the reactor is at hot shutdown at the minimum required shutdown margin, or after the plant has been tripped manually, or by the reactor protection system following a steam line break from an at-power condition. For an at-power break, the FSAR Update Section 15.4.2.1 analysis represents the limiting condition with respect to core protection for the time period following reactor trip. The analysis of a main steam pipe rupture at power is performed to demonstrate that the following criteria are satisfied:
(1) Assuming a stuck RCCA and a single failure in the engineered safety features, there is no damage to the primary system and the core remains in place and intact. (2) Core protection is maintained prior to, and immediately following, a reactor trip, if one is required, such that the DNBR remains above the applicable limit value for any rupture assuming the most reactive assembly stuck in its fully withdrawn position.
DCPP UNITS 1 & 2 FSAR UPDATE 15.4-37 Revision 21 September 2013 Depending on the size of the break, this event is classified as either an ANS Condition III (infrequent fault) or Condition IV (limiting fault) event. The main steam pipe rupture at power is protected by the same reactor protection and ESF functions as the main steam pipe rupture at hot zero power. Although DNB and possible clad perforation following a steam pipe rupture are not necessarily unacceptable, the analysis shows that the calculated DNBR remains above the applicable DNBR limit value. 15.4.2.3.3 Analysis of Effects and Consequences The analysis of the steam line rupture is performed in the following stages:
(1) The RETRAN-02W code (Reference 70) is used to calculate the nuclear power, core heat flux, and RCS temperature and pressure transients resulting from the cooldown following the steam line break. (2) The core radial and axial peaking factors are determined using the thermal-hydraulic conditions from the transient analysis as input to the nuclear core models. The THINC-IV code (see Section 4.4.3) is then used to calculate the DNBR for the limiting time during the transient.
This accident is analyzed with the Improved Thermal Design Procedure as described in Reference 62.
To give conservative results in calculating the DNBR during the transient, the following assumptions are made: (1) Initial Conditions - The initial core power, reactor coolant temperature, and RCS pressure are assumed to be at their nominal full-power values. The full power condition is more limiting than part-power with respect to DNBR. Uncertainties in initial conditions are included in the DNBR limit value, as described in Reference 62. (2) Break size - A spectrum of break sizes is analyzed. Small breaks do not result in a reactor trip; in this case core power stabilizes at an increased level corresponding to the increased steam flow. Intermediate-size breaks may result in a reactor trip on overpower T as a result of the increasing core power. Larger break sizes result in a reactor trip soon after the break from the safety injection signal actuated by low steam line pressure, which includes lead/lag dynamic compensation. (3) Break flow - The steam flow out the pipe break is calculated using the Moody curve for an fL/D value of 0 (Reference 16). DCPP UNITS 1 & 2 FSAR UPDATE 15.4-38 Revision 21 September 2013 (4) Reactivity Coefficients - The analysis assumes maximum EOL moderator reactivity feedback and minimum Doppler-only power reactivity feedback in order to maximize the power increase following the break. (5) Protection System - The analysis only models those reactor protection system features that would be credited for at power conditions and up to the time a reactor trip is initiated. Section 15.4.2.1, presents the analysis of the bounding transient following reactor trip, where engineered safety features are actuated to mitigate the effects of a steam line break. (6) Control Systems - The results of a main steam pipe rupture at power would be made less severe as a result of control system actuation. Therefore, the mitigation effects of control systems have been ignored in the analysis. 15.4.2.3.4 Results A spectrum of steam line break sizes was analyzed for each unit. The results show that for break sizes up to 0.49 ft2 (Unit 1) and 0.50 ft2 (Unit 2) a reactor trip is not generated. In this case, the event is similar to an excessive load increase event as described in Section 15.2.12. The core reaches a new equilibrium condition at a higher power equivalent to the increased steam flow. For break sizes larger than those noted above, a reactor trip is generated within a few seconds of the break on the safety injection signal from low steam line pressure.
The limiting case for demonstrating DNB protection is the 0.49 ft2 (Unit 1) break, the largest break size that does not result in an early trip on low steam pressure SI actuation. The peak linear heat rate (kW/ft) remains below a value corresponding to fuel centerline melting. The time sequence of events for this case is shown in Table 15.4-8. Figures 15.4.2-18 through 15.4.2-21 show the transient response. 15.4.2.3.5 Conclusions The analysis demonstrates the acceptance criteria are met as follows: 15.4.2.3.5.1 Fuel Damage Any fuel damage calculated to occur is of sufficiently limited extent that the core will remain in place and intact with no loss of core cooling capability. This is conservatively demonstrated by the following: (1) The analysis demonstrates that there is a large margin to the DNBR Safety Analysis Limit of 1.71/1.68 (typical cell/thimble cell). (2) The analysis calculates that the maximum linear power meets the fuel centerline melt limit of 22.0 kW/ft. DCPP UNITS 1 & 2 FSAR UPDATE 15.4-39 Revision 21 September 2013 The analysis concludes that the DNB and fuel centerline design bases are met for the limiting case. Although DNB and possible clad perforation following a steam pipe rupture are not necessarily unacceptable and not precluded by the criteria, the above analysis shows that the minimum DNBR remains above the safety analysis limit. 15.4.2.3.5.2 Radiological Section 15.5.18 concludes that potential exposures from main steam line ruptures at full power will be well below the guideline levels specified in 10 CFR Part 100, and that the occurrence of such ruptures would not result in undue risk to the public. 15.4.3 STEAM GENERATOR TUBE RUPTURE (SGTR) 15.4.3.1 Acceptance Criteria The following limiting criteria are applicable for a SGTR: (1) The resulting potential exposures to individual members of the public and to the general population shall be lower than the applicable guidelines and limits specified in Section 15.5.20. (2) There are no regulatory acceptance criteria associated with a SGTR margin-to-overfill transient analysis. However, it will be demonstrated that there is sufficient margin to prevent overfill of the SG during an SGTR event. Overfill of the SG may result in significantly increased offsite dose consequences, along with damage to secondary components such as the turbine and the main steam line. 15.4.3.2 Identification of Causes and Accident Description The accident examined is the complete severance of a single steam generator tube. The accident is assumed to take place at power with the reactor coolant contaminated with fission products corresponding to continuous operation with a limited amount of defective fuel rods. The accident leads to an increase in contamination of the secondary system due to leakage of radioactive coolant from the reactor coolant system (RCS). In the event of a coincident loss of offsite power, or failure of the condenser steam dump system, discharge of activity to the atmosphere takes place via the steam generator power-operated relief valves (and safety valves if their setpoint is reached).
Although the steam generator tube material is thermally treated Inconel 690, a highly ductile material, it is assumed that complete severance could occur. The more probable mode of tube failure would be one or more minor leaks of undetermined origin. Activity in the steam and power conversion system is subject to continual surveillance and an accumulation of minor leaks that exceeds the limits established in the Technical Specifications (Reference 30) is not permitted during the unit operation.
DCPP UNITS 1 & 2 FSAR UPDATE 15.4-40 Revision 21 September 2013 The operator is expected to determine that a steam generator tube rupture has occurred, to identify and isolate the ruptured steam generator, and to complete the required recovery actions to stabilize the plant and terminate the primary to secondary break flow. These actions should be performed on a restricted time scale in order to minimize contamination of the secondary system and ensure termination of radioactive release to the atmosphere from the ruptured unit. Consideration of the indications provided at the control board, together with the magnitude of the break flow, leads to the conclusion that the recovery procedure can be carried out on a time scale that ensures that break flow to the secondary system is terminated before water level in the affected steam generator rises into the main steam pipe. Sufficient indications and controls are provided to enable the operator to carry out these functions satisfactorily.
Assuming normal operation of the various plant control systems, the following sequence of events is initiated by a tube rupture:
(1) Pressurizer low pressure and low-level alarms are actuated and charging pump flow increases in an attempt to maintain pressurizer level. On the secondary side there is a steam flow/feedwater flow mismatch before trip as feedwater flow to the affected steam generator is reduced due to the break flow that is now being supplied to that unit. (2) The main steam line radiation monitors, the air ejector radiation monitor and/or the steam generator blowdown radiation monitor will alarm, indicating a sharp increase in radioactivity in the secondary system, and steam generator blowdown will be automatically terminated. (3) Continued loss of reactor coolant inventory leads to a reactor trip signal generated by low pressurizer pressure or overtemperature T. An SI signal, initiated by low pressurizer pressure, follows soon after the reactor trip. The SI signal automatically terminates normal feedwater supply and initiates AFW addition. (4) The reactor trip automatically trips the turbine and, if offsite power is available, the steam dump valves open permitting steam dump to the condenser. In the event of a coincident loss of offsite power, the steam dump valves would automatically close to protect the condenser. The steam generator pressure would rapidly increase resulting in steam discharge to the atmosphere through the steam generator power-operated relief valves (PORVs) and safety valves if their setpoint is reached. (5) Following reactor trip and SI actuation, the continued action of AFW supply and borated SI flow (supplied from the refueling water storage tank) provides a heat sink that absorbs some of the decay heat. This reduces the amount of steam bypass to the condenser, or in the case of loss of offsite power, steam relief to the atmosphere.
DCPP UNITS 1 & 2 FSAR UPDATE 15.4-41 Revision 21 September 2013 (6) SI flow results in stabilization of the RCS pressure and pressurizer water level, and the RCS pressure trends toward the equilibrium value where the SI flow rate equals the break flow rate. In the event of an SGTR, the plant operators must diagnose the SGTR and perform the required recovery actions to stabilize the plant and terminate the primary to secondary leakage. The operator actions for SGTR recovery are provided in the Emergency Operating Procedures (Reference 42). The major operator actions include identification and isolation of the ruptured steam generator, cooldown and depressurization of the RCS to restore inventory, and termination of SI to stop primary to secondary leakage. These operator actions are described below:
(1) Identify the ruptured steam generator. High secondary side activity, as indicated by the main steam line radiation monitors, the air ejector radiation monitor, or steam generator blowdown radiation monitor typically will provide the first indication of an SGTR event. The ruptured steam generator can be identified by an unexpected increase in steam generator level, or a high radiation indication on the corresponding main steam line monitor, or from a radiation survey of the main steam lines. For an SGTR that results in a reactor trip at high power, the steam generator water level may decrease off-scale on the narrow range for all of the steam generators. The AFW flow will begin to refill the steam generators, distributing approximately equal flow to each of the steam generators. Since primary to secondary leakage adds additional liquid inventory to the ruptured steam generator, the water level will return to the narrow range earlier in that steam generator and will continue to increase more rapidly. This response, as indicated by the steam generator water level instrumentation, provides confirmation of an SGTR event and also identifies the ruptured steam generator. (2) Isolate the ruptured steam generator from the intact steam generators and isolate feedwater to the ruptured steam generator. Once a tube rupture has been identified, recovery actions begin by isolating steam flow from and stopping feedwater flow to the ruptured steam generator. In addition to minimizing radiological releases, this also reduces the possibility of overfilling the ruptured steam generator with water by (a) minimizing the accumulation of feedwater flow and (b) enabling the operator to establish a pressure differential between the ruptured and intact steam generators as a necessary step toward terminating primary to secondary leakage.
DCPP UNITS 1 & 2 FSAR UPDATE 15.4-42 Revision 21 September 2013 (3) Cool down the RCS using the intact steam generators. After isolation of the ruptured steam generator, the RCS is cooled as rapidly as possible to less than the saturation temperature corresponding to the ruptured steam generator pressure by dumping steam from only the intact steam generators. This ensures adequate subcooling in the RCS after depressurization to the ruptured steam generator pressure in subsequent actions. If offsite power is available, the normal steam dump system to the condenser can be used to perform this cooldown. However, if offsite power is lost, the RCS is cooled using the PORVs on the intact steam generators. (4) Depressurize the RCS to restore reactor coolant inventory. When the cooldown is completed, SI flow will increase RCS pressure until break flow matches SI flow. Consequently, SI flow must be terminated to stop primary to secondary leakage. However, adequate reactor coolant inventory must first be assured. This includes both sufficient reactor coolant subcooling and pressurizer inventory to maintain a reliable pressurizer level indication after SI flow is stopped. Since leakage from the primary side will continue after SI flow is stopped until the RCS and ruptured steam generator pressures equalize, an "excess" amount of inventory is needed to ensure pressurizer level remains on span. The "excess" amount required depends on RCS pressure and reduces to zero when RCS pressure equals the pressure in the ruptured steam generator. The RCS depressurization is performed using normal pressurizer spray if the reactor coolant pumps (RCPs) are running. However, if offsite power is lost or the RCPs are not running for some other reason, normal pressurizer spray is not available. In this event, RCS depressurization can be performed using a pressurizer PORV or auxiliary pressurizer spray. (5) Terminate SI to stop primary to secondary leakage. The previous actions will have established adequate RCS subcooling, a secondary side heat sink, and sufficient reactor coolant inventory to ensure that SI flow is no longer needed. When these actions have been completed, SI flow must be stopped to terminate primary to secondary leakage. Primary to secondary leakage will continue after SI flow is stopped until the RCS and ruptured steam generator pressures equalize. Charging flow, letdown, and pressurizer heaters will then be controlled to prevent repressurization of the RCS and reinitiation of leakage into the ruptured steam generator. Following SI termination, the plant conditions will be stabilized, the primary to secondary break flow will be terminated and all immediate safety concerns will have been DCPP UNITS 1 & 2 FSAR UPDATE 15.4-43 Revision 21 September 2013 addressed. At this time a series of operator actions are performed to prepare the plant for cooldown to cold shutdown conditions. Subsequently, actions are performed to cooldown and depressurize the RCS to cold shutdown conditions and to depressurize the ruptured steam generator. 15.4.3.3 Analysis of Effects and Consequences 15.4.3.3.1 SGTR Margin to Overfill (MTO) Analysis An SGTR results in the leakage of contaminated reactor coolant into the secondary system and subsequent release of a portion of the activity to the atmosphere. Therefore, an analysis must be performed to assure that the radiological consequences resulting from an SGTR are within allowable guidelines. Another concern for SGTR consequences is the possibility of steam generator overfill because this could potentially result in a significant increase in the radiological consequences. Overfill could result in water entering the main steam line. If water continues to leak into the main steam lines, the release of liquid through the steam generator safety valves could result in an increase in radiological doses. Therefore, an analysis was performed to demonstrate margin to steam generator overfill, assuming the limiting single failure relative to overfill. The results of this analysis demonstrate that there is margin to steam generator overfill for DCPP.
The overfill analysis is presented in Reference 72 and the major assumptions include: (1) Complete severance of a single tube located at the top of the tube sheet on the outlet side of the steam generator, resulting in double ended flow (2) Initiation of the event from full power (3) A loss of offsite power coincident with reactor trip (4) Failure of an AFW control valve to close (limiting single failure) (5) The PORVs on all three intact steam generators are fully opened during the RCS cooldown (6) Operator actions are consistent with the times shown in Table 15.4-12 The SGTR MTO analysis acceptance criterion is to maintain a positive margin to overfill when the event is terminated. The limiting margin to overfill analysis presented in Reference 72 demonstrates that the steam generator liquid volume is 30 cubic feet less than the total steam generator volume of 5800 cubic feet when the SGTR event is terminated. The SGTR MTO analysis sequence of events is listed in Table 15.4-13A and the transient responses are presented in Figures 15.4.3-1A to 15.4.3-4A and Figures 15.4.3-6A to 15.4.3-8A. DCPP UNITS 1 & 2 FSAR UPDATE 15.4-44 Revision 21 September 2013 An analysis was also performed to determine the transient thermal hydraulic data for input into the radiological consequences analysis, assuming the limiting single failure relative to doses without steam generator overfill (as opposed to one that is relative to overfill). Because steam generator overfill does not occur, the radiation consequences (see Section 15.5.20) calculated using the results of this analysis represent the limiting consequences for an SGTR for DCPP. The thermal hydraulic results used by the radiological consequences (Dose) analysis are discussed below. 15.4.3.3.2 SGTR Dose Input Analysis A thermal and hydraulic analysis was performed to determine the plant response for a design basis SGTR, and to determine the integrated primary to secondary break flow and the mass releases from the ruptured and intact steam generators to the condenser and to the atmosphere. This information was then used to calculate the quantity of radioactivity released to the environment and the resulting radiological consequences. The thermal and hydraulic analysis discussed in this section is presented in Reference 41 and the results of the environmental consequences analysis are discussed in Section 15.5.20. The plant response following an SGTR was analyzed with the RETRAN-02W program until the primary to secondary break flow is terminated. The reactor protection system and the automatic actuation of the engineered safeguards systems were modeled in the analysis. The major operator actions which are required to terminate the break flow for an SGTR were also simulated in the analysis. Analysis Assumptions The accident modeled is a double-ended break of one steam generator tube located at the top of the tube sheet on the outlet (cold leg) side of the steam generator. However, as indicated subsequently, the break flow flashing fraction was conservatively calculated assuming that all of the break flow comes from the hot leg side of the steam generator. The combination of these conservative assumptions regarding the break flow location results in a very conservative calculation of the radiation doses. It was assumed that the reactor is operating at full power at the time of the accident and the secondary mass was assumed to correspond to operation at the steam generator nominal level with an allowance for uncertainties. It was also assumed that a loss of offsite power occurs at the time of reactor trip and the highest worth control assembly was assumed to be stuck in its fully withdrawn position at reactor trip.
The limiting single failure was assumed to be the failure of the PORV on the ruptured steam generator. Failure of this PORV in the open position will cause an uncontrolled depressurization of the ruptured steam generator which will increase primary to secondary leakage and the mass release to the atmosphere. It was assumed that the ruptured steam generator PORV fails open when the ruptured steam generator is isolated, and that the PORV was isolated by locally closing the associated block valve.
DCPP UNITS 1 & 2 FSAR UPDATE 15.4-45 Revision 21 September 2013 The major operator actions required for the recovery from an SGTR are discussed in Section 15.4.3.2 and these operator actions were simulated in the analysis. The operator action times which were used for the analysis are presented in Table 15.4-12. It is noted that the PORV on the ruptured steam generator was assumed to fail open at the time the ruptured steam generator was isolated. It was assumed that the operators isolate the failed open PORV by locally closing the associated block valve to complete the isolation of the ruptured steam generator before proceeding with the subsequent recovery operations. It was assumed that the ruptured steam generator PORV was isolated at 30 minutes after the valve was assumed to fail open. After the ruptured steam generator PORV was isolated, an additional delay time of 5 minutes (Table 15.4-12) was assumed for the operator action time to initiate the RCS cooldown. Transient Description The RETRAN-02W (Reference 70) analysis results are described below. The sequence of events for this transient is presented in Table 15.4-13B.
Following the tube rupture, reactor coolant flows from the primary into the secondary side of the ruptured steam generator since the primary pressure is greater than the steam generator pressure. In response to this loss of reactor coolant, pressurizer level decreases as shown in Figure 15.4.3-1B. The pressurizer pressure also decreases as shown in Figure 15.4.3-2B as the steam bubble in the pressurizer expands. As the RCS pressure decreases due to the continued primary to secondary leakage, automatic reactor trip occurs on an overtemperature T trip signal. After reactor trip, core power rapidly decreases to decay heat levels. The turbine stop valves close and steam flow to the turbine is terminated. The steam dump system is designed to actuate following reactor trip to limit the increase in secondary pressure, but the steam dump valves remain closed due to the loss of condenser vacuum resulting from the assumed loss of offsite power at the time of reactor trip. Thus, the energy transfer from the primary system causes the secondary side pressure to increase rapidly after reactor trip until the steam generator PORVs (and safety valves if their setpoints are reached) lift to dissipate the energy, as shown in Figure 15.4.3-3B. The main feedwater flow will be terminated and AFW flow will be automatically initiated following reactor trip and the loss of offsite power.
The RCS pressure decreases more rapidly after reactor trip as energy transfer to the secondary shrinks the reactor coolant and the tube rupture break flow continues to deplete primary inventory. Pressurizer level also decreases more rapidly following reactor trip. The decrease in RCS inventory results in a low pressurizer pressure SI signal. After SI actuation, the SI flow rate maintains the reactor coolant inventory and the pressurizer level begins to stabilize. The RCS pressure also trends toward the equilibrium value where the SI flow rate equals the break flow rate.
Because offsite power was assumed lost at reactor trip, the RCPs trip and a gradual transition to natural circulation flow occurs. Immediately following reactor trip the DCPP UNITS 1 & 2 FSAR UPDATE 15.4-46 Revision 21 September 2013 temperature differential across the core decreases as core power decays (see Figures 15.4.3-4B and 15.4.3-5B), however, the temperature differential subsequently increases as natural circulation flow develops. The cold leg temperatures trend toward the steam generator temperature as the fluid residence time in the tube region increases. The intact steam generator loop temperatures slowly decrease due to the continued AFW flow until operator actions are taken to control the AFW flow to maintain the specified level in the intact steam generators. The ruptured steam generator loop temperatures also continue to slowly decrease until the ruptured steam generator is isolated, at which time the PORV is assumed to fail open. Major Operator Actions (1) Identify and Isolate the Ruptured Steam Generator As indicated in Table 15.4-12, it was assumed that the ruptured steam generator is identified and isolated at 10 minutes after the initiation of the SGTR or when the narrow range level reaches 38 percent, whichever time is longer. Since the time to reach 38 percent narrow range level was 953 seconds, it was assumed that the actions to isolate the ruptured steam generator are performed at this time. The ruptured steam generator PORV was also assumed to fail open at this time, and the failure was simulated at 953 seconds. The failure causes the ruptured steam generator to rapidly depressurize, which results in an increase in primary to secondary leakage. The depressurization of the ruptured steam generator increases the break flow and energy transfer from primary to secondary which results in a decrease in the ruptured loop temperatures as shown in Figure 15.4.3-5B. As noted previously, the intact steam generator loop temperatures also decrease, as shown in Figure 15.4.3-4B, until the AFW flow to the intact steam generators is throttled. These effects result in a decrease in the RCS pressure and pressurizer level, until the failed open PORV is isolated. It was assumed that the time required for the operator to identify that the ruptured steam generator PORV is open and to locally close the associated block valve is 30 minutes. Thus, the isolation of the ruptured steam generator was completed at 2753 seconds, and the depressurization of the ruptured steam generator was terminated. At this time, the ruptured steam generator pressure increases rapidly and the primary to secondary break flow begins to decrease. (2) Cool Down the RCS to establish Subcooling Margin After the ruptured steam generator PORV block valve was closed, a 5 minute operator action time was imposed prior to initiation of cooldown. The depressurization of the ruptured steam generator affects the RCS DCPP UNITS 1 & 2 FSAR UPDATE 15.4-47 Revision 21 September 2013 cooldown target temperature because the temperature is dependent upon the pressure in the ruptured steam generator. Since offsite power was lost, the RCS was cooled by dumping steam to the atmosphere using the intact steam generator PORVs. The cooldown was continued until RCS was subcooled 36°F including an allowance for instrument uncertainty. Because the pressure in the ruptured steam generator continued to decrease during the cooldown, the associated temperature the RCS was less than the initial target temperature, which had the net effect of extending the time for cooldown. The cooldown was initiated at 3053 seconds and was completed at 4424 seconds. The reduction in the intact steam generator pressures required to accomplish the cooldown is shown in Figure 15.4.3-3B, and the effect of the cooldown on the RCS temperature is shown in Figure 15.4.3-4B. The pressurizer level and pressurizer pressure also decrease during this cooldown process due to shrinkage of the reactor coolant, as shown in Figures 15.4.3-1B and 15.4.3-2B, respectively.
(3) Depressurize to Restore Inventory After the RCS cooldown, a 4 minute operator action time was included prior to depressurization. The RCS depressurization was initiated at 4664 seconds to assure adequate coolant inventory prior to terminating SI flow. With the RCPs stopped, normal pressurizer spray is not available and thus the RCS was depressurized by opening a pressurizer PORV.
The depressurization was continued until any of the following conditions are satisfied: RCS pressure is less than the ruptured steam generator pressure and pressurizer level is greater than the allowance of 12 percent for pressurizer level uncertainty, or pressurizer level is greater than 74 percent, or RCS subcooling is less than the 20°F allowance for subcooling uncertainty. The RCS depressurization reduces the break flow as shown in Figure 15.4.3-6B, and increases SI flow to refill the pressurizer as shown in Figure 15.4.3-1B. (4) Terminate SI to Stop Primary to Secondary Leakage The previous actions have established adequate RCS subcooling, verified a secondary side heat sink, and restored the reactor coolant inventory to ensure that SI flow is no longer needed. When these actions have been completed, the SI flow must be stopped to prevent repressurization of the RCS and to terminate primary to secondary leakage. The SI flow is terminated after a delay to allow for operator response if RCS subcooling is greater than the 20°F allowance for uncertainty, minimum AFW flow is available or at least one intact steam generator level is in the narrow range, the RCS pressure is stable or increasing, and the pressurizer level is greater than the 12 percent allowance for uncertainty. DCPP UNITS 1 & 2 FSAR UPDATE 15.4-48 Revision 21 September 2013 After depressurization was completed, an operator action time of 2 minutes was assumed prior to SI termination. Since the above requirements are satisfied, SI termination was performed at this time. After SI termination, the pressurizer pressure decreases as shown in Figure 15.4.3-2B. Figure 15.4.3-6B shows that the primary to secondary leakage continues after the SI flow was stopped until the RCS and ruptured steam generator pressures equalize.
The ruptured steam generator water volume for the radiological consequences analysis is shown in Figure 15.4.3-7B. The mass of water in the ruptured steam generator is also shown as a function of time in Figure 15.4.3-8B. Mass Releases The mass releases were determined for use in evaluating the exclusion area boundary and low population zone radiation exposure. The steam releases from the ruptured and intact steam generators, the feedwater flows to the ruptured and intact steam generators, and primary to secondary break flow into the ruptured steam generator were determined for the period from accident initiation until 2 hours after the accident and from 2 to 8 hours after the accident. The releases for 0-2 hours were used to calculate the radiation doses at the exclusion area boundary for a 2 hour exposure, and the releases for 0-8 hours were used to calculate the radiation doses at the low population zone for the duration of the accident.
The operator actions for the SGTR recovery up to the termination of primary to secondary leakage were simulated in the RETRAN-02W analysis. Thus, the steam releases from the ruptured and intact steam generators, the feedwater flows to the ruptured and intact steam generators, and the primary to secondary leakage into the ruptured steam generator were determined from the RETRAN-02W results for the period from the initiation of the accident until the leakage was terminated. Following the termination of leakage, it was assumed that the actions are taken to cool down the plant to cold shutdown conditions. The PORVs for the intact steam generators were assumed to be used to cool down the RCS to the RHR system operating temperature of 350°F, at the maximum allowable cooldown rate of 100°F/hr. The steam releases and the feedwater flows for the intact steam generator for the period from leakage termination until 2 hours were determined from a mass and energy balance using the calculated RCS and intact steam generator conditions at the time of leakage termination and at 2 hours. The RCS cooldown was assumed to be continued after 2 hours until the RHR system in-service temperature of 350°F is reached. Depressurization of the ruptured steam generator was then assumed to be performed to the RHR in-service pressure of 405 psia via steam release from the ruptured steam generator PORV. The RCS pressure was also assumed to be reduced concurrently as the ruptured steam generator is depressurized. It was assumed that the continuation of the RCS cooldown and depressurization to RHR operating conditions are completed within 8 hours after the accident since there is ample time to complete the operations during this time period. The steam releases and feedwater flows from 2 to 8 hours were DCPP UNITS 1 & 2 FSAR UPDATE 15.4-49 Revision 21 September 2013 determined for the intact steam generators from a mass and energy balance using conditions at 2 hours and at the RHR system in-service conditions. The steam released from the ruptured steam generator from 2 to 8 hours was determined based on a mass and energy balance for the ruptured steam generator using the conditions at the time of leakage termination and saturated conditions at the RHR in-service pressure.
After 8 hours, it was assumed that further plant cooldown to cold shut down as well as long-term cooling is provided by the RHR system. Therefore, the steam releases to the atmosphere are terminated after RHR in-service conditions are assumed to be reached at 8 hours.
During the time period from initiation of the accident until leakage termination, the releases were determined from the RETRAN-02W results for the time prior to reactor trip and following reactor trip. Since the condenser is in service until reactor trip, any radioactivity released to the atmosphere prior to reactor trip would be through the condenser air ejector. After reactor trip, the releases to the atmosphere were assumed to be via the steam generator PORVs. The mass release rates to the atmosphere from the RETRAN-02W analysis are presented in Figures 15.4.3-9 and 15.4.3-10 for the ruptured and intact steam generators, respectively, for the time period until leakage termination. The total flashed break flow from the RETRAN-02W analysis is presented in Figure 15.4.3-11. The mass releases calculated from the time of leakage termination until 2 hours and from 2-8 hours were also assumed to be released to the atmosphere via the steam generator PORVs. The mass releases for the SGTR event for the 0-2 hour and 2-8 hour time intervals are presented in Table 15.4-14. 15.4.3.4 Conclusions The analysis demonstrates the acceptance criteria are met as follows: 15.4.3.4.1 Overfill Analysis The SGTR MTO analysis acceptance criteria are to maintain a positive margin to overfill when the event is terminated. Therefore, the limiting margin to overfill analysis demonstrates that the steam generator liquid volume is less than the total steam generator volume of 5800 cubic feet when the SGTR event is terminated. 15.4.3.4.2 Radiological Section 15.5.20 demonstrates that the acceptance criteria for Dose Consequences of a SGTR are met. Table 15.5-71 provides offsite radiation doses from SGTR accident. Table 15.5-74 provides control room radiation doses from airborne activity in SGTR accident. DCPP UNITS 1 & 2 FSAR UPDATE 15.4-50 Revision 21 September 2013 15.4.4 SINGLE REACTOR COOLANT PUMP LOCKED ROTOR 15.4.4.1 Identification of Causes and Accident Description The accident postulated is an instantaneous seizure of an RCP rotor.
Following initiation of the reactor trip, heat stored in the fuel rods continues to be transferred to the coolant causing the coolant to expand. At the same time, heat transfer to the shell-side of the steam generators is reduced, first because the reduced flow results in a decreased tube-side film coefficient and then because the reactor coolant in the tubes cools down while the shell-side temperature increases (turbine steam flow is reduced to zero upon plant trip). The rapid expansion of the coolant in the reactor core, combined with reduced heat transfer in the steam generators causes an insurge into the pressurizer and a pressure increase throughout the RCS. The insurge into the pressurizer compresses the steam volume, actuates the automatic spray system, opens the power-operated relief valves, and opens the pressurizer safety valves in that sequence. The three power-operated relief valves are designed for reliable operation and would be expected to function properly during the accident. However, for conservatism, their pressure-reducing effect as well as the pressure-reducing effect of the spray is not included in the analysis. 15.4.4.2 Analysis of Effects and Consequences Three digital computer codes are used to analyze this transient. The LOFTRAN (Reference 26) code is used to calculate the resulting loop and core coolant flow following the pump seizure. The LOFTRAN code is also used to calculate the time of reactor trip based on the calculated flow, the nuclear power following reactor trip, and to determine the peak pressure. The thermal behavior of the fuel located at the core hot spot is investigated using the FACTRAN (Reference 17) code, using the core flow and the nuclear power calculated by LOFTRAN. The FACTRAN code includes the use of a film boiling heat transfer coefficient. The THINC (Reference 31) code is used to calculate the DNBR during the transient based on flow calculated by LOFTRAN and heat flux calculated by FACTRAN.
The following case is analyzed:
(1) All loops operating, one locked rotor At the beginning of the postulated locked rotor accident, i.e., at the time the shaft in one of the RCPs is assumed to seize, the plant is assumed to be operating under steady state operating conditions with respect to the margin to DNB, i.e., normal steady state power level, nominal steady state pressure, and nominal steady state coolant average temperature (+ 2.5°F for SG fouling). When the peak pressure is evaluated, the initial pressure is conservatively estimated as 38 psi above nominal pressure (2250 psia) to allow for errors in the pressurizer pressure measurement and control DCPP UNITS 1 & 2 FSAR UPDATE 15.4-51 Revision 21 September 2013 channels. This is done to obtain the highest possible rise in the coolant pressure during the transient. To obtain the maximum pressure in the primary side, conservatively high loop pressure drops are added to the calculated pressurizer pressure. The pressure response is shown in Figure 15.4.4-1. 15.4.4.2.1 Evaluation of the Pressure Transient After pump seizure and reactor trip, the neutron flux is rapidly reduced by the effect of control rod insertion. Rod motion is assumed to begin 1 second after the flow in the affected loop reaches 87 percent of nominal flow (see Note d on Table 15.1-2). No credit is taken for the pressure-reducing effect of the pressurizer relief valves, pressurizer spray, steam dump, or controlled feedwater flow after plant trip.
Although these operations are expected to occur and would result in a lower peak pressure, an additional degree of conservatism is provided by ignoring their effect. The pressurizer safety valves are assumed to initially open at 2500 psia and achieve rated flow at 2575 psia (3 percent accumulation). 15.4.4.2.2 Evaluation of the Effects of DNB in the Core During the Accident For this accident, DNB is assumed to occur in the core and, therefore, an evaluation of the consequences with respect to fuel rod thermal transients is performed. Results obtained from analysis of this hot spot condition represent the upper limit with respect to cladding temperature and zirconium-water reaction.
In the evaluation, the rod power at the hot spot is conservatively assumed to be greater than or equal to two and a half times the average rod power (i.e., FQ 2.5) at the initial core power level. 15.4.4.2.3 Film Boiling Coefficient The film boiling coefficient is calculated in the FACTRAN code using the Bishop-Sandberg-Tong film boiling correlation. The fluid properties are evaluated at film temperature (average between wall and bulk temperatures). The program calculates the film coefficient at every time step based on the actual heat transfer conditions at the time. The neutron flux, system pressure, bulk density, and mass flowrate as a function of time are used as program input.
For this analysis, the initial values of the pressure and the bulk density are used throughout the transient since they are the most conservative with respect to cladding temperature response. For conservatism, DNB was assumed to start at the beginning of the accident.
DCPP UNITS 1 & 2 FSAR UPDATE 15.4-52 Revision 21 September 2013 15.4.4.2.4 Fuel Cladding Gap Coefficient The magnitude and time dependence of the heat transfer coefficient between fuel and cladding (gap coefficient) has a pronounced influence on the thermal results. The larger the value of the gap coefficient, the more heat is transferred between pellet and cladding. Based on investigations on the effect of the gap coefficient upon the maximum cladding temperature during the transient, the gap coefficient was assumed to increase from a steady state value consistent with the initial fuel temperature to 10,000 Btu/hr-ft2-°F in 0.5 seconds after the initiation of the transient. This assumption causes energy stored in the fuel to be released to the cladding at the initiation of the transient and maximizes the cladding temperature during the transient. 15.4.4.2.5 Zirconium-steam Reaction The zirconium-steam reaction can become significant above 1800°F (cladding temperature). The Baker-Just parabolic rate equation shown below is used to define the rate of the zirconium-steam reaction. x=1.986T45,500exp61033.3dt)2(w d (15.4-1) where: w = amount reacted, mg/cm2 t = time, sec T = temperature, °K and the reaction heat is 1510 cal/gm. 15.4.4.3 Results Transient values of pressurizer pressure, flow coastdown, hot channel heat flux, and neutron flux are shown in Figure 15.4.4-1 and Figures 15.4.4-3 through 15.4.4-5. Maximum RCS pressure, maximum cladding temperature, and amount of zirconium-water reaction are contained in Table 15.4-10. Figure 15.4.4-2 shows the cladding temperature transient for the worst case. 15.4.4.4 Conclusions (1) Because the peak RCS pressure reached during any of the transients is less than that which would cause stresses to exceed the faulted condition stress limits, the integrity of the primary coolant system is not endangered. (2) Because the peak cladding surface temperature calculated for the hot spot during the worst transient remains considerably less than 2700°F and the amount of zirconium-water reaction is small, the core will remain in place and intact with no consequential loss of core cooling capability. DCPP UNITS 1 & 2 FSAR UPDATE 15.4-53 Revision 21 September 2013 (3) The results of the transient analysis show that for four-loop operation, less than 10 percent of the fuel rods will have DNBRs below the safety analysis limit values. 15.4.5 FUEL HANDLING ACCIDENT 15.4.5.1 Acceptance Criteria The following limiting criterion is applicable for a fuel handling accident: (1) The resulting potential exposures to individual members of the public and to the general population shall be lower than the applicable guidelines and limits specified in 10 CFR Part 100. 15.4.5.2 Identification of Causes and Accident Description 15.4.5.2.1 Fuel Handling Procedures One major task that must be performed routinely as part of the operation of a nuclear power plant is the handling of the reactor fuel. The bulk of this fuel handling occurs during refueling outages, which occur every one to two years, and all of these operations are carried out with the fuel under water. A typical refueling outage would include the following major operations:
(1) Shutdown of the reactor and cooldown to ambient conditions (2) Removal and storage of pressure vessel head (3) Filling of refueling cavity above the pressure vessel with water to provide shielding from radioactive fuel (4) Transfer of the reactor fuel assemblies from the reactor itself to underwater storage racks in the spent fuel pool (5) Performance of outage tasks appropriate to the "core off-load" window (6) Return of the appropriate number of partially burned and new fuel assemblies to the reactor Fuel handling operations within the containment building and the fuel handling area are accomplished with overhead cranes, specially designed fuel grapples, and miscellaneous other equipment. To facilitate the transfer of the fuel between the two buildings, an underwater penetration called the transfer tube is provided through the walls where the buildings adjoin. A conveyer cart is used to transport the fuel from one building to the other through this penetration. A more detailed description of the equipment used in fuel handling operations can be found in Chapter 9.
DCPP UNITS 1 & 2 FSAR UPDATE 15.4-54 Revision 21 September 2013 Spent fuel remains in storage in the spent fuel pool until placed in a cask for transport to the Diablo Canyon Independent Spent Fuel Storage Installation (ISFSI) or for shipment from the site. 15.4.5.2.2 Probability of Activity Release In the above operations, there exists the remote possibility that one or more fuel assemblies will sustain some mechanical damage. There exists an even more remote possibility that this damage will be severe enough to breach the cladding and release some of the radioactive fission products contained therein.
Both the fuel handling procedure and the fuel handling equipment design adhere to the following safety criteria:
(1) Fuel handling operations must not commence before short-lived core activity has decayed, leaving only relatively long-lived activity. Equipment Control Guidelines for refueling operations specify the minimum waiting time. (2) Fuel handling operations must preclude any critical configuration of the core, spent fuel, or new fuel. (3) The fuel handling system design must ensure an adequate water depth for radiation shielding of operating personnel. (4) Active components of the fuel handling systems must be designed such that loss-of-function failures will terminate in stable modes. (5) The design of fuel handling equipment must minimize the possibility of accidental impact of a moving fuel assembly with any structure. (6) The design of fuel handling equipment and procedures must minimize the possibility of any massive object damaging a stationary fuel assembly. (7) Fuel assembly design must minimize the possibility of damage in the event that portable or hand tools come into contact with a fuel assembly. (8) The design of structures around the fuel handling system must minimize the possibility of the structures themselves failing in the event of a double design earthquake (DDE), which is the safe shutdown earthquake.
Furthermore, the structures must minimize the possibility of any external missile from reaching fuel assemblies. (9) Fuel handling equipment must be capable of supporting maximum loads under seismic conditions. Furthermore, fuel handling equipment must not generate missiles during seismic conditions. The earthquake loading of DCPP UNITS 1 & 2 FSAR UPDATE 15.4-55 Revision 21 September 2013 the fuel handling equipment is evaluated in accordance with the seismic considerations addressed in Section 9.1.4.3.2. Implementation of the above safety criteria into the fuel handling system design is discussed in greater detail in Chapter 9.
Because of the above design, the probability of breaching the fuel cladding and releasing radioactive fission products is very small. 15.4.5.2.3 Accident Description In order to assess the probable extent of fuel cladding damage from a fuel handling accident, it is necessary to look more closely at specific fuel handling accidents that might realistically occur.
Multiple assemblies are loaded into the multi-purpose canister (MPC)/transfer cask assembly for movement to the ISFSI, as described in Section 9.1.4.6. The MPC is subsequently drained, evacuated, backfilled with helium, and sealed. However, extensive design and analysis along with application of the ISFSI Technical Specifications ensure temperatures remain within the design basis and no fuel cladding damage occurs.
The possibility of damaging fuel cladding by overheating during fuel handling operations was considered. Because irradiated fuel is always handled under water, overheating would require draining either the refueling cavity or the spent fuel pool while irradiated fuel was located within them. Consideration has been given in design of the cavity and pool to prevent either of these possibilities. The probability of losing coolant while an assembly is in the transfer tube is also extremely small in view of the fact that the tube is open on one end to the reactor cavity and on the other end to the pool. There is no realistic occurrence that would simultaneously block off both ends of the tube. Therefore, it is expected that there will be no radiological consequences over the lifetime of the plant that results from overheating during fuel handling operations.
The possibility of dropping a foreign object of sufficient size to produce cladding rupture onto irradiated fuel located either in the reactor or the pool is extremely remote because the design of the plant is such that only rarely are objects of this size transported over locations containing irradiated fuel. The three large objects that are routinely handled in the vicinity of irradiated fuel are the reactor head, upper internals package, which must be removed and reinstalled from the pressure vessel at each refueling outage, and the spent fuel shipment cask, which must be placed in the pool for loading. As discussed in Section 9.1.4.3.5, load drop analyses were performed for the reactor head and upper internals and are summarized in the PG&E NUREG-0612 submittal. It is not necessary to lift the cask over the fuel racks in moving it to or from the pool. Protection of nuclear fuel assemblies from overhead load handling is a key element of the Control of Heavy Loads Program described in Section 9.1.4.3.5.
DCPP UNITS 1 & 2 FSAR UPDATE 15.4-56 Revision 21 September 2013 The possibility has also been considered of one of the bridge cranes falling into the reactor or the pool as a result of an earthquake. However, both of these cranes are seismically qualified to Hosgri response spectra. Therefore, it is expected that there will be no radiological consequences over the lifetime of the plant that result from dropping objects onto radiated fuel.
If a fuel assembly were to strike an object, it is possible that the object might damage the fuel rods with which it comes into contact. If a fuel assembly were to strike against a flat, plane-like object or a linear, edge-like object, impact loads would be distributed across several fuel rods, and no cladding damage would be expected. If a fuel assembly were to strike against a sharp, corner-like object, impact loads would be concentrated, and cladding damage might occur. Thus, there is a very remote possibility that impact loads would be severe enough to rupture fuel cladding.
Analyses have been made by Westinghouse of the effects that would result from dropping a fuel assembly from an initial vertical orientation onto a flat surface, the core, or a loaded fuel rack. Westinghouse has also analyzed the case where an assembly in the holder on the conveyor car falls from the vertical to the horizontal position. The results of these analyses indicate there is only a very remote possibility of fuel cladding rupture.
The above discussion indicates that the unlikely event of a fuel cladding integrity failure would most likely result from a fuel assembly striking a sharp object or dropping a fuel assembly. 15.4.5.3 Results 15.4.5.3.1 Containment Building Accident During fuel handling operations, the containment ventilation penetrations to the outside atmosphere are maintained in a closed or automatically isolable condition. Isolation is automatically actuated if either of the Containment Purge Exhaust (CPE) monitors, RM-44A or RM-44B, alarms due to a concentration of radioactivity in the containment purge exhaust duct that exceeds the alarm setpoint. However, these penetrations are also allowed to be open under administrative controls, which provide the capability of closure within approximately 30 minutes.
Other containment penetrations, such as the personnel airlock and equipment hatch are allowed to be open during fuel handling operations. These penetrations are capable of manual closure and will be closed in accordance with plant procedures should a fuel handling accident occur.
In addition to the functions of the above mentioned monitors, fixed area radiation monitors are located in the containment. Should a fuel assembly be dropped and release activity above a prescribed level, the area monitors would sound an audible DCPP UNITS 1 & 2 FSAR UPDATE 15.4-57 Revision 21 September 2013 alarm. Personnel would exit the containment and containment closure would be initiated immediately per administrative procedures.
Because of containment isolation and closure capabilities, activity released from damaged fuel rods will be managed such that both the onsite and offsite exposures are minimized. The containment iodine removal system (see Section 9.4.5) can be used to remove any radioactive iodine from the containment atmosphere, but is not credited for iodine removal in the radiological analysis (see Section 15.5.22), and controlled containment venting can be initiated with offshore winds. Thus, there is a reasonable probability that only limited onshore exposures will result from a containment fuel handling accident. 15.4.5.3.2 Fuel Handling Area Accident A fuel assembly could be damaged in the transfer canal or the spent fuel pit in the fuel handling area. Supply air for the spent fuel pit area is swept across the fuel pit and transfer canal and exhausted through the vent. An area radiation monitor is located on the bridge over the spent fuel pit. Doors in the fuel handling area are closed to maintain controlled leakage characteristics in the spent fuel pit region during refueling operations involving irradiated fuel. Should a fuel assembly be damaged in the canal or in the pit and release radioactivity above a prescribed level, the radiation monitors sound an alarm and the spent fuel pit ventilation exhaust through charcoal filters will remove most of the halogens prior to discharging it to the atmosphere. If the discharge is greater than the prescribed levels, an alarm sounds and the supply and exhaust ventilation systems servicing the spent fuel pit area can be manually shut down from the control room, limiting the leakage to the atmosphere. The analysis of the radiological effects of this accident is contained in Section 15.5.22.1. 15.4.5.4 Conclusions The analysis demonstrates the acceptance criteria are met as follows: (1) Section 15.5.22 concludes that all potential exposures from a fuel handling accident will be well below the guideline levels specified in 10 CFR Part 100, and that the occurrence of such accidents would not result in undue risk to the public. Table 15.5-47 provides a summary of doses from a fuel handling accident in the fuel handling area. Table 15.5-50 provides a summary of offsite doses from a fuel handling accident inside containment. DCPP UNITS 1 & 2 FSAR UPDATE 15.4-58 Revision 21 September 2013 15.4.6 RUPTURE OF A CONTROL ROD DRIVE MECHANISM HOUSING (ROD CLUSTER CONTROL ASSEMBLY EJECTION) 15.4.6.1 Acceptance Criteria Conservative criteria are applied to ensure that there is little or no possibility of fuel dispersal in the coolant, gross lattice distortion, or severe shock waves. These criteria are: 15.4.6.1.1 Fuel Damage Criteria (1) Average fuel pellet enthalpy at the hot spot below 225 cal/gm for unirradiated fuel and 200 cal/gm for irradiated fuel (2) Average cladding temperature at the hot spot below the temperature at which cladding embrittlement may be expected (2700°F) (3) Fuel melting will be limited to less than 10 percent of the fuel volume at the hot spot even if the average fuel pellet enthalpy is below the limits of Criterion (1) above 15.4.5.1.2 Maximum RCS Pressure Criteria (1) Peak reactor coolant pressure less than that which would cause stresses to exceed the faulted condition stress limits 15.4.6.1.3 Radiological Criteria (1) The resulting potential exposures to individual members of the public and to the general population shall be lower than the applicable guidelines and limits specified in 10 CFR Part 100. 15.4.6.2 Identification of Causes and Accident Description This accident is defined as the mechanical failure of a control rod mechanism pressure housing resulting in the ejection of an RCCA and drive shaft. The consequence of this mechanical failure is a rapid positive reactivity insertion and system depressurization together with an adverse core power distribution, possibly leading to localized fuel rod damage. 15.4.6.2.1 Design Precautions and Protection Certain features of the DCPP are intended to preclude the possibility of a rod ejection accident, or to limit the consequences if the accident were to occur. These include a sound, conservative mechanical design of the rod housings, together with a thorough quality control (testing) program during assembly, and a nuclear design that lessens the DCPP UNITS 1 & 2 FSAR UPDATE 15.4-59 Revision 21 September 2013 potential ejection worth of RCCAs and minimizes the number of assemblies inserted at high power levels. 15.4.6.2.2 Mechanical Design The mechanical design is discussed in Section 4.2. Mechanical design and quality control procedures intended to preclude the possibility of an RCCA drive mechanism housing failure are listed below:
(1) Each full length control rod drive mechanism housing is completely assembled and shop tested at 3107 psig. (2) Pressure housings were individually hydrotested. The lower latch housing to nozzle connection is hydrotested during hydrotest of the completed replacement RVCH. (3) Stress levels in the mechanism are not affected by anticipated system transients at power, or by the thermal movement of the coolant loops.
Moments induced by the design-basis earthquake can be accepted within the allowable primary working stress range specified by the ASME Code, Section III, for Class I components. (4) The latch mechanism housing and rod travel housing are each a single length of forged Type-304 stainless steel. This material exhibits excellent notch toughness at all temperatures that will be encountered. (5) The CRDM housing plug is an integral part of the rod travel housing. A significant margin of strength in the elastic range together with the large energy absorption capability in the plastic range gives additional assurance that gross failure of the housing will not occur. The joints between the latch mechanism housing and rod travel housing are threaded joints reinforced by canopy-type rod welds. Administrative regulations require periodic inspections of these (and other) welds. 15.4.6.2.3 Nuclear Design Even if a rupture of an RCCA drive mechanism housing is postulated, the operation of a plant utilizing chemical shim is such that the severity of an ejected RCCA is inherently limited. In general, the reactor is operated with the RCCAs inserted only far enough to permit load follow. Reactivity changes caused by core depletion and xenon transients are compensated by boron changes. Further, the location and grouping of control rod banks are selected during the nuclear design to lessen the severity of an RCCA ejection accident. Therefore, should an RCCA be ejected from its normal position during full-power operation, only a minor reactivity excursion, at worst, could be expected to occur.
DCPP UNITS 1 & 2 FSAR UPDATE 15.4-60 Revision 21 September 2013 However, it may be occasionally desirable to operate with larger than normal insertions. For this reason, a rod insertion limit is defined as a function of power level. Operation with the RCCAs above this limit guarantees adequate shutdown capability and acceptable power distribution. The position of all RCCAs is continuously indicated in the control room. An alarm will occur if a bank of RCCAs approaches its insertion limit or if one RCCA deviates from its bank. There are low and low-low level insertion monitors with visual and audio signals. Operating instructions require boration at low-level alarm and emergency boration at the low-low alarm. 15.4.6.2.4 Reactor Protection The reactor protection in the event of a rod ejection accident has been described in Reference 18. The protection for this accident is provided by the power range high neutron flux trip (high and low setting) and high rate of neutron flux increase trip. These protection functions are described in detail in Section 7.2. 15.4.6.2.5 Effects on Adjacent Housings Disregarding the remote possibility of the occurrence of an RCCA mechanism housing failure, investigations have shown that failure of a housing due to either longitudinal or circumferential cracking is not expected to cause damage to adjacent housings leading to increased severity of the initial accident. 15.4.6.2.6 Limiting Criteria Due to the extremely low probability of an RCCA ejection accident, limited fuel damage is considered an acceptable consequence. Comprehensive studies of the threshold of fuel failure and of the threshold of significant conversion of the fuel thermal energy to mechanical energy have been carried out as part of the SPERT project by the Idaho Nuclear Corporation (Reference 19). Extensive tests of zirconium-clad UO2 fuel rods representative of those in PWR-type cores have demonstrated failure thresholds in the range of 240 to 257 cal/gm. However, other rods of a slightly different design have exhibited failures as low as 225 cal/gm. These results differ significantly from the TREAT (Reference 20) results, which indicated a failure threshold of 280 cal/gm. Limited results have indicated that this threshold decreases by about 10 percent with fuel burnup. The cladding failure mechanism appears to be melting for zero burnup rods and brittle fracture for irradiated rods. Also important is the conversion ratio of thermal to mechanical energy. This ratio becomes marginally detectable above 300 cal/gm for unirradiated rods and 200 cal/gm for irradiated rods; catastrophic failure, (large fuel dispersal, large pressure rise) even for irradiated rods, did not occur below 300 cal/gm.
DCPP UNITS 1 & 2 FSAR UPDATE 15.4-61 Revision 21 September 2013 15.4.6.3 Analysis of Effects and Consequences The analysis of the RCCA ejection accident is performed in two stages: (a) an average core nuclear power transient calculation and (b) a hot spot heat transfer calculation.
The average core calculation is performed using spatial neutron kinetics methods to determine the average power generation with time including the various total core feedback effects, i.e., Doppler reactivity and moderator reactivity. Enthalpy and temperature transients in the hot spot are then determined by multiplying the average core energy generation by the hot channel factor and performing a fuel rod transient heat transfer calculation. The power distribution calculated without feedback is pessimistically assumed to persist throughout the transient.
A detailed discussion of the method of analysis can be found in Reference 21. 15.4.6.3.1 Average Core Analysis The spatial kinetics computer code, TWINKLE (see Section 1.6.1 item 50 and Section 15.1.9.5) is used for the average core transient analysis. This code solves the two group neutron diffusion theory kinetic equations in one, two, or three spatial dimensions (rectangular coordinates) for six delayed neutron groups and up to 2000 spatial points. The computer code includes a detailed multi-region, transient fuel-clad-coolant heat transfer model for calculating pointwise Doppler, and moderator feedback effects.
In this analysis, the code is used as a one-dimensional axial kinetics code since it allows a more realistic representation of the spatial effects of axial moderator feedback and RCCA movement and the elimination of axial feedback weighting factors. However, since the radial dimension is missing, it is still necessary to employ very conservative methods (described below) of calculating the ejected rod worth and hot channel factor. A further description of TWINKLE appears in Section 15.1.9.5. 15.4.6.3.2 Hot Spot Analysis The average core energy addition, calculated as described above, is multiplied by the appropriate hot channel factors, and the hot spot analysis is performed using the detailed fuel and cladding transient heat transfer computer code, FACTRAN. This computer code calculates the transient temperature distribution in a cross section of a metalclad UO2 fuel rod, and the heat flux at the surface of the rod, using as input the nuclear power versus time and the local coolant conditions. The zirconium and water (Zr-H2O) reaction is explicitly represented, and all material properties are represented as functions of temperature. A parabolic radial power generation is used within the fuel rod.
FACTRAN uses the Dittus-Boelter (Reference 28) or Jens-Lottes (Reference 29) correlation to determine the film heat transfer before DNB, and the Bishop-Sandberg-Tong correlation (Reference 23) to determine the film boiling coefficient after DNB. The DCPP UNITS 1 & 2 FSAR UPDATE 15.4-62 Revision 21 September 2013 DNB heat flux is not calculated; instead the code is forced into DNB by specifying a conservative DNB heat flux. The gap heat transfer coefficient can be calculated by the code; however, it is adjusted in order to force the full power steady state temperature distribution to agree with that predicted by design fuel heat transfer codes.
For full power cases, the design initial hot channel factor (FQ) is input to the code. The hot channel factor during the transient is assumed to increase from the steady state design value to the maximum transient value in 0.1 seconds, and remain at the maximum for the duration of the transient. This is conservative, since detailed spatial kinetics models show that the hot channel factor decreases shortly after the nuclear power peak due to power flattening caused by preferential feedback in the hot channel. Further description of FACTRAN appears in Section 15.1.8. 15.4.6.3.3 System Overpressure Analysis Because safety limits for fuel damage specified earlier are not exceeded, there is little likelihood of fuel dispersal into the coolant. The pressure surge may therefore be calculated on the basis of conventional heat transfer from the fuel and prompt heat generation in the coolant.
The pressure surge is calculated by first performing the fuel heat transfer calculation to determine the average and hot spot heat flux versus time. Using this heat flux data, a THINC calculation is conducted to determine the volume surge. Finally, the volume surge is simulated in a plant transient computer code. This code calculates the pressure transient taking into account fluid transport in the system, heat transfer to the steam generators, and the action of the pressurizer spray and pressure relief valves. No credit is taken for the possible pressure reduction caused by the assumed failure of the control rod pressure housing (Reference 21). 15.4.6.3.4 Calculation of Basic Parameters Input parameters for the analysis are conservatively selected on the basis of calculated values for this type of core. The more important parameters are discussed below. Table 15.4-11 presents the parameters used in this analysis. A summary of the values used in the reload analysis process is also provided in Table 15.4-11. 15.4.6.3.5 Ejected Rod Worths and Hot Channel Factors The values for ejected rod worths and hot channel factors are calculated using three-dimensional calculations. Standard nuclear design codes are used in the analysis. No credit is taken for the flux-flattening effects of reactivity feedback. The calculation is performed for the maximum allowed bank insertion at a given power level as determined by the rod insertion limits. Adverse xenon distributions are considered in the calculations.
DCPP UNITS 1 & 2 FSAR UPDATE 15.4-63 Revision 21 September 2013 The total transient hot channel factor FQ is then obtained by combining the axial and radial factors. 15.4.6.3.6 Reactivity Feedback Weighting Factors The largest temperature rises, and hence the largest reactivity feedbacks, occur in channels where the power is higher than average. Since the weight of regions is dependent on flux, these regions have high weights. This means that the reactivity feedback is larger than that indicated by a simple single channel analysis. Physics calculations were carried out for temperature changes with a flat temperature distribution, and with a large number of axial and radial temperature distributions. Reactivity changes were compared and effective weighting factors determined. These weighting factors take the form of multipliers that, when applied to single channel feedbacks, correct them to effective whole core feedbacks for the appropriate flux shape. In this analysis, since a one-dimensional (axial) spatial kinetics method is employed, axial weighting is not used. In addition, no weighting is applied to the moderator feedback. A conservative radial weighting factor is applied to the transient fuel temperature to obtain an effective fuel temperature as a function of time accounting for the missing spatial dimension. These weighting factors were shown to be conservative compared to three-dimensional analysis. 15.4.6.3.7 Moderator and Doppler Coefficient The critical boron concentrations at the beginning of life (BOL) and end-of-life (EOL) are adjusted in the nuclear code in order to obtain moderator density coefficient curves which are conservative compared to actual design conditions for the plant. As discussed above, no weighting factor is applied to these results. The Doppler reactivity defect is determined as a function of power level using the one-dimensional steady state computer code with a Doppler weighting factor of 1. The resulting curve is conservative compared to design predictions for this plant. The Doppler weighting factor should be larger than 1 (approximately 1.3), just to make the present calculation agree with design predictions before ejection. This weighting factor will increase under accident conditions, as discussed above. 15.4.6.3.8 Delayed Neutron Fraction Calculations of the effective delayed neutron fraction (eff) typically yield values of 0.70 percent at BOL and 0.50 percent at EOL for the first cycle. The accident is sensitive to eff if the ejected rod worth is nearly equal to or greater than eff as in zero power transients. In order to allow for future fuel cycles, pessimistic estimates of 0.55 percent at beginning of cycle and 0.44 percent at end of cycle were used in the analysis. DCPP UNITS 1 & 2 FSAR UPDATE 15.4-64 Revision 21 September 2013 15.4.6.3.9 Trip Reactivity Insertion The trip reactivity insertion assumed is given in Table 15.4-11 and includes the effect of one stuck rod. These values are reduced by the ejected rod reactivity. The shutdown reactivity was simulated by dropping a rod of the required worth into the core. The start of rod motion occurred 0.5 seconds after the high neutron flux trip point was reached. This delay is assumed to consist of 0.2 seconds for the instrument channel to produce a signal, 0.15 seconds for the trip breaker to open, and 0.15 seconds for the coil to release the rods. The analyses presented are applicable for a rod insertion time of 2.7 seconds from coil release to entrance to the dashpot, although measurements indicate that this value should be closer to 1.8 seconds.
The choice of such a conservative insertion rate means that there is over 1 second after the trip point is reached before significant shutdown reactivity is inserted into the core. This is particularly important conservatism for hot full power accidents.
The rod insertion versus time is described in Section 15.1.4. 15.4.6.4 Results Typical reload values of the parameters used in the VANTAGE 5 analysis, as well as the results of the analysis, are presented in Table 15.4-11 and discussed below. Actual values vary slightly from reload to reload. 15.4.6.4.1 Beginning of Cycle, Full Power Control Bank D was assumed to be inserted to its insertion limit. The worst ejected rod worth and hot channel factor were conservatively assumed to be 0.20 percent k and 6.70, respectively. The peak hot spot cladding average temperature was 2434°F. The peak hot spot fuel center temperature exceeded the BOL melting temperature of 4900°F; however, melting was restricted to less than 10 percent of the pellet. 15.4.6.4.2 Beginning of Cycle, Zero Power For this condition, control Bank D was assumed to be fully inserted and C was at its insertion limit. The worst ejected rod is located in control Bank D and was conservatively assumed to have a worth of 0.785 percent k and a hot channel factor of 13. The peak hot spot cladding average temperature reached only 2660°F. 15.4.6.4.3 End of Cycle, Full Power Control Bank D was assumed to be inserted to its insertion limit. The ejected rod worth and hot channel factors were conservatively assumed to be 0.21 percent k and 6.50, respectively. This resulted in an average PCT of 2218°F. The peak hot spot fuel center temperature exceeded the EOL melting temperature of 4800°F. However, melting was restricted to less than 10 percent of the pellet. DCPP UNITS 1 & 2 FSAR UPDATE 15.4-65 Revision 21 September 2013 15.4.6.4.4 End of Cycle, Zero Power The ejected rod worth and hot channel factor for this case were obtained assuming control Bank D to be fully inserted and Bank C at its insertion limit. The results were 0.85 percent k and 21.5, respectively. The peak cladding average and fuel center temperatures were 2632°F and 3849°F, respectively. A summary of the cases presented above is given in Table 15.4-11. The nuclear power and hot spot fuel cladding temperature transients for these representative BOL full power and EOL zero power cases are presented in Figures 15.4.6-1 through 15.4.6-4. 15.4.6.4.5 Fission Product Release It is assumed that fission products are released from the gaps of all rods entering DNB. In all cases considered, less than 10 percent of the rods entered DNB based on a detailed three-dimensional THINC analysis. Although limited fuel melting at the hot spot was predicted for the full power cases, in practice melting is not expected since the analysis conservatively assumed that the hot spots before and after ejection were coincident. 15.4.6.4.6 Lattice Deformations A large temperature gradient will exist in the region of the hot spot. Since the fuel rods are free to move in the vertical direction, differential expansion between separate rods cannot produce distortion. However, the temperature gradients across individual rods may produce a force tending to bow the midpoint of the rods toward the hot spot. Physics calculations indicate that the net result of this would be a negative reactivity insertion. In practice, no significant bowing is anticipated, since the structural rigidity of the core is more than sufficient to withstand the forces produced. Boiling in the hot spot region would produce a net flow away from that region. However, the heat from fuel is released to the water relatively slowly, and it is considered inconceivable that cross flow will be sufficient to produce significant lattice forces. Even if massive and rapid boiling, sufficient to distort the lattice, is hypothetically postulated, the large void fraction in the hot spot region would produce a reduction in the total core moderator to fuel ratio, and a large reduction in this ratio at the hot spot. The net effect would therefore be a negative feedback. It can be concluded that no conceivable mechanism exists for a net positive feedback resulting from lattice deformation. In fact, a small negative feedback may result. The effect is conservatively ignored in the analyses. 15.4.6.5 Conclusions Even on a pessimistic basis, the analyses indicate that the described fuel and cladding limits are not exceeded. It is concluded that there is no danger of sudden fuel dispersal into the coolant. Since the peak pressure does not exceed that which would cause stresses to exceed the faulted condition stress limits, it is concluded that there is no danger of further consequential damage to the reactor coolant system. The analyses DCPP UNITS 1 & 2 FSAR UPDATE 15.4-66 Revision 21 September 2013 show that less than 10 percent of the fuel rods enter DNB. Even in the portion of the core which does reach DNB, there will be no excessive release of fission product activity if the limiting hot channel factors are not exceeded (Reference 21). The analysis shows the acceptance criteria for a RCCA Ejection Accident has been met as follows: 15.4.6.5.1 Fuel Damage (1) Table 15.4-11 shows the average fuel pellet enthalpy at the hot spot (Maximum fuel stored energy) below 225 cal/gm for non-irradiated fuel and 200 cal/gm (360 Btu/lb) for irradiated fuel. (2) Table 15.4-11 shows the average clad temperature at the hot spot (Maximum cladding average temperature) below 2700°F, the temperature above which clad embrittlement may be expected. (3) Table 15.4-11 shows the fuel melting limited to less than the innermost 10 percent of the fuel pellet at the hot spot. 15.4.6.5.2 Maximum RCS Pressure (1) A detailed calculation of the pressure surge for an ejection worth of one dollar reactivity insertion at BOL, hot full power, indicates that the peak pressure does not exceed that which would cause stress to exceed the faulted condition stress limits. Because the severity of the present analysis does not exceed this worst case analysis, the accident for this plant will not result in an excessive pressure rise or further damage to the RCS. 15.4.6.5.3 Radiological (1) Section 15.5.23 concludes that offsite exposures from a RCCA ejection accident will be well below the guideline levels specified in 10 CFR Part 100, and that the occurrence of such accidents would not result in undue risk to the public. Table 15.5-52 provides a summary of offsite doses from a rod ejection accident. 15.4.7 RUPTURE OF A WASTE GAS DECAY TANK 15.4.7.1 Identification of Causes and Accident Description Radioactive waste gas decay tanks are used to permit decay of radioactive gases as a means of reducing or preventing the release of radioactive materials to the atmosphere. This system is discussed in detail in Section 11.3.
Three gas decay tanks are provided for each unit to afford operating flexibility and allow one or more tanks to be isolated from the rest of the system for an extended period of DCPP UNITS 1 & 2 FSAR UPDATE 15.4-67 Revision 21 September 2013 time. Most of the gas stored in the decay tanks is nitrogen cover gas displaced from the liquid waste holdup tanks. The radioactive components are principally the noble gases krypton and xenon, the particulate daughters of some of the krypton and xenon isotopes, and trace quantities of halogens.
A number of combinations of inadvertent operator errors and equipment malfunctions or failures could be identified that might result in a release of some or all of the activity stored in these tanks. In general, the amounts of activity that could be released by any such combination of events are limited in the following ways: Plant Feature Function Limits on primary coolant activity Restricts total curies present in volume control tank and gas decay tanks Radiation monitor Allows early detection of release, allowing operator action to terminate release Limits on tank size Restricts total curies present in any one tank
Isolation valves Allows operator to terminate release
Operating procedures Reduces probability of releases 15.4.7.2 Conclusions In making an assessment of the probability of releases of this type, it is not possible to establish precise values. Since no occurrence of a major release has been recorded, the probability of such an event calculated on the basis of past experience would be very low. As discussed earlier, however, such events are considered possible, and for this reason, an assessment of the consequences of these events is reported in Section 15.5. 15.4.8 RUPTURE OF A LIQUID HOLDUP TANK 15.4.8.1 Identification of Causes and Accident Description Radioactive liquid waste holdup tanks are used as part of the chemical and volume control system (CVCS) to collect and permit decay of radioactive liquids drawn from the reactor primary coolant for reactivity control. The CVCS is described in detail in Chapter 9.
Five liquid holdup tanks are provided for the two units to afford operating flexibility and allow one or more tanks to be isolated from the rest of the system for extended periods of time. The liquid processed through the holdup tanks contains dissolved fission and activation products, as well as radioactive noble gases mixed with nitrogen cover gas used in the tanks. DCPP UNITS 1 & 2 FSAR UPDATE 15.4-68 Revision 21 September 2013 The liquid holdup tanks are located in vaults which are Design Class I structures, so that in the event of a rupture or spill all liquids are retained in the vaults. The volume of holdup tank vaults is sufficient to contain the full contents of the holdup tank without spillage from the vaults. Any gases released from the liquid holdup tanks are collected by the auxiliary building ventilation system and discharged via the auxiliary building vent. 15.4.8.2 Conclusions The probability of a liquid holdup tank rupture is small, but the probability of the release of all or part of the contents of a tank through operator error or valve failure is somewhat greater. The release of the total contents of a liquid holdup tank is taken as the postulated accident. Smaller leaks and spills from the liquid holdup tanks were found to have negligible environmental consequences, and therefore are not included. The analysis of the radiological effects of this accident is contained in Section 15.5. (See Reference 52.) 15.4.9 RUPTURE OF VOLUME CONTROL TANK 15.4.9.1 Identification of Causes and Accident Description The volume control tank is used as part of the CVCS to collect the excess water released from the RCS when the reactor power level is increased from zero to full power, which is not accommodated by the pressurizer. The CVCS is described in detail in Chapter 9. The liquid processed through the volume control tank contains dissolved fission and activation products, as well as undissolved radioactive noble gases. A spray nozzle located inside the tank on the inlet line strips part of the noble gases from the incoming liquid, and these gases are retained in the volume control tank vapor space. In addition, an overpressure of hydrogen cover gas is provided for the tank to control the hydrogen concentration in the reactor coolant.
The volume control tank is located in a vault which is a Design Class I structure, so that in the event of a rupture or spill all liquids are retained in the vault. The volume of the tank vault is sufficient to contain the full contents of the tank without spillage from the vault. Any gases released from the volume control tank are collected by the auxiliary building ventilation system and discharged via the auxiliary building vent. 15.4.9.2 Conclusions The probability of a volume control tank rupture is small, but the probability of the release of all or part of the contents of a tank through operator error or valve failure should be considered somewhat greater. The release of the total contents of a volume control tank is taken as the postulated accident. Smaller leaks and spills from the volume control tank were found to have negligible environmental consequences, and DCPP UNITS 1 & 2 FSAR UPDATE 15.4-69 Revision 21 September 2013 therefore are not included. The analysis of the radiological effects of this accident is contained in Section 15.5. 15.4.10 REFERENCES
- 1. "Acceptance Criteria for Emergency Core Cooling Systems for Light Water Cooled Nuclear Power Reactors" 10 CFR 50.46 and Appendix K of 10 CFR 50. Federal Register, Volume 39, Number 3, January 4, 1974.
- 2. F. M. Bordelon, et al, Westinghouse ECCS Evaluation Model - Summary, WCAP-8339, July 1974.
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DCPP UNITS 1 & 2 FSAR UPDATE 15.4-70 Revision 21 September 2013 18. T. W. T. Burnett, Reactor Protection System Diversity in Westinghouse Pressurized Water Reactor, WCAP-7306, April 1969. 19. T. G. Taxelius, ed. "Annual Report - SPERT Project, October 1968 September 1969," Idaho Nuclear Corporation IN-1370, June 1970.
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- 21. D. H. Risher, Jr., An Evaluation of the Rod Ejection Accident in Westinghouse Pressurized Water Reactors Using Spatial Kinetics Methods, WCAP-7588, Revision 1-A, January 1975.
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DCPP UNITS 1 & 2 FSAR UPDATE 15.4-71 Revision 21 September 2013 35. Deleted in Revision 12.
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DCPP UNITS 1 & 2 FSAR UPDATE 15.4-72 Revision 21 September 2013 56. Westinghouse Code Qualification Document for Best Estimate Loss of Coolant Accident Analysis, WCAP-12945-P (Proprietary), Volumes I-V. 57. Deleted in Revision 18.
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- 61. Containment Pressure Analysis Code (COCO), WCAP-8327 (Proprietary) and WCAP-8326 (Non-Proprietary), June 1974.
- 62. H. Chelemer, et al., Improved thermal Design Procedure, WCAP-8567-P-A (Proprietary) and WCAP-8568-A (Non-Proprietary), February 1989.
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DCPP UNITS 1 & 2 FSAR UPDATE 15.4-73 Revision 21 September 2013 72. PGE-10-56, "PG&E Diablo Canyon Units 1 and 2, Steam Generator Tube Rupture Margin to Overfill Analysis (CN-CRA-10-45 Rev. 0)," October 18, 2010
- 73. WCAP-16443-P , Rev. 1, Diablo Canyon Unit 2 ASTRUM BE-LBLOCA Engineering Report, November 2005 DCPP UNITS 1 & 2 FSAR UPDATE 15.5-1 Revision 19 May 2010 15.5 ENVIRONMENTAL CONSEQUENCES OF PLANT ACCIDENTS The purposes of this section are: (a) to identify accidental events that could cause environmental consequences, (b) to provide an assessment of the consequences of these accidents, and (c) to demonstrate that the potential consequences of these occurrences are within the limits, guidelines, and regulations established by the NRC. An accident is an unexpected chain of events; that is, a process, rather than a single event. In the analyses reported in this section, the basic events involved in various possible plant accidents are identified and studied with regard to the performance of the engineered safety features (ESF). The full spectrum of plant conditions has been divided into four categories in accordance with their anticipated frequency of occurrence and risk to the public. The four categories as defined above are as follows:
Condition I: Normal Operation and Operational Transients Condition II: Faults of Moderate Frequency Condition III: Infrequent Faults Condition IV: Limiting Faults The basic principle applied in relating design requirements to each of these conditions is that the most frequent occurrences must yield little or no radiological risk to the public; and those extreme situations having the potential for the greatest risk to the public shall be those least likely to occur.
These categories and principles were developed by the American Nuclear Society (Reference 1). Similar, though not identical, categories have been defined in the guide to the Preparation of Environmental Reports (Reference 3). While some differences exist in the manner of sorting the different accidents into categories in these documents, the basic principles are the same.
During the period since submittal of the Preliminary Safety Analysis Reports (PSARs) for Units 1 and 2, a number of changes have taken place that result in a somewhat different format and content in this chapter. These differences are as follows:
(1) The FSAR is written for two units. (2) Additional nuclear plant operating experience has been acquired on the performance characteristics of plant components and systems. (3) Minor changes have been made in basic plant operational procedures.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-2 Revision 19 May 2010 (4) Improvements in physical data on materials and system performance have resulted from continued research and development efforts; more precise data are available on such items as fission yields, iodine absorption, and, transport rates, etc. (5) Minor changes have been made in plant material and equipment specifications; examples are the use of cadmium-indium control rods, fuel handling area air filters, steam generator material changes, minor changes in pump flowrates, etc. (6) Some changes have been made in the assumed factors of conservatism used in the analyses; these changes do not relate to changes in the design of any system, only to the degree of conservatism employed in the evaluation of system performance. (7) In keeping with the greater level of detail required in final plant design, more detailed analysis has been performed and reported. Changes of these types can always be expected in the normal process of plant design, construction, and licensing.
It should also be noted that the range of plant operating parameters included in the Condition I category, and some of those in the Condition II category, fall in the range of normal operation. For this reason, the radioactive releases and radiological exposures associated with these conditions are analyzed in Chapter 11 and are not discussed separately in this chapter. The analyses of the variations in system parameters associated with Condition I occurrences or operating modes are discussed in Chapter 7 since these states are not accident conditions. In addition, some of the events identified as potential accidents in Regulatory Guide 1.70 (Reference 2), have no significant radiological consequences, or result in minor releases within the range of normal releases, and are thus not analyzed separately in this chapter. 15.5.1 APPROACH TO ANALYSES OF RADIOLOGICAL EFFECTS OF ACCIDENTS The potential radiological effects of plant accidents are analyzed by the evaluation of all physical factors involved in each chain of events which might result in radiation exposures to humans. These factors include the meteorological conditions existing at the time of the accident, the radionuclide uptake rates, exposure times and distances, as well as the many factors which depend on the plant design and mode of operation. In these analyses, the factors affecting the consequences of each accident are identified and evaluated, and uncertainties in their values are discussed. Because some degree of uncertainty always exists in the prediction of these factors, it has become general practice to assume conservative values in making calculated estimates of radiation doses. For example, it is customarily assumed that the accident occurs at a time when very unfavorable weather conditions exist, and that the performance of the DCPP UNITS 1 & 2 FSAR UPDATE 15.5-3 Revision 19 May 2010 plant engineered safety systems is degraded by unexpected failures. The use of these unfavorable values for the various factors involved in the analysis provides assurance that each safety system has been designed adequately; that is, with sufficient capacity to cover the full range of effects to which each system could be subjected. For this reason, these conservative values for each factor have been called design basis values.
In a similar way, the specific chain of events in which all unfavorable factors are coincidentally assumed to occur has been called a design basis accident (DBA). In the process of safety review and licensing, the radiation exposure levels calculated for the DBA are compared to the guideline values established in 10 CFR 100, and if these calculated exposures fall below the guideline levels, the plant safety systems are judged to be adequate.
As expected, the radiation exposure levels calculated for a DBA are not actually expected to occur, even if the event initiating the accident occurs. In fact, the calculated exposures resulting from a DBA are generally far in excess of what would be expected and do not provide a realistic means of assessing the expected radiological effects of real plant accidents.
For these reasons, the sections on radiological effects will include two evaluations, or cases, for each accident. The first case, called the expected case, will use values, for each factor involved in the accident, which are estimates of the actual values expected to occur if the accident took place. The resulting doses will then be close to the doses expected to result from an accident of this type. The second case, the DBA, will use the customary conservative assumptions. The calculated doses for the DBA, while not a realistic estimate of expected doses, can provide a basis for determination of the design adequacy of the plant safety systems. The specific values of all important parameters, data, and assumptions used in the radiological exposure calculations are listed in the following sections. The details of the implementation of the equations, models, and parameters are described in the description of the EMERALD computer program (Reference 4) and the EMERALD NORMAL program (Reference 5), which are described briefly in Sections 15.5.7 and 15.5.8. As discussed earlier, some of the radiological source terms for accidents and some of the releases resulting from Condition I and Condition II events have been included in Chapter 11. 15.5.2 ACTIVITY INVENTORIES IN THE PLANT PRIOR TO ACCIDENTS The fission product inventories in the reactor core, the fuel rod gaps, and the primary coolant prior to an accident have been calculated using the same assumptions, models, and physical data described in Section 11.1, but for different core and plant operating conditions. The preaccident inventories were calculated using the EMERALD computer code, described in Section 15.5.7, and are similar to those calculated for Tables 11.1-1 through 11.1-12 by the EMERALD-NORMAL code, except for slight differences in some DCPP UNITS 1 & 2 FSAR UPDATE 15.5-4 Revision 19 May 2010 nuclides due to different initial core inventories and irradiation times in the accident calculation.
The steam system operating conditions assumed for the calculation of preaccident secondary system inventories are listed in Table 11.1-23. It should be noted that these steam system flowrates and masses are approximate lumped values, used for activity balances only, and assume gross lumping of feedwater system component flows and masses. While these values are adequate for activity balances, they should not be used in the context of actual plant flow and energy balances. The activity inventories and concentrations existing in the secondary system are listed in Table 11.1-26.
Activity inventories in various radwaste system tanks are also listed in sections of Chapters 11 and 12 and will be cross-referenced in the sections of this chapter dealing with accidental releases from these tanks.
Refueling shutdown studies at operating Westinghouse PWRs indicate that, during cooldown and depressurization of the RCS, a release of activated corrosion products and fission products from defective fuel has been found to increase the coolant activity level above that experienced during steady state operation. An increased core activity release of this sort, commonly referred to as "spiking," could be expected to occur during the depressurization of the RCS as the result of an accident, and should therefore be taken into account in the calculation of postaccident releases of primary coolant to the environment.
Table 15.5-1 illustrates the anticipated coolant activity increases of several isotopes for DCPP during shutdown. This table lists the expected activities during steady state operation and anticipated peak activities during plant cooldown operations. These data are based on measurements from an operating PWR that is similar in design to the DCPP and has operated with significant fuel defects. The measured activity levels for the operating plant are also included in Table 15.5-1.
The dominant nongaseous fission product released to the coolant during system depressurization is I-131. The activity level in the coolant was observed to be higher than the normal operating level for nearly a week following initial plant shutdown with the system purification rate varying between approximately 1 x 10-5 and 3 x 10-5 per second. Although lesser in magnitude, the other fission product particulates (cesium isotopes) exhibited a similar pattern of release and removal by purification. It is reasonable to project these data to the DCPP since the purification constants are similar, and it is standard operating procedure to purify the coolant through the demineralizers during plant cooldown.
Fission gas data from operating plants indicate a maximum increase of approximately 1.5 over the normal coolant gas activity concentration. However, system degassification procedures are implemented prior to and during shutdowns, and have proven to be an effective means for reducing the gaseous activity concentration and controlling the activity to levels lower than the steady state value during the entire DCPP UNITS 1 & 2 FSAR UPDATE 15.5-5 Revision 19 May 2010 cooldown and depressurization procedure. Although a steady state Xe-133 concentration of 127 Ci/gm was observed prior to degassification procedures (see Table 15.5-1), the maximum coolant concentration during the reactor depressurization was 65 Ci/gm. Further, the coolant activity was then reduced to approximately 1 Ci/gm in less than two days of degassification. The corrosion product activity releases have been determined to be predominantly dissolved Co-58. From Table 15.5-1, it is noted that this contribution is less than 1 percent of the total expected coolant activity and is, therefore, considered to be a minor contribution.
For the calculation of the effect of spiking on accidental plant releases, the dominant isotopes were assumed to be iodines, and all others were neglected. Using the measured I-131 concentrations given in Table 15.5-1 and a primary purification rate of 1 x 10-5 per second, effective I-131 fuel escape rate to the reactor coolant during a spike of 30 times the normal equilibrium value was calculated. This value was then applied to all iodine isotopes. The duration of the spike was assumed to be 8 hours. This assumption can be justified by examining graphs of I-131 coolant concentration versus time during shutdowns for operating BWR plants (Reference 14). The assumption that the fuel escape rate continues at 30 times the normal rate for the full 8 hours of the spike is conservative. The effect of iodine spiking was included in all accidents that involved leakage of primary coolant directly or indirectly to the environment. 15.5.3 EFFECTS OF PLUTONIUM INVENTORY ON POTENTIAL ACCIDENT DOSES Because of the somewhat higher fission yields of some isotopes associated with thermal fissions in Pu-239, a sensitivity study was conducted to determine the possible influence of this effect on potential accident doses. This study demonstrates that accident doses are only slightly affected by the incorporation of Pu-239 fission yields into total core fission yields, even using the EOL plutonium inventories. The resulting differences, listed in Table 15.5-2, indicate that thyroid doses generally increase from 4 to 6 percent, and whole body doses generally decreased, from 2 to 5 percent, assuming the accident occurred at EOL.
In this study, total core fission yields were calculated by a mass weighting of U-235 fission yields and Pu-239 fission yields. Because the core mass of U-235 is considerably greater than the core mass of Pu-239, total core fission yields are close to U-235 fission yields. The masses of U-238 and Pu-241 that fission are extremely small, and thus U-238 and Pu-241 have essentially no effect on the total core fission yields. 15.5.4 POSTACCIDENT METEOROLOGICAL CONDITIONS For the analyses of offsite doses from the DBAs, the rare and unfavorable set of atmospheric dilution factors assumed in the NRC Regulatory Guide 1.4 (Reference 6) DCPP UNITS 1 & 2 FSAR UPDATE 15.5-6 Revision 19 May 2010 was used. On the basis of meteorological data collected at the DCPP site, these unfavorable dilution factors, assumed for the design bases cases, are not expected to exist for onshore wind directions more than 5 percent of the time. The particular values used for this site are given in Table 15.5-3. For the analyses of offsite doses from the expected case accidents, the assumed atmospheric dilution factors are listed in Table 15.5-4. For these cases, 10 percent of the design basis case numbers were used. On the basis of study of the site data at DCPP, this assumption will result in calculated exposures higher than would be expected.
Because of the low probability of occurrence associated with these assumed dilution factors, significant downwind decay, variable shifts in population distribution due to possible emergency evacuation, and large variations in concentrations due to downwind topographical characteristics, appropriate assumptions for population exposure (man-rem) estimates following a significant accidental release are difficult to select. It is clear that using the same factors of conservatism established for individual exposures at locations near the site (the regulatory guide dilution factors) would yield calculated population exposures much higher than could physically occur. For these reasons, the population exposures (man-rem) for the expected cases have been calculated using the long-term dilution factors given in Table 15.5-5, and ten times these values have been assumed for the DBA cases.
Effects of release duration on downwind ground level concentration have been measured directly and determined theoretically from knowledge of the horizontal and vertical spectrum of turbulence. Both the observations and theory generally agree that only the horizontal components of turbulence near ground level contain any significant amount of energy in periods longer than a few seconds. As a result, only the lateral dimension of the cloud need be modified for concentration estimates for noncontinuous releases. Slade (Reference 7) using the approach recommended by Cramer, gives a time-dependent adjustment of the lateral component of turbulence to be:
(T) = (To) (T/To)0.2 (15.5-1) where: (T) = lateral intensity of turbulence of a time period T, where T is a value less than 10 minutes (To) = lateral intensity of turbulence measured over a time period To, where To is on the order of 10 minutes Near a source there is a direct linear relationship between and the plume crosswind dimension y so that the y versus distance curves presented by Slade can be directly scaled by the factor (T/To)0.2 to provide estimates of a reference y at about 100 meters downwind from the source. Beyond this distance, the lateral expansion rates for DCPP UNITS 1 & 2 FSAR UPDATE 15.5-7 Revision 19 May 2010 continuous and noncontinuous point source releases are approximately the same, and thus the ratio of short-term release concentration to continuous release concentration for point sources is independent of stability class, downwind distance, or windspeed.
For distances less than a few thousand meters the ratio approaches unity as the volume of the source increases.
Using the above scaling concept, the dilution equation in Regulatory Guide 1.4, and the cloud dimension curves given by Slade, the ratio of short-term release concentration to continuous release concentration was calculated for several different release durations (Figure 15.5-1). For a 10-second duration, the short-term dilution factor is only 2.3 higher than the continuous release dilution factor, and thus the appropriate short-term release correction is within the uncertainty limits of the continuous release dilution factor.
The various plant accidents considered in Sections 15.2, 15.3, and 15.4 may result in activity release through various pathways: containment leakage, secondary steam dumping, ventilation discharge, and radioactive waste system discharge.
Postaccident containment leakage is a slow continuous process, and thus continuous release dilution factors apply for these cases.
Because of secondary loop isolation capabilities and because significant activity release is accompanied by large steam release, secondary steam dumping accidents release significant quantities of activity only through relief valves. Relief valve flow limitations combined with large steam release result in activity releases of long duration. Thus continuous release dilution factors apply for these cases. The approximate duration of a ventilation discharge activity release can be estimated by dividing the volume of contaminated air by the discharge flowrate. Because estimates of release duration for liquid holdup tank rupture, gas decay tank rupture, volume control tank rupture, and fuel handling area accident are all over in 10 minutes, continuous release dilution factors apply for these cases.
Continuous release dilution factors have been applied to all Conditions II, III, and IV accidents discussed in Chapter 15 for the following reasons:
(1) Almost all Conditions II, III, and IV releases are definitely long-term releases (2) Releases that might be considered short-term releases result in exposures well within 10 CFR 100 limits (3) Short-term release dilution factors are only about twice as high as continuous release dilution factors DCPP UNITS 1 & 2 FSAR UPDATE 15.5-8 Revision 19 May 2010 (4) The appropriate short-term release corrections are within the range of the uncertainties in the continuous release dilution factors Furthermore, the above reasons indicate that a more sophisticated or complex short-term release dilution model is not justified.
The atmospheric dispersion factors for pressurization and infiltration air flows to the control room are analyzed using the modified Halitsky /Q methodology, which is discussed below.
As a result of the TMI accident, the NRC, in NUREG-0737 Section III.D.3.4, asked all nuclear power plants to review their post-LOCA control room habitability designs using the guidance of Standard Review Plan 6.4 and the 1974 Murphy-Campe (M-C) paper (Reference 17). These reviews concluded that the atmospheric dispersion factor (/Q) methodology recommended in the M-C paper was overly conservative and inappropriate for most of the plant designs. The M-C equations are based primarily on the Halitsky data for round-topped EBR-II (PWR type) containments and are valid only for intake locations at least a half containment diameter from the containment wall. In most cases, however, the intake locations are closer to the building causing the wake. Thus, review of recent literature on building wake /Qs, models, wind tunnel tests, and field measurements resulted in the modified Halitsky /Q model. Historically, the preliminary work on building wake /Qs was based on a series of wind tunnel tests by James Halitsky et al. Halitsky summarized these results in Meteorology and Atomic Energy 1968, D. H. Slade, Editor (Reference 7). In 1974 K. Murphy and K. Campe of the NRC published their paper based on a survey of existing data. This /Q methodology, which presented equations without derivation or justification, was adopted as the interim methodology in SRP 6.4 in 1975. Since that time, a series of actual building wake /Q measurements have been conducted at Rancho Seco (Reference 25), and several other papers have been published documenting the results of additional wind tunnel tests (see References 26 through 31).
The Diablo Canyon plant complex is composed of square-edged buildings and two cylindrical containment buildings. Infiltration air into the control room would come from the auxiliary building, which has air intakes slightly above the control room. This intake of air will be subject to building wake caused by the portion of the containment building above the highest roof elevation of the auxiliary building. Pressurization air for the control room is provided from intakes on the turbine building. The intake will be subject to building wake caused by a portion of the containment building above the turbine building roof and a portion of the turbine building wall facing west and the wall facing north.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-9 Revision 19 May 2010 J. Halitsky's efforts, summarized in Reference 7, present the basic equation as follows: uAKQ// (15.5-2) where A = cross sectional area, m2 orthogonal to u u = wind speed, m/s K = isopleth (concentration coefficient - dimensionless)
It is found in many cases that the above Halitsky equation still provides a reasonable estimate of /Q. The following correction factors can be applied to this equation to account for situation and plant-specific features: Stream line flows are used in most wind tunnel tests Release points are generally much higher than 10 meters above ground Null wind velocity is observed at certain periods of time Isothermal temperatures are used in wind tunnel tests Buoyancy and jet momentum effects are ignored Typical 1 hr field tests account for plume meander effects, while 3 to 5 minute wind tunnel tests do not. A modified Halitsky /Q methodology, formulated by R. Bhatia, et al (Reference 32), is presented below.
/Q = K x f1 x f2 x f3 x f4 x f5 x f6 (sec/m3) (15.5-3) Au This modified Halitsky methodology is inherently conservative because the wind is assumed to be blowing towards the control room during the first or worst part of the accident, and because 5 percent wind speeds are used rather than 50 percent. In addition, the adjustment factors are always biased towards the minimum reduction that the data justifies.
As a test of the modified Halitsky method, calculated values of /Q, without using factors f4 and f5 due to their uncertainty, were compared to the 1 hour field test /Q data from Rancho Seco. Only one /Q was found to be higher than the calculated value. This was due to an external wake influence caused by wind channeling between the DCPP UNITS 1 & 2 FSAR UPDATE 15.5-10 Revision 19 May 2010 nearby cooling towers. The wind channeling prevented the normal wake turbulence and variation effects over time, which normally spread the plume over a wide area. In most cases the modified Halitsky /Q was found to be a conservative estimate of the measured /Q; in some cases it was significantly higher. The choice of K factors and the suggested modifying factors, f1, f2, etc., are discussed below. K factors: The choice of an appropriate K factor from the wind tunnel test data is critical for the /Q estimate to be valid. Halitsky in Reference 7 has several sets of K isopleths for round-topped containments (for PWRs) and block buildings (for BWRs). Multiple building complexes must be simulated by single equivalent structures. The effluent velocity to wind speed ratio of approximately 1 is valid for most power coolant systems. Various angles of wind incidence are shown to account for vortexing that could result in worse conditions than a wind normal to the building face. K factors should be estimated for various combinations of wind incidence angle and the appropriate effective building cross-sectional area causing the wake (not just the containment area) to determine the peak value, as was done by Walker (Reference 26). The K factors were determined from Figure 5.29c in Reference 7, based on a conservative analysis of the locations for infiltration and pressurization intake airflows and the appropriate dimensions relative to the containment. A single pressurization intake nearest the containment was assumed. The selected K factors and appropriate building cross-sectional areas used for the base /Q values are given below. The 5 percent wind speed was derived from an analysis of Diablo Canyon meteorological data over a period of 10 years. Case K u (meter/second) A(m2) Base /Q (sec/m3) Pressurization 4 1 3690 1.084x10-3 Infiltration 5 1 1661 3.01x10-3 u, wind speed: Halitsky's K values are based on wind speeds measured at the top of the containment or building. Therefore, the M-C 5 percent wind speed at a 10 meter height should be adjusted to the actual speed at the top of containment or release point. The 5 percent wind speed is adjusted using the formulation presented by Wilson (Reference 30) as follows. DCPP UNITS 1 & 2 FSAR UPDATE 15.5-11 Revision 19 May 2010 .23ZZuuRefT (15.5-4) where: Tu = wind speed at height Z RefZ = 10 meters (5% wind speed reference height) f1, wind speed change factor/ f2, wind direction change factor: The factors shown below were used. They are based on Diablo Canyon meteorological data for a 10 year period of record. Time Periods f1 f2 0 - 8 hrs 1.0 1.0 8 - 24 hrs 0.83 0.92 24 - 96 hrs 0.66 0.84 96 - 720 hrs 0.48 0.67 f3, wind turbulence effect: Wilson in Reference 30 and field tests confirm Halitsky's statement that his K isopleths are a factor of 5 to 10 too conservative due to not accounting for random fluctuations of the wind approaching the building. Therefore, a factor of 0.2 was used for f3. f4, elevated release effect: Bouwmeester et al. (Reference 31) indicate that there are up to 10 null wind speed conditions during an hour of data collection. During these periods the effects of jet momentum, plume rise and buoyancy would result in the radioactive effluent being discharged above the effective wake boundary and thus not entering the wake cavity. A reduction factor of 1 was used. F5, time averaging effects: Wind speed variations and wind direction meandering effects are not modeled in wind tunnel tests to account for this effect. Reference 31 indicates the use of the following equation: 1/2mtptmCpC (15.5-5) DCPP UNITS 1 & 2 FSAR UPDATE 15.5-12 Revision 19 May 2010 where: pC= prototype concentration mC= model concentration pt = prototype sampling time mt= model equivalent sampling time Normal wind tunnel data is taken for 3 to 10 minute samples. Thus, for a 1-hour field test, pC = 0.22 to 0.41mC, and for an 8 hour field test, pC= 0.08 to 0.14. mC A value of 0.5 was conservatively assumed for f5. f6, adjustments to top of containment: To account for wind speed at the top of containment, instead of the M-C 5 percent wind speed at 10 meter height, the factor f6 = u/uT was included. The f6 value equals 0.65. Table 15.5-6 presents the resultant atmospheric dispersion factors (/Q) calculated using the modified Halitsky /Q methodology. These dispersion factors do not take credit for dual pressurization inlets and do not include the control room occupancy factors. 15.5.5 RATES OF ISOTOPE INHALATION The breathing rates used in the calculations of inhalation doses are listed in Table 15.5-7. These values are based on the average daily breathing rates assumed in the ICRP Report (Reference 8) which are also used in Regulatory Guide 1.4. The active breathing rates were used for all onsite dose calculations, which are based on expected exposure times. 15.5.6 POPULATION DISTRIBUTION The distribution of population surrounding the plant site, which was used for the population exposure calculations, is discussed in Section 2.1, and the population distribution used is listed in Table 15.5-8. The actual postaccident population distribution could be significantly lower if any evacuation plan were implemented. 15.5.7 DESCRIPTION OF THE EMERALD (REVISION I) PROGRAM The EMERALD program is designed for the calculation of radiation releases and exposures resulting from abnormal operation of a large PWR. The approach used in EMERALD is similar to an analog simulation of a real system. Each component or volume in the plant that contains a radioactive material is represented by a subroutine, which keeps track of the production, transfer, decay, and absorption of radioactivity in DCPP UNITS 1 & 2 FSAR UPDATE 15.5-13 Revision 19 May 2010 that volume. During the course of the analysis of an accident, activity is transferred from subroutine to subroutine in the program as it would be transferred from place to place in the plant. For example, in the calculation of the doses resulting from a LOCA, the program first calculates the activity built up in the fuel before the accident, then releases some of this activity to the containment volume. Some of this activity is then released to the atmosphere. The rates of transfer, leakage, production, cleanup, decay, and release are read in as input to the program.
Subroutines are also included that calculate the onsite and offsite radiation exposures at various distances for individual isotopes and sums of isotopes. The program contains a library of physical data for 25 isotopes of most interest in licensing calculations, and other isotopes can be added or substituted. Because of the flexible nature of the simulation approach, the EMERALD program can be used for most calculations involving the production and release of radioactive materials, including design, operational and licensing studies. The complete description of the program, including models and equations, is contained in Reference 4. 15.5.8 DESCRIPTION OF THE EMERALD-NORMAL PROGRAM The EMERALD-NORMAL program is a program incorporating the features of EMERALD, but designed specifically for releases from normal and near-normal operating conditions. It contains an expanded library of isotopes, including all those of interest in gaseous and liquid environmental exposures. Models for a radwaste system are included, using the specific configuration of radwaste system components in the DCPP. The program contains a subroutine for doses via liquid release pathways developed by the Bechtel Corporation and a tritium subroutine. The code calculates activity inventories in various radwaste tanks and plant components which are used for the initial conditions for accidents involving these tasks. In addition, it is used in some near-normal plant conditions classified in this document as Condition I and Condition II and discussed in Chapter 11. 15.5.9 DESCRIPTION OF THE ISOSHLD PROGRAM ISOSHLD (Reference 9) is a computer code used to perform gamma ray shielding calculations for isotope sources in a wide variety of source and shield configurations. Attenuation calculations are performed by point kernel integration; for most geometries this is done by Simpson's rule numerical integration. Source strength in uniform or exponential distribution (where applicable) may be calculated by the linked fission product inventory code RIBD or by other options as desired. Buildup factors are calculated by the code based on the number of mean free paths of material between the source and detector points, the effective atomic number of a particular shield region (the last unless otherwise chosen), and the point isotropic NDA buildup data available as Taylor coefficients in the effective atomic number range of 4 to 82. Other data needed to solve most isotope shielding problems of practical interest are linked to ISOSHLD in various libraries.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-14 Revision 19 May 2010 15.5.10 ENVIRONMENTAL CONSEQUENCES OF CONDITION II FAULTS As reported in Section 15.2, none of the Condition II faults are expected to cause breach of any of the barriers preventing fission product release from the core or plant. Under some conditions, however, small amounts of radioactive isotopes could be released to the atmosphere following Condition II events as a result of atmospheric steam dumps required for plant cooldown. The particular Condition II events that are expected to result in some atmospheric steam release are: (1) Loss of electrical load and/or turbine trip (2) Loss of normal feedwater (3) Loss of offsite power to the station auxiliaries (4) Accidental depressurization of the main steam system The amount of steam released following these events depends on the time relief valves remain open and the availability of condenser bypass cooling capacity. The amount of radioactive iodine released depends on the amount of steam released and the iodine concentration in the steam generator water prior to the accident. An analysis of potential thyroid doses has been made over the full range of possible values of these two key parameters; the results are presented in Figures 15.5-2 through 15.5-5. As shown on the figures, the potential thyroid doses are higher with increasing steam releases and iodine concentrations. Figures 15.5-2 and 15.5-3 are results that assume Regulatory Guide 1.4 assumptions for postaccident meteorology and breathing rates (Design Basis Case Assumptions). As shown in Figure 15.5-2, approximately 1.6 x 106 lbm of steam is the maximum steam release expected for a full cooldown without any condenser availability, and a steam release of approximately 1 x 105 lbm would result from releasing only the contents of one steam generator due to a safety valve release or steam line break with condenser cooling available.
Figures 15.5-2 through 15.5-5 illustrate the range of possible thyroid doses from Condition II events. The highest anticipated doses would result from an event such as loss of electrical load, and the potential thyroid and whole body doses from this particular event have been analyzed using the EMERALD program. For both the design basis case and the expected case, it was assumed that 656,000 lbm of steam would be released to the atmosphere during the first 2 hours, and an additional 1,035,000 lbm would be released during the following 6 hours for a limiting total release of about 1.7E+06 lbm (see Table 6.4.2-1 of Reference 49 for a summary of OSG and RSG Condition II event steam releases). The assumptions used for meteorology, breathing rates, population density, and other common factors were described in earlier paragraphs. Note that the preceding steam release quantities are associated with the original steam generator (OSG) loss of load (LOL) analysis which provides the basis for the dose analysis of record. These values are greater than the replacement steam generator (RSG) LOL with Tavg and Tfeed Range analysis releases (651,000 Ibm and DCPP UNITS 1 & 2 FSAR UPDATE 15.5-15 Revision 19 May 2010 1,023,000 Ibm, respectively) and are therefore bounding since total dose is proportional to total steam release. For the design basis case, it was assumed that the plant had been operating continuously with 1 percent fuel cladding defects and 1 gpm primary-to-secondary leakage. For the expected case calculation, operation at 0.2 percent defects and 20 gallons per day to the secondary was assumed. In both cases, leakage of water from primary to secondary was assumed to continue during cooldown at 75 percent of the preaccident rate during the first 2 hours and at 50 percent of the preaccident rate during the next 6 hours. These values were derived from primary-to-secondary pressure differentials during cooldown.
It was also conservatively assumed for both cases that the iodine partition factor in the steam generators releasing steam was 0.01, on a mass basis (Reference 15). In addition, to account for the effect of iodine spiking, fuel escape rate coefficients for iodines of 30 times the normal operation values given in Table 11.1-8 were used for a period of 8 hours following the start of the accident. Other detailed and less significant modeling assumptions are presented in Reference 4.
The resulting potential exposures from this type of accident are summarized in Table 15.5-9 and are consistent with the parametric analyses presented in Figures 15.5-2 through 15.5-5. It can be concluded from these results that the occurrence of any of the events analyzed in Section 15.2 (or from other events involving insignificant core damage, but requiring atmospheric steam releases) will result in insignificant radiation exposures.
15.5.11 ENVIRONMENTAL CONSEQUENCES OF A SMALL LOCA - NO FUEL DAMAGE As discussed in Section 15.3.1, a small LOCA is not expected to cause fuel cladding failure. For this reason, the only activity release to the containment will be the dissolved noble gases and iodine in the reactor coolant water expelled from the pipe rupture. Some of this activity could be released to the containment atmosphere as the water flashes, and some of this amount could leak from the containment as a result of a rise in containment pressure.
The detailed description of the models used in calculating the potential exposures from a small LOCA is contained in Reference 4, and a general description is contained in Section 15.5.17 of this report. The specific assumptions used in the analysis are as follows:
(1) The fission product inventories, preaccident power levels, breathing rates, population data, meteorology, and other common assumptions are described in the previous sections of 15.5.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-16 Revision 19 May 2010 (2) It has been assumed that all of the water contained in the RCS is released to the containment. For the design basis case, the reactor coolant activities associated with 1 percent defective cladding were used; and for the expected case, the reactor coolant activities associated with 0.2 percent defective cladding were used. These activities and concentrations are listed in Tables 11.1-11 and 11.1-12, and all models and assumptions used in determining these values are described in Section 11.1. (3) Of the amounts of noble gases contained in the primary coolant, 100 percent is assumed to be released to the containment atmosphere at the time of the accident. For the iodines, it is assumed that only 10 percent of the dissolved iodine in the coolant is released to the containment atmosphere, due to the solubility of the iodine. It is assumed that the amounts of iodine in chemical forms that are not affected by the spray system are negligible. These release fractions are used for both the design basis case and the expected case. (4) In addition, to account for the effect of iodine spiking, all of the activity released from the fuel up to 8 hours after the accident is assumed to be released to the containment. Of the amounts of noble gases released to the containment, 100 percent is assumed to be released to the containment atmosphere. For the iodines, it is assumed that only 10 percent of the iodines released to the containment are released to the containment atmosphere. (5) The spray removal rates for the small LOCA are assumed to be the same as those applicable for the large break LOCA as described in Section 15.5.17. (6) The containment leakage rates in this analysis are also assumed to be the same as for the large LOCA and are discussed in Section 15.5.17. The resulting potential exposures are listed in Table 15.5-10 and demonstrate that all calculated doses are well below the guideline values specified in 10 CFR 100. Since the activity releases from this type of event will be significantly lower than those from a large break LOCA, any control room exposure which might occur would be well within the established criteria discussed in Section 15.5.17. In addition, because of significantly lower fission product releases to the sump and the absence of any zirconium-water reaction, the amounts of free hydrogen produced by sump radiolysis following a small LOCA would not be of concern. 15.5.11.1 Environmental Consequences of a Small LOCA - With Fuel Damage Westinghouse has determined that the amount of fuel damage during a small break Loca (SBLOCA) can be much higher than the small amount previously assumed, and that credit for automatic initiation of the containment spray system (CSS) cannot be taken (Reference 40). Based on this, the radiological consequences of a SBLOCA have been reanalyzed (Reference 48). The assumptions for the SBLOCA are the same DCPP UNITS 1 & 2 FSAR UPDATE 15.5-17 Revision 19 May 2010 as the large break LOCA (LBLOCA) as described in Section 15.5.17.1, with the following exceptions:
(1) The source activity is 2 percent iodines and 2 percent noble gases accumulated in the core at the end of core life. (2) 100 percent of the iodine activity released from the fuel reached the containment atmosphere and 100 percent of the activity is retained in the reactor coolant system. (3) There is no initiation of CSS. (4) An iodine removal coefficient by containment surface deposition of 2.0 per hour is applied.
The resulting potential doses are listed in Table 15.5-10 and demonstrate that all calculated doses are well below the guidelines values specified in 10 CFR 100. Additionally, the SBLOCA doses are less than the calculated doses for the LBLOCA listed in Table 15.5-75. Thus, even with fuel damage assumptions and no credit for the CSS, the SBLOCA remains bounded by the LBLOCA.
Since the activity releases from the SBLOCA are less than those from a LBLOCA, any control room dose which might occur would be well within the established criteria discussed in Section 15.5.17. 15.5.12 ENVIRONMENTAL CONSEQUENCES OF MINOR SECONDARY SYSTEM PIPE BREAKS The effects on the core of sudden depressurization of the secondary system caused by an accidental opening of a steam dump, relief or safety valve were described in Section 15.2 and apply also to the case of minor secondary system pipe breaks. As shown in that analysis, no core damage or fuel rod failure is expected to occur. In Section 15.5.18, analyses are presented that show the effects on the core of a major steam line break, and, in this case also, no fuel rod failures are expected to occur in the event of minor secondary pipe ruptures.
The analyses presented in Section 15.2 demonstrate that a departure from nucleate boiling ratio (DNBR) of less than the safety analysis limit will not occur anywhere in the core in the event of a minor secondary system pipe rupture. The possible environmental consequences of this event, due to the release of some steam that might contain radioactive iodines, is discussed in Section 15.5.10. The resulting thyroid doses are presented parametrically in Figures 15.5-2 through 15.5-5 as a function of quantity of steam released and secondary system activity. In the event that a complete plant cooldown without condenser cooling capacity is necessary following the break, the potential exposures would be the same as those reported in Table 15.5-9 for loss of DCPP UNITS 1 & 2 FSAR UPDATE 15.5-18 Revision 19 May 2010 electrical load. On the basis of these values, it can be concluded that the potential exposures following a minor secondary system pipe rupture would be insignificant. 15.5.13 ENVIRONMENTAL CONSEQUENCES OF INADVERTENT LOADING OF A FUEL ASSEMBLY INTO AN IMPROPER POSITION Fuel and core loading errors such as inadvertently loading one or more fuel assemblies into improper positions, loading a fuel rod during manufacture with one or more pellets of the wrong enrichment, or loading a full fuel assembly during manufacture with pellets of the wrong enrichment will lead to increased heat fluxes if the error results in placing fuel in core positions calling for fuel of lesser enrichment. The inadvertent loading of one or more fuel assemblies requiring burnable poison rods into a new core without burnable poison rods is also included among possible core loading errors. Because of margins present, as discussed in detail in Section 15.3.3, no events leading to environmental consequences are expected as a result of loading errors. 15.5.14 ENVIRONMENTAL CONSEQUENCES OF COMPLETE LOSS OF FORCED REACTOR COOLANT FLOW A complete loss of forced reactor coolant flow may result from a simultaneous loss of electrical supplies to all reactor coolant pumps (RCPs). If the reactor is at power at the time of the accident, the immediate effect of loss of coolant flow is a rapid increase in the coolant temperature.
The analysis performed and reported in Section 15.3.4 has demonstrated that for the complete loss of forced reactor coolant flow, the DNBR does not decrease below the safety analysis limit during the transient, and thus there is no cladding damage or release of fission products to the RCS. For this reason, this accident has no significant environmental effects. 15.5.15 ENVIRONMENTAL CONSEQUENCES OF AN UNDERFREQUENCY ACCIDENT A transient analysis for this unlikely event has been carried out. The analysis demonstrates that for an underfrequency accident, the DNBR does not decrease below the safety analysis limit during the transient, and thus there is no cladding damage or release of fission products to the RCS. However, small amounts of radioactive isotopes could be released to the atmosphere as a result of atmospheric steam dumping required for plant cooldown.
A detailed discussion of the potential environmental consequences of accidents involving atmospheric steam dumping is presented in Section 15.5.10. From the parametric analyses presented in that section, the potential exposures from an underfrequency accident are given in Table 15.5-11. On the basis of these potential exposures, it can be concluded that, although very unlikely, the occurrence of this accident would not cause undue risk to the health and safety of the public. DCPP UNITS 1 & 2 FSAR UPDATE 15.5-19 Revision 19 May 2010 15.5.16 ENVIRONMENTAL CONSEQUENCES OF A SINGLE ROD CLUSTER CONTROL ASSEMBLY WITHDRAWAL AT FULL POWER A complete transient analysis of this accident is presented in Section 15.3.5. For the condition of one rod cluster control assembly (RCCA) fully withdrawn with the rest of the bank fully inserted, at full power, an upper bound of the number of fuel rods experiencing DNBR less than the safety analysis limit is 5 percent of the total fuel rods in the core.
A detailed discussion of the potential environmental consequences of accidents involving small amounts of fuel rod failure is included in Section 15.5.21. From the parametric analyses presented in that section, the potential exposures from an RCCA withdrawal at full power resulting in 5 percent fuel failure are given in Table 15.5-12. On the basis of these potential exposures, it can be concluded that the occurrence of this accident would not cause undue risk to the health and safety of the public. 15.5.17 ENVIRONMENTAL CONSEQUENCES OF MAJOR RUPTURE OF PRIMARY COOLANT PIPES Various aspects of the environmental consequences of a large break LOCA are presented in this section. 15.5.17.1 Basic Events and Release Fractions The accidental rupture of a main coolant pipe is the event assumed to initiate a major LOCA. Analyses of the response of the reactor system, including the emergency core cooling system (ECCS), to ruptures of various sizes have been presented in previous sections. As demonstrated in these analyses, the ECCS, using emergency power, is designed to keep cladding temperatures well below melting and to limit zirconium-water reactions to an insignificant level. As a result of the increase in cladding temperature and the rapid depressurization of the core, however, some cladding failure may occur in the hottest regions of the core. Following the cladding failure, some activity would be released to the primary coolant and subsequently to the inside of the containment building. Because of the pressurization of the containment building by the primary coolant water escaping from the pipe break, some of the volatile radioactive iodines and noble gases could leak from the containment building to the atmosphere.
It is not expected that a significant amount of organic iodine would be liberated from the fuel as a result of a LOCA. This conclusion is based on the results of fuel meltdown experiments conducted by the Oak Ridge National Laboratory. The fraction of the total iodine that is released in organic forms is expected to be on the order of 0.2 percent, or less, since the rate of thermal radiolytic decomposition would exceed the rate of production.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-20 Revision 19 May 2010 Organic compounds of iodine can be formed by reaction of absorbed elemental iodine on surfaces of the containment vessel. Experiments have shown that the rate of formation is dependent on specific conditions such as the concentration of iodine, concentration of impurities, radiation level, pressure, temperature, and relative humidity. The rate of conversion of airborne iodine is proportional to the surface-to-volume ratio of the enclosure, whether the process is limited to diffusion to the surface or by the reaction rate of the absorbed iodine. The observed yields of organic iodine as a function of aging time in various test enclosures, with various volume-to-surface area ratios, were extrapolated to determine the values for the DCPP containment vessel. The iodine conversion rates predicted in this manner did not exceed 0.0005 percent of the atmospheric iodine per hour.
The potential exposures following the postulated sequence of events in large LOCAs have been analyzed for two cases. In the expected case, it has been assumed that the entire inventory of volatile fission products contained in the pellet-cladding gap spaces is released to the coolant during the time the core is being flooded by the ECCS. Of this gap inventory, 25 percent of the iodines and 100 percent of the noble gases are considered to be released to the containment atmosphere immediately following the pipe rupture. In this respect, the expected case does contain some degree of conservatism since the ECCS is designed to prevent gross cladding damage. In accordance with the experimental data reported in the previous paragraph, the fraction of iodine that is released in organic form is assumed to be 0.2 percent, and the production rate of organic forms is considered negligible. The iodine plateout rates are negligible (Reference 10) compared to the spray washout rates and are assumed to be zero. The particulate fraction of iodine is also assumed to be zero for the expected case since this fraction is small and the spray removal rates for particulates is large as shown in Reference 10. For the design basis LOCA, it has been assumed that 25 percent of the equilibrium radioactive iodine inventory in the core is immediately available for leakage from the reactor containment. Ninety-one percent of this 25 percent is assumed to be in the form of elemental iodine, 4 percent of this 25 percent is in the form of organic iodides, and 5 percent of this 25 percent is in the form of particulate iodine. In addition, 100 percent of the noble gas inventory in the core is assumed to be immediately released to the containment building. As discussed in earlier paragraphs, releases of these magnitudes are not expected to occur, even if the ECCS does not perform as expected. An analysis using these assumptions is presented because these values are considered acceptable for a design basis analysis in Regulatory Guide 1.4. 15.5.17.2 Spray System Iodine Removal Rates The containment spray system (CSS) is described in detail, along with a performance analysis, in Chapter 6. The performance analysis includes the representation of the spatial distribution of droplets and iodine in the containment, as well as drop coalescence and other effects. For the expected case analyses, the CSS is assumed to function with both spray pumps operating, giving an effective elemental DCPP UNITS 1 & 2 FSAR UPDATE 15.5-21 Revision 19 May 2010 iodine removal coefficient of 92 per hour. On the basis of experiments at Battelle, as described in Reference 10, the spray removal rate for organic iodides was assumed to be 0.058 per hour.
For the design basis case, it is assumed that one of the two spray pumps fails to operate, and the elemental iodine removal coefficient is reduced to 31 per hour. This assumption is consistent with the value of 32 per hour used in the PSAR analysis. It has also been assumed, for the design basis case, that the CSS has no effect on the organic and particulate iodines.
Although a subsequent safety evaluation showed that the Design Case coefficient of 31 per hour (for 2600 gpm spray header flow) should be reduced to approximately 29 per hour (for 2466 gpm spray header flow), the potential offsite dose increase due to this change is extremely small and can be considered insignificant (Reference 39). 15.5.17.3 Offsite Exposures from Containment Leakage As a result of the pressurization of the containment following a LOCA, there is a possibility of containment leakage during the time that the containment pressure is above atmospheric. For the design basis case, the leakage rate has been assumed to be 0.1 percent per day for the first 24 hours following the accident, and 0.05 percent per day after the first day. These assumed rates are consistent with the Technical Specifications (Reference 22) limit, the assumed rates considered acceptable in Regulatory Guide 1.4, and the values assumed in the PSAR analyses. For the expected case, the containment leakage rates used are 0.05 percent per day for the first day and 0.025 percent per day for the periods after 1 day. These rates were determined from averages of the actual predicted containment pressures presented in previous sections, with the assumption that some of the heat removal systems do not function at full capacity. In this regard, the leakage rates assumed for the expected case analysis retain some degree of conservatism since the containment heat removal systems are designed to reduce the containment pressure to atmospheric following the initial pressure rise, thus terminating the leakage. The quantities of activity released from the containment to the atmosphere were calculated with the EMERALD digital computer code, which solves the following first order linear differential equation for each isotope. dA(I) = - (I)A(I) (15.5-6) dt where: A(I) = containment inventory of isotope I at any time, Ci (I) = total removal rate of isotope I, hr-1 DCPP UNITS 1 & 2 FSAR UPDATE 15.5-22 Revision 19 May 2010 t = time, hr The total removal rate, (I), is the sum of the rates of reduction of the containment inventory due to natural decay, leakage, and sprays. The code uses values of (I), which are constant for each of the several time periods in a computation. The initial inventories used in this analysis are those listed in Table 11.1-4, reduced by the release fractions discussed earlier. The total activity of each isotope released from the containment for each time period is computed with the relationship: 21)()(),(ttLdtIAITIACT (15.5-7) where:
)T,I(ACT = activity of isotope I released in time t2 - t1, Ci )(IL = containment leak rate, hr-1 A(I) = containment inventory of isotope I at any time, Ci The resulting activity releases are used in the dose subroutines of the EMERALD code to calculate the offsite inhalation, whole body, and population exposures. The total activity released to the atmosphere during each period after the accident is given in Tables 15.5-13 and 15.5-14.
The potential exposures resulting from the releases listed in the above tables are given in Tables 15.5-15 through 15.5-22. These values were calculated with the EMERALD program, using the values of breathing rates, dose conversion factors, and atmospheric dilution factors discussed earlier and listed in Tables 15.5-3, 15.5-4, 15.5-6, and 15.5-7. The site boundary and low population zone exposures are summarized in Table 15.5-23, along with the guideline values from 10 CFR 100. It can be concluded from the values in these tables that all calculated exposures are well below the guideline levels specified in 10 CFR 100. 15.5.17.4 Containment Leakage Exposure Sensitivity Study Sensitivity studies were performed to illustrate the dependence of the thyroid exposures on the spray system removal constant and the fraction of nonremovable iodines present in the containment. The results of these studies are shown in Figures 15.5-6, 15.5-7, and 15.5-8. The thyroid exposures, normalized to the exposure for zero spray removal constant, are shown as a function of spray constant in Figure 15.5-6, for a fixed fraction of nonremovable iodine forms of 15 percent. In Figures 15.5-7 and 15.5-8 thyroid exposures are plotted as a function of two parameters: the spray removal constant and the percent of nonremovable iodines. To determine an absolute exposure (rem) from Figure 15.5-7, the normalized exposure should be multiplied by 940.9 rem, which is the reference 2 hour-800 meter exposure for the design basis case with a zero spray constant and a zero nonremovable fraction. To determine an absolute exposure (rem) DCPP UNITS 1 & 2 FSAR UPDATE 15.5-23 Revision 19 May 2010 from Figure 15.5-8, the normalized exposure should be multiplied by 197.4 rem, which is the reference 30-day-10,000 meter exposure for the design basis case with a zero spray constant and a zero nonremovable fraction. As shown in these figures, combinations of these parameters that result in normalized exposures below the criterion line would result in a calculated absolute exposure less than the 300 rem guideline level specified in 10 CFR 100. 15.5.17.5 Delay of Containment Spray Initiation Calculations also have been done to determine the effects of delay in containment spray initiation upon the offsite radiological doses from post-LOCA containment leakage. These calculations utilized a verified computer code that uses the dose conversion factors implemented in Revision 1 to Regulatory Guide 1.109 (Reference 21). The results of the DBA analysis for the 2-hour thyroid dose at the site boundary were 85.6 rem with no spray delay, and 93.4 rem with a delay in effective spray start time to 81.5 seconds. Both of these values are less than the value of 95.9 rem given in Table 15.5-23, and the latter value remains as a conservative result which is well within the acceptable regulatory criteria of 10 CFR 100. 15.5.17.5.1 Radiological Consequences with Reload Fuel The design basis LOCA was reviewed to evaluate potential differences in the offsite radiological dose consequences with the use of reload fuel having higher initial enrichment and extended burnup than the original design basis.
Calculations were made relative to 10 CFR 100 requirements of the radiological dose consequences from this accident for fuel of maximum initial enrichment of 4.5 percent by weight, which is the design basis for the high density spent fuel storage racks, and for fuel of maximum initial enrichment of 3.5 percent by weight. Each enrichment was evaluated at low fuel burnup of 1,000 MWD/MTU and an extended burnup (50,000 MWD/MTU for 4.5 percent fuel, and 33,000 MWD/MTU for 3.5 percent fuel).
These calculations determined the offsite doses at the site boundary (800 meters) at 2 hours, and the LPZ (10,000 meters) at 30 days, from post-LOCA containment leakage and from post-LOCA recirculation loop leakage (RHR pump seal large leakage case). A containment spray delay of 81.5 seconds was used as discussed in Section 15.5.17.5. The radionuclide inventory source terms for the various fuel conditions were calculated using the ORIGEN-2 computer code with a power level of 3580 MWt. The radionuclide atmospheric releases and offsite doses were calculated with the same LOCADOSE (Reference 47) computer code used for the calculations in Section 15.5.17.5.
Table 15.5-61 presents the calculated offsite dose consequences from post-LOCA containment leakage. The thyroid and whole body gamma doses at the site boundary at 2 hours are significantly larger than the corresponding doses at the LPZ at 30 days. The thyroid doses at high fuel burnups (high relative plutonium inventories) are larger than the corresponding thyroid doses at low fuel burnups. The maximum thyroid dose is 98.6 rem (3.5 percent enrichment at 33,000 MWD/MTU). The whole body gamma DCPP UNITS 1 & 2 FSAR UPDATE 15.5-24 Revision 19 May 2010 doses at low fuel burnups (low relative plutonium inventories) are larger than the corresponding doses at high fuel burnups. The maximum whole body gamma dose is 3.19 rem (4.5 percent enrichment at 1,000 MWD/MTU).
The maximum thyroid dose of 98.6 rem exceeds the original design basis LOCA thyroid dose of 95.9 rem in Table 15.5-23 by less than 3 percent. This increase is within the 5 percent increase estimated for the effects of end of life plutonium inventories on the original LOCA 2-hour thyroid dose, discussed in Section 15.5.3 and listed in Table 15.2-2.
The original design basis LOCA whole body dose of 5.61 rem in Table 15.5-23 is the sum of beta surface body and gamma whole body doses, of which the gamma contribution was 3.69 rem. The maximum whole body gamma dose of 3.19 rem for 4.5 percent enrichment at 1,000 MWD/MTU is less than the original design basis whole body gamma dose. Table 15.5-62 presents the calculated offsite dose consequences from post-LOCA recirculation loop leakage for the design basis RHR pump seal large leakage case described in Section 15.5.17.8 and Table 15.5-24. The largest thyroid and whole body gamma doses are at the site boundary at 2 hours. All doses are within the 10 CFR 100 guidelines. 15.5.17.5.2 Radiological Consequences with DF of 100 The design basis LOCA was reviewed to evaluate potential differences in the offsite radiological dose consequences using a containment decontamination factor of 100 and a containment mixing flowrate of 94,000 cfm. A containment mixing rate of 94,000 cfm corresponds with our current minimum design basis operation of two containment fan cooler units (CFCU). Calculations were based on reload fuel. A containment spray delay of 80 seconds was used. The radionuclide inventory source terms for the various fuel conditions were calculated using the ORIGEN-2 computer code with a power level of 3580 MWt. The radionuclide atmospheric released and offsite doses were calculated with the same LOCADOSE computer code used for the calculations in 15.5.17.5.1.
Calculations were made relative to 10 CFR 100 requirements for offsite doses, at the 800 meter exclusion area boundary (EAB) at 2 hours and the 10,000 meter low population zone (LPZ) at 30 days, from post-LOCA containment leakage.
Table 15.5-75 presents the calculated offsite dose consequences from post-LOCA from various pathways. The limiting doses is the thyroid at the EAB. For the containment leakage pathway, the maximum thyroid dose of 107.06 rem exceeds the original design basis LOCA thyroid dose of 95.9 rem in Table 15.5-23. For the pre-existing small leakage, the EAB thyroid dose is 8.22 rem. These doses are comparable with the corresponding original design basis LOCA large leakage and small leakage cases doses. DCPP UNITS 1 & 2 FSAR UPDATE 15.5-25 Revision 19 May 2010 All doses are within the 10 CFR 100 guidelines. 15.5.17.6 Offsite Exposures from Containment Shine The site boundary 30-day DBA exposure from direct containment gamma radiation (containment shine) is estimated to be 0.0048 rem. Containment shine is a function of the activity present in the containment atmosphere. The EMERALD computer code was used to calculate the postaccident containment activity time-history, and the ISOSHLD II (Reference 11) computer code was then used to calculate the containment shine exposure. The shine exposure model assumes a cylindrical radiation source having the same radius and height as the containment structure with a 3.5-foot-thick concrete shield surrounding it. The site boundary receptor point is assumed to be 800 meters from the containment structure. 15.5.17.7 Offsite Population Exposures from Containment Leakage The calculated population exposures for the design basis case assumptions, and for the expected case, are summarized in Table 15.5-23. These whole body population exposures do not include the effects of any population redistribution due to evacuation. These exposures were calculated using the EMERALD computer code. The atmospheric dilution factors and population distribution utilized in the population exposure calculations are discussed in Section 15.5.4. 15.5.17.8 Offsite Exposures from Post-LOCA Recirculation Loop Leakage in the Auxiliary Building Reactor coolant water that collects in the containment recirculation sump after a LOCA would contain radioactive fission products. Because containment recirculation sump water is circulated outside the containment, problems of potential exposure due to post-LOCA operation of external circulation loops with leakage have been evaluated.
Reactor coolant water, ECCS injection water, and containment spray water accumulate in the containment recirculation sump following a LOCA. Containment recirculation sump water is circulated by the residual heat removal (RHR) pumps, cooled via the RHR heat exchangers, returned to the containment via the RHR system piping and the CSS piping (if recirculation spray is used), passed through the RCS and the containment spray nozzles (if recirculation spray is used), and finally returned to the containment recirculation sump. In the event of circulation loop leakage in the auxiliary building, post-LOCA activity has a pathway to the atmosphere.
An illustration of this pathway for a small leak is given in Figure 15.5-9. For the small leakage situation, fission products in the leakage water are exposed to auxiliary building ventilation air flow for a long period of time. Thus, for the small leakage situation, all activity released to the auxiliary building would be released to the auxiliary building air, i.e., no credit for liquid-gas partitioning. DCPP UNITS 1 & 2 FSAR UPDATE 15.5-26 Revision 19 May 2010 An illustration of post-LOCA activity pathway for a large leak is given in Figure 15.5-10. For the large leakage situation, fission products in the leakage water are exposed to auxiliary building ventilation air flow for a short period of time. Thus, most of the activity released to the auxiliary building would be transferred to the floor drain receiver tank, i.e., credit for liquid-gas partitioning.
The complete RHR system and CSS description, including estimates of leakage, detection of leakage, equipment isolation, and corrective maintenance, are contained in Chapter 6.
The activity released to the atmosphere in the event of post-LOCA recirculation loop leakage in the auxiliary building was evaluated using the EMERALD computer code. The activity released to the atmosphere was calculated in the computer code by the following equation: dtVOLUME3785t)I(e)I(ACxLEAKRATE)I(DFAUXFIL(I))-(1.0ACT(I))2(T)1(T= (15.5-8) where:
ACT(I) = activity of isotope I released to the atmosphere, Ci AC(I) = activity of isotope I released to the containment sump, Ci VOLUME = volume of water in which activity is deposited, gal LEAKRATE = loop leakrate into auxiliary building volume, cc/hr (I) = radiological decay constant for isotope I, hr-1 AUXFIL(I) = auxiliary building filter efficiency for isotope I DF(I) = auxiliary building decontamination factor for isotope I; the ratio of the total amount of isotope I which entered the auxiliary building volume to the amount of isotope I in the auxiliary building atmosphere at the end of the process, gram/gram T(1) = time after LOCA that loop leakage begins, hours T(2) = time after LOCA that loop leakage ends, hours t = time, hours 3785 = cubic centimeters per gallon
The above equation considers radiological decay of the activity in the containment recirculation sump for both the time period prior to loop leakage and the time period during loop leakage. Radiological decay is not considered during the auxiliary building residence time. The above equation also assumes that activity is homogeneously and instantly mixed with containment sump water.
The integral in the above equation yields the total amount of isotope I that entered the auxiliary building volume. To account for liquid-gas partitioning, this total amount of isotope I is divided by the auxiliary building decontamination factor (DF), that is, the ratio DCPP UNITS 1 & 2 FSAR UPDATE 15.5-27 Revision 19 May 2010 of the total amount of isotope I that entered the auxiliary building volume to the amount of isotope I in the auxiliary building atmosphere at the end of the process. The auxiliary building DF can be expressed in terms of the auxiliary building partition factor (PF): PFPFDF1 (15.5-9) where:
DF = auxiliary building decontamination factor for isotope I, gram/gram PF = auxiliary building partition factor for isotope I; the ratio of the amount of isotope I in the gas phase to the amount of isotope I in the liquid phase at the end of the process, gram/gram For small PFs, the DF is approximately equal to the reciprocal of the PF.
The PF for isotope I for a particular process (flashing, evaporation, etc.) can be expressed by: PC1xVVxMMPFliquidvaporliquidvapor (15.5-10) where:
PF = partition factor for isotope I for a particular process, gram/gram vaporM = ratio of the mass vapor to the mass of water liquid at the end of liquidM the process, 1bm/1bm vaporV = ratio of specific volume of water vapor to specific volume of liquidV water liquid at the end of the process, (ft3/ lbm)/(ft3/lbm) PC = equilibrium partition coefficient; the ratio of the concentration of isotope I in the liquid phase to the concentration of isotope I in the gas phase at equilibrium, (grams/l)/(grams/l) This expression assumes that the process duration is long enough and that reaction rates are rapid enough that chemical equilibrium is realized. For iodine isotopes, equilibrium partition coefficients and justification for the assumption of chemical equilibrium are obtainable from Eggleton's calculations (Reference 12). Exposures from radioactive fission products released to the atmosphere can be calculated using the EMERALD computer code. The EMERALD exposure model does not consider radiological decay during atmospheric dispersion.
Post-LOCA auxiliary building loop leakage exposures were calculated for four different leakage cases: DCPP UNITS 1 & 2 FSAR UPDATE 15.5-28 Revision 19 May 2010 (1) Expected small leakage case (2) Expected large leakage case (3) DBA small leakage case (4) DBA large leakage case Assumptions and numerical values used to calculate loop leakage exposures are listed in Table 15.5-24, and thyroid exposures for the four loop leakage cases are listed in Table 15.5-25. Because an insignificant amount of noble gases would be in the containment recirculation sump water, the whole body exposures are negligible.
One possible approach to the evaluation of offsite exposures from post-LOCA recirculation loop leakage would include the following assumptions: (1) A LOCA as an initiating event (2) Failure of two ECCS trains resulting in gross fuel damage: Release of 50 percent of core iodine inventory and 100 percent of core noble gas inventory to the containment (3) Failure of an RHR pump seal, resulting in the release of a significant amount of the above containment activity to the auxiliary building (4) Failure of the passive auxiliary building charcoal filters resulting in the unfiltered release of iodine fission products to the environment The assumption of this sequence of failures for analysis of offsite exposures, however, would be requiring plant design features in excess of the current guides and regulations, and in particular the requirements of ANS Standard N18.2, Nuclear Safety Criteria for the Design of Stationary Pressurized Water Power Plants. (See proposed addendum to ANS Standard N18.2, Single Failure Criteria for Fluid Systems (Reference 16)).
Applying the proposed standard to post-LOCA recirculation loop leakage the LOCA was assumed as the initiating event: "The unit shall be designed to tolerate an initiating event which may be a single active or passive failure in any system intended for use during normal operation." The ECCS was assumed to function properly, as required by the ECCS acceptance criteria, preventing gross fuel damage. Although meeting these criteria is expected to preclude gross cladding damage, it was assumed for this analysis that 100 percent of the gap iodine and noble gas inventories were released to the containment recirculation sump.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-29 Revision 19 May 2010 For the large leakage cases, failure of an RHR pump seal was assumed as the single failure and can be tolerated without loss of the required functioning of the RHR system, as required by the following clauses in the proposed addendum to the ANS Standard N18.2:
"Fluid systems provided to mitigate the consequences of Condition III and Condition IV events shall be designed to tolerate a single failure in addition to the incident which requires their function, without loss of the function to the unit. "A single failure is an occurrence which results in the loss of capability of a component to perform its intended safety functions when called upon. Multiple failures resulting from a single occurrence are considered to be a single failure.
Fluid and electrical systems are considered to be designed against a single failure if neither (a) a single failure of any active component (assuming passive components function properly); nor (b) a single failure of a passive component (assuming active components function properly) results in a loss of the safety function to the nuclear steam electric generating unit. "An active failure is a malfunction, excluding passive failures, of a component which relies on mechanical movement to complete its intended function upon demand. "Examples of active failures include the failure of a valve or a check valve to move to its correct position, or the failure of a pump, fan or diesel generator to start. "Spurious action of a powered component originating within its actuation system shall be regarded as an active failure unless specific design features or operating restrictions preclude such spurious action. "A passive failure is a breach of the fluid pressure boundary or blockage of a process flowpath." For the expected and DBA large leakage cases, the failure of auxiliary building charcoal filters, a second failure, was not assumed, in accordance with the standard.
For the expected and DBA small leakage cases, failure of auxiliary building charcoal filters was assumed as the single failure and can be tolerated without loss of the required function of the auxiliary building ventilation system, which provides cooling for ECCS components. For the long-term small leakage cases, the charcoal filters are not needed to reduce exposures below the guideline values given in 10 CFR 100. In any case, the fans in the ventilation system are redundant, and only the passive charcoal beds themselves are not redundant.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-30 Revision 19 May 2010 For the expected small and large leakage cases, it was assumed that two ECCS trains, five fan coolers, and two containment spray trains functioned. For the DBA small and large leakage cases, it is assumed that two ECCS trains, two fan coolers, and one containment spray train functioned. The DBA assumptions result in high containment recirculation sump water temperatures and minimum containment recirculation sump water pHs.
For all four circulation loop leakage cases it was assumed that 100 percent of the gap iodine inventory was deposited in containment recirculation sump water. For the expected small and large leakage cases, the assumed gap iodine inventories are listed in Table 11.1-7. The expected case gap iodine was assumed to be only elemental iodine. For the DBA small and large leakage cases, the assumed gap iodine inventories are based on release fractions given in Regulatory Guide 1.25 (Reference 23). The DBA case gap iodine was assumed to be 99.75 percent elemental iodine and 0.25 percent organic iodine per Regulatory Guide 1.25.
Radiological decay of activity in the containment recirculation sump was assumed for all leakage cases for both the time periods before and during loop leakage. No credit was taken for cleanup of activity in the containment recirculation sump.
Reactor coolant water, accumulator water, and refueling water storage tank (RWST) water make up the total volume of water in which activity is deposited. Consideration of emergency core cooling injection flowrates and containment spray injection flowrates yields the volume of RWST water (Chapter 6). Table 15.5-24 lists the assumed volume of water in which activity is deposited for the four leakage cases. For the large leakage cases, the volume of diluting water was taken as the volume when the leakage began. No credit was taken for the extra diluting water added from the RWST during the 30-minute leakage period.
Sodium hydroxide spray additive will provide for an increased pH in the containment recirculation sump water. Consideration of emergency core cooling injection flowrates and containment spray injection flowrates yields the pH of the containment recirculation sump water (Chapter 6). Table 15.5-24 lists the assumed pH of recirculation loop leakage water for the four leakage cases. For the large leakage cases, the pH was taken as the pH when the leakage began. No credit was taken for the extra sodium hydroxide in the spray water added during the 30-minute leakage period.
The design evaluation conducted for the containment functional design yields the temperature of containment recirculation sump water as a function of time (Chapter 6). Table 15.5-24 lists the assumed temperature of recirculation loop leakage water for the four leakage cases. For the large leakage cases, the water temperature was taken as the temperature when the leakage began. No credit was taken for the decrease of water temperature during the 30-minute leakage period.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-31 Revision 19 May 2010 A review of the equipment in the RHR system loop and the CSS loop indicates that the largest leakage would result from the failure of an RHR pump seal. Evaluation of RHR pump seal leakage rate, assuming only the presence of a seal retention ring around the pump shaft, shows that flows less than 50 gpm would result (Chapter 6). Circulation loop piping leaks, valve packing leaks, and flange gasket leaks are much smaller and less severe than an RHR pump seal failure leak. Leakage from these components during normal post-LOCA operation of the RHR system loop and the CSS loop is estimated to be 1910 cc/hr (Chapter 6). On this basis, a 50 gpm leakrate was assumed for both the expected large leakage case and the DBA large leakage case, and a 1910 cc/hr leakrate was assumed for both the expected small leakage case and the DBA small leakage case.
For the DBA large leakage case, recirculation loop leakage was assumed to commence 24 hours after the start of the LOCA. This assumption is consistent with the discussion in Sections 3.1.1.1 and 6.3A.3, and with the guidance in Standard Review Plan 15.6.5, Appendix B. In this context, the limiting recirculation loop long term passive failure is 50 gpm leakage at 24 hours after the start of the LOCA. Evaluation of an RHR pump seal failure shows that the failure could be detected and the pump isolated well within 30 minutes (Chapter 6). A leakage duration of 30 minutes is conservatively assumed for both the expected and DBA large leakage cases. A leakage duration of 30 days is assumed for both the expected and DBA small leakage cases. As discussed earlier, the auxiliary building DF is a function of the PF for a particular isotope (Equation 15.5-7).
For both the expected and DBA large leakage cases, it was assumed that leakage water was pumped away to the floor drain receiver tank. Iodine in the leakage water was assumed to be exposed to auxiliary building ventilation air flow for a short period of time (0.05-0.10 hours), and thus, liquid-gas partitioning was assumed for elemental iodine isotopes.
The large leakage case elemental iodine PFs were calculated using the previously presented PF expression. Because the circulation water will be above 212F (Chapter 6), a flashing process must be considered. For heat energy conservation on the basis of 1 lb: xhx)(1h=hgff0 (15.5-11) Rearranging yields fgff0h-hh -hx (15.5-12) where:
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-32 Revision 19 May 2010 hf0 = initial enthalpy of liquid, Btu/lbm hf = final enthalpy of liquid, Btu/lbm hg = final enthalpy of vapor, Btu/lbm x = fraction of initial mass that became vapor The end point of the flashing process is 212F, and thus the final enthalpies are based on this temperature. The mass fraction, x, is the ratio of the final mass of vapor to the total initial mass of water, so the mass ratio at the end of the flashing process becomes: x1xMMliquidvapor (15.5-13) Figures 15.5-11 and 15.5-12 present the expected and DBA large leakage case elemental iodine PFs as a function of both temperature and pH. For small PFs, the DF (see Equation 15.5-7) is approximately equal to the reciprocal of the PF. Figures 15.5-11 and 15.5-12 illustrate that auxiliary building iodine PFs and resulting DFs are relatively insensitive to water temperature, but much more sensitive to pH. Table 15.5-24 lists the assumed temperatures and pHs along with the resulting elemental iodine PFs and auxiliary building decontamination factors for both the expected and DBA large leakage cases.
For both the expected and DBA small leakage cases, it was assumed that leakage water was not pumped away. Elemental iodine in the leakage water was assumed to be exposed to auxiliary building ventilation air flow for a long period of time (100-150 hours), and thus, liquid-gas partitioning for elemental iodine isotopes was not assumed. For the small leakage case all elemental iodine activity released to the auxiliary building was assumed to be released to the auxiliary building atmosphere, i.e., a DF of 1.
Liquid-gas partitioning for organic iodine isotopes was not assumed for any of the four leakage cases. All organic iodine activity released to the auxiliary building was assumed to be released to the auxiliary building atmosphere, i.e., a decontamination factor of 1.
For all four loop leakage cases, no credit was taken for auxiliary building radiological decay or fission product plateout.
For the expected and DBA large cases, credit for auxiliary building charcoal filters was taken, and for the expected and DBA small leakage cases, no credit for auxiliary building charcoal filters was taken (as previously discussed with reference to ANS Standard N18.2 single failure criteria). Table 15.5-24 lists the assumed iodine filter efficiencies for each loop leakage case.
From the calculated DBA case offsite exposures from post-LOCA recirculation loop leakage in the auxiliary building listed in Table 15.5-25, it can be concluded that any DCPP UNITS 1 & 2 FSAR UPDATE 15.5-33 Revision 19 May 2010 exposures that occur via this combination of unlikely events would be well below the guideline levels in 10 CFR 100. In addition, even if no consideration is given to the effectiveness of the auxiliary building charcoal filters for the DBA leakage cases, the calculated exposures would still be below guideline levels specified in 10 CFR 100. Offsite exposures for the expected case are also listed in Table 15.5-25. 15.5.17.8.1 Maximum Allowable Leakage From Post-LOCA Recirculation Loop Calculations have been performed to determine the maximum allowable leakage from recirculation loop components that could occur during post-LOCA recirculation operations before offsite and control room operator design basis radiation doses would exceed regulatory limits. A computer code (LOCADOSE) was used to determine design basis exclusion area boundary (EAB) and low population zone outer boundary (LPZ) offsite radiation doses and control room operator airborne radiation dose from post-LOCA containment leakage, RHR pump seal leakage, and pre-existing leakage from recirculation loop components outside containment. The calculations determined the amount of pre-existing recirculation leakage which could exist before offsite exposures would exceed 10 CFR 100 limits or control room operator exposures would exceed 10 CFR 50, Appendix A, General Design Criterion (GDC) 19 limits, if a LOCA were to simultaneously occur.
Table 15.5-63 shows the results of the calculations based on the above assumptions which determined that the maximum allowable leakage (in addition to the RHR pump seal leakage) from the recirculation loop at post-LOCA conditions of pressure and temperature was 1.85 gpm where the airborne activity is filtered by charcoal filters or 0.186 gpm where the airborne activity is unfiltered. The limitation is the GDC 19 allowable dose of 30 rem for the control room. 15.5.17.9 Offsite Exposures from Controlled Postaccident Containment Venting Because of the potential release of significant amounts of hydrogen to the containment atmosphere following a LOCA, it is necessary to provide means of monitoring and controlling the postaccident concentration of hydrogen in the containment atmosphere. Redundant thermal hydrogen recombiners are the primary means of postaccident hydrogen control. As a backup, controlled containment venting (via the containment hydrogen purge system) with offshore flow, wind directions from northwest through east-southeast measured clockwise, provides hydrogen control with a high probability of no inland exposures. As shown in Table 15.5-26, offshore wind directions occur over 50 percent of the time regardless of the season and, as shown in Table 15.5-27, have a high degree of persistence. The large time period (312 hours for DBA case) between the proposed hydrogen venting level (3.5 v/o) and the hydrogen flammability level (4.0 v/o) is much greater than the longest recorded period (37 consecutive hours) of onshore winds in any 22.5 sector. These data ensure a very high probability that venting can be carried out during the occurrence of offshore winds. Even though there is a high probability that containment venting can be carried out when the wind is blowing offshore, if necessary at all, an evaluation is presented in the DCPP UNITS 1 & 2 FSAR UPDATE 15.5-34 Revision 19 May 2010 following paragraphs to determine potential exposures if venting were carried out during onshore winds.
Chapter 6 contains the analysis of postaccident hydrogen production and accumulation in the containment atmosphere and its control. Containment venting is also described in Section 6.2.5. The purge stream is withdrawn from the containment through one of two penetration lines. The stream is routed through a flow-measuring device, charcoal filters, exhaust fans, the radiation monitors, and finally to the plant vent.
Postaccident containment venting activity releases are calculated with the following equation: dtt)I(e)I(ACxVENRATVOLUME(I)]600.01FILEFF[1.0ACT(I))2(T)1(T (15.5.14) where: ACT(I) = activity of isotope I released to the atmosphere, Ci AC(I) = activity of isotope I released to the containment atmosphere, Ci VOLUME = volume of containment atmosphere, cu ft VENRAT = venting rate, cfm (I) = removal constant for isotope I, hr-1 FILEFF(I) = filter efficiency for isotope I, % T(1) = time after LOCA that containment venting begins, hr T(2) = time after LOCA that containment venting ends, hr t = time, hr 60 = minutes per hr
The above equation considers radiological decay during the time period prior to containment venting and the time period during containment venting. It also assumes that the LOCA activity released to the containment atmosphere is homogeneously dispersed throughout the containment atmospheric volume. Exposures from activity released to the atmosphere were calculated using the EMERALD computer code. EMERALD assumes there is no radiological decay during the atmospheric dispersion. Containment venting exposures were calculated for both the expected case and the DBA case. Assumptions and numerical values used to calculate venting exposures are itemized in Table 15.5-28. Onshore controlled containment venting thyroid and whole body exposures are listed in Table 15.5-29.
Postaccident containment venting schedules are evaluated in Chapter 6. Assuming the venting system will operate an average 2 hours per day, the system flowrates during short venting periods are 120 cfm (expected) and 300 cfm (DBA). Equivalent continuous venting rates, 10 cfm and 25 cfm, were used to calculate venting activity releases.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-35 Revision 19 May 2010 In the event containment venting should be required during periods with onshore flow, the venting would be limited to those periods when Pasquill Stability Category D exists. Therefore, ground-level centerline atmospheric dispersion factors for Pasquill Stability Category D and an elevated release height of 70 meters were evaluated using a conventional Gaussian plume model and are listed in Table 15.5-30. The meteorological input parameters utilized were determined from onsite measurements, given in References 18, 19, and 20. Because an individual is assumed to be located on the plume centerline for the entire venting duration, exposures are centerline exposures and represent worst case conditions. The probability of an individual being located on the plume centerline for a 2-hour period is very small, and thus centerline exposures listed in Table 15.5-29 are very conservative.
During the time period prior to venting, activity released to the containment atmosphere is significantly reduced by both radiological decay and functioning of the safety features systems. The main contributors of radioactivity several hundred hours after the accident are the noble gases: Kr-85, Xe-133, and, to some extent, Xe-131m. Because Kr-85 has a half-life of 10.6 years, the exposures resulting from containment venting would not be significantly reduced if the venting could be further delayed for many months.
It can be concluded from the results presented in Table 15.5-29, along with the consideration of the very high probability of opportunities for offshore venting and the other favorable factors associated with the DCPP design and site, that, as a backup to the internal hydrogen recombiner system, controlled venting using the containment hydrogen purge system is an acceptable contingency method of postaccident hydrogen control for this plant. In addition, it can be concluded that the expected exposures due to venting, even using the assumptions in Regulatory Guide 1.7, will not exceed the annual dose limits of 10 CFR 20. 15.5.17.10 Postaccident Control Room Exposures The design basis for control room ventilation, shielding, and administration is to permit access and occupancy of the control room under accident conditions without personnel receiving radiation exposures in excess of 5 rem whole body, or its equivalent to any part of the body, for the duration of the most severe design basis accident. This basis is consistent with GDC 19.
The control room shielding, described in Chapter 12 is designed to attenuate gamma radiation from postaccident sources to levels consistent with the requirements of GDC 19.
The control room ventilation system is described in Chapter 9. It is designed to limit the concentration of postaccident activity in the control room air to levels consistent with requirements of GDC 19.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-36 Revision 19 May 2010 The control room postaccident administration is described in the DCPP Manual. It is to limit postaccident control room personnel exposures to levels consistent with requirements of GDC 19.
Exposures to control room personnel have been estimated for a design basis LOCA to evaluate the adequacy of the control room shielding, the adequacy of the control room ventilation system, and the adequacy of the control room administration in limiting exposures to the specified limits. Exposures have also been calculated for the expected case LOCA to obtain a more realistic estimate of exposure to control room personnel.
Radiation exposures to personnel in the control room could result from the following sources:
(1) Airborne activity, which infiltrates into the control room (2) Direct gamma radiation to the control room from activity in the containment structure (3) Direct gamma radiation to the control room from activity in the containment leakage plume.
The control room ventilation system is designed to minimize infiltration of postaccident airborne activity into the control room complex. Mode 4 operation of the ventilation system provides zone isolation with filtered positive pressurization and filtered recirculation. Mode 4 operation of the ventilation system is initiated automatically and the least contaminated positive pressurization inlet is selected manually as described in Chapter 9. Both the pressurization and partial recirculation air flow pass through high-efficiency particulate air (HEPA) and charcoal filters.
In addition to positive pressurization, there are vestibules on control room doors that will minimize infiltration. Table 15.5-31 identifies infiltration pathways and flowrates that have been used in the calculation of postaccident control room radiological exposures.
Airborne radiation doses inside the control room were evaluated for a DBA LOCA. Regulatory Guide 1.4 was used to determine activity levels in the containment. Activity releases are based on a containment leakage of 0.1 percent/day for the first day and 0.05 percent/day thereafter.
The containment leakage was assumed to be released unfiltered from the containment building to the atmosphere. Recirculation loop leakages, assumed to be from an RHR pump seal, will pass through charcoal filters and be released to the atmosphere through the main vent at the top of the containment.
Radioactivity from the atmosphere would enter the control room through two pathways:
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-37 Revision 19 May 2010 via the pressurization air intakes through charcoal filters via infiltration of air inleakage The flow rate of pressurization air into the control room is 2100 cfm. The flow rate of recirculated control room air through the charcoal filters is 2100 cfm. Previous analyses had not taken credit for recirculation of control room air. This was an unnecessary conservatism in that a passive failure had already been assumed to occur (RHR pump seal leak) and a second failure is not required.
A 10 CFM inleakage rate per Standard Review Plan, Section 6.4, was conservatively assumed in the analysis due to the possible pathway through the single doors from the equipment condensing unit areas to the HVAC equipment room. Additionally, an assumed 10-second delay in closure of the CRVS outside air isolation dampers results in 2110 cfm of control room infiltration for the first 10 seconds following the design basis LOCA.
Table 15.5-32 presents a summary of the parameters used in the analysis.
The control room shielding is designed to minimize direct gamma radiation (containment shine). Control room exposures resulting from containment shine were estimated using ISOSHLD II. The control room receptor point is 27 feet from the containment structure and protected by an additional 2.5-foot-thick concrete shield. A further contribution to control room direct gamma radiation results from the atmospheric activity cloud external to the control room. Control room exposures resulting from plume shine were estimated using ISOSHLD II. The shine exposure model assumes a parallelepiped radiation source located directly above the control room. The control room receptor point is protected by a 1.5-foot-thick concrete shield.
Radiation exposures to personnel during egress and ingress could result from the following sources:
(1) Airborne activity in the containment leakage plume (2) Direct gamma radiation from fission products in the containment structure Postaccident egress-ingress exposures are based on 27 outbound excursions, from the control room to the site boundary, and 26 inbound excursions, from the site boundary to the control room. It was estimated that each excursion would take 5 minutes, and no credit was taken for breathing apparatus or special whole body shielding.
Egress-ingress thyroid and whole body exposures from airborne activity are functions of containment activity, containment leakage, atmospheric dispersion, and excursion time. The EMERALD computer code was used to calculate the airborne activity concentrations, and then conventional exposure equations were used to calculate gamma, beta, and thyroid exposures (Reference 6). The exposure from betas is DCPP UNITS 1 & 2 FSAR UPDATE 15.5-38 Revision 19 May 2010 calculated on the basis of an infinite uniform cloud, and exposure from gammas is calculated on the basis of a semi-infinite cloud.
Because of the containment shielding and short excursion time, egress-ingress containment shine exposures are small. Egress-ingress containment shine exposures were calculated using ISOSHLD-II. The shine model assumes a cylindrical radiation source having the same radius and height as the containment structure with a 3.5-foot-thick concrete shield surrounding it. The receptor point is assumed to be a distance of 10 meters.
Estimates of postaccident control room exposures and egress-ingress exposures are listed in Table 15.5-33. The sum of the DBA case exposures are within the specified criteria, and the expected case exposures demonstrate the conservatism of the DBA case exposures. 15.5.17.11 Summary and Conclusions In the preceding sections, the potential exposures from a major primary system pipe rupture have been calculated for various possible mechanisms:
(1) Containment leakage (2) RHR recirculation loop leakage (3) Controlled postaccident containment venting (4) Containment shine The analyses have been carried out using the models and assumptions specified in regulations 10 CFR 100, 10 CFR 50, and the regulatory guides. In all analyses, the resulting potential exposures to plant personnel, to individual members of the public, and to the general population have been found to be lower than the applicable guidelines and limits specified in 10 CFR 100, 10 CFR 50, and 10 CFR 20.
Consequently, the occurrence of a major pipe rupture in the primary system of a DCPP unit would not constitute an undue risk to the health and safety of the public. In addition, the ESF provided for the mitigation of the consequences of a LOCA are adequately designed. 15.5.18 ENVIRONMENTAL CONSEQUENCES OF A MAJOR STEAM PIPE RUPTURE As reported in Section 15.4.2, a major steam line rupture is not expected to cause cladding damage, and thus no release of fission products to the coolant is expected following this accident. If significant radioactivity exists in the secondary system prior to the accident, however, some of this activity will be released to the environment with the steam escaping from the pipe rupture. In addition, if an atmospheric steam dump from DCPP UNITS 1 & 2 FSAR UPDATE 15.5-39 Revision 19 May 2010 the unaffected steam generators is necessitated by unavailability of condenser capacity, additional activity will be released. Section 15.5.18.1 discusses the main steam line break (MSLB) dose analysis of record which is based on the OSGs. The OSG MSLB dose analysis is bounding for the RSGs as discussed in the following section. (See Table 6.4.2-1 of Reference 49 for a summary of OSG and RSG MSLB steam releases.) 15.5.18.1 Radiological Assessment for Accident-Induced Leakage Because tubes in the faulted steam generator encounter a higher differential pressure during steam line rupture conditions than normal operating conditions, there is a potential for primary-to-secondary leakage in degraded tubing to increase to a rate that is higher than that during normal operation. This leakage is referred to as accident-induced leakage. This section provides the updated licensing basis description and radiological consequence analysis for a major steam line rupture analysis using an accident-induced leak rate of 10.5 gpm (at room temperature conditions), which is higher than the operational leakage limit in the Technical Specifications. The NRC approved this analysis in a letter to PG&E dated February 20, 2003, "Issuance of Amendment: RE: Revision to Technical Specification 1.1, 'Definitions, Dose Equivalent I-131,' and Revised Steam Generator Tube Rupture and Main Steam Line Break Analyses." Application of this accident-induced leak rate is governed by SG Program accident-induced leakage performance criteria documented in the Technical Specifications.
The methodology selected for performing the radiological assessment follows NRC Standard Review Plan (SRP) 15.1.5, "Steam System Piping Failures Inside and Outside of Containment (PWR)," Revision 2, 1981. Using an accident-induced leak rate of 10.5 gpm (at room temperature conditions) in the faulted SG, calculations using the LOCADOSE computer program demonstrate that the offsite doses are within 10 percent of 10 CFR 100 limits and control room doses are within GDC 19 limits.
The resultant doses from the MSLB event using an accident-induced leak rate of 10.5 gpm are listed below. The limiting case is the accident initiated iodine spike as the thyroid dose at the Exclusion Area Boundary (EAB) is at the 30 rem limit.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-40 Revision 19 May 2010 Dose (rem) Location Thyroid CDE Beta Skin SDE Whole Body DDE Case 1: Accident-Initiated Spike EAB (0-2 hr) 30.0 1.50E-1 9.40E-2 LPZ (30 days) 6.49 1.92E-2 1.18E-2 Dose Limit (10% of 10 CFR 100) 30.0 2.5 2.5 Control Room (30 days) 6.68E-1 7.10E-3 1.50E-4 Dose Limit (GDC 19) 30.0 5 5 Case 2: Pre-Existing Spike EAB (0-2 hr) 46.4 1.37E-1 8.26E-2 LPZ (30 days) 3.69 9.70E-3 5.72E-3 Dose Limit (10 CFR 100) 300 25 25 Control Room (30 days) 4.61E-1 5.56E-3 1.10E-4 Dose Limit (GDC 19) 30 5 5 The input parameters for the dose analysis are summarized below. (1) The operational (pre-MSLB) primary-to-secondary leak rate was assumed to be 1 gpm to yield a conservatively high isotopic concentration in the secondary system. Use of 1 gpm is more conservative than the Technical Specifications operational leak rate limit of 150 gpd per SG. (2) During the accident, the primary-to-secondary leak rate in the faulted steam generator is assumed at the maximum rate of 10.5 gpm. The primary-to-secondary leak rate in each intact SG was assumed to be at the Technical Specifications operational leak rate limit of 150 gpd; therefore, the total leakage is 450 gpd. (3) The MSLB occurred in the section of piping between the containment building and the main steam line isolation valves (MSIVs). Prior to control room isolation and pressurization, the control HVAC intake /Q is the unfiltered /Q taken from the LOCA condition outside containment. (4) Loss of offsite power is assumed to occur coincident with MSLB accident. (5) Conservatively, based on the Technical Specifications requirements for the safety injection signal and containment Phase A isolation, the control room will be isolated well within 35 seconds. To add more conservatism in this calculation, the control room is assumed to be isolated in 2 minutes. (6) All releases were assumed to end after 8 hours, when the plant is placed on the residual heat removal (RHR) system. DCPP UNITS 1 & 2 FSAR UPDATE 15.5-41 Revision 19 May 2010 (7) For a pre-existing iodine spike, the activity in the reactor coolant is based upon an iodine spike that has raised the reactor coolant concentration to 60 Ci/g of I-131 DEC, based on the Technical Specifications. The secondary coolant activity is 0.1 Ci/g of I-131 DEC, based on the Technical Specifications. Noble gas activity is based on 651 Ci/g of Xe-133 DEC associated with 1 percent failed fuel, which bounds the value in the Technical Specifications. The calculation of Xe-133 DEC ignores the contribution from Kr-83m, Kr-85, Kr-89, Xe-131m, and Xe-137 due to low concentration, short half life, or small dose conversion factor. (8) For an accident-initiated (concurrent) iodine spike, the accident initiates an iodine spike in the reactor coolant system (RCS) that increases the iodine release rate from the fuel to a value 500 times greater than the release rate corresponding to an RCS concentration of 1 Ci/g of I-131 DEC. The 1 Ci/g I-131 DEC is based on the Technical Specifications. The iodine activity released to the RCS for the duration of the accident is conservatively assumed to mix instantaneously and uniformly in the RCS. Noble gas activity is based on 651 Ci/g of Xe-133 DEC associated with 1 percent failed fuel, which bounds the value in the Technical Specifications. To maximize the accident-initiated iodine spiking, a RCS letdown rate of 143 gpm with 100 percent iodine removal through the filters in the demineralizers is assumed. (9) The thyroid dose conversion factors are based on International Commission on Radiological Protection Publication 30 (Reference 21) as documented in Federal Guidance Report (FGR) 11 and FGR 12 (References 41 and 42). The noble gas whole body dose conversion factors are based on those documented in FGR 12, Table III.1. I-131 1.08E+06 (Rem/Ci) I-132 6.44E+03 (Rem/Ci} I-133 1.80E+05 (Rem/Ci} I-134 1.07E+03 (Rem/Ci} I-135 3.13E+04 (Rem/Ci} Kr-85m 7.48E-15 (sv m3/bq s) Kr-87 4.12E-14 (sv m3/bq s) Kr-88 1.02E-13 (sv m3/bq s) Xe-133m 1.37E-15 (sv m3/bq s) Xe-133 1.56E-15 (sv m3/bq s) Xe-135m 2.04E-14 (sv m3/bq s) Xe-135 1.19E-14 (sv m3/bq s) Xe-138 5.77E-14 (sv m3/bq s) DCPP UNITS 1 & 2 FSAR UPDATE 15.5-42 Revision 19 May 2010 (10) Following the pipe rupture, auxiliary feedwater to the faulted loop is isolated and the SG is allowed to steam dry. The iodine partition factor for the faulted SG is assumed to be 1.0. Also, the iodine partition factor for the intact SG is conservatively assumed to be 1.0; i.e., no credit is taken for iodine partition. (11) All activity in the SGs is released to the atmosphere in accordance with the release rates in Table 15.5-34, with added releases from primary-to-secondary leaks in the faulted loop and intact loops. Atmospheric steam releases (not including primary-to-secondary leaks): Ruptured loop 162,784 lb at 45.0 lb/ft3 (0-2 hr) 0 lb (2-8 hr) Intact loops 393,464 lb at 45.0 lb/ft3 (0-2hr) 915,000 lb at 50.0 lb/ft3 (2-8 hr) The above steam releases are for the OSG MSLB. The RSG MSLB steam releases are shown in Table 15.5-34. As noted above, the limiting dose for MSLB is the EAB thyroid dose for the accident initiated iodine spike case and is based on steam releases in the first two hours of the accident. The OSG MSLB dose calculation assumes an accident-induced SG tube leak rate of 10.5 gpm using the Alternate Repair Criteria (ARC) methodology. The RSGs can not credit ARC and are required to maintain a much lower assumed SG tube leakage subsequent to a MSLB. Note that although the zero to two hour RSG ruptured loop release of 171,100 Ib is slightly greater than the equivalent OSG release of 162,784 Ib, the OSG MSLB dose analysis bounds the RSG MSLB releases since the assumed ARC tube leakage impact on dose is the dominant factor in the assessment of post-accident radiological consequences. (12) The source term is based on a composite source term of 3.5 percent and 4.5 percent fuel enrichment. An evaluation has been performed and concluded that the current source term bounds the 5 percent enrichment fuel up to 50,000 MWD/MTU for a 21-month operating cycle. (13) Atmospheric Dispersion Factors (sec/m3) (Reference Tables 15.5-3 and 15.5-6) DCPP UNITS 1 & 2 FSAR UPDATE 15.5-43 Revision 19 May 2010 Time EAB LPZ Control Room Pressurized Infiltration 0-2 hr 5.29E-4 2.20E-5 7.05E-5 1.96E-4 2-8 hr 2.20E-5 7.05E-5 1.96E-4 8-24 hr 4.75E-6 5.38E-5 1.49E-4 24-96 hr 1.54E-6 3.91E-5 1.08E-4 96-720 hr 3.40E-7 2.27E-5 6.29E-5 (14) Control Room HVAC Flow Rates and Filtration Efficiencies: Filtered Intake Flow 2100 cfm Unfiltered Intake Flow 10 cfm (2110 cfm for t=0 to 10 sec.) Exhaust Flow 2110 cfm Filtered Recirculation Flow 2100 cfm Charcoal Filter Iodine Removal Efficiency Elemental 95% Organic 95% Particulate 95% (15) RCS and Secondary Water Volume and Water Mass RCS water volume 94,000 gallons RCS water mass 566,000 pounds Water in SGs 6735.54 ft3 at 45.0 lb/ft3 (0-2 hr) and 50.0 lb/ft3 (2-8 hr) Loop 1 1683.88 ft3 Loops 2, 3, 4 5051.65 ft3 Water in Condensers 27243.59 ft3 at 62.4 lb/ft3 Water in SGs and Condensers 33979.13 ft3 15.5.19 ENVIRONMENTAL CONSEQUENCES OF A MAJOR RUPTURE OF A MAIN FEEDWATER PIPE As reported in Section 15.4.2, a major feedwater line rupture is not expected to cause cladding damage, and thus no release of fission products to the coolant is expected following this accident. If significant radioactivity exists in the secondary system prior to the accident, however, some of this activity will be released to the environment with the feedwater escaping from the pipe rupture. In addition, if an atmospheric steam dump from the unaffected steam generators is necessitated by unavailability of condenser capacity, additional activity will be released. As discussed in Section 15.5.10, about 1.7E+06 lbm of secondary coolant is the limiting Condition II event release expected for a full cooldown without any condenser availability.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-44 Revision 19 May 2010 The radiological consequences of about 1.7E+06 lbm of secondary coolant release has been discussed in Section 15.5.10. It can be concluded that potential exposures from major feedwater line ruptures will be well below the guideline levels specified in 10 CFR 100, and that the occurrence of such ruptures would not result in undue risk to the public. 15.5.20 ENVIRONMENTAL CONSEQUENCES OF A STEAM GENERATOR TUBE RUPTURE (SGTR) The SGTR accident is reanalyzed for RSGs and is discussed in Section 15.4.3, and the thermal and hydraulic analysis presented in Section 15.4.3.3 provides the basis for the evaluation of radiological consequences discussed in this section. 15.5.20.1 Offsite Exposures The evaluation of the radiological consequences of a steam generator tube rupture event assumes that the reactor has been operating at the maximum allowable Technical Specification (Reference 22) limits for primary coolant activity and 1 gpm primary to secondary leakage for sufficient time to establish equilibrium concentrations of radionuclides in the reactor coolant and in the secondary coolant. Radionuclides from the primary coolant enter the steam generator via the ruptured tube and primary to secondary leakage, and are released to the atmosphere through the steam generator PORVs (and safety valves) and via the condenser air ejector exhaust.
The quantity of radioactivity released to the environment, due to an SGTR, depends upon primary and secondary coolant activity, iodine spiking effects, primary to secondary break flow flashing fractions, attenuation of iodine carried by the flashed portion of the break flow, partitioning of iodine between the liquid and steam phases, the mass of fluid released from the generator, and liquid-vapor partitioning in the turbine condenser hot well. (1) Design Basis Analytical Assumptions The major assumptions and parameters used in the analysis are itemized in Table 15.5-64. (2) Source Term Calculations The radionuclide concentrations in the primary and secondary system, prior to and following the SGTR are determined as follows: (a) The iodine concentrations in the reactor coolant will be based upon preaccident and accident initiated iodine spikes. (i) Accident Initiated Spike - The initial primary coolant iodine concentration is 1 Ci/gm of Dose Equivalent (DE) I-131. DCPP UNITS 1 & 2 FSAR UPDATE 15.5-45 Revision 19 May 2010 Following the primary system depressurization associated with the SGTR, an iodine spike is initiated in the primary system which increases the iodine release rate from the fuel to the coolant to a value 335 times greater than the release rate corresponding to the initial primary system iodine concentration. The initial appearance rate can be written as follows: Pi = Ai i (15.5-15) where: Pi = Equilibrium appearance rate for iodine nuclide i Ai = equilibrium RCS inventory of iodine nuclide i corresponding to 1 Ci/gm of DE I-131 i = removal coefficient for iodine nuclide i (j) Preaccident Spike - A reactor transient has occurred prior to the SGTR and has raised the primary coolant iodine concentration from 1 to 60 Ci/gram of DE I-131. (b) The initial secondary coolant iodine concentration is 0.1 Ci/gram of DE I-131. (c) The chemical form of iodine in the primary and secondary coolant is assumed to be elemental. (d) The initial noble gas concentrations in the reactor coolant are based upon 651 Ci/g of Xe-133 DEC for the noble gasses Kr-85m, Kr-87, Kr-88, Xe-133, Xe-133m, Xe-135m, Xe-135, and Xe-138, using noble gas whole body dose conversion factors documented in FGR 12 (Reference 42) Table III.1, associated with 1 percent fuel defects. The calculation of Xe-133 DEC ignores the contribution from Kr-85 and Xe-131m due to low concentration and small dose conversion factor. (3) Radioactivity Transport Analysis The iodine transport analysis considers break flow flashing, steaming, and partitioning. The analysis assumes that a fraction of the iodine carried by the break flow becomes airborne immediately due to flashing and atomization. The analysis conservatively took no credit for scrubbing of iodine contained in the atomized coolant droplets. The fraction of primary coolant iodine which is not assumed to become airborne immediately mixes with the secondary water and is assumed to become airborne at a rate proportional to the steaming rate and the iodine partition coefficient. DCPP UNITS 1 & 2 FSAR UPDATE 15.5-46 Revision 19 May 2010 This analysis conservatively assumes an iodine partition coefficient of 100 between the steam generator liquid and steam phases. Droplet removal by the dryers is conservatively assumed to be negligible. The following assumptions and parameters were used to calculate the activity released to the atmosphere and the offsite doses following a SGTR. (a) The mass of reactor coolant discharged into the secondary system through the rupture and the mass of steam released from the ruptured and intact steam generators to the atmosphere are presented in Table 15.4-14. (b) The mass of break flow that flashes to steam and is immediately released to the environment is contained in Table 15.4-14 and is presented in Figure 15.4.3-11. The break flow flashing fraction was conservatively calculated assuming that 100 percent of the break flow is from the hot leg side of the steam generator, whereas the break flow actually consists of flow from both the hot leg and cold leg sides of the steam generator. (c) No iodine scrubbing is credited in the analysis and the iodine scrubbing efficiency is assumed to be 0 percent. Thus the location of the tube rupture is not significant for the radiological consequences. However, as discussed in Section 15.4.3.3, in the thermal and hydraulic analysis the tube rupture break flow is calculated conservatively assuming that the break is at the top of the tube sheet. (d) The rupture (or leakage) site is assumed to be always covered with secondary water based on Reference 33, which concluded the effect of tube uncovery is essentially negligible for the radiological consequences for the limiting SGTR transient. (e) The total primary to secondary leak rate for the 3 intact steam generators is assumed to be 1.0 gpm. The leakage to the intact steam generators is assumed to persist for the duration of the accident. (f) The iodine partition coefficient between the liquid and steam of the ruptured steam generator is assumed to be 100 for non-flashed flow and 1 for flashed flow. The iodine partition coefficient between the liquid and steam of the intact steam generator is assumed to be 100. DCPP UNITS 1 & 2 FSAR UPDATE 15.5-47 Revision 19 May 2010 (g) No credit was taken for radioactive decay during release and transport, or for cloud depletion by ground deposition during transport to the site boundary or outer boundary of the low population zone. (h) Short-term atmospheric dispersion factors (/Qs) for accident analysis and breathing rates are provided in Table 15.5-68. The breathing rates were obtained from NRC Regulatory Guide 1.4 (Reference 35). (i) The noble gases in the break flow and primary to secondary leakage are assumed to be transferred instantly out of the steam generator to the atmosphere. The whole body gamma doses are calculated combining the dose from the released noble gases with the dose from the iodine releases. (j) For the accident initiated iodine spike case, an iodine spiking factor of 335, obtained from Regulatory Guide 1.195 (Reference 44) is assumed. For conservatism, an iodine spiking factor of 500, obtained from the Standard Review Plan (SRP), Section 15.6.3, (Reference 37) is assumed for the accident initiated iodine spike low population zone thyroid dose calculation.) (4) Offsite Dose Calculation In equations 15.5-17 and 15.5-18, no credit is taken for a cloud depletion by ground deposition or by radioactive decay during transport to the exclusion area boundary or to the outer boundary of the low population zone. Offsite thyroid doses are calculated using the equation:
ijj)Q/(j)BR(ij)IAR(iDCFThD (15.5-17) where: ij)IAR( = integrated activity of iodine nuclide i released during the time interval j in Ci j)BR( = breathing rate during time interval j in meter3/ second (Table 15.5-68) j)Q/( = atmospheric dispersion factor during time interval j in seconds/meter3 (Table 15.5-68) DCPP UNITS 1 & 2 FSAR UPDATE 15.5-48 Revision 19 May 2010 iDCF = thyroid dose conversion factor via inhalation for iodine nuclide i in rem/Ci (Table 15.5-69) ThD = thyroid dose via inhalation in rem Offsite whole-body gamma doses are calculated using the equation:
ijj)Q/(ij)IAR(iE25.0D (15.5-18) where: ij)IAR( = integrated activity of noble gas nuclide i released during time interval j in Ci j)Q/( = atmospheric dispersion factor during time interval j in seconds/m3 iE = average gamma energy for noble gas nuclide i in MeV/dis (Table 15.5-70) D = whole body gamma dose due to immersion in rem (5) Offsite Dose Results Thyroid and whole-body gamma doses at the Exclusion Area Boundary and the outer boundary of the Low Population Zone are presented in Table 15.5-71. All of these RSG doses are within the allowable guidelines as specified by the SRP, Section 15.6.3, Revision 2. The SGTR dose analysis of record is based on the OSGs and all doses are within 10 CFR 100 limits. The limiting dose for this analysis is the EAB zero to two hour thyroid dose of 30.5 rem for the accident initiated iodine spike analysis case. This dose exceeds the SRP 15.6.3 allowable guideline value of 30 rem by 0.5 rem. However, the NRC found the 30.5 rem value acceptable in a letter to PG&E, dated February 20,2003, "Issuance of Amendment: RE: Revision to Technical Specification 1.1, 'Definitions, Dose Equivalent 1-131,' and Revised Steam Generator Tube Rupture and Main Steam Line Break Analyses." 15.5.20.2 Control Room Exposures Additional analyses were performed to determine the airborne doses to the control room operators from an SGTR. These calculations used the atmospheric releases of radioactivity determined in the analysis discussed in Section 15.5.20.1 and Reference 46. The control room is modeled as a discrete volume. The atmospheric dispersion factors calculated for the transfer of activity to the control room intake DCPP UNITS 1 & 2 FSAR UPDATE 15.5-49 Revision 19 May 2010 contained in Table 15.5-68 are used to determine the activity available at the control room intake. The inflow (filtered and unfiltered) to the control room and the control room filtered recirculation flow are used to calculate the concentration of activity in the control room. Control room parameters used in the analysis are presented in Table 15.5-72. The control room occupancy factors assumed were taken from Table 15.5-32.
Thyroid, whole body gamma, and beta skin doses are calculated for 30 days in the control room. Although all releases are terminated when the RHR system is put in service, the calculation is continued to account for additional doses due to continued occupancy.
The total primary to secondary leak rate is assumed to be 1.0 gpm. The leakage to the intact steam generators is assumed to persist for the duration of the accident.
The calculations determine the thyroid doses based on a pre-accident iodine spike and based on an accident initiated iodine spike with a spiking factor of 335. Both spike assumptions consider 0.1 Ci/gm D.E. I-131 secondary activity. The whole body doses are calculated combining the dose from the released noble gases with the dose from the iodine releases. Control room thyroid doses are calculated using the following equation: ijjijiThBR*ConcDCFD (15.5-19) where: DTh = thyroid dose via inhalation (Rem) DCFi = thyroid dose conversion factor via inhalation for isotope i (Rem/Ci) (Table 15.5-69) Concij = concentration in the control room of isotope i, during time interval j, calculated dependent upon inleakage, filtered recirculation and filtered inflow (Ci-sec/m3) (BR)j = breathing rate during time interval j (m3/sec) (Table 15.5-68) DCPP UNITS 1 & 2 FSAR UPDATE 15.5-50 Revision 19 May 2010 Control room whole body doses are calculated using the following equation: ijijiWBConcE*GF1*25.0D (15.5-20) where:
DWB = whole body dose via cloud immersion (Rem) GF = geometry factor, calculated based on Reference 17, using the equation 0.338V1173GF where V is the control room volume in ft3 Ei = average gamma disintegration energy for isotope i (Mev/dis) (Table 15.5-70) Concij = concentration in the control room of isotope i, during time interval j, calculated dependent upon inleakage, filtered recirculation and filtered inflow (Ci-sec/m3) Control room skin doses are calculated using the following equation: ijijiConcE*23.0D (15.5-21) where D = whole body dose via cloud immersion (Rem) Ei = average beta disintegration energy for isotope i (Mev/dis) (Table 15.5-70) Concij = concentration in the control room of isotope i, during time interval j, calculated dependent upon inleakage, filtered recirculation and filtered inflow (Ci-sec/m3) Table 15.5-74 presents the resulting airborne doses to the control room operators. The resultant doses are well below the guidelines of GDC 19, and are below the corresponding post-LOCA control room exposures presented in Table 15.5-33. 15.5.21 ENVIRONMENTAL CONSEQUENCES OF A LOCKED ROTOR ACCIDENT As reported in Section 15.4.4, under adverse circumstances, a locked rotor accident could cause small amounts of fuel cladding failure in the core. If this occurs, some fission products will enter the coolant and will mostly remain in the coolant until cleaned up by the primary coolant demineralizers, or in the case of noble gases, until stripped from the coolant. Following such an incident, there are several possible modes of release of some of this activity to the environment. DCPP UNITS 1 & 2 FSAR UPDATE 15.5-51 Revision 19 May 2010 In the short-term, if the accident occurs at a time when significant primary-to-secondary leakage exists, some of the additional activity entering the coolant will leak into the secondary system. The noble gases will be discharged to the atmosphere via the air ejectors or by way of atmospheric steam dump. The iodines will remain mostly in the liquid form and be picked up by the blowdown treatment system. Some fraction of the iodines, however, will be released via the air ejectors or by way of atmospheric steam dump. In addition, if an atmospheric steam dump is necessary, some of the activity contained in the secondary system prior to the accident will be released.
The amounts of steam released depend on the time relief valves remain open and the availability of condenser bypass cooling capacity. The amounts of radioactive iodine released depend on the amounts of steam released, the amount of activity contained in the secondary system prior to the accident, and the amount contained in the primary coolant which leaks into the secondary system. As discussed in Section 15.5.10, the amount of steam released following the locked rotor accident, if no condenser cooling is available, would not exceed approximately 1.7E+06 Ibm. In the analysis of both the design basis case and the expected case, this amount of steam was assumed to be released.
For the design basis case, it was assumed that the plant had been operating continuously with 1 percent fuel cladding defects and 1 gpm primary-to-secondary leakage. For the expected case calculation, operation at 0.2 percent defects and 20 gallons per day to the secondary was assumed. In both cases, leakage of water from primary to secondary was assumed to continue during cooldown at 75 percent of the preaccident rate during the first 2 hours and at 50 percent of the preaccident rate during the next 6 hours. These values were derived from primary-to-secondary pressure differentials during cooldown. It was also conservatively assumed for both cases that the iodine PF in the steam generators releasing steam was 0.01 on a mass basis (Reference 15). In addition, to account for the effect of iodine spiking, fuel escape rate coefficients for iodines of 30 times the normal operation values given in Table 11.1-9 were used for a period of 8 hours following the start of the accident. Other detailed and less significant modeling assumptions are presented in Reference 4.
The assumptions used for meteorology, breathing rates, population density and other common factors were also described earlier. Both the primary and secondary coolant activities prior to the accident are discussed in Section 15.5.2.
In order to determine the primary coolant activities immediately after the accident, it was assumed that less than 10 percent of the total activity contained in the fuel rod gaps would be immediately released to the coolant and mixed uniformly in the coolant system volume. The gap inventories used are listed in Table 11.1-7.
All of the data and assumptions listed above were used with the EMERALD computer program to calculate the activity releases and potential doses following the accident. The calculated activity releases are listed in Table 15.5-41. The potential doses are given in Table 15.5-42. The exposures are also shown in Figures 15.5-14 and 15.5-15 DCPP UNITS 1 & 2 FSAR UPDATE 15.5-52 Revision 19 May 2010 as a function of the amount of fuel failure that occurs. On the left boundary of these graphs, in the region of negligible fuel failures, the exposures are just the component resulting from the activity already present in the secondary system, or which leaks through the steam generators at preaccident primary coolant levels. These exposures correspond to those shown in Figures 15.5-2 through 15.5-5.
Another mode of release following a locked rotor accident, or any accident involving significant fuel failure, is the long-term release by way of cleanup and leakage from the primary coolant system. The activity going through these pathways, principally Kr-85, would result in some incremental long-term dose beyond the normal yearly releases. This pathway of release has been evaluated, and the results are presented in Figure 15.5-16. Since the activity released in this way would reach the environment over a long term, the annual average atmospheric dilution factors (Table 15.5-5) and breathing rates have been used. The amounts of activity released were determined by multiplying the activities released from the gaps following the accident by the release fractions listed in Table 15.5-40.
These long-term release fractions were determined from the normal radioactivity transport analysis carried out for Chapter 11, for the anticipated operational occurrences case. In essence, these fractions are the fractions of a curie reaching the environment per curie released to the coolant, for each isotope. The pathways included are primary cleanup, leakage to the containment, and leakage to the auxiliary building. As shown in Table 15.5-40, essentially all of the Kr-85 released to the coolant is eventually released to the environment, as would be physically expected, and lower fractions of the other isotopes are released, depending on their respective overall cleanup, leakage, and decay factors in the plant. It can be concluded by comparing these exposures to the short-term exposures in Figure 15.5-12 that the incremental long-term exposures are negligible additions to the radiological consequences of accidents of this kind.
In addition, it can be concluded that accidents of this kind would not result in significant additions to the annual doses expected from normal plant operation.
From these short-term and long-term analyses, it can also be concluded that all potential exposures from a locked rotor accident will be well below the guideline levels specified in 10 CFR 100, and that the occurrence of such accidents would not result in undue risk to the public. A detailed evaluation of potential exposures to control room personnel was made in Section 15.5.17, for conditions following a LOCA. The containment shine contribution to control room dose would not be applicable following a locked rotor accident. By comparing the activity releases following a locked rotor accident, given in Table 15.5-41, with the activity releases calculated for a LOCA, given in Tables 15.5-13 and 15.5-14, it can be concluded that any control room exposures following a locked rotor accident will be well below the GDC 19 criterion level.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-53 Revision 19 May 2010 15.5.22 ENVIRONMENTAL CONSEQUENCES OF A FUEL HANDLING ACCIDENT The procedures used in handling fuel in the containment and fuel handling area are described in detail in Section 15.4.5. In addition, design and procedural measures provided to prevent fuel handling accidents are also described in that section, along with a discussion of past experience in fuel handling operations. The basic events that could be involved in a fuel handling accident are discussed in that section, and the following discussion evaluates the potential environmental consequences of such an accident. 15.5.22.1 Fuel Handling Accident In The Fuel Handling Area The radiological consequences of a fuel handling accident in the fuel handling area were analyzed using the LOCADOSE computer code.
The values assumed for individual fission product inventories are calculated for a source term assuming approximately 105 percent full power operation (3580 Mw thermal) immediately preceding shutdown. The accident is assumed to occur 100 hours after shutdown. This latter interval represents approximately the minimum time required to prepare (cooldown, head and internals removal, cavity flooding, etc.) the core for refueling and is therefore somewhat conservative in that it would require that the accident occur during handling of the first few fuel assemblies.
The source term is conservatively assumed to be a composite of the highest fission product activity totals for various combinations of burnup and enrichment. The ORIGEN-2 computer code was used to calculate these worst-case fission product inventories. The DBA gap activity inventory is based on NRC Regulatory Guide 1.25 assumptions: radial peaking factor of 1.65, gap fraction of 10 percent for noble gases other than Kr-85, gap fraction of 30 percent for Kr-85, and gap fraction of 10 percent for iodines.
The assumption is made for both cases that 100 percent of the activity (consisting principally of fission product isotopes of the elements xenon, krypton, and iodine) present in the gap between the fuel pellets and the cladding in the damaged rods is immediately released to the pool or cavity water. This assumption is conservative for elemental iodine because the low cladding and gap temperatures would result in a large fraction of it being condensed and temporarily retained within the cladding.
The analysis assumes that the fission product release occurs at a water depth of 23 feet, which is the minimum water depth above the top of the fuel as required by Technical Specifications. The spent fuel pool, where handling operations are most likely to result in fuel damage, has a water depth of about 38 feet. Using a depth of 23 feet accounts for cases in which the release occurs from the top of an assembly that is resting vertically on the floor, and for releases that occur near the top of the storage racks. Finally, consistent with Regulatory Guide 1.25, the analysis assumes that all activity that escapes from the pool to the fuel handling area air spaces is released from the area within a 2-hour time period.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-54 Revision 19 May 2010 Of the activity reaching the water, 100 percent of the noble gases, xenon and krypton, are assumed to be immediately released to the fuel handling area air spaces. However, the ability of the pool water to scrub iodine from the gas bubbles as they rise to the surface has been considered. The pool DFs for the inorganic and organic species are 500 and 1, respectively, giving an overall effective DF of 200 (i.e., 99.5 percent of the total released from the damaged rods is retained by the pool water). This difference in DFs for inorganic and organic iodine species results in the iodine above the fuel pool being composed of 75 percent inorganic and 25 percent organic species. These assumptions are consistent with those suggested in NRC Regulatory Guide 1.183. Table 15.5-44 itemizes the gap activity available for release from the FHB atmosphere to the environment.
Table 15.5-45 itemizes the assumptions and numerical values used to calculate the fuel handling accident radiological exposures. The potential releases of activity to the atmosphere are listed in Table 15.5-44. The exposures resulting from the postulated fuel handling accident inside the fuel handling area are presented in Table 15.5-47. These exposures are well below the Regulatory Guide 1.183 limits and demonstrate the adequacy of the fuel handling safety systems.
In the very unlikely event of a serious fuel handling accident and in combination with the conservative assumptions discussed above, containment building or fuel handling area activity concentrations may be quite high. High activity concentrations necessitate the evacuation of fuel handling areas in order to limit exposures to fuel handling personnel. Upon indication of a serious fuel handling accident, the fuel handling area will be evacuated until the extent of the fuel damage and activity levels in the area can be determined. Any serious fuel handling accident would be both visually and audibly detectable via radiation monitors in the fuel handling areas that locally alarm in the event of high activity levels and would alert personnel to evacuate.
Although conservatively neglected for this analysis, the fuel handling area has the additional safety feature of ventilation air flow that sweeps the surface of the spent fuel pool carrying any activity away from fuel handling personnel. This sweeping of the spent fuel pool is expected to considerably lower activity levels in the fuel handling area in the event of a serious fuel handling accident.
After charcoal filter cleanup (another design feature conservatively neglected in this analysis), fuel handling area post-accident ventilation air exhausts through the plant vent at a height of 70 meters. Site meteorology is such that it is very unlikely that any airborne activity will enter the control room ventilation system.
Spent fuel cask accidents in the fuel handling area causing fuel damage are precluded due to crane travel limits and design and operating features as described in Sections 9.1.2.3 and 9.1.4.6. Spent fuel handling accidents in the fuel handling area would not jeopardize the health and safety of the public. DCPP UNITS 1 & 2 FSAR UPDATE 15.5-55 Revision 19 May 2010 15.5.22.2 Fuel Handling Accident Inside Containment The offsite radiological consequences of a postulated fuel handling accident inside the containment are mitigated by containment closure. The following evaluation shows that in all cases the calculated exposures would be well below limits specified in 10 CFR 100.
During fuel handing operations, containment closure is not required. Generally, the containment ventilation purge system is operations and exhausts air from the containment through two 48-inch containment isolation valves. These two valves are connected in series. This flow of air from the containment is discharged to the environment via the plant vent.
This exhaust stream is monitored for activity by monitors in the plant vent. In the event of a postulated fuel handling accident, the plant vent monitors will alarm and result in the automatic closure of containment ventilation isolation valves. This activity release may result in offsite radiological exposures.
Containment penetrations are allowed to be open during fuel handling operations. The most prominent of these penetrations are the equipment hatch and the personnel airlock. Closure of these penetrations is achieved by manual means as discussed in Section 15.4.5. The closure of these penetrations is not credited in the design-basis fuel handling accident inside containment.
The FHA analysis assumes that the control room ventilation system of each unit remains in the normal mode of operation following the FHA. Thus, the design basis FHA does not credit charcoal filtration of the control room atmosphere intake flow or recirculation flow.
The evaluation of potential offsite exposures was performed for a design basis case, assuming plant parameters as limited by Technical Specifications. The assumptions of Regulatory Guide 1.25 were used as guidance with the exceptions detailed below. 15.5.22.2.1 Activity Released to Containment Atmosphere The assumptions made in determining the quantity of activity available for release from the containment refueling pool following the postulated accident are identical to those discussed in Section 15.5.22.1. For the DBA case, these assumptions are consistent with those in Regulatory Guides 1.25 and 1.183.
Consistent with the guidance of Regulatory Guide 1.25, it was assumed that all the gap activity in the damaged rods is released and consists of 10 percent of the total noble gases other than Kr-85, 30 percent of the Kr-85, and 10 percent of the total radioactive iodine in the rods at the time of the accident.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-56 Revision 19 May 2010 An effective DF of 200 for the iodines was assumed for the water in the refueling cavity. This DF is consistent with the current guidance provided in Regulatory Guide 1.183. The dose conversion factors used are from ICRP-30, "Limits For Intake of Radionuclides by Workers." The use of these dose conversion factors is consistent with the current guidance provided in Regulatory Guide 1.183. 15.5.22.2.2 Containment Isolation Following the postulated accident, airborne activity evolves from the surface of the pool where it mixes with air above the pool. Airborne activity is then assumed to be discharged to the environment via the open penetrations. The duration of the release was assumed to be one second.
In addition to radiation monitor indications, a fuel handling accident would immediately be known to refueling personnel at the scene of the accident. These personnel would initiate containment closure actions and are required by an Equipment Control Guideline to be in constant communication with control room personnel. The plant intercom system is described in FSAR Section 9.5.2. 15.5.22.2.3 Activity Released to Environment The containment refueling pool is approximately rectangular in shape with approximate dimensions of 25 by 70 feet. The pool has a surface area of about 1750 square feet.
It was assumed that activity evolved from the pool was instantaneously mixed and retained within the approximately 33,600 cubic foot rectangular parallelepiped formed by the 25- by 70-foot pool and the 40-foot-high steam generators. Where the steam generators do not surround the pool, the radioactivity would actually be dispersed into a larger volume of air which would have the effect of reducing the dose. However, for conservatism, it was assumed that all the radioactivity remained within this 33,600-cubic-foot volume and was then transported to the environment over a one second time period through the open equipment hatch. 15.5.22.2.4 Offsite Exposures The integrated release of activity to the environment and the resulting offsite radiological exposures were calculated for the postulated fuel handling accident inside containment using the LOCADOSE computer program.
Table 15.5-48 itemizes the DBA assumptions and numerical values used to calculate fuel handling accident radiological exposures. The calculated releases of activity to the atmosphere are listed in Table 15.5-49. The DBA exposures resulting from the postulated fuel handling accident inside containment are presented in Table 15.5-50. These exposures are well within the 10 CFR 100 limits. DCPP UNITS 1 & 2 FSAR UPDATE 15.5-57 Revision 19 May 2010 15.5.22.2.5 Action Following Containment Isolation Following manual containment closure after the fuel handling accident, activity can be removed from the containment atmosphere by the redundant Seismic Category II cleanup system (two trains at 12,000 cfm per train), which consists of HEPA/charcoal filters. This system is described in FSAR Section 9.4.5. There are no Technical Specification requirements for this filtration system.
The containment can also be purged to the atmosphere at a controlled rate of up to 300 cfm per train through the HEPA/charcoal filters of the hydrogen purge system. This system is described in Section 6.2.5. 15.5.22.3 Conclusion, Fuel Handling Accidents In the preceding sections the potential offsite exposures from major fuel handling accidents have been calculated. The analyses have been carried out using the models and assumptions specified in 10 CFR 100 and pertinent regulatory guides. In all analyses the resulting potential exposures to individual members of the public and the general population have been found to be lower than the applicable guidelines and limits specified in 10 CFR 100. On this basis, it can be concluded that the occurrence of a major fuel handling accident in a DCPP unit would not constitute an undue risk to the health and safety of the public. In addition, it can be concluded that the ESF provided for the mitigation of the consequences of a major fuel handling accident are adequate. 15.5.23 ENVIRONMENTAL CONSEQUENCES OF A ROD EJECTION ACCIDENT As discussed in Section 15.4.6, under adverse combinations of circumstances, some fuel cladding failures could occur following a rod ejection accident. In this case, some of the activity in the fuel rod gaps would be released to the coolant and in turn to the inside of the containment building. As a result of pressurization of the containment, some of this activity could leak to the environment. For the design basis case, it was assumed that the plant had been operating continuously with 1 percent fuel cladding defects and 1 gpm primary-to-secondary leakage. For the expected case calculation, operation at 0.2 percent defects and 20 gallons per day to the secondary was assumed.
Following a postulated rod ejection accident, activity released from the fuel pellet-cladding gap due to failure of 10 percent of the fuel rods is assumed to be instantaneously released to the primary coolant. Releases to the primary coolant are assumed to be immediately and uniformly mixed throughout the coolant.
The activity released to the containment from the primary coolant through the ruptured control rod mechanism pressure housing is assumed to be mixed instantaneously throughout the containment and is available for leakage to the atmosphere.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-58 Revision 19 May 2010 It has been assumed for both the design basis and expected cases that 10 percent of the elemental iodine leaked to the coolant is released to the containment atmosphere as a result of flashing of some of the primary coolant water. Of the amounts of noble gases released to the primary coolant, 100 percent is assumed to be released to the containment atmosphere at the time of the accident. It is assumed that the amount of iodine in chemical forms that are not affected by the spray system are negligible. These release fractions are used for both the design basis case and the expected case.
Following the release to the containment, the fission products are assumed to leak from the containment at the same rates assumed for the large LOCA, discussed in Section 15.5.17. In addition, the spray system is assumed to be in operation and acts to remove the iodines from the containment atmosphere at the same rates assumed for the large LOCA.
The assumptions used for meteorology, breathing rates, population density, and other common factors were also described in earlier sections. Both the primary and secondary coolant activities prior to the accident are given in Section 15.5.2. The gap activities are listed in Table 11.1-7.
All of the data and assumptions listed above were used with the EMERALD computer program to calculate the activity releases and potential doses following the accident. The calculated activity releases are listed in Table 15.5-51, and the potential doses are given in Table 15.5-52. Thyroid doses that would result from secondary steam releases with different sets of assumed conditions can be determined from Figures 15.5-2 through 15.5-5. If atmospheric steam releases occur following this accident, there will be some additional exposures via this pathway. The detailed assumptions used in estimating mode of exposure are described in Section 15.5-21. The results are given parametrically in Figures 15.5-13 and 15.5-14. It should be noted that these figures are based on the assumptions of a full plant cooldown with no condenser capacity available, a condition that would not be expected to occur following a rod ejection accident.
From these analyses, it can be concluded that offsite exposures from this accident will be well below the guideline levels specified in 10 CFR 100, and that the occurrence of such accidents would not result in undue risk to the public. A detailed evaluation of potential exposures to control room personnel is made in Section 15.5.17 for conditions following a LOCA. By comparing the activity releases following a rod ejection accident, given in Table 15.5-51, with the activity releases calculated for a LOCA, given in Tables 15.5-13 and 15.5-14, it can be concluded that any control room exposures following a rod ejection accident will be well below the GDC 19 criterion level.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-59 Revision 19 May 2010 15.5.24 ENVIRONMENTAL CONSEQUENCES OF A RUPTURE OF A WASTE GAS DECAY TANK The basic events involved in a rupture of a gas decay tank, along with the procedural and design features provided to prevent such an occurrence, are described in Section 15.4.7.
In the evaluation of the waste gas decay tank failure accident, the fission product accumulation and release assumptions for the DBA case are consistent with those of NRC Regulatory Guide 1.24 (Reference 24). These assumptions are:
(1) The reactor has been operating at full power with 1 percent defective fuel and a shutdown to cold condition has been conducted at the end of an equilibrium core cycle. (2) All noble gases have been removed from the primary cooling system and transferred to the gas decay tank that is assumed to fail. No radioactive decay is assumed during transfer. (3) The failure occurs immediately on completion of the waste gas transfer, releasing the entire maximum contents of the tank to the auxiliary building.
The assumption of the release of the noble gas inventory from only a single tank is based on a design that allows all gas decay tanks to be isolated from each other when they are in use. (4) All of the gases are exhausted from the auxiliary building at ground level over a 2-hour time period. There is no decay in the auxiliary building. The evaluation of the radiation doses resulting from the design basis case accident is based on the maximum gas decay tank inventories given in Table 11.3-5. The fission product accumulation and release assumptions used for the expected case are identical with those used for the DBA basis case, except that the tank inventories are based on operation with 0.2 percent defective fuel. The radiation doses resulting from the expected case accident are calculated from the maximum gas decay inventories given in Table 11.3-6.
The whole body doses resulting from the rupture of a gas decay tank were calculated for the time period 0-2 hours using the semi-infinite cloud submersion model as discussed in earlier sections. Atmospheric dispersion factors used in the analysis are given in Tables 15.5-3 and 15.5-4, and the breathing rates used are given in Table 15.5-7. Due to the presence of only trace amounts of iodine in the waste gas tanks, inhalation thyroid doses are negligible.
The resulting approximate radiation exposures from the rupture of a gas decay tank are presented in Table 15.5-53. As shown in the table, the individual doses are all well below the guideline doses of 10 CFR 100. DCPP UNITS 1 & 2 FSAR UPDATE 15.5-60 Revision 19 May 2010 15.5.25 ENVIRONMENTAL CONSEQUENCES OF A RUPTURE OF A LIQUID HOLDUP TANK The basic events involved in a rupture in a liquid holdup tank, along with the design features provided to mitigate the consequences of such an occurrence, are described in Section 15.4.8. In the evaluation of the liquid waste holdup tank rupture accident, the following fission product accumulation and release assumptions are used for the design basis case:
(1) The reactor has been operating at full power with 1 percent defective fuel for an equilibrium core cycle. (2) A liquid holdup tank has been filled with primary coolant at a rate of 120 gpm, with credit for decay as the tank is filling. (3) The failure occurs immediately upon completion of the liquid transfer, releasing the entire contents of the tank to the auxiliary building vault. The assumption of the release of the contents of only a single tank is based on a design that allows all liquid holdup tanks to be isolated from each other when they are in use. (4) All of the noble gases and varying amounts of the iodines are released from the auxiliary building vault to the auxiliary building atmosphere.
These effluents are exhausted from the auxiliary building at ground level. There is no decay in the auxiliary building. No liquids escape from the vaults during the accident. The whole body radiation doses resulting from the rupture of a liquid holdup tank were calculated for the time period 0-2 hours using the semi-infinite cloud submersion model, and the inhalation thyroid doses were calculated using the models discussed earlier. Atmospheric dispersion factors used in the analysis are given in Tables 15.5-3 and 15.5-4, and the breathing rates used are given in Table 15.5-7.
The resulting radiation exposures from the rupture of a liquid holdup tank are listed in Table 15.5-56. As shown in the table, the individual doses are well below the guideline doses of 10 CFR 100. 15.5.26 ENVIRONMENTAL CONSEQUENCES OF A RUPTURE OF A VOLUME CONTROL TANK The basic events involved in a rupture of a volume control tank, along with the procedural and design features provided to prevent such an occurrence, are described in Section 15.4.9.
In the evaluation of the volume control tank rupture accident, the following fission product accumulation and release assumptions are used for the design basis case: DCPP UNITS 1 & 2 FSAR UPDATE 15.5-61 Revision 19 May 2010 (1) The reactor has been operating at full power with 1 percent defective fuel for an equilibrium core cycle. (2) The volume control tank contains its maximum equilibrium inventory of radioactivity at the time of the accident. The failure of the tank releases the entire tank contents to the containment vault. (3) All of the noble gases and 10-4 of the iodines are released from the containment vault to the auxiliary building atmosphere. These effluents are exhausted from the auxiliary building at ground level over a 2-hour time period through the auxiliary building filters, which have efficiencies of 90 percent for iodines and 0 percent for noble gases. A discussion of the assumed effectiveness of the auxiliary building charcoal filters is given in Section 15.5.17. There is no decay in the auxiliary building. No liquids escape from the vault during the accident. The evaluation of the radiation exposures resulting from the postulated accident for the design basis case is based on the maximum tank inventories given in Table 11.3-7.
The fission product accumulation and release assumptions for the expected case are identical with those used for the design basis case, with the exceptions that the tank inventories are based on operation with 0.2 percent defective fuel and the auxiliary building filter efficiency is 99 percent for iodines. The evaluation of the resulting radiation exposures for the expected case is based on the maximum tank inventories given in Table 11.3-8. The whole body radiation doses resulting from the rupture of a volume control tank were calculated for the time period 0-2 hours using the semi-infinite cloud submersion model as discussed in earlier sections, and the inhalation thyroid doses were calculated using the models described in Reference 4. Atmospheric dispersion factors used in the analysis are given in Tables 15.5-3 and 15.5-4, and the breathing rates used are given in Table 15.5-7. The resulting radiation exposures are listed in Table 15.5-57. As shown in the table, the individual doses are well below the guideline doses of 10 CFR 100.
If credit for the Auxiliary Building filters is not taken, the dose contributions from noble gases are unchanged and the dose contributions from iodines are increased by a factor of ten. The resulting thyroid doses are increased by a factor of ten from those in Table 15.5-57, and the resulting whole body doses are not significantly affected. These results are still well below the guideline doses of 10 CFR 100. 15.5.27 SUMMARY OF ANALYSES OF ENVIRONMENTAL CONSEQUENCES OF POTENTIAL PLANT ACCIDENTS In accordance with the requirements of 10 CFR 20, 10 CFR 50, and 10 CFR 100, accident analyses have been performed for DCPP Units 1 and 2. DCPP UNITS 1 & 2 FSAR UPDATE 15.5-62 Revision 19 May 2010 Potential plant accidents and abnormal operating conditions were identified. The selected events covered the full range of accident analyses defined in the guide for the preparation of safety analysis reports and the American Nuclear Society PWR criteria.
The analyses of potential accidents and abnormal operating conditions have been performed using models and assumptions specified in federal regulations and regulatory guides. Conservative methods and assumptions were employed where models or assumptions were not specified by these guidelines, or where specific characteristics of the DCPP units were considered more applicable.
In all accident analyses, the resulting potential radiological exposures to plant personnel, to individual members of the public, and to the general population have been found to be lower than the applicable guidelines and limits specified in 10 CFR 20, 10 CFR 50, and 10 CFR 100. The results of the accident analyses indicate that the conservation, redundancy, and flexibility incorporated into the plant safety features ensures that these units can be operated without undue risk to the health and safety of the public. 15.5.28 REFERENCES 1. Nuclear Safety Criteria for the Design of Stationary Pressurized Water Reactor Plant, N18.2, American Nuclear Society, 1972.
- 2. Regulatory Guide 1.70, Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants, US Atomic Energy Commission (AEC), Rev. 1, October 1972.
- 3. Regulatory Guide 4.2, Preparation of Environmental Reports for Nuclear Power Plants, Directorate of Regulatory Standards, AEC, March 1973.
- 4. W. K. Burnot, et al, EMERALD (REVISION I) - A Program for the Calculation of Activity Releases and Potential Doses, Pacific Gas and Electric Company, March 1974.
- 5. S. G. Gillespie and W. K. Brunot, EMERALD NORMAL - A Program for the Calculations of Activity Releases and Doses from Normal Operation of a Pressurized Water Plant, Program Description and User's Manual, Pacific Gas and Electric Company, March 1973.
- 6. Regulatory Guide Number 1.4, Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss-of-Coolant Accident for Pressurized Water Reactors, AEC, Rev. 1, June 1973.
- 7. D. H. Slade, ed., Meteorology and Atomic Energy 1968, AEC Report Number TID-24190, July 1968.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-63 Revision 19 May 2010 8. ICRP Publication 2, Report of Committee II, Permissible Dose for Internal Radiation, 1959.
- 9. R. L. Engel, et al, ISOSHLD - A Computer Code for the General Purpose Isotope Shielding Analysis, BNWL-236, UC-34, Physics, Pacific Northwest Laboratory, Richland, WA, June 1966.
- 10. R. K. Hilliard, et al, "Removal of Iodine and Particles by Sprays in the Containment Systems Experiment," Nuclear Technology, April 1971.
- 11. R. L. Engel, et al, ISHOSHLD - A Computer Code for General Purpose Isotope Shielding Analysis, BNWL-236 SUP1, 1966.
- 12. L. F. Parsly, Calculation of Iodine - Water Partition Coefficients, ORNL-TM-2412, Part IV, January 1970.
- 13. Westinghouse, Radiological Consequences of a Fuel Handling Accident, December 1971.
- 14. F. J. Brutschy, et al, Behavior of Iodine in Reactor Water During Plant Shutdown and Startup, General Electric Co. Atomic Power Equipment Department Report, NEDO-10585, August 1972.
- 15. Deleted in Revision 16.
- 16. Proposed Addendum to ANS Standard N18.2, Single Failure Criteria for Fluid Systems, American Nuclear Society, May 1974.
- 17. K. G. Murphy and K. M. Campe, "Nuclear Power Plant Control Room Ventilation System Design for Meeting General Design Criteria 19," 13th AEC Air Cleaning Conference, August 1974.
- 18. M. L. Mooney and H. E. Cramer, Meteorological Study of the Diablo Canyon Nuclear Power Plant Site, Meteorological Office, Gas Control Department, PG&E, 1970 (see also Appendix 2.3A in Reference 27 of Section 2.3 in this FSAR Update).
- 19. M. L. Mooney, First Supplement, Meteorological Study of the Diablo Canyon Nuclear Power Plant Site, Meteorological Office, Gas Control Department, PG&E, 1971 (see also Appendix 2.3C in Reference 27 of Section 2.3 in this FSAR Update).
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-64 Revision 19 May 2010 20. M. L. Mooney, Second Supplement, Meteorological Study of the Diablo Canyon Nuclear Power Plant Site, Meteorological Office, Gas Control Department, PG&E, 1972 (see also Appendix 2.3D in Reference 27 of Section 2.3 in this FSAR Update).
- 21. International Commission on Radiological Protection Publication 30, Limits for Intakes of Radionuclides by Workers, 1979.
- 22. Technical Specifications, Diablo Canyon Power Plant Units 1 and 2, Appendix A to License Nos. DPR-80 and DPR 82, as amended.
- 23. Regulatory Guide 1.25, Assumptions Used for Evaluating the Potential Radiological Consequences of a Fuel Handling Accident in the Fuel Handling and Storage Facility for Boiling and Pressurized Water Reactors (Safety Guide 25) USNRC, March 1972.
- 24. Regulatory Guide 1.24, Assumptions Used for Evaluating the Potential Radiological Consequences of a Pressurized Water Reactor Radioactive Gas Storage Tank Failure (Safety Guide 24) USNRC, March 1972.
- 25. Start, G. E., J. H. Cate, C. R. Dickson, N. R. Ricks, G. H. Ackerman, and J. F. Sagendorf, "Rancho Seco Building Wake Effects on Atmospheric Diffusion, NOAA Technical Memorandum, ERL ARL-69, 1977.
- 26. Walker, D. H., R. N. Nassano, M. A. Capo, "Control Room Ventilation Intake Selection for the Floating Nuclear Power Plant," 14th ERDA Air Cleaning Conference, 1976.
- 27. Hatcher, R. N., R. N. Meroney, J. A. Peterka, K. Kothari, "Dispersion in the Wake of a Model Industrial Complex," NUREG-0373, 1978.
- 28. Meroney, R. N., and B. T. Yang, Wind Tunnel Study on Gaseous Mixing due to Various Stack Heights and Injection Rates Above an Isolated Structure, FDDL Report CER 71-72 RNM-BTY16, Colorado State University, 1971.
- 29. R. P. Hosker, Jr., "Dispersion in the Vicinity of Buildings," Preprints of Second Joint Conference on Applications in Air Pollution Meteorology and Second Conference on Industrial Meteorology, New Orleans, LA, March 24-28, 1980, pp. 92-107, American Meteorological Society, Boston, Mass. Also in "Flow and Diffusion Near Obstacles," Chapter 7 of Atmospheric Sciences and Power Production, D. Randerson, ed., USDOE.
- 30. D. J. Wilson, Contamination of Air Intakes from Roof Exhaust Vents, ASHRAE Trans. 82, Part 1, pp. 1024-1038, 1976.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-65 Revision 19 May 2010 31. R. J. B. Bouwmeester, K. M. Kothari, R. N. Meroney, An Algorithm to Estimate Field Concentrations Under Nonsteady Meteorological Conditions from Wind Tunnel Experiments, NUREG/CR-1474, USNRC, September 1980. 32. R. Bhatia, J. Dodds, and J. Schulz, Building Wake /Qs for Post-LOCA Control Room Habitability, Bechtel Power Corporation, San Francisco, CA.
- 33. Report on the Methodology for the Resolution on the Steam Generator Tube Uncovery Issue, WCAP-13247, March 1992.
- 34. Deleted in Revision 18.
- 35. Regulatory Guide 1.4, Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss of Coolant Accident for Pressurized Water Reactors, AEC, Revision 2, June 1974.
- 36. T. R. England and R. E. Schenter, ENDF-223, ENDF/B-IV Fission Product Files: Summary of Major Nuclide Data, October 1975.
- 37. Standard Review Plan, Section 15.6.3, Radiological Consequences of Steam Generator Tube Failure (PWR), NUREG-0800, USNRC, July 1981.
- 38. Deleted in Revision 18. 39. Westinghouse Letter PGE-91-533, Safety Evaluation for Containment Spray Flow Rate Reduction, February 7, 1991. 40. Westinghouse Letter PGE-93-652 dated October 5, 1993, transmitting NSAL-93-016, Revision 1.
- 41. K. F. Eckerman et. al., Limiting Values of Radionuclide Intake and Air Concentration and Dose Conversion Factors for Inhalation, Submersion, and Ingestion, Federal Guidance Report 11, EPA-520/1-88-020, Environmental Protection Agency, 1988.
- 42. K. F. Eckerman and J. C. Ryman, External Exposure to Radionuclides in Air, Water, and Soil, Federal Guidance Report 12, EPA-402-R-93-081, Environmental Protection Agency, 1993.
- 43. Deleted in Revision 12.
- 44. Regulatory Guide 1.195, "Methods and Assumptions for Evaluating Radiological Consequences of Design Basis Accidents at Light-Water Nuclear Power Reactors," 05/2003.
DCPP UNITS 1 & 2 FSAR UPDATE 15.5-66 Revision 19 May 2010 45. ICRP-30, "Limits For Intake of Radionuclides by Workers," 07/1978.
- 46. Diablo Canyon Units 1 and 2 Replacement Steam Generator Program - NSSS Licensing Report, WCAP-16638 (Proprietary), September 2007. 47. LOCADOSE-NE319, A Computer Code System for Multi-Region Radioactive Transport and Dose Calculation, Release 6, Bechtel Corporation.
- 48. PG&E Calculation N-166, Small Break LOCA Doses, Revision 0, October 31, 1994. 49. Diablo Canyon Units 1 and 2 Tayg and Tfeed Ranges Program NSSS Engineering Report, WCAP-16985 (Proprietary), April 2009.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.1-1 Revision 14 November 2001 NUCLEAR STEAM SUPPLY SYSTEM POWER RATINGS Guaranteed core thermal power (license level) 3411
Thermal power generated by the reactor coolant pumps minus heat losses to containment and letdown system (b) 14 Guaranteed nuclear steam supply system thermal power output 3425 The engineered safety features design 3570 rating (maximum calculated turbine rating)(a)
(a) The units will not be operated at this rating because it exceeds the license ratings. (b) As noted on Table 15.1-4, some analyses assumed a full power NSSS thermal output of 3,423 MWt, based on the previous net reactor coolant pump heat of 12 MWt. An evaluation concluded that the effect of an additional 2 MWt for NSSS is negligible such that analyses based on 3,423 MWt remain valid.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.1-2 Sheet 1 of 1 Revision 19 May 2010 TRIP POINTS AND TIME DELAYS TO TRIP ASSUMED IN ACCIDENT ANALYSES Trip Limiting TripPoint Assumed Time Delay, Function In Analyses sec Power range high neutron flux, high setting 118% 0.5
Power range high neutron flux, low setting 35% 0.5 Power range high positive nuclear power rate 9% / 2 sec 3.0 Overtemperature T Variable, see Figure 15.1-1 7(a) Overpower T Variable, see Figure 15.1-1 7(a) High pressurizer pressure 2445 psig 2
Low pressurizer pressure 1845 psig 2
High pressurizer water level 100% N/A(f) Low reactor coolant flow (from loop flow detectors) 87% loop flow(d) 1 Undervoltage trip (b)1.5 Low-low steam generator level 8.2% of narrow range level span 2(c) High steam generator level trip of the feedwater pumps and closure of feedwater system valves and turbine trips 100% of narrow range level span(e) 2 _________________ (a) Total time delay consists of a maximum 5-second RTD lag time constant and a maximum 2-second electronics delay (b) A specific undervoltage setpoint was not assumed in the safety analysis. (c) When below 50% power, a variable trip time delay is utilized as discussed in Section 7.2.1.1.1.5. (d) Westinghouse letter PGE-96-582, Diablo Canyon Units 1 & 2 Evaluation of Revised Low Reactor Coolant Flow Reactor Trip Setpoint, June 27, 1996, concludes that a safety analysis setpoint of 85% loop flow is acceptable. (e) The analysis assumed 100% narrow range level span for conservatism. The plant setpoint analytical limit is 98.8% narrow range level span for Model Delta 54 steam generators due to void effects. Although the turbine trip is modeled for completeness it is not needed for DNBR analysis. (f) Westinghouse Letter PGE-02-072, Diablo Canyon Units 1 & 2 Evaluation of Reactor Trip Functions for Uncontrolled RCCA Withdrawal at Power, 12/13/02, documents that a specific response time is not assumed since it is not a sensitive parameter for the generic evaluation results. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.1-4 Sheet 1 of 4 Revision 21 September 2013 SUMMARY OF INITIAL CONDITIONS AND COMPUTER CODES USED Assumed Reactivity Coefficients Initial NSSS Thermal
Faults Computer Codes Utilized Moderator Temp(a), pcm/°F(d) Moderator Density(a), k/gm/cc Doppler(b) Power Output Assumed(c), MWt CONDITION II
Uncontrolled RCCA bank withdrawal from a subcritical condition TWINKLE, THINC, FACTRAN +5 - Least negative defect - 954 pcm 0 Uncontrolled RCCA bank withdrawal at power LOFTRAN +7 0.43 Lower and Upper 3,423 RCCA misoperation THINC, ANC, LOFTRAN - - Lower 3,425 Uncontrolled boron dilution 0 and 3,423 Partial loss of forced reactor coolant flow LOFTRAN, THINC, FACTRAN +5 - Upper 3,423 Startup of an inactive reactor coolant loop LOFTRAN, FACTRAN, THINC - 0.43 Lower 2,396 Loss of external electrical load and/or turbine trip LOFTRAN, RETRAN-02 +5 0.43 Lower and Upper 3,423 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.1-4 Sheet 2 of 4 Revision 21 September 2013 Assumed Reactivity Coefficients Initial NSSS Thermal
Faults Computer Codes Utilized Moderator Temp(a), pcm/°F(d) Moderator Density(a), k/gm/cc Doppler(b) Power Output Assumed(c), MWt CONDITION II (Cont'd) Loss of normal feedwater RETRAN-02W 0 - Upper 3,425 Loss of offsite power to the plant auxiliaries RETRAN-02W 0 - Upper 3,425 Excessive heat removal due to feedwater system malfunctions RETRAN-02W - 0.43 Lower 3,425 Excessive load increase LOFTRAN - 0 and 0.43 Lower and Upper 3,423 Accidental depressurization of the reactor coolant system LOFTRAN +7 - Lower 3,425 Inadvertent operation of ECCS during power operation - DNBR LOFTRAN +5 0.43 Lower and Upper 3,423 Inadvertent operation of ECCS during power RETRAN - - - 3,425 Operation - Pressurizer Overfill
CONDITION III Loss of reactor coolant from small ruptured pipes or from cracks in large pipe which actuate emergency core cooling NOTRUMP SBLOCTA - - - 3,479 Inadvertent loading of a fuel assembly into an improper position PHOENIX-P, ANC - - - 3,483 Complete loss of force reactor coolant flow LOFTRAN, THINC, FACTRAN +5 - Upper 3,423 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.1-4 Sheet 3 of 4 Revision 21 September 2013 Assumed Reactivity Coefficients Initial NSSS Thermal
Faults Computer Codes Utilized Moderator Temp(a), pcm/°F(d) Moderator Density(a), k/gm/cc Doppler(b) Power Output Assumed(c), MWt CONDITION III (Cont'd) Single RCCA withdrawal at full power ANC, THINC, PHOENIX-P - - - 3,423 Underfrequency accident LOFTRAN, THINC, FACTRAN +5 - Upper 3,423 CONDITION IV
Major rupture of pipes containing reactor coolant up to and including double-ended rupture of the largest pipe in the reactor coolant system (loss-of-coolant accident) WCOBRA/TRAC HOTSPOT MONTECF Function of moderator density. See Sec. 15.4.1 0 Function of fuel temp. 3,479 Major secondary system pipe rupture up to and including double-ended rupture (rupture of a steam pipe) RETRAN-02W, ANC,THINC - Function of moderator density. See Figure 15.4.2-2. See Figure 15.4.2-1 0.0 (Subcritical) Major rupture of a main feedwater pipe RETRAN-02W 0.0 Lower 3,425
Rupture of a main steam line at power RETRAN-02W, ANC, THINC-IV 0.43 Lower 3,425 Waste gas decay tank rupture - - - - 3,577 Steam generator tube rupture RETRAN-02W - 0.0 Lower and Upper 3,425 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.1-4 Sheet 4 of 4 Revision 21 September 2013 Assumed Reactivity Coefficients Initial NSSS Thermal
Faults Computer Codes Utilized Moderator Temp(a), pcm/°F(d) Moderator Density(a), k/gm/cc Doppler(b) Power Output Assumed(c), MWt CONDITION IV (Cont'd) Single reactor coolant pump locked rotor LOFTRAN, THINC, FACTRAN +5 Upper 3,423 Fuel handling accident 3,577 Rupture of a control rod mechanism housing (RCCA ejection) TWINKLE, FACTRAN PHOENIX-P +5.2 BOL -23.EOL - Least negative defect. See Table 15.4-11. 0 and 3,423 (a) Only one is used in analysis, i.e., either moderator temperature or moderator density coefficient. (b) Reference Figure 15.1-5. (c) Two percent calorimetric error considered where applicable. (d) Pcm means percent mille. See footnote Table 4.3-1. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.2-1 Sheet 1 of 7 Revision 19 May 2010 TIME SEQUENCE OF EVENTS FOR CONDITION II EVENTS Accident Event Time, sec Uncontrolled RCCA Withdrawal from a Subcritical Condition Initiation of uncontrolled rod withdrawal 7.5 x 10-4 k/sec reactivity insertion rate from 10-9 of nominal power 0.0 Power range high neutron flux low setpoint reached 9.6 Peak nuclear power occurs 9.8 Rods begin to fall into core 10.1 Peak heat flux occurs 11.9 Peak hot spot average fuel temperature occurs 12.4 Peak hot spot average cladding temperature occurs 12.3 Uncontrolled RCCA Withdrawal at Power 1. Case A Initiation of uncontrolled RCCA withdrawal at maximum reactivity insertion rate (7.5 x 10-4 k/sec) 0.0 Power range high neutron flux high trip point reached 1.6 Rods begin to fall into core 2.1 Minimum DNBR occurs 3.0 2. Case B Initiation of uncontrolled RCCA withdrawal at a small reactivity insertion rate (3.0 x 10-5 k/sec) 0.0 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.2-1 Sheet 2 of 7 Revision 19 May 2010 Accident Event Time, sec Overtemperature T reactor trip signal initiated 31.8 Rods begin to fall into core 33.8 Minimum DNBR occurs 34.2 Uncontrolled Boron Dilution 1. Dilution during refueling and startup Dilution begins Operator isolates source of dilution; minimum margin to criticality occurs 0.0 ~1920 or more 2. Dilution during full power operation a. Automatic reactor control 1.6 % shutdown margin lost ~1180 b. Manual reactor control Dilution begins 0.0 Reactor trip setpoint reached for high neutron flux 40 Rods begin to fall into core 40.5 1.6 % shutdown is lost (if dilution continues after trip) ~ 900 Partial Loss of Forced Reactor Coolant Flow 1. All loops operating, two pumps coasting down Coastdown begins Low-flow reactor trip(b) Rods begin to drop Minimum DNBR occurs 0.0 1.43 2.43 3.9 Startup of an Inactive Reactor Coolant Loop Initiation of pump startup 0.0 Power reaches high nuclear flux trip 3.2 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.2-1 Sheet 3 of 7 Revision 19 May 2010 Accident Event Time, sec Rods begin to drop 3.7 Minimum DNBR occurs 4 Loss of External Electrical Load 1. With pressurizer control (BOL) Loss of electrical load 0.0 High pressurizer pressure reactor trip setpoint reached 11.9 Initiation of steam release from steam generator safety valves 12.0 Rods begin to drop 13.9 Peak pressurizer pressure occurs 14.5 Minimum DNBR occurs 15 2. With pressurizer control (EOL) Loss of electrical load 0.0 Peak pressurizer pressure occurs 9.0 Initiation of steam release from steam generator safety valves 12.5 Low-low steam generator water level reactor trip 57 Rods begin to drop 59 Minimum DNBR occurs (a) 3. Without pressurizer control (BOL) Loss of electrical load 0.0 High pressurizer pressure reactor trip point reached 6.1 Rods begin to drop 8.1 Minimum DNBR occurs (a) DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.2-1 Sheet 4 of 7 Revision 19 May 2010 Accident Event Time, sec Peak pressurizer pressure occurs 9.5 Initiation of steam release from steam generator safety valves 12.0 4. Without pressurizer control (EOL) Loss of electrical load 0.0 High pressurizer pressure reactor trip point reached 6 Rods begin to drop 8 Minimum DNBR occurs (a) Peak pressurizer pressure occurs 8.5 Initiation of steam release from steam generator safety valves 12.5 W/Power W/O Power Loss of Normal Feedwater and Loss of Offsite Power to the Station Auxiliaries Main feedwater flow stops 0.0 0.0 Low-low steam generator water level reactor trip 52.7 54.2 Rods begin to drop 54.7 56.2 Reactor coolant pumps begin to coast down - 58.2 Four SGs begin to receive aux feed from both motor-driven AFW pumps 112.7 114.2 Peak water level in pressurizer occurs (post-trip) 1294 2030 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.2-1 Sheet 5 of 7 Revision 19 May 2010 Accident Event Time, sec Excessive Feedwater at Full Load One main feedwater control valve fails full open 0.0 High-high steam generator water level is reached 33.6 Turbine trip signal (from high-high steam generator level, turbine stop valve fully closed 0.1second later 36.0 Reactor trip occurs from turbine trip (rod motion begins) 38.1 Minimum DNBR occurs 39.0 Initial pressurizer PORV opens (all PORVs closed 1.3 seconds later) 39.7 Feedwater isolation valves closed in all four loops (from high-high steam generator level) 99.6 Excessive Load Increase 1. Manual reactor control (BOL minimum moderator feedback) 10% step load increase Equilibrium conditions reached (approximate times only) 0.0 240 2. Manual reactor control (EOL maximum moderator feedback) 10% step load increase Equilibrium conditions reached (approximate times only) 0.0 64 3. Automatic reactor control (BOL minimum moderator feedback) 10% step load increase Equilibrium conditions reached (approximate times only) 0.0 150 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.2-1 Sheet 6 of 7 Revision 19 May 2010 Accident Event Time, sec 4. Automatic reactor control (EOL maximum moderator feedback) 10% step load increase Equilibrium conditions reached (approximate times only) 0.0 150 Accidental Depressuri- zation of the Reactor Coolant System Inadvertent opening of one pressurizer safety valve Overtemperature T reactor trip setpoint reached 0.0 27.5 Rods begin to drop 29.5 Minimum DNBR occurs 29.8 Inadvertent Operation of ECCS During Power Operation - DNBR Charging pumps begin injecting borated water 0.0 Low-pressure trip point reached 23 Rods begin to drop 25 Inadvertent Operation of ECCS During Power Operation - Pressurizer Overfill Reactor Trip/Safety injection 0 Case 1 Pressurizer fills 517 PSV opens 580 Last PSV relief 726 Case 2 Reactor Trip/Safety Injection 0 Pressurizer fills 517 PORV opens 529 45 PORV cycles 1,560 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.2-1 Sheet 7 of 7 Revision 19 May 2010 Accident Event Time, sec Case 3 Reactor Trip/Safety Injection 0 PORV opens 63 Pressurizer fills 778 93 PORV cycles 1,560 (a) DNBR does not decrease below its initial value. (b) Analysis assumed low flow setpoint of 87 percent loop flow. An evaluation concludes that 85 percent loop flow is acceptable. See Table 15.1-2, footnote (d). DCPP UNITS 1 & 2 FSAR UPDATE Revision 21 September 2013 TABLE 15.3-1 TIME SEQUENCE OF EVENTS - SMALL BREAK LOCA Unit 1 2-inch 3-inch 4-inch 6-inch Transient Initiated, sec 0 0 0 0 Reactor Trip Signal, sec 43.58 18.32 10.55 5.9 Safety Injection Signal, sec 58 26.8 16.57 8.58 Safety Injection Begins(1), sec 85 53.8 43.57 35.58 Loop Seal Clearing Occurs(2), sec 1197 514 300 110 Top of Core Uncovered(3), sec 1796 941 635 N/A Accumulator Injection Begins, sec N/A 1984 885 385 Top of Core Recovered, sec 6500 3170 2545 N/A RWST Low Level, sec 1709 1689 1664 1640 Unit 2 2-inch 3-inch 4-inch 6-inch Transient Initiated, sec 0 0 0 0 Reactor Trip Signal, sec 44.72 18.78 10.82 6.11 Safety Injection Signal, sec 59.45 27.41 16.68 9 Safety Injection Begins(1), sec 86.45 54.41 43.68 36 Loop Seal Clearing Occurs(2), sec 1360 575 290 120 Top of Core Uncovered(3), sec 3200 722 770 N/A Accumulator Injection Begins, sec N/A 3050 985 400 Top of Core Recovered, sec N/A 3215 1630 N/A RWST Low Level, sec 1708 1690 1666 1641 (1) Safety Injection begins 27.0 seconds (SI delay time) after the safety injection signal is reached. (2) Loop seal clearing is considered to occur when the broken loop seal vapor flow rate is sustained above 1 lbm/s. (3) Top of core uncovery time is taken as the time when the core mixture level is sustained below the top of the core elevation. DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 15.3-2 FUEL CLADDING RESULTS - SMALL BREAK LOCA Unit 1 2-inch 3-inch 4-inch PCT (°F) 907 1391 1241 PCT Time (s) 2173.3 1891.7 975.8 PCT Elevation (ft) 10.75 11.25 11.00 Burst Time (s) (1) N/A N/A N/A Burst Elevation (ft) (1) N/A N/A N/A Maximum Hot Rod Transient ZrO2 (%) 0.01 0.38 0.07 Maximum Hot Rod Transient ZrO2 Elev. (ft) 10.75 11.25 10.75 Hot Rod Average Transient ZrO2 (%) 0.01 0.06 0.01 Unit 2 2-inch 3-inch 4-inch PCT (°F) 814 1288 1004 PCT Time (s) 4838.3 1961.8 1079.2 PCT Elevation (ft) 11.00 11.25 10.75 Burst Time (s) (1) N/A N/A N/A Burst Elevation (ft) (1) N/A N/A N/A Maximum Hot Rod Transient ZrO2 (%) 0.01 0.18 0.01 Maximum Hot Rod Transient ZrO2 Elev. (ft) 11.00 11.25 10.75 Hot Rod Average Transient ZrO2 (%) 0 0.03 0.01 (1) Burst was not predicted to occur for any break size.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 15 September 2003 TABLE 15.3-3 TIME SEQUENCE OF EVENTS FOR CONDITION III EVENTS Accident Event Time, sec Complete Loss of Forced Reactor Coolant Flow All loops operating, all pumps coasting down Coastdown begins Rod motion begins Minimum DNBR occurs 0.0 1.5 3.6
DCPP UNITS 1 & 2 FSAR UPDATE Revision 21 September 2013 TABLE 15.4.1-1A UNIT 1 BEST ESTIMATE LARGE BREAK LOCA TIME SEQUENCE OF EVENTS FOR THE REFERENCE TRANSIENT Event Time (sec)Start of Transient0.0Safety Injection Signal6.0Accumulator Injection Begins11.0 End of Blowdown29.0Safety Injection Begins33.0Bottom of Core Recovery37.0Accumulator Empty50.0PCT Occurs39.0Hot Rod Quench>300.0End of Transient500.0 DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 15.4.1-1B UNIT 2 BEST ESTIMATE LARGE BREAK SEQUENCE OF EVENTS FOR LIMITING PCT CASE Event Time (sec) Start of Transient 0.0 Safety Injection Signal 6.0 Accumulator Injection Begins 13.0 End of Blowdown 29.0 Safety Injection Begins 33.0 Bottom of Core Recovery 37.0 Accumulator Empty 48.0 PCT Occurs 110.0 Hot Rod Quench 285.0 End of Transient 500.0
DCPP UNITS 1 & 2 FSAR UPDATE Revision 21 September 2013 TABLE 15.4.1-2A UNIT 1 BEST ESTIMATE LARGE BREAK LOCA ANALYSIS RESULTS Component Blowdown Peak First Reflood Peak Second Reflood Peak PCTaverage <1485°F <1621°F <1486°F PCT95% <1744°F <1900°F <1860°F Maximum Oxidation <11% Total Oxidation <0.89% DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 15.4.1-2B UNIT 2 BEST ESTIMATE LARGE BREAK LOCA ANALYSIS RESULTS Result Criterion 95/95 PCT 1,872°F < 2,200°F 95/95 LMO 1.64% < 17% 95/95 CWO 0.17% < 1% PCT - Peak Cladding Temperature LMO - Local Maximum Oxidation CWO - Core Wide Oxidation DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-3A Sheet 1 of 4 Revision 21 September 2013 UNIT 1 KEY BEST ESTIMATE LARGE BREAK LOCA PARAMETERS AND REFERENCE TRANSIENT ASSUMPTIONS Parameter Reference Transient Uncertainty or Bias 1.0 Plant Physical Description a. Dimensions Nominal PCTMOD b. Flow resistance Nominal PCTMOD c. Pressurizer location Opposite broken loop Bounded d. Hot assembly location Under limiting location Bounded e. Hot assembly type 17x17 V5 w/ZIRLO clad Bounded f. SG tube plugging level High (15%) Bounded(a) 2.0 Plant Initial Operating Conditions 2.1 Reactor Power a. Core average linear heat rate Nominal - 100% of uprated power (3411 MWt) PCTPD b. Peak linear heat rate (PLHR) Derived from desired Technical Specifications (TS) limit and maximum baseload PCTPD c. Hot rod average linear heat rate (HRFLUX) Derived from TS FH PCTPD DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-3A Sheet 2 of 4 Revision 21 September 2013 Parameter Reference Transient Uncertainty or Bias d. Hot assembly average heat rate HRFLUX/1.04 PCTPD e. Hot assembly peak heat rate PLHR/1.04 PCTPD f. Axial power distribution (PBOT, PMID) Figure 3-2-10 of Reference 60 PCTPD g. Low power region relative power (PLOW) 0.3 Bounded(a) h. Hot assembly burnup BOL Bounded i. Prior operating history Equilibrium decay heat Bounded j. Moderator Temperature Coefficient (MTC) TS Maximum (0) Bounded k. HFP boron 800 ppm Generic 2.2 Fluid Conditions a. Tavg Max. nominal Tavg = 577.3°F Nominal is bounded, uncertainty is in PCTIC b. Pressurizer pressure Nominal (2250.0 psia) PCTIC c. Loop flow 85000 gpm PCTMOD(b) d. TUH Best Estimate 0 e. Pressurizer level Nominal (1080 ft3) 0 f. Accumulator temperature Nominal (102.5°F) PCTIC g. Accumulator pressure Nominal (636.2 psia) PCTIC DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-3A Sheet 3 of 4 Revision 21 September 2013 Parameter Reference Transient Uncertainty or Bias h. Accumulator liquid volume Nominal (850 ft3) PCTIC i. Accumulator line resistance Nominal PCTIC j. Accumulator boron Minimum Bounded 3.0 Accident Boundary Conditions a. Break location Cold leg Bounded b. Break type Guillotine PCTMOD c. Break size Nominal (cold leg area) PCTMOD d. Offsite power Off (RCS pumps tripped) Bounded(a) e. Safety injection flow Minimum Bounded f. Safety injection temperature Nominal (68°F) PCTIC g. Safety injection delay Max delay (27.0 sec, with loss of offsite power) Bounded h. Containment pressure Minimum based on WC/T M&E Bounded i. Single failure ECCS: Loss of 1 SI train Bounded j. Control rod drop time No control rods Bounded 4.0 Model Parameters a. Critical Flow Nominal (as coded) PCTMOD DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-3A Sheet 4 of 4 Revision 21 September 2013 Parameter Reference Transient Uncertainty or Bias b. Resistance uncertainties in broken loop Nominal (as coded) PCTMOD c. Initial stored energy/fuel rod behavior Nominal (as coded) PCTMOD d. Core heat transfer Nominal (as coded) PCTMOD e. Delivery and bypassing of ECC Nominal (as coded) Conservative f. Steam binding/entrainment Nominal (as coded) Conservative g. Noncondensable gases/accumulator nitrogen Nominal (as coded) Conservative h. Condensation Nominal (as coded) PCTMOD (a) Confirmed by plant-specific analysis. (b) Assumed to be result of loop resistance uncertainity. Notes: 1. PCTMOD indicates this uncertainty is part of code and global model uncertainty. 2. PCTPD indicates this uncertainty is part of power distribution uncertainty. 3. PCTIC indicates this uncertainty is part of initial condition uncertainty. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-3B Sheet 1 of 3 Revision 21 September 2013 UNIT 2 KEY BEST ESTIMATE LARGE BREAK LOCA PARAMETERS AND INITIAL TRANSIENT ASSUMPTIONS Parameter Initial Transient Range/Uncertainty 1.0 Plant Physical Description a. Dimensions Nominal Sampled b. Flow resistance Nominal Sampled c. Pressurizer location Opposite broken loop Bounded d. Hot assembly location Under limiting location Bounded e. Hot assembly type 17x17 V5 + with ZIRLOTM cladding, Non-IFBA Bounded f. Steam generator tube plugging level High (15%) Bounded(a) 2.0 Plant Initial Operating Conditions 2.1 Reactor Power a. Core average linear heat rate (AFLUX) Nominal - Based on 100% thermal power (3468 MWt) Sampled b. Hot rod peak linear heat rate (PLHR) Derived from desired Technical Specification limit FQ = 2.7 and maximum baseload FQ = 2.1 Sampled c. Hot rod average linear heat rate (HRFLUX) Derived from Technical Specification FH = 1.7 Sampled d. Hot assembly average heat rate (HAFLUX) HRFLUX/1.04 Sampled e. Hot assembly peak heat rate (HAPHR) PLHR/1.04 Sampled f. Axial power distribution (PBOT, PMID) Figure 15.4.1-15B Sampled g. Low power region relative power (PLOW) 0.3 Bounded(a) h. Cycle burnup ~2000 MWD/MTU Sampled i. Prior operating history Equilibrium decay heat Bounded DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-3B Sheet 2 of 3 Revision 21 September 2013 Parameter Initial Transient Range/Uncertainty 2.0 Plant Initial Operating Conditions (continued) j. Moderator temperature coefficient Technical Specification Maximum (0) Bounded k. HFP boron 800 ppm Generic 2.2 Fluid Conditions a. Tavg High Nominal Tavg = 577.6°F Bounded(a), Sampled b. Pressurizer pressure Nominal (2250.0 psia) Sampled c. Loop flow 85,000 gpm Bounded d. Upper head fluid temperature Tcold 0 e. Pressurizer level Nominal 0 f. Accumulator temperature Nominal (102.5°F) Sampled g. Accumulator pressure Nominal (636.2 psia) Sampled h. Accumulator liquid volume Nominal (850 ft3) Sampled i. Accumulator line resistance Nominal Sampled j. Accumulator boron Minimum (2200 ppm) Bounded 3.0 Accident Boundary Conditions a. Break location Cold leg Bounded b. Break type Guillotine (DECLG) Sampled c. Break size Nominal (cold leg area) Sampled d. Offsite power Loss of offsite power Bounded(a) e. Safety injection flow Minimum Bounded f. Safety injection temperature Nominal (68°F) Sampled g. Safety injection delay Maximum delay (27.0 sec, with loss of offsite power) Bounded DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-3B Sheet 3 of 3 Revision 21 September 2013 Parameter Initial Transient Range/Uncertainty 3.0 Accident Boundary Conditions (continued) h. Containment pressure Bounded - Lower (conservative) than pressure curve shown in Figure 15.4.1-14B. Bounded i. Single failure ECCS: Loss of one safety injection train; Containment pressure: all trains operational Bounded j. Control rod drop time No control rods Bounded 4.0 Model Parameters a. Critical flow Nominal (CD = 1.0) Sampled b. Resistance uncertainties in broken loop Nominal (as coded) Sampled c. Initial stored energy/fuel rod behavior Nominal (as coded) Sampled d. Core heat transfer Nominal (as coded) Sampled e. Delivery and bypassing of emergency core coolant Nominal (as coded) Conservative f. Steam binding/entrainment Nominal (as coded) Conservative g. Noncondensable gases/accumulator nitrogen Nominal (as coded) Conservative h. Condensation Nominal (as coded) Sampled (a) Per Confirmatory Study results (Section 15.4.1.1.2.5) DCPP UNITS 1 & 2 FSAR UPDATE Revision 21 September 2013 TABLE 15.4.1-4A UNIT 1 SAMPLE OF BEST ESTIMATE SENSITIVITY ANALYSIS RESULTS FOR ORIGINAL ANALYSIS (Reference 60) Type of Study Parameter Varied Value PCT Results (°F) Blowdown Reflood 1 Reflood 2 Reference Transient See Table 15.4-3 1600 1852 1984 Confirmatory Cases Steam Generator Tube Plugging 0% 1569 1798 1878 Offsite Power Assumption Available 1500 1685 1781 Normalized Power in Outer Assemblies 0.8 1611 1805 1939 Vessel Average Temperature 565°F 1573 1843 1871 Initial Accumulator +50 ft3 1601 1856 1823 Condition Volume 50 ft3 1599 1863 2182 Global Models DECLG, CD 1.0 1600 1852 1984 SPLIT, CD 1.4 - 1596 1637 1.6 - 1784 1799 1.8 - 1790 1738 2.0 - 1765 1804
DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 15.4.1-4B UNIT 2 RESULTS FROM CONFIRMATORY STUDIES Transient Description PCT (°F) Reflood Initial Transient (High Tavg, High SGTP, Low PLOW, LOOP) 1595 SGTP Confirmatory Transient (High Tavg, Low SGTP, Low PLOW, LOOP) 1576 Tavg, Confirmatory Transient (Low Tavg, High SGTP, Low PLOW, LOOP) 1536 PLOW Confirmatory Transient (High Tavg, High SGTP, High PLOW, LOOP) 1657 LOOP Confirmatory Transient (High Tavg, High SGTP, Low PLOW, no-LOOP) 1425 Reference Transient (High Tavg, High SGTP, High PLOW, LOOP) 1657
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-5A Sheet 1 of 2 Revision 18 October 2008 UNIT 1 CONTAINMENT BACK PRESSURE ANALYSIS INPUT PARAMETERS USED FOR BEST ESTIMATE LOCA ANALYSIS Net Free Volume, cu ft 2,630,000 Initial Conditions Pressure, psia 14.7 Temperature, °F 85 RWST temperature, °F 35 Service water temperature, °F 45 Outside temperature, °F 33 Spray System Number of pumps operating 2 Runout flowrate per pump, gpm 3400 Actuation time, sec 40.8 Safeguards Fan Coolers Number of fan coolers operating 5 Fastest post-accident initiation of fan coolers, sec 0 Structural Heat Sinks Thickness, in. Area, ft2 42.0 concrete 65,749 12.0 concrete 24,054 24.0 concrete 14,313 12.0 concrete 48,183 12.0 concrete 15,725 108.0 concrete 20,493 30.0 concrete 33,867 1.68 steel 8,525 1.92 steel 4,015 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-5A Sheet 2 of 2 Revision 18 October 2008 Structural Heat Sinks (continued) Thickness, in. Area, ft2 6.99 steel 1,771 0.5656 steel 43,396 0.088 steel 24,090 0.22 steel 10,597 0.088 steel 8,470 0.102 steel 23,438 0.071 steel 20,266 0.708 steel 26,050 0.127 steel 33,000 0.773 steel 11,004 0.375 steel 99,616 1.596 steel 1,530 1.098 steel 21,022 0.745 steel 6,755 0.96 steel 792 0.144 stainless steel 9,737 0.654 stainless steel 943 0.642 steel 1,373 3.0 steel 575 0.75 steel 17,542 DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 15.4.1-5B UNIT 2 CONTAINMENT BACK PRESSURE ANALYSIS INPUT PARAMETERS USED FOR BEST ESTIMATE LBLOCA ANALYSIS Net Free Volume 2,630,000 ft3 Initial Conditions Pressure 14.7 psia Temperature 85.0°F RWST temperature 35.0°F Service water temperature 48.0°F Temperature outside containment 33.0°F Initial spray temperature 35.0°F Spray System Number of spray pumps operating 2 Post-accident spray system initiation delay 40.8 sec Maximum spray system flow from all pumps 6,800 gal/min. Containment Fan Coolers Post-accident initiation fan coolers 0.0 sec(a) Number of fan coolers operating 5 (a) Bounds delay with and without LOOP DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-7A Sheet 1 of 3 Revision 19 May 2010 UNIT 1 PLANT OPERATING RANGE ALLOWED BY THE BEST-ESTIMATE LARGE BREAK LOCA ANALYSIS Parameter Operating Range 1.0 Plant Physical Description a. Dimensions No in-board assembly grid deformation assumed due to LOCA + SSE b. Flow resistance N/A c. Pressurizer location N/A d. Hot assembly location Anywhere in core e. Hot assembly type Fresh 17X17 V5, ZIRLO, or Zircaloy cladding, 1.5X IFBA or non-IFBA f. SG tube plugging level 15% g. Fuel assembly type Vantage 5, ZIRLO, or Zircaloy cladding, 1.5X IFBA or non-IFBA 2.0 Plant Initial Operating Conditions 2.1 Reactor Power a. Core average linear heat rate Core power 102% of 3411 MWt b. Peak linear heat rate FQ 2.7 c. Hot rod average linear heat rate FH 1.7 d. Hot assembly average linear heat rate PHA 1.57 e. Hot assembly peak linear heat rate FQHA 2.7/1.04 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-7A Sheet 2 of 3 Revision 19 May 2010 Parameter Operating Range f. Axial power distribution (PBOT, PMID) Figure 15.4.1-15A g. Low power region relative power (PLOW) 0.3 PLOW 0.8 h. Hot assembly burnup 75,000 MWD/MTU, lead rod i. Prior operating history All normal operating histories j. MTC 0 at HFP k. HFP boron Normal letdown 2.2 Fluid Conditions a. Tavg 560.0 Tave 582.3°F b. Pressurizer pressure 2190 PRCS 2310 psia c. Loop flow 85,000 gpm/loop d. TUH Current upper internals e. Pressurizer level Normal level, automatic control f. Accumulator temperature 85 accumulator temperature 120°F g. Accumulator pressure 579 PACC 664 psig h. Accumulator volume 814 Vacc 886 ft3 i. Accumulator fL/D Current line configuration DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-7A Sheet 3 of 3 Revision 19 May 2010 Parameter Operating Range j. Minimum accumulator boron 2200 ppm 3.0 Accident Boundary Conditions a. Break location N/A b. Break type N/A c. Break size N/A d. Offsite power Available or LOOP e. Safety injection flow Figure 15.4.1-13A f. Safety injection temperature 46 SI Temperature 90°F g. Safety injection delay 17 seconds (with offsite power) 27 seconds (with LOOP) h. Containment pressure Bounded - see Figure 15.4.1-14A i. Single failure Loss of one train j. Control rod drop time N/A DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-7B Sheet 1 of 2 Revision 18 October 2008 UNIT 2 PLANT OPERATING RANGE ALLOWED BY THE BEST-ESTIMATE LARGE BREAK LOCA ANALYSIS Parameter Operating Range 1.0 Plant Physical Description a) Dimensions No in-board assembly grid deformation during LOCA + SSE b) Flow resistance N/A c) Pressurizer location N/A d) Hot assembly location Anywhere in core interior (149 locations)(a) e) Hot assembly type Fresh 17x17 V5+ fuel with ZIRLOTM cladding f) Steam generator tube plugging level 15% g) Fuel assembly type 17x17 V5+ fuel with ZIRLOTM cladding, non-IFBA or IFBA 2.0 Plant Initial Operating Conditions 2.1 Reactor Power a) Core average linear heat rate Core power 100.3% of 3,468 MWt b) Peak linear heat rate FQ 2.7 c) Hot rod average linear heat rate FH 1.7 d) Hot assembly average linear heat rate HAP < 1.7/1.04 e) Hot assembly peak linear heat rate FQHA < 2.7/1.04 f) Axial power distribution (PBOT, PMID) See Figure 15.4.1-15B. g) Low power region relative power (PLOW) 0.3 PLOW 0.8 h) Hot assembly burnup 75,000 MWD/MTU, lead rod(a) i) Prior operating history All normal operating histories j) Moderator temperature coefficient 0 at HFP k) HFP boron (minimum) 800 ppm (at BOL) 2.2 Fluid Conditions a) Tavg 565 - 5°F Tavg 577.6 + 5°F b) Pressurizer pressure 2250 - 60 psia PRCS 2250 + 60 psia DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4.1-7B Sheet 2 of 2 Revision 18 October 2008 Parameter Operating Range c) Loop flow 85,000 gpm/loop d) TUH Converted upper internals, TCOLD UH e) Pressurizer level Nominal level, automatic control f) Accumulator temperature 85°F TACC 120°F g) Accumulator pressure 579 psia PACC 664 psia h) Accumulator liquid volume 814 ft3 VACC 886 ft3 i) Accumulator fL/D Current line configuration j) Minimum accumulator boron 2200 ppm 3.0 Accident Boundary Conditions a) Break location N/A b) Break type N/A c) Break size N/A d) Offsite power Available or LOOP e) Safety injection flow See Figure 15.4.1-13B. f) Safety injection temperature 46°F SI Temp 90°F g) Safety injection delay 17 seconds (with offsite power) 27 seconds (with LOOP) h) Containment pressure See Figure 15.4.1-14B and raw data in Table 15.4.1-5B. i) Single failure All trains operable(b) j) Control rod drop time N/A (a) 44 peripheral locations will not physically be lead power assembly. (b) Analysis considers loss of one train of pumped ECCS. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4-8 Sheet 1 of 3 Revision 21 September 2013 TIME SEQUENCE OF EVENTS FOR MAJOR SECONDARY SYSTEM PIPE RUPTURES Accident Event Time, sec Steam Line Rupture @ HZP
- 1. With Offsite Power Available Main steam line ruptures 0.0 Low steam line pressure setpoint reached 0.6 SIS flow begins(maximum flow assumed) 2.6 Steam line isolation occurs 8.6 Criticality attained 36.5 Borated water from the RWST reaches the core ~40 Main feedwater isolation occurs 64.6 Accumulators inject 79.0 Peak core heat flux, minimum DNBR occurs 90.5 2. Without Offsite Power Available Main steam line ruptures 0.0 Low steam line pressure setpoint reached 0.6 SIS flow begins (maximum flow assumed) 2.6 RCPs begin to coast down 3.0 Steam line isolation occurs 8.6 Criticality attained 44.4 Borated water from the RWST reaches the core ~50
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4-8 Sheet 2 of 3 Revision 21 September 2013 Accident Event Time, sec Main feedwater isolation occurs 64.6 Peak core heat flux, minimum DNBR occurs 123.4
Accumulators inject 129.7
Rupture of Main Feedwater Pipe (Offsite Power Available) Feedline rupture occurs 20 Low-low steam generator level reactor trip setpoint reached in affected steam generator 32 Rods begin to drop 34
Auxiliary feedwater is started 623 Pressurizer liquid water relief begins if operator action is not assumed 2053 Total RCS heat generation (decay heat + pump heat) decreases to auxiliary feedwater heat removal capability 5900 Rupture of Main Feedwater Pipe (Offsite Power Unavailable) Feedline rupture occurs 20 Low-low steam generator level reactor trip setpoint reached in affected steam generator 32 Rods begin to drop 34
Reactor coolant pump coastdown 36
Auxiliary feedwater is started 632 Peak pressurizer level after initial outsurge reached 2091
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.4-8 Sheet 3 of 3 Revision 21 September 2013 Accident Event Time, sec Total RCS heat generation decreases to auxiliary feedwater heat removal capability 2200 Steam Line Rupture at Power (0.49 ft2) Steam line ruptures 0.0 Peak core heat flux occurs 53.1
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.4-10 SUMMARY OF RESULTS FOR LOCKED ROTOR TRANSIENT 4 Loops Operating Initially 1 Locked Rotor Maximum RCS pressure, psia 2672 Maximum clad temperature, °F core hot spot 2040 Amount of Zr - H2O at core hot spot, % by weight 0.7%
DCPP UNITS 1 & 2 FSAR UPDATE Revision 15 September 2003 TABLE 15.4-11 TYPICAL PARAMETERS USED IN THE VANTAGE 5 RELOAD ANALYSIS OF THE ROD CLUSTER CONTROL ASSEMBLY EJECTION ACCIDENT Time in Life Beginning Beginning End End Generic Vantage 5 Reload Analysis Values Power level, % 102 0.0 102 0.0 Ejected rod worth, % k 0.20 0.785 0.21 0.85 Delayed neutron fraction, % 0.55 0.55 0.44 0.44 Feedback reactivity weighting 1.30 2.071 1.30 3.55 Doppler - only power defect, pcm -955 -954 -829 -788 Trip reactivity, % k 4 2 4 2 Fq before rod ejection 2.60 - 2.60 - Fq after rod ejection 6.70 13 6.50 21.50 Number of operating pumps 4 2 4 2 Generic Vantage 5 Reload Analysis Results Maximum fuel pellet average temperature, °F 4154 3509 3812 3408 Maximum fuel center temperature, °F >4900 (a) 4025 >4800 (a) 3849 Maximum cladding average temperature, °F 2434 2660 2218 2632 Maximum fuel stored energy, cal/gm 183 149 165 144 Reload Analysis Evaluation Values Power level, % 102 0.0 102 0.0 Ejected rod worth, % k 0.20 0.785 0.21 0.83 Delayed neutron fraction, % 0.55 0.55 0.44 0.44 Feedback reactivity weighting 1.30 2.071 1.30 3.55 Doppler - only power defect, pcm -995 -954 -829 -788 Trip reactivity, % k 4 2 4 2 Fq before rod ejection 2.60 - 2.60 - Fq after rod ejection 6.70 13 6.50 22.50 Number of operating pumps 4 2 4 2 (a) Less than 10% fuel pellet melt (at hot spot) DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 15.4-12 OPERATOR ACTION TIMES FOR DESIGN BASIS SGTR ANALYSIS Action Time (min) Identify and isolate ruptured SG 10 min or RETRAN-02W calculated time to reach 38% narrow range level in the ruptured SG, whichever is longer Operator action time to initiate cooldown 5 Cooldown Calculated by RETRAN-02W
Operator action time to initiate depressurization 4 Depressurization Calculated by RETRAN-02W
Operator action time to initiate SI termination 2 SI termination and pressure equalization Calculated time for SI termination and equalization of RCS and ruptured SG pressures DCPP UNITS 1 & 2 FSAR UPDATE Revision 20 November 2011 TABLE 15.4-13A TIMED SEQUENCE OF EVENTS - SGTR MTO ANALYSIS Event Time (sec) SG Tube Rupture 100
Reactor Trip 274
SI Actuated 380
Turbine Driven AFW Pump Flow Isolated 700
Ruptured SG Steamline Isolation 700
Ruptured SG MDAFW Pump Flow Isolated 820
RCS Cooldown Initiated 1120
RCS Cooldown Terminated 1706
RCS Depressurization Initiated 1946
RCS Depressurization Terminated 2072
SI Terminated 2192
Break Flow Terminated 3475 DCPP UNITS 1 & 2 FSAR UPDATE Revision 20 November 2011 TABLE 15.4-13B TIMED SEQUENCE OF EVENTS - SGTR DOSE ANALYSIS Event Time (sec) SG Tube Rupture 100
Reactor Trip 279
SI Actuated 315
Ruptured SG Isolated 953
Ruptured SG PORV Fails Open 953
Ruptured SG PORV Block Valve Closed 2753
RCS Cooldown Initiated 3053
RCS Cooldown Terminated 4424
RCS Depressurization Initiated 4664
RCS Depressurization Terminated 4839
SI Terminated 4959
Break Flow Terminated 5972
DCPP UNITS 1 & 2 FSAR UPDATE Revision 21 September 2013 TABLE 15.4-14 MASS RELEASE RESULTS - SGTR DOSE INPUT ANALYSIS 0 - 2 Hrs, lbm 2 - 8 Hrs, lbm Ruptured SG
- Condenser 294,500 0 - Atmosphere 140,200 27,000
- Feedwater 288,700 0 Intact SGs
- Condenser 878,100 0 - Atmosphere 367,100 922,600
- Feedwater 1,476,800 961,700
Break Flow 262,200 0 Flashed Break Flow 18,150 0 Note: The 0-2 hour releases to the condenser and feedwater flows include 100 seconds of steady state operation.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-1 REACTOR COOLANT FISSION AND CORROSION PRODUCT ACTIVITIES DURING STEADY STATE OPERATION AND PLANT SHUTDOWN OPERATION Operating PWR Plant Diablo Canyon - Design Basis Case
Isotope Measured Activity Before Shutdown, mCi/gm Measured Peak Shutdown Activity, mCi/gm Calculated Activity Before Shutdown, mCi/gm Expected Peak Shutdown Activity, mCi/gm I -131 0.83 14.9 2.45 43.9
Xe-133 127.00 65.0(a) 255.8 130.9(a) Cs-134 1.29 1.7 0.198 0.26
Cs-137 1.67 2.14 0.31 0.39
Ce-144 0.00068 0.0058 0.00034 0.0029
Sr-89 0.0033 0.40 0.0026 0.32
Sr-90 0.00057 0.013 0.00013 0.003
Co-58 --- 0.95 0.026 1.04 (a) Activity reduced from steady state level by approximately 1 day of system degasification prior to plant shutdown. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-2 RESULTS OF STUDY OF EFFECTS OF PLUTONIUM ON ACCIDENT DOSES
Type of Accident Change in 30-day Thyroid Dose, % Change in 30-day Whole Body Dose, % Change in 2-hour Thyroid Dose, % Change in 2-hour Whole Body Dose, % Release from gas decay tank 0 -4 0 -4 Fuel handling accident +6 -3 0 0
Loss of reactor primary coolant - large break +6 -3 +5 -7 Steam generator tube rupture accident +6 -2 +4 -2 Steam line rupture accident +5 -2 +5 -2 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-3 DESIGN BASIS POSTACCIDENT ATMOSPHERIC DILUTION FACTORS (SEC/M3) Distance from Release Point, meters(a) Period, hrs 800 1200 2000 4000 7000 10,000 20,000 0-8 5.29x10-4 3.40x10-41.87x10-5 7.78x10-5 3.59x10-5 2.20x10-5 8.85x10-6 8-24 2.15x10-4 1.10x10-4 5.00x10-5 1.75x10-5 7.50x10-6 4.75x10-6 1.75x10-6 24-96 7.70x10-5 3.90x10-5 1.75x10-5 5.70x10-6 2.50x10-6 1.54x10-6 5.50x10-7 96-720 1.75x10-5 8.20x10-6 3.70x10-61.35x10-6 5.20x10-7 3.40x10-7 1.20x10-7
(a) Minimum site boundary radius is 0.5 miles (approximately 800 m). Radius of low population zone is 6.2 miles (approximately 10,000 m).
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-4 EXPECTED POSTACCIDENT ATMOSPHERIC DILUTION FACTORS (SEC/M3) Distance from Release Point, meters(a) Period, hrs 800 1200 2000 4000 7000 10,000 20,000 0-8 5.29x10-5 3.40x10-5 1.87x10-5 7.78x10-5 3.59x10-6 2.20x10-6 8.85x10-7 8-24 2.15x10-5 1.40x10-5 5.00x10-6 1.75x10-6 7.50x10-7 4.75x10-7 1.75x10-7 24-96 7.70x10-6 3.90x10-6 1.75x10-6 5.70x10-7 2.50x10-7 1.54x10-7 5.50x10-8 96-720 1.75x10-6 8.20x10-7 3.70x10-7 1.35x10-7 5.20x10-8 3.40x10-8 1.20x10-8 (a) Minimum site boundary radius is 0.5 miles (approximately 800 m). Radius of low population zone is 6.2 miles (approximately 10,000 m).
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-5 ATMOSPHERIC DILUTION FACTORS /Q x 108 sec-m-3 Onshore Sector Sector Midpoint Downwind Distance, miles Midpoint Directions 5 15 25 35 45 55 SSE 1.61 0.54 0.32 0.23 0.18 0.15 S 1.44 0.48 0.29 0.21 0.16 0.13 SSW 0.79 0.26 0.16 0.11 0.09 0.07 SW 0.54 0.18 0.11 0.08 0.06 0.05 WSW 0.65 0.22 0.13 0.09 0.07 0.06 W 1.08 0.36 0.22 0.15 0.12 0.10 WNW 1.19 0.40 0.24 0.17 0.13 0.11 NW 5.39 1.80 1.08 0.77 0.60 0.49 NNW 1.94 0.65 0.39 0.28 0.22 0.18
Atmospheric Dilution Factors /Q x 106 sec-m-3 Downwind Distance, meters Direction 800 1200 2000 4000 7000 10,000 20,000 SE 0.75 0.47 0.19 0.087 0.050 0.035 0.018
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-6 ASSUMED ONSITE ATMOSPHERIC DILUTION FACTORS (SEC/M3) FOR THE CONTROL ROOM Base /Q(a) Modifying Factors Final Period, hrs. Sec/m3 f1 f2 f3 f4 f5 f6 Q(a) A. For The Pressurization Case
0-8 1.084x10-3 1 1 .2 1 .5 .65 7.05x10-5 8-24 1.084x10-3 .83 .92 .2 1 .5 .65 5.38x10-5 24-96 1.084x10-3 .66 .84 .2 1 .5 .65 3.91x10-5 96-720 1.084x10-3 .48 .67 .2 1 .5 .65 2.27x10-5 B. For The Infiltration Case
0-8 3.01x10-3 1 1 .2 1 .5 .65 1.96x10-4 8-24 3.01x10-3 .83 .92 .2 1 .5 .65 1.49x10-4 24-95 3.01x10-3 .66 .84 .2 1 .5 .65 1.08x10-4 96-720 3.01x10-3 .48 .67 .2 1 .5 .65 6.29x10-5 (a) The /Q calculated above do not account for credit for dual pressurization inlet and occupancy factors. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-7 BREATHING RATES(a) ASSUMED IN ANALYSIS Design Basis Case Expected Case Period Offsite Onsite Offsite Onsite 0-8 hrs 3.47x10-4 3.47x10-4 2.32x10-4 3.47x10-4 8-24 hrs 1.75x10-4 3.47x10-4 2.32x10-4 3.47x10-4 1-30 days 2.32x10-4 3.47x10-4 2.32x10-4 3.47x10-4 (a) All breathing rates are expressed in m3/sec. Values taken from Reference 8. DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-8 POPULATION DISTRIBUTION Onshore Sector Sector Midpoint Downwind Distance, miles Total Midpoint Sector Directions 5 15 25 35 45 55 Population SSE 1,014 4,727 2,700 5,433 1,567 697 16,138 S 1,000 4,666 2,000 4,234 466 466 12,832 SSW 1,367 20,334 7,000 4,933 1,167 1,100 35,901 SW 366 15,666 5,000 700 700 634 23,066 WSW 840 26,000 6,600 1,767 1,433 1,533 38,173 W 474 10,334 1,600 1,066 734 900 15,108 WNW 1,843 20,033 22,933 19,734 16,066 6,900 87,509 NW 0 9,700 21,334 18,666 15,334 6,000 71,034 NNW 0 0 21,333 22,267 19,133 6,500 69,233
Total Radial Population 6,904 111,460 90,500 78,800 56,600 24,730 368,944
DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 15.5-9 SUMMARY OF OFFSITE DOSES FROM LOSS OF ELECTRICAL LOAD Thyroid Doses, rem Site Boundary - 2 Hours LPZ - 30 Days 10 CFR 100 300 300 Design basis case 0.028 0.0065 Expected case 5.2 x 10-6 8.7 x 10-7 Whole Body Doses, rem Site Boundary - 2 Hours LPZ - 30 Days 10 CFR 100 25 25 Design basis case 2.3 x 10-3 2.3 x 10-4 Expected case 7.2 x 10-7 6.9 x 10-8 Population Doses, man-rem Design basis case 0.15 Expected case 3.8 x 10-5
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-10 Sheet 1 of 2 Revision 12 September 1998 SUMMARY OF OFFSITE DOSES FROM A SMALL LOSS-OF-COOLANT ACCIDENT NO FUEL DAMAGE Thyroid Doses, rem Site Boundary - 2 Hours LPZ - 30 Days 10 CFR 100 300 300 Design basis case 2.0 x 10-4 2.7 x 10-5 Expected case 9.0 x 10-7 1.2 x 10-7 Whole Body Doses, rem Site Boundary - 2 Hours LPZ - 30 Days 10 CFR 100 25 25 Design basis case 1.8 x 10-4 5.4 x 10-5 Expected case 4.4 x 10-6 1.4 x 10-6 Population Doses, man-rem Design basis case 0.36 Expected case 0.013
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-10 Sheet 2 of 2 Revision 12 September 1998 FUEL DAMAGE Thyroid Doses, rem EAB - 2 Hours LPZ - 30 Days 10 CFR 100 300 300 Design basis case 26.38 2.60 Whole Body Doses, rem EAB - 2 Hours LPZ - 30 Days 10 CFR 100 25 25 Design basis case 0.148 0.0108
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-11 SUMMARY OF OFFSITE DOSES FROM AN UNDERFREQUENCY ACCIDENT Thyroid Doses, rem Site Boundary - 2 Hours LPZ - 30 Days 10 CFR 100 300 300 Design basis case 0.021 0.0066 Expected case 4.0 x 10-6 1.2 x 10-6 Whole Body Doses, rem Site Boundary - 2 Hours LPZ - 30 Days 10 CFR 100 25 25 Design basis case 0.0018 2.2 x 10-4 Expected case 5.3 x 10-7 6.6 x 10-8 Population Doses, man-rem Design basis case 0.15 Expected case 4.3 x 10-5
DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 15.5-12 SUMMARY OF OFFSITE DOSES FROM A SINGLE ROD CLUSTER CONTROL ASSEMBLY WITHDRAWAL Thyroid Doses, rem Site Boundary - 2 Hours LPZ - 30 Days 10 CFR 100 300 300 Design basis case 0.12 0.043 Expected case 9.5 x 10-5 3.4 x 10-5 Whole Body Doses, rem Site Boundary - 2 Hours LPZ - 30 Days 10 CFR 100 25 25 Design basis case 6.1 x 10-3 6.7 x 10-4 Expected case 6.5 x 10-6 6.9 x 10-7 Population Doses, man-rem Design basis case 0.42 Expected case 4.3 x 10-4
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-13 CALCULATED ACTIVITY RELEASES FROM LOCA - EXPECTED CASE (CURIES) Nuclide 0-2 hr 2-8 hr 8-24 hr 24-96 hr 4-30 Days I-131 0.4105E-01 0.0 0.0 0.0 0.0 I-132 0.6675E-02 0.0 0.0 0.0 0.0 I-133 0.3110E-01 0.0 0.0 0.0 0.0 I-134 0.7392E-02 0.0 0.0 0.0 0.0 I-135 0.1629E-01 0.0 0.0 0.0 0.0 I-131ORG 0.1424E-01 0.3356E-01 0.4704E-01 0.1384E-01 0.1660E-03 I-132ORG 0.1780E-02 0.1556E-02 0.2210E-03 0.4311E-06 0.6136E-17 I-133ORG 0.1049E-01 0.2211E-01 0.2334E-01 0.3542E-02 0.5058E-05 I-134ORG 0.1314E-02 0.2862E-03 0.1670E-05 0.9077E-12 0.0 I-135ORG 0.5139E-02 0.8365E-02 0.4731E-02 0.1933E-03 0.1730E-08 I-131PAR 0.0 0.0 0.0 0.0 0.0 I-132PAR 0.0 0.0 0.0 0.0 0.0 I-133PAR 0.0 0.0 0.0 0.0 0.0 I-134PAR 0.0 0.0 0.0 0.0 0.0 I-135PAR 0.0 0.0 0.0 0.0 0.0 Kr-83M 0.3823E 00 0.3085E 00 0.3684E-01 0.4757E-04 0.1063E-15 Kr-65 0.5356E 01 0.1598E 02 0.4257E 02 0.9571E 02 0.8243E 03 Kr-85M 0.1750E 01 0.2889E 01 0.1689E 01 0.7387E-01 0.8775E-06 Kr-87 0.1285E 01 0.6227E 00 0.2430E-01 0.1922E-05 0.1515E-22 Kr-88 0.3503E 01 0.4192E 01 0.1180E 01 0.1097E-01 0.1648E-09 Xe-133 0.5617E 02 0.1648E 03 0.4139E 03 0.7359E 03 0.1469E 04 Xe-133M 0.9285E 00 0.2650E 01 0.6162E 01 0.8236E 01 0.5596E 01 Xe-135 0.6662E 01 0.1490E 02 0.1826E 02 0.3887E 01 0.1721E-01 Xe-135M 0.1289E 00 0.6268E-03 0.7107E-10 0.1070E-28 0.0 Xe-138 0.3957E 00 0.1035E-02 0.1840E-10 0.1979E-31 0.0
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-14 CALCULATED ACTIVITY RELEASES FROM LOCA - DESIGN BASIS CASE (CURIES) Nuclide 0-2 Hr 2-8 Hr 2-24 Hr 24-96 Hr 4-30 Days I-131 0.2703E 02 0.0 0.0 0.0 0.0 I-132 0.3985E 02 0.0 0.0 0.0 0.0 I-133 0.6207E 02 0.0 0.0 0.0 0.0 I-134 0.7063E 02 0.0 0.0 0.0 0.0 I-135 0.5712E 02 0.0 0.0 0.0 0.0 I-131ORG 0.7340E 02 0.2170E 03 0.5561E 03 0.1070E 04 0.3227E 04 I-132ORG 0.8325E 02 0.8763E 02 0.1862E 02 0.9240E-01 0.8557E-10 I-133ORG 0.1639E 03 0.4314E 03 0.8078E 03 0.5263E 03 0.5383E 02 I-134ORG 0.9847E 02 0.2469E 02 0.2045E 00 0.2811E-06 0.2665E-31 I-135ORG 0.1411E 03 0.2838E 03 0.2668E 03 0.3148E 02 0.1834E-01 I-131PAR 0.9175E 02 0.2713E 03 0.6951E 03 0.1338E 04 0.4033E 04 I-132PAR 0.1041E 03 0.1095E 03 0.2327E 02 0.1155E 00 0.1070E-09 I-P33PAR 0.2048E 03 0.5392E 03 0.1010E 04 0.6579E 03 0.6728E 02 I-134PAR 0.1231E 03 0.3086E 02 0.2557E 00 0.3514E-06 0.3331E-31 I-135PAR 0.1764E 03 0.3548E 03 0.3335E 03 0.3935E 02 0.2293E-01 Kr-83M 0.9280E 03 0.7487E 03 0.8940E 02 0.1154E 00 0.2578E-12 Kr-85 0.6379E 02 0.1913E 03 0.5097E 03 0.1145E 04 0.9827E 04 Kr-85M 0.2823E 04 0.4660E 04 0.2723E 04 0.1191E 03 0.1413E-02 Kr-87 0.3847E 04 0.1864E 04 0.7273E 02 0.5752E-02 0.4530E-19 Kr-88 0.7090E 04 0.8484E 04 0.2388E 04 0.2220E 02 0.3333E-06 Xe-133 0.1684E 05 0.4942E 05 0.1241E 06 0.2205E 06 0.4392E 06 Xe-133M 0.4250E 03 0.1212E 04 0.2819E 04 0.3766E 04 0.2556E 04 Xe-135 0.7402E 04 0.1655E 05 0.2028E 05 0.4316E 04 0.1910E 02 Xe-135M 0.8506E 03 0.4137E 01 0.4690E-06 0.7061E-25 0.0 Xe-138 0.2504E 04 0.6552E 01 0.1164E-06 0.1252E-27 0.0
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-15 THYROID DOSE HOUR - CONTAINMENT LEAKAGE - EXPECTED CASE (REM) Distance From Release Point, meters Nuclide 800 1200 2000 4000 7000 10000 20000 I-131 0.7456E-03 0.4792E-03 0.2636E-03 0.1097E-03 0.5060E-04 0.3101E-04 0.1247E-04 I-132 0.4383E-05 0.2817E-05 0.1549E-05 0.6445E-06 0.2974E-06 0.1823E-06 0.7332E-07 I-133 0.1527E-03 0.9814E-04 0.5398E-04 0.2246E-04 0.1036E-04 0.6350E-05 0.2554E-05 I-134 0.2268E-05 0.1458E-05 0.8017E-06 0.3336E-06 0.1539E-06 0.9432E-07 0.3794E-07 I-135 0.2479E-04 0.1593E-04 0.8763E-05 0.3646E-05 0.1682E-05 0.1031E-05 0.4147E-06 I-131ORG 0.2587E-03 0.1663E-03 0.9145E-04 0.3805E-04 0.1756E-04 0.1076E-04 0.4328E-05 I-132ORG 0.1169E-05 0.7514E-06 0.4132E-06 0.1719E-06 0.7933E-07 0.4862E-07 0.1956E-07 I-133ORG 0.5149E-04 0.3310E-04 0.1820E-04 0.7573E-05 0.3495E-05 0.2142E-05 0.8615E-06 I-134ORG 0.4031E-06 0.2591E-06 0.1425E-06 0.5929E-07 0.2736E-07 0.1677E-07 0.6744E-08 I-135ORG 0.7820E-05 0.5026E-05 0.2764E-05 0.1150E-05 0.5307E-06 0.3252E-06 0.1308E-06 I-131PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-132PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-133PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-134PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-135PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0
TOTAL 0.1249E-02 0.8030E-03 0.4416E-03 0.1837E-03 0.8479E-04 0.5196E-04 0.2090E-04
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-16 THYROID DOSE HOUR - CONTAINMENT LEAKAGE - DESIGN BASIS CASE (REM) Distance From Release Point, meters Nuclide 800 1200 2000 4000 7000 10000 20000 I-131 0.7342E 01 0.4719E 01 0.2595E 01 0.1080E 01 0.4983E 00 0.3053E 00 0.1228E 00 I-132 0.3913E 00 0.2515E 00 0.1383E 00 0.5755E-01 0.2656E-01 0.1627E-01 0.6547E-02 I-133 0.4558E 01 0.2929E 01 0.1611E 01 0.6703E 00 0.3093E 00 0.1895E 00 0.7625E-01 I-134 0.3241E 00 0.2083E 00 0.1146E 00 0.4767E-01 0.2200E-01 0.1348E-01 0.5422E-02 I-135 0.1300E 01 0.8356E 00 0.4596E 00 0.1912E 00 0.8823E-01 0.5407E-01 0.2175E-01 I-1310RG 0.1994E 02 0.1282E 02 0.7049E 01 0.2933E 01 0.1353E 01 0.8292E 00 0.3336E 00 I-1320RG 0.8176E 00 0.5255E 00 0.2890E 00 0.1202E 00 0.5548E-01 0.3400E-01 0.1368E-01 I-1330RG 0.1203E 02 0.7734E 01 0.4253E 01 0.1770E 01 0.8166E 00 0.5004E 00 0.2013E 00 I-1340RG 0.4519E 00 0.2904E 00 0.1597E 00 0.6646E-01 0.3067E-01 0.1879E-01 0.7560E-02 I-1350RG 0.3211E 01 0.2064E 01 0.1135E 01 0.4723E 00 0.2179E 00 0.1336E 00 0.5372E-01 I-131PAR 0.2492E 02 0.1602E 02 0.8811E 01 0.3666E 01 0.1692E 01 0.1037E 01 0.4170E 00 I-132PAR 0.1022E 01 0.6568E 00 0.3613E 00 0.1503E 00 0.6936E-01 0.4250E-01 0.1710E-01 I-133PAR 0.1504E 02 0.9667E 01 0.5317E 01 0.2212E 01 0.1021E 01 0.6255E 00 0.2516E 00 I-134PAR 0.5648E 00 0.3630E 00 0.1997E 00 0.8307E-01 0.3833E-01 0.2349E-01 0.9450E-02 I-135PAR 0.4014E 01 0.2580E 01 0.1419E 01 0.5904E 00 0.2724E 00 0.1669E 00 0.6715E-01
TOTAL 0.9593E 02 0.6166E 02 0.3391E 02 0.1411E 02 0.6511E 01 0.3990E 01 0.1605E 01
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-17 THYROID DOSE DAY - CONTAINMENT LEAKAGE - EXPECTED CASE (REM) Distance From Release Point, meters Nuclide 800 1200 2000 4000 7000 10000 20000 I-131 0.7456E-03 0.4792E-03 0.2636E-03 0.1097E-03 0.5060E-04 0.3101E-04 0.1247E-04 I-132 0.4383E-05 0.2817E-05 0.1549E-05 0.6445E-06 0.2974E-06 0.1823E-06 0.7332E-07 I-133 0.1527E-03 0.9814E-04 0.5398E-04 0.2246E-04 0.1036E-04 0.6350E-05 0.2554E-05 I-134 0.2268E-05 0.1458E-05 0.8017E-06 0.3336E-06 0.1539E-06 0.9432E-07 0.3794E-07 I-135 0.2479E-04 0.1593E-04 0.8763E-05 0.3646E-05 0.1682E-05 0.1031E-05 0.4147E-06 I-131ORG 0.1252E-02 0.7543E-03 0.3960E-03 0.1587E-03 0.7223F-04 0.4452E-04 0.1762E-04 I-132ORG 0.2250E-05 0.1438E-05 0.7882E-06 0.3270E-06 0.1507E-06 0.9242E-07 0.3713E-07 I-133ORG 0.2091E-03 0.1280E-03 0.6797E-04 0.2751E-04 0.1257E-04 0.7734E-05 0.3074E-05 I-134ORG 0.4911E-06 0.3156E-06 0.1736E-06 0.7222E-07 0.3332E-07 0.2042E-07 0.8215E-08 I-135ORG 0.2352E-04 0.1473E-04 0.7955E-05 0.3264E-05 0.1498E-05 0.9202E-06 0.3679E-06 I-131PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-132PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-133PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-134PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-135PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0
TOTAL 0.2417E-02 0.1496E-02 0.8016E-02 0.3266E-03 0.1466E-03 0.9195E-04 0.3666E-04
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-18 THYROID DOSE DAY - CONTAINMENT LEAKAGE - DESIGN BASIS CASE (REM) Distance From Release Point, meters Nuclide 800 1200 2000 4000 7000 10000 20000 I-131 0.7342E 01 0.4719E 01 0.2595E 01 0.1080E 01 0.4983E 00 0.3053E 00 0.1228E 00 I-132 0.3913E 00 0.2515E 00 0.1383E 00 0.5755E-01 0.2656E-01 0.1627E-01 0.6547E-02 I-133 0.4558E 01 0.2929E 01 0.1611E 01 0.6703E 00 0.3093E 00 0.1895E 00 0.7625E-01 I-134 0.3241E 00 0.2083E 00 0.1146E 00 0.4767E-01 0.2200E-01 0.1348E-01 0.5422E-02 I-135 0.1300E 01 0.8356E 00 0.4596E 00 0.1912E 00 0.8823E-01 0.5407E-01 0.2175E-01 I-131ORG 0.1575E 03 0.8997E 02 0.4562E 02 0.1771E 02 0.7929E 01 0.4908E 01 0.1907E 01 I-132ORG 0.1716E 01 0.1098E 01 0.6020E 00 0.2499E 00 0.1152E 00 0.7062E-01 0.2838E-01 I-133ORG 0.5971E 02 0.3626E 02 0.1915E 02 0.7703E 01 0.3515E 01 0.2163E 01 0.8576E 00 I-134ORG 0.5654E 00 0.3633E 00 0.1998E 00 0.8314E-01 0.3836E-01 0.2351E-01 0.9457E-02 I-135ORG 0.1099E 02 0.6888E 01 0.3724E 01 0.1529E 01 0.7020E 00 0.4311E 00 0.1724E 00 I-131PAR 0.1969E 03 0.1125E 03 0.5703E 02 0.2214E 02 0.9912E 01 0.6135E 01 0.2384E 01 I-132PAR 0.2145E 01 0.1372E 01 0.7525E 00 0.3123E 00 0.1440E 00 0.8828E-01 0.3548E-01 I-133PAR 0.7464E 02 0.4532E 02 0.2394E 02 0.9628E 01 0.4394E 01 0.2704E 01 0.1072E 01 I-134PAR 0.7067E 00 0.4542E 00 0.2498E 00 0.1039E 00 0.4795E 01 0.2939E-01 0.1182E-01 I-135PAR 0.1373E 02 0.8610E 01 0.4655E 01 0.1911E 01 0.8775E 00 0.5389E 00 0.2155E 00
TOTAL 0.5326E 03 0.3117E 03 0.1608E 03 0.6342E 02 0.2862E 02 0.1767E 02 0.6926E 01
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-19 WHOLE BODY DOSE HOUR - CONTAINMENT LEAKAGE - EXPECTED CASE (REM) Distance From Release Point, meters Nuclide 800 1200 2000 4000 7000 10000 20000 I-131 0.3042E-06 0.1955E-06 0.1075E-06 0.4474E-07 0.2065E-07 0.1265E-07 0.5089E-08 I-132 0.2274E-06 0.1462E-06 0.8039E-07 0.3344E-07 0.1543E-07 0.9457E-08 0.3804E-08 I-133 0.4190E-06 0.2693E-06 0.1481E-06 0.6162E-07 0.2843E-07 0.1742E-07 0.7009E-08 I-134 0.1843E-06 0.1185E-06 0.6517E-07 0.2711E-07 0.1251E-07 0.7667E-08 0.3084E-08 I-135 0.4245E-06 0.2729E-06 0.1501E-06 0.6244E-07 0.2881E-07 0.1766E-07 0.7102E-08 I-131ORG 0.1055E-06 0.6784E-07 0.3731E-07 0.1552E-07 0.7163E-08 0.4389E-08 0.1766E-08 I-132ORG 0.6066E-07 0.3899E-07 0.2144E-07 0.8921E-08 0.4117E-08 0.2523E-08 0.1015E-08 I-133ORG 0.1413E-06 0.9082E-07 0.4995E-07 0.2078E-07 0.9589E-08 0.5876E-08 0.2364E-08 I-134ORG 0.3277E-07 0.2106E-07 0.1158E-07 0.4819E-08 0.2224E-08 0.1363E-08 0.5482E-09 I-135ORG 0.1339E-06 0.8608E-07 0.4734E-07 0.1970E-07 0.9089E-08 0.5570E-08 0.2241E-08 I-131PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-132PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-133PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-134PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-135PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Kr-83M 0.1915E-06 0.1231E-06 0.6771E-07 0.2817E-07 0.1300E-07 0.7965E-08 0.3204E-08 Kr-85 0.1469E-04 0.9439E-05 0.5192E-05 0.2160E-05 0.9967E-06 0.6108E-06 0.2457E-06 Kr-85M 0.9000E-05 0.5784E-05 0.3181E-05 0.1324E-05 0.6108E-06 0.3743E-06 0.1506E-06 Kr-87 0.4797E-04 0.3083E-04 0.1696E-04 0.7056E-05 0.3256E-05 0.1995E-05 0.8026E-06 Kr-88 0.1048E-03 0.6735E-04 0.3704E-04 0.1541E-04 0.7112E-05 0.4358E-05 0.1753E-05 Xe-133 0.1260E-03 0.8097E-04 0.4453E-04 0.1853E-04 0.8550E-05 0.5239E-05 0.2108E-05 Xe-133M 0.2658E-05 0.1708E-05 0.9396E-06 0.3909E-06 0.1804E-06 0.1105E-06 0.4447E-07 Xe-135 0.4764E-04 0.3062E-04 0.1684E-04 0.7006E-05 0.3233E-05 0.1981E-05 0.7969E-06 Xe-135M 0.8720E-06 0.5605E-06 0.3083E-06 0.1282E-06 0.5918E-07 0.3627E-07 0.1459E-07 Xe-138 0.9485E-05 0.6096E-05 0.3353E-05 0.1395E-05 0.6437E-06 0.3945E-06 0.1587E-06
TOTAL 0.3653E-03 0.2348E-03 0.1291E-03 0.5373E-04 0.2479E-04 0.1519E-04 0.6112E-05
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-20 WHOLE BODY DOSE HOUR - CONTAINMENT LEAKAGE - DESIGN BASIS CASE (REM) Distance From Release Point, meters Nuclide 800 1200 2000 4000 7000 10000 20000 I-131 0.2003E-02 0.1287E-02 0.7080E-03 0.2946E-03 0.1359E-03 0.8329E-04 0.3351E-04 I-132 0.1358E-01 0.8726E-02 0.4799E-02 0.1997E-02 0.9213E-03 0.5646E-03 0.2271E-03 I-133 0.8362E-02 0.5374E-02 0.2956E-02 0.1230E-02 0.5674E-03 0.3477E-03 0.1399E-03 I-134 0.1761E-01 0.1132E-01 0.6226E-02 0.2590E-02 0.1195E-02 0.7325E-03 0.2947E-03 I-135 0.1489E-01 0.9568E-02 0.5262E-02 0.2189E-02 0.1010E-02 0.6191E-03 0.2491E-03 I-131ORG 0.5439E-02 0.3496E-02 0.1923E-02 0.7999E-03 0.3691E-03 0.2262E-03 0.9100E-04 I-132ORG 0.2836E-01 0.1823E-01 0.1003E-01 0.4171E-02 0.1925E-02 0.1180E-02 0.4745E-03 I-133ORG 0.2207E-01 0.1419E-01 0.7803E-02 0.3247E-02 0.1498E-02 0.9180E-03 0.3693E-03 I-134ORG 0.2456E-01 0.1578E-01 0.8681E-02 0.3612E-02 0.1667E-02 0.1021E-02 0.4108E-03 I-135ORG 0.3677E-01 0.2363E-01 0.1300E-01 0.5408E-02 0.2495E-02 0.1529E-02 0.6152E-03 I-131PAR 0.6799E-02 0.4370E-02 0.2403E-02 0.9999E-03 0.4614E-03 0.2828E-03 0.1137E-03 I-132PAR 0.3545E-01 0.2279E-01 0.1253E-01 0.5214E-02 0.2406E-02 0.1474E-02 0.5931E-03 I-133PAR 0.2759E-01 0.1773E-01 0.9754E-02 0.4058E-02 0.1873E-02 0.1148E-02 0.4616E-03 I-134PAR 0.3070E-01 0.1973E-01 0.1085E-01 0.4514E-02 0.2083E-02 0.1277E-02 0.5135E-03 I-135PAR 0.4546E-01 0.2954E-01 0.1625E-01 0.6760E-02 0.3119E-02 0.1911E-02 0.7689E-03 Kr-83M 0.4649E-02 0.2988E-02 0.1643E-02 0.6837E-03 0.3155E-03 0.1933E-03 0.7777E-04 Kr-85 0.1749E-02 0.1124E-02 0.6182E-03 0.2572E-03 0.1187E-03 0.7273E-04 0.2926E-04 Kr-85M 0.1452E 00 0.9330E-01 0.5131E-01 0.2135E-01 0.9851E-02 0.6037E-02 0.2428E-02 Kr-87 0.1436E 01 0.9232E 00 0.5077E 00 0.2112E 00 0.9747E-01 0.5973E-01 0.2403E-01 Kr-88 0.2121E 01 0.1363E 01 0.7498E 00 0.3120E 00 0.1440E 00 0.8822E-01 0.3549E-01 Xe-133 0.3778E 00 0.2428E 00 0.1335E 00 0.5556E-01 0.2564E-01 0.1571E-01 0.6320E-02 Xe-133M 0.1216E-01 0.7818E-02 0.4300E-02 0.1789E-02 0.8255E-03 0.5059E-03 0.2035E-03 Xe-135 0.5293E 00 0.3402E 00 0.1871E 00 0.7784E-01 0.3592E-01 0.2201E-01 0.8855E-02 Xe-135M 0.5756E-01 0.3699E-01 0.2035E-01 0.8465E-02 0.3906E-02 0.2394E-02 0.9629E-03 Xe-138 0.6003E 00 0.3858E 00 0.2122E 00 0.8829E-01 0.4074E-01 0.2497E-01 0.1004E-01
TOTAL 0.5606E 01 0.3603E 01 0.1982E 01 0.8245E 00 0.3805E 00 0.2332E 00 0.9379E-01
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-21 WHOLE BODY DOSE DAY - CONTAINMENT LEAKAGE - EXPECTED CASE (REM) Distance From Release Point, meters Nuclide 800 1200 2000 4000 7000 10000 20000 I-131 0.3042E-00 0.1955E-06 0.1075E-06 0.4474E-07 0.2065E-07 0.1265E-07 0.5089E-08 I-132 0.2274E-06 0.1462E-06 0.8039E-07 0.3344E-07 0.1543E-07 0.9457E-08 0.3804E-08 I-133 0.4190E-06 0.2693E-06 0.1481E-06 0.6162E-07 0.2843E-07 0.1742E-07 0.7009E-08 I-134 0.1843E-06 0.1185E-06 0.6517E-07 0.2711E-07 0.1251E-07 0.7667E-08 0.3084E-08 I-135 0.4245E-06 0.2729E-06 0.1501E-06 0.6244E-07 0.2881E-07 0.1766E-07 0.7102E-08 I-131ORG 0.5109E-06 0.3078E-06 0.1616E-06 0.6474E-07 0.2947E-07 0.1816E-07 0.7187E-08 I-132ORG 0.1167E-06 0.7463E-07 0.4090E-07 0.1697E-07 0.7822E-08 0.4796E-08 0.1927E-08 I-133ORG 0.5738E-06 0.3511E-06 0.1865E-06 0.7549E-07 0.3448E-07 0.2122E-07 0.8435E-08 I-134ORG 0.3992E-07 0.2566E-07 0.1411E-07 0.5870E-08 0.2709E-08 0.1660E-08 0.6677E-09 I-135ORG 0.4028E-06 0.2522E-06 0.1362E-06 0.5590E-07 0.2566E-07 0.1576E-07 0.6301E-08 I-131PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-132PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-133PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-134PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I-135PAR 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Kr-83M 0.3536E-06 0.2263E-06 0.1241E-06 0.5151E-07 0.2375E-07 0.1456E-07 0.5851E-08 Kr-85 0.2189E-03 0.1162E-03 0.5620E-04 0.2106E-04 0.9086E-05 0.5697E-05 0.2150E-05 Kr-85M 0.2744E-04 0.1717E-04 0.9267E-05 0.3800E-05 0.1744E-05 0.1071E-05 0.4283E-06 Kr-87 0.7159E-04 0.4596E-04 0.2526E-04 0.1050E-04 0,4846E-05 0.2970E-05 0.1195E-05 Kr-88 0.2446E-03 0.1553E-03 0.8472F-04 0.3503E-04 0.1612E-04 0.9891E-05 0.3968E-05 Xe-133 0.1222E-02 0.6844E-03 0.3406E-03 0.1298E-03 0.5784E-04 0.3588E-04 0.1383E-04 Xe-133M 0.2137E-04 0.1224E-04 0.6179E-05 0.2385E-05 0.1072E-05 0.6632E-06 0.2578E-06 Xe-135 0.2113E-03 0.1283E-03 0.6775E-04 0.2729E-04 0.1244E-04 0.7664E-05 0.3040E-05 Xe-135M 0.8763E-06 0.5632E-06 0.3098E-06 0.1289E-06 0.5947E-07 0.3644E-07 0.1466E-07 Xe-138 0.9510E-05 0.6112E-05 0.3362E-05 0.1399E-05 0.6454E-06 0.3955E-06 0.1591E-06
TOTAL 0.2031E-02 0.1169E-02 0.5949E-03 0.2319E-03 0.1041E-03 0.6441E-04 0.2510E-04
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-22 WHOLE BODY DOSE DAY - CONTAINMENT LEAKAGE - DESIGN BASIS CASE (REM) Distance From Release Point, meters Nuclide 800 1200 2000 4000 7000 10000 20000 I-131 0.2003E-02 0.1287E-02 0.7080E-03 0.2946E-03 0.1359E-03 0.8329E-04 0.3351E-04 I-132 0.1358E-01 0.8726E-02 0.4799E-02 0.1997E-02 0.9213E-03 0.5646E-03 0.2271E-03 I-133 0.8362E-02 0.5374E-02 0.2956E-02 0.1230E-02 0.5674E-03 0.3477E-03 0.1399E-03 I-134 0.1761E-01 0.1132E-01 0.6226E-02 0.2590E-02 0.1195E-02 0.7325E-03 0.2947E-03 I-135 0.1489E-01 0.9568E-02 0.5262E-02 0.2189E-02 0.1010E-02 0.6191E-03 0.2491E-03 I-131ORG 0.5773E-01 0.3196E-01 0.1580E-01 0.5993E-02 0.2655E-02 0.1650E-02 0.6331E-03 I-132ORG 0.6080E-01 0.3874E-01 0.2118E-01 0.8773E-02 0.4041E-02 0.2478E-02 0.9950E-03 I-133ORG 0.1350E 00 0.7950E-01 0.4103E-01 0.1617E-01 0.7327E-02 0.4523E-02 0.1777E-02 I-134ORG 0.3073E-01 0.1975E-01 0.1086E-01 0.4519E-02 0.2085E-02 0.1278E-02 0.5140E-03 I-135ORG 0.1402E 00 0.8624E-01 0.4599E-01 0.1868E-01 0.8540E-02 0.5254E-02 0.2091E-02 I-131PAR 0.7216E-01 0.3995E-01 0.1975E-01 0.7492E-02 0.3318E-02 0.2062E-02 0.7914E-03 I-132PAR 0.7600E-01 0.4843E-01 0.2648E-01 0.1097E-01 0.5051E-02 0.3098E-02 0.1244E-02 I-133PAR 0.1687E 00 0.9938E-01 0.5128E-01 0.2022E-01 0.9158E-02 0.5654E-02 0.2221E-02 I-134PAR 0.3842E-01 0.2469E-01 0.1358E-01 0.5648E-02 0.2606E-02 0.1597E-02 0.6425E-03 I-135PAR 0.1752E 00 0.1078E 00 0.5749E-01 0.2334E-01 0.1067E-01 0.6567E-02 0.2614E-02 Kr-83M 0.8581E-02 0.5492E-02 0.3011E-02 0.1250E-02 0.5764E-03 0.3533E-03 0.1420E-03 Kr-85 0.2616E-01 0.1389E-01 0.6716E-02 0.2517E-02 0.1086E-02 0.6809E-03 0.2570E-03 Kr-85M 0.4426E 00 0.2769E 00 0.1495E 00 0.6129E-01 0.2813E-01 0.1728E-01 0.6907E-02 Kr-87 0.2143E 01 0.1376E 01 0.7563E 00 0.3145E 00 0.1451E 00 0.8892E-01 0.3576E-01 Kr-88 0.4951E 01 0.3144E 01 0.1715E 01 0.7090E 00 0.3264E 00 0.2002E 00 0.8032E-01 Xe-133 0.3663E 01 0.2051E 01 0.1021E 01 0.3891E 00 0.1734E 00 0.1075E 00 0.4145E-01 Xe-133M 0.9778E-01 0.5599E-01 0.2827E-01 0.1091E-01 0.4906E-02 0.3035E-02 0.1180E-02 Xe-135 0.2347E 01 0.1425E 01 0.7527E 00 0.3032E 00 0.1383E 00 0.8515E-01 0.3377E-01 Xe-135M 0.5784E-01 0.3717E-01 0.2045E-01 0.8506E-02 0.3925E-02 0.2405E-02 0.9676E-03 Xe-138 0.6019E 00 0.3868E 00 0.2128E 00 0.8852E-01 0.4085E-01 0.2503E-01 0.1007E-01
TOTAL 0.1535E 02 0.9385E 01 0.4989E 01 0.2019E 01 0.9218E 00 0.5671E 00 0.2253E 00
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-23 SUMMARY OF EXPOSURE FROM CONTAINMENT LEAKAGE(a) Thyroid Doses, rem EAB - 2 Hours LPZ - 30 Days 10 CFR 100 300 300 Design basis case 95.9 17.7 Expected case 1.25 x 10-3 9.20 x 10-5 Whole Body Doses, rem EAB - 2 Hours LPZ - 30 Days 10 CFR 100 25 25 Design basis case 5.61(b) 0.57(c) Expected case 3.65 x 10-4 6.44 x 10-5 Population Doses, man-rem Design basis case 932.1 Expected case 0.269 (a) These values correspond to the original analysis. See Table 15.5-75 for current analysis
(b) The EAB Whole Body dose of 5.61 rem is 3.69 rem gamma and 1.92 rem beta
(c) The LPZ Whole Body dose of 0.57 rem is 0.33 rem gamma and 0.24 rem beta
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-24 Sheet 1 of 5 Revision 12 September 1998 ASSUMPTIONS USED TO CALCULATE OFFSITE EXPOSURES FROM POST-LOCA CIRCULATION LOOP LEAKAGE IN THE AUXILIARY BUILDING Expected Expected DBA DBA Small Leakage Large Leakage Small Leakage Large Leakage A. ECCS, Containment Fan Cooler, Containment Spray System Operation 1. ECCS trains functioning 2 2 2 2
- 2. Containment fan coolers functioning 5 5 2 2
- 3. Containment spray system trains functioning 2 2 1 1 B. Activity Deposited in Containment Recirculation Sump Water 1. Iodine
- 1. Iodine (Core inventory base on both U-235 & PU-239 fissions) 100% of gap inventory per Table 11.1-7; (I-127, 129, rel.
fract. of 0.015; I-131, 132, 133, 134, 135 rel. fract. Table 11.1-
- 7) 100% of gap inventory per Table 11.1-7; (I-127, 129, rel. fract. of 0.015; I-131, 132, 133, 134, 135, rel. fract.
Table 11.1-7) 100% of gap inventory per Regulatory Guide 1.25; (I-127, 129, rel. fract. of 0.30; I-131, 132, 133, 134, 135 rel. fract. of 0.10) 100% of gap inventory per Regulatory Guide 1.25; (I-127, 129, rel. fract. of I-131, 132, 133, 134, 135, rel. fract. of 0.10) a. Elemental iodine inventory 100% of gap iodine inventory 100% of gap iodine inventory 99.75% of gap iodine inventory 99.75% of gap iodine inventory (1) I-127 30.2g, 0 Ci 30.2g, 0 Ci 903g, 0 Ci 903g, 0 Ci (2) I-129 148.5g, 0 Ci 148.5g, 0 Ci 4,445g, 0 Ci 4,445g, 0 Ci (3) I-131, 132, 133, 134, 135 6.5g, 1.82x106Ci 6.5g, 1.82x106Ci 97g, 8.45x107Ci 97g, 8.45x107Ci DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-24 Sheet 2 of 5 Revision 12 September 1998 Expected Expected DBA DBA Small Leakage Large Leakage Small Leakage Large Leakage
- b. Organic iodine 0% of gap iodine inventory 0% of gap iodine inventory 0.25% of gap iodine inventory 0.25% of gap iodine inventory (1) I-127 0.0 0.0 2g, 0 Ci 2g, 0 Ci (2) I-129 0.0 0.0 11g, 0 Ci 11g, 0 Ci (3) I-131, 132, 133, 134, 135 0.0 0.0 02g, 2.12x105Ci 02g, 2.12x105Ci c. Total iodine 185.2g, 1.82x106Ci 185.2g, 182x106Ci 5.458g, 8.47x107Ci 5.458g, 8.47x107Ci 2. Noble Gases 0.0 0.0 0.0 0.0 Other fission products 0.0 0.0 0.0 0.0
C. Containment Recirculation Sump Decay and Cleanup 1. Radiological decay credit Yes Yes Yes Yes
- 2. Cleanup credit None None None None D. Volume of Water in Which Activity is Deposited (diluted) 1. Reactor coolant water, gal. 93,960 93,960 93,960 93,960
- 2. Accumulator water, gal. 25,040 25,040 25,040 25,040
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-24 Sheet 3 of 5 Revision 12 September 1998 Expected Expected DBA DBA Small Leakage Large Leakage Small Leakage Large Leakage D. Volume of Water in Which Activity is Deposited (diluted) (Cont'd) 3. Refueling water storage tank, gal. (Table 6.3-1) 350,000 262,030 350,000 254,220 4. Total, gal. 469,000 381,030 469,000 373,220 E. Conditions of Loop Leakage Water
- 1. pH of leakage water (Figure 6.2-15) 8.8 8.4 8.5 7.85 2. Temperature of leakage water, °F 120 238 120 242 F. Loop Leakage Rate 1910 cc/hr. 50 gpm (Table 6.3-9) 1910 cc/hr 50 gpm (Table 6.3-9)
G. Duration of Loop Leakage
- 1. Time after LOCA leakage begins, hr (Table 6.3-5) 0.337 0.337 0.395 0.395 2. Time after LOCA leakage ends, hr 720 0.837 720 0.895 3. Total duration of loop leakage, hr 719.7 0.5 719.6 0.5 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-24 Sheet 4 of 5 Revision 12 September 1998 Expected Expected DBA DBA Small Leakage Large Leakage Small Leakage Large Leakage H. Auxiliary Building Iodine Decontamination Factors
- 1. Elemental iodine decontamination factor a. M vapor, lbm - 2.78 x 102-2 - 3.22 x 10-2 M liquid, lbm b. V vapor, ft3/lbm - 1.60 x 10+3 - 1.60 x 10+3 V liquid, ft3/lbm c. Partition coefficient, - 7.22 x 10+5 - 6.77 x 10+3 PC, (g/1) liquid (g/1) gas
- d. Partition factor, - 6.18 x 10-5 - 7.62 x 10-3 PF, (g) gas (g) liquid
- e. Decontamination factor, 1.0 1.62 x 10+4 1.0 1.32 x 10+2 DF, (g) leak (g) gas
- 2. Organic iodine decontami- 1.0 1.0 1.0 1.0 nation factor, DF, (g) leak (g) gas
I. Auxiliary Building Decay, Plateout, and Filter Removal
- 1. Radiological decay credit None None None None
- 2. Plateout credit None None None None
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-24 Sheet 5 of 5 Revision 12 September 1998 Expected Expected DBA DBA Small Leakage Large Leakage Small Leakage Large Leakage I. Auxiliary Building Decay, Plateout, and Filter Removal (Cont'd) 3. Auxiliary building None Yes None Yes filter credit a. Iodine filter efficiency (1) Elemental iodine, % 0.0 99.0 0.0 90.0 (2) Organic iodine, % 0.0 85.0 0.0 70.0 (3) Particulate iodine % 0.0 99.0 0.0 90.0 b. Noble gases 0.0 0.0 0.0 0.0 J. Atmospheric Dispersion
- 1. Down wind radiological None None None None decay credit 2. Atmospheric dilution Table 15.5-4 Table 15.5-4 Table 15.5-4 Table 15.5-4 factors K. Breathing Rates Table 15.5-7 Table 15.5-7 Table 15.5-7 Table 15.5-7
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-25 OFFSITE EXPOSURES FROM POST-LOCA CIRCULATION LOOP LEAKAGE IN THE AUXILIARY BUILDING Expected Expected Small Large DBA Small DBA Large Leakage Leakage Leakage Leakage Case Case Case Case (1000m, (800m, (1000m, (800m, 30-day) 2-hour) 30-day) 2-hour) Elemental iodine thyroid exposure, rem 0.012 4.0 x 10-5 2.1 13.5 Organic iodine thyroid exposure, rem - - 0.0054 13.4
Total iodine thyroid exposure, rem 0.012 4.0 x 10-5 2.1 26.9 Beta and gamma whole body exposure, rem 1.0 x 10-5 6.1 x 10-8 0.0038 0.092
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-26 PERCENTAGE OCCURRENCE OF WIND DIRECTION AND CALM WINDS EXPRESSED AS PERCENTAGE OF TOTAL HOURLY OBSERVATIONS WITHIN EACH SEASON AT THE SITE (250-FOOT LEVEL) Wind Direction
Season (a) Offshore (b) Onshore (c) Calm (d) Annual 57% 38% 5% Dry 55% 40% 5% Wet 54% 42% 4% Transitional 62% 34% 4%
(a) Dry Season - May through September Wet Season - November through March Transitional - April and October
(b) Offshore wind directions are defined as wind directions from northwest through east southeast measured clockwise. (c) Onshore wind directions are defined as wind directions from southeast through west-northwest measured clockwise. (d) Calm wind directions are defined as winds with speeds less than one 1 mph.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-27 Sheet 1 of 2 Revision 11 November 1996 DIABLO CANYON POWER PLANT SITE PROBABILITY OF PERSISTENCE OFFSHORE WIND DIRECTION SECTORS (250-FOOT LEVEL) Conse- NNE NE ENE E ESE cutive Hours A(a) D(a) W(a) T(a) A D W T A D W T A D W T A D W T 1 0.461 0.652 0.432 0.390 0.426 0.655 0.373 0.477 0.505 0.769 0.401 0.732 0.678 0.906 0.577 0.840 0.400 0.430 0.370 0.434 2 0.245 0.107 0.327 0.178 0.252 0.241 0.237 0.318 0.190 0.231 0.180 0.195 0.158 0.038 0.189 0.160 0.152 0.180 0.154 0.110 3 0.129 0.054 0.039 0.248 0.136 0.103 0.151 0.102 0.133 - 0.176 0.073 0.069 0.057 0.090 - 0.082 0.075 0.068 0.124 4 0.073 0.071 0.049 0.118 0.041 - 0.047 0.045 0.064 - 0.090 - 0.066 - 0.100 - 0.086 0.120 0.046 0.138 5 0.058 0.045 0.077 0.030 0.041 - 0.044 0.057 0.064 - 0.090 - 0.000 - 0.000 - 0.058 0.100 0.028 0.069 6 0.010 0.000 0.000 0.036 0.050 - 0.071 - 0.019 - 0.027 - 0.000 - 0.000 - 0.060 0.060 0.034 0.124 7 0.012 0.000 0.022 - 0.000 - 0.000 - 0.000 - 0.000 - 0.000 - 0.000 - 0.050 0.035 0.080 - 8 0.013 0.071 - - 0.033 - 0.047 - 0.025 - 0.036 - 0.000 - 0.000 - 0.023 - 0.046 - 9 - - - - 0.000 - 0.000 - - - - - - - 0.045 - 0.013 - 0.026 - 10 - - - - 0.021 - 0.030 - - - - - - - - - 0.014 - 0.028 - 11 - - - - - - - - - - - - - - - - 0.000 - 0.000 - 12 - - - - - - - - - - - - - - - - 0.000 - 0.000 - 13 - - - - - - - - - - - - - - - - 0.037 - 0.074 - 14 - - - - - - - - - - - - - - - - 0.000 - 0.000 - 15 - - - - - - - - - - - - - - - - 0.000 - 0.000 - 16 - - - - - - - - - - - - - - - - 0.023 - 0.046 - 17 - - - - - - - - - - - - - - - - - - - - 18 - - - - - - - - - - - - - - - - - - - - 19 - - - - - - - - - - - - - - - - - - - - 20 - - - - - - - - - - - - - - - - - - - -
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-27 Sheet 2 of 2 Revision 11 November 1996 Conse- NW NNW N Calm cutive Hours A D W T A D W T A D W T A D W T 1 0.105 0.086 0.157 0.105 0.364 0.453 0.318 0.348 0.504 0.701 0.461 0.442 0.364 0.329 0.393 0.426 2 0.091 0.073 0.142 0.090 0.194 0.194 0.201 0.178 0.200 0.124 0.217 0.231 0.237 0.214 0.239 0.313 3 0.078 0.064 0.137 0.056 0.125 0.115 0.135 0.118 0.088 0.051 0.078 0.144 0.152 0.166 0.151 0.101 4 0.067 0.058 0.111 0.049 0.085 0.089 0.103 0.042 0.104 0.090 0.122 0.077 0.103 0.081 0.164 0.054 5 0.058 0.040 0.086 0.085 0.067 0.051 0.071 0.078 0.018 0.000 0.022 0.048 0.055 0.074 0.016 0.068 6 0.062 0.048 0.098 0.068 0.036 0.036 0.046 0.016 0.049 0.034 0.052 0.058 0.018 0.022 0.000 0.041 7 0.050 0.045 0.046 0.068 0.034 0.028 0.045 0.018 0.016 - 0.030 - 0.014 0.026 0.000 - 8 0.047 0.039 0.046 0.072 0.039 0.032 0.021 0.084 0.009 - 0.017 - 0.000 0.000 0.000 - 9 0.045 0.044 0.029 0.059 0.016 - 0.023 0.024 0.000 - - - 0.027 0.050 0.000 - 10 0.038 0.044 0.008 0.049 0.006 - 0.000 0.026 0.012 - - - 0.030 0.037 0.031 - 11 0.046 0.060 0.009 0.054 0.007 - 0.000 0.029 - - - - - - - - 12 0.035 0.028 0.049 0.039 0.007 - 0.016 0.000 - - - - - - - - 13 0.038 0.054 0.011 0.011 0.000 - - 0.000 - - - - - - - - 14 0.038 0.043 0.011 0.045 0.000 - - 0.000 - - - - - - - - 15 0.019 0.027 0.000 0.012 0.009 - - 0.039 - - - - - - - - 16 0.020 0.025 0.000 0.026 0.010 - - - - - - - - - - - 17 0.022 0.031 0.000 0.014 - - - - - - - - - - - - 18 0.023 0.033 0.015 0.015 - - - - - - - - - - - - 19 0.030 0.034 0.016 0.046 - - - - - - - - - - - - 20 0.013 0.021 - 0.000 - - - - - - - - - - - - 21 0.003 0.005 - 0.000 - - - - - - - - - - - - 22 0.007 0.006 - 0.018 - - - - - - - - - - - - 23 0.004 0.006 - 0.000 - - - - - - - - - - - - 24 0.012 0.012 - 0.020 - - - - - - - - - - - - 25 0.012 0.019 - - - - - - - - - - - - - - 26 0.012 0.020 - - - - - - - - - - - - - - 27 0.004 0.007 - - - - - - - - - - - - - - 28 0.004 0.007 - - - - - - - - - - - - - - 29 0.000 0.000 - - - - - - - - - - - - - - 30 0.000 0.000 - - - - - - - - - - - - - - 31 0.005 0.008 - - - - - - - - - - - - - - (a) A = Annual D = Dry season (May through September) W = Wet season (November through March) T = Transitional months (April and October)
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-28 Sheet 1 of 2 Revision 11 November 1996 ASSUMPTIONS USED TO CALCULATE ONSHORE CONTROLLED CONTAINMENT VENTING Expected Case DBA Case A. Activity Released to Containment Atmosphere 1. Iodine 25% of gap iodine inventory 25% of core iodine inventory a. Elemental 24.95% of gap iodine inventory 22.75% of core iodine inventory b. Organic 0.05% of gap iodine inventory 1.0% of core iodine inventory
- c. Particulate 0% of gap iodine inventory 1.25% of core iodine inventory 2. Noble gases 100% of gap inventory 100% of core inventory 3. Other fission products None None B. Decay, Cleanup, and Leakage in Containment Atmosphere 1. Radiological decay credit Yes Yes 2. Iodine spray cleanup a. Elemental 92.0 hr-1 31.0 hr-1(a) b. Organic 0.58 hr-1 0 hr-1 c. Particulate 0 0 3. Filter cleanup of containment atmosphere a. Iodines None None b. Noble gases None None 4. Containment leak rate 0.05%/per day 0.05%/per day DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-28 Sheet 2 of 2 Revision 11 November 1996 Expected Case DBA Case C. Containment Atmosphere Volume 2.68 x 106 cubic feet 2.68 x 106 cubic feet D. Purge Schedule 1. Time after LOCA purging begins 1968 hours, Chapter 6 672 hours, Chapter 6
- 2. Time after LOCA purging ends 6792 hours, remainder of 1 yr. 8088 hours, remainder of 1 yr. E. Purge Flowrate 10 cfm, Chapter 6 25 cfm, Chapter 6 F. Filter Efficiency 1. Iodines a. Elemental 99% 90%
- b. Organic 85% 70%
- c. Particulate 99% 90% 2. Noble gases None None G. Atmospheric Dispersion 1. Radiological decay credit None None 2. /Qs Table 15.5-30 Table 15.5-30 H. Breathing Rates Table 15.5-7 Table 15.5-7 (a) Although a subsequent safety evaluation showed that the Design Case coefficient of 31-1 (for 2600 gpm spray header flow) should be reduced to approximately 29 hr-1 (for 2466 gpm spray header flow), the potential offsite dose increase due to this change is extremely small and can be considered insignificant (Reference 39).
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-29 ONSHORE CONTROLLED CONTAINMENT VENTING EXPOSURES DBA Expected Thyroid exposure at site 2.21 9.83 x 10-25 boundary (800 meters), rem
Whole body exposure 0.0841 7.15 x 10-3 at site boundary (800 meters), rem
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-30 ATMOSHPERIC DISPERSION FACTORS FOR ONSHORE CONTROLLED CONTAINMENT VENTING (STABILITY CATEGORY D) Distance, km /Q, sec/m3 0.8 1.437 x 10-6 1.2 2.440 x 10-6 2.0 1.968 x 10-6 4.0 7.884 x 10-7 7.0 3.135 x 10-7 10.0 1.691 x 10-7 20.0 6.099 x 10-8
Meteorological Input Parameters:
Height of release = 70 meters Mixing depth = 350 meters Mean wind speed = 5.8 meters per second Sigma theta = 10 degrees Sigma phi = 3 degrees Vertical expansion rate beta, , = 0.9 Azimuth expansion rate alpha, , = 0.9 y = x and Z = x DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-31 Sheet 1 of 2 Revision 11 November 1996 CONTROL ROOM INFILTRATION ASSUMED FOR RADIOLOGICAL EXPOSURE CALCULATIONS Leakage Path Leakage Equation Leakage (cfm) A. Windows No leakage, no windows. 0.0 B. Doors 3 C. Penetrations 1. Ducting (external seal) No leakage: ducting penetrations caulked to full depth 0.0 and exterior surfaces sealed with FLAMEMASTIC 71A and control room will be positively pressurized.
- 2. Piping (external seal) No leakage: concrete walls and floor poured with piping 0.0 in place and control room will be positively pressurized.
- 3. Conduits and trays a. External seal No leakage: space between exposed conductors and trays is 0.0 sealed with B&W KAOWOOL ceramic fiber 6 inches in depth, with two coats of FLAMEMASTIC 72A, and control room will be positively pressurized.
- b. Internal seal No leakage: conduits are sealed with THIXOTROPIC silicone 0.0 rubber compound, with a minimum depth of one diameter, and control room will be positively pressurized.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-31 Sheet 2 of 2 Revision 11 November 1996 Leakage Path Leakage Equation Leakage (cfm) D. Dampers Q = A x q x p where: Q = leakage, cfm A = damper area, square feet q = leakage per unit damper area per in. of water(a) p = pressure difference across damper, in. of water(b) 1. Mode damper #2 A = 6.00 ft2, q = 0.001 cfm/ft2 - in. and p = 6.0 in. W.G. <0.05 2. Mode damper #3 A = 1.84 ft2, q = 0.001 cfm/ft2 - in. and p = 6.0 in. W.G. <0.05 3. Mode damper #7 A = 6.00 ft2, q = 0.001 cfm/ft2 - in. and p = 6.0 in. W.G. <0.05 4. Mode damper #8 A = 1.78 ft2, q = 0.001 cfm/ft2 - in. and p = 6.0 in. W.G. <0.05 E. Total 3(c) (a) From manufacturer's published data. (b) Assume conservatively large value of 6 inches of water; dampers will never see a pressure differential this large. (c) 10 cfm is conservatively assumed in the analysis. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-32 Sheet 1 of 3 Revision 12 September 1998 ASSUMPTIONS USED TO CALCULATE POSTACCIDENT CONTROL ROOM RADIOLOGICAL EXPOSURES DBA Case A. Power Level 3580 MWt B. Activity Released to Containment Atmosphere
- 1. Iodine, % of core iodine inventory 25 a. Elemental, % of core iodine inventory 22.75
- b. Organic, % of core iodine inventory 1.00
- c. Particulate, % of core iodine inventory 1.25 2. Noble gases, % of core inventory 100
- 3. Other fission product None C. Decay, Cleanup, and Leakage in Containment Atmosphere
- 1. Radiological decay included Yes
- 2. Iodine spray cleanup
- a. Elemental 31 hr-1(a) b. Organic 0 hr-1 c. Particulate 0 hr-1 3. Decontamination factor (DF) cut-off for spray, elemental 100
- 4. Time post-LOCA spray starts 80 seconds 5. Filter cleanup of containment atmosphere None a. Iodines None
- b. Noble gases None
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-32 Sheet 2 of 3 Revision 12 September 1998 DBA Case 6. Containment leakrate
- a. First 24 hours 0.1% per day
- b. Remainder of accident period 0.05% per day D. Recirculation Loop Leakage
- 1. RHR leakage rate 50 gpm
- 2. Start of RHR leakage 0.395 hrs
- 3. Duration of RHR leakage 0.5 hr
- 4. Charcoal filter efficiency for release of RHR leakage
- a. Iodine filter efficiency (1) Elemental, % 90.0 (2) Organic, % 70.0 (3) Particulate, % 90.0
- b. Noble gas filter efficiency 0.0 E. Meteorology (atmospheric dilution factors from the containment to the control room) Table 15.5-6 F. Control Room Ventilation Flowrates 1. Flowrate of contaminated air 10 cfm infiltrating into the control room
- 2. Flowrate of pressurization air into 2100 cfm the control room 3. Flowrate of recirculated control room air 2100 cfm through cleanup filters DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-32 Sheet 3 of 3 Revision 12 September 1998 DBA Case G. Decay and Cleanup in Control Room
- 1. Radiological decay included Yes
- 2. Filter cleanup of pressurization air Yes
- a. Iodines (1) Elemental 95%
(2) Organic 95%
(3) Particulate 95%
- b. Noble gases 0%
H. Control Room Complex Volume (total for 170,000 ft3 Units 1 and 2) I. Control Room Occupancy Factors
- 1. 0-24 hours 1 2. 24-96 hours 0.6 3. 96-720 hours 0.4
(a) Although a subsequent safety evaluation showed that the Design Case coefficient of 31 hr-1 (for 2600 gpm spray header flow) should be reduced to approximately 29 hr-1 (for 2466 gpm spray header flow), the potential offsite dose increase due to this change is extremely small and can be considered insignificant (Reference 39).
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-33 ESTIMATED POSTACCIDENT EXPOSURE TO CONTROL ROOM PERSONNEL DBA Expected Case Accident Gamma Beta Thyroid Gamma Beta Thyroid Exposure, Exposure, Exposure, Exposure, Exposure, Exposure, Radiation Source rem rem rem rem rem rem
- 1. Radiation from airborne fission products 0.053 0.73 6.69(a) --- --- --- postulated to enter the control room 2. Direct radiation to the control room from 0.032 0 0 6.8 x 10-5 0 0 fission products in the containment structure
- 3. Direct radiation to the control room from 0.022 0 0 1 x 10-5 0 0 fission products in the containment leakage plume
- 4. Radiation from airborne fission products 0.0066 0.0243 4.72 1.6 x 10-5 1.0 x 10-4 5 x 10-6 in the containment leakage plume to control room personnel during egress ingress
- 5. Direct radiation from fission products in 0.022 0 0 5.3 x 10-5 0 0 the containment structure to control room personnel during egress-ingress (53 5-minute trips)
TOTAL 0.14 0.76 11.41 (a) Containment Leakage 5.74 rem HR Pump Seal Leakage (50 gpm) 0.10 rem Pre-existing leakage 0.85 rem
DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 15.5-34 STEAM RELEASES FOLLOWING A MAJOR STEAM LINE BREAK Time Period 0-2 hr 2-8 hr Steam release from ruptured pipe, lbm 171,100 Steam release from relief valves, lbm 384,000 893,000
Note: All steam releases listed above are for RSGs. OSG MSLB steam releases, which are used in the MSLB does analysis of record, are listed in item 11 of Section 15.5.18.1.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-40 LONG-TERM ACTIVITY RELEASE FRACTIONS FOR FUEL FAILURE ACCIDENTS Isotopes Release Fractions I-131 1.37 x 10-9 I-132 2.51 x 10-10 I-133 9.43 x 10-10 I-134 1.02 x 10-10 I-135 5.34 x 10-5 Kr-83M 2.16 x 10-5 Kr-85 0.98 Kr-85M 5.02 x 10-5 Kr-87 1.51 x 10-5 Kr-88 3.14 x 10-5 Xe-133 1.68 x 10-3 Xe-133M 5.52 x 10-4 Xe-135 1.07 x 10-4 Xe-135M 3.23 x 10-7 Xe-138 2.89 x 10-6
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-41 Sheet 1 of 2 Revision 11 November 1996 ACTIVITY RELEASES FOLLOWING A LOCKED ROTOR ACCIDENT (CURIES) Design Basis Case Nuclide 0-2 hr 2-8 hr I-131 8.643E-1 4.1783E0 I-132 1.121E-1 2.505E-1 I-133 7.753E-1 3.4725E0 I-134 6.086E-2 4.067E-2 I-135 3.673E-1 1.4067E0 I-131ORG 0.0 0.0 I-132ORG 0.0 0.0 I-133ORG 0.0 0.0 I-134ORG 0.0 0.0 I-135ORG 0.0 0.0 I-131PAR 0.0 0.0 I-132PAR 0.0 0.0 I-133PAR 0.0 0.0 I-134PAR 0.0 0.0 I-135PAR 0.0 0.0 Kr-83M 9.975E-1 4.281E-1 Kr-85 1.2282E1 1.6610E1 Kr-85M 4.9366E0 4.1691E0 Kr-87 3.2949E0 8.647E-1 Kr-88 8.5004E0 5.4137E0 Xe-133 2.7392E2 3.6840E2 Xe-133M 3.8638E0 5.1188E0 Xe-135 2.0293E1 2.2393E1 Xe-135M 3.026E-1 0 Xe-138 9.120E-1 0
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-41 Sheet 2 of 2 Revision 11 November 1996 Expected Case Nuclide 0-2 hr 2-8 hr
I-131 8.217E-8 2.089E-8 I-132 4.166E-8 5.113E-9 I-133 1.144E-7 2.647E-8 I-134 1.673E-8 1.111E-9 I-135 1.038E-7 1.976E-8 I-131ORG 0.0 0.0 I-132ORG 0.0 0.0 I-133ORG 0.0 0.0 I-134ORG 0.0 0.0 I-135ORG 0.0 0.0 I-131PAR 0.0 0.0 I-132PAR 0.0 0.0 I-133PAR 0.0 0.0 I-134PAR 0.0 0.0 I-135PAR 0.0 0.0 Kr-83M 7.796E-9 4.03E-10 Kr-85 5.723E-7 5.092E-8 Kr-85M 3.737E-7 2.483E-8 Kr-87 1.945E-6 8.939E-8 Kr-88 4.193E-6 2.455E-7 Xe-133 6.335E-6 5.553E-7 Xe-133M 1.248E-7 1.079E-8 Xe-135 2.020E-6 1.543E-7 Xe-135M 3.462E-8 1.440E-9 Xe-138 3.750E-7 1.560E-8 DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 15.5-42 SUMMARY OF OFFSITE DOSES FROM A LOCKED ROTOR ACCIDENT Thyroid Exposures, rem Site Boundary - 2 hours LPZ - 30 days 10 CFR 100 300 300 Design basis case 0.30 0.076 Expected case 2.5 x 10-4 6.6 x 10-5 Whole Body Exposures, rem Site Boundary - 2 hours LPZ - 30 days 10 CFR 100 25 25 Design basis case 1.3 x 10-2 1.1 x 10-3 Expected case 1.6 x 10-5 1.3 x 10-6 Population Exposures, man-rem Design basis case 0.32 Expected case 2.8 x 10-4
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-44 Revision 16 June 2005 COMPOSITE SOURCE TERM FOR FUEL HANDLING ACCIDENT IN THE FUEL HANDLING BUILDING
Isotope Composite Source Term (Ci/assembly at shutdown) Activity at 100 Hours After Shutdown (Ci at 100 hrs) Pool Activity (Ci at 100 hrs) FHB Activity Based on DF200 for Iodines (Ci at 100 hrs) I-131 5.057E+05 3.625E+05 5.9813E+04 299.0625 I-132 7.283E+05 3.042E+05 5.0193E+04 250.965 I-133 1.032E+06 3.783E+04 6.2420E+03 31.21 I-134 1.165E+06 0 0 0 I-135 9.611E+05 2.689E+01 4.4369E+00 0.0222 Kr-83m 8.196E+04 9.554E-08 1.5764E-08 1.5764E-08 Kr-85m 1.901E+05 3.679E-02 0.0060704 0.0060704 Kr-85 6.353E+03 6.350E+03 3143.25 3143.25 Kr-87 3.828E+05 0 0 0 Kr-88 5.416E+05 1.350E-05 2.2275E-06 2.2275E-06 Kr-89 6.855E+05 0 0 0 Xe-131m 5.661E+03 5.469E+03 902.385 902.385 Xe-133m 3.187E+04 1.306E+04 2154.9 2154.9 Xe-133 9.993E+05 6.914E+05 114081 114081 Xe-135m 2.021E+05 4.264E+00 0.70356 0.70356 Xe-135 2.886E+05 1.327E+03 218.955 218.955 Xe-137 9.140E+05 0 0 0 Xe-138 9.477E+05 0 0 0 Where:
The activity/Assembly at 100 hours (A100)Pool after shutdown was obtained from Ref. 8. Pool activity at 100 hours = (A100)Pool = A100 x 1.65 x release fraction = A100 x 1.65 x 0.1 for iodine and noble gases except Kr-85 and = A100 x 1.65 x 0.3 for Kr-85 FHB activity at 100 hours = (A100)Pool / 200 for iodine DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-45 Sheet 1 of 2 Revision 17 November 2006 ASSUMPTIONS FOR FUEL HANDLING ACCIDENT IN THE FUEL HANDLING AREA A. Preaccident Operation
- 1. Core Power 3580 MWt B. Highest Power Fuel Assembly Characteristics 1. Radial peaking factor 1.65 C. Fuel Assembly Damage 1. Number of fuel rods per assembly 264 2. Number of fuel rods ruptured per assembly 264 3. Number of fuel assemblies damaged 1 D. Gap Activity Fractions 1. Iodine 0.10 a. Elemental 0.09975
- b. Organic 0.00025
- c. Particulate 0.0 D. Gap Activity Fractions (Continued) 2. Noble gases
- a. Other than Kr-85 0.10
- b. Kr-85 0.30
- 3. Other fission products None E. Gap Activity Release Fractions
- 1. Iodine 1
- 2. Noble gases 1 3. Other fission products None F. Fission Product Release Depth 23 feet G. Spent Fuel Pool Decontamination Factors
- 1. Iodine 200
- a. Elemental 500
- b. Organic 1 Particulate None
- 2. Noble gases 1
- 3. Other fission products None H. Decay and Cleanup in Fuel Handling Building 1. Radiological decay credit None DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-45 Sheet 2 of 2 Revision 17 November 2006 2. Radiological cleanup credit None I. Fuel Handling Building Volume 435,000 ft3 J. Fuel Handling Building Filter Efficiencies Not credited K. Fuel Handling Building Exhaust Rate 40,000 cfm L. Atmospheric Dispersion 1. Radiological decay credit None 2. /Qs EAB (800m) 0 to 2 hr 9.9E-4 sec/m3 LPZ (10 km) 0 to 8 hr 2.6E-5 sec/m3 8 to 24 hr 4.5E-6 sec/m3 24 to 96 hr 1.6E-6 sec/m3 96 to 720 hr 3.3E-7 sec/m3 M. Offsite Breathing Rates Table 15.5-7 N. Offsite Power (a) __________________
(a) Assumes the FHB ventilation operates continuously to maximize the FHB exhaust to the early stages of this event with or without offsite power.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 15.5-47 SUMMARY OF DOSES FROM FUEL HANDLING ACCIDENT IN THE FUEL HANDLING AREA TEDE Exposures, rem Site Boundary 2 - Hours LPZ - 30 Days Regulatory Limit 6.3 6.3 Design basis case 4.265 0.112
Control Room Regulatory Limit 5 Design basis case 0.689
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-48 Sheet 1 of 2 Revision 18 October 2008 DESIGN INPUTS AND ASSUMPTIONS FOR FUEL HANDLING ACCIDENTS INSIDE CONTAINMENT Parameter Value Containment: Containment Free Volume (ft3) 2.55E+06 Containment Volume above Fuel Pool (ft3) 33600 Purge Line Flowrate to Environment (CFM) 13750 Depth of Water Above Damaged Fuel (ft) >23 Iodine Decontamination Factors Organic 1 Inorganic (Elemental) 500 Overall Effective 200
Exfiltration Rate (cfs) 2.55E+06 Duration of Release (sec) 1.0
Time of Accident after Shutdown (hr) 100 Number of Failed Rods 264
Gap Activity Released from Damaged Rods (%) Kr-85 30 Noble Gases other than Kr-85 10 Iodines 10
Iodine Gap Inventory (%) Iorganic 99.75 Organic 0.25 Values Assumed for Generation of Inventories Reactor Power (%RTP) 105 Reactor Power (MWt) 3580 Radial Peaking Factor 1.65
Dose Conversion Factors for Iodine Species (REM/Ci) I-131 1.08E+06 I-132 6.44E+03 I-133 1.80E+05 I-134 1.07E+03 I-135 3.13E+04 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-48 Sheet 2 of 2 Revision 18 October 2008 Parameter Value Control Room (CR) Input Data: Control Room Volume (U1 +U2) (cubic feet) 170000 Flowrates (CFM)
Flowrate of contaminated air into CR 2110 Flowrate of recirc CR air thru filters 0 CR pressurization air filter Filter Depth 2 inches Iodine Filter Efficiency Elemental 95% Organic 95% Particulate 95% CR Occupancy Factors 0 - 8 hours 1 24 -96 hours 0.6 96 - 720 hours 0.4 Atmospheric Dispersion Factors (sec/m3) Control Room Pressurization: 0 - 8 hours 7.05E-05 8 - 24 hours 5.38E-05 24 - 96 hours 3.91E-05 96 - 720 hours 2.27E-05 Control Room Infiltration : 0 - 8 hours 1.96E-04 8 - 24 hours 1.49E-04 24 - 96 hours 1.08E-04 96 - 720 hours 6.29E-05 Exclusion Area Boundary (EAB), 800 meters 0 - 2 hours 5.29E-04 Low Population Zone (LPZ), 10,000 meters 0 - 8 hours 2.20E-05 8 -24 hours 4.75E-06 1 - 4 days 1.54E-06 4 - 30 days 3.40E-07 Control Room Breathing Rate (m3/sec): 3.47E-04 Offsite Breathing Rates: 0 - 8 hours 3.47E-04 8 -24 hours 1.75E-04 1 - 30 days 2.32E-04 DCPP UNITS 1 & 2 FSAR UPDATE Revision 15 September 2003 TABLE 15.5-49 ACTIVITY RELEASES FROM FUEL HANDLING ACCIDENT INSIDE CONTAINMENT (CURIES) (LOPAR FUEL) Design Basis Case Nuclide 0-2 hr I-131 299.0625 I-132 250.965 I-133 31.31 I-134 0 I-135 0.0222 Kr-83m 1.5764E-08 Kr-85m 0.0060704 Kr-85 3143.25 Kr-87 0 Kr-88 2.2275E-06 Kr-89 0 Xe-131m 902.385 Xe-133m 2154.9 Xe-133 114081 Xe-135m 0.70356 Xe-135 218.955 Xe-137 0 Xe-138 0 DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 15.5-50 SUMMARY OF OFFSITE DOSES FROM FUEL HANDLING ACCIDENT INSIDE CONTAINMENT Thyroid Exposures, rem Control Room - 30 Days Site Boundary - 2 Hours LPZ - 30 Days 10 CFR 100 30 (GDC 19) 300 300 Design-basis case 22.31 60.62 2.52 Whole Body Immersion Exposures, rem Control Room - 30 Days Site Boundary - 2 Hours LPZ - 30 Days 10 CFR 100 5 (GDC 19) 25 25 Design-basis case 7.57x10-3 0.43 0.018 Population Exposures, man-rem Design basis case 8.53 Expected case 3 x 10-3
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-51 Sheet 1 of 2 Revision 11 November 1996 ACTIVITY RELEASES FOLLOWING A ROD EJECTION ACCIDENT (CURIES) Design Basis Case Nuclide 0-2 hr 2-8 hr 8-24 hr 24-96 hr 4-30 Days I-131 0.9765E-02 0.0 0.0 0.0 0.0 I-132 0.1578E-02 0.0 0.0 0.0 0.0 I-133 0.7394E-02 0.0 0.0 0.0 0.0 I-134 0.1729E-02 0.0 0.0 0.0 0.0 I-135 0.3867E-02 0.0 0.0 0.0 0.0 I-131ORG 0.0 0.0 0.0 0.0 0.0 I-132ORG 0.0 0.0 0.0 0.0 0.0 I-133ORG 0.0 0.0 0.0 0.0 0.0 I-134ORG 0.0 0.0 0.0 0.0 0.0 I-135ORG 0.0 0.0 0.0 0.0 0.0 I-131PAR 0.0 0.0 0.0 0.0 0.0 I-132PAR 0.0 0.0 0.0 0.0 0.0 I-133PAR 0.0 0.0 0.0 0.0 0.0 I-134PAR 0.0 0.0 0.0 0.0 0.0 I-135PAR 0.0 0.0 0.0 0.0 0.0 Kr-83M 0.7646E-01 0.61693-01 0.7366E-02 0.9508E-05 0.2124E-16 Kr-85 0.1066E 01 0.3193E 01 0.8511E 01 0.1912E 02 0.1641E 03 Kr-85M 0.3500E 00 0.5778E 00 0.3377E 00 0.1477E-01 0.1753E-06 Kr-87 0.2570E 00 0.1245E 00 0.4858E 02 0.3842E-06 0.3026E-23 Kr-88 0.7005E 00 0.8383E 00 0.2360E 00 0.2193E-02 0.3293E-10 Xe-133 0.1123E 02 0.3297E 02 0.8275E 02 0.1471E 03 0.2929E 03 Xe-133M 0.1857E 00 0.5299E 00 0.1232E 01 0.1646E 01 0.1117E 01 Xe-135 0.1332E 01 0.2979E 01 0.3650E 01 0.7768E 00 0.3437E-02 Xe-135M 0.2577E-01 0.1253E-03 0.1421E-10 0.2140E-29 0.0 Xe-138 0.7913E-01 0.2070E-03 0.3679E-11 0.3956E-32 0.0
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-51 Sheet 2 of 2 Revision 11 November 1996 Expected Case Nuclide 0-2 hr 2-8 hr 8-24 hr 24-96 hr 4-30 Days I-131 0.1645E-02 0.0 0.0 0.0 0.0 I-132 0.2675E-03 0.0 0.0 0.0 0.0 I-133 0.1247E-02 0.0 0.0 0.0 0.0 I-134 0.2963E-03 0.0 0.0 0.0 0.0 I-135 0.6529E-03 0.0 0.0 0.0 0.0 I-131ORG 0.0 0.0 0.0 0.0 0.0 I-132ORG 0.0 0.0 0.0 0.0 0.0 I-133ORG 0.0 0.0 0.0 0.0 0.0 I-134ORG 0.0 0.0 0.0 0.0 0.0 I-135ORG 0.0 0.0 0.0 0.0 0.0 I-131PAR 0.0 0.0 0.0 0.0 0.0 I-132PAR 0.0 0.0 0.0 0.0 0.0 I-133PAR 0.0 0.0 0.0 0.0 0.0 I-134PAR 0.0 0.0 0.0 0.0 0.0 I-135PAR 0.0 0.0 0.0 0.0 0.0 Kr-83M 0.3823E-01 0.3085E-01 0.3684E-02 0.4757E-05 0.1063E-16 Kr-85 0.5339E 00 0.1599E 01 0.4260E 01 0.9570E 01 0.8242E 02 Kr-85M 0.1750E 00 0.2889E 00 0.1689E 00 0.7387E-02 0.8775E-07 Kr-87 0.1285E 00 0.6227E-01 0.2430E-02 0.1922E-06 0.1515E-23 Kr-88 0.3503E 00 0.4192E 00 0.1180E 00 0.1097E-02 0.1648E-10 Xe-133 0.5617E 01 0.1648E 02 0.4139E 02 0.7359E 02 0.1469E 03 Xe-133M 0.9285E-01 0.2650E 00 0.6162E 00 0.8236E 00 0.5596E 00 Xe-135 0.6662E 00 0.1490E 01 0.1826E 01 0.3887E 00 0.1721E-02 Xe-135M 0.1289E-01 0.6268E-04 0.7107E-11 0.1070E-29 0.0 Xe-138 0.3957E-01 0.1035E-03 0.1840E-11 0.1979E-32 0.0
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-52 SUMMARY OF OFFSITE DOSES FROM A ROD EJECTION ACCIDENT Thyroid Exposures, rem Site Boundary 2 - Hours LPZ - 30 Days 10 CFR 100 300 300 Design basis case 3.3 x 10-3 1.4 x 10-4 Expected case 3.7 x 10-5 1.6 x 10-6 Whole Body Exposures, rem Site Boundary - 2 Hours LPZ - 30 Days 10 CFR 100 25 25 Design basis case 7.3 x 10-4 1.3 x 10-4 Expected case 3.6 x 10-5 6.4 x 10-6 Population Exposures, man-rem Design basis case 0.54 Expected case 0.027
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-53 SUMMARY OF OFFSITE DOSES FROM A RUPTURE OF A GAS DECAY TANK Thyroid Exposures, rem Site Boundary 2 - Hours LPZ - 30 Days 10 CFR 100 300 300 Design basis case negligible negligible Expected case negligible negligible
Whole Body Exposures, rem Site Boundary - 2 Hours LPZ - 30 Days 10 CFR 100 25 25 Design basis case 2.0 8.4 x 10-2 Expected case 4.4 x 10-2 1.8 x 10-3 Population Exposures, man-rem Design basis case 55.1 Expected case 1.21
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-56 SUMMARY OF OFFSITE DOSES FROM RUPTURE OF A LIQUID HOLDUP TANK Thyroid Exposures, rem Site Boundary 2 - Hours LPZ - 30 Days 10 CFR 100 300 300 Design basis case 1.41 0.432 Whole Body Exposures, rem Site Boundary - 2 Hours LPZ - 30 Days 10 CFR 100 25 25 Design basis case 0.152 6.70x10-3
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-57 SUMMARY OF OFFSITE DOSES FROM RUPTURE OF A VOLUME CONTROL TANK Thyroid Exposures, rem Site Boundary - 2 Hours LPZ - 30 Days 10 CFR 100 300 300 Design Basis Case 3.31 x 10-5 1.38 x 10-6 Expected Case 4.43 x 10-8 1.84 x 10-9 Whole Body Exposures, rem Site Boundary - 2 Hours LPZ - 30 Days 10 CFR 100 25 25 Design Basis Case 0.465 0.0193 Expected Case 9.27 x 10-3 3.86 x 10-4 Population Exposures, man-rem Design Basis Case 12.72 Expected Case 0.254
DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-61 OFFSITE DOSES FROM POST-LOCA CONTAINMENT LEAKAGE 0-2 hr Site Boundary (800 meters) 30 day LPZ (10,000 meters) Fuel Burnup Whole Whole Enrichment (%) (MWD/MTU) Thyroid (rem) Body Gamma (rem) Thyroid (rem) Body Gamma (rem) 3.5 33,000 98.6 2.21 17.2 0.20 3.5 1,000 84.0 3.13 14.4 0.28 4.5 50,000 97.8 2.10 17.1 0.19 4.5 1,000 84.0 3.19 14.4 0.29 DCPP UNITS 1 & 2 FSAR UPDATE Revision 11 November 1996 TABLE 15.5-62 OFFSITE DOSES FROM POST-LOCA LARGE RHR PUMP SEAL LEAKAGE 0-2 hr Site Boundary (800 meters) 30 day LPZ (10,000 meters) Fuel Burnup Whole Whole Enrichment (%) (MWD/MTU) Thyroid (rem) Body Gamma (rem) Thyroid (rem) Body Gamma (rem) 3.5 33,000 23.1 .0763 .96 .00320 3.5 1,000 19.7 .0754 .82 .00314 4.5 50,000 22.9 .0753 .95 .00313 4.5 1,000 19.7 .0756 .82 .00314 DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 15.5-63 POST-LOCA DOSES WITH MARGIN RECIRCULATION LOOP LEAKAGE CONTROL ROOM OPERATOR DOSES (REM) Gamma Beta Pathway Thyroid Whole Body Skin Notes Containment leakage 5.96 0.0394 0.480 RHR pump seal leakage 0.022 0.0 0.0 1 Expected recirculation loop leakage 0.85 0.00002 0.0014 Recirculation loop leakage: 1.85 gpm, with charcoal filtration, or 0.186 gpm, with no filtration 18.45 0.0006 0.0083 2 Plume radiation (egress-ingress) 4.72 0.0066 0.0243 3 Other direct radiation pathways 0.00 0.0760 0.00 3 TOTAL CONTROL ROOM OPERATOR DOSES 30.00 - 10 CFR 50 APPENDIX A, GDC 19 LIMITS 30 5 30 OFFSITE DOSES (REM) SITE BOUNDARY Gamma Pathway Thyroid Whole Body Notes Containment leakage 107.06 3.24 RHR pump seal leakage 0.0 0.0 Expected recirculation loop leakage 8.22 0.03 Recirculation loop leakage: 1.88 gpm, with charcoal filtration, or 0.189 gpm, with no filtration 184.72 0.52 2 TOTAL SITE BOUNDARY DOSES 300.00 - - LPZ Gamma Pathway Thyroid Whole Body Notes Containment leakage 19.01 0.293 RHR pump seal leakage 0.09 0.0 Expected recirculation loop leakage 2.12 0.003 Recirculation loop leakage: 11.07 gpm, with charcoal filtration, or 1.11 gpm, with no filtration 278.78 0.44 2 TOTAL LPZ DOSES 300.00 - - 10 CFR 100 DOSE LIMITS 300 25
Notes:
- 1. RHR pump seal leakage of 50 gpm for 30 minutes, starting 24 hours after the start of the LOCA, see Tables 15.5-24 and 15.5-33. 2. Additional recirculation loop leakage, existing at the start of the LOCA and continuing for 30 days.
- 3. Taken from Table 15.5-33.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-64 Sheet 1 of 2 Revision 19 May 2010 PARAMETERS USED IN EVALUATING RADIOLOGICAL CONSEQUENCES FOR SGTR ANALYSIS I. Source Data A. Core power level, MWt 3580 B. Total steam generator tube leakage, prior to accident, gpm 1.0 C. Reactor coolant activity: 1. Accident initiated spike The initial RC iodine activities based on 1 µCi/gram of D.E. I-131 are presented in Table 15.5-65. The iodine appearance rates based on an iodine spiking factor of 335 assumed for the accident initiated spike are presented in Table 15.5-66 2. Preaccident spike Primary coolant iodine activities based on 60 µCi/gram of D.E. I-131 are presented in Table 15.5-65 3. Noble gas activity The initial RC noble gas activities based on 1% fuel defects are presented in Table 15.5-67 D. Secondary system initial activity Dose equivalent of 0.1 µCi/gm of I-131, presented in Table 15.5-65 E. Reactor coolant mass, grams 2.27 x 108 F. Initial steam generator mass (each), grams 4.07 x 107 G. Offsite power Lost at time of reactor trip H. Primary-to-secondary leakage duration for intact SG, hrs 8 I. Species of iodine 100 percent elemental DCPP UNITS 1 & 2 FSAR UPDATE TABLE 15.5-64 Sheet 2 of 2 Revision 19 May 2010 II. Activity Release date A. Ruptured steam generator
- 1. Rupture flow See Figure 15.4.3-6 and Table 15.4-14
- 2. Flashed rupture flow See Figure 15.4.3-11 and Table 15.4-14
- 3. Iodine scrubbing efficiency Not Modeled
- 4. Total steam release, lbs See Figure 15.4.3-9 and Table 15.4-14
- 5. Iodine partition coefficient
- non-flashed - flashed 100 1.0 B. Intact steam generators
- 1. Total primary-to-secondary leakage, gpm 1.0 2. Total steam release, lbs See Figure 15.4.3-10 and Table 15.4-14
- 3. Iodine partition coefficient 100
C. Condenser
- 1. Iodine partition coefficient 100
D. Atmospheric dispersion factors See Table 15.5-68
DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 15.5-65 IODINE SPECIFIC ACTIVITIES IN THE PRIMARY AND SECONDARY COOLANT(a) - SGTR ANALYSIS Specific Activity (µCi/gm) Primary Coolant Secondary Coolant Nuclide 1 µCi/gm 60 µCi/gm 0.1 µCi/gm I-131 0.794 47.64 0.0794
I-132 0.204 12.24 0.0204
I-133 1.113 66.78 0.1113
I-134 0.139 8.34 0.0139
I-135 0.589 35.34 0.0589 (a) Based on 1, 60 and 0.1 µCi/gm of Dose Equivalent I-131 consistent with the DCPP Technical Specifications (Reference 22).
DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 15.5-66 IODINE SPIKE APPEARANCE RATES(a) - SGTR ANALYSIS (CURIES/SECOND) I-131 I-132 I-133 I-134 I-135 2.46 1.92 4.14 2.75 3.10 (a) The accident initiated spike appearance rate is 335 times the equilibrium appearance rate. The equilibrium appearance rate is calculated based on a total letdown flow of 143 gpm. This total is comprised of 120 gpm with perfect cleanup, a letdown flow uncertainty of 12 gpm, 10 gpm identified reactor coolant system leakage, and 1 gpm unidentified leakage from the reactor coolant system.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 16 June 2005 TABLE 15.5-67 NOBLE GAS SPECIFIC ACTIVITIES IN THE REACTOR COOLANT(a) BASED ON 1% FUEL DEFECTS - SGTR ANALYSIS Nuclide Specific Activity (µCi/gm) Xe-131m 2.523
Xe-133m 3.911
Xe-133 256.3
Xe-135m 0.449
Xe-135 8.663
Xe-138 0.568
Kr-85m 2.141
Kr-85 6.209
Kr-87 1.232
Kr-88 3.907 (a) Based on a 2 year fuel cycle at a core power of 3580 MWt, a 75 gpm reactor coolant system letdown flow rate, and a 90% demineralizer iodine removal efficiency. DCPP UNITS 1 & 2 FSAR UPDATE Revision 16 June 2005 TABLE 15.5-68 ATMOSPHERIC DISPERSION FACTORS AND BREATHING RATES - SGTR ANALYSIS OFFSITE EXPOSURE Time Exclusion Area Boundary Low Population Breathing Rate(a) (hours) /Q (Sec/m3) Zone /Q (Sec/m3) (m3/Sec) 0-2 5.29 x 10-4 2.2 x 10-5 3.47 x 10-4 2-8 - 2.2 x 10-5 3.47 x 10-4
CONTROL ROOM EXPOSURE Time Control Room Filtered Pressurization Control Room Unfiltered Pressurization Control Room Breathing Rate(a) (hours) /Q (Sec/m3) Zone /Q (Sec/m3) (m3/Sec) 0-8 7.05 x 10-5 1.96 x 10-4 3.47 x 10-4 8-24 5.38 x 10-5 1.49 x 10-4 3.47 x 10-4 24-96 3.91 x 10-5 1.08 x 10-4 3.47 x 10-4 >96 2.27 x 10-5 6.29 x 10-5 3.47 x 10-4 (a) Regulatory Guide 1.4, Revision 2, June 1974
DCPP UNITS 1 & 2 FSAR UPDATE Revision 18 October 2008 TABLE 15.5-69 THYROID DOSE CONVERSION FACTORS(a) AND WHOLE BODY DOSE CONVERSION FACTORS(b) - SGTR ANALYSIS Nuclide I-131 1.07 x 106 (Rem/Curie) I-132 6.29 x 103 (Rem/Curie) I-133 1.81 x 105 (Rem/Curie) I-134 1.07 x 103 (Rem/Curie) I-135 3.14 x 104 (Rem/Curie) Kr-85m 7.48E-15 (sv m3/bq s) Kr-87 4.12E-14 (sv m3/bq s) Kr-88 1.02E-13 (sv m3/bq s) Xe-133m 1.37E-15 (sv m3/bq s) Xe-133 1.56E-15 (sv m3/bq s) Xe-135m 2.04E-14 (sv m3/bq s) Xe-135 1.19E-14 (sv m3/bq s) Xe-138 5.77E-14 (sv m3/bq s)
(a) International Commission on Radiological Protection Publication 30, 1979. (b) Table III.1 of Federal Guidance Report 12, EPA-402-R-93-081, 1993.
DCPP UNITS 1 & 2 FSAR UPDATE Revision 16 June 2005 TABLE 15.5-70 AVERAGE GAMMA AND BETA ENERGY FOR NOBLE GASES(a) - SGTR ANALYSIS (MeV/dis) Nuclide E E I-131 0.38 0.19
I-132 2.2 0.52
I-133 0.6 0.42
I-134 2.6 0.69
I-135 1.4 0.43
Xe-131m 0.0029 0.16
Xe-133m 0.02 0.21
Xe-133 0.03 0.15
Xe-135m 0.43 0.099
Xe-135 0.25 0.32
Xe-138 1.2 0.66
Kr-85m 0.16 0.25
Kr-85 0.0023 0.25
Kr-87 0.79 1.3
Kr-88 2.2 0.25 (a) ENDF-223, October 1975 (Reference 36) DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 15.5-71 OFFSITE RADIATION DOSES FROM SGTR ACCIDENT Dose (Rem) Calculated Allowable Guideline Value Value (Reference 37)
- 1. Accident Initiated Iodine Spike Exclusion Area Boundary (0-2 hr.)
Thyroid CDE 27 30
Low Population Zone (0-8 hr.) Thyroid CDE 1.5 30
- 2. Pre-Accident Iodine Spike Exclusion Area Boundary (0-2 hr.)
Thyroid CDE 67 300
Low Population Zone (0-8 hr.) Thyroid CDE 3.2 300
- 3. Whole-Body Gamma Dose Exclusion Area Boundary (0-2 hr.)
Whole Body Gamma DDE 0.3 2.5
Low Population Zone (0-8 hr.) Whole-Body Gamma DDE 0.02 2.5
DCPP UNITS 1 & 2 FSAR UPDATE Revision 16 June 2005 TABLE 15.5-72 CONTROL ROOM PARAMETERS USED IN EVALUATING RADIOLOGICAL CONSEQUENCES FOR SGTR ANA;YSIS Control Room Isolation Signal Generated Time of Safety Injection Signal Delay in Control Room Isolation After Isolation Signal is Generated 35 seconds Control Room Volume 170,000 ft3 Control Room Unfiltered In-Leakage 10 cfm Control Room Unfiltered Inflow Normal Mode 4200 cfm Emergency Mode 0 cfm Control Room Filtered Inflow Normal Mode 0 cfm Emergency Mode 2100 cfm Control Room Filtered Recirculation Normal Mode 0 cfm Emergency Mode 2100 cfm Control Room Filter Efficiency 95% ______________ DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 15.5-74 CONTROL ROOM RADIATION DOSES FROM AIRBORNE ACTIVITY IN SGTR ACCIDENT Accident Initiated Pre-Accident GDC 19 Iodine Spike, rem Iodine Spike, rem Guideline, rem Thyroid CDE (0-30 days) 0.2 0.8 30 Whole Body DDE (0-30 days) .002 .002 5 Beta Skin SDE (0-30 days) 0.09 0.09 30
DCPP UNITS 1 & 2 FSAR UPDATE Revision 19 May 2010 TABLE 15.5-75 SUMMARY OF POST-LOCA DOSES FROM VARIOUS PATHWAYS (DF OF 100) THYROID DOSES, rem EAB - 2 hours LPZ - 30 days 10 CFR 100 300 300 Containment Leakage 107.06 19.01 RHR Pump Seal (50 gpm) 0 0.09 Pre-existing leak (1910 cc/hr) 8.22 2.12
Total 115.28 21.22
WHOLE BODY DOSES, rem EAB - 2 hours LPZ - 30 days 10 CFR 100 25 25 Containment Leakage 3.24 0.293 RHR Pump Seal (50 gpm) 0.0 0.0 Pre-existing leak (1910 cc/hr) 0.03 0.003 Total 3.27 0.296
30354045 50 556065 707580550560570580590600610620630640VESSEL AVERAGE TEMPERATURE (F)VESSEL DELTA-T (F)SG SAFETY VALVES OPENOVERPOWER DELTA TCORE THERMAL LIMITS ATINDICATED PRESSURESOVERTEMPERATURE DELTA-T AT INDICATED PRESSURES 1860 PSIA 2250 PSIA2460 PSIA FIGURE 15.1-1 ILLUSTRATION OF OVERPOWER AND OVERTEMPERATURE T PROTECTION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 14 November 2001 FIGURE 15.1-2 ROD POSITION VERSUS TIME ON REACTOR TRIP UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.1-3 NORMALIZED RCCA REACTIVITY WORTH VERSUS PERCENT INSERTIONUNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.1-4 NORMALIZED RCCA BANK REACTIVITY WORTH VERSUS TIME AFTER TRIP UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.1-5 DOPPLER POWER COEFFICIENT USED IN ACCIDENT ANALYSIS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.1-6 RESIDUAL DECAY HEAT UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.1-7 1979 ANS DECAY HEAT CURVE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.1-8 FUEL ROD CROSS SECTION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.1-1 UNCONTROLLED ROD WITHDRAWAL FROM A SUBCRITICAL CONDITION NEUTRON FLUX VERSUS TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.1-2 UNCONTROLLED ROD WITHDRAWAL FROM A SUBCRITICAL CONDITION THERMAL FLUX VERSUS TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.1-3 UNCONTROLLED ROD WITHDRAWAL FROM A SUBCRITICAL CONDITION TEMPERATURE VERSUS TIME. REACTIVITY INSERTION RATE 75 X 10-5 DELTA K/SEC UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 ROD WITHDRAWAL AT POWER Minimum Feedback, 75 pcm/sec Insertion Rate DIABLO CANYON UNITS 1 & 2 FIGURE 15.2.2-1 Revision 11 November 1996 ROD WITHDRAWAL AT POWER Minimum Feedback, 75 pcm/sec Insertion Rate DIABLO CANYON UNITS 1 & 2 FIGURE 15.2.2-2 Revision 11 November 1996 ROD WITHDRAWAL AT POWER Minimum Feedback, 3 pcm/sec Insertion Rate DIABLO CANYON UNITS 1 & 2 FIGURE 15.2.2-3 Revision 11 November 1996 ROD WITHDRAWAL AT POWER Minimum Feedback, 3 pcm/sec Insertion Rate DIABLO CANYON UNITS 1 & 2 FIGURE 15.2.2-4 Revision 11 November 1996 ROD WITHDRAWAL AT POWER Reactivity Insertion Rate vs. DNBR For 100% Power Cases DIABLO CANYON UNITS 1 & 2 FIGURE 15.2.2-5 Revision 11 November 1996 ROD WITHDRAWAL AT POWER Reactivity Insertion Rate vs. DNBR For 60% Power Cases DIABLO CANYON UNITS 1 & 2 FIGURE 15.2.2-6 Revision 11 November 1996 ROD WITHDRAWAL AT POWER Reactivity Insertion Rate vs. DNBR For 10% Power Cases DIABLO CANYON UNITS 1 & 2 FIGURE 15.2.2-7 Revision 11 November 1996 FIGURE 15.2.3-1 TRANSIENT RESPONSE TO DROPPED ROD CLUSTER CONTROL ASSEMBLY UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.3-2 TRANSIENT RESPONSE TO DROPPED ROD CLUSTER CONTROL ASSEMBLY UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.4-1 VARIATION IN REACTIVITY INSERTION RATE WITH INITIAL BORON CONCENTRATION FOR A DILUTION RATE OF 262 GPM UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.5-1 ALL LOOPS OPERATING TWO LOOPS COASTING DOWN CORE FLOW VERSUS TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.5-2 ALL LOOPS OPERATING TWO LOOPS COASTING DOWN FAILED LOOP FLOW VERSUS TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.5-3 ALL LOOPS OPERATING TWO LOOPS COASTING DOWN HEAT FLUX VERSUS TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.5-4 ALL LOOPS OPERATING TWO LOOPS COASTING DOWN NUCLEAR POWER VERSUS TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.5-5 ALL LOOPS OPERATING TWO LOOPS COASTING DOWN DNBR VERSUS TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.6-1 NUCLEAR POWER TRANSIENT DURING STARTUP OF AN INACTIVE LOOP UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.6-2 AVERAGE AND HOT CHANNEL HEAT FLUX TRANSIENTS DURING STARTUP OF AN INACTIVE LOOP UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.6-3 CORE FLOW DURING STARTUP OF AN INACTIVE LOOP UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.6-4 PRESSURIZER PRESSURE TRANSIENT AND CORE AVERAGE TEMPERATURE TRANSIENT DURING STARTUP OF AN INACTIVE LOOP UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.6-5 DNBR TRANSIENT DURING STARTUP OF AN INACTIVE LOOP UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 LOSS OF LOAD With Pressurizer Spray and Power Operated Relief Valve For DNB Concern at Beginning of Life DIABLO CANYON UNITS 1 & 2 FIGURE 15.2.7-1 Revision 11 November 1996 LOSS OF LOAD With Pressurizer Spray and Power Operated Relief Valve For DNB Concern at Beginning of Life DIABLO CANYON UNITS 1 & 2 FIGURE 15.2.7-2 Revision 11 November 1996 FIGURE 15.2.7-3 LOSS OF LOAD WITH PRESSURIZER SPRAY AND POWER OPERATED RELIEF VALVE FOR DNB CONCERN AT END OF LIFE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996
FIGURE 15.2.7-4 LOSS OF LOAD WITH PRESSURIZER SPRAY AND POWER OPERATED RELIEF VALVE FOR DNB CONCERN AT END OF LIFE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 LOSS OF LOAD Without Pressurizer Spray and Power Operated Relief Valves For Overpressure Concern at Beginning of Life DIABLO CANYON UNITS 1 & 2 FIGURE 15.2.7-9 Revision 11 November 1996 LOSS OF LOAD With Pressurizer Spray and Power Operated Relief Valves For Overpressure Concern at Beginning of Life DIABLO CANYON UNITS 1 & 2 FIGURE 15.2.7-10 Revision 11 November 1996 LOSS OF LOAD With Pressurizer Spray and Power Operated Relief Valves For Overpressure Concern at Beginning of Life DIABLO CANYON UNITS 1 & 2 FIGURE 15.2.7-11 Revision 11 November 1996 LOSS OF LOAD With Pressurizer Spray and Power Operated Relief Valves For Overpressure Concern at Beginning of Life DIABLO CANYON UNITS 1 & 2 FIGURE 15.2.7-12 Revision 11 November 1996 FIGURE 15.2.8-1 LOSS OF NORMAL FEEDWATER - RCS TEMPERATURES AND STEAM GENERATOR MASS TRANSIENTS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010 FIGURE 15.2.8-2 LOSS OF NORMAL FEEDWATER PRESSURIZER WATER VOLUME AND PRESSURIZER PRESSURE TRANSIENTSUNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010 FIGURE 15.2.8-3 LOSS OF NORMAL FEEDWATER NUCLEAR POWER AND STEAM GENERATOR PRESSURE TRANSIENTS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010 FIGURE 15.2.10-1 FEEDWATER CONTROL VALVE MALFUNCTION FULL POWER, MANUAL ROD CONTROL NUCLEAR POWER AND CORE HEAT FLUX TRANSIENTS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010 FIGURE 15.2.10-2 FEEDWATER CONTROL VALVE MALFUNCTION FULL POWER, MANUAL ROD CONTROL PRESSURIZER PRESSURE AND FAULTED LOOP DELTA-T TRANSIENTS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010 FIGURE 15.2.10-3 FEEDWATER CONTROL VALVE MALFUNCTION FULL POWER, MANUAL ROD CONTROL CORE AVERAGE TEMPERATURE AND DNBR TRANSIENTS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010 FIGURE 15.2.11-1 EXCESSIVE LOAD INCREASE WITHOUT CONTROL ACTION, BEGINNING OF LIFE, (MTC), MINIMUM FEEDBACK, DELTA-T AND TAVG AS A FUNCTION OF TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.11-2 EXCESSIVE LOAD INCREASE WITHOUT CONTROL ACTION, BEGINNING OF LIFE, (MTC), MINIMUM FEEDBACK, DNBR, NUCLEAR POWER AND PRESSURIZER PRESSURE AS A FUNCTION OF TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.11-3 EXCESSIVE LOAD INCREASE WITHOUT CONTROL ACTION, END OF LIFE, (MTC), MAXIMUM FEEDBACK, DELTA-T AND TAVG AS A FUNCTION OF TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.11-4 EXCESSIVE LOAD INCREASE WITHOUT CONTROL ACTION, END OF LIFE, (MTC), MAXIMUM FEEDBACK, DNBR, NUCLEAR POWER AND PRESSURIZER PRESSURE AS A FUNCTION OF TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.11-5 EXCESSIVE LOAD INCREASE WITH REACTOR CONTROL, BEGINNING OF LIFE, (MTC), MINIMUM FEEDBACK, DELTA-T AND TAVG AS A FUNCTION OF TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.11-6 EXCESSIVE LOAD INCREASE WITH REACTOR CONTROL, BEGINNING OF LIFE, (MTC), MINIMUM FEEDBACK, DNBR, NUCLEAR POWER AND PRESSURIZER PRESSURE AS A FUNCTION OF TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.11-7 EXCESSIVE LOAD INCREASE WITH REACTOR CONTROL, END OF LIFE, (MTC), MAXIMUM FEEDBACK, DELTA-T AND TAVG AS A FUNCTION OF TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.2.11-8 EXCESSIVE LOAD INCREASE WITH REACTOR CONTROL, END OF LIFE, (MTC), MAXIMUM FEEDBACK, DNBR, NUCLEAR POWER AND PRESSURIZER PRESSURE AS A FUNCTION OF TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 0.00.20.40.60.81.01.20102030405060TIME (SEC)NUCLEAR POWER (FRACTION OF NOMINAL)1.02.03.0 4.05.06.00.010.020.030.040.050.060.0TIME (SEC)DNBR FIGURE 15.2.12-1 NUCLEAR POWER AND DNBR TRANSIENTS FOR ACCIDENTAL DEPRESSURIZATION OF THE REACTOR COOLANT SYSTEM UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 14 November 2001 140015001600170018001900200021002200230024000102030405060TIME SECPRESSURIZER PRESSURE (PSIA) 520.0540.0560.0580.0600.0620.00.010.020.030.040.050.060.0TIME (SEC)CORE AVERAGE TEMPERATURE (*F) FIGURE 15.2.12-2 PRESSURIZER PRESSURE AND CORE AVERAGE TEMPERATURE TRANSIENTS FOR ACCIDENTAL DEPRESSURIZATION OF THE REACTOR COOLANT SYSTEM UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 14 November 2001 FIGURE 15.2.15-1 SPURIOUS ACTUATION OF SAFETY INJECTION SYSTEM AT POWER DNBR ANALYSIS - PRESSURIZER WATER VOLUME AND PRESSURIZER PRESSURE VERSUS TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 16 June 2005 FIGURE 15.2.15-2 SPURIOUS ACTUATION OF SAFETY INJECTION SYSTEM AT POWER DNBR ANALYSIS - NUCLEAR POWER, STEAM FLOW, AND CORE WATER TEMPERATURE VERSUS TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 16 June 2005
21002200230024002500020040060080010001200140016001800Time (sec)Pressurizer Pressure (psia)Case 3 w/o SpraysCase 2Case 1 - w/o Sprays and PORVSFIGURE 15.2.15-3 SSI PRESSURIZER OVERFILL ANALYSIS TYPICAL PRESSURIZER PRESSURE RESPONSE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
10001200140016001800020040060080010001200140016001800Time (sec)Pressurizer Liquid Volume (ft3)Case 3 - w/o SpraysCase 2Case 1 - w/o Sprays and PORVsFIGURE 15.2.15-4 SSI PRESSURIZER OVERFILL ANALYSIS TYPICAL PRESSURIZER LIQUID VOLUME RESPONSE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
550555560565570020040060080010001200140016001800Time (sec)RCS Tavg (F)Case 3 w/o SpraysCase 2Case 1 - w/o Sprays and PORVSFIGURE 15.2.15-5 SSI PRESSURIZER OVERFILL ANALYSIS TYPICAL RCS AVERAGE TEMPERATURE RESPONSE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008 FIGURE 15.3-1 SAFETY INJECTION FLOW RATE FOR SMALL BREAK LOCA UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 13 April 2000 DCPP Unit 1 FIGURE 15.3-2 (Sheet 1 of 2) RCS DEPRESSURIZATION 4-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 21 September 2013 DCPP Unit 2 FIGURE 15.3-2 (Sheet 2 of 2) RCS DEPRESSURIZATION 4-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 21 September 2013 DCPP Unit 1 FIGURE 15.3-3 (Sheet 1 of 2) CORE MIXTURE ELEVATION 4-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 21 September 2013 DCPP Unit 2 FIGURE 15.3-3 (Sheet 2 of 2) CORE MIXTURE ELEVATION 4-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 21 September 2013 DCPP Unit 1 FIGURE 15.3-4 (Sheet 1 of 2) CLADDING TEMPERATURE TRANSIENT4-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 DCPP Unit 2 FIGURE 15.3-4 (Sheet 2 of 2) CLADDING TEMPERATURE TRANSIENT4-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 10010-110410310210110010-110-2TIME AFTER SHUTDOWN (SECONDS)TOTAL RESIDUAL HEAT (WITH 4% SHUTDOWN MARGIN)WATTS/WATT AT POWER FIGURE 15.3-8 LOCA CORE POWER TRANSIENT UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 13 April 2000 DCPP Unit 1 FIGURE 15.3-9 (Sheet 1 of 2) RCS DEPRESSURIZATION 3-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 21 September 2013 DCPP Unit 2 FIGURE 15.3-9 (Sheet 2 of 2) RCS DEPRESSURIZATION 3-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 DCPP Unit 1 FIGURE 15.3-11 (Sheet 1 of 2) CORE MIXTURE ELEVATION 3-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 21 September 2013 DCPP Unit 2 FIGURE 15.3-11 (Sheet 2 of 2) CORE MIXTURE ELEVATION 3-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 21 September 2013 DCPP Unit 1 FIGURE 15.3-13 (Sheet 1 of 2) CLAD TEMPERATURE TRANSIENT 3-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 DCPP Unit 2 FIGURE 15.3-13 (Sheet 2 of 2) CLAD TEMPERATURE TRANSIENT 3-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 4026-385 RPNMLKJHGFEDCBA-8.9-7.41-5.6-9.1-8.52-8.2-6.8-4.10.23-7.9-8.2-7.74-8.4-6.0-3.8-1.85-8.5-8.4-7.4-5.5-0.36-7.7-5.0-1.2-1.07-7.7-7.3-5.9-3.21.53.23.43.68-6.92.75.96.09-3.40.710.610-5.3-1.85.917.111.4111.312.324.6120.10.77.723.613 2.54.711.117.6142.16.515CASE A THE NUMBERS REPRESENT THE PERCENT DEVIATION FROM ASSEMBLY AVERAGE POWER FIGURE 15.3-15 INTERCHANGE BETWEEN REGION 1 AND REGION 3 ASSEMBLY UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 4026-386 RPNMLKJHGFEDCBA0.31.513.20.83.26.021.20.01.610.330.02.96.54-2.2-1.02.26.96.65-1.70.58.86-3.25.216.75.47-3.5-3.4-2.6-0.711.411.35.84.48-3.6-2.0-2.32.29-3.8-3.8-3.6-2.90.510-3.9-4.3-4.6-1.511-2.8-3.1-4.512-4.8-4.4-2.61.413-0.4-4.8-4.814-4.8-4.515CASE B-1 THE NUMBERS REPRESENT THE PERCENT DEVIATION FROM ASSEMBLY AVERAGE POWER. FIGURE 15.3-16 INTERCHANGE BETWEEN REGION 1 AND REGION 2ASSEMBLY, BURNABLE POISON RODS BEING RETAINED BY THE REGION 2 ASSEMBLY UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 21 September 2013 4026-387
THE NUMBERS REPRESENT THE PERCENT DEVIATION FROM ASSEMBLY AVERAGE POWER. FIGURE 15.3-17 INTERCHANGE BETWEEN REGION 1 AND REGION 2ASSEMBLY, BURNABLE POISON RODS BEING TRANSFERRED TO THE REGION 1 ASSEMBLY UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 21 September 2013 R PN ML K JHGFEDCBA 1.01.115.1 1.01.021.11.11.94.931.71.7 1.441.11.81.10.750.00.2 1.83.94.060.05.22.2-0.37-0.7-0.60.35.11.5-0.3-0.6-0.78-1.0-1.1-0.8-0.99-1.4-3.1-1.310-0.9-1.7-1.7-0.911-2.5-2.9-1.1120.7 -1.9-2.92.5132.3 -2.8-2.4-0.814-2.1-2.815CASE B-2 4026-388
THE NUMBERS REPRESENT THE PERCENT DEVIATION FROM ASSEMBLY AVERAGE POWER. FIGURE 15.3-18 ENRICHMENT ERROR: A REGION 2 ASSEMBLYLOADED INTO THE CORE CENTRAL POSITIONUNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 21 September 2013 RPNMLKJHGFEDCBA-2.2-2.112.0-2.0-2.12-1.5-1.6-1.02.03-0.9-1.0-0.44-0.41.2-0.5-1.45-2.1-1.62.35.7-2.06-3.29.74.4-1.77-2.3-1.61.813.65.6-0.4-1.6-2.18-2.29.71.1-2.290.34.5-0.910-1.9-0.41.8-0.5-1.911-0.9-0.6-1.1120.4-1.4-1.52.0132.0-2.1-2.0-0.914-1.9-2.215CASE C 4026-389
THE NUMBERS REPRESENT THE PERCENT DEVIATION FROM ASSEMBLY AVERAGE POWER. FIGURE 15.3-19 LOADING A REGION 2 ASSEMBLY INTO A REGION 1 POSITION NEAR CORE PERIPHERYUNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 21 September 2013 RPNMLKJHGFEDCBA-11.0-14.010.4-9.2-12.02-12.0-14.0-15.0-13.033.21.2-11.04-1.5-12.0-15.0-16.059.87.1-1.6-8.0-16.069.2-2.3-12.0-14.0720.017.810.80.8-10.0-14.0-15.0-16.0827.2-5.5-11.0-15.0920.75.8-12.01042.023.61.9-8.6-13.01114.0-1.7-8.91238.620.42.8-7.01335.97.0-3.3-6.31415.32.915CASE D DCPP Unit 1 FIGURE 15.3-33 (Sheet 1 of 2) TOP CORE NODE VAPOR TEMPERATURE3-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 DCPP Unit 2 FIGURE 15.3-33 (Sheet 2 of 2) TOP CORE NODE VAPOR TEMPERATURE3-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 DCPP Unit 1 FIGURE 15.3-34 (Sheet 1 of 2) ROD FILM COEFFICIENT 3-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLOCANYON SITEFSAR UPDATERevision 21 September 2013 DCPP Unit 2 FIGURE 15.3-34 (Sheet 2 of 2) ROD FILM COEFFICIENT 3-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 21 September 2013 DCPP Unit 1 FIGURE 15.3-35 (Sheet 1 of 2) HOT SPOT FLUID TEMPERATURE3-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 DCPP Unit 2 FIGURE 15.3-35 (Sheet 2 of 2) HOT SPOT FLUID TEMPERATURE3-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 DCPP Unit 1 FIGURE 15.3-36 (Sheet 1 of 2) BREAK MASS FLOW 3-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 DCPP Unit 2 FIGURE 15.3-36 (Sheet 2 of 2) BREAK MASS FLOW 3-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 DCPP Unit 1 FIGURE 15.3-37 (Sheet 1 of 2) RCS DEPRESSURIZATION 2-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 DCPP Unit 2 FIGURE 15.3-37 (Sheet 2 of 2) RCS DEPRESSURIZATION 2-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 DCPP Unit 1 FIGURE 15.3-38 (Sheet 1 of 2) CORE MIXTURE ELEVATION 2-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 DCPP Unit 2 FIGURE 15.3-38 (Sheet 2 of 2) CORE MIXTURE ELEVATION 2-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 DCPP Unit 1 FIGURE 15.3-39 (Sheet 1 of 2) CLADDING TEMPERATURE TRANSIENT2-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 21 September 2013 DCPP Unit 2 FIGURE 15.3-39 (Sheet 2 of 2) CLADDING TEMPERATURE TRANSIENT2-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 21 September 2013 DCPP Unit 1 DCPP Unit 2 FIGURE 15.3-40 RCS DEPRESSURIZATION 6-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 21 September 2013 DCPP Unit 1 DCPP Unit 2 FIGURE 15.3-41 CORE MIXTURE ELEVATION 6-INCH COLD LEG BREAK UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 FIGURE 15.3.4-1 ALL LOOPS OPERATING ALL LOOPS COASTING DOWN FLOW COASTDOWN VERSUS TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.3.4-2 ALL LOOPS OPERATING ALL LOOPS COASTING DOWN HEAT FLUX VERSUS TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.3.4-3 ALL LOOPS OPERATING ALL LOOPS COASTING DOWN NUCLEAR POWER VERSUS TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.3.4-4 ALL LOOPS OPERATING ALL LOOPS COASTING DOWN DNBR VERSUS TIME UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996
FIGURE 15.4.1-1A REFERENCE TRANSIENT PCT AND PCT LOCATION UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
FIGURE 15.4.1-1B LIMITING PCT CASE AND PCT LOCATION UNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
FIGURE 15.4.1-2A REFERENCE TRANSIENT VESSEL SIDE BREAK FLOW UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
FIGURE 15.4.1-2B LIMITING PCT CASE VESSEL SIDE BREAK FLOW UNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
FIGURE 15.4.1-3A REFERENCE TRANSIENT LOOP SIDE BREAK FLOW UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
FIGURE 15.4.1-3B LIMITING PCT CASE LOOP SIDE BREAK FLOW UNIT 2 DIABLO CANYON SITEFSAR UPDATE Revision 18 October 2008
FIGURE 15.4.1-4A REFERENCE TRANSIENT BROKEN AND INTACT LOOP PUMP VOID FRACTIONUNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
FIGURE 15.4.1-4B LIMITING PCT CASE BROKEN AND INTACT LOOP PUMP VOID FRACTIONUNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008 FIGURE 15.4.1-5A REFERENCE TRANSIENT HOT ASSEMBLY/TOP OF CORE VAPOR FLOW UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
FIGURE 15.4.1-5B LIMITING PCT CASE HOT ASSEMBLY/TOP OF CORE VAPOR FLOW UNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008 FIGURE 15.4.1-6A REFERENCE TRANSIENT PRESSURIZER PRESSURE UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
FIGURE 15.4.1-6B LIMITING PCT CASE PRESSURIZER PRESSURE UNIT 2 DIABLO CANYON SITEFSAR UPDATE Revision 18 October 2008 FIGURE 15.4.1-7A REFERENCE TRANSIENT LOWER PLENUM COLLAPSED LIQUID LEVEL UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
FIGURE 15.4.1-7B LIMITING PCT CASE LOWER PLENUM COLLAPSED LIQUID LEVEL UNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008 FIGURE 15.4.1-8A REFERENCE TRANSIENT VESSEL WATER MASS UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
FIGURE 15.4.1-8B LIMITING PCT CASE VESSEL FLUID MASS UNIT 2 DIABLO CANYON SITEFSAR UPDATE Revision 18 October 2008 FIGURE 15.4.1-9A REFERENCE TRANSIENT LOOP 1 ACCUMULATOR FLOW UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
FIGURE 15.4.1-9B LIMITING PCT CASE LOOP 1 ACCUMULATOR FLOW UNIT 2 DIABLO CANYON SITEFSAR UPDATE Revision 18 October 2008 FIGURE 15.4.1-10A REFERENCE TRANSIENT LOOP 1 SAFETY INJECTION FLOW UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
FIGURE 15.4.1-10B LIMITING PCT CASE LOOP 1 SAFETY INJECTION FLOW UNIT 2 DIABLO CANYON SITEFSAR UPDATE Revision 18 October 2008 FIGURE 15.4.1-11A REFERENCE TRANSIENT CORE AVERAGE CHANNEL COLLAPSED LIQUID LEVELUNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
FIGURE 15.4.1-11B LIMITING PCT CASE CORE AVERAGE CHANNEL COLLAPSED LIQUID LEVELUNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008 FIGURE 15.4.1-12A REFERENCE TRANSIENT LOOP 1 DOWNCOMER COLLAPSED LIQUID LEVELUNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
FIGURE 15.4.1-12B LIMITING PCT CASE LOOP 1 DOWNCOMER COLLAPSED LIQUID LEVELUNIT 2 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
FIGURE 15.4.1-13A TOTAL ECCS FLOW (3 LINES INJECTING) UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
05001000150020002500 3000 3500 40000200400600800100012001400160018002000Pressure (psia)Total SI Flow (gpm)FIGURE 15.4.1-13B TOTAL ECCS FLOW (3 LINES INJECTING) UNIT 2 DIABLO CANYON SITEFSAR UPDATE Revision 18 October 2008 FIGURE 15.4.1-14A REFERENCE TRANSIENT PRESSURE TRANSIENT UNIT 1 DIABLO CANYON SITE FSAR UPDATE Revision 18 October 2008
FIGURE 15.4.1-14B LOWER BOUND COCO CONTAINMENT PRESSURE TRANSIENT UNIT 2 DIABLO CANYON SITEFSAR UPDATE Revision 18 October 2008
FIGURE 15.4.1-15A AXIAL POWER DISTRIBUTION LIMITS UNIT 1 DIABLO CANYON SITEFSAR UPDATERevision 21 September 2013 0.46, 0.20.46, 0.37250.28, 0.450.28, 0.30.150.20.250.30.350.40.450.50.250.30.350.40.450.5PMIDPBOT
FIGURE 15.4.1-15B AXIAL POWER DISTRIBUTION LIMITS UNIT 2 DIABLO CANYON SITEFSAR UPDATE Revision 18 October 2008 -1500-1000-50000.000.050.100.150.200.250.30Power (fraction of nominal)Integral of Power Coefficient (pcm)
UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 15.4.2-1 RUPTURE OF A MAIN STEAM LINE VARIATION OF REACTIVITY WITH POWER AT CONSTANT CORE AVERAGE TEMPERATURE Revision 19 May 2010 Zero Power 1050 psia EOL Rodded Core One RCCA Stuck Full Out FIGURE 15.4.2-2 RUPTURE OF A MAIN STEAM LINE VARIATION OF KEFF WITH CORE AVERAGE TEMPERATURE UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010
FIGURE 15.4.2-3 RUPTURE OF A MAIN STEAM LINESAFETY INJECTION CURVE UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 21 September 2013 FIGURE 15.4.2-4 RUPTURE OF A MAIN STEAM LINE WITH OFFSITE POWER AVAILABLE CORE HEAT FLUX AND STEAM FLOW TRANSIENTS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010 FIGURE 15.4.2-5 RUPTURE OF A MAIN STEAM LINE WITH OFFSITE POWER AVAILABLE LOOP AVERAGE TEMPERATURE AND REACTOR COOLANT PRESSURE TRANSIENTS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010 UNITS 1 AND 2 DIABLO CANYON SITE FIGURE 15.4.2-6 RUPTURE OF A MAIN STEAM LINE WITH OFFSITE POWER AVAILABLE REACTIVITY AND CORE BORON TRANSIENTS FSAR UPDATE Revision 19 May 2010 UNITS 1 AND 2 DIABLO CANYON SITE FIGURE 15.4.2-7 RUPTURE OF A MAIN STEAM LINE WITHOUT OFFSITE POWER AVAILABLE CORE HEAT FLUX AND STEAM FLOW TRANSIENTS FSAR UPDATE Revision 19 May 2010 UNITS 1 AND 2 DIABLO CANYON SITE FIGURE 15.4.2-8 RUPTURE OF A MAIN STEAM LINE WITHOUT OFFSITE POWER AVAILABLE LOOP AVERAGE TEMPERATURE AND REACTOR COOLANT PRESSURE TRANSIENTS FSAR UPDATE Revision 19 May 2010 UNITS 1 AND 2 DIABLO CANYON SITE FIGURE 15.4.2-9 RUPTURE OF A MAIN STEAM LINE WITHOUT OFFSITE POWER AVAILABLE REACTIVITY AND CORE BORON TRANSIENTS FSAR UPDATE Revision 19 May 2010 FIGURE 15.4.2-10 MAIN FEEDLINE RUPTURE WITH OFFSITE POWER AVAILABLE NUCLEAR POWER AND CORE HEAT FLUX TRANSIENTS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010 FIGURE 15.4.2-11 MAIN FEEDLINE RUPTURE WITH OFFSITE POWER AVAILABLE PRESSURIZER PRESSURE AND WATER VOLUME TRANSIENTS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010 FIGURE 15.4.2-12 MAIN FEEDLINE RUPTURE WITH OFFSITE POWER AVAILABLE REACTOR COOLANT TEMPERATURE TRANSIENTS FOR THE FAULTED AND INTACT LOOPS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010 UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 15.4.2-13 MAIN FEEDLINE RUPTURE WITH OFFSITE POWER AVAILABLE STEAM GENERATOR PRESSURE AND TOTAL MASS TRANSIENTS Revision 19 May 2010 FIGURE 15.4.2-14 MAIN FEEDLINE RUPTURE WITHOUT OFFSITE POWER AVAILABLE NUCLEAR POWER AND CORE HEAT FLUX TRANSIENTS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010 FIGURE 15.4.2-15 MAIN FEEDLINE RUPTURE WITHOUT OFFSITE POWER AVAILABLE PRESSURIZER PRESSURE AND WATER VOLUME TRANSIENTS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010 FIGURE 15.4.2-16 MAIN FEEDLINE RUPTURE WITHOUT OFFSITE POWER AVAILABLE REACTOR COOLANT TEMPERATURE TRANSIENTS FOR THE FAULTED AND INTACT LOOPS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 19 May 2010 UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 15.4.2-17 MAIN FEEDLINE RUPTURE WITHOUT OFFSITE POWER AVAILABLE STEAM GENERATOR PRESSURE AND TOTAL MASS TRANSIENTS Revision 19 May 2010 UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 15.4.2-18 MAIN STEAM LINE RUPTURE AT FULL POWER, 0.49 ft2 BREAK NUCLEAR POWER AND CORE HEAT FLUX TRANSIENTS Revision 19 May 2010 UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 15.4.2-19 MAIN STEAM LINE RUPTURE AT FULL POWER, 0.49 ft2 BREAK PRESSURIZER PRESSURE AND WATER VOLUME TRANSIENTS Revision 19 May 2010 UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 15.4.2-20 MAIN STEAM LINE RUPTURE AT FULL POWER, 0.49 ft2 BREAK REACTOR VESSEL INLET TEMPERATURE AND LOOP AVERAGE TEMPERATURE TRANSIENTS Revision 19 May 2010 UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE FIGURE 15.4.2-21 MAIN STEAM LINE RUPTURE AT FULL POWER, 0.49 ft2 BREAK TOTAL STEAM FLOW AND STEAM PRESSURE TRANSIENTS Revision 19 May 2010 FIGURE 15.4.3-1A PRESSURIZER LEVEL SGTR MTO ANALYSIS UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 20 November 2011 FIGURE 15.4.3-1B PRESSURIZER LEVEL SGTR DOSE INPUT ANALYSIS UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 FIGURE 15.4.3-2A PRESSURIZER PRESSURE SGTR MTO ANALYSIS UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 20 November 2011 FIGURE 15.4.3-2B PRESSURIZER PRESSURE SGTR DOSE INPUT ANALYSIS UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 FIGURE 15.4.3-3A SECONDARY PRESSURE SGTR MTO ANALYSIS UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 20 November 2011 FIGURE 15.4.3-3B SECONDARY PRESSURE SGTR DOSE INPUT ANALYSIS UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 FIGURE 15.4.3-4A INTACT LOOP HOT AND COLD LEG RCS TEMPERATURES SGTR MTO ANALYSIS UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 20 November 2011 FIGURE 15.4.3-4B INTACT LOOP HOT AND COLD LEG RCS TEMPERATURES SGTR DOSE INPUT ANALYSIS UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 FIGURE 15.4.3-5B RUPTURED LOOP HOT AND COLDLEG RCS TEMPERATURES SGTR DOSE INPUT ANALYSIS UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 FIGURE 15.4.3-6A PRIMARY TO SECONDARY BREAK FLOW RATE SGTR MTO ANALYSIS UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 20 November 2011 FIGURE 15.4.3-6B PRIMARY TO SECONDARY BREAK FLOW RATE SGTR DOSE INPUT ANALYSIS UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 FIGURE 15.4.3-7A RUPTURED STEAM GENERATOR WATER VOLUME SGTR MTO ANALYSIS UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 20 November 2011 FIGURE 15.4.3-7B RUPTURED STEAM GENERATORWATER VOLUME SGTR DOSE INPUT ANALYSIS UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 FIGURE 15.4.3-8A RUPTURED STEAM GENERATOR WATER MASS SGTR MTO ANALYSIS UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATERevision 20 November 2011 FIGURE 15.4.3-8B RUPTURED STEAM GENERATORWATER MASS SGTR DOSE INPUT ANALYSIS UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 FIGURE 15.4.3-9 RUPTURED SG MASS RELEASE RATETO THE ATMOSPHERE SGTR DOSE INPUT ANALYSIS UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 21 September 2013 FIGURE 15.4.3-10 INTACT SGs MASS RELEASE RATETO THE ATMOSPHERE SGTR DOSE INPUT ANALYSIS UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 FIGURE 15.4.3-11 TOTAL FLASHED BREAK FLOW SGTR DOSE INPUT ANALYSIS UNITS 1 AND 2 DIABLO CANYON SITEFSAR UPDATE Revision 21 September 2013 FIGURE 15.4.4-1 ALL LOOPS OPERATING ONE LOCKED ROTOR PRESSURE VERSUS TIMEUNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.4.4-2 ALL LOOPS OPERATING ONE LOCKED ROTOR CLAD TEMPERATURE VERSUS TIMEUNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.4.4-3 ALL LOOPS OPERATING ONE LOCKED ROTOR FLOW COASTDOWN VERSUS TIMEUNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.4.4-4 ALL LOOPS OPERATING ONE LOCKED ROTOR HEAT FLUX VERSUS TIMEUNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.4.4-5 ALL LOOPS OPERATING ONE LOCKED ROTOR NUCLEAR POWER VERSUS TIMEUNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.4.6-1 NUCLEAR POWER TRANSIENT, BOL, HZP, ROD EJECTION ACCIDENT UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.4.6-2 HOT SPOT FUEL AND CLAD TEMPERATURES VERSUS TIME, BOL, HZP, ROD EJECTION ACCIDENT UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.4.6-3 NUCLEAR POWER TRANSIENT, EOL, HFP, ROD EJECTION ACCIDENT UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 FIGURE 15.4.6-4 HOT SPOT FUEL AND CLAD TEMPERATURES VERSUS TIME, EOL, HZP, ROD EJECTION ACCIDENT UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 11 November 1996 Ratio of Short-term Release Concentration to Continuous Release Concentration vs. Release Duration DIABLO CANYON UNITS 1 & 2 FIGURE 15.5-1 Revision 11 November 1996 Thyroid Dose at 800 Meters Verses Weight of Steam Dumped to Atmosphere (Design Basis Case Assumptions) DIABLO CANYON UNITS 1 & 2 FIGURE 15.5-2 Revision 11 November 1996 Thyroid Dose at 10,000 Meters Verses Weight of Steam Dumped to Atmosphere (Design Basis Case Assumptions) DIABLO CANYON UNITS 1 & 2 FIGURE 15.5-3 Revision 11 November 1996 Thyroid Dose at 10,000 Meters Verses Weight of Steam Dumped to Atmosphere (Expected Case Assumptions) DIABLO CANYON UNITS 1 & 2 FIGURE 15.5-4 Revision 11 November 1996 Thyroid Dose at 800 Meters Verses Weight of Steam Dumped to Atmosphere (Expected Case Assumptions) DIABLO CANYON UNITS 1 & 2 FIGURE 15.5-5 Revision 11 November 1996 Thyroid Exposures for 15 Percent Nonremovable Iodine (Normalized to Exposures for Zero Spray Removal Constant) DIABLO CANYON UNITS 1 & 2 FIGURE 15.5-6 Revision 11 November 1996 DBA 2-Hour 800-Meter Thyroid Exposures Verses Spray Removal Constant and Percent Nonremovable Iodine (Normalized to Exposures with Zero Spray Removal Constant and Zero Percent Nonremovable Iodine) DIABLO CANYON UNITS 1 & 2 FIGURE 15.5-7 Revision 11 November 1996 DBA 30-Hour 800-Meter Thyroid Exposures Verses Spray Removal Constant and Percent Nonremovable Iodine (Normalized to Exposures with Zero Spray Removal Constant and Zero Percent Nonremovable Iodine) DIABLO CANYON UNITS 1 & 2 FIGURE 15.5-8 Revision 11 November 1996 Containment Recirculation Sump Activity Pathway to the Atmosphere for Small Leak Case DIABLO CANYON UNITS 1 & 2FIGURE 15.5-9 Revision 11 November 1996 Containment Recirculation Sump Activity Pathway to the Atmosphere for Large Leak Case DIABLO CANYON UNITS 1 & 2 FIGURE 15.5-10 Revision 11 November 1996 Equilibrium Elemental Iodine Partition and Decontamination Factors for the Expected Case - Large Circulation Loop Leakage in the Auxiliary Building DIABLO CANYON UNITS 1 & 2 FIGURE 15.5-11 Revision 11 November 1996 Equilibrium Elemental Iodine Partition and Decontamination Factors for the DBA Case - Large Circulation Loop Leakage in the Auxiliary Building DIABLO CANYON UNITS 1 & 2 FIGURE 15.5-12 Revision 11 November 1996 Potential Radiation Exposures as a Result of Accidents Involving Failure of Fuel Cladding (Design Basis Case Assumptions) DIABLO CANYON UNITS 1 & 2 FIGURE 15.5-14 Revision 11 November 1996 Potential Radiation Exposures as a Result of Accidents Involving Failure of Fuel Cladding (Expected Case Assumptions) DIABLO CANYON UNITS 1 & 2 FIGURE 15.5-15 Revision 11 November 1996
Incremental Long-term Doses From Accidents Involving Failure of Fuel Cladding DIABLO CANYON UNITS 1 & 2 FIGURE 15.5-16Revision 11 November 1996 DCPP UNITS 1 & 2 FSAR UPDATE i Revision 21 September 2013 Chapter 16 TECHNICAL SPECIFICATIONS AND EQUIPMENT CONTROL GUIDELINES CONTENTS Section Title Page 16.1 TECHNICAL SPECIFICATIONS AND EQUIPMENT CONTROL GUIDELINES 16.1-1
DCPP UNITS 1 & 2 FSAR UPDATE ii Revision 21 September 2013 Chapter 16 TABLES Table Title 16.1-1 Equipment Control Guidelines
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 16 TECHNICAL SPECIFICATIONS AND EQUIPMENT CONTROL GUIDELINES 16.1 TECHNICAL SPECIFICATIONS AND EQUIPMENT CONTROL GUIDELINES The Technical Specifications (TSs) for Diablo Canyon Power Plant (DCPP) are contained in Appendix A of the Operating Licenses. The TS Bases provide the bases or reasons for these technical specifications other than those covering administrative controls. In accordance with 10 CFR 50.36, the TS Bases are not part of the TS, and are included by reference in this section of the FSAR Update in accordance with 10 CFR 50.34 and 10 CFR 50.36. Changes to the TS Bases are processed in accordance with TS 5.5.14, "Technical Specifications (TS) Bases Control Program."
The Equipment Control Guidelines (ECGs) provide administrative controls and operability requirements for selected equipment that is not addressed by the TSs. ECGs are developed when controls are required by regulatory commitments or when plant management determines that it is prudent to control equipment to maximize its availability. TSs that have been relocated to licensee controlled documents are generally transferred to ECGs. ECGs containing relocated TSs are incorporated into the FSAR Update by reference.
Similar to TSs, ECGs provide operability requirements, action statements, and surveillance requirements. If the equipment cannot be returned to service as required by the ECG, administrative review, approval, and evaluation under the plant Quality Assurance Programs is required. Table 16.1-1 lists those DCPP ECGs that have been implemented due to relocated TSs in accordance with the NRC's Final Policy Statement on TS Improvements and 10 CFR 50.36, which include four criteria to be used for identifying TS requirements that may be relocated to licensee controlled documents. Several license amendments were issued by the NRC related to relocated TSs as noted in Table 16.1-1. Fire Protection TSs relocated to ECGs are listed in Appendix 9.5H.
The preparation and revision process for ECGs requires evaluation under 10 CFR 50.59 or other applicable requirements. All ECGs and ECG revisions are approved by the Station Director. 16.1-1 Revision 19 May 2010 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 16.1-1 Sheet 1 of 3 EQUIPMENT CONTROL GUIDELINES - TECHNICAL SPECIFICATIONS RELOCATED IN ACCORDANCE WITH NRC'S FINAL POLICY STATEMENT ON TECHNICAL SPECIFICATION IMPROVEMENTS Number Title Notations ECG 4.3 Steam Generator Pressure/Temperature Limitation 1
ECG 4.4 Instrumentation - Turbine Overspeed Protection and Turbine Trip 3, 7 ECG 7.3 Reactor Coolant System - Safety Valves Shutdown 2 ECG 7.4 Reactor Coolant System - Chemistry 2 ECG 7.5 Reactor Coolant System - Pressurizer 2
ECG 7.6 Reactor Coolant System - Structural Integrity 2
ECG 7.7 Reactor Coolant System - Reactor Vessel Head Vents 2
ECG 7.8 Accident Monitoring Instrumentation 4, 5
ECG 8.4 Reactivity Control Systems - Flow Paths - Operating 3
ECG 8.5 Reactivity Control Systems - Boration Systems - Flow Path - Shutdown 4 ECG 8.6 Reactivity Control Systems - Charging Pump - Shutdown 4
ECG 8.7 Reactivity Control Systems - Charging Pumps - Operating 4
ECG 8.8 Reactivity Control Systems - Borated Water Source - Shutdown 4 ECG 8.9 Reactivity Control Systems - Borated Water Sources - Operating 4 ECG 9.1 Accumulator Pressure and Water Level Instrumentation 8
ECG 13.2 Water Level - Spent Fuel Pool 4
ECG 17.3 Flood Protection 1 Revision 16 June 2005 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 16.1-1 Sheet 2 of 3 Number Title Notations ECG 19.1 Liquid Radwaste - Temporary Outdoor Tanks 4
ECG 21.3 Miscellaneous Emergency Diesel Generator (EDG) Functions 4 ECG 23.1 Area Temperature Monitoring 1
ECG 23.2 Instrumentation - Chlorine Detection System 3 ECG 23.3 Containment Ventilation System 4
ECG 23.4 Hydrogen Recombiners 4, 5
ECG 23.5 Plant Systems - Control Room Ventilation System (CRVS) 4
ECG 24.1 Explosive Gas Effluent Monitoring Instrumentation 4 ECG 24.2 Gaseous Radwaste - Explosive Gas Mixture 4
ECG 24.3 Gaseous Radwaste - Gas Storage Tanks 4 ECG 33.1 Nuclear Instrumentation - Power Distribution Monitoring System Instrumentation 6 ECG 37.2 Axial Flus Difference (AFD) Monitor Alarm 4 ECG 37.3 Quadrant Power Tilt Ratio Alarm 4
ECG 38.1 Reactor Trip System (RTS) - Instrumentation Response Times 4 ECG 38.2 Engineered Safety Features (ESF) Response Times 4
ECG 39.6 Sealed Source Contamination 1 ECG 40.1 Meteorological Instrumentation 4
ECG 41.1 Reactivity Control Systems - Position Indication System - Shutdown 3 ECG 41.2 Special Test Exceptions - Position Indication System - Shutdown 4 Revision 16 June 2005 DCPP UNITS 1 & 2 FSAR UPDATE TABLE 16.1-1 Sheet 3 of 3 Revision 16 June 2005 Number Title Notations ECG 42.1 Refueling Operations - Decay Time 4 ECG 42.2 Refueling Operations - Communications 4 ECG 42.3 Refueling Operations - Manipulator Crane 4 ECG 42.4 Refueling Operations - Crane Travel - Fuel Handling Building 4 ECG 42.5 Refueling Operations - Water Level - Reactor Vessel 4 ECG 45.2 Containment Systems - Containment Structural Integrity 3 ECG 45.3 Containment Penetration Conductor Overcurrent Protective Devices 3 ECG 48.1 Movable Incore Detectors 4 ECG 51.1 Instrumentation - Seismic Instrumentation 3 ECG 64.1 MOV Thermal Overload Protection and Bypass Devices 3 ECG 99.1 Snubbers 1 Notes: 1. Technical Specifications (TS) relocated pursuant to License Amendments (LAs) 106 (Unit 1) and 105 (Unit 2), dated July 6, 1995.
- 2. TS relocated pursuant to LAs 98 (Unit 1) and 97 (Unit 2), dated March 9, 1995. 3. TS relocated pursuant to LAs 120 (Unit 1) and 118 (Unit 2), dated February 3, 1998. 4. TS relocated pursuant to LAs 135 (Unit 1) and 135 (Unit 2), dated May 28, 1999.
- 5. TS relocated pursuant to LAs 168 (Unit 1) and 169 (Unit 2), dated May 4, 2004. 6. TS changes pursuant to LAs 164 (Unit 1) and 166 (Unit 2), dated March 31, 2004. 7. TS relocated pursuant to LAs 173 (Unit 1) and 175 (Unit 2), dated September 24, 2004. 8. TS relocated pursuant to LAs 102 (Unit 1) and 101 (Unit 2), dated May 26, 1995.
DCPP UNITS 1 & 2 FSAR UPDATE i Revision 21 September 2013 Chapter 17 QUALITY ASSURANCE CONTENTS
Section Title Page 17.1 ORGANIZATION 17.1-1
17.2 QUALITY ASSURANCE PROGRAM 17.2-1
17.2.1 Program Applicability 17.2-1
17.2.2 Program Control 17.2-3
17.2.3 Independent Review Program 17.2-4
17.2.4 Plant Staff Review Committee 17.2-6
17.3 DESIGN CONTROL 17.3-1
17.4 PROCUREMENT DOCUMENT CONTROL 17.4-1
17.5 INSTRUCTIONS, PROCEDURES, AND DRAWINGS 17.5-1 17.6 DOCUMENT CONTROL 17.6-1
17.7 CONTROL OF PURCHASED MATERIAL, EQUIPMENT, AND SERVICES 17.7-1
17.8 IDENTIFICATION AND CONTROL OF MATERIALS, PARTS, AND COMPONENTS 17.8-1
17.9 SPECIAL PROCESSES 17.9-1
17.10 INSPECTION 17.10-1
17.11 TEST CONTROL 17.11-1
17.12 CONTROL OF MEASURING AND TEST EQUIPMENT 17.12-1
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 17 QUALITY ASSURANCE CONTENTS (Continued) Section Title Page ii Revision 21 September 2013 17.13 HANDLING, STORAGE, AND SHIPPING 17.13-1 17.14 INSPECTION, TEST, AND OPERATING STATUS 17.14-1
17.15 CONTROL OF NONCONFORMING CONDITIONS 17.15-1
17.16 CORRECTIVE ACTION 17.16-1
17.17 QUALITY ASSURANCE RECORDS 17.17-1
17.17.1 DCPP Lifetime Records 17.17-2
17.17.2 DCPP Nonpermanent Records 17.17-3
17.17.3 Diablo Canyon ISFSI Records 17.17-4
17.18 AUDITS 17.18-1
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 17 QUALITY ASSURANCE TABLES Table Title iii Revision 21 September 2013 17.1-1 Current Regulatory Requirements and PG&E Commitments Pertaining to the Quality Assurance Program
DCPP UNITS 1 & 2 FSAR UPDATE Chapter 17 QUALITY ASSURANCE FIGURES Figure Title iv Revision 21 September 2013 17.1-1 Pacific Gas and Electric Company Utility Organization 17.1-2 Nuclear Quality in the Utility Organization DCPP UNITS 1 & 2 FSAR UPDATE 17.1-1 Revision 21 September 2013 Chapter 17 QUALITY ASSURANCE 17.1 ORGANIZATION The Pacific Gas and Electric Company's (PG&E) efforts to assure the quality and safety of its nuclear power plants and the Diablo Canyon (DC) independent spent fuel storage installations (ISFSI) is organized in a structured manner with clearly defined levels of authority, assignments of responsibility, and lines of communication. Assignment of responsibility for an item or activity includes responsibility for its quality. Figure 17.1-1 depicts the organizational structure of PG&E. The position of the quality verification (QV) organization in the utility organization is shown in Figure 17.1-2.
PG&E has assumed full responsibility to its employees, stockholders, the general public, and affected governmental regulatory agencies for the establishment and execution of the Quality Assurance (QA) Program prescribed herein, quality-related program directives, and administrative procedures. The work of executing selected portions of the QA Program may be delegated to organizations external to PG&E; however, in all such instances, PG&E retains overall responsibility.
Specific responsibilities pertaining to quality assurance matters are assigned by the QA Program and its implementing procedures and instructions to various individuals throughout PG&E. In each instance, the assignment of a responsibility to an individual includes with it a commensurate delegation of sufficient authority that the person can, in fact, fulfill that responsibility. Unless otherwise specifically prohibited, it is understood that the functions, tasks, and activities necessary to carry out a responsibility may be delegated to and performed by other qualified individuals. All delegations of functions, tasks, activities, and authority shall be documented.
Figure 17.1-2 identifies those individuals and organizational components of PG&E with direct responsibilities related to the quality of the:
- design, maintenance, and operation of DCPP, and
- design, fabrication, construction, testing, operation, maintenance, modification, and decommissioning of ISFSI structures, systems, and components (SSCs) that are important to safety.
The narrative description throughout this section is based on Figures 17.1-1 and 17.1-2. THE BOARD OF DIRECTORS OF PG&E CORPORATION is responsible for all facets of PG&E's utility business.
THE CHAIRMAN, CEO, AND PRESIDENT, PG&E CORPORATION, is accountable to the Board of Directors and establishes the corporate policies, goals, and objectives DCPP UNITS 1 & 2 FSAR UPDATE 17.1-2 Revision 21 September 2013 related to all of PG&E's activities and operations. Reporting to the Chairman, CEO, and President is the President - PG&E Company. THE PRESIDENT - PG&E, is a member of the Board of Directors and is responsible for and directs the planning, distribution, and development of all the Company's energy resources and nuclear power generation. These functions include such activities as planning and development, engineering, information services, construction, and fossil and nuclear power plant and ISFSI operations. Reporting to the President - PG&E is the Senior Vice President, Energy Supply; the Senior Vice President, Safety and Shared Services; and the Executive Vice President, Electric Operations. THE EXECUTIVE VICE PRESIDENT - ELECTRIC OPERATIONS, through the Director - Applied Technology Services, is responsible for providing, upon request: (1) technical investigations, tests, analyses, examinations, and calibration services in support of DCPP and its ISFSI; (2) developing, evaluating, qualifying, testing, and improving welding, brazing, and heat-treating procedures required by the company; and (3) providing evaluation support of these procedures.
THE SENIOR VICE PRESIDENT - SAFETY AND SHARED SERVICES, through the Support Services Supervisor - Engineering Records Unit, is responsible for providing document services support for DCPP and the ISFSI. These services include indexing, preparing, and duplicating microfiche for the drawing control system; storing the master microfiche and drawings that cannot be microfilmed; and scanning and indexing drawings when requested. They also provide remote storage of master microfilm reels for the records management system (RMS) and storage of vendor manuals. The Senior Vice President - Safety and Shared Services, through the Manager - Nuclear Supply Chain, is responsible for administering, coordinating, planning, and operation of warehousing and procurement of materials in support of DCPP and ISFSI construction and operations, as well as for contract services. THE SENIOR VICE PRESIDENT, ENERGY SUPPLY is responsible for the safe and efficient operation of utility owned generation. Reporting to the Senior Vice President, Energy Supply is the Senior Vice President, Chief Nuclear Officer. THE SENIOR VICE PRESIDENT - CHIEF NUCLEAR OFFICER, is responsible for the safe and efficient operation of the Company's nuclear power plants. He is responsible for overall ISFSI safety and for taking measures needed to ensure acceptable performance of the ISFSI staff in designing, fabricating, constructing, testing, operating, modifying, decommissioning, and providing technical support to the ISFSI. The Senior Vice President - Chief Nuclear Officer, is the corporate officer specified by the DCPP Technical Specifications, who shall have corporate responsibility for overall DCPP nuclear safety and shall take any measures needed to ensure acceptable performance of the staff in operating, maintaining, and providing technical support to DCPP to ensure nuclear safety. Reporting directly to the Senior Vice President - Chief Nuclear Officer is the Site Vice President; the Senior Director, Engineering and Projects; the Director - Quality Verification; the Director, Station Support; the Director, Strategic Projects; and DCPP UNITS 1 & 2 FSAR UPDATE 17.1-3 Revision 21 September 2013 the Employee Concerns Program supervisor. The Senior Vice President - Chief Nuclear Officer, or his designee, as specified in administrative procedures, approves and signs official company correspondence to the U.S. Nuclear Regulatory Commission (NRC) or its representatives. The Independent Review and Audit Program, the Diablo Canyon Plant Staff Review Committee (PSRC) and Nuclear Safety Oversight Committee (NSOC) report to the Senior Vice President - Chief Nuclear Officer. He approves revisions to the QA Program as described herein that constitute a reduction in a commitment made to the NRC. He also approves revisions to program directives.
THE SITE VICE PRESIDENT is responsible for the conduct of all onsite activities related to the safe and efficient maintenance and operation of the plant as well as activities related to ISFSI operation and decommissioning. He is responsible to develop, and has been delegated the necessary authority to approve and direct the implementation of, those programs, procedures, and instructions required for the operation of the plant and ISFSI, within limits established by the QA Program, Technical Specifications, and administrative guidelines established by the Senior Vice President - Chief Nuclear Officer. Reporting directly to the Site Vice President is the Station Director and the Director, Security Services. THE SENIOR DIRECTOR - ENGINEERING AND PROJECTS, is responsible for providing engineering and design services, geotechnical services, project management and nuclear fuels management. This includes configuration control, design bases defense and management, performance of modifications to DCPP, providing day-to-day technical support for DCPP operations; managing technical programs related to system and component health and long-term planning; and complying with regulatory requirements pertaining to SSCs. This includes the ISFSI. This position, through the Manager, Regulatory Services, is responsible for coordinating with the NRC for all matters relating to obtaining, maintaining, amending, revising, and otherwise changing the DCPP and ISFSI licenses. This position is responsible for reporting trend and performance status information to the Site Vice President. This position is specifically charged with development, evaluation, qualification, testing, and improvement of nondestructive examination procedures required by PG&E and for evaluation of these types of procedures that are used at DCPP by other organizations. Reporting directly to the Senior Director - Engineering Services and Projects are the Director - Engineering Services; the Manager - Nuclear Fuels; the Director - Nuclear Projects; the Director, Geosciences; and the Manager, Regulatory Services. The Senior Director - Engineering Services and Projects is also responsible for the specification of technical and quality requirements for the purchase of DCPP and ISFSI material and equipment. THE DIRECTOR, STATION SUPPORT is responsible for training and site services, which includes emergency planning and performance improvement. This position is also responsible for providing support for the independent review groups and agencies, such as the Diablo Canyon Independent Safety Committee. Reporting directly to the Director DCPP UNITS 1 & 2 FSAR UPDATE 17.1-4 Revision 21 September 2013 Station Support is the Director, Learning Services; Director, Site Services and the Director, Compliance, Alliance, and Risk. THE STATION DIRECTOR is the plant manager specified in the DCPP TS, Section 5. He is responsible for operations and maintenance. Reporting directly to the Station Director is the Director - Operations Services; the Director - Maintenance Services; the Director - Nuclear Work Management; and the Manager, Radiation Protection. THE DIRECTOR - OPERATIONS SERVICES, is responsible for operations. Reporting to the Director - Operations Services are the Manager - Operations; Manager - Operations Planning; Manager - Operations Performance; and the Manager, Chemistry and Environmental Services. THE DIRECTOR - QUALITY VERIFICATION, is responsible for management of the QA Program and for assuring that the QA Program prescribed herein, program directives, and administrative procedures are effectively implemented and complied with by all involved organizations, both internal and external to PG&E. The Chairman, CEO, and President - PG&E Corporation; the President - PG&E; the Senior Vice President - Energy Supply; and the Senior Vice President, Chief Nuclear Officer, have given the Director, Quality Verification, the organizational freedom and delegated the requisite authority to investigate any area or aspect of PG&E's operations as necessary to identify and define problems associated with establishment or execution of the QA Program. They have also delegated to the Director, Quality Verification, the authority to initiate, recommend, or provide solutions for such problems to whatever management level is necessary, and to verify that effective corrective action is taken in a timely manner. This delegation includes the authority to assess, review, inspect, audit, and monitor the conduct of quality-related activities performed by or for PG&E to assure compliance with the QA Program and other regulatory requirements.
The Director - QV, reports directly to the Senior Vice President - Chief Nuclear Officer and has access to the Chairman, CEO, and President - PG&E Corporation; the President - PG&E; the Senior Vice President, Energy Supply; the Site Vice President; the Senior Director, Engineering and Projects; the Director, - Humboldt Bay Nuclear; and appropriate directors and managers for any significant quality-related problem or deficiency. He is authorized to prescribe a uniform company-wide method of performing an activity affecting quality by sponsoring or requiring the issuance of procedures when such standardization is considered desirable or essential to the effectiveness of the QA Program. Such uniform methods are contained in program directives and administrative procedures, and compliance with their requirements by all PG&E personnel is mandatory.
The Director - QV, will not be responsible for any activities unrelated to responsibilities described in the QA Program that would prevent the required attention to QA matters. Further, the responsibility of the implementation of the QA Program will take precedence over the other non-QA duties.
DCPP UNITS 1 & 2 FSAR UPDATE 17.1-5 Revision 21 September 2013 The Director - QV, shall meet the following qualification requirements: management experience through assignments to responsible positions; knowledge of QA regulations, policies, practices, and standards; and experience working in QA or related activity in reactor design, construction, or operation or in a similar highly technological industry. At the time of initial core loading or assignment to the active position, the Director - QV, shall have six years experience in implementing quality assurance, preferably at an operating nuclear plant, or operations supervisory experience. At least one year of these six years of experience shall be nuclear power plant experience in the overall implementation of the QA Program. A minimum of one year of this six-year experience requirement shall be related technical or academic training. A maximum of four years of this six-year experience requirement may be fulfilled by related technical or academic training.
The Director - QV, is responsible to regularly assess and report on the status, adequacy, and effectiveness of PG&E's QA Program to the Senior Vice President - Chief Nuclear Officer and other affected PG&E management and nuclear oversight committees. He is responsible to identify, prepare, and submit for approval such changes to the QA Program prescribed herein as are necessary to maintain the QA Program up to date and in conformance with current regulatory requirements and PG&E commitments to the NRC. He is responsible for the review of all regulatory submittals as they pertain to the QA Program, and his concurrence is required prior to submittal. He is responsible for assessing and assuring that the QA Program is effectively implemented at DCPP and the ISFSI. He assures timely and effective corrective actions through audits, regular assessments, and quality assessment status reports. Reporting to the Director - QV, are the quality assurance, supplier quality, project quality, and independent quality control inspection functions. The Director - QV, is responsible for providing recommendations on solutions to quality problems and performing monitoring, assessments, independent QC inspections, reviews, and audits for the areas covered by the QA Program including supplier quality. The Director - QV, is also responsible for quality assurance associated with the Humboldt Bay Power Plant.
The Director - QV, has the authority and responsibility to stop work should there be a serious breach of any part of the QA Program, or of technical or regulatory requirements wherein public health or safety could be involved. If stopping work would involve changing a nuclear generating unit's power level or separating such a unit from the PG&E system, the concurrence of the Senior Vice President - Chief Nuclear Officer, the Site Vice President; or the Station Director is required.
Through the conduct of assessments, audits, reviews, monitors, and independent QC inspections, the Director - QV, is responsible for quality overview of:
- DCPP operating characteristics, operations, modifications, maintenance, and surveillance; and DCPP UNITS 1 & 2 FSAR UPDATE 17.1-6 Revision 21 September 2013
- ISFSI design, fabrication, construction, testing, operation, modification, decommissioning, and related activities to verify independently that these activities are performed correctly and that human errors are reduced as much as practicable.
THE EMPLOYEE CONCERNS PROGRAM SUPERVISOR reports to the Senior Vice President - Chief Nuclear Officer. THE MANAGER - NUCLEAR SUPPLY CHAIN, reports through the Director - Generation Supply Chain, to the Senior Vice President - Safety and Shared Services and is matrixed to the Director - Station Support through the Director, Compliance, Alliance, and Risk. The Manager - Nuclear Supply Chain, is responsible for administering, coordinating, planning, and operation of warehousing and procurement of materials in support of DCPP and ISFSI operations and construction, as well as for contract services. This position is responsible for the functions within the materials procurement group including: the procurement specialist group, warehousing operations, administrative coordination of warehouse quality control receipt inspection activities, and materials coordination.
The DIRECTOR - GEOSCIENCES, is responsible to the Senior Director - Engineering and Projects for providing geo-scientific studies; reports, and calculations (including geology, seismology, vibration ground motion studies, surface faulting, stability of subsurface materials, and slope stability) in support of DCPP and the ISFSI.
The following committees function at the managerial level within PG&E to provide review of DCPP and ISFSI design, maintenance, and operation activities.
THE NUCLEAR SAFETY OVERSIGHT COMMITTEE, which reports to the Senior Vice President - Chief Nuclear Officer, implements the Independent Review and is described in Section 17.2.3.
The mission of the NSOC is to provide an integral part of the DCPP oversight process by independently assessing the nuclear safety and performance of the station and advising the Senior Vice President - Chief Nuclear Officer on issues that could affect station performance and/or nuclear safety. The scope includes facility operations, the adequacy and implementation of all DCPP nuclear safety policies and programs, and any issues related to nuclear, radiological, industrial, and environmental safety. Based on this assessment, the NSOC will provide comments and/or recommendations to the Senior Vice President - Chief Nuclear Officer that are directed at ensuring overall excellence in Operations and overall station performance. THE DCPP PLANT STAFF REVIEW COMMITTEE reports to the Senior Vice President - Chief Nuclear Officer, and is responsible to advise the Station Director on matters related to nuclear safety. The Committee is responsible for providing timely and continuing monitoring of operating activities to assist the Station Director in keeping DCPP UNITS 1 & 2 FSAR UPDATE 17.1-7 Revision 21 September 2013 aware of general DCPP and ISFSI conditions and to verify that day-to-day operating activities are conducted safely and in accordance with applicable administrative controls. The Committee performs periodic reviews of DCPP and ISFSI operations and to plan future activities. In addition, the PSRC performs special reviews, investigations or analyses, and screens subjects of special concern. PSRC functions, responsibilities, and meeting requirements are described in Section 17.2. Administrative procedures or charters for the above committees or programs provide detailed responsibilities and functions, as well as membership, authority, and reporting requirements. The reporting relationships of the committee are identified in the organization chart on Figure 17.1-2.
Verification of conformance to established requirements (except designs) is accomplished by individuals or groups within QV who do not have direct responsibility for performing the work being verified or by individuals or groups trained and qualified in QA concepts and practices and independent of the organization responsible for performing the task. The persons and organizations performing QA and quality control functions have direct access to management levels that assure the ability to: (a) identify quality problems; (b) initiate, recommend, or provide solutions through designated channels; and (c) verify implementation of solutions. They are sufficiently free from direct pressures for cost and schedule and have the responsibility to stop unsatisfactory work and control further processing, delivery, or installation of nonconforming material. (The organizational positions with stop work authority are identified in the implementing procedures.) QV reviews and documents concurrence with all procedures and instructions that define methods for implementing the QA Program.
Each organization that supports DCPP and the ISFSI documents and maintains current a written description of its internal organization. This documentation describes the business unit or department's structure, levels of authority, lines of communication, and assignments of responsibility. Such documentation takes the form of organization charts supported by written job descriptions or other narrative material in sufficient detail that the duties and authority of each individual whose work affects quality is clear. Interfaces between organizations are described in administrative procedures or other documents controlled in accordance with the appropriate requirements of FSAR Update, Section 17.6.
The individuals assigned to the positions having a particular responsibility in program directives and administrative procedures (as described above) are the only individuals who are authorized to perform these activities. However, circumstances may arise where it is considered either necessary or desirable to have such activities, or some portion of them, actually performed by someone else. In such cases, the assigning organization retains responsibility and shall verify that the procedures and instructions to be followed in performing the work are adequate for controlling the work and meet applicable requirements. In such circumstances, the detailed procedures and instructions to be followed in performing the work are reviewed and approved by the person assigned responsibility for the work prior to the commencement of work. The DCPP UNITS 1 & 2 FSAR UPDATE 17.1-8 Revision 21 September 2013 purpose of such review and approval is to verify that such procedures and instructions reflect an acceptable method of performing the work and are in compliance with the requirements of the QA Program. All instances in which authority is to be delegated or support services are to be provided are documented.
Suppliers to DCPP and the ISFSI are required to conform to the PG&E QA Program or to their own program approved by PG&E. Supplier QA Programs are required to comply with the applicable portions of both 10 CFR 50, Appendix B, and 10 CFR 72, Subpart G, and the applicable regulatory documents and industry standards identified in Table 17.1-1. The quality program is defined in the contract or similar procurement document. Suppliers to PG&E are required to document their internal organizational arrangements to the extent necessary for PG&E to assure the supplier is capable of effectively managing, directing, and executing the requirements of the procurement documents. The authority and responsibility of persons and organizations who perform activities that might affect the quality of the procured items or services shall be clearly established. The Suppliers' organizational structure, levels of authority, and functional assignments of responsibility shall be such that:
(1) The QA function of formally verifying conformance to the technical and quality requirements of the procurement documents is accomplished by qualified personnel who are independent of those who performed or directly supervised the work. (2) Personnel who perform QA functions have sufficient authority and organizational freedom to identify quality problems; to initiate, recommend, or provide solutions; to verify implementation of those solutions; and to control further processing of the items or services until proper dispositioning has occurred.
DCPP UNITS 1 & 2 FSAR UPDATE 17.2-1 Revision 21 September 2013 17.2 QUALITY ASSURANCE PROGRAM 17.2.1 PROGRAM APPLICABILITY The quality of the:
- safety-related aspects of the design, construction, and operation of DCPP, and
- important-to-safety aspects related to the design, fabrication, construction, testing, operation, maintenance, modification, and decommissioning of the Diablo Canyon ISFSI structures, systems, and components (SSCs) shall be assured through the QA Program prescribed herein, quality-related program directives, and administrative procedures. The QA Program requirements, as a minimum, apply to those DCPP SSCs classified as Design Class I in Section 3.2 of the FSAR Update. The QA Program requirements apply to Diablo Canyon ISFSI SSCs classified as important to safety in their respective ISFSI FSAR Update, Section 4.5.
The applicable QA criteria are executed to an extent that is commensurate with the importance to safety.
The QA Program also applies to the following:
(1) DCPP design, construction, and operation of SSCs that prevent or mitigate the consequences of postulated accidents that could cause undue risk to the health and safety of the public. The SSCs that serve these functions are classified as Design Class I. In addition, certain QA Program requirements apply to the nonsafety-related programs discussed below to provide additional assurance that these objectives are satisfied. (2) The design, construction, and operation of those portions of DCPP SSCs whose function is not required as above but whose failure could reduce the functioning of the above DCPP features to an unacceptable level or could incapacitate control room occupants. Certain of these SSCs are conservatively designated as Design Class I. Other nonsafety-related SSCs with seismic qualification requirements are subject to the seismic configuration control program listed below. Seismically Induced System Interaction Program requirements are governed by quality-related procedures. (3) Activities affecting the above DCPP features.
(4) Geo-scientific studies performed by Geosciences. The Geosciences organization maintains QA Program administrative controls independent from DCPP. These administrative controls are specific to the DCPP UNITS 1 & 2 FSAR UPDATE 17.2-2 Revision 21 September 2013 Geosciences organization, are reviewed and approved by the Director, QV, and comply with the requirements listed in DCPP FSAR Update, Chapter 17. (5) Technical investigations, tests, analyses, examinations, calibration services performed at Applied Technology Services (ATS) in support of nuclear generation. This includes responsibility for the Nuclear Weld Control Manual. The ATS organization maintains QA Program administrative controls independent from DCPP. These administrative controls are specific to the ATS organization, are reviewed and approved by the Director, QV, and comply with the requirements listed in DCPP FSAR Update, Chapter 17 (6) Managerial and administrative controls to ensure safe operation of the ISFSI, both prior to issuance of a license and throughout the life of the licensed activity. (7) Activities that provide confidence that ISFSI SSCs will perform satisfactorily in service, including activities that determine that physical characteristics and quality of materials or components adhere to predetermined requirements. In addition, the QA Program includes requirements that apply to the following DCPP and ISFSI nonsafety-related programs: Program DCPP ISFSI (1) Fire Protection (2) Emergency Preparedness (3) Security (4) Radiation Protection (5) Radiological Monitoring and Controls Program (6) ISFSI Radiological Environmental Monitoring (7) Environmental Monitoring (8) Radioactive Waste Management (9) Fitness for Duty (10) Regulatory Guide 1.97, Category 2 and 3 Instrumentation X X X X X
X X X X X X X
X
X DCPP UNITS 1 & 2 FSAR UPDATE 17.2-3 Revision 21 September 2013 Program DCPP ISFSI (11) Seismic Configuration Control (12) Anticipated Transient Without Scram Mitigation System Actuation Circuitry (AMSAC) Equipment X X 17.2.2 PROGRAM CONTROL The status and adequacy of this QA Program shall be regularly monitored, and it shall be revised as necessary to improve its effectiveness or to reflect changing conditions.
The Director - Quality Verification (QV), is responsible for the preparation, issue, interpretation, and control of this QA Program, and for concurring with changes to quality-related program directives and administrative procedures that propose a change to the QA Program as it is described in a commitment to a regulatory agency. The Director - QV, is responsible to assure the requirements set forth in this QA Program, quality-related program directives, and administrative procedures are in compliance with current regulatory requirements and PG&E commitments to the NRC as shown in Table 17.1-1. Proposed changes to program directives are also approved by the Senior Vice President - Chief Nuclear Officer. The QA Program documents, including any changes, supplements, or appendices, are issued and maintained as controlled documents. Changes to the QA Program as described herein that do not reduce commitments shall be included in the periodic updates required by 10 CFR 50.71. Proposed changes to this QA Program that reduce commitments are reviewed and concurred with in writing by the Director - QV, and are approved by the Senior Vice President - Chief Nuclear Officer, or his designee, prior to being submitted to and approved by the NRC in accordance with 10 CFR 50.54 prior to issue for use.
Implementation of the QA Program is accomplished through separately issued procedures, instructions, and drawings. Each vice president, director, and manager is responsible for the establishment and implementation of detailed procedures and instructions prescribing the activities for which he is responsible. Such documents are derived from the requirements and reflect the responsibilities specified in the QA Program. Activities affecting quality are accomplished in accordance with these instructions, procedures, and drawings. All personnel are instructed that compliance with those requirements, and the requirements of the QA Program, is mandatory.
Questions or disputes involving interpretations of QA Program requirements, or of the commitments and requirements upon which it is based, are referred to the Director - QV, for resolution. Questions or disputes involving the responsibilities defined in this chapter and program directives are referred to the Senior Vice President - Chief Nuclear Officer. Questions or disputes involving other quality matters are resolved by referring DCPP UNITS 1 & 2 FSAR UPDATE 17.2-4 Revision 21 September 2013 the matter in a timely manner to successively higher levels of management until, if necessary, the matter reaches that level which has direct authority over all contesting parties.
Personnel who perform functions addressed by the QA Program are responsible for the quality of their work. They are indoctrinated, trained, and appropriately qualified to assure that they have achieved and maintained suitable proficiency to perform those functions. Qualifications of such personnel are in accordance with applicable codes, standards, and regulatory requirements.
The Director - QV, or his designated representative, regularly reports to the Senior Vice President - Chief Nuclear Officer, responsible company management, and NSOC on the effectiveness of the QA Program as it relates to DCPP and ISFSI design, maintenance, and operation of DCPP and the ISFSI. Such reports are based on the results of audits, reviews, inspections, tests, and other observations of activities as prescribed by the QA Program.
Annually, the Director - QV, shall report to the Senior Vice President - Chief Nuclear Officer, on the effectiveness of the QA Program and results of the Audit Program. The report shall include an evaluation of compliance with current regulatory requirements and commitments to the NRC. 17.2.3 INDEPENDENT REVIEW PROGRAM The QA Program also includes an independent review, implemented by NSOC. This function provides an independent review of DCPP and ISFSI changes, tests, and procedures, which constitute a change to the DCPP facility or ISFSI as described in the DCPP FSAR Update or ISFSI FSAR Update. In addition, the independent review function will verify that reportable events are investigated in a timely manner and corrected in a manner that reduces the probability of recurrence of such events; and detect trends that may not appear to a day-to-day observer. The individuals assigned responsibility for independent reviews shall be qualified in specific disciplines. These individuals shall collectively have the experience and competence required to review activities in the following areas:
(1) DCPP and ISFSI operations (2) Nuclear engineering (3) Chemistry and radiochemistry (4) Metallurgy (5) Nondestructive testing DCPP UNITS 1 & 2 FSAR UPDATE 17.2-5 Revision 21 September 2013 (6) Instrument and control (7) Radiological safety (8) Mechanical and electrical engineering (9) Administrative controls (10) Quality assurance practices (11) Other appropriate fields NSOC shall report to and advise the Senior Vice President - Chief Nuclear Officer, on those areas of responsibility specified in the sections below. Composition - NSOC membership shall be comprised of site representatives and external members. Membership will normally include the Site Vice-President and four external members. The NSOC Chair shall have a minimum of 6 years of professional level managerial experience in the power field and NSOC members shall have a minimum of 5 years of professional level experience in the power field.
The NSOC Chair and all members shall have qualifications that meet or exceed the requirements and recommendations of Section 4.7 of ANSI/ANS 3.1 1978. An individual may possess competence in more than one specialty area. Consultants: Consultants shall be used as determined by the NSOC Chair to provide expert advice to NSOC. Meeting Frequency: NSOC shall meet at least twice a year. Quorum: A quorum of NSOC is necessary for the performance of the NSOC function required by the QA Program. The quorum shall consist of the Chair and a minimum of 3 members, as long as one of the quorum is the Site Vice President or his designee. Review: NSOC shall review: (1) The evaluations for: (a) changes to procedures, equipment, or systems, and (b) tests or experiments completed under the provision of 10 CFR 50.59 or 10 CFR 72.48, to verify that such actions did not require prior NRC approval (2) Proposed changes to procedures, equipment, or systems, that require prior NRC approval as defined in 10 CFR 50.59 or 10 CFR 72.48 DCPP UNITS 1 & 2 FSAR UPDATE 17.2-6 Revision 21 September 2013 (3) Proposed tests or experiments that require prior NRC approval as defined in 10 CFR 50.59 or 10 CFR 72.48 (4) Proposed changes to Diablo Canyon Power Plant's Technical Specifications or Operating License (5) Proposed changes to the ISFSI Technical Specifications or licenses (6) Violations of codes, regulations, orders, Technical Specifications, license requirements, or of internal procedures or instructions having nuclear safety significance (7) Significant operating abnormalities or deviations from normal and expected performance of DCPP and ISFSI equipment that affect nuclear safety (8) All reportable events (9) All recognized indications of an unanticipated deficiency in some aspect of DCPP design or operation of safety-related SSCs that could affect nuclear safety (10) All recognized indications of an unanticipated deficiency in some aspect of ISFSI design or operation of important-to-safety SSCs that could affect nuclear safety (11) Meeting minutes of the PSRC. (12) Any other matter involving safe operation of DCPP or ISFSI. NSOC may delegate reviews of selected topics such as changes processed under 10 CFR 50.59 and 10 CFR 72.48 to QV. The appropriate NSOC subcommittee will consider QV's reviews of those topics in their meetings. Records - A report documenting the scope and conclusions of each NSOC meeting shall be prepared, approved, and forwarded to the Senior Vice President - Chief Nuclear Officer. 17.2.4 PLANT STAFF REVIEW COMMITTEE A PSRC has been established for DCPP and the ISFSI. The committee satisfies applicable requirements of ANSI N18.7, 1976, and its activities are controlled as described below: PSRC Function - The PSRC shall function to advise the Station Director on all matters related to nuclear safety. DCPP UNITS 1 & 2 FSAR UPDATE 17.2-7 Revision 21 September 2013 Composition - The PSRC shall be composed of a minimum of 8 senior management individuals, including the chairman. PSRC membership shall include one or more individuals knowledgeable in the following areas: operations, maintenance, radiation protection, engineering, and performance improvement. The PSRC Chairman and regular PSRC members shall be appointed in writing by the Station Director. The qualifications of each PSRC member shall meet or exceed the requirements and recommendations of Section 4.7 of ANSI/ANS 3.1-1978. To maintain quality assurance and independent review independence, the Director - QV, shall not be a member of the PSRC, however, PSRC meeting notifications and review material shall be provided to the Director - QV. Alternates - The Station Director shall designate in writing other regular members who may serve as the Acting Chairman of PSRC meetings. All alternates to regular members shall be appointed in writing by the Station Director. Alternates may be designated for specific PSRC members and shall have expertise and qualifications in the same general area as the regular PSRC member they represent. No more than two alternates shall participate as voting members in PSRC activities at any one time. Meeting Frequency - The PSRC shall meet at least once per calendar month and as convened by the PSRC Chairman or his designated alternate. Quorum - The minimum quorum of the PSRC necessary for performance of the PSRC responsibility and authority provisions of this QA Program shall be a majority (more than one-half) of the members of the PSRC. For purposes of the quorum, this majority shall include the Chairman or the acting chairman, and no more than two alternate members. The PSRC shall be responsible for: (1) Reviewing the documents listed below to verify that proposed actions do not require prior NRC approval or require a change to the Technical Specifications and recommending approval or disapproval in writing to the appropriate approval authority (a) Evaluations of proposed procedures and procedure changes completed under the provisions of 10 CFR 50.59 or 10 CFR 72.48 (b) Evaluations of proposed tests or experiments completed under the provisions of 10 CFR 50.59 or 10 CFR 72.48 (c) Evaluations of proposed changes or modifications to plant structures, systems, or equipment completed under the provisions of 10 CFR 50.59 or 10 CFR 72.48 DCPP UNITS 1 & 2 FSAR UPDATE 17.2-8 Revision 21 September 2013 (d) Evaluations of proposed changes to the following plans and programs completed under the provisions of 10 CFR 50.59, 10 CFR 72.48, or other applicable regulations: 1. Security Plan 2. Emergency Plan 3. Process Control Program 4. Fire Protection Program (2) Reviewing all proposed changes to the DCPP Technical Specifications and ISFSI Technical Specifications and advising the Station Director on their acceptability (3) Investigating all violations of the DCPP Technical Specifications and the applicable ISFSI Technical Specifications including the preparation and forwarding of reports covering evaluation and recommendations to prevent recurrence to the Senior Vice President - Chief Nuclear Officer. The assessment shall include an assessment of the safety significance of each violation (4) Reviewing all reportable events in order to advise the Station Director on the acceptability of proposed corrective actions, and forwarding of reports covering evaluation and recommendations to prevent recurrence to the Senior Vice President - Chief Nuclear Officer (5) Reviewing significant DCPP and ISFSI operating experience or events that may indicate the existence of a nuclear safety hazard, and advising the Station Director on an appropriate course of action (6) Reviewing the Security Plan and implementing procedures and submitting results and recommended changes to the Station Director (7) Reviewing the Emergency Plan and implementing procedures and submitting results and recommended changes to the Station Director (8) Reviewing any accidental, unplanned, or uncontrolled radioactive release including the preparation and forwarding of reports covering evaluation, recommendations, and disposition of the corrective action to prevent recurrence to the Senior Vice President - Chief Nuclear Officer (9) Recommending in writing to the appropriate approval authority, approval or disapproval of the items considered under paragraphs (1) and (2), above (10) Rendering determinations in writing with regard to whether each item considered under paragraphs (1) through (4), above, require prior NRC approval DCPP UNITS 1 & 2 FSAR UPDATE 17.2-9 Revision 21 September 2013 (11) Providing written notification within 24 hours to the Senior Vice President - Chief Nuclear Officer, of disagreement between the PSRC and the Station Director; however, the Station Director shall have responsibility for resolution of such disagreements (12) Reviewing, prior to approval, new procedures used to handle heavy loads in exclusion areas and changes directly related to methods and routes used to handle heavy loads in exclusion areas. Records - The PSRC shall maintain written minutes of each PSRC meeting that, at a minimum, document the results of all PSRC activities performed under the responsibility and authority provisions of this QA Program section. Copies shall be provided to the Senior Vice President - Chief Nuclear Officer, and to the quality verification director. DCPP UNITS 1 & 2 FSAR UPDATE 17.3-1 Revision 19 May 2010 17.3 DESIGN CONTROL Design activities shall be performed in an orderly, planned, and controlled manner directed to achieving the DCPP and independent spent fuel storage installation (ISFSI) design that best serves the needs of PG&E and its customers without posing an undue risk to the health and safety of the public.
Design activities shall be controlled to assure that design, technical, and quality requirements are correctly translated into design documents and that changes to design and design documents are properly controlled. Design control procedures shall address responsibilities for all phases of design including:
(1) Responsibilities (2) Interface control (3) Design input (4) Design performance (5) Design verification (6) Design change Systematic methods shall be established and documented for communicating needed design information across the external and internal design interfaces, including changes to the design information, as work progresses. The interfaces between the DCPP engineering organization and other organizations, either internal or external to PG&E, performing work affecting quality of design shall be identified and documented. This identification shall include those organizations providing criteria, designs, specifications, technical direction, and technical information and shall be in sufficient detail to cover each structure, system, or component (SSC) and the corresponding design activity.
Provisions for design input shall define the technical objectives for SSCs being designed or analyzed. For the SSC being designed, or for the design services being provided (for example, design verification), design input requirements shall be determined, documented, reviewed, approved, and controlled.
Required design analyses (such as physics, stress, thermal, hydraulic, and accident analysis; material compatibility; accessibility for inservice inspection, maintenance, and repair; and ALARA considerations) shall be performed in a planned, controlled, and correct manner. PG&E procedures shall identify the review and approval responsibilities for design analyses.
DCPP UNITS 1 & 2 FSAR UPDATE 17.3-2 Revision 19 May 2010 The preparation and control of design documents (such as specifications, drawings, reports, and installation procedures) shall be performed in a manner to assure design inputs are correctly translated into design documents (for example, a documented check to verify the dimensional accuracy and completeness of design drawings and specifications).
PG&E shall provide for reviewing, confirming, or substantiating the design to assure that the design meets the specified design inputs. Design verification shall be performed by competent individuals or groups other than those who performed the original design, but who may be from the same department. Individuals performing the verification shall not:
(1) Have immediate supervisory responsibility for the individual performing the design. In exceptional circumstances, the designer's immediate supervisor can perform the verification provided: (a) The supervisor is the only technically qualified individual (b) The need is individually documented and approved in advance by the supervisor's management (c) Quality assurance audits cover frequency and effectiveness of use of supervisors as design verifiers to guard against abuse (2) Have specified a singular design approach (3) Have ruled out certain design considerations (4) Have established the design inputs for the particular design aspect being verified The results of the design verification efforts shall be documented with the identification of the verifier clearly provided. Design verification methods may include, but not be limited to, the following: design reviews, use of alternate calculations, and qualification testing. The design verification shall be identified and documented. The design verification shall be completed prior to relying upon the component system or structure to perform its function. Procedures shall assure that verified computer codes are certified for use and that their applicability is specified.
Proposed changes or modifications to ISFSI or DCPP systems or equipment that affect nuclear safety shall be designed by a qualified individual or organization, and reviewed by a qualified individual/group other than the individual/group who prepared the change or modification, but who may be from the same organization. These reviews shall include a determination as to whether additional cross-discipline reviews are necessary. If deemed necessary, they shall be performed by review personnel of the appropriate discipline(s). These reviews shall also determine whether an evaluation per 10 CFR 50.59 or DCPP UNITS 1 & 2 FSAR UPDATE 17.3-3 Revision 19 May 2010 10 CFR 72.48 is necessary. If necessary, one shall be prepared and presented to the PSRC for review prior to approval. Each DCPP and ISFSI change or modification shall be approved by the Station Director or his designee, as specified in administrative procedures, prior to implementation. Procedures for implementing design changes, including field changes, shall assure that the impact of the change is carefully considered, required actions documented, and information concerning the change transmitted to all affected persons and organizations. These changes shall be subjected to design control measures commensurate with those applied to the original design. Design changes shall be reviewed and approved by the same organization or group that was responsible for the original design.
Document control measures shall be established for design documents that reflect the commitments of the DCPP FSAR Update and the ISFSI FSAR Update. These design documents shall include, but are not limited to, specifications, calculations, computer programs, system descriptions, the DCPP FSAR Update and ISFSI FSAR Update when used as a design document, and drawings including flow diagrams, piping and instrument diagrams, control logic diagrams, electrical single line diagrams, structural drawings for major facilities, site arrangements, and equipment locations.
Nonconforming activities such as procedure violations, deviations, or errors and deficiencies in approved design documents, including design methods (such as computer codes), shall be controlled as described in Sections 17.15 and 17.16.
DCPP UNITS 1 & 2 FSAR UPDATE 17.4-1 Revision 11 November 1996 17.4 PROCUREMENT DOCUMENT CONTROL The procurement documents shall include those requirements necessary to assure that the items and services to be provided will be of the desired quality.
The procurement documents shall also include provisions for the following, as appropriate:
(1) Basic Technical Requirements - These include drawings, specifications, codes, and industrial standards with applicable revision data; test and inspection requirements; and special instructions and requirements, such as for designing, fabricating, cleaning, erecting, packaging, handling, shipping, and, if applicable, extended storage in the field. (2) Quality Assurance Requirements - These include the requirements for the supplier to have an acceptable QA Program; provisions for access to the supplier's facilities and records for source inspection and audit when the need for such inspection and audit has been determined; and provisions for extending applicable QA Program and other requirements of procurement documents to subcontractors and suppliers, including PG&E's access to facilities and records. (3) Documentation Requirements - These shall include records to be prepared, maintained, submitted or made available for review and instructions on record retention and disposition. The procedures that implement procurement document control shall describe the organizational responsibilities for procurement planning; preparation, review, approval and control of procurement documents; supplier selection; bid evaluations; and review and evaluation of supplier QA Programs prior to initiation of activities affected by the program.
Procedures shall be established to review the adequacy of technical and quality assurance requirements stated in procurement documents; determine that requirements are correctly stated, inspectable, and controllable; assure adequate acceptance and rejection criteria; and provide for the preparation, review, and approval of procurement documents in accordance with QA Program requirements. The review and documented concurrence of the adequacy of quality assurance requirements stated in procurement documents shall be performed by independent personnel trained and qualified in applicable QA practices and concepts.
Changes to procurement documents shall be subject to the same control as the original document.
DCPP UNITS 1 & 2 FSAR UPDATE 17.5-1 Revision 19 May 2010 17.5 INSTRUCTIONS, PROCEDURES, AND DRAWINGS Activities affecting quality shall be prescribed by and accomplished in accordance with documented procedures, instructions, and drawings.
The vice president in charge of each PG&E organizational unit that performs activities affecting quality is responsible for the establishment and implementation of instructions, procedures, or drawings prescribing such activities. Standard guidelines for the format, content, and review and approval processes shall be established and set forth in a procedure or instruction issued by that organizational unit.
The method of performing activities affecting quality shall be prescribed in documented instructions, procedures, or drawings of a type appropriate to the circumstances. This may include shop drawings, process specifications, job descriptions, planning sheets, travelers, QA manuals, checklists, or any other written or pictorial form provided that the activity is described in sufficient detail such that competent personnel could be expected to satisfactorily perform the work functions without direct supervision.
Within the constraints, limitations, or other conditions as may be imposed by the specific DCPP Technical Specifications and other license requirements or commitments, procedures prescribing a preplanned method of conducting the following aspects of DCPP operations shall be established in accordance with the applicable regulations, codes, standards, and specifications: preoperational tests, systems operations, general DCPP activities, startup, shutdown, power operations and load changing, process monitoring, fuel handling, maintenance, modifications, radiation control, calibrations and tests, chemical-radiochemical control, abnormal or alarm conditions, emergency plan, tests and inspections, emergencies, and significant events. Within the constraints, limitations, or other conditions as may be imposed by the independent spent fuel storage installation (ISFSI) Technical Specifications and other license requirements or commitments, procedures prescribing a preplanned method of conducting the activities and programs specified shall be established in accordance with the applicable regulations, codes, standards, and specifications. In addition to the above, DCPP and ISFSI procedures and programs shall be established and controlled as described below.
(1) Written procedures shall be established, implemented, and maintained covering the activities referenced in the ISFSI Technical Specifications. (2) Written procedures shall be established, implemented, and maintained covering the activities referenced in Specification 5.4.1 of the Diablo Canyon Power Plant's Technical Specifications. (3) Each procedure of paragraphs (1) and (2) above, and changes thereto, and all proposed tests or experiments that affect nuclear safety shall be DCPP UNITS 1 & 2 FSAR UPDATE 17.5-2 Revision 19 May 2010 reviewed and approved prior to implementation in accordance with the review and approval requirements below. Each procedure of paragraphs (1) and (2) above, as modified by Table 17.1-1, shall also be reviewed periodically as set forth in administrative procedures. These procedure review and approval requirements apply when approving DCPP and ISFSI programs and procedures, or changes to DCPP and ISFSI programs and procedures. They also apply when approving or changing corporate procedures and procedures used by support organizations if they could have an immediate effect on DCPP and ISFSI operations or the operational status of safety-related structures, systems, or components (SSCs) or ISFSI SSCs that are important to safety. They do not apply to editorial or typographical changes. (4) Each procedure or program required by paragraphs (1) and (2) above, and other procedures, tests, and experiments that affect nuclear safety or the treatment of radwaste, and changes thereto, shall be prepared by a qualified individual/group. Each procedure, program, test, or experiment, and changes thereto, shall be reviewed by an individual/group other than the individual/group who prepared the proposed document or change, but who may be from the same organization as the individual/group who prepared it, and shall be approved, prior to implementation, by the Station Director or his designee, as identified in administrative procedures. (5) A responsible organization shall be assigned for each program or procedure required by paragraphs (1) and (2) above. The responsible organization shall assign reviews of proposed procedures, programs, and changes to qualified personnel of the appropriate discipline(s). (6) Individuals responsible for the above reviews shall be knowledgeable in the document's subject area, shall meet or exceed the qualification requirements of Section 4.7.2 of ANSI/ANS 3.1-1978, and shall be designated as qualified reviewers by the Station Director or his designee for DCPP and ISFSI procedures. (7) The reviews specified in paragraph (3) above shall include a determination as to whether additional cross-discipline reviews are necessary. If deemed necessary, they shall be performed by review personnel of the appropriate discipline(s). (8) The reviews specified in paragraph (3) above shall also determine whether an evaluation per 10 CFR 50.59 or 10 CFR 72.48 is necessary. If necessary, one shall be prepared and presented to the PSRC for review prior to approval.
DCPP UNITS 1 & 2 FSAR UPDATE 17.5-3 Revision 19 May 2010 (9) Temporary changes to procedures of paragraph (1) above may be made provided: (a) The intent of the original procedure is not altered (b) Administrative controls for approval and timely notification or training of personnel affected by the temporary change shall be implemented. (c) The change is documented, reviewed as described above, and approved by the appropriate approval authority within 14 days of implementation. (10) Temporary changes to procedures of paragraph (2) above may be made provided: (a) The intent of the original procedure is not altered (b) The change is approved by at least two exempt staff members who meet applicable qualification requirements of ANSI/ANS 3.1, 1978, and are knowledgeable in the subject area of the procedure. For changes to procedures listed below, at least one approver shall hold a Senior Reactor Operators license. (Refer to the second exception for Regulatory Guide 1.33 in Table 17.1-1.) 1. All Operations Section procedures
- 2. Surveillance Test Procedures
- 3. Emergency Plan Implementing Procedures 4. Any other procedure if the proposed change affects equipment or system operating status If the approving Senior Reactor Operator is not the Shift Foreman of the affected unit, that individual shall determine whether the Shift Foreman should be notified of the change immediately, and shall notify him/her if appropriate. (c) The change is documented, reviewed as described above, and approved by the appropriate approval authority within 14 days of implementation.
DCPP UNITS 1 & 2 FSAR UPDATE 17.6-1 Revision 19 May 2010 17.6 DOCUMENT CONTROL Documents and changes to documents that prescribe or verify activities affecting quality shall be controlled in a manner that precludes the use of inappropriate or outdated documents. As a minimum, controlled documents include: design documents, including documents related to computer codes; procurement documents; instructions and procedures for such activities as fabrication, construction, modification, installation, test, operation, maintenance, and inspection; as-built documents; quality assurance and quality control manuals and quality-affecting procedures; DCPP FSAR Update; Diablo Canyon Independent Spent Fuel Storage Installation FSAR Update; and nonconformance reports.
The organization responsible for establishing instructions, procedures, drawings, or other documents prescribing activities affecting quality is also responsible to develop and implement systematic methods for the control of such documents in accordance with the requirements herein. In those instances where such documents directly involve organizational interfaces, that organization with ultimate responsibility for the issuance of the documents is responsible for establishing the methods for their control.
Procedures and instructions shall assure that documents, including changes, are prepared; reviewed by a qualified individual other than the person who generated the document; approved for release by authorized personnel; distributed to the location where the activity is performed prior to commencing work; and used in performing the activity. Procedures and instructions shall require the development of as-built drawings and the removal or appropriate identification of obsolete or superseded documents. Procedures and instructions that define methods for implementing the QA Program requirements shall be reviewed and concurred with by quality verification (QV), for compliance and alignment with the Program. Revisions to these documents shall also be reviewed and concurred with by QV if they propose a change to the QA Program as it is described in a commitment to a regulatory agency.
The controls shall identify those responsible for preparing, reviewing, approving, and issuing documents to be used. They shall also define the coordination and control of interfacing documents and shall require the establishment of current and updated distribution lists.
A document control system shall be established to identify the current revision of instructions, procedures, specifications, drawings, and procurement documents. Master lists, when utilized as an element of the document control system, shall be updated and distributed to predetermined responsible personnel.
DCPP UNITS 1 & 2 FSAR UPDATE 17.7-1 Revision 18 October 2008 17.7 CONTROL OF PURCHASED MATERIAL, EQUIPMENT, AND SERVICES Supplier activities in providing purchased material, equipment, and services shall be monitored as planned and necessary to assure such items and services meet procurement document requirements.
Procedures shall describe each organization's responsibilities for the control of purchased material, equipment, and services, including the interfaces between all affected organizations.
All materials, equipment, and services shall meet the specified technical and quality requirements. Verification that a supplier can meet the specified technical and quality requirements shall be by one or a combination of the following:
(1) Evaluation of the supplier's history (2) Evaluation of current supplier quality records (3) Evaluation of the supplier's facilities, personnel, and implementation of a QA Program Such evaluations shall be documented. Suppliers whose QA Programs have been found by quality verification (QV), to satisfy specified quality requirements shall be listed on the PG&E Qualified Suppliers List, which is controlled by QV.
Suppliers of commercial grade calibration services may be qualified based on their accreditation by a nationally-recognized accrediting body, as an alternative to qualification by supplier audit, commercial grade survey, or in-process surveillance.
A documented review of the suppliers' accreditation by the purchaser may be used as the qualification method, as described in PG&E commitments to NRC Regulatory Guides 1.123 and 1.144, which are documented in Table 17.1-1. This review shall include, at a minimum, all of the following:
(1) The accreditation is to ANSI/ISO/IEC 17025 (2) The accrediting body is either the National Voluntary Laboratory Accreditation Program (NVLAP) or an accrediting body recognized by NVLAP through a Mutual Recognition Agreement (MRA). (3) The published scope of accreditation for the calibration laboratory covers the needed measurement parameters, ranges, and uncertainties.
A quality verification plan shall be established and documented that applies to each procurement and identifies the manner by which PG&E intends (with appropriate QV organization involvement) to assure the quality of the material, equipment, or service as DCPP UNITS 1 & 2 FSAR UPDATE 17.7-2 Revision 18 October 2008 defined in the procurement documents and to accept those items or services from the supplier.
The quality verification plan shall identify inspection, audit, and/or surveillance activities to be performed including the characteristics or processes to be witnessed, inspected, or verified; the method of surveillance; and the extent of documentation required. The timing and sequence of the activities shall be planned to identify any system or product deficiencies before subsequent activities may preclude their disclosure.
The plan shall also be based on consideration of:
(1) Importance to DCPP and independent spent fuel storage installation safety (2) Complexity of inspectable characteristics (3) Uniqueness of the item or service Supplier performance and compliance with procurement documents may be monitored by either source verification, receiving inspection, or a combination of the two. Source verification activities may consist of inspections, audits, surveillance, or a combination thereof and are conducted at the supplier's facility. When source verification activities are specified in the quality verification plan, the timing and sequence of these activities are to be delineated.
Receiving inspection activities, as required by the quality verification plan, shall be coordinated with source verification activities performed prior to shipments. If sampling is performed, it shall be in accordance with procedures and/or recognized standards. Receipt inspection shall include a review which verifies that supplier quality records required by procurement documents are acceptable and that items are properly identified and traceable to appropriate documentation.
Records of quality verification activities shall be traceable to the materials, equipment, or services to which they apply. Documentation of acceptance in accordance with the procurement quality verification plan shall be available at the site prior to installation or acceptance for use. Documentary evidence that procurement document requirements have been met shall clearly reflect each requirement. Supplier's Certificates of Conformance are periodically evaluated by audits and independent inspections or tests to assure they are valid and the results documented.
When spare or replacement parts are procured, supplier selection and quality verification activities shall be planned and implemented to verify compliance with requirements meeting or exceeding those of the original.
DCPP UNITS 1 & 2 FSAR UPDATE 17.8-1 Revision 11 November 1996 17.8 IDENTIFICATION AND CONTROL OF MATERIALS, PARTS, AND COMPONENTS Materials, parts, and components shall be identified and controlled in a manner to preclude the use of incorrect or defective items.
All materials, parts, and components, including partially fabricated subassemblies, batches, lots, and consumables, shall be identified in a manner that each can be related to its applicable drawing, specification, or other technical documentation at any stage from initial receipt through fabrication, installation, repair, or modification. Controls and implementing procedures shall ensure that only correct and accepted items are used during all stages and describe the responsibilities of the involved organizations.
Physical identification of items shall be used whenever possible and practical. Controls may, however, be through physical separation, procedure, or other appropriate means. Identification may be either on the item or on records traceable to the item.
Identification marking, where employed, shall be clear, unambiguous, and indelible and its application shall not impair the function of the identified item or any other item. When an item is subdivided, the identifying marking shall be transferred to each resulting part. Markings shall not be rendered illegible by treatment, process, assembly, installation, or coating unless other means of identification and determining acceptability are provided.
Verification activities, such as inspection, shall be performed to ensure that the provisions of this policy and related implementing procedures are followed for items prior to release for fabrication, assembly, shipping, installation, and use. When required by code, standard, or specification, traceability of materials, parts, or components to specific inspection or test records shall be provided for and verified.
DCPP UNITS 1 & 2 FSAR UPDATE 17.9-1 Revision 13 April 2000 17.9 SPECIAL PROCESSES Special processes shall be controlled and performed by qualified personnel using qualified procedures or instructions in accordance with applicable codes, standards, specifications, criteria, or other special requirements.
A special process is an activity in which the quality of the result is highly dependent upon either process variables or the skill and performance of the person doing the work, and the specified quality is difficult to verify by inspection and test after the process is completed.
Special processes include, but are not limited to:
(1) Welding (2) Heat treating (3) Nondestructive examination (4) Chemical cleaning (5) Others as specified in design and procurement documents (examples are certain protective coating applications and concrete batch plant operations, which are controlled by specifications on a case-by-case basis) The implementing instructions shall contain the criteria for assuring proper process control and shall be qualified and controlled to assure compliance with applicable codes, standards, QA procedures, and design specifications. Substantiating records of qualifications and controls shall be maintained.
DCPP UNITS 1 & 2 FSAR UPDATE 17.10-1 Revision 17 November 2006 17.10 INSPECTION A comprehensive program of inspection of items and activities affecting quality shall be conducted to verify conformance with established requirements. Procedures shall describe the organizational responsibilities necessary to carry out the inspection program.
The objective of the inspection program shall be to verify the quality of the items and activities and conformance to the applicable documented instructions, procedures, and drawings for accomplishing activities affecting quality. The inspection program, including information relative to individual inspections to be performed, shall be developed based on a review of the design drawings, specifications, and other controlled documents which prescribe items and activities affecting quality. Inspections shall be performed utilizing appropriate inspection procedures and instructions together with the necessary drawings, specifications, and other controlled documents. The inspections shall be documented and evaluated.
Inspection procedures, instructions, or checklists shall provide for the following: identification of characteristics and activities to be inspected; a description of the method of inspection; identification of the individuals or groups responsible for performing the inspection operation; acceptance and rejection criteria; identification of required procedures, drawings, and specifications and revisions; recording the name of the inspector or data recorder and the results of the inspection operation; and specifying necessary measuring and test equipment including accuracy requirements. The inspection program shall include, but not be limited to, those inspections required by applicable codes, standards, specifications, and DCPP and Independent Spent Fuel Storage Installation (ISFSI) Technical Specifications. The inspection program shall also require the following during the operational phase of DCPP:
(1) Inspection of modifications, repairs, and replacements, where required to assure a suitable level of confidence that an item will perform its intended function, shall verify conformance to the original design requirements or appropriately approved equivalents (2) Verification of the cleanness of those portions of plant safety-related systems that have been subject to potential contamination during maintenance and modification activities through an inspection performed immediately prior to closure of the portion of the system The inspection program shall require inspection of ISFSI modifications, repairs, and replacements to be in accordance with existing design requirements.
The inspection program shall require inspection and/or test of items for each work operation where such is necessary to assure quality. If inspection of processed items is impossible or disadvantageous, indirect control by monitoring of process shall be required. Both inspection and process monitoring shall be required when control is DCPP UNITS 1 & 2 FSAR UPDATE 17.10-2 Revision 17 November 2006 inadequate without both. Both inspection and process control shall be performed when required by applicable code, standard, or specification.
Mandatory quality control inspection hold points shall be identified in the inspection program. When required, the specific hold points shall be indicated in the drawings, procedures, or instructions that prescribe the work activity. Work shall not proceed beyond such hold points without the documented consent of Quality Verification.
When the inspection program permits or requires a sample of a large group of items that are amenable to statistical analysis, the sampling procedures to be used shall be based on recognized standard practices.
Inspections to verify the quality of work shall be performed by qualified individuals other than those who performed or directly supervised the activity being inspected. During the inspection, such persons shall not report directly to the immediate supervisors who are responsible for the work being inspected.
Personnel performing inspections shall be qualified in accordance with applicable regulations, codes, standards, and specifications.
Inspection records shall contain the following where applicable: a description of the type of observation, the date and results of the inspection, information related to conditions adverse to quality, inspector or data recorder identification, evidence as to the acceptability of the results, and action taken to resolve any discrepancies noted.
DCPP UNITS 1 & 2 FSAR UPDATE 17.11-1 Revision 11 November 1996 17.11 TEST CONTROL A program of testing shall be conducted as necessary to demonstrate that structures, systems, and components will perform satisfactorily in service. This program shall ensure that the necessary testing is identified and performed at the appropriate time in accordance with written test procedures that incorporate or reference the requirements and acceptance limits contained in the applicable design documents.
The program shall cover all required tests, including tests prior to installation, preoperational tests, and operational tests.
The procedures that implement testing shall provide for meeting appropriate prerequisites for the test (for example, environmental conditions, specification of instrumentation, and completeness of tested item), sufficient instruction for the performance of the test, specification of any witness or hold points, acceptance and rejection criteria and limits, and the documentation of the test. The procedures shall provide for evaluation and documentation of the test results and data and their acceptability as determined by a qualified person or group.
Test records shall contain the following where applicable: a description of the type of observation, the date and results of the test, information related to conditions adverse to quality, inspector or data recorder identification, evidence as to the acceptability of the results, and action taken to resolve any discrepancies noted.
DCPP UNITS 1 & 2 FSAR UPDATE 17.12-1 Revision 15 September 2003 17.12 CONTROL OF MEASURING AND TEST EQUIPMENT Organizational responsibilities shall be delineated for establishing, implementing, and assuring the effectiveness of the calibration program for measuring and test equipment (M&TE). This program shall include the generation, review, and documented concurrence of calibration procedures; the calibration of measuring and test equipment; and the maintenance and use of calibration standards. M&TE, including reference standards, used to determine the acceptability of items or activities shall be strictly maintained within prescribed accuracy limits. M&TE, including reference standards, shall be of suitable range, type, and accuracy to verify conformance with requirements. Procedures for control of M&TE shall provide for the identification (labeling, codes, or alternate documented control system), recall, and calibration (including documented precalibration checks) of the M&TE. The calibration procedures shall delineate any necessary environmental controls, limits, or compensations in excess of those which may be inherent to the general program. The calibrations shall utilize documented valid relationships to nationally recognized standards or accepted values of natural physical constants. Where national standards do not exist, the basis for the calibration shall be documented. Calibration of M&TE shall be against standards that have an accuracy of at least four times the required accuracy of the equipment being calibrated or, when this is not practical, have an accuracy that assures the equipment being calibrated will be within required tolerance and that the basis of acceptance is documented and authorized by responsible management of the PG&E organization performing that activity. Calibrating standards have greater accuracy than standards being calibrated. Calibrating standards with the same accuracy may be used if it can be shown to be adequate for the requirements and the basis of acceptance is documented and authorized by responsible management. The calibration intervals, whether calendar- or usage-based, shall be predetermined and documented. Indication of expiration, if feasible, will be displayed on or with the M&TE. Significant environmental or usage restrictions will be indicated on or with the equipment or be factored into the documented system used to control the issuance of the M&TE. Special calibration shall be required whenever the accuracy of the equipment is suspect. Records shall be maintained to show that established schedules and procedures for the calibration of the M&TE have been followed. M&TE shall be identified and traceable to the calibration test data. Records of the usage of the M&TE shall be maintained to facilitate corrective action in the event of the discovery of a deficiency concerning the calibration or use of M&TE, so that measures may be taken and documented to determine the validity of previous inspections performed and of the acceptability of items inspected or tested since the previous calibration of the deficient M&TE. DCPP UNITS 1 & 2 FSAR UPDATE 17.13-1 Revision 11 November 1996 17.13 HANDLING, STORAGE, AND SHIPPING Material and equipment shall be handled, stored, and shipped in accordance with design and procurement requirements in a manner that will prevent damage, deterioration, or loss.
Special coverings, equipment, and protective environments shall be specified and provided where necessary for the protection of particular items from damage or deterioration. When such special protective features are required, their existence shall be verified and monitored as necessary to assure they continue to serve their intended function.
Special handling tools and equipment shall be provided where necessary to ensure items can be handled safely and without damage. Special handling tools and equipment shall be controlled and maintained in a manner such that they will be ready and fit to serve their intended function when needed. Such control shall include periodic inspection and testing to verify that special handling tools and equipment have been properly maintained.
Special attention shall be given to marking and labeling items during packaging, shipment, and storage. Such additional marking or labeling shall be provided as is necessary to ensure that items can be properly maintained and preserved. This shall include indication of the presence of special environments or the need for special control. Provisions shall be described for the storage of chemicals, reagents (including control of shelf life), lubricants, and other consumable materials. Special handling, preservation, storage, cleaning, packaging, and shipping requirements are established and accomplished by suitably trained individuals in accordance with predetermined work and inspection instructions. DCPP UNITS 1 & 2 FSAR UPDATE 17.14-1 Revision 11 November 1996 17.14 INSPECTION, TEST, AND OPERATING STATUS The inspection, test, and/or operating status of material, equipment, and operating systems shall be readily apparent and verifiable.
The procedures used to indicate status shall provide means for assuring that required inspections and tests are performed in the prescribed sequence; acceptability is indicated; and nonconforming items are clearly identified throughout fabrication, installation, test, maintenance, repairs, and modification to prevent inadvertent use or operation. Items accepted and released are identified to indicate their inspection status prior to forwarding them to a controlled storage area or releasing them for installation or further work. Deviations from the prescribed sequence shall be subject to the same level of control as the generation of the original sequence to prevent the bypassing or omission of a required test or inspection.
Identification of status may be by such means as, but not limited to, tags, stamps, markings, labels, or travelers. In some instances, records traceable to the item may be used. The procedures implementing control of inspection, test, and operating status shall clearly delineate authority for the application, change, or removal of a status identifier. DCPP UNITS 1 & 2 FSAR UPDATE 17.15-1 Revision 17 November 2006 17.15 CONTROL OF NONCONFORMING CONDITIONS Items and activities that do not conform to requirements shall be controlled in a manner that will prevent their inadvertent use or installation. Technical decisions as to the disposition of each nonconforming condition shall be made by personnel with assigned authority in the relevant disciplines. The control, review, and disposition of nonconforming conditions shall be accomplished and documented in accordance with approved written procedures and instructions.
Nonconforming conditions shall be documented and affected organizations notified of such conditions. Further processing of the nonconforming conditions and other items affected by them shall be controlled in a manner to prevent their inadvertent use or installation pending a decision on their disposition.
The responsibility and authority for the disposition of nonconforming conditions shall be established and set forth in the applicable procedures and instructions for their control. The rework or repair of nonconforming items and the disposition of operational nonconforming conditions shall be accomplished in accordance with written procedures and instructions. Dispositions involving design changes shall be approved by the organization with the authority for design.
The acceptability of rework or repair of materials, parts, components, systems, or structures shall be verified by reinspecting and retesting the item as originally inspected and tested, or by a method that is at least equal to the original inspection or testing method. Reworked and repaired items shall be reinspected in accordance with applicable procedures and instructions. The acceptability of nonconforming items that have been dispositioned "repair" or "accept-as-is" shall be documented. Such documentation shall include a description of the change, waiver, or deviation that has been accepted in order to record the change and, if applicable, denote the as-built condition.
Corrective action for conditions adverse to quality shall be processed in accordance with Section 17.16.
In cases where required documentary evidence that items have passed required inspections and tests is not available, the associated materials or equipment shall be considered nonconforming. Until suitable documentary evidence is available to show that the material or equipment is in conformance, affected systems shall be considered to be inoperable and reliance shall not be placed on such systems to fulfill their intended safety functions.
Nonconforming conditions that require reporting to the NRC shall be reviewed by the Quality Verification organization. Such review shall include the results of any investigations made and the recommendations resulting from such investigations to preclude or reduce the probability of recurrence of the event or circumstance.
DCPP UNITS 1 & 2 FSAR UPDATE 17.16-1 Revision 17 November 2006 17.16 CORRECTIVE ACTION Each individual condition adverse to quality shall be identified, controlled, and evaluated, and a disposition shall be determined for the remedial action and corrective action as soon as practicable. These activities shall be performed consistent with Section 17.15, Control of Nonconforming Conditions.
Systematic review and evaluation of all conditions adverse to quality shall be conducted and documented. Conditions adverse to quality shall include, but not be limited to: engineering, design, and drafting errors; equipment failures and malfunctions; abnormal occurrences; deficiencies; deviations; and defective material, equipment, and services.
The review and evaluation shall include identification of quality trends, repetitive occurrences, and significant conditions adverse to quality. The quality trends and other significant review findings shall be analyzed and appropriate corrective action determined. Findings and actual or recommended corrective action shall be reported to management by the responsible organization for review and assessment.
Significant conditions adverse to quality shall be investigated to the extent necessary to assess the root causes and to determine the corrective action required to prevent recurrence of the same or similar conditions. The corrective action required for significant conditions adverse to quality shall be accomplished in a timely manner. Significant conditions adverse to quality, the cause of the condition, and the corrective action taken shall be documented and reported to management.
Significant conditions adverse to quality that are related to DCPP or Independent Spent Fuel Storage Installation (ISFSI) operations or maintenance shall be reported to the Quality Verification organization. Completion of corrective actions for significant conditions adverse to quality shall be reviewed and verified by personnel having no direct responsibility for either the disposition or the corrective action taken.
Follow-up reviews shall be conducted to verify that the corrective action was properly implemented, performed in a timely manner, and that it was effective in correcting the identified condition.
Significant conditions adverse to quality shall be evaluated for reportability to the NRC in accordance with 10 CFR 21, 10 CFR 50.72, 10 CFR 50.73, 10 CFR 50.9, 10 CFR 72.74, and 10 CFR 72.75, the DCPP and ISFSI Technical Specifications, and other applicable regulations and shall be reported as required.
DCPP UNITS 1 & 2 FSAR UPDATE 17.17-1 Revision 21 September 2013 17.17 QUALITY ASSURANCE RECORDS Sufficient records shall be maintained to furnish evidence of both the quality of items and activities affecting quality and to meet applicable code, standard, and regulatory requirements. The records include all documents referred to or described in the QA Program or required by implementing procedures such as operating logs, maintenance and modification procedures, related inspection results, and reportable occurrences; and other records required by the DCPP and independent spent fuel storage installation (ISFSI) Technical Specifications and Code of Federal Regulations. In addition to the records of the results of reviews, designs, fabrication, installation, inspections, calibrations, tests, maintenance, surveillances, audits, personnel qualification, special process qualification, and material analyses for PG&E quality-related activities and ISFSI structures, systems, and components that are important to safety, those of vendors, suppliers, subcontractors, and contractors shall also be maintained.
A management control system for the collection, storage, and maintenance of completed quality assurance (QA) records shall be maintained. This records management program shall be designed and implemented to assure that the QA records are complete, readily retrievable when needed, and protected from damage or destruction during storage by fire, flooding, theft, environmental conditions, or other causes.
QA records stored electronically will follow the guidance for electronic records management given in the Nuclear Information and Records Management Association (NIRMA) technical guidelines, TG 11-1998, "Authentication of Records;" TG 15-1998, "Management of Electronic Records;" TG 16-1998, "Software Configuration Management and Quality Assurance;" and TG 21-1998, "Electronic Records Protection and Restoration." QA records will be stored on electronic media (that is, optical disk, magnetic tape, network array, etc.) meeting the requirements of the NIRMA guidelines. Alternately, records stored on optical disks may meet the requirements of Generic Letter 88-18, "Plant Record Storage on Optical Disk," dated October 20, 1988. Information Systems will determine the appropriate electronic media. Regardless of the electronic media selected, the process must be capable of producing legible, accurate, and complete records during the required retention period.
Backup copies of in-process electronic media records will be maintained in multiple, physically-independent electronic locations. Backup copies of QA records in electronic media will be maintained in multiple, physically-independent electronic locations until such time as images of these records are created, copied, and verified on two copies of an appropriate electronic storage media. The two copies will then be stored in separate physical locations. File legibility verification will be completed on all QA records stored on electronic media by either visually verifying the file legibility or by electronically verifying exact binary file transfer.
Periodic media inspections to monitor image degradation will be conducted in accordance with the NIRMA guidelines or media manufacturers' recommendations. These periodic inspections shall be documented. DCPP UNITS 1 & 2 FSAR UPDATE 17.17-2 Revision 21 September 2013 QA records stored on electronic media will be refreshed or copied on to new media and subsequently verified if the projected lifetime of that media does not exceed the retention period of the records stored on that media. These requirements meet the intent of Generic Letter 88-18.
Detailed records for items or activities shall be specified by instructions, procedures, drawings, or specification or other documents that prescribe the item or activity and shall be generated by the organization responsible for the item or activity including PG&E and non-PG&E organizations. Each department generating QA records is responsible for transmitting those records to the records processing organization for archival purposes.
All records shall be assigned a retention period in conformance with Title 10, Code of Federal Regulations, other applicable codes, standards, and specifications. 17.17.1 DCPP LIFETIME RECORDS The following records are retained for the duration of the unit Operating License: (1) Records and drawing changes reflecting unit design modifications made to systems and equipment described in the FSAR Update (2) Records of new and irradiated fuel inventory, fuel transfers, and assembly burnup histories (3) Records of radiation exposure for all individuals entering radiation control areas (4) Records of gaseous and liquid radioactive material released to the environs (5) Records of transient or operational cycles for those unit components identified in FSAR Update, Table 5.2-4. (6) Records of reactor tests and experiments (7) Records of training and qualification for current members of the unit staff (8) Records of in-service inspection performed pursuant to 10 CFR 50.55a (9) Records of QA activities required by the FSAR Update, Chapter 17 (10) Records of reviews performed for changes made to procedures or equipment or reviews of tests and experiments pursuant to 10 CFR 50.59 (11) Records of PSRC meetings DCPP UNITS 1 & 2 FSAR UPDATE 17.17-3 Revision 21 September 2013 (12) Records of the Independent Review Program (13) Records of analyses required by the Radiological Environmental Monitoring Program (Reg. Guide 4.15). (14) Records of service lives of all hydraulic and mechanical snubbers required by the FSAR Update including the date at which the service life commences and associated installation and maintenance records (15) Records of secondary water sampling and water quality (16) Records of reviews performed for changes made to the Offsite Dose Calculation Manual (17) Records of reviews performed for changes made to the Process Control Program 17.17.2 DCPP NONPERMANENT RECORDS The following records are retained for at least five years: (1) Records and logs of unit operation covering time interval at each power level (2) Records and logs of principal maintenance activities, inspections, repair, and replacement of principal items of equipment related to nuclear safety (3) All reportable events (4) Records of surveillance activities, inspections, and calibrations required by the Technical Specifications (5) Records of changes made to procedures required by Technical Specification 5.4.1 (6) Records of radioactive shipments (7) Records of sealed source and fission detector leak tests and results (8) Records of annual physical inventory of all sealed source material of record
DCPP UNITS 1 & 2 FSAR UPDATE 17.17-4 Revision 21 September 2013 17.17.3 DIABLO CANYON ISFSI RECORDS Important-to-safety records shall be classified as lifetime or nonpermanent. The following records shall be maintained as required for the Diablo Canyon ISFSI: (1) Radiation protection program and survey records (2) Records associated with reporting defects and noncompliance) (3) Records important to decommissioning (4) Records of changes to the physical security plan made without prior NRC approval (5) Records of changes, tests and experiments, and of changes to procedures described in the ISFSI FSAR Update pursuant to 10 CFR 72.48 (6) Records showing receipt, inventory, location, disposal, acquisition, and transfer of spent fuel (7) A copy of the current inventory of spent fuel in storage at the ISFSI (8) A copy of the current material control and accounting procedures (9) Other records required by license conditions or by NRC rules, regulations or orders (10) Records of the occurrence and severity of important natural phenomena that affect ISFSI design (11) QA records (including records pertaining to the design, fabrication, erection, testing, maintenance, and use of structures, systems, and components important to safety; and results of reviews, inspections, tests, audits, monitoring of work performance, and material analyses) (12) A copy of the current physical security plan, plus any superseded portions of the plan (13) A copy of the current safeguards contingency plan procedures, plus any superseded portions of the procedures (14) Operating records, including maintenance, alterations or additions made (15) Records of off-normal occurrences and events
DCPP UNITS 1 & 2 FSAR UPDATE 17.17-5 Revision 21 September 2013 (16) Environmental survey records (17) Records of employee qualifications and certifications (18) Record copies of:
- ISFSI FSAR Updates
- Reports of accidental criticality or loss of special nuclear material
- Material status reports
- Nuclear material transfer reports
- Reports of pre-operational test acceptance criteria and results
- Procedures
- Environmental Report
- Emergency Plan (19) Construction Records; and (20) Records of events associated with radioactive releases.
Facilities for the temporary or permanent storage of completed QA records shall be established in predetermined locations as necessary to meet the requirements of codes, standards, and regulatory agencies. Such facilities shall be constructed and maintained so as to protect the contents from possible damage or destruction.
DCPP UNITS 1 & 2 FSAR UPDATE 17.18-1 Revision 21 September 2013 17.18 AUDITS The adequacy and effectiveness of the Quality Assurance (QA) Program shall be continually monitored through a comprehensive system of internal and supplier audits. The audit system implemented by the Quality Verification (QV) organization includes all aspects of the QA Program. The audit system shall:
(1) Verify, through examination and evaluation of objective evidence, that this QA Program has been implemented as required (2) Identify any deficiencies or nonconformances in this QA Program (3) Verify the correction of any identified deficiencies or nonconformances (4) Assess the adequacy and effectiveness of this QA Program A comprehensive plan for the audit system shall be established and documented. Audit frequencies are determined by a performance-based evaluation plan. This plan uses assessment indicators to identify and schedule audits based on performance results and importance of the activity relative to safety. The plan shall identify the scope of individual audits that are to be performed, the aspects of this QA Program covered by each audit, and the schedule for performing audits. The audit system plan shall be reviewed at least semiannually, and revised as necessary, to assure that coverage and schedule reflect current activities and that audits of DCPP operational phase activities and independent spent fuel storage installation (ISFSI) activities are being accomplished in accordance with applicable requirements. Other associated activities included as part of the audit program are: indoctrination and training programs; the qualification and verification of implementation of QA programs of contractors and suppliers; interface control among the applicant and the principal contractors; audits by contractors and suppliers; corrective action, calibration, and nonconformance control systems; DCPP FSAR Update and ISFSI FSAR Update commitments; and activities associated with computer codes.
Auditors shall be independent of direct responsibility for the performance of the activities that they audit, have experience or training commensurate with the scope and complexity of their audit responsibility, and be qualified in accordance with applicable standards.
Auditing shall be initiated as early in the life of an activity as is practicable and consistent with the schedule for accomplishing the activity. In any case, auditing shall be initiated early enough to assure that this QA Program is effectively implemented throughout each activity. Individual audits shall be regularly scheduled on the basis of the status and importance of the activities, which they address.
For audits, other than those who's scheduled frequency is mandated by regulation (such as the Safeguards Contingency Plans or the Security Program), a grace period of up to 90 days may be utilized when the urgency of other priorities makes meeting the specified DCPP UNITS 1 & 2 FSAR UPDATE 17.18-2 Revision 21 September 2013 schedule dates impractical. For audit activities deferred by using a grace period, the next scheduled due date shall be based on the original schedule due date but may not exceed the original due date plus 90 days.
Audit reports shall be prepared, signed by the Audit Team Leader, and issued to responsible management of both the audited and auditing organizations.
Audits are regularly scheduled on a formal audit schedule prepared by QV. The audit schedule is reviewed regularly by the Director - QV, and the schedule is revised as necessary to assure adequate coverage as commensurate with activities and past performance. Audits are performed in accordance with approved audit plans. Such audits may be augmented by other QV assessments and independent inspections. Additional audits may be performed as requested by NSOC, the Senior Vice President - Chief Nuclear Officer, the Site Vice President, or the Director - QV. The following areas shall be audited at least once per 24 months, or more frequently as performance dictates:
(1) The conformance of DCPP and ISFSI operation to provisions contained within the applicable Technical Specifications and applicable licenses (2) The performance, training, and qualifications of the entire DCPP and ISFSI staff (3) The results of actions taken to correct deficiencies occurring in DCPP and ISFSI equipment, structures, systems, or method of operation that affect nuclear safety (4) The performance of activities required by the QA Program to meet the criteria of Appendix B, 10 CFR 50 (5) The Radiological Environmental Monitoring Program, implementing procedures, and program results (6) The Offsite Dose Calculation Procedure and its implementing procedures (7) The Process Control Program and implementing procedures for processing and packaging radioactive wastes (8) The Nonradiological Environmental Monitoring Program (9) A representative sample of routine DCPP and ISFSI procedures that are used more frequently than every two years. This audit is to ensure the acceptability of the procedures and to verify that the procedures review and revision program is being implemented effectively.
DCPP UNITS 1 & 2 FSAR UPDATE 17.18-3 Revision 21 September 2013 (10) The performance of activities required to be audited by ANS-3.2/ANSI N18.7-1976, Section 4.5. (11) Review of design documents and process to ensure compliance with the FSAR Update, Section 17.3 (i.e., use of supervisors as design verifiers). In addition, QV shall sample and review specifications and design drawings to assure that the documents are prepared, reviewed, and approved in accordance with PG&E procedures and that the documents contain the necessary QA requirements, acceptance requirements, and quality documentation requirements. (12) QV shall audit the departments that qualify personnel and procedures to assure that the process qualification activity, records, and personnel meet the applicable requirements. They shall also audit the organizations implementing special processes to provide assurance that the processes are carried out in accordance with approved procedures by qualified personnel using qualified equipment and that required records are properly maintained. (13) The performance of activities required by the QA Program for the Radioactive Effluent Controls Program. (14) The Radiation Protection Program, in accordance with 10 CFR 20. (15) The Fitness for Duty Program in accordance with 10 CFR 26.41. (16) Each element of the Physical Security Protection Program in accordance with 10 CFR 73.55(m)(1). However, changes to personnel, procedures, equipment, or facilities that potentially could adversely affect security shall be audited within 12 months of the change. (17) Each element of the of the Safeguards Contingency Plan in accordance with 10 CFR 73 Appendix C and 10 CFR 50.54(p)(3). However, changes to personnel, procedures, equipment, or facilities that potentially could adversely affect security shall be audited within 12 months of the change. (18) Review of the Security Training and Qualification Program in accordance with 10 CFR 73 Appendix B Section I. (19) The Access Authorization Program in accordance with 10 CFR 73.56(n)(1) (20) The Emergency Preparedness Program in accordance with 10 CFR 50.54(t). However, changes to personnel, procedures, equipment, or facilities that potentially could adversely affect emergency preparedness shall be audited within 12 months of the change. DCPP UNITS 1 & 2 FSAR UPDATE 17.18-4 Revision 21 September 2013 (21) The Fire Protection and Loss Prevention Program. Each audit shall include the annual, biennial, and triennial topical areas described in NRC Generic Letter 82-21, and shall utilize qualified independent licensee personnel or an outside fire protection consultant. An outside fire protection consultant shall be utilized at least every third year. Performance based scheduling for this audit (at least once per 24 months, or more frequently as performance dictates) is applied under the provision of NRC Administrative Letter 95-06. The following activities shall be audited at least once per 12 months unless specified otherwise. However, if the audit frequencies required by the governing regulations are changed, audit frequencies shall at least meet the revised minimum requirements.
(1) If a contractor's or vendor's Access Authorization Program is accepted, that contractor's or vendor's Access Authorization Program shall be audited in accordance with 10 CFR 73.56(n)(2) - at least once every 12 months. (2) FFD services that are provided by contractor/vendor personnel who are offsite or are not under the direct daily supervision or observation of DCPP personnel and HHS-certified laboratories must be audited on a nominal 12-month frequency in accordance with 10 CFR 26.41.
Management of the audited organization shall review the audit report and respond to any quality problem reports, investigate any significant findings to identify their cause and determine the extent of corrective action required, including action to prevent recurrence. They shall schedule such corrective action and also take appropriate action to assure it is accomplished as scheduled. They shall respond to QV regarding each significant finding stating the root cause, immediate action taken, and the corrective action taken or planned to prevent recurrence. Such responses may be documented directly within electronic databases used for the corrective action program.
QV shall review the written responses to all audit findings, evaluate the adequacy of each response, assure that corrective action to prevent recurrence is identified and taken for each significant finding, and confirm that corrective action is accomplished as scheduled.
Audit records shall be generated and retained by QV for all audits.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 17.1-1 Sheet 1 of 13 Revision 21 September 2013 CURRENT REGULATORY REQUIREMENTS AND PG&E COMMITMENTS PERTAINING TO THE QUALITY ASSURANCE PROGRAM The Quality Assurance Program for DCPP and Diablo Canyon Independent Spent Fuel Storage Installation (ISFSI) described in Chapter 17 of the FSAR Update, program directives, and administrative procedures complies with the requirements set forth in the Code of Federal Regulations. In addition, it complies with the regulatory documents and industry standards listed below. Changes to this list are not made without the review and concurrence of the Director - Quality Verification. Reg. Guides Date Standard No. Rev. Title/Subject Exceptions (S.G.) 28 6/72 ANSI N45.2 1971 Quality Assurance Program Requirements for Nuclear Power Plants 1.37 3/73 ANSI N45.2.1 1973 Quality Assurance Requirements for Cleaning Fluid Systems and Associated Components of Water-Cooled Nuclear Power Plants Not applicable to the ISFSI. 1.38 5/77 ANSI N45.2.2 1972 Quality Assurance Requirements for Packaging, Shipping, Receiving, Storage, and Handling of Items for Water-Cooled Nuclear Power Plants Warehouse personnel will normally visually scrutinize incoming shipments for damage of the types listed in Section 5.2.1, this activity is not necessarily performed prior to unloading. Separate documentation of the shipping damage is not necessary. Release of the transport agent after unloading and the signing for receipt of the shipment provides adequate documentation of completion of the shipping damage inspection. Any damage noted will be documented and dispositioned. Persons performing this visual scrutiny are not considered to be performing an inspection function as defined under Reg. Guide 1.74; therefore they do not require certification as an inspector under Reg. Guide 1.58. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 17.1-1 Sheet 2 of 13 Revision 21 September 2013 Reg. Guides Date Standard No. Rev. Title/Subject Exceptions 1.39 9/77 ANSI N45.2.3 1973 Housekeeping Requirements for Water-Cooled Nuclear Power Plants Housekeeping zones established at the power plants differ from those described in the standard; however, PG&E is in compliance with the intent of the standard. 1.30 8/72 ANSI N45.2.4 1972 Quality Assurance Requirements for the Installation, Inspection, and Testing of Instrumentation and Electric Equipment The evaluation of (data sheet) acceptability is indicated on the results and data sheets by the approval signature (paragraph 2.4). No visual examination for contact corrosion is made on breaker and starter contacts unless there is evidence of water damage or condensation. Contact resistance tests are made on breakers rated at 4 kV and above. No contact resistance test is made on lower voltage breakers or starters (paragraph 3[4]). No system test incorporates a noise measurement. If the system under test meets the test criteria, then noise is not a problem (paragraph 6.2.2). 1.94 4/76 ANSI N45.2.5 1974 Quality Assurance Requirements for Installation, Inspection, and Testing of Structural Concrete and Structural Steel During the Construction Phase of Nuclear Power Plants Except PG&E will not require manufacturer's certification for material suitability as inferred in ANSI N45.2.5, Sections 3.1 and 3.2 when PG&E procures: (a) material from a supplier that has a QA program that meets the relevant requirements of 10CFR50, Appendix B and the supplier is included ASME Section III (NCA-3800/NCA-4000) or on the PG&E Qualified Suppler List; or (b) material as a "Commercial-Grade" item and dedicates it in accordance with PG&E's Commercial-Grade Dedication Program. Not applicable to the ISFSI. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 17.1-1 Sheet 3 of 13 Revision 21 September 2013 Reg. Guides Date Standard No. Rev. Title/Subject Exceptions 1.29 9/78 -- -- Seismic Design Classification 1.58 9/80 ANSI N45.2.6 1978 Qualification of Nuclear Power Plant Inspection, Examination and Testing Personnel ANSI N45. 2. 6 applies to individuals conducting independent QC inspections, examinations, and tests. ANSI/ ANS 3.1-1978 applies to personnel conducting inspections and tests of items or activities for which they are responsible (e.g., plant surveillance tests, maintenance tests, etc.). Except that inspector/examiner reevaluation due dates may be extended a maximum of 90 days. The next reevaluation due date shall be based on the original scheduled due date but shall not exceed the original due date plus 90 days. NDE personnel shall be qualified and certified in accordance with CP-189-1995. ISI ultrasonic examiners shall meet the additional requirements of ASME Section XI, Appendix VIII, 2001 Edition with no Addenda. 1.116 5/77 ANSI N45.2.8 1975 Quality Assurance Requirements for Installation, Inspection, and Testing of Mechanical Equipment and Systems
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 17.1-1 Sheet 4 of 13 Revision 21 September 2013 Reg. Guides Date Standard No. Rev. Title/Subject Exceptions 1.88 10/76 ANSI N45.2.9 1974 Collection, Storage, and Maintenance of Nuclear Power Plant Quality Assurance Records Except PG&E will comply with the 2-hour rating of Section 5.6 of ANSI N45.2.9 issued July 15, 1979. Except PG&E will also meet the intent of the guidelines for the storage of QA records in electronic media as, endorsed by Generic Letter 88-18, "Plant Record Storage on Optical Disks," issued October 20, 1988, and Regulatory Issues Summary 2000-18, "Guidance on Managing Quality Assurance Records in Electronic Media," issued October 23, 2000. Note: PG&E will maintain records of spent fuel and high-level radioactive waste in storage in accordance with ANSI N 45.2.9-1974 rather than 10 CFR 72.72(d). Refer to ISFSI FSAR Update, Section 9.4.2. 1.74 2/74 ANSI N45.2.10 1973 Quality Assurance Terms and Definitions 1.64 6/76 ANSI N45.2.11 1974 Quality Assurance Requirements for the Design of Nuclear Power Plants Except PG&E will allow the designer's immediate supervisor to perform design verification in exceptional circumstances and with the controls as described in NUREG-0800, Revision 2, July 1981.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 17.1-1 Sheet 5 of 13 Revision 21 September 2013 Reg. Guides Date Standard No. Rev. Title/Subject Exceptions 1.144 1/79 ANSI N45.2.12 1977 Auditing of Quality Assurance Programs for Nuclear Power Plants Except the scheduled date for triennial vendor audits and annual supplier evaluations may be extended a maximum of 90 days. The next scheduled due date shall be based on the original scheduled due date but shall not exceed the original due date plus 90 days. Except that the corrective action program stipulated in the QA Program may be used instead of the requirements of Section 4.5.1 as long as the appropriate time limits are applied to significant conditions adverse to quality. Also, no additional documentation is necessary if needed corrective actions are taken and verified prior to audit report issuance. See Note for Reg Guide 1.144 1.123 7/77 ANSI N45.2.13 1976 Quality Assurance Requirements for Control of Procurement of Items and Services for Nuclear Power Plants In addition to ANSI N45.2.13, Section 10.3.3, PG&E will accept items and services which are complex or involve special processes, environmental qualification, or critical characteristics which are difficult to verify upon receipt by suppliers' Certificate of Conformance if and only if the supplier has been evaluated and qualified utilizing Performance Based Supplier Audit techniques. See Note for Reg Guide 1.123
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 17.1-1 Sheet 6 of 13 Revision 21 September 2013 Reg. Guides Date Standard No. Rev. Title/Subject Exceptions 1.146 8/80 ANSI N45.2.23 1978 Qualification of Quality Assurance Program Audit Personnel for Nuclear Power Plants Except that auditor recertification due dates may be extended a maximum of 90 days. The next recertification due date shall be based on the original scheduled due date but shall not exceed the original due date plus 90 days. Except that in lieu of the requirements of 2.3.4 of ANSI N45.2-1978, the prospective lead auditor shall have participated in at least one nuclear quality assurance audit within the year preceding the individual's effective date of qualification.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 17.1-1 Sheet 7 of 13 Revision 21 September 2013 Reg. Guides Date Standard No. Rev. Title/Subject Exceptions 1.33 2/78 ANSI N18.7 1976 Quality Assurance Program Requirements (Operation) Except that PG&E will not perform biennial review of all DCPP and ISFSI procedures, except under the conditions described in note below (See note at end of table). Except for temporary changes to procedures, PG&E will require a review by an individual who holds a Senior Reactor Operators license only if the procedure is one of the types listed in Section 17.5 (10) of this FSAR Update. Furthermore, this individual need not be the supervisor in charge of the shift. Except that audit frequencies specified in Regulatory Guide 1.33, Revision 2, need not be met. Audits shall be performed at the frequencies specified in Section 17.18 of this FSAR Update. Except that audits and reviews of the Emergency Preparedness Program shall be performed in accordance with 10 CFR 50.54(t). Except that a grace period of up to 90 days will be allowed for audit scheduling, except where the schedule is mandated by regulation. The next schedule due date shall be based on the original scheduled date but shall not exceed the original due date plus 90 days.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 17.1-1 Sheet 8 of 13 Revision 21 September 2013 Reg. Guides Date Standard No. Rev. Title/Subject Exceptions Except that when purchasing commercial-grade calibration services from certain accredited calibration laboratories, the procurement documents are not required to impose a quality assurance program consistent with ANSI N45.2-1971. Alternative requirements described in FSAR Update, Section 17.7 for Regulatory Guide 1.123 may be implemented in lieu of imposing a quality assurance program consistent with ANSI N45.2-1971. 1.8 2/79 ANSI/ANS 3.1 1978 Personnel Selection and Training Except that for the Quality Verification Director, the one year of qualifying nuclear power plant experience in the overall implementation of the Quality Assurance program can be obtained outside the Quality Assurance organizations. Except certain personnel are trained and qualified to the Institute of Nuclear Power Operations (INPO) criteria as described in the DCPP FSAR Update Chapter 13. Except that a retraining and replacement training program for the plant staff meet or exceed the requirements and recommendations of Section 5.5 of ANSI N18.1-1971 and 10 CFR Part 55. This exception is based on the NRC letter to PG&E, dated July 19, 1989, issuing License Amendments No. 43 and 42. Except that the Radiation Protection Manager's qualifications shall meet or exceed the qualifications of Regulatory Guide 1.8, Revision 2, April 1987, for the Radiation Protection Manager. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 17.1-1 Sheet 9 of 13 Revision 21 September 2013 Reg. Guides Date Standard No. Rev. Title/Subject Exceptions Except that the person serving as the manager responsible for the independent review and audit program shall have a minimum of 6 years of professional level managerial experience in the power field. This exception is based on NRC letter to PG&E dated February 6, 1992, issuing Licensing Amendment No. 68/67. Except that the Operations Manager shall meet the requirements of the Technical Specifications. Except that the licensed reactor operators and senior reactor operators shall meet or exceed the minimum qualifications of ANSI/ANS 3.1-1993 as endorsed by Regulatory Guide 1.8, Revision 3, May 2000 with the exceptions clarified in the current revision to the Operator Licensing Examination Standards for Power Reactors, NUREG-1021, Section ES-202. This exception is based on NRC letter to PG&E dated May 26, 2006, issuing License Amendment Nos. 187/189. 4.15 2/79 -- -- Quality Assurance for Radiological Monitoring Programs (Normal Operations) - Effluent Streams and the Environment Record retention requirements are stated in Chapter 17, Section 17.17. This Regulatory Guide does not apply to the ISFSI.
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 17.1-1 Sheet 10 of 13 Revision 21 September 2013 Reg. Guides Date Standard No. Rev. Title/Subject Exceptions BTP PCSB 9.5-1 Appendix A 5/76
--
-- Guidelines for Fire Protection for Nuclear Power Plants The fire protection program for DCPP satisfies the requirements of GDC 3 (1967) by complying with the guidelines of Appendix A to NRC Branch Technical Position (BTP) (APCSB) 9.5-1, and with the provisions of 10 CFR 50.48 and Appendix R, Section III.G, J, L, and O, as stipulated by Operating License Condition 2.C(5) and 2.C(4) for Units 1 and 2, respectively. Approved deviations from Appendix A to BTP (APCSB) 9.5-1, and Appendix R sections are identified in Supplement Numbers 8, 9, 13, 23, 27, and 31 to the Safety Evaluation Report. Due to the absence of combustible materials within the ISFSI, other than the fuel in the onsite transporter, and based upon an analysis of a transporter fuel tank fire, it is concluded that a fire protection program is not required for the ISFSI. Thus, this BTP is not applicable. 1.26 2/76 -- -- Quality Group Classifications and Standards for Water, Steam, and Radioactive Waste Containing Components of Nuclear Power Plants Design and construction of Diablo Canyon Power Plant started in 1965 and most of the work cannot comply with the specific requirements of Regulatory Guide 1.26, February 1976. The intent of the Regulatory Guide has been followed as shown by comparing the Reg. Guide with Table 3.2-2 in the FSAR Update and the Q-List (Reference 8 of Section 3.2). This Regulatory Guide does not apply to the ISFSI. --- -- NCIG-01 2 Visual Weld Acceptance Criteria for Structural Welding at Nuclear Power Plants DCPP UNITS 1 & 2 FSAR UPDATE TABLE 17.1-1 Sheet 11 of 13 Revision 21 September 2013 Reg. Guides Date Standard No. Rev. Title/Subject Exceptions --- -- NCIG-02 2 Sampling Plan for Visual Reinspection of Welds --- -- NCIG-03 1 Training Manual for Inspection of Structural Weld at Nuclear Power Plants Using the Acceptance Criteria of NCIG-01 1.97 05/83 ANSI/ANS 4.5 1980 Instrumentation for Light-Water-Cooled Nuclear Power Plants To Assess Plant And Environs Conditions During And Following An Accident This Regulatory Guide is not applicable to the ISFSI. Note for Reg. Guide 1.33: These controls replace the biennial procedure review requirement found in Section 5.2.15 of ANSI N18.7-1976. 1. All applicable DCPP and ISFSI procedures (shall)* be reviewed following an unusual incident, such as an accident, unexpected transient, significant operator error, or equipment malfunction, and following any modification to a system, as specified by Section 5.2 of ANSI N18.7/ANS 3.2, which is endorsed by Regulatory Guide 1.33. 2. Non-routine procedures (e.g. emergency operating procedures, procedures which implement the emergency plan, and other procedures whose usage may be dictated by an event) (shall)* be reviewed at least every two years and revised as appropriate. 3. Routine DCPP and ISFSI procedures that have not been used for two years (shall)* be reviewed before use to determine if changes are necessary or desirable.
- The word should has been changed to shall denoting a regulatory commitment. Note for Reg. Guide 1.144: The following interpretation is added with respect to Regulatory Guide 1.144, Section C.3.b(2):
DCPP UNITS 1 & 2 FSAR UPDATE TABLE 17.1-1 Sheet 12 of 13 Revision 21 September 2013 When purchasing commercial-grade calibration services from calibration laboratories accredited by a nationally-recognized body, the accreditation process and accrediting body may be credited with carrying out a portion of the Purchaser's duties of verifying acceptability and effective implementation of the calibration service supplier's quality assurance program. Nationally-recognized accrediting bodies include the National Voluntary Laboratory Accreditation Program (NVLAP) administered by the National Institute of Standards and Technology (NIST) and other accrediting bodies recognized by NVLAP via a Mutual Recognition Agreement (MRA) In lieu of performing an audit, accepting an audit by another licensee, or performing a commercial-grade supplier survey, a documented review of the suppliers' accreditation shall be performed by the Purchaser. This review shall include, at a minimum, verification of all the following: (1) The accreditation is to ANSI/ISO/IEC 17025 (2) The accrediting body is either NVLAP or other Accreditation Bureau (AB) accepted as signatory (full member) to the International Laboratory Accreditation Cooperation (ILAC) through a Mutual Recognition Arrangement (MRA) e.g., American Association for Laboratory Accreditation (A2LA), ACLASS Accreditation Service (ACLASS), Laboratory, Accreditation Bureau (LAB), International Accreditation Service (IAS) or similar. (3) The published scope of accreditation for the calibration laboratory covers the needed measurement parameters, ranges, and uncertainties. Note for Reg. Guide 1.123: The requirements of ANSI N45.2.13, Section 3.2, "Content of the Procurement Documents," Subsection 3.2.3, "Quality Assurance Program Requirements" are accepted with the following exception: When purchasing commercial-grade services from calibration laboratories accredited by a nationally-recognized accrediting body, the procurement documents are not required to impose a quality assurance program consistent with ANSI N45.2-1971. Nationally-recognized accrediting bodies include the NVLAP administered by the NIST and other accrediting bodies recognized by NVLAP via a MRA. In such cases, accreditation may be accepted in lieu of the Purchaser imposing a QA Program consistent with ANSI N45.2-1971, provided all the following are met: (1) The accreditation is to ANSI/ISO/IEC 17025 (2) The accrediting body is either NVLAP or other Accreditation Bureau (AB) accepted as signatory (full member) to the International Laboratory Accreditation Cooperation (ILAC) through a Mutual Recognition Arrangement (MRA) e.g., American Association for Laboratory Accreditation (A2LA), ACLASS Accreditation Service (ACLASS), Laboratory, Accreditation Bureau (LAB), International Accreditation Service (IAS) or similar. (3) The published scope of accreditation for the calibration laboratory covers the needed measurement parameters, ranges, and uncertainties. DCPP UNITS 1 & 2 FSAR UPDATE TABLE 17.1-1 Sheet 13 of 13 Revision 21 September 2013 (4) The purchase documents impose additional technical and administrative requirements, as necessary, to satisfy DCPP QA Program and technical requirements, including the requirement that the calibration/certificate report include identification of the laboratory equipment/standard used. (5) The purchase documents require reporting as-found calibration data when calibrated items are found to be out-of-tolerance.
Chairman, CEO and President PG&E Corporation President PG&E Senior Vice President Energy Supply Senior Vice President Safety and Shared Services Executive Vice President Electric Operations Director Applied Technology Services Support Services Supervisor, Engineering Records Unit Senior Vice President Chief Nuclear Officer Director Quality Verification Site Vice President FIGURE 17.1-1 PACIFIC GAS AND ELECTRIC COMPANY UTILITY ORGANIZATION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 21 September 2013Manager Nuclear Supply Chain Employee Concerns Program Supervisor Director Strategic Projects Senior Director Engineering and Projects Director Station Support
Senior Vice President - Chief Nuclear Officer Site Vice President Director Learning Services Employee Concerns Program Supervisor Director Quality Verification Senior Director Engineering and Projects Director Operations Services Director Security Services Director Site Services Station Director Director Nuclear Work Management Director Engineering Services Director Nuclear Projects Manager Nuclear Fuels FIGURE 17.1-2 NUCLEAR QUALITY IN THE UTILITY ORGANIZATION UNITS 1 AND 2 DIABLO CANYON SITE FSAR UPDATE Revision 21 September 2013Director Maintenance Services Manager Performance ImprovementManager Emergency Planning Director Station Support Director Compliance, Alliance, and Risk Director Geosciences Manager Regulatory Services Nuclear Safety Oversight Committee Manager Nuclear Supply Chain Director Strategic Projects}}